Baroid SOPs

Standard Operating Procedures Review and Update in Progress These pages came from the original Well BluePrint documents that were in the Information Reservoir. In 2005 minor edits were made to delete inactive products and add some product replacements. Some edits were made to the Lost Circulation section by a subject matter expert. Other than those edits, these topics have not been changed since 1997.

Contents Anhydrite/Gypsum Drilling Barite Plugs Barite Sag Bit Balling Carbon Dioxide (CO2) Cement, Drilling Corrosion Depleted Sands/Differential Sticking DRIL-N Systems Filter Cake/Filtration Control Fluid Displacements Fractured Limestone, Drilling Gas Hydrates Gunk Squeezes Hole Cleaning Hole Stability Horizontal Drilling High Temperature Wells Hydrogen Sulfide (H2S) Lost Circulation Mechanical Sticking Permafrost, Drilling Quality Assurance Safety Salt Drilling Shale Drilling Sliding Slim Hole Drilling Solids Control Stuck Pipe Torque and Drag Well Control

Drilling Conditions Anhydrite/Gypsum Drilling

SOP Code: DG Revision Date: 02/10/1997; Amended May 2005

Anhydrite/Gypsum Drilling Introduction H2O) or Anhydrite (CaSO4). It is found in thick Calcium sulfate occurs in nature as Gypsum (CaSO4 sections, stringers, in make-up water, embedded in silts as in evaporite formations and sometimes in the caprock of a salt dome. Causes of Anhydrite/Gypsum Contamination Calcium sulfate causes aggregation and flocculation of a fresh water mud, resulting in thickening. The calcium sulfate causes an increase in apparent viscosity, yield point, gel strength and filtrate. The partially soluble calcium sulfate increases the hardness and sulfate content of the filtrate. If a calcium base mud is in use, the calcium sulfate contamination has little or no effect on the mud properties. Preventing and Curing Anhydrite/Gypsum Contamination A common method of drilling anhydrite or gypsum formations is to pre-treat the mud with thinners that works effectively in the presence of calcium and sulfates and alkali's. The contamination of the mud by the drilled calcium sulfate is nullified.If it is desired to maintain a fresh water mud after calcium sulfate contamination has occurred, it is necessary to treat out the ions that cause aggregation and flocculation. This may be done by adding soda ash (Na2CO3) or Barium carbonate (BaCO3). Na2CO3 + CaSO4 = CaCO3 (precipitate) + Na2SO4 The calcium is precipitated as insoluble calcium carbonate (limestone). A general rule is to add 0.02 lb/bbl of soda ash for every epm of hardness. After adding the soda ash, a thinner is usually added to reduce the viscosity and gel strength. A difficulty is encountered if large amounts of soda ash are added. The soluble sodium sulfate tends to build up and cause "ash gels" which are indicated by high progressive gel strength. Another method to treat out calcium sulfate contamination is to treat the thickening and filtration increase that has occurred and let the system become an aggregated-deflocculated one. This can be done by using a thinner, adjusting the pH and using a fluid loss controller. If a high pH is maintained, this too may result in "ash gels" due to the formation of sodium sulfate. If high sodium sulfate (Na2SO4) occurs, it will require water dilution and lime additions for alkalinity.

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Drilling Conditions Anhydrite/Gypsum Drilling

Contaminant

Contaminant Compound/ ion

Contaminant Source

Method of Measurement

Possible Course of Action Effect on Mud

Anhydrite/

CaSO4

Formation

Ca+2

High Yield Point

Treat with Soda Ash

Gypsum

CaSO4 + H2O

Commercial

titration

High Fluid Loss

Ca+2(mg/L) x 0.00093 = lb/bbl Na2CO3

Ca+2

Gypsum

High gels

or

Thick filter cake

Ca+2 (epm) x 0.0188 = lb/bbl Na2CO3

Ca+2increase pH decrease

Break over to a gypsum mud

Materials and Systems Mud systems to use if thick sections of Anhydrite/gypsum are expected: • POLYNOX® • GYPSUM • MUD Chemicals to treat out calcium sulfate contamination: • Soda Ash (CaCO3) • Barium Carbonate (BaCO3) • Caustic products Products to condition mud after Calcium has been removed: • QUIK-THIN™ Thinner • LIGNOX® PLUS Thinner • DEXTRID® Filtration Control Agent • PAC™ Filtration Control Agent

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Drilling Conditions Barite Plugs

SOP Code: BP Revision Date: 02/12/1997; Amended May 2005

Barite Plugs Introduction Barite plug use is normally limited to extreme or emergency conditions where it is imperative that some measures be taken to seal off the bottom section of the wellbore. This type of plug is applicable in several situations including: •

Simultaneous kicking and lost circulation.

