Drilling Fluids Manual Handbook

hse section 1

health, safety and environment (hse)

your health & safety is primarily your own responsibility your actions will directly impact the health & safety of others we all have a duty to support and promote the health and safety of others

section 1

Scomi Oiltools

Introduction

2

drilling fluid engineer - roles and responsibilities

2

hazard and risk assessment

2

hazardous materials

3

Personal Protective Equipment (PPE)

4

material safety data sheet – msds

5

chemical wallcharts

5

mixing guidelines

5

hydrogen sulphide

6

non aqueous fluids

9

9

potential hazards and risks

miscellaneous rig hazards

11

trips and falls

11

falling objects

11

hand injuries

12

fire

12

stepback 5 x 5

12

Section

1

health, safety and environment


introduction

The purpose of this section is to provide general guidelines for prudent work practices and procedures for the use of chemicals, and to protect Drilling Fluids Engineers and Rig Personnel from the potential health hazards of the chemicals they encounter in the workplace. All personnel must be made aware of the guidelines. New employees should receive safety training before beginning work with hazardous chemicals.

drilling fluid engineer - roles and responsibilities

ƒ Attend Operators/Contractors safety meetings and advise on all HSE matters pertaining to Scomi Oiltools products. The requirement for Drilling Fluids Engineers is to not only attend, but to contribute, to safety meetings onsite, including giving presentations about the fluids and chemicals being used. ƒ Give toolbox / pre-tour talks on chemical safety. ƒ Take part in risk assessments relevant to fluids, in particular for the first use of new systems e.g. SBM / OBM etc., ƒ Follow all procedures related to HSE and follow all wellsite directives issued by the operator and / or drilling contractor. ƒ Ensure correct and updated safety posters are in place in the mud and sack rooms or mixing areas for land rigs. ƒ Ensure MSDS are up to date and easy to locate. ƒ Use engineering controls and personal protective equipment, as appropriate. ƒ Use rig specific HSE Observation system e.g. STOP.

hazard and risk assessment

The use of chemicals in the workplace presents hazards and risks to personnel involved in their handling and application. In order to minimise these hazards risk assessments are performed and HSE control measures and management systems are established to achieve the following:Identify hazards ƒ Safely manage those hazards. Identify risks ƒ Where possible, eliminate those risks through control / engineering measures e.g. ventilation and collection of dust. ƒ Where not possible, manage those risks through processes including the use of PPE. ƒ Provide training and awareness systems designed to achieve the above and promote continuous improvement. A health Hazard is defined as: The potential of a chemical or substance to cause harm to the health of personnel or the environment. A health Risk is defined as: The likelihood that a chemical or substance will cause harm to personnel or the environment in the actual circumstances of exposure.

RISK = Hazard x Exposure

hazardous materials

The effect on a person of a hazardous material depends on: ƒ ƒ ƒ ƒ

The nature of the hazardous material. The site of the action. The amount of the hazardous material involved (“dose”). The reaction of the individual (“susceptibility”).

Hazardous Material Effects Local effects: ƒ Skin and eye irritation & burns. ƒ Skin defatting leading to dermatitis. Systemic effects: ƒ Central nervous system (headaches, nausea, dizziness). ƒ Cardiovascular system (CO poisoning). ƒ Sensitisation (allergy) and asthma. ƒ Teratogenic and carcinogenic. Chemical hazardous effects may be: ƒ ƒ ƒ

Acute - effects lasting minutes, hours or days e.g. irritation i.e. generally short term recoverable effects. Chronic - effects lasting weeks, months or years e.g. occupational asthma – generally long and possibly permanent effects. Effects may be reversible or irreversible.

Routes of Entry to the Body ƒ Injection

EYES INGESTION

SKIN ADSORPTION

ƒ Inhalation ƒ Ingestion (swallowing)

INHALATION

ƒ Skin and eye contact Layer & Structures of the Skin (Epidermis raised to show papillae)

Hair shaft

Cornified layer (dead cells) Pigment layer

EPIDERMIS

Spiny (Prickle cell layer) Germinating layer Dermal papilla Capillary tuft Oil (sebum) Sebacecous (oil) glands

DERMIS

Sensory nerve endings for touch (Ruffini’s corpuscles) Erector muscle for hair follicle Hair follicle Sweat gland Papilla of hair follicle

SUBCUTANEOUS FATTY TISSUE

Sensory nerve endings for pressure (Pacini’s corpuscles) Fat

Beck

Blood vessels

SKIN-PROTECTION AND TOUCH

Chemical Injuries to the Skin ƒ One of the body’s biggest organs – one major function is protection. ƒ Composed of the outer (epidermal) and inner (dermal) layer. ƒ Major protection provided by the outer layer. ƒ Irritant contact dermatitis a common skin disease which results from direct contact with a chemical. ƒ Effects occur only where contact occurs and can range from a redness to blistering and formation of pustules.

Section

1


Burn 1 A caustic burn at the back of the ankle.

Burn 2 The same caustic burn one week later.

Personal Protective Equipment (PPE) ƒ Hard Hat

ƒ Coveralls, i.e. long sleeved, fire resistant, to cover as much body skin as possible, rubber apron when handling hazardous material.

ƒ Gloves, long rubber gloves for handling hazardous materials.

ƒ Boots – recommended rubber or treated leather.

ƒ Eye Protection, glasses, goggles or full face mask (as appropriate).

ƒ Dust mask, particulate filter mask, respirator (as appropriate).

PPE should be checked before use each time and examined on a regular basis if not in regular use. Remember – PPE requires care and maintenance.

Ensure PPE being worn is in good condition and provides the desired protection !!

material safety data sheet – msds

An assessment is made of the physical and health hazards of each chemical supplied by Scomi Oiltools. This information is included in a Material Safety Data Sheet (MSDS) and, in part, on container labels. Material Safety Data Sheets contain the following information: 1 Product Identification 2 Composition, information on ingredients 3 Hazard identification 4 First aid measures 5 Fire fighting measures 6 Accidental release measures 7 Handling and storage measures 8 Exposure controls, personal protection 9 Physical and chemical properties 10 Stability and reactivity Ensure that the following practices are followed regarding MSDS information at the workplace: ƒ Provide active up-to-date MSDS files covering all drilling fluid chemicals on location either on CD or paper copies. This must also include the laboratory testing chemicals. ƒ Distribute the MSDS files to the Wellsite Manager / OIM, Medic (or designate) and sack storage / mixing areas. ƒ Update the MSDS file list whenever a new item is received.

chemical wallcharts

Display wallchart with basic safety information in key areas, laboratory, sack room and mixing areas. The wallchart should include short information covering immediate actions in case of exposure of personnel or spill.

Promotions Committee


Kwok Kian Hai (Chairman)


Tan Sri Datuk Dr Yusof Basiron


Dato’ Haji Sabri Ahmad


Haji Nasrullah Khan

Haji Nasrullah Khan

Er Kok Leong

Er Kok Leong

Carl Bek-Nielsen

Carl Bek-Nielsen

Zubir Abdul Aziz

Zubir Abdul Aziz

Kwok Kian Hai Chairman, Asia Pacific


Chairman, SubContinent

Chairman, SubContinent

Dato’ Haji Sabri Ahmad Chairman, Africa

Dato’ Haji Sabri Ahmad Chairman, Africa

Zubir Abdul Aziz Chairman, Middle East










Haji Nasrullah Khan

Haji Nasrullah Khan

Er Kok Leong

Er Kok Leong

Carl Bek-Nielsen

Carl Bek-Nielsen

Zubir Abdul Aziz

Zubir Abdul Aziz

Regiona l Market Committee

Regiona l Market Committee



Chairman, Sub-Continent

Chairman, Sub-Continent

Dato Haji Sabri Ahmad ’ Chairman, Africa

Dato Haji Sabri Ahmad ’ Chairman, Africa



Carl Bek-Nielsen Chairman, Europe

Carl Bek-Nielsen Chairman, Europe

Haji Nasrullah Khan

Haji Nasrullah Khan

Haji Nasrullah Khan

Haji Nasrullah Khan

Financial and General Affairs Committee




Dato’ Low Mong Hua

Dato’ Low Mong Hua

Mohd Zain Omar

Mohd Zain Omar

Dato’ Mamat Salleh


Mohd Zain Omar

Mohd Zain Omar

Er Kok Leong

Er Kok Leong





Er Kok Leong

Er Kok Leong




Tan Sri Datuk Dr Yusof Basiron Haji Nasrullah Khan Neazullah

Haji Nasrullah Khan Neazullah

Er Kok Leong

Er Kok Leong

Carl Bek-Nielsen

Carl Bek-Nielsen

Er Kok Leong

Er Kok Leong

Carl Bek-Nielsen

Carl Bek-Nielsen

mixing guidelines pre-job

ƒ Select the chemicals to be mixed. ƒ Review MSDS (Material Safety Data Sheets). ƒ Review the wall charts. ƒ Obtain appropriate tools, e.g. barrel pump. ƒ Inspect the condition of the chemicals to be mixed. ƒ Obtain appropriate PPE and WEAR IT. ƒ Ensure mixing personnel have clear written instructions. ƒ Perform a Job Hazard Analysis for any new chemicals or personnel.

mixing ƒ Check that hopper is running and that the correct lines valves and pits have been selected. ƒ Ensure sufficient extraction and ventilation in hopper area. ƒ Ensure that sacks and drums are conveniently positioned and use correct lifting procedures. ƒ Be aware of any forklift operations. ƒ Clean up spills as soon as possible. ƒ Close the hopper any time chemicals are not being mixed.

Section

1


cleaning up ƒ Inform derrickman, pump man or supervisor that job is complete. ƒ Clean up mixing area. ƒ Dispose correctly of empty sacks, drums and pallet waste, e.g. banding, wood & plastic wrapping in the correct manner. ƒ Ensure forklift is parked in designated area with forks lowered. housekeeping rules for drilling fluids ƒ Immediately clean-up all chemical spills, dry or liquid. ƒ Immediately clean-up all drilling fluid spills. ƒ Have a dedicated storage area for hazardous chemicals – this may require a bunded area to prevent leakage of any liquid spillage. ƒ Ensure that pallets are labelled on all four sides and the top to allow easy and correct identification of chemicals. ƒ Maintain fume and dust extraction equipment over mixing hoppers, shale shakers and mud pit area. ƒ Ensure adequate supply of masks for dust protection. ƒ Provide particulate filters and respirators as necessary. ƒ Rotate personnel working in high risk areas to minimise exposure.

hydrogen sulphide Hydrogen Sulphide (H2S) hydrogen sulphide is highly poisonous as well as corrosive. Small concentrations in air may be fatal in minutes.

Hydrogen sulphide (H2S) is a colourless poisonous gas that smells like rotten eggs. Often referred to as “sewer gas” it occurs naturally in the earth in crude petroleum, natural gas reservoirs, volcanic gases and hot springs. As well as being found downhole in sour gas reservoirs hydrogen sulphide can be produced by the action of sulphur reducing bacteria and the break down of a number of products anerobically, particularly in fluids left behind casing. It can be detected by smell at concentrations ranging from as low as 0.01 - 0.3 parts per million (ppm). However, relying solely on its odour is dangerous because at concentrations above 100 ppm it deadens a person’s sense of smell within a few minutes. The pure gas is heavier than air and can collect in low areas on rigs such as pits, storage areas and accommodation units. The presence of hydrogen sulphide in a drilling fluid, [if not treated with caution], can be lethal to personnel, apart from the corrosive impact of even low concentrations on the drilling fluid and rig equipment. Short–term (acute) exposure to hydrogen sulphide can cause irritation to the nose, throat, eyes and lungs and exposure to higher concentrations can cause very serious health effects, and even death as detailed in Table 1.

oncentration C (ppm) 0.01 - 0.3 1 - 20

20 - 50

100 - 200 250 - 500 500

500 -1000 >1000 Table 1.

Health effect Odour threshold Offensive odour, possible nausea, tearing of the eyes or headaches with prolonged exposure Nose, throat and lung irritation; digestive upset and loss of appetite; sense of smell starts to become fatigued; acute conjunctivitis may occur (pain, tearing and light sensitivity) Severe nose, throat and lung irritation; ability to smell odour completely disappears. Pulmonary oedema (build up of fluid in the lungs) Severe lung irritation, excitement, headache, dizziness, staggering, sudden collapse (knockdown), unconsciousness and death within a few hours, loss of memory for the period of exposure Respiratory paralysis, irregular heart beat collapse and death without rescue. Rapid collapse and death

Hydrogen sulphide toxicity to man

proactive actions for the mud engineer On wells where there is a high likelihood of encountering hydrogen sulphide it is recommended that beards are shaved. This is to ensure that breathing sets are sealed tightly against the face. It is imperative that all personnel be aware of the hydrogen sulphide alarm, as well as the designated safe area to evacuate to. It must be stressed that the safe area, unless in a positive pressure environment, must be upwind at a higher elevation than the gas source. Even on wells that are unlikely to have hydrogen sulphide it is recommended that a contingency stock of sulphide scavengers is kept at the rig site. When the presence of H2S is suspected the mud engineer is asked to confirm the presence and concentration of the gas. Never ever enter an area where any acid gas is suspected unless specifically trained and wearing the appropriate personal protective equipment. During displacements if the mud engineer has to be at the flow line ensure that there are at least two means of gas detection and available PPE as well as being aware of the nearest escape route.

first aid ƒ Immediately remove the victim from further exposure. Designated rescuers must wear properly fitting, positive pressure self-contained breathing apparatus (SCBA) and other required safety equipment appropriate to the work site. ƒ If the worker is not breathing, apply cardio-pulmonary resuscitation in the nearest safe area. ƒ Remove contaminated clothing, but keep the individual warm. Keep conscious individuals at rest. ƒ Be aware of possible accompanying injuries (e.g. the victim may have fallen when they were overcome) and treat them accordingly. ƒ If the victim’s eyes are red and painful, flush with large amounts of clean water for at least 15 minutes. ƒ Ensure the worker receives medical care as soon as possible. The worker must not be allowed to return to work or other activities.

h2s tests

On rigs where H2S is expected, there are fixed hydrogen sulphide detectors placed in strategic locations, shale shakers, pit room, rig floor and flow-line. In addition portable detectors should be available and are to be used when entering enclosed spaces or as personal monitors when contamination is suspected. There are 2 common tests for H2S in drilling fluids, a qualitative test and a quantitative test. The qualitative test should only be used as a quick method to confirm the presence of H2S in the mud. In order to effectively treat and remove sulphides it is essential to perform the qualitative test, Garret Gas Train, and determine the concentration in the system.

Section

1


qualitative test Lead acetate (Hach test): An alka-seltzer tablet drives hydrogen sulphide gas from solution and the hydrogen sulphide reacts with lead acetate soaked in a filter paper. The degree of colour change is a measure of hydrogen sulphide concentration in the mud.

quantitative test The Garrett Gas train is an instrument used for quantitative analyses of sulphides and carbonates. Specific test methods have been published by API. The oil-mud procedure analyzes active sulphides and uses whole mud samples, whereas the water-base mud procedure tests filtrate. The Garrett Gas Train method for sulphides is detailed in Section 3, mud testing procedures for both WBM and NAF.

drilling fluid treatment A common field approach is to neutralise H2S by the addition of caustic soda and or lime. At pH 12 and above the sulphides are soluble and the H2S is dissociated. H2S + H20→H+ + HS- → 2H+ + S= This reaction is reversible and as the pH drops the hydrogen and the sulphide re-associate and H2S may be released from mud. Ionic Distribution of H2S with pH 1 1 0.1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

HSH2S

S-

0.01

n tio ac Fr 0.001

0.0001

pH

This treatment is only recommended to treat very minor amounts of H2S such as that associated with pore space gas. It does not remove the H2S from the drilling fluid. This treatment will only sequester the H2S. Continued exposure of the liquid to H2S will reduce the pH of the system and will eventually begin to release the gaseous H2S once the pH has fallen below pH 7. In order to effectively deal with an influx of H2S it is essential to use a sulphide scavenger which is an additive that reacts with sulphides to convert them to an inert form e.g. zinc sulphide and is an irreversible reaction. Zinc or iron compounds are the products of choice e.g. Zinc Carbonate and Zinc Oxide. It is estimated that 0.002 lb/bbl (0.0057 kg/m3) of Zinc Carbonate will precipitate 1 mg/ l of sulphide. Zinc carbonate is used primarily in water based muds but caution must be taken as continuous treatments may produce undesirable zinc or carbonate concentrations which can adversely effect drilling fluid rheology and fluid loss. Zinc oxide is primarily used in NAF (Non Aqueous Fluids) but may also be used in water based systems.

zinc carbonate 2ZnCO3 + 3Zn(OH)2 + 5H2S = 5ZnS + 2CO2 + 8H20 zinc oxide (contains more zinc than zinc carbonate) H2S + ZnO → ZnS + H2O. It should be noted that there may be environmental restrictions preventing the use of zinc based H2S scavengers. If this is the case alternative iron based treatments should be used.

pre-treatment

To ensure a high level of protection against H2S influxes, zinc oxide should be added to the active mud system before drilling out the last casing shoe above a potentially H2S bearing zone. Add slowly and evenly through the hopper to achieve good distribution and any new volume mixed or added should be similarly treated. Note that pre-treatment might mask small influxes as they react with the zinc oxide in the system and detection may not occur until all the zinc has reacted. Hydrogen sulphide treatment of drilling fluids, along with proper pH control, should be used to reduce the amount of hydrogen sulphide that is recirculated. Caution is needed when handling drilling fluid that has been exposed to hydrogen sulphide because hydrogen sulphide can move from the liquid into the vapour space of the storage tank and will be released when the tank is opened.

non aqueous fluids

Invert emulsion muds (Non Aqueous Fluids) are generally a brine water phase emulsified in a hydrocarbon base fluid along with other chemicals to provide a stable drilling fluid with the required drilling properties. The components and properties of these fluids are detailed in section 8, NAF Fundamentals. From an HSE perspective these fluids present significantly more challenges in their use as the impacts of personnel exposure and environmental discharge are greater than with the majority of water base systems.

potential hazards and risks Personnel may come into direct or indirect contact these fluids in the following areas on the rig: ƒ The drill floor. ƒ The mud pit area and the mud pump room. ƒ The sack room and mixing area. ƒ The shale shaker and solids process area. ƒ The laundry. It is imperative that any exposure is dealt with immediately and personnel do not continue to work with wet clothing as this can lead to long term health issues. The following exposure effects may occur.

eye / skin contact Due to the higher salinity and oil content of invert systems, irritation to both the skin and eyes can occur if they come into contact with the fluids. Calcium chloride accentuates the tendency to irritate by removing the natural oils in the skin and weakening the skins tolerance to other components in the NAF such as the base fluids. Untreated exposure may lead to dermatitis and or eczema.

Section

1


Use barrier creams to reduce this effect and if skin becomes dry use a good lanolin based moisturising cream to replenish removed natural oils.

dust, mist & vapour inhalation Rig personnel may inhale dust, vapours or mists which are at their highest concentration in the shaker house, pit room and mixing area. Vapours are generally generated by higher temperatures driving off water vapour which will contain some of the organic components in the system. Mists are normally generated when using pressure wash down equipment. Dust is generated when powders become released into air. During the mixing of sacked and bulk powders, dust will be generated. Ensure that there is adequate ventilation and extraction available at the mixing hopper. All flowlines / mud ditches should be fully enclosed. Shale Shakers and solids control equipment should be enclosed in extraction hoods to contain and remove mists and vapours. Areas where vapours or mists are generated must be well ventilated and personnel should minimise their exposure time in these areas, and be rotated if there is a need to spend extensive periods working on equipment such as shale shakers whilst drilling.

slippery floors OBM / SBM fluids are usually lubricious and any spillage will produce a very slippery surface creating a significant safety hazard to personnel. All spills must be cleaned up immediately. ƒ Minor spills should be “squeegeed” or mopped up or covered with an absorbent material such as sawdust, barite or dedicated spill absorbency materials which should be disposed of correctly. NB. Barite used to adsorb spills can be recycled into the mud system. ƒ Larger spills should be vacuumed with a diaphragm pump or dedicated vacuum system.

noise Loud and continuous noises will gradually degrade hearing. When in high noise environments such as the Shakers, Pump Room and Rig floor ensure that hearing protection is used.

laundry One of the main sources of skin problems is incorrect laundering. OBM and SBM are difficult to clean from clothing. It is recommended that a dedicated washing machine is used to wash coveralls, slicker suits, gloves etc. separately from personal clothing, Detergent specifically manufactured for cleaning oily clothing should be used. If possible a pre-wash then wash cycle should be introduced in the washing programme to ensure maximum cleanliness of all clothing worn close to the skin. Incorrectly washed clothes may cause skin irritation.

ppe It is recommend that PPE as specified elsewhere in this section is used at all times and in particular the following points are noted:ƒ Coveralls should cover as much skin as possible with full length sleeves which can be sealed at the wrist. Coveralls should be made from flame resistant materials. ƒ All buttons or zips should remain closed when exposed to chemicals. ƒ Gloves and footwear should overlap where the coveralls end. ƒ Use barrier creams in those areas that cannot be covered by some form of PPE. These areas include portions of the face, neck and arms where one piece of PPE may not meet another. A barrier cream for protection against Organic / Water emulsions is recommended.

10

immediate first aid In the event of personnel becoming exposed to any chemical and the chemical is known then refer to the MSDS or Wallchart for the appropriate action to be taken. If the chemical is not known then the following general first aid measures apply. EYE

Immediately flood the eye with water for at least 15 minutes while holding the eye open. Then obtain medical attention. INHALED Remove from exposure, keep warm and at rest. If breathing difficulty develops, ensure airways are clear and give Oxygen through a face mask. If breathing has stopped apply artificial respiration immediately. Seek urgent medical assistance. SKIN Remove contaminated clothing. Remove any mud with medicated degreaser, then wash with soap and water. Obtain medical attention if irritation develops. SWALLOWED Wash out the mouth. Give water to drink, DO NOT INDUCE VOMMITING unless specifically recommended in the MSDS. Obtain medical attention. If any medical condition, however minor, occurs seek medical attention immediately. All incidents and unsafe conditions must be reported to the rig medic and / or rig safety representative.

miscellaneous rig hazards

Most engineers work at the rig site of the clients, it is imperative that they follow the clients HSE requirements and systems. The engineers should be aware of the rig safety systems including the alarms and emergency responses. The engineer must actively participate in any and all preventative systems. All accidents and or near miss incidents should be reported through the STOP card or equivalent systems. Engineers work for a number of different clients and are a crucial element in the transfer of HSE experience between operators. A number of rig specific risks exist some are detailed below:

trips and falls There are numerous trip hazards on a rig site. In order to prevent tripping good house keeping is essential. The following actions are suggested ƒ Ensure that waste material is tidied away as soon as possible. ƒ When rigging up temporary hoses ensure that they are clearly sign posted. ƒ The most common tripping occurrence is while climbing stairs. Ensure that while climbing stairs at least one hand is on the rails. ƒ Ensure that guard rails around tanks are in place and in good condition. ƒ Ensure that tops of pits are covered an if opened they are barriered off with clear signs. ƒ Obey all rig-site signs and barriers. ƒ Never work at heights without appropriate training and equipment.

falling objects Mud Engineers rarely work at heights but on occasion due the rig layout it may prove necessary e.g. during displacements the flow line may be at height. However if working at heights do not work without an approved platform and wear inertia protection. While at a rig site be aware that other personnel may be working atheights and using hand held tools which can fall and cause severe injuries. Always be conscious of the need to identify and avoid such potential hazards. Also note that cranes may be shifting loads overhead; never stand or walk under a load. 11

Section

1


hand injuries Hand injuries are the most common injuries on rigs. Always be aware of potential squeeze points and assess all activities carefully before commencing the work.

fire The mud engineer should be aware of the specific fire fighting systems of the rig, location of the muster points and evacuation procedures. Ensure that all heating and electrical equipment in the mud lab is in good condition and can be operated in a safe manner. Ensure that the lab has two exits and is equipped with an appropriate fire extinguisher. Ensure that materials are stored as per MSDS instructions to minimise the danger of fire and that the required fire fighting equipment available and operational. Not only is fire lethal, but it may generate toxic smoke from drilling fluid products. If a fire is found raise the alarm, and only attempt to fight the fire with the available fire fighting equipment, if you have been trained in its use and as long as this will not result in personal injury.

stepback 5 x 5

Before you start any job take 5 steps back from the work area and invest a few minutes to step through the work in your mind. Before the Job: ƒ Stop and think. ƒ Observe the work area and surroundings. ƒ Think through the steps of what you will be doing. ƒ Identify what is happening today in your area. ƒ Identify any hazards. ƒ Develop methods for eliminating and controlling these hazards. ƒ Satisfy yourself that the hazards are controlled before starting the job. During the Job: ƒ Do you feel safe doing the job? ƒ Are others around you working safely? ƒ Repeat the steps above if you encounter an unexpected problem. After the job: ƒ Observe the work area. ƒ Take action to control any hazards that may have been created because of the job. ƒ Reflect on the job performed. ƒ Can any improvements be made? ƒ Discuss these improvements at tour and safety meetings.

STOP AND THINK BEFORE YOU ACT

12

functions section 2

drilling fluid functions

section 2

Scomi Oiltools

Introduction

2

primary functions

2

control formation pressure

2

transport cuttings

3

maintain stable wellbore

4

secondary functions

10

support weight of tubulars

10

cool and lubricate bit and drill string

10

transmit hydraulic horsepower to bit

10

provide medium for wireline logging

10

assist in formation evaluation

10

Section

2



introduction The objective of a drilling operation is to drill, evaluate and complete a well that will produce oil and/or gas efficiently. Drilling fluids perform numerous essential functions that help make this possible. A properly designed drilling fluid will enable an operator to reach the desired geological objective at the lowest overall cost. A fluid should enhance penetration rates, reduce hole problems and minimise formation damage. Removing cuttings from the well, maintaining wellbore stability and controlling formation pressures are of primary importance on every well. Though the order of importance is determined by well design, conditions and current operations, the most common drilling fluid functions are: 1 Transport cuttings from the well 2 Control formation pressures 3 Maintain stable wellbore 4 Seal permeable formations 5 Suspend cuttings downhole and release them on surface 6 Minimise reservoir damage 7 Cool, lubricate, and support the bit and drilling assembly 8 Transmit hydraulic energy to tools and bit 9 Ensure good data recovery 10 Control corrosion 11 Facilitate cementing and completion 12 Minimise HSE risk

primary functions Drilling fluids are designed and formulated to perform three prime functions: ƒ Control Formation Pressure ƒ Transport Cuttings ƒ Maintain Stable Wellbore

control formation pressure A drilling fluid controls the subsurface pressure by its hydrostatic pressure. Hydrostatic pressure is the force exerted by a fluid column and depends on the mud density and true vertical depth (TVD). Borehole instability is a natural result of the unequal mechanical stresses and physico-chemical interactions and pressures created when surfaces are exposed in the process of drilling a well. The drilling fluid must overcome both the tendency for the hole to collapse from mechanical failure and/or from chemical interaction of the formation with the drilling fluid. Normal formation pressures vary from a pressure gradient of 0.433 psi/ft (9.79 kPa/m) (equivalent to 8.33 lb/gal or SG 0.99 freshwater) in inland areas to 0.465 psi/ft (10.51 kPa/m) (equivalent to 8.95 lb/gal or SG 1.07) in marine basins. Elevation, location, and various geological processes and histories create conditions where formation pressures depart considerably from these normal values. The density of drilling fluid may range from that of air (essentially 0 psi/ft or 0 kPa/m), to in excess of 20.0 lb/gal (1.04 psi/ft) or SG 2.40 (23.51 kPa/m).

In most drilling areas, a fresh water fluid which includes the solids incorporated into the water from drilling subsurface formations is sufficient to balance formation pressures. However, abnormally pressured formations may be encountered requiring higher density drilling fluids to control the formation pressures. Failure to control downhole pressures may result in an influx of formation fluids, resulting in a kick, or blowout. Hydrostatic pressure also controls stresses adjacent to the wellbore other than those exerted by formation fluids. In geologically active regions, tectonic forces impose stresses in formations and may make wellbores unstable even when formation fluid pressure is balanced. Wellbores in tectonically stressed formations can be stabilised by balancing these stresses with hydrostatic pressure. Similarly, the orientation of the wellbore in high-angle and horizontal intervals can cause decreased wellbore stability, which can also be controlled with hydrostatic pressure.

transport cuttings As drilled cuttings are generated by the bit, they must be removed from the wellbore. To do so, drilling fluid is circulated down the drillstring and through the bit, transporting the cuttings up the annulus to the surface. Cuttings removal is a function of cuttings size, shape and density combined with Rate of Penetration (ROP), drillstring rotation, plus the viscosity, density and annular velocity of the drilling fluid. Cleaning the hole is an essential function of the mud. This function is also the most abused and misinterpreted. The drill solids generally have a specific gravity of 2.3 - 3.0 SG; an average of 2.5 will normally be assumed. When these solids are heavier than the mud being used to drill the hole, they slip downward through the mud. The rate at which a cutting settles in a fluid is called the slip velocity. The slip velocity of a cutting is a function of its density, size and shape, plus the viscosity, density and velocity of the drilling fluid. If the annular velocity of the drilling fluid is greater than the slip velocity of the cutting, the cutting will be transported to the surface While the fluid is in laminar flow, the slip velocity of cuttings is affected directly by the viscosity or shear characteristics of the mud. Thus, when the annular mud velocity is limited by pump volume or enlarged hole sections, it often is necessary to viscosify the mud to reduce the slip velocity of the formation cuttings to keep the hole clean. Sometimes the decision to increase the lifting capacity of the mud is complicated by the fact that any viscosifying of the mud may adversely affect other drilling conditions. For example, if the mud is viscosified, circulating pressure losses increase and the danger of lost circulation increases. Small batches of viscous mud can be used to lift cuttings and to minimise the requirement for viscosifying all of the mud. Fluid flowing from the bit nozzles exerts a jetting action to clear cuttings from the bottom of the hole and the bit, and carries these cuttings to the surface. Several factors influence cuttings transport. If the cuttings generated at the bit face are not immediately removed and carried towards the surface, they will be ground very fine, stick to the bit and retard effective penetration. Velocity - Increasing annular velocity generally improves cuttings transport. Variables include pump output, borehole size and drill string size. Density - Increasing mud density increases the carrying capacity through the buoyant effect on cuttings.

Section

2


Viscosity - Increasing viscosity often improves cuttings removal. Pipe Rotation - Rotation tends to throw cuttings into areas of high fluid velocity from low velocity areas next to the borehole wall and drill string. Hole Angle - Increasing hole angle generally makes cuttings transportation more difficult. Drilling fluids must have the capacity to suspend weight materials and drilled solids during connections, bit trips, and logging runs. Otherwise they will settle to the low side or bottom of the hole. Failure to suspend weight materials can result in a reduction in the drilling fluid density, which in turn can lead to kicks and a potential blowout. The drilling fluid must also be capable of transporting cuttings out of the hole at a reasonable velocity that minimises their disintegration and incorporation as a fine solid into the drilling fluid system. At the surface, the drilling fluid must release the cuttings for efficient removal. Failure to adequately clean the hole or suspend drilled solids are contributing factors to hole problems such as fill on bottom after a trip, hole pack-off, lost returns, differentially stuck pipe, and inability to reach bottom with logging tools.

maintain stable wellbore Wellbore instability during drilling causes ƒ Packoffs ƒ Excessive trip and reaming time ƒ Mud losses ƒ Stuck pipe & BHA’s ƒ Loss of equipment – Sidetracks ƒ Inability to land casing ƒ Poor logging and cementing conditions There are 3 stresses acting on the formation sv Vertical Stress – Weight of rock and water above sH Maximum Horizontal Stress – Regional Stress sh Minimum Horizontal Stress – Regional Stress

Overburden stress

Maximum horizontal stress

Manimum horizontal stress

The following diagram illustrates how the earth stresses adapt to the borehole as mud pressure substitutes for the load bearing capacity of the drilled rock Earth stresses

Borehole stresses

SV So

SH

Sr So

Sh

Wellbore failure problems can be categorised in two groups; Tensile failure: where the well pressure is too high for the wellbore at a given trajectory, losses occur through opening pre-existing natural fractures and initiation of new (induced) fractures occurs if the well pressure exceeds the fracture gradient e.g. when mud weight overcomes borehole stresses and rock strength. Compressive failure: when the well pressure is too low for a particular well trajectory, wellbore stress builds up and the wellbore wall tries to contract and close. This can occur at high or low mud weights. The mode of failure depends on mechanical properties of the rock, varying from creep closure in weak and soft ductile formations like salt to while in competent and brittle rocks, this leads to cavings and overgauge holes, when the cavings fall into the wellbore. These generalised failure types are illustrated below and overleaf

Tensile failure Circulation lost through induced fractures Mud pressure

Section

2


Compressional failure

Hole enlargement through breakouts

Elastic formations such as sandstones and shales

Ductile formations such as salt

Hole reduction

OVERGAUGE HOLE Breakout OVERGAUGE HOLE Washout

Shale (Brittle ) Shale /

muds

tone

Friab le sa n

dsto ne / s and Lime ston e San dsto ne Salt

LOST CIRCULATION Induced fractures

HOLE CLOSURE Creep

The following diagram illustrates the safe mud weight window for trouble-free drilling in a conventionally stressed earth in which ÓV>ÓH≥Óh. The blue curves show the compressional failure limits while the red curve shows the tensile fracture limit. The window narrows as well deviation increases

Borehole deviation, degree

80

Tensile failure Compressional failure

60

40

Safe window 20

0

2

4

6

8

10

12

14

16

18

20

(0.24)

(0.48)

(0.72)

(0.96)

(1.20)

(1.45)

(1.69)

(1.93)

(2.17)

(2.4)

Mud weight, lbm/gal (SG)

When we drill the wellbore we replace a cylinder of rock with a cylinder of mud. The first critical step towards designing a drilling fluid is to establish the mud weight required to provide the correct level of bore hole pressure support. Borehole Pressure Support Pore pressure prediction involves the full cooperation of several different engineering disciplines, i.e. Petrophysical, Geology, Reservoir & Geomechanics. It is crucial that rigorous seismic and / or geological well data interpretation is done to determine the anticipated pore pressure regimes in order to identify any pressure reversals and therefore facilitate appropriate casing design. Mud weight planning is based on the predicted pore pressure gradient plus, typically, 200 to 500 psi (1379 – 3449 kPa). It is crucial that the drilling engineers thoroughly review all available offset well data with a special emphasis on procuring offset “leak off” and / or F.I.T. test data. One of the key elements to successfully drilling a stable, near gauge wellbore depends upon planning the correct mud weight. Maintaining Borehole Support Wellbore stability is a complex balance of mechanical (pressure and stress) and chemical factors. The chemical composition and mud properties must combine to provide a stable wellbore until casing can be run and cemented. Regardless of the chemical composition of the fluid and other factors, the weight of the mud must be within the necessary range to balance the mechanical forces acting on the wellbore (formation pressure, wellbore stresses related to orientation and tectonics). Wellbore instability is most often identified by a sloughing formation, which causes tight hole conditions, bridges and fill on trips. Fluid hydrostatic pressure acts as a confining force on the wellbore. This confining force acting across a filter cake will assist in physically stabilising a formation.

Section

2


Stable Mud Weight Window

STABLE WINDOW

Pore pressure gradient

+/- 200 psi (1379 kPa) to 500 psi (3449 kPa) overbalance

Fracture gradient

Wellbore stability is greatest when the hole maintains its original size and cylindrical shape. Once the hole is eroded or enlarged in any way, it becomes weaker and more difficult to stabilise. Hole enlargement leads to a number of problems, including low annular velocity, poor hole cleaning, increased solids loading, fill, increased treating costs, poor formation evaluation, higher cementing costs and inadequate cementing. Borehole stability is also maintained or enhanced by controlling the loss of filtrate to permeable formations and by careful control of the chemical composition of the drilling fluid. Most permeable formations have pore space openings too small to allow the passage of whole mud into the formation; however, filtrate from the drilling fluid can enter the pore spaces. The rate at which the filtrate enters the formation is dependent on the pressure differential between the formation and the column of drilling fluid, and the quality of the filter cake deposited on the formation face. Large volumes of drilling fluid filtrate, and filtrates that are incompatible with the formation or formation fluids, may de-stabilise the formation through hydration of shale and/or chemical interactions between components of the drilling fluid and the wellbore. Drilling fluids, which produce low quality or thick filter cakes, may also cause tight hole conditions including stuck pipe, difficulty in running casing and poor cement jobs. Chemical wellbore instability is due to chemical interaction between the formation being drilled and the drilling fluid. This occurs primarily in shales and salt formations. In both cases, it is an interaction with water that causes instability. Thus, chemical instability is always minimised by using oil-base muds. In shales, if the mud weight is sufficient to balance formation stresses, wells are usually stable - at first. With water-base muds, chemical differences cause interactions between the drilling fluid and shale, and these can lead (over time) to swelling or softening. This causes other problems, such as sloughing and tight hole conditions. Highly fractured, dry, brittle shales, with high dip angles, can be extremely unstable when drilled. The failure of these dry, brittle formations is mostly mechanical and not normally related to water or chemical forces. When shales react with water, they can soften, disperse, swell, and crack. These effects can cause a wide range of operational problems, as shown in the table below.

Table 1 Shale Type

Typical Hole Problems

Soft (shallow)

• Tight hole due to swelling • Hole enlargement due to washout • Ledges if interbedded with sandstones • Bit balling, mud rings, blocked flowlines • Tight hole due to swelling • Possible washout • Prone to bit balling • Occasional cavings • Cavings • Cuttings beds causing packing off • Tight hole in stressed formations • Possible stuck pipe • Cavings • Hole collapse

Firm (deeper)

Hard (deep)

Brittle (very deep)

MBT* (meq/100g) 20-40

Clay Types smectite + illite

10-20

illite + mixed layer

3-10

illite + poss. smectite

0-3

illite kaolinite chlorite

* MBT = methylene blue test - a measure of cation exchange capacity; high MBT equates to smectite rich shale. Various chemical inhibitors or additives can be added to help control mud/shale interactions. Systems with high levels of calcium, potassium or other chemical inhibitors are best for drilling into water-sensitive formations. Salts, polymers, asphaltic materials, glycols, oils, surfactants and other shale inhibitors can be used in water-base drilling fluids to inhibit shale swelling and prevent sloughing. Shale exhibits such a wide range of composition and sensitivity that no single additive is universally applicable. Oil or synthetic-base drilling fluids are often used to drill the most water sensitive shales in areas with difficult drilling conditions. These fluids provide better shale inhibition than water-base drilling fluids. Clays and shales do not hydrate or swell in the continuous oil phase, and additional inhibition is provided by the emulsified brine phase (usually calcium chloride) of these fluids. The emulsified brine reduces the water activity and creates osmotic forces that prevent adsorption of water by the shales. In salt formations, chemical instability occurs if the formation is soluble in water. Using an incorrectly formulated fluid will lead to uncontrollable washouts in these formations. Formation types which exhibit this behaviour are: ƒ ƒ ƒ ƒ ƒ

Halite (NaCl) Carnallite (KMgCl3.6H2O) Bischofite (MgCl2.6H2O) Sylvite (KCl) Polyhalite (K2Ca2Mg(SO4)4.2H2O)

Salt beds are usually drilled using salt saturated water phase fluids, the salt selected is usually the same as the salt being drilled.

Section

2


secondary functions Secondary functions of a drilling fluid include: ƒ ƒ ƒ ƒ ƒ

Support weight of tubulars Cool and lubricate the bit and drill string Transmit hydraulic horsepower to bit Provide medium for wireline logging Assist in the gathering of subsurface geological data and formation evaluation

support weight of tubulars Drilling fluid buoyancy supports part of the weight of the drill string or casing. The buoyancy factor is used to relate the density of the mud displaced to the density of the material in the tubulars; therefore, any increase in mud density results in an increase in buoyancy.

cool and lubricate bit and drill string Considerable heat and friction is generated at the bit and between the drill string and wellbore during drilling operations. Contact between the drill string and wellbore can also create considerable torque during rotation, and drag during trips. Circulating drilling fluid transports heat away from these frictional sites, reducing the chance of pre-mature bit failure and pipe damage. The drilling fluid also lubricates the bit tooth penetration through rock and serves as a lubricant between the wellbore and drill string thus reducing torque and drag. An additional source of heat is derived from the increasing thermal energy stored in formations with depth, geothermal gradient. The circulating fluid not only serves as a lubricant helping to reduce the friction between the drilling components in contact with the formation, but also helps conduct heat away from the friction points and formation.

transmit hydraulic horsepower to bit Hydraulic horsepower generated at the bit is the result of flow volume and pressure drop through the bit nozzles. This energy is converted into mechanical energy which removes cuttings from the bottom of the hole and improves the rate of penetration.

provide medium for wireline logging Air/gas-based, water-based, and oil-based fluids have differing physical characteristics which influence log suite selection. Log response may be enhanced through selection of specific fluids and conversely, use of a given fluid may eliminate a log from use. Drilling fluids must be evaluated to assure compatibility with the logging program.

assist in formation evaluation The gathering and interpretation of sub-surface geological data from drilled cuttings, cores and electrical logs is used to determine the commercial value of the zones penetrated. Invasion of these zones by the fluid or its filtrate, whether it is oil or water, may mask or interfere with the interpretation of the data retrieved and/or prevent full commercial recovery of hydrocarbon.

10

testing section 3

mud testing procedures

section 3a - wbm testing procedures section section 3b - naf testing procedures

Section

3



Mud Engineers will be responsible for ensuring that all mud testing activities are carried out in a safe and responsible manner, especially those involving high pressures, high temperatures and dangerous chemicals. Be aware of the hazards and ensure that all risks are well managed. Mud Engineers will be responsible for ensuring that all hazardous testing chemicals are correctly labelled, and safely stored and handled. They will also ensure that testing chemicals sent off the rig are correctly packaged and labelled. MSDS sheets for all the mud testing chemicals should be available in the mud lab. Copies should also be distributed to the Medic, client representative and the contractor representative. Empty bottles of testing chemicals should be thoroughly flushed out with water and then returned to the Mud Company for re-cycling or disposal. A Hazchem poster should be posted in the lab, detailing all the mud testing chemicals: ƒ Product Name ƒ Colour Code ƒ UN Code ƒ First Aid Treatment ƒ Fire Fighting Media ƒ Action for Spillage ƒ Personal Protection Recommended It is recommended to have a pair of oven gloves available for handling hot testing equipment, eg. retort and HTHP. Safety glasses are mandatory when conducting any mud test. This will help protect the eyes from broken glass, or being splashed with chemicals, mud or mud filtrate. Pipette filling devices are recommended for titrating, as they will prevent any dangerous chemicals being swallowed. Mud engineers should ensure that the mud lab has an adequate method of extracting fumes from chemicals or retorts. Either a strong extractor or a fume cupboard is recommended. If fume extraction is not adequate then recommendations for its improvement should be submitted to the client representative. If the mud lab is sited in a designated hazardous area the mud engineers should ensure that the mud lab is suitably pressurised. If pressurisation is inadequate then recommendations for its improvement should be submitted to the client representative. An adequate number of power points of the correct voltage should be available in the mud lab. Power points that have too many appliances running off them are a common source of fire. If there are not enough power points often a request to the rig electrician can resolve the matter. If that is not successful then the client representative should be consulted. Any base oil, or synthetic or ester based mud samples that are used for testing should be kept and disposed of in the active mud system. It should not be flushed down the sink. If practical, the surfactant mixtures that have already been used for testing non water base muds should be kept in a suitable container and later sent to shore for appropriate disposal. Surgical gloves should be available for handling dangerous testing chemicals or non water base fluids.

Section

3


good laboratory practices Regularly calibrate mud balances, pH, electrical stability and K+ meters. Ensure that all testing equipment is kept clean, working properly and that spare parts are available. This is particularly important in reference to “O” rings, batteries, gaskets, pressure regulators, HTHP valves, and meter probes. For critical instruments like the 6 speed Viscometer, it is necessary to have a back up 6 speed Viscometer, or handcrank available. All bottles of titrating chemicals must have a manufactured date on them. The date will indicate whether the chemical is still fresh enough to return accurate results. Ensure that a good supply of fresh testing chemicals is available. If there is any uncertainty about the accuracy and/or age of a particular chemical compare results obtained using a fresh sample of the same chemical. Ensure, where applicable, that all testing chemicals, including Dräger tubes and stick chemical testers, eg. nitrates and sulphites are within their use by date. Always use a dedicated, labelled pipette for each testing chemical. This prevents cross contamination of testing chemicals and erroneous test results. After use the WBM filtrate sample pipette should be flushed with distilled water and allowed to dry before re-use. This prevents salt crystals forming on the tip of the pipette. Use 50 ml glass beakers stirred with a small magnetic bead on a hot plate/stirrer in preference to the traditional ceramic or plastic titration dish and a glass rod stirrer. This method is far simpler and will lead to more consistent results. Wash all glassware with distilled water after use and drain dry or dry off with a clean paper towel. Keep the mud lab clean and tidy.

section 3a wbm testing procedures

section 3a

Scomi Oiltools

mud density

2

funnel viscosity

3

rheology

4

retort analysis

7

api filtrate

10

hthp filtration

11

sand content

13

pH

14

filtrate alkalinity – Pf and Mf

16

filtrate hardness – Ca++ and Mg++

18

filtrate chlorides

20

phpa content

22

potassium ion – direct reading potassium ion meter 25 potassium ion – sodium perchlorate method

(steiger method)

26

mbt test

27

glycol – cloud point and % by vol concentration

29

garrett gas train - sulphides

30

garrett gas train - carbonates

34

silicate testing

37

Section

3a

wbm testing procedures


mud density discussion The Mud Balance is used for mud weight determinations and is the recommended equipment in the API 13B standard procedures for testing drilling fluids. The mud balance is accurate to within +/- 0,1 lb/gal (or 0.5 lb/cu.ft, 0.01 g/ml, 10 g/l). It is designed such that the mud cup, at one end of the beam, is balanced by a fixed counterweight at the other end, with a sliding weight rider free to move along the graduated scale. A level bubble is mounted on the beam to allow accurate balancing. This, most basic, of mud properties is often reported incorrectly due to the use of an inaccurately calibrated mud balance. The time to check the balance is not when a well control situation develops but on a routine daily basis. The mud test kit will contain both standard mud balances and a pressurised Halliburton mud balance. Both types are calibrated by weighing distilled water at 70 °F (21.1 °C) and obtaining a reading of 1.00 SG / 8.345 lb/gal. If this is not the case adjust the balance by adding or removing lead shot as required. Experience has shown that, under normal drilling conditions, the standard balance gives the same reading as the pressurised balance. For ease of use, therefore, the standard balance may be routinely used to measure mud density. At the first indication of gas or air entrapment in the mud only the pressurised balance should be used. On a per tour basis the pressurised balance will be used to confirm it is reading the same as the standard balance

equipment ƒ Standard Mud Balance ƒ Pressurised Mud Balance

procedure – standard balance 1) Instrument base must be set on a flat level surface. 2) Measure and record the mud temperature. 3) Fill the mud cup with the mud to be tested. Gently tap the cup to encourage any entrapped gas to break out. 4) Replace cap and rotate until it is firmly seated, ensuring some of the mud is expelled through the hole on top, to free any trapped gas. 5) Holding cap firmly (with cap hole covered with thumb) wipe the outside of the cup until it is clean and dry. 6) Place the beam on the base support and balance it by using the rider along the graduated scale. Balance is achieved when the bubble is directly under the centre line. Example of standard mud balance

Have you checked the mud balance lately?

procedure – pressurised balance A problem with many drilling fluids is that they contain considerable amounts of entrained gas, leading to inaccurate mud weight measurements on the standard mud balance. By pressurising the mud cup the entrained air volume can be decreased to a minimum. The balance operates in much the same way as standard mud balance except the lid of the mud cup has a check valve. 1) Follow steps 1 - 5 as for the standard mud balance procedure. 2) Place the lid on the cup, with the valve in the open position, wipe the outside of the cup clean and dry. 3) The pressurising plunger is similar to operating a syringe. The plunger is filled by submersing the nose of the plunger in the drilling fluid with the piston rod in the completely inward position. The piston rod is then drawn up, thereby filling the plunger with fluid. 4) The nose of the plunger is then placed into the female ‘O’ ring on top of the cap. The sample is pressurised by maintaining a downward force on the cylinder housing in order to hold the check valve open, whilst at the same time forcing the piston rod inwards. Approximately 50 pounds of force or greater should be maintained on the piston rod. 5) The check valve in the lid is pressure actuated, i.e. closing as pressure is applied. The valve is therefore closed by gradually easing up on the cylinder housing while maintaining pressure on the piston rod. 6) Having applied pressure to the sample with the pump there should be no indication of fluid leaking back through the nipple. It should not be possible to depress the nipple by hand – if the nipple can be easily depressed it is a sign that pressure is not being held and a true weight is not being obtained. Change the ‘O’ ring and repeat the test. 7) Once the check valve is closed, disconnect the plunger and weigh the fluid as in step 6 of the standard mud balance procedure.

interpretation The density of WBM does not vary greatly with temperature. However, it is still a requirement to report the density at flowline and ambient temperatures. Water based muds can be prone to air entrapment and foaming. It is important to ensure that the density reported is as accurate as possible. The reason for this is that under downhole conditions the mud is compressed and thus the effective mud weight at the bottom can be much higher than indicated by a gas cut surface sample. Do not weigh up mud to compensate for an aerated or gas cut surface sample – Ensure you have a true mud weight before doing anything. For density control purposes the mud weight will always relate to what is being measured at flowline temperatures as this is the best indicator of what is actually in the hole at any particular time.

funnel viscosity discussion The Marsh Funnel Viscometer is used for routine viscosity measurements. The results obtained are greatly influenced by rate of gelation and density. The latter varies the hydrostatic head of the column of mud in the funnel. Because of these variations, the viscosities obtained cannot be correlated directly with those obtained using the rotational viscometers, and therefore can ONLY be used as an indicator of mud stability, or relative changes to mud properties.

Section

3a


The funnel viscosity will be measured in seconds per quart. The funnel must be calibrated on a regular basis. The viscosity of fresh water at 70 °F (21.1 °C) is 26 secs/qt (27.6 sec/l) and any reading above this would indicate that the spout of the funnel required cleaning. The diameter of the spout is 3/16” and a hand held drill bit of this diameter should be used to clear any deposits/cake.

equipment ƒ ƒ ƒ ƒ

Thermometer: 32 – 220 °F (0 – 105 °C) Stopwatch Graduated cup: one quart / litre Marsh funnel

procedures 1) Cover the orifice with a finger and pour a freshly agitated fluid sample through the screen into the clean, dry and upright funnel until the liquid level reaches the bottom of the screen. 2) Quickly remove the finger and measure the time required for the fluid to fill the receiving vessel to the one quart (946 ml). 3) Report the result to the nearest second as Marsh Funnel viscosity and the temperature to the nearest degree.

interpretation The funnel viscosity is a good quick guide to whether a water based mud is thickening or thinning. However further analysis of rheology and solids content will be required before embarking on any treatment program. The result is temperature dependent but not to the same degree as SBM. The funnel viscosity is, therefore, a more relevant indicator of trends in a WBM.

rheology discussion The rheology will be determined using a Motor Driven Fann 6 speed Viscometer. Ensure that the Viscometer motor runs at the same electrical cycles (either 50 hertz or 60 hertz) as the rig power, otherwise erroneous readings will be obtained. Offshore rigs usually operate on 60 hertz. All Viscometers sent to the rig site must have been recently calibrated and carry a label noting the date of the last calibration. Drilling fluid is contained in the annular space between two concentric cylinders. The outer cylinder or rotor sleeve is driven at a constant rotational velocity. The rotation of the rotor sleeve in the fluid produces a torque on the inner cylinder or bob, and the dial attached to the bob indicates displacement of the bob. This is the standard procedure recommended by API 13B for field testing water based drilling fluids. Instrument constants have been adjusted so that the Bingham plastic viscosity and yield point can be obtained by using the readings at 300 rpm and 600 rpm.

When checking oil base mud systems it is recommended to insert the thermometer in the actual fluid to ensure the correct testing temperature has been reached

The six readings will be taken at 120 °F (48.9 °C). A heated cup will be used for this purpose. Water Based Muds exhibit thinning tendencies with temperature and so it is still necessary to standardise this test by taking the readings at the same temperature on each occasion. The thermometer used must be calibrated against a mercury or alcohol type thermometer to confirm its accuracy. To adjust the thermometer simply use a small spanner to turn the nut on the back of the dial so that the thermometer reads the same temperature as the mercury or alcohol thermometer. The rheometer readings may be taken at a higher temperature, to reflect flow line temperatures, if required. However, to avoid confusion and to allow comparisons between wells, usually only the 120 °F (48.9 °C) readings will be entered in the mud check columns on the mud report. If necessary, readings taken at higher temperatures can be noted in the comment section. Note: Maximum operating temperature is 200 ˚F (93 ˚C). If fluids above 200 ˚F (93 ˚C) are to be tested, a solid metal bob or a hollow metal bob, with completely dry interior, should be used. Liquid trapped inside a hollow bob may vaporise when immersed in high temperature fluid and cause the bob to explode. The gelling characteristics of the fluid can be determined from taking a 10 second and a 10 minute gel reading. Consequently there is no requirement to take a 30 minute gel under normal circumstances. However if increasing rheology is becoming a problem a 30 min gel should also be taken in order to determine the effectiveness of the treatment programme.

Example of 6 Speed Rheometer

equipment ƒ Fann 35, 110 volt or 120 volt, powered by a two speed synchronous motor to obtain speeds of 3, 6, 100, 200, 300 and 600. ƒ Mud cup ƒ Stopwatch ƒ Thermometer 32 – 220 °F (0 – 104 °C)

procedures 1) Stir the sample at 600 rpm while the sample is heating, or cooling, to 120 °F (48.9 °C). Ensure the dial reading has stabilized at this speed before noting the result and proceeding to the 300, 200, 100, 6 and 3 RPM speeds. 2) Having taken the 3-RPM reading stir the sample at 600 RPM for 30 secs before taking the 10-second gel at 3 rpm. 3) Restir the sample at 600 rpm for 30 seconds and leave undisturbed for 10 minutes, ensuring the temperature stays at 120 °F (48.9 °C). Take the 10 minute gel reading at 3 rpm.

Section

3a


calculations Apparent Viscosity (AV) in Centipoise (cps) Yield Stress

= 600 reading ÷ 2 = 2 x 3 reading – 6 reading

Plastic Viscosity (PV) in = 600 reading - 300 reading Centipoise (cps) Yield Point (YP) Yield Point (YP) in Ib/100 ft2 Yield Point (YP) in Pa Power Law Index (n)

= 300 reading – PV = (300 reading – PV) x 0.48 = 3.32 log (600 reading / 300 reading)

Consistency Index (K): n Consistency Index (K) in Ib/100 ft2 = 600 reading / 1022 n Consistency Index (K) in Pa = (600 reading / 1022 ) x 0.48 Gels: Gels in Ib/100 ft2 Gels in Pa

= As per 10 sec & 10 min reading = (As per 10 sec & 10 min reading) x 0.48

Note: If the 600 rpm reading is off scale then the PV and YP can be calculated as follows; YP in Ib/100 ft2 = (2 X 100 rpm reading) – 200 rpm reading YP in Pa = [(2 X 100 rpm reading) – 200 rpm reading] x 0.48 PV

= 300 rpm – YP

PV (S.I units)

=

300 rpm reading – YP 0.48

interpretation The main focus of attention, with regards to mud rheology, is the 6 rpm reading. Mud programs will specify a range for the 6 rpm reading and so the other indicators of rheological properties, i.e. yield point, apparent viscosity, plastic viscosity and initial gel strengths, become a function of what is required to meet this low end specification. Experience has shown that the initial gel strength will be more or less the same as the 6-rpm reading. 10 minute gels that show an increasing trend and a widening divergence from the initial gel are a good indicator of a colloidal solids build up that may not be detected by solids analysis. This is due to the fact that while the solids percent may remain the same the actual size of the particles, and hence the surface area they present to the liquid phase, will decrease as degradation occurs. If the colloidal solids increase is not due to reactive claystones then the MBT test may not reveal the true nature of what is happening. The 10 minute gel in a WBM will always react to increasing fines and can often be the best indicator of solids related changes to mud properties. Increasing PV values are also generally a good indicator of a solids build up.

It is important to identify increasing trends at an early stage so that timely measures may be taken before they reach problem levels.

retort analysis discussion The accurate determination of the high gravity solids and low gravity solids in a WBM mud relies on the correct usage of the 50 ml retort and the correct interpretation of the results. A retort is used to determine the quantity of liquids and solids in a drilling fluid. A carefully measured sample of mud is placed in a steel cell and then heated until it vaporises. The vapours are then passed through a condenser and collected in a calibrated cylinder. The volume of liquid, water and oil can then be calculated in percent. The percent solids value, both suspended and dissolved, is determined by subtraction of the total liquid from 100%. Small errors in the measurement of the solids percentage can result in seriously erroneous reporting of the drilled solids content. It is apparent that inaccurate retort results can lead to unnecessary mud treatments aimed at reducing an apparently out of spec LGS concentration. It is essential that the retort be run at a high enough temperature to burn off the heavier fractions of any liquid additives such as glycol or lubricants. It is absolutely critical that the correct mud weight is used in the calculation to determine the relative concentrations of HGS and LGS. Using the flowline mud weight when the sample to be retorted has in fact cooled considerably, and hence increased in density, will give a much higher LGS content than is actually the case. The retort mud weight, i.e. the actual density of the mud in the retort as opposed to the flow line mud weight, will, therefore, be utilised in all calculations. The volume of the retort will be confirmed by filling the cell with distilled water (at ambient temperature) and checking that 50 cc’s is in fact received in the test tube. If 50 cc’s is not consistently obtained with distilled water (it might be necessary to repeat the check with distilled water to ensure the error is genuine) then, either the 50 cc retort cell must be replaced with an accurate one, or, a correction factor must be applied to the volume of distillate actually obtained, as per the following formula: 50 x Volume of distillate ccs Volume of distilled water obtained ccs Any smoke emerging from the heating jacket is an indication that vapour is escaping through the threads connecting the upper and lower parts of the retort cell. If this is noted it is an indication that the tube to the condenser is, or has been, blocked. A blocked tube will result in the bottom of the upper part of the retort cell “flaring” to allow an escape route for increasing pressure. Even if the tube is subsequently cleaned the flaring will remain and is still an escape route for a proportion of the vapour. This will obviously result in an inaccurate solids measurement. Any hint of smoke from the heating jacket is an indication that the top part of the retort cell is damaged and should be discarded.

Section

3a


It can be appreciated that a combination of all, or some of the factors mentioned above, i.e. insufficient retort temperature, incorrect mud weight used in calculations, volume being retorted not in fact 50 cc’s, partial escape of vapour through flared threaded area, can result in wildly inaccurate determinations of the drilled solids content.

equipment Three retort sizes are available to the industry, 10 ml, 20 ml and 50 ml. The latter is recommended for drilling operations, due to its greater precision and accuracy. Each unit consists of; ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ

Sample cup Thermostatically controlled heating element Liquid condenser Pyrex measuring cylinder (50 ml) Fine steel wool Pipe cleaner High temperature silicone grease Defoaming agent Spatula

procedures 1) Ensure retort assembly to be used is clean and dry. It is vital that all traces of previously retorted solids are removed from the retort cup to guarantee 50 ml of fluid is actually retorted. Remove all traces of previously used steel wool. Water can be retained in steel wool when the upper retort body is washed / cleaned. Failure to change the steel wool can result in inaccurate Example of Retort measurements, as this extraneous water will become included in the total water content. 2) Weigh the clean and dry retort cup and lid on the triple beam balance. 3) Add the mud, which has been allowed to cool to ambient temperature, to the retort cup, gently tap the cup to remove any air bubbles and place the lid with a rotational movement to obtain a proper fit. Be sure an excess of fluid flows out of the hole in the lid. 4) Carefully clean the cup and lid of excess fluid and reweigh on the triple beam balance. The retort mud weight SG is determined as the difference between the empty and full weights, in grams, divided by 50 (the volume of mud). 5) Pack the retort body with new steel wool, apply Never–Seez, to the threads and assemble top and bottom parts. Ensure that the two parts are fully screwed together. If it is not possible to fully screw together the two parts it will be necessary to clean the threads and repeat the above steps. Failure to get a good seal could result in leakage that will lead to an inaccurate result. 6) Attach the condenser and place the retort assembly in the heating jacket and close the insulating lid. 7) Place clean, dry liquid receiver below condenser outlet and turn on heating jacket. 8) The temperature control should be adjusted so that the retort cell glows dull red at the end of the distillation. Ultimately smoke will emerge from the retort and the distillation is only complete when the smoke stops.

calculations

SG of drilled solids (LGS) = 2.60 SG of Barite (HGS) = 4.25 SG of oil additive = SGo

Input Data

SG of mud in retort Retort % oil Retort % water Retort % solids

= = = =

Salinity mg/l

=

SG of Brine = Correction factor = Brine fraction = Corrected Solids =

SGm Of Wf Sf mls of 0.282NAgNO3 x 10,000 % Water ÷100 SGb (Look up Salinity in specific brine table) CF (From brine table) Bf (Correction factor x Wf) CS [Sf - Salt content (Bf - Wf)]

Then… Average SG of Solids (AVSG) % LGS % HGS lb/bbl LGS lb/bbl LGS kg/m3 LGS kg/m3 HGS

SGm x 100 - [(Of x SGo) + (Bf x SGb)] CS CS x (4.25 - AVSG) = 4.25 - 2.6 =

= CS x (4.25 - AVSG) 1.65 = = = = = = = = =

CS - % LGS %LGS x 3.5 x 2.6 %LGS x 9.1 %HGS x 3.5 x 4.25 %HGS x 14.87 %LGS x (9.1 x 6.2897) ÷ 2.205 %LGS x 25.96 %HGS x (14.87 x 6.2897) ÷ 2.205 %HGS x 42.42

interpretation The control of the low gravity solids content of a WBM system will trigger the use of centrifuges or dilutions. If mud costs were broken down and assigned to a particular reason then the control of LGS would probably account for the bulk of expenditure on most wells. For this reason very careful attention must be paid to the points outlined in the Discussion section above. This test is a reliable indication of the condition of a drilling fluid on a one off basis. The results of other tests may change, for example, with shear and temperature i.e. the rheology may increase, the API filter loss may decrease without any additions being made to the mud. The LGS content, however, is something that can be assessed, and tackled if required, without waiting for trends to be established from further tests. The calculations are extremely sensitive and a 0.5% difference in total solids content will have a large affect on the LGS fraction. For this reason it is important to be meticulous when taking the volumes of oil, water and solids.

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api filtrate discussion Filtration control is one of the primary characteristics of a drilling fluid and fulfils a variety of functions from the prevention of differential sticking to minimisation of formation damage. Filtrate control can be established at just about any level but the cost increases almost exponentially as tighter and tighter properties are required. A fit for purpose attitude must be adopted when programming fluid loss levels to avoid non-justifiable expense. No benefit may be gained, for example, from having a fluid loss of 3 ml as opposed to 5 ml but mud costs will have doubled. Further, over treatment with fluid loss polymers, especially PAC polymers, can have a detrimental effect on the rheology by reducing the mud’s shear thinning characteristics. The API test for WBM is carried out at ambient temperature and with only 100 psi (690 kPa) of differential pressure. This quite patently does not mirror downhole conditions. However experience has shown that this test is a reliable way of measuring the performance of a drilling fluid at any given moment. The results must be viewed in conjunction with the thickness of the filter cake that has been formed by the end of the test. A low solids polymer mud may have a relatively high fluid loss but the filter cake is almost non existent whereas a high solids mud may have a lower fluid loss but a much thicker filter cake.

equipment ƒ Filtration Cell ƒ OFI specially Hardened Filter paper - Filtration Area 7.07 sq.in (Alternatively - Whatman No 50 paper) ƒ Low Pressure CO2 supply 100 psi (690 kPa) (Soda stream cartridges) ƒ Stop Clock ƒ 10 and 25 ml measuring cylinders

procedure 1) Assemble the clean and dry components that form the cell of this piece of equipment. 2) Ensure the filter paper is Whatman no 50 (or equivalent) and make sure the screen is not damaged. A creased screen can result in weaknesses in the filter cake that seem to result in higher results than would normally be expected. 3) Pour the mud sample into the cell to 0.5” from the top, put the top in place and position it in the support frame. 4) Place a dry graduated cylinder of suitable size (usually 10 cc’s) under the drain tube and apply 100 psi of pressure over 15 seconds. 5) Maintain a constant 100 psi (690 kPa) throughout the test period. 6) After 7.5 mins measure and record the amount of filtrate collected to the nearest 0.1 ml. 7) After 30 mins measure and report the amount of filtrate collected to the nearest 0.1 ml. 8) Having bled off the pressure, dismantle the equipment and examine the filter cake. Report the thickness in 32nds of an inch (mm). Comments about the quality of the cake should be noted in the comments section of the mud report i.e. texture, colour, hardness, compressibility, flexibility etc. 10

calculations

API Fluid Loss = 30 min Reading * Relative API Fluid Loss = (30 min Reading - 7.5 min reading) x 2 Spurt Loss = API Fluid Loss - Relative API Fluid Loss * Relative API Fluid Loss is corrected for spurt loss prior to cake formation.

interpretation The API fluid loss may not give an accurate representation of what is happening under dynamic conditions at downhole temperatures and pressures. Dynamic lab testing has shown solids content to be the key influencing factor. Thus it could follow that a mud that has lower API fluid loss than another may have a much higher dynamic loss. However any change in fluid loss properties is a good indicator of general mud health. Having established the required control any increasing trend must be identified and treated as required. Fluid loss can also decrease without any chemical additives as solids content and particle size distribution optimises under drilling conditions. Generally speaking, therefore, an increasing trend is bad and a decreasing trend is good. The results must be viewed in conjunction with the thickness of the filter cake that has been formed by the end of the test. A low solids polymer mud may have a relatively high fluid loss but the filter cake is almost non existent whereas a high solids mud may have a lower fluid loss but a much thicker filter cake.

hthp filtration discussion The high pressure / high temperature filter press is a static filtration procedure recommended by the API 13B standard procedures for testing drilling fluids at elevated temperatures and pressures. This test tends to be run at temperatures that reflect expected bottom hole temperatures and thus there is no standardised temperature. However ensure the test temperature is noted on the mud report. These procedures are for temperatures up to 300 °F (148.9 °C). If higher test temperatures are required a porous stainless steel disc will need to be utilized instead of the normally used filter paper and higher top and bottom pressures applied. When heating, apply 100 psi (690 kPa) to top and bottom, increase top pressure to 600 psi (4138 kPa) for the test. The thermometer used must be calibrated against a mercury or alcohol type thermometer to confirm its accuracy. To adjust the thermometer, simply use a small spanner to turn the nut on the back of the dial so that the thermometer reads the same temperature as the mercury or alcohol thermometer. Remember the screen and bomb are a matched pair. The use of unmatched pieces of equipment may result in it being impossible to get a result as whole mud breaches the seals at some point during the test. This is indicated when the pressure gauge on the bottom pressure vessel suddenly goes off scale. 11

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Remember the screen and bomb are a matched pair. The use of unmatched pieces of equipment may result in it being impossible to get a result as whole mud breaches the seals at some point during the test. This is indicated when the pressure gauge on the bottom pressure vessel suddenly goes off scale. Continuing bypass problems could be the result of incorrect ‘O’ rings. Ensure they are of a rounded, rather than flat, profile

equipment ƒ ƒ ƒ ƒ ƒ

HTHP Filtration Cell OFI specially Hardened Filter paper High Pressure CO2 supply 600 psi (4138 kPa) Stop Clock 10 and 25 ml measuring cylinders

procedure 1) Turn on heated jacket at the mains and insert a thermometer into the jacket and leave to preheat to the desired temperature. 2) Check out all the “O” rings on the HPHT bomb and lid. Change out any damaged rings. The rings to be checked are the four small stem “O” rings, which tend to pick up cuts and grooves with time, and the two large “O” rings, one in the lid and one in the cell. The large “O” rings Example of HTHP should have a rounded profile and be free from Filter Press dirt. 3) With stem valve closed on bottom of cell, fill up cell with mud to within 0.5” of the ‘O’ ring groove, to allow for thermal expansion. 4) Insert filter paper into the cell followed by the bottom cell plate assembly over the filter paper and twist to align with the safety locking lugs. Ensure the lid stem is open while doing this to avoid damaging the filter paper. 5) Tighten the 6 grub screws evenly using the Allan key provided. 6) Ensure all stem valves are tightly closed. 7) Invert cell and place in filtration mounted heated jacket assembly. Rotate the bomb until it seats on the locking pin. Insert a thermometer into the HPHT cell. 8) Place a CO2 or N2 cartridge in each regulator and tighten up the retainers. 9) Place the pressure unit on top valve and lock into place using a locking pin. Lock the bottom pressure unit to the bottom valve into place, again ensuring that locking pin is inserted. 10) Apply 100 psi to both ends of the HPHT cell with the valves still closed. 11) Open the top valve by turning 1/4 to 1/2 anticlockwise to apply 100 psi to the mud while heating to prevent the mud from boiling prior to reaching the target temperature. The time for heating the mud sample to the target temperature should not exceed 60 minutes! 12) When the cell reaches the required test temperature open the bottom stem (1/2 turn) and then increase the pressure on the top regulator to 600 psi over +/- 20 seconds. 13) Commence the test. The test should be carried out as soon as the bomb reaches the test temperature. 14) If the pressure on the bottom regulator increases significantly above 100 psi bleed off some of the filtrate into the graduated cylinder.

12

Do not use nitrous oxide (N2O) as a pressure source for this test. N2O can detonate when under temperature and pressure in the presence of oil, grease, or carbonaceous materials. Use only carbon dioxide (CO2) or nitrogen (N2).

If the bottom pressure rises 20 psi above the specified pressure during the test, carefully bleed off pressure by draining a small volume of filtrate.

15) Collect the filtrate for 30 minutes maintaining the temperature to within +/- 5 °F (2.7 °C). 16) Once the test has finished close the top and bottom valves and shut off the pressure supply from the regulators. Bleed the lines using the relief valves provided. 17) Allow filtrate to cool for 30 minutes and then draw off into a graduated 20 ml measuring cylinder and read volume. SAVE the filtrate for ionic analysis. 18) CAUTION - the cell still contains 500 psi (3449 kPa) pressure, so cool cell to room temperature ideally in a water bath or alternative safe place and then bleed off the pressure slowly by opening the valves. 19) Disassemble the cell and discard mud into mud waste container only. Save filter paper handling with care and wash filter cake with a gentle stream of distilled water. 20) Measure and report the thickness of the cake to the nearest 1/32” (0.8 mm). Report any other observations, such as texture, colour, hardness, flexibility etc.

calculations The total filtrate volume should be doubled, as the standard API press is twice the area of the HPHT cell. Mud in the filtrate would indicate that the ‘O’ ring seals needed replacing as whole mud was bypassing the filter paper. Do not instigate mud treatments on the results of any test that has mud in the filtrate. Overhaul the equipment and repeat the test.

sand content discussion It is important to remember that this test is a measure of sand size particles, which can be of any rock type, or indeed sacked additives, as opposed to just sand. If finer than 200 mesh shaker screens are in use, an increase in sand size particles would be a clear indicator of screen damage requiring immediate attention.

equipment ƒ 2 1/2” inch diameter sieve (200 mesh, 74 micron), ƒ Plastic funnel to fit the sieve ƒ Glass measuring tube marked for the volume of mud to be added in order to read the percentage of sand directly in the bottom of the tube, which is graduated from 0 to 20%.

procedures 1) Fill the tube with mud to the mark labelled “Mud to Here”, and then add water to the mark “Base Fluid to Here”. Cover the mouth of the tube with the thumb and shake the tube vigorously. Example of Sand Content Kit

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2) Pour the suspension through the clean, dry mesh screen, being careful to remove all solids out of the tube by flushing with base fluid back through the same mesh screen. By tapping the side of the screen the pouring of the mud through the screen may be facilitated. 3) Wash the sand retained on the screen with water to remove any remaining mud 4) Fit the funnel upside down over the top of the sieve, invert slowly turning the tip of the funnel into the mouth of the tube and wash the sand back into the tube with some clean water. Allow the sand to settle. 5) Record the quantity of sand settled in the graduated tube as the sand “sized” content of the mud in percent by volume.

calculations Allow the sand to settle. From the graduations on the tube, read and report the percent by volume of sand size drilled solids (see interpretation below).

interpretation Some interpretation of the result will need to be made based on the differential settling speeds of the different materials present. The reported result should be that proportion of the settled particles that are attributable to drilled solids. These would be the particles that settle out first and are usually followed by calcium carbonates, other types of LCM and undissolved black powders. The differing particles aggregate, therefore, in clearly identifiable strata and, depending what was being added to the active system at any given time, the apparent sand content can appear much higher than it actually is. The sand content is not really of any significance with respect to overall mud properties but is of importance when it comes to wear on mud pump parts etc. 2% is normally accepted as the upper limit. Generally speaking the sand content is also useful to gauge the effectiveness of the shaker screen sizes being employed. If the sand content rises quickly then this is an indication that finer mesh screens need to be tried. A rapid increase in sand content over a short period can also indicate that the shaker screens are torn and need immediate replacing.

pH discussion Field measurement of drilling fluid (or filtrate) pH and adjustments to the pH are fundamental to controlling water-based drilling fluid properties. pH expresses acidity or alkalinity of an aqueous solution. An acid can be defined as a substance which dissociates in aqueous solution to give hydrogen [H+] ions, whilst a base or alkali gives [OH-] ions. The term “pH” denotes the negative logarithm of the hydrogen ion, [H+], activity in aqueous solutions (activity and concentration are equal only in dilute solutions). The pH of a water based mud is controlled to improve the performance of mud additives, to minimise pipe corrosion and to reduce the solubility of claystones. A balance is struck between these factors when choosing a pH for any particular system. 14

Generally speaking for low pH muds eg KCl / PHPA, 8.5 to 9.5 are the norm. At these levels: ƒ Sufficient alkalinity is maintained to control corrosion, i.e. the mud is not acidic. ƒ Polymer additives are not co-precipitated with other ions and hardness is minimised. ƒ The dispersive tendencies of claystones are minimised, thus helping to prevent solids problems. It is important to remember that pH is a logarithmic function and that it will take 10 times as much caustic soda (in pure water) to increase a pH from 10 to 11 as it will from 9 to 10. The recommended method for pH measurement is with a glass electrode pH meter. This method is accurate and reliable, being free of interferences if a high quality electrode system is used with a properly designed instrument. Rugged pH instruments are available that automatically temperature compensate the slope and are preferred over the manually adjusted instruments. For anything other than basic freshwater mud systems a pH meter should be used to measure pH. Note: Colour matching pH paper and strips are used for field measurements, but are not recommended as they are only reliable in very simple water base muds. Mud solids, dissolved salts and chemicals, and dark coloured liquids cause serious errors in pH paper values. Readability is normally about 0.5 pH units.

equipment ƒ pH Meter: Millivolt range potentiometer calibrated to show pH units for measuring the potential between a glass membrane electrode and a standard “reference” electrode. ƒ Electrode system: A combination system of a glass electrode for sensing [H+] ions and a standard voltage reference electrode (silver/silver chloride), constructed as a single electrode. ƒ Buffer solutions: Three solutions to calibrate and set the slope of the pH meter prior to sample measurement. ƒ pH = 4.0: potassium hydrogen phthalate at 0.05 molar in water. Gives 4.01 pH at 75 °F (23.9 °C). ƒ pH = 7.0: Potassium dihydrogen phosphate at 0.02066 molar and disodium hydrogen phosphate at 0.02934 molar in water, gives 7.00 pH at 75 °F (23.9 °C). ƒ pH = 10.0: Sodium carbonate at 0.025 molar and sodium bicarbonate at 0.025 molar in water, gives 10.01 pH at 75 °F (23.9 °C).

Only use fresh calibration fluids when calibrating the pH meter

Note: The shelf life of all buffers should not exceed six months before disposal. Date of preparation of the buffer should be shown on bottles used in the field. Bottles should be kept tightly stoppered. ƒ Distilled or deionised water: in spray bottle. ƒ Soft tissues: to blot electrodes. ƒ Thermometer: glass, 32-220 °F (0-104 °C).

15

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procedures – pH indicator strips 1) Place an indicator strip in mud and allow it to remain for one minute to allow the colour to stabilise. 2) Rinse the strip off with deionised water but do not wipe. 3) Compare the colours of the strip with the standard chart provided and estimate the pH to the nearest .5.

procedures – pH meter 1) The pH meter must be calibrated, as per the manufacturer’s instructions, on a regular basis (at least once a week, more frequently if meter usage is high. Buffer solutions used must be within their use by date. Do not re-cycle the buffer solutions used to calibrate the meter. Throw them away each time and use fresh samples of the buffer solutions every time the meter is calibrated. 2) For accurate pH measurements the test fluid, buffer solutions and reference electrode must all be at the same temperature i.e. ambient temperature. 3) Insert the electrode into the fluid contained in a small glass flask and swirl gently. 4) Measure the fluid pH according to the directions supplied with the instrument. When the meter reading becomes constant record the pH to the nearest 0.1 of a unit. 5) Thoroughly clean off electrode with distilled water and store it in accordance with manufacturer’s recommendations.

interpretation Trickle treatments of either sodium hydroxide or potassium hydroxide are usually made to maintain the pH in the optimum range of 8.5 to 9.5. A quick check with the pH meter will avoid a situation where pH increases above this range due to over treatment or drops too low due to under treatment. The usual tendency is for the pH to drop slowly as alkaline ions are neutralised by other naturally occurring ions. A rapid drop in pH can indicate such hazards as acid gas or CO2 influxes.

filtrate alkalinity – Pf and Mf discussion Alkalinity can be considered as the acid-neutralising power of a substance. Alkalinity measurements can be made on either the whole mud (designated with the subscript m) or on the filtrate (subscript f ). The data collected can also be used to estimate the concentrations of hydroxyl (OH-), carbonate (CO3--) and bicarbonate (HCO3-) ions in the drilling fluid. Pf and Mf refer to titrations performed on the mud filtrate (f ). The P refers to the indicator Phenolphthalein and thus Pf refers to the mls of 0.02N sulphuric acid required for the indicator colour change at a pH of 8.3. The M refers to the indicator Methyl Orange and the Mf is the mls of 0.02N sulphuric acid for the colour change that at occurs at a pH of 4.3. The Mf includes the acid taken to get to the Phenolphthalein end point and so will always be equal to, or greater than, the Pf.

16

In colourless filtrates the Pf is a distinctive end point from red pink to colourless. The Mf however is a very poor endpoint, orange to pink, much dependent on the eye of the beholder, and casts into doubt alkalinity calculations based upon it. Another indicator, Bromo Cresol Green, changes from blue to apple green and is a much easier end point to see. For historical reasons it is still referred to as the Mf. It is this indicator, Bromo Cresol Green that will be used to calculate Mf. The following table highlights the “rules of thumb” for conventional gel based mud systems.

Hydroxyl ions Hydroxyl + Carbonate Carbonate Carbonate + bicarbonate Bicarbonate

Mud stable and in good condition Stable and in good condition Unstable but can be controlled Stable but difficult to control Unstable and very difficult to control

Knowledge of the mud and filtrate alkalinity is essential to ensure proper control of mud chemistry. Mud additives, particularly some deflocculants, require an alkaline environment to function properly. The source and nature of the alkalinity is often as important as the fact that some alkalinity exists. Alkalinity arising from hydroxyl ions is generally accepted as being beneficial, while alkalinity resulting from carbonates and/or bicarbonates may have adverse effects on mud performance and stability.

equipment ƒ Sulphuric acid solution: standardised 0.02 Normal (N/50). ƒ Phenolphthalein indicator solution: 1 g dissolved in 60 ml ethyl or methyl alcohol made up to 100 ml with distilled water. ƒ Methyl Orange Indicator solution: 0.2 g dissolved in 100 ml distilled water. ƒ Bromo-phenol Blue (Bromo-cresol Green): 0.02 g in 100 ml distilled water (instead of methyl orange for dark filtrates). ƒ pH meter: optional, but is more accurate than indicator solution. ƒ Titration vessel: 100 - 150 ml. preferably white. ƒ Volumetric pipettes: 1 ml. ƒ Graduated pipettes: one 1 cc. and one 10 ml ƒ Hypodermic syringe: 2.5 ml. ƒ Distilled water free of carbon dioxide (by boiling) ƒ Stirring rod.

procedures 1) Measure one ml of filtrate into a clean and dry 50 ml glass beaker. 2) Dilute with 10 - 20 mls of distilled water. 3) Add 2 or three drops of Phenolphthalein indicator. If the sample turns pink, add 0.02N sulphuric acid drop by drop from a pipette while gently stirring with a small magnetic bead on a hot plate/stirrer until the pink colour just disappears. 4) If the sample is so coloured that the colour change of the indicator is masked, the endpoint is taken when the pH reaches 8.3, as measured with the glass electrode pH meter. 5) Report the Phenolphthalein alkalinity as the mls of acid required to reach the end point.

17

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6) To the same sample add 3 or 4 drops of Bromo Cresol Green. A blue colour will develop. 7) Add 0.02N sulphuric acid drop by drop from a pipette while gently swirling or mixing until the blue colour changes to apple green. 8) The Mf is the total amount of acid used for both titrations.

interpretation Historically great effort went into interpreting the relationship between Pf and Mf as a means of detecting some of the factors causing mud instability such as high gels or deteriorating fluid loss properties. Carbonates and Bicarbonates are usually responsible when analysis shows an increasing Mf. They can be incorporated due to: ƒ Over treatment with soda ash or bicarb to remove calcium or cement contamination. ƒ Carbon Dioxide dissolution due to formation gas, fluid mixing equipment etc ƒ Thermal degradation of organic materials such as polymers ƒ Contaminated Bentonite and Barite. It is true that carbonate and bicarbonate ions can have severe effects on conventional kinds of water base mud systems, particularly gel based ones. The inherent inaccuracy in the second end point determination makes accurate analysis very difficult. Other alkaline materials can also contribute to the overall alkalinity, further complicating interpretation. These include but are not exclusive to anions such as, borate, silicate, aluminate, sulphide and phosphate. If Carbonate or Bicarbonate contamination is suspected it must be confirmed and quantified by use of a Garret Gas Train. In most applications Pf should always be greater than zero, i.e. always have some pink colour, and the closer the Mf is to the Pf the better. Experience shows, however, that in low solids polymer muds an increasing Mf does not necessarily result in any affect at all on other key mud properties such as filtration and viscosity. The focus should, therefore, be on observing changes in fluid loss and rheology and if unwanted changes are occurring see if they are related to an increasing trend in Mf and treat accordingly.

filtrate hardness – Ca++ and Mg++ discussion The ions that contribute most significantly to hardness in water are Calcium and Magnesium. These ions are divalent and can act as bridging agents between ionic polymers by complexing with more than one charged group on the molecule. This bridging can reduce polymer solubility and hence adversely affect performance.

18

In a similar manner the divalent ions can bridge between two clay particles producing flocculation. When EDTA (sodium salt of ethylene-diaminetetracetic acid) is added to aqueous solutions containing calcium and/or magnesium, it combines to form a complex whose end-point is determined by a suitable indicator. EDTA-Na + Ca++ + Mg++ ----> EDTA- Ca + EDTA- Mg + Na+ Keeping the mud alkaline with trickle treatments of hydroxides will ensure no magnesium is present. The OH– ion will react with free magnesium to give an insoluble precipitate of magnesium hydroxide. Thus in a properly maintained system, where an excess of OH– ions exist, no free magnesium can exist and all hardness is due to calcium. If huge sources of Magnesium are encountered then it is pointless trying to keep adding hydroxides, as the increasing amounts of fine precipitates will eventually result in uncontrollable viscosity increases. In situations where hydroxide additions have no effect on pH and free magnesium is present the system must be run at neutral pH, as the lesser of evils.

equipment ƒ 0.02 N EDTA (0.01 M) (Versenate Solution) ƒ Ammonia Buffer* in dropper bottle ƒ 8N Potassium hydroxide buffer (KOH) ƒ Manver Indicator (solution or crystals) ƒ Calver II Indicator (crystals) ƒ Masking agent** : 1:1:2 mixture by volume of triethanolamine : tetraethylenepentamine : water ƒ Deionised water : free of carbon dioxide by boiling ƒ Graduated pipettes: one 1 ml, 2 ml and 5 ml ƒ Titration vessel : 100 - 150 ml preferably white ƒ Stirring rods * Ammonia buffer = 54 g Ammonium chloride and 400 ml Ammonium hydroxide (15 N) made up to 1000 ml with deionised water. ** 1 ml of Masking agent should be added if soluble iron is suspected to be present.

procedures – total hardness 1) This test measures the total hardness, calcium, magnesium and other metals (of no real significance for drilling fluids) precipitated by Versenate solution, of the mud filtrate. 2) To a clean and dry 50 ml glass beaker add 50 ml of distilled water and 2 ml of standard buffer solution. 3) Add 1 ml of Calmalgite / Manver indicator solution. 4) If a red colour develops, indicating the presence of calcium or magnesium, add Versenate solution (0.01M EDTA – 1 ml = 400 mg/l.) drop wise with a pipette until the colour first changes to a brilliant blue, while stirring with a small magnetic bead on a hot plate/stirrer. This would indicate your distilled water was contaminated or the titration vessel was not clean. Do not include this amount of versenate in calculations. 19

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5) Measure 1 ml of mud filtrate into the titration vessel and the red colour will reappear. 6) Add Versenate solution as before until the blue colour returns. The end point may appear as a purple brown if masking agents are present. However it is the clear colour change that is the end point.

calculations – total hardness Total Hardness in mg/l (expressed as calcium) = ml of versenate solution x 400

procedures – calcium 1) To a clean and dry 50 ml glass beaker add 1 ml of filtrate (the purity of the distilled water and your ability to clean a titration vessel will have been proved in the previous procedure) and add 50 ml of distilled water and 5 ml 8N KOH or NaOH. 2) The OH¯ ions will precipitate out any magnesium. 3) Add a satchel (or a pinch if loose powder is provided) of Calver II calcium indicator. This will produce a pink to a wine red coloration. 4) While stirring with a small magnetic bead on a hot plate/stirrer add standard Versenate solution (0.01M EDTA – 1 ml = 400 mg/l.) until the solution changes to clear blue.

calculations – calcium Calcium hardness in mg / lt. = ml of versenate x 400

calculations – magnesium Magnesium hardness in mg / lt. = (ml of versenate for total hardness test - ml of versenate for calcium test) x 0.243

Interpretation Keeping hardness levels under control improves the efficiency of water based mud systems. Remember, in a properly maintained alkaline system where excess OH– ions exist, free magnesium cannot exist and all hardness will be due to calcium.

The acceptable upper limit for hardness is pH dependent but in systems run at pH 8.5 to 9.5 the upper limit should be no more than 600 mg/l. Remember that elevated hardness levels may not impinge at all on mud properties such as filtration and viscosity but due to lowered efficiency levels you are spending more money to achieve the same results. Control calcium hardness with suitable treatments.

filtrate chlorides discussion This standard method (Mohr’s method) consists of titrating all chlorides present in the filtrate and expressing the result in terms of sodium chloride. This explains why in some cases, for example in the presence of calcium and magnesium chlorides, the result obtained (expressed in NaCl), can

20

give concentrations greater than the solubility of NaCl. The chlorides are precipitated in the form of silver chloride, in the presence of an indicator, potassium chromate. The reaction occurs in two steps: Cl- + AgNO3 → AgCl (white precipitate) + NO3CrO4-- + 2Ag+ → Ag2CrO4 (orange-red precipitate) The end point is detected with Potassium Chromate. The excess Ag+ ions present after all the Cl- ions have been removed from solution, react with chromate to form silver chromate, an orange-red precipitate. Since AgCl is less soluble than Ag2CrO4 the latter cannot form permanently in the mixture until the precipitation of AgCl has reduced the Cl- to a very small value. Note: This titration must be carried out in a neutral medium because; in an acid medium the silver chromate dissolves, and in an alkaline medium silver oxide or silver carbonate precipitate. In practice, as the filtrate is neutral or alkaline, it is first acidified with sulphuric or nitric acid, then neutralised with calcium carbonate. The addition of the nitric acid has the advantage of discolouring the filtrate (partially). Numerous papers have been generated explaining different ways of reporting salinity mg/l Cl-, ppm KCl etc. This has caused great confusion in the past where apparently wildly different figures were in fact conveying exactly the same salinity. It is essential that salinity be always reported as mg/l chlorides. Remember ppm is not the same as mg/l, (ppm x brine SG = mg/l)

equipment ƒ Silver nitrate solution: 4.7910 g/l (0.0282 N or equivalent to 0.001 g chloride ion/ml). Store in amber or opaque bottle. ƒ Potassium Chromate Indicator solution: 5 g/100 ml water. ƒ Sulphuric or nitric acid: standardised 0.02 N (N/50). ƒ Phenolphthalein indicator solution: 1 g/100 ml of 60% alcohol in water solution. ƒ Calcium Carbonate: precipitated, chemically pure grade. ƒ Distilled water: free of carbon dioxide by boiling. ƒ Graduated pipettes: one 1 ml and One 10-ml. ƒ Titration vessel: 100 - 150 ml preferably white. ƒ Stirring rod.

procedures 1) Ensure the filtrate sample pipette doesn’t have any crystallised salt on its tip. Measure one ml of filtrate into a clean and dry 50 ml glass beaker. 2) Dilute with 25 mls of distilled water. 3) Add three drops of Phenolphthalein indicator. If the sample turns pink, add 0.02N sulphuric acid drop by drop from a pipette while gently stirring with a small magnetic bead on a hot/plate stirrer until the pink colour just disappears.

21

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4) Add 10 drops of standard potassium chromate solution (5 gms in 100 mls of distilled water). A yellow colour develops. 5) Stir continuously while adding 0.0282 N or 0.282 N silver nitrate (depending on expected range – below 5000 mg/l use 0.0282 N and above use 0.282 N) on a drop by drop basis. 6) The end point is reached when a reddish tinge appears and persists for 30 seconds. Do not titrate to “brick red” as this is too far past the end point. 7) Note the amount of silver nitrate required to reach the end point.

calculations Report the chloride ion concentration of the filtrate in mg/l, calculated as follows: Chloride, (mg/l) =

1000 x (0.0282 N silver nitrate, ml) filtrate sample ml

Or when using 0.282 N silver nitrate Chloride, (mg/l) =

10000 x (0.282 N silver nitrate, ml) filtrate sample ml

To convert units: (Chloride, mg/l) ___ Chloride, (ppm) = Specific gravity of filtrate Salt (NaCl), mg/l = (1.65) x (Chloride, mg/l)

interpretation The Cl– ion does not deplete, so once a system has been established the concentration should remain constant. Any variation in established concentration could be indicative of a; fresh or salt-water flow, seawater or freshwater additions, planned or evaporite formations being drilled. Chloride level on its own is not a reliable indicator of the amount of active ion (potassium) present and so more emphasis should be placed on the specific test for that ion.

phpa content discussion PHPA (partially hydrolysed polyacrylamide) is a polymer specifically designed to provide encapsulation of claystone cuttings, thus preventing dispersion and facilitate solids removal on surface. Very high molecular weight, long chain anionic polymers are selected and the adsorption of these chains at numerous positively charged sites around the clay cutting results in a gelatinous coating which retards the movement of water into the clay and consequently slows the processes of hydration.

22

Further to this a viscous filtrate is produced which slows water penetration into the formation. The requirement for PHPA is dependent on the types of formations to be drilled and the ROP experienced. PHPA will be depleted constantly and once a new system has been circulated into the well and initial screening problems have passed the concentration should rapidly be increased to program requirements. As drilling continues it will be necessary to constantly add PHPA to maintain levels and hence optimise the inhibitive environment. Regular monitoring is required to ensure sufficient free polymer is available in the fluid achieve the expected results. The test involves connecting two Erlenmeyer flasks with a rubber tube. One flask contains the sample to be tested and the other a mixture of boric acid and methyl red indicator. At the end of the test the acid / indicator mix is titrated to determine the amount of PHPA that was in the sample. ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ

Hot plate magnetic stirrer 2 x 125 ml Erlenmeyer flasks Magnetic stirring bar Distilled water 2% by weight Boric acid solution Methyl red indicator 6 N Sodium Hydroxide solution 2 - 3 ft (0.6 - 0.9m) of Tygon tubing #6 rubber stopper with a 1/4” hole 0.02 N sulphuric acid solution Silicon defoamer (i.e. Dow-Corning 84, AFC-78) 2 x 1/4” OD glass tubing each 3 or 4 inches (7.5 - 10 cm) long

procedure 1) Attach the two glass tubes to the ends of the Tygon tubing and fit one of them into the rubber stopper so the end of the tube just fits flush with the bottom of the stopper. 2) It is important the glass tubing be flush with the bottom of the rubber stopper. If the glass tube protrudes below the stopper the caustic solution being distilled will collect around the exposed tube and be sucked up and over to the boric acid solution. This will lead to erroneous results. 3) To one flask add 25 ml of the Boric acid solution and 6 drops of methyl red indicator. The solution will turn a red / pink colour. 4) To the other flask add 50 mls of distilled water, 2 ml of silicone defoamer and 5 mls of whole mud. 5) If foaming is a problem, or the mud bumps over, more defoamer can be used for the next test. 6) Place the flask containing the mud on the hot plate/stirrer and begin stirring. 7) Add 3 mls of 6N sodium hydroxide solution and immediately fit the flask with the rubber stopper. 8) Submerse the other end of the tubing into the boric acid/methyl red solution and begin heating the mud sample. 9) Ensure the receiving flask is at a lower level than the one being heated to allow the distillate to run downhill.

If an ammonia odor is detected as the solution in the flask boils, immediately stop the test. An ammonia odor indicates leakage from the flask

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10) Heat for 60 minutes during which time approximately 20 to 25 ml of distillate should collect. 11) The temperature setting at which to distil should be so as not to cause boil over (which invalidates the test), but to give a gentle boil which causes distillate to condense at the top of the glass tubing. Hence the distillate isn’t boiled across but merely collects in the tubing and runs down to the boric acid solution. Do not try to adjust the temperature too much during heating as it can induce a pressure differential and suck back the distillate, invalidating the test. Experience will show what temperature setting on the hot plate is the most effective. Once this has been established simply set the hot plate to that setting and leave it for the duration of the test. 12) The boric acid solution should now be yellow. 13) Titrate the acid back to its original starting colour with the 0.02 N sulphuric acid solution and record the amount of acid used.

calculation The result will be read from a standard graph that has been prepared using a known concentration of the particular PHPA to be used. It is recommended to use powdered PHPA, as this is usually 100% active, whereas liquid PHPA usually has between 30 – 40% active constituent.

Example of PHPA concentration curve Example of PHPA Concentration Curve 2.5

PHPA (lb/bbl)

2.0

1.5

1.0

0.5

0.0 1

2

3

4

5

6

7

8

9

10

Millilitres of N50 Sulphuric Acid

interpretation This test will establish the rate at which PHPA is being depleted from the system and thus allow the treatment rate to be varied accordingly. Maintaining the correct level of PHPA will decrease overall mud expenditure by reducing the amount of dump and dilute treatments required to maintain key mud properties such as filtration and viscosity. As well as regularly doing this test it is essential to observe the cuttings at the shakers. The cuttings should have a glossy appearance and remain discrete when squeezed into a ball and then released. If this is not the case then, no matter what the test result indicates, the PHPA concentration should be increased.

24

potassium ion – direct reading potassium ion meter discussion Potassium chloride is added to water based muds as source of potassium ions. The potassium ions have a dehydrating effect on potentially swelling clays by exchanging with sodium ions on the active clay surfaces. While drilling reactive formations potassium ion levels can deplete while chloride levels remain constant. It is apparent therefore that the mud must be checked specifically for excess potassium. The actual level of potassium required to provide adequate fluid inhibition is dependent on the level of exchangeable ions in the formation clay and to a lesser extent on the make up water. A higher level is required in seawater based fluid in order to overcome the competitive effect of the sodium present in the seawater. For this reason it is better for KCl / polymer type muds to be freshwater based. An Orion PerpHecT Model 370 meter or similar is suitable for use offshore. This method is intended to be used for the analysis of filtrate samples only and NOT whole mud samples!!

procedure 1) Carefully assemble and condition the electrode as per manufacture’s instructions. 2) Calibrate the meter using known Potassium standards (ref manufacture’s instructions). These standards should span the expected Potassium concentration range to be measured. They should be prepared by diluting 0.1M Potassium Standard solution with distilled water. Use accurate glassware and pipettes for all measurements. Ensure they are all thoroughly clean and dry before use. It is recommended to check the meter’s calibration every couple of days and to make fresh calibration standards every well. 3) Take 1 ml of mud filtrate sample and dilute with distilled water to reduce the concentration to within the range of the calibration standards. Add manufacturers recommended amount of Potassium ISA to sample as this will ensure correct pH and reduce the effect of interfering ions. Ensure all glassware is thoroughly cleaned with distilled water and dried before use. It is important to realise that it is very easy to contaminate a test sample by dirty glassware. 4) Stir all standards and samples at a uniform rate during measurement. It is not recommended to use a magnetic stirrer as it may generate sufficient heat to change solution temperature. 5) Samples or standards should be measured at ambient room temperature for best results. 6) Always rinse electrode thoroughly with distilled water after use and store as per manufacturer’s instructions. Do not wipe or rub the electrode’s sensing membrane as you may contaminate and damage the surface.

calculations Direct reading Potassium ion meters return direct Potassium concentrations. Simply multiply the result by the dilution factor used on the filtrate sample to obtain the actual filtrate Potassium ion concentration. Formulae or charts can be used to convert the results into KCl % by wt, ppb or mg/l. etc. 25

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interpretation The test reveals the rate of potassium exchange by reactive clay surfaces. Again the test must be viewed in conjunction with the observed condition of the cuttings at the shakers. Soft and unconsolidated cuttings could indicate an increase in potassium level was required even though the test may indicate the programmed concentration was present.

potassium ion – sodium perchlorate method (steiger method) discussion As potassium ion – direct reading above The test is not as accurate as the specific ion meter but has proved useful for revealing trends and should be used where a meter is unavailable or out of service. The test involves precipitating potassium, centrifuging the precipitate formed and then comparing the volume with a pre prepared standard graph to determine amount present.

procedures 1) Prepare a standard curve for a range of known concentrations by ƒ Preparing standard solutions over the range of 1 to 8% KCl by adding the appropriate amount of standard potassium chloride solution (0.5 ml = 1%, the equivalent of 3.5 lb/bbl or 9.99 kg/m3) to centrifuge tubes and diluting to the 7cc mark with distilled water. ƒ Adding 3 cc’s of Sodium Perchlorate solution to each tube. ƒ Centrifuging for one minute at approximately 1800 revs. With the hand crank centrifuges normally provided offshore some practice will be required to ensure consistency from test to test. ƒ Plotting mls of precipitate against lb/bbl (kg/m3) of potassium chloride using rectangular graph paper. Obviously this procedure will only need to be done once at the commencement of drilling. Example of KCl Concentration Standard Curve Example of KCl Concentration Standard Curve 1.6

Millilitres of Precipitate

1.4 1.2 1 0.8 0.6 0.4 0.2 0 0

1

2

3

4

5

% KCl

26

6

7

8

9

2) Measure 7 mls of filtrate into the centrifuge tube. 3) Add 3 mls of Sodium Perchlorate solution. 4) Centrifuge for one minute at approximately 1800 revs. 5) Read the precipitate volume immediately.

calculations Determine the potassium chloride concentration by comparing to the, previously prepared, standard graph.

interpretation As potassium ion – direct reading above

mbt test discussion The cation exchange capacity (CEC) is a measure of the potential reactivity of the clay components of mud solids or shales. Clay minerals all exhibit ion exchange behaviour to some degree. Isomorphous substitution of various cations onto a clay surface depends on the number of available exchange sites per unit weight of solids, reported in lb/bbl bentonite equivalent or meq/100 g. Cation exchange capacities in clay minerals are not a very precise or fundamental quantity, as it varies significantly with pH. Some reported CEC’s are as follows; Vermiculites Smectites Illites Kaolinite

120 - 200 meq/100g 80 - 150 meq/100g 10 - 40 meq/100g 1 -10 meq/100g

80 % of all sedimentary rocks are shales, which are generally composed of varying proportions of these clay minerals. The CEC of shales can generally be classed as follows; Non-dispersive Moderate dispersion Dispersive Highly dispersive

0 - 10 meq/100g 10 - 20 meq/100g 20 - 30 meq/100g > 30meq/100g

Increasing MBT values indicate both an increases in solids content, (whether clay or no), and/ or a decreases in particle size distribution. Both of these conditions are undesirable as ultimately they lead to deterioration in mud properties and a consequent increase in mud costs. The test is one of the key triggers for dump and dilute treatments and so due care and attention must be given to the procedures and the interpretation of the results. An upper limit for MBT values will be given in the mud program and this reflects a level above which, experience has shown, the efficiency of the system is compromised.

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equipment ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ

Methylene Blue Solution ( 3.74 USP grade) 3% Hydrogen Peroxide 5 N Sulphuric Acid 125 ml Conical Flask 25 ml Graduated Measuring Cylinder Hot plate Stirring Rod Filter paper, Whatman No 4 2 x 5ml Syringes 0 ml Burette and clamp stand

procedures (mud solids) 1) 2) 3) 4) 5) 6) 7) 8) 9)

10)

Measure 2.0 mls of mud into the 125 ml conical flask. Add 15 ml of the 3 % hydrogen peroxide using a measuring cylinder. 1 ml of the 5 N Sulphuric acid using a clean syringe. Swirl mixture gently to ensure mud solids are completely dispersed within the mixture. Place conical flask on a hotplate and heat gently until simmering. Leave to simmer for about 10 minutes. Dilute to approximately 50 ml with distilled water and stir. Add 1ml increments of the methylene blue indicator via a burette and swirl the flask vigorously for 30 seconds. After each addition dip the end of the stirring rod into the solution and apply a drop to the filter paper. The end point is reached when the colour of the blue solids containing droplet migrates away from the nucleus to form a light blue/turquoise halo. Once you reach the end point it is important to keep stirring the mixture and dropping further solution onto the filter paper to ensure the end point is persistent and has actually been reached. Cation exchange is a time dependent process and the solution will go on reacting if all the sites have not been completely exchanged.

calculations Bentonite (equivalent) ppb = mls of methylene blue solution X 2.5

procedure (shale) 1) Dry shale at 220 ˚F (104 ˚C) in an oven for 16 hours. 2) Grind shale using a pestle and mortar 3) Weigh 0.57 g of powdered shale into the conical flask and repeat steps ii - xiii in the Mud Solids procedure above.

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calculation CEC (meq/100g) = mls of methylene blue solution x 1.95 This test, in association with the solids content, tells us something about the type, size and therefore the active surface areas of solids in the mud.

interpretation The result of this test could be the trigger for dump and dilute treatments depending on the activity of the formations being drilled. However in formations of low activity the low gravity solids content may reach undesirable levels before the MBT reaches the programmed upper limit. In this case the LGS content becomes the trigger point. In cases where the LGS content remains low but the MBT reaches trigger point whole mud dilution is the only solution – there is either a build up of highly active clay or, more likely, a problem with ultrafines / colloidal material.

glycol – cloud point and % by vol concentration discussion TAME (thermally activated micro emulsions) polyols are used primarily to stabilise reactive clays and to minimise pressure transmission through tectonically stressed shales. In order to optimise the benefits of the clouding point mechanism of TAME polyols, it is necessary to engineer the cloud point. For optimum performance from cloud point polyols, the cloud point should be maintained close to, or slightly lower than the BHCT (bottom hole circulating temperature). Generally TAME polyols are effective at concentrations of 2 – 3% by volume of the aqueous phase Note: the percentage volume of polyol is always expressed as a percentage of the aqueous phase and not of the whole mud. Depletion of the polyol concentration while drilling is usually very low. Consequently, the key to maintaining an adequate concentration in the active mud system is to ensure that all new mud added to the active system contains 3% by vol and any direct water additions, intentional or unintentional, are compensated for by appropriate additions of glycol.

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equipment ƒ Hot plate ƒ 10 ml measuring cylinder ƒ Thermometer – Mercury or Alcohol

procedure – cloud point 1) Collect at least 3 ml of filtrate in a 10 ml glass cylinder. 2) Put the 10 ml glass cylinder in a conical flask of water. 3) Heat up slowly on a hot plate. 4) Using either a mercury or alcohol thermometer take the temperature of the filtrate as soon as it starts to become cloudy. This temperature is called the cloud point.

calculations Knowing the cloud point and the KCl concentration, derived from either the potassium ion – direct reading or potassium ion – sodium perchlorate, the polyol concentration can be obtained from empirically derived charts showing polyol concentrations as a consequence of KCl concentration versus cloud point temperature. Where a blend of different cloud point polyols are being used, it is not possible to determine the polyol concentration by the above method. In these situations it is necessary to track the concentrations by the material balance method.

interpretation By increasing the concentration of either the KCl and/or the polyol the cloud point can be lowered. Conversely by decreasing the concentration of either the cloud point can be raised. By utilising this the cloud point can be engineered for downhole temperatures in order to achieve optimum stability when drilling reactive claystones or stressed shales. Reliable BHCT can be obtained from the downhole measure while drilling tools (eg. MWD or FEWD). The cloud point, BHCT and polyol % by vol should be recorded on the daily mud report as part of each full mud check.

garrett gas train - sulphides discussion The presence of hydrogen sulphide in a drilling fluid can be lethal to personnel as well as being damaging to equipment and mud properties. Hydrogen sulphide will dissolve in the fluid and remain in solution until saturation point has been reached when it will break out. It is very important to know if H2S is entering the fluid and it is obviously advantageous to detect it before it is picked up by gas detectors, after having broken out on surface.

30

The presence of hydrogen sulphide in the mud manifests itself in two ways as it goes into solution. Firstly there will be a rapid drop in the pH as hydrogen ions are neutralised. Secondly soluble sulphides will appear in the mud. Measuring the latter of these two will provide conclusive evidence of hydrogen sulphide in the mud. Active soluble sulphides can be analysed and monitored because of their characteristic reaction with acid that involves the release of H2S gas. The test is performed on mud filtrate.

equipment ƒ Garrett Gas Train: consisting of a transparent plastic gas train, an inert gas supply (CO2N2 or N2O) with pressure regulator, a floating ball flowmeter and a Dräger tube. ƒ Flexible tubing.

Syringe to inject Acid and Aktaflo E

Dispersion Tube

Dräger Tube

Injection Tube Rubber Bung

Gas Supply

Exhaust

Exhaust 1

2

3

Flowmeter Porous China Membrane

Magnetic Stirrer Pellet

Magnetic Stirrer

Mud

ƒ Low and high range Dräger analysis tubes, the first marked `H2S 100/a´- CH 29101 and the second `H2S 0.2%/A´ - CH 28101. Ensure the Dräger tubes to be used are within their use by date. ƒ Dräger Multigas Detector Hand Operated Vacuum Pump, Model 31. ƒ Stopcock: (2-way bore): 8 mm glass with Teflon plug. ƒ Sulphuric Acid: 5N, reagent grade. ƒ Hypodermic syringes: one 10 cc. (for acid), and one each 10 cc, 2.5 cc and 1.0 cc (for sample). ƒ Hypodermic needles: two 1.5 inch (38 mm) with 21 gauge needles. ƒ Octanol defoamer in a dropper bottle. ƒ Inert Carrier Gas: Nitrogen (N2) bottle with low pressure regulator (preferred), or Nitrous oxide (N20) cartridges. ƒ Deionised water.

Ensure Dräger tubes are within their “use by date

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procedure 1) With the regulator backed off install and puncture a CO2 cartridge in the carrier gas assembly. 2) Add 20 ml of distilled water to chamber one. 3) Add 5 drops of Octanol to chamber one. 4) Add the required volume of mud filtrate into chamber 1 as determined by which Dräger tube is to be employed and an estimate of the sulphide range. Sulphide Sample Dräger Range Volume Tube (mg/l) 1.5 - 30 10.0 ml H2S 100/a 3 - 60 5.0 ml “ 60 - 120 2.5 ml “ 60 - 1020 10.0 ml H2S 0.2%/a 120 - 2040 5.0 ml “ 240 - 4080 2.5 ml “

Factor Tube

12 12 12 600 600 600

5) Select a Dräger tube for the estimated range as per the table above and break the tip from each end. 6) Install the tube with the arrow pointed down in the receptacle bored in the corner of the train. Be sure the “O”-ring seals. 7) Install the clean, dry flow meter tube with the word TOP upward. Be sure the “O”-ring seals. 8) Install the top on the gas train and hand tighten all screws evenly to seal. 9) Attach the flexible tubing to the dispersion tube and to the Dräger tube. Use only latex or flexible, inert plastic tubing. Do not clamp the flexible – it does not require it and will provide pressure relief in the event of over pressurisation. 10) Adjust the dispersion tube to 0.5 cm from bottom. 11) Put 10 ml of 5N Sulphuric acid into the hypodermic syringe. 12) Gently flow CO2 for 15 seconds to purge the system, checking for leaks. Stop the flow. 13) Slowly inject the 10 ml of acid into chamber one through the rubber septum. 14) Restart the carrier gas flow and adjust the flow so that the ball is between the red lines. (200 to 400 cm3 per minute – one CO2 cartridge should provide between 15 and 20 minutes of flow at this rate). 15) Continue flowing for a minimum of 15 minutes.

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16) Observe changes in the appearance of the Dräger tube and record the maximum darkened length, in units marked on the tube, before the front starts to smear. ƒ Any soluble sulphites in the fluid will, upon the addition of acid, convert to sulphur dioxide (SO2) gas that can interfere with test results. ƒ In the low range tube this manifests itself as diffusion at the front of the sulphide stain. The stain itself may be of a lighter colour than when SO2 is not present and a lower reading may be attained. ƒ It is important to note that while SO2 can produce a negative error it does not falsely indicate a positive H2S reading. ƒ In the high range tube an orange colour may appear ahead of the black front if sulphites are present in the sample. The orange section should be ignored when darkened length is recorded.

calculations Using the sample volume, the Dräger tubes maximum darkened length and the tube factor the sulphides present are calculated as: Sulfides mg/l =

darkened length x tube factor sample volume ml

For the higher range tube it may be necessary to correct the tube factor. The tube factor is based on a batch factor (stencilled on the box) of 0.40. If a different batch factor is stencilled on the box a corrected tube factor should be calculated as follows: Corrected tube factor = 600 x actual batch factor 0.40

interpretation Any indication of soluble sulphides in the mud would indicate the presence of H2S gas. With water based muds it is vital to remember that H2S can be a by-product of degrading drilling fluid additives. Make sure biodegradation is eliminated as a source of H2S before starting treatment programs. It may be the case however that the presence is due to the release of gas from the pore spaces of the rock actually being drilled. In this case ensuring proper overbalance and maintaining alkalinity is sufficient to control any hazard. This is not suitable for dealing with influxes, as the alkaline neutralisation of H2S is instantly reversible by reductions in pH. In these cases a scavenger, such as zinc oxide, should be added to convert soluble sulphides into an insoluble precipitate, thus removing them permanently from the equation. Where H2S is expected it is advisable to pre-treat with a scavenger. However with a scavenger in the system no indications of H2S will be picked up, by conventional means, until the scavenger has been used up. Thus while a scavenger increases safety levels it makes detection of small amounts of H2S very difficult indeed.

33

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garrett gas train - carbonates discussion This method of quantifying the amount of soluble carbonate, bicarbonates and carbon dioxide in the mud filtrate is far more accurate than the P f :M f relationship. Carbonate or bicarbonate contamination usually occurs as a result of CO2 influxes or over treatment with soda ash or sodium bicarbonate when treating out cement contamination. They can also result as a consequence of thermal degradation of organic compounds such as lignosulphonates and lignites at temperatures >300 °F (148.9 °C). The final source of carbonates can be contaminated Barite. The test is based on converting all bicarbonates and carbonates to CO2, which is then evolved by bubbling an inert carrier gas through the sample. The gas stream is collected and subsequently drawn through a Dräger tube at a fixed rate. The amount of total soluble carbonates is then calculated based on the length of the purple stain in the Dräger tube. The test is performed on mud filtrate.

equipment ƒ Garrett Gas Train: consisting of a transparent plastic gas train, an inert gas supply (N2 or N2O) with pressure regulator, a floating ball flowmeter and a Dräger tube. Garret Gas Train Setup for Measuring Carbonates ƒ Flexible tubing: Type inert to carbon dioxide. ƒ Dräger CO2 Analysis Tube: marked CO2 0.01 %/a - (No. CH-308-01). ƒ Dräger One litre Alcotest Gas Bag: (No 7626425). ƒ Dräger Multigas Detector Hand Operated Vacuum Pump, Model 31. ƒ Stopcock: (2-way bore): 8 mm glass with Teflon plug. ƒ Sulphuric Acid: 5N, reagent grade. ƒ Hypodermic syringes: one 10 cc. (for acid), and one each 10 cc, 2.5 cc and 1.0 cc (for sample). ƒ Hypodermic needles: two 1.5 inch (38 mm) with 21 gauge needles. ƒ Octanol defoamer in a dropper bottle. ƒ Inert Carrier Gas: Nitrogen (N2) bottle with low pressure regulator (preferred), or Nitrous oxide (N20) cartridges. ƒ Deionised water. Note: Nitrogen is preferred over nitrous oxide as the carrier gas. Because nitrous oxide cools upon expansion and chills the diaphragm in the regulator, prolonged flow will cause the regulator to perform erratically.

procedure 1) Be sure the GGT is clean, dry and on a level surface, with top removed. 2) Check bag and pump for leaks. To check the pump, insert a sealed Dräger tube into the pump opening and depress bellows. It will remain depressed if pump does not leak.

34

Ensure Dräger tubes are within their “use by date”

3) Add 20 ml of deionised water to chamber one. 4) Add 5 drops of Octanol to chamber one. 5) Install the top on the gas train and hand tighten evenly to seal all Orings. 6) Adjust the dispersion tube to approx 1/4” (5 mm) off bottom. 7) With regulator backed off, connect carrier gas supply to glass dispersion tube of Chamber one using flexible tubing. 8) Flow carrier gas through train for one minute to purge air from the system. Check for leaks in gas train unit. 9) With bag fully deflated install flexible tubing from stopcock bag onto the outlet of chamber three. 10) Inject a measured volume of filtrate into chamber one through septum with hypodermic syringe and needle. See table Carbonate Sample Dräger Range Volume Tube (mg/l) 25 - 750 10.0 ml CO2 100/a 50 - 1500 5.0 ml “ 250 - 7500 2.5 ml “

Factor Tube

2.5 2.5 2.5

Note: For best Dräger tube accuracy, the stain length should fill more than half the tube length, therefore sample volume must be carefully selected. 11) Slowly inject 10 ml sulphuric acid solution into chamber one through rubber septum using a clean syringe and needle. Gently shake the gas train to mix acid with sample in chamber one. 12) Open the stopcock on the gas bag. Restart gas flow and allow gas bag to fill steadily during a 10 minute interval. When bag is firm to touch (do not burst it!), shut off flow and close the stopcock. 13) Break the tip off each end of the Dräger tube. 14) Remove the tubing from chamber three outlet and reinstall it onto the upstream end of the Dräger tube. Attach Dräger hand pump to downstream end of Dräger tube. 15) Open the stopcock on the bag. With steady hand pressure, fully depress the hand pump. Release pump so that gas flows out of the bag and through the Dräger tube. Ten strokes should empty the bag. More than ten strokes indicates leakage occurred and your results will not be accurate. 16) Record the stain length in units marked on the Dräger tube (include the faint blue tinge in the purple stain length reading). 17) To clean the GGT, remove the flexible tubing and remove the top. Wash out the chambers with warm water and mild detergent using a brush. Use a pipe cleaner to clean the passages between chambers. Wash and rinse the unit with deionised water and allow to drain dry. Be sure to periodically replace the disposal gas bag to avoid leaks and contamination in the bag (bag replacement is suggested after 10 analyses).

35

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3a


calculations Using the sample volume, the Dräger tube’s stain length and the tube factor the total soluble carbonates (CO2 + CO3– – + HCO3– ) present are calculated as follows: stainlength x tube factor Carbonate mg/l = sample volume ml Reaction Amounts: Lime: 0.00043 lb (.00123 kg/m3) treats 1.0 mg/l CO3– – 0.00021 lb (.0006 kg/m3) treats 1.0 mg/l HCO3–

interpretation Excessive amounts of carbonates or bicarbonates can cause severe rheology problems, particularly high and progressive gel strengths, and filtration control problems. Typically these effects are worse in high solids muds in high temperature applications. The symptoms are very similar to a build up of very fine reactive solids. Care must be taken not to confuse the two very different problems, as their solutions are completely different. The acceptable concentration of carbonates will always depend on the concentration of solids, temperature and chemical concentrations. Generally a range of 1200 - 2400 mg/l is tolerated by most mud systems. It is recommended that not all the carbonates be treated out. A minimum of 1000 - 1200 mg/l should be allowed to remain in the system. The presence of carbon dioxide manifests itself in three ways as it goes into solution. Firstly there will be a rapid drop in the pH. Secondly the ratio between Pf and Mf will increase. Thirdly, depending on the pH, the Ca++ mg/l might drop. However, the presence of calcium in the filtrate, as detected in the Hardness titration does not eliminate the possibility of a carbonate problem. Always pilot test the proposed solution before treating the active system for carbonates. The basic treatment for carbonate contamination is to precipitate the carbonate with the calcium ion derived from Lime. However, the addition of calcium will have no effect on bicarbonates. These first must be converted to carbonates by addition of OH- ions. This is achieved by additions of Lime. Bicarbonates cannot exist in the presence of hydroxyls. Under normal conditions bicarbonates convert to carbonates at a pH above 9.5 Lime is slow to go into solution in most mud systems. This can be accelerated by adding Lime, mixed in water, via a chemical barrel. If necessary, Citric Acid can be added to limit the pH increase from Lime. However, don’t prevent the bicarbonates from converting to carbonates by lowering the pH too much, i.e. <9.5. If PHPA is a component of the mud system the higher pH necessary to treat out carbonate contamination will have an adverse effect on it. Fresh additions of PHPA should be made to compensate once the contamination has been treated out, the pH reduced to <9.5 and there is no chance of further carbonate contamination.

36

silicate testing the titration method The procedure describes a method as per SPE 35059 to determine silicate concentration in the drilling fluid. The procedure will also evaluate the alkalinity (sodium content). Silicates have an affinity with glass so the test may be carried out using plastic titration dish. In case only glass beakers etc are available they need to be washed very thoroughly after every test.

equipment ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ

pH Meter with calomel electrode Balance, accurate to 0.1g Stirrer c/w small stir bar Pipettes, 5 ml and 2 ml Plastic titrating dish De-ionised Water Hydrochloric Acid, 0.2N Hydrochloric Acid, 2.0N Methyl Red Indicator Solution Sodium Fluoride, reagent grade pH buffers, pH 4 and 10

procedure blank titration A blank titration is first performed to compensate for Silica present in the reagents. 1) Take 5 ml de-ionized water into the plastic titration dish and add 1 drop of methyl red. 2) Add 0.2N hydrochloric acid until the colour first changes to pink. 3) Add 1g Sodium Fluoride. Stir the mixture. The colour changes to yellow. 4) Titrate with 2.0N Hydrochloric Acid to a pink colour change, at pH 6.0. 5) Record the amount of acid used -. A. alkalinity (sodium content) 1) pH meter should be calibrated. 2) Take 5 ml of de-ionised water into a plastic titrating dish and add 1 drop of methyl red indicator. 3) Set the beaker on a stirrer, and insert the pH electrode. The indicator solution is used as a guide, but accurate measurements are against the pH value. 4) Add a few drops of 0.2N Hydrochloric Acid, until the colour is pink. 5) Pipette 2 ml of filtrate into this beaker. The colour changes to yellow. 6) Titrate with 0.2N Hydrochloric Acid to pH 5.5, or when the colour will change to pink note the volume of acid used (B).

silica (SiO2) content 1) Weigh 1 gm of Sodium Fluoride and add to the above titrated sample. The colour will change to yellow, and the pH will rise to 8 - 9. 2) Titrate with 2.0N Hydrochloric Acid to pH 6.0, and record the volume of acid used (C).

37

Section

3a


calculation alkalinity For a 2 ml sample: Na2O= 31,000 x A x N (mg/L) V K2O=

47,000 x A x N (mg/L) V

Where: A is ml of acid to first colour change N is acid normality (0.2 N) V is ml of filtrate sample silica (SiO2) For a 2 ml sample ppm(mg/I)SiO2= 15000 x N x (C-A) 2 (samplevol) g/I SiO2=

SiO2= 15000 x N x (C-A) (mg/L) V

15 x N x (C-A) 2 (samplevol)

Where: “C” is the volume of 2.0N Hydrochloric Acid used in the titration, “A” is the volume of acid used in the blank correction (typically <0.1 ml), “N” is the normality of the acid (2N). To convert g/l SiO2 to % vol/vol Silicate in system % vol Silicate = g/l SiO2 x 0.2237 Where the S.G. of Silicate is 1.475, with a SiO2 activity of 30.3% wt.

38

section 3b naf testing procedures

section 3b

Scomi Oiltools

mud density

2

funnel viscosity

4

rheology

4

hthp filtrate – temperatures up to 300 °F (148.9 °C)

7

retort analysis – oil base mud

11

sand content

12

electrical stability

13

lime content

14

water phase salinity

15

garrett gas train - sulfides

17

oil on cuttings measurements

20

Section

3b

naf testing procedures


mud density discussion The Mud Balance is used for mud weight determinations and is the recommended equipment in the API 13B standard procedures for testing drilling fluids. The mud balance is accurate to within +/- 0,1 lb/gal ( or 0.5 lb/ ft3, 0.01 g/ml , 10 g/l). It is designed such that the mud cup, at one end of the beam, is balanced by a fixed counterweight at the other end, with a sliding weight rider free to move along the graduated scale. A level bubble is mounted on the beam to allow accurate balancing. This, most basic, of mud properties is often reported incorrectly due to the use of an inaccurately calibrated mud balance. The time to check the balance is not when a well control situation develops but on a routine daily basis. The mud test kit will contain both standard mud balances and a pressurised Halliburton mud balance. Both types are calibrated by weighing distilled water at 70 °F (21.1 °C) and obtaining a reading of 1.00 SG / 8.33 lb/gal. If this is not the case adjust the balance by adding or removing lead shot as required. Experience has shown that, under normal drilling conditions, the standard balance gives the same reading as the pressurised balance. For ease of use, therefore, the standard balance may be routinely used to measure mud density. At the first indication of gas or air entrapment in the mud only the pressurised balance should be used. On a tourly basis the pressurised balance will be used to confirm it is reading the same as the standard balance.

equipment ƒ Standard Mud Balance ƒ Pressurised Mud Balance

procedure – standard balance 1) Instrument base must be set on a flat level surface. 2) Measure and record the mud temperature. 3) Fill the mud cup with the mud to be tested. Gently tap the cup to encourage any entrapped gas to breakout. 4) Replace cap and rotate until it is firmly seated, ensuring some of the mud is expelled through the Example of standard mud balance hole on top, to free any trapped gas.

Have you checked the mud balance lately?

5) Holding cap firmly (with cap hole covered with thumb) wipe the outside of the cup until it is clean and dry. 6) Place the beam on the base support and balance it by using the rider along the graduated scale. Balance is achieved when the bubble is directly under the centre line.

procedure – pressurised balance A problem with many drilling fluids is that they contain considerable amounts of entrained gas, leading to inaccurate mud weight measurements on the standard mud balance. By pressurising the mud cup the entrained air volume can be decreased to a minimum. The balance operates in much the same way as standard mud balance except the lid of the mud cup has a check valve. 1) Follow steps 1 - 5 as for the standard mud balance procedure. 2) Place the lid has been placed on the cup, with the check valve in the open position, wipe the outside of the cup clean and dry. 3) The pressurising plunger is similar to operating a syringe. The plunger is filled by submersing the nose of the plunger in the drilling fluid with the piston rod in the completely inward position. The piston rod is then drawn up, thereby filling the plunger with fluid. 4) The nose of the plunger is then placed into the female ‘O’ ring on top of the cap. The sample is pressurised by maintaining a downward force on the cylinder housing in order to hold the check valve open, whilst at the same time forcing the piston rod inwards. Approximately 50 pounds of force or greater should be maintained on the piston rod. 5) The check valve in the lid is pressure actuated, i.e. closing as a pressure is applied. The valve is therefore closed by gradually easing up on the cylinder housing while maintaining pressure on the piston rod. 6) Having applied pressure to the sample with the pump there should be no indication of fluid leaking back through the nipple. It should not be possible to depress the nipple by hand – if the nipple can be easily depressed it is a sign that pressure is not being held and a true weight is not being obtained. Change the ‘O’ ring and repeat the test. 7) Once the check valve is closed, disconnect the plunger and weigh the fluid as in step 6 of the standard mud balance procedure.

interpretation The density of an OBM will vary according to the temperature of the sample. Differences of up to 0.03 SG are normal between ambient and flowline temperatures of 65 °C. Mud weights noted on the mud report will refer to both the density at the flow line temperature and the density at ambient temperature when the sample has cooled. For density control purposes the mud weight will always relate to what is being measured at flowline temperatures as this is the best indicator of what is actually in the hole at any particular time.

Section

3b


funnel viscosity discussion The Marsh Funnel Viscometer is used for routine viscosity measurements. The results obtained are greatly influenced by rate of gelation and density. The latter varies the hydrostatic head of the column of mud in the funnel. Because of these variations, the viscosities obtained cannot be correlated directly with those obtained using the rotational viscometers, and therefore can ONLY be used as an indicator of mud stability, or relative changes to mud properties. The funnel viscosity will be measured in seconds per quart. The funnel must be calibrated on a regular basis. The viscosity of fresh water at 70 °F (21.1 °C) is 26 sec/qt (27.6 sec/l) and any reading above this would indicate that the spout of the funnel required cleaning. The diameter of the spout is 3/16” and a hand held drill bit of this diameter should be used to clear any deposits/cake.

equipment ƒ ƒ ƒ ƒ

Marsh funnel Graduated cup: one quart / litre Stopwatch Thermometer: 32 – 220 °F (0 – 104 °C)

procedures 1) Cover the orifice with a finger and pour a freshly agitated fluid sample through the screen into the clean, dry and upright funnel until the liquid level reaches the bottom of the screen. 2) Quickly remove the finger and measure the time required for the fluid to fill the receiving vessel to the one quart (946 ml). 3) Report the result to the nearest second as Marsh Funnel viscosity and the temperature to the nearest degree.

interpretation The funnel viscosity is of little significance in relation to SBM. This is due to the fact that SBM thin with heat and the result is therefore very temperature dependent. However, if temperature remains constant, the funnel viscosity may indicate trends that require further investigation.

rheology discussion The rheology will be determined using a Motor Driven Fann 6 speed Viscometer. Ensure that the Viscometer motor runs at the same electrical cycles (either 50 hertz or 60 hertz) as the rig power, otherwise erroneous readings will be obtained. Offshore rigs usually operate on 60 hertz. All Viscometers sent to the rig site must have been recently calibrated and carry a label noting the date of the last calibration.

Drilling fluid is contained in the annular space between two concentric cylinders. The outer cylinder or rotor sleeve is driven at a constant rotational velocity. The rotation of the rotor sleeve in the fluid produces a torque on the inner cylinder or bob, and the dial attached to the bob indicates displacement of the bob. This is the standard procedure recommended by API 13B for field testing oil based drilling fluids. Instrument constants have been adjusted so that the Bingham plastic viscosity and yield point can be obtained by using the readings at 300 rpm and 600 rpm. The six readings will be taken at 120 °F (48.9 °C). A heated cup will be used for this purpose. Synthetic Base Muds exhibit thinning tendencies with temperature and so it is still necessary to standardise this test by taking the readings at the same temperature on each occasion. The thermometer used must be calibrated against a mercury or alcohol type thermometer to confirm its accuracy. To adjust the thermometer, simply use a small spanner to turn the nut on the back of the dial so that the thermometer reads the same temperature as the mercury or alcohol thermometer.

When checking oil base mud systems it is recommended to insert the thermometer in the actual fluid to ensure the correct testing temperature has been reached

The rheometer readings may be taken at a higher temperature, to reflect flow line temperatures, if required. However, to avoid confusion and to allow comparisons between wells, only the 120 °F (48.9 °C) readings will be entered in the mud check columns on the mud report. Readings taken at higher temperatures can be noted in the comment section. Note: Maximum operating temperature is 200 ˚F (93 ˚C). If fluids above 200 ˚F (93 ˚C) are to be tested, a solid metal bob or a hollow metal bob, with completely dry interior, should be used. Liquid trapped inside a hollow bob may vaporise when immersed in high temperature fluid and cause the bob to explode. The gelling characteristics of the fluid can be determined from taking a 10 second and a 10 minute gel reading. Consequently there is no requirement to take a 30 minute gel under normal circumstances. However if increasing rheology is becoming a problem a 30 min gel should also be taken in order to determine the effectiveness of the treatment program.

equipment ƒ Fann 35, 110 volt or 120 volt, powered by a two speed synchronous motor to obtain speeds of 3, 6, 100, 200, 300 and 600. ƒ Mud cup ƒ Stopwatch ƒ Thermometer 0 – 104 °C

procedures 1) Stir the sample at 600 rpm while the sample is heating, or cooling, to 120 °F (48.9 °C). Ensure the dial Example of 6 Speed reading has stabilised at this speed before noting Rheometer the result and proceeding to the 300, 200, 100, 6 and 3 RPM speeds.

Section

3b


2) Having taken the 3-RPM reading stir the sample at 600 RPM for 30 secs before taking the 10-second gel at 3 rpm. 3) Restir the sample at 600 rpm for 30 seconds and leave undisturbed for 10 minutes, ensuring the temperature stays at 120 °F (48.9 °C). Take the 10 minute gel reading at 3 rpm.

calculations Apparent Viscosity (AV) in Centipoise (cps) Plastic Viscosity (PV) in Centipoise (cps) Yield Point (YP): Yield Point (YP) in lb/100 ft2 Yield Point (YP) in Pa

= 600 reading ÷ 2 = 600 reading - 300 reading

= 300 reading – PV = (300 reading – PV) x 0.48

Power Law Index (n) = 3.32 log (600 reading / 300 reading) Consistency Index (K): n Consistency Index (K) in Ib/ 100 ft2 = 600 reading / 1022 n Consistency Index (K) in Pa = (600 reading / 1022 ) x 0.48 Gels: Gels in lb/ 100 ft2 = As per 10 sec & 10 min reading Gels in Pa = (As per 10 sec & 10 min reading) x 0.48 Note: If the 600 rpm reading is off scale then the PV and YP can be calculated as follows; YP in lb/100 ft2 = (2 X 100 rpm reading) – 200 rpm reading YP in Pa = [(2 X 100 rpm reading) – 200 rpm reading] x 0.48 PV

= 300 rpm - YP

PV (S.I units)

=

300 rpm reading – YP 0.48

interpretation The main focus of attention, with regards to mud rheology, is the 6 rpm reading.

Mud programs will specify a range for the 6 rpm reading and so the other indicators of rheological properties, i.e. yield point, apparent viscosity, plastic viscosity and initial gel strengths, become a function of what is required to meet this low end specification.

Experience has shown that the initial gel strength will be more or less the same as the 6-rpm reading. 10 minute gels that show an increasing trend and a widening divergence from the initial gel are a good indicator of a colloidal solids build up that may not be detected by solids analysis. This is due to the fact that while the solids percent may remain the same the actual size of the particles, and hence the surface area they present to the liquid phase, will decrease as degradation occurs. Increasing PV values are also generally a good indicator of a solids build up. It is important to identify increasing trends at an early stage so that timely measures may be taken before they reach problem levels.

hthp filtrate – temperatures up to 300 ˚F (148.9 °C) discussion These procedures are for temperatures up to 300 ˚F (148.9 °C). If higher test temperatures are required a porous stainless steel disc will need to be utilised instead of the normally used filter paper and higher top and bottom pressures applied. When heating apply 100 psi (690 kPa) to top and bottom, increase top pressure to 600 psi (4138 kPa) for the test. This test provides the definitive rigsite answer, (more sophisticated equipment is available in onshore laboratories), to the effectiveness of the emulsification package and the quality of the filter cake. Remember the screen and bomb are a matched pair. The use of unmatched pieces of equipment may result in it being impossible to get a result as whole mud breaches the seals at some point during the test. This is indicated when the pressure gauge on the bottom pressure vessel suddenly goes off scale. Continuing bypass problems could be the result of incorrect “O” rings. Ensure they are of a rounded, rather than flat, profile

ƒ ƒ ƒ ƒ ƒ

HTHP Filtration Cell - Diameter 3” x Height 3.0” OFI specially Hardened Filter paper - Diameter 2.5” / Filtration Area 4.91 sq.in High Pressure CO2 supply (600 psi - 4138 kPa) Stop Clock 10 and 25 ml measuring cylinders

Section

3b


procedure 1) To standardise this test the following procedure must be adhered to. Backpressure is applied during the test to avoid filtrate evaporation. 2) Allow the heating jacket to reach the required temperature. 3) Check out all the “O” rings on the HPHT bomb and lid. Change out any damaged rings. The rings to be checked are the four small stem “O” rings, which tend to pick up cuts and grooves with time, and the two large “O” rings, one in the lid and one in the cell. The large “O” rings should have a rounded profile and be free from dirt. 4) Tighten the bottom valve stem, taking care not to over Example of HTHP tighten, and fill the cell to about 0.5 inch from the rim. 5) Place a filter paper on the rim and put the lid on the cell. Filter Press Ensure the lid stem is open while doing this to avoid damaging the filter paper. 6) Tighten the six studs in the bomb and close the lid stem. 7) Place the bomb in the heating jacket with the lid facing downwards. Rotate the bomb until it seats on the locking pin. 8) Place a CO2 cartridge in each regulator and tighten up the retainers. 9) Place the top regulator on the stem and engage the locking pin. Close the bleed off valve and turn the regulator clockwise until 100 psi (690 kPa) is showing on the gauge. 10) Repeat the process with the bottom regulator. 11) Turn the top valve stem 1/4 to 1/2 turn anti clockwise to pressure up the cell to 100 psi (690 kPa). 12) When the cell reaches the required test temperature open the bottom stem (1/2 turn) and then increase the pressure on the top regulator to 600 psi (4138 kPa) over +/- 20 seconds. 13) Commence the test. The test should be carried out as soon as the bomb reaches the test temperature. Leaving the cell for long periods at high temperatures will produce unreliable results. 14) If the pressure on the bottom regulator increases significantly above 100 psi (690 kPa) bleed off some of the filtrate into the graduated cylinder. 15) After 30 minutes, close the top and bottom valve stems. Slack off the regulator on the bottom collection vessel. Bleed off the filtrate into the graduated cylinder. Disconnect bottom collection vessel, fully open the bleed off valve and tip any residual filtrate into the graduated cylinder. 16) Bleed the pressure off the top regulator. 17) Disconnect the top regulator and remove the bomb from the heating jacket, allowing it to cool in a safe place. 18) When the bomb has cooled bleed off the trapped pressure by slowly opening the top valve with the bomb in an upright position. With the residual pressure bled off invert the cell, loosen the six studs and remove the lid. 19) Examine the filter paper and report the thickness in 32nds (mm) of an inch. Comments about the quality of the cake should be noted in the comments section of the mud report i.e. tough rubbery etc.

Do not use nitrous oxide (N2O) as a pressure source for this test. N2O can detonate when under temperature and pressure in the presence of oil, grease, or carbonaceous materials. Use only carbon dioxide (CO2) or nitrogen (N2).

If the bottom pressure rises 20 psi above the specified pressure during the test, carefully bleed off pressure by draining a small volume of filtrate.

20) Thoroughly clean the bomb and stems in preparation for the next test. 21) Do not preheat the bomb by resting on the heating jacket.

calculations The total filtrate volume, both oil and water, should be doubled, as the standard API press is twice the area of the HPHT cell. Record the volume of water, if any, in the filtrate and remember that this volume must also be doubled for reporting purposes.

interpretation There should be no free water in the filtrate – any indication of water would indicate a problem with the emulsification package that requires immediate attention. The oil fraction should be clear with no hint of muddiness. If there is any sign of mud in the filtrate then the result of the test is void. Mud in the filtrate would indicate that the ‘O’ ring seals needed replacing as whole mud was bypassing the filter paper. Do not instigate mud treatments on the results of any test that has mud in the filtrate. Overhaul the equipment and repeat the test.

retort analysis – oil base mud discussion The accurate determination of the oil, water, high gravity solids and low gravity solids in an OBM mud relies on the correct usage of the 50 ml retort and the correct interpretation of the results. Small errors in the measurement of the solids percentage can result in seriously erroneous reporting of the drilled solids content. It is apparent that inaccurate retort results can lead to unnecessary mud treatments aimed at reducing an apparently out of spec LGS concentration. It is essential that the retort be run at a high enough temperature to burn off the heavier fractions of the oil phase. The heavy fraction can easily account for up to 1% of the total volume and a failure to distil this will result in an equivalent increase in apparent solids content. It is critical that the correct mud weight is used in the calculation to determine the relative concentrations of HGS and LGS. It is commonly the case that the difference in density between a hot and cold OBM is .03 sg. Using the flowline mud weight when the sample to be retorted has in fact cooled considerably, and hence increased in density, will give a much higher LGS content than is actually the case. The retort mud weight, i.e. the actual density of the mud in the retort as opposed to the flow line mud weight, will, therefore, be utilised in all calculations.

Section

3b


The volume of the retort will be confirmed by filling the cell with distilled water and checking that 50 cc’s is in fact received in the test tube. If 50 cc’s is not consistently obtained with distilled water (it might be necessary to repeat the check with distilled water to ensure the error is genuine) then, either the 50 cc retort cell must be replaced with an accurate one, or, a correction factor must be applied to the volume of distillate actually obtained, as per the following formula: 50 x Volume of distillate ccs Volume of distilled water obtained ccs Any smoke emerging from the heating jacket is an indication that vapour is escaping through the threads connecting the upper and lower parts of the retort cell. If this is noted it is an indication that the tube to the condenser is, or has been, blocked. A blocked tube will result in the bottom of the upper part of the retort cell “flaring” to allow an escape route for increasing pressure. Even if the tube is subsequently cleaned the flaring will remain and is still an escape route for a proportion of the vapour. This will obviously result in an inaccurate solids measurement. Any hint of smoke from the heating jacket is an indication that the top part of the retort cell is damaged and should be discarded. It can be appreciated that a combination of all, or some of, the factors mentioned above, i.e. insufficient retort temperature, incorrect mud weight used in calculations, volume being retorted not in fact 50 cc’s, partial escape of vapour through flared threaded area, can result in wildly inaccurate determinations of the drilled solids content.

equipment Three retort sizes are available to the industry, 10 ml, 20 ml and 50 ml. The latter is recommended for drilling operations, due to its greater precision and accuracy. Each unit consists of; ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ

Sample cup Thermostatically controlled heating element Liquid condenser Pyrex measuring cylinder (50 ml) Fine steel wool Pipe cleaner High temperature silicone grease Defoaming agent Spatula

procedures 1) Ensure retort assembly to be used is clean and dry. It is vital that all traces trof previously retorted solids are removed from the retort cup to guarantee 50 ml of fluid is actually retorted. Remove all traces of previously used steel wool. Water can be retained in steel wool when the upper retort body is washed / cleaned. Failure to Example of Retort change the steel wool can result in inaccurate measurements, as this extraneous water will become included in the total water content. 10

2) Weigh the clean and dry retort cup and lid on the triple beam balance. 3) Add the mud, which has been allowed to cool to ambient temperature, to the retort cup, gently tap the cup to remove any air bubbles and place the lid with a rotational movement to obtain a proper fit. Be sure an excess of fluid flows out of the hole in the lid. 4) Carefully clean the cup and lid of excess fluid and reweigh on the triple beam balance. The retort mud weight SG is determined as the difference between the empty and full weights, in grams, divided by 50 (the volume of mud). 5) Pack the retort body with new steel wool, apply Never–Seez, to the threads and assemble top and bottom parts. Ensure that the two parts are fully screwed together. If it is not possible to fully screw together the two parts, it will be necessary to clean the threads and repeat the above steps. Failure to get a good seal could result in leakage that will lead to an inaccurate result. 6) Attach the condenser and place the retort assembly in the heating jacket and close the insulating lid. 7) Place clean, dry liquid receiver below condenser outlet and turn on heating jacket. 8) The temperature control should be adjusted so that the retort cell glows dull red at the end of the distillation and the final drops coming out of the retort should be observed to be black (the heavy fraction) and sink through the clear oil to the meniscus. Ultimately smoke will emerge from the retort and the distillation is only complete when the smoke stops.

calculations It will be assumed that all salt in the brine phase is Calcium Chloride.

SG of drilled solids (LGS) = 2.60 SG of Barite (HGS) = 4.25 SG of Base Oil = SGo

Input Data

SG of mud in retort Retort % oil Retort % water Retort % solids

= = = =

Salinity mg/l

=

SG of Brine Correction factor Brine fraction Corrected Solids

= = = =

SGm Of Wf Sf

mls of 0.282N AgNO3 x 10,000 % Water÷100

SGb (Look up Salinity in specific brine table) CF (From brine table) Bf (Correction factor x Wf) CS [Sf - Salt content (Bf - Wf)]

Then… Average SG of Solids (AVSG) % LGS % HGS lb/bbl LGS

SGm x 100 - [(Of x SGo) + (Bf x SGb)] CS CS x (4.25 - AVSG) = 4.25 - 2.6 CS x (4.25 - AVSG) = 1.65 =

= CS - % LGS = %LGS x 3.5 x 2.6

11

Section

3b


lb/bbl HGS kg/m3 LGS kg/m3 HGS

= = = = = = =

%LGS x 9.1 %HGS x 3.5 x 4.25 %HGS x 14.87 %LGS x (9.1 x 6.2897) ÷ 2.205 %LGS x 25.96 %HGS x (14.87 x 6.2897) ÷ 2.205 %HGS x 42.42

interpretation The control of the low gravity solids content of a OBM system will trigger the use of centrifuges or dilutions. If mud costs were broken down and assigned to a particular reason then the control of LGS would probably account for the bulk of expenditure on most wells. For this reason very careful attention must be paid to the points outlined in the Discussion section above. It is possible to envisage a situation where vast sums of money are spent treating a non-existent solids problem. This test is a reliable indication of the condition of a drilling fluid on a one off basis. The results of other tests may change, for example, with shear and temperature i.e. the rheology may increase, the HTHP filter loss may decrease without any additions being made to the mud. The LGS content, however, is something that can be assessed, and tackled if required, without waiting for trends to be established from further tests. The calculations are extremely sensitive and a 0.5% difference in total solids content will have a large affect on the LGS fraction. For this reason, it is important to be meticulous when taking the volumes of oil, water and solids.

sand content discussion It is important to remember that this test is a measure of sand size particles, which can be of any rock type, or indeed sacked additives, as opposed to just sand. If finer than 200 mesh shaker screens are in use, an increase in sand size particles would be a clear indicator of screen damage requiring immediate attention.

equipment ƒ 2 1/2” diameter sieve (200 mesh, 74 micron) ƒ Plastic funnel to fit the sieve ƒ Glass measuring tube marked for the volume of mud to be added in order to read the percentage of sand directly in the bottom of the tube which is graduated from 0 to 20%.

procedures 1) Fill the glass measuring tube to the indicated with mud. Add clean base oil to the next mark. Close the mouth of the tube and shake vigorously. Example of Sand Content 12

2) Pour the mixture onto the screen, add more base oil to the tube, shake and again pour onto the screen. Repeat until the wash fluid is clear. 3) Wash the sand retained on the screen with base oil to remove any remaining mud. 4) Fit the funnel over the top of the sieve. Invert slowly and insert the mouth of the funnel into the glass tube. Wash the sand into the tube with clean base oil.

calculations Allow the sand to settle. From the graduations on the tube, read and report the percent by volume of sand size drilled solids (see interpretation below).

interpretation Some interpretation of the result will need to be made based on the differential settling speeds of the different materials present. The reported result should be that proportion of the settled particles that are attributable to drilled solids. These would be the particles that settle out first and are usually followed by calcium carbonates, other types of LCM and undissolved black powder. The differing particles aggregate, therefore, in clearly identifiable strata and, depending what was being added to the active system at any given time, the apparent sand content can appear much higher than it actually is. The sand content is not really of any significance with respect to overall mud properties but is of importance when it comes to wear on mud pump parts etc. 2% is normally accepted as the upper limit. Generally speaking the sand content is also useful to gauge the effectiveness of the shaker screen sizes being employed. If the sand content rises quickly then this is an indication that finer mesh screens need to be tried. A rapid increase in sand content over a short period can also indicate that the shaker screens are torn and need immediate replacing.

electrical stability discussion ƒ The test will be carried out at 120 °F (48.9 °C) or whatever the rheology temperature is carried out at. The mud to be tested will be the mud in the heated cup after the rheology measurements have been completed. ƒ Regularly check the accuracy of the ES meter with standard resistors and / or Zener diodes The ES readings should fall within 2.5% of the expected values; if any of the ES readings fall outside this range, the instrument should be replaced.

equipment ƒ The electrical stability will be measured with a Fann or OFI digital meter and reported in volts.

13

Section

3b


procedures 1) Before placing the probe in the mud, it is essential to test the meter in air. The reading should go off scale and the display start flashing. If the meter does not go off scale, it is an indication that the probe is shorting out due to an accumulation of detritus between the two prongs. It is clear that the probe can short out before the end point of the mud is reached and an erroneous reading will result. The probe should be carefully cleaned and retested in air to ensure that it now goes off scale before testing the mud. 2) Place the clean and checked probe in the sample at 120 °F (48.9 °C) and use it to stir the fluid to ensure homogeneity. Position the probe so it does not touch the bottom or sides of the heated cup, ensuring the tip of the electrode is completely immersed. 3) Press the button to initiate the voltage ramp, holding the probe still until the end point is reached and a steady reading is seen in the digital display. Note the reading. 4) Repeat the test. The two ES values should be within 5% and anything greater would indicate a problem with the equipment. 5) The result is the average of the two readings.

calculations The result is simply the average of the two readings in volts.

interpretation It is essential to remember that the stability reading is not just a measurement of emulsion strength and will vary with water percentage and water phase salinity. Trends are of more interest than absolute values. A decreasing stability reading while other mud properties remained constant would be an indication of decreasing emulsifier effectiveness.

lime content discussion The measurement of lime in the mud has been the subject of numerous studies to establish why results often do not match known concentrations. For example, a brand new mud mixed at the mud plant has 6 lb/bbl (17.1 kg/m3) of lime added and yet the test may indicate only 3 lb/bbl (8.55 kg/m3). Results will also be affected by the combination of contaminants into the mud system. Magnesium will actually react with the OH ions in the conical flask as water is added to the demulsified sample during the test and, thus, no pink colour will develop when phenolphthalein is added. It should be remembered that this test is measuring the pH of the sample, as excess lime is dissolve d by the addition of distilled water. The back titration method has been found to give the most accurate measurement of the excess lime content of an OBM.

14

equipment ƒ Xylene / Isopropanol (1:1 mixture) or equivalent ƒ 250 ml conical flask ƒ Variable temperature and speed hot plate/stirrer with suitable magnetic beads ƒ Distilled water ƒ Phenolphthalein indicator ƒ 0.1N H2SO4 ƒ 0.1N NaOH ƒ Pipettes

procedures 1) Measure 50 ml of Xylene / Isopropanol (1:1 mixture) into a 250 ml conical flask. 2) Disperse 1 ml of whole mud into the 50 ml of solvent while mixing on a magnetic stirrer for 30 seconds. 3) Add 100 mls of distilled water, 10 drops of phenolphthalein indicator and allow to mix for 5 mins. A strong pink / red colour will develop. 4) Add 10 cc’s of 0.1N H2SO4 - the red colour will disappear. 5) Back titrate with 0.1N NaOH until a pink tinge returns.

calculations Alkalinity (Mp) lb/bbl excess lime kg/m3 excess lime

= = = =

10 - ml of NaOH Mp x 1.295 Mp x (1.295 x 6.2897) ÷ 2.205 Mp x 3.69

interpretation It is important to maintain the lime content as recommended in the mud program to optimise the emulsification package. Mud companies are often of the opinion that lime is not required in modern emulsification packages. However, experience has consistently shown that many mud problems (thick mud, water in the filtrate etc) can be corrected by restoring a depleted lime content. If it is obvious that large lime additions to the mud are not being reflected in test results then increasingly large amounts of lime should not be continuously added – a masking agent is undoubtedly at work.

water phase salinity discussion Numerous papers have been generated explaining different ways of reporting salinity eg ppm CaCl2 whole mud, mg/l Cl brine phase etc. This has caused great confusion in the past where apparently wildly different figures were in fact conveying exactly the same salinity. It is essential that salinity is always reported as mg/l chlorides in the water phase i.e. WPS.

15

Section

3b


Remember ppm is not the same as mg/l (ppm x brine SG = mg/l) It will always be assumed that all chlorides in the mud are from Calcium Chloride i.e. there is no requirement to differentiate between Sodium Chloride and Calcium Chloride.

equipment ƒ Xylene / Isopropanol (1:1 mixture) ƒ 250 ml conical flask ƒ Variable temperature and speed hot plate/stirrer with suitable magnetic beads ƒ Distilled water ƒ Potassium chromate indicator ƒ 0.1N H2SO4 ƒ 0.282 AgNO3. ƒ Pipettes

procedure 1) The chloride titration is a continuation of the lime content test. 2) Add 0.5 ml of 0.1N H2SO4 to remove the pink tinge from the sample remaining from the lime test (more if required). 3) Add 15 drops of potassium chromate indicator to the colourless sample. 4) While agitating vigorously with the magnetic stirrer, titrate with 0.282 AgNO3. 5) The end point is reached at the first sign of a lasting orange tinge (not brick red). 6) A heavy precipitate of silver chloride will develop during this titration. To ensure even distribution of the AgNO3 the magnetic stirrer should be at a high speed. However, not so high that the sides of the flask become splashed with sample.

calculations WPS mg/l

=

mls of 0.282N AgNO3 x 10,000 % Water÷100

The result will be reported in mg/l of total Chlorides in the water phase.

interpretation The accurate calculation of the WPS is obviously dependent on the precise determination of the water content of the whole mud. The end point must be consistently picked at the same colour change. Great care must be taken to ensure that results are consistent over several samples before embarking on a treatment program to increase salinity levels. This is because while it is very easy to add salt, large dilutions with freshwater, base oil and chemicals would be required to reduce the effects of any over treatment.

16

garrett gas train - sulfides discussion The presence of hydrogen sulphide in a drilling fluid can be lethal to personnel as well as being damaging to equipment and mud properties. Hydrogen sulphide will dissolve in the fluid and remain in solution until saturation point has been reached when it will break out. It is very important to know if H2S is entering the fluid and it is obviously advantageous to detect it before it is picked up by gas detectors, after having broken out on surface. The presence of hydrogen sulphide in the mud manifests itself in two ways as it goes into solution. Firstly there will be a rapid drop in the lime content as hydrogen ions are neutralised. Secondly soluble sulphides will appear in the mud. Measuring the latter of these two will provide conclusive evidence of hydrogen sulphide in the mud. Active soluble sulphides can be analysed and monitored because of their characteristic reaction with acid that involves the release of H2S gas. Since the test is performed on whole mud, strong acids, such as sulphuric acid, are not used since they would release inert sulphides (from barite for example) which are non hazardous in normal drilling situations. By adding citric acid, a relatively mild acid, to a whole mud sample in a Garret Gas Train it is possible to detect the presence of active sulphides in the mud.

equipment ƒ A Garret Gas Train (GGT) – See detailed diagram. ƒ The GGT separates the gas from the liquid, thereby preventing contamination of the H2S detector by the liquid phase. ƒ Low and high range Dräger analysis tubes, the first marked `H2S 100/a´CH 29101 and the second `H2S 0.2%/A´ - CH 28101. ƒ The two types of Dräger tube will span a sufficiently wide range for sulphide analysis of muds. The low range tube is white until H2S turns it brownish black and the high range blue until turned jet black. No other common mud contaminant or component has this affect. ƒ Citric acid + demulsifier solution. This is prepared by dissolving 420 grams of reagent grade citric acid into 100 ml of deionised water and stirring in 25 ml of Aktaflo E. ƒ Octanol in a dropper bottle as a defoamer. ƒ A 20 ml hypodermic syringe, with 21 gauge needle, for acid and a selection of 2.5 ml, 5 ml and 10 ml disposable syringes for oil mud sample volume measurements. ƒ Magnetic stirrer with plastic or glass covered stirring bar to fit into GGT chamber 1.

17

Section

3b


procedure Syringe to inject Acid and Aktaflo E

Dispersion Tube

Dräger Tube

Injection Tube Rubber Bung

Gas Supply

Exhaust

Exhaust 1

2

3

Flowmeter Porous China Membrane

Magnetic Stirrer Pellet

Magnetic Stirrer

Mud

1) Arrange the magnetic stirrer and GGT body so that the stir bar will rotate freely to agitate the contents of chamber 1. 2) With the regulator backed off install and puncture a CO2 cartridge in the carrier gas assembly. 3) Add the required volume of mud into chamber 1 as determined by which Dräger tube is to be employed and an estimate of the sulphide range (Chambers 2 and 3 remain empty as foam traps). Sulphide Sample Dräger Factor Range Volume Tube Tube (mg/l) 1.5 - 30 10.0 ml H2S 100/a 12 3 - 60 5.0 ml “ 12 60 - 120 2.5 ml “ 12 60 - 1020 10.0 ml H2S 0.2%/a 600 120 - 2040 5.0 ml “ 600 240 - 4080 2.5 ml “ 600 4) Select a Dräger tube for the estimated range as per the table above and break the tip from each end. 5) Add 10 drops of Octanol to chamber 1. 6) Install the tube with the arrow pointed down in the receptacle bored in the corner of the train. Be sure the “O”-ring seals. 7) Install the clean, dry flow meter tube with the word TOP upward. Be sure the “O”-ring seals. 8) Install the top on the gas train and hand tighten all screws evenly to seal. 9) Attach the flexible tubing to the dispersion tube and to the Dräger tube. Use only latex or flexible, inert plastic tubing. Do not clamp the flexible – it does not require it and will provide pressure relief in the event of over pressurisation. 18

10) Adjust the dispersion tube to 0.5 cm from bottom or enough to clear the stirring bar. 11) Put 20 ml of acid / Aktaflo E into the hypodermic syringe. 12) Gently flow CO2 for 15 seconds to purge the system, checking for leaks. Stop the flow. 13) Start rapid stirring of the contents of chamber 1 while slowly injecting the acid / Aktaflo through the rubber septum. Stir for at least 5 minutes or until the sample is well dispersed with no obvious oil drops. 14) Restart the carrier gas flow and adjust the flow so that the ball is between the red lines. (200 - 400 cm3 per minute – one CO2 cartridge should provide between 15 and 20 minutes of flow at this rate). 15) Continue flowing for a minimum of 15 minutes. 16) Observe changes in the appearance of the Dräger tube and record the maximum darkened length, in units marked on the tube, before the front starts to smear. ƒ Any soluble sulphites in the fluid will, upon the addition of acid, convert to sulphur dioxide (SO2) gas that can interfere with test results. ƒ In the low range tube this manifests itself as diffusion at the front of the sulphide stain. The stain itself may be of a lighter colour than when SO2 is not present and a lower reading may be attained. ƒ It is important to note that while SO2 can produce a negative error it does not falsely indicate a positive H2S reading. ƒ In the high range tube an orange colour may appear ahead of the black front if sulphites are present in the sample. The orange section should be ignored when darkened length is recorded. 17) Thoroughly clean the unit after use.

calculations Using the sample volume, the Dräger tubes maximum darkened length and the tube factor the sulphides present are calculated as: Sulfidesmg/I =

darkenedlength x tube factor sample volume ml

For the higher range tube it may be necessary to correct the tube factor. The tube factor is based on a batch factor (stencilled on the box) of 0.40. If a different batch factor is stencilled on the box a corrected tube factor should be calculated as follows: Corrected tube factor = 600 x

actual batch factor 0.40

interpretation Any indication of soluble sulphides in the mud would indicate the presence of H2S gas. It may be the case however that the presence is due to the release of gas from the pore spaces of the rock actually being drilled. In this case ensuring proper overbalance and maintaining alkalinity is sufficient to control any hazard. This is not suitable for dealing with influxes, as the alkaline neutralisation of H2S is instantly reversible by reductions in pH. In these cases a scavenger, such as zinc oxide, should be added to convert soluble sulphides into an insoluble precipitate, thus removing them permanently from the equation.

19

Section

3b


Where H2S is expected it is advisable to pre-treat with a scavenger. However with a scavenger in the system no indications of H2S will be picked up, by conventional means, until the scavenger has been used up. Thus while a scavenger increases safety levels it makes detection of small amounts of H2S very difficult indeed.

oil on cuttings measurements introduction When drilling with an SBM every effort must be made to minimise losses to the sea. The main source of SBM discharge is the shale shakers and is a consequence of the SBM adhering to the cuttings that are discharged overboard. A second source of fluid loss is through the centrifuges, once again as a result of SBM adhering to the solids content. There are two ways of measuring the amount of oil being discharged to the sea. ƒ Analyses of the amount of oil adhering to the cuttings and centrifuged solids at any given time. ƒ Analysis of the total amount of oil that has been lost to the sea at the end of the well. This is a mass balance calculation based on the actual amount of whole mud discharged during drilling operations. The first method gives a snapshot of what is happening at the time the sample is taken and does not really reflect the overall picture. The second method gives a true measurement of what has actually been lost. Typical target for Oil on Cuttings analysis is: ƒ Less than 10% oil by weight (Both shakers and Centrifuges) (i.e. less than 100 grams of oil per kilogram of dry cuttings) The primary variable in determining the percentage of mud associated with the discharged rock is the size of the cuttings i.e. the larger the cuttings the smaller the surface area, available for adhesion, for a given volume of drilled formation. The converse is also true i.e. the smaller the cuttings the larger the surface area. Other variables include shaker screen size, type of formation, OWR and rheology. If available, drying screens should be utilised in an attempt to reduce the measured Oil on Cuttings (OOC) content to less than 10% by weight. However this goal should not take preference over utilising the finest possible screens on the shakers and maintaining the optimum mud properties for drilling. OOC analysis should be carried out at least once during every 24 hour period when drilling has occurred. Testing will be more frequent during periods of high ROP when a check should be performed at least every 300m drilled.

20

Centrifuges should be run at such bowl speeds and flow rates as to ensure the measured OOC is always less than 10% by weight. A check will be performed, as per the shaker analysis, once in any 24-hour period the centrifuges have been run.

oil on cuttings analysis It is important that the weighted average OOC is reported along with individual daily test results. This is reported as an expression of the percentage of total cumulated oil discharge of the total cumulated cuttings discharge, calculated daily. This is because during periods of slower drilling the OOC is invariably higher as more fines are generated. However long periods of slow drilling will result in many days of high oil on cuttings results but not many feet/ meters being drilled – this arithmetical average is obviously, therefore a distortion of the well average.

sampling 1) A representative bulk sample of at least 0.5 kg - 1.0 kg should be taken and must include material from each deck of all the shakers. This is best achieved by “scanning” a suitable container, preferably a wide tray which will retain all the material i.e. both the solids and liquids, beneath the discharge of the shakers. 2) The sample would then be thoroughly mulched to ensure a homogenous sample. 3) Immediately transfer the sample to the mud lab for analysis.

equipment ƒ Proprietary mud, oil and water retort kit with at least three mud chambers. A 50 ml chamber must be used. ƒ The distillate receiver must be an accurately calibrated 20 ml or 50 ml measuring cylinder calibrated in 1.0 ml divisions (dependent on amount of distillate expected). ƒ A triple beam balance capable of weighing to an accuracy 0.1 g under offshore conditions.

procedure 1) Weigh the distillate receiver. 2) Weigh the empty retort cell (top and bottom screwed together with both the lid in place and the steel wool in the upper chamber). 3) Unscrew the retort and fill the bottom part with cuttings as completely as possible, replace the lid and clean off any adhering mud and oil. Re-screw the upper chamber. 4) Re-weigh the filled assembly. 5) Retort the sample for as long as it takes to burn off all the heavy fractions of oil. 6) Switch off the heater, remove the mud chamber and allow to cool. Read off the volume of the water and oil collected in the distillate receiver. Reweigh the distillate receiver. Reweigh the retort assembly when it has cooled.

21

Section

3b


calculation The result is calculated by the steps: A = Weight of chamber (empty with steel wool + lid)

gm

B = Weight of chamber and sample

gm

C = Weight of empty graduated glass cylinder

gm

D = Weight of chamber after heating

gm

E = Weight of glass cylinder and distillate

gm

F = Volume of distillate

mls

G = Volume of water

mls

H = Weight of cuttings (B - A)

gm

I = Weight of dry solids (D - A)

gm

J = Weight of distillate (E - C)

gm

K = Weight of oil in distillate (J - G)

gm

L = Volume of oil in distillate (F - G)

mls

M = Calculate oil on cuttings (K ÷ I) x 1000

gm / kg

Percentage oil on cuttings (M x 100) ÷ 1000

%

The content of oil in the cuttings should be expressed as grams of oil per kilogram of dry retorted solids and in % by weight. Mistakes have been made due to experimental error eg, the weight of the dry solids plus oil and water does not tally with the weight wet cuttings etc. The reporting form is designed to allow easy cross checks at a glance and so ensure no erroneous results are taken as true. ƒ The weight of wet cuttings (H) should be slightly more than the weight of dry cuttings (I) + the weight of distillate (J). A slight amount of distillate would appear to evaporate. ƒ The weight of oil in the distillate (K) should equal the volume of oil (L) x the SG of the oil. It all sounds obvious but often these basic sums do not tally. If these simple crosschecks reveal experimental error then the figures need to be checked or the test repeated.

check calibration The heating element in the retort kit can decline in efficiency over a period of time and this needs to be checked. Such checks should be carried out, for each well drilled with oil based mud: ƒ Prior to drilling with OBM. ƒ At completion of the well.

22

To calibrate a retort the following mixture should be mixed on a Hamilton Beach mixer at the very high speed setting, adding each component in order as listed below:

Base Oil Organophilic Clay Emulsifier Lime Fresh Water Wetting Agent Barite

106 mls 1.0 g 3.0 mls 2.0 g 28 mls 3.0 g 750 g

Mixing Notes: ƒ The Barite should be added in stages, until the mixer can no longer incorporate the solids (approximately 650 gm), the remaining Barite should be thoroughly mixed in with a spatula. ƒ The final mixture should be of a highly viscous, grainy-looking, semisolid nature, but fluid enough to allow proper filling of the retort cup. ƒ The above mixture should yield a measured oil/water ratio of 80/20. Solids content is 56%. ƒ Total volume of the mix is 320 mls and thus one mix should be sufficient for calibration of a 50 mls retort six times (allowing for the inevitable losses). The measured figure of oil on dry retorted solids should be within +/- 10 g/kg of the calculated value.

23

pilot testing section 4

basic pilot testing and contamination

section 4

Scomi Oiltools

introduction

2

designing pilot tests

2

pilot testing equipment

4

interpretation of pilot test results

4

rheological properties

5

retort analysis

6

filtrate analysis

7

cationic exchange capacity of clays

12

filtration

13

static aging

14

Section

4

basic pilot testing & contamination


introduction Pilot testing of drilling fluids is testing performed on proportionately small-scale samples. It is an essential part of drilling fluid testing and treating. Pilot testing minimises the risk of sending a fluid downhole that may be incompatible with the formations to be drilled or that may be ineffective under downhole conditions. Pilot testing is generally concentrated on the physical properties such as rheology and fluid loss; however, it is important that chemical properties are also evaluated. Most chemical reactions require heat, mixing and time to drive the reaction. Therefore, it is necessary to have a means for heating and agitating pilot test samples. Problems such as carbonates and bicarbonates are not readily detectable and require a complete mud analysis and a pilot test series with heat aging to determine proper treatment. Without heat aging, it is easy to over treat the contaminant and create an even more severe problem. Ideally a portable roller oven should be available at the rig site if extensive pilot testing is required. Once the anomaly or anomalies of a drilling fluid’s characteristics have been identified via conventional mud testing, the actual pilot test can begin. Guidelines that are fundamental to the successful pilot test can be listed as follows: 1. On every test on which analysis is made, a control sample of mud should be taken. 2. If a combination of additives is to be tested, the effect of each additive on the mud should be determined independently. 3. Some effects of additives will be observed almost instantly while other products may need a minimum time (e.g., 4 hours hot rolling @ 150 °F or 65.6 °C) to determine their value. 4. Cost and availability of the products to be tested must always be considered in the final choice of conditioning materials. 5. Duplicate the environment of each test as much as possible, i.e., use the same agitation (speed and mixer), test temperature, volume, mechanical and electrical test devices, etc. A pilot test sample should be representative of the fluid being used. Pilot testing is thus based on the fact that 1g/350 cm3 of the sample is equivalent to 1 lb/bbl in 42 gal of the actual mud system.

designing pilot tests

A pilot test or a series of pilot tests must be designed to answer the questions that you have in mind. Therefore, it is necessary to know exactly the reason for the test. Some typical reasons are: 1. Mud response to downhole conditions, such as:

ƒ temperature effects ƒ drilling uncured cement ƒ drilling anhydrite ƒ encountering salt/saltwater flows ƒ acid gas (CO2, H2S) intrusions ƒ water on water-based mud contamination in oil-based mud

2. Product response as a result of:

ƒ ƒ ƒ ƒ ƒ ƒ

purity, material variation (different lot numbers) concentration compatibility with other components in the mud comparison to other products temperature/contamination shelf life

3. Adjustments to mud properties such as:

ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ

weight up/dilution changing fluid loss properties changing alkalinity/pH treating carbonate/bicarbonate contamination reducing hardness adjusting MBT - clay content of the mud changing oil/water ratio of oil muds increasing electrical stability of oil muds

4. Study of effects of breakover, converting or displacement of muds, such as:

ƒ ƒ ƒ ƒ ƒ

displacing water-based mud with oil-based mud or vice versa converting from freshwater mud to saturated salt mud breakover to lime or gyp mud reducing components in mud to convert to bland coring fluid treatment required to convert mud to a packer fluid 42 gallons

BARITE 100 lbs

100 lb 42 gal

(1.0 barrel)

100 lb/bbl

100.0 G 100 g 350 cm3

100 lb/bbl

To determine how to design a pilot test or test series, look at economics and potential for problems down the road. For example, if you expect to encounter a pressured saltwater flow (16 lb/gal or SG 1.92) with a 15 lb/gal (SG 1.80) freshwater mud at 350 °F (176.7 °C), the parameters for testing could be: 1) maximum volume of saltwater anticipated in the mud 2) weight up to 16 lb/gal (SD 1.92) with and without contaminant (the saltwater) 3) effects of temperature on mud (15 and 16 lb/gal or 1.80 and 1.92 SG) with and without contamination 4) dilution and thinner treatments Pilot test design requires calculating amounts of materials to put into the test samples. In pilot tests, grams are equivalent to pounds and 350 cm3 is equivalent to one 42 gal oilfield barrel. Material balance equations are used for pilot test design. For example, to weigh the 15 lb/gal (SG 1.80) mud to 16 lb/gal (SG 1.92) without increasing the mud volume, one must calculate how much 15 lb/gal (SG 1.80) mud to dump and how much barite to add to increase density. For simpler pilot tests, such as adding only a few lb/bbl (kg/m3) treatments, it is not necessary to account for material balance.

Section

4


Note: For liquid additives, volumes (gallons, cans, drums, bulk bags) must be converted into weights (pounds, grams, millilitres) for pilot testing.

Material Fresh Water Seawater Diesel Oil Saturated Saltwater API Bentonite Barite Calcium Carbonate Caustic Soda Lime Lignite Gypsum Lignosulphonate Soda Ash Salt, NaCl

Specific Gravity 1.00 1.03 0.84 1.20 2.60 4.2 2.75 2.13 2.20 1.50 2.30 0.83 2.53 2.16

lb/gal 8.33 8.58 7.0 10.0 21.6 35.05 22.9 17.7 18.3 12.5 19.2 6.9 21.1 18.0

lb/bbl 350 361 294 420 910 1472 963 525 746 525 805 290 886 756

kg/m3 997.5 1028.85 837.90 1197 2593.5 4195.2 2744.55 1496.25 2126.10 1496.25 2294.25 826.50 2525.10 2154.60

Rig site pilot tests have distinct practical advantages over sending a mud into the laboratory or having a laboratory mud prepared for pilottesting. Rig site testing allows actual material and mud to be used, which allows results to be readily available quicker (which is usually very important), and allows the rig supervisor and the mud engineer to evaluate and review the pilot test results. Laboratory pilot tests and planning are both important in preparing to drill a troublesome well. Both should be done well in advance of anticipated problems. In this case, lab pilot tests are advantageous in that they can be performed in advance, but then pilot tested again at the rig site with the actual mud and chemicals. Note: Protective eyewear (safety glasses or safety goggles) must be worn at all times when mixing chemicals.

pilot testing equipment

A balance that can weigh from 0.1 to 300 g and a portable oven (preferably roller oven) that can go to approximately 400 °F (204 °C) are needed. Mud cells made of stainless steel to hold at least 300 cm3 of mud at 1000 psi (6897 kPa) a mixer such as a Hamilton Beach mixer are also needed. Mud testing equipment that is accurately calibrated, along with fresh reagents for titrations are essential for pilot testing.

interpretation of pilot test results

A single pilot test can give only limited information, but this is often sufficient for the need. Most often a series of pilot tests (three to five samples) are required to properly answer the questions. For every pilot test (single or series) a control sample must be run in parallel with the test sample. A control sample is the base mud which has not been treated, but which is taken through all the mixing, heating, rolling, etc. processes. The control is used to aid interpretation of results. Data is compared between the control and test sample to sort out the effects due to treatment versus mechanical effects (mixing, rolling or time of exposure). For example, a mud engineer has an oil mud with a low electrical stability (ES). He pilot tests a sample with 2 lb/bbl (2 g/350 cm3 ) additional emulsifier and shears it on the mixer for 10 minutes. The ES is much higher than before. He also has run a control sample on the mixer for 10 minutes, but without the additional emulsifier, and obtained almost the same higher ES. Was the emulsifier responsible for the improved ES? No, in this case the shearing gave the improvement. Results of pilot testing should be thoroughly reviewed before drawing conclusions. Often, one pilot test will lead to another one or two tests before the answer is satisfactorily clear.

rheological properties plastic viscosity Plastic viscosity is proportional to rate of shear, thus largely reflects the resistance to flow due to mechanical friction of the particles. Plastic viscosity is a function of solids’ concentration and shape. It will be expected to increase with decreasing particle size with the same volume of solids. In oil muds, the plastic viscosity decreases with an increase in temperature or oil content. a) Causes for increase in PV ƒ Drilled solids ƒ Rapid penetration rates with inadequate drilling solids control and extended drilling with a PDC bit produce more drilled solids particles per unit of volume ƒ Surface additions ƒ Oil additions to water muds; water additions to oil muds; asphalt additions to water or oil muds. Lost circulation materials; weighting materials, (e.g. graded calcium carbonate, barite, ilmenite, iron carbonate, galena, etc.) b) Cross reference

ƒ Retort - drilled solids content high

Average specific gravity solids low considering the density of mud.

c) Solutions to reduce plastic viscosity ƒ Dilution ƒ Employment of mechanical solids removal devices ƒ Surfactants (Water or oil wetting agents) yield point Yield Point is a function of the concentration of mud solids and their surface charges and potentials which affect interparticle forces. Dispersants and deflocculants are believed to adsorb on the mud particles. This action changes the chemical nature of the surfaces and likewise affects the interparticle forces, resulting in viscosity and YP reductions. a) Causes for Increase YP ƒ Flocculation due to soluble contaminants produced from formation (e.g., calcium, magnesium, sulphides, carbon dioxide) ƒ Surface Additives: • Polymers • Clays • Surfactants • Lubricants • Lime • Cement • Detergents • Lost circulation materials ƒ Drilling hydratable shales ƒ pH too low to solubilise deflocculants or dispersants b) Cross References ƒ Filtrate analysis ƒ Methylene blue determination (CEC) ƒ pH

Section

4


c) Solution to reduce yield point ƒ Reduction of interparticle attraction forces ƒ Chemical thinners ƒ Deflocculants ƒ Surfactants ƒ Precipitation of flocculating ions

retort analysis Determine percent by volume of oil, water and solids. Compare results with solids and average specific gravity of solids graphs. a) A frequent error encountered in the retort analysis is the result of loading the cell with gas-cut mud. A higher solids content than actual is therefore calculated.

Causes for increases in the liquid phase originate from formation fluids or from surface additions (inadvertent or on purpose).

Increases of solids can be caused by fast drilling rates, penetration of salts, sands or failure or absence of solids separating devices.

b) Cross reference

ƒ Rheometer - plastic viscosity ƒ Mud balance - rapid density fluctuation

c) Solution (see rheological properties - plastic viscosity). ƒ Dilution. ƒ Employment of mechanical solids removal devices (e.g., decanting centrifuges) and/or reduction of screen size openings of shale shakers and mud cleaners. Solids Check List for Diagnosing and Treating Non-Dispersed Mud Systems

Mud Wt.

lb/gal

SG

9 9.5 10 10.5 11 11.5 12 12.5 13 13.5 14 14.5 15 15.5 16 16.5 17

1.08 1.14 1.20 1.26 1.32 1.38 1.44 1.50 1.56 1.62 1.68 1.74 1.80 1.86 1.92 1.98 2.04

Bentonite

ACCEPTABLE RANGE FOR Total Solids Barite

Drilled Solids

b/bbl

kg/m3

%by vol.

lb/bbl

kg/m3

lb/bbl

kg/m3

14 14 14 14 14 14 13 13 12 11 10 10 9 9 8 8 8

39.94 39.94 39.94 39.94 39.94 39.94 37.09 37.09 34.24 31.38 28.53 28.53 25.68 25.68 22.82 22.82 22.82

3-4 5-7 7-8 9 - 11 11 - 12 12 - 14 14 - 16 16 - 18 18 - 20 20 - 22 22 - 24 24 - 26 25 - 27 27 - 29 29 - 30 30 - 32 32 - 34

29 - 13 60 - 32 83 - 64 115 - 85 138 - 115 160 - 136 194 - 166 230 - 200 249 - 218 270 - 246 300 - 269 336 - 306 360 - 335 380 - 358 420 - 400 455 - 432 475 - 455

83 - 37 171 - 91 237 - 183 328 - 243 394 - 328 456 - 388 554 - 474 656 - 571 710 - 622 770 - 702 856 - 767 959 - 873 1027 - 956 1084 - 1021 1198 - 1141 1298 - 1233 1355 - 1298

0 - 28 0 - 28 0 - 28 0 - 28 0 - 28 0 - 28 0 - 26 0 - 26 0 - 24 0 - 22 0 - 20 0 - 20 0 - 18 0 - 18 0 - 16 0 - 16 0 - 16

0 - 80 0 - 80 0 - 80 0 - 80 0 - 80 0 - 80 0 - 74 0 - 74 0 - 68 0 - 63 0 - 57 0 - 57 0 - 46 0 - 46 0 - 45 0 - 45 0 - 45

l

Relative Proportion of Clay and Barite S.G. of mud solids % by wt barite % by wt clay / drilled solids

2.6

2.8

3.0

3.2

3.4

0

18

34

48

60

100

82

66

52

40

S.G. of solids

3.6

3.8

4.0

4.3

% by wt barite

71

81

89

100

% by wt clay / drilled solids

29

19

11

0

filtrate analysis Generally, the results from the filtrate analysis will confirm the departure from normal of the values of yield point and gel strengths from rheological tests. Increases in mud volume due to liquid or gas intrusions should also be noted. Salt water flows are almost always accompanied by methane gas. Methane does not affect the chemical properties of either oil or water-based muds. Hydrocarbon gases can thin an oil-based mud through becoming dissolved in the base oil. Sour gases (i.e. hydrogen sulphide and carbon dioxide), are generally found together, although rarely in one to one proportions. When carbon dioxide is the major component of the intrusive gas, it will mask the hydrogen sulphide. The reverse, however, is not true. All salt water flows bring some calcium, magnesium, sodium and chloride ions into the mud. High concentrations of magnesium chloride in water are not uncommon in North Sea drilling. Water flows in other areas have shown high concentrations of calcium chloride. In addition to gases and liquids, soluble formation salts can contribute to the contamination of the mud system. The common ones encountered are : ƒ Halite, rock salt, (NaCl) ƒ Sylvite (KCl) ƒ Tachhydrite (2MgCl2 - CaCl2 - 12H2O) ƒ Anhydrite (CaSO4) ƒ Gypsum (CaSO4 - 2H2O) Calcite, CaCO3 (common name, limestone) and dolomite, (CaCO3 - MgCO3) are not considered chemical contaminants because their solubilities are too low. Cements are made from limestone and clay or shale. If the clay or shale does not contain enough iron and aluminium oxides, these materials are added to the cement. The finely ground raw material, either wet or dry processed, is fired in a rotary kiln and the carbon dioxide is driven off. The resultant “clinker” is finely ground and mixed with small amounts of gypsum. This is the basic “common cement”. Cement can be considered a contaminant, especially if it is entrained in a water base mud before it has hardened or set. As much as 2% borax may be found in some cements. Borax has an extreme viscosifying effect on some polymers, especially the guar family.

Section

4


Contaminants and Precipitating Chemicals Contaminant Calcium Calcium w/bicarbonate Gypsum or anhydrite Magnesium Soluble sulphides Soluble carbonate Soluble bicarbonate Phosphate Sulphate with calcium available Sodium chloride Cement

Chemical to Remove soda ash lime barium carbonate soda ash zinc oxide (OBM) zinc carbonate (WBM) zinc chelate (WBM) sodium chromate lime/caustic soda Ironite sponge lime lime lime barium carbonate Dilution sodium bicarbonate and/or chemical thinner

alkalinity Most contaminants with the exception of cement will lower the pH and/or alkalinity. Virtually all water base muds perform better on the alkaline side of neutral. In addition, corrosion is retarded by an alkaline environment. The exception is when aluminium drill pipe is being used in which case the pH is controlled below 10 to prevent attack of the metal by hydroxyl ions. Sodium carbonate (soda ash) and sodium bicarbonate precipitate soluble calcium in water-based muds. Mud properties, after a continued use of either, become difficult to control. Poor filtration control, high viscosity and gels and ineffectiveness of dispersants are a result of that treatment. The Pf-Mf test is accurate for water but because muds contain ions other than hydroxyls, carbonates and bicarbonate which interfere with the test, the back titration method (P, P1, P2) is preferred. Pm (Pmud) is the test to determine the amount of alkalinity present from soluble caustic soda and insoluble lime present in the mud. Lime reacts with sodium bicarbonate to give caustic soda and a precipitate of limestone (CaCO3). The chemical formula for this is as follows: Ca (OH)2 + NaHCO3 = CaCO3 + NaOH + H2O The pH is increased and soda ash is formed: NaOH + NaHCO3 = Na2CO3 + H2O The product soda ash reacts with lime also to give limestone: Ca (OH)2 + Na2CO3 = CaCO3 + 2NaOH Bicarbonate is converted to CO3 and OH ion alkalinity by lime treatment.

If the bicarbonate is present as calcium bicarbonate, lime treatment will remove it: Ca (OH)2 + Ca (HCO3)2 = 2CaCO3 + 2H2O Lime will not always improve unstable muds high in bicarbonate probably due to the effect of a high sodium concentration. There is no way to reduce this sodium concentration. Avoidance of long periods of treatment with soda ash or sodium bicarbonate for soluble calcium is advisable. Instead, the use of some lime is recommended. Similarly, maintenance of alkalinity with caustic soda for prolonged periods should be avoided by switching to lime or using a combination of both. ion analysis a) Chloride - Cl

In water muds, an increase in chlorides signifies the penetration of a salt water flow, formation salt, or the swabbing of a salt water sand by sudden withdrawal of the drill pipe and bit in a near gauge hole.

Generally, an increase in chlorides is accompanied by an increase in the amount of filtrate; a decrease in filtrate alkalinity, and an increase in viscosity and gels of the mud.

Dilution and restoration of the alkalinity are recommended. There is no chemical treatment to precipitate the Chloride ion to render it ineffective.

b) Sulphate - SO4 -

Sulphates are usually derived from formation waters and anhydrite or gypsum. “Gyppy” make-up water is common in wells or stock tanks. Anhydrite and gypsum are found as formations in many drilling areas. In the cap rock of salt domes, anhydrite and gypsum are commonly found. Some drilling fluid products that contain sulphates are plaster of Paris (sulphate-hemihydrate), gypsum, salt cake (sodium sulphate), and cement.

A result of excessive soluble sulphates in water-based muds is flash gels or high 10-minute gels. An oilfield term, “soda ash gels”, is derived from the addition of soda ash to a water-based mud, producing high gels when agitation ceases. The sodium ions react with soluble sulphates to cause flash thickening of some polymers and clays.

Muds treated with chemical thinner and dispersant can tolerate high sulphates. Barium carbonate can be used to convert the soluble sulphate to an insoluble precipitate of barium sulphate if enough calcium is available to react with the excess carbonate of the reaction. EPM of sulphate x 0.0346 equals the lb/bbl (x 0.0987 equals the kg/m3) of chemical treatment by barium carbonate.

The Hach Meter is preferred to the test tube estimation for determining sulphate value even though dilution of the filtrate sample is necessary.

c) Calcium and Magnesium - Ca++ and Mg++

Generally considered together, they are termed “total hardness”. Soluble calcium and magnesium are found in salts and formation waters. They are common in make-up water whether it be from the sea, producing wells, rivers, or stock ponds. The solubility of calcium is 600 - 800 ppm when derived from gypsum and anhydrite.

Section

4


Most water based muds can tolerate 200 - 400 ppm of hardness. Filtration control is affected by the calcium flocculating the clays and/or polymers in the drilling fluid. Magnesium reacts generally the same with polymers. Exceptions exist however with certain high quality PAC materials tolerating magnesium but not working very well with calcium in excess of 1,000 ppm. Calcium will affect the thinning performance of lignite also although it does not inhibit the thinning ability of ferrochrome lignosulphonate.

Calcium can be precipitated from solution by several common chemicals. The choice depends on conditions and the mud type (e.g. No hardness solubility would be anticipated in a high pH lime mud.) They are :

Salt Cake - Na2SO4

Recommended for salty muds. Does not affect magnesium. Reacts with calcium to form calcium sulphate (solubility of 600 - 800 ppm). Use only when calcium is in excess of 1000 ppm. One lb/bbl will reduce calcium by about 800 ppm. Use of salt cake in fresh water muds is not recommended for the reasons already described under “sulphate”. Salt muds are already flocculated so increase of sulphates has little effect on mud properties.

Soda Ash - Na2CO3

Forms CaCO3 (limestone). About 0.2 lb/bbl (0.571 kg/m3) for every 200 ppm of calcium

Polyphosphates

Small amount of polyphosphates are used for light calcium contamination in fresh water muds. The calcium is precipitated as an insoluble phosphate. Treatments should not in general exceed 0.5 lb/bbl (1.43 kg/m3).

Polyphosphates are unstable above 180 °F (82 °C) and can cause mud thickening.

Commonly used Polyphosphates (1% In Water) Chemical Name sodium tetraphosphate sodium hexametaphosphate (Calgon) sodium acid pyrophosphate (SAPP) tetra sodium pyrophosphate (TSPP)

10

Formula Na6P4O13

pH 7.5

(Na PO3)6

4.8

Na2H2P2O7

4.8

Na4P2O7

10.0

d) Bicarbonates, Carbonates - HCO3- , CO3-

Soluble carbonates or bicarbonates found in drilling fluids generally originate from these sources ; (1) formation carbon dioxide gas, (2) make-up water, (3) decomposition of mud products and (4) reaction products from the use of sulphide scavengers. Carbon dioxide in an alkaline environment forms bicarbonate which then proceeds to the carbonate. i.e. CO2 + OH- = HCO3- + OH- = CO3-- + H2O

Carbon dioxide is generally found along with methane and hydrogen sulphide. Although coexisting with hydrogen sulphide, it will sometimes mask it and go undetected in an alkaline environment. Taking the carbonate from the above reaction, it is believed to react in the following way: H2S + CO3-- = HS- + HCO3HS- + CO3-- = S-- + HCO3-

Raising the pH is not recommended for treatment of soluble calcium derived from cement contamination because pH is already high.

Sodium Bicarbonate - NaHCO3

Reacts with soluble calcium to form limestone. Recommended for cement contamination because pH is lowered and calcium precipitated.

Small amounts of carbon dioxide are derived from lignite subjected to high bottom hole temperatures.

Limestone - CaCO3 is almost insoluble in drilling mud, as is dolomite CaMg (CO3)2.

A build up of soluble carbonates or bicarbonates in the mud filtrate is accompanied by a drop in alkalinity, an increase in filtrate, gel strengths and yield point. (See discussion under “Alkalinity”). One reaction product of hydrogen sulphide and zinc carbonate (metallic scavenger) is a soluble carbonate. Heavy usage of scavenger with continued sulphide influx has contributed to mud instability.

Soluble carbonates and bicarbonates can be converted to insoluble calcium carbonate through the use of some form of calcium such as lime, gypsum, or calcium chloride. Generally, lime is used although the pH will be raised. The gypsum or calcium chloride will affect pH very little but will contribute sulphates and chlorides, respectively. Slight fluctuation may occur upon the entry of any of the three if reactive clay content is high.

Epm of carbonate or bicarbonate: x 0.013

=

lb/bbl

x 0.0371

kg/m3 Lime

x 0.024

lb/bbl

=

x 0.0685

kg/m3 Gyp

x 0.025

lb/bbl

=

x 0.0713

kg/m3 Calcium Chloride (78%)

11

Section

4


Carbonates, which are reacting out, are generally evidenced after several minutes of stirring through reduced viscosity and gels.

e) Sulphides - S-f) Soluble sulphides are generally derived from the sour formation gas, hydrogen sulphide. Packer fluids, but rarely drilling fluids, are attacked by sulphate-reducing bacteria which produce sulphides. Some formation waters as well as crude oil contain sulphides that can possibly contaminate muds. Some additives, such as liquid asphalt or other asphalt derivatives contain soluble sulphides.

Flocculation of clay solids, increased viscosity, yield point, gels and filter loss, are some of the effects of sulphide contamination. A decrease in alkalinity and a colour change (dark green to black) of mud, along with a rotten vegetation or rotten egg odour are common symptoms of a sulphide contaminated mud.

A useful general equation to determine the amount of H2S (ppm) a given mud can neutralise: ppm H2S = 682 (Pm) (8.33/Mud Wt) or 682 (Pm) (0.998/Mud Wt (kg/m3))

cationic exchange capacity of clays This test is based on the dye adsorption capacity of clays in mud. Methylene blue (methylthionine chloride) solution, 1 ml = 0.01 milliequivalents, is added in small increments to an acidified, diluted mud sample until an excess is reached. An excess is noted when a drop of test solution on appropriate paper seems to radiate a halo of brighter blue than the central dot. This is one of the most overlooked tests in the field but its significance related to viscosity, filtration, filter cake quality, high temperature gelation, and drilling rate is very important. Sampling and testing the cuttings using the same technique will produce an insight as to effect of the borehole on the drilling fluid. The following table is a guide for clay content of four mud types.

Recommended Bentonite Content

Mud Wt Non-dispersed low solids Fresh Water Caustic lilgnosulphonate GYP/ lignosulphonate Lignite surfactant (204 ˚C)

Mud Wt Non-dispersed low solids Fresh Water Caustic lilgnosulphonate GYP/ lignosulphonate Lignite surfactant (204 ˚C)

12

9 14 26 30 16

10 14 24 27 15

lb/bbl 11 12 14 13 22 20 24 22 14 13

15 9 14 16 10

16 8 12 14 8

lb/bbl 17 18 8 - 10 8 12 10 6 4

28.5 39.9 68.5 77.0 42.8

kg/m3 31.4 34.2 37.1 39.9 37.1 34.2 62.8 57.1 51.4 68.5 62.8 57.1 39.9 37.1 34.2

39.9 28.5 45.6 51.4 31.4

19 20 42.8 45.6 - 25.7 22.8 7 6 39.9 34.2 8 7 45.6 39.9 3 2 28.5 22.8

kg/m3 48.5 51.4 54.2 22.8 20.0 - 28.5 22.8 20.0 34.2 28.5 22.8 17.1 11.4 8.6

57.1 17.1 20.0 5.7

13 12 18 20 12

14 25.7 10 39.9 16 74.2 18 85.6 11 45.6

The solution to the problem of excessive reactive clay entrained in the drilling mud can be approached from two directions: 1. If more of the mud-making formation is to be drilled, a more inhibitive mud system would be recommended. 2. Treating the symptoms : ƒ Addition of more dispersant or deflocculant. ƒ Dilution with water. ƒ Introduction of a surfactant to coat the cuttings and reduce the activity of clays already incorporated into the system. As a general rule, 1 lb/bbl bbl (2.85 kg/m3) of the surfactant is recommended per 4 lb/bbl (11.4 kg/m3) of clay. ƒ Combinations of the above.

filtration The rate of loss through a cake is dependent upon particle size distribution in the mud and the incorporation of droplets of water and/or oil in the openings between the solids. The openings are controlled by the filtration control agents. The basic filtration control agent of many water base muds is bentonite (whether it is to be as little as 3 - 4 lb/bbl (8.56 – 11.4 kg/m3) in low solids non-dispersed muds, or as much as 25 - 35 lb/bbl (71.3 – 100 kg/m3) in seawater dispersed muds). It should be noted that to have liquid loss, a porous medium must be present. The viscosity of the filtrate has some effect also on rate of loss. Although shales are practically impermeable, hole stability in some areas is directly related to liquid loss. Some shales are micro-fractured and the migration of liquids through these passages has a lubricating effect. This effect is thought to occur in certain areas using oil base mud. When the shales are steeply-bedded, semi-collapse of the borehole has been a result of this phenomenon. In some areas the chemical nature of the filtrate, rather than the amount, is more important as related to shale stability. Importance is also attached to productivity of porous zones as affected by mud filtrates. 1. The significance of increase in filtration at room temperature and 100 psi (690 kPa) pressure is that it is associated with contaminants. ƒ Salt Water flow Increase in :

Volume Calcium Magnesium Sulphates Chlorides

ƒ Acid gases, i.e., hydrogen sulphide and carbon dioxide

Increase in : Soluble sulphides Soluble carbonates ƒ Salt stringers or salt domes

Increase in : Chlorides Calcium

13

Section

4


ƒ Gypsum of anhydrite associated with massive beds or stringers and the cap rock of salt domes Increase in : Sulphates Calcium ƒ Contaminants are often found in bulk products, such as barites and clays, due to carelessness in transportation and handling. ƒ Drilling personnel on offshore rigs have mistakenly pumped cement or seawater into the active mud system. ƒ Drilled solids, especially sand, can increase the filtrate. Some shales will reduce the filter loss. 2. Cross references to the increase in filter losses are almost always detected by increases in the viscosity measurements and in the ion analysis of the filtrate. 3. The significance of increases in bottom hole temperature. 500 psi filtration losses are generally associated with the lack of certain mud products or the thermal degradation of the products being used. The presence of oxygen with some mud materials lowers their thermal stability. However, in analysing a mud’s performance in regard to temperature, the following should be considered : ƒ Circulating temperatures never reach the bottom hole temperature. ƒ Heat transfer in mud is very slow. ƒ Unless the drill pipe is out of the hole for extended periods, mud temperature will not be in equilibrium with the formation temperature. ƒ Temperature stabilities are exceeded on the following products at the designated temperature :

Polyphosphates Starch Fermentation-resistant starch CMC PAC Xanthan gum Ferrochrome lignosulphonate Certain lignite thinners Various high temperature polymers (e.g. polyacrylates)

185 °F (85 °C) 250 °F (121 °C) 265 °F (129 °C) 275 °F (135 °C) 280 °F (138 °C) 280 °F (138 °C) 350 °F (177 °C) +400 °F (+204 °C) +400 °F (+204 °C)

ƒ The amount of clay (bentonite) should be carefully observed. Too little can give high filter losses. This can be the case where decanting centrifuges are being used on a regular basis. Excessive clays however, can produce undesirable gelation and viscosity at elevated temperatures.

static aging This test is an effort to duplicate the effect of temperature on the mud left in the hole during a trip for a new bit, a logging run, running casing, or any other extended period of time when the pumps are idle. The standard cells are normally pressured to 500 psi (3449 kPa), or less, and that, in essence, is where part of the test loses its credibility with oil muds. Tests have shown that pressure increases do not affect the viscosity of water based muds. Oil based muds become thinner at higher temperature but more viscous at higher pressures. Thus, the pressure partially offsets the effect of the higher temperature.

14

The significance of the test is that it indicates: ƒ The degree of suspension to prevent weighting materials from settling under temperature and pressure. This is very important for muds which are used as packer fluids. One of the criteria for success is being able to pull the packer without having to wash down to the top of it. ƒ The degree of trouble getting casing, logging tools, and drill bits to the bottom of the hole after extended periods without bottom hole circulation. This indicator is the shear strength of the aged sample. ƒ Thermal stability after long-term aging with regard to filter loss. This is tested by both room temperature, 100 psi psi (690 kPa) and HTHP filtrations. ƒ The effect of temperature on the mud chemicals and resulting alkalinity. ƒ The amount of fluid separating from the mud itself. This applies to oil muds only. ƒ The effect of temperature on the degree of emulsification. This refers to oil muds only and electrical stability specifically. Suspension in several water based muds is generally related to the amount and type of commercial clays used. Excessive drilled solids, bentonite, alkalinity, and temperature can form cement. Some suspension as well as temperature stability regarding fluidity can be achieved with large amounts (15 - 30 lb/bbl or 43 – 86 kg/m3) of thinner (lignite) or leonardite (brown coal). Both are aids to filtration control as well as suspension in hot holes. More modern fluids however rely solely on polymers for suspension with bentonite added only in high temperature applications to provide desired filter cake characteristics/fluid loss control. Much success has recently been experienced in large diameter hole drilling, milling operations and horizontal hole drilling using mixed metal hydroxide systems which demonstrate significantly improved suspension characteristics and superior return permeability data. Alkalinity must be maintained for good mud performance as far as corrosion, filtration, and fluidity are concerned; but excess in alkalinity leads to high temperature gelation and / or solidification. Decreasing the shear strength of a particular mud generally involves dilution, reduction of drilled solids and/or commercial clays, adjustment of alkalinity, and increase in dispersant or deflocculant. Top oil separation can be decreased by an increase of water content; additions of organophilic clays (gellants) accompanied by some fluid loss additive; certain emulsifiers. This applies to oil muds only. Reduction of gellant content and drilled solids by oil dilution, accompanied by oil mud thinner and oil wetter additions, will reduce excessive shear strengths of oil muds.

15

rheology section 5

drilling fluid rheology

section 5a - rheology of drilling fluids section 5b - rheology and hydraulics of drilling fluids

section 5a rheology of drilling fluids

section 5a

Scomi Oiltools

theory of rheology

2

rheology background

2

shear rate

3

shear stress

3

viscosity

4

fluid models

4

Herschel-Bulkley (modified power law) model

6

measurement of shear stress - shear rate

relationship

“n” and “K” constants

10

laminar and turbulent flow regimes

12

9

rheology – field application

13

plastic viscosity (pv)

13

yield point (yp)

13

gel strength

14

funnel viscosity

15

low shear rheology

16

shear rates in the drilling fluid circulating system

16

cuttings transportation theory

16

cuttings transport ratio

16

general transport ratio (gtr)

17

annular cutting concentration and optimum rop 17

Section

5a

rheology of drilling fluids


theory of rheology rheology background Rheology is derived from the Greek words rheo, meaning flow and logi, meaning science. It can be defined as the science of the deformation and/or flow of solids, liquids and gases under applied stress. In essence, the science deals with the stress-strain-time relationships of any matter. The rheological characteristics of materials form a continuous spectrum of behaviour ranging from that of the perfectly elastic solid at one extreme to that of the purely viscous Newtonian fluid at the other. Between these extremes lies the behaviour of fluids which possess varying degrees of the character of both extreme materials, such materials are termed visco-elastic. Relatively little theoretical or experimental work was done in the field of rheology until the early twentieth century. The science is in fact still in it’s infancy in terms of the ability to provide accurate predictions of the behaviour of real systems. This is particularly true with regard to both the polymer and invert oil emulsion muds being used in drilling operations today, which have far more complex behaviour than true fluids. Despite this it is still common practice to express flow characteristics in terms of simple viscosity terms such as the constants used in the Bingham Plastic and Power Law models. It is also recognized that surface measurements do not truly represent the fluid behaviour under downhole conditions at temperature and pressure, but extensive field studies have resulted in a high degree of success in predicting a fluids performance from this data. Certain basic concepts of rheology require to be understood to make optimum use of collected data. Of these concepts the relationship between shear stress and shear rate is most important in predicting drilling fluid behaviour. Knowledge of the flow characteristics of circulating fluids is of advantage in almost all phases of down hole operations. Some of the more important applications relate to selection and design of fluids to obtain optimum rates of circulation to transport and suspend drill cuttings, increase drilling rates and reduce hole erosion. In the drilling situation the application of rheological concepts for drilling fluids are primarily directed towards:

a) Suspension. b) Hydraulic calculations. c) Hole cleaning and hole erosion. d) Filtrate migration. e) Solids Control.

Although these applications may be of equal importance, drilling requirements vary with time and location so that one may take precedence over another at a particular time. In all applications, whether or not a fluid performs a specific function can be attributed to the absence or presence of viscosity at the shear rate of interest.

shear rate In a moving fluid shear rate can be defined as the rate at which one layer of fluid is moving by another layer divided by the distance between the layers. It is the velocity gradient i.e. the ratio of velocity to distance between layers. Consider a fluid between two flat plates one centimetre apart. If the bottom plate is fixed while the top plate slides parallel to it at a constant velocity of 1 cm per sec, a velocity profile will be found within the fluid. The fluid layer in contact with the bottom plate is static while the layer in contact with the top plate is moving at 1 cm per sec. Halfway between the plates the fluid velocity is the average 0.5 per sec. If a moving layer of fluid has a velocity 1cm/sec relative to a static layer at separation distance of 1cm then the shear rate between these layers will be: 1 cm/sec 1cm

= 1 sec –1

The reciprocal second is the standard unit of shear. In a drilling fluid circulating system the shear rate is determined by the flow rate through a particular geometrical configuration. Since the relative velocity between fluid layers is greatest adjacent to the pipe or hole wall the shear rate is highest at this point. An average shear rate may be used, but the shear itself is not constant everywhere in the flow.

shear stress Shear Stress is defined as the force required to move a given area of the fluid. In this case one Newton is required for each square meter of area. The units of shear stress are Newtons per square metre, also known as Pascals. Alternative units for shear stress are dynes per square centimetre and pounds force per square inch. Shear stress is related to the force required to sustain fluid flow. In a drilling fluid circulating system this is analogous to the pump pressure.

This diagram shows the forces acting on a theoretical liquid. The liquid is contained between the two 1 square metre plates which are separated by one metre. The bottom plate is stationary and the top plate is moved at a rate of 1 metre per second. The amount of force required to maintain this movement is measured in Newtons. In a drilling fluid circulating system the shear rate is determined by the flow rate through a particular geometrical configuration. Since the relative velocity between fluid layers is greatest adjacent to the pipe or hole wall the shear rate is highest at this point. An average shear rate may be used, but the shear itself is not constant everywhere in the flow. If, in the parallel plate example used to describe shear rate, a force of 1.0 dyne was applied to each square centimetre of the top plate to keep it moving. Then the shear stress would be 1.0 dyne per cm2. The same force in the opposite direction would be needed on the bottom plate to keep it from moving. The same shear stress would be found at any level in the fluid. Shear stress is constant only as long as the flow system geometry is constant. It is more common to find the shear stress varying from one part of a flow system to another.

Section

5a


The units of shear stress are the same as for pressure, but whereas pressure defines the applied force per unit area, shear stress is the internal resistance to an applied stress. Shear stress can be expressed: shear stress = F/A Where

F = force A = area of surface subject to stress.

The standard unit of shear stress is dynes/cm2

Shear rate and shear stress are the two basic quantities involved in the sliding (shearing) flow of a fluid. Then shear rate is related to the velocity of motion and the shear stress to the forces being transmitted both to the fluid and from one part of a fluid to another.

viscosity Viscosity can be described as the resistance to flow and is defined as the ratio of shear stress to shear rate shear stress.dynes/cm2 Viscosity= = Poise shear ratesec–1 Viscosity = shear stress dynes / cm2 = Poise Shear rate sec–1 The units of Poise are too large for drilling fluid studies and viscosity is reported in centipoises or millipascal.second (1cP = 1 mPa.s). Since viscosity is dependent on both shear rate and shear stress, one or the other must be specified when a viscosity measurement is stated. Shear rate is the usual variable defined, either as an actual shear rate in reciprocal seconds or as speed in rpm from a concentric cylinder viscometer.

fluid models Fluids can be separated into different classes according to the relationships which exists in a fluid between shear rate and shear stress. The most simple class of fluids are called Newtonian. Water and light oils are examples of Newtonian fluids.

In these fluids the shear stress is directly proportional to the shear rate. When the shear rate is doubled the shear stress is doubled i.e. when the circulation rate is doubled the pressure required to pump the fluid is doubled. Such fluids have a constant viscosity. For most fluids, viscosity is not a constant, but varies with the shear rate. Such non Newtonian fluids are called rate dependent. Almost all drilling fluid viscosifiers provide rate dependent fluids. To illustrate rate dependent effects a fluid is tested for shear stress or viscosity at a number of shear rates. When these data are plotted on a log-log scale a viscosity profile of the fluid is obtained. Examples of types of flow are:

The shear rate / shear stress ratio of non Newtonian fluids is not constant, which is true of most drilling fluids. The two most popular mathematical models for describing non-Newtonian drilling fluids are called the Bingham Plastic model and Power Law model.

SHEAR STRESS,

t

Non Newtonian Fluid Behaviour

SHEAR RATE

g,

Section

5a


Some fluids have a critical yield stress which must be exceeded before flow is initiated. If the fluid has essentially Newtonian flow after the yield stress is exceeded it is termed a Bingham Plastic fluid. The major shortcoming of the application of this model to drilling fluids is that it only describes fluid flow over a short shear rate range of 511 - 1022 sec-1. Consequently the Bingham model may not accurately describe fluid rheological characteristics in all drilling situations. Most drilling fluids are Pseudoplastic. In this case increased shear rate produces a progressive decrease in viscosity. In polymer solutions this is due to the alignment of the long polymer chains along the flow lines. If the application of any shear stress above zero produces fluid flow, i.e. no critical yield stress, the fluid is termed a Power Law fluid. This model more accurately describes flow characteristics of drilling fluids over the shear rate ranges experienced in the annulus of a well bore. Polymeric drilling fluids can be shown to follow the Power Law model very closely. Some other fluids show a profile which falls between Power Law and Bingham Plastic. Although the API has selected the Power Law model as the standard model, the Power Law model, however, does not fully describe drilling fluids because it does not have a yield stress and underestimates low shear rate viscosity. The modified Power Law or Herschel-Bulkley model can be used to account for the stress required to initiate fluid movement (yield stress).

The diagram shows the differences between the modified Power Law, the Power Law and Bingham Plastic models. The modified Power Law falls between the Bingham Plastic model, which is highest, and the Power Law, which is lowest and consequently more closely resembles the flow profile of a typical drilling mud.

Herschel-Bulkley (modified power law) model In reality, most drilling fluids have a yield stress. The Herschel-Bulkley or the modified power law is the best model to precisely describe the rheological behaviour of drilling fluids compared to any other models. It is a three parameter model that reproduces the results of the previous models (Bingham Power Law, Newtonian) when the appropriate parameters have been measured. The Herschel-Bukley model uses the following equation to describe fluid behaviour:

t = t o+ (K

x

gn)

Where t = shear stress in lb/100 ft2 t o = fluids yield stress (shear stress at zero shear rate) in lb/100 ft2 K = fluids consistency index in cP - secn or lb - secn/100 ft2 n = fluids flow index g = shear rate in sec-1 In Herschel-Bulkley model, the K and n values are worked out differently than their counterparts in the power law model. The Herschel-Bulkley reflects more to Bingham model when n = 1 and it reflects to the power law model when τ0 = 0. [One obvious advantage the Herschel-Bulkley model has over the power law model is that, from a set of data input, only one value for n and K are calculated.] Hydraulics calculations for Herschel-Bulkley (modified power law) fluids cannot be solved by simple equations. For quick solutions, consult the Scomi Oiltools hydraulics programs using HyPR-CALC. Calculated Results Rheology Model

YP (Ibf/100ft2)

Newtonian Bingham-Plastic Power-Law Herschel-Bulkley

0 13.1257 0 10.9075

Vis., PV or K (cp) 46.8023868 37.2818854 2842.1364294 97.1097869

n

Standard Deviation

1 1 0.3578 0.8627

3.9039 0.7181 3.6169 0.1644

Draw Curve

3

Figure 1: Calculated rheology model in “HyPR-CALC”

Viscometer Reading

100 90 80 70 60 50 40 30 20 10 0

Measurement Newtonian Herschel-Bulkley

0

100

200

300

400

500

600

Speed (rpm) Figure 2: Rheology models available in Scomi Oiltools hydraulic program “HyPR-CALC” Herschel-Bulkley graph usually reflects a yield stress where the shear stress is greater than zero where as a Newtonian graph is usually a straight line that originates from shear stress equal to zero.

Section

5a


Invert emulsion muds are suspensions of both solids and emulsions and there is no accepted rheological model that can be applied to both emulsions and suspensions, in addition these fluids show pronounced pressure and temperature effects. A Casson Model is sometimes used to describe invert fluids though some oil muds can be shown to follow the Bingham Plastic model between shear rates of 127- 340 sec–1 (75-250 rpm). Below 127–1 the characteristics lie between Power Law and Bingham Plastic. The Newtonian, Bingham Plastic, and Power Law models are specific cases of the Robertson-Stiff model. It is a three parameter model that includes the 3 rpm rheometer dial reading and is written in its general form as: t = K(g 0 + g)n To use common rheometer data for the analysis of a fluid conforming to the Robertson-Stiff model, the general equation becomes

t1 t2

1 n

N3 - N2 N3 – N1

+

t3 t2

1 n

N2 - N1 N3 – N1

=1

Where: N3, N2, and N1 are rpm speeds and N3 > N2 > N1, t3, t2, and t1 are rheometer sheer stress readings at N3, N2, and N1, respectively. This equation must be solved iteratively to find n. g0 and k can then be calculated by solving the following equations.

30 ln(b)

ln(b) where b = the ratio of the rheometer sleeve radius to the bob radius. The Robertson-Stiff equation will generally provide the best approximation for pressure losses in the circulating system in most drilling situations. It will not, however, emulate a fluid that follows the Casson equation. If a fluid profile shows a critical yield stress and then flows like the pseudoplastic model it is referred to as an Ellis fluid. This model has been used to describe Xanthan Gum solutions. The yield stress is equivalent to the elastic modulus of the solution. Some rare fluids show Dilatant or reverse pseudoplastic behaviour. These are characteristically suspensions having a high solids loading e.g. high concentration gypsum suspensions. These fluids increase in viscosity with increasing shear rate and can show a negative calculation of yield point, the true figure is zero.

Besides shear rate dependent effects some fluids can also exhibit time dependent effects. In these cases the viscosity changes with continued shear at constant rate. Time Dependent Effects

VISCOSITY

RHEOPECTIC

THIXOTROPIC

TIME

Fluids which are thixotropic in nature decrease in viscosity with time. This type of fluid shows a memory effect or hysteresis when subjected to varying rates of shear. There is a time lag in establishing an equilibrium viscosity when the shear rate is changed, the fluid will initially tend towards to the viscosity associated with the previous shear rate. Some highly concentrated suspensions can display herpetic flow. In this case the viscosity of the fluid will increase with time at a constant shear rate.

measurement of shear stress - shear rate relationship. The most commonly used instrument for the rheology evaluation of a drilling fluid is the concentric cylinder or cup and bob viscometer. This is typically a Fann 35A six speed model. In operation the rotor and bob is immersed in the fluid sample and the rotor is turned at a constant speed. The fluid’s resistance to flow imparts a torque on the bob which deflects the dial proportionally to the viscous properties of the fluid. The geometry of rotor and bob determines the shear rates obtainable with this viscometer. The standard rotor – bob combination has a 0.117cm gap and the conversion of rpm to shear rate in sec–1 is given by the formula Shear rate (sec–1) = rpm x 1.703 The shear stress from this instrument is taken from the dial reading R. Shear Stress (lb/100ft2) = R x 1.067 Shear Stress (dynes/cm2) = R x 5.1

Section

5a


The six speeds of the Fann 35A and the corresponding shear rates are:600 rpm - 1022.0 sec–1 300 rpm - 511.0 sec–1 200 rpm - 340.7 sec–1 100 rpm - 170.3 sec–1 6 rpm - 10.22 sec–1 3 rpm - 5.11 sec–1 In order to obtain accurate correlations, it is important that viscometer readings are taken at the same temperature, normally 120 ˚F (49 °C). Using the Bingham Plastic model for data interpretation, the following values are reported. PV = YP =

R600 reading – R300 reading R300 reading – PV or (R300 reading – PV) x 0.48 in Pa Bingham Plastic Model Parameters

Shear Stress, t

PV

YP

300

600

Shear Rate (RPM), g

The Bingham values PV and YP give a poor definition of the flow characteristics of the fluid over a wide shear range, but shear stress values at all six speeds can be converted to viscosity values for the six shear rates and plotted on a log/log viscograph. This gives a good viscosity profile in a form readily correlated with the various shear ranges experienced in the circulating system and solids control equipment. Measurement of initial gel strength is indicative of the elastic modulus and hence suspension characteristics of the fluid and the relationship of initial and 10 minute gel strength illustrates the degree of thixotropy present. The R6 value is directly relevant to annular viscosity of some hole diameters and this value is increasingly being used as a control parameter in ensuring good hole cleaning properties.

“n” and “K” constants Although the Bingham Model constants, PV and YP are the most widely used properties for evaluating drilling fluid rheology, it has to be recognised that this model does not always accurately predict drilling fluid performance. This applies in particular to annular rheological calculations.

10

Shear Stress v Shear Rate

The Power Law Model more closely approximates to the actual drilling fluid, in particular to low solids polymer based systems. This model can be calculated over the annular region (normally less than 100 rpm or 150 sec–1 shear rate), it will more accurately predict a drilling fluids performance. Power Law Model τ = K g n Where

τ = shear stress dynes / cm2 K = Consistency index dynes secn/ cm2 g = Shear rate sec–1 n = Power Law Index

The “n” constant indicates the degree of non-Newtonian character that a fluid exhibits over a defined shear rate range. Newtonian Fluids have an “n” value of equal to one. As “n” decreases from one the fluid becomes more pseudoplastic or shear thinning with increase in shear rate. Lowering the “n” value improves hole cleaning performance by increasing the effective annular viscosity and flattening the annular velocity profile. This reduces any turning effect on cuttings, helping to prevent particle breakage and moves the solids more directly up the hole. The “n” constant is dependant upon the type of viscosifier used. Every material has an inherent “n” constant, but it may vary with concentration and shear rate. Xanthan Gum provides the lowest “n” constant, the only material providing a similar value being extended bentonite.

11

Section

5a


“K” the consistency index is the shear stress or viscosity of the fluid at a shear rate of one sec–1 . It relates directly to the system viscosity at low shear rates. An increase in “K” raises the effective annular viscosity and therefore the hole cleaning capacity. It can also increase, however, the bit viscosity and circulating pressure loss. The “K” constant is controlled by both the type of viscosifier and the total solids content of the fluid. It will increase with decrease in the “n” constant or by increase in solids concentration. “K” can be reported as dynes/cm2 secn or lbs/100ft2 secn. An increase in “K” value should if possible be obtained via a decrease in “n” value to avoid increasing the circulating system viscosity. The “n” and “K” values can be calculated from any two viscometer dial readings. For Hydraulic calculations determining “n” and “K” in the range of interest (i.e. 5 -150 sec–1 for annular calculations) will provide more accurate results. " n"=

)

log (rpm2 ÷rpm1)

" K"=

where:

(

log R2 ÷ R 1

5.11R2

(1.7 rpm 2 )

n

R1 = Dial reading at rpm1 R2 = Dial reading at rpm2

laminar and turbulent flow regimes Single phase flow can be either laminar or turbulent. In a drilling situation it is usually important to know which of these two flow regimes are present in a hole interval. In laminar flow, motion is parallel to the walls of the flow channel. The particles of fluid move in straight lines or in long smooth curves. Flow tends to be laminar when it is slow or the fluid is viscous. In laminar flow the force required to move the fluid increases with increase in the velocity and viscosity. In turbulent flow the fluid is continually swirling and eddying as it moves along the flow channel. There is an average movement of the fluid in a particular direction but individual particles of the fluid move along in random loops and circles. In turbulent flow these velocity fluctuations arise spontaneously and are not caused by wall projections or changes in direction. These factors can however increase the degree of turbulence. Flow tends to be turbulent when the flow is rapid or when the fluid has low viscosity. In turbulent flow, the force required to move the fluid increases linearly with density and as the square of viscosity. Transition Velocity - The flow of any particular fluid in any particular flow channel can be either laminar or turbulent. At low velocities, the flow will be laminar. If the velocity of a fluid in laminar flow is increased, the flow at some point will suddenly become turbulent. If the velocity is reduced again, the flow will return to it’s laminar character. Thus for any particular system there will be a transition velocity where the flow shifts between laminar and turbulent. The transition between laminar and turbulent flow occurs because the inertial forces vary as the square of the flow rate, while viscous forces vary only as the flow rate. The ratio of inertial forces to viscous forces is the Reynolds Number.

12

In general laminar flow is the desired regime, but exceptions occur where turbulent flow is desired for specialized applications e.g. turbulent sweeps to remove cutting beds and clean out enlarged hole sections. Turbulent flow is often chosen by preference to drill horizontal intervals. Turbulent flow however, does give larger annular pressure losses, increased wellbore erosion and cause drill cutting attrition through the tumbling effect in the annulus. In a turbulent regime the fluid viscosity has no contribution to hole cleaning, but the viscosity of a fluid determines whether a flow regime is turbulent or laminar for a given velocity and hole diameter.

rheology – field application plastic viscosity (pv) Drilling muds are usually composed of a continuous fluid phase in which solids are dispersed. Plastic viscosity is that part of the resistance to flow caused by mechanical friction. The friction is caused by: ƒ Solids concentration. ƒ Size and shape of solids. ƒ Viscosity of the fluid phase. For practical field applications, plastic viscosity is regarded as a guide to solids control. Plastic viscosity increases if the volume percent of solids increases or if the volume percent remains constant, and the size of the particle decreases. Decreasing particle size increases surface area, which increases frictional drag. Plastic viscosity can be decreased by decreasing solids concentration or by decreasing surface area. Plastic viscosity is decreased by reducing the solids concentration by dilution or by mechanical separation. As the viscosity of water decreases with temperature, the plastic viscosity decreases proportionally. Therefore, controlling PV of a mud in practical terms involves controlling size, concentration and shape of the solids and minimising the viscosity of the liquid phase - such as avoiding viscosifying polymers and salts unless absolutely needed. The value of plastic viscosity is obtained by subtracting the 300 rpm reading from the 600 rpm reading: PV = 600 rpm reading – 300 rpm reading PV of a mud is the theoretical minimum viscosity a mud can have because it is the effective viscosity as shear rate approaches infinity. The highest shear rate occurs as the mud passes through the bit nozzles; therefore, PV will approximate the mud’s viscosity at the nozzles.

yield point (yp) The yield point is the initial resistance to flow caused by electrochemical forces between the particles. This electrochemical force is due to charges on the surface of the particles dispersed in the fluid phase. Yield point is a measure of these forces under flow conditions and is dependent upon: ƒ ƒ ƒ

The surface properties of the mud solids The volume concentration of the solids and Ionic environment of the liquid surrounding the solids

13

Section

5a


High viscosity resulting from high yield point is caused by: ƒ Introduction of soluble contaminant (ions) such as: salt, cement, anhydrite or gypsum, which interact with the negative charges on the clay particles. ƒ Breaking of the clay particles through mechanical grinding action creating new surface area of the particles. These new charged surfaces (positive and negative) pull particles together as a floccs. ƒ Introduction of inert solids (barite) into the system, increasing the yield point. This is the result of the particles being forced closer together. Because the distance between the particles is now decreased, the attraction between particles is greatly increased. ƒ Drilling hydratable shales or clays which introduces new, active solids into the system, increasing attractive forces by bringing the particles closer together and by increasing the total number of charges. ƒ Insufficient deflocculant treatment. Yield point can be controlled by proper chemical treatment. As the attractive forces are reduced by chemical treatment, the yield point will decrease. The yield point can be lowered by the following methods: ƒ Charges on the positive edges of particles can be neutralised by adsorption of large negative ions on the edge of the clay particles. These residual charges are satisfied by chemicals such as: tannins, lignins, complex phosphates, lignosulphonate, etc. The attractive forces that previously existed are satisfied by the chemicals, and the negative charge of the clay particles predominates, so that the solids now repel each other. ƒ In the case of contamination from calcium or magnesium, the ions causing the attractive force are removed as insoluble precipitants, thus decreasing the attractive forces and YP of the mud. ƒ Water dilution can lower the yield point, but unless the solids concentration is very high, it is relatively ineffective. Yield point (YP) is calculated from VG measurements as follows: YP = 300 rpm reading – (600 rpm reading - 300 rpm reading) YP = 300 rpm reading – PV or YP = (300 rpm reading – PV) x 0.48 in Pa

The limitation of the Bingham plastic model is that most drilling fluids, being pseudoplastic, exhibit an actual yield stress which is considerably less than calculated Bingham yield point. This error exists because the Bingham plastic parameters are calculated using a VG meter at 600 rpm (1022 sec-1) and 300 rpm (511 sec-1); whereas, typical annular shear rates are much less (Table 1).

gel strength Gel strengths, 10-second and 10-minute, measured on the VG meter, indicate strength of attractive forces (gelation) in a drilling fluid under static conditions. Excessive gelation is caused by high solids concentration leading to flocculation.

14

Types of Gel Strengths Diagram (to convert to Pa multiply gel strength by 0.48)

Signs of rheological trouble in a mud system often are reflected by a mud’s gel strength development with time. When there is a wide range between the initial and 10-minute gel readings they are called “progressive gels”. This is not a desirable situation. If initial and 10-minute gels are both high, with no appreciable difference in the two, these are “high-flat gels”, also undesirable. The magnitude of gelation with time is a key factorin the performance of the drilling fluid. Gelation should not be allowed to become much higher than is necessary to perform the function of suspension of cuttings and weight material. For suspension “low-flat gels” are desired. Excessive gel strengths can cause: ƒ Swabbing, when pipe is pulled. ƒ Surging, when pipe is lowered. ƒ Difficulty in getting logging tools to bottom. ƒ Retaining of entrapped air or gas in the mud. ƒ Retaining of sand and cuttings while drilling. Gel strengths and yield point are both a measure of the attractive forces in a mud system. A decrease in one usually results in a decrease in the other; therefore, similar chemical treatments are used to modify them both. The 10-second gel reading more closely approximates the true yield stress in most drilling fluid systems. Water dilution can be effective in lowering gel strengths, especially when solids are high in the mud.

funnel viscosity The funnel viscosity is measured with the Marsh funnel and is a timed rate of flow in seconds per quart. It is basically a quick reference check that is made routinely on a mud system; however, there is no shear rate/shear stress relationship in the funnel viscosity test. Thus, it cannot be related to any other viscosity nor can it give a clue as to why the viscosity may be high or low.

15

Section

5a


low shear rheology While many invert emulsions, particularly high o/w ratio formulations, approximate Bingham plastic behaviour at shear rates most commonly examined (600 & 300 rpm) they do not maintain this behaviour as shear rates decrease. This is of particular importance when studying hole cleaning with inverts particularly in large diameter holes where annular shear rates are low. The use of Yield Point derived from 600 & 300 viscometer readings can be misleading when considering efficient hole cleaning particularly in large diameter or deviated holes. Both experimental and field data have shown that it is of great importance to study the viscosity at shear rates nearer to those prevailing at the wall of the hole. The 6 rpm reading, equivalent to a shear rate of 10.2 sec-1, is the best approximation of low annular shear rate for fluids in laminar flow available on a standard V-G meter. This shear rate of 10.2 sec-1 is equivalent to a mean annular velocity of 53 ft/min (16.2 m/min) in 17 1/2” hole. The following rule of thumb for 6 rpm readings for fluids in laminar flow is useful: Hole deviation

0 - 45° 45 - 90°

1.0 x Hole Diameter (inches) 1.2-1.5 x Hole Diameter (inches)

In water based fluids, increases in low shear viscosities are best achieved with biopolymers e.g. XCD, Rhodopol. In invert emulsions the required 6 rpm readings can usually be attained with the normal organophilic clay viscosifiers. Several rheology modifiers are currently available which claim to boost low end viscosity without greatly altering overall viscosity. The success of these products appears to vary greatly with base oil type hence laboratory pilot testing is necessary before inclusion in invert formulations.

shear rates in the drilling fluid circulating system. Shear rates present in the circulating system of a drilling operation usually fall within the following ranges. Shear Rate Mud Pits 1 - 5 sec -1 Annulus 5 - 170 sec -1 Solids Removal Equipment 170 -10,000 sec -1 Bit 10,000 - 100,000 sec -1

V-G Meter rpm 0-3 3 - 100 100 - 600 (+) N/A

cuttings transportation theory cuttings transport ratio Cuttings transport ratio is the ratio of the cuttings transport velocity (Vt) and the mean annular velocity (Va). Cuttings transport velocity is the difference between the mean annular velocity and the cuttings slip velocity (Vs). Transport Ratio (Tm)

= Vt / Va = (Va - Vs) / Va = 1 - Vs/Va

This ratio is a measure of the effectiveness of hole cleaning. Any positive value indicates that some cuttings will be removed. A value of 100% indicates the removal of all cuttings from the hole. Any value in excess of 75% is generally considered to indicate efficient hole cleaning.

16

Slip Velocity

=

Where

= Particle diameter (cm) = Particle density (kg/m3) = Fluid density (kg/m3) = Fluid viscosity (cps) (Equivalent thickness)

Dp Pp Pf u

The above equation approximates to slip velocity, in fact the equation varies with Reynold’s number. Many PC and hand held calculator programmes exist for slip velocity calculations and first principle calculations for all cases will not be given here. It suffices to say that in all cases slip velocity can be reduced by increasing viscosity and fluid density, or by reducing particle size (by bit selection). The most practical approach is to increase fluid viscosity bearing in mind that this will increase ECD, and oil retention figures and hinder efficient solids removal. It can be seen from the second equation that the transport ratio can be increased by increasing annular velocity or by decreasing slip velocity.

general transport ratio (gtr) The application of Cuttings Transport Ratio, in hole cleaning calculations works well in vertical holes, but its effectiveness is reduced as hole angle increases. To allow for this fact, in calculations of optimum rates of penetration a constant (the GTR) is required and has been determined by experimentation to fall within the following range:

Hole Angle GTR

0 1.0

20 0.8

30 0.5

40 0.3

50 0.25

60 0.2

annular cutting concentration and optimum rop It is generally accepted that the recommended cuttings concentration in the annulus should not exceed 4% v/v and that an optimum ROP should be employed to achieve this figure is not exceeded. The optimum ROP is calculated as follows: -

where F = cuttings concentration (0.04) Tm = cuttings transport ratio GTR = general transport ratio

17

section 5b rheology and hydraulics of drilling fluids

section 5b

Scomi Oiltools

bit hydraulics

2

equivalent circulating density

3

power law inside the drillpipe for each hydraulic interval

3

power law inside the annulus for each hydraulic interval

4

bingham-plastic inside the drillpipe for each hydraulic interval

6

bingham-plastic inside the annulus for each hydraulic interval

7

Section

5b

rheology and hydraulics of drilling fluids


Bit hydraulics Nozzle area AN (in 2 ) =

∑ (Jet ) × 0.000767 n

2 i

i =l

Nozzle velocity POGPM × 0.32

V N ( ft / sec ) =

AN

Bit pressure drop PD Bit (psi ) =

V N2 × ρ 1120

Bit hydraulic horsepower HHPBit (hp ) =

PD Bit × POGPM 1714

Bit hydraulic horsepower per unit bit area HHP / area =

HHPBit ABit

Percent pressure drop at bit PD Bit × 100 Pr ess Pump

Jet impact force Im p Bit (lbf ) = Where ρmud Presspump POGPM Jeti ABit AN VN PDBit

V N × POGPM × ρ mud 1932

= Mud density in lb/gal = Pump press in psi = Pump output in gal/min = Nozzle diameter in 32nds of an inch = Area of the bit = Total nozzle area in in2 = Nozzle velocity in ft/sec = Bit pressure drop in psi

Equivalent circulating density The following formulas can be used to calculate pressure drop (PD) and equivalent circulating density (ECD). Where PDa n Li LVI ρmud

= pressure drop in the annulus in psi = number of intervals = length of intervals in feet = vertical length of the interval in feet = density of mud in lb/gal

The sum of the pressure drops for each annular section (regardless of hole angle) is: PD a =

∑

n

i =l

PDi

The equivalent circulating density (ECD) for any vertical wellbore is:   ECD =  

   + ρ mud n Li × 0.052  i =l  PD a

∑

In deviated wellbores, the TVD must be taken into account when calculating ECD values. The above equation then becomes:   PD a   ECD =  n  + ρ mud  i = l LV i × 0.052 

∑

Power Law inside the drillpipe for each hydraulic interval Average velocity inside the drillpipe (Vp) V p ( ft / sec ) =

Where IDDP POGPM Vp

POGPM × 0.408 2 ID DP

= inside diameter of drillpipe or drill collar in in2 = pump output in gal/min = average mud velocity inside drillpipe in ft/sec

Reynolds number (NRep) 2− n p

N Re p =

Where IDDP Kp ρmud np Vp

89,100 × ρ mud × V p Kp

 0.0416 ID DP   3 +1 n p 

   

np

= inside diameter of drillpipe or drill collar in in2 = consistency index in drillpipe, eq cP = mud density in lb/gal = flow index n inside drillpipe = average mud velocity inside drillpipe in ft/sec

Section

5b


Friction factor (f) If the Reynolds number is greater than 2100 the flow is turbulent and the friction factor is: a f = (N RE ) b Where a=

log n + 3.93 50

b=

1.75 − log n 7

If the Reynolds number is less than 2100 the flow is laminar and the friction factor is: f =

16 N RE

Turbulent flow pressure drop PD p =

Where IDDP fp L ρmud Vp

f p × ρ mud × V p2 25.8 ID DP

×L

= inside diameter of drillpipe or drill collar in in2 = friction factor inside drillpipe = length of drillpipe in feet = mud density in lb/gal = average mud velocity inside drillpipe in ft/sec

Laminar flow pressure drop

PD p =

Where IDDP Kp np ρmud Vp

n  3 +1 n p K p × V p p   0.0416

(1+ n p )

144,000 ID DP

   

np

×L

= inside diameter of drillpipe or drill collar in in2 = consistency index inside drillpipe, eq cP = flow index n inside drillpipe = mud density in lb/gal = average mud velocity inside drillpipe in ft/sec

Power Law inside the annulus for each hydraulic interval Average velocity inside the annulus (Va) V a ( ft / sec ) =

Where IDHOLE ODDP POGPM Va

POGPM × 0.408 2 2 ID HOLE − OD DP

= diameter of borehole or inside diameter of casing in in2 = outside diameter of drillpipe or drill collar in in2 = pump output in gal/min = average mud velocity inside drillpipe in ft/sec

Reynolds number (NRea) N Re a =

109,100 × ρ mud × V a2 − na  0.0208(ID HOLE − OD DP )     K 2 +1 n p

Where IDHOLE ODDP Ka ρmud na Va

na

a

= diameter of borehole or inside diameter of casing in in2 = outside diameter of drillpipe or drill collar in in2 = consistency index in annulus, eq cP = mud density in lb/gal = flow index n inside annulus = average mud velocity inside drillpipe in ft/sec

Friction factor (f) If the Reynolds number is greater than 2100 the flow is turbulent and the friction factor is: a f = (N RE ) b Where a=

log n + 3.93 50

b = 1.75 − log n 7

If the Reynolds number is less than 2100 the flow is laminar and the friction factor is: 16 f = N RE

Turbulent flow pressure drop in annulus PDa =

Where IDHOLE ODDP fa L ρmud Va

f a × ρ mud × V a2 ×L 21.1(ID HOLE − OD DP )

= diameter of borehole or inside diameter of casing in in2 = outside diameter of drillpipe or drill collar in in2 = friction factor inside annulus = length of drillpipe in feet = mud density in lb/gal = average mud velocity inside annulus in ft/sec

Laminar flow pressure drop in annulus PD a =

Where IDHOLE ODDP Ka na ρmud Va

 2 + 1 na K a × V ana   0.0208

  

np

(1+ na )

144,000(ID HOLE − OD DP )

×L

= diameter of borehole or inside diameter of casing in in2 = outside diameter of drillpipe or drill collar in in2 = consistency index inside annulus, eq cP = flow index n inside annulus = mud density in lb/gal = average mud velocity inside annulus in ft/sec

Section

5b


Bingham-plastic inside the drillpipe for each hydraulic interval Average velocity inside the drillpipe (Vp) V p ( ft / sec ) =

Where IDDP POGPM Vp

POGPM × 0.408 2 ID DP

= inside diameter of drillpipe or drill collar in in2 = pump output in gal/min = average mud velocity inside drillpipe in ft/sec

Determine whether the flow is laminar or turbulent.

Calculate the Hedstrom number in the drillpipe (NHep) N Hep =

Where ρmud IDDP Vp YP PV

2 37,000 × ρ mud × YP × ID DP

PV 2

= mud density in lb/gal = inside diameter of drillpipe or drill collar in in2 = average mud velocity inside drillpipe in ft/sec = yield point in lb/100 ft2 = plastic viscosity in Cp

Determine critical Reynolds number (NRec) from figure 1 (page 8) using the calculated Hedstrom number

Calculate the Reynolds number in the drillpipe (NRep) N Re p =

Where ρmud IDDP Vp YP PV

928 × ρ mud × V p × ID DP PV

= mud density in lb/gal = inside diameter of drillpipe or drill collar in in2 = average mud velocity inside drillpipe in ft/sec = yield point in lb/100 ft2 = plastic viscosity in cP

If NRep < NRec, the flow is laminar. If NRep > NRec, the flow is turbulent.

Turbulent flow pressure drop PD P =

ρ Vp PV IDDP L

ρ 0.75 × V p1.75 × PV 0.25 .25 1800 × ID 1DP

×L

= mud density in lb/gal = average mud velocity inside drillpipe in ft/sec = plastic viscosity in Cp = inside diameter of drillpipe or drill collar in in2 = length of the drillpipe in feet

Laminar flow pressure drop Where Vp YP IDDP L PV

 PV × V p YP PD P =  +  1500 × ID 2 225 × ID DP DP 

 × L  

= average mud velocity inside drillpipe in ft/sec = yield point in lb/100 ft2 = inside diameter of drillpipe or drill collar in in2 = length of the drillpipe in feet = plastic viscosity in cP

Bingham-plastic inside the annulus for each hydraulic interval Average velocity inside the annulus (Va) V a ( ft / sec ) =

Where IDHOLE ODDP POGPM Va

POGPM × 0.408 2 2 ID HOLE − OD DP

= diameter of borehole or inside diameter of casing in in2 = outside diameter of drillpipe or drill collar in in2 = pump output in gal/min = average mud velocity inside annulus in ft/sec

Determine whether the flow is laminar or turbulent

Calculate the Hedstrom number in the annulus (NHea) 24,700 × ρ mud × YP × (ID HOLE − OD DP )

2

Where IDHOLE ODDP YP PV ρmud

N Hea =

PV 2

= diameter of borehole or inside diameter of casing in in2 = outside diameter of drillpipe or drill collar in in2 = yield point in lb/100 ft2 = plastic viscosity in cP = mud density in lb/gal

Determine critical Reynolds number (NREC) from figure1 using the calculated Hedstrom number

Calculate the Reynolds number in the annulus (NRea) Where ρmud Va IDHOLE ODDP PV

N Re a =

757 × ρ mud × V a × (ID HOLE − OD DP ) PV

= mud density in lb/gal = average mud velocity inside annulus in ft/sec = diameter of borehole or inside diameter of casing in in2 = outside diameter of drillpipe or drill collar in in2 = plastic viscosity in cP

If NRea < NRec, the flow is laminar. If NRea > NRec, the flow is turbulent.

Section

5b


Turbulent flow pressure drop in annulus PD a =

Where ρmud Va PV IDHOLE ODDP L

0.75 ρ mud × V a1.75 × PV 0.25

1396 × (ID HOLE − OD DP )1.25

×L

= mud density in lb/gal = average mud velocity inside annulus in ft/sec = plastic viscosity in cP = diameter of borehole or inside diameter of casing in in2 = outside diameter of drillpipe or drill collar in in2 = length of the drillpipe in feet

Laminar flow pressure drop in annulus Where PV YP Va IDHOLE ODDP L

� � PV × V a YP �×L PD P = � + 2 � 1000(ID 200(ID HOLE − OD DP )�� HOLE − OD DP ) �

= plastic viscosity in cP = yield point in lb/100 ft2 = average mud velocity inside annulus in ft/sec = diameter of borehole or inside diameter of casing in in2 = outside diameter of drillpipe or drill collar in in2 = length of the drillpipe in feet

Critical Reynolds number, NRec

1.0E+05

Critical Reynolds numbers for Bingham Plastic Fluids

1.0E+04

1.0E+03

1.0E+02 1.00E+03

1.00E+04

1.00E+05

1.00E+06

1.00E+07

Hedstrom number, NHe

Figure 1: Critical Reynolds numbers for Bingham-plastic fluids. This graph shows Hedstrom numbers vs Reynolds numbers for Bingham-plastic fluids.

deviated drilling

erd

section 6

section 6a - hole cleaning section 6b - barite sag section 6c - lubricity

section 6a

hole cleaning

section 6a factors that impact hole cleaning annular velocity (av) drill pipe rotation mud weight hole angle rheology cutting size drill pipe eccentricity feed concentration (rop) mud type drill pipe size significant parameters noted for cuttings bed heights of <10%: angle 60˚ or greater significant parameters noted for cuttings bed heights of >50% general conclusions summary hole cleaning in deviated wells good hole cleaning practices mud and rheology guidelines flowrates and hydraulics drillpipe rotation monitoring hole cleaning performance clean-up practices tripping practices back reaming and pumping out remedial hole cleaning running casing

Scomi Oiltools

2 2 2 2 3 3 3 3 4 4 4 4 4 4 5 5 6 6 7 8 9 10 10 11 13 14

Section

6a

deviated drilling - hole cleaning


factors that impact hole cleaning The ten factors identified as being of most importance to good hole cleaning in deviated wells are: ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ

Annular velocity Mud density Mud rheology Mud type (oil or water) Cutting size ROP Drill pipe rotation Drill pipe eccentricity Drill pipe diameter Hole angle (45-90 deg)

annular velocity (av) Annular velocity has been found to be the most significant factor impacting hole cleaning and minimising cuttings bed height. In studies bed heights have been found to occupy >40% of the annular space when the annular velocity is maintained below 40 m/min (131 ft/min) and <10% of annular space when maintained at greater than 80 m/min (262 ft/min). Increasing the annular velocity can, in combination with other variables, diminish the cuttings bed height. Additionally the effects of other variables such as hole angle and drill pipe rotation will diminish with increasing annular velocity.

drill pipe rotation Rotation is desirable and effective in minimising cuttings beds. The effect of rotation is substantial at low annular velocities and high hole angles and minimal at high annular velocities and low hole angles. The effect of rotation diminishes with increased annular velocity and increases with increased mud density. The impact of eccentric drill pipe positively improves the effect of drill pipe rotation and high rotary rpm will combine effectively with high rheology at low annular velocities to reduce the cuttings bed height. The effect of rotation is optimised by increasing the drill pipe diameter. Cutting size will also impact the effect of rotation, i.e. by doubling the size of the cutting the effect of rotation will be halved. Rotation is especially desirable and effective at angles of 60˚ or greater. Where ROP, cuttings size and cuttings density is high the effect of rotation decreases.

mud weight Along with annular velocity, mud weight has the greatest impact on hole cleaning. Bed heights can occupy >40% of the annular space when mud weights are low and <10% of annular space when mud weights were high. The industry study found there was little potential for cuttings bed formation when the mud density is >1.70 S.G., even for low annular velocities. Field experience indicates cuttings beds are unavoidable at low mud weights, even when annular velocities are maximised. From acuminated data it would appear mud weight had a significantly greater impact on cuttings bed height than mud rheology. It was also observed in the study that cuttings bed sliding diminished with increasing mud weight.

hole angle Between 45˚ and 60˚, dynamic cuttings beds continuously slide downward, especially at lower annular velocities and diminishes as the hole angle increases past 60˚. Between 45˚ and 60˚, cuttings beds immediately slide and tumble downward under static conditions. Average dynamic cuttings bed height is consistently higher at 60˚ than at 45˚. Between 75˚ and 90˚, cuttings beds are maintained uniformly in height over time, and become packed. Of the 4 major variables i.e. AV, rotary rpm, mud weight and hole angle, hole angle had the lowest impact.

rheology Rheology is only moderately effective at reducing cuttings bed height. The effect of rheology is improved at high annular velocities and is greatest when one or more of the major variables are optimised (i.e. AV, mud density and rpm. Cuttings bed heights tend to be lower at hole angles between 75˚ and 90˚ with low rheology muds. The effect of rheology on bed height is less evident in hole angles between 45˚ and 60˚. High rheology combines effectively with high rotary rpm at low AV and reduces cuttings bed height. Bed heights occupy >40% of annular space with low AV and low mud density and no rotation in high angle holes. Bed heights occupy <10% of annular space with low rheology combined with high AV, low mud weight and no rotation in high angle holes.

cutting size The impact of cutting size is dependent upon cutting density and feed rate (i.e. ROP). Doubling the cutting size and ROP may double the bed height unless one or more of the major variables are optimised (i.e. AV, rotary rpm and mud density). Doubling the size of cuttings generally halves the impact of rotary rpm on hole cleaning.

drill pipe eccentricity The eccentric position of drill pipe is desirable in high angle and horizontal wells when rotary rpm is applied. The effect of rotary rpm on hole cleaning is greatest when pipe position is eccentric. AV will tend to reduce cuttings bed height more effectively when drill pipe is concentric or centred. Figure 1: Eccentric Pipe Flow Patterns

Section

6a


Drill pipe eccentricity: ƒ Significant effect on annular pressure drop ƒ A skewed drill string can have infinite number of eccentricities at the same time ƒ Usually an unmeasured factor, but of great importance to hole cleaning ƒ While sliding, equals tool joint stand-off ƒ While rotating > 25 rpm, DP lifts off-bottom Effect of Drill Pipe Eccentricity in Deviated Wellbore ƒ Rapidly alters velocity distribution throughout the annulus ƒ Flow in the annular narrow gap greatly reduced; flow in the wide gap greatly increased ƒ Flow distribution largely controlled by fluid flow index ‘n’ ƒ Flow profils can be generated in computer programs

feed concentration (rop) Increases in ROP do not greatly impact cuttings bed height as compared to the major variables (i.e. AV, rotary rpm and mud density). High ROP is sustainable in most cases if the cuttings size is small. High ROP is not sustainable if the cuttings size is large unless the major variables are optimised (i.e. AV, rotary rpm and mud density).

mud type Mud type has marginal effects and does not interact with other variables. Results are more predictable with OBM and bed sliding is normally more prevalent with OBM

drill pipe size Drill pipe diameter has minimal effects on cuttings bed heights. Effectiveness of rotary rpm is impacted by drill pipe diameter and cuttings size.

significant parameters noted for cuttings bed heights of <10%: angle 60˚ or greater ƒ High AV ƒ High mud weight ƒ Drill pipe centred ƒ Lower mud rheology ƒ Drill pipe rotating

significant parameters noted for cuttings bed heights of >50% ƒ Low AV ƒ No drill pipe rotation ƒ Low mud wt ƒ Horizontal flow ƒ Higher mud rheology ƒ Drill pipe centred

general ƒ Studies consistently demonstrate the difficulty of removing cuttings beds once they accumulate. ƒ Under normal circumstances, as much as half the annular area may be filled by a cuttings bed. ƒ Cuttings beds formed at angles of between 45˚ – 60˚ tend to continuously slide and tumble down the low side of the hole. ƒ At angles of between 60o and 90o, cuttings beds are static, with little tumbling and sliding behaviour. ƒ The most significant variables impacting cuttings bed height are AV, rpm, mud weight and hole angle.

conclusions summary

Major impact on cuttings bed Annular Velocity Pipe Rotation Mud Density Hole Angle

Moderate impact on cuttings bed Rheology Cuttings Size Eccentricity Minor impact on Cuttings bed Feed Rate (ROP) Type of Mud Drill Pipe Size

ƒ It requires a “heavy” emphasis on AV and rotation to minimise the development of a cuttings bed. ƒ Mud weight is subject to the predicted pore pressure gradients and therefore cannot be easily manipulated to optimise hole cleaning. ƒ Hole angle while subject to target location can to a certain extent be designed to optimise hole cleaning. ƒ Cuttings beds are easier to “control” during the drilling phase than they are to subsequently remove at TD.

hole cleaning in deviated wells Cuttings beds will form in high angle wellbores, regardless of how efficient the hole cleaning practices are. How the cuttings are distributed in the hole will dictate the measures that are required to move them. Management of the cuttings in the hole is a key to efficient drilling operations. A wellbore does not have to be 100% clean, or free of cuttings to be “clean”. Every high angle wellbore will have a cuttings bed of some kind. A cuttings bed that is clean for drilling is not necessarily the same as that for tripping a BHA, running casing or running wireline logs. When approaching hole-cleaning issues it is important to understand the behaviour of cuttings beds at different hole angles. Hole cleaning in general can be divided into 3 categories which have quite different strategies and circumstances. ƒ 0˚ - 45˚ wells ƒ 45˚ - 60˚ wells ƒ 60˚ - 90˚ wells In a vertical to 45˚ well cuttings are brought to surface by combating cuttings slip velocity where the cutting must fall thousands of feet to reach the bottom of the hole. Figure 2 shows dynamic cuttings bed behaviour at 45˚, the cuttings bed takes on a dune formation as cuttings are continually picked up and brought into the mud flow by pipe rotation. After some distance the cutting again falls to the low side of the hole where it is again picked up and transported further up the wellbore, this process is continually repeated until the cutting is finally discharged onto the shale shaker screen at surface.

Section

6a


Figure 2

In wells with inclinations in the range of 45˚ - 60˚, cuttings begin to form dunes as the distance for them to fall to bottom is now measured in inches. Due to the hole angle there is a constant tendency for cuttings beds to tumble and slide during the drilling process, and once flow stops cuttings beds will immediately slide. Inclinations of 60˚ - 90˚ present a different set of operational circumstances. Here the cuttings fall to the low side of the hole and form a long continuous cuttings bed. Although the challenges associated with an avalanching dune have gone away, hole cleaning in this environment is actually more difficult and time consuming. Figure 3 shows dynamic cuttings bed behaviour at 90o, beds quickly become packed and bed height remains stable over time (with constant rpm / gpm). Figure 3 90 degrees

Flow

good hole cleaning practices Good tripping and drilling practices are critical to ensuring acceptable hole cleaning. The benefits of a powerful, purpose built drilling rig can easily be negated by poor or inappropriate drilling practices.

mud and rheology guidelines Regardless of the mud type the overall objective is to maintain a pumpable fluid with low-end rheology that is high enough to keep cuttings moving out of the hole. The use of 6 rpm readings as a primary indicator of hole cleaning capability and maintaining low PV (plastic viscosity) for pumpability is widely accepted. Generally maintain 6 rpm Fann readings at 1.0 to 1.5 x hole diameter. Maintain high rheology, YP = > 25 lbs/100ft2 to achieve good primary hole cleaning. Try to avoid pumping low-vis / hi-vis pills. The focus should be on primary hole cleaning to minimise the formation of cuttings beds in the first place. It is thought that such pills lead to uneven mud properties and pack offs, contributing to the hole instability.

Low-vis pills create turbulent flow (intended to stir up cuttings) in the wellbore but this has a number of detrimental effects. The turbulent flow may contribute to the erosion of shales and the turbulence creates localised shifting patterns of lower than average and higher than average pressure which can give rise to shale splinters. These shale splinters are often interpreted as pressure cavings and the mud weight is increased, increasing PV and exacerbating the problem. Hi-vis pills are likely to pick up large quantities of cuttings and cavings, which can result in pack-off.

flowrates and hydraulics Pump at the maximum available flowrate at all time. This will be limited by formation pressure integrity. Use the ECD as a guide to maximum flowrate possible without compromising hole integrity. Flowrate is the key parameter for hole cleaning rate, as shown in the figure 4. The faster the pump rate the quicker the hole is cleaned, so long as the rpm is sufficiently high, preferably >120 rpm. Figure 4 - Flowrate Effect on Hole Cleaning

There is a minimum hurdle flowrate that must be exceeded if there is to be any hole cleaning in a high angle wellbore. Field experience also suggests that there is a point of diminishing benefit for flowrate increases. It is important to appreciate that as long as cuttings are moving up the hole at a faster rate than they are being generated, then the hole is being cleaned. Flowrate will affect the rate of cleaning and allow faster cuttings generation to be tolerated. When discussing the desired flowrate for highly deviated, say 1,000 – 1,200 gpm in 12-1/4” hole, it is not unusual to be told that such high flowrate will wash out the hole. Many people have concerns that turbulent flow will result in erosion of the wellbore. This is a misnomer for several reasons. For all intents and purposes, it is impossible to get turbulent flow in the drillpipe annulus, regardless of the flowrates with the viscous mud systems that will be used in highly deviated wells.

Section

6a


Such high flowrates, 1,000 – 1,200 gpm (3785 - 4543 L/min) in 12-1/4” hole will give theoretical AV’s (Annular Velocities) of 196 – 231 ft/min (60 - 70 m/min) across 5” drillpipe and 235 – 277 ft/min (72 - 85 m/min) across 6-5/8” drillpipe. When you consider that walking pace is approximately 350 ft/min (107 m/min) (4 mph / 6.4 kph) it is difficult to visualise that such relatively low velocities can erode the wellbore.

drillpipe rotation High speed drillpipe rotation is critical for good hole cleaning in the high angle portion of the well. Flowrate alone is ineffective unless the pipe is being rotated fast enough to stir the cuttings into the flow regime. When slide drilling the drilling fluid is near stationary on the low side of the hole where the cuttings are so no hole cleaning takes place. Figure 5: Annular Fluid Movement in High Angle Wells

Vertical Wellbore

High Angle Wellbore

High Velocity Fluid Low Velocity Fluid on Low side of Hole Cuttings bed on low side of hole will be disturbed by fluid flow unless stirred up by pipe rotation

Fluid moves almost uniformly throughout annulus in a vertical wellbore. Cuttings move evenly in annullus

Field experience suggests that there are key rotary speeds that produce step changes in hole cleaning performance on highly deviated wells. The mechanics of why these key speeds occur is unclear, especially since they remain relatively constant for variations in hole size, drillpipe size and mud systems. Step changes in cuttings returns occur at 100 – 120 rpm and again at 150 – 180 rpm as shown in the figure 6 overleaf. Figure 6 - Effect of Pipe Rotation on Hole Cleaning Cuttings Return Variation with Pipe Speed

Cuttings Return

Step changes in cuttings return occur at 100 – 120 rpm and again at 150 – 180 rpm.

Fine tuning of rotary speed from 60 – 80 rpm is generally not meaningful. The hurdle speed of 100 – 120 rpm must be exceeded for significant improvement

0

25

50

75

100

125

Rotary Speed (rpm)

150

175

200

If possible slide only in the middle of a stand. This will result in rotating before and after the sliding period to move cuttings deposited during the sliding period well away from the BHA prior to making a connection. Also less angle will be lost when reaming the stand.

monitoring hole cleaning performance rop Historically, there have been two different schools of thought on drilling ROP in high angle hole sections. Some choose to drill at maximum instantaneous ROP and then perform remedial hole cleaning operations as required. Alternately some nominate a safe ROP at which the hole can be kept clean as it is drilled ahead. High instantaneous ROP and remedial hole cleaning are likely to result in periods when the well unloads cuttings at a rate that cannot be handled by the containment system. torque and drag monitoring This is one of the primary methods of monitoring hole cleaning as the information is readily available and easily interpreted on the rig floor. Surface torque and drag monitoring involves taking torque, rotating string weight, pick and slackoff weights at every connection. As the well is drilled deeper the values for up weight, rotating weight and down weight will all slowly increase, as will the difference between them. When the up and down weight lines diverge away from the predicted trends, i.e. up weight increases and down weight decreases it can indicate build up of cuttings beds in the well and a requirement to stop and circulate clean. Examples of these trends are shown in figure 7 below. Figure 7 - Torque & Drag Monitoring S tr i ng W e i ghts 140 U p W e ig h t

130

R o t a t in g W e ig h t D o w n W e ig h t

120 U p & D o w n w e ig h t s d iv e rg in g , in d ica t in g p o o r h o le c le a n in g

110 100 90 80

U p & D o w n w e ig h t s d iv e r g in g , in d ic a t in g p o o r h o le c le a n in g . S t o p d r illin g & circ u la t e cle a n

70

S t o p p e d d r illin g & circ u la t e d w e ll c le a n

60 2400

2600

2800

3000

3200

3400

3600

3800

Measured Depth (feet)

The theoretical predictions that the actual data is compared to must be of good quality. Not only is the software model important but the input data must be of good quality and continuously calibrated with actual measured values. Most importantly, the data must be collected in the same manner for each data point to ensure consistent, reliable output.

Section

6a


It is important to trust the torque and drag modelling but it is just as important that its limitations are well understood. Torque and drag modelling has proven to be an excellent tool for monitoring cuttings bed build up but there are many actions that may be occurring that will not necessarily show up or may be misinterpreted. Differential sticking, key-seating and wellbore instability effects should not be misinterpreted as cuttings build up. The symptoms of these problems are different and their identification underlines the importance of collecting and interpreting the torque and drag data in conjunction with centrally monitored drilling parameters on an ongoing basis.

clean-up practices Effective hole clean-up practices are essential to successful and risk free tripping. It is vital that the hole is cleaned adequately prior to POOH. This does not mean that there should be no cuttings at all but simply that any cuttings bed height is sufficiently low and evenly distributed to allow the bit and BHA or casing to pass through without problems. The introduction of the top drive system has lead to many operators choosing not to invest time in cleaning the hole prior to tripping since they have the ability to backream if necessary. This has developed into a time consuming and risky practice. Generally, prior to POOH, the hole should be circulated with maximum available flowrate and maximum allowable pipe rpm while working the last stand on bottom. Do not stop circulating as the sudden reduction in flowrate may induce avalanching of cuttings, leading to pack-off and stuck pipe. Avoid circulating at the same depth for an extended period to prevent the creation of ledges but do not lay out stands unless absolutely necessary. When reciprocating the pipe do not run the pipe up and down between the same depths, as this will create ledges at these depths. The consequence of this is that the rotating bit will damage the lowermost stand of the wellbore. As the rest of the section is likely to have washouts anyway this is deemed acceptable but the impact of any loss of inclination may have to be determined. Circulation and rotation should continue until the hole cleans up. Do not stop circulation after a nominal 1 or 2 bottoms up. Good cuttings return in highly deviated wells does not actually commence until after 1 to 2 bottoms up, and for the shakers to clean up may take 4 bottoms up. The cuttings return volume will also vary erratically with time as the hole is cleaned up, especially if periods of slide drilling have been used. Slide drilling will create dunes of cuttings in the wellbore, which as they are circulated out will give the appearance that the hole is unloading. Regardless of the length of time that it takes to clean the hole up prior to POOH, it is worth the investment.

tripping practices Tripping practices should be tailored specifically for high angle wells. As the inclination increases and cuttings beds form, these can be very problematic. If tripping procedures do not account for this phenomenon, then back reaming through tight hole will result in an inappropriate, time consuming and sometimes dangerous operation. The primary rules are: ƒ Always assume that any tight hole or overpull is due to cuttings and hole cleaning related. ƒ Clean up the hole using maximum rotation and circulation for the minimum number of bottoms up as calculated using the lag model and then until the shakers are clean. ƒ Do not assume that cased hole is a safe haven for tight hole avoidance. It is not unheard of for stuck pipe to occur inside casing, either just inside the shoe or many thousands of feet inside casing.

10

ƒ POOH without pumps or rotation. ƒ If tight hole is encountered, progressively increase overpull ensuring that the string is free to move down at each stage before increasing the overpull. If the string cannot be pulled through the tight hole proceed as per the guidelines in the Section Guidelines For Back Reaming Through Tight Hole.

back reaming and pumping out Although back reaming may be considered an appropriate practice in vertical wells and conventional low angle deviated wells. Back reaming and pumping out of hole are not appropriate practices for high angle well bores when tight hole is encountered or as a primary hole cleaning tool. Back reaming and pumping out of hole are not only considered to be very inefficient but can also be very risky on highly deviated wells. Whereas tight hole in vertical wells is likely to be due to wellbore conditions, tight hole in highly deviated wells is likely to be due to hole cleaning and cuttings. Back reaming and pumping out of hole through a cuttings bed can very easily lead to packing off, stuck pipe and possible loss of the string and wellbore. The reason that back reaming or pumping out is so dangerous in high angle wellbores is that the process completely cleans the hole below the bit/BHA rather than leaving a small cuttings bed along the bottom of the hole. The cuttings instead are deposited in a dune just above the top of the drill collars. This significantly increases the chance of packing off as the top of the drill collars is pulled into the cuttings bed. Figure 8 : Effect on Cuttings Bed of Back reaming or Pumping Out

Acceptable Cuttings Bed for Tripping

A cuttings bed exists but the hole is acceptably clean to allow trouble free tripping. Cutting are left below the bit.

Harmless cuttings are left below the bit

Situation During Back Reaming or Pumping OOH

Cutting Dune is created above the BHA

No cuttings are left below the bit

When back reaming or pumping out the hole is completely cleaned below the bit and the cuttings deposited as a dune above the top of the BHA. The dune represents a significant pack-off/sruckpipe risk.

11

Section

6a


A feature of high angle wells that utilise back reaming is that the wellbores often seem to deteriorate over time, especially if any tight hole occurred whilst back reaming. When a well packs off whilst back reaming or pumping out of the hole, the wellbore below the pack-off is subjected to a very rapid increase in pressure as the rig pumps are still running. This can force mud into the shales creating micro-fractures and consequently cavings, which add to the hole cleaning problems. back reaming guidelines If back reaming is necessary the following recommendations are made: ƒ Pumping out of the hole will not be carried out as the pumping out process creates a cuttings dune above the BHA but provides no hole cleaning ability in the drill pipe annulus above the BHA. ƒ Back reaming should only be performed with ideal parameters. Even at low flowrate the process will still clean the wellbore extremely well around the BHA, creating a cuttings dune above the BHA. However without sufficient flowrates and rotary speed the cuttings dune cannot be cleaned away from the BHA sufficiently. ƒ The pulling speed is a critical parameter, too fast and the top of the drill collars will be pulled into the cuttings dune, creating a pack off and possibly leading to stuck pipe. The process needs to be based on surface torque readings by the driller as a means of determining pulling speed. guidelines for back reaming through tight hole It should always be assumed that any tight spot during a trip is a cuttings related problem. If a tight spot is encountered while POOH then the following guidelines should be followed. 1. If the hole is sufficiently tight that the string cannot be pulled through, RIH 3 to 5 stands until the BHA is clear of the obstruction and circulate with maximum flowrate and rotation for 30 minutes. 2. Never commence pumping or rotation while the BHA lies in or close to the obstruction. If the BHA cannot be moved down, perhaps because it is close to bottom, then gradually start rotation prior to bringing on the pumps slowly. 3. POOH again without pumps or rotation. If the tight spot has disappeared or moved up the hole then the tight hole was probably due to a cuttings bed. The BHA should then be tripped back into hole and the well circulated clean with maximum flowrate and rotary speed. 4. If the tight spot is in the same place, then it may be assumed to be something other than cuttings alone and careful back reaming may be necessary until past the restriction. 5. If back reaming has taken place, great care should be taken when beginning to POOH again as a cuttings dune may have built up above the BHA and may cause a pack off and stuck pipe. Consider circulating the hole clean again before resuming tripping. guidelines for precautionary back reaming On occasion, it may be necessary to back ream in an highly deviated well for precautionary reasons. 1. Prior to precautionary back reaming, the hole should be cleaned up with maximum flowrate and rotation. 2. The is some danger that cleaning up the hole before back reaming may be seen as a waste of time, given that the hole is to be back reamed anyway. However, the intent of circulating clean is to get the cuttings level down to a more manageable, lower risk level, before commencing a relatively high risk operation (i.e. back reaming). 3. Back ream slowly out of the hole with maximum allowable flowrates and pipe rotation. If flowrate is limited it may be advisable to back ream in stages with several stops to clean the hole to a safer level of cuttings or at least redistribute them away from the BHA. 4. It must always be remembered that a potentially dangerous cuttings dune exists above the BHA. The driller should be vigilant for indications (e.g. increased torque) that the BHA is being pulled into this cuttings dune and that a pack off or stuck pipe is imminent if appropriate action is not taken.

12

remedial hole cleaning It is better to stay on bottom at an optimised ROP, controlled to match hole cleaning and cuttings containment capacity than it is to drill in short fast burst and then use remedial operations to clean the hole. If drilling practices and parameters are optimised, it is generally possible to drill for very long intervals and very long periods without any wiper trips or any other remedial measures. However, there may be occasions where some remedial actions may be required, e.g. equipment failure, deteriorating wellbore condition or suddenly poor mud properties. Any remedial operations should be based on clear torque and drag and cuttings return trends. Furthermore, the effectiveness of the remedial operations should be observed and quantified before and after the operation. use of sweeps If the correct mud properties are maintained and drilling practices include high rotary speeds then the mud system will clean the hole. Once the mud system is right the use of sweeps only acts to cause deterioration of the ideal mud properties. In highly deviated wells mud rheology is already difficult enough to keep within specification without the detrimental effect of sweeps being absorbed into the system. Furthermore, their use in highly deviated wells has proven largely ineffective, regardless of the sweep design. In an highly deviated well with the fluid flow along the top of the hole, even the most viscous of pills will allow cuttings to fall to the bottom of the hole. Also as the pipe is rotated and the fluid flow profile takes effect, mixing of the sweep with the drilling fluid is inevitable. The most common result is that a sweep is never detected back at surface. A further concern is that sweeps may pick up cuttings in concentrated amounts, which can have a detrimental effect on ECD. On the rare occasions that sweeps do bring cuttings back it is unlikely that they come from very far down the hole. Almost certainly, the cuttings recovered are from the build or vertical section of the well. stop drilling and circulate Picking up off bottom and circulating should be looked upon as the first remedial hole cleaning option once changes in the drilling parameters and ROP have proved ineffective. As discussed previously this operation should be performed with maximum flowrate and rotary speed. Remember off bottom flowrate and rotary speed may be higher than that used for drilling. If hole cleaning is a problem consider circulating prior to connections for 10 minutes while rotating at maximum speed and gently reciprocate the string to minimise hole damage in one spot. This will ensure that cuttings are well above the BHA so that when the pumps are turned off they will not avalanche back across the BHA and pack it off.

13

Section

6a


wiper trips Generally, it should be possible to make precautionary and remedial wiper trips for hole cleaning unnecessary. It has been proved that if good practices and strategies have been used throughout then long high angle hole sections can be drilled without wiper trips. It may still be necessary to wipe a hole for other reasons, e.g. swelling shale interval. back reaming As discussed previously, back reaming is a time consuming and risky practice on highly deviated wells. It should not be used as a general practice or tool. If back reaming is to be performed as a remedial option due to tight hole then it should only be performed after determining that cuttings are not the problem. A significant cuttings bed will probably be created above the BHA after back reaming, therefore, it is important to clean the hole up via circulation and rotation prior to POOH after back reaming. It is accepted that there is a time an place for back reaming, such as across a depleted reservoir or through a swelling shale.

running casing Should it be required to circulate casing, the well should be circulated clean. Otherwise, cuttings will just be deposited as cuttings beds higher up in the well. The casing will be run deeper past the trouble spot. The cuttings higher up in the wellbore may now avalanche down and pack-off the casing.