•

Abandonment procedure allowing safe withdrawal of drill pipe to allow setting of cement plug.

•

Withdrawal of drill pipe to either set casing or repair existing casing strings.

•

Plugging drill pipe in emergency situations.

•

High pressure salt water flows where required kill mud weight approaches or exceeds the formation breakdown equivalent at some point in the open hole, usually the last casing shoe.

Objectives of Setting Barite Plugs A barite plug is basically a slurry of barite that is pumped down the drill pipe and placed at the bottom of the wellbore. A successful Barite plug should accomplish two things: Initially, the weight of the barite slurry should kill the well. After a period of time, the settled barite plug should mechanically block any flow up the wellbore. The well should be killed before a mechanical blockage is established in the wellbore. Barite Plug Design Designing a barite plug for killing a well is straightforward. The barite slurry pumped into the well must be heavy enough and fill enough of the wellbore to increase the bottomhole pressure to a level exceeding the formation pressure. Problems arise when formation pressure is unknown or when weight or volume of the required barite slurry become excessive. Designing a barite plug to physically block the wellbore is somewhat more complicated. The generally accepted method is to mix a slurry so that the barite settles out from the slurry into a hard plug which will block the wellbore. The rate that barite will settle into a hard plug is usually slow and predictable. Fairly accurate field predictions may be made from an observation of the initial barite settling rate in a small container. The initial rate is constant and independent of the height of the slurry. The initial settling rate lasts for a short period of time, after which the settling rate decreases as fewer barite particles remain in suspension. In a container one foot high, the initial settling rate applies for approximately five minutes. In a field situation with 500 or more feet (150 or more meters) of barite slurry, the initial rate may apply for a day or longer. The amount of barite settling in a shorter period can be computed as the product of the initial rate times the waiting time.

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Field experience has shown that slurries of up to 20 lbs/gal (2.40 SG) are relatively easily prepared using only Base Oil, EZ MUL (Oil Wetting Agent), DRILTREAT and Barite for oil muds. Water, SAPP, caustic soda and barite are used for water-based muds. Preparation From a practical point of view, the following points should be considered: Use of a cement unit is preferable. This requires that either bulk barite be fed directly to the cement unit surge tank or that sufficient stocks of sacked barite be available at the rigsite. Standard plugs can be mixed to the desired density with no problems of massive settling before displacement. Oil Mud Application Barite plug settling rates in oil muds are normally dependent on the density of the slurry and the type and concentration of oil wetting agents. Laboratory studies have shown that oil-based plugs have a tendency to settle, on average, more slowly than water-based slurries. At too low a concentration of EZ MUL and DRILTREAT the barite is insufficiently oil-wet and is not self-suspending. At too high a concentration the barite becomes extremely well suspended and the rate of settling is reduced. It is therefore very important to carefully select the optimum concentration of EZ MUL for the plug density required. If a cement unit is not able to mix barite, use a slug pit or the reserve mud pits, depending on the total volume of slurry required. The length of the plug is a well site determination to be based on the severity of the situation. In most cases a plug in the range of 250 - 500 ft (75-150 m) is sufficient. Oil-Based Mud Procedure Oil-based mud slurries can be mixed as follows: 1. Transfer sufficient oil-based mud to the slug pit to maintain circulation through the mixing pump. 2. Fill pit to half its capacity with base oil and add approximately 4 lbs/bbl (11.4 kg/m3) EZ MUL and 4 lbs/bbl (11.4 kg/m3) DRILTREAT. 3. Weight up with barite to required density; the pit should then be nearly full. 4. If total capacity of the slug pit is insufficient for the required volume of plug, transfer the slurry already mixed to a reserve pit making sure that agitators are used constantly and another mixing pump put on to circulate that pit. The Engineer on site should ensure that the following measures are also adhered to: • To avoid the chance of initiating rapid settling, excessive additions of base oil are not made at any stage. • Small additions of up to 1.5 lbs/gal (4.3 kg/m3) EZ MUL may be made to control viscosity increases noted during barite additions. • Barite addition rate is controlled to avoid excessive increases in viscosity or possibly initiating settling.