14

section 6b

barite sag

section 6b

Scomi Oiltools

introduction

2

barite sag fandamentals

2

key parameters

2

3

influencing factors

symptoms

3

awareness & planning

3

4

mud properties & testing

prevention

5

management of sag problems

5

monitoring

5

operational practices

6

Section

6b


deviated drilling - barite sag

introduction Barite sag is recognised as a significant hazard in deviated wells using both weighted oil and water based drilling muds. Detailed research has been conducted into the underlying fundamentals and key influencing factors causing barite sag. The following guidelines will detail how good planning and job execution will ensure the drilling fluid does not allow barite sag.

barite sag fundamentals Barite sag is the result of dynamic and / or static slumping of weight material in the annulus. The majority of sag occurs under dynamic conditions in deviated wells. Barite beds caused by dynamic sag tend to slump down the well during static periods, causing density variations. Sag beds behave differently and have different characteristics to cuttings beds. At low solids concentrations, settling occurs in a segregated way, whereas in dense concentrations settling occurs block-wise at relatively low velocity. During sag, the denser, larger particles settle first, causing the overlying fluid to be lighter and more buoyant. This reduces the settling velocity of the smaller particles in the higher buoyed fluid over time. Sag can occur in any well deviated by more than 30o. The effect is most pronounced in wells with a deviation of between 60o and 75o. Sag beds formed at angles below 60o slump faster than those at higher angles. Sag can occur in any fluid type and at any density range where weight material is present. Generally, the higher the density the greater the risk. Sag increases with time Sag can occur dynamically where it is absent or minimal under static conditions. Local settling at the top and low sides of the well during low-rate circulations and static periods causes a pressure imbalance, forcing lighter mud upwards and accelerating the sag process, known as the Boycott effect. The 4 zones of barite sag beds are, from bottom to top, the slump bed, sediment bed, suspension zone and clarified fluid zone. Volume gains / losses can be induced by sag due to annular density variations.

key parameters ƒ Hole Angle & Length ƒ Annular Velocity ƒ Drill Pipe Rotation ƒ Flow Regime ƒ Mud density ƒ Mud Rheology ƒ Weight Material ƒ Particle Size & Shape ƒ Particle Concentration ƒ Time

influencing factors ƒ Barite sag is principally controlled by dynamic flow. ƒ Flow rate & drill pipe rotation are the most important drilling parameters which influence sag. ƒ Low annular velocities induce sag, especially when the drill pipe is eccentric & not rotating. ƒ Mud rheology is a key sag control mechanism. ƒ Sag impacts upon critical wells with close pore pressure & fracture gradients. ƒ High temperatures generally thin muds, increasing the sag potential of fluids. ƒ Sag potential depends upon the mass of weight material. ƒ Casing design impacts sag potential when small gauge holes coincide with large annular diameters in the well, reducing the annular velocities in the broader zones. ƒ The higher the O/W ratio of an oil mud, the greater the sag potential. ƒ Over-treatment of wetting agents can thin fluids and increase sag potential. ƒ Fluid loss reducers and other additives can reduce mud rheology and increase the sag potential. ƒ In water base fluids, there is a greater potential for solids agglomeration of smaller particles. ƒ Particle size distribution is a key determining factor. ƒ Excessive solids control processing can increase sag potential by reducing particle size variations.

symptoms Mud Weight Fluctuations Any inexplicable variations in mud weights might indicate a sag problem. Heavy spots can often be correlated with slugs pumped. Light spots are often the first indications of barite sag. Stand Pipe Pressure Variations Fluctuations can occur as light and heavy spots pass through the drill pipe and nozzles. Variations can occur due to mud hydrostatic differentials and frictional pressure losses. These are often cyclic in nature. Increased torque & drag Settled barite beds may increase torque and drag in a similar way to cuttings beds in deviated wells. Mud losses and gains Unexpected losses may occur when heavy spots reach the near-vertical section of the well, causing increases in the fluid hydrostatic pressure. The opposite may occur, when light spots reduce the hydrostatic, causing the well to flow.

awareness & planning Awareness and planning are essential prerequisites to eliminating sag problems. Anticipate and plan for potential barite sag in all deviated wells above 30o, especially for 60o - 75o wells. Be aware that well planning, well type, well environment, well profile, casing design and hole size, will directly influence the potential risk of sag. Where necessary, conduct pre-well fluids testing to assess the potential for barite sag and incorporate specific mud property and engineering guidelines in fluids programs. Program for, and provide, the relevant additional fluids testing equipment and reporting guidelines for well site engineers. In ERD wells, recognise that constraining factors, such as the need to control ECD values and SPP limitations, may restrict the ability to manipulate anti-sag mechanisms such as rheology adjustments and flow rates.

Section

6b


Recognise that barite sag beds are different from cuttings beds in their behaviour and that sag beds may be readily dispersed by correct application of flow rates and rotary.

mud properties & testing rheology • Primary Mechanisms The primary mud property control mechanism for barite sag is manipulation of the low shear rheology, Fann 6 and 3 rpm values, for dynamic sag and the initial 10 sec gel strength for control of static sag. Well-bore temperatures affect rheology and well-site measurements need to properly account for the effects of bore hole temperatures on rheology. • Low Shear Rheology Elevating the low shear rheology and establishing the correct relationship between these two variables is a proven mud control mechanism for eliminating dynamic sag. A rheology value known as the Low Shear Rate Yield Point (LSRYP), obtained by the formula 2 x 3 rpm – 6 rpm, may be used to measure the fluid sag-control condition. In general, LSRYP values in the range 7 - 15 lb/100ft2 have been shown to eliminate sag but the optimum range of LSRYP values for a specific fluid should be arrived at by experience. • Gel Strengths The 10 sec gel strength should be high enough to deter static sag. Values below 7 have been shown to result in greatly increased static sag potential. Again, testing and field experience will indicate the correct range of values for a specific fluid. The 10 min & 30 min gels do not form sag control mechanisms. • Temperature Effects Higher temperatures thin muds and generally lower the rheology, especially oil base systems. Rheology measurements need to account for temperature effects. mud weight Mud weight measurements are a key area for monitoring sag. To ensure accuracy, measurements should be taken frequently, especially after trips, using a pressurised mud balance, which should be regularly calibrated. Plotting mud weights against other variables such as time and SPP can often reveal cyclic and other trends in sag behaviour. oil / water ratio Increasing the O/W ratio tends to thin oil based muds and increase the sag potential or sag rate. Increasing the low shear rate modifier concentration will help combat this problem. particle size distribution Particle size variations are beneficial in deterring sag. Conversely, uniformity of particle size encourages sag. Measurement of the particle size distribution and other particle properties helps to understand sag problems and provides information that may be used correctively. sag testing Various apparatus exist for sag measurement for use on high temperature ERD wells. It may be prudent to provide well-site sag testing apparatus such as this for critical wells, where the results can then be used as a guide to treatments.

prevention ƒ Ensure that adequate pre-well fluid testing has been conducted and that the sag potential of the fluid has been identified. ƒ Avoid using old fluid that has been identified as problematical. If using an old fluid, ensure that it has been properly re-conditioned and contains as broad a spectrum of particle sizes as practicable. ƒ Ensure that the fluid has a sufficient LSRYP to deter sag and that the LSRYP is maintained within the desired range. ƒ Ensure that all organophilic clays are exposed to high temperature and pressure shear. This is important for them to achieve full yield and therefore effectiveness. This type of shear is usually accomplished either by a special HTHP surface shear system or by circulating through the bit. ƒ Maintain the 10 sec gel strength within the desired range and avoid low static barite sag. ƒ Avoid excessive dilutions, which lower rheological values and encourage sag. ƒ Avoid excessive solids control techniques, which degrade the solids and reduce the particle size variation. Where protracted centrifuging is necessary to control LGS, replenish the fluid with fresh weight material and suspension agents. ƒ Maintain an adequate concentration of low shear rate (LSR) modifier, i.e. premium grade clay, especially when diluting. ƒ Avoid using low shear rate (LSR) liquid rheology modifiers, which have been shown to be less effective sag control mechanisms than solids. ƒ Levels of surfactant or oil wetting agent must be sufficient to prevent barite agglomeration into large clusters. ƒ Avoid increases in the O/W ratio unless specifically required to reduce or minimise pump pressures. ƒ Avoid over thinning fluids prior to running casing and preferably do not thin until casing has been run. ƒ Ensure that the fluid is in condition prior to any extended low-shear operations such as running casing or logging. ƒ Maintain strict QC testing of weight materials, LSR modifier, LSR liquid rheology modifiers and suspension agents. ƒ Avoid over-treating with additives and surfactants which are known to encourage sag. ƒ Avoid prolonged periods of non-rotational slow circulation, especially where annular velocities in critical deviated intervals fall below 50 ft/min. ƒ Regularly calibrate mud testing equipment and use a pressure balance to measure the fluid density. ƒ Periodically conduct particle size analysis in order to provide a early warning of impending sag. ƒ The use of sub API grade (325 mesh) barite has proven beneficial.

management of sag problems Sometimes, it is not possible to prevent a sag problem. Therefore, it is necessary to manage it. Success or failure will be governed by the well conditions and by well-site actions.

monitoring It is important to monitor the variables appropriately in order to be able to determine if there is a problem and to judge the effectiveness or otherwise of any remedial actions. Mud Weights – Monitor mud weights closely and ensure that a pressure balance is used for accuracy. Plot graphs of mud weight against other variables to determine any cyclic behaviour. Stand Pipe Pressure – Monitor the SPP and record any unexplainable fluctuations. Fluctuations could be caused by density variations inside the drill string, barite beds leading to slumping and partial pack-off or density variations in the well resulting in U-tubing differentials.

Section

6b


Torque & Drag – High torque and drag may indicate the presence of a barite sag bed. Remember that, unlike cuttings beds, sag beds behave as liquids and flow down the well bore. Volumes – Monitor volumes closely. Barite sag can become a well-control problem, caused by density variations in the upper near-vertical annulus, leading to down-hole losses and gains.

operational practices Circulating & Conditioning - If barite sag is observed, attempt to remedy by stopping operations to circulate and condition the fluid for as long as necessary. Ensure sufficient circulating time to allow for any rheology modifications to be effective and to balance out any density variations. Premium grade clay viscosifiers, e.g. CONFI-GEL HT, require both shear and temperature to fully develop the rheology. If there is no impediment, ensure maximum annular velocity and rotary during circulations. Adjusting the LSRYP – Where possible, adjust the LSRYP to a higher value by additions of low shear rate modifiers and allow time for treatments to be effective. Rotary Vs Sliding – Sag is greater when the pipe is stationary and otationis a proven deterrent mechanism. If slide drilling, especially on ERD wells with angles between 60˚ and 75˚, attempt to compensate with high annular velocities. Supplement this technique where necessary by pulling back one stand and rotating at high speed, especially after prolonged periods of slide drilling. Design the BHA for this contingency. Trips – Recognise that sag increases with time. Consider rotary wiper trips to stir up barite beds and consider staging into the well following trips and static periods in order to minimise the effect of reintroducing settled weight material into the system. Additional Mud Testing - Determine if there are additional tests, site or shore-based, or mud testing methods that may help to indicate the way to reduce or even eliminate the sag problem.

fine grind weight materials Traditional weight materials used for high density fluids are primarily API barite and occasionally haematite. Recently interest has been growing in the use of specialty materials including fine grind barite (HyPR-BAR) and manganese tetraoxide (HYDRO-MAX). These fine grind materials do not readily settle or sag but support the formulation of reduced viscosity high density fluids which allow lower ECD values in critical wells. HyPR-BAR is an economical non API sub-400 mesh barite which typically exceeds API quality specifications for mineral quality. HyPR-BAR is specifically ground for formulation and maintenance of drilling fluids in which ‘barite sag’ is virtually eliminated in all fluid types and densities. HyPR-BAR with its inherently low contribution to viscosity provides a solution for wells with narrow mud density windows. HyPR-BAR is useful for the design of economical reservoir drill in fluids which readily flow back through and are non-damaging to production screens. This characteristic also allows use of up to API 325 mesh screens on surface equipment. Drilled solids build up is greatly reduced, dilution may be reduced by up to 75%, and reduction in overall mud cost can more than compensate for the modest increase in cost of this material.

HyPR-BAR grind size is in the range of: D10 1 - 3μ D50 7 - 12μ D90 27 – 32μ Maximum 3% > 44μ (as measured with Malvern PSA) Compared with API barite: D10 D50 D90 Maximum (as measured with Malvern PSA)

2 – 4μ 18 – 25μ 60 – 68μ 3% > 74μ

HYDRO-MAX, average particle size of about 1 micron, is a high purity precipitated manganese tetraoxide. The density of 4.8 SG is superior to that of the highest quality barite available. High density fluids formulated with HYDRO-MAX have lower solids content than conventional barite systems. Lower solids content generally allows improved (lower) rheological properties, with potential improvement in filtration control, and typically higher penetration rate.

Note: As with all critical wells and applications, fluids using these products should be formulated and tested before being used in the field.

section 6c

lubricity

section 6c

Scomi Oiltools

introduction

2

friction coefficient

2

types of lubricant

2

liquids

3

solids

3

lubricant selection

3

summary

3

lubricity truisms

4

Section

6c

deviated drilling - lubricity


introduction Understanding the relative lubricity of a particular mud system and knowing what factors affect and control lubricity are all-important areas of mud technology. This is a brief summary of how lubricity is tested, what factors can affect and control lubricity and other key issues concerned with the subject.

friction coefficient General - The friction coefficient (FC) forms the basis for measuring relative mud lubricity. This is important for understanding comparison tests and judging relative differences in lubricity. For any given system, the base line default FC values should be established in controlled tests. These in turn may be used to make direct comparisons with known systems and for developing and improving lubricity. Test Apparatus - There are many different apparatus & test rigs used to measure FC. For more dependable test results, the larger scale testers should be used, although accuracy with regard to field calculations is still questionable. As a result, the FC should be used as a guide only when applying data to the field. Influencing Factors - The main factors affecting the FC are: ƒ Wellbore geometry ƒ Surface type & roughness ƒ Contact pressure ƒ Mud type & density ƒ Time ƒ Temperature ƒ Lubricant effects ƒ Well & string design ƒ Wellbore stability ƒ Cuttings bed thickness & type ƒ Filter cake characteristics FC Values For OBM & WBM - FC values for oil based muds are generally low, in the range 0.11 – 0.15, whereas for weighted WBM the range is generally 0.25 – 0.35 and for unweighted WBM the values are still higher at between 0.35 – 0.50. It is well proven that increasing the O/W ratio of a given OBM will lower the FC and that different oils exhibit different lubricity values. Tests show that WBM FC values are lower in fully formulated systems where mud additives such as polymers and barite have a measurably beneficial effect. In both cases, friction coefficients are highest against sandstone, with shales showing lower values and smooth steel surfaces such as casing producing the lowest range. For any mud system, lab tests measuring the contribution mud additives make to the FC is important in understanding and improving the lubricity potential.

types of lubricant There are two types of lubricant, liquid and solid, which may be used singly or in various combinations. Environmental concerns preclude the use of some of the more effective lubricants, such as oils, while mud compatibility and other problems preclude others.

liquids Liquid lubricants are almost always added to WBM and only recently, in a limited extent, to OBM. Often, blends of different liquid lubricants are most beneficial, whereas a single liquid may be sometimes all that is required. Occasionally, liquids may be used in conjunction with solids to good effect. Oils added loosely to a WBM tend to be effective FC reducers, whereas adding an emulsifying agent to bind in the oil greatly reduces this effect. Although the FC for waters, brines and very simple water base muds is almost always reduced by the addition of a liquid lubricant, only fatty acids and a blend of alcohols and triglycerides have been found to be effective liquid lubricants over the wide range of WBM systems . Lubricants may work well in one type of WBM system and fail or make matters worse in another, so that the selection process is very much system specific. The FC of a WBM may be reduced by as much as 68% by the correct application of liquid lubricants.

solids Although sometimes effective in reducing the FC, solid lubricants suffer from the disadvantage of being screened out or physically degraded in a mud system. As a result, solids lubricants can be much more expensive to maintain. In many cases, solids additives have been seen to reduce torque and drag in the well but have not shown up well in tests. Other solids not intended as lubricants (e.g. cellulosic fibres, biopolymers, etc) have been seen to produce beneficial effects in torque reduction in the field. Proven solid lubricants include synthetic graphite, HYDRO-SEAL G, and asphaltines, HYDROPLAST. Generally, other mud solids have a negative impact on mud lubricity by entering the contact space between surfaces to break any established lubricity-enhancing film present. Liquid lubricants are also generally adsorbed onto solid surfaces and may be depleted by high solids loading within the mud system.

lubricant selection Factors affecting lubricant selection include: ƒ general mud compatibility ƒ foaming ƒ formation of unwanted emulsions ƒ stability within the system ƒ environmental concerns ƒ elastomer compatibility ƒ formation fluorescence masking ƒ formation impairment.

summary A working knowledge of the range of friction coefficients for a base mud and its constituent parts is a necessary precursor to tackling the lubricity capabilities of that fluid. Once these values are known, further lab testing gives a guide to the compatible lubricants and their type and optimum formulation. This is in turn is used to help improve the mud lubricity in the field where necessary.

Section

6c


Successful application will also depend upon the extraneous influences and variables such as well design, surface types and roughness, time, temperature, contact pressures, well bore stability, etc, etc. In certain cases, test results obtained in the lab may give incorrect guidance due to the difficulty of simulating field conditions in particular identifying the tendency of a lubricant to cause a foaming problem. In this respect, certain lubricants may also prove to be successful in the field but indicate otherwise during lab testing. Certain lubricants may be precluded due to, for example, environmental considerations. Mud solids should be controlled to as low as practically where mud lubricity is a problem. Problem muds include silicate systems, which, despite detailed research, continue to defy a solution to the lubricity issue.

lubricity truisms Certain proven truisms concerning lubricity can be listed as follows: 1. 2. 3. 4.

Oil base muds have lower friction coefficients than water base muds Increasing the O/W ratio leads to a lower friction coefficient Ester based systems have lower friction coefficients than mineral oil or other synthetic inverts The friction coefficients of water base muds can be reduced with the appropriate additive(s) and can be as low as some OBM systems 5. Unweighted WBM systems exhibit the greatest response to lubricant treatments 6. Above 1.50 SG, addition of a lubricant to a WBM has a minimal effect 7. Liquid lubricants have a greater effect on steel/steel friction than on steel/rock friction where solids lubricants are the more effective 8. Oil based muds are less lubricating as temperature increases 9. Lab lubricity test gear results do not always correspond to full scale rig results 10. String rotation is a significant factor in drag reduction 11. The most effective liquid lubricants for WBM are based upon esters, amines, fatty acids and some glycols 12. Lubricant selection is system specific

well control section 7

pressure control

section 7a - pore pressure predictiion section 7b - well control

section 7a

pore pressure prediction

section 7a

Scomi Oiltools

introduction

2

pore pressure

2

pore pressure detection

4

planning

4

ppd during drilling

5

drilling parameters

5

mwd

7

pore pressure plotting

8

Section

7a

pressure control - pore pressure prediction


introduction Sedimentary rock contain fluids trapped in the voids, pores space, fractures and vugs etc., The fluids in these sediments are under some pressure, from compaction and density of the overlying rock. This is known as the formation pressure. As the sediments are drilled the formation pressures are controlled by the density of the drilling fluid column, the pressure applied by which is known as the hydrostatic pressure. Normal formation pressures at any depth are the equivalent pressure of a column of water and higher pressures are known as abnormal pressures. If the applied hydrostatic head from the drilling fluid is less than the formation pressure, formation fluids will start flowing in the wellbore, therefore, while drilling the density of the drilling fluid is maintained at a sufficient level to provide a hydrostatic pressure greater than that of the formation. In effect the difference in the pressure, between the hydrostatic and the formation is kept positive. If a formation is penetrated with a higher formation pressure than the hydrostatic pressure of the drilling fluid, then DP will become negative resulting in an influx of formation fluids into the well, the scale of the influx depending on size of the pressure differential. The influx of formation fluids, especially oil or gas into the wellbore, if not adequately controlled, can result in blow outs, which have been a major cause of loss of life, equipment and environmental hazard in oil and gas well drilling operations. In order to avoid well control activities during drilling operations, it is necessary to predict pore pressures in advance and plan the well accordingly. To be able to predict pore pressures requires some fundamental knowledge of the causes of formation presssure, in particular abnormal pressures.

pore pressure All clastics have some pore or void spaces which contain fluids, water containing salts, crude oil, gas, associated or dissolved, or different combinations of all. The fluids in the pore spaces of the rock support the overburden along with the grains of the rock. Pore pressure or formation pressure is that part of the overburden which is supported by the fluid in the pores. All sedimentary rocks have voids (pore spaces) which are filled with fluid. The density of any formation will depend on the rock type plus the extent and size of voids and the type of fluid in the voids. The average density of clay, sand or shale without any pore space is 2.6 SG. A formation with 20% pore space containing 1.021 SG water will have an SG of 2.284. Table -1 indicates how rock density varies with porosity and water salinity:

Water Density Porosity % lb/gal SG 8.38 1.004 10 8.38 1.004 25 8.51 1.02 10 8.51 1.02 25 8.99 1.08 10 8.99 1.08 25

Table. 1- Rock Density Variation

Rock - SG 2.44 2.20 2.445 2.21 2.448 2.22

As the depth of burial increases so does the overburden pressure compacting the formation and forcing the connate fluids from the pores spaces, thus decreasing the pore volume. The overburden pressure is then supported both by the grains of rock (intergranular pressure) and the remaining fluid in the pore spaces. Po = Pg + Pf Pf = Po - Pg

alternatively

Where Po = Overburden pressure Pg = Pressure supported by grains/matrix of the rock Pf = Pressure supported by fluid or formation pressure When the fluids cannot escape from the formation due to closure during compaction, e.g. clays sealing the formation, then more of the overburden pressure is supported by the pore fluids. This increases the formation pressure over and above the expected normal pressure at the depth. The normal pressure gradient at a depth is taken as water gradient at that depth which varies depending on the salt concentration in water. The fresh water gradient for inland areas is generally is 0.433 psi/ft (9.79 kPa/m), water density – 8.34 lb/gal (1.0 SG ) while the gradient in marine basis is 0.465 psi/ft (10.51 kPa/m), 8.9 lb/gal (1.07 SG ) salt water. Formations with such gradients are classified as normal pressure. Abnormally pressured formations may have pressure gradients from the normal values to > 1 psi/ft (22.61 kPa/m). Pressure vs Depth 5000 4500 4000 Depth (m)

3500 3000 2500 2000 1500 1000 500 0

0

2000

4000

6000

8000

10000

12000

14000

(13790)

(27580)

(41370)

(55160)

(68950)

(82740)

(96530)

Pressure in psi and (kPa)

Normal Pore Pressure-0.465psi/ft

Abnormal Pressure-1 psi/ft

Figure: 1 Normal & Abnormal Pressure vs. Depth Metamorphic rocks are eroded to sand, silts and clays by environmental weathering and are transported by water or air to the depositional sites where the pore spaces are filled with the water which may contain dissolved salts depending on the terrain traversed by the water. Lime-stones are chemical rocks, CaCO3, in which porosity and permeability is created by water percolating through the rock dissolving or eroding the formation. Permeability in lime-stones is characterised by fractures and vugs. During deposition these sediments can form alternate layers, intermixed layers or any of the multiple combinations possible. Typical depositional characteristics are dependent on the terrain traversed and distance of transportation before the sedimentation process.

Section

7a


As further sediments are deposited, the formations compact and fluid is driven from the pore spaces. If the fluid cannot escape due to impermeability barriers then the fluid begins too support more of the overburden density and the formation pressure increases. Over a geologically large period of time and under conditions of pressure and temperature hydrocarbons are formed in clays and shales from organic materials deposited along with the clay particles. The hydrocarbons migrate during the compaction process and accumulate in porous and permeable sedimentary rocks known as reservoirs, often sealed by a clay / shale formation. The compaction process and the ability of the fluids to escape will determine the pressure regime of the hydrocarbon reservoirs. Due to sub-surface tectonic activities formations with normal pressures may be uplifted resulting in high pressures than normal for a particular depth. Tectonic activity can also result in the sealing of the normal exit routes of the formation fluid leaving them trapped and over geological time leading to abnormal pressures. Abnormal pressures may be caused by: 1. Entrapment of pore fluids – under compaction. 2. Tectonic activities – up-thrust; faulting; massive salt intrusion. 3. Structural causes, normal pressures on flanks of an anticline may manifest as abnormal on the crest of the same structure. 4. Physical and chemical changes resulting in volume increases which causes abnormal pressures for instance dia-genetic transformation of anhydrite to gypsum. Due to water absorption, volume increase can be up to 40%. 5. Sub surface blow outs leading to charging of shallower formations from deep fluid bearing formations. This process can also occur as a normal geological phenomenon through migration along a fault or through a seal in the network of micro-fractures. 6. Swamp or marshy gases due to bio-chemical process. They are at shallower depths and are one of the major hazards to drilling operations.

pore pressure detection Existence of abnormal pressure is usually characterised by: 1. Porosity in shales changes from normal trends, in particular porosity increase with depth. Normally porosity decreases with depth (due to compaction) as a linear function. 2. Formation fluids undergo changes in terms of content and density. 3. Sound velocity is slower than expected for the depth and area. Based on the likely causes of abnormal pressures and associated characteristics a number of techniques have been developed to assist in predicting abnormal pressures both during the planning and drilling stages of a well.

planning The initial source of planning information is the seismic data which is combined with the information from the offset wells. 1. Seismic: The velocity of the sound waves is measured in the different sub surface formations and converted to formation interval transit time Dt. High speed processing of the data is used to plots trend lines of Dt with depth which are calibrated for pore pressure gradient specific to the area. Velocity depends on two factors - type of formation or constituents and density or compaction.

Transit time will vary with litho-logy and as such petro-physical variations and heterogeneities can lead to less accurate information. As a continuous process litho-logical data of an area should be updated and corroborated with the recorded Dt. Normally the Dt decreases with depth as the formation undergoes compaction. In the case of abnormal pressures there is under-compaction of the formation whereby the velocity of sound is reduced increasing the Dt. Variations from the trend line can indicate the existence of abnormal or subnormal pressures. An increase of transit time compared to the trend indicates abnormal pressures where as decrease in the Dt is indicative of subnormal pressures. Formations with gases have a tendency to absorb the sound waves. The formations above the gas zone will relatively be highly reflective, thereby giving a Bright Spot effect for the gas bearing formations. This property is also used for detecting hydrates associated with gas in deep water drilling which show as a Bright Spot Reflector (BSR). 2. Offset Well Data: Drilling and Log data from offset wells is examined for evidence of abnormal pressures. Electric logs are the best and most accurate source of data. ƒ Neutron/Gamma logs provide porosity and density data of formations. In case of a normally pressured structure there is a continuous decrease in porosity and an increase in density with depth. All the values will be on straight line, however, in the case of abnormal pressures there will be a increase in porosity and a decrease in density which will show on the graph as an anomaly compared with the trend for the area. ƒ Sonic logs provide Dt similar to the seismic data. Sonic / pressure gradient plots can indicate the pressure profile. Dt is plotted against depth and a normal trend is established. In the case of abnormal pressures, compaction is reduced which increases the transit time, indicative of abnormal pressures.

ppd during drilling Abnormal pressure has an impact on drilling parameters, an impact which provides a excellent tool for pore pressure prediction, taking into account other factors which also impact the drilling parameters. Measurement While Drilling tools, MWD, provide resistivity data which is used for predicting pore pressures with new developments such as look ahead VSP providing very accurate data on transit times for pore pressure prediction:

drilling parameters 1. Rate of Penetration. ROP is one of the most commonly used tools for identifying abnormal pressures. In shale formations the ROP decreases with depth due to compaction. Abnormal pressure in shale is characterised by under compaction as such increase in ROP, be an indication of increasing pore pressures. However, there are other factors which also impact the ROP: ƒ Bit type ƒ Bit Condition ƒ Bit weight ƒ Bit diameter – Hole size ƒ Rotary speed ƒ Hydraulics – Bottom-Hole cleaning ƒ Type of formation ƒ Drilling fluid parameters specially density

Section

7a


The impact of these varying parameters are taken into account in a mathematical model called the ‘d-exponent’. The ROP is not only dependent on the drilling parameters but is also dependent on the compaction; density and porosity of the formation which is described in the following Bingham formula:ROP RPM

=

C ( WOB )d D

Where ROP = Rate of Penetration RPM = Rotary speed WOB = Weight on Bit D = Bit diameter C = Constant d = exponent It is established that there is an inverse relationship between the ROP and the pressure differential across the formation DP, i.e. the difference between drilling fluid hydrostatic and formation pressure. The normal trend is an increase in DP with depth meaning that the ROP decreases with depth. In the case of abnormal pressure DP will decrease resulting in an increase of ROP. On the other hand a decrease in formation pressures below normal, known as subnormal pressures, may be indicated by a decreasing d-exponent.

When ROP is plotted against depth, the other drilling parameters remaining the same, a trend line will emerge and a deviation from the trend may indicate abnormal or subnormal pressure.

The Bingham equation can be solved for d – exponent and putting the units will result in the following equation:

d = [log(ROP/60*RPM)/log(12*WOB/106 * D)]

where Oilfield units ROP log ( 60 x RPM ) d= 12 x WOB log ( 1000 x D ) Where ROP = ft/hr WOB = lbs D = inches

S.I units d=

ROP

log

( 60 x RPM )

log

( 1000 x D )

67 x WOB

Where ROP = m/hr WOB = kg D = mm

If the calculated value of d is plotted against depth a trend is established and a deviation indicates abnormal pressure.

Subsequently the equation was modified to factor the drilling fluid density and is known as the ‘modified d – exponent’ or dxc where:-

dxc = d*(normal drilling fluid density / actual drilling fluid density) (normal drilling fluid density is the normal pressure gradient for the area) This modification led to very good results and made it possible for graphic determination of pressure gradients.

2. Shale Density increases with depth linearly due to compaction. In the case of abnormal pressures, due to under compaction or fluid retention in shales, the shale density will decrease and is clearly identified if plotted against depth and a trend line generated. 3. Cutting size and shape depends on the type of bit used. Normal cuttings are small and flat depending on shale reaction with the fluid whereas pressured shale cuttings are larger, sharper and rounded. The Drilling Fluid Engineer must make it a habit of closely observing the cuttings both to assist in determining mud treatments and also to identify abnormal pressures indicators. 4. Gas in Drilling Fluid. Gas is released into the drilling fluid as rock containing gas is drilled and ground up releasing the gas in the pore spaces. This is known as ‘drill gas’ and a background level will be established for each well. This gas level may also show peaks known as connection gas. The connection gas is due to slight reduction in hydrostatic when the pumps are switched off to connect a pipe. Increases in background or connection gas are excellent indicators of potential overpressures.

NB. There are gassy shales which sustain high levels of gas in the mud system due to the large volume of gas trapped in the shale. In this case high gas levels may not be a reliable indicator. Gas is soluble in base oil, therefore, background and trip gas levels may not be detectable at a level to provide good indicators.

5. Connection ‘Fingerprinting’ in Non Aqueous Fluids. Base oils used for and SBM are compressible and there may be a slight flow back of fluids during connections when the pumps are off and the pressure on the mud is reduced, allowing the fluid to expand. This flow back of volume versus time is ‘fingerprinted’ by the mud loggers and an increase in volume or time indicates an increase of formation pressure. 6. Chloride ions. An increase in mud chloride content can indicate changes in formation pressure due to the higher salinity of trapped water, and can be recorded by resistivity tools and mud checks. 7. Flow line temperature. Flow line temperature increases with depth, due to the geothermal gradient of the earth. It is also dependent on the number of hours of circulation, the treatment being given to the drilling fluid, solid content, bit torque and variations in ambient temperatures. Rapid increase in circulating temperature may indicate an increase in the geothermal gradient often associated with abnormal pressures.

mwd Various downhole tools are placed in the drillstring to record formation characteristics while drilling. This equipment is known as Measurement While Drilling – MWD or Logging While Drilling – LWD tools 1. Porosity/Density Tool. Neutron/gamma log is utilised for ascertaining the formation porosity / density. Shale density / porosity data can be used for identifying the presence of abnormal pressures. MWD/LWD tools are placed 15 – 20 meters above the bit so the data recorded is from the formation some meters above the bit position. 2. Resistivity. This resistivity tool is valid only while using water base fluids and is a part of the MWD / LWD package. The tool measures the shale resistivity. A deviation from the trend may indicate presence of abnormal pressures. 3. Sonic. This tool records sound velocity from the formation which can be converted to Dt for identifying presence of abnormal pressures.

Section

7a


4. Look Ahead VSP. A sonic tool is placed on the bottom hole assembly which transmits sound waves ahead of the bit. Sound velocity from the formation yet to be drilled is recorded and processed as transit time. As discussed in seismic profiling Dt is plotted and presence of any abnormal pressure detected. This is an online tool which provides Dt values a few meters ahead of the bit allowing immediate action in case of any indication of abnormal pressures.

pore pressure plotting Data, based on the fact that compaction due to overburden increases with depth in a consistent manner, is plotted and compared to the standard trends for the area. Properties plotted include density; porosity; interval transit time and the conductivity. These properties when plotted on a semi-log paper against depth show a straight line for normal pressures. Any changes from the trend of these parameters will give indications of the abnormal / subnormal pressures and the pressure gradient in terms of equivalent mud weight.

section 7b

well control

section 7b

Scomi Oiltools

introduction

2

kick detection

3

determining the drilling fluid density requirement

3

well control calculations

4

controlling the well

5

wait and weight method

6

drillers method

7

concurrent method

7

volumetric method

7

barite plugs

7

Section

7b

pressure control - well control


introduction The primary control of formation pressure is provided by the hydrostatic head of the drilling fluid. Secondary control is provided with the use of a mechanical barrier - the Blow Out Preventors (BOP). When a well influx (a kick) occurs, the formation fluid flows into the well bore and primary control from the drilling fluid is lost. The BOP is closed to provide well control while actions are taken to regain the primary control by increasing the density of the drilling fluid. If the flow becomes large and unmanageable e.g. failure of the BOP or undetected flow, a blow out can occur with disastrous results. Well control signifies that the well has become active or a kick has been taken and a series of steps are required to circulate out the kick and take remedial action to re-establish hydrostatic control of the formation pressures. The following steps are required, the well control strategy: 1. 2. 3. 4.

Detection of a kick. Ascertaining the drilling fluid density requirement to re-establish control. Raising the density of the drilling fluid to the required value. Circulating out the kick.

Well influxes typically occur during the following drilling operations: 1. Drilling: If abnormally pressured formations are encountered while drilling, an influx will occur, if the hydrostatic head provided by the drilling fluid is less than the formation pressure. Kicks may also occur during lost circulation events due to a drop in the fluid height in the annulus causing a reduction in the hydrostatic head. 2. Tripping out: One of the most common causes of well control events is not keeping the hole full while tripping the drillpipe out. As the pipe is pulled from the well, the volume of the steel removed must be replaced with drilling fluid, or the fluid level in the annulus will drop and the hydrostatic head will become less than the formation pressure. Hole fill up must be closely monitored to ensure that the correct volume of fluid is being used to keep the hole full at all times. While pulling out of hole it is possible that formation fluids may be swabbed into the hole, as the drillpipe pulls fluid off bottom, reducing the hydrostatic pressure in the wellbore. This can occur due to balling of the bit, or balling of drill collars which reduce the annular clearance such that the drillpipe acts like a piston as it is pulled up the wellbore. High fluid viscosity or reactive (swelling) formations can also cause swabbing during drill pipe removal from the wellbore.

Swabbing is indicated if the volume of mud required to fill up the hole is less than the volume of steel removed. Trip speeds should be controlled and if required maintain the drilling fluid below the bit by pumping through the drill pipe or slowly pumping out through a Top Drive System (TDS).

3. Tripping in: The speed of running the drillstring into the hole can result in pressure surges ahead of the string which can break down the formation causing downhole losses with subsequent loss of hydrostatic head and formation influx. Tripping speed needs to be controlled to preserve fluid column integrity.

Fluid returns from the well while running in are closely monitored to ensure the correct volume of fluid is being returned. Too little flow indicates losses may be occurring while too much flow is an indication that the there has been an influx.

Industry studies have shown that the majority of well control activities occur during tripping in development wells, and in the early morning hours between 0300 to 0500. The major cause being crew inattentiveness from a decreased level of alertness or overconfidence.

kick detection Wells become active when the hydrostatic head of the drilling fluid becomes less than the formation pressure and formation fluids enter the wellbore and are detected by the following indicators: 1. Drilling Break: A sudden increase in ROP may be due to abnormal pressure or a change in lithology. It is advisable to perform a flow check and observe the well before drilling ahead. 2. Flow increase: When the formation fluids flows into the wellbore there is an increase in the mud volume resulting in an increase in the return flow at surface. Return flow rates are constantly monitored to detect these changes. 3. Pit Gain: An influx will also increase the volume in the pits which should be closely monitored. Accurate measurements will determine the influx volume if detected quickly.

A trip tank is used to monitor the volume of fluid used to fill the hole while tripping out and volume of fluid displaced while tripping in. These are small tanks, with volume measurements, allowing detection of small changes in volume.

4. Reduction In Pump Pressure: As an influx rises in the annulus the pump pressure available to lift the drilling fluid up the annulus is increased. This will show as a reduction in pump pressure. Note that this can also be an indication of lost circulation. 5. Gas Level in the Drilling Fluid: As has been noted in the pore pressure prediction section, increases in gas levels in the drilling fluid occur due to increased gas content of the rock being drilled or due to an influx. Increasing trends both in background gas and connection gas levels are closely observed. Frequently they are an excellent indicator of drilling close to balance with little margin between the hydrostatic and formation pressures.

determining the drilling fluid density requirement After a kick has been detected it is important that the well be shut in immediately, firstly to ensure integrity and well control and also to be able to correctly determine the drilling fluid density required to control formation pressure and regain primary well control. When the BOP is closed on the wellbore, the pressure on the drill-pipe and the casing at surface will increase. The drill-pipe surface pressure reading is used to determine the actual downhole formation pressure and, therefore, drilling fluid density requirements. At this point the fluid in the drill string is uncontaminated mud and the influx fluid is in the annulus. The pressure exerted by the formation on the drill pipe is the difference between the formation pressure and the drilling fluid hydrostatic head. This excess pressure shows up as Shut in Drill Pipe Pressure – SIDPP. The formation pressure is the sum of the hydrostatic pressure from the mud plus the SIDPP. This is calculated as an Equivalent Mud Weight (EMW), which is the required mud weight to safely control the formation pressures and drill ahead. The drilling fluid in the annulus is contaminated with the formation fluid. The pressure on the annulus side consists of three elements: ƒ The drilling fluid gradient

Section

7b


ƒ The formation fluid gradient (depend on influx type and height) ƒ A U tube effect from the drill string pressure differential. This pressure is the Shut In Casing Pressure (SICP) which is higher than the SIDPP due to the loss of hydrostatic head from the kick fluid. The height of the influx can be determined from the influx volume recorded at surface, and the pressure gradient of the influx calculated. This gradient will indicate the influx type, water, oil or gas. Quick kick detection and closing of the BOP will lead to the most accurate determination of SIDPP and SICP. The more accurate this data, the easier it is to regain well control.

well control calculations Oilfield units Hydrostatic pressure (psi) = depth (ft) * mud weight (lb/gal) * 0.052

S.I units Hydrostatic pressure (kPa) = depth (m) * mud weight (SG) * 9.81

Drilling fluid gradient (psi/ft) = hydrostatic pressure (psi) / depth (ft)

Drilling fluid gradient (kPa/m) = hydrostatic pressure (kPa) / depth (m)

Formation pressure (psi) = hydrostatic pressure (psi) + SIDPP (psi)

Formation pressure (kPa) = hydrostatic pressure (kPa) + SIDPP (kPa)

Equivalent mud weight (lb/gal) = formation pressure / (depth (ft) * 0.052

Equivalent mud weight (SG) = formation pressure / (depth (m) * 9.81

Influx height (ft) = kick volume (bbl) / annulus vol (bbl/ft)

Influx height (m) = kick volume (m3) / annulus vol (m3/m)

Influx (psi/ft) = Drilling fluid gradient – [(SIDPP (psi) – SICP (psi) / Influx Height (ft)]

Influx (kPa/m) = Drilling fluid gradient – [(SIDPP (kPa) – SICP (kPa) / Influx Height (m)]

well control calculation - example An exploratory well took a kick while drilling a 6” (152 mm) hole at 8000 ft (2438 m) with 10.2 lb/gal (1222.23 kg/m3) drilling fluid. SIDPP was 600 psi (4138 kPa) and the SICP was 800 psi (5516 kPa). Pit increase was 10 bbl (1.6 m3). Company policy is to drill with a safety margin of 150 psi (1034 kPa). Oilfield units Drilling Fluid Hydrostatic = 0.052 x 10.2 x 8000 = 4243.4 psi

S.I units Drilling Fluid Hydrostatic = 9.81 x 1.22 x 2438 = 29178 kPa

Drilling Fluid Gradient = 4243.2 / 8000 = 0.5304 psi/ft

Drilling Fluid Gradient = 29178 / 2438 = 12 kPa/m

Formation Pressure = 4243.2 + 600 = 4843.2 psi

Formation Pressure = 29178 + 4138 = 33316 kPa

EMW = 4843.2 / (0.052 X 8000) = 11.64 lb/gal

EMW = 33316 / (9.81 x 2438) = 1.40 SG

EMW + 150 psi = 11.64 + [150 / (0.052 x 8000)] = 12.0 lb/gal to drill with safety margin

EMW + 1034 kPa = 1.40 + [1034 / (9.81 x 2438)] = 1.44 SG to drill with safety margin

Identifyng the influx fluid < 0.14 psi/ft (3.17 kPa/m) 0.14 – 0.442 psi/ft (3.17 – 9.99 kPa/m) 0.442 – 0.52 psi/ft (9.99 – 11.76 kPa/m)

= Gas = Mixture of gas, water or oil = Saltwater

Annular volume with 4 3/4” (122 mm) DC = 0.091 bbl/ft (9.96 L/m) Oilfield units Influx height = 10 / 0.0191 = 524 feet

S.I units Influx height = 1590L / 9.96 L/m = 159.6 m

Influx Fluid Gradient = 0.5304 - [(800 – 600 / 524] = 0.148 psi/ft indicating gas

Influx Fluid Gradient = 12 – [(5516 – 4138.2) / 159.7] = 3.37 kPa

controlling the well Circulating out the kick and raising the fluid density to the desired value are actions requiring a thorough understanding of the engineering involved. These processes together are the key parts of all well control procedures During the process of circulating the kick to surface, the influx fluid will undergo temperature and pressure changes. While temperature variations have a limited effect on the influx fluid, pressure changes can have dramatic effect if the influx is gas. As the fluid moves up the wellbore the hydrostatic pressure decreases and the gas volume will increase. Circulating out a water or oil kick can be a straightforward process depending on the type of well control procedure followed as there is little change in pressures or temperatures as the fluid is circulated out. Gases follow Boyles and Charles law:

P1V1 = P2V2

where

P1 & P2 = initial and final pressures V1 & V2 = initial and final volumes

Pressure & Volumes are inversely proportional - as the pressure decreases the volume increases and vice versa e.g. If P2 = 0.5 P

V2 = 2V1

In this case, the gas volume has doubled as the pressure decreased. If the well was not closed in with the BOP, this would result in large volumes of mud being ejected from the wellbore, due to the expansion of gas volume reducing the hydrostatic, and allowing more gas to flow into the wellbore. With the BOP closed and the gas circulated up the annulus without being allowed to expand, the surface pressures will increase beyond the casing shoe pressure limit, the burst pressures of the casing, and possibly the pressure limits of the BOP. This will cause failure in the ability of the wellbore design to handle the high pressures that will develop. For this reason, proper well control procedures have to be followed for safe removal of the gas influx from the wellbore.

Section

7b


Kill mud, depending on the well control procedure being followed, is pumped to bit in a carefully controlled operation, using a predetermined Slow Pump Rate. When the mud has reached the bit the SIDPP should equal zero. As the heavy mud circulates up the annulus the choke is regulated to maintain the required pressure by bleeding off volume at higher or lower rates as the influx fluids expand on their way to surface. A kill sheet is used to show the pressures required at all stages of the operation. The Slow Pump Rate is recorded every tour due to the change in drilling fluid density, fluid flow properties, and well depth. The initial circulating pressure, ICP, is the sum of SPR and SIDPP. There are three main methods of well control involving circulating out of kick and pumping the required density of drilling fluid to regain primary control. All of the methods are based on maintaining a Constant Bottom Hole Pressure. The fourth method is basically when the bit is not at bottom that is the well activity during tripping operation or when the string is out of hole. A) Wait and weight method B) Drillers method C) Concurrent method D) Volumetric method

wait and weight method This is also known as Engineer’s method of well control. The well is closed in and monitored while the drilling fluid is weighted to the required density. No operation is carried out until the required volume and density of fluid is available. The weighted fluid is then pumped and the well killed in one circulation. This method is preferred in most cases. The kill mud is pumped to the bit holding an ICP as calculated above. Once the kill mud is at the bit the mud is circulated at a constant Final Circulating Pressure (FOP) and the kick circulated out as per the pressure schedule in the kill sheet. FOP = Slow Pump Rate Pressure * Kill Mud Weight / Original Mud Weight When the weighted mud reaches surface the adjustable choke pressure should = FOP and on stopping the pumps SIDPP = SICP = 0 Advantages: a) Maximum pressure exerted on weakest point, i.e. the casing shoe, is the lowest of the methods with less chance of lost circulation. b) Requires only one circulation and least time to regain primary control. c) Well is exposed to lower pressures. Disadvantages: a) if the well is not clean, i.e. loaded with cuttings pack off and stuck pipe can occur. b) Gas migration up the annulus during waiting period may cause problems.

drillers method With this method the kick is circulated out before heavy mud is circulated. A constant bottomhole pressure is maintained using the adjustable choke throughout the circulation until. The well is shut in with back pressure equal to the SIDPP recorded earlier to avoid any more influx. During this time the drilling fluid is being weighted. Once the heavy fluid is ready it is pumped in the well maintaining a constant casing pressure. May be used in HPHT wells. Advantages: a) Less chance of pack off. b) Gas migration not an issue. c) Maintain well control while waiting on materials or weather. Disadvantages: a) Requires multiple circulations. b) Exposes casing shoe to relatively higher pressures.

concurrent method In this method the drilling fluid is weighted while circulating out the kick. It is not a preferred method for well control.

volumetric method This procedure is followed when a kick is taken while tripping in or out of the well and also if the well flows when the string is out of the hole. The main objectives are to get the bit to the bottom while ensuring that the back pressure or SICP is sufficient to avoid further influx without breaking down of the formation. Pressure is maintained by bleeding off volume through the choke as an equal volume of drilling fluid is pumped down the drillpipe to keep the hole full. Simultaneously the string is stripped in the well through the closed BOP. Once the bit is on bottom standard well control techniques are followed to regain primary control.

barite plugs During well control operations the increase in mud weight and hydrostatic pressure may be sufficient to exceed the fracture gradient and cause loss of circulation. In this case the influx will flow into the loss zone in a situation known as an ‘underground blow-out’. The placing of a heavy barite plug is usually done in order to stabilise the borehole for running casing. It is not recommended to drill ahead after inducing loss of circulation, unless the losses can be cured. Barite plugs seal the wellbore in the following ways:ƒ They are designed with low viscosities and zero fluid loss so that the barite may dehydrate and settle to form a solid plug in the hole. ƒ The high density increases the hydrostatic head and may prevent additional influx of formation fluid. ƒ The high fluid loss and lack of inhibition may also cause the hole to collapse and bridge itself. Barite plugs in water based mud Barite slurries are usually mixed and pumped with the cementing unit. The pills are mixed in freshwater and thinners such as SAPP and or lignosulphonate (HYDRO-SPERSE) are added to keep the slurry thin and promote settling. It is extremely important to pilot test first as high concentrations of these products, SAPP 0.2 – 1.0 lb/bbl (0.57 – 2.85 kg/m3) and/or HYDRO-SPERSE up to 10 lb/bbl (28.53 kg/m3) may be required to allow the barite to settle. At these very high densities barite can support itself.

Section

7b


Density kg/m3 lb/gal 2157 18 2277 19 2397 20 2516 21 2636 22

Weight/Volume Relationships (Barite Specific Gravity = 4.2) Slurry Water Barite 100 lb (45.4 kg) sack L/m3 gal/bbl sacks/m3 sacks/bbl 640 26.9 33 5.30 602 25.3 37 5.94 564 23.7 40 6.43 529 22.2 44 6.95 490 20.6 47 7.50

Slurry Volume/ Sack of Barite m3/sack bbl/sack ft3/sack 0.0300 0.189 1.060 0.0267 0.168 0.945 0.0247 0.156 0.873 0.0228 0.144 0.807 0.0212 0.133 0.748

Table 1. Barite slurry (water base) Mixing 1. Choose a slurry weight and barite/water requirements between 18 and 22 lb/gal (2.16 & 2.64 SG) from Table 1. 2. Determine how many feet/metres of barite plug in the open hole are desired. 3. Calculate the bbl (m3) of slurry and sacks of barite required, and add an extra 10 bbl (1.6 m3). 4. Mix the slurry and pump it into drill pipe. 5. Displace the slurry so that the height of the barite plug in the drill pipe is 2 bbl (0.3) m3 higher than the top of the barite plug in the annulus. 6. Break connections and pull up immediately above the plug. If possible circulate on top of the plug, if possible circulate for several hours. Barite settling can be very slow with unpredictable results. In many cases numerous pills may be set before well control is regained. Example Open hole = 8.5 inches (216 mm) Height of barite plug desired = 500 ft (152.4 m) Weight of slurry = 18 lb/gal (2.16 SG ) 1.

Volume of barite slurry = Oilfield units S.I units 8.52 1029 x 500 ft = 35 bbl

2.

Total volume required = Oilfield units 35 + 10 = 45 bbl

215.92 3 1.273 x 106 x 152.4 m = 5.59 m

S.I units 5.57 + 1.59 = 7.16 m3

3.

Materials to mix 45 bbl (7.16 m3 ) slurry: Oilfield units Water = 26.9 x 45 = 1121 gal = 29 bbl

S.I units Water = 640 l/m3 x 7.16 m3 = 4579.2 l = 4.6 m3

SAPP = 0.5 x 29 = 14.5 lb

SAPP = 1.423 kg/m3 x 4.58 m3 = 6.53 kg

Caustic Soda = as needed

Caustic Soda = as needed

HYDRO-SPERSE = as determined from pilot test

HYDRO-SPERSE = as determined from pilot test

DRILL-BAR = 5.3 x 45 = 239 x 100 lb/sx = 23,900 lbs

DRILL–BAR = 33 sxs/m3 x 7.16 m3 = 239 x 45.4 kg/sxs = 10828 kg

Total slurry volume = 239 x 0.189 = 45 bbl

Total slurry volume = 239 sxs x 0.0300 m3 = 7.16 m3

Barite plugs in non aqueous fluids The mixing procedure for an NAF Barite plug is to “water wet” the barite in order to provide viscosity and barite suspension, then to oil wet the Barite just prior to pumping, allowing the barite to settle out and form a solid plug. Barite is added to a mix containing primarily base fluid with a small quantity of water and water wetting surfactant, HYDRO-KLEEN or equivalent, as quickly as possible. This mix will become very thick. Before the mix becomes un-pumpable a small amount of oil wetting agent, CONFI-WET, should be added to thin the mix back so that more barite can be added, it is important not to over-thin the mix at this point. More barite should be added until the mix becomes very thick again and more oil wetting agent added, this process continuing until the desired weight is achieved. Just before pumping, a drum of oil wetting agent should be added, this will thin the mix dramatically and allow the barite to settle rapidly. The exact amount of oil wetting agent required should be determined by pilot testing, the amount of base fluid used in the mix, from table 2 below, should then be reduced by this amount.

Plug density (kg/m3) (lb/gal3) 2157 18 2277 19 2397 20 2516 21 2636 22 2756 23 2876 24

Base Oil Barite 3 3 (L/m ) (gal/bbl) (kg/m ) (lb/bbl) 593 24.9 1682 588 557 23.4 1828 639 521 21.9 1959 685 486 20.4 2131 745 452 19.0 2274 795 417 17.5 2422 847 381 16.0 2571 899

Water (L/bbl) 6.29 1 6.29 1 6.29 1 6.29 1 6.29 1 6.29 1 6.29 1

(L/m3)

Surfactant (L/m3) (L/bbl) 0.629 0.1 0.629 0.1 0.629 0.1 0.629 0.1 0.629 0.1 0.629 0.1 0.629 0.1

Table 2 – Product requirements for various density barite plugs (less oil wetting agent)

Section

7b


Mixing and Pumping Procedure The mixing pit and mix lines must be free of mud before mixing this plug, contamination with mud will result in the plug not thinning properly at the end of the mixing process. 1. 2. 3. 4. 5.

Fill slug pit, mix tank or batch tank with the required volume of base fluid. Add 1% of the final pill volume of water. Add 0.5% of the final pill volume of HYDRO-KLEEN or similar water wetting agent. Add barite at the maximum possible rate with maximum agitation, including gun lines if possible. Just before the mix becomes so thick it is un-pumpable, add sufficient oil wetting agent CONFI-WET to thin the mix but not enough to cause the barite to settle. 6. Repeat steps 4 & 5 until the required density is achieved. 7. Just before pumping, sufficient oil wetting agent should be added to thin the mud dramatically, 1 x 55 US gallon (1 x 208 l/drm) is usually sufficient in a 50 bbl (7.95 m3) plug. Spacers A base fluid spacer can be pumped ahead and/or behind the plug but is not absolutely necessary, as mixing of the plug and oil based mud will not result in a particularly high viscosity mixture.

10

NAF section 8

non-aqueous fluid (NAF) fundamentals

section 8

Scomi Oiltools

general description

2

NAF applications

4

disadvantages of NAF

6

NAF products description

6

properties of base fluids

10

mixing procedures

11

NAF mud properties

11

trouble shooting NAF

14

spacers for displacing NAF

15

displacing NAF to the hole

15

displacing NAF out of the hole

16

cementing with oil based muds

16

types of NAF base fluids

18

oil base mud (obm)

18

enhanced mineral oil base mud (emobm)

18

synthetic base mud (sbm)

18

environmental performance

which drilling base fluid is best for the

environment?

22 24

Section

8

NAF fundamentals

NAF fundamentals

general description In recent years the industry has sought new terminology to properly describe oil based mud systems and has adopted the term “non-aqueous fluid” or NAF, to cover non-water based systems, in general use today. Generally speaking, much of our industry is changing terminology to emphasize that NAF are not necessarily formulated from environmentally noxious diesel or crude mineral oils. From a performance standpoint, however, NAF and traditional oil-based mud formulations are virtually identical. A non-aqueous fluid or NAF might be defined as a drilling fluid which has a natural or synthesized hydrophobic fluid or oil as its continuous or external phase and has water, if present, as a dispersed or internal phase. The solids in a NAF are “oil” wet, all additives are “oil” dispersible and the filtrate of the mud is specialized non-aqueous base fluid (NABF) or “oil”. The water, if present, is emulsified in the “oil” phase, or we can call it, NABF phase. There are two basic classifications of NAF; invert emulsion NAF and water free NAF. The amount of water present will describe the type of NAF. The base fluids used can range from crude oil, refined oils such as diesel, mineral oils, olefins and paraffins, to the non-petroleum organic fluids i.e. esters that are currently available and silicone oils. The latter type fluids - variously called inert fluids, pseudo oils, non-aqueous fluids and synthetic fluids - are considered more environmentally acceptable than diesel or mineral oil based NAF. Conventional all-oil muds (water-free NAF) have a non-aqueous external phase but they are designed to be free of water when formulated or in use. Since water is not present, asphaltic, polymeric, or lignitic type materials may be required to control the fluid loss and viscosity. Since there is no water added to this system during the formulation and water additions are avoided if possible while drilling, there is only a minimum requirement for emulsifiers. All-oil muds, water-free NAF, can withstand small quantities of water; however, if the water becomes a contaminating effect, the mud should be converted to an invert emulsion. If the water is not quickly emulsified, the solids in the mud can become water wet and will cause stability problems. The water wet solids will blind the shaker screens and loss of whole mud will occur. Invert emulsions are NAF that are formulated to contain moderate to high concentrations of water which is an integral part of the invert emulsion and can contain a salt; commonly calcium or sodium chloride. In a mixture of oil and water the interfacial tension between oil and water is very high, consequently if the liquids are mixed together mechanically they usually separate once the agitation ceases.

Any emulsion that does form from this will be a direct emulsion with water as the external continuous phase. Lowering the interfacial tension with a surfactant (surface active agent) enables one liquid to form a stable dispersion of fine droplets in the other. The two fluids however remain immiscible. The lower the interfacial tension, the smaller the droplets and the more stable the emulsion. The interfacial tension between mineral oil and water is approximately 50 dynes/cm2, and a good emulsifier will lower this to about 10 dynes/cm2. Besides lowering the interfacial tension, the emulsifier stabilises the emulsion through adsorption of its molecules at the oil/water interfaces thereby forming a skin around the droplets. The skin acts as a physical barrier preventing the water droplets, in the case of an invert, from coalescing when they collide.

The surfactants, emulsifiers, consist of an oil soluble, lipophilic, chain of atoms linked to a water soluble (hydrophilic) chain. The lipophilic portion dissolves in the oil side of the interface and the hydrophilic in the water side. Whether the emulsion formed is direct (oil in water) or invert (water in oil) depends upon the hydrophilic/lipophilic balance (HLB) which is the ratio by weight of the hydrophilic part of the molecule to the lipophilic.

Because the creation of new surfaces, requires energy, some degree of mechanical agitation or shear is required to form an emulsion. The lower the interfacial tension the lower the amount of energy required. Under the high shear conditions which exist for example at the drill bit, the internal phase breaks into increasingly smaller droplets which effectively act as a solid providing some viscosity and fluid loss control.

Section

8

NAF fundamentals

The fluids characteristics can be varied to achieve desired specifications by the addition of varying amounts of emulsifiers, viscosifiers and filtrate reduction products, An invert emulsion can contain as much as 60% of the liquid phase as water. Special emulsifiers are added to tightly emulsify the water as the internal phase and prevent the water from breaking out and coalescing into larger water droplets. These water droplets, if not tightly emulsified, can water wet the already oil wet solids and seriously affect the emulsion stability. Special lignite derivatives or asphaltines are used as the fluid loss control agents, and bentonite derivatives are used to increase the viscosity and suspension properties of the system. Invert emulsions are usually tightly emulsified, low fluid loss NAF. An improvement in drilling rates has been seen when the fluid loss control of the system is relaxed, thus the name “relaxed” invert emulsion. The relaxed invert emulsions fluids use less emulsifier than regular invert emulsion systems.

NAF applications NAF offer many advantages over water based muds. The high initial cost of the oil based mud can be a factor in not selecting this type of mud system. However, if the overall drilling costs are considered, the costs accompanying the use of an oil mud are usually less than that for a water mud. Some of the applications of oil-based muds will be described below. Shale Stabilisation NAF are most suited for drilling water sensitive shales. Formulated with the proper salinity, NAF can prevent water movement from the mud into the shale. In some cases, water can actually be drawn from the shale and could result in strengthening. However, it is also possible to draw too much water from the shale, with too high a salinity, and cause a shale to be less stable. It is desirable to have enough salinity to prevent water migration into the shale but not to allow dehydration of the shale. This is the “balanced activity” concept. The required salinity is usually determined through field experience. Shale cores that have not been altered by the oil mud are necessary to accurately determine the salinity requirements. Optimise Rate Of Penetration NAF, as a general rule, deliver faster ROP than WBM while providing improved shale stability. Relaxed filtrate invert emulsions usually have a high oil to water content and some of the additives used to control fluid loss are omitted. These systems do not use the primary emulsifiers, which have been shown to reduce drilling rate, and they do not have the same temperature stability as conventional NAF. The relaxed type NAF are especially suited to drilling with PDC bits. High Temperature Wells NAF have the ability to drill formations where bottom hole temperatures exceed water base mud tolerances, especially in the presence of contaminants. NAF have been used at temperatures approaching 550 °F. NAF can be formulated to withstand high temperatures over long periods of time, unlike water muds, which can break down and lead to loss of viscosity and fluid loss control, as well as corrosion. Drilling Salts Invert NAF will provide gauge hole and do not leach out salt. The addition of salt to the water phase will prevent the salt from dissolving into the emulsified water phase. Water-based mud, even up to saturation and over saturation does not assure that the salts will not be leached out.

Coring Fluids Special NAF provide a native state coring fluid with minimum wettability changes. These fluids are usually water-free and thus require only a minimal content of emulsifiers. Oil mud emulsifiers are very strong oil-wetting agents and can cause oil-wetting of the formation. Oil-based coring fluids will not introduce any water into the core, so determination of water saturation can be more accurately determined. Packer Fluids Oil mud packer fluids are designed to be stable over long periods of time and when exposed to high temperatures. NAF provide long term stable packer fluids under conditions of high temperature since the additives are extremely temperature stable. Since oil is the continuous phase, corrosion is almost negligible compared to water base muds under the same conditions. Properly formulated, oil mud packer fluids can suspend weighting material over long periods of time. Lubricity In Deviated Wells The high lubricity offered by NAF makes them especially suited for highly deviated and horizontal wells. Differential Sticking An oil mud has a thin filter cake and the friction between the pipe and the wellbore is minimised, thus reducing the risk of differential sticking. Low Pore Pressure Formations The ability to drill low pore pressure formations is more easily accomplished with NAF as the mud weight can be maintained at a density less than water with densities as low as 7.5 lb/gal (0.90 SG) being achieved. Corrosion Control Corrosion of metal is controlled since oil is the external phase and coats the pipe. NAF offer exceptional corrosion protection due to the non-conductive nature of the oil, and corrosion cells cannot develop since the metal surfaces are oil wet. The products used in oil mud are very thermally stable and do not degrade to produce corrosive products. Bacteria do not thrive in NAF. Hydrate Formation Prevention There is a greater risk of forming gas hydrates in WBM than NAF. Gas hydrates are, relatively, stable solids that can plug lines and valves. They form under certain conditions of pressure and temperature in the presence of free gas and water. These conditions can occur during critical well control operations and may present a risk to operations, especially in deep water. For this reason, chemicals, salt, methanol, and/or glycol, are often added to WBM used for deepwater wells to prevent hydrate formation. The water phase of a NAF does not normally contribute to hydrate problems, because it is present in a relatively low concentration (20% or less by volume) and it generally has a high salt content, primarily for shale inhibition. Re-Cycling NAF are well suited to being recycled and reused as they can be stored for long periods of time. The oil mud can be conditioned before being used again by reducing the drill solids content with mechanical removal equipment instead of relying on dilution.

Section

8

NAF fundamentals

disadvantages of NAF ƒ The initial cost of oil mud is high, especially formulations based on mineral or synthetic fluids. The high cost can be offset by oil mud buy-back or leasing from the mud service company. ƒ Kick detection is reduced compared to that of water-based muds due to high gas solubility in the oil phase. ƒ NAF are costly when lost circulation occurs. ƒ Greater emphasis is placed on environmental concerns when using NAF as related to discharge of cuttings, loss of whole mud and disposal of the oil mud. ƒ Special precautions should be taken to avoid skin contact which may promote allergic reactions. Inhalation of fumes from NAF can be irritating. ƒ NAF can be damaging to the rubber parts of the circulating system and preclude the use of special oil resistant rubber. ƒ NAF pose potential fire hazards due to low flash points of vapours coming off the oil mud. Mineral oils and synthetic base fluids typically have higher flash points than diesel and crude oils. Crude oils should be “weathered” before using in NAF. ƒ Additional rig equipment and modifications are necessary to minimise the loss of NAF. ƒ Electric logging must be modified for use in NAF. NAF are non-conductive therefore resistively measuring logs will not work in NAF (SP, resistivity, Dipmeters). Imaging logs (FMI) are also less effective in an oil mud. ƒ NAF require emulsifiers that are very powerful oil-wetting materials, which can also change the wettability of the rock to an oil-wet condition. ƒ NAF type muds are more compressible than water muds, and, therefore, the downhole density may vary considerably from that measured at the surface.

NAF products description NAF require special products to ensure that the emulsion is stable and can withstand conditions of high temperature and contaminants. NAF products must be dispersible in the external NABF or “oil” phase. Primary & Secondary Emulsifiers These products reduce the surface tension between immiscible liquids to allow the formation of dispersions as described above.

Besides lowering surface tension the emulsifiers stabilise the dispersion by adsorption of emulsifier molecules at the oil/water interface forming a skin around the discrete droplets. This skin forms a physical barrier preventing coalescence on inter-particle collision. The stability of an invert emulsion increases with increasing viscosity of the continuous (oil) phase as the frequency of collisions between internal phase droplets decreases.

Calcium soaps are generally the primary emulsifier in NAF. These are made in the mud by the reaction of lime and long chain, C-16 to C-22, fatty acids. Soap emulsions are very strong emulsifying agents but take some reaction time before emulsion is actual formed. Wetting agents prevent solids from becoming water wet while the emulsion is forming. Secondary emulsifiers are very powerful oil wetting chemicals. Generally these products do not form emulsions as well as the primary emulsifiers, but oil wet solids before the emulsion is formed. They are used to readily emulsify any water intrusions quickly. Oil Wetting Agents Oil wetting agents are added to NAF to prevent the water wetting of drilled solids and barite. Water wet solids in NAF tend to agglomerate, blinding shale shaker screens and settling out in mud pits. Most oil wetting agents consist of a negatively charged phosphate group attached to a positively charged quaternary amine. The phosphate group has a non polar hydrocarbon tail which dissolves in the oil phase. Most metal and minerals carry a negative surface charge which attract the positively charged amine group. The oil attached to the non polar end of the molecule is thus attached to the metal or mineral surface. Since the majority of un-dissolved solids are contained in the continuous NABF phase of an invert, the fluid’s solids tolerance can be increased by increasing the oil/water ratio. It follows that significant increases in density (i.e., weighting agents) should generally be accompanied by increases in oil/water ratio. Note: A balance must be found between emulsification and oil wetting, since if emulsification is too strong, oil wetting may not be adequate and if the oil wetting action is too strong excessive oil will be lost on cuttings. Fatty Acid Emulsifiers and Lime Lime, Ca(OH)2 is added to form calcium soaps with tall oil fatty acid type emulsifiers.

The Role of Lime in OBM Saponification reaction with fatty acid type emulsifiers

RC

O 2R C

O H

+ Ca (OH )

O

2

O RC

R - Long chain hydrocarbon

O

Ca2 + + 2 H 2 O

O

Calcium soaps do not offer stability in the presence of magnesium or acid gas contamination and are no longer generally used without addition of oil wetting agents or other more powerful emulsifiers. A new generation of non-soap emulsifiers do not require lime. Lime, however, is helpful to rapidly stabilise properties, particularly HTHP filtrate control, at elevated temperatures. A high alkalinity is maintained in the water phase to provide a degree of safety and stability in the presence of acid gas influxes.

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NAF fundamentals

Organophilic Clay While some viscosity is imparted to invert emulsion by the water droplets in the internal phase, a the key rheological profile is obtained from the addition of clay. Untreated clays such as montmorillonite and hectorite will not readily disperse or yield in the non polar environment of the NABF phase. Clays are pre-reacted with oil wetting agents, aliphatic amine salts and quaternary ammonium salts to form a clay-organic product which can be dispersed in oil. High levels of shear are required to develop full yield and viscosity from these clays. This is initially only partially achieved in mud plants using vigorous blending with centrifugal pumps. Complete yield is most rapidly obtained by circulation through the drilling bit nozzles. Montmorillonite is most commonly used and is compatible with diesel and mineral oils up to 350 °F (177 °C). For temperatures above 325 °F (163 °C), especially in synthetic fluid and mineral oil formulations, hectorite based clay should be used. Polymeric Viscosifiers Polymeric viscosifiers are additives that increase the viscosity of NAF in the presence of orgonophilic bentonite, especially when the orgonophilic bentonite performance is reduced by high temperatures; they work up to 400 °F (204 °C). A high molecular weight sulphonated polystyrene becomes effective only when the temperature exceeds 250 °F (121 °C). Rheological Modifiers Rheological modifiers are low molecular weight fatty acids which provide an increase in viscosity at low shear rates, 3 and 6 rpm. Barite can “sag” or slide down the hole, especially on deviated wells; these additives will aid in minimising or eliminating this “sag” providing there is a good base rheology from organophilic clays. Increases in total mud viscosity are minimised when using these additives. Amine Lignite Lignite is treated in a similar process to clays to make it dispersible in oil. High temperature filtration control is improved by plugging of the filter cake by the lignite particles. It can be used at high concentrations without causing excessive viscosities ( 20 lb/bbl or 57.2 kg/m3). Asphaltic Fluid Loss Additives Asphaltic fluid loss additives generally consist of gilsonite or asphalt derivatives. Gilsonite has high temperature stability 400 °F (204 °C) whereas asphalt is not as temperature stable 250 °F (121 °C). High concentrations can cause excessive viscosity and gelation of the mud. Treatment level will not usually exceed 15 lb/bbl (43 kg/m3). The Internal Water Phase Water, or more commonly, brine is dispersed throughout the continuous oil phase in the form of discrete droplets ranging in size from submicron to a few microns in diameter. In general, the tighter the emulsion, the smaller will be the droplets. These droplets perform as a solid in the fluid imparting basic viscosity and filtration control. The viscosity of an emulsion increases with increase in the proportion of the dispersed phase. By calculation the maximum packing of spheres of uniform diameter is 74% of the gross volume. This can however be exceeded, as the droplets are not of uniform size and are deformable. It is largely this deformable nature that produces the filtration characteristics of invert emulsions. In practice this maximum packing is not approached. Some 40:60 OWR inverts have been run successfully in the field (at low mud weights). If the continuous oil phase is of relatively low volume (i.e. 60/40 compared to 85/15) there is little room for insoluble solids i.e., these systems offer poor solids tolerance.

Water in the internal phase is not completely isolated from the formation but may interact by osmotic movement of water across the layers of surfactants between the oil and water phases. An efficient osmotic membrane, or semi-permeable membrane, offers little resistance to transit by water, but restricts movement of solutes, especially salts and high molecular weight sugars.

The Role of Salt (CaCl2 or NaCL) in OBM To prevent hydration of clays, reduce volume of high cost oil phase and activate organophilic day Formation

Migration of water from the dilute solution to the concentrated solution

OBM

OSMOSIS

OSMOSIS

Semi permeable membrance

Semi permeable membrance (skin) of emulsifier molecules formed on the face of the well bore

This layer acts as a semi permeable membrane which will allow any imbalance in osmotic pressure to equalise by movement of water molecules. Essentially the tendency will be for strong brines to be diluted by the intake of water molecules from lower salinity fluids. Consequently, salts are added to the water phase of inverts in attempts to prevent undesirable osmotic movement of water. If the brine is of higher salinity than the formation, interstitial water will be drawn from the formation which may cause dehydration and instability. In practice this is not as significant a problem as water transfer from the invert brine phase to the formation which can destabilise clays/shales by hydration. Salinity levels actually correspond to the relative humidity (RH) or activity of the brines and this process of adding salt to invert brine to equal the RH of the in situ formation brine is known as balanced activity.

Formation

No migration

OBM

X

of water

Chloride concentration balanced ie in a state of equilibrium between formation and the mud

Section

8

NAF fundamentals

Calcium chloride is usually selected to adjust brine phase activity. Activities as low as 0.32 can be achieved with saturated CaCl2. Osmotic pressure in excess of 10000 psi (68970 kPa) has been achieved and measured. Saturated sodium chloride has an RH of 0.75 and consequently offers less flexibility. Continuous Oil Phase Almost any NABF can be used as the external phase of an invert emulsion. Historically for drilling fluid purposes the most common oil used was diesel oil. Increasing environmental awareness has resulted in the replacement of diesel by mineral oils of low aromatic content referred to by the general term “low toxicity” oils or synthetic oils. It is the oil phase that accommodates all the insoluble solids. As plastic viscosity is directly related to interparticle action of these insoluble solids it follows that for a given solids content, higher oil/water ratios will produce lower plastic viscosities. Weighting Agents Weighting agents are used to increase the density of the oil mud. The most commonly used weighting agent is barite. A mud weight of around of 21.0 lb/gal (2.52 SG) is the highest achievable with barite. Hematite, with a S.G. of 5.0 can also be used to increase the density of the oil mud. A mud weight of around 24 lb/gal (2.88 SG ) can be achieved with fine grind hematite.

properties of base fluids The properties of base fluids can have a significant effect upon the physical properties of the oil mud. The properties of the oil which are tested are: ƒ Flash Point - a measure of the volatility of the base fluid. The higher the flash point of the oil, the less likely the oil mud will catch fire. The flash point of an oil will change with age as the more volatile components of the oil vaporise into the atmosphere. In practice, once the oil is incorporated into an invert mud, the water phase provides an extinguishing effect greatly increasing flash points. The flash point of the oil should be greater than 150 °F (65.6 °C). ƒ Aniline Point - This is defined as the minimum equilibrium solution temperature for equal volumes of aniline and solvent which, in the case of invert emulsions, is the base fluid. The aniline point relates to the percentage of aromatics in the base fluid - the lower the aromatic content the higher will be the aniline point. In general high aniline point, and therefore low aromatic content oils are desirable to minimise damage to rubber parts in pumps and downhole tools. This is a simplification as other factors, particularly temperature are involved in the deterioration of rubber. The aniline point should be at least 140 °F (60 °C). Certain oil mud products such as the organoclay viscosifiers are affected by the amount of aromatic components in the base fluid. As the aromatic content is decreased, more viscosifier will generally be required or a different viscosifier will have to be used. ƒ Kinematic Viscosity - In general, base fluids which exhibit low viscosity within a stipulated temperature range are preferred as they allow reductions of mud viscosity with dilution if required. High viscosity oils tend to form viscous muds especially at low temperatures (e.g., in marine risers) which impair hydraulics efficiency and can cause induced fracturing of formations and increased oil retention on cuttings. Crude oils usually have very high viscosities because of higher asphaltic components, whereas the refined oils have considerably lower viscosities. Addition of brine and solids to an oil increases its viscosity substantially, but the viscosity of any mud is generally proportional to the viscosity of the base fluid. ƒ Aromatic Content - a measure of the quantity of aromatics or benzene-like compounds in the oil. These are the compounds that will affect the toxicity of the base fluid with the higher content of aromatics, the more toxic the oil mud will be. Most of the mineral oils and synthetics now used in NAF have a aromatic content less than 1% by weight. Other factors such as sulphur content affect toxicity. Toxicity testing is performed before governmental approval for use is granted.

10

mixing procedures The addition of components in their proper sequence when initial mixing an oil mud will optimise the performance of each product. The order of addition as listed below is the most common procedure for preparation of NAF, though each mud system may require some modification of this procedure. The mixing time may vary depending upon the amount of shear either at the rig or at the liquid mud plant. Organophilic viscosifiers require a considerable quantity of shear to fully develop their viscosity. Therefore, more of this additive may be required on initial mixing. As the oil mud is used over the first couple of days, improvement in the emulsion stability and fluid loss control will vastly improve compared to what the mud was when it was initially mixed. 1. 2. 3. 4. 5. 6. 7. 8. 9.

Add the required quantity of base fluid to the mixing tank. Add the primary emulsifier and secondary emulsifier as required. Add organophilic viscosifier as required. Add filtration control additives if required. Add lime as required. Add required amount of water to the above mixture. If brine is to be used, then add brine after the lime additions. Add calcium chloride powder if brine is not used. If calcium chloride powder is not available, then mix the calcium chloride flakes into the water and add as a brine. Mix above for several hours to ensure a good emulsion is formed. Add weighting material as required for the desired density.

The viscosity contributed by the organophilic gellant will be higher if it is added to the mud after the water is added and before the calcium chloride is added. If brine is used, then the gellant is added after the brine and the viscosity will generally be lower. The electrical stability of the mud after mixing will initially be lower if brine is used compared with adding calcium chloride to the mud after the water is added. The electrical stability and fluid loss control will improve after use due to the shear generated during circulation.

NAF properties Mud Weight and Solids Content In a correctly formulated oil mud drilled solids will not hydrate or chemically disperse. Fine solids can still be produced by mechanical attrition. This being the case use of centrifugal pumps must be minimised. Centrifuges should be fed by positive displacement pumps and mud cleaners should not routinely be used. The recent development of vortex type centrifugal pumps may in future alter this approach as attrition by an impeller does not occur in this type of pump. In the non polar environment of an oil continuous fluid polar actions between charged particles cannot occur; consequently all solids essentially become inert. This is why NAF generally exhibit far better solids tolerance than water based muds. Even so it is still essential to control low gravity solids to:

11

Section

8

NAF fundamentals

ƒ minimise chemical additions - the mechanical degradation of solids produces large surface areas with a high requirement for surfactants. ƒ minimise plastic viscosities - again the attrition of drilled solids produces increased mechanical interaction of solids within the oil phase which in turn produces increased plastic viscosities. ƒ reduce the necessity for centrifuging and reconditioning in mud plant. Disposal of centrifuge discard is becoming increasingly difficult on land. It is important to remember that as virtually all non dissolved solids are contained in the continuous oil phase of an invert emulsion increased solids tolerance and improved flow properties are achieved with increased oil/water ratio. Consequently, when high mud weights are required or when particularly good rheology (i.e., high YP/PV ratio) is required for efficient cleaning of deviated holes, a high oil/water ratio must be selected. Mud weight in NAF is temperature dependent – for instance a fluid with a weight of 10.2 lb/gal (1.22 SG) at 80 °F (26.7 °C) can be expected to be 10 lb/gal (1.2 SG) at a flow line temperature of 140 °F (60 °C). This is due to the high thermal expansion of the base fluid used in the formulation of the fluid. Under downhole conditions this decrease in mud weight with temperature is largely overcome by increases in density with pressure. Plastic Viscosity In a water based fluid plastic viscosity, PV, is directly related to the solids content. In an oil mud however this relationship is complicated by the brine droplets of the internal phase that have a similar effect as solids. For a given yield point the PV will effectively find its own level and significant reductions can best be achieved by increasing the oil content, hence reducing interparticle action, i.e., of water droplets and drill solids. While drilling ahead a judicious combination of centrifuging and dilution should be used to control the plastic viscosity. Eventually solids will be broken down by attrition to below the cut point of the centrifuge and dilution with base fluid or newly formulated mud is the only means of subsequently reducing this parameter. Yield Point The yield point, YP, as with all other rheological parameters is measured at 120 ° F (48.9 °C). Increases are made with an organophilic clay which is specially treated to be dispersible in the continuous oil phase. To avoid over treatment with viscosifier it should be remembered that organophilic clays may, depending upon type and shear conditions, take a considerable time to fully yield. While it is of course necessary to ensure that the yield point is sufficiently high to promote efficient hole cleaning, it should also be remembered that unnecessarily high viscosities can cause excessive pump pressures and inefficient solids separation. This in turn results in increases in oil retention on cuttings and dilution requirements. Reduction of YP can be achieved with oil mud thinners or base fluid additions. Low Shear Rheology The importance of maintaining good low shear rheology (6 RPM readings) increases with increasing hole deviation. Cuttings which tend to settle on the low side of the hole will only be removed efficiently by a fluid with high low 6 RPM readings, or by a fluid in turbulent flow.

12

High Temperature/High Pressure Filtrate Filtration control in NAF is largely related to emulsion stability. The emulsified water droplets act as colloidal solids that deform under pressure and, in conjunction with solids in the fluid, form effective filter cakes. The HTHP filtrate should be all oil. However, by running the test 25 °F (14 °C) above BHT and accepting a trace of water in the filtrate overtreatment is avoided. The theory is that if only a trace of water is in the filtrate at, say 250 °F (121 °C), the filtrate at a lower temperature would be all oil. If no water was present at 250 °F (121 °C), the fluid could be considered to be over specification and therefore over treated. Specifically designed products such as amine treated lignite are available should particularly low filtrate rates be required. The standard test is at 250 °F (121 °C) and 500 psi (3449 kPa) differential pressure. An occasional test should be run at a lower temperature, say 200 °F (93.3 °C), to confirm that an all oil free filtrate is produced at prevailing down hole temperature. If BHT exceeds 250 °F (121 °C) perform standard tests at 300 °F (149 °C) with check test for water in filtrate at 250 °F (121 °C). Oil/Water Ratio The prime consideration when selecting an oil/water ratio is, as previously explained, mud weight. Other factors should be considered; primarily the likelihood of water or brine influxes. Sufficient oil should be in the system to accommodate such influxes. Low oil/water ratio fluids may offer the benefits of lower cost and marginally lower oil retention on cuttings, they are however less tolerant to solids and brine/water influxes. High oil/water ratios are selected for highly deviated wells to provide maximum lubricity and to provide the high YP/PV ratio required to ensure efficient hole cleaning. Alkalinity and Excess Lime Claims are made that many modern emulsification packages do not require lime to function correctly. There is however strong field evidence to show that lime does improve product function particularly at high BHT, above 300 °F (149 °C). Lime is also added to buffer the system against influxes of the acid gases H2S and CO2. Generally an excess lime content of 3 lb/bbl (8.58 kg/m3) is sufficient but if hydrogen sulphide is expected this should be increased to 5 lb/bbl (14.3 kg/m3). Electrical Stability Known as ES, this test measures the voltage required to break down the continuous oil phase and allow the passage of current across two electrodes via the brine phase. Stability is related to the size of brine droplets which in turn is related to the concentration of emulsifier present and the energy, shear, applied to the emulsion.Different NAF fluids exhibit markedly different ES levels and it is difficult to specify a definitive minimum value. Essentially this test should be used in conjunction with the HTHP filtrate test to establish adverse trends in the emulsion stability allowing corrective treatment to be undertaken. This test becomes particularly unreliable when drilling massive salt sections because the salt suspended in the fluid interferes with conductivity. Oil Wetting The major advantage of continuous oil phase fluids is that formations are only contacted by the non polar oil. Most emulsifiers supply a degree of oil wetting and many invert formulations include a specific oil wetting agent. Should sufficient oil wetting surfactants not be present in a system problems may occur when drilling water wet formations. Water wet cuttings can be generated and may associate through polar action to produce high viscosities, solids settling and blinding of shaker screens. Similar problems can occur if insufficient surfactant is present to satisfy the surface requirements of barite additions. In general the addition of emulsifiers and wetting agent will thin an invert containing water wet solids. Avoid overtreatment as excessive thinning of rheology may occur.

13

Section

8

NAF fundamentals

Note: Difficulties exist in weighting new NAF beyond 15.0 lb/gal (1.8 SG) in mud plants. When heavier muds are required increases must be made at the rig site. It is imperative that the surface requirements of the barite additions are met with adequate oil wetting agent and emulsifier additions. A small excess is preferable to undertreatment. Salinity Salinity Measurements of calcium and sodium chloride are performed on the whole mud. Undissolved calcium chloride can cause water wetting problems and should be dissolved by adding water or oil mud premix with no salt in the water phase. Insoluble sodium chloride can be reduced in the same manner, but it does not cause water wetting of solids. Sulphides Sulphides in the oil mud are measured with the Garrett gas train. A sample of whole mud is used instead of filtrate. Zinc oxide is the preferred compound to treat for soluble sulphides. Increased lime additions are also necessary when H2S is present.

trouble shooting NAF PROBLEM

SOLUTIONS AND INDICATORS

Low viscosity

Add water and emulsifier, add gellant. If high temperature add polymeric viscosifier. All of these affect the low-shear viscosity, gel strength and yield point more than the plastic viscosity. Remove low gravity solids with solids control equipment and/or dilution. Increase o/w ratio if water content is too high. Add oil wetting agent to reduce viscosity. Remove water wet solids and add oil wetting agent and oil. Ensure that there is no insoluble calcium chloride in the mud. Water wet solids will blind screens and give low E.S. readings. Suspected water wet solids added to water will disperse easily. Water wet solids, un-dissolved solids, inadequate concentration of emulsifiers, inadequate concentration of lime for emulsifiers, and some weighting agents (such as hematite) generate low electrical stability readings. All except hematite require chemical treatment. Most muds made with mineral oil will have lower electrical stability than those made with diesel. Low viscosity muds usually have low electrical stability readings. Mud viscosity will increase and electrical stability readings will decrease even though emulsifier concentration is adequate. Improve solids removal efficiency. Use dual centrifuge to remove drill solids while recovering the barite and oil phase. Add additional emulsifier if water appears in filtrate. Organo-lignite will also emulsify water and lower filtrate. Ensure mud has excess lime. Newly formulated mud may have high HPHT until properly sheared. Sometimes small amounts of water will lower HPHT in high O:W ratio muds. Organo-lignites are not effective when bottom hole temperature is less than about 150 °F (65.6 °C) Detected in mud by drop in alkalinity. If H2S is detected by the Garrett gas train, alkalinity has decreased so increase lime additions. Maintain lime additions and add sulphide scavenger such as zinc oxide. If carbon dioxide is present, add lime.

High Viscosity Water Wet Solids

Low ES

High Solids

High Filtrate

Acid Gas

14

PROBLEM

SOLUTIONS AND INDICATORS

Mud Losses

If loss is not complete, use oil-wettable fibrous material or solid bridging material such as calcium carbonate. Use same technique for seepage losses to minimise thick filter cake and differential sticking. If losses are complete, consider organophilic clay squeeze, cement or displacing to water based mud until loss zone is cased off. After periods of inactivity, free oil may cover the surface of the pits. Agitate the mud in the pits or add organophilic clay to increase viscosity.

Free Top Oil

spacers for displacing NAF displacing NAF to the hole In the typical situation, top hole sections are drilled with water based mud and the fluid to be displaced out of the casing afterwards is usually seawater. In this case the density difference between the two fluids and the zero gel strengths of the seawater will ensure that channelling does not occur. If weighted water based mud is to be displaced from the hole efforts should be made to thin the fluid immediately ahead of the oil mud. To summarise the two situations described above: Displacing Seawater out of hole No spacer is generally required. However, if pit space allows, 50 bbl (8 m3) of active mud with organophilic clay, ±10 lb/bbl (28.5 kg/m3), can be viscosified and pumped ahead of active mud. Displacing Water Based Mud out of Hole Thin one pit of water based mud with water (if hydrostatic head requirements allow) or chemical thinners (FCL, Desco or SAPP) if hydrostatic must be maintained. Thicken 50 bbl (8 m3) of active NAF with organophilic clay, ±10 lb/bbl (28.5 kg/m3). Recommended pumping sequence: ƒ Thinned WBM ƒ Viscosified NAF ƒ NAF Note: ƒ Pump as fast as possible while displacing. ƒ Rotate pipe ± 60 rpm while displacing. ƒ Since the majority of displacements are within cased hole, accurate calculation of pump strokes required for displacement are possible. When the WBM/NAF interface is due at surface slow mud pumps and observe flowline/header tank. ƒ Ensure the header tank (possum belly) is empty during displacement. This avoids mixing of NAF and WBM in header tank when NAF arrives at surface. ƒ At first appearance of NAF shut down pumps and line up gates and shakers to begin circulation of NAF.

15

Section

8

NAF fundamentals

displacing NAF out of the hole The usual problem with this type of displacement is that the NAF is being displaced with a lighter density water based fluid of low viscosity over considerable annular lengths. All of these conditions are liable to promote channelling of the displacement fluid. If reverse circulation is possible these problems will be avoided. If conventional circulation is necessary it is advisable to reduce the viscosity of the NAF and to ensure good separation by use of a viscous water based spacer. Thin one pit of NAF with base fluid (if hydrostatic head requirements allow) or thinner if hydrostatic head must be maintained. Prepare 50 bbl (8 m3) of viscous water base spacer, 3 lb/bbl (8.6 kg/m3) HEC or Xanthan Gum in brine or seawater). Recommended pumping sequence: ƒ Thinned NAF ƒ 25 bbl (4 m3) base fluid* ƒ 50 bbl (8 m3) viscous HEC/Xanthan spacer ƒ Seawater / brine / WBM * If pit space, or cement unit, is available. If not follow thinned NAF with HEC/Xanthan spacer. Note: a) Pump as fast as possible while displacing to minimise time for annular migration of lighter displacement fluid. b) Reciprocate and rotate pipe (± 60 rpm) while displacing to break gel structures in NAF. c) Displace NAF to mud pits/boat together with base fluid spacer and any contaminated interface. d) Ensure header tank (possum belly) is empty immediately prior to interface arrival. This avoids mixing of WBM with NAF in the header tank. e) The thinned mud/base fluid spacer should be recognisable at surface. Slow pumps and shut down when high viscosity HEC/Xanthan pill is observed. Line up gates and shakers for circulation of water based fluid.

cementing with oil based muds Many factors are involved in achieving a good cement job with oil based mud in the hole. Of prime concern is the displacement of mud from the length of annulus to be cemented and subsequent water wetting of the casing. To achieve this a suitable spacer fluid must be selected. The spacer should ideally meet the following criteria: a) Compatibility with mud and cement. A spacer that severely thickens the mud at the interface could produce significantly increased pump pressure. b) High surfactant concentration to water wet casing. c) Rheological properties conducive to a turbulent flow regime. d) Sufficient suspension characteristics to suspend weight material. To meet these requirements the following procedure is recommended: ƒ Pump 10 bbl (1.6 m3) of base fluid. Its low viscosity should ensure turbulence while it is being pumped. The oil in turbulent flow will thin the NAF adhering to the casing and facilitate its removal by the surfactant spacer. 16

ƒ Pump sufficient surfactant spacer to ensure a contact time of at least ten minutes e.g., 50 bbl (8 m3) if pumping at 5 bbl/min (795 L/min). This spacer should be formulated at a weight midway between the weights of the mud and the cement. Xanthan Gum should be used as the viscosifier; this produces a highly shear thinning fluid yet possesses good suspension characteristics. This spacer should be of the minimum viscosity that is capable of suspending barite. A typical formulation for 50 bbl (8 m3). pumpable is:

Seawater Caustic Soda Xanthan Barite Surfactant

55 bbl (8.75 m3) 0.5 lb/bbl (1.43 kg/m3) 0.75 lb/bbl (2.15 kg/m3) As required 12 x 25 litre cans

The Surfactant should be added directly to the slug pit immediately prior to pumping to avoid foaming. It is preferable to use the cement unit to pump both the base fluid and the surfactant spacer. This ensures that all the spacer goes ahead of the cement. Using the rig pumps will result in a loss of some of the spacer in the lines from the pump to the rig floor. High displacement rates will result in a better displacement. However, pump rates might be limited by increasing ECD values which can result in formation breakdown and subsequent loss of large volumes of mud. When pumping and displacing cement careful observation of the active pit must be maintained to detect mud losses. If losses occur a reduction in pump rate should be considered to reduce the rate of loss. During displacement of the cement, pipe movement, both rotation and reciprocation, will enhance mud displacement as will correct centralisation of the casing. In the event that cement is not planned to come to surface a suitable volume of water based spacer treated with caustic soda and corrosion inhibitor can be pumped ahead of the surfactant spacer to displace all of the NAF out of the annulus. Prior to formulating this spacer consideration must be given to formation type and hydrostatic requirements. An allowance should be made for over gauge hole resulting from mechanical erosion or solution of salts. This is of particular significance on deviated wells where the increase in hole size due to mechanical erosion can be substantial. Any cement and spacer seen at the surface should be separated and disposed of. Great care must however be taken to ensure that oil based mud is not dumped. If contaminated mud is detected this should be diverted to a separate pit and reconditioned or disposed of in the proper manner. Reverse circulation to clear the pipe of excess cement will greatly reduce contamination of the drilling fluid system. When the cement job is completed an inspection of the flowline and shaker area, particularly the header box, must be made to ensure these areas are free of cement. Prior to a cement job, particularly a large one, calculations should be made to ensure enough spare pit volume is available to receive displaced mud. This should be calculated well in advance of the job as it may be necessary to organise a boat for back-loading oil based mud prior to or during cementation.

17

Section

8

NAF fundamentals

types of base fluids There are three main types of invert emulsion mud systems, based on the chemical composition of the base fluid in the mud. These are oil based muds (OBM), enhanced mineral oil based muds (EMOBM), and synthetic based muds (SBM).

oil base mud (obm) OBM contain diesel fuel or conventional mineral oil as the continuous phase. They are the least expensive invert emulsion systems and were the only ones in use until the late 1980s. Mineral oils were developed as low-toxicity replacements for diesel fuel in the OBM in an attempt to reduce the environmental impacts of discharge of OBM contaminated drill cuttings.

enhanced mineral oil base mud (emobm) EMOBM contains an enhanced mineral oil as the continuous phase. Enhanced mineral oils are conventional paraffinic mineral oils that have been hydrotreated or otherwise purified to remove all aromatic hydrocarbons. Enhanced mineral oils generally contain less than about 0.25 percent total aromatic hydrocarbons and less than 0.001 weight percent total polycyclic aromatic hydrocarbons. One of the enhanced mineral oils evaluated contained less than 1 mg/L benzene. Aromatic hydrocarbons, including polycyclic aromatic hydrocarbons, are considered to be the most toxic components of OBM.

synthetic base mud (sbm) what does “synthetic” mean? In order to really define “synthetic”, as it applies to drilling fluids, it is necessary to review the nonaqueous fluid (NAF) offshore disposal regulations as legislated in several parts of the world. This includes NADF regulations from Europe (OSPAR, 2000), the United States (USEPA, 2001), Canada (CNOSP, 2002), and Australia (DoIR, 1999). Also included is a review of NADF by the International Association of Oil and Gas Producers (OGP, 2003). Base fluid Process Europe Canada US Australia OGP (2000) (2002) (2001) (1999) (2003) diesel refinery extraction OBM1 OBM OBM OBM OBM mineral oils/ refinery OBM OBM OBM OBM OBM paraffins extraction mineral oils/ refinery SBM2 EMOBM EMOBM NA4 EMOBM paraffins extraction and 3 severe hydro-treatment synthesised Fischer - Troph SBM SBM SBM NA SBM paraffins or LAO hydro-formulation linear alpha ethylene olefins oligomerisation SBM SBM SBM SBM SBM internal olefins LAO SBM SBM SBM SBM SBM ethylene esters condensation of SBM SBM SBM SBM SBM fatty acids and alcohol 1 OBM = oil base fluid 2 SBM = synthetic base fluid 3 EMOBM = enhanced mineral oil base fluid 4 NA = not addressed

18

As the chart shows, all the regulatory bodies and organizations agree that diesel, mineral oil and paraffins extracted from refineries are oil base muds (OBM). They also agree that synthetic base muds (SBM) include paraffins produced via Fischer Tropsch (gas to liquids) or linear alpha olefin hydro formulation processes, linear alpha olefins, internal olefins, and esters. Controversy, however, continues over fluids extracted from refinery streams that are severely hydrotreated. Hydrotreatment is a processing step used to convert aromatics in fluids to paraffins. In the process, some minor chemical reactions occur as the aromatics are treated. Europe’s OSPAR classifies such fluids as “synthetic”. The US EPA, CNOSP and OGP classify these products as neither an SBM nor an OBM, but instead create an entirely new category known as enhanced mineral oil base mud (EMOBM). The EPA (EPA 1996) defines a “synthetic material”, as applied to synthetic based drilling fluids, as: “A material produced by the reaction of a specific purified chemical feedstock, as opposed to the traditional base fluids such as diesel and mineral oil which are derived from crude oil solely through physical separation processes. Physical separation processes include fractionation and distillation and/or minor chemical reactions such as cracking and hydro processing. Since they are synthesized by the reaction of purified compounds, synthetic materials suitable for use in drilling fluids are typically free of polycyclic aromatic hydrocarbons (PAH) but tests sometimes report levels of PAH up to 0.001 weight percent PAH expressed as phenanthrene.” The Norwegian regulatory authority defines a SBM as (Norway 1997): “A drilling fluid where the base fluid consists of non water soluble organic compounds and where neither the base fluid nor the additives are of petroleum origin.” characteristics of synthetic fluids Base Chemicals Synthetic base fluids may be classified into four general categories: ƒ synthetic hydrocarbons ƒ ethers ƒ esters ƒ acetals The chemistry of these basic classes of synthetic base materials is discussed in the following and example chemical structures are shown in Table 1. TYPE

CHEMICAL STRUCTURE Synthetic Hydrocarbons

Linear Alpha Olefin (LAO) CH3 - (CH2)n - CH = CH2 Poly Alpha Olefin (PAO) CH3 - (CH2)n - C = CH2)m - CH3 (CH2)p - CH3 CH3 - (CH2)m - CH = CH - (CH2)n - CH3 Internal Olefin (IO) CH3 - CH - (CH2)n - CH3 Linear Alkyl Benzene (LAB) C6H5 Other Synthetic Base Chemicals

Ether Ether

Acetal

CH3 - (CH2)n - (CH2)n - CH3 CH3 - (CH2)n - C = O O - (CH2)m - CH3 CH3 - (CH2)n - O O - (CH2)n - CH3 CH - (CH2)m - CH3 19

Section

8

NAF fundamentals

Synthetic Hydrocarbons Polymerised olefins are the most frequently used synthetic hydrocarbons in SBM today. Polymerised olefins include linear alpha olefins (LAO), poly alpha olefins (PAO), and internal olefins (IOs), Linear paraffins (LP) (also sometimes called n-paraffins) sometimes are included in this class; however, they usually are prepared from a petroleum feedstock. Synthetic linear paraffins are available commercially for use in SBM, but are not widely used because of their cost. Synthetic paraffins are produced by the low-pressure Fischer-Tropsch synthesis, involving catalytic hydrogenation of carbon monoxide. Because EPA classifies synthetic paraffins as SBM, synthetic LP cuttings are permitted for offshore discharge in the Gulf of Mexico. Linear Alpha Olefins (LAO) LAO are produced by the polymerisation of ethylene. Ethylene (C2H4), the smallest unsaturated hydrocarbon, is oligomerised by heating in the presence of a catalyst and triethyl aluminium to produce LAO with different hydrocarbon chain lengths. Each LAO molecule has a single, double bond in the alpha position (between the first and second carbon in the chain) (Table 1). LAO have molecular weights ranging from 112 (C8H16) to 260 (C20H40). The LAO mixture is distilled to produce different molecular weight blends. The physical-chemical properties of the mixtures can be altered systematically by changing the chain lengths and branching of the LAO molecules. Typical LAO mixtures used in SBM are LAO C14C16 (a blend of C14H28 and C16H32 LAO) and LAO C16C18. In a typical LAO, about 28 percent of the molecules contain branching; most branches are methyl groups (-CH3). Poly Alpha Olefins (PAO) PAO are manufactured in a four- to five-step process: 1. 2. 3. 4. 5.

polymerisation of ethylene to form a series of linear alpha olefins distillation to isolate LAO of the desired chain length oligomerisation of the LAO to produce PAO hydrogenation to saturate the PAO (sometimes) distillation to isolate PAO with the desired physical-chemical properties.

Typical LAO used to manufacture PAO include 1-octene (C8H16) and 1-decene (C10H20). PAO may be hydrogenated, producing alkanes for some applications. However, the unsaturated PAO is more biodegradable than the saturated alkane; therefore, unsaturated PAO are preferred to the saturated congeners in applications where PAO cuttings may be discharged to the ocean. Depending on the chain length of the LAO and the nature of the oligomerisation reactions, PAO can be produced with varying degrees of branching and carbon chain lengths. In a typical PAO SBM, more than 90 percent of the molecules have branching. The PAO fluid may contain a mixture of several PAO from C8H16 to C30H62 and sometimes to C40H82. The average PAO is C20H42 (Eicosane) with a molecular weight of 282.6 and an aqueous solubility less than 1 mg/L. Internal Olefins (IO) IOs are formed by isomerisation of LAO in the presence of heat and a suitable catalyst. Isomerisation shifts the double bond from the alpha position to a position between two internal (Table 1). Isomerisation of a LAO decreases its pour point and flash point. Commercial IO usually has a chain length of 16, C16H32, or 18, C18H36, carbons, and usually contain more than 20 percent internal branching.

20

As with LAO and PAO, the IO mixture may be hydrogenated to produce saturated hydrocarbons; however, they are still referred to as LAO, PAO, and IO. In today’s market, LAO and IO usually are preferred over PAO. LAO and IO often is used in blends that are designed to achieve a balance among the physical properties important to the drilling operation (e.g. viscosity, pour point, flash point, etc.). Ethers Alcohols with different chain lengths are condensed and partially oxidized to produce mono- and diethers. Ethers are saturated hydrocarbons with an oxygen atom in the centre (Table 1). Hydrocarbon chain lengths and branching are selected to optimise drilling properties and minimise toxicity. Ethers are more stable both chemically and biologically than esters or acetals. Ether SBM have a high hydrolytic stability. This is an advantage during drilling, but results in low biodegradability following ocean disposal of SBM cuttings. At one time, ethers were used frequently in the North Sea; before September 1994, ether or acetal SBM were used to drill 13 wells in the UK Sector of the North Sea. However, they are no longer used in the North Sea. Ethers have never been used in U.S. offshore waters. Acetals Acetals are dialkylethers that are closely related to ethers. They are formed by the acid-catalysed reaction of an aldehyde with an alcohol or carbonyl compound (One mole of aldehyde and two moles of alcohol). A typical acetal in a SBM has the formula, C20H42O2, and has a molecular weight of 314.3. Acetals are relatively stable under neutral and basic conditions, but may revert back to the aldehyde and alcohol under acidic conditions. At one time, acetals were used frequently in the North Sea; however, they are not used today. Acetals have never been used in U.S. waters. Esters Esters are formed by the reaction of a carboxylic acid with an alcohol under acidic conditions. The ingredients of esters used in SBM include fatty acids (carboxylic acids) with 8 to 24 carbons and alcohols with different chain lengths. 2-Ethylhexanol (C8H18O, molecular weight 130.2) is the alcohol used most frequently, however, mono- and poly-hydric alcohols (glycerols) may also be used. The fatty acids usually are derived from natural vegetable or fish oils. They also can be made by oxidation of the terminal double bond of LAO. An example of ester used in SBM is a mixture of C8 through C14 fatty acid esters of 2-ethylhexanol. The first ester SBM system consisted of a mixture of five homologous fatty acid esters, of which the main component was 2-ethylhexyl dodecanoate. A typical ester has a molecular weight of 396.4 and the chemical formula, C26H52O2. Esters are somewhat polar and more water soluble than would be expected from their molecular weights. Chain length and branching of the fatty acids and alcohol are modified to optimise viscosity, pour point, and hydrolytic stability. Esters also may be mixed with synthetic hydrocarbons (LAO, IO, or PAO) in an SBM to attain some particular drilling performance characteristic. Esters are relatively stable under neutral conditions, but may undergo hydrolysis and revert back to the acid and alcohol under basic or acidic conditions. Esters are commonly used in the North Sea and have been used extensively in the Gulf of Mexico.

21

Section

8

NAF fundamentals

environmental performance By reviewing product classifications, we learn that the “synthetic” label has little bearing on environmental impact. There are differences between products labelled SBM, OBM, and EMOBM. Even within a certain class of compounds (e.g. paraffins), some products may have less environmental impact than others. Not all drilling base fluids have equal environmental performance. Differences in physical/ chemical characteristics result in differences in key environmental performance criteria such as aerobic biodegradability, anaerobic biodegradability, water column toxicity and sediment toxicity. The environmental properties of base fluids depend on the physical and chemical characteristics of the material. Classification (e.g. whether a product is a “synthetic”) or point of origin does not necessarily guarantee specific environmental performance. Field environmental fate and effects data assessment is generally viewed as the best practice to understand the potential environmental impact of a base fluid. In the absence of field data, laboratory biodegradation and toxicity test data is recommended to assess environmental fate and effect. An overall assessment of potential environmental impact can only be completed when a full environmental data set is available. This includes both anaerobic (absence of oxygen) and aerobic (presence of oxygen) biodegradation test data as well as water column and sediment toxicity test data. The following table illustrates typical toxicity test data of some drilling base fluids for selected water column species. Compound Mysid SPP1 Fathead 96-h LC50 Minnow2 (mg/L) 96-h LC50 (mg/L) internal olefins > 1000 alpha olefins > 1000 synthetic paraffin 1 > 1000 synthetic paraffin 2 > 1000 synthetic paraffin 3 > 1000 diesel 100 - 300

Daphnia magna2 48-h EC50 (mg/L) > 1000 > 1000

1 Seawater test 2 Freshwater test

Water column toxicity test results generally show that olefin and paraffin base fluids are non-toxic to water column organisms, but diesel base fluids do exhibit toxicity. When toxicity to sediment-dwelling organisms is considered, internal olefin and some alpha olefin products have significantly lower toxicity compared to most paraffinic materials. The table that follows illustrates typical relative sediment toxicity data for several types of base fluids.

22

Compound 1618 Internal olefin internal olefin 2 alpha olefin 1 alpha olefin 2 synthetic paraffin 1 synthetic paraffin 2 synthetic paraffin 3 synthetic paraffin 4 synthetic paraffin 5 diesel

Relative sediment toxicity 1 1.0 0.6 28 1.0 15 16 19 6.0 1.0 18

1 Relative sediment toxicity compared to C16,18 internal olefin.

Higher relative values indicate greater sediment toxicity. The type of olefin or paraffin makes a difference. Most paraffins and some olefins that can be used as base fluids have significant sediment toxicity, similar to that of diesel. Biodegradation test data for both aerobic and anaerobic conditions are summarised in the table that follows. Compound Aerobic biodegradation (%)1 internal olefin 1 internal olefin 2 60 - 80 alpha olefin 1 60 - 75 alpha olefin 2 60 - 75 synthetic paraffin 1 55 - 60 synthetic paraffin 2 synthetic paraffin 5 63 synthetic paraffin 6 > 90 Diesel 60 - 75

Anaerobic biodegradation (%)1 50 - 55 55 - 60 60 - 80 50 - 60 17 10

3

1 Aerobic biodegradation assessed by OECD 301 or 306. 2 Anaerobic biodegradation assessed by modified ISO 11734.

The need to drill increasingly difficult deviated and deep-water wells, coupled with the desire to discharge cuttings, led to the development of SBM. SBM is designed to be less toxic and degrade faster than OBM, and they yield mud systems similar to OBM in drilling performance. Furthermore, synthetics have certain technical and human health advantages over most mineral oils and diesel fuel. For example, they are less volatile than OBM and their vapours are free of aromatic compounds. Thus, the use of SBM can reduce vapour inhalation by workers in closed, poorly ventilated areas on the drilling platform. In many cases, SBM does not appear to have better drilling properties than OBM, although they are much more expensive than OBM. However, if the discharge of cuttings associated with SBM is allowed and the discharge of cuttings associated with OBM is prohibited, the higher cost of the SBM usually is more than offset by the cost of onshore disposal of OBM cuttings.

23

Section

8

NAF fundamentals

which drilling base fluid is best for the environment? Unfortunately, there’s no simple answer to this question. The full potential environmental impact of a base fluid can only be assessed with a complete environmental data set that includes water column and sediment toxicity, aerobic and anaerobic biodegradation, and deposition of the cuttings and base fluid concentration in the sediment. All olefin and paraffin base fluids and diesel will biodegrade aerobically. However, under anaerobic conditions, alpha olefin and internal olefin base fluids biodegrade more extensively (> 50%) than paraffins and diesel (< 5 - 20%). As a result, paraffin base fluids may persist in the environment for longer periods of time if they are not exposed to aerobic conditions. The concentration of base fluid in sediments may decrease with time after discharge by resuspension, bed transport, mixing, and biodegradation. In many cases, sediment-dwelling microorganisms are able to use base fluids as a source of nutrition. However, biodegradation of base fluids in sediments may result in a decrease in sediment oxygen concentration. If the initial base fluid concentration is sufficiently high, the sediments could become anoxic (oxygen depleted). Ideally, base fluids should be biodegradable under both aerobic and anaerobic conditions.

24

polymer section 9

polymer chemistry

section 9

Scomi Oiltools

Introduction

2

polymer types

2

polyacrylate, polyacrylamide, and phpa

2

carboxymethylcellulose (cmc) and

polyanionic cellulose (pac)

3

hydroxyethylcellulose (hec)

4

starch

4

guar gum

4

xanthan gum

4

other naturally derived polymers

5

polymer uses

5

viscosity

5

bentonite extension

5

flocculants

5

deflocculants

5

surfactants

5

filtration control

6

shale stabilisation

6

polymer limitations

6

Section

9

polymer chemistry

polymer chemistry

introduction A polymer is a molecule consisting of a series of repeating units. The number of units can vary from several to tens of thousands with corresponding variance in chain length and molecular weight. The polymer can be linear or branched and can be synthetic or naturally derived. The lower molecular weight polymers are used as deflocculants; whereas, the high molecular weight molecules are used as viscosifiers and flocculants. The repeating unit need not always be the same. Copolymers consist of two or more different groups joined together and may be ‘random’ or ‘block’ depending on how the groups are distributed on the chain. The two major mechanisms for manufacturing polymers are condensation, which alters the makeup of the repeating units, and addition which utilises the presence of a double bond in the reacting unit to form a long chain. The addition process will generally yield higher molecular weight polymers than will condensation. The condensation process produces a polymer in which the repeating units contain fewer atoms than the monomers from which they were formed. Frequently, water is formed as a by-product of the process. The process requires two or more compounds which react chemically and does not depend upon the presence of a double bond for propagation of the chain. This mechanism is susceptible to interruption by impurities or any outside influence which would reduce the efficiency of the process. Many commercially available polymers are not readily soluble in water. This is an undesirable property for drilling fluid chemicals. Fortunately, many of the polymers available have been chemically treated in order to make them water-soluble. The solubility of these polyelectrolytes will be affected by the chemical makeup of the drilling fluid, pH, salts and presence of divalent cations, etc.

polymer types Each type of polymer has aits own characteristics in terms of how it functions in a particular type of drilling fluid. Therefore, selection of the correct type of polymer is critical to good performance. Below are listed five general types of commonly used polymers.

polyacrylate, polyacrylamide, and phpa Polyacrylates are used as dispersants (low mol. weight), fluid loss reducing agents (medium mol. weight) or flocculants (high molecular weight). Simple ones are cheap, but calcium sensitive. Copolymers are common, e.g. vinyl sulphonate – vinyl acrylate copolymers used as high temperature fluid loss reducing agent. High molecular weight, partially hydrolysed polyacrylamides (PHPA) are very effective shale stabilisers, clay extenders, flocculants, and encapsulating colloids. More correctly they are block copolymers of polyacrylamide (c. 70%) and polyacrylate (c. 30%). The presence of excess PHPA can be monitored via various tests and is reported on the mud report form.

Hydrolysis CH2 - CH alkali C=N n

n CH2 = CH - C = N Acrylonitrille (Monomer) CH2 CH

Polyacrylonitrile (Polymer)

CH2 CH

CH2 CH

Co _

Co _ CONH

Na+

Na+

2

2

CH2 CH

CH2

CH

CH

Co _

Co _

Na+

Na+

2

2

CH2

CH

CONH

2

Co _

2

2

Na+

PHPA Polymer

carboxymethylcellulose (cmc) and polyanionic cellulose (pac) These are widely used as viscosifiers and fluid loss reducing agents. Carboxymethyl cellulose and polyanionic cellulose are both produced by carboxymethylation. The quality of the product is determined by the degree to which the reaction is carried out (degree of substitution) and by whether the salt by-product is removed or not. Viscosity can be either high or low depending on chain length. When cellulose is reacted with sodium monochloroacetate, a sodium methylacetate group is substituted on one of the three hydroxyl groups. Cellulose Structure H

OH

HO 4

CH2OH

H OH H

H

H1 O

O

H

4

O

H

CH2OH

H

H

O

H OH H

CH2OH

OH

H OH H

H O

O

H

OH

H

n

CH2OH

O H OH

H

H

OH

H.OH

The degree of substitution (DS) refers to the number of hydroxyl groups upon which substitution takes place divided by the number of repeating units in the molecule. Carboxymethylcellulose Structure H

OH

HO 4

CH2O

H OH H

H

H1 O

H

4

O

CH2COO-Na+

CH2O

CH2COO-Na+

O

H H

OH

H

O

H OH H

CH2O

OH

H OH H

H

H O

H

O

CH2COO-Na+

CH2O

n

CH2COO-Na+

O H OH

H

H

OH

H.OH

The degree of substitution will range from zero to a maximum of three. Generally, CMC will have a DS in the range of 0.4 to 0.8 with 0.45 being required for solubility. The degree of polymerisation (DP) will range from 500 to 5000. The polymers with the greater DP will impart more viscosity to the fluid. High DS on the other hand, will permit more tolerance to salts and cation contamination. Thermal degradation accelerates above 250 °F (121 °C). Polyanionic cellulose is similar to CMC but generally has a degree of substitution (DS) of about 1.0. The PAC materials generally are more expensive than CMC due to higher processing costs, but show a greater tolerance to hardness and chlorides. PAC begins to thermally degrade at 250 °F (121 °C).

Section

9

polymer chemistry

hydroxyethylcellulose (hec) Hydroxyethyl cellulose. This is used mainly as a viscosifier for completion fluids. Its non ionic nature means that it is not affected by salt. Key factors are purity and high acid solubility. HEC is formed by causticising cellulose and reacting it with ethylene oxide which replaces one or more of the hydroxyl groups present on the cellulose molecule. Hydroxyeathylcellulose Structure CH2OCH2CH2OCH2CH2OH H H

Cellulose +

H

C H

C O

H

O O

H OH

H

H

H

OH

H

H

H

O O

H H

Ethylene oxide

OCH2CH2OH

OH CH2OCH2CH2OH

n

Hydroxyethylcellulose

Although HEC is non ionic, it is still water soluble due to the hydroxy ethyl groups. HEC imparts high viscosity to water or brines but exhibits no gel strengths. It is prone to degradation through shear or heat and has a maximum thermal stability of around 225 °F (107 °C).

starch Widely used as fluid loss reducing agents, particularly in salty muds. Can be potato or grain derived. Quality and temperature stability can be improved by various processes. The starches are pre-gelatinised in order to permit them to readily hydrate. Starches are peptised chemically or by exposure to heat. The peptisation ruptures the microscopic sacks which contain the amylose and amylopectin allowing them to contact with water and hydrate. Starches are used mainly for fluid loss control and are effective in a large range of fluid systems, such as seawater, saturated saltwater, KCl muds and lime muds. Starches are thermally stable to about 250 °F (121 °C). Starches, unless chemically modified are not resistant to bacteria and require a biocide to prevent fermentation, except in saturated salt and high pH muds.

guar gum Viscosifier used to make spud muds. Derivatives (eg.hydroxy propyl guar) may be used in certain completion /workover fluids. Guar gum is manufactured from the seed of the guar plant. Guar is a naturally occurring non ionic polymer used as a viscosifier in waters ranging from fresh to saturated salt (NaCl). High levels of hardness and alkalinity will slow or even eliminate the hydration process and can cause a significant decrease in viscosity. Guar has a maximum thermal stability of about 200 °F (93 °C) and a biocide is necessary to retard fermentation.

xanthan gum Excellent viscosifier giving shear stable rheology with progressive gels. It is derived from bacteria. Xanthan Gum is a biopolymer and is a product of the action of a bacteria (Xanthomonas Campestris) on sugar. It may be used in a variety of brines and salinity levels. Xanthan gum begins to degrade thermally at temperatures of about 225 - 250 °F (107 – 121 °C). Xanthan gum is the only polymer that provides thixotropy, i.e., formation of gel structures.

other naturally derived polymers Other products which may loosely be described as polymers include: Lignosulphate - used as a dispersant Lignite - used a fluid loss reducer and dispersant Lignin (esp. polyanionic lignin) - used for fluid loss control Tannin/ Quebracho - used as dispersants

polymer uses Some of the major uses of polymers in drilling fluids are: ƒ Viscosity ƒ Bentonite Extension ƒ Deflocculation ƒ Filtration Control ƒ Shale Stabilisation

viscosity Viscosity is due to the interactions between the polymer molecules and water, between the polymers themselves and between polymers and solids. The longer the molecules the greater the viscosity. The interaction between the polymers, water and solids can be disrupted by applying energy or shear. The result is that the higher the shear, the lower the viscosity.

bentonite extension

The bentonite extenders work by cross-linking bentonite particles to increase the physical interaction between particles. There is a narrow band of concentrations which allow this cross-linking to occur, but above which a viscosity decrease may occur.

flocculants These polymers are characterised by a anionic high molecular weight which will enable the polymer to bridge from particle to particle. The ionic groups of the polymer will allow it to absorb strongly on the ionic sites of solids and form an aggregate. The aggregates will settle or be removed by shakers or centrifuges. It is possible to have either total or selective flocculation. Selective flocculation removes some of the drill solids.

deflocculants The deflocculants or thinners are usually negatively charged polymers. These products absorb onto the edges of clay particles resulting in an overall negative charge. Deflocculants are anionic polymers. Polymer deflocculants are shorter molecules with a greater charge density. These characteristics facilitate adsorption onto the clay particle without causing cross-linking. These polymers are sensitive to divalent cations and are less effective when hardness exceeds about 400 mg/l.

surfactants These are discussed in the “OBM Fundamentals” section. They are polymers with a polar, water loving end and a non polar oil soluble end. These polymers will stabilise emulsions either direct or indirect depending on the length of each entity.

Section

9

polymer chemistry

filtration control Three mechanisms can be envisaged for polymers to act as fluid loss additives. a. Deflocculants. These pack down the filter cake forming a flatter, less permeable medium. b. Viscosity of the filtrate. The thicker the liquid phase being forced through the filter cake, the lower rate of filtration. c. Colloidal particles. Compressible colloidal particles will deform to plug pores in the filter cake. Often a combination of mechanisms will provide the most effective control. Starches, CMC, PAC, and hydrolysed polyacrylates are effective filtration control agents. Anionic polymers control filtration by viscosifying the water phase to restrict fluid flow through the filter cake. Non ionic materials such as the starches, some anionic materials such as PAC and CMC, work by hydrating and swelling and physically plugging pores in the filter cake.

shale stabilisation Shale stabilisation is provided through polymer attachment to the positively charged sites on the edge of clay particles in shales. This attachment minimises water invasion into the clay particle and reduces hydration and dispersion. These polymers have been used with success in conjunction with salt and potassium-based muds for added inhibition.

polymer limitations Polymers have many advantages, particularly for formulating drilling fluids from sea water or salt saturated brine or for making highly inhibitive muds such as the KCl/PHPA systems. They do have limitations however. Rheological Characteristics Linear polymers such as CMC, PAC, HEC , produce almost ideal power law fluids with poor viscosities at low shear rates and flat, low gel strengths. Thus suspension properties are poor. Xanthan gum is the exception and has good suspension characteristics. Note, however, that gels increase as the low gravity solids build up. Tolerance to Contaminants Most polymers tolerate salt or KCl very well, but the anionic ones e.g. CMC or PAC can be precipitated by calcium if the pH is high. Cement is the worst contaminant. Calcium values over 1000 mg/l (as in, for example, gyp muds) can be tolerated if the pH is below 10. Polymer yields are higher in fresh water than in saturated salt. Temperature The polysaccharides have relatively poor temperature stability max. BHT 250 - 300 °F (121 – 149 °C) depending on grade). This can be increased by using stabilisers. The synthetic polymers can tolerate much higher temperatures (350 °F – 500 °F or 177 °C - 260 °C). Bacteria Starch, guar gum and Xanthan gum are quite easily attacked. The use of a biocide is recommended. CMC and PAC are more resistant to attack. Shear Degradation/ Absorption Some polymers do undergo shear degradation and are absorbed onto cuttings and drill solids. Consequently their viscosifying effects are reduced (but inhibition is increased). High molecular weight, linear polymers such as PAC and PHPA are most susceptible. Cost Polymer muds are generally more expensive in terms of cost/bbl than bentonite muds. However, the advantages obtained by their use (better hole stability, ROP etc.) will normally outweigh the extra cost.

hole problems section 10

hole problems

section 10a - shale instability section 10b - stuck pipe section 10c - lost circulation

section 10a shale instability

section 10a

Scomi Oiltools

fundamentals

2

causes of shale instability

4

consequences of shale instability

4

classification of troublesome shales

4

hydratable and dispersing shales

4

brittle shales

5

abnormally pressured shales

5

tectonically stressed shales

5

shale stabilisation with drilling fluids

6

oil base muds

6

water base muds

6

ionic inhibition

7

encapsulation

7

physical plugging

7

pore-pressure transmission

8

process for selecting suitable drilling fluid

10

drilling depleted reservoirs or weak shales

11

Section

10a

hole problems - shale instability


fundamentals Wellbore instability as a consequence of shale formations is a problem encountered all over the world. Despite much experience and considerable research, drilling and completion operations continue to be troubled by hole problems attributable directly to shale formations. Solutions to shale problems are not a simple matter owing to the variety and complexity of the clay chemistry involved. Shales are sedimentary rocks, which were generally deposited in marine basins. They are composed of compacted beds of muds, silts and clays. In the soft or unconsolidated shale, mud or clay predominates, and in the more consolidated formation it is shale or argillite. At increased depth the shales become denser due to the compaction caused by overburden weight. Shales may also be subjected to tectonic stresses, producing further alteration. Much attention is paid to the degree of hydration of shales, and with the cementing materials holding the shales together. As compaction occurs water is squeezed out of the shale. The degree of compaction is proportional to the depth of the burial, provided that the water is free to escape from the shale. If the water does not escape from the shale, then the water supports a portion of the overburden and the shale becomes pressured. If the water does escape the shale, the rock becomes dehydrated. Shale problems are a direct result of the way in which the shale reacts with the water from the drilling fluid. Hydration from water tends to reduce their strength. Strength loss increases borehole instability. Younger sediments soften, swell and disperse when mixed with water. Older shales, usually having undergone diagenesis, may remain hard and will not easily disperse into water. However, of equal importance with hydration are the inclination of the bedding planes and the stresses acting within or upon the shale formation. Shales contain various clay minerals which differ structurally. The more common minerals are: ƒ ƒ ƒ ƒ

Montmorillonite. Illite. Chlorite. Kaolinite.

Some of these clay minerals will hydrate while others will not. Shales containing montmorillonite will hydrate the most readily. There are two basic building units from which all the different clay minerals are constructed : The Octahedral Layer This consists of two sheets of closely packed hydroxoyl ions in which aluminium, iron or magnesium ions are embedded.

The Tetrahedral unit In each tetrahedral unit, a silicon atom is located in the centre of the tetrahedron, equidistant from the four oxygen atoms. The OH groups may replace the oxygen atoms, if needed to electrically balance the structure.

Silica (tetrahedral)

Octahedral

Aluminium

Silicon

Hydroxyis

Oxygens

The montmorillonite clay group has a high base exchange capacity, where one cation will replace another which can increase or decrease the tendency of the shale to hydrate. The degree of hydration is influenced by the type of cation involved and the pH of the fluid. Mass action by a high concentration of salts will suppress the hydration of clays. The basic structure of illite is similar to montmorillonite but it does not hydrate readily in fresh water. Both are composed of two silica tetrahedral sheets and a central octahedral alumina sheet. Illite, however, develops a charge deficiency, negative charge, from the replacement of silicon by aluminium on the surface of the silica sheet. This charge deficiency is largely satisfied by potassium ions which fit into the surface oxygen layers. The diameter of the potassium ion allows it to fit the locations in the surface permitting very close association of the clay layers and aiding in resistance to swelling. Chlorite clay minerals, which are also composed of three layers, are similar to illite and do not noticeably hydrate. Kaolinite is somewhat different from montmorillonite, illite, or chlorite. The clay structure is composed of two layers instead of three: a single silica tetrahedral sheet and an alumina octahedral sheet. There is no charge deficiency and the particles are electrically neutral. Kaolinite does not swell but will readily disperse. The hydrating-type shales containing montmorillonite are found at shallow depths and are often referred to as gumbo shales. At greater depths their ability to hydrate decreases due to modification of the internal lattice structure. They tend to become a more illitic or chloritic type of clay.

Section

10a


causes of shale instability Shale instability can result from any or a combination of the following factors. 1. Mechanical Forces ƒ Erosion (variety in size and shape of cuttings) ƒ Pressure differential (pressurised shales resulting in narrow pointed sharp shale splinters) ƒ Pipe whip (small mixed shapes from different formations) ƒ Surge and swab (results in lost circulation or large quantities of fill and debris) 2. Overburden Pressure 3. Pore Pressure 4. Tectonic Forces 5. Water Adsorption (hydration) The time the hole is exposed to the drilling fluid is very important. Since most instability problems are time related, the less time spent drilling with potentially unstable formations open, the lower the possibility of developing a stability problem.

consequences of shale instability The following are the potential consequences of shale instability: ƒ Hole enlargement ƒ Hole cleaning problems ƒ Stuck pipe ƒ Bridges and fill on trips ƒ Large fluid volume and treating costs ƒ Poor cement jobs and increased cement requirements ƒ Well logging problems running tools ƒ Poor data quality retrieval ƒ Tight hole ƒ Increased torque and drag ƒ Decreased rate of penetration (bit balling)

classification of troublesome shales Various classification schemes for problem shales have been proposed, but problem shales can be broadly classified by their mechanism of failure: hydratable and dispersing shales, brittle shales, pressured shales and stressed shales.

hydratable and dispersing shales The process of hydration (swelling) and dispersion are related, although each is affected by the amount and type of clays in the shale. Some shales will swell significantly with little dispersion while for other shales, the reverse is true. Hydration results from two distinct mechanisms, surface hydration and osmotic hydration. Surface hydration is a slight expansion between compacted clay particles by the addition of several molecular layers of water on the clay particle surfaces. Osmotic hydration is primarily the expansion of the structure of the clay particle caused by the adsorption of water between the clay platelets. Dispersion is a continual and often rapid disintegration of the shale surface, and results when the strength of the bonds between particles is reduced by the entrance of water. Various clays react differently when exposed to water. As previously stated, the clays that are most commonly found in shales are kaolinite, montmorillonite, illite, and chlorite. Montmorillonites are highly dispersible, readily disintegrate, and hydratable. Illites are non-swelling in the pure form.

Due to leaching and weathering, however, the exchangeable cation, potassium, can be replaced with other cations which may permit some swelling. The chlorite group contains orderly stacks of alternate layers of different types of clays. Disintegration tendencies are high since the layering reduces the number of strong bonds between particles. Non-uniform swelling causes high hydrational stresses and weakens the structure.

brittle shales Brittle shales appear quite firm and competent, but fall to pieces when placed in water. The pieces do not soften or swell in the water. Instability of brittle shales can be caused by either of two mechanisms. The shale can be weakened by hydration of micro fracture surfaces, and bedding planes, parting within the shale structure. The second mechanism results when a small amount of clay is surrounded by a completely non-swelling quartz and feldspar matrix. Even slight hydration of the clays will cause high differential swelling pressure, and will make the formation unstable. Many brittle shales have a high percentage of kaolinite. Kaolinite may become unstable in the presence of a high pH environment.

abnormally pressured shales Shales are abnormally pressured when a layer of low-permeability compacted clay develops adjacent to a sand, restricting the flow from the remainder of the clay body. Thus, in a thick clay formation, the rate of fluid expulsion is not able to keep pace with the rate of compaction, and the pore pressure increases above that normal for the depth of burial. Any sand body, either interbedded or contiguous with the shale, will also be geopressured if it is isolated from the surface either by pinchout or faulting. Abnormally high pressures may also be found in initially normally pressured formations that have been elevated above deposition level by tectonic forces, and surface layers then eroded. Isolated sand bodies within such formations will then have high pore pressures relative to their depth below the surface.

tectonically stressed shales Stressed shales occur in areas where diastrophic movement has occurred. This is the process by which the earth’s crust is reshaped, producing continents, oceans, mountains, etc. The shales may incline considerably from the horizontal, having steeply dipping bedding planes. Forces may be acting upon the formation which, when relieved, cause the shale to fall into the hole. The problem may be further aggravated if the bedding planes become wet with water or oil. It is agreed that formation stresses induced by diastrophic movement make these shales vulnerable to sloughing. It is also recognized that the natural material cementing these shales is relatively weak. It may be amorphous silica, an aluminium or calcium silicate, or an organic material that is sensitive to oil. There is evidence that chemical inhibition is helpful in minimising the problem, but it is not the entire answer. There is also evidence that slightly higher mud densities can be helpful, but it does not seem to be the entire answer. To more effectively control these shales a way has to be found to seal the formation against fluid invasion. This is typically accomplished by carefully controlling the high pressure, high temperature filtration properties of muds. The improvement can be significant but still does not completely solve the problem. Blended organic compounds, containing an emulsifier and a sulphonated blown asphalt or modified gilsonites are materials used in plugging the micro-fractures in shale. This minimises fluid contact along the fractures, and when combined with other remedies will generally reduce the severity of the problem.

Section

10a


shale stabilisation with drilling fluids oil base muds The hydratable, dispersible, and brittle shales are all sensitive to water. Instability can be partially eliminated by preventing the water in the drilling fluid from contacting the shale. One solution is to use an oil-based fluid where water is emulsified in the continuous oil phase. The interfacial film surrounding the emulsified water droplets in an oil mud can act as a semi-permeable membrane and provide a mechanism for osmosis. Osmosis is the flow of water from a less concentrated salt solution into a more concentrated solution through a semi-permeable membrane. Water will migrate from the oil mud into the shale when the salinity of the water phase of the oil mud is lower than the salinity of the water phase of the shale. There is evidence that dehydration of the shale occurs when the reverse is true. No migration occurs when the salinities are equal. This is the ideal scenario as it means no alteration of the state of the shale. Although maximum shale inhibition is realized with oil muds, their use in some wells may not be considered practical because of other factors. These factors must be carefully evaluated in relation to the severity of the shale instability problem. Some of the disadvantages of oil base muds can: ƒ Limit quality data acquisition ƒ Affect cuttings analysis ƒ Increase logistic burden ƒ Require special preparation and maintenance programs ƒ Be environmentally unacceptable ƒ Ineffective in fractured shales

water base muds Stability is generally obtained in water-based muds from: ƒ Ionic inhibition ƒ Encapsulation ƒ Physical plugging The degree of stability will not be as great as with the oil base muds, but properly treated and run water muds can be successfully used for even the most troublesome shales. From a drilling efficiency standpoint, the most practical, semi-inhibitive water-based muds are classified as low-solids, non-dispersed fluids. Their stabilising characteristics are obtained partially from soluble salts and partially from low concentrations of polymer additives. These fluids exhibit good rheological characteristics and generally promote high penetration rates. Proper solids control is a key to using these fluids in the field. High drilled solids content will create rheological problems, reduce the penetration rate, and increase the costs of the mud system and the well. Each mechanism may work independently or in a synergistic manner with one or more of the other mechanisms dependent upon the mineralogy presented by a specific rock sample

ionic inhibition Ionic inhibition is effective in reducing the dispersion and hydration of clays, therefore reducing the instability of shales containing swelling clays. The degree of hydration is dependent on the type and concentration of the inhibiting ion, for example, montmorillonite will swell only to about three times its original volume when placed in a saturated NaCl solution. The hydration is greatly reduced, but not eliminated. The common clays described earlier are all bonded by cations. These cations bond the platelets that make up the clay structure and can greatly affect the degree of hydration of the shale. The cation associated with montmorillonite is usually either Na + ,as in bentonite, or Ca ++ , as in sub-bentonite. Illites contain K + in the pure form, but Na + or Ca ++ may have replaced the K + through time. Clays, when placed in water, develop a strong negative charge imbalance on the surface of the platelets. Any cations in the solution will be oriented to satisfy the negative charges. If the concentration of the cation in solution is sufficiently high, a base exchange with the bonding cation of the clay will take place. The various cations behave differently because of ionic size and hydrational energy. Potassium and ammonium are proposed as the most inhibitive ions for use in a drilling fluid. Their diameters are both very close to the available distance of 2.8 Å between the three-layer packets of montmorillonites and illites. Potassium and ammonium have the lowest hydrational energies, smallest hydrated diameters. The low energies produce inter-layer dehydration and layer collapse, and help in forming a compact, tightly held structure. Potassium cations are expected to perform best as an inhibitive cation on shales having a large percentage of illite. The potassium returns the illite to the pure form which is a non-swelling structure.

encapsulation Encapsulation is a chemical and physical interaction with the clay surfaces. Long chain polymers, such as partially hydrolysedpolyacrylamide, PHPA, are believed to wrap around the particles. This aids in the control ofsurface hydration and reduces the tendency to disperse anddisintegrate.

physical plugging In some of the brittle shales, ionic inhibition and encapsulation may not sufficiently reduce shale instability. Even slight hydration of micro-fractures will make the formations unstable. Asphaltenes have been effectively used in the field to seal micro-fractures. Their use must be coupled with proper fluid loss control to minimise filtrate invasion into the fractures. The materials that are purely oil soluble appear to be the most desirable for treatment of brittle shales. The asphaltenes that are water soluble tend to further disperse into the formation water and reduce the sealing effect. Gilsonite is another mineral product used effectively to maximise shale stabilisation. It is thought that these materials minimise shale sloughing by sealing off micro-fractures and pores in the shales and limiting exposure of the shale surfaces due to a plating action on the wellbore. In the most severe cases of brittle shales, not even the use of asphaltenes will prevent instability. The only alternative is to try a balanced activity oil mud. When shales with abnormal pressure are encountered they must be balanced by hydrostatic pressure or they will become unstable and cause borehole problems. An indication of an overpressured shale is long sharp concave/convex splinters coming from the shale shaker. The amount of cuttings coming over the shaker is also increased. A directional hole will usually require a higher mud density than a straight hole in the same area or field.

Section

10a


Tectonically stressed shales may also require a higher mud density to stabilise the borehole. The amount and appearance of drill cuttings may or may not change. The drag and torque of the drill string may be increased dramatically when geo-pressured shales are encountered without sufficient mud density. Frequently, long sections of hole must be reamed when running the drill string in hole after trips. The borehole can become elliptical due to stress and appear to be under gauge. A good drilling practice is to raise the mud density prior to drilling sections of hole which are tectonically stressed. This will usually allow a lower final mud density to be run compared to a higher final density if the hole is allowed to deteriorate and remedial action is required.

pore-pressure transmission One of the major mechanisms which can cause shale failure is a formation pressure increase in combination with swab/surge pressures. In permeable formations such as sandstones, the pressure differential between drilling fluid and pore fluid (overbalance) generates a filter-cake on the borehole wall that acts as an impermeable membrane. The mud pressure differential will be exerted on the filter cake and provide effective mud pressure support to the borehole wall. Shales are normally considered non permeable, but in fact have limited permeability in the order of 10-6 to 10-12 Darcy. In shales no filter cake can be formed, because the permeability of shales is lower that the permeability of the “normal” filter cake. Thus the drilling fluid pressure is directly in contact with the formation and will equalise with the pore-pressure around the well-bore. With time the drilling fluid pressure will gradually reach further into the formation. This slow mud pressure invasion is referred to as pore pressure penetration. A slow pore pressure increase will reduce effective mud support and increase the rock stress level around the well-bore. Stress levels may then become so high that compressive rock failure will occur. Swab pressures temporarily lower the effective mud support even further, bringing the shale or claystone close to failure or causing actual failure resulting in cavings or borehole collapse. An initially stable wellbore can become unstable with time due to pore pressure penetration in combination with swab/surge pressures. Mud overbalance Pore pressure penetration

Naturally pressured rock zone

Mud pressure zone

Filtrate invasion zone

The invasion of filtrate elevates the “in-situ” pore pressure in an extended zone around the well bore, i.e. as the wellbore pore pressure increases the net effective mud weight overbalance decreases resulting in reduced bore hole pressure support. This can lead “in time” to the necessity to increase the mud weight in order to stabilise the well bore. The degree of pore pressure penetration depends on:ƒ the type of drilling mud. ƒ type of shale (permeability). ƒ amount of overbalance.

Capillary Effect Neither water based muds nor oil based muds forms a solid filter cake in shale. Under normal mud pressures shales are permeable to water based fluids but completely impermeable to oil. The stable behaviour of shales whilst drilling with oil based mud or synthetic fluids is a result of capillary action. When oil enters a shale it has to overcome a threshold pressure caused by the capillary effect between oil and the pore fluid. The capillary pressure is in the order of thousands of psi and thus is generally too large to be overcome by the mud pressure differential. The threshold pressure therefore acts as an alternative “mud filter cake” providing effective mud support to the wellbore.

Oil/Synthetic Based mud Wellbore pressure

Water Based mud Wellbore pressure

Water Pore Pressure

Water

Water

Pore Pressure

Capillary Action in oil/synthetic muds versus water based muds A consequence of the above is that shale instability with oil and synthetic drilling fluids is normally caused by lack of mud support i.e. too low a mud density. Cloud Point In recent years TAME glycols (polyols) have been used successfully to control pore pressure transmission in water base muds. The mechanism used by polyols to do this is “clouding out”. The cloud point of a polyol is the temperature at which it starts to change between being water soluble and water insoluble. On increasing the temperature of the fluid, the polyol starts to come out of solution and an otherwise clear liquid starts to become opaque and cloudy. The temperature at which this occurs is usually very precise and is particular to each polyol type. Control of the cloud point is crucial to the drilling fluid and wellbore performance. Cloud point is also a function of the following variables: ƒ ƒ ƒ ƒ

salinity of the solution. type of electrolyte. molecular weight and type. concentration of polyol.

There have been many theories put forward to explain the shale inhibition mechanism; of these the following mechanisms are believed to be the most conclusive:

Section

10a


ƒ It has been suggested that the main function of the polyol is to compete with water molecules for adsorption sites on the clay minerals present in shales. They also conclude that when KCl is present, there is a good correlation between inhibition and adsorption of polyol. Strong adsorption still occurs from distilled water and, although polyol intercalates are formed, they have a slightly higher basal spacing and the resulting complexes are much less stable in water. ƒ Other research has studied the effects of clouding polyols in aqueous solutions with varying salinities. They conclude that the formation of an aggregation of hydrophobic molecular droplets contribute to the lowering of both static and dynamic filtration, thus achieving a reduction in pore pressure penetration of invasive fluids. They also demonstrate that a relatively narrow operating band exists for optimum benefit from clouding polyols in Thermally Active Micro Emulsion (TAME) type muds.

The ideal environment for TAME type muds to operate is when the mud temperature is below the cloud point and the formation temperature is close to or above the cloud point. In these cases, pore plugging will occur just inside the rock matrix as the material clouds out within the hotter environment, sealing the formation against further ingress. At this point, surfactant - polymer interactions will also be at their greatest as well as any complexation of surfactant with monovalent ions in solution such as potassium. Optimum benefit for long term borehole stability should occur in this scenario.

process for selecting suitable drilling fluid The following table details the processes that can be used to identify a suitable fluid for drilling a particular shale. It involves analysing the shale to characterise it and understand it. It then subjects the shale to fluids to quantify its reaction.

Process Sample Sourcing, Preparation and Characterisation

Detail Sample collection.

Detail Mineralogy by XRD.

Specific Method XRD

Identification of exchangeable cations.

IC

Water content.

Water Content

Activity.

Activity

Methylene blue index - cation exchange capacity

MBT

Process Physicochemical Analysis

Reactivity Quantification

10

Specific Method

Preparation of samples. Description of samples Colour, hardness, texture and UV response.

Dielectric constant - surface area

DCM

Capillary suction time

CST

Process Swelling, Dispersiveness and Hardness Testing

Detail Swelling potential.

Specific Method Shale Wafer Test

Dispersion tests.

Dispersion by Dynamic Ageing

Hardness - Penetrometer tests

Durometer or Elf Penetrometer

Stability Testing

Pore pressure transmission.

PPT

Inhibition Testing

Fluid compatibility testing – Quantification of effectiveness of alternative strategies to inhibit hydration, swelling, disintegration and dispersion.

Fluid Compatibility Testing

Solids Tolerance

Solids contamination tests.

Solids Tolerance

Accretion potential - Evaluate anti-accretion (bit-balling) strategies.

Accretion Testing

drilling depleted reservoirs or weak shales Many of us were taught as mud engineers that hydrostatic pressure provided by a drilling fluid must exceed pore pressure in reservoir rock to prevent influx of fluids and to provide wellbore stability. This incomplete concept has been for many years more often than not accepted without question. However, as wells are drilled deeper, often in deep water, or through depleted zones, loss of circulation due to fracture induction has become an ever increasing problem. Fracture induction has been most often been observed when drilling relatively impermeable shale with non-aqueous fluids. Most mud engineers have experienced mud losses to a shale followed by return of most or all of that same fluid after the mud density was reduced a small amount, sometimes less than 0.2 lb/gal. The same phenomenon exists in more permeable, especially depleted, reservoir rock when drilling with non-aqueous fluids because NAF fluids do not readily penetrate pores of producing sands due to capillary effects. Producing sands, whether oil or gas producing, are generally water wet. The entry of a non-aqueous fluid to the permeable matrix of reservoir rock is opposed by hundreds of pounds per square inch of capillary pressure. The NAF mud or mud filtrate simply cannot easily “push” aside the water sealing a reservoir rock and readily enter the porous permeable matrix. Thus, the hydrostatic pressure exerted by the mud column cannot leak to the reservoir when grain separation occurs as the wellbore dilates with increased ECD. Drilling fluids, with sufficiently high hydrostatic pressure, can exceed the horizontal stresses of rock and cause dilation of the wellbore. The rock may be shale or reservoir sand. Dilation of the wellbore is seen as a slight increase in diameter of the bore and grain separation around the circumference of the hole. Depending upon rock and drilling fluid properties and components a simple winged vertical fracture can develop in the direction of highest principal stress, or a few to myriad smaller fractures can develop radially all about the wellbore. As small fractures develop radially about the wellbore, they will be seen to turn in the direction of the highest principal stress.

11

Section

10a


These initial fractures are called proto-fractures or juvenile fractures by some operators. The initial fractures are confined to the “near-wellbore” and do not initially penetrate far into the rock. Juvenile fractures may penetrate to a depth usually assumed less than one hole diameter before they begin to propagate due to entry of mud pressurized to the full hydrostatic head of the mud column. To drilling engineers, the near wellbore can be said to be about one hole diameter (this can be confusing because a production engineer may see the near wellbore as hundreds of meters depending upon reservoir and production characteristics). In a barite weighted fully formulated mud, circulating loss will not be observed until the proto-fracture exceeds about 150 microns in width. This means that barite itself is a “StressCage” material. When formation proto-fractures begin to form using a barite weighted mud: the hoop stress of the rock increases; (term widely used by many engineers BP and Shell and others) the fracture-closure stress increases; (term perhaps more typically used by Exxon and others) the tangential stress of the rock increases; (term typically used by Schlumberger and others) the formation becomes “Stress Caged™” (BP trademark and patented concept) A leakoff test using a barite weighted mud can yield a 200 - 400 psi increase over a clear fluid. Barite is the mud engineer’s primary LCM and primary Stress Cage(d)™ material. In reality, barite is the “FINE” LCM we heard about in mud school. Barite will allow for an increase in fracture width of up to about 150 microns for each fracture which develops. More fractures indicate a higher potential increase in fracture closure stress and more StressCage effect. However, at some point a fracture will exceed 150 - 175 microns and the whole mud will be lost to the “far-field” more than the depth of well-bore diameter. At this point a larger sized LCM must be selected to further extend formation strength. Work by BP, Exxon, Conoco-Phillips, Texas A&M University/Shell Bellaire Research has shown that hard granular materials are the most effective materials for sealing and closing fractures which are beyond the sealing capacity of API barite. Prototype materials tested and found to be effective in lab and field were fine grind hard nut hull, ground petroleum coke, and synthetic graphite. Calcium carbonate can also be used but the higher specific gravity and bulk density and less textured surface make it less effective at any given concentration. The most effective size was measured (Malvern and Coulter particle size analyzers) to be about: D10 of about 100 microns D50 of about 300 microns D90 of about 600 microns Material must be tough, hard, rough surfaced, with a net spheroidal symmetry for the highest effectiveness. Use of platey and fibrous materials with high aspect ratio WILL NOT INCREASE THE STRENGTH OF A FORMATION. Likewise, smoothly spherical materials such as un-ground petroleum coke or synthetic graphite act more like proppants, cannot seal a fracture and DO NOT IMPROVE FORMATION STRENGTH OR SEALING. “Spheroidal symmetry” describes the cubic, tetrahedral, and other regular symmetries seen in synthetic graphite, petroleum coke, ground nut hulls, and other efficient fracture sealants. “Spherical” describes ball symmetry. These terms are not equivalent. Rules for effectively increasing strength of shale: • NAF muds are often more likely to fracture sands and shales than WBM because of capillary effects. • Bridging material should be in the mud before the loss zone is encountered. • Bridging material must be maintained in the mud system while drilling and until casing is set and cemented.

12

• • • • • • •

Bridging material does not enter the fracture unless fracture penetrates to the far-field. Maintain HTHP filtration below 2 ml or as low as possible. Some premium fine fibrous materials may help reduce dynamic filtration; this should be evaluated by pilot test. If mud penetrates to the far-field any hoop stress or Stress Cage™ increase is lost. Bridging material will wash off the fracture unless continuously replenished in the mud system. Material must be continuously replenished at pump suction OR Shakers can be bypassed; OR Screen size of + 40 mesh can be installed.

Do your best to ELIMINATE FINE, MEDIUM and COARSE from your thinking. These terms are largely bogus concepts which only apply if you know what sizes you are talking about. There are no “API” or standard industry sizes associated with FINE, MEDIUM and COARSE. In most circumstances! - the size we can call FINE as used in the Stress Cage™ business is that of API barite. To increase the strength of shale beyond that provided by API barite, a material “one” size larger is selected. That material has: D10 of about 100 microns D50 of about 300 microns D90 of about 600 microns DO NOT USE ANY MATERIAL LARGER THAN 1 mm. It will not seal properly. Do not invent or improvise with materials with unknown particle size. It is best to forget FINE, MEDIUM and COARSE unless you know the screen or measured size of those particles. Scomi Oiltools markets the following “Stress Cage™” materials which can increase wellbore strength as measured by increased LOT and FIT measurements. • • •

calcium carbonate or marble with d50 of 250 - 350 microns when drilling with API barite weighted mud. HYDRO-SEAL G, resilient synthetic graphite standard and fine. The standard grind size should be used while drilling; the fine material can be added while tripping or running pipe. sized ground nut shell (typically walnut and pecan) as described in publications by Fred Dupriest of ExxonMobil. This size is typically called “FINE”, but make certain the d50 is close to 300 - 400 microns with no particles above about 1 - 1.2mm.

other wellbore stability issues As mud weight is increased the near wellbore can be put in tension. Tensile failure in vertical wells has been the major cause of mud losses since rotary drilling with weighted muds began. Tensile failures can cause mud losses and sometimes hole collapse in rubble zones when stretched broken shale can no longer support itself. The problems can rapidly become worse as hole angle increases. As hole angle deviates from 90° the horizontal stresses opposing fluid hydraulic pressure become a complex product of angle, overburden pressure, formation “Poisson’s ratio”, and pore pressure. Hoop stresses about the wellbore become distorted from an easy to comprehend near circular stress field to one that puts the wellbore in tensile stress in one direction and in compression at a near right angle around the wellbore. This means the mud engineer may observe splintery cuttings typical of an underbalanced well, chunky cavings from tensile failure, and mud losses all at the same time.

13

Section

10a


Geomechanics problems in high angle wells can be a difficult to resolve and may require special well designs which consider formation dip and hole direction to minimize the effect of unstable rock. As a mud engineer we should be aware of these issues. When rocks bend due to salt intrusion, strike-slip faults, thrust faults; if bedding plains dip; or when drilling high angles holes through any of these conditions; frustrating and seemingly unpredictable rock failure can occur. In many or most cases mud chemistry is a minor contribution to the problem. Many companies offer services which (more or less!) accurately predict wellbore stability based upon poro-elastic measurements and assumptions, rock strength measurements, mud properties, and hole angle and dimension. fixed fracture and micro-fractured shale considerations As depth increases overburden pressure increases at typically more than 1 psi/foot. At most depths the overburden load exceeds the compressive strength of the supporting rock. Pore pressure contributes to matrix stress of the rock and the formation can support a higher load than the strength of the rock itself if the rock remains confined.

14

For this reason, natural fractures in most sands and shales are closed and non-conductive. It should not be assumed that massive losses occur to open natural fractures, especially as depth increases. Natural fractures may open or new fractures may be induced by the hydrostatic pressure of the mud column if that hydrostatic pressure exceeds the minimum horizontal stress of the rock. Fracture opening or facture induction can be resolved with thoughtful application of LCM of optimised size, shape, surface roughness, and hardness BEFORE THE LOSS ZONE IS DRILLED. If a fracture is sealed as it begins to open, the faces of the fracture will not feel the full hydrostatic head of the mud column and the fracture will not extend with massive losses to the far field of the formation, sand or shale. It will be “caged”. Likewise, fractured limestones and hard tight sands which can support the weight of the overburden despite loss of confinement may have fractures conductive to gas, oil, and occasionally barite weighted drilling fluid, but in most cases those fractures also can be sealed with the same materials discussed above. Always use these recommended sizes and concentrations before responding with those irrationally shaped and sized LCM that we mud engineers have promoted for 100 years. Mica and other platey type materials have been shown again and again to be ineffective and usually increase rate of mud loss. Spherical materials can become proppants and increase mud loss. Losses to vuggy and karsty limestone and fractured basalts are exceptions. When drilling through vugs, caverns, or large fractures, especially in metamorphic rock, other techniques should be employed, see section 10c. lost circulation

15

section 10b stuck pipe

section 10b

Scomi Oiltools

mechanisms of pipe sticking problems

2

differential sticking

2

mechanical sticking

2

formation related sticki

3

prevention of stuck pipe

3


3

mechanical sticking

4

formation related sticking

5

methods of freeing pipe

5


5

reducing the mud weight

6

mechanical sticking

8

formation related causes

9

NAF

11

12

stuck pipe decision tree

Section

10b

hole problems - stuck pipe


mechanisms of pipe sticking problems The occurrence of stuck pipe can usually be attributed to one of three major mechanisms: ƒ Differential Sticking ƒ Mechanical Sticking ƒ Formation Related Sticking

differential sticking Differential sticking is caused by, a positive differential pressure and a permeable formation. The chances of becoming differentially stuck under these circumstances are increased by poor filtration control, thick filter cake and poor drilling practices. Differential sticking can occur when, in a permeable Example of Differential Sticking formation, the hydrostatic pressure exceeds formation pressure. This results in the drill string, particularly the BHA, becoming embedded in the filter cake and the force to free the pipe becomes excessive. It is characterised by the ability to circulate but the inability to rotate or move the pipe either upwards or downwards. Conditions contributing to the likelihood of differential sticking are: ƒ High formation permeability. ƒ High positive differential pressure. ƒ Hole angle. ƒ Undergauge hole. ƒ Poor mud filtration properties. ƒ The relative geometry of the pipe and the wellbore. ƒ Period of time the drill string remains immobile. ƒ The degree of drill collar stabilization. Configuration of drill collars may also be important. ƒ Poor particle size distribution in the mud leading to formation of a thick high permeability filter cake.

mechanical sticking Mechanical sticking occurs for a variety of reasons including inefficient hole cleaning, key seating, under gauge hole, junk, collapsed casing and well bore geometry. The actual cause is often difficult to ascertain as it may be possible to move the pipe either up or down, it may be possible to rotate and it may be possible to circulate. A key seat is caused by the drill pipe cutting or wearing a slot into the side of the borehole. The drill collars, being larger than the drill pipe, can become wedged into this slot and stuck. The drill string is usually stuck while pulling out of the hole. The drill collars are pulled into the key seat and stuck.

Example of Key Seating

Mechanics of key seat sticking are: ƒ The number and severity of dog-legs. ƒ Length of time that the uncased section of the wellbore is left exposed, especially in terms of rotating hours and number of trips. ƒ The drillability of the formation. ƒ The relative size between the drill pipe tool joints and the drill collars. Very large collars are less likely to pull into a key-seat and become stuck than are collars that are just slightly larger than the tool joint outside diameter. ƒ Rapid transition from a formation that is prone to wash out to one that remains close to gauge, or the reverse. The washed out section no longer provides support for the adjacent formation and thereby concentrates the wall stress exerted by the drill pipe. The drill string can become stuck when drill cuttings are not adequately removed from the hole. This type of sticking is usually accompanied by loss or partial loss of circulation caused by “packing off”.

formation related sticking Formation related sticking occurs as a direct result of the nature of the formation. Unconsolidated formations may collapse, fractured formations may give rise to ledges, geopressured formations may expand into the well bore and reactive formations may swell to restrict the annulus. Again determination of the cause may not be immediately, or ever, possible.

prevention of stuck pipe differential sticking Differential sticking is probably the most preventable cause of stuckpipe as contact area, mud density and filter cake thickness are all controllable. The use of spiral collars will minimise the contact area and, in the event of sticking occurring, a micro annulus is present to facilitate spotting of the pipe freeing agent across the stuck point. The differential pressure into the formation can be minimised by running mud weights at or just above formation pressure providing other open formations permit. The filter cake thickness and cake permeability can be controlled by minimising fluid loss and ensuring good particle size distribution to provide a compressible filter cake with good lubricity characteristics. Graded Calcium Carbonate exhibits a good particle size distribution and can be used in formations where offset data indicates the possibility of differential sticking.

Section

10b


Differential sticking generally occurs when the drill-string remains stationary opposite a permeable zone. To minimise differential sticking: ƒ Drill with mud density as low as practical. ƒ Keep hole as straight as possible. ƒ Keep solids content of mud as low as possible. ƒ Use bridging particles, e.g. CaCO3 ƒ Keep static drill string time to a minimum. ƒ Use extreme pressure (EP) lubricants. ƒ Avoid long strings of drill collars where the diameter is larger than 65% of the hole diameter and/or ƒ Use stabilisers or spiral drill collars. ƒ Use an non aqueous fluid (NAF).

mechanical sticking Mechanical sticking can be prevented by a combination of mud parameter control, especially rheology relating to hole cleaning, and good drilling practices. Inefficient hole cleaning is a major cause of mechanical sticking especially in the larger diameter holes where annular velocities are governed by available pump output. Sufficient yield point and low shear rheology values will minimise the build-up of cuttings in the annulus which may not be apparent until the pipe is tripped, when the hole may pack off. It is imperative for this reason to ensure the hole is clean prior to tripping and that rates of penetration are controlled to avoid the annular cuttings concentration exceeding 4%. To minimise key seating: ƒ Drill with a stiff bottom hole assembly which tends to minimize the chance of severe dog legs. ƒ Use key-seat wipers properly positioned in the string. To prevent pipe sticking due to debris or cuttings accumulation and swelling or plastic movement: ƒ Maintain drilling fluid properties capable of good hole cleaning and general wellbore stability. ƒ For high-angle holes (>35°), rigs should have top drives, three mud pumps, advanced solids control systems and well-trained crews. ƒ Maximize rotary drilling especially for high-angle holes (>35°). ƒ A rough guideline for flow rate is that it should be 60 times the hole diameter in inches for highangle holes and about 1/2 as much for low-angle holes (<35°). Typical annular velocities range from 120 ft/minute for low-angle wells to greater than 200 ft/minute high-angle wells. ƒ Both low and high viscosity fluids have provided good hole cleaning indrilling operations. The suitability of a particular rheology mud can be checked using a hole cleaning design program. This provides minimum operating flow rates and corresponding maximum ROP with ECD predictions. ƒ Use routine hole-cleaning prevention methods such as back reaming, drillpipe rotation and reciprocation, and circulation with bit off bottom. This is especially important in wells with hole angles between 45° and 75° where bed slumping is likely and before tripping out of hole.

formation related sticking Formation related sticking because of the variety of causes is more difficult to predict and prevent without offset data. Unconsolidated formations may require adjustment to rheology profiles and/or mud weights to stabilise the hole. Formations prone to ledging may require rheology adjustments to prevent washout of the less competent interbedded strata and perhaps more care on trips to prevent breaking off of the ledges.

Geopressured formations may require increased mud Example of Formation Related Sticking weights to stabilise the hole provided other exposed formations are not prone to lost circulation. Reactive formations may require increased levels of inhibition or increased mud weights to overcome hydrational forces. To minimise formation related sticking: ƒ Use the lowest mud weight consistent with wellbore stability considerations, lost circulation. ƒ Ensure proper selection of casing points to minimise exposure time of formations to drilling fluids. ƒ Maintain sufficient mud density in pressured zones.

methods of freeing pipe differential sticking There are two mud related techniques used to attempt to free the pipe. The first is to reduce the hydrostatic pressure of the mud column. This can be achieved by lowering the mud weight of the entire active mud system during conventional circulation or by introducing lower density fluids into the annulus. The second method can incorporate the use of stuck pipe spotting fluids (conventional oil based or environmentally safe types for WBM; surfactant types for NAF).

This type of sticking requires an immediate action as, under static conditions, the filter cake thickness will increase with time. Preparations for either of the mud related freeing options must begin immediately.

Section

10b


reducing the mud weight a) Reduction of the mud weight in the entire active water based system is best achieved with measured even additions of water. Chemical additions should be made to maintain other properties, particularly fluid loss. Use can also be made of centrifuges to discard solids and reduce weight. b) Introduction of lower density fluids into the annulus is a fast way to reduce the hydrostatic pressures responsible for the differential sticking, i.e. ‘U’ tubing. c) If well condition permit use of an unweighted spotting pill spotted across the stuck zone will also reduce the hydrostatic pressure Well control considerations and assessment of the effect of reduced hydrostatic head on formation instability elsewhere in the wellbore is a prerequisite to either of the above actions. Other non mud related methods of freeing differentially stuck pipe include: ƒ Working or jarring loose, washing over, using a taper tap or overshot, fishing tools, etc. ƒ Application of a drill stem test (DST) tool. The pipe is backed off and a DST tool with open-ended drill pipe below is screwed into the fish. When the DST tool is opened, differential pressure is relieved, freeing the pipe. This method depends largely on having a section of hole above the fish where the DST packer will seal properly. stuck pipe spotting fluids 1) Conventional Base Fluid Pills - WBM application In the event of differentially stuck pipe where a mud weight decrease proves ineffective or impractical, a conventional stuck pipe spotting fluid will be used. This should be formulated with base fluid and seawater then weighted 0.2 lb/gal (0.02 SG) above the active system mud weight with barite. The exact process involved in freeing of stuck pipe by base fluid/surfactant pills is not fully understood but is believed to be related to capillary pressure of the base fluid, compression of the filter cake and reduction of surface tension between pipe and the filter cake. None of these processes are instantaneous and consequently patience must be exercised when using spotting fluids. Important: Up to 12 hours may be required for the pipe freeing processes to reach equilibrium. Placement Procedures ƒ Determine position of stuck pipe by pipe stretch coefficients or free point logging tool. ƒ Calculate volume requirement. In the vast majority of cases it is the BHA that is stuck. Sufficient volume should be pumped to cover the BHA with a 50% excess. ƒ Spot the fluid around the pipe leaving sufficient volume in the drill string to allow small periodic displacements (1 or 2 bbl (0.16 or 0.32 m3)) every hour for up to 12 hours. Scomi Oiltools Environmentally Friendly Stuck Pipe Solutions D-FUSE Unique blend of surfactants and food grade paraffins for unweighted spotting fluid. Can be mixed in all types of non aqueous base fluids and glycols. Add 3 - 4 gals (11.4 – 15.4 liters) of D-FUSE per bbl (m3) of base fluid.

BREAK-FREE Blend of surfactants, emulsifiers and an oil soluble water emulsifiable polymer. Used where a weighted pill is required. Normal treatment level is 5 gal (18.9 liters) of BREAK-FREE per bbl (0.16 m3) of finished spotting fluid.

Recommended Formulation - 100 bbl (16 m3) Density BREAK-FREE Base Fluid Water SG (lb/gal) (55 US gallon drums) (m3) (bbl) (m3) (bbl) 0.96 8 9 10.18 64 4.29 27 1.20 10 9 9.22 58 4.13 26 1.44 12 9 8.59 54 3.50 22 1.68 14 9 8.11 51 3.34 21 1.92 16 9 7.79 49 1.75 11 2.16 18 9 7.00 44 1.59 10

Barite 25 kg (55.1 lbs) sacks 69 254 456 636 846 1036

Mixing instructions: 1. Clean slug pit and mixing lines 2. Add base fluid 3. Add required volume of BREAK-FREE 4. Add required volume of water 5. Add DRILL-BAR as required 2) Surfactant Type – NAF application Despite the inherent low sticking risk characteristics of NAF, differentially stuck pipe remains a potential problem when using this type of fluid. In the event that mud weight decrease proves ineffectual or impractical in freeing differentially stuck pipe with NAF in use, then the spotting of a surfactant type pill should be considered. As with the conventional base fluid type pill in WBM applications patience must be exercised to permit the pipe freeing process to reach equilibrium. It should be noted that unlike spotting an base fluid / surfactant pill in water based muds this approach does not present a new fluid type to the filter cake, merely an increase in the surfactant concentration. The envisaged mechanism is that the increased oil wetting capability of the fluid may produce penetration between pipe and filter cake thus reducing contact area. This approach cannot be expected to produce as high a success rate as an base fluid / surfactant pill in WBM where physical shrinking and cracking of the filter cake occurs. Placement procedures are essentially the same as described for the conventional WBM type pills and consideration must be given to weighting the fluid spotted to keep it in place and prevent upward migration away from the area of sticking.

Section

10b


The surfactant type spotting fluid for NAF applications should be formulated as follows : Formulation for 50 bbl 8 m3 (unweighted) Surfactant Type Spotting Fluid Base Fluid : 45 bbl (7.16 m3) Secondary Emulsifier : 3 drum, 55 US gallon, approx. 25 lb/bbl (71.3 kg/m3) Oil Wetting Agent : 1 drum, 55 US gallon, approx. 8 lb/bbl (22.8 kg/m3) If the fluid is to be weighted then a conventional free pipe spotting agent - capable of suspension of barite - may need to be used instead of the secondary emulsifier shown above. Formulations for this type of pill will be essentially the same as those detailed in WBM applications with increased levels of oil wetting agent being added. N.B., Formulation may change according to mud weight, emulsifier and oil wetting agent brands on the rig.

mechanical sticking inefficient hole cleaning Preventing Stuck Pipe It is possible to become stuck due to hole pack off both while drilling and tripping. It is critical to ensure that the hole is circulated clean before tripping. This should not just be a calculated “bottoms up”. The high slip velocity of cuttings often results in cuttings “bottoms up” being considerably longer than that calculated for the mud. While drilling, pump around selected sweeps to check if the hole is being cleaned. Refer to good hole cleaning practices in Section 6a, Deviated Drilling, Hole Cleaning, for recommendations. Additionally, wiper trips can help to clean the hole by disturbing the cuttings beds and removing any bridges which may have formed. Freeing Pipe Packing off and hole bridging normally permit only limited rotation with no pipe reciprocation or circulation. It is necessary to break down the pack off by applying limited pump pressure and rotation, then waiting for pressure bleed off. Once circulation is established, the pack off can be cleared using normal pump rates. At this point the hole ought to be circulated clean, using an optimised viscosity pill as required. key seating, undergauge hole, junk, collapsed casing, cement related There are no mud property controls for prevention of these causes of stuck pipe. wellbore geometry This type of stuck pipe can be caused by several factors unrelated to mud, but the mud needs to be tailored to overcome any problems of hole instability and insufficient hole cleaning, and to produce efficient hydraulics. Preventing Stuck Pipe There are no hard and fast rules for mud property control to prevent this type of stuck pipe. In deviated well bores it is usually necessary to have a higher mud weight to maintain borehole stability than for a vertical hole. The addition of lubricants to reduce drag and torque should also be considered.

When an undergauge bit/stabilizer is pulled out of the hole great care must be taken when running a new full gauge bit into the undergauge hole. Freeing Pipe The main reasons for sticking due to wellbore geometry are profile and ledges. Any changes in the mud will be dependent upon the reason for the stuck pipe. Additions of lubricants or an increase in mud weight can in many cases, reduce torque and drag and also stabilise the wellbore.

formation related causes unconsolidated formations The most common effect of unconsolidated formations is bridging or packing off. Preventing Stuck Pipe In vertical holes use high viscosity sweeps as a matter of course while drilling unconsolidated formations. Often there will be surges of solids and cuttings at the shakers which will cause screen blinding, which must be prepared for. While drilling these formations it is advisable to clean the hole after a trip before drilling ahead, as fill is often found on bottom. Freeing Pipe Circulation will normally be lost if the pipe becomes stuck due to the collapse of unconsolidated formations. Circulation must be regained, while working the pipe downwards to disturb the bridge. The pipe will come free once circulation is regained, but the hole must be cleaned prior to drilling ahead. At this point consideration should be given to raising the mud weight which may stabilise the hole. fractured/faulted formations Some unconsolidated formations respond to stabilising agents such as asphalts and gilsonite. Ultimately it may be necessary to cement the zone and redrill it. This type of formation when drilled will often produce ledges at the fault or washouts across the fractured zone. Preventing Stuck Pipe Hole cleaning will be a problem where washouts and ledges have formed as cuttings will accumulate in the washed out sections. Prior to tripping it may be necessary to circulate well beyond calculated bottoms up because of the reduced annular velocities. Furthermore, faulting gives rise to the risk of lost circulation, so an increase in the mud weight to stabilise the wellbore may not be possible. This will often make it necessary to ream the hole on the way in. Checking hole condition during wiper trips at programmed depths is advisable. Freeing Pipe The cause of sticking in fractured/faulted formations will usually be due to an obstruction falling into the wellbore causing pack-off. Working the pipe to break up the obstruction or the pack-off will be necessary. Where fractured limestone has caused stuck pipe consideration may be given to the use of an inhibited hydrochloric acid pill which can dissolve the obstruction.

Section

10b


geopressured formations These are formations which are pressured due to loading pressures from the rock above and below. The rock and its associated fluids will require higher mud weights for stabilisation. The signs of the geopressured formations are usually pressure cavings and tight hole. Preventing Stuck Pipe Action must be taken to stabilise the wellbore at the earliest opportunity, since the situation will usually deteriorate with time. There may be problems with annulus overloading and cavings at the shakers. A rise in the mud weight will be necessary, but can only be carried out if other exposed formations can tolerate the increased hydrostatic. The mud must have been within specifications throughout the section in order for proper interpretation of the problem. Freeing Pipe The mechanism for stuck pipe to occur will be hole pack-off due to geopressured shale splintering into the annulus. With circulation established, a rise in the mud weight must be considered and rheological parameters must be adjusted to facilitate removal of larger than normal rock particles. reactive formations In some instances reactive formations may “swell” and reduce the annulus sufficiently to grip the pipe. Historically this has often been nominated as the cause of stuck pipe. Recent studies suggest that in many of these cases stuck pipe may in fact have been due to inefficient hole cleaning in the reactive clay sections where rapid ROP occurs. Preventing Stuck Pipe Select a suitably inhibitive drilling fluid and mud weight. Reactive formations tend to deteriorate with time, consequently casing schemes should be designed to set casing as soon as possible to ‘case off’ the clays. Freeing Pipe This will usually be achieved by mechanical methods i.e., jarring. Once “free, increase inhibition levels and consider mud weight increases. mobile formations Two types of rocks which are known to readily deform under pressure are plastic shales and salts. In the stuck pipe situation rotation may often be possible but up and down movement is usually very limited. Example of Deformation under Pressure

10

Preventing Stuck Pipe If these formations are known to be present a rise in the mud weight will almost always be necessary prior to penetrating the formation. Because the formations are mobile, wiper trips will be advantageous to establish the condition of the hole. In some situations however, e.g., mobile salts such as the European Zechstein Salt, prevention of salt movement is not possible by increasing the mud weight since the required density would greatly exceed the fracture gradient/shoe strength. In these instances wiper trips and the use of freshwater pills to dissolve the salt, and other mechanical aids such as eccentric bits are the usual techniques applied to minimize stuck pipe problems. Freeing Pipe Stuck in Salt – Water Based Mud 1) Pump 50 bbl (8 m3) freshwater. Displace with mud until the drill collars/open hole annulus is displaced to freshwater. 2) Stage the remaining volume of freshwater around the BHA in 5 bbl (0.8 m3) increments allowing 15 - 30 min between stages, while continually jarring on the pipe. 3) If the pipe is not free after displacing all the water into the annulus, circulate out the water at maximum pump rates continuing to jar. 4) Repeat 1 - 3 above until pipe becomes free.

NAF The advantage of using NAF muds is that they are more inhibitive which, in itself gives rise to more stable hole conditions, lowering the risk of many well problems including stuck pipe. Stuck pipe is less likely to occur when using NAF because they exhibit: ƒ Extremely high levels of inhibition. ƒ Good lubricating properties. ƒ Low fluid loss. ƒ Thin filter cakes. ƒ Ability to drill with lower mud weights for wellbore stability compared with WBM. The fact that all surfaces are oil wet and that NAF muds generally produce thin filter cakes reduces the possibility of differential sticking. It is, however, still possible to become differentially stuck if excessive overbalance is used. In such cases spotting a surfactant type pill may prove beneficial if mud weight reductions are ineffectual or impractical.

11

Section

10b

12


section 10c lost circulation

section 10c

Scomi Oiltools

introduction definition and classification type of losses severity of losses prevention and control minimise annular loading good drilling fluid properties maintenance minimise surge and swab pressures ecd minimisation surface equipment downhole equipment locate and identify loss zone avoiding stuck pipe water base muds vs. non aqueous fluids lost circulation materials lcm types lcm in productive zones permanent remedial treatments bridging / sealing of porosity and fractures losses into porosity losses into natural fractures losses into induced fractures responding to losses basic strategy seepage losses (< 10 bbl/hr or 1.59 m3/hr) partial losses (10 to 30 bbl/hr or 1.59 to 4.77 m3/hr) Severe Losses (30 to 100 bbl/hr or 4.77 to 15.9 m3/hr) total losses (>100 bbl/hr or 15.9 m3/hr) gunk squeezes gel/polymer gunk squeeze reverse gunk squeeze for use in obm decision tree to identify losses

2 3 3 4 5 5 5 6 6 6 6 6 7 9 7 7 8 8 8 9 9 9 10 10 10 11 12 13 15 15 16 18

Section

10c

hole problems - lost circulation


introduction Lost circulation is one of the most common and potentially one of the most expensive problems encountered in a drilling operation. In the best case results are often additional operating time and increased mud and operating costs, in the worst case results are often blowouts and lost hole. Lost circulation adversely affects the overall drilling operation by: ƒ The loss of hydrostatic head that may result in a well-control situation. ƒ The reduction in the pressure gradient may lead to wellbore stability, which could result in hole collapse and/or stuck pipe. ƒ Side tracks or complete loss of the well. ƒ Failure to achieve adequate annular cement coverage. ƒ Good quality formation evaluation may not be possible.

Lost Circulation Cost Impact Drilling Cementing Loss of mud Reduced annular coverage Lost time Casing corrosion Poor cement job Poor zonal isolation Reduced safety Reduced safety Stuck in hole Wasted casing string Failure to reach target TD Blow out and kill operations Downhole blowouts Environmental incident

Completion/Work-over Loss of completion fluid Lost time Formation damage Reduced safety Lost reserves Loss of well

Whenever loss circulation is anticipated a lost circulation contingency plan should be put in place. This will ensure that, when losses are encountered, the appropriate treatments are executed competently and methodically. In this manner the time and costs associated with losses can be controlled. The Lost Circulation Contingency Plan should set out response guidelines by: ƒ Defining and classifying the type and severity of losses ƒ Selecting the most appropriate material available ƒ Applying the most effective responses and treatments (LCM pill selection) ƒ Analysing the success of the treatments It must be emphasised that losses, like any other problem on the rig, should be approached methodically. Each sequential action should be discussed, planned and then executed. All relevant data should be documented so that a database can be compiled which will help to analyse and refine the current responses and treatments.

definition and classification Losses can simply be defined as the loss of whole mud to the formation. For this to occur both of the following conditions must exist: ƒ The dynamic or static pressure exerted by the total mud column exceeds the total formation pore pressure and or fracture gradient. ƒ The porosity and permeability of the formation is such that whole mud is lost to the formation thus preventing the sealing effect of the filter cake. Lost circulation of differing intensity can occur at any depth in various formations. In order to precisely and accurately define the situation on the rig the type and volume of losses must be identified and classified. Therefore, in the vast majority of cases, it should be possible to identify, classify, treat and report losses using the format set out in this lost circulation contingency plan. The type of losses can generally be classed as one of the following: ƒ Naturally occurring losses ƒ Mechanically induced losses The severity of losses can arbitrarily be classed as one of the following: Type of losses Seepage losses Partial losses Severe losses Total losses

Dynamic Losses bbl/hr < 10 10 – 30 30 – 100 > 100

Dynamic Losses m3/hr < 1.59 1.59 – 4.77 4.77 – 15.9 > 15.9

type of losses naturally occurring losses Naturally occurring losses can be defined as losses resulting from some aspect of the formation being drilled. Losses are common in various formations such as: ƒ Unconsolidated formations which include sand and gravel. ƒ Permeable formations such as poorly cemented sandstone. ƒ Cavernous and vugular formations which include gravel, limestone and dolomite. ƒ Natural fractures or fissures which can occur at all depths in all formations. Losses increase in older, harder more consolidated formations with depth. It is common to encounter fractures near faults and areas exposed to tectonic stress. Voids and fractures can generally be recognised by a change in the drilling parameters and when this occurs losses can be expected. Commonly, when losses occur whilst drilling these formations, they will increase proportionally with depth as more of the formation is exposed. Invariably LCM treatment of some degree, and associated lost time, is required to minimise or cure these losses. mechanically induced losses Mechanically induced losses can be defined as losses resulting from some aspect directly related to the drilling operation. Losses are caused by overpressuring and fracturing the formation which, once fractured, will easily re-fracture with l over pressure. The most common causes of mechanically induced losses are:

Section

10c


ƒ High hydrostatic pressure resulting from an excessive mud weight. ƒ High hydrostatic pressure resulting from an excessive annular cuttings load. ƒ High hydrostatic pressure resulting from an excessive ECD. ƒ High surge pressure resulting from an excessive drillstring or casing running speed. ƒ High downhole pressure resulting from a restricted annulus. Commonly, when losses are induced, they can be minimised or cured by altering the drilling or operational parameters without resort to a loss circulation treatment.

severity of losses seepage losses Seepage losses are arbitrarily defined to as dynamic losses of up to 10 bbl (1.59 m3) per hour when circulating at the minimum pump rate used for drilling. Static losses are generally not associated with this classification. Commonly, initial seepage losses will be minimal and will increase with drilling as more of the specific formation is exposed. Losses of this severity are commonly encountered in porous sands and fractured formations. The type of loss, naturally occurring or mechanically induced, can usually be resolved by suspending drilling, circulating the hole clean and observing the losses whilst varying the pump rate and pressure. It is not uncommon for seepage losses to self heal with time as cuttings bridge the pore throats or microfractures. partial losses Partial losses are arbitrarily defined as dynamic losses of 10 – 30 bbl (1.59 – 4.77 m3) per hour when circulating at the minimum pump rate used for drilling. Static losses are sometimes associated with this classification. Losses of this severity are commonly encountered in unconsolidated formations, vugular carbonates and fractured formations. The type of loss, naturally occurring or mechanically induced, can usually be resolved by suspending drilling, circulating the hole clean and observing the losses whilst varying the pump rate and pressure. severe losses Severe losses are arbitrarily defined as dynamic losses of more than 30 - 100 bbl (4.77 – 15.9 m3) per hour when circulating at the minimum pump rate used for drilling. Static losses are generally associated with this classification. Commonly, severe losses are instantaneous as fluid is lost to a void, the initial volume lost can range from tens to hundreds of barrels after which the losses may moderate or cease. Losses of this severity are commonly encountered in vugular carbonates and fractured formations. The type of loss can be assumed to be naturally occurring. total losses Total losses are arbitrarily defined as a total absence of returns when circulating at the minimum pump rate used for drilling. Static losses are also very high which necessitates new mud volume with which to maintain a full annulus. Commonly, it is often difficult, if not impossible, to mix new mud volume at the rate required to maintain a full annulus with high static losses, such a situation may result in a well control situation as the mud column and resultant hydrostatic pressure is diminished. Losses of this severity are commonly encountered in vugular carbonates and fractured formations. The type of loss can assumed to be naturally occurring.

prevention and control Outlined below are general rules of thumb to help cure and prevent losses: ƒ Geology, rock type and drilling fluid control the location and severity of most mud losses. Ask the rig, geologist about the rock types. ƒ If the loss zone occurs within highly soluble rock (evaporites such as salt), cure the loss immediately, even if at present it is not causing operational problems. Otherwise, it will only become worse if expecting heavy losses, use as large a bit nozzle as possible. ƒ First signs of downhole losses will be reduced mud return flow. A good drilling practice when first encountering losses is to pull off bottom immediately, reduce flowrate to 100 gpm, continue to rotate string to avoid packing off of cuttings around BHA as the annulus falls and KEEP PIPE MOVING. Pump initial LCM pill as soon as possible. ƒ The shape of the mud loggers’ pit level trace often enables the type of loss zone to be diagnosed, allowing the correct remedial measures to be made. ƒ For a mud possessing good fluid loss control, major whole mud losses will not occur through the matrix pores at permeabilities below 10 darcy. ƒ If possible, try curing losses caused by induced fractures immediately by reducing the ECD. ƒ If in doubt about the type of loss zone, first use a fine LCM and then progressively increase particle size, while maintaining, a wide distribution. ƒ Too high a concentration of LCM can cause problems (thick filter cake and packing off), and generally does not improve bridging. Instead for problematic zones, increase the viscosity of the pill. ƒ If possible, displace the pill slowly at approximately 200 gpm. ƒ If severe losses are anticipated run a circulating sub in the drill string. This will permit high concentrations of LCM material, including coarse material, to be pumped without risk of plugging bit or downhole tools. ƒ If losses are expected, premix a suitable LCM pill, designed for the type of losses expected, and store it in reserve. As soon as losses occur the LCM pill will then be ready to be pumped immediately, minimising impact on the operation critical path. The following potential causes and general measures can be taken to prevent losses from occurring. The applicability will be dependent on well design and may not be possible in all cases.

minimise annular loading An increase in annular drilling fluid weight due to drilled cuttings can break down the formation, particularly in surface holes. The effective increase in annular drilling fluid weight must be calculated and taken into account. Controlled drilling may be required.

good drilling fluid properties maintenance ƒ Efficient solids control packages allow the drilling fluid properties to be closely controlled. ƒ The density should be kept as low as possible to give a satisfactory overbalance. The overbalance required for wellbore stability is higher in a highly deviated well compared to a vertical well. ƒ Maintain gel strengths, yield point and 6 rpm reading at lowest levels that will effectively clean the hole. High viscosities can increase the ECD to a level that will break down the formation while circulating. ƒ Maintain low MBT levels. ƒ Keep fluid loss low to prevent excessive filter cake build up.

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minimise surge and swab pressures ƒ Use computer hydraulic modelling for determining trip velocity and acceleration schedule. ƒ If fluid density or the surge pressures are close to formation fracture pressure then, while tripping in, break circulation at the shoe and approximately every 1000 ft (305 m) in open hole. Circulate for at least 5 minutes. ƒ Bring the pumps up slowly after connections. ƒ Rotate the pipe before turning on the pumps. ƒ While tripping out, pump out for the first few stands/single off bottom. ƒ Keep tripping speeds slow across areas of potential lost circulation. ƒ Surge pressures calculations should be performed and the driller instructed as to the maximum allowable speed for running the pipe. ƒ Consider the use of lubricants to reduce drag. ƒ Consider the use of sweeps to clear the cuttings from wellbore prior to POOH to run the casing.

ecd minimisation ƒ Use computer modelling software to calculate equivalent circulating density. ƒ Reduce restrictions in the annulus by minimising filter cake build-up. This can be done by utilising high quality fluid loss additives and maintaining low drill solids content. ƒ Keep hydraulics at the minimum level required to clean the hole. ƒ Control ROP to avoid loading the annulus.

surface equipment ƒ Remove pump strainers. ƒ Line up surface piping so at least one mud pump can be rapidly switched to water or seawater. ƒ Test all surface equipment in advance. The normal procedure would be to check for leaks in the surface equipment before assuming losses downhole. ƒ Ensure that no unnecessary drilling fluid transfers, additions, or dilutions are carried out while drilling proceeds toward or in a loss zone.

downhole equipment ƒ As a general rule LCM particles should be less than a third of the nozzle size. ƒ Remove bit nozzles if large losses are expected. ƒ Use a circulating sub to pump high concentrations of LCM, including coarse LCM, to avoid plugging jets or downhole tools. It is important to use a ball made of high density material, relative to mud density, as this ensures it will sink. A circulating sub is less likely to function, open and close, the higher the inclination. ƒ Avoid running tools with limited flow paths or restrictions where possible. This includes core barrels, MWD, mud motors, floats and survey rings. ƒ If possible, avoid running drill pipe casing protectors as these can swell and act like a packer. ƒ Ideally losses should be dealt with as soon as they occur. It is possible to ahead with losses so long as there is adequate surface volume to sustain it. However, care must be taken if there is the possibility of penetrating a higher pressure zone as an underground blowout may result. ƒ If losses are anticipated a LCM pill should be prepared in advance and stored in an agitated pit. Usually a 100 bbl (15.9 m3) pill is adequate. Treat the pill with biocide if it contains organic matter. ƒ Prepare a large volume of reserve mud.

locate and identify loss zone ƒ If losses first occur while drilling ahead, or are accompanied by a change in torque or a drilling break, the losses are likely to be on bottom. ƒ If losses occur while tripping or increasing fluid weight, the losses may be off bottom. If necessary, a temperature or spinner survey can be run.

avoiding stuck pipe ƒ When losses occur, cuttings will settle out around the BHA and may mechanically stick the pipe. The cuttings will act as a packer and exacerbate losses below them. Always keep the pipe moving. Where possible, pull to the shoe before attempting a treatment. As a rule, have enough open hole volume below the bit to accommodate the whole treatment. ƒ Reactive clays overlaying the loss formation are likely to become unstable if exposed to uninhibited fluids. ƒ As loss zones may be at low pressure beware of differential sticking.

water base muds vs. non aqueous fluids The incidents of induced fracturing is the same for both WBM and NAF since the fracture initiation pressure is the same for both fluid types. NAF, however, may have a higher density / ECD downhole than WBM of equal surface density due to the effects of base fluid compressibility. In addition, NAF losses are much harder to control owing to the following reasons : ƒ Fracture propagation pressure is lower with conventional NAF ƒ Formation fracture generated during LOT may be easily re-opened and extended Losses are easier to control with WBM because these screen-out in the fracture tip. A pressure gradient is generated across the filter plug generated in the fracture, preventing transmission of the mud pressure to the fracture tip that may extend the fracture. NAF do not form solid plugs in fractures. They generally have very low leak-off and form very effective internal filter cakes, such that the induced fracture is usually filled with emulsified water and base oil. There is therefore effective communication with the fracture tip which will results in propagation of the fracture. The following recommendations are made to minimise LC problems with NAF : ƒ Relax on filtration and generate an external filter cake, if consistent with balancing differential pressures; use 100:0 oil/water ratio i.e. all oil if possible, mainly applicable to reservoirs. ƒ Add fibres/particles of appropriate size to increase fracture propagation pressures.

lost circulation materials lcm types Commercially available LCM products encompass a wide array of materials. Moreover, if it can be pumped down a well, it probably has been at one time or another. Particle shapes are granular, flake or fibrous at sizes denoted as fine (typically 20 - 60 mesh), medium (16 - 60 mesh) and coarse (16 30 mesh) : (a) Granular LCM - nutshells, calcium carbonate, sized salt, hard rubber, asphalt, gilsonite, plastic. (b) Flake-shaped LCM - mica, cellulose, cottonseed hulls, wood chips, laminated plastic, graphite, calcium carbonate. (c) Fibre-shaped LCM - cellulose fibres’, saw dust, shredded paper, hay, rice husks. (d) Commercial Blends - Blends of two or three different materials, meant to cover a range of sizes and shapes, e.g. combining granular, fibrous and flaked in one sack. Treatments in an active system should typically be at 5 - 20 lb/bbl (14.3 – 57.1 kg/m3), with the choice of using a single size and shape, combination of shapes and sizes or commercial blends. Pill treatments are typically at 25 – 50 lb/bbl (71.3 – 142.7 kg/m3) of LCM in slugs of 50 – 100 bbl (7.95 – 15.9 m3).

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lcm in productive zones When the loss zone is in or close to a potential production horizon, the use and subsequent removal of LCM by acid or other alternatives could result in formation damage. Therefore, the selection of suitable LCM is critical, particularly if open hole completions are planned, perhaps involving open hole gravel pack placements or sand control screens. In these cases it is best to incorporate LCM that has a proven history and can be removed by downhole treatments such as acid and hypochlorite treatments. ƒ Calcium carbonate can be subsequently removed using acid, typically 15% HCl. ƒ Cellulose fibres can also be used, with caution. While only about 40% soluble in acid, the fibres can usually be oxidised and removed by a 2% to 5% hypochlorite solution at high pH. It is recommended to confirm removal by lab work prior to use in the field. ƒ Sized salt particles, e.g. NaCl can be used in saturated salt fluids. The salt can be dissolved using water or dilute brine. ƒ Oil-soluble resins. Crude oil or condensate can in theory dissolve the resin when the well is brought on production, or treatments with diesel can be applied. This type of treatment requires some careful pre-planning and laboratory testing to ensure viability. Note: Productive formations or injection zones usually use a drilling fluid specifically designed to prevent formation damage, often referred to as a “Drill-In Fluid”. These fluids may already incorporate one or more of the aforementioned materials to minimise fluid invasion and formation damage.

permanent remedial treatments Various methods can be applied to more permanently isolate formations and heal lost circulation : ƒ Soft plugs – i.e. cross linked polymers, silicate gels, oil/bentonite mixtures and gunk. ƒ High Fluid Loss Pills - i.e. EZ-SQUEEZE ®, salt gel slurries. ƒ Hard Plugs - i.e. cement or cement added to soft plug materials, temperature activated resins that react in place.

bridging / sealing of porosity and fractures When lost circulation occurs, first determine the nature of the loss zone. Is the zone of high porosity or is it likely that fractures have been induced? Use formation and pressure information from: ƒ on-site geologists, mud loggers. ƒ relevant MWD logs (e.g. Gamma Ray, sonic). ƒ Downhole ECD tools, downhole pressure gauges or surface gauges (pay attention to the fact that compressibility may affect the downhole EMW/ECD of oil base muds). Next, devise a suitable response. If this response requires LCM to be pumped, than the material should be sized according to the type and size of the opening to which the losses occur. It should also take into consideration any downhole restrictions that the LCM must pass through, e.g. bit jets, downhole tools. Not all materials will work automatically, a successful remedial job requiring two stages, bridging and subsequent sealing of the loss zone. Bridging Guidelines ƒ For parallel slots/fractures - particles of 1/2 the width of the slot size are required. ƒ For round openings - particles of 1/3 the diameter of the opening are required.

Sealing Guidelines ƒ Sealing requires bridging first. ƒ After bridging, the sealing material will fill in the gaps between the bridging material. The gradation of sealing particle sizes lies below that of the bridging particle size. ƒ No seal will be formed if all particles are too large or if there are not enough small particles to bridge. ƒ Note that an internal seal may also be formed. This could give problems in the clean-up phase when production zones are drilled.

losses into porosity High porosity loss zones are characterised by pore throats that are large enough to allow the passage of all mud solids, e.g. drill solids and barite. The average particle size for barite is around 15 microns, so pores must be on the order of 45 microns, assuming a 1/3 rule for plugging, equivalent to a sandstone permeability of about 2000 mD. Start with mud carrying a base concentration, 5 – 15 lb/bbl (14.3 – 42.8 kg/m3) of fine lost circulation material. When losses are noticed and do not quickly self heal, add progressively larger particles to mud. Use cellulosic fibres and/or granular materials, typically at 5 lb/bbl (14.3 kg/m3) that do not interfere with shaker screens or that alter rheology. Pump pills/sweeps of mud treated with higher concentrations, 50 – 100 bbl (7.95 – 15.9 m3) of larger particles if these cannot be carried in the active system. Repeat pumping after a specific footage e.g. 50 - 100 ft (15 – 30 m) has been drilled.

losses into natural fractures Naturally fractured formations are characterised by in-situ fractures that must be large enough to allow the passage of all mud solids e.g. drill solids and barite. The average particle size for barite is around 15 microns, so fractures must be at least 30 microns or larger. The fracture width can be increased by increasing the mud density, therefore opening and further propagating the fracture. Start with mud carrying a base concentration, 5 – 15 lb/bbl (14.3 – 42.8 kg/m3) of fine lost circulation material. When losses are noticed and do not quickly self heal, add progressively larger particles to mud. Use cellulosic fibres and/or granular materials, typically at 5 lb/bbl (14.3 kg/m3) that do not interfere with shaker screens or that alter rheology. Pump pills/sweeps of mud treated with higher concentrations, 50 – 100 bbl (7.95 – 15.9 m3) of larger particles if these cannot be carried in the active system. Repeat pumping after a specific footage e.g. 50 – 100 ft (15 – 30 m) has been drilled.

losses into induced fractures To minimise exposure to induced losses, practice the following : (a) Use proper technique for running LOT to asses fracture gradients and in-situ minimum horizontal stress. (b) Keep mud density / ECD below fracture initiation, or fracturing reopening, pressure. (c) Keep rheological properties to a manageable minimum: ƒ Minimise ECD and surge pressures ƒ Monitor downhole pressure with ECD tools or downhole pressure gauges ƒ Ensure the rheology, 6 rpm reading, is adequate to prevent sag of the weighting material

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When fractures are induced and propagated, reduce mud density below fracture gradient. This, however, may not be possible when other formations are exposed such as over pressurised zones or weak formations, e.g. shales which require high mud overbalance for stability, or when the margins between pore-pressure and fracture gradient are low. Remedial treatments are essentially similar to the remediation of natural fractures.

responding to losses basic strategy 1. Maintain lowest possible equivalent circulating density (ECD) for conditions. Hole size, angle, and drilling fluid density requirements affect the ability to use one or more of the following to optimise ECD as low as possible. ƒ Reduce plastic viscosity and yield point of drilling fluid. Plastic viscosity may be difficult to reduce depending upon drilling fluid weight. Minimise yield point while maintaining hole cleaning ability. ƒ Reduce flow rate; use computer modelling to calculate requirements for hole cleaning. ƒ Reduce rotating rate, rpm. Maximum of 100 rpm, 80 - 90 recommended. 2. Use ECD effects to simulate weight up while drilling and circulating. 3. Pre-treat drilling fluid system prior to entering the depleted, potential loss, zone. Equipment Requirements and Limitations 1. Use of motors to drill generally precludes pre-treatment of the drilling fluid with loss circulation material, LCM. 2. Use of measurement while drilling, MWD, tools in the drill string can limit the type and amount of LCM used in the drilling fluid system or pills that may be spotted to heal loss zones. Check specification of the tools to be used to determine feasibility of pumping LCM-containing drilling fluid through them. 3. Use of a circulating sub in the drilling string above MWD or motors may provide flexibility to spot or circulate LCM treated pills in cases where severe losses are possible. 4. Bit Jets: 16 or larger preferred, 14 minimum. 5. Shaker screens: 20 - 40 mesh.

seepage losses < 10 bbl/hr (1.59 m3) Non Productive Zones: 1. Firstly, decide if the loss rate is acceptable/sustainable. At low loss rates and with inexpensive mud it may be OK to drill ahead without treatment. 2. If the losses are thought to be induced, reduce ECD, flow rate, viscosity and ROP, and consider a mud weight reduction. Ensure hole cleaning is maintained. If these approaches are successful this confirms the losses were induced. Drill ahead - LCM treatment may not be required. 3. If losses continue, drill ahead and add 5 -10 sacks per hour medium LCM to suction pit. Calcium carbonate is recommended, or it may be substituted with other medium grade LCM. If the mud does not contain fines, add 2 sacks/hr fine LCM in addition to the medium grade until the fines build in the system. 4. If seepage continues, increase LCM particle size and quantity, and consider different blends of materials. e.g. mix 10 sacks per hour of a combination of medium fibre and medium calcium carbonate. 5. Check that mud weight and viscosity restrictions are not being exceeded. Monitor shaker screens for blinding.

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6. If the seepage continues and is unacceptable, locate the loss zone and spot minimum 50 bbl (8 m3) pill and pull up ƒ 20 lb/bbl (57.1 kg/m3) medium grade calcium carbonate ƒ 20 lb/bbl (57.1 kg/m3) medium grade fibre or flake ƒ 10 lb/bbl (28.53 kg/m3) fine grade calcium carbonate

If the loss zone cannot be located change shaker screens to larger mesh size and treat entire system with 15 - 25 lb/bbl (42.8 – 71.3 kg/m3) medium/fine LCM blend in ratio 2:1 medium to fine.

Productive Zones 1. If the losses are suspected to be induced, reduce ECD, flow rate, viscosity, and ROP, and consider a mud weight reduction. Ensure hole cleaning/well bore stability is maintained otherwise pack-off could occur. If these approaches are successful this confirms the losses were induced. Drill ahead. LCM treatment may not be required. 2. If losses continue, drill ahead and add 5 - 10 sacks per hour medium LCM to suction pit. Calcium carbonate must be used unless other materials have been approved for use in the production zone, such as certain cellulose fibres. If the mud does not contain fines, add 2 sacks/ hr fine calcium carbonate in addition to the medium grade until the fines build in the system. 3. Check that mud weight and viscosity restrictions are not being exceeded. Monitor shaker screens for blinding. 4. If the seepage continues, locate the loss zone and spot minimum 50 bbl (8 m3) pill, made using active mud, and pull up and wait 2 – 4 hours. Pill should contain 30 – 50 lb/bbl (85.6 – 142.7 kg/m3) calcium carbonate or other approved LCM blend: ƒ 20 lb/bbl (57.1 kg/m3) medium grade calcium carbonate. ƒ 20 lb/bbl (57.1 kg/m3) medium grade approved cellulose fibre. ƒ 10 lb/bbl (28.5 kg/m3) fine grade calcium carbonate. Alternatively, if the loss zone has not been located change shaker screens to larger mesh size and treat entire system with 15 - 25 lb/bbl (42.8 – 71.3 kg/m3) of medium/fine calcium carbonate blend in ratio 2:1 medium to fine.

partial losses 10 to 30 bbl/hr (1.59 – 4.77 m3/hr) Non Productive Zones: 1. Consider reducing mud weight and ECD, if possible. Drill slower, reduce circulation rate and rheology, ensure adequate hole cleaning and maintain well bore stability, trip in hole slower, break circulation while rotating and working pipe, etc. Evaluate and eliminate any annular restrictions which may be causing an imposed annular pressure, such as balling of bit / BHA, mud rings, cuttings beds, etc. These actions may cure the problem if the losses are induced. 2. Drill ahead but consider treating entire system with 15 – 25 lb/bbl (42.8 – 71.3 kg/m3) medium LCM. If the mud contains very few fine solids, add 5 lb/bbl (14.3 kg/m3) fine grade LCM initially as well, until the larger LCM starts to grind down and produce the smaller particles. Check shaker screens for blinding. 3. If losses continue and loss zone identified, spot 50 -100 bbl (7.95 – 15.9 m3) coarse LCM pill and pull up and wait 2 - 4 hours. Pill should be mixed using active mud containing: ƒ 30 lb/bbl (85.6 kg/m3) coarse LCM (e.g. calcium carbonate, fibre, or nut shells). ƒ 20 lb/bbl (57.1 kg/m3) medium LCM. ƒ 5 lb/bbl (14.3 kg/m3) fine LCM. Note: Be sure bit nozzles and any MWD equipment are large enough to allow larger LCM to pass without plugging. Use circulating ports in the drill string.

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4. If partial losses continue, repeat pill procedure, spotting larger volume pill. Drill ahead and add 5 – 10 sacks/hr medium LCM to maintain sealing capability of the mud. Check bit nozzles/ MWD can handle the LCM and that shaker screens are not blinding. Productive Zones: 1. Consider reducing mud weight and ECD, if possible. Drill slower, reduce circulation rate and rheology, be sure to maintain adequate hole cleaning and well bore stability, trip in hole slower, break circulation while rotating and working pipe, etc. Evaluate and eliminate any annular restrictions which may be causing an imposed annular pressure, such as balling of bit / BHA, mud rings, cuttings beds, etc. These actions may cure the problem if the losses are induced. 2. Drill ahead but consider treating entire system with 15 – 25 lb/bbl (42.8 – 71.3 kg/m3) medium LCM. Use calcium carbonate unless other LCM has been approved for the pay zone. If the mud contains very few fine solids, add 5 lb/bbl (14.3 kg/m3) fine calcium carbonate initially as well, until the larger LCM starts to grind down and produce smaller particles. Check screens for blinding. 3. If losses continue and loss zone identified, spot 50 -100 bbl (7.95 – 15.9 m3) coarse LCM pill and pull up and wait 2 - 4 hours: Pill should be made using active mud containing: ƒ 30 lb/bbl (85.6 kg/m3) coarse grade calcium carbonate, or blend 20 lb/bbl (57 kg/m3) with 10 lb/ bbl (28.5 kg/m3) of approved cellulose fibre. ƒ 20 lb/bbl (28.5 kg/m3) medium grade calcium carbonate, or blend with approved cellulose fibre. ƒ 5 lb/bbl (14.3 kg/m3) fine grade calcium carbonate. Note: Be sure bit nozzles and any MWD equipment is large enough to allow larger LCM to pass without plugging. 4. If partial losses continue, repeat pill procedure, spotting larger volume pill. Drill ahead and add 5 – 10 sacks/hr approved medium LCM to maintain sealing capability of the mud. Check bit nozzles/ MWD can handle the LCM and shaker screens are not blinding.

Severe Losses 30 to 100 bbl/hr (4.77 – 15.9 m3/hr) Non Productive Zones: 1. Consider reducing mud weight and ECD, if possible. Drill slower, reduce circulation rate and rheology, be sure to maintain adequate hole cleaning and well bore stability, trip in hole slower, break circulation while rotating and working pipe, etc. Evaluate and eliminate any annular restrictions which may be causing an imposed annular pressure, such as balling of bit / BHA, mud rings, cuttings beds, etc. These actions may cure the problem if the losses are induced. 2. Identify loss zone, spot 50 –100 bbl (7.95 – 15.9 m3) LCM pill, pull up and wait 2- 4 hrss: Pill should be made using active mud containing: ƒ 30-50 lb/bbl (85.6 – 142.7 kg/m3) extra coarse LCM, single additive or blend, preferably containing fibre or nut shells. ƒ 20 lb/bbl (57.1 kg/m3) coarse LCM. ƒ 10 lb/bbl (28.5 kg/m3) medium LCM. Note: Be sure bit nozzles/downhole equipment are large enough to allow larger LCM to pass without plugging. Use drillstring circulating subs. Be prepared for shaker blinding. 3. If severe losses continue, repeat the pill. If partial losses now occur, refer to earlier procedures 1 and 2 to suit the new loss rate. 4. If severe losses still continue, consider soft or hard plugs; refer to total loss section, below, for options.

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Productive Zones: 1. Consider reducing mud weight and ECD, if possible. Drill slower, reduce circulation rate and rheology, be sure to maintain adequate hole cleaning and well bore stability, trip in hole slower, break circulation while rotating and working pipe, etc. Evaluate and eliminate any annular restrictions which may be causing an imposed annular pressure, such as balling of bit / BHA, mud rings, cuttings beds, etc. These actions may cure the problem if the losses are induced. 2. Identify loss zone, spot 50 –100 bbl (7.95 – 15.9 m3) LCM pill, pull up and wait 2 - 4 hrs: Pill should be made using active mud containing: ƒ 30-50 lb/bbl (85.6 – 142.7 kg/m3) extra coarse grade calcium carbonate, or other approved LCM for the production zone. ƒ 20 lb/bbl (57.1 kg/m3) coarse grade calcium carbonate, or other approved LCM for the production zone. ƒ 10 lb/bbl (28.5 kg/m3) medium grade calcium carbonate, or other approved LCM for the production zone. Note: Be sure bit nozzles/downhole equipment are large enough to allow larger LCM to pass without plugging. Use drillstring circulating subs. Be prepared for shaker blinding. 3. If severe losses continue, repeat the pill. If partial losses now occur, refer to earlier procedures to suit the new loss rate. 4. If severe losses still continue, consider soft or hard plugs; refer to total loss section, below, for options.

total losses >100 bbl/hr (15.9 m3/hr) There are many options available to address high loss rates, ranging from ordinary cements to specialised cements, ‘gunks’ and polymer systems. With such a wide choice of options available it can be difficult to make a selection. In practice, the exact chemical system chosen is not critical, provided it is the right type of system for the job and is engineered correctly. Most failures actually occur because of engineering errors. To avoid engineering errors ensure: ƒ sufficient pill volume is pumped. ƒ setting time is correctly calculated. ƒ no contamination. ƒ the pill is spotted in the right place. ƒ appropriate equipment for mixing and pumping is available. engineering principles Many of these treatments will require specialised mixing and pumping procedures. The product supplier should provide detailed instructions on the mixing and placement of the material. Some general guidelines are as follows: ƒ Locate the loss zone and design sufficient pill volume. ƒ Establish how the material will be delivered downhole (i.e. by a pumping unit or with the rig equipment); make sure the equipment is set up. ƒ Count pump strokes and be sure to know where the treatment is at any one time. ƒ Some treatments are polymer systems which are triggered by cross-linking agents. Setting time is usually very dependent on temperature so accurate downhole temperature prediction is very important. If possible it is recommended a pilot test is done to confirm cross-linking time at downhole temperature and pressure. Note that the temperature will normally be less than the static BHT due to cooling which has occurred due to the losses. So setting times can be longer than expected. Pills pumped down will take a considerable time to heat up. 13

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ƒ Monitor pipe and casing pressures to reduce the possibility of induced losses and to verify the displacement of the LCM from the pipe. ƒ Squeeze the treatment into the formation, if possible. ƒ Pull the drill pipe clear of the calculated top of the pill by at least 100 bbl (15.9 m3) of hole volume or pull into casing - otherwise the string could become cemented in. ƒ Wait the required time for the treatment to react and take effect. ƒ To avoid blockage, do not try to pump particles bigger than 1/3rd the nozzle diameter through the BHA, and check MWD restrictions. ƒ Use a pill with density equal to the active mud to avoid migration. treatment selection Conventional LCM are not effective for very high loss rate situations (>100 bbl/hr or 15.9 m3 /hr). They work by bridging, and at loss rates >100bbl/hr (15.9 m3 /hr) the fractures/voids are generally too large for the materials to function. The alternative is to use chemical systems which set and seal the loss zone. There are several types of system available: ƒ Cements/Modified Cements ƒ Gunks and Reverse Gunks ƒ Dilatant Slurries ƒ Cross-linked Polymers & Gelled plugs ƒ Silicate systems Points to consider when using these type of pills: 1. Ordinary cements form a hard set which tends to be brittle. This is long-lasting but will not ‘breath’ with the well bore. If flexing of fractures is likely to occur a more flexible plug, e.g. polymer plug or gunk type system, is more appropriate. Cements also have relatively long setting times and are not generally pumped through the bit. This can cause long delays. 2. Cements used for extreme losses should be preceded with a silicate type pill which flash-sets the cement. Otherwise, large volumes would need to be pumped. 3. Gunk and reverse gunk treatments are a cheap and often effective cure in very high loss situations. They have the advantage they are not very sensitive to temperature, setting time. However, these systems generally have a limited lifetime and do not withstand high differential pressures. A gunk pill strengthened with added cement powder will allow it to withstand higher differential pressure, although this is only suitable for WBM applications. 4. When considering cross-linked polymer treatments for sealing, ensure there are bridging solids present which will help to screen out and seal any fracture. Many polymer systems already contain such solids. Ensure the treatment can still be pumped through the BHA, if this is intended. Be aware of the importance of temperature. 5. Curing losses in the production zone requires special attention. It should be assumed that damage will occur to the region where the pill is pumped. There are few treatments which are usable in open hole completions and any solution should be lab tested to ensure it can be removed at a later date if necessary. It is more effective to try to engineer a treatment with bridging solids to minimise the invasion of material into the rock matrix.

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gunk squeezes Description The basic system forms a fairly soft plug. Essentially the gunk treatment involves mixing bentonite, or bentonite/polymer into an oil such as diesel. This mixture is pumped down the drill pipe while water based mud is pumped down the annulus. When the two streams meet, a thick gunk is formed as the bentonite or other additives hydrate in the water. This is then squeezed into the formation. The hardness of the gunk depends on the relative pump rates and the concentration of the pill. Typically the mud and pill would be pumped at similar rates and the pill would contain around 200 - 400 lb/bbl (571 – 1141 kg/m3) bentonite. In many situations today environmental regulations may preclude the use of diesel oil. Low toxicity or synthetic base fluids may be used in place of diesel. They should be pilot tested in the mud laboratory at the wellsite to determine performance. A cement unit is best for displacing the gunk squeeze. The pumping unit displaces the mixture down the drill string and the mud pump pumps fluid down the annulus. The slurry reacts with water so that precautions to keep water from prematurely contacting the slurry are needed. An oil spacer is pumped in front of and behind the pill. Benefits: ƒ Temperature is not very important. ƒ Soft set avoids sidetracking problems, easy to wash/drill out. ƒ Slurry will normally pass through BHA. ƒ Procedures are well established. ƒ Suited to large fractures/voids. Limitations: ƒ Placement – need to generate gunk in the right place. ƒ Flow rate and mix is important to achieve suitable consistency. ƒ Suitable experience required. ƒ Avoid premature mud contamination. ƒ Possible environmental restrictions dealing with oily returns. ƒ Effect can be short-lived due to softness of the plug, simple gunk. ƒ May not work with high salt muds, >50,000 mg/l chlorides.

gel/polymer gunk squeeze Formulation for 25 bbl (4 m3 ) ƒ 18 bbl (2.86 m3) Diesel or other base fluid. ƒ 4,800 lbs (2,177 kg) bentonite, final density = +/-10 lb/gal (1.20 SG). ƒ 750 lbs (340 kg) PHPA powder if available can also be added.

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Section

10c


Recommended Mixing Procedure Mix in a cementing batch tank. This pill should not be mixed in the pits: ƒ Ensure the cement unit, batch tank and all associated pipe work is completely drained and then flushed through with diesel or other suitable base fluid. ƒ (Add PHPA powder to the diesel or other base fluid first, then add the bentonite. Preferably add the PHPA through a mixing jet, not directly into the tank, to avoid lumps) ƒ If the mixture becomes too thick to add the required quantity of bentonite, stop mixing and use the slurry as it is. ƒ Test the gunk by mixing a sample of it 50:50 with the mud. Check the quality - it should be a consistency similar to a thick paste within 30 seconds. Recommended Pumping Procedure 1. Place the bit above the loss zone such that the height between the bit and loss zone is equivalent to 50 bbl (8 m3) of hole volume. 2. Line up mud pumps to pump simultaneously down the drill pipe and annulus. 3. Line up cement unit to pump down the drill pipe. 4. With the cement unit pump 10 bbl (1.59 m3) diesel or base fluid followed by 25 bbl (4 m3) gunk and a further 10 bbl (1.59 m3) diesel/base fluid down the drill pipe. 5. Displace with the mud pump until diesel/base fluid is at the bit. Close annular. 6. Pump at 5 bpm (0.795 m3 /min) down the drill pipe and 10 bpm (1.59 m3 /min) down the annulus simultaneously until half of the gunk is out of the bit. 7. Pump at 5 bpm (0.795 m3 /min) simultaneously down both the drill pipe and annulus until the gunk has been over displaced from the drill pipe by 5 bbl (0.795 m3). 8. Squeeze gunk into the loss zone. Leave at least 5 bbl (0.795 m3) gunk inside the wellbore to prevent over displacement. Try to establish a shut-in pressure at the end. 9. If successful, leave the gunk to firm up for 8 – 10 hours prior to washing out. Remarks The gunk pill is inert until it is mixed with water or water based mud. It must only contact water based fluids as it exits the bit. The purpose of initially pumping down the annulus at twice the rate down the pipe is to initially produce a slower reacting product that can penetrate the formation more easily. The last part of the gunk is mixed 50:50 and plugs the loss zone quickly. The flow rates are designed to deliver the gunk to the loss zone quickly after the gunk has been mixed with the mud. The progress of the job should be determined and monitored by the volume of displacement mud pumped down the drill pipe.

reverse gunk squeeze for use in OBM This is the reverse procedure compared to ordinary WBM gunk squeezes. Typically, organophilic clay is mixed into an aqueous suspension and pumped down the drill pipe. The oil mud is pumped simultaneously down the annulus and gelation occurs when the two fluids meet. The gunk is squeezed into the formation. Note that it is not possible to add cement to strengthen the pill. Benefits: ƒ Temperature is not very important. ƒ Soft set avoids sidetracking problems (easy to wash/drill out). ƒ Slurry will normally pass through BHA. ƒ Procedures are well established. ƒ Suitable for large fractures/voids.

16

Limitations: ƒ Placement – need to generate gunk in the right place. ƒ Suitable experience required. ƒ Avoid premature mud contamination. ƒ Mixing time/placement often greater than 6 hrs. ƒ Effect can be short-lived due to soft plug formed. ƒ The type of clay used to make the treatment can be quite critical. Recommended Formulations A. Formulation for 1 bbl (0.159 m3) of unweighted reverse gunk pill

Product Water Caustic Soda Dispersant (CFL) Organophilic clay

Amount 0.72 bbl (0.114 m3) 1.5 lb (0.68 kg) 3.5 lb (1.59 kg) 250 – 350 lb (113.4 – 158.7 kg)

Note: This formulation is provided as a guide only. The yield obtained will vary greatly dependant on the particular organophilic clay used. Pilot testing of the pill formulation is strongly recommended. The formulation given above will have a density of approximately 12.0 lb/gal (1.44 SG). B. Formulation for 1 bbl (0.159 m3) of weighted 13.0 lb/gal (1.56 SG) reverse gunk pill. The slurry density can be increased to that of the active mud weight by viscosifying the water/clay slurry with XCD polymer and adding barite. This must be pilot tested prior to use to determine the optimum amount of XCD Polymer.

Product Water Caustic Soda Dispersant (CFL) Organophilic clay Barite XCD Polymer

Amount .72 bbl (0.114 m3) 1.5 lb (0.7 kg) 4.4 lb (2 kg) 100 lb (45 kg) 80 lb (36 kg) as determined

Recommended Mixing Procedure The pill should preferably be prepared in the cement batch tank. Ensure that the batch tank and all associated lines are clean by flushing thoroughly with a water based rig wash followed by large volumes of water. Add the ingredients in the order shown utilising as much shear as possible to disperse the organophilic clay. A minimum pill of 25 bbl is recommended. The resultant slurry is preferably pumped through open ended pipe but may be pumped through the bit if it is not practicable to POOH. The following displacement procedure should be strictly followed to prevent gelation within the drill pipe. Before the displacement the string should be pulled back to a height sufficient to leave the pill volume of open hole.

17

Section

10c


Recommended Pumping Procedure 1. Pump 10 bbl (1.59 m3) oil 2. Pump 10 bbl (1.59 m3) water 3. Pump the slurry 25 bbl (4 m3) 4. Pump 10 bbl (1.59 m3) water 5. Pump 10 (1.59 m3) oil 6. Displace the pill to the bottom of the drill string. 7. If the hole is full, close the annular and squeeze at 300 – 500 psi (2069 – 3448 kPa) into the formation. 8. If the hole is full, close the annular and pump the pill at 1 bbl/min (0.159 m3 /min) down the drill pipe and mud at 1 bbl/min (0.159 m3 /min) down the annulus. 9. Allow at least 4 hours for the plug to set. Note: Ensure that the entire pill is pumped out of the string. Do not attempt to reverse circulate.

decision tree to identify losses

Whole mud loss

Is loss occurring downhole?

NO

Cure surface loss

YES

Were losses successfully treated?

YES Similar loss in same section of adjacent well

NO

NO

Unconsolidated or high permeability formation in open hole section?

YES Repeat cure, using same placement procedure and LCM

Continue analysis in light of past experience

YES

NO

Did loss start gradually, building up to maximum rate?

Did loss start while tripping?

NO

YES Scenario: Induced Fractures 3or 7

Scenario: Natural Fractures 3or 7

o Is loss associated with recent

o Is loss associated with drill

increase in ECD?

o Is ECD near anticipated fracture gradient?

o Is formation permeable? o Is loss rate highly sensitive to change in ECD?

o Is loss associated with lithology change from shale to sandstone More 3than 7 Natural Fractures

break?

YES

NO

o Is fault or fractured interval anticipated in open hole section?

o Is rock dolomitised or karstified?

o Have small losses in past 1020meters slowed considerably?

Is loss rate highly sensitive to change in ECD?oss

NO

o Is formation interbedded? More 3than 7 Induced Fractures

YES

YES

Losses through induced fractures

18

YES

Losses through natural fractures

Losses through pores

system guidelines section 11

fluid systems guidelines

section 11a - roles and responsibilities section 11b - water base drilling fluids section 11c - non aqueous fluids section 11d - completion fluids

section 11a roles and responsibilities

roles and responsibilities roles and responsibilities – mud engineers The drilling fluids engineer is the Scomi Oiltools representative and therefore responsible for the day-to-day operations at the wellsite. The lead / senior drilling fluids engineer and the second / junior engineer are responsible for the daily running of the mud and all activities associated with the operation, including but not limited to: fluid testing, logistics, inventory control and communication with the drill crew, the mud loggers, other members of the mud team and primarily the operators drilling representative. The drilling fluids engineers are responsible for all mixing and maintenance of the drilling fluid, at the wellsite, as per the drilling fluids programme and amendments. They will also suggest changes to the operators drilling supervisor as conditions dictate preferably including discussion with the Scomi Oiltools operations manager / co-ordinator beforehand when possible. The drilling fluids engineers will comply with all of the operators and rig contractor’s HSE plans, and carry out their specific HSE drilling fluid responsibilities. The roles and responsibilities for the drilling fluid engineers may vary depending on the particular job and operator, e.g. onshore / offshore, drilling with WBM / OBM / SBM, deepwater, ERD, HPHT etc., and in many cases the following list will be considerably more expansive and detailed than shown here:Responsibility 3 Attend operators / contractors safety meetings and advise on all matters pertaining to Scomi Oiltools HS&E and products. The requirement for drilling fluids engineers is to not only attend but to contribute to safety meetings onsite, including giving presentations on the fluids and chemicals being used. 3 Give toolbox / pre tour talks on chemical safety. 3 Take part in risk assessments relevant to fluids in particular for first use of new systems e.g. SBM/OBM etc., 3 Ensure correct and updated safety posters are in place in the mud and sack rooms or mixing areas for land rigs. 3 Ensure MSDS are up to date and easy to locate. 3 Use rig specific HSE observation system e.g. STOP. 3 Maintain safe & tidy mud laboratory. Daily 3 Be familiar with all aspects of the drilling unit and it’s equipment including limitations and bottlenecks that may impact the efficiency of the drilling fluid Mud service. Maintenance 3 Ensure that all drilling fluid systems are correctly formulated to fully meet the and company’s fluid specifications prior to displacement into the well. Performance 3 Ensure that clear written instructions are provided to all relevant rig crew working in the pit room, mixing area, shaker house and rig floor to cover all planned fluid transfers, chemical additions and solids control equipment utilisation. 3 Ensure that mud logging and drilling personnel are informed of all transfers or changes of pit utilisation. 3 Ensure that all drilling fluid properties are maintained, as specified in the drilling fluid programme. 3 Perform all necessary API mud checks for mud report – minimum 3 times daily while drilling. Mud test results that deviate sharply from established mud property trends must be re-run before treatments commence to reverse apparent negative trends. Role HSE

Section

11a

roles and responsibilities

Responsibility 3 Run pilot tests as required to diagnose drilling fluid problems, identify their solutions and/or optimise chemical treatment levels. 3 Calibrate, maintain and monitor certification of mud testing equipment. 3 Closely monitor the condition, i.e. shape, size and integrity, and volume of cuttings at the shale shakers to assess the adequacy of:3 Formation inhibition (water based mud) 3 Salinity levels (synthetic based mud) 3 Hole stability (mud weight) 3 Hole cleaning efficiency 3 Reconcile circulating volumes on a continuous basis in particular with OBM / SBM. 3 Optimise solids control equipment performance to minimise the build up of low gravity solids and therefore maintain plastic viscosity values as low as possible. 3 Select and monitor shaker screen sizes and usage. Order new screens. 3 Closely monitor, control and minimise surface drilling fluid losses. 3 Ensure that the rig crews monitor and record pit volumes, density and marsh funnel viscosity as required, i.e. minimum 30 minute intervals during drilling / circulating operations. 3 7-day sample rota:-collect a 1-litre mud sample every day and store this sample for 7 days. This can be done by having seven 1-litre bottles, one for each day. When all 7 bottles are full, the bottle from day one shall be emptied and filled with a sample from the present day. The mud sample has to match a mud check, preferably the last mud check for the day. (You have to notify the laboratory which mud check this is on the daily report, if you have to send the samples t o the lab.). 3 Carry out mud pit management, including; identifying fluid interfaces, spacers, pills, cement and divert. 3 Prepare pit management plans for upcoming operations e.g. intervals displacements, spotting pills / LCM, well clean up etc. 3 Call operations manager / co-ordinator. Daily 3 Attend operators morning meeting as required. Meetings / 3 Attend operators / contractors safety meetings / per tour safety meetings, advise on all matters pertaining to Scomi Oiltools HS&E and products. Calls 3 Report unscheduled events in operators specific system, attend meeting if required. 3 Prepare and distribute drilling fluids report. Daily 3 Complete all sections of the daily mud report. Reporting 3 If drilling fluid properties are out of specification a comment should be put on the daily drilling fluid report explaining the reason for the nonconformity and the plan for bringing the properties back into specification. 3 If the well conditions or other operational circumstances dictate the properties to be out of specification this should also be stated as a comment on the report. 3 All mud treatments should be commented on in the daily report. 3 Update all end of well reports / graphs for fluid trends, volumes, inventory, discharge etc. 3 Update end of well written report. 3 Update volume reports, transport loss, concentration sheets and other contract specific reports for signatures by Scomi Oiltools and operator. 3 Write handover to night / second engineer to be completed thoroughly. 3 Maintain discharge / environmental reports. 3 Update shaker screen usage sheet. End of Hitch 3 Compile end of hitch report. Paperwork 3 Complete timesheet / service voucher signed by engineer and operator. 3 Complete – and send to town - all end of well reports / graphs for fluid trends volumes, End of inventory, discharge etc. as required for the well. Section Reporting Role

Responsibility Role End of Well 3 Complete all aspects of end of well report with emphasis on performance measures achievement, lessons learned and conclusions / recommendations for reporting future wells. 3 Update rig information manual / rig drilling fluids audit / rig induction manual. 3 Order chemicals / bulk (drill water if applicable) in a timely manner. Logistics 3 Order laboratory chemicals and equipment. 3 Advise on the loading / unloading of bulk fluids & chemical containers. 3 Advise rig crews to ensure cargo is securely fastened e.g. cargo nets in containers. 3 Chemicals and fluids are to be ordered and accounted for in units according to contract. 3 Ensure that all materials received at the rig site and handled for shipment to shore or land warehouse are correctly stored, handled and used according to guidelines given in quality plans and materials safety data sheets. Maintain a rig site chemical and container inventory sheet including; chemical name, container number, amount and location of items. Update on a regular basis for information purposes. 3 Perform QA / QC checks on received dry bulk and liquid muds / brines as specified by the operator. 3 Take samples for and send to office as requested for QA / QC testing. 3 Update chemical inventory and container list – offshore. 3 With any backload of chemicals, mud, laboratory equipment, copies of the Backload manifest to be sent. Ensure that bulk barite stocks are maintained above government / company’s minimum stipulated levels. 3 Ensure that pipe freeing agents are available and accessible for immediate displacement. 3 Ensure that stock levels of lost circulation materials are maintained above minimum specified levels. 3 Ensure that all materials and equipment orders for the next hole section or operation are carefully prepared in advance. 3 Order and maintain an adequate inventory for supplies of PC, testing equipment and testing chemicals. 3 Last engineer on rig due to down-manning etc., to prepare full chemical, liquid End of job mud, and equipment inventory. This sheet must be signed by drilling supervisor and or and sent to the office. Demanning

section 11b water base drilling fluids

section 11b

Scomi Oiltools

spud muds

2

hydro-foil

5

hydro-foil gen 1

9

hydro-foil S8

12

hypr-Foil S8

17

HyPR-Drill

20

salt polymer

25

opta-flo

27

rheo-plex

34

dispersed and calcium muds

37

Section

11b

water base drilling fluids


spud muds This system consists of water which has been viscosified with DRILL-GEL (Bentonite) or guar gum. This system is normally used to spud a well and to drill top hole sections, often being pumped as sweeps when drilling blind. The basic system has little inhibitive characteristics and as it is usually used where the primary concern is hole cleaning, there is little or zero need for inhibition or fluid loss control. When drilling top hole sections, the operational practice may require displacing the hole to a weighted spud mud before running casing. This displacement mud may be engineered to fulfil more specific requirements and will be addressed in well specific planning. Benefits of the DRILL-GEL Spud Mud System ƒ Fluid has high carrying capacity ƒ Simple to formulate ƒ Highly flexible can be converted into different systems ƒ Low costs ƒ Simple to use ƒ Environmentally benign Limitations of the DRILL-GEL Spud Mud System ƒ May have logistical restrictions on fresh water availability in remote locations ƒ Requires time to mix ƒ In complex spuds, logistics are difficult ƒ Requires high quality water, with low chlorides and low hardness ƒ Easily contaminated Formulation An example of a basic Spud Mud formulation is shown in Table 1. PRODUCT drill water soda ash DRILL-GEL caustic soda PROPERTY Mud Weight PV YP 6 RPM Gel API

Function Base Fluid Total Hardness Reducer Viscosifier pH modifier TYPICAL VALUE 8.8 20 20 - 60 10 + 11/20 No control

Table 1 – Indicative DRILL-GEL spud mud formulation

CONCENTRATION +0.95 bbl/bbl / 0.95 (m3/ m3) To Ca++ <100 mg/l 20 - 30 lb/bbl ( 57 – 85 kg/m3) To pH 9+ UNITS lb/gal cP lbs / 100 ft2 dial reading lbs / 100 ft2 ml / 30 min

The normal method is to prehydrate DRILL-GEL (PHB) at concentrations of 35 - 40 lb/bbl (100 – 114 kg/m3) in drill (fresh) water, allowing the gel to hydrate as long as operationally possible. The fluid is then diluted to give a final bentonite concentration of + 20 lb/bbl (57 kg/ m3) with water. To maximise the yield of the DRILL-GEL high quality water is recommended throughout, however, due to logistical / operational restraints the initial prehydration should be performed in high quality drill water then diluted with seawater or lower quality water e.g. brackish water. To optimise the hydration, 6 – 8 hours minimum is required for the DRILL-GEL to fully yield. While the basic formulation detailed in Table 1 is very simple, operational needs may dictate the addition of other products to ensurethe integrity of the hole and the security of the operations. Typical contingency / supplementary products and reasons for addition to the basic bentonite system are detailed in Table 2. Chemical Function Operational HYDRO-PAC

Viscosity and Filtration

CMC


HYDRO-STARCH


Isothiazolin

Biocide

DRILL-BAR

Barite

Enhanced filtration control in displacement mud and sweeps Enhanced filtration control in displacement mud and sweeps Enhanced filtration control in displacement mud and sweeps Prevention of microbiological action To build spud mud and displacement mud where density is greater than 8.8 lb/gal (1.05 SG)

Concentration lb/bbl

Concentration kg/m3

1.0 – 5.0

2.85 – 14.15

1.0 – 5.0

2.85 – 14.15

1.0 – 5.0

2.85 – 14.15

500 -1000 ppm As required

Table 2 –Supplementary Products Engineering Guidelines The primary concern while drilling and casing the top hole is to ensure that it is performed safely, quickly because the integrity of the hole may be time dependant, and economically. When drilling with a spud mud the major concern is to ensure there is always sufficient volume available to complete the operation. Thus a high level emphasis should be placed on ensuring the availability of bentonite, drill water and other required chemicals. As there may also be requirements for displacement and cementing fluids as well as the spud mud, a pit management is a major consideration during the planning and execution of the operations.

Section

11b


Offshore On an offshore rig the normal approach is to drill riserless, with no returns to surface. The rig pumps are used to continuously pump seawater down hole. The bentonite is then pumped as sweeps to clean the hole. These sweeps are pumped according to operational needs, usually at every connection and every 30 ft (9 m). The volume of these sweeps vary according to needs of the operation but are normally in the range of 50 - 100 bbl (8 - 16 m3), depending on hole size, pump capability and rate of penetration. At the end of the section the hole is normally swept with a large spud mud pill, generally 100 - 200 bbl, to ensure that the hole is clean. In order to ensure the integrity of the hole during the casing and cementing, operations the hole is then displaced to a fluid which may be weighted, may contain some filtration control polymers, fine LCM and or inhibitors such as KCl. An excess volume, usually 50% over the gauge hole volume, is pumped to ensure that the hole is full. Onshore The approach is normally to circulate water from the water pit, taking returns to the cellar pit and recirculating. Sweeps can then be pumped to ensure the hole is cleaned. Once the conductor (the top hole casing string) is set, normally ± 50 - 100 ft (15 - 30 m), the spud mud can be circulated from the pits taking returns via the flow line and through the solids control equipment. Mixing Spud Mud ƒ Treat out the hardness of the water with soda ash. Ensure hardness value is less than 200 mg/l ƒ Mix in the required DRILL-GEL ƒ Leave gel to hydrate for as long as possible ƒ Cut back the prehydrated bentonite with the required volume of water ƒ Added the required caustic soda As mentioned above displacement fluids for top holes may be, diluted spud mud, neat PHB or spud mud / PHB containing polymers, lost circulation materials and may also be weighted. This will be mixed as described above with the addition of the required products. Cementing Bentonite spud mud is sensitive to cement contamination. The effect of cement is to flocculate the bentonite, increase the pH. If the fluid is to be salvaged to drill another section, pre-treatment with sodium bicarbonate should be considered and at the end of the cement job, the contamination treated out by use of SAPP and /or dumping and diluting. If salvaging the fluid is not required, it is suggested that the fluid is kept to drill out the rat hole and the shoe, provided this is operationally feasible. This will prevent the contamination of more expensive fluids by the cement. Alternative Spud System – GUAR GUM The logistical limitations to the use of DRILL-GEL sweeps may require the use of an alternative system particularly in the offshore environment. The most common and economically effective alternative is guar gum which can be mixed directly with seawater. The concentration of guar gum is normally in the range 3.0 - 5.0 lb/bbl (8.6 - 14.25 kg/m3). PRODUCT sea water citric acid guar gum HYDRO-CIDE

Function Required Only if necessary to reduce the pH <8.0 4.0 lb/bbl (11.4 kg/m3) Only if fluid is to be stored more than 24 hours.

Recommended Mixing Procedure: 1. Ensure the chosen pit is clean and free of any hydroxyl bearing fluid e.g. lime, caustic soda or biocide. Guar Gum will not hydrate in the presence of hydroxyl ions. pH <8.0 is recommended. If necessary treat the mixing water with citric acid to lower the pH prior to mixing the guar gum. 2. Fill the pit to the required level with sea water. 3. Mix guar gum slowly through the hopper to avoid “Fish Eyes” and then circulate through the shearing unit. Do not over shear as this will eventually degrade the polymer chain and result in lowering the viscosity. 4. Add biocide if the guar gum slurry is to be left for more than 24 hours. This should only be added after the guar gum has been completely dispersed and hydrated. It should be noted that although guar gum sweeps have high viscosity, they have little gel structure giving minimal suspension characteristics. They should be used as ‘sweeps’ only.

hydro-foil HYDRO-FOIL is a KCl / PHPA low solids, non dispersed drilling fluid system that is used primarily to drill moderately reactive shales. It can be used effectively at temperatures up to 275 - 300 ˚F (135 - 149 ˚C). The primary shale inhibition mechanisms in the HYDRO-FOIL system are: 1. The cation exchange of potassium ions with the clay to reduce hydration and swelling in conjunction with; 2. HYDRO-CAP XP a partially hydrolysed polyacrylamide (PHPA) which adheres to the surface of the drilled cuttings, encapsulating them, and also coats the well bore reducing the hydration of clays in the formation. Potassium chloride is the primary source of the potassium ions in the HYDRO-FOIL system. However due to restriction on the use of chloride ions, in some areas, the potassium Ion may also be supplied by:ƒ potassium sulphate ƒ potassium carbonate

ƒ potassium formate ƒ potassium acetate

The HYDRO-FOIL system can be used in any salinity from freshwater to near NaCl saturation, although in the higher salt content systems increased polymer concentrations will be required as the polymer does not fully uncoil and hydrate. When using a HYDRO-FOIL system formulated with potassium carbonate a third mechanism of inhibition is speculated. The calcium ions in the interstitial (pore) fluids will cause the carbonate ions in the filtrate to precipitate, plugging the pore throats and reducing the pore pressure transmission effect. Benefits of the HYDRO-FOIL system include: ƒ ƒ ƒ ƒ ƒ

Effective inhibition Environmentally acceptable in most areas Highly lubricious fluid Simple to use Readily upgradeable to more advanced systems such as HYDRO-FOIL GEN 1

Section

11b


Formulation An example of a HYDRO-FOIL formulation and mud properties is shown in Table 3. Product Function drill water Base Fluid Salt (KCl) Water activity and density caustic soda / pH modifier potassium hydroxide HYDRO-ZAN / Viscosifier HYDRO-ZAN RD HYDRO-CAP XP PHPA HYDRO-PAC Filtration Control HYDRO-STAR Filtration Control CMS, HT or NF) DRILL-BAR Weight material

Concentration Concentration lb/bbl kg/m3 0.85 bbl/bbl 0.85 m3/ m3 + 30 85.5 To pH 9.0 0.75 -1.0

2.1 – 2.85

1 – 1.5 1 - 3 4 - 8

2.85 – 4.3 2.85 – 8.55 11.4 – 22.8

As required

As required

Table 3 – Indicative HYDRO-FOIL formulation Mud Weight PV YP 6 RPM Gel API HTHP (@ Bottom Hole Temp °F)

9.7 20 30 11 7 / 10 / 12 <5 <12 ml

lb/gal cP lb / 100 ft2 dial reading lb / 100 ft2 ml / 30 min / 30 min

Table 4 – Indicative HYDRO-FOIL properties In addition to the basic products supplementary products can be used to optimise the system for specific use as detailed in Table 5. Chemical Function OX-SCAV Oxygen scavenger to extend usage in high temperature and salinity sodium chloride To increase inhibition and to drill in salt environment HYDRO-CAP SC Low molecular weight PHPA HYDRO-CAP RD Readily dispersible -- highmolecular weight PHPA HYDRO-CAP L Liquid PHPA Isothiazolin Biocide DRILL-GEL Viscosifier. Used in initial make up HYDRO-THIN Deflocculant HYDRO-PLAST / High temperature HYDRO-PLAST PLUS filtration controller HyPR-DRL ROP Enhancer

Concentration lb/bbl 120 ppm

Concentration kg/m3 120 ppm

To 110

To 313.5

1 -1.5 1 -1.5

2.85 – 4.3 2.85 – 4.3

3+ 500 -1000 ppm 5 0.5 - 1 2-8

8.55 + 500 – 1000 ppm 14.25 1.4 – 2.85 5.7 – 22.8

0.5 - 5%

0.5 - 5%

Table 5 –Supplementary products for HYDRO-FOIL System Engineering Guidelines Maintain a minimum of 1 – 1.2 lb/bbl (2.85 - 3.4 kg/m3)of excess PHPA in the system as determined by a materials balance calculation..

The HYDRO-CAP concentration in the system will deplete while drilling as the PHPA encapsulates the cuttings and coats the wellbore. The HYDRO-CAP concentration must be maintained by regular treatments, ideally in the form of HYDRO-CAP rich pre-mixes containing 1.5- 2.0 (4.3 – 5.7 kg/m3) lb/bbl. The PHPA concentration may be measured using the test described in Section 3 of this Handbook, Mud Testing Procedures. Field experience has determined that as a general rule the PHPA depletes at a rate of 2 – 8 lb/bbl (5.7 – 22.8 kg/m3) of cuttings removed depending on the reactivity of the formation:Typical Depletion Factors Highly reactive shales Moderately reactive shales Low reactivity shales

6 - 8 lb/bbl (17.1 – 22.8 kg/m3) 4 - 6 lb/bbl (11.4 - 17.1 kg/m3) 2 - 4 lb/bbl (5.7 – 11.4 kg/m3)

Actual depletion factors should be determined on a formation by formation and field by field basis e.g.:Drilled 100m of 12 ¼” Hole (capacity 0.4783 bbl/m) - moderately reactive shale Depletion factor = 5 lb/bbl (14.3 kg/m3) Total depletion = 100 x .4783 * 5 = 239 lbs (108 kg) of PHPA Required to add to maintain > 1 lb/bbl excess = 5 x 25 kg sacks (275 lbs (124 kg). NB. Liquid PHPA, HYDRO-CAP L, is 35% active PHPA, therefore, 14 x 25 kg pails of liquid PHPA would be required to maintain the 1 lb/bbl (2.85 kg/m3) excess Mixing HYDRO-FOIL While mixing the HYDRO-FOIL system the shearing of the fluid has to be maximised. It is recommended that a shearing unit be used and that shearing is maximised by circulating through the gun lines. However once the polymers are mixed it is recommended that high pressure shearing is stopped, as the long chain encapsulating polymer will be physically degraded. ƒ Treat out the hardness with soda ash. Ensure hardness value is less than 200 mg/l. ƒ Blend the brine (KCl, NaCl or alternative). ƒ Add the HYDRO-CAP XP polymer. If possible use the SHOTGUN method (described below). ƒ Add the remaining polymers. Care must be taken so as not to mix these so fast that fish eyes will form. ƒ Add the required amounts of bridging material. ƒ Add the pH modifiers. ƒ Weight up the system. ƒ Just prior to circulating, add the polymer extenders if required. A limitation with a PHPA system is the difficulty of mixing the dry polymer since, if the polymer is mixed too quickly into the fluid it will very easily form fish eyes. Alternative mixing solutions include:ƒ Have the polymer solubilised into the brine and shipped from town for offshore locations. ƒ Have a stock of HYDRO-FOIL. Note however that this is 35 % active. ƒ Reduce the pH of the brine with citric acid to 6. Then mix in the polymer. Raise the pH to 8 with caustic after all the polymers is mixed in. ƒ If the initial viscosity is too high and there are mixing limitations, mix only half of the required PHPA in the initial mix and add the remainder after displacement while drilling. It is recommended in order to ensure that the minimum excess is maintained that initial concentrations of HYDRO-CAP are in the range of 1.2 – 1.5 lb/bbl.

Section

11b


5. Mix the PHPA by the SHOTGUN method. ƒ Have the total volume to be treated in one pit and an empty pity pit ready ƒ Have all the sacks of HYDRO-CAP XP by the hopper. ƒ Transfer the volume from the pit to be treated to the empty pit. ƒ Add the sacked HYDRO-CAP XP via the hopper to the transfer stream approximately 1 sack every 1 minute. Ensure that the hopper does not become blocked. In some cases the product specified for particular application might be HYDRO-CAP SC a low molecular weight, short chain, PHPA or HYDRO-CAP RD a PHPA treated to make it easier to mix and disperse. In both cases mixing will be easier as initial fluid viscosities from these products will be reduced. Hardness It is recommended that the hardness level is minimised. Prior to mixing the system treat out hardness with soda ash. The efficiency of the polymers is improved when the calcium concentration is less than 200 mg/l. Fluid Loss Control Maintain filtrate as per requirements by the use of HYDRO-PAC, HYDRO-STAR CMS and or HYDROSTAR NF. The type of HYDRO-PAC (R or LV) will be decided by the operational requirements. Ideally it is recommended that HYDRO-PAC LV is used in the initial formulation as this has minimal impact on the rheology compared with the use of HYDRO-PAC R. Rheology While the HYDRO-CAP XP will add considerable initial rheology to the mud this will eventually shear thin with circulation and temperature. Xanthan Gum, HYDRO-ZAN or HYDRO-ZAN RD, is recommended to achieve the desired rheological properties as this product delivers improved low end rheology and shear thinning characteristics. The shear thinning rheology from HYDRO-ZAN is preferred to the rheology achieved with the use of products such as HYDRO-PAC R. pH This should be maintained at 8.5 – 9.5. High pH will result in hydrolysing of the polymer, at pH above 10.0 hydrolysis of the PHPA will start resulting in the release of ammonia gas (NH3) which is very evident on the rig even at low concentrations. In the event that the system is over treated, treat immediately with citric acid to reduce to the specified level. To prevent pH hot spots, pH modifiers should be presolubilised before addition to the system. Due to the hydrolysis of the PHPA at high pH it is not recommended to drill cement with the HYDROFOIL system unless it is unavoidable. If cement has to be drilled then the mud should be pre-treated with using a low molecular weight polyacrylate thinner such as HYDRO-THIN. Subsequent treatment with additional HYDRO-CAP XP and other products should be made as required to achieve specifications. Density Density is provided by DRILL-BAR and or calcium carbonate. If higher densities or flatter rheological profiles are required, the HYDRO-FOIL system can be formulated with HyPR-BAR, fine grind barite, or HAEMATITE. Temperature Limitation and Treatment The HYDRO-FOIL system is effective in a range of temperatures from 275 – 300 ˚F (135 - 149 ˚C), thermal stability being dependent on the type and concentration of salt in the formulation and the use of oxygen scavengers. Fluid loss, in particular the HPHT, can be controlled with the addition of HYDROTHERM Amps/Co-polymers.

Cementing HYDRO-FOIL is particularly sensitive to cement contamination. Cement contamination increases the calcium ion content and the pH of a fluid which has the effect of hydrolysing the PHPA polymers, thus increasing filter loss and reducing rheology. ƒ When cementing it is recommended a large sacrificial spacer is used to protect the fluid system. ƒ When cementing a liner ensure that all the excess cement and spacer is reverse circulated out of hole. ƒ If possible on the first circulation after a conventional cement job is over it is recommended that an attempt is made to isolate any preflush and excess cement. ƒ Prior to a cement job consideration needs to be made whether to pre-treat the system to deal with bicarbonate to treat out possible contamination. However be aware of the possibility of over treatment. ƒ To prevent the contamination of the HYDRO-FOIL system it is recommended that the old fluid, which will be displaced from the hole, is used to drill out the cement and shoe. It is worth noting that although the high pH from cement contamination will degrade the HYDROCAP polymer the residue will contain some acrylate polymer which has significant encapsulating properties. It may therefore be possible to isolate the contaminated fluid, treat out the cement contamination then reuse as a base fluid.

hydro-foil gen 1 HYDRO-FOIL GEN 1 is a KCl / PHPA system which has been enhanced by increasing the inhibition of the fluid with the inclusion of cloud point glycol(s). Mechanism of Shale Stabilisation The 2 methods of shale inhibition from the HYDRO-FOIL system, potassium and PHPA encapsulation are enhanced by the clouding effect of the glycol which prevents pore pressure transmission. The stabilisation mechanisms combine synergistically to provide inhibition close to that of non aqueous fluids. At a specific temperature (cloud point) a water soluble glycol starts to change from soluble to insoluble, forming a thermally activated emulsion (TAME). As the temperature increases the glycol starts to come out of solution and the liquid begins clouding. Eventually the single phase liquid separates into two separate phases.

A

B

Figure 1 Visualisation of Glycol Behaviour as a Function of Temperature A: Glycol and water together – at ambient temperature the glycol is 100% water soluble B: Solution is heated until the glycol reaches ‘cloud point’ and becomes insoluble. Cloud point is a function of the following variables: ƒ Salinity of the solution ƒ Molecular weight and type ƒ Type of electrolyte ƒ Concentration of the glycol

Section

11b


Figure 2. Cloud Points for Various Glycols in KCl Research has concluded that the glycol is associated by hydrogen bonding to the reactive sites of clays. During this adsorption process, water is displaced and ordered structures of glycols are formed. There is little depletion of the glycol from the fluid when drilling, the glycol returning to solution as the cutting moves up the wellbore and the fluid temperature drops below the cloud point. This supports the theory that the bonding between the clay and the glycol is transitory, and there is some mechanism for association and disassociation due to changes in the environment. It can be concluded that the shale inhibition and formation protection will be achieved by one or both of the following mechanisms: ƒ The glycol displaces water from adsorption sites on the clay minerals present in shales, especially in the presence of potassium Ions. ƒ Blocking the formation pores, preventing further ingress of invasive fluids by clouding out preventing pore pressure transmission. The HYDRO-FOIL GEN 1 is compatible with and used with the same range of salts as the HYDRO-FOIL system. Benefits of the HYDRO-FOIL GEN 1 system include ƒ Effective inhibition ƒ Environmentally acceptable in most areas ƒ High lubricity fluid ƒ Ease of mixing and maintenance ƒ Low dilution rates ƒ Drilling depleted sands where differential sticking is a potential problem ƒ Increase protection against stuck pipe ƒ Minimisation of bit and BHA balling

ƒ Extension of polymeric efficiency at high temperatures ƒ Enhance drill solid tolerance ƒ Enhanced solids control efficiency ƒ Some protection against corrosion by acid gasses ƒ High flexibility ƒ Possibility of recycling the fluid ƒ Simple to use

In order to cover the range of operational conditions Scomi Oiltools has developed a family of inhibitive clouding glycols:PPRODUCT CIRRUS CPG STRATUS CPG CUMULUS CPG NIMBUS CPG

Application Low to medium temperature applications Medium temperature applications Moderate to high salinity brines or higher temperatures Saturated salt systems

Table 6. Scomi Oiltools Glycol Product Range 10

Glycol and Salt Selection The quantity and type of glycol used will depend both on the quantity and type of salt in the system as well as on the temperature range over which the product is required to cloud out. Normal glycol operational concentrations are in the range 0.5% to 5%. Note although normal formulation usually contains only one type of glycol, the glycols are all compatible and the use of a blend of two or more glycols, e.g. CIRRUS and STRATUS, is possible, should this be required to fulfil operational needs. Formulation An example of a HYDRO-FOIL GEN 1 formulation and mud properties is shown in Table 7. Product Function drill water salt caustic soda / potassium hydroxide HYDRO-CAP XP HYDRO-ZAN / HYDRO-ZAN RD HYDRO-PAC HYDRO-STAR (CMS, HT,NF) CUMULUS CPG / NIMBUS CPG / CIRRUS CPG DRILL-BAR Property Mud Weight PV YP 6 RPM Gel API HTHP (@ Bottom Hole Temp° F)


Concentration kg/m3

Base Fluid Water activity and density pH modifier

0.85 bbl/bbl 5 - 109

PHPA Viscosifier

0.75 – 1.5 0.75 – 1.0

2.14 – 4.28 2.14 – 2.85

Filtration Control Filtration Control GLYCOL

1-2 4-8

2.85 – 5.7 11.4 – 22.8

Barite Typical Value 8.4 - 18.8 ALAP 30 8 - 20 7 / 10 / 12 <5 <12

0.85m3/m3 14.25 - 310

To pH 9.0

0.5 - 5% by volume As required Units lb/gal cP lbs/100 ft2 dial reading lbs/100 ft2 ml/30 min ml/30 min

Table 7 – Indicative HYDRO-FOIL GEN 1 formulation In addition to the basic products supplementary products can be used to optimise the system for specific use as detailed in Table 4 –Supplementary products for HYDRO-FOIL System Engineering Guidelines The HYDRO-FOIL GEN 1 system is engineered in the same manner as the HYDRO-FOIL system described in the previous section with the exception of the addition of the glycol. Glycol Concentration The glycol concentration is measured using the method described in Section 3 of this Handbook, Mud Testing Procedures.

11

Section

11b


Closely monitor the concentration, replacing lost product as required. Field evidence shows that the rate of depletion is quite low as the product returns to solution with reduced wellbore temperature. If 2 glycols are used during a section closely follow the mud program instructions on the relative concentration of each product with depth.

hYdro-foil s8 HYDRO-FOIL S8 is a salt/polymer system which has been enhanced by increasing the inhibition of the system with the inclusion in the formulation of 5 -15% of sodium silicate, HYDRO-SIL S, or potassium silicate, HYDRO-SIL K, The silicate is used to enhance inhibition and mechanical wellbore stability particularly in highly fractured and unconsolidated formations. HYDRO-FOIL S8 can be used effectively with temperatures to 250 ˚F (125 ˚C). FEATURES AND BENEFITS ƒ Effective shale inhibition. ƒ Environmentally acceptable in most areas. ƒ Ease of mixing and maintenance. ƒ Increase protection against stuck pipe. ƒ Minimisation of bit and BHA balling. ƒ Enhanced solids control efficiency. ƒ Some protection against corrosion by acid gasses. ƒ Simple to use. ƒ Potential to seal micro-fractured shales.

ƒ Treated cuttings with potential to be used as fertiliser. ƒ Low corrosion rates. ƒ Cheaper than glycol systems although maintenance additions are expected to be higher so this cost advantage can be eroded if the rig has poor solids control. ƒ Good environmental properties for offshore applications.

LIMITATIONS The principal advantage of the HYDRO-FOIL S8 system is that it is a very inhibitive water base system. The main application for silicate fluids is the replacement of oil and synthetic fluids in difficult drilling applications e.g. wells containing reactive claystones. Silicate fluids exhibit a very high degree of shale inhibition exceeding that of glycol fluids, however, they have a number of limitations which must be considered in fluid selection. ƒ Not highly lubricous when compared to Bentonite mud. ƒ High pH system. ƒ High dilution rates may be required making logistics challenging.

ƒ High plastic viscosities, low tolerance of drill solids. ƒ Incompatible with ester based and natural oil type lubricants. ƒ Temperature limited to 250 ˚F (125 ˚C) ƒ Density limited to 15 lb/bbl (1.80 SG)

MECHANISM OF SHALE STABILISATION The primary shale inhibition mechanisms in the HYDRO-FOIL S8 system are: ƒ The prevention of pore pressure transmission by the precipitation of soluble silicates in the pore spaces. ƒ The cation exchange of ions, most commonly potassium, with the clay to reduce hydration and swelling in conjunction with; ƒ The use of cloud point glycols such as CIRRUS or CUMULUS CPG which also minimise the pore pressure transmission.

12

As the soluble silicate laden filtrate comes into contact with or penetrates the low pH formation, typically close to neutral at 7.0, the pH of the mud filtrate drops. The drop from pH 12 combined with a reaction with divalent cations such as Mg++ and Ca++ present in the interstitial formation water results in the formation of a silica gel which precipitates in the pore spaces forming a semi permeable membrane blocking further penetration by the drilling fluid. This reaction is essentially irreversible and can rapidly deplete the silicate concentration. Sea water will reduce the effective silicate concentration by approximately 4 lb/bbl (11.4 kg/m3). Surface adsorption onto minerals and oxides will also deplete silicate levels. The gel and the precipitate will quickly form an impenetrable layer which prevents further fluid invasion thus retarding the transmission of pressure from the hydrostatic mud column to the rock matrix. The wellbore and the shale are effectively “pressure isolated” and Pore Pressure Transmission is minimised. This latter phenomenon is critical in tectonically stressed and fractured shales, which require sufficient over balance mud pressure to support the bore hole from collapsing. The presence of solutes such as Potassium Acetate / Sulphate / Carbonate is synergetic and will balance the mud and the shale activities to reduce the net flow of ions into the shale. The presence of K+ is useful as it will exchange for Ca ++ and Mg++ making these ions available to form precipitates.

Sealing of micro-fractured shales by silicates It should be noted that oil and synthetic based fluids cannot stabilise micro-fractured shales, as their filtrates are restricted from entering or invading the shales due to capillary threshold pressures, which are significant for intact shales with small pores. Soluble silicates however have the ability to fill small cracks and seal them.

13

Section

11b


Formulation Two example formulations and properties of the HYDRO-FOIL S8 system are detailed in Table 8. Product Function drill water salt (KCl) soda ash HYDRO-ZAN HYDRO-PAC LV HYDRO-STAR (CMS ) HYDRO-SIL S / HYDRO-SIL K OX-SCAV * DRILL-BAR


Concentration kg/m3

Base Fluid Water activity and density Hardness Control Viscosifier Filtration Controller Filtration Controller Shale Stabilisation

0.74 30 <400 mg/l 0.75 - 1.0 2.5 2.0 11 % v/v

0.74 m3/m3 85 <400 mg/l 2.1 – 2.85 7.1 5.7 11 % v/v

Oxygen Scavenger Weighting Agent

1.0 - 1.5 155

2.85 – 4.3 442

Table 8 – Indicative HYDRO-FOIL S8 formulation Property Mud Weight PV YP 6 rpm Gel API pH

Units Lb/gal cP lbs/100 ft2 dial reading lbs/100 ft2 ml/30 min

Typical Value 12 20 - 30 15 - 25 10 6 / 11 <6 12 - 12.5

Table 9 – Indicative HYDRO-FOIL S8 properties *Note that an oxygen scavenger is included as part of the standard formulation. This is an integral part of the system. In addition to the basic products additional products can be used to optimise the system for specific use as detailed in Table 9 PRODUCT sodium chloride Isothiazolin HYDRO-LUBE SL CUMULUS CPG, NIMBUS CPG, CIRRUS CPG, STRATUS CPG HyPR-DRL

Function

CONCENTRATION

To increase inhibition and to drill in Salt environment Biocide Lubricity Cloud Point Glycol

Up to 110 lb/bbl 441/ kg/m3 500-1000 ppm 0 – 3% 0.5- 3%

ROP Enhancer

0.5 - 5%

Table 10 – Supplementary products Engineering Guidelines The silicates used for drilling fluids are solutions of water soluble glasses primarily potassium silicates. A key element in their use for inhibition is the molecular ratio between the silica and the potassium. The activity of potassium silicates generally ranges from 35 – 50% with a density + 1.5 SG (12.5 lb/gal). While drilling the silicate concentration should ideally be maintained above 30 g/l SiO2 by frequent testing and addition of HYDRO-SIL (S or K). The depletion of silicate will increase when drilling reactive claystones. It is recommended that the initial fluid is made up to 50 g/l SiO2. It is also imperative that that all premixes are mixed at this concentration.

14

The HYDRO-SIL (S or K) concentration in the system will deplete while drilling as the silicate interacts with the cuttings and inhibits the wellbore. The concentration must be maintained by regular treatments, ideally in the form of HYDRO-SIL (S or K) rich pre-mixes. The state of the cuttings on the shakers is a good indication of the effectiveness of the system inhibition, with the ideal cutting being firm and dry. Should the cuttings turn into “toothpaste”, this a good indication that the silicate is depleting. The silicate concentration may be measured using the test described in Section 3 of the Drilling Fluid Engineering Manual, WBM Mud Testing Procedures. Mixing HYDRO-FOIL S8 ƒ Treat out the hardness with soda ash. Ensure hardness value is less than 100 mg/l. ƒ Blend the brine KCl or NaCl. ƒ Add the pH modifiers as required. ƒ Add the required volume of HYDRO-SIL (S or K) ƒ Add the polymers, HYDRO-ZAN, HYDRO-STAR CMS and HYDRO-PAC LV. Care must be taken so as not to mix these too fast such that fish eyes will form. ƒ Add the required amounts of any bridging material. ƒ Weight up the system. ƒ Just prior to circulating, add the oxygen scavenger. Hardness It is recommended that the hardness level is minimised. Prior to mixing the system treat out Mg ++ and Ca ++ with soda ash and caustic soda, both to improve the efficiency of the polymers and to ensure that the silicate is not precipitated. Fluid Loss Control Maintain filtrate as per requirements by the use of OPTA-STAR PLUS and or HYDRO-PAC. The type of HYDRO-PAC, R or LV will be decided by the operational requirements. Ideally it is recommended that HYDRO-PAC LV is used in the initial formulation as this has minimal impact on the rheology compared with the use of HYDRO-PAC R. Use nitrogen cartridges in the filter press to avoid CO2 reacting with silicates in the mud sample. Rheology Xanthan Gum, HYDRO-ZAN or HYDRO-ZAN RD, is recommended to achieve the desired rheological properties as this product delivers improved low end rheology and shear thinning characteristics. The shear thinning rheology from HYDRO-ZAN is preferred to the rheology achieved with the use of products such as HYDRO-PAC R. pH and Silicate Concentration It is imperative that the pH is maintained in the range specified i.e. above 11.5. The silicates are only soluble above a pH of 10.4 and when divalent cations are absent. This system is pH sensitive and lowering the pH will cause the silicates to begin precipitating thus increasing the plastic viscosity. By maintain the concentration of the silicate, the pH will be maintained. However if required the pH can be maintained by the use of KOH additions provided the silicate concentration is at the required concentration. pH should only be measured with an accurately calibrated meter. Increase the silicate concentration before trips as silicate depletion has been recorded during lengthy static periods possibly due to high BHT or CO2.

15

Section

11b


Density Density is provided with DRILL-BAR and or calcium carbonate. Oxygen Scavenger OX-SCAV should be maintained, at all times, at 1.0 - 2.0 lb/bbl (2.85 - 5.7 kg/m3)to stabilise rheology. Temperature Limitation and Treatment The HYDRO-FOIL S8 system is effective up to a temperatures of 250 ˚F(125 ˚C), thermal stability being dependent on the type and concentration of salt in the formulation and the use of oxygen scavengers Lubricity A characteristic of this system is its relatively high co-efficient of friction. Maintaining a low drill solids content will prevent increases in torque. However the high pH makes the system incompatible with conventional lubricants based on esters and natural oils. Normal ester and fatty acid lubricants hydrolyse in such environments and ‘grease out’. Specifically designed lubricants such as HYDROLUBE SL can be used or HYDRO-LUBE SL PLUS a premium silicate lubricant for challenging directional and ERD wells. Glycols The addition of cloud point glycols, such as CIRRUS or CUMULUS CPG, further enhances well bore inhibition and lubricity as well as aiding in extending the thermal stability of the system to 250 ˚F (125 ˚C). CO2 Contamination: The silicate concentration will be depleted by contamination with CO2 resulting in a fall in pH, an increase in filter loss and gelation problems. Treat out any such contamination with KOH and soda ash as well as maintain the pH and soluble silicates at the required level. Reservoir Drilling It must be highlighted that the silicate mechanism for inhibition will block pores in the reservoir thus the use of HYDRO-FOIL S8 in the reservoir must be carefully considered. If the method for completion involves the by passing of any potential damage by perforation then formation damage is not an issue. Drilling Practices Good drilling practice must be followed at all times. As the silicate system is highly inhibitive cuttings will not disperse into the system and must be removed from the wellbore. Pumping at maximum flow rates, and back reaming on connections and trips is recommended especially in deviated wells. Frequent wiper trips and pipe rotation should be used to ensure adequate hole cleaning is taking place. Observe shakers closely for volume of returns and act immediately on any reduction in cuttings volume. Before POOH, circulate at least 1.5 x bottoms up to ensure that the hole has been thoroughly cleaned. Cementing HYDRO-FOIL S8 is sensitive to cement contamination. Cement contamination increases the calcium ion content which will cause the precipitation of the soluble silicates thus increasing filter loss, increase gels, and rheology. It is not recommended to drill cement with the HYDRO-FOIL S8 system unless it is unavoidable. If cement has to be drilled then the mud should be pre-treated using a low molecular weight polyacrylate thinner such as HYDRO-THIN. Once the cement is drilled it will be necessary to treat the system to rebuild the concentration of the silicate.

16

ƒ When cementing it is recommended that a large sacrificial spacer is used to protect the fluid system. ƒ If possible on the first circulation after a conventional cement job is over it is recommended that an attempt is made to isolate any pre-flush and excess cement. ƒ Before a cement job, consideration needs to be made whether to pre-treat the system with bicarbonate to treat out possible contamination, however, be aware of the possibility of over treatment. ƒ To prevent the contamination of the HYDRO-FOIL S8 system it is recommended, when displacing to this system, that the old fluid being displaced is used to drill out the cement and shoe. Post HYDRO-FOIL S8 After the silicate system has been used ensure that the pits are effectively cleaned especially if subsequent operations involve the use of prehydrated bentonite as the presence of silicate will prevent the hydration of bentonite. Solids Control Equipment During displacements to HYDRO-FOIL S8 the shakers should be dressed with relatively coarse screens to prevent polymer blinding of the screens and subsequent loss of fluid. The shakers should be quickly dressed with finer screens as the fluid warms up and become fully sheared. As previously mentioned this system is not solids tolerant. It is imperative that the drill solids are maintained below 5%. This should be done by optimisation of the available solids control and the use of dilution with pre-mixes. Health and Safety While soluble silicates are not classified as being dangerous or toxic they have a high alkalinity, pH 13.0 - 13.5, which means that they can be irritating to the skin and severely irritating to the eyes. Ensure that rig crews are wearing the correct PPE as specified in the relevant MSDS for all chemicals handled. At a minimum suitable gloves and eye/face protection should always be worn when handling soluble silicates and silicate drilling fluids. Avoid breathing mists.

HyPR-FOIL S8 The disposal of drilled cuttings, particularly in sensitive areas on land, poses significant environmental burdens and very high costs for disposal and site remediation. HyPR-FOIL S8 is a high performance silicate system engineered and patented, to provide a sodium chloride free inhibitive drilling fluid for environmentally sensitive environments and cuttings treatment, providing a recycling route for the cuttings thus minimising environmental impact, in particular, for land based operations. HyPR-FOIL S8 is a silicate system wherein sodium and chloride ions have been replaced with potassium cations from carbonates, sulphates, acetates, nitrates and / or hydroxides. Potentially harmful leachates can be ultimately removed by precipitation as insoluble calcium salts. Intensive development has identified high performing polymers to be used in the system to deliver excellent low end rheology and fluid loss. The aim of the HyPR-FOIL S8 system development is to provide a low cost method of treating cuttings and waste fluids producing a reusable material offers potentially significant savings, both financial and environmental.

17

Section

11b


The treated cuttings and waste mud should yield soil material rich in potassium and nitrates which enhance plant growth without the introduction of potentially harmful contaminants. Sodium and chloride are excluded from the drilling fluids formation minimising their concentration in the drill cuttings. The fertiliser rich “soil” can be sold or given away to farmers or used for beneficial fill. Operators are presented with an opportunity for the reuse of drilling cuttings or disposed mud which essentially eliminates long term disposal liability and cost. Alternative sources of potassium are used in the system, potassium acetate, sulphate, formate and carbonate which deliver similar inhibitive performance compared with KCl as shown in the following graph. SHALE RECOVERY COMPARING DIFFERENT TYPES OF SILICATE DRILLING FLUID 100.00 99.00

98.92

SHALE RECOVERY (%)

98.00

98.76

98.99

98.26

97.00 96.00 95.00 94.00 93.00 92.00 91.00 90.00 SILIC-8L

K2C03-D

CH3C00K-F

K2504-D

SILICATE SYSTEM Figure 3 Shale recovery system performance HyPR-FOIL S8 System Components: OPTA-STAR PLUS A premium grade starch product, OPTA-STAR PLUS is very effective at reducing the fluid loss and providing a thin, tough and low permeability cake. HYDRO-SIL K Is a drilling fluid water based shale inhibitor. It is a solution of potassium silicate oligomers with a molecular ratio of 3.3 and density of 1.5 SG (12.5 lb/gal). Potassium Sulphate / Potassium Carbonate / Potassium Acetate Alternative sources of potassium ions to the more commonly used potassium chloride. They are principally used to formulate water based fluids where KCl cannot be used due to environmental restrictions on the use of chloride ions. HYDRO-ZAN Xanthan gum used for increasing the rheological parameters in water-based drilling fluids. Small quantities provide excellent viscosity for suspending weighting material for all water-based drilling fluids systems. HYDRO-ZAN has the unique ability to produce a fluid that is highly shear-thinning and develops a true gel structure. HYDRO-PAC LV or HYDRO-STAR CMS High quality polyanionic cellulose polymer or carboxymethyl starch (CMS), are water based filtration controllers which do not produce the viscosity associated with regular grade Pac materials. 18

OX-SCAV A formulated sulphite-based chemical in liquid form used to scavenge oxygen. It reacts with and eliminates dissolved oxygen as a possible source of corrosion in drilling mud systems. OX-SCAV can be used in all freshwater and saltwater drilling fluids. DRILL-BAR Is a finely ground, low abrasion and high purity API barite with the chemical formula, BaSO4, used to increase the density of all types of drilling fluids. Potassium Hydroxide KOH, is used primarily as a pH modifier and as an alternative to caustic soda. It acts as source of potassium ions in a water based mud system. TYPICAL FORMULATION Product Unit Drill-water HYDRO-SIL K Potassium Sulphate Potassium Carbonate HYDRO-ZAN HYDRO-PAC LV or HYDRO-STAR CMS OPTA-STAR PLUS OX-SCAV * DRILL-BAR Potassium Hydroxide


Concentration kg/m3

bbl / litres lb/bbl lb/bbl lb/bbl lb/bbl lb/bbl

0.82 bbl 38 35 2 1.5 2.5

0.82 m3/m3 108 100 5.7 4.3 7.1

lb/bbl lb/bbl lb/bbl lb/bbl

6 1 42 If required

17.1 2.85 120 If required

*Note that an oxygen scavenger is included as part of the standard formulation. TYPICAL PROPERTIES AFTER HOT ROLLING AT 194 ˚F FOR 16 HOURS Parameter Mud Weight (lb/gal) Rheology 600 RPM 300 RPM 200 RPM 100 RPM 6 RPM 3 RPM PV (cP) YP (lb/100 ft2) Gel 10 sec (lb/100 ft2) Gel 10 min (lb/100 ft2) pH Mud API Filtrate (cc/30min) pH Filtrate

Value 10.0 75 54 44 29 12 10 21 33 9 11 12.1 4.0 12.3

Engineering Guidelines Silicate system guidelines are detailed in the previous section, HYDRO-FOIL S8. The HyPR-FOIL S8 system is run in the same fashion with the exception of the different salts and chemicals as detailed above.