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Formulations for oil-base muds: 18.0 lbs/gal

19.0 lbs/gal

20.0 lbs/gal

Base Oil (bbls)

0.582

0.547

0.513

EZ MUL (lbs)

4

4

4

DRILTREAT (lbs)

4

4

4

Barite (lbs)

597

650

700

Water-Based Mud Application The slurry is composed of barite, fresh water, sodium acid pyrophosphate (SAPP) and caustic soda. SAPP, a thinner, increases the barite settling rate by lowering the yield point and gel strength of the slurry, and the caustic soda is added to provide an alkaline environment (pH = 10). Formulation for one barrel of a 20 lbs/gal barite slurry is: Material

Amounts

Fresh water

0.56 bbls

Caustic soda

0.25 lbs

Barite

656 lbs

SAPP

0.7 lbs

Or Material

Amounts

Fresh water

0.56 bbls

Caustic soda

1.0 lbs

Barite

656 lbs

QUIK-THIN™ Thinner

8 lbs

Displacement Displacement techniques are the same as in cementing; i.e., the slurry should be under displaced so that the height of the slurry in the drill pipe is 2 bbls greater than in the annulus. This allows the drill pipe to be withdrawn with a natural slugging action and will minimize movement of the slurry in the hole, reducing contamination.

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Because of the high density of these slurries, high differential pressures can be created by under or over displacement. Care must be taken when calculating volumes. After the plug is spotted in place, tripping out of the hole should be done as quickly as possible and the plug allowed to settle for several hours. The well should be observed to ensure there is no flow. When tripping back into the hole, "feeling" for the plug should begin near the theoretical top of the plug. Operations can then be started to set a cement plug above the barite, and the well can be safely secured.

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Drilling Conditions Barite Sag

SOP Code: BS Revision Date: 02/10/1997; Amended May 2005

Barite Sag Introduction When weighted muds are used in highly deviated wells, there is the tendency for barite to settle towards the low side of the hole, creating a stratification of lighter mud on top and heavier mud on bottom. The heavier layer then begins to migrate downwards along the length of the hole due to the gravitational pull. This continuous movement of the mud prevents the development of more substantial gel strengths, compounding the settling problem. Variations in hydrostatic head can cause formation fracturing with accompanying loss of circulation, possibly leading to an influx of formation fluids. Barite sag can be troublesome and time consuming to correct, and therefore, very expensive. While sag is more of a problem in angled wells, it has also been observed in vertical wells. Causes Incidents of barite sag have been reported on highly extended or deviated wells numerous occasions since the mid 1980's. Sag can occur in either dynamic or static conditions, and may be indicated by variations in mud weight when circulating. Hole conditions which may influence sag tendency are: •

Temperature - Higher temperatures increase sag tendency. Hole angle - Sag tendency is increased in deviations >30°.

•

Static time - Although sag can occur under dynamic conditions, its effects are usually not apparent until the mud system has been static for a considerable period of time - after tripping, logging or running casing.

•

Semi-Static conditions - Minor movements which break gels, such as tripping pipe or running wireline logs increase sag tendency. Slow circulation rates can create conditions likely conducive to sag. Hydrocarbon influxes can affect mud rheological properties

Mud properties which influence sag tendency are: •

Rheology, Surface vs. Downhole - Sag occurs even when traditional rheology measurements taken under surface conditions (high PV, YP and Gels) indicate that it should not. When measured under downhole temperature and pressure conditions on a FANN® 70 viscometer, muds which exhibit sagging behavior in the well usually demonstrate different rheology and suspension characteristics than their normal surface measurements. The degree of variance between surface and downhole rheology is to some extent a measure of the stability of the mud system. The less variance the more stable the mud system. A key factor that effects the variance in rheological behavior in an invert emulsion mud system is the type of base oil used. The base oil's viscosity versus temperature behavior is critical.

•

Mud weight - Variations in density will be more pronounced at higher mud weights.

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Drilling Conditions Barite Sag

Preventing and Curing Barite Sag Rheology The Hershel-Bulkley/Yield-Power Law model better correlates with lab measured sag coefficients, since it more accurately describes fluid behavior at low shear rate. A fluid Tau0 (yield stress) of 7 to 8 lbs/100 sq ft will normally be enough to reduce the static sag in field muds to acceptable levels. Check the mud rheology at elevated temperatures (e.g. 120°F) to obtain an indication of downhole rheology. Use FANN® 70 testing before the well to optimize mud product concentration for stable downhole mud rheological properties. Testing with special apparatus called the High Angle Sag Tester (HAST) simulates downhole conditions and shows whether a fluid requires special additive treatments to improve suspension properties. Additions of DURATONE have been shown to reduce sag tendency. Mud Weight Maximum and minimum mud weights should be recorded when circulating bottoms up after trips in deviated wells, especially after logging. It is important to maintain uniform mud weight throughout the circulating system. Efforts should be made to treat and equalize any imbalance as quickly as possible. If the equivalent circulating density (ECD) is close to the fracture gradient, this could require circulating until density is homogeneous prior to resuming drilling operations. Note: When using invert emulsion muds in high temperature wells, it is important to measure the temperature at which the mud weight is recorded to avoid misinterpretations between barite sag and thermal expansion/contraction effects. Oil/Water Ratio HAST tests have shown that decreasing the oil/water ratio decreases sag tendency. Materials and Systems The best treatment to prevent barite sag is to ensure sufficient gels and low end rheology. In waterbased muds this can be achieved with several products, including AQUAGEL™ and AQUAGEL™ GOLD SEAL, and polymers such as BARAZAN® PLUS. In oil-based and synthetic muds the use of low end rheological modifiers such as RM-63™ in conjunction with GELTONE® and SUSPENTONE™ (a suspension agent for invert emulsions) have been used successfully to prevent barite sag.

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Drilling Conditions Bit Balling

SOP Code: BB Revision Date: 02/10/1997; Amended May 2005

Bit Balling Introduction Balling occurs when clay based drilled solids adhere together and cling to the metal surfaces of the bit and pipe. Bit balling usually occurs while drilling shale. Clay adhesion is a function of the electrochemical attraction of clay to clay solids and clay to metal (surface tension). The reaction begins when clay solids become wet and hydration/dispersion of the clay occurs. Adhesion magnitude is determined by the degree of clay hydration, the chemical properties of the clay, chemical composition of the mud's aqueous phase, and the proximity between reactive solids or the solids concentration. Massive concentrations of reactive solids can overwhelm most mud systems. Balling will normally slow down the rate of penetration (ROP). ROP will not respond to rotary RPM increases or weight on the bit, this may result in pulling a bit before it is due to be replaced. Causes Balling can occur with any hydratable clay. Clays particles can adhere to each other or metal surfaces, given the right water and solids ratio. Therefore, reduction of adhesion and/or balling can be achieved by controlling hydration and/or solids concentration. Bit balling is more of a problem when using water-based muds. When invert emulsions are used, bit or bottom hole assembly (BHA) balling normally does not occur. For bit and or BHA balling to take place two or more of these conditions must exist: •

A reactive clay formation must be present.

•

Water must be available for the clays to become hydrated.

•

Cuttings are compressed - causing adhesion.

•

Sufficient concentrations of electrochemically attractive clays.

•

Inadequate bit cleaning due to poor hydraulics.

•

Electrochemical attraction of clay to metal.

Procedures to Prevent Balling It is important to limit the concentration of cuttings in the annulus. When large volumes of dispersible solids or cuttings are generated into a specific volume of drilling mud, an infinite amount of surface area is created. If these cuttings are not quickly removed from the area of the bit, the electrochemical attraction of the clays for metal will cause these cuttings to adhere to the bit. The following procedures can aid in cuttings removal. Control ROP vs Flow Rate High concentrations of mud solids and drilled solids lead to bit balling. This is a function of mud composition and ROP vs flow rate. Excessive penetration rates relative to flow rates can create a massive concentration of reactive solids in the annulus. Therefore, when drilling "clay type" 1