19

Section

11b


HyPR-DRILL high performance water base mud system A large percentage of drilling problems and associated NPT are caused by unstable clay and shale formations, > 40% in GOM. Rig time is lost in dealing with well bore instability problems which can result in loss of the interval and costly sidetracks. Non aqueous drilling fluids or “NAF” provide the most inhibitive environment for drilling reactive shales and clays and deliver superior drilling and all round performance when compared with WBM. NAF are expensive, and many locations require expensive treatment and disposal procedures for dealing with cuttings and other drilling wastes as legislated by nearly all oil and gas producing countries The Drilling Fluids industry has been constantly conducting research to develop more inhibitive water based fluids with enhanced performance. The use of water based mud results in lower environmental costs and potentially reduced drilling costs, but arguably the most significant contribution is reduction of unending long term liabilities associated with NAF soaked cuttings piles, liquid storage, disposal sites, and potential damage to water sources. In particular this ongoing development of water based replacements for NAF has focused on High Performance Water Base Muds, HPWBM HyPR-DRILL is an advanced and cost effective drilling fluid system which provides an inhibitive environment comparable to that of NAF for drilling reactive formations and maintaining wellbore stability PERFORMANCE ƒ prevents hydration of chemically reactive formation ƒ controls dispersion of clays ƒ provides anti-accretion properties, minimising balling of the BHA

ƒ maintains clean cutters at the bit face, maximizing penetration rate ƒ drill cuttings remain firm and intact and are easier to remove with the primary solids control equipment ƒ provides excellent lubricating properties

ADVANTAGE ƒ stable well-bore ƒ low dilution rate ƒ increased ROP ƒ in-gauge hole

ƒ good cementation providing zonal isolation ƒ reduced drill solids content ƒ reduced torque & drag ƒ optimised drilling performance

HyPR-DRILL is specifically engineered to serve a broad range of high performance drilling fluid applications both offshore and on land:1. A fresh water formulation for use in environments where low to zero chloride contents are required e.g. for on land disposal of drilling wastes 2. An inhibitive salt formulation for all drilling applications e.g. potassium chloride / acetate / sulphate etc., 3. A high salt formulation, typically 20% NaCl, for deep water drilling to inhibit hydrate formation. Water and ions from drilling fluids diffuse into clays and shale by either pressure difference or osmotically due to electrolytic imbalance. This leads to hydration and swelling of the clay/shale matrix which can destabilise the wellbore and allow clay cuttings to swell and disperse into the fluid system.

20

HyPR-DRILL inhibits hydration of the clays using a combination of a quaternary ammonium salt and a low molecular weight encapsulating terpolymer. This superior reduction in shale hydration is demonstrated in Figures 1, 2 and 3 which compare the linear expansion of shales exposed to the HyPR-DRILL system with other fluid types including competitors HPWBM systems These figures clearly show that only invert emulsion SBM reduced shale swelling to a greater degree. LINEAR EXPANSION OF SHALE - HyPR-DRILL (FRESHWATER)

PERCENT EXPANSION

120 100

Bentonite

SBM

PHPA/GLYCOL

HYPR-DRILL

Competitor A

Competitor B

80 60 40 20 0 0

1000

2000

3000

TIME (minutes)

Figure 4. HyPR-DRILL fresh water formulation vs. other inhibitive drilling fluids. LINEAR EXPANSION OF SHALE - HyPR-DRILL (6% KCI) 120

PERCENT EXPANSION

Bentonite

SBM

PHPA/GLYCOL

HYPR-DRILL

100 80 60 40 20 0 0

1000

2000 T TIME

3000

(minutes)

Figure 5. HyPR-DRILL 6% KCl formulation vs. other inhibitive drilling fluids.

21

Section

11b

water base drilling fluids LINEAR EXPANSION OF SHALE - HyPR-DRILL (20% NaCI) 120

PERCENT EXPANSION

100

Bentonite

SBM

PHPA/GLYCOL

HYPR-DRILL

Competitor A

Competitor B

80 60 40 20 0 0

1000

2000

3000

TIME (minutes)

Figure 7. HyPR-DRILL 20% NaCl formulation vs. other inhibitive drilling fluids. Stability tests consistently demonstrate shale recovery > 95 % with all HyPR-DRILL applications. HyPR-DRILL PRODUCTS The HyPR-DRILL system comprises several core components HyPR-HIB, HyPR-CAP, HyPR-DRL and CUMULUS CPG in combination with a wide range of standard drilling fluid additives. HyPR-DRILL should be formulated specifically for each application to ensure that the correct level of inhibition is provided. HyPR-HIB A quaternary ammonium salt which prevents water absorption by shales, suppressing hydration of shales and clays and restricting dispersion. Cuttings are transported by the inhibitive mud to the primary solids control equipment firm and intact for efficient removal. Due to the high level of inhibition the HyPR-DRILL dilution requirements are lower than conventional water base fluids which reduces overall cost of drilling fluid and waste disposal. HyPR-HIB is a liquid which is completely soluble in water and easy to mix. HyPR-HIB is used at a minimum concentration of 2% v/v. This can be increased to 5% v/v depending on the formation reactivity. The minimum concentration of 2% is recommended only to supplement other inhibitive cations. HyPR-CAP A very low molecular weight acrylamide terpolymer which encapsulates shale and clay cuttings as they are formed, preventing water adsorption. Cuttings dispersion and build up of low gravity solids in the system is reduced. These intact cuttings are more efficiently removed by the shale shakers. HyPR-CAP is a granular powder used at of 1 – 4 lb/bbl (2.85 – 11.4 kg/m3). Concentration is dependent upon the reactivity of the formations being drilled with maintenance treatment dependent on the ROP. HyPR-CAP encapsulates cuttings and is continuously but slowly depleted from the system and must be replaced. HyPR-CAP being an acrylamide terpolymer is susceptible to hydrolysation at high pH. The system pH must be maintained below 9.5 and drilling of cement should be avoided. When cement has to be drilled with the HyPR-DRILL pre-treat with citric acid and sodium bicarbonate of soda and replace the HyPR-CAP with fresh product as soon as the pH of the system is within specification.

22

HyPR-DRL A proprietary blend of surfactants and other products which forms a tough lubricating film on the metal preventing water wet drill cuttings from adhering to metal surfaces. PDC cutter fouling, bit balling and cuttings accretion on the bottom hole assembly is prevented. HyPR-DRL is a liquid product used at 2 – 4% v/v. It is recommended that the product be added on a continuous basis so that fresh product is constantly available at the bit and BHA to maximise the filming effect. CUMULUS CPG A cloud point glycol used for inhibiting clay and shale formations and is a key component of Scomi Oiltools well known HYDRO-FOIL GEN1 system. The synergism of HyPR-HIB and HyPR-CAP with CUMULUS CPG provides the HyPR-DRILL system with significantly enhanced inhibitive characteristics. CUMULUS CPG ‘clouds out’ on the formation and cuttings, blocking diffusion of water into the shale matrix effectively controlling swelling and dispersion. CUMULUS CPG provides increased lubricating properties along with anti accretion character to the drilling fluid. It is used at a minimum level of 3% by volume. These four products form the core of the HyPR-DRILL system and. Only formulations containing these four products with the specified minimum dosage, or higher, will be classed as a HyPR-DRILL system. Other products SODA ASH Is used for treating out Ca2+ and Mg2+ ions from the make up water. Total hardness in the makeup water should be below 400 mg/l. CAUSTIC SODA, Sodium hydroxide, is used to maintain the pH at a level of + 9.0. Ensure that pH is maintained below a maximum of 9.5 to prevent hydrolysing of the acrylamide polymers HYDRO-ZAN Xanthan polymer, provides the required rheological properties for the fluid. Normal usage is in the range of 1 - 2 lb/bbl, (2.8 – 5.6 kg/m3). HYDRO-ZAN PLUS Premium grade Xanthan polymer, provides the required rheological properties for the fluid. Normal usage is in the range of 1 – 1.5 lb/bbl, (2.8 – 4.3 kg/m3). HYDRO-STAR NF Non-fermenting starch, fluid loss reducer is used at 4 - 6 lb/bbl (11 – 17 kg/m3). OPTA-STAR PLUS A premium grade starch product, OPTA-STAR PLUS is very effective in reducing the fluid loss and providing a thin, tough and low permeability cake. KCl Or other potassium based salts, may be used to provide cation exchange capability for swelling sodium based clays. KCl is mixed at 6 - 8% by weight but may be used at higher concentrations as determined by planning requirements or as preferred by some operators. KCl should be measured using an ion selective electrode or by the Perchlorate analytical method.

23

Section

11b


NaCl Can be added at 20% to provide thermodynamic suppression of hydrate formation in deep water drilling. KCl, CUMULUS CPG, and HyPR-HIB also provide a degree of hydrate suppression. LCM usage with HyPR-DRILL system There are no restrictions on the use of LCM. HSE: As with all chemicals always review the MSDS for safe handling procedures for each system component. There are no specific HSE issues with the HyPR-DRILL system. MIXING PROCEDURE for HyPR-DRILL system: ƒ Clean tanks thoroughly. ƒ Fill water to the appropriate level leaving sufficient margin for volume increase from adding chemicals. Calculate the volume of chemicals required as per the formulation. ƒ Add soda ash to reduce total hardness to below 400 mg/l. ƒ Mix caustic soda to get a pH of 9.0. ƒ Mix OPTA-STAR PLUS ƒ Add HYDRO-ZAN / HYDRO-ZAN PLUS, and shear the fluid for some time to ensure that the polymers yield. 75% of the required quantity of HYDRO-ZAN / HYDRO-ZAN PLUS may be added to facilitate addition of the other products. ƒ Mix HyPR-HIB. ƒ Add HyPR-DRL ƒ Treat with CUMULUS CPG. ƒ Slowly pour in HyPR-CAP. The product should be added gradually to avoid formation of fish eyes and the fluid should be well sheared. ƒ Add KCl if required as per the formulation. ƒ Mix NaCl if required as per the formulation. ƒ Add barite to the required drilling fluid density. ƒ Shear the system well to make it homogenous. ƒ Add the balance of HYDRO-ZAN / HYDRO-ZAN PLUS. ƒ Adjust pH to 9.0 with caustic soda if required Typical HyPR-DRILL Formulation and Parameters with fresh water FORMULATION for 1 bbl and 1 m3 of drilling fluid: Additive water soda ash caustic soda OPTA-STAR PLUS HYDRO-ZAN PLUS

24

Concentration lb/bbl 0.85 bbl/bbl 0.2 0.5 4.0 1.5

kg/m3 0.85 m3/m3 .56 1.4 11.2 4.3

Additive

Concentration

HyPR-HIB HyPR-DRL HyPR-FOIL CUMULUS CPG

3% v/v 3% v/v 3 3% v/v

3% v/v 3% v/v 3 3% v/v

PARAMETERS after hot rolling for 16 hours @ 200 ˚F/ 93 ˚C Parameter Density Fann-VG Meter 6 / 3 rpm PV Yield Point Gel 10 sec Gel 10 min API Filtrate pH

Unit

Value

lb/gal SG °dial rotation cP lb/100 ft2 lb/100 ft2 lb/100 ft2 ml / 30 mins.

10.0 1.20 5/4 16 23 4 4 4 9.5

salt polymer System Description Salt-based muds are muds containing varying amounts of predominantly sodium chloride ranging from 10,000 mg/l of NaCl up to saturation. Salt muds maybe be classified as:

1. Saturated Salt Muds 2. Saltwater Muds 3. Brackish-Water Muds

315,000 mg/l 25,000 – 315,000 mg/l 10,000 – 25,000 mg/l

Saturated Salt Muds are primarily used to prevent excessive hole enlargement while drilling massive salt beds. They can also be used to reduce dispersion and hydration of shales and clays. Saltwater muds are often prepared from fresh water or bentonite-water muds. These muds normally contain low solids concentrations, have low densities, have minimal chemical treatment, and possess low viscosities and high fluid losses. Saltwater muds may be prepared intentionally with salt to drill troublesome shale sections. They are used as an inhibitive mud to decrease dispersion and viscosity build-up from drilled solids. In many areas, because of economics or lack of sufficient fresh water, brackish water often is used as the makeup water for drilling fluids. These muds generally are termed brackish-water if their salt content is between 10,000 to 15,000 mg/l. They are usually found in inland bay areas or marshes. The polymers and products used for the salt systems are the same as those used for the HYDRO-FOIL systems. A typical formulation for a salt saturated system is shown in Table 10.

25

Section

11b


Product Function HYDRO-ZAN Viscosifier HYDRO-PAC LV Filtration Control HYDRO-STAR / Filtration Control HYDRO-STARCH / HYDRO-STAR CMS HYDRO-SPERSE Deflocculant HYDRO-DEFOAM A Defoamer

Concentration lb/bbl 0.75 – 1.0 0.5 – 2.5 2.0

1–6

Concentration kg/m3 2.14 – 2.85 1.43 – 7.13 5.7

2.85 – 17.12 As required

Table 11 – Typical saturated salt formulation For the saltwater and brackish water systems the product concentrations will vary with the salt concentration, the higher salt systems generally requiring increased concentrations. Supplementary products which are used with salt muds include:-

Product Isothiazolin HYDRO-LUBE, LUBRI- GREEN HYDRO-CAP XP HyPR-DRL

Function Biocide Lubricity Shale encapsulation ROP enhancer

Concentration 500 – 1000 ppm 0 – 3% 1 – 2 lb/bbl 2.85 – 5.7 kg/m3 0.5 – 5 %

Table 12 Supplementary products Engineering guidelines The chloride content of saturated salt muds is 192,000 mg/l (315,000 mg/l NaCl) at saturation. As the temperature of the mud increases, more salt is able to go into solution. This means that a fluid which is saturated under surface conditions may not be saturated at downhole temperatures and can cause substantial washout in a salt zone due to increased salt solubility. Mixing salt muds ƒ Prehydrate DRILL-GEL at 20 – 30 lb/bbl (57 - 85.5 kg/m3) in freshwater ƒ Mix the salt brine to the required concentration ƒ Treat out the calcium from the mix water with the required amount of soda ash ƒ Raise the pH of the water with caustic soda to above 10.5 as this will precipitate any magnesium and other divalent ions ƒ Mix in the required amount of prehydrated DRILL-GEL ƒ Add the required fluid loss control agent e.g. HYDRO-STAR ƒ Add defoamer as required ƒ Weight up the system with DRILL-BAR

26

If the system is converted from an existing mud it is recommended that the following treatment levels are determined by pilot testing. ƒ Break over will require a minimum of three circulations (two to add all the chemicals evenly and one to ensure that the fluid is thin) Adjust pH to > 10.5 and treat out hardness with caustic soda and soda ash ƒ Reduce the MBT to 10 -15 lb/bbl (28.5 - 42.3 kg/m3) by dilution and if dumping necessary ƒ Add deflocculant – HYDRO-SPERSE as required ƒ Add sodium chloride at + 110 lb/bbl (313.5 kg/m3) to saturation ƒ Adjust fluid loss with HYDRO-STAR or HYDRO-PAC LV ƒ Adjust rheology with prehydrated DRILL-GEL or HYDRO-ZAN ƒ Weight up the system with DRILL-BAR pH These muds do not require pH to function however it is a common practice to maintain the pH of the mud from 10.5 – 12.0 with additions of caustic soda. Saturated salt muds require larger additions of caustic soda to maintain a higher pH than do freshwater muds. Maintaining a 10.5 -12 pH offers several advantages: ƒ Deflocculants are more effective ƒ Corrosion is reduced ƒ Lower concentrations of filtration control additives are required when Ca ++ and Mg ++ solubility is reduced ƒ Foaming tendency is lessened ƒ Mud is generally more stable Hardness Saturated salt muds will normally contain soluble calcium due to the formations penetrated and the type of makeup water used. Generally, the presence of calcium does not produce detrimental effects on the mud; except when the pH is increased beyond 12.0 when the fluid loss will be difficult to control. Foaming Saturated salt muds are characterised by foaming. Foaming is generally restricted to surface foam and is not troublesome unless aggravated by mechanical agitation. The degree of foaming may sometimes be decreased by increasing the alkalinity of the mud (Pm). A defoaming agent may be necessary. Temperature Stability The temperature limitation of saturated salt muds is around 250 °F (125 °C) and is normally dictated by the filtration control additives used. Fluid Loss Control Ca ++ and Mg ++ hardness do not adversely affect filtration control in Saturated Salt Muds when using HYDRO-STARCH however, when HYDRO-PAC is used, hardness should be below 400 mg/l.

opta-flo The selection of drilling fluids to drill reservoir sections is critical to the success of any well in order to minimise or prevent damage to the reservoir rock. Formation damage is caused by various mechanisms including fines migration, clay swelling, emulsion blocking and solids invasion all of which can result in poor completions and loss of production. A ‘fit for purpose ‘Drill In Fluid’, DIF, must provide inhibition/wellbore stability, lubricity, bridging and solids suspension yet provide filtercakes which are easily removed in the production process.

27

Section

11b


OPTA-FLO is a water based ‘Drill In’ Fluid (DIF) designed to drill reservoir sections with zero to minimal formation damage. OPTA-FLO DIF systems are based on bridging methods which provide a positive control of filtrate and mud leak off over a wide permeability range, into the formation, while providing filter-cakes which are readily removed by the produced fluids. OPTA-FLO systems are flexible and can be designed for specific reservoirs based on the petro-physical properties of the rock as well as the pore fluid chemistry. OPTA-FLO systems are environmentally safe with no special HSE requirements. Specially selected enzyme treatment systems may also be utilised for post completion treatments to enhance the removal of the filter cake. Damage mechanisms while drilling reservoirs include: ƒ fluid invasion ƒ solids invasion ƒ incompatible filtrate and pore fluid chemistry leading to:ƒ emulsion blocking ƒ interstitial clay hydration ƒ In-situ fines migration ƒ wrong or incorrect stimulation methods Subsequent filter cake may not be easily ‘lifted off and completely removed which can adversely affect the well production. OPTA-FLO is formulated to ensure ƒ fluid invasion is minimised ƒ solids do not impair the reservoir permeability and are acid soluble ƒ filtrate compatibility with pore fluids ƒ the filter cake is easily removed at low lift off pressure during production ƒ deliver or exceed prognosed well productivity OPTA-FLO is a high performance drilling fluid with the following characteristics; ƒ provides cutting suspension for hole cleaning ƒ thin, tough and resilient low permeability filter cake ƒ lubricity to minimise drag and torque in directional and horizontal wells ƒ engineered PSD of bridging agents to provide effective sealing ƒ non damaging fluid The OPTA-FLO system can be used to drill reservoirs with various well profiles : ƒ directional wells ƒ extended reach wells ƒ horizontal wells and for wells with a wide range of completion strategies ƒ cased hole completion ƒ slotted and perforated liner ƒ expandable slotted screen ƒ open hole gravel pack ƒ barefoot completions

28

The OPTA-FLOsystem provides the following features and benefits: Features:

Benefits:

ƒ Non-damaging ƒ Low Skin ƒ Low lift off pressure ƒ Low permeability, tough, thin & resilient filter cake ƒ High lubricity / low friction factors ƒ Environmentally compliant ƒ Works with any completion tool assembly

ƒ High return permeability ƒ High production ƒ No blockage with cake pieces ƒ Low leak off and minimum chances of stuck pipe ƒ Low torque and drag ƒ Low disposal cost ƒ Wide flexibility in usage

OPTA-FLO System Components: OPTA-VIS A premium quality non xanthan based viscosifier has been selected for use in the OPTA-FLO system. OPTA-VIS is readily dispersible in makeup water, is highly shear thinning, does not leave any residue and may be completely removed with acid treatments . OPTA-VIS increases the LSRV & LSYP to provide excellent suspension properties for effective hole cleaning. OPTA-ZAN A high purity clarified xanthan gum used in the OPTA-FLO system fluid as a viscosifier. Small quantities provide viscosity and weight material suspension for all water-based drilling fluids systems. OPTAZAN has the unique ability to produce a fluid that is highly shear-thinning and develops a true gel structure. OPTA-STAR PLUS A premium grade starch product developed for applications in DIF, OPTA-STAR PLUS is very effective at reducing the fluid loss and providing a thin, tough and low permeability cake. The filter cake formed is lifted off with low pressures. OPTA-CARB Sized calcium carbonate particles, ground marble. High grade marble is used to provide particles which exhibit minimal attrition while drilling. A common occurrence with softer limestone. Proprietary software HyPR-SIZER is used to engineer the OPTA-CARB PSD to match, as closely as possible, the reservoir pore size distribution thus providing an effective sealing on the formation surface to minimising fluid and/or solid invasion of the pay zone. OPTA-LUBE CB An environmental friendly and non-damaging lubricant which increases the lubricity of the system and reduces the torque and drag especially in directional and horizontal wells. OPTA-ZYME S An alpha-amylase enzyme designed to remove polymer damage caused by the starch based products used in the OPTA-FLO Drill-In fluids system primarily in horizontal and multilateral wells. As the starch is broken down by the enzymes the bridging agents present in the filter cake will be readily dispersed and may even be completely removed by additional treatments. All enzyme treatments should be customised in the laboratory before use in the field.

29

Section

11b


OTHER PRODUCTS: KCl Potassium chloride is used as an clay / shale inhibitor where clay and or shale formations are inter layered in the producing sand. The concentration required will be based on the extent of the clay / shale layers but will generally vary from 3 – 8% in OPTA-FLO systems. KCl should not be used if Kaolinite is present. KCl can destabilise Kaolinite in shales and causing Kaolinitic fines to mobilise and migrate in reservoir rocks. Glutaraldehyde OPTA-STAR PLUS and OPTA-ZAN may be subject to bacterial degradation in under saturated brines. A biocide such as Glutaraldehyde should be used in the system. Inhibition While some inhibition, sufficient for most reservoirs, will be provided by the salt selected for the system, many reservoirs which have shales present in the formation may require additional inhibition. The OPTA-FLO system is compatible with the inhibitive cloud point glycols CIRRUS and CUMULUS as well as the amine inhibitor, HyPR-HIB. These products will increase the inhibitive nature of the fluid and will have minimal impact on the fluids properties. However it is recommended that these products are only added to the OPTA-FLO after their effects on the reservoir have been confirmed. Formulation An example of an OPTA-FLO formulation and associated properties is shown in Table 13. All formulations must be engineered to meet characteristics of individual reservoirs. Product water soda ash caustic soda KCl OPTA-VIS OPTA-STAR PLUS OPTA-CARB Parameter Density PV Yield Point 6 rpm Brookfield Viscosity API Filtrate

Concentration lb/bbl kg/m3 0.85 bbl/bbl 0.85 m3/m3 0.2 0.6 0.5 1.4 22 62.7 1-2 2.85 – 5.7 4-6 11.2 – 17.1 30 - 50 4.3 Unit Typical Value lb/gal /SG 9.4 / 1.13 cP 12 - 16 lb/100 ft2 12 - 20 Dial reading > 10 cP > 40,000 ml / 30 mins. <4

Mixing Guide lines: The OPTA-FLO system is readily mixed at the wellsite with no specialised equipment required. It is critical that the OPTA-FLO system is kept clean to avoid compromising its non-damaging characteristics. Care must be taken to isolate the system from other WBM or NAF to prevent contamination.

30

ƒ Clean the mud tanks thoroughly ƒ Flush all the hopper and mixing lines ƒ Add appropriate amount of water (or brine) in the tank (NB polymers will yield faster in fresh water – mixing in brine will require a longer time to fully hydrate, however, the use of brine or fresh water will depend on the practicality of mixing at the wellsite or mud plant) ƒ Add biocide ƒ Determine total hardness of water, calculate and mix soda ash required to treat the hardness to below 200 mg/l ƒ Citric acid may be added at this point to lower the pH to 3 to 4 for maximum polymer dispersion; this is optional and not always required ƒ Add OPTA-VIS or OPTA-ZAN ensuring fish eyes are not formed ƒ Shear for one to two hours if time permits ƒ Add NaOH, KOH or MgO to achieve a pH of +/- 9.0 – 9.5 NB. Use only MgO in high calcium fluids, > 1,000 mg/l ƒ Add salts, including KCl for inhibition, if brine not used previously ƒ Mix OPTA-STAR PLUS ƒ Mix OPTA-CARB ƒ Add additional products after mud has fully sheared and hydrated, lubricant, stabilisers etc., Treatment and maintenance of OPTA-FLO Systems OPTA-FLO fluids are polymer based systems with similar maintenance and treatment requirements to other water base polymer systems, however, to ensure the minimal damaging aspects of the fluids, the system formulation should be maintained throughout. As treatment is required it is recommended that, as far as possible, additions either as dilution or displacement fluid should be made with whole mud / premix. Pilot testing of additives is also recommended to prevent any undesired effects which may affect return permeability. It is strongly recommended that, another fluid should be used to drill cement plugs and casing shoes before displacing to OPTA-FLO to preserve the quality of polymers which can be adversely affected by drilling cement. Density OPTA-FLO fluid density is primarily determined by the density of the brine used as the ‘base fluid’ with approximately + 0.6 lb/bbl (0.07 SG) from the system components. Typical brines used are potassium or sodium chloride, with higher densities provided by the use of formate brines. Additionally viscosity may be provided by further additions of OPTA-CARB but the use of clear brines is preferred in order that the bridging agent concentration is not compromised- DO NOT USE BARITE. Rheology The OPTA-FLO system exhibits exceptional rheological characteristics and does not ordinarily require supplemental additions of viscosifier although the LSRV may decrease while drilling, due to shear and temperature degradation, oxidation (depending on formulation and temperature. If required OPTA-ZAN or OPTA-VIS may be added directly to the system – pilot testing is recommended to determine treatment level to minimise polymer additions. Fluid Loss The rapid mechanism for laying down filter cake ensures that there is a low spurt loss and low filtrate invasion. Despite the relative low concentration of polymer filtration controllers this fluid system has tight filter loss due to the synergetic relationship between the polymers and the bridging materials. Initial fluid loss should be + 4 ml/30 minutes and will generally decrease as the fluid is circulated. Additional OPTA-STAR PLUS may be added as needed to further reduce the fluid loss.

31

Section

11b


pH The pH of the system should be maintained within the 8.5 - 9.5 range using NaOH, KOH or MgO which will generally be determined by the brine phase selected. MgO is recommended as a pH buffer for most systems but particularly so in calcium based systems where the calcium level is > 1,000 mg/l. Pilot testing should be performed to determine the exact quantity needed in all systems. If cement contamination occurs citric acid may be used to reduce the pH to around 10 – do not use acid to reduce the pH further as it will be dissipated on the calcium carbonate in the system. MBT The MBT values should be checked frequently as the initial system is built with no reactive clays. Increases in MBT values indicate that shale stringers are being drilled in the production formation. Accurate checking on MBT levels will help determine when displacement volumes are required to keep the system in the optimum range. Present lab data indicates a severe reduction in return permeability when MBT values are allowed to increase. Solids control Drill solids in the circulating system must be eliminated or maintained at the lowest possible level as these solids will negatively impact the fluid properties and the filter cake formation reducing the non damaging nature of the system. As there is no barite in the system there are no high gravity solids. The bridging material, calcium carbonate, is the same density of drill solids. It is therefore imperative that the solids content be monitored and the drill solids content differentiated from that of calcium carbonate. It must be highlighted that while the primarily purpose of solids control equipment is to remove drill solids, bridging materials will also be removed negating the non damaging nature of the fluids. A balance has to be struck between solids removal and controlling the effects of drill solids contamination by dilution. Fresh bridging agents are frequently added on a continuous basis to replace material lost through solids control equipment. Modern Linear Motion shakers are the preferred option with screen selection determined by OPTACARB particle size and concentration, as well as hole size, cutting size, ROP and flow rate. Observe for any damage to screens. Torn screens should be changed IMMEDIATELY. Do not use Hydro-cyclones as OPTA-CARB will be discarded, unless excessive sand build up requires intermittent use to reduce the sand content, in which case fresh additions of bridging agent must be made to maintain the concentration. The hydro-cyclone discharge must be tested to ensure that excessive amounts of bridging material are not being discarded. The use of any equipment requiring centrifugal pumps should be minimised because the excessive shear can degrade the polymers and solids prematurely. Do not leave the mud running through the mixing system. Corrosion OPTA-FLO systems are not corrosive but corrosion issues might arise due to formation type, fluids and temperature. The combination of alkalinity and bacterial control in the system may be supplemented with oxygen scavengers, OX-SCAV, or filming forming inhibitors. Temperature stability In unsaturated systems polymer stability will be limited to < 250 °F (121 °C) and to + 300 °F (+149 °C) in saturated and formate systems.

32

Temperature stability is improved with the use of: ƒ Oxygen scavengers (OX-SCAV) ƒ pH buffered to > 9.0 with MgO ƒ HYDRO-BUFF a pH buffer and polymer extender for water base drilling fluids used when temperatures range above 280 ˚F (137 ˚C). All formulations must be tested and approved in the lab to determine the correct treatment levels for the thermal stability desired. Displacement Cement the casing above the pay zone. RIH to TD with bit and casing scrapers. Drill the cement to within 5 ft (2 m) of the casing shoe using the existing mud system. Circulate and condition mud to prepare for displacement. During all displacement operations rotate and reciprocate the drillstring to ensure the low side of the hole is clean. Displacement from SBM to OPTA-FLO Pump clean up pill sequence as set out in the detailed well cleanup programme:As a guide: 1. 2. 3. 4. 5.

Pump base oil fluid pill, 15 – 50 bbl ( 2 – 8 m3) Pump viscous pill containing clean up surfactant Pump clean up pill with surfactant Pump 50 bbl (8 m3) viscosified brine (same density as OPTA-FLO) Pump and displace OPTA-FLO

Once the OPTA-FLO system is observed at the shakers, discontinue pumping and clean the flow-line, shaker pits, and return ditch prior to initiating drilling. At this point, change screens on all solids control equipment. Displacement from WBM to OPTA-FLO Pump clean up pill sequence as set out in well cleanup programme:As a guide: 1. Pump 100 bbl (16 m3) seawater pill containing detergent to clean casing 2. Pump 50 bbl (8 m3) viscosified brine (same density as OPTA-FLO) 3. Pump and displace OPTA-FLO If possible pump 1 - 2 hole volumes of seawater to fully clean the casing before displacement to OPTAFLO. Once the OPTA-FLOsystem is observed at the shakers, discontinue pumping and clean the flowline, shaker pits, and return ditch prior to initiating drilling. At this point, change screens on all solids control equipment.

33

Section

11b


From OOPTA-FLO to Brine 1. After reaching TD circulate the hole clean, minimum of one circulation and make a wiper trip into casing. 2. Return to bottom and circulate until hole is clean. 3. Displace to either brine or a fresh solids free OPTA-FLO system containing no bridging agent – minimum displacement = open hole + 500’ (150m) inside casing / liner. 4. If open hole displaced with solids free system then pull into casing / liner and displace to filtered completion brine. 5. Displace brine / OPTA-FLO out of the well as detailed in the completion programme. Field Trouble Shooting Guideline Observation High PV

Possible Reasons ƒ Solid build up ƒ Inefficient or inadequate solid removal

High YP

ƒ Solid build up ƒ Increase MBT value ƒ High LGS ƒ High Solids ƒ Shift in particle size. Polymers degrading Bacterial problem ƒ Surface tension

High Gels High API Fluid loss

Foaming Lubricity Low values of LSRV & YP

ƒ Well geometry ƒ BHA configuration ƒ Polymers degrading ƒ Excess water added through shaker cleaning or from other places

Recommended Treatment ƒ Check Shaker screens for holes ƒ Use finer screens Dilute the system with premix Use other SCE judiciously ƒ As above ƒ Dump & dilute with premix ƒ As above ƒ Dump & dilute with premix ƒ Add OPTA-CARB ƒ Add OPTA-STAR PLUS ƒ Add bio-cide ƒ Maintain pH above 9 ƒ Add defoamer ƒ Add OPTA-LUBE CB ƒ Mix OPTA-VIS or OPTA-ZAN ƒ Pilot test to determine optimum treatment ƒ Identify and stop the source of water addition.

rheo-plex System Description RHEO-PLEX is a mixed metal oxide system, MMO, providing a highly thixotropic water based fluid that is both environmentally friendly and cost effective. The system shear thins, provides exceptional hole cleaning, is stable above 300 ˚F (149 ˚C) and delivers an enhanced rheology profile and stability that is easy to design, mix and maintain. When RHEO-PLEX is added to the bentonite suspension the species displace the resident cations and forms a bond on the surface of the bentonite platelets. The system is based on the unique interaction between the MMO cationic specie and the bentonite platelet. The anionic specie bonds to the negative charged sites of the bentonite forming a complex which structures the fluid and provides its unique gels and viscosity profile. The system is viscous at rest and once shear stress is applied it thins, only to regain its viscosity once the stress is removed.

34

The chemical inhibition of the RHEO-PLEX system is relatively low as it is formulated with little or no salts provides a level of inhibition by non movement of fluid at the wall of the wellbore and minimal filtration. It is also suspected that any filtrate that enters the formation will contain MMO and will inhibit by cationic exchange. RHEO-PLEX applications include drilling deviated hole sections, milling, depleted reservoirs and unconsolidated formations. It must be noted that the fluid can provide chemical inhibition if used with 3% KCl. The mechanism for interactions between the individual MMO – bentonite complex is weakly electrostatic. This electrostatic interaction is readily broken by mechanical means and reforms once the stress is removed which explains the extreme thixotropic behaviour, i.e. why the RHEO-PLEX fluid instantly shear thins with the application of mechanical agitation. This chemistry gives the RHEO-PLEX fluid a unique rheological profile that exhibits high flat gels which are fragile and easily broken with the start of circulation, but reform immediately when the fluid is static giving very effective cuttings suspension. During circulation the fluid has a inverted U shaped velocity profile in the wellbore with high annular velocity in linear flow at the centre of the well and zero movement at the wellbore wall. This flow profile leads to the effect of negative lag times whereby cuttings appear to reach surface faster than the calculated time as only part of the fluid system is moving at velocity. This low velocity at the well bore subjects the formation to zero shear stress. Benefits of this system include: ƒ Exceptional hole cleaning ƒ Excellent suspension properties ƒ Low torque and drag ƒ Low ECD ƒ Efficient solids removal ƒ Proactive lost circulation remedy ƒ Universal environmental approvals ƒ High cost efficiency Pre-System Checks Prior to utilising the system on the rig, the rig site drilling fluids representative must become familiar with system and well information which includes but is not limited to: ƒ Ensure that all non fresh water or seawater pipes are blanked off and locked. ƒ Clean all pits and circulating systems with drill water. ƒ Ensuring that the rig contractor and other service companies are aware that the system will be used. ƒ Pilot check all products prior to building at the rig site. Formulation An example formulation and associated properties is detailed in Table 13.

35

Section

11b


Product Function drill water soda ash DRILL-GEL UA caustic soda RHEO-PLEX HYDRO-STAR CMS DRILL-BAR PROPERTY Mud Weight PV YP 6 RPM Gel API pH

Base Fluid Alkalinity Control Viscosifier pH control Complexing Agent Fluid Loss control Weighting Agent UNITS lb/gal cP lb/100 ft2 dial reading lb/100 ft2 ml/ 30 min


Concentration kg/m3

0.85 bbl/bbl 0.85m3/m3 <400 mg/l hardness 8 -12 22.8 – 34.2 9.5 -10.0 0.80 -1.2 2.3 – 3.4 3.0 - 5.0 8.55 – 14.25 192 547 TYPICAL VALUE 12 4 25 - 30 20 30 / 36 <8 9.5 -10

Table 14. Example RHEO-PLEX formulation It is imperative that all materials are pilot tested. The system cannot be formulated using PAC, CMC or charged polymers. Engineering Guidelines Hardness It is recommended that the hardness be minimised. Prior to mixing treat out any hardness by the use of soda ash. The interaction of the between the MMO and the bentonite is enhanced if the hardness is below 400 mg/l. API Filtration control is provided by the use of HYDRO-STAR CMS, a non ionic starch. PAC or CMC materials are incompatible with the MMO / bentonite complex. Rheology A characteristic of the RHEO-PLEX system is that the 3 rpm rheometer reading is about 20% lower than the 600 RPM reading. The rheology of the system is based on RHEO-PLEX- DRILL-GEL UA complex. In the event that the rheology is too high do not treat the system with polymeric deflocculants or lignosulphonate thinners. Correct high rheology with dilution. Density Density is provided from DRILL-BAR and or calcium carbonate. pH It is imperative that the pH is maintained in the range specified 9.5-10. The interaction between the RHEO-PLEX and the bentonite is optimised in this pH range. Solids Tolerance: This system is not solids tolerant and the drill solids must be maintained below 5%. Contamination All common contaminants, plus the drilling of lignitic and anhydritic formations, have a disruptive effect on the RHEO-PLEX- DRILL-GEL UA complex which will cause a rapid loss of rheology. If this occurs the only effective solution is to rebuild the system.

36

Reserve Volume: Ensure that there is always sufficient RHEO-PLEX- DRILL-GEL UA blend on surface to rebuild the circulating system. Mixing RHEO-PLEX When building the RHEO-PLEX particular care has to be taken. The following method is suggested. ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ ƒ

Pilot test with the actual products Ensure that the water being used has hardness below 200 mg/l Ensure the bentonite being used is high quality untreated bentonite Prehydrate bentonite, ensuring that the gel is fully yielded Adjust the pH of the bentonite to pH range of 9.5 -10 using caustic soda Add the RHEO-PLEX Add the filtration control agent. (HYDRO-STAR CMS) If necessary dilute with sea or drill water Weight up to required density

Cementing RHEO-PLEX is highly sensitive to divalent and polyvalent cations. Cement should not be drilled with the system. Displacement Drill out the cement with the fluid that is to be displaced out of hole, prior to displacing to the RHEOPLEX fluid. ƒ Displacement out of hole: If displacing with a lighter water based fluid, pump ahead a 50 bbl (8 m3) brine spacer between the RHEO-PLEX system as well as a high viscosity water based pill, 6 lb/bbl (17.1 kg/m3) HYDRO-ZAN.

dispersed and calcium muds System Description A bentonite water based mud system which has been chemically deflocculated and the end charges neutralised can be described as a dispersed system. The most common dispersants are lignosuphonates, acylamide copolymers and phosphates. These systems have low inhibitive qualities and are used to drill low reactivity shales. Bentonite systems are made more inhibitive by being converted to calcium based systems with lime or gypsum. These systems have lower filtration loss, higher pHs and more stabilised rheology than conventional non dispersed bentonite system. Systems which can be described as dispersed include: ƒ HYDRO-SPERSE (Lignosulphonate) ƒ HYDRO-TAN CF (Tannin) ƒ Phosphate (SAPP) ƒ Calcium Muds (lime and gypsum muds) Benefits of Dispersed Bentonite Mud System ƒ Fluid has high carrying capacity ƒ Simple to formulate ƒ Highly flexible and can be converted into inhibitive systems ƒ Low fluid cost ƒ High temperature tolerance ƒ Simple to use 37

Section

11b


Limitations of Dispersed Bentonite Mud System ƒ Requires time to mix ƒ High dilution rates ƒ Relatively thick filter cakes ƒ May have environmental restrictions on the use of some of the lignosulphonates HYDRO-SPERSE (Lignosulphonate Muds) HYDRO-SPERSE muds are used to drill well sections which have high bentonitic clay sections. The system can be formulated with fresh and brackish water. However bentonite should prehydrated with water that is of a good quality containing low hardness and chlorides. HYDRO-SPERSE provides good filtration control and stabilizes the rheology. An example formulation is detailed in table 14. The system may be further treated with the supplementary products detailed in Table 15. Product Function ddrill water soda ash DRILL-GEL caustic soda HYDRO-SPERSE DRILL-BAR PROPERTY Mud Weight PV YP 6 RPM Gel API

Base Fluid Calcium Reducer Viscosifier / Filtration Control pH modifier Thinner / Filtration controller Weighting Agent TYPICAL VALUE 9.2 20 12- 15 10 11/20 6-8


Concentration kg/m3

0.90 bbl/bbl 0.90 m3/m3 To Ca++ <100 mg/l 10 - 25 28.5 – 71.25 To pH 10 -11 2-8 5.7 – 22.8 35 99.75 UNITS lbs/gal cP lbs / 100 ft2 dial reading lbs / 100 ft2 ml / 30 min

Table 14. Example lignosulphonate system formulation Order of Mixing ƒ Treat out the calcium from the mix water with the required amount of soda ash ƒ Raise the pH of the water with caustic soda to above 9.5 to precipitate any magnesium and other divalent ions ƒ Mix in the required amount of DRILL-GEL ƒ Add the required HYDRO-SPERSE ƒ Weight up the system with DRILL-BAR ƒ Add supplementary filtration controller if required If the system is formulated using a previous bentonite mud as a base then: ƒ Reduce the MBT to 10 -15 lb/bbl by dilution and if necessary dumping ƒ Treat out the calcium from the mix water with the required amount of soda ash ƒ Raise the pH of the water to above 10.5 as this will precipitate any magnesium and other divalent ions ƒ Although the system can be formulated with sea and brackish water, DRILL-GEL should be hydrated with fresh water with low chloride content (< 5000 mg/l) ƒ Mix in the required amount of DRILL-GEL ƒ Add the required HYDRO-SPERSE ƒ Weight up the system with DRILL-BAR

38

Maintenance of HYDRO-SPERSE fluids: ƒ Regular treatments with HYDRO-SPERSE are required to maintain the rheology while drilling. ƒ The efficiency of the products are enhanced by maintaining low concentrations of Cl-, Ca2+ and Mg2+ ions. ƒ Ensure that the solids control equipment is optimised and control the solids content by dumping and diluting as required. ƒ To ensure optimal drilling fluid performance and costs maintain the MBT below 20 lb/bbl. It may be necessary to maintain the density and plastic viscosity by means of premixes. ƒ Treatments with HYDRO-THIN will stabilise rheology and enhance filtration control. ƒ Polymers such as HYDRO-PAC, HYDRO-STAR and CMC can be used to provide supplementary filtration control. ƒ In order to ensure the efficiency of the HYDRO-SPERSE ensure that the system pH is maintained in the range of 9 – 9.5. Calcium Treated Muds Lime muds are more inhibitive than HYDRO-SPERSE fluids, due to the presence of soluble calcium, and can be used to drill sections that have formations where shale reactivity may result in hole instability and sections that have anhydrite formations and stringers. By increasing the concentration of soluble calcium in the fluid, the inhibitiveness of the fluid is increased. The lime system may be viewed as a HYDRO-SPERSE system that has been treated with soluble calcium ions. Example formulations and properties as well as supplementary product are shown in Tables 15 and 16. PRODUCT Function

drill water DRILL-GEL HYDRO-SPERSE lime gypsum HYDRO-TROL caustic soda HYDRO-PAC or HYDRO-STAR NF DRILL-BAR PROPERTY Mud Weight PV YP 6 RPM Gel Pf mF Excess calcium calcium in filtrate pH API

Concentration Concentration Concentration Concentration Lime Mud Lime Mud Gypsum Gypsum lb/bbl kg/m3 lb/bbl kg/m3

Base Fluid Viscosifier / Filtration Control Thinner / Filtration controller Calcium Generator Calcium Generator Filtration Controller pH modifier Filtration controller

0.90 bbl/bbl 10 - 25

0.90 m3/m3 28.5 – 71.25

0.90 bbl/bbl 10 – 25

0.90 m3/m3 28.5 – 71.25

1-4

2.85 – 11.4

3-6

8.56 – 17.12

1-8

2.85 – 22.8 4-8 5.7 – 11.4 2–4 To pH 10 -11 2.85 1

11.4 – 22.8 5.71 – 11.4

Weighting Agent Units lb/gal cP lb /100 ft2 dial reading lb /100 ft2 ml

35 Typical Value 9.2 18 6-7 2 3/13 1 – 2.5 5 -10 1 - 10 75 - 200 10.5 – 11.5 5 - 11

lb/bbl mg/l ml / 30 min

2-4 1

99.75

35 Typical Value 9.2 18 7-8 3 2/18 0.15- 0.8 3-5 2-5 600 - 1200 9.5 - 10 4–8

2.85 99.75

Table 16. Formulation and properties of calcium treated muds.

39

Section

11b


Supplementary Products Chemical Function Operational Viscosity and Filtration Enhanced filtration HYDRO-PAC control in displacement mud and sweeps Viscosity and Filtration Enhanced filtration CMC control in displacement mud and sweeps Viscosity and Filtration Enhanced filtration HYDRO-TROL control in displacement mud and sweeps Prevention of Glutaraldehyde Biocide microbiological action Stuck pipe freeing Is used as a stuck pipe SAPP agent/ bit balling freeing agent when preventer disrupting the filter cake when placed over the sticking zone Enhanced filtration HYDRO-PLAST / High Temperature Filtration Controller control in displacement HYDRO-PLAST mud. PLUS Barite To build spud mud and DRILL-BAR displacement mud where density is greater than 8.8 lb/gal Shear thinning As a rheology enhancer HYDRO-ZAN Viscosifier for operations where poor water quality prevents DRILL-GEL from fully yielding. ROP Enhancer Minimising bit balling HyPR-DRL

Concentration Concentration lb/bbl kg/m3 1.0 – 5.0 2.85 – 14.3

1.0 – 5.0

2.85 – 14.3

1.0 – 5.0

2.85 – 14.3

500 -1000 ppm 2.0 - 5.0

5.7 – 14.3

2-8

5.7 – 22.8

As required 0.25 -1.0 lb/bbl

0.7 – 2.85

0.5 - 5%

Table 17. Supplementary products for dispersed systems Note lime muds can be classified as: ƒ low lime when the mud contains 1- 2.5 lb/bbl (2.85 – 7.1 kg/m3) of excess lime and ƒ high lime when the excess lime content of the mud is 5 – 15 lb/bb (14 – 42 kg/m3). Excess Lime Calculation Excess lime (lb/ bbl) is estimated by the following formulae Lime Content = PM – PF 4 Or Lime Content = 0.26 (PM - % water fraction x PF) Excess Lime kg/m3 = Excess lime lb/bbl x 2.85

40

Excess Gypsum Calculation Excess Gypsum (lb/ bbl) is estimated by the following formula Gypsum Content = VM – VF 4 3 Excess Gypsum kg/m = Excess lime lb/bbl x 2.85 VM VF

is the ml of versanate from the hardness test on the whole mud is the ml of versanate from the hardness test on the filtrate

Order of Mixing ƒ Treat out the calcium from the mix water with the required amount of soda ash ƒ Raise the pH of the water with caustic soda to above 10.5 as this will precipitate any magnesium and other divalent ions ƒ Mix in the required amount of DRILL-GEL ƒ Add the required HYDRO-SPERSE ƒ Add the required lime or gypsum ƒ Add the required filtration controller ƒ Weight up the system with DRILL-BAR ƒ Note the fluid may have a viscosity hump; this should disappear with shear thinning. However that it does thin by agitation on the Hamilton beach mixer. Confirm that the pH is correct. Pilot test with higher caustic then more HYDRO-SPERSE If the system is formulated using a previous bentonite mud as a base then: ƒ Break over will require a minimum of three circulations (two to add all the chemicals evenly and one to ensure that the fluid is thin). ƒ There will be a viscosity hump, during which there will be high filtration loss that will thin on circulation. It is advisable to perform the break over inside casing. ƒ Reduce the MBT to 10 -15 lb/bbl (28.5 – 42.75 kg/m3) by dilution and if necessary dumping. ƒ Treat out the calcium from the mix water with the required amount of soda ash. ƒ Raise the pH of the water to above 10.5 as this will precipitate any magnesium and other divalent ions. ƒ Although the system can be formulated with sea and brackish water, the DRILL-GEL should be hydrated with fresh water with low chloride content (< 1000 mg/l). ƒ Mix in the required amount of DRILL-GEL. ƒ Add the required HYDRO-SPERSE. ƒ Add the required lime or gypsum. ƒ Weight up the system with DRILL-BAR. ƒ Add the require supplementary filtration control. Maintenance of calcium muds: ƒ While drilling with calcium fluids regular treatments with HYDRO-SPERSE, gypsum / lime / caustic soda are required to maintain the rheology and filtration control. ƒ Ideally all additions should be in the form of premixes. ƒ Maintain the calcium concentration in the filtrate. ƒ Avoid mixing of lime / gypsum and polymeric filtration controllers at the same time. ƒ Avoid over treatment with caustic soda as the higher the pH the lower the solubility of the calcium. ƒ Maintain drill solids content as low as possible. Ensure that the solids control equipment are optimised and control the solids content by dumping and diluting as required. ƒ To ensure optimal drilling fluid performance and cost, maintain the MBT below 20 lb/bbl. ƒ It may be necessary to maintain the density and plastic viscosity by means of premixes.

41

Section

11b


ƒ Treatments with HYDRO-THIN will stabilise rheology and enhance filtration control. ƒ If after three circulations the viscosity hump is still present, check the pH. Treatment with caustic may be required to ensure that the HYDRO-SPERSE becomes effective . Tannin dispersed fluids are prepared in the same manner as HYDRO-SPERSE muds substituting HYDRO-TAN CF for HYDRO-SPERSE .

42

section 11c non aqueous drilling fluids

section 11c

Scomi Oiltools

confi-drill

2

confi-dense

6

confi-deep

8

opta-vert

17

Section

11c

non aqueous drilling fluids


confi-drill CONFI-DRILL is an invert emulsion drilling fluid system which can be tailored to meet environmental and performance criteria. The system has excellent rheological and filtration characteristics easily modified to meet changing pressure and temperature conditions, The system consists of three phases; non aqueous, brine and solid. The key to the system is the emulsifying chemicals designed to create and maintain the invert emulsion. The system can be formulated with a range of base fluids including low toxic mineral oil (LMO), linear paraffin (LP), linear alpha olefin (LAO) and internal olefin (IO). Mechanism of Shale Stabilisation Invert emulsion drilling fluids provide the highest level of shale inhibition by a drilling fluid. An invert emulsion consists of two liquid phases:ƒ A hydrophilic brine internal phase. ƒ A hydrophobic non polar continuous phase. The internal phase is emulsified into the continuous phase with the use of emulsifiers. As the hydrophobic continuous phase will not solvate or swell exposed shales, it makes the fluid system ideal for drilling hydratable shales. This characteristic is the basis for the use invert emulsions as non-reactive, inert drilling fluids. As water contamination of the drilling fluid is unavoidable from drilled formation, the drilling fluid system must be formulated to tolerate this additional water. To prevent the internal hydrophilic phase from reacting with the formations, the system is formulated with high salinity brine, usually calcium chloride. If the salinity of the brine is maintained at a concentration higher than the formation salinity, water will flow by a process of reverse osmosis from the formation into the fluid, stabilising reactive formations. Benefits of the invert emulsion system include:ƒ Inhibition ƒ Low filter loss ƒ Re-use ƒ Can be engineered to any specific requirement ƒ Thin, slick filter cake ƒ Can be engineered with environmentally friendly base fluids ƒ Simple to use

ƒ Fluid properties are tolerant of solids ƒ Resistant to contamination ƒ Protection against corrosion ƒ Low dilution rates ƒ Can be formulated to relatively low densities ƒ Highly lubricious

The advantages of the system must be considered along with the limitations:ƒ High cost of losses ƒ High initial make up costs ƒ May have environmental restrictions ƒ May require complex clean up procedures

ƒ Cost of remediation ƒ Re use may lead to build up of low gravity solids

Formulation An example of a CONFI-DRILL formulation and associated properties is detailed in Table 1. It must be highlighted that product concentration will vary depending not only due to the density, temperature and product ratio’s but also with the type of base oil utilised. Product Function Base Fluid Base fluid CONFI-MUL P Primary emulsifier CONFI-MUL S Secondary emulsifier CONFI-GEL HT Viscosifier CONFI-MOD Rheology modifier CONFI-TROL / Filtration controller CONFI-TROL HT drillwater Liquid phase calcium chloride Water phase salinity lime Emulsifier activator DRILL-BAR Weight material

Concentration lb/bbl 0.68 bbl/bbl 6 2.5 6 1 2-8

Concentration kg/m3 0.68 m3/m3 17.1 7.1 17.1 2.85 5.7 - 22.8

0.175 bbl/bbl 22 8 120

0.175 m3/m3 62.7 22.8 342

Table 1. Example CONFI-DRILL formulation Property Mud Weight PV YP 6 rpm 10 minute Gel HTHP (@ 250 °F)

Typical Value 9.5 15 12 8 10 2.0

Units lb/gal cP lbs/100 ft2 dial reading lbs/100 ft2 ml /30 min

Table 2. Example CONFI-DRILL properties In addition to the basic products supplementary products can be used to optimise the system for specific use. These supplementary products and their function and concentration are listed in Table 3. Product Function CONFI-COAT Oil wetting agent CONFI-LUBE Lubricant for SBM CONFI-PLEX LSR modifier CONFI-THIN Oil wetting agent CONFI-TROL Solid fluid loss control additive CONFI-TROL F Liquid fluid loss control additive CONFI-WET Oil wetting agent

Concentration lb/bbl 0.5 - 2 1–3 1–3 0.5 - 2 2–8 1–5

Concentration kg/m3 1.4 – 5.7 1 – 3% 2.85 – 8.55 1.4 – 5.7 5.7 -22.8 2.85 – 14.25

0.5 - 2

1.4 – 5.7

Table 3. Supplementary products for CONFI-DRILL systems

Section

11c


Engineering Guidelines In general the following guidelines and mixing procedures apply to all non-aqueous fluids except where indicated in system specific sections of this handbook. Mixing CONFI-DRILL When mixing an invert emulsion system the amount of shear in the mixing system has to be maximised. It is recommended that a shearing unit is used and the fluid shear is maximised by circulating through the gun lines. 1. Add the required quantity of base fluid to the mixing tank. 2. Add the primary emulsifier, CONFI-MUL P, and secondary emulsifier, CONFI-MUL S, as required. 3. Add organophilic viscosifier, CONFI-GEL / CONFI-GEL HT, as required. 4. Add required amount of water to the above mixture. If brine is to be used, then add brine after the lime additions. 5. Add rheology modifier e.g. CONFI-MOD or CONFI-RM as required. 6. Add lime as required. 7. Add filtration control additives, CONFI-TROL, CONFI-TROL HT, CONFI-SEAL or or CONFI-TROL F, as required. 8. Add calcium chloride powder if brine is not used. If calcium chloride powder is not available, then mix the calcium chloride flakes into the water and add as a brine. 9. Mix above for several hours to ensure a good emulsion is formed. 10. Add weighting material as required for the desired density. The shear available on most rigs is rarely sufficient to ensure that the organophilic clays have fully yielded. Once the fluid is sheared through the bit, and heated, the rheology profile should increase. Emulsifier Emulsifier ensures that the invert emulsion is stabilised and provides initial filtration control with zero water breakthrough. The measurement of emulsion stability gives an indication of the condition of the emulsion. Optimisation of the emulsifier concentration will ensure that there is good temperature stability, stabilised rheology and optimised lubricity. Filter Loss Filtration controllers are used to maintain filtration control. They act in conjunction with the emulsifier package. Scomi Oiltools have a proprietary family of powdered filtration controllers including, CONFI-TROL and CONFI-TROL HT as well as a liquid product, CONFI-TROL F, specifically formulated to act synergistically with the emulsifier package. The effect of these products is specific to the emulsifier, oil water ratio, temperature of test, density of the fluid and type of base fluid. It is recommended that the HPHT filtration test is run at 25 ˚F (14 ˚C) higher than the maximum expected bottom hole temperature. Density DRILL-BAR is used to provide density. If higher densities or flatter rheological profiles are required then HyPR-BAR, fine grind barite, HAEMATITE or HYDRO-MAX can be used in the formulation. In some cases additional density may be achieved by replacing the calcium chloride brine with calcium or sodium bromide brine or by maintaining lower oil: brine ratios using either calcium chloride or alternatives including sodium formate, in particular where a low solids content of the fluid is required.

Rheology It must be highlighted that while drilling ahead there will be an increase in rheology as the organophilic clay yields. This is particularly true when new fresh mud is delivered to or mixed on the rig. Ensure that this increase in rheology does not become an operational problem, it must be controlled. The two principal methods of imparting rheology are the use of the Organophilic clay, CONFI-GEL/ CONFI-GEL HT and or low end rheological modifiers. Optimise the effectiveness of organophilic clays, with the addition of CONFI-MOD and/or CONFI-RM. The use of these modifiers will provide a flatter rheology profile minimising the ECD. Note that overuse of rheology modifiers without sufficient underlying organophilic clay structure can promote barite sag, which is detailed in section 6b of this handbook, barite sag. Oil Wetting Agents The use of oil wetting agents, CONFI-WET and thinners, CONFI-COAT, should be avoided as the difference between product effectiveness and over treatment can be a very fine balance. The thinners act on the organophilic agents and destroy their effectiveness. Once a system is over treated it becomes difficult to re gain the rheology and the danger of sag becomes more pronounced. If a treatment of oil wetting agents is to be made to the circulating system, it is advisable that the treatment is pilot tested extensively beforehand to determine the correct treatment level. Lime Lime is required to activate the emulsifiers; therefore, it is imperative the lime concentration be maintained in excess as the efficacy of the emulsifiers is optimised. Experience demonstrates while drilling ahead the excess lime concentration is steadily depleted. This is particularly noticeable while drilling reservoir sections and or higher temperature zones. Lime will also be removed by acid gases. Water Phase Salinity The activity coefficient of the water, or brine phase, Aw, should be maintained lower than the activity of the formation fluids. The water phase salinity ensures that the drilling fluid exerts a reverse osmotic pressure on the formation, the activity level being determined by the type and concentration of the salt. The Aw is maintained with a salt most commonly calcium chloride. The determining factor for the concentration of salt used is the status of the shale cuttings which should be firm and discrete. Any sign of hydration of cuttings indicates that the water phase salinity level must be increased. For reservoir drilling the brine phase may be provided by alternative salts including sodium bromide, sodium formate and calcium bromide. Temperature A characteristic of invert emulsion systems is high temperature stability. The limiting factors being the effectiveness of the emulsifiers, viscosifiers, rheological modifiers and filtration control, agents at the elevated temperature. At elevated temperatures there will be a more rapid depletion of the emulsifiers. This will also vary with density and type of base fluid. Cementing The primary effects of cement contamination are increases in the excess lime and water contents. However the pre-flush pills used prior to cementing are designed to change the wettability of surfaces which they achieve by attacking the emulsion package of the fluid. To minimise contamination of the drilling fluid the volume of preflush pills should be minimised. Contamination of the mud by the preflush results in a fall in emulsion stability, an increase in the HPHT filtrate and a decrease in the base fluid/brine ratio. This contamination may be treated by increasing the oil/brine ratio with an base fluid rich premix that contains an excess of emulsifiers.

Section

11c


If possible any excess pre flush that reaches surface should be isolated from the system on the first circulation, though in most cases it is so entrained into the mud it is impossible to isolate. When cementing liners, however, the excess cement and preflush may be reversed out and it should be possible to readily isolate the contamination in this case. Solids Control Equipment During displacements or after a trip, the shakers should be dressed with relatively coarse screens. The size of the screen should be reduced as the fluid warms up and the viscosity of the mud decreases. Gas Solubility Gas is soluble in NAF which has major consequences for well control as gas will stay in solution until close to surface and for deepwater wells expansion may not occur until the influx is in the riser. Kick detection may be severely compromised and the ability to detect and react to very minor volume changes is highly significant. This is especially true for H2S which is 40 times more soluble than methane. It should also be noted that solution gas, including trip gas, will be detected, in decreasing quantity, at the same spot in the circulating system for several circulations until it is finally released from the mud. Gas solubility is a function of temperature and pressure and will vary with base fluid type e.g. internal olefins and mineral oils the response of both base fluids is similar to 4,000 psi. Above 4,000 psi (27579 kPa) the effects of pressure dominate the solubility for mineral oils with methane being completely miscible above 7,000 psi (48263 kPa) and effects of temperature are not significant. On the other hand temperature has a pronounced affect on gas miscibility in internal olefins above 4,000 psi, higher temperatures significantly reducing the pressure at which methane is fully miscible, from + 11,000 psi at 150 ˚F to + 8,500 psi at 300 ˚F (+ 75800 kPa at 65 ˚C to + 58600 kPa at 149 ˚C ) If condensate is either present or the main component of a ‘kick’ there may be differences in behaviour compared to methane alone in solution: 1. Kick detection may be delayed for condensate kicks relative to methane kicks. 2. As the kick / base fluid mixture becomes heavier there is a corresponding decrease in volatility and bubblepoint pressure, i.e. rapid expansion happens closer to surface. 3. Significant expansion of a kick occurs nearer to surface for ondensates than for methane and, when it does occur because of gas evolution, it is more rapid. The rise in surface pressure shows the same trend. The heavier the condensate and, for SBM, the lower the concentration, the nearer the surface the rapid expansion and pressure rise occur as the bubblepoint pressure is lower. 4. When a condensate kick occurs in SBM contamination of the mud with condensate occurs as only the volatile components are released at surface. This may have consequences for discharge and or disposal of contaminated mud.

confi-dense System Description CONFI-DENSE is base oil or synthetic fluid based drilling fluid specifically engineered to provide emulsion stability for high density and high temperature applications beyond the range of the standard CONFI-DRILL system. The CONFI-DENSE system is stable to temperatures in excess of 400 ˚F (204 ˚C), exhibiting minimal density differentiation under both dynamic and static conditions. The system can be weighted to above 18.5 lb/gal (2.22 SG) with barite, or alternative weight materials such as HAEMATITE and is run with higher Oil:Brine ratios of 85/15 to 90/10+. The system has excellent rheological and filtration characteristics which are easily modified to meet changing pressure and temperature conditions.

Formulation An example of a CONFI-DENSE formulation and properties is detailed in Tables 4 and 5 Product Function Base Fluid – Iso Base fluid Paraffin CONFI-MUL HT Primary emulsifier CONFI-GEL HT Viscosifier CONFI-TROL F Filtration controller CONFI- TROL HT Filtration controller calcium chloride Water phase salinity Drillwater lime Emulsifier activator DRILL-BAR Weighting agent

Concentration lb/bbl 0.48 bbl/bbl

Concentration kg/m3 0.48 m3/m3

4-6 2-4 5-6 4-8 7 0.05 bbl/bbl 10 493

11.4 – 17.1 5.7 – 11.4 14.25 – 17.1 11.4 – 22.8 20 0.05 m3/m3 18.5 1405

Table 4. Example CONFI-DENSE formulation Property Mud Weight PV YP 6 rpm OWR ES Excess Lime HTHP (@ 350 °F)

Typical Value 17.5 2.10 49 18 8 90:10 1655 4 <2.0

Units lb/gal SG cP lbs/100 ft2 Dial reading volts lb/bbl ml/ 30 min

Table 5. Example CONFI-Dense properties In addition to the basic products supplementary products can be used to optimise the system for specific use. These supplementary products and their function and concentration are listed below Product Function CONFI-TROL XHT HT fluid loss control CONFI-GEL XHT HT viscosifier HyPR-BAR Fine grind barite

Concentration lb/bbl 1-4 1-4 As required

Concentration kg/m3 2.85 – 11.4 2.85 -11.4 As required

Table 6. Supplementary products for CONFI-DENSE systems A number of key aspects of the CONFI-DENSE system are; ƒ Both polymeric and organophilic clay viscosifiers are used to provide optimum rheology with a high base fluid:brine ratio. ƒ Formulations are engineered specifically to each project. ƒ Several filtration control additives are used to ensure the efficacy of the system at elevated temperature. ƒ The system is formulated such that the parameters are independent of base oil type. ƒ Due to the high solids content the system requires higher base fluid:brine ratios. Engineering Guidelines See guidelines under CONFI-DRILL.

Section

11c


Pressure and Temperature Effects for HTHP fluids Drilling fluid density and rheology are functions of temperature and pressure encountered in the well. Higher pressures will increase rheology and density; higher temperatures will decrease them. Note: The temperature effects on NAF are much higher than WBM as base oils have a much lower specific heat capacity and lower thermal conductivity than water. Fann 35 rheology readings at surface conditions do not reflect the rheology of the fluid at elevated pressures and pressures therefore it is very important to regularly run the rheology on a Fann 75 and measure the rheology at bottom hole conditions. Rheological modelling, e.g. ECD calculations, using only Fann 35 data will be inaccurate. The volume of the fluid will increase and decrease while drilling and tripping as the fluid heats and cools. This normal volume variation can lead to the interpretation that the well is flowing or losing. To fully establish the effects of pressure and temperature and establish a ‘fingerprint’ of the fluid behaviour to provide information to distinguish between “normal losses”, “down hole losses”, or “gains” the following steps should be taken. When the mud has reached equilibrium operating temperatures for each interval establish and record the normal changes in surface volume due to:1. operation / shut down of mud pumps, 2. Running mud pumps at different rates, 3. Operation / shut down of mix pumps and solids control equipment. Mud Coolers To lower both the surface and downhole circulating temperatures a mud cooler may frequently be used on HTHP wells. This surface cooling can lead to a reduction of > 25 - 50 ˚F (14 - 28 ˚C) plus in the maximum flowline and circulating downhole temperature. This is of particular benefit for extending the range and life of downhole tools.

confi-deep CONFI-DEEP is a flat rheology invert emulsion drilling fluid system designed and formulated for application in deep water drilling. HSE: The CONFI-DEEP system is handled in the same way as any other non aqueous system. Always refer to the MSDS of the base oil and the individual additives for safe handling instructions. In deep water environments, a seawater temperature of 39 °F (4 ˚C) is typically measured. The formation temperature may range to 212 °F (100 ˚C) or more. This variation in temperature causes wide fluctuation of rheological properties in conventional invert emulsion drilling fluids which leads to: ƒ pressure spikes ƒ induced fractures with “wellbore ballooning/breathing” ƒ barite sag ƒ poor cuttings suspension ƒ reduced hole cleaning ƒ excessive ECD ƒ severe mud losses ƒ cuttings pack-off leading to stuck pipe ƒ reduced drilling efficiency

The problem is compounded when pore pressure and fracture gradient converge. The margin for density fluctuations is low or non-existent. Strict control of the ECD is required to prevent fracture induction and often extremely expensive mud losses. A comprehensive investigation of the complex and interactive chemistry of surface active agents including emulsifiers; wetting agents and novel polymeric rheological modifiers to formulate a fluid system with remarkably constant rheological properties over a broad temperature range has been undertaken. Development was and continues to be focused on reducing the organophilic clay content and balancing hole cleaning, suspension requirements using special rheology modifiers to deliver a fluid with cold water viscosity values 33 – 50% of those of a conventional invert system The result is the flat rheology CONFI-DEEP system which delivers a consistent rheological profile over a wide range of temperatures, 40 - 200+ °F (4 - 95 °C) with ongoing development work demonstrating the potential of the system to perform at temperatures up to 250 °F (121 °C). Flat rheology of these deepwater systems typically considers plastic viscosity, yield point, and 6 rpm values. Each application is rigorously pilot tested in the lab to assure conformance of design to ECD requirements established by very detailed hydraulic modelling.

YP (Ib/100ft2) / 6 rpm reading

Figure 1 compares the yield point and 6 rpm values of CONFI-DEEP with a typical non aqueous fluid.

Figure 1 Rheology of CONFI-DEEP CONFI-DEEP system is surprisingly tolerant of solids, water and oil contamination. While the rheological properties change with contaminant concentration, the fluid remains stable and very resistant to water wetting of solids. Rheological properties remain flat despite high concentrations of contaminants. Incorporation of drill solids actually improves system properties and performance

Section

11c


CONFI-DEEP can be formulated using wide variety of base oils providing the same level of flexibility as with any other conventional non aqueous system currently in use in deep water drilling: ƒ low toxic mineral oil ƒ linear paraffin ƒ linear alpha olefin ƒ internal olefin Conversion Flexibility and System Stability The standard invert emulsion system CONFI-DRILL may be converted to the CONFI-DEEP system, but only after thorough pilot testing. Conversion of salvaged mud offers potential cost savings and in some cases a more stable and flat “pre-aged” mud system. The conversion process and the treatment have been verified in the laboratory using a variety of salvaged mud systems mixed in 33 – 50% proportions. Extensive lab tests also have confirmed the ability of CONFI-DEEP to incorporate surprisingly large quantities of drilled solids, seawater, and cement as illustrated in Figure 2.

F ig ure 2 : C O N F I -DEE P S yst em S tab ility (after hot roll @ 2 0 0 F for 16 hours) 40 35

YP (Ib/100ft2)

30 25 20 15 C O N F I -D E E P + 4 0 p p b r e v d u s t

10

C O N F I -D E E P + 2 5 p p b r e v d u s t + 5 p p b c e m e n t

5

C O N F I -D E E P + 2 5 p p b r e v d u s t + 2 0 % ( v /v ) s e a w a t e r

0 40 F

70 F

120 F Temp (deg F)

Figure 2 CONFI-DEEP contamination tolerance

10

150 F

Performance:

ƒ Stable Rheology over wide range of temperatures ƒ Pressure spikes minimised ƒ Carrying & Suspension capacity increased ƒ Decreased barite sagging tendencies

ƒ Decreased pack off chances ƒ Less dilution required ƒ Can be converted from CONFI-DRILL system ƒ Can be formulated using variety of base oil

Advantages: ƒ Improved ECD management ƒ Reduced fracture induction ƒ Reduced losses ƒ Less chances of formation breathing ƒ Better hole cleaning

ƒ Less chances of stuck pipe ƒ Flexible formulation ƒ Reduced environmental cost ƒ Lower overall well cost ƒ Optimized drilling performance

The CONFI-DEEP system, similar to other invert emulsions, consists of three phases, two immiscible liquids, base oil and brine, and the third, a solids phase of barite and drilled solids. CONFI-DEEP products Pilot testing at the wellsite, with these products, is strongly advised for assuring economical and effective treatment levels Base Fluid As noted previously a wide selection of base fluids may be used to build a CONFI-DEEP system, however, as is the case with any system for low temperature applications a base fluid with a pour point lower than the expected sea bed temperature must be used to avoid mud solidification. Brine Calcium chloride, CaCl2, is the salt of choice to be used for lowering the mud activity to balance shale activity. CaCl2 is used to ensure Aw as close to that of the clay/shale or lower. cDEEP-MUL A specially engineered surface active emulsifier and wetting agent in the CONFI-DEEP system is based upon complex surfactant chemistry, cDEEP-MUL emulsifies the brine in the base fluid and maintains an oil wet state of drilled solids, barite, and other solids. Other functions of cDEEP-MUL include deflocculation of system components and rheological control and stability. cDEEP-MUL also provides very effective HPHT fluid loss control up to about 200 °F (93 °C), reducing the requirement for fluid loss agents. cDEEP-MUL provides stable and tight emulsion over a wide temperature range from 32 – 250 °F (0 - 120 °C). The cDEEP-MUL concentration is custom optimised for each field application to provide stable rheology and fluid loss over the temperature range specific to the well. CONFI-MUL SA A blend of saturated fatty acids used in non-aqueous fluids to increase viscosity and provide support for weight materials particularly for freshly mixed muds during transportation as the full viscosity of the fluid is dependent on heat and shear in the wellbore along with solids incorporation. When exposed to higher temperatures in the wellbore CONFI-MUL SA liquefies, the initial temporary viscosity is lost, and the product and works as a weak secondary emulsifier. Its primary function is to provide suspension characteristics to freshly prepared mud before the viscosifiers have fully yielded.

11

Section

11c


cDEEP-MOD Is a specially designed organic polymer designed to maintain a flat rheological profile over the full range of temperatures encountered in a deepwater well. cDEEP-MOD is the primary viscosifier of the CONFI-DEEP system at temperatures > 68 °F (20 °C). cDEEP-RM Is a secondary modifier to assist in maintaining a flat rheology profile while drilling. An engineered combination of a special organic polymer and rheology modifier provides a stable dynamic flow profile. CONFI-GEL HT Premium organophilic clay which may be used as a supplementary viscosifier in the CONFI-DEEP system to provide additional gel structure to minimise sag. CONFI-GEL HT primarily provides rheological control below about 68 °F (20 °C) when used at low concentration. CONFI-GEL HT also is an effective emulsifier of water into non-aqueous fluids and a fluid loss reducer. cDEEP-TROL Is the primary fluid loss control additive for the CONFI-DEEP system. The additive has a synergistic effect with the system emulsifiers in controlling and reducing the HPHT fluid loss. Other non aqueous fluid loss additives may also be used but should be pilot tested before addition. The effectiveness of different fluid loss control additives is dependent on OWR; temperature, density and the type of base oil. Laboratory tests are advised for ascertaining the correct formulation for the project. cDEEP-BAR Is an economical non API sub-400 mesh barite for use in deepwater operations. cDEEP-BAR typically exceeds API quality specifications for mineral quality. cDEEP-BAR is specifically ground for formulation and maintenance of drilling fluids in which ‘barite sag’ is virtually eliminated in all fluid types and densities. cDEEP-BAR is a solution for fracture induction losses due to a narrow mud weight window. The products inherently low contribution to viscosity supports use in ECD sensitive wells. cDEEP-THIN A specially formulated and engineered complex surfactant polymer used in low concentrations as a thinner for the CONFI-DEEP system. It is very powerful and must be used carefully and judiciously – again pilot testing must take place before addition of ANY quantity. Overtreatment of any nonaqueous fluid with a thinner, can result in a serious deterioration of fluid properties which may be expensive to correct. Lime is required for activation of the emulsifiers and proper solubilisation of cDEEP-MOD. Extensive studies have determined that the EXCESS lime content must be maintained greater than 3 lb/bbl AT ALL TIMES

12

CONFI-DEEP formulations General formulation Product Function base fluid Continuous phase of emulsion cDEEP-MUL Primary emulsifier and wetting agent CONFI-MUL SA Suspension for fresh mud cDEEP-MOD Primary viscosifier – flat rheology additive cDEEP-TROL Filtration control CDEEP RM Secondary modifier CONFI-GEL HT cDEEP-THIN

Secondary viscosifier Thinner – rheology control

lime CaCl2 DRILL-BAR

Alkalinity Water phase activity, Aw Density

Concentration lb/bbl As required 7 - 13 1–3 1.5 – 3

Concentration kg/m3 As required 20 - 37 2.85 – 8.55 4.3 – 8.55

2–5 As required – pilot test 0–4 < 0.5 (as required) 8 As required As required

5.7 - 14 As required – pilot test 0 – 11.4 < 1.4 (as required) 22.8 As required As required

Table 7 General Formulation

Example CONFI-DEEP formulations (by density and SWR) with Saraline 185V Density – lb/gal 7.9 9.0 10.5 15.0 Products cDEEP-MUL – lb/bbl 13 13 13 13 cDEEP-MOD – lb/bbl 2 2 2 1 CONFI-GEL HT– lb/bbl 3 2 1.5 1 cDEEP-MUL SA – lb/bbl As required As required As required As required lime – lb/bbl 8 8 8 8 95% CaCl2 - lb/bbl 36 34 35 22 DRILL-BAR 61 153 394 Fluid Properties OWR 70/30 70/30 75/25 75/25 Rheology at 150 °F PV – cP 13 13 16 22 2 YP - lb/100 ft 20 20 16 25 6 rpm 13 12 12 15 HTHP filtrate, ml <4 <4 <4 <4 Table 8 CONFI-DEEP formulations (Product concentrations lb/bbl will vary with base fluid selection)

13

Section

11c


Example CONFI-DEEP formulations (by density and SWR) with Saraline 185V Density - SG 0.95 9.0 1.26 1.80 Products cDEEP-MUL – kg/m3 37 37 37 37 cDEEP-MOD – kg/m3 5.7 5.7 5.7 2.85 CONFI-GEL HT– kg/m3 8.55 5.7 4.3 2.85 cDEEP-MUL SA – lb/bbl As required As required As required As required lime – lb/bbl 22.8 22.8 22.8 22.8 95% CaCl2 - lb/bbl 103 97 100 63 DRILL-BAR 174 436 1123 Fluid Properties OWR 70/30 70/30 75/25 75/25 Rheology at 150 °F PV – cP 13 13 16 22 2 YP - lb/100 ft 20 20 16 25 6 rpm 13 12 12 15 HTHP filtrate, ml <4 <4 <4 <4 Table 9 CONFI-DEEP formulations (Product concentrations kg/m3 will vary with base fluid selection)

The following graphs, figure 3 plot the rheology of different fluid densities vs. temperature

CONFI-DEEP - Yield Point graph 30

YP, Ib/100ft2

25 20 15 10

7 .9 p p g ( s o lid f r e e ) 9 ppg 1 0 .5 p p g

5

15 ppg

0 40 F

70 F

120 F

150 F

Temp, deg F CONFI-DEEP - 6 rpm graph 20

6-rpm, DR

16 12 8

7 .9 p p g ( s o lid f r e e ) 9 ppg

4

1 0 .5 p p g 15 p pg

0 40 F

70 F

120 F

Temp, deg F

14

150 F

CONFI-DEEP -PV graph 90 80

PV, cP

70 60

7 .9 p p g ( s o lid f r e e ) 9 p pg

50

1 0 .5 p p g

40

15 p pg

30 20 10 0 40 F

70 1 F20 F

150 F

Temp, degF Figure 3 Rheology vs. Temperature and pressure CONFI-DEEP mixing procedure: ƒ Add the required amount of base fluid in the mixing tank. ƒ Add cDEEP-MUL to the base fluid at the required dosage. ƒ Mix cDEEP-MOD slowly in the mixing tank and shear thoroughly for proper dispersion to get viscosity. The use of a shearing device is recommended. ƒ Mix CONFI-GEL HT if required and continue shearing. Shearing is very important for viscosifiers to yield. ƒ Add lime ƒ Add prepared brine of the required salt concentration to the mixing tank. If brine is not available, bleed in water slowly running the hopper continuously while bleeding in the brine or water. ƒ Add CaCl2 powder if brine was not prepared. ƒ. Thoroughly shear the fluid to develop maximum emulsion stability and viscosity. ƒ Add cDEEP-TROL required for HPHT fluid loss control and continue shearing. ƒ If the desired viscosity has not been achieved in the mud plant due to low shear levels even with a dedicated device, add CONFI-MUL SA which will impart viscosity at low temperature with low shear in a low solids system. ƒ Load barite to get the desired density. ƒ Shear the system to get stable uniform properties. ƒ Bridging agents should not be mixed in the liquid mud plant (LMP) to avoid shear degradation. Bridging agents are best added in the field immediately before their use is required.

15

Section

11c


Field Trouble Shooting of the CONFI-DEEP system: Observation High PV

Possible Reasons ƒ Solid build up ƒ Inefficient or inadequate solid removal

High YP

ƒ Solid build up ƒ Water contamination ƒ Excess viscosifier

High Gels

ƒ High LGS ƒ High Solids ƒ Less concentration of cDEEP-MOD • In case Rheological parameters permit add cDEEP-MOD ƒ Poor emulsification • Mix cDEEP-MUL ƒ High concentration of organophilic • Dilute SBM with base oil and mix clays cDEEP-MOD • Mix cDEEP-MOD ƒ Reduction in cDEEP-MOD • Mix cDEEP-RM – Be careful to ƒ Reduction in cDEEP-RM ensure Flat rheology is maintained. Unstable emulsion Excess of organophilic clay may give temperature dependent rheology. • Mix cDEEP-MUL • Mix cDEEP-MUL ƒ Drop in concentration of cDEEP-MUL • Add cDEEP-MUL ƒ Weak emulsification or less • Mix cDEEP-TROL emulsifier in the system • Reduce solids as per “A” ƒ Less of Fluid Loss additive ƒ Less of clay in the system ƒ Solids build up • Check all water sources like taps on ƒ Surface water contamination surface – check drill floor cleaning ƒ Excessive shale dehydration • Bleed in base oil to increase OWR removing water from formation with concurrent treatment to maintain parameters • Observe shale cuttings for being very brittle & fragile due to excessive dehydration. Normal dehydration strengthens shale • Reduce WPS by dilution and treating the drilling fluid with proper additives

Non-Flat rheology

Low values of LSRV & YP

Low ES High HTHP Fluid loss

Decreasing Oil Water ratio

Table 10. Supplementary products for EXTRA-VERT systems

16

Recommended Treatment Check Shaker screens for holes Use finer screens Run Centrifuge in correct mode Dilute the system with base oil For solids as above Add base oil to get the correct OWR and to reduce viscosifier concentration • Same as “A” • • • • • •

opta-vert System Description OPTA-VERT is an invert emulsion DRILL-IN fluid that has been custom designed to provide minimal reservoir damage across of a wide range of porosities and permeabilities whilst laying down a filter cake readily removable on draw down. The system is custom designed for each individual reservoir and uses a range of high quality components and design tools to facilitate the design process including the HyPR-SIZER program which allows the concentration and particle size of the bridging agent to be optimized to ensure solids are deposited across the pore throat with minimal invasion while sealing off the reservoir with a thin and resilient filter cake. OPTA-VERT is recommended for reservoir drill-in applications with the raised potential for problems such as emulsion blocking associated with water based drilling fluids. Problems which OPTA-VERT minimises include: ƒ Wellbore instability caused by hydratable shales above or inter-bedded in the reservoir sands. ƒ Fluid instability due to high bottom hole temperatures. ƒ Excessive torque and drag related to high angle and extended reach drilling. The result is a system that provides strong benefits as a high performance, non-damaging drill-in fluid optimising production rates across a wide range of completion methods: ƒ Open hole gravel pack or non gravel pack completions. ƒ Expandable slotted screen completions. ƒ Slotted or perforated liner completions. ƒ Cased hole completions where hole cleaning or minimised fluid invasion is critical. The system is highly inhibitive and ideally suited to drilling reservoirs with shale interbeds. The OPTA-VERT system can be used to drill overbalanced by optimising the concentration of the bridging material to effectively seal new virgin formation as it is exposed by the bit, thus preventing losses. Benefits of the OPTA-VERT System include: ƒ Highly inhibitive ƒ Low filter loss ƒ Re-use ƒ Can be engineered on reservoir specific basis ƒ Rapid bridging ƒ Easily removable filter cake ƒ Filter cake has low lift off pressure ƒ Filter cake can be back produced through slotted liners ƒ Acid soluble filter cake

ƒ Re-use ƒ Can be engineered with environmentally friendly base fluids ƒ Simple to use ƒ Fluid properties are tolerant of solids ƒ Resistant to contamination ƒ Protection against corrosion ƒ Low dilution rates ƒ Can be formulated to relatively low densities

17

Section

11c


The advantages of the system must be considered along with the limitations: ƒ May require complex clean up procedures ƒ Cost of remediation ƒ Re use may lead to build up of drill solids content

ƒ High cost of losses ƒ High initial make up costs ƒ May have environmental restrictions

Formulation An example of an OPTA-VERT formulation and associated properties is shown in Table 11. All formulations must be engineered specifically for each reservoirs individual characteristics. Product Function Base Oil LP Base Fluid CONFI-MUL P Primary emulsifier CONFI-MUL S Secondary emulsifier CONFI-GEL Viscosifier calcium chloride Brine phase drillwater lime Lime OPTA-CARB Bridging & density

Concentration lb/bbl 0.65 bbl/bbl 6-8 3-4 4-6 15 0.12 bbl/bbl 10 10 – 55 as required

Concentration kg/m3 0.65 m3/ m3 11.4 8.55 – 11.4 11.4 – 17.1 42.75 0.12 m3/ m3 28.5 18 – 156 as required

Table 11. Example OPTA-VERT formulation Property Mud Weight PV YP 6 RPM SWR ES HTHP (@ Bottom Hole Temp °F)

Typical Value 9.1 26 21 13 85:15 1040 <4.0

Units lb/gal cP lbs/100 ft2 dial reading volts ml/30 min

Table 12. Typical OPTA-VERT properties A number of aspects of this formulation need to be highlighted. ƒ Note the relatively low concentration of emulsifier. The system is run with little or no excess emulsifier to minimise emulsion blockage in the formation. However, must be emphasised that the amount of emulsifier must be sufficient to ensure emulsion stability. ƒ Filtration control additives maybe restricted to prevent formation damage. In that case filtration control is provided by the emulsion and the concentration of bridging material. ƒ The concentration, particle size distribution and type of the OPTA-CARB bridging material, will be project and well specific. Engineering Guidelines Ensure that the emulsion remains stable, with low filter loss and no water break through. It is also imperative that there is sufficient bridging material of the correct size to ensure that the non damaging nature of the fluid. The drilling process will degrade the bridging material and some of the material will be removed by the shale shakers. New bridging material should be added to regularly to the circulating system to maintain the correct particle size distribution.

18

Mixing OPTA-VERT ƒ Add the required quantity of base fluid to the mixing tank. ƒ Add the primary emulsifier, CONFI-MUL P, and secondary emulsifier, CONFI-MUL S, as required. ƒ Add organophilic viscosifier, CONFI-GEL / CONFI-GEL HT, as required. ƒ Add required amount of water to the above mixture. If brine is to be used, then add brine after the lime additions. ƒ Add rheology modifier e.g. CONFI-MOD or CONFI-RM as required. ƒ Add lime as required. ƒ Add filtration control additives, CONFI-TROL, CONFI-TROL HT, CONFI-SEAL or CONFI-TROL F, as required. ƒ Add calcium chloride powder if brine is not used. If calcium chloride powder is not available, then mix the calcium chloride flakes into the water and add as a brine. ƒ Mix above for several hours to ensure a good emulsion is formed. ƒ If the formulation requires barite add the required amount. ƒ Add the bridging material e.g. OPTA-CARB as the final product. ƒ After the bridging material has been added it is advisable that shear in the mixing system is minimised to prevent the grinding of the bridging material. It is recommended that if logistically possible the bridging materials are not added to the fluid until it is needed e.g. immediately before entering the reservoir or after the casing / liner is drilled out. The shear available on most rigs is rarely sufficient to ensure that the organophilic clays have fully yielded. Once the fluid is sheared through the bit the rheology profile may increase. Filter Loss The HPHT should be run at the maximum expected bottom hole temperature. As there is a minimal concentration of emulsifiers in the fluid, the HPHT test should be run several times on each shift to ensure that the fluid remains within the required parameters. Density Initial density is provided by the OPTA-CARB in the system. Barite should be added only if the engineered bridging material is not sufficient to provide the required density. In order to minimise the amount of solids, alternative weight materials such as HAEMATITE, or for specialist applications, HYDRO-MAX, may be used. These weight materials will deliver fluids which have lower plastic viscosities than systems formulated with conventional barite. Rheology It must be highlighted that while drilling ahead there will be an increase in rheology as the organophilic clay yields. This is particularly true when new fresh mud is delivered to or mixed on the rig. Ensure that this increase in rheology does not become an operational problem, it must be controlled. The two principal methods of imparting rheology is by the use of the Organophilic clay, CONFIGEL / CONFI-GEL HT and or low end rheological modifiers. Optimise the effectiveness of organophilic clays, with the addition of CONFI-MOD and/or CONFI-RM. The use of these modifiers will provide a flatter rheology profile minimising the ECD. Note that overuse of rheology modifiers without sufficient underlying organophilic clay structure can promote barite sag, which is detailed in section 6b of this handbook, barite sag.

19

Section

11c


Oil Wetting Agents The use of oil wetting agents, CONFI-WET, and thinners, CONFI-COAT, should be avoided as the difference between product effectiveness and over treatment can be a very fine balance. The thinners act on the organophilic agents and destroy their effectiveness. Once a system is over treated it becomes difficult to re gain the rheology and the danger of sag becomes more pronounced. If a treatment of oil wetting agents is to be made to the circulating system, it is advisable that the treatment is pilot tested extensively beforehand to determine the correct treatment level. Emulsifier Emulsifier ensures that the invert emulsion is stabilised and aid in filtration control. The measurement of emulsion stability gives an indication of the condition of the emulsion. While drilling with the OPTA-VERT system the emulsifier concentration is minimised to prevent formation damage. Filtration Controllers The use of filtration controllers may be restricted when using the OPTA –VERT system. However, depending on fluid loss requirements OPTA-VERT systems may be formulated with the CONFITROL product range or blend of these products. Water Phase Salinity Refer to CONFI-DRILL. Non Standard Rig Site Testing The primary method of preventing damage is the use of bridging materials. The quantity and quality (particle size distribution) needs to be monitored. A number of additional testing regimes may be required. These include Test Pore Plug Test Calcium Carbonate Concentration Particle Size Distribution

Reason Bridging Efficiency Determine the quantity of bridging material Determine the size of the particles in the fluid

Equipment / Test PPA apparatus Non Standard Test Malvern Particle Size tester

These tests will determine the rate of depletion of bridging material in terms of quantity and quality which will allow addition of the required bridging material to the system while drilling ahead. Solids Control Equipment It must be highlighted that while the primarily purpose of solids control equipment is to remove drill solids, bridging materials will also be removed negating the non damaging nature of the fluids. A balance has to be struck between solids removal and controlling the effects of drill solids contamination by dilution. Fresh bridging agents are frequently added on a continuous basis to replace material lost through solids control equipment.

20

section 11d completion fluids

section 11d

Scomi Oiltools

clear brines

2

density

2

crystallisation point

5

environmental concerns

6

brine / formation water compatibility

6

cost

7

brine testing procedures

7

hse

8

engineering guide lines

9

filtration

10

corrosion inhibition

10

wellbore clean up and displacement

11

losses during completion

12

Section

11d

completion fluids

completion fluids

Clear brines are use to provide hydrostatic pressure control barrier both during the running of completion strings and during work over operations and are generally selected for non formation damaging characteristics.

clear brines The ideal fluid should be free from solids, polymers and compatible with the formation therefore clear brines are the preferred option. The selection of brine will be dependent on the following criteria: ƒ Brine density range ƒ Brine crystallisation point ƒ Fluid / formation compatibility ƒ Corrosion ƒ Local environmental rules ƒ Cost ƒ Availability Brines are classified by the valency of the cation into monovalent and divalent brines. Monovalent brines include: ƒ Potassium chloride ƒ Potassium formate ƒ Potassium nitrate ƒ Potassium bromide ƒ Sodium chloride ƒ Sodium bromide ƒ Sodium formate ƒ Sodium nitrate ƒ Caesium formate ƒ Caesium acetate Divalent brines include: ƒ Calcium chloride ƒ Calcium bromide ƒ Zinc bromide ƒ Zinc chloride ƒ Magnesium chloride Brines may be made from blends of these salts, however, divalent and monovalent brines should not be mixed, as this will result in co- precipitation. Typical blends are Sodium / Potassium Chloride and Calcium Chloride / Calcium Bromide.

density The density of brine depends both on the type and quantity of salt dissolved in water and all brines have a maximum concentration of salt (saturation) after which the salt no longer goes into solution.

Brine densities vary as detailed in Table 1 below: Brine Potassium Chloride Magnesium Chloride Sodium Chloride and Sodium Chloride Potassium Chloride Blend Calcium Nitrate Sodium Formate Potassium Bromide and Potassium Bromide / Potassium Chloride Blend Calcium Chloride Potassium Carbonate Sodium Bromide and Sodium Bromide/ Sodium Chloride Blend Potassium Carbonate Calcium Nitrate Potassium Formate Calcium Bromide and Calcium Chloride / Calcium Bromide Blend Caesium Formate / Caesium Acetate Zinc Bromide and Calcium Bromide Zinc Bromide Blend

Maximum Density lb/gal SG 9.7 1.16 9.9 1.19 10.0 1.20 10.5 11.1 11.5 11.7 12.8 12.7 12.8 12.9 13.3 15.4 19.7 20.5

1.26 1.33 1.38 1.39 1.536 1.52 1.53 1.54 1.59 1.85 2.36 2.46

Table 1 Brine density To determine the relationship between density and salt concentration a brine table must be consulted, as the mass balance equation does not apply to brines that are not fully saturated. Brine tables are detailed in Section 18, Salt Tables. It is imperative that the maximum temperature requirement (usually BHT) is quoted when specifying the fluid density requirements as there is significant volume, therefore density, variation with temperature in clear brines. As the temperature increases the fluid density decreases e.g. Calcium Chloride with a density of 11.0 lb/gal (1.32 SG) at 60 ˚F (15.5 ˚C) has a density of 10.5 lb/gal (1.26 SG) at 220 ˚F (104 ˚C). It is also important to know the minimum surface temperature the brine will be exposed to as high concentrations of some salts e.g. Potassium Chloride having crystallisation points (see below) > freezing point. In cold climates / winter conditions the maximum density achievable with the brine might be reduced. Brine selection for any application will be dependent initially on the ability to meet the density requirements at the maximum temperature in the wellbore. Factors to consider when calculate drilling fluid density include: ƒ type of fluid in use ƒ fluid column properties - dynamic or static ƒ if mud is circulating in well, has temperature and density steady state been achieved ƒ temperature gradient of well - uniform or variable Calculation of hydrostatic pressure at any point in the well is affected by the gradient of temperature increase to which the fluid is exposed in the earth. However in deep-water wells the gradient of temperature decrease to which the mud is exposed in the riser extending through the column of seawater must also be considered. When circulation is broken before or after a trip a near steady state may be interrupted and temperatures and pressures begin to change minute by minute. For this reason the following expressions can provide only serviceable estimates which may not apply when maintaining bottom hole pressure is critical to well control or circulating losses.

Section

11d

completion fluids

Specific comments important to understanding the significance of the following equation include: ƒ In a circulating well which has not reached a near steady state the fluid temperatures are in flux. ƒ As a near equilibrium or steady state temperature gradient is achieved during continuous circulation the flow line, temperature will generally be significantly above ambient conditions. Fluid temperature at wellbore will be less than BHT. ƒ Actual surface density and temperature at flowline should be used in the calculations. ƒ If BHT is used results will be conservative. If estimated BHCT is applied, calculated pressure will be increased. ƒ This simple mathematical treatment assumes a linear temperature gradient which may not reflect the actual well conditions. ƒ When drilling in cold water (deepwater Gulf of Mexico or in arctic waters for example) the cooling effect on riser may reduce flowline temperature to near 32 ˚F (0 ˚C). In these examples a separate calculation should be performed on the mud column contained by the riser. ƒ A carefully described computer model which considers temperature transfer across the tubulars, thermal conductivity of cased and open hole, thermal conductivity of the fluid, allows for changing temperature gradients when applicable, flow rate, and temperature change of fluid at bit nozzles will provide a more accurate estimate of pressure. The following expressions yield approximate corrections for density gain or loss. To calculate an average well temperature is straight-forward (BHT + ST) 2

Where BHT = bottom hole temperature (˚F) ST = surface temperature (˚F) AT = average well temperature (˚F) Using the previous calculation an average temperature increase can be calculated AT - ST = ATI Where AT = average well temperature (˚F) ST = surface temperature (˚F) ATI = average temperature increase (˚F) From the temperature increase and an estimated correction factor constant (Table 2) can be calculated change in density ATI x Cft = DDt Where ATI = average temperature increase (˚F) Cft = temperature correction factor DDt = change in density (lb/gal) due to temperature From previous calculations can be calculated average hydrostatic pressure (SD - DDT) x 0.052 x TVD = AHP 2

Where SD DDt TVD AHP 0.052

= surface density (lb/gal) = change in density (lb/gal) due to temperature = true vertical depth of well (ft) = average hydrostatic pressure (lb/in2) = hydraulic constant

From previous calculations can be calculated density change due to increase in pressure AHP x Cfp = DDP Where AHP = average hydrostatic pressure (lb/in2) Cfp = correction factor for pressure DDp = density change (lb/gal) due to hydrostatic pressure The average wellbore density resulting from the temperature gradient and hydrostatic pressure can then be estimated using the following equation: SD + DDt + DDp= DP Where SD = surface density (lb/gal) DDt = change in density (lb/gal) due to temperature DDp = density change (lb/gal) due to hydrostatic pressure Correction Factors Fluid Type NaCl or KCl CaCl2 NaBr NaBr / NaCl blend CaBr2 CaCl2 / CaBr2 blend ZnBr2 / CaBr2 / CaCl2 - 14 to 17.5 lb/gal ZnB2 / CaBr2 / CaCl2 - > 17.5 lb/gal

Temp 0.0024 0.0027 0.0033 0.0033 0.0033 0.0033 0.0036 to 0.0048

Pressure 0.000019 0.000017 0.000021 0.000021 0.000023 0.000023 0.000024 to 0.000031

Table 2 Brine correction Factors

crystallisation point As the temperature of brine is reduced the solubility of the salt is reduced and at a specific temperature salt crystals will begin to precipitate. The point at which the salt begins to precipitate is described as the crystallisation point. The precipitation of these solid salts will result not only in a density drop, with an impact on safe well control, but may also cause plugging in pumps and lines as the salt settles out. Four temperatures values are used to describe the crystallisation point: ƒ First crystal to appear (FCTA) ƒ True crystallisation temperature (TCT) ƒ Last Crystal to dissolve (LCTD) ƒ Pressure Crystallisation Temperature (PCT) The crystallisation point is also a determining factor in brine selection. For instance in cold environments and / or offshore operation, the temperature may be too low to allow particular brine or brine blend to be used as the operation temperature is below the crystallisation temperature. To provide a safe operating margin allow a 10 ˚F margin below the lowest crystallisation temperature of the brine.

Section

11d

completion fluids

Crystallisation - TCT for NaCl, KCl & CaCl2 70 60 50

KCl

40

CaCl2 NaCl

20 10

7

7 .3

8

.5 11

11

.1 11

1

2

.9 9 10

.8

.6 10

10

7

4 .4 10

.2 10

.1 10

93

76 9.

9.

60

44

9.

9.

28

13

9.

9.

84

98 8.

70

56

8.

8.

8.

42

0

0 -10

8.

CP (deg F)

30

-20 -30 -40 -50 -60

Density (ppg)

Figure 1: TCT GRAPH

environmental concerns In some locations the selection of brines may be limited due to environmental regulations on the use and / or disposal of the brine. These regulations may prevent the use of particular brines and / or limit the discharge to below a certain threshold concentration. In case of discharge restrictions, the use of the brine may be allowed if there is a remedial method such as total containment at the rig site.

brine / formation water compatibility Completion and work over brines will come into contact with the formation solids, fluids and gasses raising the possibility of chemical incompatibility, which will interfere with the passage of fluids to and from the well bore during production or injection activities. The most common incompatibilities include: ƒ Reaction of the brine with the shale formation causing shale swelling. ƒ Precipitation of iron compounds in the formation from iron dissolved in the brine. ƒ Formation of emulsions between the brine and hydrocarbon liquids in the formation. ƒ Scale formation from the reaction between the brines and dissolved solutes in the formation e.g. calcium brines with dissolved carbon dioxide. ƒ Co precipitation of salts when divalent ions in the formation mix with monovalent ions from the brine and vice versa. In order to ensure the compatibility of completion fluid the following tests can be used to evaluate compatibility. ƒ Return Permeability ƒ Brine and formation water compatibility test ƒ Formation mineralogy ƒ Chemical Analysis of formation water ƒ Produced fluid brine compatibility tests

It should be noted that in order for these tests to be valid, core and produced fluids from the nearest offset wells should be used for the test.

cost Cost may be a limiting factor as to the selection of clear brines, there being a considerable cost variation for brine types in particular the high density brines. If a brine can cover the density range, has a high enough crystallisation point, fulfils all the environmental regulatory requirements, is non corrosive, its selection may be precluded in the event that the cost is too high to make the project financially viable.

brine testing procedures Brine Density Although density of brine can be determined using a mud balance, a more accurate way to determine the density is by the use of a hydrometer. The density of an aqueous solutions is measured with a hydrometer. A hydrometer consists of a leaded weight encased in a long glass bulb and a calibrated scale on the top end of the bulb. When placed in an aqueous solution, the hydrometer sinks to a level that corresponds to the density of the solution. Figure 2 Hydrometer Set

Crystallisation Point The true crystallisation point can be determined using a Brine Crystallisation Kit.

Corrosion Rate of corrosion can be determined by the use of corrosion coupons.See section 12, Corrosion. pH It is recommended that pH be tested using strips as opposed to the use of an electrode type pH meter as the high electrolyte concentration in brines interferes with the meters accuracy. Solids Content Clear brines are free from solids; however they will pick up contamination when they are circulated down hole. To determine the level of solids contamination there are two test methods ƒ Centrifuge The sample is placed in a cell and the centrifuge is spun. Solids are reported as % solids. ƒ Turbidity Meter The brine is placed in a sample tube and tested on a standardised turbidity meter. The result is reported in Nephelometric Turbidity Units (NTU) and acceptable values will vary, generally being in the range of 40 – 200 NTU

Section

11d

completion fluids

It should however be highlighted that some dissolved ions will increase the turbidity of the fluid while not affecting the solids content. It is recommended that when the Turbidity is suspected to be due to dissolved ions, that the turbidity is tested after the brine is treated with concentrated hydrochloric acid.

hse It is important that the HSE issues associated with the use of brines are communicated to the rig crew and service personnel before the beginning of brine handling operations. High density brines have unique chemical properties and consequently should be handled in a different manner from conventional muds, especially for safety reasons. Personnel safety when handling these brine systems involves two basic aspects: 1. Education of all personnel 2. Proper Personnel Protective Equipment (PPE) Each person involved with the well site project must be aware of brine properties and how to handle these systems before brines are used on the rig site. People working with these brine systems must be aware of brine properties before the drill-in, completion, or workover actually begins. At the rigsite, they should wear the necessary safety equipment to perform the job. Proper preparation and teamwork during the job will ensure a safe effective operation. Toolbox talks should be given to all people that will be involved with the project. The topics should include: ƒ A description of the brine system and fluid properties that affect safety. ƒ Safety equipment on the rig, the reason it’s there, its location, when to use it and how to use it. ƒ Personal wearing apparel, why, when and how to use it, and how to maintain it. ƒ Specific safety procedures. Pre-spud meetings should be held between the operating company and all service companies involved. The service company personnel, as well as the regular crews, should be made aware of all the safety procedures and equipment needed. Safety and knowledge go hand in hand. Personnel armed with correct information, will be comfortable with the system, aware of the correct procedures, alert to any situation, and able to avoid potential pitfalls. Exposure To Skin As a general rule, brine solutions become more irritating to the skin as the density of the fluid is increased and/or the pH of the fluid becomes more acidic. Brines such as CaCI2 and CaBr2 can be extremely irritating to the skin and if not washed off and if contaminated clothing is not removed, skin burns can result. Monovalent brines are much less irritating to skin Brines should be washed off using soap and water as soon as possible especially as the more irritating brines will pull the moisture directly from the skin due to their hygroscopic properties. Remove contaminated clothing from the body as this will continue to cause irritation. Report all incidents of exposure and get qualified medical attention if the irritation is not relieved.

Exposure To Eyes Or Mucous Membranes Always wear appropriate eye protection. Heavy brines immediately irritate the eyes, mucous membranes and any cuts or scratches that are contaminated. Wash the affected area, immediately, with large amounts of water for a minimum of 15 minutes. Get qualified medical attention. Ingestion Consult the MSDS for response information. Induce vomiting if the victim is conscious. Do not induce vomiting if the victim is unconscious. PPE The type and amount of safety apparel to be worn will vary with the specific task being done. The following are the minimum recommended requirements:ƒ Use chemical splash goggles to seal against the skin around both eyes and protect the wearer from splashing at almost any angle as safety glasses with side shields and full face do not provide this full protection. ƒ Use plastic or rubber gloves, preferably with long arms, that will protect the hands. Cotton gloves should be worn over this type of glove to prevent the glove from tearing. ƒ Ensure that barrier and moisturising creams containing lanolin and/or glycerine. Barrier creams should be rubbed on the hands before putting on gloves. They are not a substitute for gloves. ƒ Wear steel toe rubber boots as leather boots will become stiff and shrink when saturated with heavy brines. ƒ Wear rubber or plastic aprons when lifting sacks of dry salt or other additives. ƒ The use of slicker suits or disposable coveralls is recommended for activities when splashing is probable, such as tripping pipe. ƒ Use disposable dust/mist respirators when mixing dry additives or salts. Rig Safety Equipment Ensure that eye wash fountains and drench showers are near to and working at each area of high activity.

engineering guide lines Completion / clean-up programs detail the requirements and pumping sequences for completion fluids including timing sequence and volumes of each specific fluid being pumped and any contingency pill requirements. Transport of Brine On occasion it may be possible to prepare the brine in town at a brine plant. Ensure the following: ƒ Tanks that the brine is to be mixed in are clean and dry. ƒ In order to reduced the cost of transport brine may be delivered as concentrated higher density liquor, and cut back at the rig site to the required density. ƒ Ensure the tanks are closed securely during transport. ƒ If possible it is suggested that the brine is pre-filtered prior to loading. This will reduce time at the rig site for filtration. ƒ Ensure all hoses used in the transfer are in good condition. ƒ Ensure that the transport personnel are aware of brine safety issues.

Section

11d

completion fluids

Rig Preparation Prior to mixing the brine or receiving the brine at the rig site the rig fluid system has to be clean. The degree of cleanliness will depend on the operational needs. It should be noted, pit and line cleaning can take as long as 20 – 30 hours of dedicated cleaning. Pits may be cleaned with water with soap or surfactant pills pumped through all lines and pumps. Ensure that the following areas are cleaned, dried and free from contamination. ƒ Flow line / return lines ƒ Process pits ƒ Pits ƒ Trip Tank ƒ Mud pits ƒ Mixing lines ƒ Transfer lines ƒ Area under the solids control equipment Other rig preparations considerations are: ƒ It is advisable that the pits be covered to prevent contamination of the brine by debris and or rain water. ƒ Ensure that the pits are not leaking. (Hydro testing is suggested). ƒ All gates should be sealed shut. ƒ Blank off all water pipes, to ensure that there is no inadvertent contamination of brine with water. ƒ If possible in order to prevent cross contamination of brine, it is advisable to only have brine on the rig during completion operations. ƒ Hold planning meetings to discuss the safety and operational issues where brine is concerned. ƒ Ensure hoses are in good condition and compatible with the brine. ƒ Ensure that other service personnel are aware of the type of brine to be used in order to ensure that their equipment is compatible.

filtration To ensure the non damaging nature of the brine after mixing or receiving brine it may be necessary to remove solids particles and or dirt. The most common method is to filter the brine. The two most common filtration mediums are: 1. Diatomaceous earth filter (DE) 2. Cartridge type filter. The two systems can be used in series with, initial filtration by the diatomaceous earth filter then a final polish through the cartridge type filter. Filters come in a range of sizes and can filter as low as 2 microns. Note filtration can reduce the density by as much as 0.2 lb/gal as solids and contaminants are removed. If higher density brine liquor has been supplied then It is advisable to filter the brine before dilution with water to the required density.

corrosion inhibition In order to reduce the possibility contamination due to corrosion of the metal surfaces on the tubular and the completion string the fluid may be treated with a variety of corrosion inhibitors as listed below:

10

Function

Product Name

Biocide 3 in 1 corrosion inhibitor Oxygen Scavenger Oxygen Scavenger for divalent brines pH Modifier

Isothiazolin COR-MUSCLE OX-SCAV OX-SCAV CA Caustic Soda

Typical Concentration lb/bbl kg/m3 500 – 1000 ppm 3 – 7 gal / 100 bbl 0.71 – 2.3 litres/m3 0.5 – 1 1.42 – 2.85 0.5 – 1 1.42 – 2.85 As required

Prior to treatment it is imperative that the compatibility of the products with the brine is confirmed. It is recommended that should filtration of the brine be needed then the inhibitor treatment is done after filtration as treatments may destroy the filtering mediums causing contamination of the brine.

wellbore clean up and displacement After the well has been drilled, and cased the standard procedure is to clean the casing with a sequence of clean up pills. If possible consideration should be given to cleaning the well before mixing or receiving brine. Care should also be taken not to contaminate any brine with the clean up pills. Clean up procedures and requirements vary depending on completion type and operator specifications. Clean up procedures can include the use of: ƒ Thinning pills ƒ Flocculating pills ƒ Wettability changing pills ƒ Surfactant pills (to clean up the well) ƒ Scrub pills ƒ High viscosity pills ƒ Low viscosity pills. These pills may be combined in sequence, usually in combination with scrapers, brushes and magnets installed in the drill-string. The pills are usually displaced at high pump rates with large volumes of water until the specified cleanliness level (NTU) is achieved and may include displacement to the completion brine as part of the clean-up circulating process. The following procedure outlines some requirements for brine displacement ƒ Develop a logistic and pit plan. Ensure there is enough volume available to fill the hole, process and active pits. Determine the number of stokes required for each part of the displacement. ƒ Discuss the plan with derrick man / pump man prior to operation. ƒ By pass the shakers. ƒ Hold a pre–job tool box talk with every one involved with operation. Discuss and highlight safety aspects of the operations and distribute a copy of the logistic plan. ƒ the drilling fluids engineer must monitor the displacement and trouble shoot any problems. ƒ If weighted fluid is being displaced out of the well with a lower density brine or water it is recommended that a 50 bbl (8 m3) displacement pill weighted to 2.0 lb/gal (0.24 SG) above the density of the brine system is pumped between the fluids. ƒ Pump as fast as operationally possible. ƒ Once the brine is 150 ft (45 m) above the bit begin rotating and reciprocating the drill string. ƒ When the interface is at surface divert the returns until the correct density is received at the flow-line. It should be noted that the interface can use up 50 % of the hole volume depending on the well geometry and porosity. Ensure that this is taken into account in planning required volumes and pit space requirements.

11

Section

11d

completion fluids

losses during completion Down hole losses may occur during completion or workover operations such as perforation, pulling of tubing, pulling of completion, injectivity tests and during cycling of pumps to set balls or close valves. As clear fluids are solids free the loss rates may be larger than with fluids containing solids. Ensure that there is a loss circulation plan developed and included in the operation plan, if losses are a potential hazard. This plan should include what loss rate and loss of time is acceptable before remedial action becomes necessary as well as which technique should be used. Technique to cure down hole losses include ƒ The lowering of the hydrostatic over burden ƒ The use of viscosified solids free loss circulation pills ƒ The use of pills containing sized solids ƒ The closure of down hole valves ƒ Setting of packers The type and cause of loss will determine which method is used to cure the losses. When using a loss circulation pill during completion and work over operations it is imperative that the pill is non-damaging and formulated from material which can be produced back or broken down by a wash treatment e.g. Perchlorate or acid and alkali washes. Solids Free Viscosified LCM Pill A pill may be formulated by blending 1- 5 lb/bbl (2.85 - 14.25 kg/m3) of HEC-TOR in brine. LCM Pills It is recommended that an optimised OPTA-FLO pill is used as a lost circulation pill. A typical pill consists of a viscosified brine with a sized calcium carbonate or marble. Product

Function

OPTA-ZAN OPTA-CARB , 5, 25, 50 & 100

Clarified Viscosifying Polymer Bridging Agents

Concentration llb/bbl kg/m3 1–2 2.85 – 5.7 30 – 50 85.5 – 142.5

Other bridging agents that may be used include Sized Salts and Oil Soluble Resin.

12

corrosion

corrosion

section 12

section 12

corrosion

section 12

Scomi Oiltools

corrosion defined

2

why does corrosion occur?

2

what environments assist corrosion?

2

main types of corrosion

2

main causes of corrosion

3

main types of corrosion inhibitor

3

mode of operation of corrosion inhibitors

4

the effect of pH on corrosion of metals

5

controlling corrosion in wbm with film-forming

products

6

measurement of corrosion rate

7

corrosion coupon / rings

8

interpreting corrosion coupon analysis

8

Section

12

corrosion

corrosion

corrosion defined Corrosion is the destruction of any substance, particularly metals, by a reaction with its environment. Corrosion cannot be stopped, only controlled. Safety and economics are the main considerations when implementing a corrosion control programme.

why does corrosion occur? Most metals occur in nature as reacted ones e.g., haematite, iron oxide or pyrites, iron sulphide. The production of pure metal from these ores requires a large input in energy, thus the pure metal is unstable and is always trying to return to a low energy ore state. Corrosion is therefore an electrochemical process.

what environments assist corrosion? For corrosion to occur, three conditions must be satisfied; ƒ Obviously the metal must be present, e.g. iron. ƒ A conducting medium must be present, e.g. Brine. ƒ A dissolved gas must be present, e.g. oxygen. If any of these three are missing corrosion will not occur. The presence of all three will allow the following reduction - oxidation reactions to take place. OXIDATION Fe -> Fe2+ + 2e- REDUCTION 02 + H20 + 4e- -> 4OH-

ANODE CATHODE

The hydroxyl ions will combine with the ferrous ion to produce ferrous hydroxide with subsequent metal loss from the anode surface.

main types of corrosion There are many types of corrosion, but of particular interest in connection with the use of drilling fluids, particularly water based fluids, are: Uniform Corrosion This is the most common and desirable form of corrosion caused by continuous shifting of anode and cathode sites resulting in a uniform metal loss over the entire metal surface. Pitting Corrosion One of the most destructive forms, caused by permanent location of anodic and cathodic sites. Since anodic sites are small in area, this results in the formation of deep pits on the surface at the anodic sites which ultimately penetrate the metal causing washouts and possible twist-offs. Crevices Corrosion Crevices in metal surfaces e.g., tool joints, allow entrapment of fluid which then changes its composition producing an anodic site where corrosion is concentrated, often resulting in tool joint failures. Stress Corrosion When a metal is subjected to stress, such as at a tool joint by over torquing, the stressed area becomes anodic and corrosion is concentrated in that area resulting in failures.

Hydrogen Embrittlement This type of corrosion is seen particularly when hydrogen sulphide is present. The absorption of atomic hydrogen into the crystal structure of the metal, via intergranular crevices, and the subsequent combination of hydrogen atoms to form hydrogen molecules, results in embrittlement of the metal and a loss of tensile strength and ductility.

main causes of corrosion The main contributors to corrosion in water based muds are as follows. Dissolved and Entrapped Oxygen By far the most common cause of corrosion, levels as low as 1 ppm can substantially increase corrosion rates. The higher the oxygen concentration the faster the rate of corrosion. Oxygen from the atmosphere is incorporated into the system, especially at the shakers, and via mixing hoppers. It is a potential problem especially with low solids, high yield point polymer systems. As the mud is pumped downhole, the temperature rises, oxygen comes out of solution and directly reacts with the metal surfaces. Carbon Dioxide If the pH of the mud is allowed to fall as the result of carbon dioxide intrusion, carbonic acid will be produced which will directly attack metal surfaces and in the presence of dissolved oxygen the rate of corrosion will be greatly increased. The type of corrosion occurring will be predominantly pitting so every effort should be made to prevent or redress a pH drop. The source of carbon dioxide is redominantly from formations, but may be as a result of the thermal decomposition of mud additives such as organic polymers. Hydrogen Sulphide The presence of hydrogen sulphide, even in very small quantities and particularly in the presence of dissolved oxygen, may give rise to catastrophic failures of drilling equipment. The source of H2S is often the formation itself but may be caused by thermal degradation of drilling fluid additives containing sulphur such as lignosulphonates, or by the action of sulphate reducing bacteria (SRB) on sulphate scales under anaerobic conditions. Soluble Salts In combination with dissolved gases soluble salts will invariably increase corrosion rates due to increased conductivity of the fluid phase up to a limiting point. Above this point an increase in salinity may reduce corrosion rates due to lower oxygen solubilities. For example the most corrosive concentration of sodium chloride occurs when the chlorides reach approximately 20,000 mg/l (roughly equivalent to seawater).

main types of corrosion inhibitor The two primary types of corrosion inhibitor are oxygen scavengers and film-forming amines. Chromate and phosphate derivatives have also been used. Other types of chemical which are added to mud systems primarily to combat different problems but which assist in the prevention of corrosion are hydrogen sulphide scavengers, biocides and scale inhibitors. Control of pH also provides corrosion inhibition.

Section

12

corrosion

mode of operation of corrosion inhibitors oxygen scavengers Most commonly these are simple chemical compounds such as sodium sulphite or ammonium bisulphite, OX-SCAV, OX-SCAV S, which dissolve into the drilling fluid to provide an ion in a reduced state, in these cases sulphite, which will then react with dissolved oxygen in the mud to produce a stable ion, in these cases sulphate, resulting in the permanent removal of oxygen from the fluid. The main advantage of this type of product is that it removes the primary cause of most types of corrosion; very little corrosion can occur in the complete absence of oxygen, the exception being hydrogen sulphide induced corrosion. The major drawback of oxygen scavengers is that they also scavenge atmospheric oxygen when the fluid is in contact with air. For this reason, the best results are obtained when an injection pump is used to add oxygen scavenger to a mud system in order to prevent the chemical reacting with air before it can react with dissolved oxygen in the mud. Air is continually being mixed into circulating mud systems, particularly at the shale shakers and at the hopper and therefore oxygen scavenger needs to be added on a continual basis which can lead to high treatment costs. Normal practice is to measure the concentration of the scavenger at the flowline and to maintain an excess of scavenger at all times. For foam and mist drilling, it is usually economically impractical to add oxygen scavenger. film-forming amines These are solutions of organic amines, HYDRO-FILM and HYDRAMINE, which, due to their charged nature, are attracted to metal surfaces forming a film on them. This film acts as a barrier between the metal and the dissolved oxygen in the mud. This barrier formation is the main advantage of this type of product as no other product can achieve the same effect. Some disadvantages do however exist. If insufficient material is added to completely coat all metal surfaces, corrosion cells can be set up between protected and unprotected metal surfaces which can actually enhance corrosion. Most film-forming amines are not soluble in water therefore they must be applied as a solution in oil/base fluid or some other organic chemical as a carrier. As a result, large treatments can have an adverse effect on drilling fluid rheology and it may be undesirable / impossible to add the carrier to a system for environmental reasons. chromates/phosphates These chemicals have been used in the past primarily in mist and foam drilling where it is not possible to use oxygen scavengers. These inhibitors work by chemically interfering with the electrical current necessary to form corrosion cells. With present levels of concern about the environment, chromium compounds are now seldom used and they have been largely replaced by phosphates. Phosphate inhibitors are most effective in low pH, fresh water systems and solids free systems where field evidence has shown that a concentration of between 70 and 120 mg/litre is effective in controlling corrosion. hydrogen sulphide scavengers H2S has long been recognised as a major contributor to corrosion and a variety of products exist to remove hydrogen sulphide from a mud system. The majority are based on zinc and work by releasing zinc ions into the mud which then react with sulphide ions, removing them from the system as insoluble zinc sulphide. Some iron compounds have been used but these can promote abrasion due to their hardness and their high density makes them difficult to suspend.

Typical zinc-containing products are zinc carbonate, zinc oxide and zinc chelates. The carbonate and oxide are relatively insoluble which leads to a fairly slow reaction rate. Zinc chelates are the most efficient scavengers in terms of reaction rate as they are supplied as solutions and the dissolved zinc ion is immediately available for reaction with any sulphides present. biocides Micro-organisms contribute to corrosion in different ways. Some utilise any available hydrogen and act as cathodic depolarisers, creating corrosion cells while others form slimes or growths which shield a portion of the metal and form an oxygen concentration cell. In aerobic environments, the species thiobacillus accounts for the majority of the corrosion by converting sulphur to sulphuric acid which stimulates corrosive attack of metals. Sulphate-reducing bacteria are found in anaerobic environments. These bacteria contribute to corrosion both by direct attack of iron by hydrogen sulphide, produced by the bacteria, to form iron sulphide and by cathodic depolarisation. Even in aerobic systems, sulphate-reducing bacteria may be found within active corrosion pit areas where the oxygen content becomes low. Broad-spectrum biocides, Isothiazolin and Glutaraldehyde are usually employed in drilling fluids so that a single treatment is effective against all likely species. Drawbacks of biocides are that they tend to be expensive and many are adversely affected by temperature, salt concentration and other treatment chemicals. Compatibility tests with the other mud chemicals should be conducted for all biocides prior to use. scale inhibitors A very wide variety of chemical types are used as scale inhibitors, a typical one being an aqueous solution of polyacrylate. All these chemicals function by interfering with the deposition of scaling compounds such as sulphates and carbonates onto the metal surfaces. These chemicals have a limited ability to protect metal surfaces. They can however make some contribution to preventing corrosion although none are likely to be as effective as purpose designed corrosion inhibitors.

the effect of ph on corrosion of metals pH is the measure of the hydrogen ion concentration in an aqueous system. As hydrogen ions are in equilibrium with hydroxyl ions the pH can be seen to be directly related to the concentration of both ions. Hydrogen ions and hydroxyl ions can both play a major part in chemical reactions which result in corrosion of metal although the relationship between pH and corrosion is complicated. The importance of the hydrogen ion lies in its ability to interact with a metal surface. Many metals form an oxidised surface region, the outermost atomic layer of which often contains hydroxidelike species when water is present. Such a structure would tend to have a dependence on hydrogen ion concentration. Thus, under a number of conditions, the hydrogen ion concentration can influence corrosion through the equilibrium that exists between it, water and the hydroxide ion formed on the metal surface. This interaction often results in a corrosion rate which is proportional to the hydrogen ion concentration. As pH is measured on a logarithmic scale, this dependence can produce a ten-fold increase in the rate of corrosion for a change of 1 in pH.

Section

12

corrosion

Iron and carbon steel exhibit a complex dependence of the corrosion rate on pH. At low pH, the rate of corrosion is dependent not only on the hydrogen ion concentration but also on the counter ions present. For example, the corrosion rate of steel in sulphuric acid at pH 3 is not the same as in hydrochloric acid at the same pH. Under near-neutral conditions (5< pH <9), pH does not in most cases play a direct role in corrosion. Under more strongly acidic conditions, the oxide or hydroxide layers tend to dissolve thus exposing fresh metal for attack. At pH levels near neutral, these layers tend to remain on the surface. The layers have significant structure which tends to be determined by the anions present in solution. Under these circumstances, the major reaction governing corrosion is the reduction of oxygen present in solution. The oxygen ions produced as a result of this reduction then attack metal surfaces. The presence of chloride ions and oxygen play a much more dominant role than pH under these conditions, possibly changing the mechanism from one of uniform attack to localised attack. Under near-neutral conditions, the use of an oxygen scavenger is one of the most effective ways to combat corrosion. Under more strongly alkaline conditions (pH >9), corrosion mechanisms are somewhat different. The main mechanism being the formation of soluble metal hydroxides which because of their solubility, continually expose fresh metal to attack. Metals or alloys which are resistant to corrosion at high pH levels are usually those which form an insoluble hydroxide layer which then protects the metal beneath it. In a number of cases, corrosion rates increase with increasing pH while in others, corrosion occurs where none was present at lower pH. These two types of behaviour represents most metals and alloys. Corrosion of iron persists even at high pH and is caused by the formation of soluble iron tri-hydroxide particularly in the presence of sodium hydroxide. A number of metals exhibit a very marked increase in rate of corrosion with increase in pH. Among these are aluminium, zinc and lead. Aluminium corrosion increases very dramatically, increasing by almost two orders of magnitude between pH 8 and pH 10. In summary, pH has a direct effect on rates of corrosion at both high and low values. Under these strongly acidic or alkaline conditions, corrosion can be very severe although it should be remembered that other factors such as anion type and concentrations can exacerbate or ameliorate this effect. At intermediate pH values the concentration of oxygen in the system has a much greater effect on corrosion rate than the direct effect of pH.

controlling corrosion in wbm with film-forming products Corrosion can be a severe problem when drilling with water-based muds in certain environments. Recognition of the causes of corrosion has led to the development of numerous techniques for its control. It is well known that environmental compounds such as oxygen, carbon dioxide, hydrogen sulphide and dissolved salts accelerate rates of corrosion. Techniques used to offset the effects of these components include dilution, concentration, precipitation, neutralisation and chemical inhibition. The use of chemical corrosion inhibitors is an example of the last of these techniques. Water-based muds present corrosion problems primarily because they are subject to contamination from corrosion accelerators such as oxygen, carbon dioxide, hydrogen sulphide or salts that are always present in varying quantities. A recent study has, for example, correlated the amount of pitting corrosion with oxygen contamination. Examination of the corrosion by-products has in many cases revealed oxides of iron, clearly indicating the involvement of oxygen in surface corrosion.

Film-forming organic amines are frequently used as corrosion inhibitors. These anionic materials adsorb strongly onto metal surfaces creating a film which prevents the contact of oxygen and other gases with the metal, thus preventing corrosion. Experience has shown that these chemicals are ineffective at low concentrations as partial coverage of metal surfaces leads to the development of concentration cells. Ionic concentrations on the metal surface underneath the inhibitor film will be different from the concentrations on untreated metal surfaces and where the two meet, a corrosion cell will be set up. Under these conditions, localised corrosion rates can exceed those which would prevail if no inhibitor was added. In fluids contaminated with oxygen (i.e., most muds), concentration cells act as serious pitting accelerators. The presence of scale or other barriers on metal surfaces can have the same effect. Film-forming amines are most effective when applied as a solution in oil directly to the metal surface. In one study, a corrosion rate of 455 mils per year, mpy, while drilling with untreated mud was reduced to 88 mpy by pumping 4 gallons of amine inhibitor down the drill string every 30 minutes while drilling. Because film-forming amines have the ability to displace water in surface pitting and cracks, they are extremely useful in drilling fluid environments. One major drawback of this type of chemical is that they will adsorb strongly on the surfaces of solids in the drilling fluid (both barite and drilled solids) and thereby lose their effectiveness as inhibitors for metal surfaces. Because of their ionic character, these products can also have a detrimental effect of drilling fluid rheology if added directly to the mud in significant quantities. Film-forming products are effective against hydrogen embrittlement as well as preventing oxygeninduced corrosion. High strength steel under conditions of stress (e.g., rock bit bearings) is particularly susceptible to hydrogen embrittlement and such steel has been known to fail in as little as five hours when drilling in hydrogen sulphide contaminated mud. Failure occurs as hydrogen gas penetrate the metal surface, enters the lattice of metal atoms and weakens the whole structure as a result. A protective film of organic amine on the surface of the metal has been shown to greatly prolong the life of steel in a hydrogen-rich environment. Alternative products are now being produced as filming inhibitors which are non-ionic in character. They still have a preference to adsorb onto metal surfaces, thus providing the protective film but have a greatly reduced affinity for other solid surfaces and are also designed to spread evenly on the metal surface, thus preventing the setting up of localised corrosion cells. These products are chemically modified amines which have been reacted with functional groups to give the molecules surfactant as well as filming properties. This ensures that the build up of molecules on metal surfaces occurs evenly, one layer at a time, thus preventing partial or incomplete coverage. At concentrations below those required to achieve a uniform mono-molecular layer, the product does not function as a corrosion inhibitor.

measurement of corrosion rate Methods of monitoring corrosion fall into two basic categories. Direct measurement of corrosion taking place can be achieved by the use of corrosion coupons, see below for detailed discussion. Levels of corrosion inhibitors / corrosive species in the drilling fluid can be monitored by chemical means. Meters for measuring the concentration of dissolved oxygen are now available although their suitability for use directly in solids-laden drilling fluids is still not fully proven. Corrosive components in the mud can be measured by the Garrett Gas Train, hydrogen sulphide, carbon dioxide, and bacteriological test-kits, to gain an indirect indication of likely corrosion potential. Sulphite based oxygen scavengers can be measured in muds using a sulphite test-kit.

Section

12

corrosion

corrosion coupon / rings The placement of corrosion rings in the drill string yields critical information about the corrosive nature of drilling muds. This is particularly valid since the entire mud system circulates through the ring in the drill string. Examination of scales, pits or general attack aids in the choice of corrective action. The drawback of this test method is that long term exposure, minimum 40 hours, is required and accurate analysis is not usually feasible at the well site. Data obtained is extremely useful in devising long term corrosion control programmes but does not provide data for daily scavenger / inhibitor requirements. The corrosion ring is machined to fit in the tool joint box recess. The inside diameter should be the same as that of the tool joint to minimize turbulence. Unless clearly noted to the contrary the ring will be of AISI 4130 composition of steel. The ring will be clearly marked with an identification number. An important information record accompanies each corrosion ring. This takes the form of a packaging envelope which comes marked with the ring identification number, the initial weight of the ring and the calibration “K FACTOR” number. Note: This information record should remain associated with each individual ring. If it is lost any quantitative data on the ring becomes useless. For best results the corrosion ring should be exposed to a minimum of 40 hours of mud circulation. If at all possible more than one ring should be placed in the drill string. One ring is usually placed in the tool joint at the top of the first stand above the drill collars. An additional ring should be placed in the kelly saver sub. However, when top drives are used the only place a coupon can be put is in the goose neck. Care should be taken to insure that the box recess is clean to prevent interference with proper make up of the joint and to avoid damage to the ring. During installation the ring should be handled with clean, dry gloves. The corrosion ring information record must be filled out with the conditions prevalent when the ring was placed in the drill string. This should include drilling fluid composition, location of the ring in the drill string, hole depth in, date in, time in, well location, operator and any other required information. When the corrosion ring is removed from the drill string, drilling fluid residue should be removed from the coupon by wiping with a cloth. The ring should be visually examined for severity of corrosion or mechanical damage. If severe corrosion is evident the cause of the corrosion should be determined promptly so corrective action can be taken. Following the visual observations, immediately coat the coupon with oil or grease, do not use pipe thread compound. Place the ring in a plastic bag then in the envelope, and return to the lab for evaluation. Complete the information record for that numbered ring. This should include the drilling fluid composition, hole depth out, date out, time out, visual observations and total exposure time in the drill string.

interpreting corrosion coupon analysis Upon receipt of the corrosion coupons in the laboratory they will: ƒ Be tested for the presence of sulphide / carbonate scale. ƒ Be cleaned and re-weighted to determine the corrosion rate. ƒ Be microscopically inspected for the presence of pitting corrosion.

The corrosion rate based on weight loss is calculated as follows: Oilfield units Corrosion rate, lb/ft2 /yr =

S.I units Corrosion rate, kg/m2 /yr =

Mils per year, mpy = 24.6 x lb/ft2 /yr

Mils per year, mpy = 5.03 x kg / m2 / yr

K = constant printed on the corrosion ring envelope. The results obtained will be reported back to the company representative onshore and the mud engineer on location together with conclusions as to the severity of the problem and recommendations as to remedial action. The severity of uniform corrosion rates are characterised as follows: Corrosion Rate (lb/ft2 /yr) 0 - 2 2 - 4 4 - 6 > 6

Corrosion Rate (kg / m2 / yr) 0 - 0.4082 0.4082 - 0.8164 0.8164 - 1.225 >1.225

Severity Low (acceptable) Moderate High Severe

The presence of pitting corrosion, regardless of the uniform corrosion rate, indicates a severe problem and, after determining its cause, should be acted upon without delay. Treatment chemicals should be on standby and used at their recommended dosage levels.

corrosion coupon analysis The corrosion rate based on weight loss is calculated as follows:

Oilfield units Corrosion rate, lb/ft2 /yr = Weight Loss (grams) xK Exposure timre (hours)

S.I units Corrosion rate, kg/m2 /yr = [0.2041 x Weight Loss (grams)] xK Exposure time (hours)

Mils per year, mpy = 24.6 x lb/ft2 /yr

Mils per year, mpy = 5.03 x kg / m2 / yr

K = constant printed on the corrosion ring envelope. The results obtained will be reported back to the company representative onshore and the mud engineer on location together with conclusions as to the severity of the problem and recommendations as to remedial action. The severity of uniform corrosion rates are characterised as follows: Corrosion Rate (lb/ft2 /yr) 0 - 2 2 - 4 4 - 6 > 6

Corrosion Rate (kg / m2 / yr) 0 - 9.8 9.8 - 19.6 19.6 - 29.4 > 29.4

Severity Low (acceptable) Moderate High Severe

The presence of pitting corrosion, regardless of the uniform corrosion rate, indicates a severe problem and, after determining its cause, should be acted upon without delay. Treatment chemicals should be on standby and used at their recommended dosage levels.

hydrates section 13

hydrates (deepwater drilling)

section 13 hydrates (deepwater drilling)

section 13

Scomi Oiltools

physical characteristics

2

hazards

3

seafloor instability

3

borehole instability

4

gas release

4

hydrate formation

4

free gas

5

other concernss

5

detection

5

before drilling

5

during drilling

6

mitigation

7

geological interpretation

7

casing design

7

cement design

7

pressure regulation

7

mud temperature regulation

7

drilling fluid additives

7

non aqueous fluids

8

bits and bha

9

drilling parameter

9

special equipment / requirements

9

Section

13

gas hydrates (deepwater drilling)


physical characteristics A gas hydrate is a crystalline solid, similar to ice, except that the crystalline structure is stabilised by the guest gas molecule within the cage of water molecules. Hydrates are part of a group of substances known as clathrates which is Latin for “to enclose with bars”. Hydrate Structures:

Although most marine hydrates that have been analysed are methane hydrates, C2, C3, C4, H2S and CO2 are also known to produce hydrates with water. Hydrocarbons larger than nC5 cannot form hydrates with water because of limited host molecule cage size. Heavy hydrates (e.g. nC4) form hydrates first (at lower pressures and higher temperatures), in preference to lighter components (e.g. C1). Gas hydrate formation is an exothermic process. Hydrates form as either: ƒ Finely disseminated particles interspersed within the sediment acting to cement the pore spaces of sediment; or ƒ Concentrated bands (layers or nodules) interspersed with hydrate-poor, anomalously dry layers. May resemble ice-like rods or blobs. Accumulations may be several hundred metres thick. They also appear to have the capacity to fill sediment pore space and reduce permeability so that hydrate-cemented sediments act as seals for gas traps. Hydrates are a gas concentrator. The BCC (body-centred cubic) crystal structure of methane hydrates allows a volume ratio of 160:1 methane to water.

Concentration occurs at depocenters (thickest part of sediment), probably because most gas in hydrate is from biogenic methane. Therefore it is concentrated where there is a rapid accumulation of organic detritus (from which bacteria generate methane) and also where there is a rapid accumulation of sediments (which protect detritus from oxidation). Hydrates are found in marine sediments on the continental slope and rise, and in the arctic permafrost under specific pressure and temperature regimes known as the gas HSZ (Hydrate Stability Zone). Whether or not gas hydrate actually forms depends on the amount of gas available. HSZ can be identified on seismic reflections by the BSR (Bottom Simulating Reflector). HSZ can be effected by: ƒ Pressure and temperature conditions - an increase in water temperature changes the location of the HSZ so that the gas hydrate may become unstable and dissociate in certain areas. Underlying free hydrocarbons would then vent to the sea floor. ƒ Gas composition – specific gravity can effect the pressure/temperature range over which hydrates are stable. ƒ Liquid-phase composition – solutes may act to depress the hydrate formation temperature at a given pressure. Several factors can lead to changing pressure/temperature conditions, potentially causing gas dissociation: ƒ Drilling operations ƒ Sediment and mud re-deposition (earthquakes, volcanic eruptions, gravity slides) ƒ Interglacial/glacial conditions (removal of ice will decrease pressure and increase temperature) ƒ Sea-level rise and fall ƒ Enrichment by longer chain hydrocarbons ƒ Aeolian winter cooling and summer heating conditions Dissociation can be explosive if pressure and/or temperature change too quickly (e.g. Barents Sea). Hydrates can occur in water depths beyond 300m, depending on temperature and pressure conditions. Hydrates may occur up to 1000m below the seabed. Theoretically, the presence of other gasses (C2 and higher) may extend the Hydrates Stability Zone (HSZ) to higher temperature and/or lower pressure conditions. Large hydrate deposits that formed from gas in deeper reservoirs will occur from the lower limit of the HSZ upwards. Shallower deposits may also occur due to gas vents or fractures or from the generation of biogenic gas within the seabed. Apart from the pressure/temperature conditions required for the formation of gas hydrates, the distribution of gas hydrates may be largely controlled by structural and stratigraphic factors. A source of biogenic gas and a migration pathway are both fundamental for formation of the hydrates.

hazards seafloor instability Mud volcanoes may result from hydrate dissociation and subsequent flow of fluid towards the seafloor. They are a potential problem since soil in the crater is very unconsolidated and could be filled with hydrates. They may also be (periodically) reactivate. Dissociation of massive hydrates leaves a formation that offers less support to any sediments or structures above including the rig, anchors, wellhead and well foundations. For example, landslides may occur on the steep continental slopes where hydrates occur.

Section

13


High weight of the subsea wellhead and BOP on formations weakened by hydrate dissociation may cause buckling of the conductor.

borehole instability Hydrate saturated layers are characterised by an extremely low permeability that prevents infiltration of drilling mud and the formation of a mud cake. The absence of a protective layer opens the gas hydrate deposits to temperatures above hydrate equilibrium and to chemically active solutions. This results in hydrate decomposition. Decomposition of hydrates may be accompanied with a sharp weakening of intergranular bonds and fluidising of a part of the rock allowing ejection in to the well. This process, accompanied by an intensive formation of caverns and shearing rock, may cause seizing of tools, hole fill, stuck pipe and hole washouts.

gas release Intensity of hydrate decomposition and gassing of a drilling mud are determined mainly by the excess temperature of drilling mud above the equilibrium temperature of hydrate in a layer. An unknown and changing kick volume due to hydrate dissociation must be considered. Gas evolving from hydrates at high pressure results in an intensive saturation and ejection of drilling mud from the well. Potential exists for liberation of gas from the hydrates at or below the seabed prior to setting conductor or surface casing. Risk to rig is limited in deepwater. Volume changes associated with thawing and formation of hydrates may cause very high collapse pressure on tubulars (casing and conductor). Hydrates behind casing may dissociate, migrate up and generate extra annular pressure on tubulars (casing and conductor) well above the hydrate zone. This is possible because there is not necessarily a seal above a hydrates layer. It can be a problem if surface casing/conductor is not designed to withstand these annular pressures. Little is known about blow-outs from solid hydrates. The production potential of hydrates is probably quite low, and any blow-out would probably stop without intervention within a relatively short period. During cementing, the cement hydration heat may dissociate hydrates in the borehole wall and cause gas channelling and bad cement bond. Hydrate cuttings may accumulate in mud tanks, slowly releasing gas as they dissociate.

hydrate formation Gas, originating from hydrate dissociation or from a bad cementation of a deeper zone, could percolate up possibly reforming. Formation of gas hydrates during deepwater drilling operations can lead to a number of problems: ƒ Choke and kill-line plugging which prevents their use in well circulation ƒ Plug formation at or below the BOP which prevents well pressure monitoring below the BOP ƒ Plug formation around the drillstring in the riser, BOP or casing which prevents drillstring movement

ƒ Plug formation between the drillstring and the BOP which prevents full BOP closure ƒ Plug formation in the ram cavity of a closed BOP which prevents the BOP from fully opening ƒ During periods of no circulation (or low circulation) hydrates may form which restrict/prevent mud circulation Hydrates require several hours to form and to plug subsea equipment, however, once they form a plug they will not move under an applied pressure differential. As hydrates form they draw water out of the drilling fluid leaving solids that may form a plug or block.

free gas It is possible that the presence of has hydrates may be acting as a seal to underlying hydrocarbons. These hydrocarbons may vent at the seafloor at the location of pock-marks. If free gas from below hydrates is encountered and blows out, the consequences can be more serious. The course of the incident will be similar to a “normal” shallow gas blow-out, with very high flow rates and potential loss of well.

other concerns Concentrated methanol is acidic (pH ≈ 5). Destruction of concrete or cement stones becomes noticeable at pH ≤ 6.5. The destructive action of methanol increases under pressure. Dissociation of hydrates into gas and water can be a slow process depending on heat transfer and crystal structure. For drilling activities this means that hydrates may occur in an environment outside the pressure/temperature stability zone. In this case the danger exists that no precautions are taken.

detection before drilling 1) High resolution seismic surveys in conjunction with 3D interpretation. 2) Anomalous pore-water sulphate gradients may be a potential indicator of gas hydrates in deepwater sediments. Reaction of sulphate with gas from hydrates results in pore waters that are partially depleted with sulphate relative to their environment. 3) Anomalous low salinity in seabed sediments provides a good indication of hydrate presence. Upon freezing, the NaCl in pore waters is excluded from the hydrates structure. The excess salt diffuses away over time. If a well enters the hydrate, chances are that some hydrate will dissociate due to a higher temperature in which process fresh water is liberated and dilutes the pore water. 4) Search for a BSR (bottom simulating reflector) by interpretation of the seismic survey. ƒ BSR (bottom simulating reflector) signifies the occurrence of in-situ gas hydrates, but gas hydrates may still be present even if no BSR is observed. ƒ Volume of gas is not indicated by the presence or strength of the BSR. ƒ BSR might be lower than the HSZ due to the “capillary undercooling effect”. That is, the gas hydrate growth is dependent on the size of the pores. Gas hydrate will only form in smaller pores at lower temperatures than the theoretical HSZ indicates. Consequently, when the larger pore spaces are filled, the hydrate will tend to grow as a displaced inclusion or segregated layer rather than penetrating into smaller pores.

Section

13


5) Predict the presence of Hydrates based on a theoretical HSZ. Sea Level

18ºC 13ºC 7ºC

500

4ºC

1000

10º

Depth in meters

1500

3ºC

2500

3500

0

20º

10º

30º

0

20º

40ºC

10º

30º

20º

40ºC

Sediment water Interface

2000

3000

0

2ºC

1.5ºC 0

30º

10º 20º

C 2H 6, C 3H 8,

4000

30º

H 2 S,CO 2 ,

4500

40ºC

40ºC

3ºC

Hydrate zone under the oceon Assumed geothermal gradient = 27.3º C / 1000m

Figure 1. An example of the hydrate stability zone in an outer continental margin setting. [ Modified from Kvenvolden (1988) ]

during drilling 1) A watch should be kept at surface for gas bubbles and for hydrates in mud return. 2) Maintain observation of the wellbore discharge with a ROV if visibility is sufficient. 3) Monitor background gas in drill mud – drilling operations through hydrates will be characterised by gas cut mud caused by dissociated hydrate gas. 4) Monitor ROP - hydrates are harder than liquid or gas in formation pores, so drilling rate would be expected to decrease. 5) Pressurised coring - to measure and quantify, sidewall samples. 6) Consider static temperature gradients to identify HSZ. 7) Logging. Mud log Dual Induction log Calliper Sonic log Spontaneous potential (SP) Neutron porosity

Temperature log

Pronounced gas kick associated with a hydrate due to thawing during drilling Relatively high resistivity kick in the gas hydrate zone. Long normal separates from the short normal due to thawing next to the bore hole Usually indicates an oversized well bore due to spalling from the decomposition of a hydrate Increase in acoustic velocities Relatively small spontaneous potential deflection in a hydrate zone when compared to a free gas Increase in neutron porosity, in contrast to a normal apparent reduction in neutron porosity in a free gas, due to the gas volume reduction which allows a large increase in water volume in the thawing hydrate zone Thermal conditions within the HSZ

Note: if the well is not logged soon after the penetration of a hydrate it can thaw beyond the maximum sensing depth for normal well logging tools and not appear on the log surveys. 8) RFT samples.

mitigation geological interpretation High resolution seismic survey.

casing design ƒ Set casing before encountering hydrates to provide well control. ƒ Case off hydrate zone at the first opportunity to improve probability that hydrates are retained in place, and to stop further gas from entering the well bore. ƒ Design casing to withstand full displacement to gas. This also applies to casing strings terminating above the HSZ as gas liberated from hydrates in lower zones may migrate up through the annulus/ formation. ƒ Thermal isolation of casing from produced fluids and drilling mud may be required to reduce hydrate thawing.

cement design ƒ Cement as high as possible, preferably into the previous casing string. ƒ Ensure thermal isolation of casing. ƒ Foamed cements are effective in minimising gas influx due to the mechanism in which they maintain pressure on the formation with the inclusion of nitrogen. ƒ Use cements that have a low heat generation to minimise hydrate disassociation.

pressure regulation Increase mud weight to offset the gas cut. Maintain sufficient overbalance To stabilise hydrates: Increase mud weight to facilitate hydrate stability. To destabilise hydrates: Decrease the system pressure below hydrate stability.

mud temperature regulation To stabilise hydrates: Reduce system temperature to within the HSZ by: ƒ Cool mud. ƒ Decrease circulation time to minimise mud heating by formation. ƒ Decrease circulation rate to minimise friction related heat generation. ƒ Reduce ROP. ƒ Use smaller mud motors. To destabilise hydrates: Maintain system temperature to keep fluids outside of HSZ by: ƒ Heat mud. ƒ Control circulation rates to minimise cooling. Where possible keep some circulation going at all times.

drilling fluid additives The effects of components added to a drilling fluid to change hydrate stability are approximately additive. Mud samples should be tested to determine the temperature of gas hydrate formation before field use.

Section

13


thermodynamic inhibitors ƒ Adjust the hydrate stability conditions so that higher pressures and lower temperatures will be required for hydrate stability. ƒ Can completely prevent hydrate formation in a certain temperature-pressure envelope where it would otherwise occur. Beyond this envelope hydrates form as per normal. ƒ Not sufficient for many of the more extreme environments. ƒ Examples: Electrolytes, alcohols, glycols etc. ƒ Large amounts of these additives are usually required to be effective, usually of the order of 10 to 40% by volume. This is expensive and may effect the other functions of the mud. ƒ On a per mass basis NaCl is the most effective. ƒ Glycol/methanol may be spotted down the choke/kill lines and BOP stack to prevent plugging in a kick situation or whenever pumping is stopped for an extended period of time. ƒ From experience, the most effective inhibitor used in deepwater so far is a high aqueous concentration of salt/glycol/glycerol (balanced to provide correct mud weight and viscosity) in the mud system to obtain a low freezing point in combination with a polymer as a chemical inhibitor. ƒ Mixtures of glycerol + salt, glycerol + PHPA + salt or polymer + oil-in-water can serve as a safe, environmentally friendly, and cost-effective gas hydrate inhibitor for drilling fluids. ƒ 20% (w/w) NaCl with 20% (v) glycerol can give a thermodynamic suppression of close to 50 ˚F. ƒ Pills may be placed in BOP stack and choke and kill lines. ƒ Some typical components of mud (e.g. bentonite, barite and polymers) promote the rate of hydrate formation because they actually stabilise hydrates at higher temperatures than pure water. kinetic inhibitors ƒ May work in three ways: Delay nucleation, Slow growth, Prevent Agglomeration. ƒ It is suspected that kinetic inhibitors of hydrate formation do not act in the first of the above three mechanisms. ƒ Retard but NOT PREVENT hydrate formation. ƒ Will slow the process and/or prevent the formation of large blocks. ƒ May be able to function at very low concentrations. e.g. 0.01 to 1% ƒ Such additives as bentonite, surfactants and alcohols or any surface-active species may potentially effect the rate at which hydrates form. Many have been discovered to actually act as kinetic promoters. ƒ WBM contain many sites for crystal nucleation which allow hydrates to form faster than they do in pure water. kinetic stabilisers Slow rate of disassociation. (See section on Lecithin).

non aqueous fluids A thermodynamic inhibitor but also a kinetic promoter. NAF is a good inhibitor, however, once initiated, the rate of formation is much greater in an NAF than WBM. This is probably a result of the high solubility of gas in the oil phase and the large surface area of the dispersed water phase. Hydrates do not form easily in NAF. Temperature extent of gas hydrate formation can be inhibited significantly but not necessarily prevented in NAF. Addition of dissolved solids, e.g. CaCl into the aqueous phase of NAF reduces the gas hydrates formation temperature even further

lecithin Lecithins are a group of compounds that are glyceryl esters of two fatty acid molecules. They are esterified at the third carbon atom with phosphoric acid, which in turn is bound by ester linkage to a nitrogen base. They are a mixture of surface-active species. Lecithin will ‘coat’ the surfaces of shale and other solids. Lecithin is a kinetic promoter which speeds the rate of hydrate nucleation. It prevents agglomeration. Widely used in the ice-cream industry for this purpose. Slows growth of larger masses by adsorption onto the surface of crystals. Does not significantly effect the hydrate thermodynamic equilibrium conditions. It is believed that surface adsorption is a key mechanism by which lecithin slows the rate of hydrate melting. This property allows for minimal disassociation of hydrates in the formation and may contribute to stabilising hydrate cuttings long enough for them to be brought to surface.

bits and bha Minimise well bore diameter to minimise hydrate dissociation.

drilling parameter ƒ Control drilling and circulation rates to manage the quantity of gas in the well. ƒ Ensure that some circulation occurs periodically to prevent cooling at critical times. ƒ Test mud gas samples to confirm the presence of hydrates.

special equipment / requirements

ƒ Select equipment with appropriate seals to minimise hydrate migration into the wellhead and surrounds, causing mechanical blockages and release problems during abandonment of wells. ƒ Consider insulation of well control equipment to decrease rate of heat transfer during extended shut-in periods. ƒ Contingency planning for the occurrence of gas hydrates during well control operations should consider long shut-in periods. Maintenance of temperature in subsea BOP above static mud line temperature by previous mud circulation cannot be relied on as an adequate hydrate preventive measure. ƒ Mud mat and seal to direct dissociating gas away from BOP equipment. ƒ Surface BOP. ƒ Drill without a riser – treat as per shallow gas. ƒ Simulation indicates that during deepwater riserless drilling using a seawater mud, a hydrate zone, if encountered, will remain mostly intact. ƒ Shale shaker and mud tank areas should be well ventilated.

dwm section 14

drilling waste management

drilling waste management background section 14a - solids control section 14b - containment section 14c - treatment and disposal

Section

14


drilling waste management background

No well can be drilled without the generation of wastes. The types of waste generated include drill cuttings, waste water, spent drilling fluids, completion fluids and filtration wastes. The contaminants on the waste depend largely on the types of drilling fluids used to drill the well. With increasing legislation, public awareness and minimum operator environmental standards, the containment, handling and treatment of drilling waste has increased in importance and now ranks in importance along side that of drilling fluids in many countries around the world. The treatment processes utilised on the waste generated vary from country to country and very much depend on the local legislation. In countries where no legislation exists, many operators will fall back on minimum standards used in other countries or standards set at a corporate level. The Four R’s are one of many ways to describe the waste management hierarchy approach and are important when considering what our drilling waste management product line consist of. The four R’s are: ƒ Reduce ƒ Reuse ƒ Recycle ƒ Recover Reduce – if we do not generate the waste in the first place, then a reduction is obvious. However, no well can be drilled without the generation of waste. It is possible though to reduce the volumes through a number of means including better planning, a reduction in hole sizes, minimising washout through the selection of appropriate drilling fluids etc. Reuse – solids control equipment is key to the reuse strategy. Solids control efficiencies will dictate how much drilling fluid is recovered in a suitable state for reuse in further drillings activities. Poor solids control efficiencies will lead to more solids entering the active system, further reducing their particle size, and ultimately resulting in the requirement to dump fluids as waste, or to dilute, thereby increasing volumes and costs, all of which have a negative environmental impact. Other specialist equipment is used to further improve the recovery of drilling fluids such as the Oil Free Plus Dryer (vertical) and Extractor Dryer (horizontal), which reduces the residual oil on cuttings to a level not achievable using traditional solids control equipment. Liquid waste such as waste water and spilt drilling fluids can also be reused in many cases provided they are collected, treated if necessary, and checked prior to reuse. Recycle – after recovery of the drilling fluid for reuse, the drill cuttings may require further processing. The low temperature thermal treatment of NADF cuttings offers the opportunity to recycle the recovered base oil to build new drilling fluids. Similarly, slop water generated during the use of NADF can be treated with chemicals to recover and ultimately recycle much of the NADF portion. Recover – high temperature thermal treatment of drill cuttings will generate a recovered hydrocarbon which is not suitable for reuse in drilling fluids due to “cracking” of the oil caused by the higher treatment temperature. However, this hydrocarbon is often suitable for recovery as a fuel oil. The Drilling Waste Management product line is designed to help maximise compliance with the waste management hierarchy principles, as well as ensuring that local regulations and standards are complied with. Ultimately, disposal will be required in all cases, be it solids and / or liquids.

section 14a

solids control

section 14a

Scomi Oiltools

overview

6

sources and sizes of solids

6

impact of drill solids

7

drill solids removal

7

dilution

8

gravity settling method

8

mechanical solids removal equipment

8

solids control equipment

10

shale shakers

10

vibration patterns

11

acceleration

13

frequency (rpm), stroke length

14

deck angle

14

screen fastening and support

15

three dimensional screens

16

blinding, plugging

16

estimating number of shakers required

17

summary

17

position in the system

18

set up

18

hydroclone - desander

19

hydroclone – desilter

21

section 14a

Scomi Oiltools

principle and theory of operation

21

function

22

flow rates through hydrocyclones

24


24

mud cleaners

24

principle and theory of operation

24

function

25


25

set up and variables

25

summary

26

performance operation

27

centrifuge

28

principle & theory of operation

28

function

31

centrifuge uses

31


33

centrifuge set up

33

summary

41

shale shaker screens

41

screen identification

42

mesh size designation

43

API RP 13C Designation

43

cut points

48

Section 14a

Scomi Oiltools

causes of premature screen failure

48

screen blinding

49

screen panels

49

hook strip screens

50

bonded screens

50

three-dimensional screen panels

50

screen effectiveness

51

screen designations

52

system layout

53

fundamental principles

53

tank design

53

compartment equalisation

54

sand trap

54

equipment arrangement

56

do’s and don’ts

56

zero discharge set-up

56

Section

14a

solids control

solids control

overview Solids control is the process of controlling the build-up of undesirable solids in a mud system. The buildup of solids has undesirable effects on drilling fluid performance and the drilling process. Rheological and filtration properties can become difficult to control when the concentration of drilled solids (lowgravity solids) becomes excessive. Penetration rates and bit life decrease and hole problems increase with a high concentration of drill solids. Solids control equipment on a drilling operation should be operated like a processing plant. In an ideal situation, all drill solids are removed from a drilling fluid. Under typical drilling conditions, low-gravity solids should normally be maintained below 6 percent by volume.

sources and sizes of solids The two primary sources of solids (particles) are chemical additives and formation cuttings. Formation cuttings are contaminants that degrade the performance of the drilling fluid. If the cuttings are not removed they will be ground into smaller and smaller particles that become more difficult to remove from the drilling fluid. Most formation solids can be removed by mechanical means at the surface. Small particles are more difficult to remove and have a greater effect on drilling fluid properties than large particles. The particle size of drilled solids incorporated into drilling fluid can range from 1 to 250 microns (1 micron equals 1/25, 400 of an inch of 1/1000 of a millimetre). The following table lists the approximate sizes of contaminating solids. Material Diameter (Microns) Clay Colloidals Bentonite Silt Barites Fine Cement Dust Fine Sand

API Sand Coarse Sand

Screen Mesh Required to Remove

1 5

-

6 - 44

1,470 - 400

44 53 74 105 149 500 1,000

325 270 200 140 100 35 18

Table 1 – Solids Sizes (Common solids found in drilling fluids range in size from 1 to 1,000 microns) The following table details the common particle size classification:

API Class

Size Range (microns)

Coarse Intermediate Medium Fine Ultra Fine Colloidal

>2000 250 – 2000 73 - 250 44 - 73 2 - 44 0-2

Common Term Sand Sand Silt Silt Clay Clay

Screen Mesh 10 60 210 460

Table 2 – Common Particle Size Classification

impact of drill solids Drill solids are the main contaminant of all drilling fluids and therefore their control is of the utmost importance. The importance of good solids control include: ƒ Increased Penetration Rates ƒ Reduced Mud Costs ƒ Less Water Requirements ƒ Less Mixing Problems ƒ Less Differential Sticking ƒ Reduced Hole Drag and Torque ƒ Lower Pumps Costs ƒ Pumps Operate More Efficiently ƒ Better Cementing Jobs ƒ Reduced Annular Pressures ƒ Minimise Lost Circulation ƒ Reduced Formation Damage ƒ Environmental Protection ƒ Reduced Disposal Costs The consequences of poor solids control: ƒ Stuck pipe ƒ Reduced Drilling rate ƒ Thick Filter cake ƒ Increased Drilling Fluid Dilution ƒ Increased Chemical consumption ƒ Increased Torque and Drag ƒ Formation Damage ƒ Problems with well Evaluation ƒ Poor cement jobs ƒ Increased surge/swab pressures, ECD ƒ Increased equipment wear and tear, decreased bit life

drill solids removal There are 3 main ways of controlling solids: ƒ Dilution ƒ Mechanical removal ƒ Gravity Settling

Section

14a

solids control

dilution Oil muds can be diluted with base oil (or clean oil mud) and water muds can be diluted with water (or clean water mud) to keep the concentration and surface area of solids within bounds. Two approaches for dilution are: 1. Dump and dilute continuously while drilling. This is the most expensive approach to solids control in most situations. 2. Dump periodically and dilute while drilling. This is more cost effective than the first approach. Certain practices can be applied to make it less costly. The total costs of dilution are: the cost of the water hauled to the rig, the cost of converting that water into a mud of correct density, plus the cost of disposal of the mud that was dumped. To make dilution less expensive, these practices should be followed: 1. minimize the total volume of mud to be diluted. 2. dump (displace) the maximum possible dirty mud before adding water and materials, and 3. do as much dilution as possible in a single step- not a series of small dilutions. Therefore, as mud becomes more expensive, dilution becomes a less attractive option and mechanical separation should be pursued.

gravity settling method In locations where large, shallow earthen pits can be built, a mud can be circulated through the pits and drill solids allowed to settle out. It is a rare situation today when this can be done; but, it is an alternative to be considered. On rigs with steel pits, the sand trap (under the shale shaker) is the only place where settling should occur.

mechanical solids removal equipment Equipment that removes solids mechanically can be grouped into two major classifications: ƒ Screen Devices ƒ Centrifugal Separation Devices. The following table identifies the particle sizes (in microns) the equipment can remove. Solids Control Equipment Screen Devices Centrifugal Separation Devices - Decanting Centrifuges - Hydrocyclones

Particle Sizes Removed 61 micron cut with 250 mesh screen Colloidal Solids to 5 micron 20-70 micron solids, depending on cone size

Table 3 – Solids Control Equipment and Effective Operating Ranges in Microns (the particle size removed depends on the type of solids control equipment.

Table 4 - Summary table of solids particle size versus mechanical removal device

Section

14a

solids control

Screen Devices The most common screen device is a shale shaker, which contains one or more vibrating screens that mud passes through as it circulates out of the hole. Shale shakers are classified as circular/elliptical or linear motion shale shakers. Circular/elliptical motion shaker. This shaker uses elliptical rollers to generate a circular rocking motion to provide better solids removal through the screens. Linear motion shaker. This shaker uses a straightforward and back rocking motion to keep the fluid circulating through the screens. Centrifugal Separating Devices The devices rely upon exerting a substantial “G” force on the fluid to separate the denser particles from the lighter fluids. They include all hydroclones, Desanders, Desilters etc, and centrifuges. In the case of a mud cleaner the two principles of screen and centrifugal separation are combined.

solids control equipment shale shakers Function The shale shakers performance can be easily observed, all aspects of its operation are visible. Shale shakers provide the advantage of not degrading soft or friable cuttings. When well operated and maintained, shale shakers can produce a relatively dry cuttings discharge. In unweighted muds, the shale shaker’s main role is to remove as much solids as possible and reduce the solids loading to the downstream hydrocyclones and centrifuges to improve their efficiency. In muds containing solid weighting agents such as barite, the shale shaker is the primary solids removal device. It is usually relied upon to remove all drilled cuttings coarser than the weighting material. Downstream equipment will often remove too much valuable weighting material. Enough shakers should be installed to process the entire circulating rate with the goal of removing as many drilled cuttings as economically feasible. Given the importance of the shale shaker, the most efficient shakers and screens should be selected to achieve optimum economic performance of the solids control system. Shaker performance is a function of: • Vibration pattern • Vibration dynamics • Deck size and configuration • Shaker screen characteristics • Mud rheology (plastic viscosity) • Solids loading rate (penetration rate, hole diameter) The impact of each is discussed in detail in this chapter. Guidelines for shaker and screen selection are also provided. Principle of Operation Simply stated, a shale shaker works by channelling mud and solids onto vibrating screens. The mud and fine solids pass through the screens and return to the active system. Solids coarser than the screen openings are conveyed off the screen by the vibratory motion of the shaker. The shaker is the only solids removal device that makes a separation based on physical particle size. Hydrocyclones and centrifuges separate solids based on differences in their relative mass. 10

vibration patterns Shale shakers are classified in part of the vibration pattern made by the shaker basket location over a vibration cycle (e.g. linear motion shakers). The pattern will depend on the placement and orientation of the vibrators. Four basic vibration patterns are possible, • circular • balanced elliptical motion • unbalanced elliptical • linear Circular Motion As the name implies, the shaker basket moves in a uniform circular motion when viewed from the side. This is a “balanced” vibration pattern because all regions of the shaker basket move in phase with the identical pattern. In order to achieve “balanced” circular motion, a vibrator must be located on each side of the shaker basket at its centre of gravity (CG) with the axis of rotation perpendicular to the side of the basket. The Brandt Tandem is a common example of a circular motion shaker.

Solids Conveyance and Fluid Throughput Circular motion shakers will not efficiently convey solids uphill. Therefore, most shakers of this type are designed with horizontal configurations. Fluid throughput is limited by the deck angle, but augmented slightly by the higher “G”’s normally used (see Vibration Dynamics section). The “soft” acceleration pattern does not tend to drive soft, sticky solids, such as gumbo into the screens. Recommended Applications • Gumbo or soft sticky solids conditions • Scalping shakers for coarse solids removal Balanced Elliptical Motion The latest design have the motors placed above the basket and produce a ‘lazy’ elliptical motion

Recommended Applications • General solids removal. Equally good in water based and oil based drilling fluids

11

Section

14a

solids control

Unbalanced Elliptical Motion The difference between circular motion and unbalanced elliptical notion is a matter of vibrator placement. To achieve unbalanced elliptical motion, the vibrators are typically located above the shaker basket. Because the vibrator counterweights no longer rotate about the shaker’s centre of gravity, torque is applied on the shaker basket. This causes a rocking motion which generates different vibration patterns to occur along the length of the basket, hence the item “unbalanced”.

This figure illustrates how the vibration pattern may change along the length of the basket. At the feed end of the shaker, an elliptical vibration pattern is created; the angle of vibration is pointed toward the discharge end. In this region, forward solids conveyance is good. However, at the discharge end of the shaker, angle of the elliptical pattern is point back towards the feed end. This will cause the solids to convey backwards unless the deck is pitched downhill at a sufficient angle to overcome the uphill acceleration imparted on the solids by the shaker motion. Solids Conveyance and Fluid Throughput The downhill deck orientation restricts the unbalanced elliptical motion shaker’s ability to process fluid, mud losses can be a concern. However the deck orientation is beneficial for removing sticky solids such as gumbo. Recommended Applications ƒ Gumbo, or soft sticky solids conditions ƒ Scalping shakers for coarse solids removal Linear Motion Linear motion is achieved by using two counter rotating vibrators which, because of their positioning and vibration dynamics, will naturally operated in phase. They are located so that a line drawn from the shaker’s centre of gravity bisects at 90˚ a line drawn between the two axis of rotation.

12

Because the counterweights rotate in opposite directions, the net force on the shaker basket is zero except along a line passing through the shaker’s centre of gravity. The resultant shaker motion is therefore “linear”. The angle of this line of motion is usually at 45-50˚ relative to the shaker deck to achieve maximum solids conveyance. Because acceleration is applied through the shaker CG, the basket is dynamically balanced; the same pattern of motion will exist at all points along the shaker. Solids Conveyance and Liquid Throughput Linear motion shakers have become the shaker of choice for most applications because of their superior solids conveyance and fluid handling capacity. Solids can be strongly conveyed uphill by linear motion. The uphill deck configuration allows a pool of liquid to form at the shaker’s feed end to provide additional head and high fluid throughput capability. This allows the use of fine screens to improve separation performance. The Derrick Flo-Line Cleaner is one example of a linear motion shale shaker. One drawback to linear motion shakers is their relatively poor performance in processing gumbo. The short vibration stroke length when combined with long basket lengths, uphill deck angles and strong acceleration forces tends to make the soft gumbo “patties” adhere to the screen cloth. The removal of gumbo is important prior to feeding to a linear motion shaker. Recommended Applications •

All applications where fine screening is required.

acceleration During the vibration cycle, the shaker basket undergoes acceleration which changes in both magnitude and direction. As discussed previously, the placement of the vibrators determines the vibration pattern and therefore the net acceleration direction during the vibration cycle. The mass of the counterweights and the frequency of the vibration determines the magnitude of the acceleration. The vertical component of acceleration has the most effect on shaker liquid throughput. We relate the vertical components of acceleration and stroke length to frequency by the following equation: Oilfield units G’s = stroke (in.) x RPM2 70, 490

S.I units G’s= stroke (m) x RPM2 1790.45

where the stroke length is the total vertical distance travelled by the shaker basket and the G-force is measured from midpoint to peak. An acceleration of one “G” is the standard acceleration due to gravity (386 in./sec2 or 9.81/sec2). Most shakers operate at accelerations within the range of 2.5 - 7.0 G’s, depending upon the vibration pattern. Field experience has shown this range offers the best compromise between throughput capacity and screen life. Many manufacturers report the acceleration of linear motion shakers along the line of motion. This yields a larger number and looks good on the specification sheet. However, unless the angle of vibration is also specified, it reveals little about the performance of the shaker. Some shakers have adjustable counterweights to vary acceleration. Although flow capacity and cuttings dryness improves with increased acceleration, screen life is negatively affected. By reducing the “G”s when extra flow capacity is available, screen life may be improved.

13

Section

14a

solids control

frequency (rpm), stroke length The vibrator frequency of most shale shakers is not normally adjustable. The vibrators typically rotate at a nominal RPM or 1200 or 1800 at 60Hz. Stroke length varies inversely with rpm. A higher rpm will result in a shorter stroke length at the same acceleration. The effect of vibrator frequency and stroke length on shaker processing rate has been evaluated in the laboratory. The results of these tests show improved shaker flow capacity in the presence of solids with decreased rpm (or conversely, increased stroke length) at the same G level. Therefore, the term “high speed” should not be used to mean “high performance” since the opposite relationship is often more correct. The main disadvantage to lower frequency shale shakers is that the mud tends to “bounce” much higher off the screens and cover the area around the shakers with a fine coating of mud. More frequent housekeeping is required to maintain a safe environment around the shakers. Longer stroke lengths also tend to reduce screen life.

deck angle Because linear motion shakers will convey uphill, most provide an easily adjustable deck angle feature to optimise fluid throughput capacity and cuttings conveyance velocity. Uphill deck angles also provide protection against overflow due to surges at the flowline. At deck angles greater than 3o, solids grinding in the pool region can be a problem. Although fluid throughput increases with uphill deck angle, cuttings conveyance decreases. Solids conveyance within the pool region is slower than out of the pool due to viscous drag forces and the differential pressure created across the cuttings load by the hydrostatic head of the fluid. If the deck angle is too high, a stationary mound of solids can build up in the pool even though conveyance is observed at the discharge end. The vibrating action of the screen and extended residence time will tend to grind soft or friable cuttings before they have the opportunity to be conveyed out of the pool. This condition should be avoided since the generation of fines in the mud is definitely not desired.

To check for this problem, observe the feed end of the shaker at a connection immediately after circulation is stopped. There should not be a disproportionate amount of solids accumulated at the feed end. The problem can be rectified by lowering the deck angle until the solids mound is eliminated.

14

screen fastening and support The type of screen panel dictates the type and amount of support and fastening system necessary. The screen fastening and support structure provide the following functions: ƒ Prevent leakage past the screens ƒ Expedite screen replacement ƒ Provide even tension on screens to extend screen life The two types of screen panels are commonly labelled as “pretensioned” and “nonpretensioned” panels. However, these terms do not exactly describe the construction since many nonpretensioned panels are, indeed, pretensioned. The terms “rigid frame” and “hookstrip” more correctly differentiate the two main panel types. hookstrip screen panels This is the most common type of panel, consisting of one to three layers of screen cloth. The cloth is frequently bonded to a thin perforated metal grid plate or a plastic grid. The next figure shows the construction of a typical hookstrip screen. The screen panel is tensioned on the shaker deck by an interlocked hookstrip and drawbar arrangement located on both sides of the shaker. Three or more tensioning bolts are used to pull each drawbar down and towards the side of the basket. This seats the screen on the shaker deck and distributes even tension along the hookstrip.

Fine Middle Layer

These panels are not rigid; the shaker deck must be crowned to maintain screen 1. The screen cloth is tensioned and glued directly to the steel frame. Additional glue lines may be included between the frame members to provide additional support. The bonding pattern divides the panel into 3 - 4 in (76 - 102 mm) wide strips orientated parallel to the flow. This design is used in the fluid systems Model 500. 2. This panel design maximises usable screening area. However, the large unsupported area normally limits cloth selection to the heavier grades with lower flow capacity. The panel is not normally considered repairable. 3. Alternatively, the screen cloth may be bonded to a perforated metal backing plate similar to a hookstrip screen. The metal backing plate is then bonded to the support from to create a rigid panel. The Brandt ATL-1000 and the Thule VSM-100 use this type of panel.

15

Section

14a

solids control

Usable screen area is reduced by the performed plated design, but this is offset by the option of using higher conductance screen cloth, reparability and better screen life under high solids loading conditions.

three dimensional screens In recent year three dimensional screens have been introduced to the oil industry. This wave design increases the area of the screen by 40% over the flat screens. This increase in conductance is only relevant if the screen is completely submerged in drilling fluid.

blinding, plugging Screen blinding occurs when grains of solids being screened lodge in a screen hole. This often occurs when drilling fine sands, such as in the Gulf of Mexico. The following sequence is often observed during screen blinding. 1. When a new screen is installed, the circulation drilling fluid falls through the screen in a short distance. 2. After a time, the fluid endpoint travels to the end of the shaker. 3. Once this occurs, the screens are changed to eliminate the rapid discharge of drilling mud off the end of the shaker. 4. After the screens have been washed, fine grains of sand that are lodged in the screen surface can be observed. The surface of the screen will resemble fine sandpaper because of the sand particles lodged in the openings. One common solution to screen blinding is to change to a finer or coarser screen that he one being blinded. This tactic is successful if the sand that is being drilled has a narrow size distribution. Another solution is to change to a rectangular screen, although rectangular screens can also blind with multiple grains of sand. Blinding – the “plastering” of a soft material over and in the mesh, rendering it blocked. Remedy = wash with high pressure fluid using the base fluid of the drilling fluid. If this fails, fit coarser screens temporarily. Plugging – the blocking of the mesh by a particle (usually sand) fitting into the pore throat of the mesh. Remedy = wash with high pressure fluid using the base fluid of the drilling fluid. This is best done from beneath the screen (after removal). It is often successful to place a finer screen on to reduce the “near size” plugging. Lost Circulation Material Do not bypass the shakers to avoid screening out the LCM material. Scalping shakers can be used to recover LCM when high concentrations are continuously required in the mud, provided. Cuttings size distribution is sufficiently fine to pass through the scalping screens. ƒ Solids loading rates do not negatively impact the performance of the downstream shakers and cause solids build-up in the active system.

16

estimating number of shakers required Base the number of shakers required on the economics and physical constraints of the specific application. A “ballpark” estimate of shaker requirements, based on average drilling conditions can be made from the following table. This is a very rough estimate and should be used only as a guide. Shakers Required Approximate Number of High Performance Linear Motion Shakers Maximum Viscosity (cP) GPM 300 400 500 600 700 800 900 1000 1100 1200 1300 1400

5 1 1 1 1 2 2 2 2 3 3 3 3

10 1 1 1 2 2 2 2 2 3 3 3 3

15 20 25 30 40 50 1 1 1 1 2 2 1 2 2 2 2 2 2 2 2 2 3 3 2 2 2 3 3 3 2 2 3 3 3 3 2 3 3 3 4 4 3 3 3 4 4 4 3 3 4 4 4 3 4 4 4 3 4 4 4 4 4

60 2 2 3 3 4 4

Table 5 – Shakers Required The guide however does not reflect the performance of the most modern market leading shale shakers. The Derrick Flo-Line Cleaner 514 will out perform smaller units and allow less units to be used with finer screens to produce the same fluid handling ability.

summary ƒ The shale shaker is the only solids control device that makes a separation based on the physical size of the particle. The separation size is dictated by the opening sizes in the shaker screens. Hydrocyclones and centrifuges separate solids based on differences between their relative mass and the fluid. ƒ Shale shakers with linear vibratory motion are preferred for most applications because of their superior processing capacity and fine screening ability. Circular motion or unbalanced elliptical motion shakers are recommended as scalping shakers in cascading systems. ƒ Vibration of the shaker basket creates G-forces which help drive shear thinning fluids such as drilling mud through the screens. Vibration also conveys solids off the screens. Most linear motion shakers operate in the range of 3 to 4 G’s to balance throughput with screen life. G-force is a function of vibration frequency (rpm) and stroke length. ƒ “High-Speed” should not be equated with “high performance”. Laboratory tests indicate that, in the normal operating range for linear motion shale shakers, lower frequency vibration and longer stroke lengths improve throughput capacity. Most linear motion shakers operate at 1200 to 1800 rpm. ƒ Avoid deck inclinations above 3˚. High deck angles reduce solids conveyance and increase the risk of grinding soft or friable solids through the screens. ƒ Shakers are designed to accept either hookstrip or rigid frame screen panels. Hookstrip screen panels are the most common and are usually cheaper, although cuttings wetness can be a concern due to deck curvature. Flat, rigid frame panels promote even fluid coverage, but can cost more. ƒ Shakers may have single or tandem screening decks. Single deck shakers offer mechanical simplicity and full access to the screening surface. Single deck shakers may be arranged to process mud sequentially as a “cascading” system to improve performance under high solids loading conditions. Tandem deck shakers offer improved processing capacity under high solids loading conditions when space is limited.

17

Section

14a

solids control

ƒ Manifolds should provide even distribution of mud and solids to each shaker. Avoid branch tee’s. Recommended manifold designs are illustrated. ƒ Operating guidelines are provided for optimising screen life and cuttings dryness, handling sticky solids, polymer muds, blinding and LCM problems.

position in the system Positioned downstream of the gumbo trap and flow distribution system. May comprise a single set or a dual set or cascade system.

set up Use enough shakers to provide sufficient non-blanked screen area to run 100 mesh or finer screens. Shaker set up should be sufficient to process solids-laden fluids at maximum flow rates over any significant hole interval. For double-deck shakers, run a coarser screen on top and a finer screen on bottom. The coarser screen should be at least two meshes coarser. Watch for a torn bottom screen. Replace or patch torn screens at once. Cover 75% to 80% of the bottom screen with mud to maximise utilisation of the available screen area. Flow back pans are recommended for improving coverage and throughput. For a single deck shaker with parallel screens, try to run all the same mesh screens. If coarser screens are necessary to prevent mud loss, no more than two meshes should be on the shaker at one time, with the finer mesh screen closest to the possum belly. The two meshes should have approximately the same size opening. For example, use a combination of 100 mesh (140u) and 80 mesh (178u), not 100 mesh (140u) and 50 mesh (279u). Cover 75% to 80% of the screen area with mud to properly utilise the screen surface area. Use spray bars (mist only) as needed for sticky clay, etc. Use spray bars only with unweighted water based muds. Spray bars are not recommended for weighted or oil based muds. Do not bypass or operate with torn screens; these are the main causes of plugged hydrocyclones. Use screens with mesh back-up so that coarser solids will be screened out when the finer mesh tears. For improved screen life with non-pretensioned screens, make sure the components of the screen tensioning system, including any rubber supports, nuts, bolts, springs, etc are in place and in good shape. Install screens according to the manufacturer’s recommended installation procedure. Check the bearing lubrication according to manufacturer’s maintenance schedule. Lubricate and maintain the unit according to manufacturers instructions. Rig up with sufficient space and walkways with handrails around the shaker skid to permit easy service. The shaker skid should be level. Check for correct direction of motor rotation for shakers with one vibrator.

18

The flow line should enter at the bottom of the possum belly to prevent solids settling and build-up in the possum belly. If the flow line enters over the top of the possum belly, the flow line should be extended to within 8 -10 ins (20 - 25 cms) of the bottom of the possum belly. Rig up for equal fluid and solids distribution when more than one shaker is used. A cement bypass is desirable.

hydroclone - desander Think of a tornado inside a bottle and you have a rudimentary idea of how a hydrocyclone operates. The following figure illustrates the basic concepts of hydrocyclone operating principles. Hydrocyclone Operating Principles A large hydrocyclone can process large volumn of mud due to this upright spiral design. LIQUID DISCHARGE

CLEANED DRILLING MUD (OVERFLOW)

FEED NOZZLE

VORTEX FINDER

DRILLING MUD SAND AND SILT, DRIVEN TOWARD WALL AND DOWNWARD IN ACCELERATING SPIRAL

DRILLING MUD MOVES INWARD AND UPWARD AS SPIRALLING VORTEX

SAND AND SILT (UNDERFLOW)

Mud enters the feed chamber tangentially at a high velocity provided by pump pressure. As the mud spirals downward through the conical section, centrifugal force and inertia cause the solids to gravitate towards the wall. The solids settle according to their mass, a function of both density and volume. Since the density range of drilled solids is normally quite narrow, size has the largest influence on settling. The largest particles will settle preferentially. As the cone narrows, the innermost layers of fluid turn back toward the overflow creating a low pressure vortex in the centre of the cone. This low pressure area causes air to be pulled in from the underflow outlet. Correctly operating cones should exhibit a slight vacuum at the cone underflow. The air and cleaned fluid then report to the overflow through the vortex finder. The purpose of the vortex finder is to prevent some of the feed mud from “short circulating” directly into the overflow. Solids with sufficient mass cannot make the turn back towards the overflow because of their momentum and continue out of the underflow. Maximum cone wear usually occurs at or near the underflow exit, where velocities are the highest. In cones which have a “balanced design” whole mud losses out of the underflow are slight. Only the solids and bound liquid will report to the underflow. If the solids are too fine to be removed by the cyclone, no liquid should be discharged. “Unbalanced” hydrocyclones will discharge mud without the presence of solids in the mud.

19

Section

14a

solids control

Because fine solids have more specific area (surface area per unit volume) than large particles, the amount of liquid removed per pound of solids is higher with fine solids than with coarse solids. Therefore, the difference between the feed and underflow density is not a reliable indicator of hydrocyclone performance. The Cone Efficiency graph shows the relationship between underflow density and cone efficiently for an unweighted mud. Observe how overall cone efficiency decreases as underflow density increases. Cone Efficiency

Function Desanders consist of a battery of 10 inch (254 mm) or larger cones. Even though desanders can process large volumes of mud per single cone, the minimum size particles that can be removed are in the range of 40 microns (with 6 inch or 152 mm cones). Use To remove solid sized particles from drilling fluid. Used predominantly in top hole sections where fine screens cannot be used on the shale shakers and when screens become blinded by sand particles and coarse mesh screens have to be used. Position in the system The first levels of solids removal after the shale shakers. Fed by a dedicated centrifugal pump and sized appropriate for pressure drop in fluid dynamics.

20

hydroclone – desilter principle and theory of operation The cone separator relies on propelling drilling fluid water pressure tangentially into a cone vessel. The differential setting creates separation with the lighter solids depleted fluid being expelled from the overflow, the denser solids laden fluid is ejected from the hose. The diameter of the cone controls the cut point and particle size separated. The larger the cone diameter the larger particle diameter that can be separated.

Desilter

Desander

Use of high performance shakers reduces the drilled solids loading on the hydrocyclones. However, during the drilling of large diameter holes, high penetration rate and high flow rates (greater than 50 ft/hr, 15.2 m/hr); 10” or 12” (254 mm or 305 mm) hydrocyclones are recommended to reduce solids loading on the smaller hydrocyclones. There should be sufficient 10” or 12” (254 mm or 305 mm) cones to process 110% of the mud circulating flow rate normally only water base muds. The underflow from these cones, since it is fairly dry, should go to the cuttings pit. If the underflow is not sufficiently dry, it may be further dewatered by screening or centrifuging. If dewatering desander underflows is inconvenient, an extra shale shaker might be used to negate the need of the desander. This may not be true for gumbo areas. A desander may be utilised with a light weighted drilling fluid (<13.0 lb/gal or 1.56 SG) to discard sand size solids. Be careful not to discard too much Barite or liquid mud. The next type of solids removal equipment downstream of the shakers or large hydrocyclones, are usually 4” (102 mm) desilters, which may be followed by 2” (51mm) microcones. The 3” (76 mm) may be use for replacements of the 4” (102 mm) units, based on fine screening (<175 μ) ahead of the cyclones. There should be enough hydrocyclones to process at least 110% of the rig mud circulation rate. If hydrocyclones are sized to process surface hole circulation rates, there will be sufficient hydrocyclone capacity for the remaining hole sections. A hydrocyclones underflow will have an estimated 10% to 25% solids content, which means that over 3 to 7 barrel (0.48 m3 - 1.1 m3) of fluid can be wasted with one barrel (0.159 m3) of cuttings under the best operating conditions. A 2” (51 mm) or 3” (76 mm) cone is more efficient because of finer particle size separation but the discharge is wetter. A new 3” (76 mm) cone design removes 50% more solids than a typical 4” (102 mm) hydrocyclone. The price for improvement in efficiency is again paid in terms of discarding more liquid with the solids. A high performance shaker may be used to de-water hydrocyclone underflows prior to being fed to a centrifuge. All hydrocyclones must operate at their specified Feet of Head (Fh) for maximum efficiency, gallons per minute capacity, and particle size cut points.

21

Section

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solids control

Optimum Hydrocyclone Operation Fh Mh D50u 80 24.4 38 75 22.9 45 75 22.9 24 100 30.5 10 120 36.6 08

10” (254 mm) Desander 12” (305 mm) Desander 4” (102 mm) Desilter 3” (76 mm) Desilter 2” (51 mm) Desilter

GPM 450 500 50 35 25

Litres 1703 1893 189 132 94

Table 6 – Optimum Hydrocyclone Operation Any variance in Feet of Head (Fh) delivery to the hydrocyclones will affect the performance. For example: Feet of Head

Meter of Head

4” Desilter (16 cones) operating at 25 psi, feed mud at 9.5 ppg

102 mm Desilter (16 cones) operating at 172.4 kPa feed mud at 1138 kg/m3 (SG x 1000)

P = Fh 0.052 x Mwt

P = Mh 0.00982 x Mwt

25 = 50.6 Fh, actual (0.052 x 9.5 lb/gal)

172.4 = 50.6 Fh, actual (0.00982 x 1138 kg/m3)

√

Fh actual x GPM =GPM per cone Fh

√

Mh actual x L/min = L/min Mh

√

50.6 x 50 = 33.7 GPM per cone 75

√

15.4 x 189 =127 litres per cone 22.9

33.7 gpm x 16 cones = 539 GPM

127L x 16 cone = 2032 litres/min

Rule of Thumb: Feed pressure should be 4 x the mud weight in lb/gal. Table 7 - Hydrocyclones – Operating Pressures Recommended Operating Pressure - Desilter Units (@ 75 ft. of Head) Mud weight (lb/gal) 8.33 9.00 10.00 11.00 12.00 13.00 14.00 15.00 16.00 17.00

Specific Gravity 1.00 1.08 1.20 1.32 1.44 1.56 1.68 1.80 1.92 2.04

Where: lb/gal = Pounds Per Gallon Specific Gravity = Mud Weight ÷ 8.33 1 PSI = 2.309 Feet of Head Operating Pressure = [ Feet of Head ÷ 2.309] X [ Mud Weight ÷ 8.33] 22

Operating Pressure (psi) 32 35 39 43 47 51 54 58 62 66

function Hydrocyclones, classified as desanders or desilters, are conical solids separation devices in which hydraulic energy is converted to centrifugal force. Mud is fed by a centrifugal pump through the feed inlet tangentially into the feed chamber. The centrifugal forces thus developed multiple the settling velocity of the heavier phase material, forcing it toward the wall of the cone. The lighter particles move inward and upward in a spiralling vortex to the overflow opening at the top. The discharge at the top is the overflow or effluent; the discharge at the bottom in the underflow. The underflow should be in a fine spray with a slight suction at its centre. A rope discharge with no air suction is undesirable. Example of Normal Discharge

Example of Rope Discharge

Spray Patterns

23

Section

14a

solids control

The sizes of the cones and the pump pressure determine the cut obtained. Lower pressures result in coarser separation and reduced capacity. The following table shows the flow rate capability of different diameter cones. flow rates through hydrocyclones Designation Desilter Desilter Desilter Desander Desander Desander Desander

Cone Diameter (inches) 2 4 5 6 8 10 12

Cone Diameter (mm)

Flow Rate Through Each Cone (GPM)

51 102 127 152 203 254 305

10 – 30 50 – 65 75 – 85 100 – 120 200 – 240 400 – 500 500 – 600

Table 8 – Hydrocyclone flow rates Desilters consist of a battery of 4-inch or smaller cones. Depending on the size of the cone, a particle size cut between 6 and 40 microns can be obtained. Even though hydrocyclones are effective in removing solids from a drilling fluid, their use is not recommended for fluids that contain significant amounts of weighting materials or muds that have expensive fluid phases. When hydrocyclones are used with these fluids, not only will undesirable drilled solids be removed, but also the weight material along with base fluid, which can be cost prohibitive. position in the system The second stage of non-screening separation used to remove silt sized particles.

mud cleaners principle and theory of operation By accelerating mud through a curved vessel, solids and mud are separated according to Stokes Law. These solids are passed over a screen to recover excess fluid.

24

function The mud cleaner is a solids separation device that combines a desilter with a screen device. The mud cleaner removes solids using a two stage process. First, the drilling fluid is processed by the desilter. Second, the discharge from the desilter is processed by a high-energy, fine mesh screen shaker. This method of solids removal is recommended for muds containing significant amounts of weighting materials or having expensive fluid phases. Note: When recovering weight material with a mud cleaner, be aware that any fine solids that go through the cleaner’s screen are also retained in the mud. Over time, the process can lead to a fine-solids build-up. position in the system A desilter positioned over a screen is a mud cleaner.

set up and variables A mud cleaner is a bank of hydrocyclones mounted over a vibrating screen. Free liquid and particles smaller than the screen openings are returned to the circulating system. Solids removed by the screen are discarded. Screen sizes between 100 mesh and 325 mesh are commonly available. Mud cleaners were originally developed for use in weighted muds to remove drilled solids down to the size of barite (<74 microns) when shakers could only run 100 mesh (149 microns) screens at best. However, with the fine-screening capability of today’s linear motion shakers, the applications for mud cleaners are limited. Where possible, the installation of sufficient fine screen shakers is recommended for weighted muds in lieu of a mud cleaner. Shakers equipped with fine mesh screens guarantee that all of the circulation rate is processed, whereas mud cleaners may treat only a portion of the circulation rate. Shakers are more dependable and their screens typically last longer. Barite losses measured over mud cleaner screens are higher than losses over shaker screens at the same mesh size. This is due to the high viscosity of the cone underflow and the relatively small screening area of most mud cleaners. Derrick, among others, have addressed this by mounting desilter cones over a full size shaker deck. Derrick uses a specially designed High-G shaker which will also improve cuttings dryness. Regardless, overall system efficiency would be better served by an additional shaker at the flowline rather than a mud cleaner in most cases.

25

Section

14a

solids control

Trouble shooting Since the mud cleaner is both a hydrocyclone and a shaker, many of the operating guidelines listed for these devices apply to mud cleaners. A decrease in solids coming off the screen may indicate a torn screen, which should be replaced immediately. Plugged cones or large solids coming off the screen can imply a problem with the upstream shale shakers. The likely causes are bypassed screens, torn screens or dumping the shaker box into the active system. The desilter cones on the mud cleaner should be 6 in. diameter or smaller. The median cuts of larger cones are too coarse to be useful. Unweighted Muds ƒ In unweighted water based muds, the mud cleaner should be used as a desilter by blanking off the screen and discharging the underflow directly. ƒ Because the mud cleaner is operated as a desilter, it must be run in parallel with other desilters (same suction and discharge compartments). As with desilters, the suction should be from the desander discharge compartment and the overflow discharged to a downstream compartment. ƒ If the hydrocyclone underflow is to be processed by a centrifuge, the screens may be used to reduce solids loading to the centrifuge. Run the finest screens possible. ƒ In closed loop systems, route the desanders underflow onto the mud cleaner screens to help dry the discharge. Note: however, that the mud passing through the screen should be processed by a centrifuge. ƒ The hydrocyclones on the mud cleaner should be run as wet as possible to improve solids removal efficiency. Weighted Muds ƒ Use the mud cleaners when 150 mesh (100 micron) screens cannot be run on the shale shakers, (water based mud). ƒ At higher mud weights, the screen may become overloaded with solids. If the screen overloads, remove enough cones to keep it from discharging excess fluid. ƒ Monitor the composition and rate of losses over the screens, especially in oil based muds. Use the same procedure as outlined in the shaker section. ƒ For water based muds, dilution water added at the mud cleaner screen may reduce barite losses by reducing the viscosity of the hydrocyclone underflow. However, the amount of drilled solids discarded may also be reduced. summary ƒ A mud cleaner is a desilter mounted over a vibrating screen. The desilter underflow is screened. Fluid and solids finer than the screen are returned to the active system. Only solids coarser than the screen openings are removed. ƒ Mud cleaners were originally designed for use in weighted muds when shakers were incapable of screening down to the size of the weighting material. With today’s fine screen shakers, the applications for mud cleaners are limited. ƒ Fine screen shakers are recommended in lieu of mud cleaners. Screen life is better, all of the circulation rate is processed and barite losses are reported to be lower. ƒ In unweighted mud, the mud cleaner should be used as a desilter. Screening the underflow is unnecessary unless the mud cleaner is used to screen abrasive solids that will be processed by a centrifuge. ƒ Use the mud cleaner on existing solids control systems, when 150 mesh (100 microns) screens cannot be run on the shakers in weighted mud.

26

performance operation If a mudcleaner were to be utilised, a number of areas should be addressed: ƒ The unit should be installed in such a way that access, both for monitoring and maintenance purposes is adequate. ƒ It is extremely important that the centrifugal feed pump is correctly matched to whatever mud system is in use, so as to guarantee the correct feed pressure. ƒ Impeller size and condition is critical to operational efficiency. Any found to have seriously washed blades should be replaced at the earliest opportunity. ƒ The output of the electrical motor in relation to impeller size and mud weight should be given serious consideration. An under powered pump will seriously affect performance by constantly cutting out. ƒ In order for the system to be effective it must have the capacity to process at least 120% of the maximum circulating rate, ideally 150%. Cone sizes and processing rates should be checked accordingly. ƒ Ensure that all cones are in place so as not to compromise system capacity. ƒ If a system has not been in use for a considerable time it would be advisable to remove all cones and carry out a thorough inspection. Any parts that are observed to be washed (eroded) should be replaced, as should any clamps that may appear to be loose. ƒ A pressure gauge should be fitted to the cone manifold. ƒ Under normal conditions the screen fitted to the mudcleaner should be finer than the finest fitted to the shale shakers. ƒ Unit underflow should be routed to a catch tank to be further processed by the centrifuge system. The catch tank should be fitted with an overflow facility or equalised with adjacent process tanks. ƒ During operation the mudcleaner must be monitored on regular basis. ƒ Any blocked cones should be immediately unplugged by the use of a welding rod or similar. If necessary, the unit should be shutdown and any blocked cones removed and cleaned out. Operating the mudcleaner with a number of blocked cones will be extremely detrimental to the mud system, surface equipment and downhole tools. ƒ If screen flooding is apparent, this may indicate either that the free pressure is too low, resulting in poor separation (practically all fluid being discharged as underflow) or the screen is of too fine a mesh. Remedial action should be taken immediately. ƒ If an adjustable screening unit is used, extreme caution should be exercised in using any adjustment to prevent whole mud carryover. Screen life of the less robust finer screens will be seriously diminished, with any damage resulting in the reintroduction to the system of large quantities of concentrated solids. ƒ Only use where appropriate: - Unweighted muds - Where the primary solids control cannot screen satisfactorily. ƒ Ensure the cones are operating correctly - spray discharge ƒ Always ensure correct feed pressure ƒ Rule of Thumb Oilfield units S.I units 4 x (MW in lb/gal) MW in SG e.g. 12 lb/gal = 48 psi required. .004 e.g. 1438 kg/m3= 360 kPa ƒ Screen appropriately – 230 mesh or finer. ƒ Avoid use in oil/synthetic based systems to avoid solids breakdown. ƒ Be aware that as viscosity increases, efficiency decreases!

(

)

27

Section

14a

solids control

centrifuge principle & theory of operation A centrifuge works on the principle of accelerated settling. By imparting addition “G” forces to the content of a centrifuge, solids (in a solids laden fluid) will settle much quicker. To understand how a decanting centrifuge works, first look at a simple sedimentation vessel. Solids in this fluid will settle to the bottom of the vessel over a period of time. One way to speed the process of settling is to reduce the height of the vessel so the solids do not have as far to drop. If a specific volume is required, the vessels dimensions can be lengthened or widened. Depending on the rheological properties of the fluid and the size and density of the solids, settling time can still prove quite slow. Stokes Law Particles will settle in a given fluid according to Stokes’ Law, which is expressed as follows: 2 -6 V1= aD (P2 – P1) X 10 116U

where Vt = a = D = PS = P1 = U =

terminal or settling velocity bowl acceleration, in./sec2 = 0.0054812 x bowl diameter x rpm2 particle diameter, micron solid (particle) density, grams/cm3 liquid density, grams/cm3 liquid viscosity, centipoise (dyne-sec/100 cm2)

Stokes’ Law shows that as fluid viscosity and density increases, the settling rate decreases. Figure - Simple Sedimentation Vessel

h1

It is impossible to separate a drilled solid particle of equivalent mass by settling. d ds2

=

d ds2

where

dds = db = pds = pb = p =

(P ds – P1) (P ds – P1)

diameter of drilled solids particle diameter of barite particle density of drilled solids particle density of barite density of liquid

Figure – Vessel with Small Sedimentation Height

h2

28

Assuming barite has a specific gravity of 4.25 and drilled solids 2.65, the equivalent diameter ratio for settling in a 14 pound per gallon mud (specific gravity = 1.68) is: d ds2 4.25 – 1.68 2.57 d ds2 = 2.65 – 1.68 = 0.97 = 2.65 or

d ds d d = 1.63

In a drilling fluid weighing 14 lb/gal, a 50 micron barite particle will settle at the same rate as a an 81 micron drilled solid particle. All solids, including low gravity and barite particles 2 microns and smaller (colloidal), can have a detrimental effect on drilling fluid viscosity. That is, a low specific-gravity particle that has an equivalent spherical diameter that is 1.6 times that of a barite particle, will settle at the same rate as the barite particle. The low gravity solid will have the same mass as the barite particle. This is the reason that a centrifuge does not separate barite from low gravity solids. The particles in a vessel experience an acceleration of 1 “G”. The force on a particle is the product of the particle mass and the acceleration. This is called a “G” force. One way to increase the “G” force is to rotate the vessel about an axis. In doing so, a simple centrifuge is created. One problem with this design is that as the solids accumulate on the walls of the centrifuge, there is no way to remove them while rotating the centrifuge. Therefore, only small batches of fluid can be treated at one time. One method that would enable the continuous removal of settled solids is to design a tank as shown. This unit uses a drag chain system to remove the settled solids. As the solids are conveyed out of the pool and up the ramp, or beach, they are partially dried prior to discharge. As new fluid is poured into the tank, cleaner fluid may spill out of the weirs. Unfortunately, only 1G is applied to the particles so settling will be very slow. Another way to remove solids from the tank would be to use an auger, or conveyor, in the tank as shown. However, this would not remove the solids that settle away from the conveyor. This could be solved by wrapping the tank around the conveyor. This process results in the creation of a complete centrifuge. Figure – A Simple Centrifuge

29

Section

14a

solids control

The entire assembly is rotated while increasing the “G” force on the solids, which accelerates settling. The fluid moves with the outer cylinder of the centrifuge, so there is no shear within the fluid. This is the reason that dilution fluid is normally added to the input stream of a decanting centrifuge. The low shear rate viscosity of most drilling fluids is increased to aid hole cleaning and to provide weighting agent support. This low shear rate viscosity elevation will also inhibit settling within a centrifuge. To convey the solids out of the centrifuge, the conveyor and bowl must rotate at slightly different speeds. This is accomplished using a planetary gearbox for belt drive centrifuges. Typically the entire assembly rotates in the same direction, but the conveyor rotates at a slightly slower sped. The conveyor moves the solids to the solids discharge end and the liquid, or effluent, empties out of the weirs at the liquid discharge end. To calculate the “G” factor, a centrifuge imparts to solids, the formula is as follows: Oilfield units S.I units 2 G Factor = bowl diameter (in) x rpm G Factor = 70422

bowl diameter (cm) x rpm2 178872

where G is the ratio of the centripetal acceleration of the bowl compared to the acceleration of gravity. (Note, this is the same equation used to calculate the “G” factor of shale shaker vibrators). A centrifuge provides a method of increasing the settling force on particles suspended in liquid. The force depends on the mass of the particle and not the chemical composition. Particles with the same mass, whether they are a barite, low gravity solids, gold, iron or silver will settle at the same rate. Centrifuges are able to separate solids above and below the 2- to 10-micron size range. In weighted drilling fluids, centrifuges are capable of eliminating very small particles that can cause dramatic increases in both the low and high shear rate viscosities. In unweighted drilling fluid they are used as “super desilters”. Figure - Tank for Continuous Removal of Solid Particles from a Process Liquid

Figure - Centrifuge Bowl Cross Section

30

Solids

Solids discharge with absorbed liquid only

Colloidal liquid discharge

Feed inlet Colloidal liquid discharge

Gearbox Pool level controlled by weir settings

Feed ports

Beach

function The two types of centrifugal separation devices are: • Decanting centrifuges • Hydrocyclones. A decanting centrifuge consists of a conical, horizontal steel bowl that rotates at high speed using a double screw type conveyor. The conveyor rotates in the same direction as the outer bowl but at a slightly slower speed. A single centrifuge unit set for total solids discard should be used for low-density systems. The primary function of a centrifuge is not to control total percent solids in a system, but rather to maintain acceptable and desirable flow properties in that system. Two centrifuges operating in series are recommended for the following systems: ƒ Invert emulsion (i.e. synthetic and oil based systems) ƒ High-density, water based systems ƒ Water based systems in which base fluid is expensive (i.e. brines) ƒ Closed loop ƒ Zero discharge The first centrifuge unit is used to separate barite and return it to the mud system. The second unit processes the liquid overflow from the first unit, discarding all solids and returning the liquid portion to the mud system. Note: Centrifuge efficiencies are influenced by mud weight and mud viscosity. During centrifuge operation, the underflow should be analysed regularly to determine the amount of low gravity solids and barite being removed and retained. centrifuge uses Centrifuges are typically used to: ƒ De-water hydrocyclone underflow; ƒ Remove drilled solids from the active mud system; and ƒ Control rheological properties by removing colloidal particles in weighted drilling fluids. 31

Section

14a

solids control

A decanting centrifuge is so named because it decants or removes free liquid from separated solids. It consists of a conveying screw inside a rotating bowl By exerting increased G-force on the drilling fluid, the particles are accelerated and settle on the outside of the bowl. The free liquid pool is removed and the solids are pushed away and discharged from the bowl. Dewatering For unweighted drilling fluid, the centrifuge use appears cost justified when the drilling fluid and fluid disposal costs increase. This is based solely on the economics of dewatering hydrocyclone underflow. As fluid costs increase, centrifuge use is highly recommended for reducing costs. Greater portions of the circulating flow should be processed. The improved separation efficiency that can be derived from wider use of centrifuges is recommended for reducing drilling wastes. Drilled Solids Removal To minimise the dilution rate in an unweighted mud, the centrifuge is cost effective operating on the active mud system. With solids content less than 10%, a centrifuge can operate at high speeds, thus removing a larger volume of the clay size solids. In some cases, this process can be enhanced with the use of a polymer flocculation system. Control of Mud Properties To minimise drilling waste on weighted muds (oil/water) two stage centrifuging is viable provided the centrifuges are properly chosen and adjusted. The first centrifuge should be adjusted for solids recovery, with the second centrifuge providing maximum liquid-solids separation. This process also can be enhanced by using a polymer flocculation system on the water base muds only. Proper upstream drilled solids removal is necessary to obtain the maximum benefits from centrifuging an active weighted drilling fluid system. Shale shakers should achieve a solids separation in the 70 – 75 micron range. Since the majority of the barite distribution is below this range, maximum drilled solids can be removed with minimal barite loss.

Operating Range of Centrifuges Speed(Rpm)

G-Force

Capacity(gpm)

Cap L/min

Unweighted DE-1000 14” x 49”(356 x 1245 mm) DE-1000 DB-1 24” x 45”(610 x 1143 mm) DB-2 24” x 38”(610 x 965 mm)

3250 2450 2000 1800

2100 1194 1364 1105

150 150 170 130

567 567 643 492

Weighted DB-2 DB-3 DS-2 DS-3

1450 1450 1950 1950

717 537 756 756

25 - 50 10 - 35 10 - 35 10 - 30

94 - 189 38 - 132 38 - 132 38 - 113

18” x 28”(457 x 711 mm) 14” x 30”(356 x 762 mm) 14” x 22”(356 x 559 mm)

Table 9 – Centrifuge Operating Range

32

G – Force for a Centrifuges Oilfield units G Force for a centrifuge: G’s = RPM2 x 0.0000142 x Diameter of bowl (in inches) S.I units G Force for a centrifuge: G’s = RPM2 x 0.0000559 x Diameter of bowl (in mm)

position in the system Dependent on exact application and fluid types. Typical installation has suction downstream of desilter and return downstream. If a dual system is used, an intermediate tank is used.

centrifuge set up The effect of various design and feed parameters on centrifuge performance has been evaluated. The results of this study are summarised to assist in the selection and operation of centrifuges. Since many centrifuge parameters are related, one aspect of performance cannot be discussed singularly without implicating others. However, in general, centrifuge performance is affected by the following parameters in decreasing order of importance. “G” Force According to Stokes Law, particle setting velocity is proportional to G-force. Since G-force increases with the square of bowl RPM, it is an important parameter. G-force also increases linearly with bowl diameter. Figure 1 shows how solids removal efficiency improves with increasing G-force. For a given particle size and fluid properties, there is a minimum G-force necessary to invoke settling. Although high G-force is desirable, the cost is proportional to the cube of the bowl rpm and there are similar economic limitations on bowl diameter as well. Thus, the required G-force must be obtained from a practical combination of speed and diameter. Most oilfield centrifuges have bowl dimensions from 14 - 28 inches (356 - 711 mm) in diameter and lengths from 30 - 55 inches (762 - 1397 mm). Rotational speeds range from 1000 - 4000 rpm, depending on the application. The more expensive, high “G” machines can provide up to 3,000 G’s. The specifications for each centrifuge are listed in Equipment Specifications. Note: however, that increasing G-force eventually reduces solids conveyance capacity due to torque limitations. As G-force increases, more solids are settled in the bowl and they adhere more tightly. More conveyor or torque is required to move the solids out. Once the torque limitations of the machine are reached, conveyance ceases. Effect of G-Force on Separation (Higher G’s Improve Separation Performance)

33

Section

14a

solids control

Viscosity From Stokes Law, particle settling velocity is inversely proportional to fluid viscosity. The following figure illustrates the beneficial effects of a feed mud with a low yield value. This shows the merit of diluting the centrifuge feed to improve performance. It also helps explain the relatively poor performance of centrifuges when processing polymer fluids with characteristically high viscosities at low shear rates.

Effect of Viscosity on Separation Performance (higher yield values degrade centrifuge separation performance) Cake Dryness Discharge dryness is commonly considered a direct indication of centrifuge performance. However, test results have shown that cake dryness is more correctly a function of particle size, and therefore, is inversely related to separation efficiency. Test points have yielded the driest solids corresponded to the lowest efficiency and coarsest D50 separation. As shown in Figure 3, Solids dryness occurs at a threshold G-force level. Subsequent increases in G-force do not remove additional liquid. Length of the dry beach within the centrifuge bowl (a function of pond depth) also has little effect on dryness. Dry beach length refers to the distance from the solids discharge ports to the surface of the fluid pond within the centrifuge bowl. But the small difference in dryness made a significant difference in the appearance of the solids. At 71% by weight, the solids were quite runny and at 75% weight, the solids seemed much more “stackable”. Effect of G-Force on Cuttings Dryness (above a certain threshold G-force, cuttings dryness does not improve)

34

Pond Depth and Processing Capacity Pond depth controls both fluid residence and dry beach length. With increased pond depth, residence time increases separation. However, increased pond depth reduces centrifuge flow capacity. Maximum flow capacity is controlled by the height of the cake discharge port. When the fluid depth in the centrifuge bowl reaches this height, drilling fluid flows out along with the discarded cake. The flowrate as which liquid spills out the cake discharge port is called the “flood out” point. Since one objective of centrifuging is to limit liquid waste, it is obviously not advantageous to run the centrifuge at a flow rate beyond the “flood out” point. Flooding is controlled by a combination of pond depth and flowrate. The pond depth is set mechanically by an adjustable weir. The flowrate increases pond height according to the viscous drag forces which increase the fluid head required to drive the liquid through the centrifuge. The head height is added to the fixed pond depth to give a total depth of fluid of 3 inches (76 mm) before floodout (closed fluid exit ports). If 300 gpm (1135 L/min) is the maximum flow rate at flood-out with a 1 inches (25 mm) pond depth setting, this means 2 inches (51 mm) of fluid head was developed. If the pond depth setting is adjusted to 2 inches (51 mm) then only 1 inch (25 mm) of fluid head is available before the 3 inches (76 mm) flood-out point is reached. Obviously, the maximum flowrate for this pond depth setting will have to be much less than 300 gpm (1135 L/min). Maximum flow capacity is achieved when the shallowest pond depth is used at the expense of separation efficiency. Conversely, deep ponds maximise separation efficiency at the cost of flowrate capacity. The best combination is determined by the coarseness of the solids to be separated. Figure 3 illustrates how, for a fine solids size distribution, a deep pond depth at lower flowrates can produce almost the same cake rate as a shallow pond depth at higher flowrates. This is due to improved separation efficiency of the deep pond case. Figure 4 shows how, for coarse solids, the higher flow capacity of the shallow pond produces more solids removal than the deep pond case. The results suggest that, for coarse particle size distributions as encountered in top hole drilling, shallow pond depths are advantageous, whereas deep ponds should be used for all other applications. Effect of Pond Depth on Fine Solids Removal (deeper ponds are more efficient than shallow ponds when the solids are very fine)

35

Section

14a

solids control

Effect of Pond Depth on Coarse Solids Removal (shallow pond depths are preferred for coarse solids distributions)

Bowl – Conveyor Differential RPM and Torque Differential RPM is the difference between the bowl RPM and the conveyor RPM. The differential is provided by the gearbox which transmits power from the bowl to the conveyor. Differential RPM is simply calculated by dividing the bowl RPM by the gearbox ratio. Many centrifuge manufacturers provide a “backdrive” which can independently alter the RPM. Backdrive units are, in effect, hydraulic gear reduction systems used to vary the speed of the conveyor relative to the bowl. On “backdrive” units RPM depends upon the rotation of the gearbox pinion and the orientation of the flights on the conveyor. For these units RPM may be calculated by: RPM = (Bowl RPM – Pinion Speed)/Gearbox Ratio RPM is important because it determines the velocity at which solids are conveyed through a centrifuge. For example, a RPM of 50 and a flight pitch of 3 inches (76 mm) yields a conveyance velocity of 150 in/min (3810 mm/min). Another expression takes the flight pitch and number of leads on the conveyor into account to describe the surface area of the bowl swept by the conveyor flights per unit time. The faster the rate at which the area is swept, the greater the solids capacity. As = 2 r cyl x RPM x Sn Where: As R S N

= = = =

swept area/unit time cylindrical bowl radius flight pitch number of leads on the conveyor

This equation suggests that solids capacity can be increased by increasing the RPM (lowering the gearbox ratio). Low swept area values could indicate potential torque problems. For example, centrifuges with 130:1 or higher gearbox ratios and centrifuges with 80:1 gearbox ratios with single lead conveyors may be limited in flowrate by torque. Test data indicates that by increasing RPM reduces torque. Also, torque pressure as feed median particle size increases. Despite the common belief that high RPM values agitate the pond and inhibit sedimentation, test results indicate that the effect of RPM on solids removal efficiency is slight, provided sufficient differential exists to remove the solids.

36

Centrifuging Unweighted Mud Centrifuging unweighted muds provides two major benefits (1) the removal of drilled solids that are too fine to be removed by any other solids removal device, and (2) a relatively dry discharge. Although the centrifuge cannot remove ultrafine, colloidal solids, it is important to remove the fine solids before they degrade into these submicron particles. As a rule, at least 25% of the circulating rate should be centrifuged. It is usually uneconomic (and logistically unfeasible) to process the entire circulating rate. Regardless, the benefits of centrifuging to remove fine solids cannot be understated. High-G high capacity centrifuges are recommended to maximise separation performance. Since separation efficiency varies inversely with feed rate and residence time, the optimum feed rate is not necessarily the highest possible rate. Rather, it is the combination of pond depth and feed rate that produces the highest solids discharge rate. The maximum efficient processing rate for a large oilfield centrifuge will seldom exceed 250 gpm, even for relatively coarse drilled solids and low fluid viscosities. If the particle size distribution is very fine, more solids may be removed with a lower feed rate and deeper pond depths. Centrifuging Hydrocyclone Underflow When liquid discharge must be strictly controlled due to high mud cost, high liquid disposal cost or limited reserve pit capacity, the centrifuge should process the underflow of the desilter cones. In this configuration, the hydrocyclones are used to concentrate solids to the centrifuge which then separates the drill cuttings from the free liquid and colloidal solids. System performance can be improved by opening the cone apexes to discharge more liquid. This improves the separation efficiency of the cones and produces a less viscous slurry at the underflow. Figure 5 gives an example of how centrifuging desilter underflow becomes economic with increasing mud cost and desilter underflow rates. Enough centrifuge capacity must be available to process slightly more than the cone underflow rate. Additional make-up volume should be provided from the active system downstream of the hydrocyclone feed. Because the hydrocyclone underflow must be segregated from the active system, a separate centrifuge feed compartment is required. Figure 6 and 7 illustrates two designs for the centrifuge feed compartment. The compartment should be small (<50 bbl or 8 m3) to prevent solids settling. Both high and low equalisation should be provided. The low equaliser supplies make-up volume from the active system during normal processing. A valve (normally open) should be installed on the low equaliser. This valve may be used to check that the centrifuge feed rate exceeds the cone underflow rate. If the centrifuge is to be used in weighted mud to process the centrate of the barite recovery centrifuge, the valve should be closed to isolate the feed compartment. The high equaliser is provided to prevent accidental overflow. Economics of Centrifuging Hydrocyclone Underflow (substantial savings are possible by recovering the liquid from cone underflows)

37

Section

14a

solids control

Centrifuging Unweighted Mud 1. When processing the active system, the centrifuge feed should be taken from the desilter discharge compartment or downstream. The centrate should be returned to the next downstream compartment. 2. Provide enough centrifuges to process at least 25% of the circulation rate, large, high-G units are usually required. 3. Run at maximum bowl RPM to achieve highest G-Force and best separation. 4. Operate the centrifuge just below the flood-out point. 5. The best feed rate and pond depth will depend on the size distribution of the drilled solids. Use shallow ponds and high feed rates when coarse solids predominate. Conversely, deeper ponds and lower feed rates are more efficient when fine drilled solids are to be removed. Field experimentation is necessary to optimise centrifuge set-up. 6. Always wash out the centrifuge on shutdown. (water based mud only) 7. If the centrifuge is to be used on both unweighted and weighted muds, rig up to allow either option. Both the centrate and solids streams should be rigged up to allow each to be discarded or returned to the active system. 8. The solids discharge chute should be angled at greater than 45˚ to prevent solids build-up. If this is not possible, a wash line may be necessary to assist in moving the solids. On land based operations, use the reserve pit as a source for wash fluid. Do not create unnecessary reserve pit volume by using rig water. Fluid Routing to the Centrifuge Hydrocyclone Underflows (the desilter underflow is segregated from the active system for processing by the centrifuge)

Internal Centrifuge Feed Compartment Design (the dense desilter underflow will displace the lighter active system mud from the centrifuge feed compartment)

38

Centrifuging Weighted Muds The centrifuge is used in weighted mud applications to recover valuable weighting material from mud which must be discharged due to unacceptable colloidal solids content. The centrifuge settles out barite and coarse drilled solids which are returned to the active mud system to maintain density. The relatively clean centrate containing liquid and colloidal solids is discarded. These colloidal solids cause many drilling fluid problems, such as high surge/swab pressures and ECD, differential sticking and high chemical costs. Usually the value of the weighting agent in these mud systems makes it economic to recover the weighting agent from the whole mud before it is discarded. Ideally, the barite recovery process should remove only colloidal solids without losing the larger particle sizes used as weighting material. Discarding potentially reusable barite increases barite use and drilling fluid cost. Barite losses can be reduced when the centrifuge makes the maximum liquid/ solids separation. As discussed in the previous section, this means operating the centrifuge at high Gforce. Figure 8 shows the effect of G-force on the amount of barite discarded in the centrate. Centrifuges are usually torque limited in weighted muds due to the high solids content. Typically, torque is reduced by slowing bowl RPM. This reduces G-force and RPM resulting in less effective liquid/ solids separation and the likelihood of increased torque from reduced solids conveyance. Figure 8 – Benefits of Increased G-Force on Barite Recovery (less barite is lost in the centrifuge centrate with increased G-force)

Operating Guidelines, Barite Recovery Mode 1. The following procedures are recommended to reduce torque when operating centrifuges in barite recovery mode to maximise liquid/solids separation: ƒ For a given flowrate, increase the pond depth until the recovered solids become “runny”. Buoyant force reduces the torque needed to convey solids out of the centrifuge. A shallow pond creates a long beach section. Once the solids exit the pool, the extra energy required to convey these solids results in higher torque. ƒ Process weighted mud continuously at a reduced feed rate rather than intermittently at higher feed rates. This reduces solids loads and results in less torque. It also increases residence time which will result in finer separation. ƒ At higher mud weights, use hydrocyclones to reduce the solids loading in the feed mud to the centrifuge. The cone underflow is returned to the active system. The overflow, containing fewer solids is fed to the centrifuge. Since solids concentration is reduced, torque from conveying settled solids is reduced and permits higher G-force centrifuging.

39

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solids control

2. Provide sufficient centrifuge capacity to process 5-15% of the rig circulation rate. Centrifuge capacity is reduced in weighted mud; the 25% target recommended for unweighted mud is usually difficult to attain in weighted mud. 3. Add as much dilution fluid as possible to the centrifuge feed to reduce the mud viscosity and improve centrifuge separation performance. 4. Return the solids to a well-agitated compartment upstream of the suction and mixing tanks. (preferably jet them back in) 5. Use a high weir between the barite return compartment and the next downstream compartment to keep the fluid level high. This will promote better mixing. 6. Always wash out the centrifuge on shutdown. (water based muds only) 7. Routinely check the centrifuge performance by measuring the flowrate and solids composition of the cake and centrate. Two-Stage Centrifuging Two-stage centrifuging is used in weighted muds when the liquid phase cannot be discarded for economic or environmental reasons. The most frequent application is in weighted, oil based muds where the expensive liquid phase cannot be discarded. The first centrifuge recovers weighting material from the weighted mud as discussed in the previous section on single stage centrifuging for barite recovery. The centrate, instead of being discarded is fed to a second centrifuge operating at higher G-force. This centrifuge is used to discard the solids and return the cleaned liquid phase into the active mud system. Two Stage Centrifuging (the first centrifuge recovers barite; the second centrifuge dries its centrate and recovers valuable fluid)

For two-stage centrifuging to be efficient, the first centrifuge must make a good separation since most of the solids in its centrate will be discarded. The poorer the separation, the more barite which will be carried over in the centrate and discarded by the second centrifuge. Similarly, the second centrifuge must operate at the highest possible G-force to remove the most solids. Pond depths should also be deepened to just under the flood out point for the best separation efficiency. Economics of two-stage centrifuging are site dependent. Variables such as time, drilling fluid, buy back agreements and well plans contribute to the overall economics. Field experience has been mixed on the cost effectiveness. As a rough “rule of thumb”, oil based muds with barite concentrations greater than 4 lb/gal (i.e. 12 lb/gal mud) are usually candidates for two-stage centrifuging. Below this concentration, centrifuging to strip all solids including barite may be more economical, especially at lower mud weights. At intermediate mud weights, “dump and dilute” may be a viable option depending upon the conditions of the buy back agreement. “Dump and dilute” in this case means transferring mud laden with low gravity solids from the active mud system to storage tanks for return to the mud company. Clean whole mud is used to replace the “dumped” mud in the active system. Another option is to “do nothing” except screen the mud and dilute when possible to maintain mud properties.

40

The decision to employ this alternative should be made judiciously. It is usually better to err on the side of caution. Over time, low gravity solids will become a large percentage of the weighting material. Filtercake thickness, mud viscosity and material consumption also may increase. However, this may be the least expensive alternative when drilling time is short and hole sizes are small. Oil based muds are quite “solids tolerant” and can withstand some build-up of low gravity solids. This option is not generally recommended for water based fluids. summary ƒ With the emphasis on reduced waste volumes and improved solids removal efficiency, the centrifuge has become an integral part of the drilling solids removal system. Centrifuges are capable of removing very fine solids that cannot be removed by any other mechanical solid removal device. The solids discharge is relatively dry. ƒ Laboratory tests indicate that centrifuge performance is chiefly a function of G-force, pond depth, bowl conveyor differential rpm and mud viscosity. G-force, a function of bowl rpm and diameter has the greatest impact on separation efficiency. Pond depth controls both fluid residence time and flow capacity. Differential rpm is a factor in solids conveyance and torque limitations. Increasing yield values detrimentally affect separation efficiency. ƒ Once a minimum threshold G-force is reached, cake dryness is relatively unaffected by G-force. However, a minor difference in dryness may change the appearance of the solids from runny to stackable. ƒ Large, high G-force machines are recommended for centrifuging unweighted muds. Use deep pond depths and lower flow rates for find solids distributions. Coarse solids distributions may be more efficiently processed using shallow pond depths and higher flow rates. ƒ Centrifuging hydrocyclone underflows becomes increasingly economic as mud formulation and waste disposal costs increase. The centrifuge should process in excess of the hydrocyclone underflow rate. A low-G, high capacity centrifuge is recommended for these coarse solids. ƒ The centrifuge is used in weighted mud to recover valuable weighting material from mud which must be discharged due to unacceptable colloidal solids content. The economics of barite recovery centrifuging is usually positive when the liquid phase is inexpensive and disposal costs are not prohibitive. G-force should be maximised to improve barite recovery. ƒ Two-stage centrifuging is necessary in weighted muds when liquid discharge must be minimised. The first centrifuge recovers barite, its effluent is fed to a second centrifuge operating a maximum Gs, which discards solids and returns the liquid phase. Colloidal solids are not removed. The economics of two-stage centrifuging are site dependent. ƒ Recommended features on a centrifuge include (1) Accelerator for the feed, (2) Tungsten carbide feed port entries and conveyor tiles (3) universally adjustable pond dams and (4) stainless steel bowl and conveyor. However, quality of service is paramount.

shale shaker screens Shale shakers remove solids by processing solid-laden drilling fluid over the surface of a vibrating screen. Particles smaller than the screen openings pass through the screen along with the liquid phase of the drilling fluid. Larger particles and trapped finer particles are separated into the shaker overflow for discard. For any particular shale shaker, the size and shape of the screen openings have a significant effect on solids removal. For this reason, the performance of any shaker is largely controlled by the screen cloth used. Desirable characteristics for shaker screens are: ƒ ƒ ƒ ƒ ƒ

Economical drilled solids removal Large liquid flow rate capacity Plugging and blinding resistance Acceptable service life Easy identification

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The first four items in the above list are largely controlled by the actual screen cloth used and the screen panel technology. Improvements in shale shaker performance are a direct result of improved screen cloth and panel fabrication. The plain square and rectangular weaves are simple over/under weaves in both directions. These weaves can be made from the same diameter wire in one or both directions. The square weave is made by making the spacing between the wires the same in both directions. The rectangular or oblong weave is made by spacing the wire in one direction longer than the wire in the opposite direction. The advantage of plain square and rectangular weaves is that they provide a flow path that has low resistance to flow. Layered screens were introduced to the industry in the late 1970’s. They are often chosen because they provide a high liquid throughput and a resistance to blinding from drilled solids lodging in the openings. A layered screen is the result of two or more wire cloths and overlaying each other. Both square and rectangular cloths can be layered, and reducing the diameter of the wires increases liquid throughput. A large assortment of opening sizes and shapes are produced by the multiple screen layers and the diameter of the screen wire. Because of this, a wide variety of particle sizes pass through the screen. In 1993, a three dimensional surface screen, the “pyramid” was introduced. The screen surface is corrugated, supported by a rigid frame for use primarily on linear motion shale shakers. As drilling fluid flows down these screens, solids are transported in the valleys and the vertical surfaces provide additional area for drilling fluid to pass. This increases the fluid capacity of a particular mesh size when compared with a flat surface screen.

screen identification The nomenclature used to describe screens is important in obtaining an accurate representation of the screen performance. Over the past few years, many new screen designs and types have created much confusion in the drilling industry. Traditionally the mesh count, opening size and percent open area have been used to characterise a screen. However, this description, along with a multitude of different screen clothes led to confusion over that actual screening ability of an individual product. In 2005 a new recommended practice was accepted and issued know as API RP 13C which does away with the traditional mesh size description and replaces it with a quantitative set of testing criteria to accurately describe the screen cut point (d100) and conductance. However, at the time of writing, not all screen manufacturers will be using the new recommended practice and so the market place will contain screens using both the original mesh size labelling system and the new API RP 13C standard labelling system. The following describes terms presently used within the industry, relating to the previous mesh size designations.

42

mesh size designation Plain square and rectangular weaves are often referred to by the number of wires (or openings) in each direction per linear inch. This is known as the mesh count. The mesh count is determined by starting at the centre of one wire and counting the number of openings along the screen grid to the next wire centre, one linear inch away. For example, an 8-mesh screen has 8 openings in two directions at right angles to each other. When counting mesh, a magnifying glass scale designed specifically for this purpose is helpful. Use of a single number for describing screens implies a square mesh. For example “20 mesh” usually describes a screen having 20 openings per inch in either direction along the screen grid. Oblong mesh screens are generally labelled with two numbers. A “60 x 20 mesh”, for example is usually understood to have 60 openings in one direction and 20 openings per inch in the perpendicular direction. Referring to a “60 x 20 mesh” screen as an “oblong 80 mesh” is confusing and inaccurate. The actual separation that a screen is capable of is largely determined by the size of the openings in the screen. The opening size is the distance between wires measured along the screen grid and is expressed in either fractions of an inch or in microns, although it is most often stated in microns. One inch equals 25,400 microns. Keep in mind, specifying the mesh count does not specify the opening size. This is because both the number of wires per inch and the size of the wires determines the opening size. If the mesh count and wire diameter are known, the opening size can be calculated as follows: Oilfield units S.I units L 25.4 L d D = 24,400(( )-d) D = 24,400(( )n n 25.4 Where D = opening size (microns) n = mesh count, number of wires per inch (l/inch) d = wire diameter (inch)

)

Where D = opening size (microns) n = mesh count, number of wires per mm (L/mm) d = wire diameter (mm)

The above equation indicates that screens with the same mesh count may have different size openings depending on the diameter of the wire used to weave the screen cloth. Smaller diameter wire results in larger screen openings, thereby allowing larger particles to pass through the screen. Such a screen will pass more drilling fluid than an equivalent mesh screen made of larger diameter wires. In summary, specifying the mesh count of a screen does not indicate screen separation performance since screen opening size, not mesh count, determines the particle sizes separated by the screen. Comparing the open area with the ability of a screen to transmit fluid, a better measure is the screen’s conductance (or equivalent permeability of the screen cloth). Conductance takes into account both the openings and the drag of the fluid on the wires.

API RP 13C Designation API RP 13C Testing and Labelling Procedure API RP 13C is a new physical testing and labelling procedure for shaker screens. To be API RP 13C compliant, a screen must be tested and labelled in accordance with the new recommended practice. The tests describe a screen without predicting its performance and can be performed anywhere in the world. Internationally, API RP 13C will become ISO 13501.

43

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The lack of commonly accepted screen labelling procedures and great disparity in screen designations throughout the oil and gas drilling industry led to the development of API RP 13C. The new procedure is a revision of the previous API RP 13E, which was based on optical measurements of the screen opening using a microscope and computer analysis. Under API RP 13E, screen designations were based on individual manufacturer test methods, producing inconsistent labelling. Following a review of labelling practices under API RP 13E, the API standards committee concluded that physical testing would be preferred for screen designations. API RP 13C was then developed as an objective method of describing shaker screens. Two tests were devised: cut point and conductance. Screen Cut Point Determined by ASTM* Sieves The API RP 13C cut point test is based on a time-proven testing method used by ASTM to classify particles by size. The procedure utilizes a series of standard-size screens (sieves), which have been used for such analysis since 1910. The API standards committee simply adapted the use of these sieves to designating shaker screens. The shaker screen designation is identified by matching the screen’s cut point to the closest ASTM sieve cut point. The cut point test uses aluminium oxide, a Rotap, a set of ASTM sieves, a test screen, and a digital scale for weighing the quantity of test particles retained by the test screen. The d100 cut point is used for assigning screen designations. d100 means that 100 percent of the particles larger than the test screen will be retained, and all finer particles will pass through. After conducting three Rotap tests, the results are averaged, and the screen is given an API number of the test sieve having the closest d100 cut point. For example: Using the table below, Table 5 of API RP 13C, pages 40 and 41, the average of three Rotap tests = 114.88 microns. Therefore, the API designation = API 140.

Table 5 D100 Separation and API Screen Number D100 Separation (Microns) API Screen Number >780,0 to 925,0 API 20 >655,0 to 780,0 API 25 >550,0 to 655,0 API 30 >462,5 to 555,0 API 35 >390,0 to 462,5 API 40 >327,5 to 390,0 API 45 >275,0 to 327,5 API 50 >231,0 to 275,0 API 60 >196,0 to 231,0 API 70 >165,0 to 196,0 API 80 >137,5 to 165,0 API 100 >116,5 to 137,5 API 120 >98,0 to 116,5 API 140 >82,5 to 98,0 API 170 >69,0 to 82,5 API 200 >58,0 to 69,0 API 230 >49,0 to 58,0 API 270 >41,5 to 49,0 API 325 >35,0 to 41,5 API 400 >28,5 to 35,0 API 450 >22,5 to 28,5 API 500 >18,5 to 22,5 API 635 TABLE 10 – ARI RP 13C Screen Designation

44

ASTM* sieves mounted on Rotap with the test screen in the centre. Sieves used for this test range from 70 to 140. Cut point is determined by comparing quantity of test particles trapped by test screen with quantities in ASTM sieves above and below test screen. * American Society for Testing and Materials Conductance Test Determines Permeability Conductance is a measure of the ability of a fluid to pass through a screen. This property is determined by flowing 5W30 motor oil through a screen sample and then applying the pressure differential to a formula to calculate the conductance. Motor oil was selected because it oil-wets the screen and has a high viscosity. A large volume of motor oil is needed to allow equilibrium and to prevent large temperature changes.

Screen Shape and Conductance Corrugated screens have up to 125 percent more surface area than conventional flat screens. Gravity forces the solids into the corrugated screen’s troughs, thus allowing more fluid to pass through the top of the screen. With conventional flat screens, conductance is reduced as solids form a continuous bed that impedes fluid flow. 45

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Required Screen Label Information After identifying the cut point and conductance, complying with API RP 13C requires application of a permanent tag or label to the screen in a position that will be both visible and legible. Both cut point expressed as an API number1 and conductance shown in kD/mm are required on the screen label. Previously, screens were labelled in accordance with manufacturer specifications.

The API designation text MUST be at least twice the size of any other text on the label.

1

Independent Lab Test Results Cut point and conductance were tested on four shaker screens by an independent lab for API’s Task Group 5. Compared to an ASTM 200 screen, it is obvious that one screen will have a vastly different cut point than the other. The photographs below are magnified 200x and clearly show that cut points vary significantly among screen manufacturers.

46

API RP 13C (ISO 13501)

API RP 13C Designation API Screen Number API 200 API 170 API 140 API 140 API 120 API 100 API 80 API 70 API 60 API 50 API 45 API 40 API 35

Master Tag Reference Chart NEW Part # OLD Part # According to API RP 13C

According to API RP 13E

Screen Panel D100 Cut Point Designation (Microns) DX-A200 78 DX-A170 97 DX-A140F 107 DX-A140 115 DX-A120 120 DX-A100 154 DX-A80 184 DX-A70 221 DX-A60 257 DX-A50 314 DX-A45 360 DX-A40 453 DX-A35 503

Screen Panel Designation DX 250 – DX 210 DX 175 – DX 140 DX 110 DX 84 DX 70 – DX 50 DX 44 DX 38

New Conductance # According to API RP 13C

PWP™

PMD™

PMD+™

0.79 1.30 1.56 0.98 1.48 2.01 1.00 1.62 1.98 1.10 1.67 2.24 1.39 1.78 2.14 1.36 2.30 2.85 1.53 2.45 3.08 2.21 3.56 4.71 2.71 4.13 5.87 3.25 5.42 6.62 3.80 6.72 7.38 5.16 8.03 10.54 5.91 9.76 11.63

API 325 API 270 API 230 API 200 API 200 API 170 API 140 API 120 API 100 API 80 API 70 API 60 API 50 API 45 API 40 API 35

HP-A325 HP-A270 HP-A230 HP-A200F HP-A200 HP-A170 HP-A140 HP-A120 HP-A100 HP-A80 HP-A70 HP-A60 HP-A50 HP-A45 HP-A40 HP-A35

43 50 65 77 81 83 103 120 151 184 203 255 276 336 392 499

HP 310 – – HP 265 HP 230 HP 200 HP 180 HP 150 HP 125 HP 100 HP 80 HP 70 HP 60 HP 50 HP 45 HP 40

0.66 0.86 1.23 0.67 0.90 1.27 0.68 0.93 1.30 0.69 0.96 1.33 0.72 1.11 1.54 0.93 1.46 2.05 1.06 1.85 2.50 1.25 2.33 2.94 1.46 2.57 3.63 1.94 3.20 4.35 3.46 4.35 5.33 4.44 4.98 5.69 5.01 5.26 6.80 6.61 7.67 9.66 6.71 7.38 7.71 8.59 9.36 11.57

API 325 API 270 API 230 API 200 API 140 API 120 API 100 API 20

DF-A325 DF-A270 DF-A230 DF-A200 DF-A140 DF-A120 DF-A100 DF-A20

44 53 67 76 104 121 143 821

– – DF 280 DF 230 DF 200 DF 165 DF 145 DF 24

0.39 0.51 0.71 0.47 0.62 0.89 0.64 0.85 1.22 0.74 1.07 1.40 0.78 0.94 1.20 0.88 1.17 1.54 1.21 1.48 2.08 14.05 15.46 20.61

TABLE 11 – API RP 13C Master Tag Reference Chart - RM (1/16/2008 Rev11)

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cut points In general, screens on shale shakers reject solids larger than their opening sizes and retain the drilling fluid and smaller solids. Drilling fluid properties, as well as screen conditions may affect screen performance. For example, high gel strengths and high surface Tensions tend to bridge small screen openings and prevent screens from passing small solids and liquid; filtration control additives, such as starch, tend to plug screen openings and prevent small solids and liquid from passing; and in an oil based drilling fluid, water wet, fine mesh screens may reject a large portion of the drilling fluid from flowing onto the screen. When 50% of the mass of a particular solid size is found in the underflow of a screen and 50% of the mass of that size is found in the overflow, that size is sand to be the d50 or 50% cut point. Cut point curves, or a percent separated curve, is a graphical representation of the actual measured separation of solids made by the screen. For example, a d20 cut point would be the size where 80% of the mass of solids of that size are returned to the drilling fluid (pass through the shaker screen) and 20% of the mass of that size solid is rejected from the system (discarded).

causes of premature screen failure Several factors may contribute to premature screen failure. Most failures result from improper screen installation or damage to the shaker itself. Cracked or warped shaker beds, which may result from many years of continuous use or improper maintenance, will cause poor vibration patterns. This may cause improper maintenance, will cause poor vibration patterns. This may cause improper solids conveyance, which in turn, may cause solids to gather on certain areas of the screen, wearing holes in that section. Damaged beds may also affect the tensioning ability of the tension system, inducing flexure in the screen. This increase in flex causes the screen itself to vibrate separately from the basket against the screen support stringers, damaging the spot on the screen where this is occurring. An increase in screen flexure ultimately results in most cases of early screen fatigue. All screen tensioning components must be in proper working order to eliminate screen flexure and maximise screen life. Some of the screen tensioning system materials that must be maintained include the cross and side supports, channel rubbers, and tension bolts. As prolonged use of the shakers continues, the support rubbers – rubber liners that cover the support stringers – will begin to wear. In order for the support rubbers to tension the screens properly, they must be all the same thickness; however, this is rarely the case once these rubbers begin to wear. Flexure develops in the areas where the greatest amount of wear has occurred on the rubbers, reducing the screen life. The side and cross supports – fibreglass strips on which the screens rest along the inside of the shaker bed – will wear in a similar manner. This interferes with the ability of the bolts to apply the proper amount of tension on the screens, which will again cause loose screens and rapid failure. Bent steel supports that interlock with hook strips on the screens to fasten the screens directly to the shaker bed – will not allow tension to be applied evenly throughout the full length of the screen, also resulting in early screen failure. To achieve maximum screen life, all tension bolts must be operating properly. If early screen failure occurs, check to make sure that one or more of the tension bolts are not missing and that they are tightened correctly. The tension bolts should be tightened to manufacturers recommendations. Before installing any screens, the shaker bed must be washed clean of any debris. Proper tensioning of the screen cannot be achieved if any substance comes between the screen and the bed. Improper installation or maintenance of the tensioning devices results in premature screen failure.

48

Excessive solids accumulation in conjunction with poor solids conveyance, causes increased wear on the screens where is occurring. This problem may arise, particularly with the three dimensional screen, if the screen is not in alignment. Where misalignment occurs, solids tend to accumulate and wear screens in that area. Another possible cause of improper solids conveyance, and therefore, screen wear is the linear motion vibrators running in the same direction, which causes an improper vibration pattern. This results in massive amounts of solids accumulating on the first screens, causing them to wear quickly. This can easily be remedied by reversing the electric wiring to the motors. The vibrators of the shakers should be tested before spudding he well. Also, be certain that both vibrators are operating. If not, replace the inoperable vibrator.

screen blinding Screen blinding occurs when grains of solids being screened lodge in a screen hole. This often occurs when drilling fine sands, such as in the Gulf of Mexico. The following sequence is often observed during screen blinding. 1. When a new screen is installed, the circulation drilling fluid falls through the screen in a short distance. 2. After a time, the fluid endpoint travels to the end of the shaker. 3. Once this occurs, the screens are changed to eliminate the rapid discharge of drilling mud off the end of the shaker. 4. After the screens have been washed, fine grains of sand that are lodged in the screen surface can be observed. The surface of the screen will resemble fine sandpaper because of the sand particles lodged in the openings. One common solution to screen blinding is to change to a finer or coarser screen that he one being blinded. This tactic is successful if the sand that is being drilled has a narrow size distribution. Another solution is to change to a rectangular screen, although rectangular screens can also blind with multiple grains of sand. Blinding – the “plastering” of a soft material over and in the mesh, rendering it blocked. Remedy = wash with high pressure fluid using the base fluid of the drilling fluid. If this fails, fit coarser screens temporarily. Plugging – the blocking of the mesh by a particle (usually sand) fitting into the pore throat of the mesh. Remedy = wash with high pressure fluid using the base fluid of the drilling fluid. This is best done from beneath the screen (after removal). It is often successful to place a finer screen on to reduce the “near size” plugging.

screen panels Shale shaker screens changed as demands on the shale shaker increased. Shaker screens have three primary requirements: ƒ High liquid and solids handling capacity ƒ Acceptable life ƒ Ability to be easily identified and compared. Early shale shaker screens required durability. This demand was consistent with the shaker designs and solids removal philosophies of their period. These shakers could only remove the large coarse solids from the drilling fluid while the sand trap, reserve pit and downstream hydrocyclones removed the bulk of the drilled solids.

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Changes in drilling fluids, environmental constraints, and a better understanding of solids/liquid separation have modified the role of the shale shaker. Generally, the more solids removed at the flow line, the higher the effectiveness of downstream equipment. The results include reserve pits that can be smaller (or eliminated altogether), lower clean-up costs, and increased drilling efficiency. As important as the mechanical aspects of newly designed shale shakers may be, improvements in screen panels and screen cloth have also significantly increased shaker performance. Older shakers have benefited from these improvements, as well. Two design changes have been made to extend the economic limit of fine screen operation: ƒ A coarse backing screen to support the fine mesh cloth(s), and ƒ Tensioned cloth bonded to a screen panel (pretensioned screen panel). hook strip screens Hook strip screens are also available. Because of the superior life characteristics of the panel mount units, they have been relegated to a minor role on linear motion machines, although they are used extensively on circular and elliptical motion machines. Proper tensioning (and frequent retensioning) of all screen types is good screen management and can significantly increase screen life. Individual manufacturers operation manuals should be consulted to obtain the proper installation methods and torque requirements, where applicable, for specific screens/panels. bonded screens Several types of bonded screens are available. The repairable perforated plate screen has one or more layers of fine mesh cloth bonded to a sheet of metal or plastic with punched, patterned holes. Perforated plate designs are available in various opening sizes and patterns. Additional designs include a special application where backing and fine screen(s) materials are bonded together, eliminating the need for perforated plates. Flat-surfaced, pretensioned screen panels are becoming popular because of their even tensioning, easy installation, and the even distribution of liquids and solids across the screen deck. three-dimensional screen panels Three-dimensional screen panels were introduced in the mid 1990’s. These typically offer more screening area than flat-panel, repairable plate screens while retaining the ability to be repaired. This type of screen panel adds a third dimension to the previous two-dimensional screens. The screen surface is rippled and supported by a rigid frame. Most three-dimensional screen panels resemble the metal used in a corrugated tin roof. Construction consists of a corrugated, pretensioned screen cloth and bonded to a rigid frame. Like bonded flat screens, the three-dimensional screen panel needs only to be held firmly in place with a hookstrip or other means to prevent separation between the shaker bed and the screen panel during vibration. Three-dimensional screen panels can be used to support any type or style of wire cloth and can be used with any type of motion. Three-dimensional screen panels allow solids to be conveyed down into the trough sections of the screen panel. When submerged in a liquid pool, this preferential solids distribution allows for higher fluid throughput than is possible with flat screen panels by keeping the peaked areas clear of solids. A three-dimensional screen panel improves distribution of fluid and solids across the screen panel. This reduces the characteristic “horseshoe effect” caused by shakers using crowned screen beds.

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screen effectiveness Two factors that determine the effectiveness of a screen are mesh size and screen design. Mesh Size. The screen opening size determines the particle size a shaker can remove. Screen mesh is the number of openings per linear inch as measured from the centre of the wire. For example, a 70 by 30 oblong mesh screen (rectangular opening) has 70 openings along a one inch line one way and 30 openings along a one inch line perpendicular to the first. Actual separation sizes are determined by factors such as particle shape, fluid viscosity, feed rates and particle cohesiveness. Some muds can form a high surface tension film on the wires of the screen and reduce the effective opening size of the screen. The following table lists specifications for different screen sizes and mesh shapes. Table 12 – Square and Oblong Mesh Screens (This table provides specifications for square mesh screens of different sizes) Square Mesh Screens Mesh

Wide Diameter Inches mm

Opening Width Inches

mm

Microns

Percent Open Area

20 x 20

0.016

0.41

0.0340

0.86

863

46.2

30 x 30

0.013

0.33

0.0203

0.52

515

37.1

40 x 40

0.010

0.25

0.0150

0.38

381

36.0

50 x 50

0.009

0.23

0.0110

0.28

279

30.3

60 x 60

0.0075

0.19

0.0092

0.23

234

30.5

80 x 80

0.0055

0.14

0.0070

0.18

178

31.4

100 x 100

0.0045

0.11

0.0055

0.14

140

30.3

120 x 120

0.0037

0.094

0.0046

0.12

117

30.5

150 x 150

0.0026

0.066

0.0041

0.10

104

37.4

170 x 170

0.0024

0.061

0.0035

0.089

89

35.1

200 x 200

0.0021

0.053

0.0029

0.074

74

33.6

250 x 250

0.0016

0.041

0.0024

0.061

61

36

Square Mesh Screens Mesh

Wide Diameter Inches mm

Opening Width Inches

mm

Microns

Percent Open Area

20 x 30

0.014

0.36

0.036/0.0193

0.91 / 0.49

914/490

41.8

20 x 40

0.013

0.33

0.037/0.012

0.94 / 0.30

940/305

35.6

20 x 60

0.009

0.23

0.041/0.0076

1.04 / 0.19

1041/193

34.0

40 x 60

0.009

0.23

0.016/0.0076

0.41 / 0.19

406/193

29.4

40 x 80

0.0075

0.19

0.0181/0.0055 0.46 / 0.14

457/140

35.6

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14a

solids control

Screen Design. Screens are available in two and three dimensional designs. Two-dimensional screens can be classified as: Panel Screens, with two or three layers bound at each side by a one piece, double folded hook strip. Perforated Plate Screens, with two or three layers bonded to a perforated, metal plate that provides support and is easy to repair. Three-dimensional screens are perforated, plate screens with a corrugated surface that runs parallel to the flow of fluid. This configuration provides more screen area than the two-dimensional screen configuration. The different types of three-dimensional screens are: ƒ Pyramid ƒ Plateau The following figures shows the difference between two and three dimensional screens.

screen designations The API (RI13E) recommends that all screens be labelled with the screen name, separation potential and flow capacity. Optional screen labels include US sieve number, aspect ratio and transmittance. The following table depicts how screens can be labelled using all descriptors.

US Sieve No.

Separation Potential, Microns

Flow Capacity

d50

d84

Cond

Area

Pyramid PMD DX50

48

318

231

389

6.10

7.42

1.45

45.3

Flat PI

47

327

231

349

8.85

7.28

1.43

64.4

Screen Name

d16

Aspect Ratio

Transmittance

Table 13 – Screen Designation Example The following definitions apply to this table. Separation Potential. The percentage of particles of the specific size, in microns, that can be removed. Examples: d50 Particle sizes in microns where 50 percent of the particles are removed d16 Particle sizes in microns where 16 percent of the particles are removed d84 Particle sizes in microns where 84 percent of the particles are removed Note : d50 is listed first in most tables because it is the most common.

52

Separation Potential (The percentage of microns removed increases as the equivalent spherical diameter of particles increases.

Flow Capacity. The two parts of flow capacity include conductance (Cond) and non-blanked (open space) area (Area). Conductance is the amount of open space between wires in kilodarcies per millimetre. The non-blanked (open space) area is the total effective screening area per panel in square feet. Aspect Ration. The volume weighted average length to-width of the screen openings. Transmittance. The net flow capacity of individual screens; the product of conductance and unblocked screening area.

system layout fundamental principles It is common to experience instances where incorrect pit and tank configuration occurs when this happens increased waste production results, inefficient separation and in some instances it creates hazardous conditions. tank design The surface pits that comprise the active circulating systems should be designed to contain enough usable mud to maintain mud properties and to fill the hole during a wet trip at the rig’s maximum rated depth. Usable mud is defined as the mud volume which can be pumped before suction is lost. For example, a typical 1000 ft (305 m) well will normally require a minimum active system tank volume of 500 bbl (80 m3). The active surface system can be divided into two sections; solids removal and addition suction. All solids removal equipment and degassing occurs in the solids removal section. The addition suction section is used to add fresh mud to the circulating system and provide sufficient residence time for proper mixing to occur before being pumped downhole. A slug tank is usually available to pump small “pills” such as LCM or barite slugs for tripping. Each section must be further divided into enough compartments to efficiently carry out its designed function. The number of compartments needed will depend upon the amount and type of solids removal equipment, system size and circulation rate. Each compartment must have enough surface area to allow entrained air to break out of the mud. A rule of thumb for the minimum surface area is calculated by: Area (ft2) = Maximum Circulating Rate (GPM) / 40

53

Section

14a

solids control

To maximise solids suspension and usable volume, the best tank shape is round with a conical bottom. Next best is a square or rectangular shape with a v-bottom. The least preferred shape is the square or rectangular box with a flat bottom. The ideal tank depth is equal to the width or diameter of the tank. This design provides sufficient pump suction head and is best for complete stirring. compartment equalisation Equalisation height between compartments will depend upon the duty of the compartment. As a rule, an adjustable equaliser is needed only between the solids removal section and the addition suction section. High equalisation between the solids removal and addition suction sections also increases the ability to detect volume changes due to influx or losses to formation. Because the volume of the solids removal section remains constant, any volume change is apparent as a liquid level change in the addition suction section only. This increases the sensitivity to volume fluctuations since the change in fluid level will be more pronounced per unit volume. Recommended equalisation between specific compartments is summarised below: Location Sand Trap Exit Degasser Desander Desilter Centrifuge Solids Removal – Addition Addition-Blend Blend-Suction

Equalisation High High Low Low Low High (Adjustable) Low Low

sand trap A sand trap is the settling compartment located downstream of the shale shakers. It should be the only settling compartment and preferably should not be used in closed-loop systems. Its main function is to remove large solids that might plug the downstream hydrocyclones. With the fine screen capabilities of today’s shale shakers, the sand trap mainly serves as a back-up should the shakers be bypassed or operated with torn screens. The sand trap should be the first compartment the mud enters after passing through the shaker screens. Since it is a settling tank, it should not be stirred and the mud should exit the sand trap over a high weir. The sand trap floor should have a 45° slope to its outlet. A 20 - 30 bbl (3.2 - 4.8 m3) volume is sufficient. A quick opening solids dump valve that can be closed against the mud flow is recommended to reduce mud losses. The sand trap should be dumped only when nearly filled with solids, since whole mud is lost when the sand trap is dumped (not oil based muds).

54

Optimum System Layout

55

Section

14a

solids control

equipment arrangement The solids removal equipment should be arranged to sequentially remove finer solids as the mud moves from the flowline to the suction pit. The purpose of this arrangement is to reduce the solids loading on the next piece of equipment. Each device must take mud from an upstream compartment and discharge into the next compartment downstream. This applies to both unweighted and weighted mud equipment arrangements. The amount and type of equipment required will depend upon the drilling conditions and economics specific to each well. Proper routing of fluids through the solids removal system is essential to achieve maximum solids removal efficiency. Mistakes in fluid routing can drastically reduce separation performance by causing a large percentage of the circulation flow to be bypassed. These errors are most commonly associated with mud cleaners and hydrocyclones. In addition to suction and discharge routing, overflow discharges to mud ditches and mud gun use are other common sources of routing errors.

do’s and don’ts General Guidelines for Surface System Arrangements The following guidelines are common to all equipment arrangements. 1. All removal compartments except the sand trap should be well agitated to ensure even solids loading. 2. Mechanical stirrers are recommended. Check that they are properly sized and installed correctly. 3. Mud guns are not recommended for the solids removal section. 4. When installed, the degasser should be located immediately downstream of the shale shaker and upstream of any equipment fed from a centrifugal pump. 5. Use a high equaliser between degasser suction and discharge. 6. All solids removal equipment should discharge immediately downstream of their suction compartments. 7. All equipment except the centrifuge should process at least 100% of the circulation flow. Backflow should be observed in these compartments. 8. Low equalisation between suction and discharge for all solids removal equipment. 9. Different solids control devices must not share suction compartments or share discharge compartments unless they are making the same cut. For example, two desilters may share the same fluid routing, but a desander and desilter should not. 10. Adjustable equaliser between solids removal section and addition suction section. This equaliser should normally be high except when access to the additional volume in the solids removal section is desired. 11. No solids removal equipment should discharge into the suction pit with the exception of the centrifuge if suction is achieved from the same pit.

zero discharge set-up 1. Minimisation of waste is paramount here. The use of large tank volumes is largely unnecessary. Other than the degasser system, all other pits should be bypassed wherever possible. The sandtrap is largely made redundant by effective 21st century shale shakers. 2. Pit residue must be reduced to a minimum. 3. On completion of the section, the tanks should be circulated over the shale shaker to recover as much free fluid as possible. 4. Never dump the traps, tanks and pits without understanding the implications of that action on the waste generation. Cleaning of the traps/pits/tanks in zero discharge situation requires planning on strong procedurally driven actions. Dump and flush is inappropriate. Where appropriate, recover all free fluid using pumps and vacuum recovery equipment.

56

section 14b

containment

section 14b cuttings blowing pump 800 (cbp 800)

Scomi Oiltools

2

vccs (vacuum continuous collection system) and pit cleaning

4

cuttings discharge pump (cdp)

7

screw conveyor

9

drilling waste container

10

rig-vac™

11

hippo™

12

slurry blowing pump 60 (sbp 60)

13

Section

14b

containment

containment

cuttings blowing pump 800 (CBP 800) Summary: The CBP 800 pneumatically blows drill cuttings and centrifuge waste from a collection point on the rig, to a temporary bulk storage tank(s) on the rig, or directly to a workboat / barge / truck. The movement of cuttings directly from the rig to a workboat is often described as “bulk transfer” as it negates the requirement for numerous smaller drilling waste containers lifts previously the norm for ship to shore projects. Features and Benefits: ƒ Features ƒ No moving parts in contact with the cuttings ƒ Will convey solids, sludges and slurries ƒ Conveying system is fully enclosed ƒ Proven oilfield service using dense phase conveying ƒ Flexible installation to suit the rig ƒ Benefits ƒ High capacity in excess of 35MT per hour ƒ Allows cuttings to be blown straight to a boat / barge or bulk storage tanks / containers on the rig ƒ Reduces exposure to drilling wastes on the rig ƒ Crane lifts are minimised, reducing the risks associated with lifting numerous drilling waste

containers from the rig to a boat.

Technical Description: The CBP 800 moves cuttings in what is known as dense phase conveying, with the air being generated by a compressor. A back up compressor or duel compressor is recommended to eliminate any chance of downtime due to failure of the compressor. The CBP 800 comprises of two (200 liter) pressure vessels, a plc system, and a series of 8” (203 mm), 6” (152 mm) and 1” (25 mm) valves to control the cycles for filling and discharging the vessels. The duel vessel arrangement allows one to be filled whilst the other is discharging on a continuous basis. The vessel sequence can be controlled by weight, volume or time. The plc system records all the data, which is available for subsequent downloading and analysis. Each vessel is capable of moving 35 MT per hour of drill cuttings based on a cuttings density of 2 grams / cm3. The vessels are typically fed by an auger feed system from the shakers or centrifuge. The cuttings are discharged into either a temporary bulk storage tank on the rig, or onto tanks on the boat. On a land job the cuttings could be blown directly to a truck or into a holding pit. The boat will typically be laid out with a number of holding tanks with a 20MT to 40MT capacity each. A plc controlled manifold system with diverter valves ensures that each tank can be filled in any given sequence. The system is fully automatic with plc feedback to the CBP 800 plc on the rig minimising operator intervention.

CBP 800 Unit

Details of the CBP 800

CBP 800 PLC Control System

Section

14b

containment

Bulk Tanks in Norway

Bulk Tanks on Boat

VCCS (vacuum continuous collection system) and pit cleaning Summary: The VCCS offers a safe and efficient means for containing drill cuttings at a rigsite, both offshore and onshore. The movement of air through the system allows the collection of drill cuttings and other drilling wastes, such as centrifuge waste and pit cleaning operations, into vacuum rated drilling waste containers. The system can collect wastes from the shakers and centrifuges or it can be configured to collect waste from pit cleaning operations. The vacuum rated drilling waste containers can then be sealed and transferred to the treatment and disposal location for processing. Features and Benefits: ƒ Features ƒ Low friction / non stick hoses reduce or eliminate hose blockages ƒ Small 4” (102 mm) bore hoses between the drilling waste containers and the vacuum pick-up improve manual handling. ƒ High velocity airspeed (280 ft/sec or 85 m/sec) is capable of conveying both wet and dry materials. ƒ The scrubber and filter units provide high efficiency solids removal ƒ The primary air mover provided a vacuum source up to 15” (81 mm) of mercury and operates below 85 db. ƒ Manual or automatic pit cleaning systems available ƒ Benefits ƒ Quick hook up time due to the equipment being supplied pre-assembled, necessitating attachment of interconnecting hoses only before commissioning ƒ Minimal deck space required as the VCCS framework has a small footprint ƒ Continuous vacuum collection and discharge possible due to the system capacity to isolate and / or operate into one or two drilling waste containers ƒ Collection into drilling waste containers in remote locations on the rig due to jumper hoses connecting the VCCS and drilling waste containers ƒ The automatic pit cleaning system can negate the requirement for man entry into the pits Technical Description: The system consists of: ƒ A primary air mover (PAM) to generate the vacuum source ƒ A scrubber and filter unit to filter out small particles that do not deposit in the drilling waste containers ƒ A containment pipe manifold to divert the waste stream into the appropriate container though the use of manually or automatically activated valves ƒ Drilling waste containers (DWC), designed and rated to withstand the vacuum Air moves through the system at high velocity (approximately 280 ft/sec or 85 m/sec) from the cuttings pick up point to the vacuum rated containers. Cuttings are moved in the fast air stream from the pick up point and are then deposited into the containers as the air velocity drops. Any fine particles that carry on through are captured in the scrubber unit or the air filter fitted to the PAM Unit. The system works on a continuous basis in that there are at least two skips on the containment manifold allowing one DWC to be filled whilst the full DWC is taken away and replaced.

Section

14b

containment

The “Dry” pit cleaning configuration has a small pick up hopper on the pick up line in the pit allowing the cuttings to be deposited into the high velocity air stream and onwards into one of the waste containers. The “Wet” pit cleaning system utilises an automated pressure washing nozzle that directs high pressure to the pit surfaces to clean of any fluids or solids debris. The nozzle provides 360 degree impact indexed coverage for the cleaning of the inside of all tanks and pits. The liquid waste at the bottom of the tank / pit is pumped into a closed loop pill tank where the solids are allowed to settle out for collection and disposal.

PRIMARY AIR MOVER 2000

Oiltools Vacuum Continuous Collection System (VCCS) with Drilling Waste Containers in Remote Discharge Configuration

SCRUBBER UNIT Arrows denote Air Flow

CUTTINGS PICK-UP POINT

VACUUM RATED DRILLING WASTE CONTAINERS

VCCS Drill Cuttings Collection System Layout

PRIMARY AIR MOVER

generate vacuum source

SCRUBBER & FILTER UNIT a high efficiency small particle drop out tank

CONTAINMENT PIPE MANIFOLD enables the co-ordination of containment into various Drilling Waste Containers

PIT CLEANING HOPPER AND LANCE enables the pit clearing personnel to collect pit waste

VACUUM RATED DRILLING WASTE CONTAINER collection unit for the waste vacuumed into the system

VCCS Dry Pit Cleaning System

PILL TANK

holds wash water, typically 30 bbls

POSITIVE DISPLACEMENT PUMP pressure minimum 10 ber. flow 100 USGPM

RE-CIRCULATION PUMP

returns wash water back to pill tank

IN-LINE STRANER

TANK CLEANING HEAD

protects tank cleaning head from solids carried over from pill tank

operates in a predetermined scope of movement to offer full coverage to the pit being cleaned

Wet Pit Cleaning System

Section

14b

containment

cuttings discharge pump (CDP) Summary: The CDP is a safe and efficient vacuum system designed to collect drill solids on a continuous basis and discharge them into drilling waste containers on the rig. The system is fully contained reducing exposure to drilling wastes. Features and Benefits: ƒ Features ƒ Rotary type cuttings discharge pump – provides an air lock between the drop-out and recovery tank and discharge chutes, enabling the continuous collection and discharge of drill cuttings ƒ Discharge chute – remotely operated with up / down and 270° rotational actuator ƒ Drop-our recovery tank – provides 2m3 containment volume ƒ Remotely operated telescopic arm – enables the positioning of the discharge chute to cover up to eighteen drilling waste containers ƒ Control platform – the remotely operated cuttings transfer system is operated from a single elevated location providing a panoramic view over the containment operations

ƒ Benefits ƒ Continuous vacuum collection and discharge of drill cuttings ƒ High containment capacity due to the telescopic arm supplying cuttings to a maximum of eighteen drilling waste containers ƒ Low resource requirement due to the arm being operated by one person only ƒ Exposure to drill cuttings reduced due to remote operation ƒ Reduction in manual handling of suction hoses and / or dump chute due to the remote operation of the telescopic arm and discharge chute Technical Description: Air moves through the system at high velocity from the cuttings pick up point, via the cuttings discharge pump to the airflow source, the primary air mover. The drill cuttings are picked up in the air stream, conveyed and subsequently deposited into one of multiple drilling waste containers. In the standard configuration, as many as eighteen drilling waste containers can be deployed at one time, providing a containment volume in excess of 110m3. The CDP provides and air lock between the drop-out hopper and the discharge chute enabling the continuous vacuum collection of drilling waste into drilling waste containers.

Cutting Discharge Pump

PRIMARY AIR MOVER

DROP.OUT RECOVERY TANK

CUTTING DISCHARGE PUMP (CDP)

DRILLING WASTE CONTAINERS

Typical Cutting Discharge Pump (CDP) System

Typical CDP System Layout

Section

14b

containment

screw conveyor Summary: Screw conveyors are a relatively inexpensive and oilfield proven method to transport drill cuttings and centrifuge waste from one location on the rig to another. Features and Benefits: ƒ Features ƒ Supplied with a metal lids / covers to minimise risks ƒ Metal lids / covers are hinged for easy access once the system is isolated ƒ Versatile as different length can be built and bolted together to suit the required configuration ƒ

Benefits ƒ Low power requirement ƒ Continuous discharge eliminates the need for holding tanks ƒ Minimal operator intervention required ƒ Easily sized to meet anticipated volume rates

Technical Description: The screw conveyor is designed to transport drilling wastes from one point to another safely and efficiently. This is achieved by the use of a scroll (auger), which is rotated inside a trough by an electric motor. The drilling waste is fed into the screw conveyor and transported along by the rotating scroll. The scroll is sealed inside the trough by a hinged metal lid / cover which is bolted down for increased safety. The screw conveyor typically feeds straight from the shaker discharge / centrifuge discharge into another screw conveyor and onwards to the required delivery point. The waste is then unloaded by means of a chute when it reaches the end of the screw conveyor. Where large distances or turns are to be manoeuvred it may be necessary to place several sections of screw conveyors together to achieve the desired installation.