formations, the low gravity solids concentration in the mud should be maintained as low as possible (5% by volume or less). In addition, the cuttings concentration in the annulus should be limited to 4% by volume by coordinating the flow rate and ROP. This may require controlling instantaneous rates of penetration. Sweeps Depending on hole deviation, high viscosity and/or low viscosity sweeps can be used to effectively remove cuttings from the wellbore. The turbulence of the low viscosity sweep stirs the cuttings bed and the high viscosity fluid carries the solids to the surface. Use BARAZAN® PLUS and N-VIS® (instead of commercial bentonite) to increase viscosity and avoid increasing the clay content of the mud system. Bit Type and Hydraulics Fluid dynamics such as velocity and turbulence are critical for cleaning the bit and preventing balling. Create high velocity and a high degree of turbulence. Flow rates alone are not the key. Fluid viscosity and/or turbulence at the bit are functions of fluid composition and velocity. Solids surface area is the limiting factor for a drilling fluid to shear thin. Therefore, optimizing solids concentration is critical for effective fluid dynamics at the bit. Hydraulic horsepower at the bit must be optimized. Bit design can contribute to bit balling. AntiBalling (AB) coated bits are recommended. Hole Wiping Frequent short trips in directional wells are very beneficial for reducing the buildup of cuttings beds. The cuttings bed is disturbed by the bit so it can be removed by annular flow, after circulation is resumed. This technique will also help reduce pack-off and gumbo attacks. Balling Reduction by Mud Composition Solids adhesion can be reduced by neutralizing the attractive charges on clays by ionic satisfaction, i.e., sodium, calcium, potassium, cationic and anionic polymers, and surface active agents (surfactants). Balling severity is reduced by limiting the "specific surface area" of reactive solids within the fluid. This process is partially accomplished by preventing hydration and dispersion of drilled solids with inhibitive drilling fluids. Among the basic fluids for consideration are those that contain chloride, calcium, potassium, cationic additives, surfactants, oil, esters, formates, silicates, glycols, and the multiple combinations of these basic ingredients. Effective mud systems include: • INVERMUL®

• CLAYSEAL®

• PETROFREE®

• BARASILC™

• CAT-I®

• GEM™

• EZ-MUD™

• POLYNOX® 2


pH control is an important consideration since the hydroxyl ion is dispersive. First, hydroxyl ions promote hydrogen bonding of water molecules to the steel surfaces. Second when the hydroxyl ion is hydrated, its large volume of associated water forces clay platelets and layers apart. This dispersive action increases as the pH is increased. pH ranges should be adjusted to coincide with the inhibitive nature of the mud system being used. Minimizing the clay concentration by solids removal equipment and dilution of reactive solids also reduces the "specific surface area" available for adhesion and balling. Commercial bentonite can aggravate the problem, it should be added very cautiously. When balling is a potential problem, low gravity solids should be maintained at 5% or less by volume and the equivalent bentonite concentration should be 20 lbs/bbl (57 kg/m3) or less, determined by the methylene blue test. Encapsulate cuttings with EZ-MUD™ to prevent dispersion and mechanical degradation. Coating solids with EZ-MUD will have two beneficial effects. It binds a solid to prevent dispersion and, it provides lubricious film that allows solids to slide past one another thus preventing mechanical disintegration. Adding DRIL-N-SLIDE™ will reduce electrochemical attraction of clay to metal. Treatments Associated with Cleaning Balled Bits and Assemblies These pills can be spotted or circulated through the bit and annulus, to help eliminate balling problems. Hydrostatic pressures must be maintained when utilizing these pills. The appropriate pill will depend on the mud type being used, materials available on the rig, formation sensitivity, and safety/environmental concerns. Caustic Pill A caustic pill can be spotted or circulated through the bit. Caustic can be mixed in freshwater or seawater to accelerate the hydration and dispersion of a reactive clay. Greater turbulence and a jetting action is formed in the balled area, when pumping water. CON DET™ Pill (Detergent) This pill is usually made up of whole (active) mud with 3 - 20% CON DET. This also can be done with fresh water and circulated through the bit. CON DET performs by reducing surface tension, increasing lubricity, and reducing the sticking tendency of the clay. If using whole mud, mud weights can be maintained. Note: Detergents may effect several aspects of a drilling fluid system i.e., foaming, environmental concerns. WALL-NUT® Pill This pill is made up of whole (active) mud. WALL-NUT® comes in three available sizes; fine, medium, and coarse. WALL-NUT® can be mixed from 5 to 60 lbs/bbl (14 to 171 kg/m3) depending on the mud type and mud weight. This pill is pumped down and through the bit with high pump rates to physically erode the ball of clay adhering to the bit or drill string.

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SAPP or QUIK-THIN™ Pill (Dispersant) A highly concentrated dispersive pill can be mixed in water or whole mud. This pill is designed to disperse balled up bits and assemblies. High pH ranges can also aid in dispersing clays. QUIKTHIN™ Thinner may be used up to 20 lbs/bbl (57 kg/m3). SAPP may be added from 1 to 3 lbs/bbl (2.85 to 8.5 kg/m3). Do not use SAPP in high Calcium environments. Note:

These pills are highly dispersive and can cause wellbore washout.