Multi-Point Discharge Conveyor for Container Loading

10

drilling waste container Summary: The Drilling Waste Container (DWC) is designed to hold drill cutting, centrifuge waste and pit cleaning wastes generated during drilling operations. The containers are available as vacuum rated units as required, depending on the method of collection. The full containers are typically transported to a treatment and disposal site for further processing. Features and Benefits: ƒ Features ƒ The container is fully enclosed within a lifting frame ƒ A large sealing door aids filling and emptying ƒ The containers can be provided with certified lifting slings included ƒ The discharge door has an internal seal which is secured by clasps to avoid spillage during transportation ƒ Benefits ƒ The containers are fully reusable avoiding the generation of excess waste ƒ The containers are designed to be safely stacked on top of one another when empty to minimise storage space ƒ The fork lift points at the bottom allow for easy movement and rotation during loading and unloading Technical Description: A typical DWC has an internal volume of 2.3m3 (other sizes are available) with a gross weight of 8000 kg allowing the container to be filled with a maximum of approximately 6600 kg of waste. The containers are typically filled by an auger, or a vacuum / pneumatic transfer system. The access door is easily sealed after filling for safe transport. Unloading normally entails the containers being rotated by a suitable forklift at a process facility.

11

Section

14b

containment

rig-vac™ Summary: The Rig-Vac™ is designed to clean up solids and fluids from a number of potential sources on the rig including spills, the cleaning of ditches, cellars and sumps, and general rig operations. The unit is located in a central position and vacuum lines run to various pertinent locations around the rig. Features and Benefits: ƒ Features ƒ Available with three tank capacities of 1590, 2385 and 3180 litres ƒ Can be switched between vacuum loading and discharge for tank emptying ƒ Large 18” (457 mm) manway for ease of maintenance ƒ System comes with built in pressure relief systems ƒ

Benefits ƒ Improves workplace safety by allowing quick and easy removal of spillages ƒ More powerful than a regular vacuum truck ƒ Collection points are set up at critical locations ƒ Easy to operate with electrical and diesel driven options ƒ Low maintenance

Technical Description: The Rig-Vac™ is a skid mounted system designed to be centrally located for the reclamation, containment and handling of liquids waste and sludges for both onshore and offshore applications. There are three different models, the electrically operated RV-3500 and RV-3560 and the diesel operated RV-4500. Each system is made up of two components. The first is a power plant which incorporates a positive displacement blower, muffler, valve manifold and motor. The second is a tank skid fitted with a tank, suction, discharge and inspection connections.

12

HIPPO™ Summary: The HIPPO™ is designed to reclaim drilling fluid spillages caused by tripping, pulling wet strings or accidental spillages. It can also be used for other waste stream spillages such as wastewater or slurries. The cleaning of ditches, cellars and sumps plus the skimming of pits and cuttings boxes is also possible. Features and Benefits: ƒ Features ƒ Oilfield Proven Technology – similar vacuum units have been used reliably in the oilfield for many years ƒ Anti-Static Construction – all parts are constructed from anti-static or conductive materials to eliminate the build up of static electricity ƒ Compact Skid Design – provides easier installation of the HIPPO™ System ƒ Benefits ƒ Safety – improves workplace environment by allowing quick and easy removal of spillages ƒ Quick Hook-up – only the rig air supply, suction and discharge lines need to be connected for the unit to operate ƒ Flexible Installation - due to the compact skid design, the HIPPO™ can be installed almost anywhere onboard Technical Description: The HIPPO™ System consists of a robust skid mounted package designed for the reclamation, containment and handling of waste liquids from both onshore and offshore operations. The system contains the following components: ƒ 30 gallon (113 liter) tank ƒ Air operated diaphragm pump ƒ Associated pipe work & valves The 30 gallon (113 liter) tank is filled with 2” (51 mm) suction and discharge lines and The skid also contains an inline filter and an air operated diaphragm pump.

The HIPPO™ Unit with Suction Hose and Head

3/4”

(19 mm) air inlet.

The HIPPO™ in Action

13

Section

14b

containment

slurry blowing pump 60 (SBP 60) Summary: The SBP 60 is designed to reclaim drilling fluid, sludges, and solids, transferring them on a continuous basis from one point on the rig to another. It can also be used for other waste stream spillages such as wastewater or slurries. The cleaning of ditches, cellars and sumps plus the skimming of pits and cuttings boxes is also possible. Collected wastes are typically blown into a drilling waste container or alike Features and Benefits: ƒ Features ƒ 60 litre holding tank can be filled and discharged on a continuous bases ƒ The unit can deliver up to 21.5” (546 mm) vacuum ƒ No moving parts in the tank reducing maintenance ƒ Can handle solids up to 30 mm in size ƒ Designed with safety in mind having pressure relief protection and non-return valves ƒ

Benefits ƒ Improves workplace safety by allowing quick and easy removal of spillages ƒ Flexible, being compact and portable from one rig location to another ƒ Versatile – suction distances of up to 15m and discharge distances in excess of 50m ƒ Timers, jet pack and the air regulator are all self contained in the unit making it easy to operate

Technical Description: The SBP 60 works by creating a vacuum to transfer liquids, sludges and solids into the holding tank and then pressuring up the tank to a maximum of 100 psi (690 kPa) to discharge the material. The system consists of: ƒ 60 litre holding tank ƒ Air operated timer system ƒ 2 Solid tyres and wheels The SBP 60 can be wheeled into position and can suck from up to 15 metres away, and blow the material a further 50 metres to the discharge point.

SBP 60 Unit

14

Scomi Oiltools Cuttings Blowing (CBP) 60

SBP 60 Schematic

15

section 14c

treatment and disposal

section 14c

Scomi Oiltools

cuttings re-injection (cri)

2

drill cuttings thermal treatment

4

extractor dryer

10

filtration

13

chemically enhanced centrifugation (flocculation)

15

bio-remediation

16

drill cuttings solidification and stabilisation

18

Section

14c



cuttings re-injection (cri) Summary: Cuttings Re-Injection (CRI) is an in situ method for the disposal of drill cuttings and other drilling wastes into a sub-surface stratum. Drill cuttings are slurrified with water (fresh or sea water) and ground down to a pre-determined particle size. The particle size is achieved by passing through a shaker screen. Slurry of the correct particle size and physical properties is injected via a pump, which is typically of a triplex design, into the well head at a given pressure and down into the pre-determined sub-surface injection zone. Oversize particles from the shaker are re-circulated for further grinding. Features and Benefits: ƒ Features ƒ An efficient method for disposing of NADF drill cuttings ƒ ARCO licensed slurrification system ƒ Modular concept ƒ Venturi feed system ƒ

Benefits ƒ In-situ solution for the disposal of drill cuttings ƒ Negates the need for ship to shore and double handling ƒ Reduced environmental impact compared to other disposal methods ƒ Reduced long term liability for the operator ƒ Suitable for disposal of other drilling wastes such as drilling and well clean up fluids

Technical Description: Scomi Oiltools has a vast amount of experience in cuttings re-injection, with projects in many different countries of the world. The Scomi Oiltools Cuttings / Solids Injection System is designed to receive the drilled cuttings from the rig’s Solids Control Equipment, and/or produced solids containers. The typical feed system is a screw conveyor collecting the cuttings from the shale shakers and a venturi hopper to transport the cuttings to the slurrification system. The venturi system reduces the need for augers and moves the cuttings by using a stream of fast flowing water that can move the cuttings over extended distances. The solids are passed over a shale shaker with screens sized to meet the required slurry particle size. The slurry unit normally consist of two tanks (Fines & Grinding) and four centrifugal pumps. The fines tank holds the fluid and solids which pass through the shaker screen. The grinding tank holds the oversize particles. The grinding tank is continually circulated through the ARCO patented hardened impellor pumps to further reduce the particle size. This slurry is passed over the shaker screens again in a continuous process. The slurrification system is normally designed to grind and process up to 25MT of drill cuttings per hour. Smaller and larges sizes can be accommodated. Four pumps and numerous valves provide 100% contingency in case of failure. This ensures that the injection process and drilling is not interrupted due to a failure of a pump or a valve. The slurry in the fines tank is pumped to a high pressure triplex pump where it is injected into the well. The downhole configuration, injection zone, and pump rate are determined by a separate study. In some cases the study may determine that no suitable injection zone exists.

Disposal Well

Annular Injection

Seawater Supply

Shale Shakers

Grinding Mill

Classification Shaker Chemical Addition

Mixing Hopper Holding Tank

Transfer via Screw Conveyor

Injection Pump

Shearing Tank

Wellhead Fines Tank Injection

Injection System Schematic

Section

14c


drill cuttings thermal treatment Summary: Our current thermal product line is based on the Porcupine Processor. This thermal process is designed to treat NADF Drill Cuttings (base oil can be diesel, low toxicity, or synthetic), which reduces the oil on the solids exit the process to < 1% dry weight, and recovers the valuable base oil in a state suitable for reuse. This process has been successfully operated and therefore licensed in the UK and Holland. To date the operating plants have processed well in excess of 100,000 MT of drill cuttings. The process is not designed for processing water based waste or wastes with a very high liquid content. The process is not suitable for processing ester based drill cuttings, as the ester breaks down at the process temperatures. Features and Benefits: ƒ Features ƒ An efficient method for treating NADF drill cuttings ƒ PLC controlled safety systems ƒ Non-explosive atmosphere ƒ Precise and variable temperature control ƒ

Benefits ƒ Reduces oil on cuttings to < 1% and in most cases to < 0.5% ƒ Recovered oil is un-cracked and suitable for reuse in new drilling fluid ƒ Operator liability relating to land disposal is reduced

Technical Details: The treatment of solids containing high levels of diesel oil contamination can be achieved utilising a single stage indirect thermal desorption system. The system is based on the use of the patented Porcupine Processor to remove all water and oil, leaving a residual total petroleum hydrocarbon on cuttings of less than 1%. Contaminated solids are fed into the processor by the use of an adjustable speed screw feeder. Conditioning of the feed with clean, hot recycled solids will be completed using an automated paddle mixing system. Heat transfer fluid from a hot oil heater is circulated through the inner passages of the Porcupine dryer, which consists of a sealed tub with a heated rotating paddle shaft. The oil-contaminated waste is contained within the dryer tub where they are heated by contact with the hot metal surfaces of the paddle shaft. Air locks are fitted at the inlet and outlet of the dryer to minimise the infiltration of outside air. Nitrogen is used to purge air from the airlocks and provide an inert gas atmosphere within the dryer. As the waste is mixed and folded inside the dryer, contact with the rotating paddle shaft causes the liquids to evaporate. A mixture of steam and oil vapour then passes into a Vapour Recovery Unit where it condenses and leaves the system as liquids. The remaining solids exit the system into a cooler and hydrator (to avoid dust) prior to being discharged.

Process Flow Diagram Heat transfer Fluid for the Porcupine Processor The best approach involves the use of a heat transfer fluid (hot oil) system. The unit employs the external boiler to heat the heat transfer fluid. This liquid is capable of being heated to temperatures of 343° C (650° F), and circulated by pump without boiling. A multi-fuel burner is provided to cleanly burn a variety of fuels with high efficiency. The burner heats the coil of pipe containing the circulating thermal fluid. After being heated, the heat transfer fluid (hot oil) is circulated to the dryer, where it transfers its heat to the metal surfaces. The cooler fluid is then circulated back to be re-heated.

NITROGEN

EXPANSION TANK

FUEL

CIRCULATING PUMP

FROM PORCUPINE

TO PORCUPINE

FUEL

Typical thermal fluid heater setup Modern boiler system controls are used on the Hot Oil System to assure safe operation. These include flame safety/fuel shutoff devices, automatic re-start pilots and pressure and temperature shutoff switch. Vapour Recovery Unit A single vapour recovery unit is utilised to condense and recover (for recycling) the vapours from the Porcupine Processor. The Vapour Recovery Unit consists of two stages of vapour condensing, with noncondensable gasses being oxidised in the boiler. First Stage Condenser Stage 1 consists of a gas scrubber / absorber tower equipped with a continuous circulation of cooled liquor serving as a direct contact or barometric condenser. This water stream is circulated under pressure from the cooler into a contactor column where it passes counter-current to the vapour entering from the dryer system. Intimate contact of the gas and liquid is increased by utilisation of specially designed internals that provide maximum surface area while minimising the vapour stream pressure drop. As the hot vapour comes in contact with the liquid the majority of it is condensed.

Section

14c

treatment and disposal VAPOUR SECOND

SEPARATOR

STAGE CONDENSER

100-200 CFM GAS FLOW

SCRUBBER-

I.D. FAN

RECOVERED LIGHT

CONDENSER

HEAT

VAPOUR

OILS

EXCHANGER

FROM

COOLING TOWER

PORCUPINE

RECOVERED RECOVERED OILS

CHILLER

WATER & SOLIDS

TO BOILER

All liquid exiting the condenser/scrubber column passes into an oil / water separator where two separation processes occur. Within the entry section particulate that was previously entrained with the vapour and captured by the scrubbing action of the water is removed via a baffled chamber. In the following (exit) section, the water and any oil occurring are separated through the use of a parallel plate module that utilises the difference in the specific gravity to produce a two-phase flow. A series of baffles and weirs provides skimming of the oil phase, while allowing the water to be re-circulated to the air-cooled exchanger. A removable gasket sealed lid contains any potential vapour leakage from this vessel. A sight glass is mounted on the separator, permitting visual examination of the “two-phase” section. This gives the system operator an indication of how to adjust the rate at which an oil pump removes oil from this section of the separator. Second Stage Condenser The second stage condenser is typically a shell and tube heat exchanger. Mechanically refrigerated water/glycol solution is circulated on the shell side of the heat exchanger. The remaining condensable vapours in the gas stream are thus cooled to 5 °C (4 °F), condensed and collected in a liquid recovery vessel. The Mechanical Refrigeration System will reduce the water / glycol temperature to approximately 3 °C (37 °F) before its entrance to the condenser. The mechanical refrigeration system includes a compressor; an air-cooled condenser with copper tubes and mechanically bonded plate fins immediately follows the compressor. It is designed with sufficient extended surface area to accommodate a condensing discharge temperature of 115 °F (46 °C). Propeller-type fans driven by TENV motors induce airflow. Fan cycling controls ensure the ability of the system to maintain a proper condensing pressure even at low ambient temperatures. The evaporating refrigerant cools the re-circulated water in the evaporator, which is constructed of 304 stainless steel to guard against attack if aggressive chemicals are encountered. The control scheme for the refrigeration system includes limit switches that protect against unsafe operation of the system whenever operating conditions such as high or low refrigerant or low compressor lubricating oil pressure exist. Ancillary system safeties are provided to stop operation of the refrigerant circuit whenever there is a loss of water flow or the water system temperature drops too close to its freezing point.

Blower The non-condensable gas stream that remains after the second stage Condenser / Scrubber is directed through a single positive displacement blower that discharge the gas to the boiler ensuring complete oxidation of any residual hydrocarbons. A manually variable frequency control adjusts the blower volume. The blower’s volume is adjusted in proportion to the dryer processing rate and the moisture content of the feed material. The more bulk material fed to the dryer, the more air is entrained in the material, necessitating a greater blower volume. The higher the moisture content of the feed material, the greater the volume of vapours generated by the drying process. This necessitates a greater blower volume. Oil and Water Condensate Condensed liquids (oil and water) in the vapour recovery system are separated for recycling. Oil is collected in a tank and water is utilised to re-hydrate the dry solids exiting the Porcupine to avoid the generation of dust. Automatic Motor Control Centre The thermal desorption system is controlled through an Allen-Bradley Programmable Logic Controller model PLC5/20 mounted inside the freestanding control container. The process can be monitored and controlled through the use of PC/AT Operator Interface Platform on a desktop computer and viewed on a full 19” (483 mm) monitor. Process conditions are continuously monitored by an array of instrumentation installed on the process equipment. The state of the instrumentation represents real-time conditions of the process and allows for process information to be reported by the PLC to the display screen. The microprocessor, as an integral part of the PLC, monitors the information received from the input field devices, performs the routines programmed in the ladder logic code, and delivers commands to the output instruments to automatically control system operations. The operator inputs required process criteria directly to the terminal to specify the conditions of the system operation. The PC based software relays this criteria to the PLC, which performs the logic functions to meet the specific process requirements.

Picture of a Typical Oiltools Motor Control Centre Equipment status, process criteria and alarm conditions are displayed on graphic display screens within the operator’s interface terminal, allowing the operator to perform process and machine diagnostics. The graphic display alarm and process screens also provide operators and maintenance personnel with information that aids in troubleshooting the alarm condition. The control system is user friendly and employs a simplistic method of interfacing the operator with the equipment. DC-5424 Plant in Shetland, Scotland, capable of processing 20,000 MT per annum

Section

14c


Control Room

Vapour Recovery System

Feed Hopper / Storage

Product Cooler

Thermal Fluid Heater

Discharge Auger

Section

14c


extractor dryer Summary: The EXTRACTOR Dryer is designed to remove NADF from drill cuttings exiting the shale shaker. The dryer is capable or reducing the oil on cuttings to < 3% and to an overall total of < 6.9% when the centrifuge waste is taken into account. Excess fluid is recovered after centrifugation and returned to the active system for reuse. The system is not suitable for the treatment of water based mud cuttings. Features and Benefits: ƒ Features ƒ Horizontal basket ƒ Internal scroll turns solids to improve drying ability ƒ Proprietary screen design minimises plugging ƒ ‘G’ force of 375 ‘G’s ƒ Resettable torque overload protection ƒ Screen cleaning does not require removal ƒ

Benefits ƒ Reduced environmental impact and increase drilling fluids recovery ƒ Reduced footprint and lower height compared with vertical systems ƒ Low noise and power requirement due to low friction Cyclo-Gear ƒ Reduced maintenance

Technical Details: The EXTRACTOR Dryer consists of a horizontally configured conical screen placed within a balanced cage that is driven at high speed via an electric motor through a Cyclo-Gear drive gearbox. Positioned within the cage is a scroll that turns and transports the filtered solids from the machine to obtain maximum cuttings dryness. The conical basket contains a proprietary screen specially designed to minimize screen binding. The unit is attached to an isolated sub-frame which in turn is mounted on a rugged oilfield skid for transport. The EXTRACTOR Dryer receives drill cuttings from the Solids Control equipment via screw conveyor, vacuum system, and/or solids pump. Drill cuttings are fed into the centre of the feed cone and distributed evenly through feed holes by centrifugal action into the flighting channels between the scroll and the screen. As the drill cuttings pass through the conical screen, the solids layer becomes thinner and exposed to progressively more G-force. The high gravitational force allows the liquid portion of the feed to pass through the cake bed and screen while the cake bed itself is continuously turned and swept outward to be discharged at the outer diameter of the screen. The dried drill cuttings exit from the front of the machine where they are either discharged to the environment or collected for further handling and/or treatment. The effluent exits tangentially from the base of the unit into a holding tank. This effluent should all be processed by a high speed centrifuge, where practicable, prior to return to the active system.

10

DRILL CUTTINGS IN

RECOVERED LIQUID OUT

SOLIDS OUT

Schematic of the dryer

The basket and crane

The Extractor Dryer

11

Section

14c


Scroll in position

Offshore Installation

Typical oil on cuttings graph

12

filtration Summary: A complete range of filtration equipment is available to process completion brines, oily water, water injection and other oilfield applications. The full range of equipment and consumables includes horizontal and vertical filter presses, duplex cartridge and bag units, high pressure vessels, automatic self cleaning filters, filter bags, and cartridges (wound, spunbonded, pleated, oil and heavy metal absorption, nominal, and absolute) Features and Benefits: ƒ Features ƒ Fully automatic self cleaning vertical filter press ƒ Flexible duplex unit able to hold standard cartridges, magnum cartridges or bag filters ƒ Full range of cartridge micron sizes in nominal or absolute ƒ Oil absorbing and heavy metal absorbing cartridges available for water treatment applications ƒ Benefits ƒ Reduced cleaning time and reduced exposure to waste when using the automatic self cleaning filter, saving rig time ƒ Duplex unit are suitable for numerous applications ƒ High efficiency filtration improves production rates ƒ Water treatment offshore allows discharge and reduces costly onshore disposal

Duplex Cartridge Unit

Horizontal DE Press

13

Section

14c


Vertical Pressure Leaf Press With Self Cleaning System

14

40” Cartridges

5 Bag Filters

7 Magnum Cartridges

50 Standard Cartridges

chemically enhanced centrifugation (flocculation) Summary: Chemically Enhanced Centrifugation, CEC, otherwise known as flocculation, is a method to enhance the remove of fine solids in WBM through a centrifuge. Small quantities of additives are mixed with the used WBM, which coagulate and flocculate fine colloidal solids into a larger clumps, which are then easily removed using a centrifuge. CEC reduces the volume of waste mud generated as it allows the clarified fluid to be reused to build new drilling fluids. Overall the total volume of waste, the size of the pits, and the quantity of water required per well are all reduced. Features and Benefits: ƒ Features ƒ Mixing tank including agitator and twin screw pumps for the coagulant ƒ Powder dosing unit to make up flocculent ƒ Flocculent batch tank with agitator and dosing pump ƒ Dilution unit for reducing polymer concentration ƒ Two variable speed metering pumps ƒ In-line mixing system ƒ Centrate tanks ƒ Laboratory and work area ƒ

Benefits ƒ Overall reduction in water usage and increased recycling ƒ Smaller pit volumes and in closed loop system no need for a reserve pit ƒ Reduced environmental impact ƒ Real time mixing reduces overall chemical consumption ƒ Powder polymer unit reduces chemical consumption

Technical Description: During drilling with WBM, fine colloidal solids build up, eventually leading to a requirement to dump or dilute. CEC offers an alternative as it allow the fine particles to be coagulated, flocculated and removed by the use of a centrifuge. A coagulant is added to neutralise the negative charges holding the fine colloidal particles apart followed a flocculent (typically a polymer) to bridge together the small floccs into larger clumps, which can then be removed by gravity separation or a centrifuge. The CEC system is a containerised compact unit designed to meter in the correct quantities of both coagulants and flocculent. It has tanks to store the prepared chemical solutions and metering pumps to accurately dose them into a mud mixing line. The flocculated mud should be centrifuged at low speed to ensure the clumps are not broken up by excessive shear.

30’ Containerised CEC System

15

Section

14c


bio-remediation Summary: Bioremediation utilises the ability of natural organisms to digest the organic species found in Drill Cuttings, principally the base oil. Bioremediation is used to treat NADF cuttings, reducing the residual oil on cuttings to less than 1%. Features and Benefits: ƒ Features ƒ The solid product does not require any further processing or disposal ƒ Relatively inexpensive compared with other techniques including CRI and Thermal ƒ Limited mechanical equipment so inherently safe ƒ Treatment material can be suitable for use as a soil amendment ƒ Degradation can be carried out by native bacteria ƒ

Benefits ƒ Treats the hydrocarbon and other organic compounds in the waste ƒ Suitable for variable quality wastes ƒ Does not require utilities such as electricity and diesel fuel for processing ƒ Simple and safe to manage

Technical Details: A containment area with an impermeable clay base is built to accept and process the cuttings. The impermeable layer is important to stop potential leaching of contaminants into the environment. The area is selected for ease of access and having a suitable area to cope with the projected waste volume. Drill cuttings are placed in an empty cell and mixed with a suitable organic substrate such as saw dust. Filler such as sand is added to improve the drainage and increase the airspaces in the waste. Nutrients and water are added as appropriate during the degradation period to ensure growth of the bacteria culture is maximised. The mixture is turned frequently, either by hand or machine, to ensure a plentiful supply of air (oxygen) is available to the bacteria. Over time the bacteria population will digest the oil. Samples of the cuttings are taken frequently to monitor the degradation rate of the base oil. When the residual oil level meets the customer specification the site can be closed and the product either moved to another location or left in-situ to re-vegetate.

The Six Steps

16

Application Summary

Cells in use

Watering the cells

Re-vegetation of a completed cell 17

Section

14c


drill cuttings solidification and stabilisation Summary: Oily drill cuttings from the shale shakers may not be suitable for direct disposal to land without further treatment. Regulations in some countries require the “waste” to meet certain criteria such as the leachability of specified contaminants. Solidification and stabilisation of the drilling waste is a method whereby the raw cuttings from the shaker / centrifuge are mixed with additives in order that the treated wastes will meet the criteria for land disposal. Solidification typically refers to encapsulating the waste such that the leachability of contaminants is reduced by minimising the surface area of the waste exposed to leaching, or by totally encapsulating the waste with an impervious layer. Stabilisation refers to chemical techniques that reduce the mobility of contaminants by changing their form into less soluble, mobile or toxic forms. There are concerns that the long term stability of these waste is not yet understood and as such this technique is now limited in its application around the world to just a few countries. Features and Benefits: ƒ Features ƒ Available in semi-automatic (backhoe mixing) and fully automatic (mixer and silos) configuration ƒ Easy to operate and maintain ƒ High throughputs ƒ Low manpower requirement ƒ

Benefits ƒ Relatively inexpensive ƒ Formulation can be tailored to meet the legislative requirement ƒ Additives are benign ƒ Reduces the availability of most heavy metals to the environment

Technical Description: NADF Drill cuttings are typically mixed with cement or lime and at least one more additive such as sodium silicate or organophilic clay. The mixing is completed either by the use of a backhoe or through more automated equipment such as a ploughshare mixer and associated silos for the cement and additives. In most cases some water will also be added to ensure complete hydration and reaction of the cement or lime. The final product will normally be required to meet a specification that covers the leachability of specific contaminants and in some cases a number of physical properties. The leachability requirements typically cover heavy metals and hydrocarbons whilst the physical tests cover the final strength of the product. The Louisiana State-wide Order 29-B provides a useful reference for these requirements and can often be quoted as a standard in the absence of local regulations.

18

Picture Gallery:

Ploughshare Mixer and Feed System

Disposal Pit Excavation

Burial of Stabilised Drill Cuttings 19

Scomi Oiltool Xreference section 15

Scomi Oiltools product cross-reference table

section 15 scomi product fluids cross reference chart

Section

15

drilling fluids cross reference chart


scomi product cross-reference table Scomi Oiltools

Description

MI

Halliburton

Baker Hughes

COMMERCIAL CHEMICALS Calcium chloride Caustic soda Citric acid Gypsum Lime Magnesium oxide MEG Potassium acetate Potassium carbonate Potassium chloride Potassium hydroxide Potassium sulphate Quick lime Salt SAPP Soda ash Sodium bicarbonate

Calcium chloride (CaCl2) Calcium chloride Calcium chloride Sodium hydroxide (NaOH) Caustic soda Caustic soda Citric acid Citric acid Citric acid Calcium sulphate (CaSO4·2H2O) Gypsum Gypsum Calcium hydroxide (Ca(OH)2) Lime Lime Magnesium oxide (MgO) Safe-Buff 8 Barabuf Mono ethylene glycol Di-Inhib ---Potassium acetate (CH3CO2K) Potassium acetate Potassium acetate Potassium carbonate (K2CO3) Potassium carbonate Potassium carbonate Potassium chloride (KCl) Muriate of potash Potassium chloride Potassium hydroxide (KOH) Caustic potash Potassium hydroxide Potassium sulphate (K2SO4) Potassium sulphate Potassium sulphate Calcium oxide (CaO) Hotlime Calcium oxide Sodium chloride (NaCl) Salt Salt Sodium acid pyrophosphate SAPP SAPP (Na2H2P2O7) Sodium carbonate (Na2CO3) Soda ash Soda ash Sodium bicarbonate (NaHCO3) Bicarbonate of soda Bicarbonate of soda

Calcium chloride Caustic soda Citric acid Gypsum Lime Magnesium oxide NF2 Potassium acetate Potassium carbonate Potassium chloride Potassium hydroxide Potassium sulphate Quick Lime Salt SAPP Soda ash Sodium bicarbonate

CORROSION INHIBITORS COR-MUSCLE

HYDRAMINE HYDRO-BUFF HYDRO-FILM OX-SCAV OX-SCAV CA OX-SCAV S Zinc carbonate Zinc oxide

Three in one corrosion inhibitor: Filming amine corrosion inhibitor for solids free fluids; controls corrosion, scavenges oxygen and inhibits bacteria. Water dispersible filming amine Blended ethanolamine pH buffer and polymer extender Amine base corrosion inhibitor Liquid oxygen scavenger Powder oxygen scavenger for brines containing calcium Powder oxygen scavenger - Sodium bisulphite H2S scavenger -zinc carbonate H2S scavenger - zinc oxide

CONQOR 303 A /

BARACOR 100

BRINE-PAC 1500

CONQOR 101

BARACOR100

KD 700

BARACOR 95 BARA-FILM

DFE-806 AMI-TEC

BARACOR 700 / BARASCAV-L ---

NOXYGEN / DFE 805

BARASCAV-D

NOXYGEN

NO-SULF BARACOR 44

MIL-GARD Zinc oxide

ENVIRO-THIN CC-16 QUIK-THIN ENVIRO-THIN

AQUA-THINZ LIGCON UNI-CAL UNI-CAL CF

CONQOR 202 B / SAFECOR CONQOR 404 / SAFE-SCAV NA SAFE SCAV CA

SV-120 Zinc Oxide

---

DISPERSANTS AND DEFLOCCULANTS FERRO-THIN HYDRO-LIG C HYDRO-SPERSE HYDRO-SPERSE CF

Iron lignosulphonate Causticised lignite Chrome Lignosulphonate Chrome-free lignosulphonate

SPERSENE CAUSTILIG SPERSENE SPERSENE CF

Section

15


Scomi Oiltools

Description

MI

Halliburton

Baker Hughes

DISPERSANTS AND DEFLOCCULANTS (Continued...) HYDRO-SPERSE HT

HYDRO-TAN CF HYDRO-THIN HYDRO-THIN HT

HYDRO-THIN HT L

HYDRO-THIN L

Water base liquid deflocculant and rheology stabiliser with special application in high temperature environments. Chrome-free, modified tannin Microbead, low-molecularweight anionic polymer Water base polyacrylate deflocculant and rheology stabiliser with special application in high temperature environments. Water base liquid polyacrylate deflocculant and rheology stabilizer with special application in high temperature environments. Liquid, low-molecular-weight anionic polymer

DURALON

THERMO TONE / THERMA-CHECK

ALL-TEMP

SPERSENE CF TACKLE

ENVIRO-THIN THERMA-THIN

TEQ-THIN CF NEW-THIN

TACKLE

THERMA-THIN

NEW-THIN

TACKLE

THERMA-THIN

MIL-THIN

TACKLE

THERMA-THIN

NEW-THIN

FILTRATION CONTROL AGENTS CMC LV

HYDRO-LIG MY-PAC R MY-PAC LV HYDRO-PAC R HYDRO-PAC LV HYDRO-PAC PLUS UL HYDRO-PAC PLUS R HYDRO-PAC PLUS LV HYDRO-POL HYDRO-REZ HYDRO-STAR CMS HYDRO-STAR HT HYDRO-STAR NF HYDRO-STARCH HYDRO-THERM HYDRO-THERM II

Low viscosity, technical grade CELLEX CMC LV sodium carboxymethyl cellulose for filtration control. Lignite (Leonardite) CARBONOX TANNATHIN Polyanionic cellulose PAC-R M-I PAC R Polyanionic cellulose PAC-L M-I PAC UL Polyanionic cellulose PAC-R POLYPAC R Polyanionic cellulose PAC-L POLYPAC UL Polyanionic cellulose ----High purity polyanionic cellulose POLYPAC SUPREME LV --High purity polyanionic cellulose POLYPAC SUPREME UL --Sodium polyacrylate copolymer POLY ACPLUS SP-101 Polyanionic, lignin resin BARANEX RESINEXII Modified polysaccharide, NDRIL / FILTER-CHEK FLO-TROL/ filtration control agent THERMPAC UL Modified starch derivative N-DRIL HT PLUS DUAL-FLO / FLO-PLEX Nonfermenting, DEXTRID LTE POLY-SAL polymerized starch Pregelatinised starch IMPERMEX MY-LO-JEL Acrylamide - AMPS copolymer for THERMA-CHEK DURALON / high temperature filtration control DURASTAR Acrylamide - AMPS copolymer for THERMA-CHEK DURALON high temperature filtration control

CMC LV

LIGCO MIL-PAC RT MIL-PAC LVT MIL-PAC MIL-PAC LV ------NEW-TROL FILTREX BIO-LOSE BIO-PAQ PERMA-LOSE HT MILSTARCH PYRO-TROL KEM-SEAL Plus

HyPR-DRILL - High Performance Water Based Mud HyPR-CAP HyPR-DRL HyPR-HIB

Acrylic polymer for HPWBM Bit and BHA balling preventor Ammonium salt inhibitor for HPWBM

ULTRACAP ULTRAFREE ULTRAHIB

CLAY- GRABBER --CLAY-SEAL

--PENETREX MAX-GUARD

Scomi Oiltools

Description

MI

Halliburton

Baker Hughes

LO-WATE

BARACARB

W.O. 30

FORM-A-SQUEEZE

---

SOLU-SQUEEZ

M-I-X II

BAROFIBER

CHEK-LOSS

NUT PLUG G-SEAL M-I MICA SAFE-CARB

WALL-NUT STEEL-SEAL MICATEX BARACARB Series

MIL-PLUG LC-LUBE MILMICA MIL-CARB Series

WALNUT SHELLS

WALNUT SHELLS

WALNUT SHELLS

BARA DEFOAM W-300 BARA-DEFOAM HP BARABRINE DEFOAM

LD-8 LD-9 W.O. DEFOAM

AKTAFLO S BARAKLEAN/ BAROID RIGWASH BARO-LUBE GOLD SEAL --CON DET E

DMS MIL-CLEAN

LOST CIRCULATION MATERIALS Calcium Carbonate

Sized calcium carbonate (ground limestone) E Z-SQUEEZE High Solids, High Fluid Loss Squeeze FIBRO-SEAL All grades Seepage loss control and differential pressure sticking preventative. HYDRO-PLUG Nut shells HYDRO-SEAL G Synthetic graphite MICA Sized Muscovite mica OPTA-CARB 5, 20, 50, Custom sized bridging material 100 WALNUT SHELLS Walnut shells

LUBRICANTS & SURFACTANTS HYDRO-DEFOAM HYDRO-DEFOAM S HYDRO-DEFOAM A HYDRO-DMS HYDRO-KLEEN HYDRO-LUBE HYDRO-LUBE SL HYDRO-MD HyPR-DRL LUBRI-GREEN LUBRI-GREEN II

Low toxicity defoamer Silicone base defoamer Alcohol-based defoamer Surfactant for water base muds Water soluble, biodegradable, detergent and rig wash WBM lubricant Lubricant for Silicate systems Biodegradable DF detergent Insoluble glycol, bit balling preventative Ester-based lubricant Ester-based lubricant

DEFOAM X DEFOAM X DEFOAM-A / SAFE-DFOAM DRILL-KLEEN CLEAN UP LUBE-167 --D-D DRIL XP / ULTRAFREE -----

DRILL N SLIDE ---

TEQ-LUBE ll --MILPARK MD PENETREX / BIO-DRILL LUBE 622 / OMNI-LUBE ---

OIL AND SYNTHETIC BASED ADDITIVES cDEEP-BAR

cDEEP-MOD

cDEEP-MUL

cDEEP-RM

A specialty weight material blended to reduce ECD and sag while improving rheological modifier efficiency and onomics of the “flat rheology” CONFI-DEEP deepwater system Primary rheological modifier which provides the flat rheology profiles in the CONFI-DEEP flat rheology deepwater system Primary emulsifier for the CONFI-DEEP flat rheology deepwater system Secondary rheological modifier which efficiently boosts LSRV of the “flat rheology” CONFIDEEP deepwater system for improved hole cleaning and improved overall ECD.

---

---

---

RHETHIK

---

RHEOPLEX

SUREMUL

SUPERMUL

CARBO-MUL HT

---

---

---

Section

15


Scomi Oiltools

Description

MI

Halliburton

Baker Hughes

OIL AND SYNTHETIC BASED ADDITIVES (Continued...) cDEEP-THIN cDEEP-TROL

CONFI-COAT CONFI-GEL

CONFI-GEL HT CONFI-GEL ll

CONFI-GEL XHT

CONFI-LUBE CONFI-MOD CONFI-MUL HT CONFI-MUL P CONFI-MUL S

CONFI-MUL SA

CONFI-PLEX

CONFI-RM CONFI-SEAL

CONFI-SPOT CONFI-TEC P CONFI-TROL

Thinner for the CONFI-DEEP flat rheology deepwater system Fluid loss control additive in the CONFI-DEEP flat rheology deepwater system Oil wetting surfactant / thinner Economical, organophilic Bentonite, oil mud viscosifier Organophilic Hectorite clay CONFI-GEL ll is an easy dispersing self activating organophilic viscosifier for synthetic-based and oil-based muds especially in cold environments. Viscosifier and sag prevention agent for ultra high temperature application. Ester-based lubricant Low end rheology temporary viscosifier for OBM/SBM High temperature emulsifier Primary emulsifier in paraffin carrier fluid Supplemental, anionic emulsifier for oil and synthetic base fluids Low temperature rheology modifier for non aqueous fluids – used to enhance rheology of newly mixed fluids in mud plants Synthetic polymer viscosifying agent for oil and synthetic base fluids Low end rheology modifier for oil and synthetic based fluids. Temperature stable, organophilic lignite, filtration control agent for oil and synthetic base fluids Spotting agent for use with non aqueous fluids Economical emulsifier for low density muds. Gilsonite

RHEDUCE

ATC / COLD-TROL

---

ECO-TROL RD

ADAPTA

---

FAZE-WET

DRILLTREAT

VG-69 / VG-PLUS / VG SUPREME / TRUVIS -----

GELTONE I / GELTONE II / GELTONE V BENTONE 38 ---

SURF-COTE OMNI-COTE CARBO-VIS

---

---

MAGMA-GEL

--VERSAMOD / NOVAMOD / HRP VERSACOAT HF

--X-VIS / RM-63

OMNI-LUBE 6-UP

INVERMUL/ INVERMUL NT INVERMUL/ INVERMUL NT EZ MUL/ EZ MUL NT / FACTANT

CARBO-MUL HT

VERSA HRP

---

---

VERSA HRP / NOVAMOD

X-VIS / RHEOMOD L

OMNI-PLEX

HRP

X-VIS / RM-63

6-UP

VERSALIG

DURATONE HT

OMNI-TROL / CARBO-TROL A9

---

---

---

---

---

ECCOMUL E

VERSATROL

BARABLOK

CARBO-TROL

VERSACOAT HF / VERSAMUL VERSAVERT SE

CARBO-GEL ---

CARBO-MUL HT OMNI-MIX / ECCO-MUL E

Scomi Oiltools

Description

MI

Halliburton

Baker Hughes

OIL AND SYNTHETIC BASED ADDITIVES (Continued...) CONFI-TROL F

CONFI-TROL HT CONFI-TROL VT

CONFI-TROL XHT CONFI-WET

A proprietary liquid fluid loss high temperature additive for OBM/SBM HT softening point Gilsonite Proprietary polymeric product to enhance fluid loss control and improve low end rheology in a wide range of non aqueous drilling fluids. Filtration and suspension control in the HTHP Systems Oil-wetting agent

NOVA-TEC F

---

FL1790

VERSATROL HT ---

DURATONE HT ---

CARBO-TROL HT ---

----

----

MAGMA-TROL

VERSAWET/ NOVATHIN

DRILTREAT/ LE THIN / COLDTROL / ATC

BIO-COTE

GLYDRILL C

----

AQUA-COL

GLYDRIL GP

GEM GP

AQUA-COL B

GLYDRIL MC

GEM CP

AQUA-COL D

GLYDRIL HC

GEM SP

AQUA-COL S

POLY-PLUS

EZ MUD

NEW-DRILL

POLY-PLUS RD

---

---

POLY-PLUS LV POLY-PLUS

EZ-MUD EZ-MUD

NEW-DRILL LV NEW-DRILL PLUS

ASPHASOL

BARA-TROL / SHALE-BAN / BOREPLATE ---

SHALE-BOND

Sodium silicate BARASIL S CLAY-GRABBER / BARAFLOC

--Sodium Silicate ---

SHALE CONTROL ADDITIVES CIRRUS CPG

STRATUS CPG

CUMULUS CPG

NIMBUS CPG

HYDRO-CAP L HYDRO-CAP RD HYDRO-CAP SC HYDRO-CAP XP HYDRO-PLAST

HYDRO-PLAST PLUS HYDRO-SIL K HYDRO-SIL S HyPR-CAP

Cloud point glycol for bore hole stability, ROP enhancement, lubricity and HTHP reduction in fresh water and brines Broad-cloud-point, generalpurpose polyglycol for low-salinity fluids and low temperatures Cloud point glycol for bore hole stability, ROP enhancement, lubricity and HTHP reduction in moderate to high salinity brines. Cloud point glycol for bore hole stability, ROP enhancement, lubricity and HTHP reduction in saturated salt systems Liquid, high molecular weight, PHPA polymer Readily dispersible -- highmolecular weight PHPA Low MW PHPA 100% active high-molecular weight PHPA Sulphonated asphalt

High performance sulphonated asphalt Sodium silicate dry Sodium silicate liquor Acrylic copolymer selective encapsulator

ASPHASOL SUPREME SILDRIL D SILDRIL L IDCAP D

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Section

15


Scomi Oiltools

Description

MI

Halliburton

Baker Hughes

CELLEX (High Vis)

CMC HV

---

CMC EHV

AQUAGEL AQUAGEL GOLD SEAL GUAR GUM BARAVIS ---

MIL-GEL MIL-GEL NT

Ben-Ex -----

Ben-Ex -----

BARAZAN BARAZAN D

XAN-PLEX XAN-PLEX D

BARAZAN L --BARAZAN D PLUS

XGL -----

--ZEOGEL

--Salt Water Gel

LO-WATE

BARACARB

M-I BAR

BAROID

MIL-CARB / FLOW-CARB MIL-BAR

---

BDF 195

---

FER-OX MICRO-MAX

BARODENSE MICRO-MAX

DENSIMIX MICRO-MAX

---

---

---

---

---

---

Calcium bromide Calcium chloride Caesium formate Potassium formate

Calcium bromide Calcium chloride CLEAR-DRILL C CLEAR-DRILL K

VISCOSIFIERS CMC HV

CMC EHV

DRILL-GEL DRILL-GEL UA GUAR GUM HEC HEC L HYDRO-FLOCC HYDRO-ZAN T HYDRO-ZAN TRD HYDRO-ZAN HYDRO-ZAN RD HYDRO-ZAN L HYDRO-ZAN PLUS HYDRO-ZAN PLUS RD RHEO-PLEX SEA-GEL

High viscosity, technical grade CMC HV sodium carboxymethyl cellulose for viscosity & filtration control. High viscosity, technical grade CMC EHV sodium carboxymethyl cellulose for viscosity & filtration control. API Bentonite M-I GEL API non-treated Wyoming M-I GEL SUPREME Bentonite Guar Gum GUAR GUM Hydroxyethyl cellulose POLYSAFE / SAFE-VIS Hydroxyethyl cellulose - liquid SAFE-VIS L suspension Bentonite extender Ben-Ex Technical grade Xanthan Gum DUO-TEC NS Technical grade readily DUO-TEC NS dispersible Xanthan Gum Xanthan gum DUO-VIS NS Xanthan gum, readily DUO-VIS dispersible Liquid Xanthan gum DUO-VIS L Premium grade Xanthan gum DUO-VIS PLUS NS Premium grade Xanthan gum, DUO-VIS PLUS readily dispersible Mixed metal oxide DRILPLEX API Attapulgite SALT GEL

MIL-GUAR WO-21

WEIGHTING AGENTS Calcium Carbonate DRILL-BAR DRILL-BAR XP HAEMATITE HYDRO-MAX HyPR-BAR NANO-BAR

Sized, ground calcium carbonate (S.G. 2.7)- Various grades API barite (S.G. 4.2), barium sulphate API barite (S.G. 4.4), High purity barium sulphate Haematite (S.G. 5.0), iron oxide Manganese tetraoxide (S.G.. 4.8), low ECD weighting agent Fine grind barite, specially sized to minimize sag A custom blend of weighting agents for preparing low ECD, Ultra High Density fluids

WORKOVER AND COMPLETION-FLUIDS Calcium Bromide Calcium Chloride FORM-8 C FORM-8 K

Calcium bromide Calcium chloride Caesium formate brine Potassium formate

Calcium bromide Calcium chloride Caesium formate ECOFORM PF

Scomi Oiltools

Description

MI

Halliburton

Baker Hughes

WORKOVER AND COMPLETION-FLUIDS (ContinFORM-8 N Potassium Chloride Sodium Bromide Sodium Chloride Zinc Chloride / Calcium Bromide

Sodium formate ECOFORM SF Potassium chloride Potassium chloride Sodium bromide Sodium bromide Sodium chloride Sodium chloride Zinc bromide / Calcium bromide Zinc bromide / Calcium bromide

Sodium formate Potassium chloride Sodium bromide Sodium chloride Zinc bromide / Calcium bromide

CLEAR-DRILL N Potassium chloride Sodium bromide Sodium chloride Zinc bromide / Calcium bromide

WELLBORE CLEAN-UP CHEMICALS CONFI-KLEEN

CONFI-SURF

HYDRO-WASH

RE-VERT

Blend of surfactants and solvents designed to suspend solids Displacement surfactant/ solvent for use with oil/synthetic muds Blend of ionic and non-ionic surfactants, flocculants and high-flash-point solvents Emulsion preventor for completion fluids

SAFE-FLOC II / SAFE-SURF W / SAFE-SURF WE SAFE-SOLV O / SAFE-SOLV OE

FLO-CLEAN MD / BARAKLEAN FL

CASING WASH 200

BARASCRUB FLO-CLEAN MD /

FLOW-CLEAN

SAFE-FLOC I

FLO-CLEAN Z

CASING WASH 100

---

---

W.O. DMUL

---

---

X-CIDE 102

BACBAN III

BARA B466

X-CIDE 207

PRESERVATIVES Glutaraldehyde Isothiazolin

Glutaraldehyde based liquid biocide Isothiazolin base, powdered biocide

DRILL-IN RESERVOIR OPTA-CARB 5 OPTA-CARB 20 OPTA-CARB 50 OPTA-CARB 100 OPTA-LUBE CB OPTA-STAR OPTA-STAR PLUS

OPTA-ZYME-S

OPTA-VIS OPTA-ZAN

Custom sized calcium carbonate bridging agent - d50 +/- 5 μm Custom sized calcium carbonate bridging agent - d50 +/- 20 μm Custom sized calcium carbonate bridging agent - d50 +/- 50 μm Custom sized calcium carbonate bridging agent - d50 +/- 150 μm Lubricant for brine fluids High purity non fermenting starch Proprietary starch based product for filtration control and damage minimisation in the OPTA-FLO Drill-In fluid Enzyme breaker for starch products used in the OPTA-FLO Drill-In fluid – all applications must be tested in the lab before use. Actigum high purity viscosifier High purity Xanthan gum (Clarified)

SAFE-CARB 2 / SAFE-CARB 10 SAFE-CARB 20

BARACARB 5

BARACARB 5

BARACARB 25

BARACARB 25

SAFE-CARB 40

BARACARB 50

BARACARB 50

---

---

---

--FLO-TROL / DUAL-FLO FLO-TROL / DUAL-FLO

--N-DRIL

--BIO-PAQ

---

BIO-LOSE

WELLZYME A

---

Acidgen / Acidgen HA

BIO-VIS FLO-VIS PL:US

BARA-VIS XANVIS

Actigum CS6 XANVIS

Section

15


Scomi Oiltools

Description

MI

Halliburton

Baker Hughes

PIPE LAX W

EZ SPOT

MIL-SPOT 2

PIPE LAX

ENVIROSPOT

MIL-FREE

STUCK PIPE ADDITIVES BREAK-FREE BREAK-FREE NW

10

Weighted pipe freeing spotting fluid Pipe freeing spotting fluid

dr products section 16

drilling fluid product reference table

section 16

drilling fluid product reference table

Section

16

product reference table

drilling fluid product reference table Brand Name

Generic Name / Composition

Primary Function

Manufacturer / Supplier

18A12

Liquid PHPA

Flocculants

Alloid Colloids

2K7 Water Soluble Pak

Myacide Powder

bactericides

Canamara United

Abandonpak

Multi functional packer fluid inhibitor (water soluble)

corrosion inhibitor

ICTC

Abandonpak (SD)

Self-dispersing, multi-funct packer fluid inhib (water soluble)

corrosion inhibitor

ICTC

ABI 3/8 Medium Plug

Sized bentonite

Lost Circulation Material

Millenium Technologies Ltd.

ABI High Yield Bentonite

Peptized wyoming bentonite

Viscosifiers


ABI Premium Gel

Wyoming bentonite

Viscosifiers


ABI Untreated Gel

Untreated wyoming bentonite

Viscosifiers


Actiguard

Shale & clay inhibitor for Aphron ICS

Shale Control Inhibitors

All / CIBA specialty chemicals

Activated Carbon

Charcoal

Surface Active Agents

All

Activator I

Thermal stabilizer for APHRON ICS

Polymer Stabilizers

M-I Swaco/Federal

Activator II

Thermal stabilizer for APHRON ICS

Polymer Stabilizers

M-I Swaco/Federal

Adapta

Oil mud HTHP filtrate reducer

Filtrate Reducers

Baroid

AK-70

Gilsonite

Filtrate Reducers

Baroid

Aktaflo-E

Oxyethlated alkyl phenol liquid

emulsifier

Baroid

Aktaflo-S

Mixed oxyethylated phenols


Baroid

Alcomer 110 RD

High mol wt.anionic dispersiblepolacrylamide

Flocculants


Alcomer 120L/OS

Liquid HMW anionic polyacrylamide



Alcomer 242

AMPS - polyacrylamiide copolymer

Filtrate Reducers


Alcomer 274

Liquid anionic acrylic co-polymer emulsion

Viscosifiers


Alcomer 338 RD

High Mol wt. Anionic polyacrylamide

Flocculants


Alcomer 60RD

LMW anionic dispersible PHPA

Alcomer 72L

Liquid LMW anionic acrylate-based polymer

Thinners, Dispersants


Alcomer 74

Modified acrylic polymer, calcium stable



Alcomer 74L

Liquid anionic acrylic co-polymer, calcium stable



Alcomer IIORD

HMW anionic dispersible PHPA



Aldacide G

Glutaraldyhyde solution

bactericides

Baroid

Alkafloc A-25 D

Dispersible PHPA low viscosity anionic


All/Synerchem

Alkafloc EA-73

PHPA emulsion


All/Synerchem



Section

16


Brand Name


Primary Function


Alkafloc EAS

Sulfonated AMPS


All /Synerchem

Alkapam A-1103 D

Dispersible PHPA HMW anionic

Flocculants

All / Synerchem

Alkapam A-1703D

Dispersible PHPA HMW anionic

Viscosifiers

Synerchem

Alkapam A-25D

Dispersible PHPA low viscosity anionic

Flocculants

All / Synerchem

Alkapam C-1803

Cationic

Flocculants

All / Synerchem

Alkapam CP787

PHPA cationic HMW

Flocculants

All / Synerchem

Alkapam EA-73

Liquid PHPA HMW

Viscosifiers

Synerchem

Alkapam N 1003 D

Dispersible PHPA MMW non-ionic

Flocculants

All / Synerchem

Alkapam N-1103D

Polyacrylamide


All

Alkapam S

Polyacrylamides

Flocculants

All / Synerchem

All Temp

All temperature polymeric deflocculant


Baker Hughes Inteq

Alphadrill

Liquid shale stabilizer


Canamara United

Alplex

Inhibitive aluminum complex


Baker Hughes Inteq

Aluminum Stearate

Aluminum stearate powder

defoamer

All

Aminodril

Amine based liquid shale inhibitor (winterized)


ICTC

Ammonium Bisulfite

Oxygen scavenger

corrosion inhibitor

All

Ammonium Sulphate

Ammonium sulphate


All

Aphron ICS

Water-base reservoir drill-in fluid

Systems

M-I Swaco/Federal

Aqua Pac LV

Polyanionic cellulose

Filtrate Reducers

Bri-Chem Supply Ltd.

Aqua Pac Regular


Filtrate Reducers


Aqua-Col

Cloud-point polyglycol


Baker Hughes Inteq

Aqua-Drill System

Inhibitive glycol based drilling fluid

Systems

Baker Hughes Inteq

Aquagel

Treated sodium montmorillonite

Baroid

Aquagel Gold


Filtrate Reducers/ viscosifier Filtrate Reducers/ viscosifier

Aquagel Gold Seal


Viscosifiers

Baroid

Aquamagic

Non-toxic oil free differential sticking preventative

Lubricants

Baker Hughes Inteq

Aquapac LV




Aquapac Regular

Polyanioinc cellulose

Viscosifiers


Aqua-Star D

Carboxymethyl starch

Filtrate Reducers

Canamara/Hollimex

Asphasol D

Sulfonated organic blends


M-I Swaco/Federal

Asphasol Surpreme

Sulfonated asphalt


M-I Swaco/Federal

Attapulgite

Clay viscosifier for salt water systems

Viscosifiers

All

B 1007

Granular Biocide

bactericides

ICTC

B 1008

Liquid, non-foaming biocide

bactericides

ICTC

B.A.S.E. Mud

Water based mud for bitumen & heavy oil wells

Systems

Marquis Fluids

Barablok

Powdered hydrocarbon resin

Filtrate Reducers

Baroid

Baroid

Brand Name


Primary Function


Barabuf

Magnesium Oxide pH stabilizer

alkalinity pH control

Baroid

Baracarb

Sized calcium carbonate


Baroid

Baracat

High charge cationic polymer


Baroid

Barachek

Cellulosic Polymer

Filtrate Reducers

Baroid

Baractive

Polar activator for use in 100% oil systems


Baroid

Bara-Defoam HP

Polypropylene glycol

defoamer

Baroid

Bara-Defoam I

Surface active defoamer

defoamer

Baroid

Bara-Defoam W300

Surface active defoamer

defoamer

Baroid

Baradril-N

Non damaging acid soluble clay-free system

Systems

Baroid

Barafilm

Filming amine

corrosion inhibitor

Baroid

Barafloc

Acrylamide polymeric hydrolife powder

Flocculants

Baroid

Barafoam

Sodium AO sulphonate

Foaming Agents

Baroid

Barafos

Modified sodium polyphosphate


Baroid

Baragel 3000

Oil mud viscosifier

Viscosifiers

Baroid

Baranex

Temperature stable lignite powder

Filtrate Reducers

Baroid

Baraplug

Sized and treated salts


Baroid

Bararesin-Vis

Organophilic viscosifier for oils

Viscosifiers

Baroid

Barascav D

Powdered sodium sulphite

corrosion inhibitor

Baroid

Barascav L

Liquid oxygen scavenger

corrosion inhibitor

Baroid

Barasol

Sodium ashpalt sulphonate


Baroid

HEC

Viscosifiers

Baroid

Baraweight

Processed iron carbonate

Weighting Materials

Baroid

Barazan

Polysaccharide biopolymer

Viscosifiers

Baroid

Barazan D

Dispersion enhanced xanthan gum

Viscosifiers

Baroid

Barazan D Plus

Dispersant added biopolymer

Viscosifiers

Baroid

Barazan L

Liquid xanthan gum biopolymer

Viscosifiers

Baroid

Barite

Processed barites (BaSO4)

Weighting Materials

All

Barium Carbonate

Baium carbonate

Commercial Chemicals

All

Barodense

Iron oxide

Weighting Materials

Baroid

Barofibre

Fibrous cellulosic material


Baroid

Baroid

Barite, barium sulphate (BaSO4)

Weighting Materials

Baroid

Baroid 100

All oil fluid system

Systems

Baroid

Barolift

Specially treated monofilament fiber sweeping agent

Viscosifiers

Baroid

Baro-Lube GS

Surfactant/lubricant blend

Lubricants

Baroid

Baroseal

Combination LCM


Baroid

Baro-Spot

Blend of anionic surfactants

Lubricants

Baroid

Baro-Trol Plus

Blended hydrocarbon powder


Baroid

Ben-Ex

Co-polymer flocculant and clay extender

Viscosifiers

All/Kelco Oilfield Group

Baravis

Section

16


Brand Name


Primary Function


Bentone

Modified organophilic clay

Viscosifiers


Bentone 38

HTHP performance organoclay

Viscosifiers


Bentone 910

Economical organoclay

Viscosifiers


Bentone150

Self-activating organoclay

Viscosifiers


Bex

W/calcium carbonate stabilized HEC

Viscosifiers

Brine-Add Fluids

Bicarb of Soda

NaHCO3

alkalinity pH control / calcium removers

All

Bio - Spot

Non-toxic oil free, water soluble spotted fluid for weighted muds

Lubricants

Baker Hughes Inteq

Bio-Drill

Polyglycol ROP enhancer


Baker Hughes Inteq

Bio-Lose

Non-fermenting chemically modified starch

Filtrate Reducers

Baker Hughes Inteq

Bio-Lose 90

Drill in system for fractured carbonate reservoirs

Systems

Baker Hughes Inteq

Bio-Paq

Organic derivate filtration control agent

Filtrate Reducers

Baker Hughes Inteq

Biovis

HT biopolymer

Viscosifiers

Canamara United

Biozan

HT biopolymer

Viscosifiers


Black-Magic

Oil-base spotting fluid

Lubricants

Baker Hughes Inteq

Black-Magic LT

Low toxicity spotting fluid

Lubricants

Baker Hughes Inteq

Black-Magic SFT

Spotting fluid concentrate

Lubricants

Baker Hughes Inteq

Blacknite

Coupled gilsonite-based dispersion

Filtrate Reducers

Sun Drilling Products

Blacknite K-Plus

Liquid potassium based gilsonite



Bleach

Sodium Hypochlorite

bactericides

Canamara United

Blue Streak

Conditioner/encapsulator APHRON ICS


M-I Swaco/Federal

BMI Foamtech

Anionic surfactant

Foaming Agents

Bronco Mud

Bore Liner

Blended hydrocarbon powder


Brine-Add Fluids

Boremax

Low colloidal high performance WBM

Systems

Baroid

Bore-Plate

Blend of dispersible gilsonite


Canamara United

Break

Metallic stearate dispersed in alcohol

defoamer

Brine-Add Fluids

Bri-Chem Coupler

Non-ionic surfactant



Bri-Chem Defoamer

General purpose alcohol defoamer

defoamer


Bri-Chem MRP

Concentrated anti-balling surfactant



Bri-Chemcide

Liquid Biocide

bactericides


Bridge Sal

Polymers, calcium lignosulfonate, salt

Bridgits



Brine-Add Fluids

Brine Guard

Sulphide scavenger - zinc carbonate

corrosion inhibitor

Brine-Add Fluids

Brinedril-N

Viscosified heavy brine system

Systems

Baroid

Brine-Ox

Solid catalyzed O2 scavenger

corrosion inhibitor

Brine-Add Fluids

Filtrate Reducers

Brine-Add Fluids

Brinewate

Sized salt for density and fluid loss control

Weighting Materials

Brine-Add Fluids

Bug-Killer

Gluteraldehyde (50% solution)

bactericides

Brine-Add Fluids

BXR

Blended asphalt and hydrocarbon resin


Baroid

Brand Name


Primary Function


BXR-L

Blended asphalt/ hydrocarbon resin in a glycerol/glycol base


Baroid

Cage Absorbant T408

Sized Zeolite


Canamara United

Calcium Carbonate


Weighting Materials

All

Calcium Chloride

Calcium Chloride


All

Calcium Chloride

Calcium Chloride

Weighting Materials

All

Can-Break EBS

Water soluble enzyme acid blend

Polymer Breakers

Canamara United

Can-Break ECA

cellulosic, guar and starch breaker

Polymer Breakers

Canamara United

Can-Break I

Enzyme breaker

Polymer Breakers

Canamara United

Can-Ex

Bentonite extender

Viscosifiers

Canamara United

Can-Free

Surfactant for mixing with oil to free pipe


Canamara United

Can-Oil

100% oil-based drilling fluid

Systems

Symco Drilling Fluids

Can-Oil FLC

Fluid loss control for all-oil system

Filtrate Reducers

Canamara United

Carbo-Core B

Refined Oil

Drill Mud Base Fluids

Baker Hughes Inteq

Carbo-Core B Dif

All-oil drilling / drill in fluid

Systems

Baker Hughes Inteq

Carbo-Core B System

Refined oil invert emulsion

Systems

Baker Hughes Inteq

Carbo-Drill System

Mineral oil invert emulsion

Systems

Baker Hughes Inteq

Carbo-Gel

Organophilic hectoriteviscosifier for solids suspension

Viscosifiers

Baker Hughes Inteq

Carbo-Mul (418)

Oil mud emulsifier and wetting agent

emulsifier

Baker Hughes Inteq

Carbo-Mul HT

High-temp emulsifierand wetting agent

emulsifier

Baker Hughes Inteq

Carbonox

Lignitic humic acid powder


Baroid

Carbo-Tec

Oil mud emulsifier

emulsifier

Baker Hughes Inteq

Carbo-Trol

Oil mud fitration-alphallic blend

Filtrate Reducers

M-I Swaco/Federal

Carbo-Trol A-9

Non-asphaltic filtration control agent for inverts

Filtrate Reducers

Baker Hughes Inteq

Carbo-Trol HT

Filtrate Reducers

Baker Hughes Inteq

Carbo-Vis

High -temp softening point gilsonite for improved filtration in inverts Organo-bentonite

Viscosifiers

Baker Hughes Inteq

Carbwate

Calcium carbonate

Weighting Materials

Brine-Add Fluids

Cat-300

Modified starch

Filtrate Reducers

Baroid

Cat-HI

Modified cellulosic polymer

Filtrate Reducers

Baroid

Cat-LO


Filtrate Reducers

Baroid

Cat-Vis

Welan gum biopolymer

Viscosifiers

Baroid

Caustic Potash

KOH


All

Caustic Soda

NaOH


All

CC 700

Liquid clay control (winterized)


ICTC

CC-16

Causticized leonardite

Filtrate Reducers

Baroid

CDF-100L

Anionic polyacrylamide


Concord Drilling Fluids

Cellex

Sodium carboxymethyl cellulose

Filtrate Reducers

Baroid

Celloflake

Cellophane flake


All

Cellophane

Cellophane flake


All

Cesium Formate

High density brine

Weighting Materials

Canamara United

Section

16


Brand Name


Primary Function


CF Desco II

Organic thinner chrome-free


All/Drilling Specialties

Chek-Loss

Ground complexed cellulose


Baker Hughes Inteq

Chek-Loss Coarse

Ground complexed cellulose


Baker Hughes Inteq

Chek-Loss Plus

High lignin cellulosic LCM for ES in Invert fluids


Baker Hughes Inteq

Chembreak EB

Enzyme for breaking polymers

Polymer Breakers

Brine-Add Fluids

Chembreak ECA

Enzyme blend for polymers and starch

Polymer Breakers

Brine-Add Fluids

Chembreak HC

Calcium hypochlorite oxidizing agent

Polymer Breakers

Brine-Add Fluids

Chemcide

Liquid Biocide

bactericides

Canamara United

Chemclean Rig Wash

Biodegradable cleaner/degreaser


Canamara United

Chemfoam

Foaming agent for water

Foaming Agents

Canamara United

Chemhib #3

Corrosion Inhibitor & anti-anerobi bactericide

corrosion inhibitor

Brine-Add Fluids

Chemoil

Breakable oil-based mud

Systems

Baroid

Chemoil pH

pH control - chemoil system


Canamara United

Chemoil-Buff

pH control - chemoil system


Canamara United

Chemoil-DFM

Defoamer for Chemoil system

defoamer

Canamara United

Chemoil-Gel

Silica-gelant

Viscosifiers

Canamara United

Chemoil-Link

Cross-link for chemoil gel

Viscosifiers

Canamara United

Chemoil-Thin

Thinner for chemoil system


Canamara United

Chemthin OM

Thinner for oil-based muds


Canamara United

Chemtrol X

High-temp filtration control agent for

Filtrate Reducers

Baker Hughes Inteq

water-base fluids

Chemul I

Oil mud primary emulsifier

emulsifier

Canamara United

Chemul II

Oil mud secondary emulsifier

emulsifier

Canamara United

Chemwet OM

Oil mud wetting agent

emulsifier

Canamara United

Chemwet-OM

Wetting agent


Canamara United

Chiron Floc

PHPA

Flocculants

Chiron Technologies

Chrome Alum

Chromic chloride

Commercial Chemicals

Imco/All

CI-40

Corrosion Inhibitor

corrosion inhibitor

M-I Swaco/Federal

Citric Acid

Alkalinity control


All

Clarizan

Clarified xanthan gum

Viscosifiers

Drilling Specialties Co.

Clay Grabber

Selective flocculant for Hydro-Guard system

Flocculants

Baroid

Clay Sync

Shale inhibitor for Hydro-guard system


Baroid

Clayseal Plus

Amphoteric material


Baroid

Clay-Trol

Amphoteric amine complex


Baker Hughes Inteq

Clean Up

Rig Wash Cleaner


M-I Swaco/Federal

Cleardrill

Low toxicity SHC mineral oil


ICTC

Clearex

Blended polymers with carbonates

Clearfoam K

Potassium formate



CMC

Carboxymethyl cellulose

Filtrate Reducers

All

C-Mul

PAO lubricant

Lubricants


Comcorba

Starch system (1957)

CoastaLube

PAO lubricant

Lubricants


Lost Circulation Material Millenium Technologies Ltd.

Brand Name


Primary Function


Con Det

Mud Detergent


Baroid

Conqor 404

Phosphorus-based corrosion inhibitor

corrosion inhibitor

M-I Swaco/Federal

Core-dril

All oil fluid system

Systems

Baroid

Corinox

Corrosion inhibitor/oxygen scavenger

corrosion inhibitor

Canamara United

Cottonseed Hulls

Fibrous biodegradeable hull material


Baker Hughes Inteq

Cronox MEP 426

3 way packer fluid inhibitor

corrosion inhibitor

Baker Hughes Inteq

CRW 132

3 way packer fluid inhibitor

corrosion inhibitor

Baker Hughes Inteq

Crystal-drill

Polymeric shale inhibitor


Baroid

C-squeeze

Filtrate reducer additive

Filtrate Reducers

Marquis Fluids

Cypan

Sodium Polyacrylate

Filtrate Reducers

All/Flowline Solutions

D178 Plus

High-temp polymer filtrate control for

Filtrate Reducers


high salinity environments Dakolite (lignite)

Lignite

emulsifier

All

Dap

Diamonium phosphate


All

D-Break

Viscosity breaker for pure oil systems



D-Buff

pH control - pure oil systems



D-Control

pH control - pure oil systems



DD

Drilling Detergent


M-I Swaco/Federal

Deepdrill Inhibitor

Blend of polyglycerine and methyl glucoside


Newpark Drilling Fluids

Defoam 2000

Silicone based defoamer

defoamer


Defoam-2

Water miscible for polymer systems

defoamer

Brine-Add Fluids

Defoam-A

Alcohol based defoamer

defoamer

M-I Swaco/Federal

Defoamer Silicone

Silicone based defoamer

defoamer

Canamara United

Defoam-X

Low toxicity defoamer

defoamer

M-I Swaco/Federal

Densimix

Hematite

Weighting Materials

Baker Hughes Inteq

Desco

Organic thinner



Detergent L

Drilling Mud Detergent



Dextrid LT

Partially dextrinized polysaccharide

Filtrate Reducers

Baroid

Diamond Seal

Absorbent synthetic polymer


Baroid

Diaseal M

Blended LCm material


All/ Drilling Specialties Co.

Dipro

High density low solids RDF

Systems

M-I Swaco/Federal

Disperse

Wetting agent, rheology modifier

emulsifier


D-Link

Viscosity activator-pure oil systems

Viscosifiers


DME

Non-ionic emulsifier

emulsifier

Imco

DMS



Imco

Dowcide G

Sodium Pentachlorophenate

bactericides

Imco/All

Dril Beads

Polymer beads

Lubricants

Federal / Alpine

Dril Treat

Lecithin liquid


Baroid

Drilcom

Polymer and sized carbonate blend

Viscosifiers


Dril-con D

Blend non-ionic/anionic surface agents



Drilcon DS

Liquid shale inhibitor



Dril-Doktor

Microground cellulose


Canamara United

Section

16


Brand Name


Primary Function


Drilfoam

Foaming agent for water

Foaming Agents

Baroid



Drill Kan MRP Drill Plug C/M

Blended sized cellulose fiber



Drilling Detergent

Drilling detergent liquid/powder


Canamara United

Drillout Plus

Amphoteric cellulose ether

Filtrate Reducers


Drillpac HV


Viscosifiers


Drillpac LV


Filtrate Reducers


Drill-Thin

Chrome-free organic thinner



Dril-N

Non-damaging clay-free polymer based system

Systems

Baroid

Dril-N-Slide

Blend of organics

Lubricants

Baroid

Drilplex

MMO viscosifier

Viscosifiers

M-I Swaco/Federal

Drilstar HT

High temperature starch

Filtrate Reducers

All

Drilsurf

Biodegradable demulsifier



Driscal D

Synthetic HTHP polymer

Filtrate Reducers


Drispac


Viscosifiers


Drispac Plus


Viscosifiers


Drispac Plus Superlo


Filtrate Reducers


Drispac Superlo




DSCO Beads

Polymer beads

Lubricants


DSCO Defoam

Propietary defoamer

defoamer


D-Thins

Thinner for pure oil systems



Dual-Flo

Filtrate Reducer

Filtrate Reducers

M-I Swaco/Federal

Duo-Vis

Xanthan gum, dispersible, non-clarified

Viscosifiers

M-I Swaco/Federal

Duratone Ht

Organophilic colloid powder

Filtrate Reducers

Baroid

Durenex Plus

High-temp sulfonated co-polymer

Filtrate Reducers

Baroid

D-Vis

Viscosifier - pure oil systems

Viscosifiers


Dynadet

Drilling fluid detergent



Dynafiber

Cellulose fiber



Dynared

Ground natural fiber



Ecodrill 317

Potassium silicate


National Silicates

Ecogreen B

Ester base fluid


M-I Swaco/Federal

Ecogreen P

Primary emulsifier for Ecogreen system

emulsifier

M-I Swaco/Federal

Ecogreen S

Secondary emulsifier for Ecogreen system

emulsifier

M-I Swaco/Federal

Ecotrol

Polymeric filtrate reducer

Filtrate Reducers

M-I Swaco/Federal

EK 2000 Degreaser

Detergent/cleaner



Emul-Break

Emulsion breaker


Canamara United

Emulgo

Chalk base emulsion

emulsifier

Brine-Add Fluids

Encapsulator

Liquid polyacrylamide

Flocculants

Canamara United

Encapsorfloc


Flocculants


Enkapsafloc


Flocculants

Canamara United

Envirodrill

Low toxicity SHC mineral oil


ICTC

Envirofloc

Inorganic biodegradable flocculant

Flocculants

Norske Hydro

10

Brand Name


Primary Function


Enviroplug

Sized bentonite


Canamara United

Enviro-Spot

Oil mud concentrate

Lubricants

Baroid

Enviro-Thin

Chrome-free iron lignosulphonate


Baroid

Enviro-Torq

Non-toxic lubricant

Lubricants

Baroid

Envirovert

Chloride free OBM

Systems

M-I Swaco/Federal

Extra High Yeild Bentonite

Peptized wyoming bentonite

Viscosifiers

Canamara United

EZ Drill

Non-foaming vegetable oil blend

Lubricants

BriChem/Q’Max

Ez Mul NT

Oil-soluble surfactant liquid non-toxic

emulsifier

Baroid

Ezcore

In situ invert emulsifier

emulsifier

Baroid

EZE-Slide

Liquid lubricant

Lubricants


EZE-Slide D

Liquid lubricant

Lubricants


Ezeslide OS

Liquid lubricant

Lubricants


Ezeslide XLT

Liquid lubricant

Lubricants


Ez-Glide

Blend of surfactants

Lubricants

Baroid

EZ-Mud

Polyacrylamide polyacrylate


Baroid

EZ-Mud DP

Shale stabilizing polyacrylamide


Baroid

EZ-Plug

Acid soluble blend of LCM


Baroid

EZ-Spot

Blend of emulsifiers, lubricants and viscosifiers

Lubricants

Baroid

FA liquid phpa



Flowline Solutions

Faze-Mul

Emulsifier for Fazepro system

emulsifier

M-I Swaco/Federal

Fazepro

Reversible-wetting invert emulsion mud

Systems

M-I Swaco/Federal

Fed Pac R


Viscosifiers

Federal Wholesale

Fed Pac UL


Viscosifiers

Federal Wholesale

Federal Barite

API spec barite

Weighting Materials

Federal Wholsale

Federal Bentonite

Sodium montmorillonite

Viscosifiers

Federal Wholesale

Federal Supreme

Sodium montmorillonite untreated

Viscosifiers

Federal Wholesale

Fed-Mix II

Blended LCM


Federal

Fed-Rheosmaty

Organic thinner


Federal Wholesale

Fed-Seal

Blended LCM


Federal

Fedxan D

Xanthan gum viscosifier

Viscosifiers

Federal Wholesale

Fer-Ox

Ground hematite

Weighting Materials

M-I Swaco/Federal

Ferrowate

Ferrous carbonate

Weighting Materials

Brine-Add Fluids

Fiber Fluid Coarse

Cellulose fiber



Fiber Fluid Fine

Cellulose fiber



Fibersol

Acid soluble LCM



FilDril K

Potassium silicate


M-I Swaco/Federal

Filter-Chek

High-Temp Modified Starch

Filtrate Reducers

Baroid

Filtravis

Polymeric viscosifier/fluid loss reducer used in

Viscosifiers


conjunction with bentonite Filtravis II

Enhanced foam viscosifier

Viscosifiers

Q’Max Solutions

Filtrex

Polyanionic lignin resin

Filtrate Reducers

Baker Hughes Inteq

FL-2

Water-soluble hydro colloids

Filtrate Reducers

Brine-Add Fluids

11

Section

16

12


Brand Name


Primary Function


FL-3


Filtrate Reducers

Brine-Add Fluids

FL-4


Filtrate Reducers

Brine-Add Fluids

FL-5


Filtrate Reducers

Brine-Add Fluids

FL-6


Filtrate Reducers

Brine-Add Fluids

FL-7 Plus


Filtrate Reducers

Brine-Add Fluids

FL-9


Filtrate Reducers

Brine-Add Fluids

Flake

Cellophane flake


All

Flo-Plex

Polymeric fluid loss additive

Filtrate Reducers

M-I Swaco/Federal

Flopro NT

Minimal solids non-damaging WBM

Systems

M-I Swaco/Federal

Flo-Trol

Modified starch derivitive

Filtrate Reducers

M-I Swaco/Federal

Flo-Vis Plus

Premium xanthan gum

Viscosifiers

M-I Swaco/Federal

Flowzan

Xanthan gum dispersible

Viscosifiers


Floxit

Organic flocculant

Flocculants

M-I Swaco/Federal

Foam Breaker

Propietary defoamer

defoamer

Flowline Solutions

Foam Buster

Mechanical/Chemical defoamer

defoamer


Foam Check

Mechanical/Chemical defoamer

defoamer


Form-A-Plug

Acid soluble plug


M-I Swaco/Federal

Form-A-Plug II

Acid soluble plug with smaller particles


M-I Swaco/Federal

Form-A-Set AK

Polymeric LCM


M-I Swaco/Federal

Form-A-Set ALT

Polymeric LCM for cold climates


M-I Swaco/Federal

Form-A-Set II

Polymeric LCM


M-I Swaco/Federal

FS Liquid PHPA

Liquid polyacrilimide

Flocculants

Flowline Solutions

fx Brine

Potassium formate


DMK Drilling Fluids Ltd

fx Mul I

Primary emulsifier

emulsifier


fx Mul II

Secondary emulsifier

emulsifier


fx Oil Scrub

Oil soluble sulphide scavenger

corrosion inhibitor


fx Poly

Blend of polymers

Viscosifiers


fx Scrub

Water soluble sulphide scavenger

corrosion inhibitor


fx Thin

Deflocculant



Galena

Lead sulphide powder

Weighting Materials

All

Gel

Sodium montmorillonite or Attapulgite

Viscosifiers

All

Gelex

Bentonite extender

Viscosifiers

M-I Swaco/Federal

Geltone II

Oil mud gelling agent

Viscosifiers

Baroid

Geltone IV

Polymer treated organophilic clay

Viscosifiers

Baroid

Geltone V

Amine treated organophilic clay

Viscosifiers

Baroid

Geovis XT

HT stable bioploymer

Viscosifiers


Gilsonite

Natural bitumen


All

Gilsonite HT

Natural bitumen pulverized

Filtrate Reducers

All

Glass Beads

Sized glass beads

Lubricants

Canamara United

Glide Graph 7001

Resilient spherical graphite inert

Lubricants

Canamara United

Glydril

Polyalkylene glycol


M-I Swaco/Federal

Go Devil II

Provides LSRV for AHPHRON ICS system

Viscosifiers

M-I Swaco/Federal

Brand Name


Primary Function


Graphite Powder

Graphite

Lubricants

Canamara United

Greencide

Non-U.S. Biocide

bactericides

M-I Swaco/Federal

G-Seal

Graphite plugging agent


M-I Swaco/Federal

Gumbo Shield

Liquid shale inhibitor



Gypsum

Calcium sulphate


All

H.E.C.

Hydroxyehtyl cellulose

Viscosifiers

All

H.M.E. Coupler



Canamara United

Hibtrol


Filtrate Reducers

M-I Swaco/Federal

High Permas

Amine



HSO 600 G

Oil-soluble H2S scavenger

corrosion inhibitor

All

HSW0705

Liquid H2S scavenger

corrosion inhibitor

Baker Hughes Inteq

Humalite

Lignite


Canamara United

Hydrogel

Wyoming bentonite

Viscosifiers


Hydro-Guard

High performance WBM

Systems

Baroid

Hydro-Plug

Polymeric LCM for vugular or


Baroid

cavernous formations Hyperdrill AD855



Canamara United

Hyperdrill AE851



Canamara United

Hyperdrill AF204RD

Anionic polyacrylamide

Flocculants

All

Hyperdrill AF207RD

High Mol wt. Anionic polyacrylamide

Flocculants

All

Hyperdrill AF247RD

LMW anionic dispersible PHPA


Canamara United

Hyperdrill CP 905H

HMW cationic PHPA


Canamara United

Hyperfloc CP910

Cationic polyacrylamide

Flocculants

All

Hyperfloc CP911

Cationic polyacrylamide

Flocculants

All

Hyperfloc NF301

Non-ionic polyacrylamide

Flocculants

All

Hysal-Plus

Water soluble filtrate additive brines

Filtrate Reducers

Brine-Add Fluids

I - Step Pak

Multi-funct. Packer fluid inhib & freeze protection

corrosion inhibitor

ICTC

IC- foam 1978

Winterized foamer (water soluble)

Foaming Agents

ICTC

IC-CORR 7029

Winterized liquid corrosion inhibitor (oil soluble)

corrosion inhibitor

ICTC

IC-CORR 8551

Liquid corrosion inhibitor (water soluble)

corrosion inhibitor

ICTC

IC-DEFOAM 1489

Winterized antifoam (water soluble)

defoamer

ICTC

IC-DEFOAM 1983

Winterized antifoam (oil soluble)

defoamer

ICTC

IC-floc 2069

Microtox friendly liquid flocculant (water soluble)

Flocculants

ICTC

IC-floc 2200

Microtox friendly liquid flocculant (water soluble)

Flocculants

ICTC

IC-foam 1401

Winterized foaming agent (water soluble)

Foaming Agents

ICTC

IC-foam 1540

Winterized oil foaming agent

Foaming Agents

ICTC

IC-foam1336

Multi-charge capable foaming agent (water soluble)

Foaming Agents

ICTC

IC-HSCAV 4412

Winterized liquid H2S scavenger (oil soluble)

corrosion inhibitor

ICTC

IC-HSCAV 4751

Winterized liquid scavenger

corrosion inhibitor

ICTC

(water soluble high-temp) IC-HSCAV 4935

Winterized liquid H2S scavenger (water soluble)

corrosion inhibitor

ICTC

IC-OSCAV 1050

Winterized catalyzed oxygen scavenger

corrosion inhibitor

ICTC

13

Section

16


Brand Name


Primary Function


IC-Wet

water wetting agent (winterized)


ICTC

Idcap D



M-I Swaco/Federal

Idlube

Refined vegetable oil

Lubricants

M-I Swaco/Federal

Idlube XL

Extreme pressure lubricant

Lubricants

M-I Swaco/Federal

Impermex

Pregeletanized starch

Filtrate Reducers

Baroid

Inhibi-drill

Cationic organic mulitvalent inhibitor



Inhibox

Corrosion inhibitor/oxygen scavenger

corrosion inhibitor


Insta-Flake

Flake calcium carbonate


Flowline Solutions

Invermul NT

Oil mud stabilizer non-toxic

emulsifier

Baroid

Jelflake

Shredded cellophane


Baroid

Jet Cide 250

Gluteraldehyde

bactericides


Jet Hib 5000

H2S scavenger

corrosion inhibitor


Jet Hib 5426

Corrosion inhibitor

corrosion inhibitor


Jet Hib 5432

Oxygen scavenger

corrosion inhibitor


Jet Stim 8000

Drilling detergent



K-2



Canamara United

K2(Enviro K2)

Potassium mud product

Systems

Panther Mud

Kari

Stabilized HEC

Viscosifiers

Brine-Add Fluids

KD-40

Phosphate ester corrosion inhibitor

corrosion inhibitor

Baker Hughes Inteq

Kelzan L

Liquid xanthan gum

Viscosifiers


Kelzan XC

Xanthan gum

Viscosifiers


Kelzan XCD

Dispersible grade xanthan gum

Viscosifiers


Kem-Seal

Co-polymer for high-temp filtration control

Filtrate Reducers

Baker Hughes Inteq

Kim-Mud

Polymer and sized carbonate

Viscosifiers

Brine-Add Fluids

Kontrol

Sulfonated asphalt


Flowline Solutions

K-Power

Potassium nitrate



Kwik-Seal

Combination LCM


Bri-Chem/Kelco Oilfield Group

LD-8

Nonhydrocarbon defoamer

defoamer

Baker Hughes Inteq

LD-9

Polyether polyol defoamer for both fresh &

defoamer

Baker Hughes Inteq

saltwater drilling fluids Le Mul

LAO emulsion stabilizer

emulsifier

Baroid

Le Supermul

LAO emulsifier

emulsifier

Baroid

Ligco

Lignite


Baker Hughes Inteq

Ligcon

Causticized Lignite


Baker Hughes Inteq

Lignite

Lignite(Humic acid)


All

Lignite, Causticized

Lignite, causticized


All

Lignocal

Calcium lignosulfate


Canamara United

14

Brand Name


Primary Function


Lime

Hydrated Lime


All

Liquid Drispac


Viscosifiers


Liquid Flowzan

Suspended xanthan gum

Viscosifiers


Liquid HEC

Suspended HEC

Viscosifiers


Liquidbeads

Liquid lubricant with beads

Lubricants


Liqui-Dril

ROP enhancer

Lubricants

Baroid

Liquigel

Liquid dispersed xanthan gum

Viscosifiers

Brine-Add Fluids

Liquisperse

Concentrated surfactant


Canamara United

Liqui-Vis EP

Dispersed liquid HEC

Viscosifiers

Baroid

Lube-100

Low toxicity lubricant

Lubricants

M-I Swaco/Federal

Lubra-Beads

Divinyl benzene styrene beads

Lubricants

Baroid

Lubrafiber

Modified cellulose fiber



Lubra-Glide

Divinyl benzene styrene beads

Lubricants


Lubra-Seal

Modified cellulose fiber



Lubra-Seal C

Sized cellulose fiber



Lubra-Seal M




Magcobar

Barite

Weighting Materials

Magcobar

Magma Fiber

Acid soluble spun mineral fiber



Magnafloc 10

V. high mol wt. Anionic polyacrylamide

Flocculants


Magnafloc 24

High Mol. Wt. Anioniic polyacrylamide

Flocculants


Magnafloc 351

V. high mol wt. Non- ionic

Flocculants


Magnafloc 368

Low mol. Wt. Cationic coagulant

Flocculants


Magnesium Oxide

pH buffering agent


Canamara United

Maxdril-N

Mixed metal silicate system

Systems

Baroid

MD

Biodegradable drilling fluid detergent


Baker Hughes Inteq

MF 30L


Flocculants

Marquis Fluids

MF 30L



Marquis Fluids

MF BASEal

Filtrate reducer additive

Filtrate Reducers

Marquis Fluids

MF Basemul

Surfactant


Marquis Fluids

MF Emul

Primary Emulsifier


Marquis Fluids

MF Pac LV


Filtrate Reducers

Marquis Fluids

MF Pac R


Filtrate Reducers

Marquis Fluids

MF Rigmate

Rig equipment protector


Marquis Fluids

MF Sil Floc

Low mol. wt. cationic

Flocculants

Marquis Fluids

Lubricants

Marquis Fluids

MF Silglide MF Silsoap

Rig equipment cleaner


Marquis Fluids

MF-1

Selective flocculant

Flocculants


MF-Emul

Primary emulsifier

emulsifier

Marquis Fluids

MF-I/55

Non-anionic polyacrylamide



MF-Oilwet

Oil wetting agent

emulsifier

Marquis Fluids

15

Section

16


Brand Name


Primary Function


MF-Oilwet

Oil Wetting agent


Marquis Fluids

MF-Rigmate

Rig component protector

corrosion inhibitor

Marquis Fluids

MF-Vis

Xanthan gum

Viscosifiers

Marquis Fluids

M-I Bar

Barite

Weighting Materials

M-I Swaco/Federal

M-I Cedar Fiber

Shredded cedar fiber


M-I Swaco/Federal

M-I Gel

Wyoming bentonite

Viscosifiers

M-I Swaco/Federal

M-I Gel Supreme


Viscosifiers

M-I Swaco/Federal

M-I Lube 100

General purpose lubricant

Lubricants

M-I Swaco/Federal

M-I Seal

LCM for fractured or vugular formations


M-I Swaco/Federal

Mica

Sized mica flakes


All

Micatex

Mica flakes


Baroid

Micronaire

Enhanced foam/low density fluid


Q’Max Solutions

Mil-Bar

Barite

Weighting Materials

Milchem

Mil-Bar

Barite

Weighting Materials

Baker Hughes Inteq

Mil-Carb

Sized ground carbonates


Baker Hughes Inteq

Mil-Cardb Series

Multiple grind size series of ground carbonate


Baker Hughes Inteq

Mil-Clean

water soluble, biodegradable detergent/rigwash


Baker Hughes Inteq

Milex

Co-polymer

Flocculants

Baker Hughes Inteq

Mil-Free

Vegetable oil based spotting fluid

Lubricants

Baker Hughes Inteq

Mil-Gard

Sulphide scavenger - zinc carbonate

corrosion inhibitor

Baker Hughes Inteq

Mil-Gard R

Chelated zinc lignosulfonate

corrosion inhibitor

Baker Hughes Inteq

Milgel

Wyoming bentonite

Viscosifiers

Baker Hughes Inteq

Milgel NT


Viscosifiers

Baker Hughes Inteq

Millennium Floc

Dispersible polymer flocculant

Flocculants

Mil-Lube

Vegetable oil lubricant

Lubricants

Baker Hughes Inteq

Mil-Mica

Non-abrasicve mica flakes


Baker Hughes Inteq

Mil-Pac


Filtrate Reducers

Baker Hughes Inteq

Mil-Pac LV

Low viscosity polyanionic cellulose

Filtrate Reducers

Baker Hughes Inteq

Mil-Plug

Ground nutshells


Baker Hughes Inteq

Mil-Seal

Blended LCM available in three grind sizes


Baker Hughes Inteq

MIL-SOS

Hydrolized polyacrylamide

Flocculants

Baker Hughes Inteq

Mil-SOS



Baker Hughes Inteq

Mil-Starch

Pregeletanized starch

Filtrate Reducers

Baker Hughes Inteq

Mil-Temp

Sulfonated styrene, maleic anhydride


Baker Hughes Inteq

co-polymer for water based muds

16

Mintrol

Pure oil fluid loss control

Filtrate Reducers


Mix II

Blended calcium carbonate & polymers


M-I Swaco/Federal

M-I-X II

Ground cellulose LCM & plugging agent


M-I Swaco/Federal

Mon Pac

Premium polyanionic cellulose

Filtrate Reducers


Mon Pac Ultralo

Premium polyanionic cellulose

Filtrate Reducers


MRQ 2100PS

Potassium Silicate based mud

Systems

Marquis Fluids

Brand Name


Primary Function


MTL Foambreak

Defoamer for foam systems

defoamer


MTL Power Clean 2000

Alkaline/citric degreaser



MTL Shurshale

Methanamimium



MTL Ultra Prostix

Soap surfactant stick



MTL Ultrafoam

Foaming agent

Foaming Agents


MTL Ultramine 681

Corrosion inhibitor

corrosion inhibitor


MTL Ultrascav 5000

H2S scavenger & corrosion inhiibitor

corrosion inhibitor


Mud Floc

HMW anionic flocculant

Flocculants


Mud Floc II D

Dispersible selective flocculant

Flocculants

Canamara United

Mud Lite

Enhanced foam surfactant


Q’Max Solutions

Mud-Pac

Corrosion inhibitor for solids laden packer fluids

corrosion inhibitor

Baker Hughes Inteq

Mul Sperse

wetting agent/emulsifier

emulsifier


Mulsperse

Surfactant



Natural Gel

Wyoming bentonite

Viscosifiers

All

N-Dril HT Plus

Stabilized non-ionic starch

Filtrate Reducers

Baroid

New 100 Invert

Salt-free invert

Systems


New Thin

Liquid polyacrylate


Baker Hughes Inteq

New-Drill

Liquid PHPA


Baker Hughes Inteq

New-Drill Plus

PHPA


Baker Hughes Inteq

Newfoam

Surfactant blend

Foaming Agents


Newfoam Breaker

Defoamer for foam systems

defoamer


Newgel

Wyoming bentonite

Viscosifiers


Newlig

Lignite



Newphpa LV

LMW dispersible PHPA



New-Trol

Sodium Polyacrylate

Filtrate Reducers

Baker Hughes Inteq

New-Vis

Organic polymer blend

Viscosifiers

Baker Hughes Inteq

Newxan

Xanthan gum

Viscosifiers

Newpark Drilling Fluid

N-Flow A

In-situ acid breaker system

Polymer Breakers

Baroid

N-Flow AE

In-situ acid/enzymatic breaker system

Polymer Breakers

Baroid

N-Flow AO

In-situ acid/oxidizing breaker system

Polymer Breakers

Baroid

No-Stik

Blend surface agents


All

Novamod

Rheology modifier

Viscosifiers

M-I Swaco/Federal

Novamul

Primary emulsifier for synthetic inverts

emulsifier

M-I Swaco/Federal

Novaplus

Low-viscosity IO synthetic based mud

Systems

M-I Swaco/Federal

Novapro

Olefin-base synthetic mud

Systems

M-I Swaco/Federal

Novatec

LAO base synthetic mud

Systems

M-I Swaco/Federal

Novatec B

LAO base fluid


M-I Swaco/Federal

Novatec M

Low-end rheology modifier

Viscosifiers

M-I Swaco/Federal

Novatec P

Primary emulsifier for Novatec system

emulsifier

M-I Swaco/Federal

Novathin

Thinner for synthetic invert emulsions


M-I Swaco/Federal

Novawet

Wetting agent


M-I Swaco/Federal

17

Section

16


Brand Name


Primary Function


N-Plex

Liquid alkaline salt


Baroid

N-Seal

Specially formulated extrusion material


Baroid

N-Squeeze

Sized cellulose fibers in a non-damaging


Baroid

polymer base Nut Plug

Ground nutshells


M-I Swaco/Federal

Nut Shell

Ground nutshells


Canamara/Hollimex

N-Vis P Plus

Xanthan/non-ionic starch ehter blend

Viscosifiers

Baroid

O S S Pill

Oil soluble resin polymer system


Brine-Add Fluids

Oilfaze

sacked oil base concentrate

emulsifier

M-I Swaco/Federal

Oilgel-3000

Modified organophilic clay

Viscosifiers

Canamara United

Oilsperse

Organic emulsifier

emulsifier

Brine-Add Fluids

OMC

Degelant for organophilic clays


Baroid

Omni-Plex

High performance,anionic,synthetic OBM viscosifier

Viscosifiers

Baker Hughes Inteq

OMV-100

Organophilic clay

Viscosifiers

Canamara United

Optimul

Primary emulsifier

emulsifier


Optiplus

Secondary emulsifier

emulsifier


Optiwet


emulsifier


Organolig

Organophillic lignite for OB and Synthetic Muds

Filtrate Reducers


OSR Defoamer

Oil Ssoluble resin strong defoamer

defoamer

Canamara United

Oxygen Scavenger (OS-IL)

Catalyzed ammonium bisulfate

corrosion inhibitor

M-I Swaco/Federal

Pac-L


Filtrate Reducers

Baroid

Pac-R


Filtrate Reducers

Baroid

Palcotan

18

Tannin Thinner

Paramul

Emulsifier for Paraland system

emulsifier

M-I Swaco/Federal

Parawet

Emulsifier for Paraland system

emulsifier

M-I Swaco/Federal

Peltex

Ferrochrome lignosulfonate


Reed Chemicals

Pelthinz

Chrome lignosulfonate


Georgia Pacific

Pelthinz CF

Chrome-free lignosulfonate


Georgia Pacific

Penetrex

ROP enhancer

Lubricants

Baker Hughes Inteq

Percol 919

Anionic Polyacrylamide(PHPA)

Flocculants

Ciba Specialty Chemicals

Performadril

Highly inhibitive clay-free WBM

Systems

Baroid

Performax

High performance inhibitive WBM

Systems

Baker Hughes Inteq

Perma-Lose HT

Non-fermenting polymerized starch

Filtrate Reducers

Baker Hughes Inteq

Perma-thinz



Georgia Pacific

PH-10

Buffer system magnesium oxide


Brine-Add Fluids

Phenoseal

Thermoset Laminate


Flowline Solutions

Pine Seal

Fibrous flake and granular LCM


Bri-chem

Pipe Free Agent

Starch system (1957) Gypsum/Calcium Source



Pipe Free Agent

Spotting agent

Lubricants


Pipe Lax

Stuck pipe surfactant


M-I Swaco/Federal

Pipe Out

Spotting agent



Plaster

Starch system (1957) Gypsum/Calcium Sourc

various

Brand Name


Primary Function


Pipelax W

Anionic surface active agent

Lubricants

M-I Swaco/Federal

Plug-Git

Processed cedar fiber


Baroid

Plugsal

Sized salt water-soluble bridging


Brine-Add Fluids

Plus-5

Hematite - iron oxide

Weighting Materials

Brine-Add Fluids

Polidril

Polymer blend

Viscosifiers

Brine-Add Fluids

Poliheal

Polymer blend

Filtrate Reducers

Brine-Add Fluids

Poly block

Blended LCm for vugular & cavernous formations Lost Circulation Material


Poly Flake

Polyethylene/polycellulose flakes


Canamara United

Poly Plug Clear Gel

Blended lost circulation plug


All/Canamara United

Poly Seal

Polyethylene/polycellulose flakes


All

Polyac

Broad range filtrate reducer

Filtrate Reducers

Baroid

Polydrill

100% synthetic fluidloss additive

Filtrate Reducers

Canamara United

Flocculants

JSB Resources Ltd.

Polypit Polyloss

Derivatized starch blend

Filtrate Reducers


Polypac (reg, UL)


Viscosifiers

M-I Swaco/Federal

Polypac R


Filtrate Reducers

M-I Swaco/Federal

Polypac UL

Ultra low viscosity pac

Filtrate Reducers

M-I Swaco/Federal

Polyplus

HMW anionic polyacrylamide

Flocculants

M-I Swaco/Federal

Polyplus RD



M-I Swaco/Federal

Polystar

Anti-accretion system designed for SAGD

Systems

Q’Max Solutions

Polytex

Polymer, sized carbonates

Filtrate Reducers

Brine-Add Fluids

Polythin

Powder thinner (extreme conditions)


Canamara United

Poly-Vis II

Mixed metal hydroxide

Viscosifiers

Canamara United

Poly-Xan

Dispersible grade xanthan+B727 gum

Viscosifiers

Canamara United

Potash

Potassium chloride (KCL)


All

Potassium Formate

KCOOH


Canamara United

Potassium Soltex

Potassium sulfonated ashphalt



Potassium Sulphate

K2SO4


All

Powerdrill

Inhibitive WBM

Systems


Preservative

Starch system (1957)

Prima Seal C/M

Blended LCM


Canamara United

Primary Emulsifier

Oil mud primary emulsifier

emulsifier


Proex

Polyacrylate - PHPA blend

Bentonite extender

Protec Mud

Pro-Floc

Polyacrylamide

Flocculants


Protectmagic M

Water dispersible ashphalt


Baker Hughes Inteq

Protectomagic LT

Diesel-base suspension of of clloidal ashphalt


Baker Hughes Inteq

PTS-200

HT polymer stabilizer

Polymer Stabilizers

M-I Swaco/Federal

Puredrill HT-30

Enhanced mineral oil


Petrocanada

Puredrill HT-40

Enhanced mineral oil


Petrocanada

Puredrill IA-35

Synthetic isoalkane


Petrocanada

19

Section

16


Brand Name


Primary Function


Puredrill IA-35LV

Synthetic isoalkane


Petrocanada

Puredrill OE

Synthetic ester blend


Petrocanada

Pyro-trol

Co-polymer acrylamide AMPS

Filtrate Reducers

Baker Hughes Inteq

QM-12

Potassium silicate


Q’Max Solutions

Q’Mul I

Primary emulsifier for mineral oil inverts

emulsifier

Q’Max Solutions

Q’Mul II

Secondary emulsifier for mineral oil inverts

emulsifier

Q’Max Solutions

Q’Mul Primary

Primary emulsifier for SBM’s

emulsifier

Q’Max Solutions

Q’Mul Secondary

Secondary emulsifier for SBM’s

emulsifier

Q’Max Solutions

Q’Pac

PAC

Filtrate Reducers

Q’Max Solutions

Q’Stop



Q’Max Solutions

Quikdril

Solids free non damaging coil tubing fluid

Systems

Baroid

Quik-Foam

Biodegradable foaming agent

Foaming Agents

Baroid

Quik-Free

Spotting fluid concentrate

Lubricants

Baroid

Quik-Gel

High yield bentonite

Viscosifiers

Baroid

Quik-Mud

Suspension of concentrated viscosifiers

Viscosifiers

Baroid

Quik-Thin

Ferrochrome lignosulfonate


Baroid

Quik-trol

Organic polymer


Baroid

Quik-Trol

Organic polymer

Viscosifiers

Baroid

Q’Vis L

Liquid polymeric viscosifier

Viscosifiers

Q’Max Solutions

Q’Wet

Oil wetting agent


Q’Max Solutions

Qwikthin CF

Modified sulfo-methylated tannin



R.O.P.E.

Protein lubricant

Lubricants


Lubricants

Marquis Fluids

Radiagreen EME Salt

20

Rapidrill

Water-based gilsonite/lubricant system

Systems


Rebound

Resilient carbon based LCM



Rebound Fine

Resilient carbon based LCM



Reef Floc

PHPA

Flocculants

Reef Drilling Fluids

Reef Pac

Polyanionic Cellulose


Reef Drilling Fluids

Reef Polymer Plus

Copolymer of sodium acrylate & acrylamide

Flocculants

All

Resinex

Resinated lignin

Filtrate Reducers

M-I Swaco/Federal

Resinex II

Tech grade resinated lignin

Filtrate Reducers

M-I Swaco/Federal

Rhemod L

Modified fatty acid

Viscosifiers

Baroid

Rheoflo

Blended polymer

Viscosifiers


Rhodopol 23 P

Polysaccharide polymer

Viscosifiers


Rhodopol XGD

Polysaccharide polymer

Viscosifiers


RM 63

Blend of fatty acids

Viscosifiers

Baroid

Rubber Crumb

Ground Rubber


Canamara United

Safe Solv OM

Blend of surfactants and solvents


M-I Swaco/Federal

Safe Surfo

Blend of solvents and surfactants


M-I Swaco/Federal

Safecarb



M-I Swaco/Federal

Safe-Carb


Weighting Materials

M-I Swaco/Federal

Brand Name


Primary Function


Safe-T-Coat

Amine inhibitor

corrosion inhibitor


Saf-Kote

Amine type inhibitor

corrosion inhibitor

Canamara United

Salt

NaCl

Weighting Materials

All

Salt Gel

Processed sepiolite

Viscosifiers

All

Salt Water Gel

Attapulgite

Viscosifiers

Baker Hughes Inteq

Sanheal Pill

Calcium carbonate polymer system


Brine-Add Fluids

Sapp

Sodium acid pyrophosphate


All

Sawdust

Sawdust


All

SCW0535

Liquid scale prevention

corrosion inhibitor

Baker Hughes Inteq

Seal-N-Peel

Fluid loss control pill

Systems

M-I Swaco/Federal

Secondary Emulsifier

Oil mud secondary emulsifier

emulsifier


Seperan

Polyacrylamide (Gel-Chem mud system)

Flocculants

Gel-Chem

Ser-Vis

Liquid polymeric viscosifier

Viscosifiers


Shale Bond

Water dispersible uintaite-gilsonite


Baker Hughes Inteq

Sheardril-N

Solids free modified polymer fluid system

Systems

Baroid

Sildril

Potassium silicate inhibitive drilling fluid

Systems

M-I Swaco/Federal

Simple Seal

Calcium carbonate polymer system


Brine-Add Fluids

Slugheal

Calcium carbonate base workover system

Filtrate Reducers

Brine-Add Fluids

Smart plug

Blended LCM



SN-1890

Synthetic base oil used in Synterra system


Baker Hughes Inteq

Soda Ash

Sodium Carbonate

calcium remover

All

Sodium Chromate

Na2CrO4 H2O

corrosion inhibitor

All

Sodium Formate

High density brine

Weighting Materials

Canamara United

Sodium Sulfite

HT polymer stabilizer

Polymer Stabilizers

All

Sodium Sulphite

Oxygen scavenger

corrosion inhibitor

All

Soltex

Sodium ashphalt sulphonate



Solubridge

Sized oil-soluble resins


Brine-Add Fluids

Soludril-N

Sized salt polymer system

Systems

Baroid

Soluflake

Flaked calcium carbonate


Baker Hughes Inteq

Solukleen

Oil soluble resin base workover fluid

Filtrate Reducers

Brine-Add Fluids

Solu-Squeez

Acid-soluble high fluid loss LCM squeeze


Baker Hughes Inteq

Soluvis

Polymer & sized resins

Viscosifiers

Brine-Add Fluids

Sooner Seal

Polyester flake


Canamara United

Spartan

Barite/Baroid

Weighting Agent

All

Spersene CF



M-I Swaco/Federal

Stable K



All/Bri-chem Supply Ltd.

Staflo Ex-Lo Supreme

Low viscosity PAC

Filtrate Reducers

Canamara/Hollimex

Staflo Regular


Filtrate Reducers

Canamara/Hollimex

Standrill

Tri-methyl Ammonium Chloride

Shale Inhibitor

Torandon

Stardril

Filtration control LWD

Filtrate Reducers

All

Starlose

Modified starch with biocide

Filtrate Reducers

All

Starpak DP

Non-fermenting derivatized starch

Filtrate Reducers

All

21

Section

16


Brand Name


Primary Function


Steelseal

Dual composition carbon material


Baroid

Stop-Frac

Blended LCM


Baroid

Sulfatrol

Sulfonated ashphalt


Baker Hughes Inteq

Sun CG

Coupled gilsonite-based dispersion



Super Floc

Organic Polymer

Flocculants

All

Super Sweep

Treated polypropolene fibre

Viscosifiers

Super-Col

Extra high yield bentonite

Viscosifiers

Baker Hughes Inteq

Superlig

Lignite


Canamara United

Superwet 250

Non-ionic water wetting agent


Brine-Add Fluids

Surf-Cote/ Omni-Cote

Oil wetting agent

emulsifier

Baker Hughes Inteq

Suspentone

Organophilic viscosifier for oils

Viscosifiers

Baroid

Sweep-Wate

Selectively sized barite for high density sweeps

Weighting Materials

Baroid

Synerchem CS-50

Chloride free amine inhibitor


All/Synerchem

Synerdrill FR-1

Acrylamide AMPS co-polymer

Filtrate Reducers

All / Synerchem

Synerdrill FR-2

Sulfonated pam

Filtrate Reducers

All / Synerchem

Synerfloc D-40

Poly DADMAC

Flocculants

All/Synerchem

Synerfloc D71181

Cationic Co-polymer

Flocculants

All/Synerchem

Synerfloc PA-50

Polyamine

Flocculants

All/Synerchem

Synerflow

Xanthan,guar,guar blends

Viscosifiers

Synerchem

Synerflow S

Sceroglucan

Viscosifiers

Synerchem

Synerfoam

Surfactant blend

Foaming Agents

Synerchem

Synerhib KF

Potassium formate


All/Synerchem

Synerplex

MMH

Viscosifiers

Synerchem

Synersperse

Liquid/dry LMW polymers


All/Synerchem

Synersperse 35-50

Liquid thinner polyacrylate


All/Synerchem

Synerthin EX

Power thinner polyacrylate


All/Synerchem

Synervis

Guar gum

Viscosifiers

All/Synerchem

Synervis L

Guar gum liquid

Viscosifiers

All/Synerchem

Synerxan

Xanthan gum

Viscosifiers

All/Synerchem

Synerxan D

Dispersible xanthan gum

Viscosifiers

All/Synerchem

Synerxan L

Xanthan liquid

Viscosifiers

All/Synerchem

Synterra

Low viscosity synthetic olefin isomer drilling fluid

Systems

Baker Hughes Inteq

T-352

Gluteraldehyde

bactericides

All

Tannin Thinner

All

Tannix/Tannex Tar-Clean

Anti-accretion for bitumen


M-I Swaco/Federal

Temperus

Suspension agent for oil based and synthetic muds

Viscosifiers

Baroid


Baker Hughes Inteq

Teq Detergent 20L

22

Teq Floc RD

High mol. Wt. Anionic dispersible PHPA

Flocculants

Baker Hughes Inteq

Teq-Thin



Baker Hughes Inteq

Therma Check

Extreme HT filtrate reducer

Filtrate Reducers

Baroid

Therma Vis

Extreme high bentonite extender

Viscosifiers

Baroid

Thermapac U.L.

Carboxymethyl starch

Filtrate Reducers

M-I Swaco/Federal

Brand Name


Primary Function


Therma-Thin

Extreme high-temp reducer/dispersant


Baroid

Thermosafe

High temperature stabilizer

Polymer Stabilizers

Brine-Add Fluids

Thikquik

No fish-eye stabilzed HEC

Viscosifiers

Brine-Add Fluids

Thikquik-L

Liquid dispersed HEC

Viscosifiers

Brine-Add Fluids

Thin-Tex

Modified lignosulphonate


Canamara/Hollimex

Thinzit

Oil mud dispersant



Thix

Blend of polymers

Viscosifiers

Brine-Add Fluids

Thix-Pak

Stabilized thixotropic polymers

Viscosifiers

Brine-Add Fluids

Thixsal

Polymer blend for suspending microsized salt

Viscosifiers

Brine-Add Fluids

Torkease

Non-toxic lubricating agent

Lubricants

All

Torq 2000

Non-foaming vegetable oil- based lubricant

Lubricants

Canamara United

Torq Reducer

Liquid lubricant

Lubricants


Torq-Glide

Non-foaming esther based lubricant

Lubricants

Canamara United

Torq-Lube

Liquid Glycol-base

Lubricants

Canamara United

Torq-Trim II

Alcohol Amide

Lubricants

Baroid

Torq-Trol II

Sulfonated vegetable oil

Lubricants

Canamara United

Torque-less

Friction reducing glass beads

Lubricants

Baroid

TR60

Sulfonated vegetable oil

Lubricants


Transfoam

pH controlled foam system

Systems

Weatherford

Trimulso

Oil in water emulsifier

emulsifier

Baroid

Trimulso

Oil in water emulsifier


Baroid

Trudril

All oil OBM

Systems

M-I Swaco/Federal

Truvis

Rapid yield organophilic clay

Viscosifiers

M-I Swaco/Federal

TS301

Lignosulfonate complex

Filtrate Reducers

Brine-Add Fluids

Turbolink

Liquid polymer mud system

Systems


Turbovis

Liquid polysaccharide polymer

Viscosifiers


Tylose

Hydroxyethel Cellulose

Viscosifiers

Clariant

Ultra Seal C

Coarse ground cellulose


All

Ultra Seal Plus

Medium ground cellulose


All

Ultra Seal XP

Fine ground cellulose


All

Ultrabreak M

Internal breaker for filter cake

Polymer Breakers

Brine-Add Fluids

Ultracap



M-I Swaco/Federal

Ultradrill

High performance WBM

Systems

M-I Swaco/Federal

Ultraglide Beads

Divinyl benzene styrene co-polymer

Lubricants


Ultraglide XLT

Non-foaming liquid

Lubricants


Ultrahib

Shale Inhibitor


M-I Swaco/Federal

Unical

Chrome lignosulfonate


Baker Hughes Inteq

Unical CF

Chrome -free lignosulfonate


Baker Hughes Inteq

Unifoam

Synergistic surfactant blend

Foaming Agents


Unipac

Polyanionic Cellulose

Fluidloss Reducer

Various

Unitrol

Modified starch

Filtrate Reducers

M-I Swaco/Federal

Valfor 100

Sodium aluminosilicate

calcium remover

National Silicates

23

Section

16

24


Brand Name


Primary Function


Variseal

Blended LCM



Versaclean

Mineral oil CaCl2 OBM

Systems

M-I Swaco/Federal

Versaclean B

Low toxicity SHC base oils


M-I Swaco/Federal

Versacoat

Blended emulsifier and gelling agent

emulsifier

M-I Swaco/Federal

Versadrill

Diesel calcium chloride OBM

Systems

M-I Swaco/Federal

Versadrill B

Diesel & dirty mineral salts


M-I Swaco/Federal

Versahrp

Liquid viscosifier & gellant for oil muds

Viscosifiers

M-I Swaco/Federal

Versalig

Modified lignite

Filtrate Reducers

M-I Swaco/Federal

Versamac

Emulsifier for high-brine content fluid

emulsifier

M-I Swaco/Federal

Versamod

Viscosity modifier

emulsifier

M-I Swaco/Federal

Versamod

Low shear rate modifier for oil muds

Viscosifiers

M-I Swaco/Federal

Versamul

Mineral oil emulsifier

emulsifier

M-I Swaco/Federal

Versapac

Thermally activated organic thixotrope

Viscosifiers

M-I Swaco/Federal

Versapro P/S

Primary emulsifier for Versapro system

emulsifier

M-I Swaco/Federal

Versathin

Oil mud dispersant


M-I Swaco/Federal

Versatrol

Naturally occurring gilsonite

Filtrate Reducers

M-I Swaco/Federal

Versawet

Oil wetting agent for oil muds

emulsifier

M-I Swaco/Federal

Versawet

Wetting agent


M-I Swaco/Federal

VG Supreme

Organophilic clay

Viscosifiers

M-I Swaco/Federal

VG69

Organophilic clay

Viscosifiers

M-I Swaco/Federal

Viscom

Viscosifying polymer blend

Viscosifiers


Visplus

Thixotropic viscosifying polymer blend

Viscosifiers


Volclay

Bentonite

Viscosifiers

American Colloids

W O Defoam

Alcohol based defoamer

defoamer

Baker Hughes Inteq

Walnut Hulls

Ground Walnut shells


All

Weatherfoam 104

Polymer recyclable foam system

Systems

Weatherford

Weight Salt

Sized salt for density and fluid loss control

Weighting Materials

Brine-Add Fluids

Wellzyme A

Enzyme breaker with biocide

Polymer Breakers

M-I Swaco/Federal

Wellzyme AE

Enzyme breaker without biocide

Polymer Breakers

M-I Swaco/Federal

Western Poly

Polyethylene flake


Canamara United

Wetting Agent


emulsifier


WFT Transfoam

pH controlled foam

Foaming Agents

Weatherford

WFT-C-100

UBD Inhibitors

corrosion inhibitor

Weatherford

WFT-C-200

UBD Inhibitors

corrosion inhibitor

Weatherford

WFT-C-300

UBD Inhibitors

corrosion inhibitor

Weatherford

WFT-C-400

UBD Inhibitors

corrosion inhibitor

Weatherford

WFT-DF-100

Defoamer for transfoam system

defoamer

Weatherford

WFT-DF-I

Defoamer for non-recyclable foam system

defoamer

Weatherford

WFT-DT-104

Defoamer for 104 foam system

defoamer

Weatherford

WFT-F-100

Non-recyclable foam

Foaming Agents

Weatherford

WFT-F-104

Blended surfactants

Foaming Agents

Weatherford

WFT-HP-104

Liquid blended HEC

Viscosifiers

Weatherford

Brand Name


Primary Function


WFT-Oil Foam 2002

Foaming agent for oil

Foaming Agents

Weatherford

WFT-PP-104

Liquid blended PAC

Viscosifiers

Weatherford

WL 100

Sodium polyacrylate

Filtrate Reducers

All/ Kelco Oilfield Group

WO 20

Hydroxyethyl cellulose with calcium carbonate

Viscosifiers

Baker Hughes Inteq

WO 21L

Liquid HEC

Viscosifiers

Baker Hughes Inteq

Wyoming Gel

Sodium montmorillonite

Viscosifiers

Canamara/Hollimex

X Pel-G

Treated gilsonite



Xandrill

Semi-dispersible xantham gum

Viscosifiers


Xan-Plex D

Readily dispersible xanthan gum polymer

Viscosifiers

Baker Hughes Inteq

Xanthan(Kelzan)

Xanthan gum

Viscosifiers

All

Xanvis

Clarified xanthan gum

Viscosifiers


Xanvis L

Liquid clarified xanthan gum

Viscosifiers


X-Cide 102W

Winterized Gluteraldehyde

bactericides

Baker Hughes Inteq

X-Cide 207

Isothiazolone-base biostat powder

bactericides

All

XL-Defoamer

High Molecular weightsurfactant

defoamer

Canamara/Hollimex

X-Link

Cross-linking polymer with blended LCm


Baker Hughes Inteq

XLR-Rate

ROP enhancer

X-Pel-G

Treated gilsonite



YPC 71

Bentonite extender

Viscosifiers

Mudco Services

Zeogel

Attapulgite powder

Viscosifiers

Baroid

Zetag 7117

Liquid cationic coagulant

Flocculants


Zetag 7197

Liquid low mol. Wt. Cationic coagulant

Flocculants


Zetag 7557

HMW charge cationic polyacrylamide

Flocculants


Zetag 7587

HMW medium charge cationic polyacrylamide

Flocculants


Zetag 7692

Very HMW medium charge cationic polyacrylamide

Flocculants


Zinc Carbonate

Sulphide scavenger

corrosion inhibitor

All

Lubricants

Baroid

25

engineering section 17

engineering data

section 17

engineering data

section 17

Scomi Oiltools

capacity, volume and displacement annular and pipe calculations rectangular and cylindrical mud pit calculations pump calculations pump output annular velocity bottoms up total circulating system displacement total hole volume formulas for adjusting fluid properties mud weight adjustments blending fluids of different densities mud weight required for slugging pipe adjust oil / water ratios increase oil/water ratio decrease oil/water ratio charts and tables tubulars open hole and annular volume pumps triplex pumps duplex pumps hydrostatic pressure average seawater composition chemical formulas of common treating chemicals specific gravity and hardness of common oilfield materials pH of common acids and bases pH ranges of common indicators effect of caustic soda on calcium solubility at 73 ˚F (22.8 ˚C) chemical required to remove contaminants unit conversions

2 2 3 6 6 6 7 7 7 7 7 8 8 9 9 9 10 10 13 15 15 16 17 17 17 18 19 19 20 20 21

Section

17

engineering data

engineering data

capacity, volume and displacement The capacity of a mud tank, a string of pipe, a wellbore, an annulus, or any other “vessel” is the volume that vessel could hold if it were full. The capacity of oilfield pits and tanks is usually measured in bbl, gal or m3. Capacity can also be reported in increments of height (vertical capacity), such as bbl/ft, bbl/in., gal/ft, gal/in. or m3 /m. This is only valid for vessels that have a constant cross-sectional area against height. Volume refers to how much fluid is actually in a mud tank, string of pipe wellbore or annulus, or that is inside any other vessel. If the vertical capacity (bbl/ft or m3 /m) and height of mud (ft or m) are known, then the mud height multiplied by the vertical capacity gives the actual volume (bbl or m3) of mud inside the vessel. Displacement is the volume of fluid that flows out of the wellbore when drillstring or casing is run into the hole. Conversely, it is the volume of fluid that is required to fill the well when the pipe is pulled out of the hole. Displacement usually only represents the actual metal volume of the pipe.

annular and pipe calculations open hole / casing volume - without pipe Use inside diameter (ID) for casing and bit diameter for open hole. Be aware that for “open hole” intervals, the actual hole size may be larger than the bit size due to hole enlargement. Mud logging data or caliper logs can be used to provide a more accurate hole diameter. Oilfield units

S.I units

bbl/ft =

ID 1029.4 2

or bbl =

ID 2 × length 1029.4

pipe capacity Oilfield units bbl / ft =

m3 /m =

ID 2 1.273 × 10 6

or m3 =

ID 2 × length 1.273 × 10 6

S.I units ID 1029.4

or

2

ID 2 bbl = × length 1029.4

m3 /m =

ID 2 1.273 × 10 6

or

ID 2 m3 = × length 1.273 × 10 6

where ID = inside diameter of pipe/casing or open hole in inches or in millimetres. Length = section length/pipe length in feet or in metres Use IDs from pipe tables later in this section (see Charts and Tables). pipe displacement Because of the different dimensions of the various types of tool joints, it is more accurate to read displacements from pipe tables (see Charts and Tables) than to calculate them,

Approx hole volume in bbl/1000 ft = hole diameter2

annular volume Oilfield units bbl / ft =

S.I units

ID 2 − OD 2 1029.4

or bbl =

m3 /m =

or

ID − OD × length 1029.4 2

ID 2 OD 2 1.273 × 10 6

2

m3 =

ID OD 2 × length 1.273 × 10 6 2

where ID = inside diameter of casing or bit diameter in inches or in millimetres, OD = outside diameter of drillpipe or drill collars in inches or in millimetres, Length = annular section length in feet or in metres.

rectangular and cylindrical mud pit calculations On rigs there are a variety of different shape pits and tanks. However, the 3 most common shapes encountered are rectangular, cylindrical vertical and cylindrical horizontal. Most mud tanks are rectangular with parallel sides that are perpendicular to the bottom of the tank. rectangular For a typical rectangular pit the capacity can be calculated using the height, width and length. Where: L = Pit length W = Pit width H = Pit height M = Mud height The general equation to calculate the capacity of a rectangular pit is: Volume = Length × Width × Height

Using feet, the capacity of a rectangular pit is calculated by: Oilfield units S.I units

( )

Pit Capacity ft 3 = L( ft ) × W ( ft ) × H ( ft )

( )

Pit Capacity m 3 = L ( m ) × W ( m) × H ( m)

To convert from ft3 to US barrels, divide by 5.61: Oilfield units S.I units Pit Capacity (bbl ) =

L( ft ) × W ( ft ) × H ( ft ) 5.61

( )

Pit Capacity m 3 = L ( m ) × W ( m) × H ( m)

To calculate the actual volume of mud in the tank the mud height M can be used: Oilfield units S.I units

( )

( )

Mud Volume ft 3 = L ( ft ) × W ( ft ) × M ( ft ) Mud Volume m 3 = L ( m ) × W ( m) × M( m)

To convert from ft3 to US barrels, divide by 5.61: Oilfield units S.I units Mud Volume(bbl ) =

( )

3 L ( ft ) × W ( ft ) × M ( ft ) Mud Volume m = L ( m ) × W ( m) × M( m)

5.61

Section

17

engineering data

cylindrical - vertical These tanks are usually used for fluid or dry bulk (bentonite, barite, cement) storage. Where: D = Diameter of cylinder H = Height of cylinder M = Material height p = 3.1416 Tip: an alternative way to determine the diameter is to measure the circumference and divide by 3.1416: Diameter =

Circumference π

To calculate the capacity for a vertical cylindrical tank the following formula is used: Cylinder Capacity =

π × D2× H 4

Using feet, the capacity of a vertical cylindrical tank is calculated by: Oilfield units S.I units 2 π × D ( ft ) × H ( ft ) π × D 2 (m) × H (m) Cylinder Capacity ( ft 3 ) = Cylinder Capacity ( m3 ) = 4 4 To convert from ft3 to US barrels, divide by 5.61: Oilfield units S.I units

(

)

Cylinder Capacity bbl =

π × D 2 (ft) × H (ft) 4 × 5.61

( )

Cylinder Capacity m3 =

π × D 2 (m) × H (m) 4

To calculate the actual volume of material in the tank the material height M can be used: Oilfield units S.I units 2 ( ) ( ) π × D ft × M ft π × D 2 (m) × M (m) Material Volume ( ft 3) = Material Volume ( m3 ) = 4 4 To convert from ft3 to US barrels, divide by 5.61: Oilfield units S.I units Material Volume

( bbl ) =

π × D 2 (ft) × M (ft) 4 × 5.61

Material Volume

( m ) = π × D (m4) × M (m) 2

3

Dry Bulk Conversions In order to determine how much dry bulk product can be stored in a given vertical cylindrical tank the bulk density of the product to be stored must be known. The bulk density takes into account the minute air gaps between particles. Bulk densities for some common oilfield materials: Material Barite Bentonite Cement

Bulk Density lb/ft3 135 60 94

Bulk Density kg/m3 2163 961 1506

cylindrical - horizontal These type of tanks are usually used for liquid storage on the rig site. Calculating the vertical capacity and volume of a horizontal cylindrical tank is not as straightforward as it is for a vertical cylindrical tank as it varies with horizontal cross-section area and is not a linear function of height. Charts and tabular methods are available to calculate the capacity and volume of horizontal cylindrical tanks. These values can also be calculated as follows. In order to calculate the amount of fluid in a horizontal cylindrical tank first of all determine whether the tank is more than half full. Once that is known apply the appropriate formula to determine the actual amount of fluid in the tank. Horizontal Cylindrical Tank – half full or less Where: D = Diameter of cylinder L = Length of cylinder M = Mud height

L

D D

L

M M

Using feet for all the dimensions, the actual volume of a horizontal cylindrical tank that is half full or less is calculated by:  M3 Mud Volume ft 3 =  0.3168DM + 1.403M 2 − 0.933 × L D  

( )

To convert from ft3 to US barrels, divide by 5.61: Oilfield units  M3 2  0.3168DM + 1.403M − 0.933 × L D   Mud Volume(bbl ) = 5.61

S.I units  M3 2  ×L Mud Volume(m3 ) =  0.3168DM + 1.403M − 0.933 D  

Horizontal Cylindrical Tank – more than half full Where: D = Diameter of cylinder L = Length of cylinder M = Empty space height The method employed to calculate the volume in this case is calculate the total capacity of the tank and then subtract the empty portion, which is half or less than half the tank volume.

D D

L

L

MM

Section

17

engineering data

Using feet for all the dimensions, the actual volume of a horizontal cylindrical tank that is more than half full is calculated by:   D 2 × L   M3 2 Mud Volume ft 3 =   −  0.3168DM + 1.403M − 0.933  × L  D   4   

( )

To convert from ft3 to US barrels, divide by 5.61: Oilfield units  D 2 × L   M3  2   −  0.3168DM + 1.403M − 0.933  × L 4 D      Mud Volume(bbl ) = 5.61

S.I units

 D 2 × L   M3  2   −  0.3168DM + 1.403M − 0.933  × L D    4   Mud Volume(m3 ) = 5.61

pump calculations pump output Duplex: Oilfield units

D2 D12 − r 2 ×V × S bbl / stroke = e 1 3088.2

Triplex: Oilfield units

D 2 × Ve bbl / stroke = 1 × S1 4117.7

S.I units  ( 2 × D12 ) − Dr2 S1   × 0.159 m3/ stroke =  × Ve × 3984766 25.4  

S.I units m3/ stroke =

( D12

Where: D1 = liner diameter (inches or mm), Dr = rod diameter (inches or mm), Ve = volumetric efficiency (decimal fraction), S1 = stroke length (inches or mm).

× 25.42 × Ve × 25.4 × S1 )

1.5 × 106

Pump outputs may be determined from pump charts in the Charts and Tables chapter.

annular velocity Oilfield units

24.5× V AV = ID 2 − OD 2

S.I units AV =

1275 × V ID 2 − OD 2

Where: AV = annular velocity (ft./minute or m/min), V = pump rate in gal/min or in l/min, ID = inside diameter of the hole or casing (inches or mm), OD = outside diameter of the pipe or collars (inches or mm).

bottoms up Oilfield units strokes or mins =

Annular Volume (bbls)

Pump Rate (bbls / stk or bbl / min)

S.I units strokes or mins =

Annular Volume ( m3 )

Pump Rate ( m3 / stk or m3 / min)

total circulating system displacement Oilfield units strokes or mins =


Surface Active vol (bbls) + Annular vol (bbls) + Pipe vol (bbls) Pump Rate (bbls / stk or bbl / min)

Surface Active vol m3 + Annular vol m3 + Pipe vol m3 Pump Rate ( m3 / stk or m3 / min)

total hole volume Oilfield units strokes or mins =


Annular vol (bbls) + Pipe vol (bbls) Pump Rate (bbls / stk or bbl / min)

Annular vol ( m3 ) + Pipe vol ( m3 ) Pump Rate ( m3 / stk or m3 / min)

formulas for adjusting fluid properties mud weight adjustments weight-up calculations (vol increase acceptable) Use the following formulas to calculate the amount of weight material required to increase the density of a drilling fluid when a volume increase can be tolerated. Oilfield units  350.5× WM SG × (W F − W I )  Wt Material lbs =   × V1 8.345 × WM SG − W F   Vol Increase bbls =

B 350.5 × WM SG

S.I units  1000 × WM SG × (W F − W I )  Wt Material kg =   × V1 1000 × WM SG − W F   Vol Increase m3 =

B 1000 × WM SG

If 12 lb/gal (1.44 SG.) or less mud weight is required: 60 x 100 lb (45.35 kg) sxs will increase weight by 1 lb/gal/100 bbl or 0.12 SG. per 15.9 m3 If over 12 lb/gal is required: Divide desired weight in ppg by 0.2 = number of 100 lb sxs to increase weight by 1 lb/gal/100 bbl.

Section

17

engineering data

Where: B = the weight material to add, lb or kg V1 = the starting volume of mud, bbl or m3 WMSG = the specific gravity of the weight material WM WF = the desired mud weight, lb/gal or kg/m3 WI = the starting mud weight, lb/gal or kg/m3 V = the volume increase, bbl or m3 weight-up calculations (specific final vol) Use the following formulas to calculate a starting volume of mud and amount of weight material required to increase the density of a drilling fluid when the final volume is specified. Oilfield units  8.345 × WM − W  SG F Starting Vol Mud bbls =   × VD  8.345 × WM SG − W I 

Wt Material lbs = (VD − VI ) × WM SG × 350.5

S.I units  1000 × WM − W  SG F Starting Vol Mud m3 =   × VD  1000 × WM SG − W I 

Wt Material kg = (VD − VI ) × WM SG × 1000

Where: B = the weight material to add, lb or kg VI = the starting volume of mud, bbl or m3 VD = the desired final volume of mud, bbl or m3 WMSG = the specific gravity of the weight material WF = the desired mud weight, lb/gal F or kg/m3 WI = the starting mud weight, lb/gal I or kg/m3 decrease mud weight (vol increase acceptable) Use the following formula to calculate the volume of dilution fluid required to decrease the density of a drilling fluid when a volume increase is acceptable. Oilfield units S.I units     W I −W F W I −W F Vol of Dilution bbls =   × VI Vol of Dilution m3 =   × VI W − 8.345 × DF  F  W F − 1000 × DFSG  SG 

Where: VI = the starting volume of mud, bbl or m3 WF = the desired mud weight, lb/gal or kg/m3 WI = the starting mud weight, lb/gal or kg/m3 DFSG = the specific gravity of the dilution fluid

15 x 100 lb sxs barite = 1 bbl or 15 x 45.35 kg sxs barite = 0.159 m3

decrease mud weight (final volume specified) Use the following formula to calculate the starting volume of mud and a volume of dilution fluid required to decrease the density of a drilling fluid when the final volume is specified. Oilfield units  8.345 × DF −W  SG F Starting Vol Mud bbls =   × VD  8.345 × DFSG −W I 

DilutionVol bbls = VD − VI

S.I units

 1000 × DF −W  SG F Starting Vol Mud m3 =   × VD  1000 × DFSG −W I 

DilutionVol m3 = VD − VI

Where: VI = the starting volume of mud, bbl or m3 WF = the desired mud weight, lb/gal or kg/m3 WI = the starting mud weight, lb/gal or kg/m3 DFSG = the specific gravity of the dilution fluid VD = the desired final volume, bbl or m3 VDF = the volume of dilution fluid to add, bbl or m3

blending fluids of different densities Use the following formulas for blending different fluids of varying densities. Note: This formula assumes fluids are totally miscible, no precipitation occurs, and fluids are of compatible salinity. This equation does not apply to the mixing of high density brine fluids. VF = V1 + V2 VFW F = V1W1 + V2W 2

Where: V1 = volume of first fluid (bbl or m3), V2 = volume of second fluid (bbl or m3), VF = final volume (bbl or m3), W1 = weight of first fluid (lbm/gal or kg/m3), W2 = weight of second fluid (lbm/gal or kg/m3), WF = weight of combined fluids or final weight (lbm/gal).

mud weight required for slugging pipe The following flormula can be used to calculate the density increase required to achieve a certain length of dry pipe. This is usually 500-800 ft. However, downhole tools, some blocked jets, core barrel, etc can require the overbalance to be greater. In which case increase the length of dry pipe. Oilfield units Density Increase lbs / gal =

MW × LDP × DPCAP VSLUG

Density Increase kg / m3 =

MW × LDP × DPCAP VSLUG

S.I units

Section

17

engineering data

Where: MW = Current fluid density (lbs/gal or kg/m3), DPCAP = Drill pipe capacity (bbl/ft or m3/m), VSLUG = Slug volume, usually 30 - 50 bbls (4.77 – 7.95 m3), LDP = Desired length of dry pipe, usually 500 - 800 ft (152.4 – 243.8 m).

adjust oil / water ratios Use the following formulas to calculate the volume of oil or water required to change the oil/water ratio of a mud when a volume increase is acceptable.

increase oil/water ratio Increase the oil/water ratio by adding oil using the following formulas.

PW =

RW RW + RO + VO

VO =

RW − RW − RO PW

or

Oilfield units WR =

S.I units

W I + (8.345 × OSG × VO ) 1 + VO

WR =

W I + (1000 × OSG × VO ) 1 + VO

Where: VO = the volume of oil to be added, bbl/bbl (m3/m3) mud RO = the % oil from retort, decimal equivalent RW = the % water from retort, decimal equivalent PW = the new % by volume water in the liquid W phase, decimal equivalent WR = the resulting mud weigh t, lb/gal (kg/m3) WI = the starting mud weight, lb/gal (kg/m3) OSG = the specific gravity of the oil

decrease oil/water ratio Decrease the oil/water ratio by adding water using the following formulas.

PO =

RO RO + RW + VW

VW =

RO − RO − RW PO

or

Oilfield units WR =

S.I units

W I + (8.345 × VW ) 1 + VW

WR =

W I + (1000 × VW ) 1 + VW

Where VW = the volume of water to be added, bbl/bbl (m3/m3) mud RO = the % oil from retort, decimal equivalent RW = the % water from retort, decimal equivalent PO = the new % by volume oil in the liquid phase, decimal equivalent WR = the resulting mud weight, lb/gal (kg/m3) WI = the starting mud weight, lb/gal (kg/m3)

10

charts and tables tubulars Table 1 - Casing OD in. 4-1⁄2 4-1⁄2 4-3⁄4 5 5 5-1⁄2 5-1⁄2 5-3⁄4 6 6-5⁄8 7 7 7-5⁄8 7-5⁄8 7-5⁄8 8-5⁄8 9-5⁄8 9-5⁄8 9-5⁄8 10-3⁄4 10-3⁄4 10-3⁄4 11-3⁄4 13-3⁄8 13-3⁄8 16 16 18-5⁄8 20

mm 114.3 114.3 120.65 127 127 139.7 139.7 146.05 152.4 168.28 177.8 177.8 193.68 193.68 193.68 219.08 244.48 244.48 244.48 273.05 273.05 273.05 298.45 339.73 339.73 406.4 406.4 473.08 508

lb/ft 13.5 15.1 16 15 18 20 23 22.5 26 32 26 38 26.4 33.7 39 38 40 47 53.5 40.5 45.5 51 60 54.5 68 65 75 87.5 94

Weight kg/m 20.09 22.47 23.81 22.32 26.79 29.8 34.3 33.5 38.7 47.7 38.7 56.6 39.3 50.2 58.1 56.6 59.6 70 79.7 60.3 67.8 75.9 89.4 81.2 101.3 96.9 111.8 130.4 140.1

ID in. 3.92 3.826 4.082 4.408 4.276 4.778 4.67 4.99 5.14 5.675 6.276 5.92 6.969 6.765 6.625 7.775 8.835 8.681 8.535 10.05 9.95 9.85 10.772 12.615 12.415 15.25 15.124 17.755 19.124

mm 99.57 97.18 103.68 111.96 108.61 121.36 118.62 126.75 130.56 144.15 159.41 150.37 177.01 171.83 168.28 197.49 224.41 220.50 216.79 255.27 252.73 250.19 273.61 320.42 315.34 387.35 384.15 450.98 485.75

Capacity bbl/ft m3/m 0.0149 0.00777 0.0142 0.00741 0.0162 0.00845 0.0189 0.00986 0.0178 0.00928 0.0222 0.0116 0.0212 0.01106 0.0242 0.01262 0.0257 0.01341 0.0313 0.01633 0.0383 0.01998 0.034 0.01773 0.0472 0.02462 0.0445 0.02321 0.0426 0.02222 0.0587 0.03062 0.0758 0.03954 0.0732 0.03818 0.0708 0.03693 0.0981 0.05117 0.0962 0.05018 0.0942 0.04913 0.1127 0.05878 0.1546 0.08064 0.1497 0.07808 0.2259 0.11783 0.2222 0.11590 0.3062 0.15971 0.3553 0.18532

Displacement bbl/ft m3/m 0.0047 0.00245 0.0055 0.00287 0.0057 0.00297 0.0054 0.00282 0.0065 0.00339 0.0072 0.00376 0.0082 0.00428 0.0079 0.00412 0.0093 0.00485 0.0114 0.00595 0.0093 0.00485 0.0136 0.00709 0.0093 0.00485 0.012 0.00626 0.0138 0.00720 0.0135 0.00704 0.0142 0.00741 0.0168 0.00876 0.0192 0.01001 0.0141 0.00735 0.0161 0.00840 0.018 0.00939 0.0214 0.00116 0.0192 0.01002 0.0241 0.01257 0.0228 0.01189 0.0265 0.01382 0.0307 0.01601 0.0333 0.01737

mm 50.67 62.00 54.61 70.21 66.09 84.84 97.18 92.46 108.61 107.04 121.36 118.62 123.42 120.22 146.33 177.01

Capacity bbl/ft m3/m 0.0039 0.00203 0.0058 0.00303 0.0045 0.00235 0.0074 0.00386 0.0066 0.00344 0.0108 0.00563 0.0142 0.00741 0.0129 0.00673 0.0178 0.00928 0.0173 0.00902 0.0222 0.01158 0.0212 0.01106 0.0229 0.01194 0.0218 0.01137 0.0322 0.01680 0.0472 0.02462

Displacement bbl/ft m3/m 0.0016 0.00083 0.0022 0.00115 0.0035 0.00183 0.0045 0.00235 0.0053 0.00276 0.0047 0.00245 0.0055 0.00287 0.0068 0.00355 0.0065 0.00339 0.0070 0.00365 0.0072 0.00376 0.0082 0.00428 0.0071 0.00370 0.0083 0.00433 0.0104 0.00542 0.0093 0.00485

Table 2 – Drill Pipe OD in. 2-3⁄8 2-7⁄8 2-7⁄8 3-1⁄2 3-1⁄2 4 4-1⁄2 4-1⁄2 5 5 5-1⁄2 5-1⁄2 5-9⁄16 5-9⁄16 6-5⁄8 7-5⁄8

mm 60.33 73.03 73.03 88.9 88.9 101.6 114.3 114.3 127 127 139.7 139.7 141.29 141.29 168.28 193.68

Weight lb/ft kg/m 4.85 7.23 6.85 10.21 10.40 15.50 13.30 19.82 15.50 23.10 14.00 20.86 16.60 24.73 20.00 29.8 19.50 29.06 20.50 30.55 21.90 32.63 24.70 36.80 22.20 33.08 25.25 37.62 31.90 47.53 29.25 43.58

ID in. 1.995 2.441 2.150 2.764 2.602 3.340 3.826 3.640 4.276 4.214 4.778 4.670 4.859 4.733 5.761 6.969

11

Section

17

engineering data

Table 3 - Heavy Weight Drill Pipe OD in. mm 88.9 3-1⁄2 88.9 3-1⁄2 101.6 4 114.3 4-1⁄2 127 5 139.7 5-1⁄2 168.28 6-5⁄8

Weight lb/ft kg/m 25.30 37.70 23.20 34.57 27.20 40.53 41.00 61.09 49.30 73.46 57.00 84.93 70.80 105.49

ID mm 52.4 57.15 65.1 69.85 76.2 85.73 114.3

Capacity bbl/ft m3/m 0.0042 0.00219 0.0050 0.00261 0.0064 0.00334 0.0074 0.00386 0.0088 0.00459 0.0112 0.00584 0.0197 0.01028

Displacement bbl/ft m3/m 0.0092 0.00480 0.0084 0.00438 0.0108 0.00563 0.0149 0.00777 0.0180 0.00939 0.0210 0.01095 0.0260 0.01356

in.

mm

Capacity bbl/ft m3/m

Displacement bbl/ft m3/m

1.500 2.000 2.250 2.250 2.250 2.813 2.250 2.813 2.813 3.000 3.000 3.000

38.1 50.8 57.2 57.2 57.2 71.45 57.15 71.45 71.45 76.2 76.2 76.2

0.00219 0.00389 0.00492 0.00492 0.00492 0.00768 0.00492 0.00768 0.00768 0.00874 0.00874 0.00874

0.0097 0.0126 0.0170 0.0301 0.0330 0.0334 0.0393 0.0507 0.0545 0.0789 0.0884 0.1142

in.

mm

Weight bbl/ft kg/m

1.610 1.995 2.441 2.992 3.476 3.958

40.89 50.67 62 76 88.29 100.53

in. 2.063 2.250 2.563 2.750 3.000 3.375 4.500

Table 4 - Drill Collars OD in. 3-1⁄2 4-1⁄8 4-3⁄4 6 6-1⁄4 6-1⁄2 6-3⁄4 7-3⁄4 8 9-1⁄2 10 11-1⁄4

Weight kg/m

mm

lb/ft

88.9 104.78 120.65 152.4 158.75 165.1 171.45 196.85 203.2 241.3 254 285.75

26.64 34.68 46.70 82.50 90.60 91.56 108.00 138.48 150.48 217.02 242.98 314.20

39.69 51.67 69.58 122.93 134.99 136.42 160.92 206.34 224.22 323.36 362.04 468.16

ID

0.00114 0.00203 0.00257 0.00257 0.00257 0.00401 0.00257 0.00401 0.00401 0.00456 0.00456 0.00456

0.00506 0.00657 0.00887 0.00157 0.01721 0.01742 0.02050 0.02645 0.02843 0.04115 0.046109 0.05957

Table 5 - API Tubing (standard) Nominal Size in. mm 1-1⁄2 2 2-1⁄2 3 3-1⁄2 4

12

38.1 50.8 63.5 76.2 88.9 101.6

Weight lb/ft kg/m 1-5⁄16 2-3⁄8 2-7⁄8 3-1⁄2 4 4-1⁄2

33.34 60.33 73.03 88.9 101.6 114.3

ID

2.75 4.60 6.40 10.20 11.00 12.60

4.1 6.85 9.54 15.2 16.39 18.77

Displacement bbl/ft m3/m 0.0025 0.0039 0.0058 0.0087 0.0117 0.0152

0.0013 0.00203 0.00303 0.00454 0.0061 0.00793

open hole and annular volume Table 6 - Open Hole Volume Diameter (in.)

Capacity (bbl/ft)

Diameter (mm)

Capacity (m3/m)

3-1⁄2 3-7⁄8 4-1⁄4 4-1⁄2 4-3⁄4 5-1⁄4 5-5⁄8 5-3⁄4 5-7⁄8 6 6-1⁄8 6-1⁄4 6-1⁄2 6-3⁄4 7-3⁄8 7-5⁄8 7-7⁄8 8-3⁄8

0.0119 0.0146 0.0175 0.0197 0.0219 0.0268 0.0307 0.0321 0.0335 0.0350 0.0364 0.0379 0.0410 0.0443 0.0528 0.0565 0.0602 0.0681

88.9 98.43 107.95 114.3 120.65 133.4 142.88 146.05 149.23 152.4 155.58 158.75 165.1 171.45 187.33 193.68 200.03 212.73

0.00621 0.00762 0.00913 0.01028 0.01142 0.01398 0.01601 0.01674 0.01747 0.01826 0.01899 0.01977 0.02139 0.02311 0.02754 0.02947 0.03140 0.03552

Diameter (in.)

Capacity (bbl/ft)

Diameter (mm)

Capacity (m3/m)

8-1⁄2 8-5⁄8 8-3⁄4 9-1⁄2 9-5⁄8 9-7⁄8 10-5⁄8 11 12-1⁄4 14-3⁄4 15 16 17-1⁄2 18 20 22 24

0.0702 0.0723 0.0744 0.0877 0.0900 0.0947 0.1097 0.1175 0.1458 0.2113 0.2186 0.2487 0.2975 0.3147 0.3886 0.4702 0.5595

215.9 219.075 222.25 241.3 244.475 250.825 269.875 279.4 311.15 374.65 381 406.4 444.5 457.2 508 558.8 609.6

0.03662 0.03771 0.03881 0.04574 0.04694 0.04940 0.05722 0.06129 0.07605 0.11021 0.11402 0.12972 0.15518 0.16415 0.20269 0.24526 0.29184

13

Section

17

engineering data

Table 7 - Annular Volume Oilfield units

OD in.

Drillpipe Nominal Displace Wt bbl/ft lb/ft

Capacity bbl/ft

Size in.

Hole Hole Capacity bbl/ft

Annular Capacity bbl/ft

4.250 4.750 4.750 5.625 6.125 6.125 6.625 6.750 7.750 7.750 8.500 8.750 7.875 8.500 8.750 9.875 12.250 8.500 9.8751 10.875 12.250

0.0175 0.0219 0.0219 0.0307 0.0364 0.0364 0.0426 0.0443 0.0583 0.0583 0.0702 0.0744 0.0602 0.0702 0.0744 0.0947 0.1458 0.0702 0.0947 0.1149 0.1458

0.0119 0.0164 0.0136 0.0224 0.0284 0.0241 0.0307 0.0324 0.0464 0.0423 0.0546 0.0588 0.0396 0.0496 0.0538 0.0741 0.1252 0.0453 0.0698 0.0900 0.1209

6.65 6.65 10.40 10.40 10.40 13.30 13.30 15.50

0.002419 0.002419 0.003784 0.003784 0.003784 0.004839 0.004839 0.005639

0.00320 0.00320 0.004495 0.004495 0.004495 0.007421 0.007421 0.006576

4.000

14.00 14.00

0.005093 0.005093

0.010836 0.010836

4.500

16.60 16.60 16.60 16.60

0.006390 0.006390 0.006390 0.006390

0.014219 0.014219 0.014219 0.014219

5.000

19.50 19.50

0.007094 0.007094

0.017762 0.017762

Drillpipe Nominal Displace Wt m3/m kg/m

Capacity m3/m

Size mm 107.95 120.65 120.65 142.88 155.58 155.58 168.28 171.45 196.85 196.85 215.9 222.25 200.03 215.9 222.25 250.83 311.15 215.9 250.83 276.23 311.15

2.375 2.875

3.500

S.I units OD mm

9.91 9.91 15.50 15.50 15.50 19.82 19.82 23.1

0.001262 0.001262 0.00197 0.00197 0.00197 0.00252 0.00252 0.00294

0.00167 0.00167 0.00234 0.00234 0.00234 0.00387 0.00387 0.00343

101.6

20.86 20.86

0.00266 0.00266

0.00565 0.00565

114.3

24.73 24.73 24.73 24.73

0.00333 0.00333 0.00333 0.00333

0.00742 0.00742 0.00742 0.00742

127

29.06 29.06

0.00370 0.00370

0.00926 0.00926

60.33 73.03

88.9

14

Hole Hole Capacity m3/m 0.00913 0.01442 0.01442 0.01601 0.01899 0.01899 0.02222 0.02311 0.03041 0.03401 0.03662 0.03881 0.0314 0.03662 0.03881 0.04940 0.07605 0.03662 0.04940 0.05993 0.07605

Annular Capacity m3/m 0.00621 0.00855 0.00709 0.01168 0.01481 0.01257 0.01601 0.01690 0.02420 0.02206 0.02848 0.03067 0.02066 0.02587 0.02806 0.03866 0.06530 0.02363 0.03641 0.04694 0.06306

pumps triplex pumps Table 8 - Displacement of Triplex Fluid Pumps (bbl per Stroke - 100% Efficiency) Oilfield units Stroke Length (ins.)

Lnr Size (in) 7.00 3.00 0.0153 3.25 0.0179 3.50 0.0208 3.75 0.0238

7.50

8.00

8.50

9.00

9.25

10.0

11.0

12.0

0.0164 0.0192 0.0223 0.0257

0.0175 0.0205 0.0238 0.0273

0.0186 0.0218 0.0252 0.0290

0.0197 0.0231 0.0267 0.0307

0.0202 0.0237 0.0276 0.0317

0.0219 0.0257 0.0298 0.034

0.024 0.0283 0.0326 0.0376

0.0262 0.0307 0.0357 0.0408

4.00 4.25 4.50 4.75

0.0271 0.0307 0.0345 0.0383

0.029 0.0328 0.0369 0.0411

0.0311 0.035 0.0392 0.0438

0.033 0.0374 0.0419 0.0466

0.035 0.0395 0.0443 0.0493

0.036 0.0404 0.0455 0.0507

0.0388 0.0438 0.0493 0.0547

0.0429 0.0483 0.054 0.0602

0.0467 0.0526 0.0590 0.0657

5.00 5.25 5.50 5.75

0.0426 0.0469 0.0514 0.0562

0.0455 0.0502 0.055 0.0602

0.0486 0.0535 0.0588 0.0643

0.0517 0.0569 0.0624 0.0683

0.0548 0.0602 0.0661 0.0721

0.0562 0.062 0.0678 0.0743

0.0607 0.0669 0.0736 0.0802

0.0669 0.0736 0.0807 0.0883

0.0729 0.0802 0.088 0.0964

6.00 6.25 6.50 6.75

0.0611 0.0664 0.0719 0.0774

0.0655 0.0712 0.0719 0.083

0.070 0.0759 0.0821 0.0886

0.0743 0.0807 0.0871 0.094

0.0786 0.0855 0.0924 0.0995

0.0809 0.0878 0.0949 0.1023

0.0874 0.0948 0.1026 0.1107

0.0961 0.1043 0.1129 0.1217

0.105 0.1138 0.123 0.1328

7.00

0.833

0.893

0.0952

0.101

0.1071

0.11

0.119

0.131

0.143

S.I units Lnr Size (mm) 177.80

Stroke Length (ins.) 190.50

203.20

215.90

228.60

234.95

234.95

279.40

304.80

76.20 82.55 88.90 95.25

0.39 0.45 0.53 0.60

0.42 0.49 0.57 0.65

0.44 0.52 0.60 0.69

0.47 0.55 0.64 0.74

0.50 0.59 0.68 0.78

0.51 0.60 0.70 0.81

0.56 0.65 0.76 0.86

0.61 0.72 0.83 0.96

0.67 0.78 0.91 1.04

101.60 107.95 114.30 120.65

0.69 0.78 0.88 0.97

0.74 0.83 0.94 1.04

0.79 0.89 1.00 1.11

0.84 0.95 1.06 1.18

0.89 1.00 1.13 1.25

0.91 1.03 1.16 1.29

0.99 1.11 1.25 1.39

1.09 1.23 1.37 1.53

1.19 1.34 1.50 1.67

127.00 133.35 139.70 146.05

1.08 1.19 1.31 1.43

1.16 1.28 1.40 1.53

1.23 1.36 1.49 1.63

1.31 1.45 1.58 1.73

1.39 1.53 1.68 1.83

1.43 1.57 1.72 1.89

1.54 1.70 1.87 2.04

1.70 1.87 2.05 2.24

1.85 2.04 2.24 2.45

152.40 158.75 165.10 171.45

1.55 1.69 1.83 1.97

1.66 1.81 1.83 2.11

1.78 1.93 2.09 2.25

1.89 2.05 2.21 2.39

2.00 2.17 2.35 2.53

2.05 2.23 2.41 2.60

2.22 2.41 2.61 2.81

2.44 2.65 2.87 3.09

2.67 2.89 3.12 3.37

177.80 21.16

22.68

2.42

2.57

2.72

2.79

3.02

3.33

3.63

15

Section

17

engineering data

duplex pumps Table 9 - Displacement of Duplex Pumps (bbl per Stroke - 100% Efficiency) Oilfield units Stroke Length (in.) Liner Size (in.) 4 4.25 4.5 4.75

12

14

15 16 Rod Diameter (in.) 2.25 2.25 0.086 0.096 0.097 0.104

18

20

2 0.055 0.062 0.071 0.08

2 0.064 0.073 0.083 0.093

2.5 0.099 0.113

2.5 0.111 0.126

5 5.25 5.5 5.75

0.089 0.099 0.11 0.121

0.104 0.116 0.128 0.141

0.109 0.121 0.135 0.149

0.116 0.129 0.144 0.158

0.127 0.142 0.158 0.174

0.142 0.158 0.176 0.194

6 6.25 6.5 6.75

132 0.144 0.156 0.169

0.154 0.168 0.182 0.197

0.162 0.178 0.193 0.209

0.173 0.189 0.206 0.223

0.192 0.209 0.228 0.247

0.213 0.233 0.253 0.275

7 7.25 7.5 7.75

0.183 0.196 -

0.213 0.229 -

0.226 0.243 0.261 0.279

0.241 0.259 0.278 0.298

0.267 0.288 0.31 0.332

0.297 0.32 0.344 0.369

Liner Size (mm) 101.60 107.95 114.30 120.65

304.80

355.60

457.20

508.00

50.80 1.40 1.57 1.80 2.03

50.80 1.63 1.85 2.11 2.36

63.50 2.51 2.87

63.50 2.82 3.20

127.00 133.35 139.70 146.05

2.26 2.51 2.79 3.07

2.64 2.95 3.25 3.58

2.77 3.07 3.43 3.78

2.95 3.28 3.66 4.01

3.23 3.61 4.01 4.42

3.61 4.01 4.47 4.93

152.40 158.75 165.10 171.45

3352.80 3.66 3.96 4.29

3.91 4.27 4.62 5.00

4.11 4.52 4.90 5.31

4.39 4.80 5.23 5.66

4.88 5.31 5.79 6.27

5.41 5.92 6.43 6.99

177.80 184.15 190.50 196.85

4.65 4.98 -

5.41 5.82 -

5.74 6.17 6.63 7.09

6.12 6.58 7.06 7.57

6.78 7.32 7.87 8.43

7.54 8.13 8.74 9.37

S.I units Stroke Length (in.)

16

381.00 406.40 Rod Diameter (in.) 57.15 57.15 2.18 2.44 2.46 2.64

hydrostatic pressure Hydrostatic pressure is the pressure exerted by the weight of a column of liquid on the casing and open hole sections of the wellbore and is the force that controls influx of formation fluids and provides wellbore support. Hydrostatic pressure = Mud weight x true vertical depth x conversion factor US Units:

Hydrostatic pressure ( psi) = Mud Weight × TVD( ft ) × 0.052

Metric Units Hydrostatic pressure(bar) =

Mud Weight ( SG) × TVD(m ) 10.2

Mud weight changes with temperature and pressure. This is most pronounced in deep hot wells when using clear brines, oil- or synthetic-base muds,

average seawater composition The following details typical chemicals and their concentration (ppm) in seawater (average SG = 1.025):

Constituent Parts per million Sodium 10440 Potassium 375 Magnesium 1270 Calcium 410 Chloride 18970 Sulfate 2720 Carbon dioxide 90 Other constituents 80

chemical formulas of common treating chemicals

Ammonium bisulphite Anhydrite Barite Calcium carbonate Calcium chloride Caustic soda (Sodium hydroxide) Caustic potash (Potassium hydroxide) Galena (Lead sulphide) Gypsum Lime Potassium chloride Phosphoric acid Quick lime Sodium acid pyrophosphate (SAPP) Sodium bicarbonate Sodium carbonate (Soda ash) Sodium chloride Sodium carboxymethylcellulose Sodium sulphite Sodium thiosulphate Zinc carbonate

(NH4)HSO3 CaSO4 BaSO4 CaCO3 CaCl2 NaOH KOH PbS CaSO4 · 2 H2O Ca(OH)2 KCl H3PO4 CaO Na2H2P2O7 NaHCO3 Na2CO3 NaCl R-CH2COO– Na+ Na2SO3 Na2S2O3 2 ZnCO3 · 3 Zn(OH)2 17

Section

17

engineering data

specific gravity and hardness of common oilfield materials Material Anhydrite Attapulgite Barite Bentonite Calcite (Limestone) Calcium chloride Cement Clay Diesel oil Dolomite Feldspar Galena Graphite Gypsum Halite (Salt) Hematite Illite Ilmenite Magnesite Montmorillonite Pyrite Quartz Salt Sand Shale Siderite Slate Zinc carbonate Potassium chloride Water (Fresh)

18

Chemical Formula CaSO4 BaSO4 CaCO3 CaCl2

CaMg(CO3)2 PbS C CaSO4 . 2 H2O NaCl Fe2O3 FeTiO3 MgCO3 FeS2 SiO2 NaCl

FeCO3 ZnCO3 KCl H2O

SG 2.9 2.3 - 2.7 4.0 - 4.5 2.3 - 2.7 2.7 - 2.9 1.95 3.1 - 3.2 2.5 - 2.7 0.85 2.86 2.4 - 2.7 6.95 2.09 - 2.23 2.30 - 2.37 2.16 - 2.17 5.0 - 5.3 2.6 - 2.9 4.68 - 4.76 2.98 - 3.44 2.0 - 3.0 5.02 2.65 2.2 2.1 - 2.7 2.2 - 2.9 3.96 2.7 - 2.8 3.8 1.99 1.00

Moh Scale Hardness

3.0 - 3.5 1.0 - 2.0 3.0

3.5 - 4.0 2.5 - 2.75 1.0 - 2.0 2.0 2.5 5.0 - 6.0 1.0 - 2.0 5.0 - 6.0 3.5 - 4.5 1.0 - 2.0 6.0 - 6.5 7.0

4.0 - 4.5 4.0 - 4.5 2.0

pH of common acids and bases Acid Acetic, N Acetic, 0.1N Acetic, 0.01N Alum, 0.1N Boric, 0.1N

pH 2.4 2.9 3.4 3.2 5.2

Carbonic (saturated)

3.8

Citric, 0.1N

2.2

Formic, 0.1N Hydrochloric, N Hydrochloric, 0.1N Hydrochloric, 0.01N Hydrogen sulphide, 0.1N Sulphuric, N Sulphuric, 0.1N Sulphuric, 0.01N Sulphurous, 0.1N

2.3 0.1 1.1 2.0 4.1 0.3 1.2 2.1 1.5

pH 11.6 11.1 10.6 9.2 9.4

Base Ammonia, N Ammonia, 0.1N Ammonia, 0.01N Borax, 0.1N Calcium carbonate (saturated) Calcium hydroxide (saturated) Ferrous hydroxide (saturated) Lime (saturated) Magnesia (saturated) Potassium hydroxide, N Potassium hydroxide, 0.1N Potassium hydroxide, 0.01N Sodium bicarbonate, 0.1N Sodium carbonate, 0.1N Sodium hydroxide, N Sodium hydroxide, 0.1N Sodium hydroxide, 0.01N

12.4 9.5 12.4 10.5 14.0 13.0 12.0 8.4 11.6 14.0 13.0 12.0

pH ranges of common indicators Indicator

pH Range

Initial Colour

End Point Colour

Thymol blue

1.2 - 2.8

Red

Yellow

Bromophenol blue

3.0 - 4.6

Yellow

Blue

Methyl orange

3.2 - 4.4

Red

Yellow

Bromocresol green

3.8 - 5.4

Yellow

Blue

Ethyl red

4.0 - 5.8

Colourless

Red

Methyl red

4.8 - 6.0

Red

Yellow

Bromocresol purple

5.2 - 6.8

Yellow

Purple

Bromothymol blue

6.0 - 7.6

Yellow

Blue

Phenol red

6.6 - 8.0

Yellow

Red

Phenolphthalein

8.2 - 10.0

Colourless

Pink

Thymolphthalein

9.4 - 10.6

Colourless

Blue

19

Section

17

engineering data

effect of caustic soda on calcium solubility at 73 ˚F (22.8 ˚C) 700

Filtrate Ca Ion, 500 mg/L 300

100

8.2

1

2 3 Caustic Soda Added, Ib/bbl

12.3 12.4

4

12.5

5

12.6 pH

chemical required to remove contaminants Ion to be Factor removed Ca++ x 0.00093 = (0.002653) Ca++ x 0.00074 = (0.002111) Ca++ x 0.00097 = (0.002767) Ca++ x 0.00173 = (0.004936) Mg++ x 0.00093 = (0.002653) Mg++ x 0.00116 = (0.003309) SO4= x 0.00073 = (0.002083) CO3= x 0.00043 = (0.001227) CO3= x 0.00100 = (0.002853) HCO3– x 0.00021 = (0.000599) HCO3– x 0.00200 = (0.005706) PO4= x 0.00041 = (0.00117) H2S x 0.00076 = (0.002168) H2S x 0.00128 = (0.003652) H2S x 0.000836 (0.002385)

ppb or (kg/m3) of Treating Chemical Na2CO3 (Soda ash) NaHCO3 (Bicarb.of soda) Na2H2P2O7 (SAPP) BaCO3 (Barium carbonate) Na2CO3 NaOH (Caustic soda) BaCO3 Ca(OH)2 (Lime) CaSO4 . 2 H2O (Gypsum) Ca(OH)2 NaOH (Caustic soda) Ca(OH)2 Ca(OH)2 (Lime) ZnCO3 (Zinc carbonate) ZnO (Zinc oxide)

Multiply the mg/l of ion to be removed, as determined by titration of filtrate or Drager tube, by the factor to give ppb of treating chemical required.

20

unit conversions The following table gives conversion factors used for converting one unit to another. Both metric-tostandard and standard-to-metric conversion factors are listed. Multiply Atmospheres

Barrels US (bbl)

Barrels/foot (bbl/ft)

Barrels/minute (bbl/min)

Bars

Centimetres (cm)

Cubic centimetres (cm3)

Cubic feet (ft3)

Cubic inches (in3)

Cubic meters (m3)

by 14.7 1.0132 101.32 42 35 5.615 159 0.159 350 42 5.615 159 0.159 521.6 0.5216 42 5.615 159 0.159 0.9869 14.5 100 0.0328 0.3937 0.01 10 0.0610 0.0010 1.0 0.1781 7.4805 1,728 28,317 28.3170 0.0283 16.3871 0.0164 0.0006 0.0043 6.2898 264.17 35.31 61023 1,000,000 1,000

To Calculate pounds per square inch (psi) bars kilopascals gallons US (gal) gallons (imperial) cubic feet (ft3) litres (L) cubic meters (m3) pounds (lb) [H2O at 68 ºF) gallons/ft (gal/ft) cubic ft/ft (ft3 /ft) litres (L) cubic meters/foot (m3/ft) litres/meter (L / m) cubic meters/meter (m3 /m) gallons/minute (gal/min) cubic ft/minute (ft3 /min) litres/minute (L /min) cubic meters/minute (m3/min) atmospheres pounds per square inch (psi) kilopascals feet (ft) inches (in) meters (m) millimetres (mm) cubic inches (in3) litres (L) millilitres (mL) barrels (bbl) gallons (gal) cubic inches (in3) cubic centimetres (cm3) litres (L) cubic meters (m3) cubic centimetres (cm3) litres (L) cubic feet (ft3) gallons (gal) barrels (bbl) gallons (gal) cubic feet (ft3) cubic inches (in3) cubic centimetres (cm3) litres (L)

21

Section

17

engineering data

Multiply Cubic meters/minute (m3 /min)

Degrees, angle

Degrees, temperature Celsius (°C) Degrees, temperature Fahrenheit (°F) Feet (ft)

Feet/minute (ft/min)

Feet/second (ft/sec)

Gallons, US (gal)

Gallons/minute (gal/min)

Grams (g)

Grams/litre (g/L)

Inches (in)

Kilograms (kg)

Kilograms/cubic meter (kg/m3)

Kilometres (km)

22

by 6.2898 264.17 35.31 1,000 60 0.0175 3,600 (°C x 1.8)+ 32 (°F – 32) ÷ 1.8 30.48 0.3048 12 0.3333 0.0167 0.3048 0.00508 60 18.288 0.3048 3785 3.785 0.0038 231 0.1337 0.0238 0.0238 0.1337 3.785 0.0038 0.0010 1,000 0.03527 0.0022 0.0624 0.0083 0.3505 1,000 0.0833 0.0278 25,400 25.4 2.54 0.0254 1,000 0.0010 2.2046 0.3505 0.0083 0.0624 39,370 3280.84 1,000 0.6214

To Calculate barrels/minute (bbl/min) gallons/minute (gal/min) cubic feet/minute (ft3 /min) litres/minute (L/min) minutes (min) radians seconds degrees Fahrenheit (°F) degrees Celsius (°C) centimetres (cm) meters (m) inches (in) yards (yd) feet/second (ft/sec) meters/minute (m/min) meters/second (m/sec) feet/minute (ft/min) meters/minute (m/min) meters/second (m/sec) cubic centimetres (cm3) litres (L) cubic meters (m3) cubic inches (in3) cubic feet (ft3) barrels (bbl) barrels/minute (bbl/min) cubic feet/minute (ft3/min) litres/minute (L/min) cubic meters/minute (m3/min) kilograms (kg) milligrams (mg) ounces (oz, avoirdupois) pounds (lb) pounds/cubic foot (lb/ft3) pounds/gallon (lb/gal) pounds/barrel (lb/bbl) milligrams/litre (mg/L) feet (ft) yards (yd) microns millimetres (mm) centimetres (cm) meters (m) grams (g) metric tons pounds (lb) pounds/barrel (lb/bbl) pounds/gallon (lb/gal) pounds/cubic foot (lb/ft3) inches (in) feet (ft) meters (m) miles (mi)

Multiply Kilometres/hour (km/hr or kph)

Kilopascals

Knots

Litres (L)

Litres/minute (L/min)

Meters (m)

Meters/minute (m/min)

Meters/second (m/sec)

Microns

Miles, statute (mi)

by 54.68 0.9113 0.54 0.6214 1,000 16.6667 0.2778 0.1450 0.0100 0.0099 1.15 6,080 101.27 1.69 1.85 30.87 0.5144 61.03 0.0353 0.2642 0.0063 1,000 0.001 0.2642 0.0063 0.0353 1,000 100 0.001 39.37 3.28 1.0936 3.28 0.05468 0.03728 0.01667 1.6670 0.06 2.2369 196.85 3.28 100 60 0.060 0.0010 0.0001 0.00003937 160,934 1609.34 1.6093 63,360

To Calculate feet/minute (ft/min) feet/second (ft/sec) knots miles/hour (mi/hr or mph) meters/hour (m/hr) meters/minute (m/min) meters/second (m/sec) pounds per square inch (psi) bars atmospheres miles/hour (mi/hr or mph) feet/hour (ft/hr) feet/minute (ft/min) feet/second (ft/sec) kilometres/hour (km/hr or kph) meters/minute (m/min) meters/second (m/sec) cubic inches (in3) cubic feet (ft3) gallons (gal) barrels (bbl) cubic centimetres (cm3) cubic meters (m3) gallons/minute (gal/min) barrels/minute (bbl/min) cubic feet/minute (ft /min)3 millimetres (mm) centimetres (cm) kilometres (km) inches (in) feet (ft) yards (yd) feet/minute (ft/min) feet/second (ft/sec) miles/hour (mi/hr or mph) meters/second (m/sec) centimetres/second (cm/sec) kilometres/hour (km/hr or kph) miles/hour (mi/hr or mph) feet/minute (ft/min) feet/second (ft/sec) centimetres/second (cm/sec) meters/minute (m/min) kilometres/hour (km/hr or kph) millimetres (mm) centimetres (cm) inches (in) centimetres (cm) meters (m) kilometres (km) inches (in)

23

Section

17

engineering data

Multiply Miles, nautical

Millilitres (ml) Millimetres (mm)

Ounces (oz, avoirdupois)

Pounds (lb)

Pounds/barrel (lb/bbl)

Pounds/cubic foot (lb/ft3)

Pounds/gallon (lb/gal)

Pounds/square inch (lb/in2) (psi)

Pounds/square inch/foot (lb/in2/ft) Square centimetres (cm2) Square feet (ft2)

Square inches (in2) Square kilometres (km2) Square meters (m2) Square miles (mi2)

Tons, long

24

by 5,280 1,760 6,080.27 1.1516 1,853.27 1.8533 0.0010 0.0010 0.10 0.0394 0.0625 28.3495 0.0283 16 0.0005 453.6 0.4536 0.047 2.853 0.1781 0.0238 0.0160 16.0185 0.1337 5.6146 0.1198 119.8260 0.0238 7.4805 0.0680 0.0689 0.0703 6.89 22.6203 0.1550 929.03 0.0929 144 0.1111 645.16 6.4516 0.3861 100 10.76 2.59 640 259 2,240 1,016 1.016

To Calculate feet (ft) yards (yd) feet (ft) statute miles (mi) meters (m) kilometres (km) litres (L) meters (m) centimetres (cm) inches (in) pounds (lb) grams (g) kilograms (kg) ounces (oz, avoirdupois) short tons grams (g) kilograms (kg) grams/cubic inch (g/in3) kilograms/cubic meter (kg/m3) pounds/cubic foot (lb/ft3) pounds/gallon (lb/gal) grams/cubic centimeter (g/cm3) kilograms/cubic meter (kg/m3) pounds/gallon (lb/gal) pounds/barrel (lb/bbl) grams/cubic centimeter (g/cm3) kilograms/cubic meter (kg/m3) pounds/barrel (lb/bbl) pounds/cubic foot (lb/ft2) atmospheres bars kilograms/square centimeter (kg/cm2) kilopascals kilopascals/meter square inches (in2) square centimeters (cm2) square meters (m2) square inches (in2) square yards (yd2) square millimeters (mm2) square centimeters (cm2) square miles (mi2) hectares square feet (ft2) square kilometres (km2) acres hectares pounds (lb) kilograms (kg) metric tons

Multiply Tons, metric

Tons, short

by

To Calculate

2,204 1,000 0.9842 1.1023 2,000 907.18 0.9072

pounds (lb) kilograms (kg) long tons short tons pounds (lb) kilograms (kg) metric tons

25

salt tables

salt tables

section 18

section 18a - imperial salt tables section 18b - metric salt tables

section 18a

imperial salt tables

section 18a

Scomi Oiltools

Table 1 - Concentration Conversions for Brines

2

Table 2 - Sodium Chloride

3

Table 3 - Calcium Chloride

4

Table 4 - Sodium-Calcium Chloride Blends

7

Table 5 - Magnesium Chloride

7

Table 6 - Potassium Chloride

8

Table 7 - Potassium Carbonate

9

Table 8 - Ammonium Chloride

10

Table 9 - Potassium Bromide

11

Table 10 - Formulating Calcium-Chloride/Calcium-Bromide Using 11.6

lb/gal CaCl2 Brine, 14.2 lb/gal CaBr2 Brine, and Sack CaCl2

12

Table 11 - Formulating Calcium Bromide Base Solutions Using Solid

94% CaCl2 and Liquid 14.2 lb/gal CaBr2

13

Table 12 - Formulating Calcium Bromide Base Solutions Using 95%

Powder CaBr2 Table 13 - Formulating Sodium Bromide Base Solutions Using 10.0

14

15

lb/gal NaCl Brine and 12.4 lb/gal NaBr Brine

Table 14 - Formulating Sodium Bromide Base Solutions Using

Powder NaCl, Powder NaBr and Fresh Water

16

Table 15 - Formulating Sodium Bromide (95% purity) Brine

17

Table 16 - Formulating Sodium Formate Brine

18

Table 17 - Formulating Potassium Formate Brine

19

Table 18 - Formulating Potassium Suphate Brine

21

Section

18a


salt tables

The following table details the maximum brine densities achievable with the main type of brines used in the oil industry Brine

Maximum Density (lb/gal)

Maximum Density (SG)

1198 1390 1869 1150 1510 1809 2301 1342 1558 2337

1.20 1.39 1.87 1.16 1.51 1.81 2.30 1.34 1.56 2.34

NaCl CaCl2 CaCl2 /CaBr2 KCl NaBr CaBr2 ZnBr2 NaCOOH KCOOH CsCOOH Table 1 - Concentration Conversions for Brines Salt (% wt)

Chloride (% wt)

Salt (ppm)

Chloride (ppm)

Salt (mg/l)

Chloride (mg/l)

1.0

x 1/factor

x 104

x 1/factor x 104

x 104 x SG

x 1/factor x 104 x SG

Cl-(% wt)

x factor

1.0

x factor x 104

x 104


104 x SG

Salt (ppm)

x 10-4

x 1/factor x 10-4

1.0

x 1/factor

x SG

x 1/factor x SG

Cl-(ppm)

x factor x 10-4

x 10-4

x factor

1.0

x factor x SG

x SG

Salt (mg/l)

x 10-4 x 1/SG

x 1/factor x 10-4 x 1/SG

x 1 / SG

x 1/factor x 1/SG

1.0

x 1/factor

Cl- (mg/l)

x factor x 10-4 x 1/SG

From

To

Salt (% wt)

x 10-4

x factor x1/SG

x 1 / SG

Salt

Factor

1/Factor

CaCl2 NaCl KCl

1.5642 1.6488 2.103

0.6393 0.6065 0.4755

x factor

1.0

Table 2 - Sodium Chloride Weight (%)

Density (kg/l)

Density (lb/gal)

Cl– (mg/l)

Na+ (mg/l)

NaCl (lb/bbl)

Water (bbl)

Cryst. Pt. (¡F)

Water Activity

1

1.005

8.38

6,127

3,973

3.5

0.995

30.9

0.994

2

1.013

8.44

12,254

7,946

7.1

0.992

29.9

0.989

3

1.020

8.50

18,563

12,037

10.7

0.989

28.8

0.983

4

1.027

8.56

24,932

16,168

14.4

0.986

27.7

0.977

5

1.034

8.62

31,363

20,337

18.1

0.982

26.5

0.970

6

1.041

8.68

37,914

24,586

21.9

0.979

25.3

0.964

7

1.049

8.75

44,526

28,874

25.7

0.975

24.1

0.957

8

1.056

8.81

51,260

33,240

29.6

0.971

22.9

0.950

9

1.063

8.87

58,054

37,646

33.5

0.968

21.5

0.943

10

1.071

8.93

64,970

42,130

37.5

0.964

20.2

0.935

11

1.078

8.99

71,946

46,654

41.5

0.960

18.8

0.927

12

1.086

9.05

79,044

51,256

45.6

0.955

17.3

0.919

13

1.093

9.12

86,202

55,898

49.7

0.951

15.7

0.911

14

1.101

9.18

93,481

60,619

53.9

0.947

14.1

0.902

15

1.109

9.24

100,882

65,418

58.2

0.942

12.4

0.892

16

1.116

9.31

108,344

70,256

62.5

0.938

10.6

0.883

17

1.124

9.37

115,927

75,173

66.9

0.933

8.7

0.872

18

1.132

9.44

123,570

80,130

71.3

0.928

6.7

0.862

19

1.140

9.51

131,396

85,204

75.8

0.923

4.6

0.851

20

1.148

9.57

139,282

90,318

80.4

0.918

2.4

0.839

21

1.156

9.64

147,229

95,471

84.9

0.913

0.0

0.827

22

1.164

9.71

155,357

100,743

89.6

0.908

-2.5

0.815

23

1.172

9.78

163,547

106,053

94.4

0.903

-5.2

0.802

24

1.180

9.84

171,858

111,442

99.2

0.897

1.4

0.788

25

1.189

9.91

180,290

116,910

104.0

0.892

14.7

0.774

26

1.197

9.98

188,843

122,457

109.0

0.886

27.9

0.759

% volume salt = 100 x (1.0 - bbl water). Properties based on 20 °C and 100% purity

Section

18a


Table 3 - Calcium Chloride % by Wt

Density SG

Density lb/gal

100% CaCl2 lb/bbl

95% CaCl2 lb/bbl

Water with 100% CaCl2

Water with 95% CaCl2

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40

1.009 1.017 1.026 1.034 1.043 1.051 1.060 1.068 1.077 1.085 1.094 1.103 1.113 1.122 1.132 1.141 1.151 1.160 1.170 1.180 1.190 1.200 1.210 1.220 1.231 1.241 1.252 1.262 1.273 1.284 1.295 1.306 1.317 1.328 1.340 1.351 1.363 1.375 1.387 1.398

8.42 8.49 8.56 8.63 8.70 8.77 8.84 8.91 8.98 9.05 9.13 9.20 9.28 9.36 9.44 9.52 9.60 9.68 9.76 9.85 9.93 10.01 10.10 10.18 10.27 10.36 10.44 10.53 10.62 10.71 10.81 10.90 10.99 11.08 11.18 11.27 11.37 11.47 11.57 11.67

3.53 7.13 10.78 14.50 18.27 22.11 25.99 29.94 33.95 38.03 42.18 46.39 50.69 55.05 59.49 63.98 68.55 73.18 77.91 82.72 87.59 92.53 97.55 102.62 107.82 113.09 118.44 123.85 129.39 135.00 140.70 146.48 152.32 158.25 164.32 170.47 176.76 183.13 189.53 195.99

3.72 7.50 11.35 15.26 19.23 23.27 27.36 31.52 35.74 40.03 44.40 48.83 53.36 57.95 62.62 67.35 72.16 77.03 82.01 87.07 92.20 97.40 102.68 108.02 113.49 119.04 124.67 130.37 136.20 142.11 148.11 154.19 160.34 166.58 172.97 179.44 186.06 192.77 199.50 206.31

41.93 41.85 41.78 41.69 41.60 41.49 41.38 41.27 41.14 41.01 40.90 40.76 40.65 40.53 40.40 40.25 40.10 39.95 39.80 39.65 39.48 39.31 39.14 38.95 38.76 38.57 38.37 38.16 37.96 37.75 37.53 37.30 37.06 36.81 36.57 36.32 36.06 35.81 35.53 35.23

41.91 41.81 41.71 41.60 41.48 41.35 41.22 41.08 40.93 40.77 40.63 40.47 40.33 40.18 40.02 39.85 39.67 39.49 39.31 39.13 38.93 38.73 38.52 38.30 38.08 37.86 37.62 37.38 37.14 36.90 36.64 36.38 36.10 35.81 35.53 35.24 34.95 34.65 34.33 33.99

Properties based on 20 °C

Table 3 - Calcium Chloride continued… % by Wt

Density SG

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40

1.009 1.017 1.026 1.034 1.043 1.051 1.060 1.068 1.077 1.085 1.094 1.103 1.113 1.122 1.132 1.141 1.151 1.160 1.170 1.180 1.190 1.200 1.210 1.220 1.231 1.241 1.252 1.262 1.273 1.284 1.295 1.306 1.317 1.328 1.340 1.351 1.363 1.375 1.387 1.398

Density lb/gal

8.42 8.49 8.56 8.63 8.70 8.77 8.84 8.91 8.98 9.05 9.13 9.20 9.28 9.36 9.44 9.52 9.60 9.68 9.76 9.85 9.93 10.01 10.10 10.18 10.27 10.36 10.44 10.53 10.62 10.71 10.81 10.90 10.99 11.08 11.18 11.27 11.37 11.47 11.57 11.67

CaCl2 mg/l

Clmg/l

Vol Increase Factor 100% CaCl2

Vol Increase Factor 95% CaCl2

Cryst. Pt. (°F)

Aw

10,085 20,340 30,765 41,360 52,125 63,060 74,165 85,440 96,885 108,500 120,340 132,360 144,625 157,080 169,725 182,560 195,585 208,800 222,300 236,000 249,900 264,000 278,300 292,800 307,625 322,660 337,905 353,360 369,170 385,200 401,450 417,920 434,610 451,520 468,825 486,360 504,310 522,500 540,735 559,200

6,454 13,018 19,690 26,470 33,360 40,358 47,466 54,682 62,006 69,440 77,018 84,710 92,560 100,531 108,624 116,838 125,174 133,632 142,272 151,040 159,936 168,960 178,112 187,392 196,880 206,502 216,259 226,150 236,269 246,528 256,928 267,469 278,150 288,973 300,048 311,270 322,758 334,400 346,070 357,888

1.002 1.004 1.006 1.008 1.011 1.013 1.016 1.018 1.021 1.024 1.027 1.030 1.034 1.037 1.041 1.044 1.048 1.051 1.056 1.060 1.065 1.069 1.074 1.078 1.084 1.089 1.095 1.100 1.107 1.113 1.120 1.126 1.134 1.141 1.149 1.156 1.165 1.173 1.183 1.192

1.002 1.004 1.007 1.010 1.013 1.016 1.019 1.022 1.026 1.030 1.034 1.038 1.041 1.045 1.049 1.054 1.059 1.064 1.068 1.073 1.079 1.084 1.090 1.097 1.103 1.109 1.116 1.124 1.131 1.138 1.146 1.155 1.163 1.173 1.182 1.192 1.202 1.212 1.224 1.236

31.1 30.4 29.5 28.6 27.7 26.8 25.9 24.6 23.5 22.3 20.8 19.3 17.6 15.5 13.5 11.2 8.6 5.9 2.8 –0.4 –3.9 –7.8 –11.9 –16.2 –21.0 –25.8 –31.2 –37.8 –49.4 –50.8 –33.2 –19.5 –6.9 +4.3 +14.4 +24.1 +33.4 +42.1 +49.6 +55.9

0.998 0.996 0.993 0.989 0.984 0.979 0.973 0.967 0.959 0.951 0.942 0.933 0.923 0.912 0.900 0.888 0.875 0.862 0.847 0.832 0.816 0.800 0.783 0.765 0.746 0.727 0.707 0.686 0.665 0.643 0.620 0.597 0.573 0.548 0.522 0.496 0.469 0.441 0.413 0.384


Section

18a


Properties of Calcium Chloride Solutions (at 20 °C) When Using CaCl2 with purity other than 95%: New CaCl2 (lb/bbl) = 95 x 95% CaCl2 (lb/bbl) / % Purity Volume increase from salt = 42 / New water New Water



( gal / bbl ) = Water ( gal / bbl ) −  New

CaCl 2 Ib/bbl − 95% CaCl2 ppb   8.345 

Example: 35% CaCl2 brine using 78% CaCl2 : New CaCl2 (lb/bbl) = 95 x 172.97 / 78 = 210.67  210.67 −172.97   = 31.01 New Water gal = 35.53 −  8.345  

Volume increase from 78% salt = 42 / 31.01 = 1.354 Metric Conversions: CaCl2 (g/l) = CaCl2 (lb/bbl) x 2.85714 H2O (ml/l) = H2O (gal/bbl) x 23.8086 CaCl2 (ppm) = % Wt x 10,000 Cl– (ppm) = CaCl2 (ppm) x 0.639 mg/l = ppm x specific gravity (S.G.) Formulas: Salt (lb/bbl water) = Volume incr. factor x CaCl2 (lbm/bbl) S.G. = 1.0036 [0.99707 + 7.923 (10 -3) (% wt CaCl2) + 4.964(10 -5) (% wt CaCl2)2] + 8.94922(10 -5) (% wt CaCl2)2 Aw = 0.99989 - 1.39359 (10 -3) (% wt CaCl2) – 3.50352 (10 -4) (% wt CaCl2) 2 Wt CaCl2 =

100% CaCl2 Ib/bbl x % Purity CaCl2 SG x 350

Table 4 - Sodium-Calcium Chloride Blends Density (lb/gal at 60 °F)

Water (bbl)

100% NaCl (lb/bbl)

94 - 97% CaCl2 (lb/bbl)

Cryst. Pt. (°F)

10.1

0.887

88

29

-4

10.2

0.875

70

52

-10

10.3

0.875

54

72

-15

10.4

0.876

41

89

-21

10.5

0.871

32

104

-26

10.6

0.868

25

116

-32

10.7

0.866

20

126

-38

10.8

0.864

16

135

-42

10.9

0.862

13

144

-24

11.0

0.859

10

151

-12

11.1

0.854

8

159

0

Table 5 - Magnesium Chloride Weight (%)

Density (kg/l)

Density (lb/gal)

Cl– (mg/l)

Mg2+ (mg/l)

MgCl2 (lb/bbl)

Water (bbl)

Cryst. Pt. (¡F)

Water Activity

1

1.006

8.39

7,492

2,568

3.54

0.9962

31.1

0.995

2

1.014

8.46

15,106

5,178

7.21

0.9941

30.1

0.990

3

1.023

8.52

22,842

7,830

10.98

0.9919

29

0.984

4

1.031

8.59

30,703

10,524

14.88

0.9897

27.9

0.978

5

1.039

8.66

38,696

13,264

18.91

0.9874

26.6

0.972

6

1.048

8.74

46,814

16,047

23.07

0.985

24.3

0.964

7

1.056

8.81

55,060

18,873

27.35

0.9825

22.3

0.957

8

1.065

8.88

63,444

21,747

31.77

0.9799

21.5

0.948

9

1.074

8.95

71,957

24,665

36.33

0.9772

19.6

0.939

10

1.083

9.02

80,608

27,631

41.03

0.9744

18

0.929

12

1.101

9.17

98,329

33,705

50.88

0.9685

14.4

0.906

14

1.119

9.33

116,635

39,980

61.36

0.9623

5.8

0.879

16

1.137

9.48

135,477

46,439

72.44

0.9552

-1.9

0.848

18

1.155

9.63

154,838

53,075

84.11

0.9474

-13

0.812

20

1.174

9.79

174,856

59,937

96.54

0.9394

-27.8

0.772

22

1.194

9.95

195,553

67,031

109.77

0.9312

-18.5

0.727

24

1.214

10.12

216,940

74,362

123.84

0.9226

-11.8

0.677

26

1.235

10.29

239,006

81,926

138.75

0.9136

-5

0.624

28

1.256

10.47

261,748

89,722

154.52

0.9039

1.3

0.567

30

1.276

10.64

285,091

97,723

171.09

0.8934

2.4

0.507


Section

18a


Table 6 - Potassium Chloride Weight (%)

Density (kg/l)

Density (lb/gal)

Cl– (mg/l)

K+ (mg/l)

KCl (lb/bbl)

Water (bbl)

Cryst. Pt. (¡F)

Water Activity

1

1.005

8.38

4,756

5,244

3.5

0.995

31.2

0.996

2

1.011

8.43

9,606

10,594

7.1

0.991

30.3

0.991

3

1.017

8.49

14,504

15,996

10.7

0.987

29.5

0.987

4

1.024

8.54

19,498

21,502

14.4

0.983

28.7

0.982

5

1.030

8.59

24,491

27,009

18.0

0.979

27.8

0.977

6

1.037

8.65

29,579

32,621

21.8

0.975

27.0

0.973

7

1.043

8.70

34,715

38,285

25.6

0.970

26.1

0.968

8

1.050

8.76

39,947

44,053

29.4

0.966

25.2

0.963

9

1.057

8.81

45,225

49,875

33.3

0.962

24.3

0.958

10

1.063

8.87

50,551

55,749

37.2

0.957

23.4

0.953

11

1.070

8.92

55,973

61,727

41.2

0.952

22.4

0.947

12

1.077

8.98

61,442

67,758

45.2

0.948

21.4

0.942

13

1.084

9.04

67,006

73,894

49.3

0.943

20.4

0.936

14

1.091

9.09

72,617

80,083

53.4

0.938

20.0

0.930

15

1.097

9.15

78,276

86,324

57.6

0.933

18.5

0.925

16

1.104

9.21

84,030

92,670

61.8

0.928

17.0

0.918

17

1.111

9.27

89,832

99,068

66.1

0.922

16.0

0.912

18

1.119

9.33

95,729

105,571

70.5

0.917

15.0

0.906

19

1.126

9.39

101,721

112,179

74.9

0.912

14.0

0.899

20

1.133

9.45

107,760

118,840

79.3

0.906

13.0

0.892

22

1.147

9.57

120,030

132,370

88.3

0.895

34.0

0.878

24

1.162

9.69

132,632

146,268

97.6

0.883

59.0

0.862



Wt %

S.G. (20 °C)

Density lb/gal

K2CO3 mg/l

K+ mg/l

CO3=

K2CO3 lb/bbl

Water gal/bbl

1

1.01

8.42

10,100

5,715

4,386

3.535

41.88

2

1.02

8.49

20,300

11,487

8,815

7.105

41.83

3

1.03

8.57

30,800

17,429

13,374

10.78

41.77

4

1.04

8.64

41,400

23,427

17,977

14.49

41.71

5

1.05

8.72

52,200

29,539

22,667

18.27

41.64

6

1.05

8.80

63,200

35,763

27,443

22.12

41.57

7

1.06

8.87

74,300

42,045

32,263

26.005

41.49

8

1.07

8.95

85,700

48,496

37,213

29.995

41.40

9

1.08

9.03

97,300

55,060

42,250

34.055

41.31

10

1.09

9.11

109,000

61,680

47,331

38.15

41.22

11

1.10

9.19

121,000

68,471

52,541

42.35

41.12

12

1.11

9.27

133,200

75,375

57,839

46.62

41.01

13

1.12

9.35

145,500

82,335

63,180

50.925

40.90

14

1.13

9.43

158,100

89,465

68,651

55.335

40.79

15

1.14

9.52

170,900

96,708

74,209

59.815

40.66

16

1.15

9.60

183,800

104,008

79,811

64.33

40.54

17

1.16

9.68

197,000

111,477

85,542

68.95

40.41

18

1.17

9.77

210,500

119,117

91,405

73.675

40.27

19

1.18

9.85

224,100

126,813

97,310

78.435

40.13

20

1.19

9.94

238,000

134,678

103,346

83.3

39.98

22

1.21

10.11

266,300

150,693

115,634

93.205

39.66

24

1.23

10.29

295,700

167,329

128,401

103.495

39.32

26

1.26

10.47

325,900

184,419

141,514

114.065

38.96

28

1.28

10.66

357,100

202,074

155,062

124.985

38.57

30

1.30

10.84

389,400

220,352

169,088

136.29

38.16

32

1.32

11.03

422,600

239,139

183,504

147.91

37.71

34

1.35

11.22

456,800

258,492

198,354

159.88

37.24

36

1.37

11.42

492,000

278,411

213,639

172.2

36.74

38

1.39

11.62

528,300

298,952

229,401

184.905

36.20

40

1.42

11.81

565,600

320,059

245,598

197.96

35.63

Section

18a



10

Density lb/gal

Specific Gravity @ 60 °F

lbs NH4Cl per bbl Brine

bbls Water per bbl Brine

8.4

1.007

7.0

0.990

% by Weight Ammonium Chloride (NH4Cl) 1.98

8.45

1.013

10.5

0.981

3.00

8.5

1.020

19.0

0.969

5.30

8.6

1.031

30.0

0.940

8.40

8.7

1.044

42.0

0.919

11.50

8.8

1.055

53.0

0.900

14.40

8.9

1.068

65.0

0.881

17.40

9.0

1.079

77.0

0.860

20.40

9.1

1.128

88.0

0.840

23.00

9.2

1.103

100.0

0.819

25.90

9.5

1.139

135.0

0.750

33.90

Table 9 – Potassium Bromide Density lb/gal

bbl Water per bbl Brine

lbs KBr per bbl Brine

% KBr

Crystallization Point, °F (LCTD)

8.3

1.000

–

–

32

8.6

0.985

15.1

4.2

30

8.7

0.980

21.9

6.0

30

8.8

0.974

28.1

7.6

29

8.9

0.967

34.8

9.3

28

9.0

0.962

40.8

10.8

27

9.1

0.956

47.0

12.3

27

9.2

0.954

52.6

13.6

26

9.3

0.947

58.6

15.0

26

9.4

0.942

64.7

16.4

25

9.5

0.937

70.6

17.7

24

9.6

0.932

76.6

19.0

23

9.7

0.928

82.3

20.2

22

9.8

0.922

88.5

21.5

22

9.9

0.916

94.8

22.8

21

10.0

0.911

100.8

24.0

19

10.1

0.905

106.9

25.2

18

10.2

0.901

112.7

26.3

17

10.3

0.895

119.0

27.5

16

10.4

0.888

125.4

28.7

15

10.5

0.883

131.4

29.8

14

10.6

0.878

137.6

30.9

12

10.7

0.872

143.8

32.0

13

10.8

0.865

150.6

33.2

20

10.9

0.858

157.0

34.3

27

11.0

0.854

162.6

35.2

33

11.1

0.847

169.2

36.3

41

11.2

0.842

175.5

37.3

49

11.3

0.835

181.2

38.3

57

11.4

0.829

188.2

39.3

66

11.5

0.824

194.2

40.2

75

11

Section

18a


Table 10 – Formulating Calcium-Chloride/Calcium-Bromide Using 11.6 lb/gal CaCl2 Brine, 14.2 lb/gal CaBr2 Brine, and Sack CaCl2

12

Brine Density at 60 ºF (lb/gal)

11.6 lb/gal CaCl2 (bbl)

14.2 lb/gal CaBr2 (bbl)

94-97% CaCl2 (lb) (Flake or Pellet)

Crystallisation Point (ºF)

11.7 11.8 11.9 12.0 12.1 12.2 12.3 12.4 12.5 12.6 12.7 12.8 12.9 13.0 13.1 13.2 13.3 13.4 13.5 13.6 13.7 13.8 13.9 14.0 14.1 14.2 14.3 14.4 14.5 14.6 14.7 14.8 14.9 15.0 15.1

.9714 .9429 .9143 .8857 .8572 .8286 .8000 .7715 .7429 .7143 .6857 .6572 .6286 .6000 .5714 .5429 .5143 .4851 .4572 .4286 .4000 .3714 .3429 .3143 .2857 .2572 .2286 2000 .1715 .1429 .1143 .0858 .0572 .0286 .0000

.0246 .9429 .0738 .0984 .1229 .1475 .1722 .1967 .2213 .2459 .2705 .2951 .3197 .3443 .3689 .3935 .4181 .4432 .4672 4919 .5165 .5411 .5656 .5903 .6149 .6394 .6640 .6886 .7132 .7378 .7624 .7869 .8116 .8361 .8608

3.5 6.9 10.4 13.9 17.4 20.8 24.3 27.8 31.2 34.7 38.2 41.7 45.1 48.6 52.1 55.5 59.0 62.6 66.0 69.4 72.9 75.4 79.8 83.3 86.8 90.3 93.7 97.2 100.7 104.2 107.6 111.1 114.6 118.0 121.5

+45 +51 +52 +54 +55 +55 +56 +56 +57 +58 +58 +58 +59 +59 +60 +60 +60 +61 +61 +62 +62 +63 +63 +64 +64 +64 +65 +65 +65 +66 +66 +67 +67 +67 +68

Table 11 – Formulating Calcium Bromide Base Solutions Using Solid 94% CaCl2 and Liquid 14.2 lb/gal CaBr2 CaCl2/CaBr2 Density at 60 ºF

bbl 14.2 lb/gal bbl Fresh Water per CaBr2 per bbl Brine bbl Brine

lb/gal

lb/ft3

lb CaCl2 per bbl Brine

11.7 11.8 11.9 12.0 12.1 12.2 12.3 12.4 12.5 12.6 12.7 12.8 13.0 13.1 13.2 13.3 13.4 13.5 13.6 13.7 13.8 13.9 14.0 14.1 14.2 14.3 14.4 14.5 14.6 14.7 14.8 14.9 15.0 15.1

87.52 88.26 89.01 89.76 90.51 91.26 92.00 92.75 93.50 94.25 95.00 95.74 97.24 97.99 98.74 99.48 100.23 100.98 101.73 102.48 103.22 103.97 104.72 105.47 106.22 106.96 107.71 108.46 109.21 109.96 110.70 111.45

193.39 191.00 188.42 185.85 183.28 180.70 178.13 175.56 172.99 170.41 167.83 165.27 160.12 157.54 154.97 152.40 149.82 147.26 144.68 142.12 139.54 136.98 134.40 131.84 129.26 126.68 124.11 121.54 118.97 116.39 113.82 111.25

0.0254 0.0507 0.0762 0.1016 0.1269 0.1524 0.1778 0.2032 0.2286 0.2540 0.2794 0.3048 0.3556 0.3810 0.4064 0.4318 0.4572 0.4826 0.5080 0.5334 0.5589 0.5842 0.6069 0.6351 0.6604 0.6858 0.7113 0.7366 0.7620 0.7875 0.8128 0.8382

0.8163 0.7924 0.7683 0.7443 0.7203 0.6963 0.6723 0.6483 0.6243 0.6003 0.5762 0.5523 0.5042 0.4802 0.4562 0.4322 0.4082 0.3842 0.3602 0.3361 0.3121 0.2882 0.2641 0.2401 0.2161 0.1921 0.1681 0.1441 0.1201 0.0961 0.0721 0.0481

112.20 112.95

108.67 106.10

0.8637 0.8891

00.241 0.0000

13

Section

18a


Table 12 – Formulating Calcium Bromide Base Solutions Using 95% Powder CaBr2 Brine Density

14

lb/gal

lb/ft3

bbls Fresh Water per bbl Brine

lbs 95% CaBr2 per bbl Brine

11.0 11.1 11.2 11.3 11.4 11.5 11.6 11.7 11.8 11.9 12.0 12.1 12.3 12.4 12.5

82.28 83.03 83.78 84.52 85.27 86.02 86.77 87.52 88.26 89.01 8976 90.51 92.00 92.75 93.50

0.889 0.887 0.884 0.878 0.869 0.867 0.864 0.863 0.849 0.849 0.848 0.840 0.831 0.830 0.821

150.8 155.9 160.9 167.4 174.5 179.6 184.7 188.9 198.3 202.6 207.0 214.1 225.8 230.3 237.7

12.6 12.7 12.8 12.9 13.0 13.1 13.2 13.3 13.4 13.5 13.6 13.7 13.8 13.9 14.0 14.1 14.2 14.3

94.25 95.00 95.74 96.49 97.24 97.99 98.74 99.48 100.23 100.98 101.73 102.48 103.22 103.97 104.72 105.47 106.22 106.96

0.819 0.810 0.808 0.797 0.796 0.794 0.791 0.789 0.778 0.775 0.772 0.761 0.758 0.755 0.751 0.748 0.744 0.740

242.4 250.0 254.8 266.5 267.4 272.3 277.3 282.4 290.4 295.6 300.8 309.0 314.3 319.7 325.1 330.5 335.9 341.5

Table 13– Sodium Bromide - Mixed From 10.0 lb/gal NaCl 12.3 lb/gal NaBr, and Dry NaBr Density

Specific Gravity

Fresh Water bbl

10.0 lb/gal NaCl bbl

12.3 lb/gal NaBr bbl

95% NaBr lb

TCT

8.4

1.008

0.982

-

0.018

-

31

8.5

1.020

0.957

-

0.043

-

31

8.6

1.032

0.932

-

0.068

-

30

8.7

1.044

0.907

-

0.093

-

30

8.8

1.056

0.882

-

0.118

-

29

8.9

1.068

0.856

-

0.144

-

29

9.0

1.080

0.831

-

0.169

-

28

9.1

1.092

0.806

-

0.194

-

27

9.2

1.104

0.781

-

0.219

-

26

9.3

1.116

0.756

-

0.244

-

25

9.4

1.128

0.730

-

0.270

-

24

9.5

1.140

0.705

-

0.295

-

23

9.6

1.152

0.680

-

0.320

-

19

9.7

1.164

0.655

-

0.345

-

18

9.8

1.176

0.630

-

0.370

-

17

9.9

1.188

0.605

-

0.395

-

16

10.0

1.200

0.579

-

0.421

-

15

10.1

1.212

-

0.957

0.043

-

13

10.2

1.224

-

0.913

0.087

-

12

10.3

1.236

-

0.870

0.130

-

11

10.4

1.248

-

0.826

0.174

-

10

10.5

1.261

-

0.783

0.217

-

9

10.6

1.273

-

0.739

0.261

-

6

10.7

1.285

-

0.696

0.304

-

3

10.8

1.297

-

0.652

0.348

-

1

10.9

1.309

-

0.609

0.391

-

-2

11.0

1.321

-

0.565

0.435

-

-5

11.1

1.333

-

0.522

0.478

-

-6

11.2

1.345

-

0.478

0.522

-

-8

11.3

1.357

-

0.435

0.565

-

-10

11.4

1.369

-

0.391

0.609

-

-12

11.5

1.381

-

0.348

0.652

-

-14

11.6

1.393

-

0.304

0.696

-

-16

11.7

1.405

-

0.261

0.739

-

-19

11.8

1.417

-

0.217

0.783

-

-21

11.9

1.429

-

0.174

0.826

-

-13

12.0

1.441

-

0.130

0.870

-

-6

12.1

1.453

-

0.087

0.913

-

5

12.2

1.465

-

0.043

0.957

-

16

12.3

1.477

-

-

1.000

-

27

12.4

1.489

-

-

0.996

6.6

38

12.5

1.501

-

-

0.993

12.2

45

12.6

1.513

-

-

0.989

18.2

52

12.7

1.525

-

-

0.986

23.5

60

15

Section

18a


Table 14 – Formulating Sodium Bromide Base Solutions Using Powder NaCl, Powder NaBr and Fresh Water

Density lb/gal

bbl Water per bbl Brine

Ibs NaCl per bbl Brine

lbs NaBr per bbl Brine

Crystallisation Point, °F (LCTD)

10.0

0.886

110.0

0

30

10.1

0.883

106.0

9.3

10.2

0.880

102.0

18.6

10.3

0.877

97.8

27.9

10.4

0.874

93.7

37.1

10.5

0.871

89.6

46.4

10.6

0.868

85.6

55.7

10.7

0.865

81.5

65.0

10.8

0.862

77.4

74.3

10.9

0.859

73.4

83.6

11.0

0.856

69.3

92.8

11.1

0.853

65.2

102.0

11.2

0.850

61.2

111.0

11.3

0.847

57.1

121.0

11.4

0.844

52.9

130.0

11.5

0.841

48.8

139.0

11.6

0.838

44.8

149.0

11.7

0.835

40.7

158.0

11.8

0.832

36.6

167.0

11.9

0.829

32.6

177.0

12.0

0.826

28.5

186.0

37

12.1

0.823

24.4

195.0

41

12.2

0.820

20.4

204.0

47

12.3

0.818

16.3

214.0

49

12.4

0.815

12.2

223.0

53

12.5

0.812

8.1

232.0

56

12.6

0.809

4.1

242.0

60

12.7

0.806

0

251.0

63

Note: Crystallisation points need to be determined for fluids that do not have the data detailed before use in the field.

16

Table 15 – Formulating Sodium Bromide (95% purity) Brine

Brine at 20 ºC / 68 ºF

Requirements for 1 bbl Brine

Requirements for 1 m3 Brine

Crystallisation Point

lb/gal

SG

Water gal

NaBr lbs

Water m3

NaBr kg

ºF

ºC

8.4 8.5 8.6 8.7 8.8 8.9 9.0 9.1 9.2 9.3 9.4 9.5 9.6 9.7 9.8 9.9 10.0 10.1 10.2 10.3 10.4 10.5 10.6 10.7 10.8 10.9 11.0 11.1 11.2 11.3 11.4 11.5 11.6 11.7

1.007 1.019 1.031 1.043 1.055 1.067 1.079 1.091 1.103 1.115 1.127 1.139 1.151 1.163 1.175 1.187 1.199 1.211 1.223 1.235 1.247 1.259 1.271 1.283 1.295 1.307 1.319 1.331 1.343 1.354 1.366 1.379 1.391 1.402

41.81 41.66 41.51 41.35 41.18 41.02 40.85 40.69 40.51 40.34 40.17 39.99 39.81 39.64 39.46 39.27 39.09 38.90 38.72 38.53 38.34 38.16 37.97 37.78 37.59 37.40 37.20 37.00 36.80 36.61 36.41 36.21 36.02 35.81

4.08 9.60 15.07 20.60 26.15 31.70 37.39 42.92 48.55 54.20 59.84 65.52 71.21 76.91 82.58 88.33 94.05 99.81 105.56 111.33 117.09 122.86 128.62 134.41 140.19 146.02 151.87 157.71 163.58 169.40 175.28 181.14 186.98 192.83

0.996 0.992 0.988 0.984 0.981 0.977 0.973 0.969 0.965 0.961 0.956 0.952 0.948 0.944 0.939 0.935 0.931 0.926 0.922 0.917 0.913 0.909 0.904 0.900 0.895 0.890 0.886 0.881 0.876 0.872 0.867 0.862 0.858 0.853

11.65 27.38 42.99 58.77 74.62 90.44 106.68 122.45 138.52 154.64 170.72 186.92 203.15 219.42 235.62 252.01 268.34 284.75 301.18 317.62 334.07 350.52 366.96 383.48 399.98 416.62 433.30 449.96 466.72 483.32 500.08 516.79 533.47 550.16

31.0 30.0 29.0 29.0 28.0 26.0 25.0 24.0 23.0 22.0 21.0 20.0 19.0 18.0 16.0 15.0 14.0 12.0 11.0 10.0 8.0 6.0 5.0 4.0 2.0 0.0 - 2.0 - 3.0 - 5.0 - 7.0 - 9.0 - 11.0 - 14.0 - 16.0

- 0.6 - 1.1 - 1.7 - 1.7 - 2.2 - 3.3 - 3.9 - 4.4 - 5.0 - 5.6 - 6.1 - 6.7 - 7.2 - 7.8 - 8.9 - 9.4 - 10.0 - 11.1 - 11.7 - 12.2 - 13.3 - 14.4 - 15.0 - 15.6 - 16.7 - 17.8 - 18.9 - 19.4 - 20.6 - 21.7 - 22.8 - 23.9 - 25.6 - 26.7

Note: It is recommended to confirm crystallisation points before use in the field.

17

Section

18a


Table 16 – Formulating Sodium Formate Brine

18

HCOONa (Wt%)

HCOONa (g/l)

Initial H20 (ml/l)

Density (lb/gal)

Correction Factor

Sodium (mg/l)

lbs HCOONa /bbl H2O

Activity

1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 12.0 13.0 14.0 15.0 16.0 17.0 18.0 19.0 20.0 21.0 22.0 23.0 24.0 25.0 26.0 27.0 28.0 29.0 30.0 31.0 32.0 33.0 34.0 35.0 36.0 37.0 38.0 39.0 40.0 41.0 42.0 43.0 44.0 45.0 46.0 47.0 48.0 49.0

10.05 20.20 30.47 40.86 51.38 62.02 72.80 83.71 94.75 105.83 117.24 128.68 140.26 151.97 163.81 175.79 187.91 200.16 212.56 226.08 237.75 250.58 253.56 276.69 289.99 303.46 317.09 330.90 344.89 359.08 373.42 387.96 402.68 417.58 432.66 447.90 463.30 478.85 494.52 510.29 526.14 542.04 557.93 573.79 589.58 605.19 620.59 635.71 650.45

996.6 991.7 987.0 982.4 977.9 973.4 968.9 964.4 958.8 956.1 950.3 945.4 940.4 935.2 930.0 924.5 919.1 913.5 907.7 901.9 896.0 890.0 883.9 877.8 871.5 865.2 858.9 852.4 845.9 839.3 832.7 826.9 819.0 812.1 806.0 797.7 790.3 782.7 774.9 766.8 758.5 749.9 740.9 731.6 721.9 711.7 701.1 689.9 678.2

8.371 8.415 8.461 8.509 8.559 8.611 8.663 8.716 8.770 8.824 8.878 8.933 8.987 9.042 9.097 9.152 9.207 9.263 9.318 9.374 9.431 9.488 9.546 9.604 9.663 9.722 9.783 9.844 9.907 9.970 10.034 10.099 10.165 10.231 10.297 10.364 10.431 10.497 10.562 10.627 10.690 10.750 10.808 10.863 10.913 10.959 10.999 11.032 11.058

1.0034 1.0083 1.0131 1.0179 1.0226 1.0273 1.0321 1.0369 1.0419 1.0470 1.0523 1.0578 1.0634 1.0693 1.0763 1.0816 1.0880 1.0947 1.1016 1.1087 1.1160 1.1236 1.1313 1.1392 1.1474 1.1557 1.1643 1.1731 1.1822 1.1914 1.2010 1.2108 1.2210 1.2314 1.2423 1.2536 1.2654 1.2776 1.2905 1.3041 1.3184 1.3336 1.3497 1.3669 1.3863 1.4051 1.4264 1.4494 1.4746

3397 6829 10301 13813 17367 20966 24609 28297 32030 35808 39631 43600 47413 51372 55375 59424 63519 67660 71848 76084 80369 84704 89092 93532 98027 102579 107188 111857 116586 121376 126228 131143 136119 141157 146253 151407 156613 161868 167165 172497 177855 183227 188601 193962 199293 204574 209782 214891 219874

3.53 7.13 10.81 14.56 18.39 22.30 26.30 30.38 34.55 38.82 43.18 47.64 52.20 56.87 61.65 66.55 71.56 76.69 81.95 87.34 92.87 98.54 104.36 110.33 116.46 122.75 129.22 135.87 142.70 149.73 156.96 164.41 172.08 179.98 188.12 196.52 205.19 214.13 223.37 232.91 242.78 252.99 263.56 274.51 286.86 297.61 309.82 322.50 335.67

0.992 0.986 0.979 0.972 0.965 0.958 0.951 0.946 0.938 0.932 0.925 0.919 0.913 0.906 0.900 0.893 0.887 0.880 0.873 0.866 0.859 0.852 0.844 0.836 0.828 0.819 0.810 0.800 0.790 0.780 0.770 0.759 0.748 0.736 0.725 0.713 0.702 0.691 0.680 0.670 0.660 0.651 0.643 0.636 0.630 0.626 0.622 0.619 0.617

Table 17 – Formulating Potassium Formate Brine HCOONa (Wt%)

HCOOK (g/l)

Initial H20 (ml/l)

Density (lb/gal)

Correction Factor

1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 12.0 13.0 14.0 15.0 16.0 17.0 18.0 19.0 20.0 21.0 22.0 23.0 24.0 25.0 26.0 27.0 28.0 29.0 30.0 31.0 32.0 33.0 34.0 35.0 36.0 37.0 38.0 39.0 40.0

10.06 20.25 30.55 40.97 51.51 62.16 72.92 83.79 94.78 105.88 117.11 128.45 139.91 151.49 163.21 175.05 187.03 199.14 211.40 223.80 236.34 249.04 261.88 274.88 288.04 301.36 314.84 328.49 342.30 356.29 370.44 384.76 399.25 413.92 428.76 443.77 458.96 474.32 489.85 505.56

998.0 994.0 989.7 985.1 980.4 975.5 970.5 966.3 960.1 954.7 949.2 943.6 938.0 932.3 928.5 920.7 918.8 908.9 902.9 896.8 890.7 884.5 878.3 872.0 865.7 859.3 852.8 846.2 839.6 832.8 826.0 819.1 812.1 804.9 797.7 790.3 782.9 775.3 767.6 759.7

8.382 8.433 8.484 8.533 8.581 8.629 8.677 8.725 8.772 8.820 8.868 8.916 8.965 9.014 9.063 9.114 9.164 9.216 9.268 9.321 9.375 9.429 9.485 9.541 9.598 9.666 9.714 9.773 9.832 9.883 9.954 10.016 10.078 10.141 10.204 10.268 10.333 10.398 10.463 10.528

1.0020 1.0061 1.0106 1.0161 1.0200 1.0261 1.0304 1.0359 1.0416 1.0476 1.0535 1.0597 1.0661 1.0726 1.0793 1.0862 1.0931 1.1003 1.1076 1.1151 1.1227 1.1305 1.1386 1.1467 1.1552 1.1638 1.1726 1.1817 1.1911 1.2007 1.2106 1.2209 1.2314 1.2423 1.2536 1.2653 1.2773 1.2899 1.3028 1.3163

Potassium lbs (mg/l) HCOOK /bbl H2O 4677 9411 14201 19044 23841 28890 33892 38946 44063 49214 54430 59700 65028 70413 75858 81363 86930 92561 98257 104019 109850 116750 121721 127763 133880 140071 146337 152680 159100 165599 172176 178833 185569 192386 199283 206261 213320 220459 227679 234981

3.53 7.13 10.81 14.56 18.39 22.30 26.30 30.38 34.55 38.82 43.18 47.64 52.20 56.87 61.65 66.55 71.56 76.68 81.95 87.34 92.87 98.54 104.36 110.33 116.46 122.75 129.22 135.87 142.70 149.73 156.96 164.41 172.08 179.98 188.12 196.52 205.19 214.13 223.37 232.91

Activity

0.994 0.991 0.987 0.984 0.980 0.975 0.971 0.968 0.961 0.956 0.951 0.946 0.940 0.934 0.928 0.922 0.915 0.908 0.901 0.894 0.886 0.878 0.870 0.862 0.854 0.845 0.836 0.827 0.818 0.809 0.799 0.789 0.780 0.770 0.760 0.750 0.740 0.730 0.719 0.709

19

Section

18a


Table 17 – Formulating Potassium Formate Brine cont’d.…

20

HCOONa (Wt%)

HCOOK (g/l)

Initial H20 (ml/l)

Density (lb/gal)

Correction Factor

41.0 42.0 43.0 44.0 45.0 46.0 47.0 48.0 49.0 50.0 51.0 52.0 53.0 54.0 55.0 56.0 57.0 58.0 59.0 60.0 61.0 62.0 63.0 64.0 65.0 66.0 67.0 68.0 69.0 70.0 71.0 72.0 73.0 74.0 75.0

521.44 537.50 553.73 570.13 586.71 603.46 620.38 637.48 654.76 672.21 689.84 707.65 725.64 743.82 762.19 780.76 799.54 818.52 837.71 857.14 876.80 896.71 916.88 937.32 958.06 979.11 1000.49 1022.22 1044.33 1066.84 1089.79 1113.20 1137.10 1181.54 1186.56

751.7 743.6 735.3 726.9 718.4 709.7 700.8 691.8 682.7 673.5 664.0 654.4 644.7 634.8 624.7 614.6 604.2 593.8 583.2 572.5 561.6 550.6 539.5 528.2 516.8 505.3 493.7 481.9 470.0 458.0 445.9 433.7 421.3 408.8 398.2

10.594 10.660 10.727 10.794 10.861 10.928 10.996 11.063 11.131 11.199 11.267 11.336 11.405 11.474 11.544 11.614 11.684 11.756 11.827 11.900 11.973 12.048 12.123 12.200 12.278 12.358 12.439 12.522 12.608 12.695 12.788 12.879 12.976 13.075 13.179

1.3303 1.3448 1.3599 1.3756 1.3920 1.4091 1.4269 1.4454 1.4648 1.4850 1.5081 1.5281 1.5512 1.5754 1.6007 1.6272 1.6550 1.6841 1.7147 1.7469 1.7807 1.8162 1.8537 1.8932 1.9349 1.9790 2.0267 2.0751 2.1275 2.1832 2.2425 2.3058 2.3734 2.4459 2.5238

Potassium lbs (mg/l) HCOOK /bbl H2O 242363 249826 257369 264993 272697 280482 288348 296296 304325 312436 320630 328908 337272 345722 354262 362893 371618 380440 389363 398391 407529 416783 426167 435661 445300 455083 465020 476121 486397 495861 506525 517405 528517 539876 551503

242.78 252.99 263.56 274.51 285.85 297.61 309.82 322.50 335.67 349.37 363.63 378.48 393.97 410.13 427.01 444.65 463.12 482.46 502.75 52706 546.45 570.02 594.87 621.10 648.83 678.19 709.33 742.41 777.63 815.20 855.35 898.38 944.59 994.36 1048.11

Activity

0.699 0.689 0.678 0.668 0.658 0.648 0.638 0.627 0.617 0.607 0.597 0.587 0.576 0.566 0.556 0.546 0.535 0.526 0.514 0.504 0.493 0.482 0.471 0.459 0.447 0.436 0.423 0.409 0.396 0.381 0.366 0.350 0.333 0.314 0.294

Table 18 – Formulating Potassium Sulphate Brine Weight (%)

Density (kg/l))

Density (lb/gal)

K+ (mg/l)

SO4–– (mg/l)

K2SO4 (lb/bbl)

Water (bbl)

Cryst. Pt. (°F)l

0.5

1.004

8.37

2,244

2,756

1.8

0.997

31.8

1.0

1.008

8.41

4,532

5,568

3.5

0.996

31.5

1.5

1.012

8.44

6,821

8,379

5.3

0.995

31.9

2.0

1.016

8.47

9,110

11,190

7.1

0.994

31.1

2.5

1.020

8.51

11,443

14,057

8.9

0.993

31.9

3.0

1.024

8.54

13,776

16,924

10.7

0.992

31.9

3.5

1.028

8.58

16,110

19,790

12.6

0.991

31.8

4.0

1.032

8.61

18,488

22,712

14.4

0.989

31.8

4.5

1.037

8.64

20,911

25,689

16.3

0.988

30.1

5.0

1.041

8.68

23,290

28,610

18.2

0.987

29.9

5.5

1.045

8.71

25,758

31,642

20.1

0.986

—

6.0

1.049

8.75

28,181

34,619

22.0

0.984

—

6.5

1.053

8.78

30,649

37,651

23.9

0.983

—

7.0

1.057

8.82

33,162

40,738

25.9

0.981

—

7.5

1.061

8.85

35,675

43,825

27.8

0.980

—

8.0

1.066

8.89

38,188

46,912

29.8

0.979

—

8.5

1.070

8.92

40,746

50,054

31.8

0.977

—

9.0

1.074

8.96

43,304

53,196

33.8

0.976

—

9.5

1.078

8.99

45,907

56,393

35.8

0.974

—

10.0

1.083

9.03

48,509

59,591

37.8

0.973

—


21

section 18b

metric salt tables

section 18b

Scomi Oiltools

Table 1 - Concentration Conversions for Brines

2

Table 2 - Sodium Chloride

3

Table 3 - Calcium Chloride Salt Tables

4

Table 4 - Sodium-Calcium Chloride Blends

6

Table 5 - Magnesium Chloride

6

Table 6 - Potassium Chloride

7


8


9

Table 9 – Potassium Bromide

10

Table 10 – Formulating Calcium-Chloride/Calcium-Bromide Using

1.39 SG CaCl2 Brine, 1.70 SG CaBr2 Brine, and Sack CaCl2

11

Table 11 – Formulating Calcium Bromide Base Solutions Using

Solid 94% CaCl2 and Liquid 1.70 SG CaBr2

12

Table 12 – Formulating Calcium Bromide Base Solutions Using

95% Powder CaBr2

13

Table 13 – Table 14 – Sodium Bromide - Mixed From 1.198 SG NaCl,

1.474 SG NaBr, and Dry NaBr

14

Table 14 – Formulating Sodium Bromide Base Solutions Using

Powder NaCl, Powder NaBr and Fresh Water

15


16

Table 16 – Formulating Sodium Formate Brine

17

Table 17 – Formulating Potassium Formate Brine

18

Table 18 – Formulating Potassium Suphate Brine

20

Section

18b

metric salt tables

salt tables

The following table details the maximum brine densities achievable with the main type of brines used in the oil industry Brine

Maximum Density (lb/gal)

Maximum Density (SG)

10.0 11.6 15.6 9.6 12.6 15.1 19.2 11.2 13.0 19.5

1.20 1.39 1.87 1.16 1.51 1.81 2.30 1.34 1.56 2.34

NaCl CaCl2 CaCl2 /CaBr2 KCl NaBr CaBr2 ZnBr2 NaCOOH KCOOH CsCOOH Table 1 - Concentration Conversions for Brines Salt (% wt)

Chloride (% wt)

Salt (ppm)

Chloride (ppm)

Salt (mg/l)

Chloride (mg/l)

1.0

x 1/factor

x 104

x 1/factor x 104

x 104 x SG


Cl-(% wt)

x factor

1.0

x factor x 104

x 104


104 x SG

Salt (ppm)

x 10-4

x 1/factor x 10-4

1.0

x 1/factor

x SG

x 1/factor x SG

Cl-(ppm)

x factor x 10-4

x 10-4

x factor

1.0

x factor x SG

x SG

Salt (mg/l)

x 10-4 x 1/SG

x 1/factor x 10-4 x 1/SG

x 1 / SG

x 1/factor x 1/SG

1.0

x 1/factor

Cl- (mg/l)

x factor x 10-4 x 1/SG

From

To

Salt (% wt)

x 10-4

x factor x1/SG

x 1 / SG

Salt

Factor

1/Factor

CaCl2 NaCl KCl

1.5642 1.6488 2.103

0.6393 0.6065 0.4755

x factor

1.0

Table 2 - Sodium Chloride Weight (%)

Density (kg/l)

Density (lb/gal)

Cl– (mg/l)

Na+ (mg/l)

NaCl (kg/m3)

Water (m3)

Cryst. Pt. (C)

Water Activity

1

1.005

8.38

6127

3973

9.99

0.1582

-0.61

0.994

2

1.013

8.44

12254

7946

20.26

0.1577

-1.17

0.989

3

1.02

8.5

18563

12037

30.53

0.1573

-1.78

0.983

4

1.027

8.56

24932

16168

41.08

0.1568

-2.39

0.977

5

1.034

8.62

31363

20337

51.64

0.1561

-3.06

0.97

6

1.041

8.68

37914

24586

62.48

0.1557

-3.72

0.964

7

1.049

8.75

44526

28874

73.32

0.1550

-4.39

0.957

8

1.056

8.81

51260

33240

84.45

0.1544

-5.06

0.95

9

1.063

8.87

58054

37646

95.58

0.1539

-5.83

0.943

10

1.071

8.93

64970

42130

106.99

0.1533

-6.56

0.935

11

1.078

8.99

71946

46654

118.40

0.1526

-7.33

0.927

12

1.086

9.05

79044

51256

130.10

0.1518

-8.17

0.919

13

1.093

9.12

86202

55898

141.79

0.1512

-9.06

0.911

14

1.101

9.18

93481

60619

153.78

0.1506

-9.94

0.902

15

1.109

9.24

100882

65418

166.04

0.1498

-10.89

0.892

16

1.116

9.31

108344

70256

178.31

0.1491

-11.89

0.883

17

1.124

9.37

115927

75173

190.87

0.1483

-12.94

0.872

18

1.132

9.44

123570

80130

203.42

0.1476

-14.06

0.862

19

1.14

9.51

131396

85204

216.26

0.1468

-15.22

0.851

20

1.148

9.57

139282

90318

229.38

0.1460

-16.44

0.839

21

1.156

9.64

147229

95471

242.22

0.1452

-17.78

0.827

22

1.164

9.71

155357

100743

255.63

0.1444

-19.17

0.815

23

1.172

9.78

163547

106053

269.32

0.1436

-20.67

0.802

24

1.18

9.84

171858

111442

283.02

0.1426

-17.00

0.788

25

1.189

9.91

180290

116910

296.71

0.1418

-9.61

0.774

26

1.197

9.98

188843

122457

310.98

0.1409

-2.28

0.759

1.0 - (m3 water % volume salt = 100 x ( ) 0.159 Properties based on 20 °C and 100% purity

Section

18b

metric salt tables

Table 3 - Calcium Chloride Salt Tables Wt %

SG

CImg/l

Ca++ mg/l

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40

1.007 1.015 1.023 1.032 1.04 1.049 1.057 1.066 1.075 1.084 1.092 1.101 1.111 1.120 1.129 1.139 1.148 1.158 1.168 1.178 1.190 1.198 1.210 1.218 1.231 1.239 1.252 1.260 1.273 1.282 1.295 1.304 1.317 1.326 1.340 1.349 1.363 1.372 1.387 1.396

6,460 12,985 19,637 26,417 33,261 40,233 47,333 54,561 61,853 69,273 76,885 84,560 92,364 100,295 108,355 116,542 124,858 133,301 141,936 150,635 159,846 168,545 178,012 186,967 196,769 206,028 216,137 225,665 236,136 245,941 256,783 266,794 277,994 288,350 299,879 310,609 322,577 333,508 345,876 357,111

3,640 7,315 11,063 14,883 18,739 22,667 26,667 30,739 34,847 39,027 43,315 47,640 52,036 56,505 61,045 65,658 70,342 75,099 79,964 84,865 90,054 94,955 100,288 105,333 110,856 116,072 121,768 127,135 133,034 138,559 144,667 150,306 156,616 162,450 168,946 174,991 181,733 187,892 194,859 201,189

Ca++CI- 100% CaCI2 100% Water 95% CaCI2 95% Water mg/l kg/m3 m3 kg/m3 m3 10,100 20,300 30,700 41,300 52,000 62,900 74,000 85,300 96,700 108,300 120,200 132,200 144,400 156,800 169,400 182,200 195,200 208,400 221,900 235,500 249,900 263,500 278,300 292,300 307,625 322,100 337,905 352,800 369,170 384,500 401,450 417,100 434,610 450,800 468,825 485,600 504,310 521,400 540,735 558,300

10.0 20.2 30.5 41.3 51.9 62.7 73.8 85.2 96.3 108.0 120.0 132.0 143.9 156.5 169.0 181.8 194.7 207.8 221.4 234.8 249.6 262.8 278.0 291.6 307.3 321.2 337.6 352.0 368.8 383.6 401.0 416.1 434.1 449.7 468.3 484.5 503.8 520.1 540.2 556.9

0.996 0.995 0.993 0.99 0.988 0.986 0.983 0.981 0.978 0.975 0.972 0.969 0.966 0.963 0.96 0.957 0.953 0.95 0.946 0.942 0.940 0.934 0.932 0.926 0.923 0.917 0.914 0.907 0.901 0.897 0.894 0.886 0.882 0.875 0.871 0.863 0.859 0.851 0.846 0.837

10.5 21.3 32.1 43.5 54.6 66.0 77.7 89.7 101.4 113.7 126.3 138.9 151.5 164.7 177.9 191.4 204.9 218.7 233.1 247.2 262.8 276.6 292.7 306.9 323.5 338.1 355.3 370.5 388.2 403.8 422.1 438.0 457.0 473.4 493.0 510.0 530.3 547.5 568.6 586.2


0.995 0.994 0.991 0.988 0.985 0.983 0.979 0.977 0.973 0.969 0.966 0.962 0.958 0.955 0.951 0.947 0.943 0.939 0.934 0.930 0.927 0.920 0.917 0.911 0.907 0.900 0.896 0.888 0.882 0.877 0.873 0.864 0.859 0.851 0.846 0.838 0.832 0.824 0.818 0.808

Cryst Pt °F 31.2 30.4 29.6 28.7 27.8 26.7 25.9 24.6 23.5 22.3 20.8 19.3 17.6 15.5 13.5 11.2 8.6 5.9 2.8 -0.4 -3.9 -7.8 -11.9 -13.5 -21.0 -25.8 -31.2 -37.8 -49.4 -50.8 -33.2 -19.5 -6.9 4.3 14.4 24.1 33.4 42.1 49.6 55.9

Cryst Pt °C -0.4 -0.9 -1.3 -1.8 -2.3 -2.9 -3.4 -4.1 -4.7 -5.4 -6.2 -7.1 -8.0 -9.2 -10.3 -11.6 -13.0 -14.5 -16.2 -18.0 -19.9 -22.1 -24.4 -25.3 -29.4 -32.1 -35.1 -38.8 -45.2 -46.0 -36.2 -28.6 -21.6 -15.4 -9.8 -4.4 0.8 5.6 9.8 13.3

Properties of Calcium Chloride Solutions (at 20 °C) When Using CaCl2 with purity other than 95%: 3 New CaCl2 (kg/m3) = 95 x 95% CaCl2 (kg/m ) % Purity

Volume increase from salt = m3 / New Water m3

New water (m3) =

(

3 3 Water (m3) – New CaCl2 kg/m – 95% CaCl2 kg/m 1000

)

Example: 35% CaCl2 brine using 78% CaCl2 : 492.5 New CaCl2 (kg/m3) = 95 x = 599.8 kg/m3 78 599.8 - 495.5 New Water (m3) = 0.846 - 1000 = 0.739 m3 Volume increase from 78% salt = 1 m3 / 0.739 m3 = 1.35

Formulas: Salt (kg/m3) = Volume incr. factor x CaCl2 (kg/m3)

Section

18b

metric salt tables

Table 4 - Sodium-Calcium Chloride Blends Denisty ([email protected] ˚C)

Water (m3)

100% NaCl (kg/m3)

94-97% CaCl2 (kg/m3)

Cryst. Pt.(˚C)

1.21

0.141

251.06

82.74

-20.00

1.222

0.139

199.71

148.36

-23.33

1.234

0.139

154.06

205.42

-26.11

1.246

0.139

116.97

253.92

-29.44

1.258

0.138

91.30

296.71

-32.22

1.27

0.138

71.33

330.95

-35.56

1.282

0.138

57.06

359.48

-38.89

1.294

0.137

45.65

385.16

-41.11

1.306

0.137

37.09

410.83

-31.11

1.318

0.137

28.53

430.80

-24.44

1.33

0.136

22.82

453.63

-17.78

Table 5 - Magnesium Chloride Weight (%)

Density (kg/l)

Density (lb/gal)

Cl– (mg/l)

Mg2 (mg/l)

MgCl2 (kg/m3)

Water (m3)

Cryst. Pt. (˚C)

Water Activity

1

1.006

8.39

7,492

2,568

10.10

0.158

-0.5

0.995

2

1.014

8.46

15,106

5,178

20.57

0.158

-1.1

0.99

3

1.023

8.52

22,842

7,830

31.33

0.158

-1.7

0.984

4

1.031

8.59

30,703

10,524

42.45

0.157

-2.3

0.978

5

1.039

8.66

38,696

13,264

53.95

0.157

-3.0

0.972

6

1.048

8.74

46,814

16,047

65.82

0.157

-4.3

0.964

7

1.056

8.81

55,060

18,873

78.03

0.156

-5.4

0.957

8

1.065

8.88

63,444

21,747

90.64

0.156

-5.8

0.948

9

1.074

8.95

71,957

24,665

103.65

0.155

-6.9

0.939

10

1.083

9.02

80,608

27,631

117.06

0.155

-7.8

0.929

12

1.101

9.17

98,329

33,705

145.16

0.154

-9.8

0.906

14

1.119

9.33

116,635

39,980

175.06

0.153

-14.6

0.879

16

1.137

9.48

135,477

46,439

206.67

0.152

-18.8

0.848

18

1.155

9.63

154,838

53,075

239.97

0.151

-25.0

0.812

20

1.174

9.79

174,856

59,937

275.43

0.149

-33.2

0.772

22

1.194

9.95

195,553

67,031

313.17

0.148

-28.1

0.727

24

1.214

10.12

216,940

74,362

353.32

0.147

-24.3

0.677

26

1.235

10.29

239,006

81,926

395.85

0.145

-20.6

0.624

28

1.256

10.47

261,748

89,722

440.85

0.144

-17.1

0.567

30

1.276

10.64

285,091

97,723

488.12

0.142

-16.4

0.507

1.0 - (m3 water) ) 0.159

% volume salt = 100 x (

Properties based on 20 °C and 100% purity

Table 6 - Potassium Chloride Weight (%)

Density (kg/l)

Density (lb/gal)

Cl– (mg/l)

K+ (mg/l)

KCl (kg/m3)

Water (m3)

Cryst. Pt. (˚C)

Water Activity

1

1.005

8.38

4,756

5,244

2.839

0.557

-0.4

0.996

2

1.011

8.43

9,606

10,594

2.827

1.129

-0.9

0.991

3

1.017

8.49

14,504

15,996

2.816

1.701

-1.4

0.987

4

1.024

8.54

19,498

21,502

2.804

2.290

-1.8

0.982

5

1.03

8.59

24,491

27,009

2.793

2.862

-2.3

0.977

6

1.037

8.65

29,579

32,621

2.782

3.466

-2.8

0.973

7

1.043

8.70

34,715

38,285

2.767

4.070

-3.3

0.968

8

1.05

8.76

39,947

44,053

2.756

4.675

-3.8

0.963

9

1.057

8.81

45,225

49,875

2.745

5.295

-4.3

0.958

10

1.063

8.87

50,551

55,749

2.730

5.915

-4.8

0.953

11

1.07

8.92

55,973

61,727

2.716

6.551

-5.3

0.947

12

1.077

8.98

61,442

67,758

2.705

7.187

-5.9

0.942

13

1.084

9.04

67,006

73,894

2.690

7.839

-6.4

0.936

14

1.091

9.09

72,617

80,083

2.676

8.491

-6.7

0.93

15

1.097

9.15

78,276

86,324

2.662

9.158

-7.5

0.925

16

1.104

9.21

84,030

92,670

2.648

9.826

-8.3

0.918

17

1.111

9.27

89,832

99,068

2.630

10.510

-8.9

0.912

18

1.119

9.33

95,729

105,571

2.616

11.210

-9.4

0.906

19

1.126

9.39

101,721

112,179

2.602

11.909

-10.0

0.899

20

1.133

9.45

107,760

118,840

2.585

12.609

-10.6

0.892

22

1.147

9.57

120,030

132,370

2.553

14.040

1.1

0.878

24

1.162

9.69

132,632

146,268

2.519

15.518

15.0

0.862

1.0 - (m3 water) % volume salt = 100 x ( ) 0.159 Properties based on 20 °C and 100% purity

Section

18b

metric salt tables


Weight (%)

S.G. (20 °C)

Density (lb/gal)

K2CO3 (mg/l)

K (mg/l)

CO3(mg/l)

K2CO3 (kg/m3)

Water (l/m3)

1

1.01

8.42

10,100

5,715

4386

10.085

996.95

2

1.02

8.49

20,300

11,487

8815

20.271

995.76

3

1.03

8.57

30,800

17,429

13374

30.755

994.33

4

1.04

8.64

41,400

23,427

17977

41.340

992.91

5

1.05

8.72

52,200

29,539

22667

52.124

991.24

6

1.05

8.8

63,200

35,763

27443

63.108

989.57

7

1.06

8.87

74,300

42,045

32263

74.192

987.67

8

1.07

8.95

85,700

48,496

37213

85.576

985.53

9

1.08

9.03

97,300

55,060

42250

97.159

983.38

10

1.09

9.11

109,000

61,680

47331

108.842

981.24

11

1.1

9.19

121,000

68,471

52541

120.825

978.86

12

1.11

9.27

133,200

75,375

57839

133.007

976.24

13

1.12

9.35

145,500

82,335

63180

145.289

973.62

14

1.13

9.43

158,100

89,465

68651

157.871

971.01

15

1.14

9.52

170,900

96,708

74209

170.652

967.91

16

1.15

9.6

183,800

104,008

79811

183.533

965.05

17

1.16

9.68

197,000

111,477

85542

196.714

961.96

18

1.17

9.77

210,500

119,117

91405

210.195

958.63

19

1.18

9.85

224,100

126,813

97310

223.775

955.29

20

1.19

9.94

238,000

134,678

103346

237.655

951.72

22

1.21

10.11

266,300

150,693

115634

265.914

944.11

24

1.23

10.29

295,700

167,329

128401

295.271

936.01

26

1.26

10.47

325,900

184,419

141514

325.427

927.44

28

1.28

10.66

357,100

202,074

155062

356.582

918.16

30

1.3

10.84

389,400

220,352

169088

388.835

908.40

32

1.32

11.03

422,600

239,139

183504

421.987

897.69

34

1.35

11.22

456,800

258,492

198354

456.138

886.50

36

1.37

11.42

492,000

278,411

213639

491.287

874.60

38

1.39

11.62

528,300

298,952

229401

527.534

861.74

40

1.42

11.81

565,600

320,059

245598

564.780

848.17


Density (kg/m3)

SG @ (15.6 ˚C)

Brine

m3 Water per m3 Brine

% by Weight Ammonium Chloride (NH4Cl)

kg NH4Cl per m3

1006.57

1.007

19.97

0.157

1.98

1012.56

1.013

29.96

0.156

3.00

1018.56

1.020

54.21

0.154

5.30

1030.54

1.031

85.59

0.149

8.40

1042.52

1.044

119.83

0.146

11.50

1054.50

1.055

151.21

0.143

14.40

1066.49

1.068

185.45

0.140

17.40

1078.47

1.079

219.68

0.137

20.40

1090.45

1.128

251.06

0.134

23.00

1102.44

1.103

285.30

0.130

25.90

1138.39

1.139

385.16

0.119

33.90

Section

18b

metric salt tables

Table 9 – Potassium Bromide

10

Density (SG)


kg KBr per m3 Brine

% KBr

Cryst. Pt. (˚C) (LCTD)

0.995

1.000

–

–

0.0

1.031

0.985

43.08

4.2

-1.1

1.042

0.980

62.48

6.0

-1.1

1.054

0.974

80.17

7.6

-1.7

1.066

0.967

99.28

9.3

-2.2

1.078

0.962

116.40

10.8

-2.8

1.090

0.956

134.09

12.3

-2.8

1.102

0.954

150.07

13.6

-3.3

1.114

0.947

167.19

15.0

-3.3

1.126

0.942

184.59

16.4

-3.9

1.138

0.937

201.42

17.7

-4.4

1.150

0.932

218.54

19.0

-5.0

1.162

0.928

234.80

20.2

-5.6

1.174

0.922

252.49

21.5

-5.6

1.186

0.916

270.46

22.8

-6.1

1.198

0.911

287.58

24.0

-7.2

1.210

0.905

304.99

25.2

-7.8

1.222

0.901

321.53

26.3

-8.3

1.234

0.895

339.51

27.5

-8.9

1.246

0.888

357.77

28.7

-9.4

1.258

0.883

374.88

29.8

-10.0

1.270

0.878

392.57

30.9

-11.1

1.282

0.872

410.26

32.0

-10.6

1.294

0.865

429.66

33.2

-6.7

1.306

0.858

447.92

34.3

-2.8

1.318

0.854

463.90

35.2

0.6

1.330

0.847

482.73

36.3

5.0

1.342

0.842

500.70

37.3

9.4

1.354

0.835

516.96

38.3

13.9

1.366

0.829

536.93

39.3

18.9

1.378

0.824

554.05

40.2

23.9

Table 10 - Formulting Calcium Chloride - Chloride/Calcium-Bromide Using 1.39 SG CaCl2 Brine, 1.7 SG CaBr2 Brine, and Sack CaCl2 Brine Density @ 15.6 ˚C (kg/m3)

1.395 SG CaCl2 (m3)

1.70 SG CaBr2 (m3)

94-97% CaCl2 (kg) (Flakes or Pellet)

Cryst. Pt. (˚C)

1.402 1.414 1.426 1.438 1.450 1.462 1.474 1.486 1.498 1.510 1.522 1.534 1.546 1.558 1.570 1.582 1.594 1.606 1.618 1.630 1.642 1.654 1.666 1.678 1.690 1.702 1.714 1.725 1.737 1.749 1.761 1.773 1.785

0.154 0.150 0.145 0.141 0.136 0.132 0.127 0.123 0.118 0.114 0.109 0.104 0.100 0.095 0.091 0.086 0.082 0.077 0.073 0.068 0.064 0.059 0.055 0.050 0.045 0.041 0.036 0.032 0.027 0.023 0.018 0.014 0.009

0.004 0.150 0.012 0.016 0.020 0.023 0.027 0.031 0.035 0.039 0.043 0.047 0.051 0.055 0.059 0.063 0.066 0.070 0.074 0.078 0.082 0.086 0.090 0.094 0.098 0.102 0.106 0.109 0.113 0.117 0.121 0.125 0.129

1.6 3.1 4.7 6.3 7.9 9.4 11.0 12.6 14.2 15.7 17.3 18.9 20.5 22.0 23.6 25.2 26.8 28.4 29.9 31.5 33.1 34.2 36.2 37.8 39.4 41.0 42.5 44.1 45.7 47.3 48.8 50.4 52.0

7.2 10.6 11.1 12.2 12.8 12.8 13.3 13.3 13.9 14.4 14.4 14.4 15.0 15.0 15.6 15.6 15.6 16.1 16.1 16.7 16.7 17.2 17.2 17.8 17.8 17.8 18.3 18.3 18.3 18.9 18.9 19.4 19.4

1.797 1.809

0.005 0.000

0.133 0.137

53.5 55.1

19.4 20.0

11

Section

18b

metric salt tables

Table 11 - Formulating Calcium Bromide Base Solutions Using Solid 94% CaCl2 and Liquid 1.7SG CaBr2

CaCl2/CaBr2 Density at 15.6 ˚C (SG) 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

12

kg CaCl2 per m3 Brine

m3 1.70 SG CaBr2 per m3 Brine

m3 Fresh Water per m3 Brine

551.74 544.92 537.56 530.23 522.90 515.54 508.20 500.87 493.54 486.18 478.82 471.52 456.82 449.46 442.13 434.80 427.44 420.13 412.77 405.47 398.11 390.80 383.44 376.14 368.78 361.42 354.09 346.75 339.42 332.06 324.73 317.40

0.0040 0.0081 0.0121 0.0162 0.0202 0.0242 0.0283 0.0323 0.0363 0.0404 0.0444 0.0485 0.0565 0.0606 0.0646 0.0687 0.0727 0.0767 0.0808 0.0848 0.0889 0.0929 0.0965 0.1010 0.1050 0.1090 0.1131 0.1171 0.1212 0.1252 0.1292 0.1333

0.1298 0.1260 0.1222 0.1183 0.1145 0.1107 0.1069 0.1031 0.0993 0.0954 0.0916 0.0878 0.0802 0.0764 0.0725 0.0687 0.0649 0.0611 0.0573 0.0534 0.0496 0.0458 0.0420 0.0382 0.0344 0.0305 0.0267 0.0229 0.0191 0.0153 0.0115 0.0076

310.04 302.70

0.1373 0.1414

0.0383 0.0000

Table 12 - Formulating Calcium Bromide Base Solutions Using 95% Powder CaBr2

Brine Density (SG)

m3 Fresh Water per m3 Brine

kg 95% CaBr2 per m3 Brine

1.318 1.330 1.342 1.354 1.366 1.378 1.390 1.402 1.414 1.426 1.438 1.450 1.474 1.486 1.498 1.510 1.522 1.534 1.546 1.558 1.570 1.582 1.594 1.606 1.618 1.630 1.642 1.654 1.666 1.678 1.690 1.702 1.714

0.1414 0.1410 0.1406 0.1396 0.1382 0.1379 0.1374 0.1372 0.1350 0.1350 0.1348 0.1336 0.1321 0.1320 0.1305 0.1302 0.1288 0.1285 0.1267 0.1266 0.1262 0.1258 0.1255 0.1237 0.1232 0.1227 0.1210 0.1205 0.1200 0.1194 0.1189 0.1183

430.23 444.78 459.05 477.59 497.85 512.40 526.95 538.93 565.75 578.02 590.57 610.83 644.21 657.05 678.16 691.57 713.25 726.94 760.32 762.89 776.87 791.14 805.69 828.51 843.35 858.18 881.58 896.70 912.10 927.51 942.92 958.32

0.1177

974.30

13

Section

18b

metric salt tables

Table 13 – Sodium Bromide - Mixed From 1.198 SG NaCl, 1.474 SG NaBr, and Dry NaBr

14

Density

Specific Gravity

Fresh Water m3

1.198 sg NaCl 1.474 sg NaBr m3 m3

8.4

1.008

0.982

-

8.5

1.020

0.957

-

8.6

1.032

0.932

-

8.7

1.044

0.907

-

8.8

1.056

0.882

-

8.9

1.068

0.856

-

9.0

1.080

0.831

-

9.1

1.092

0.806

-

9.2

1.104

0.781

-

9.3

1.116

0.756

-

9.4

1.128

0.730

-

9.5

1.140

0.705

-

9.6

1.152

0.680

-

9.7

1.164

0.655

-

9.8

1.176

0.630

-

9.9

1.188

0.605

-

10.0

1.200

0.579

-

10.1

1.212

-

0.957

10.2

1.224

-

0.913

10.3

1.236

-

0.870

10.4

1.248

-

0.826

10.5

1.261

-

0.783

10.6

1.273

-

0.739

10.7

1.285

-

0.696

10.8

1.297

-

0.652

10.9

1.309

-

0.609

11.0

1.321

-

0.565

11.1

1.333

-

0.522

11.2

1.345

-

0.478

11.3

1.357

-

0.435

11.4

1.369

-

0.391

11.5

1.381

-

0.348

11.6

1.393

-

0.304

11.7

1.405

-

0.261

11.8

1.417

-

0.217

11.9

1.429

-

0.174

12.0

1.441

-

0.130

12.1

1.453

-

0.087

12.2

1.465

-

0.043

12.3

1.477

-

-

12.4

1.489

-

-

12.5

1.501

-

-

12.6

1.513

-

-

12.7

1.525

-

-

95% NaBr kg

TCT

0.018

-

31

0.043

-

31

0.068

-

30

0.093

-

30

0.118

-

29

0.144

-

29

0.169

-

28

0.194

-

27

0.219

-

26

0.244

-

25

0.270

-

24

0.295

-

23

0.320

-

19

0.345

-

18

0.370

-

17

0.395

-

16

0.421

-

15

0.043

-

13

0.087

-

12

0.130

-

11

0.174

-

10

0.217

-

9

0.261

-

6

0.304

-

3

0.348

-

1

0.391

-

-2

0.435

-

-5

0.478

-

-6

0.522

-

-8

0.565

-

-10

0.609

-

-12

0.652

-

-14

0.696

-

-16

0.739

-

-19

0.783

-

-21

0.826

-

-13

0.870

-

-6

0.913

-

5

0.957

-

16

1.000

-

27

0.996

18.8

38

0.993

34.8

45

0.989

51.9

52

0.986

67.0

60

Table 14 - Formulating Sodium Bromide Base Solutions Using Powder NaCl, Powder NaBr and Fresh Water

Density SG


kg NaCl per m3 Brine

kg NaBr per m3 Brine

Cryst. Pt. (˚C) (LCTD)

1.198

0.141

313.8

0.0

-1.11

1.210

0.140

302.4

26.5

1.222

0.140

291.0

53.1

1.234

0.139

279.0

79.6

1.246

0.139

267.3

105.8

1.258

0.138

255.6

132.4

1.270

0.138

244.2

158.9

1.282

0.138

232.5

185.4

1.294

0.137

220.8

212.0

1.306

0.137

209.4

238.5

1.318

0.136

197.7

264.8

1.330

0.136

186.0

291.0

1.342

0.135

174.6

316.7

1.354

0.135

162.9

345.2

1.366

0.134

150.9

370.9

1.378

0.134

139.2

396.6

1.390

0.133

127.8

425.1

1.402

0.133

116.1

450.8

1.414

0.132

104.4

476.5

1.426

0.132

93.0

505.0

1.438

0.131

81.3

530.7

2.78

1.450

0.131

69.6

556.3

5.00

1.462

0.130

58.2

582.0

8.33

1.474

0.130

46.5

610.5

9.44

1.486

0.130

34.8

636.2

11.67

1.498

0.129

23.1

661.9

13.33

1.510

0.129

11.7

690.4

15.56

1.522

0.128

0.0

716.1

17.22

Note: Crystallisation points need to be determined for fluids that do not have the data detailed before use in the field

15

Section

18b

metric salt tables


Brine at 20 ˚C / 68 ˚F

Requirements for 1 bbl Brine

Requirements for 1 m3 Brine

Crystallisation Point

lb/gal

SG

Water gal

NaBr lbs

Water m3

NaBr kg

ºC

ºF

8.4 8.5 8.6 8.7 8.8 8.9 9.0 9.1 9.2 9.3 9.4 9.5 9.6 9.7 9.8 9.9 10.0 10.1 10.2 10.3 10.4 10.5 10.6 10.7 10.8 10.9 11.0 11.1 11.2 11.3 11.4 11.5 11.6 11.7

8.4 8.5 8.6 8.7 8.8 8.9 9.0 9.1 9.2 9.3 9.4 9.5 9.6 9.7 9.8 9.9 10.0 10.1 10.2 10.3 10.4 10.5 10.6 10.7 10.8 10.9 11.0 11.1 11.2 11.3 11.4 11.5 11.6 11.7

41.81 41.66 41.51 41.35 41.18 41.02 40.85 40.69 40.51 40.34 40.17 39.99 39.81 39.64 39.46 39.27 39.09 38.90 38.72 38.53 38.34 38.16 37.97 37.78 37.59 37.40 37.20 37.00 36.80 36.61 36.41 36.21 36.02 35.81

4.08 9.60 15.07 20.60 26.15 31.70 37.39 42.92 48.55 54.20 59.84 65.52 71.21 76.91 82.58 88.33 94.05 99.81 105.56 111.33 117.09 122.86 128.62 134.41 140.19 146.02 151.87 157.71 163.58 169.40 175.28 181.14 186.98 192.83

0.996 0.992 0.988 0.984 0.981 0.977 0.973 0.969 0.965 0.961 0.965 0.952 0.948 0.944 0.939 0.935 0.931 0.926 0.922 0.917 0.913 0.909 0.904 0.900 0.895 0.89 0.886 0.881 0.876 0.872 0.867 0.862 0.858 0.853

11.65 27.38 42.99 58.77 74.62 90.44 106.68 122.45 138.52 154.64 170.72 186.92 203.15 219.42 235.62 252.01 268.34 284.75 301.18 317.62 334.07 350.52 366.96 383.48 399.98 416.62 433.30 449.96 466.72 483.32 500.08 516.79 533.47 550.16

31.0 30.0 29.0 29.0 28.0 26.0 25.0 24.0 23.0 22.0 21.0 20.0 19.0 18.0 16.0 15.0 14.0 12.0 11.0 10.0 8.0 6.0 5.0 4.0 2.0 0.0 -2.0 -3.0 -5.0 -7.0 -9.0 -11.0 -14.0 -16.0

-0.6 -1.1 -1.7 -1.7 -2.2 -3.3 -3.9 -4.4 -5.0 -5.6 -6.1 -6.7 -7.2 -7.8 -8.9 -9.4 -10.0 -11.1 -11.7 -12.2 -13.3 -14.4 -15.0 -15.6 -16.7 -17.8 -18.9 -19.4 -20.6 -21.7 -22.8 -23.9 -25.6 -26.7

Note: It is recommended to confirm crystallisation points before use in the field

16

Table 16 – Formulating Sodium Formate Brine HCOONa (Wt%)

HCOONa (g/l)

Initial H20 (ml/L)

Density (SG)

Correction Factor

Sodium (mg/L)

kg HCOONa /m3 H2O

Activity

1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 12.0 13.0 14.0 15.0 16.0 17.0 18.0 19.0 20.0 21.0 22.0 23.0 24.0 25.0 26.0 27.0 28.0 29.0 30.0 31.0 32.0 33.0 34.0 35.0 36.0 37.0 38.0 39.0 40.0 41.0 42.0 43.0 44.0 45.0 46.0 47.0 48.0 49.0

10.05 20.20 30.47 40.86 51.38 62.02 72.80 83.71 94.75 105.83 117.24 128.68 140.26 151.97 163.81 175.79 187.91 200.16 212.56 226.08 237.75 250.58 253.56 276.69 289.99 303.46 317.09 330.90 344.89 359.08 373.42 387.96 402.68 417.58 432.66 447.90 463.30 478.85 494.52 510.29 526.14 542.04 557.93 573.79 589.58 605.19 620.59 635.71 650.45

996.6 991.7 987.0 982.4 977.9 973.4 968.9 964.4 958.8 956.1 950.3 945.4 940.4 935.2 930.0 924.5 919.1 913.5 907.7 901.9 896.0 890.0 883.9 877.8 871.5 865.2 858.9 852.4 845.9 839.3 832.7 826.9 819.0 812.1 806.0 797.7 790.3 782.7 774.9 766.8 758.5 749.9 740.9 731.6 721.9 711.7 701.1 689.9 678.2

1.003 1.008 1.014 1.020 1.026 1.032 1.038 1.044 1.051 1.057 1.064 1.070 1.077 1.083 1.090 1.097 1.103 1.110 1.117 1.123 1.130 1.137 1.144 1.151 1.158 1.165 1.172 1.180 1.187 1.195 1.202 1.210 1.218 1.226 1.234 1.242 1.250 1.258 1.266 1.273 1.281 1.288 1.295 1.302 1.308 1.313 1.318 1.322 1.325

1.0034 1.0083 1.0131 1.0179 1.0226 1.0273 1.0321 1.0369 1.0419 1.0470 1.0523 1.0578 1.0634 1.0693 1.0763 1.0816 1.0880 1.0947 1.1016 1.1087 1.1160 1.1236 1.1313 1.1392 1.1474 1.1557 1.1643 1.1731 1.1822 1.1914 1.2010 1.2108 1.2210 1.2314 1.2423 1.2536 1.2654 1.2776 1.2905 1.3041 1.3184 1.3336 1.3497 1.3669 1.3863 1.4051 1.4264 1.4494 1.4746

3397 6829 10301 13813 17367 20966 24609 28297 32030 35808 39631 43600 47413 51372 55375 59424 63519 67660 71848 76084 80369 84704 89092 93532 98027 102579 107188 111857 116586 121376 126228 131143 136119 141157 146253 151407 156613 161868 167165 172497 177855 183227 188601 193962 199293 204574 209782 214891 219874

10.07 20.34 30.84 41.54 52.47 63.62 75.03 86.67 98.57 110.75 123.19 135.92 148.93 162.25 175.89 189.87 204.16 218.80 233.80 249.18 264.96 281.13 297.74 314.77 332.26 350.21 368.66 387.64 407.12 427.18 447.81 469.06 490.94 513.48 536.71 560.67 585.41 610.91 637.27 664.49 692.65 721.78 751.94 783.18 818.41 849.08 883.92 920.09 957.67

0.992 0.986 0.979 0.972 0.965 0.958 0.951 0.946 0.938 0.932 0.925 0.919 0.913 0.906 0.900 0.893 0.887 0.880 0.873 0.866 0.859 0.852 0.844 0.836 0.828 0.819 0.810 0.800 0.790 0.780 0.770 0.759 0.748 0.736 0.725 0.713 0.702 0.691 0.680 0.670 0.660 0.651 0.643 0.636 0.630 0.626 0.622 0.619 0.617

17

Section

18b

metric salt tables

Table 17 – Formulating Potassium Formate Brine

18

HCOOK (Wt%)

HCOOK (g/L)

Initial H20 (ml/l)

Density (SG)

Correction Factor

Potassium (mg/l)

kg HCOOK / m3 H2O

Activity

1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 12.0 13.0 14.0 15.0 16.0 17.0 18.0 19.0 20.0 21.0 22.0 23.0 24.0 25.0 26.0 27.0 28.0 29.0 30.0 31.0 32.0 33.0 34.0 35.0 36.0 37.0 38.0 39.0 40.0

10.06 20.25 30.55 40.97 51.51 62.16 72.92 83.79 94.78 105.88 117.11 128.45 139.91 151.49 163.21 175.05 187.03 199.14 211.40 223.80 236.34 249.04 261.88 274.88 288.04 301.36 314.84 328.49 342.30 356.29 370.44 384.76 399.25 413.92 428.76 443.77 458.96 474.32 489.85 505.56

998.0 994.0 989.7 985.1 980.4 975.5 970.5 966.3 960.1 954.7 949.2 943.6 938.0 932.3 928.5 920.7 918.8 908.9 902.9 896.8 890.7 884.5 878.3 872.0 865.7 859.3 852.8 846.2 839.6 832.8 826.0 819.1 812.1 804.9 797.7 790.3 782.9 775.3 767.6 759.7

1.004 1.010 1.017 1.022 1.028 1.034 1.040 1.045 1.051 1.057 1.063 1.068 1.074 1.080 1.086 1.092 1.098 1.104 1.111 1.117 1.123 1.130 1.137 1.143 1.150 1.158 1.164 1.171 1.178 1.184 1.193 1.200 1.208 1.215 1.223 1.230 1.238 1.246 1.254 1.262

1.0020 1.0061 1.0106 1.0161 1.0200 1.0261 1.0304 1.0359 1.0416 1.0476 1.0535 1.0597 1.0661 1.0726 1.0793 1.0862 1.0931 1.1003 1.1076 1.1151 1.1227 1.1305 1.1386 1.1467 1.1552 1.1638 1.1726 1.1817 1.1911 1.2007 1.2106 1.2209 1.2314 1.2423 1.2536 1.2653 1.2773 1.2899 1.3028 1.3160

4677 9411 14201 19044 23841 28890 33892 38946 44063 49214 54430 59700 65028 70413 75858 81363 86930 92561 98257 104019 109850 116750 121721 127763 133880 140071 146337 152680 159100 165599 172176 178833 185569 192386 199283 206261 213320 220459 227679 234981

10.07 20.34 30.84 41.54 52.47 63.62 75.03 86.67 98.57 110.75 123.19 135.92 148.93 162.25 175.89 189.87 204.16 218.77 233.80 249.18 264.96 281.13 297.74 314.77 332.26 350.21 368.66 387.64 407.12 427.18 447.81 469.06 490.94 513.48 536.71 560.67 585.41 610.91 637.27 664.49

0.994 0.991 0.987 0.984 0.980 0.975 0.971 0.968 0.961 0.956 0.951 0.946 0.940 0.934 0.928 0.922 0.915 0.908 0.901 0.894 0.886 0.878 0.870 0.862 0.854 0.845 0.836 0.827 0.818 0.809 0.799 0.789 0.780 0.770 0.760 0.750 0.740 0.730 0.719 0.709

HCOOK (Wt%)

HCOOK (g/L)

Initial H20 (ml/l)

Density (SG)

Correction Factor

Potassium (mg/l)

kg HCOOK / m3 H2O

Activity

41.0 42.0 43.0 44.0 45.0 46.0 47.0 48.0

521.44 537.50 553.73 570.13 586.71 603.46 620.38 637.48 654.76 672.21 689.84 707.65 725.64 743.82 762.19 780.76 799.54 818.52 837.71 857.14 876.80 896.71 916.88 937.32 958.06 979.11 1000.49 1022.22 1044.33 1066.84 1089.79 1113.20 1137.10 1181.54 1186.56

751.7 743.6 735.3 726.9 718.4 709.7 700.8 691.8 682.7 673.5 664.0 654.4 644.7 634.8 624.7 614.6 604.2 593.8 583.2 572.5 561.6 550.6 539.5 528.2 516.8 505.3 493.7 481.9 470.0 458.0 445.9 433.7 421.3 408.8 398.2

1.269 1.277 1.285 1.293 1.301 1.309 1.318 1.326 1.334 1.342 1.350 1.358 1.367 1.375 1.383 1.392 1.400 1.409 1.417 1.426 1.435 1.444 1.453 1.462 1.471 1.481 1.491 1.500 1.511 1.521 1.532 1.543 1.555 1.567 1.579

1.3303 1.3448 1.3599 1.3756 1.3920 1.4091 1.4269 1.4454 1.4648 1.4850 1.5081 1.5281 1.5512 1.5754 1.6007 1.6272 1.6550 1.6841 1.7147 1.7469 1.7807 1.8162 1.8537 1.8932 1.9349 1.9790 2.0267 2.0751 2.1275 2.1832 2.2425 2.3058 2.3734 2.4459 2.5238

242363 249826 257369 264993 272697 280482 288348 296296 304325 312436 320630 328908 337272 345722 354262 362893 371618 380440 389363 398391 407529 416783 426167 435661 445300 455083 465020 476121 486397 495861 506525 517405 528517 539876 551503

692.65 721.78 751.94 783.18 815.53 849.08 883.92 920.09 957.67 996.75 1037.44 1079.80 1124.00 1170.10 1218.26 1268.59 1321.28 1376.46 1434.35 150370.22 1559.02 1626.27 1697.16 1772.00 1851.11 1934.88 2023.72 2118.10 2218.58 2325.77 2440.31 2563.08 2694.92 2836.91 2990.26

0.699 0.689 0.678 0.668 0.658 0.648 0.638 0.627 0.617 0.607 0.597 0.587 0.576 0.566 0.556 0.546 0.535 0.526 0.514 0.504 0.493 0.482 0.471 0.459 0.447 0.436 0.423 0.409 0.396 0.381 0.366 0.350 0.333 0.314 0.294

49.0 50.0 51.0 52.0 53.0 54.0 55.0 56.0 57.0 58.0 59.0 60.0 61.0 62.0 63.0 64.0 65.0 66.0 67.0 68.0 69.0 70.0 71.0 72.0 73.0 74.0 75.0

19

Section

18b

metric salt tables

Table 18 – Formulating Potassium Sulphate Brine Weight (%)

Density (SG)

K (mg/L)

SO4 (mg/L)

K2SO4 (kg/m3)

Water (m3)

Cryst. Pt. (˚C)

0.5

1.004

2,244

2,756

5.1

0.1585

-0.1

1.0

1.008

4,532

5,568

10.0

0.1584

-0.3

1.5

1.012

6,821

8,379

15.1

0.1582

-0.1

2.0

1.016

9,110

11,190

20.3

0.1580

-0.5

2.5

1.020

11,443

14,057

25.4

0.1579

-0.1

3.0

1.024

13,776

16,924

30.5

0.1577

-0.1

3.5

1.028

16,110

19,790

35.9

0.1576

-0.1

4.0

1.032

18,488

22,712

41.1

0.1573

-0.1

4.5

1.037

20,911

25,689

46.5

0.1571

-1.1

5.0

1.041

23,290

28,610

51.9

0.1569

-1.2

5.5

1.045

25,758

31,642

57.3

0.1568

—

6.0

1.049

28,181

34,619

62.8

0.1565

—

6.5

1.053

30,649

37,651

68.2

0.1563

—

7.0

1.057

33,162

40,738

73.9

0.1560

—

7.5

1.061

35,675

43,825

79.3

0.1558

—

8.0

1.066

38,188

46,912

85.0

0.1557

—

8.5

1.070

40,746

50,054

90.7

0.1553

—

9.0

1.074

43,304

53,196

96.4

0.1552

—

9.5

1.078

45,907

56,393

102.1

0.1549

—

10.0

1.083

48,509

59,591

107.8

0.1547

—

1.0 - (m3 water) % volume salt = 100 x ( ) 0.159 Properties based on 20 °C and 100% purity

20

corporate directory CORPORATE Scomi Group Bhd 5th Floor Wisma Chase Perdana Off Jalan Semantan Damansara Heights 50490 Kuala Lumpur Malaysia Tel : +603 2080 5080 Fax : +603 7490 5131 Scomi Oiltools (S) Pte Ltd 1, Raffles Place #26-01 OUB Centre Singapore 048616 Tel : +65 6324 5338 Fax : +65 6324 5331 OPERATING LOCATIONS ALGERIA BP 429, Zone Industrielle Bir Messaoud Hassi Messaoud W, Ouargala AMERICA-LATIN (ANACO) Av Jose Antonio Anzoategui Sector “El Cinco” Anaco Estado Anzoategui, Venezuela AMERICA-LATIN (BARINAS) Urbanizacion Alto Barinas Av Los Andes, C C Dona Grazla Piso 2, Ofc 4, Barinas Estado Barinas Venezuela AMERICA-LATIN (CIUDAD OJEDA) SA Avenida Intercomunal Calle Arague, Sector La Playa #12 Ciudad Ojeda Estado Zulian, Venezuela AMERICA-LATIN (MATURIN) SA Av Raul Leoni Urbanizaction Juanico Torre Empresarial Juanico piso 7 ofic 7-3, Maturin Estado-Monagas, Venezuela AMERICA-NORTH (BAKERSFIELD) 6000, “C” Schirra Court Bakersfield, California 93311 USA AMERICA-NORTH (BRIDGEPORT) Scomi Oiltools Inc 5762, HWY 380 Bridgeport Texas 76426 USA AMERICA-NORTH (BROUSSARD) Scomi Oiltools Inc 216, Milestone Road Broussard, LA 70548, USA

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Drilling Fluids Manual Handbook

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