Surfactant Pill Highly concentrated blends of surface active agents can be added directly to the suction pit, dumped down the drill pipe on connections or sprayed directly on the bottom hole assembly. These blends will lower the surface tension of the water and help neutralize the surface charges of the clays, minimizing hydratable clay adhesiveness. EZ-MUD™/CLAYSEAL® Slugging the pipe on connections with neat EZ-MUD™ or CLAYSEAL®.

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Drilling Conditions Carbon Dioxide (CO2)

SOP Code: CO2 Revision Date: 01/02/1998; Amended May 2005

Carbon Dioxide (CO2) Introduction Carbon dioxide (CO2) is a common constituent of natural gases and is present in most types of formation fluids. Carbon dioxide dissolves in water, forming carbonic acid that lowers the pH. This lowers the alkalinity of water-based muds changing hydroxyl ions (OH-) to bicarbonates (HCO3-) and carbonates (CO3-2) ions. Carbonates can be introduced into water-based muds from: • Carbon dioxide from drilled gases and formations. • Carbonates associated with drilling mud products i.e., barite, bentonite, lignite, etc. • Sodium carbonate and sodium bicarbonate overtreatments • Organic thermal degradation • Causes and Symptoms of CO2/Carbonate Problems The effect of CO2 contamination on any drilling fluid mud can be severe if corrective treatments are not made. Carbon dioxide can also cause severe corrosion problems if not treated. CO2 contamination (carbonates) can adversely affect drilling fluid properties. Gel strengths become progressive and the yield point increases as the drilling fluid becomes flocculated. The mud may have a dull/flat appearance, and the funnel viscosity is higher at the flowline than the viscosity at the suction pit. The drilling fluid may become extremely thick on bottoms up after periods of static condition, such as a long or short trip. Water-based drilling fluids contaminated with CO2 can have decreases in pH, Pm, or Pf . CO2 contamination can create a condition where the Pf , pH and solids may all be in the desired range, but, due to the lack of hydroxyl ions the rheological and filtration values do not respond to treatments. Deflocculants such as QUIK-THIN™ thinner require hydroxyl ions to perform properly. These conditions can create problems downhole, such as increasing the: Equivalent circulating density (ECD) of the drilling fluids • Surge and swab pressures • Chances of becoming stuck • Potential for lost circulation Preventing/Curing a CO2/Carbonate Contamination Problem If the contamination is from a CO2 influx, increase mud weight to stop further influx, if possible, then treat out the carbon dioxide. Even high density fluids contaminated with CO2 can be controlled satisfactorily provided the fluid contains low concentrations of bentonite and reactive drilled solids. Pretreat the system with BARACOR® 95 (a highly active inhibitor that is stable up to 350°F [177°C]) if high levels of carbon dioxide are anticipated. BARACOR® 95 has proven to be an effective tool in eliminating the flocculation effects seen with large CO2 influxes. BARACOR® 95

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Drilling Conditions Carbon Dioxide (CO2)

does not eliminate the CO2, it scavenges the gas downhole to form a BARACOR® 95•CO2 complex, rendering it inert. Traditional lime additions at the surface liberates the CO2 from the BARACOR® 95. The CO2 then reacts with lime to form insoluble calcium carbonate. This process re-activates the BARACOR® 95 without consuming it. BARACOR® 95 does not replace surface lime additions as it is the two-step process that efficiently removes the CO2. Testing for CO2/Carbonate Contamination The presence and quantity of CO2 in the filtrate may be determined by two different methods, Garrett Gas Train and back titration. The Garrett Gas Train will indicate the total amount of carbonates in the filtrate. Back titration will determine the amounts of carbonates, bicarbonates and hydroxides in the filtrate. Treating CO2/Carbonate Contamination After accurate testing for alkalinity changes, a treatment plan can be made and verified through pilot test and hot rolling. Treatments should begin as soon as CO2 contamination has been verified. CO2 can be removed effectively by treating with caustic soda (sodium hydroxide, NaOH) and lime (calcium hydroxide, Ca(OH)2). Lime treatments are preferable because contaminant are removed from solution, as shown in the reactions below. All reactions shown are reversible, dependent on the pH of the fluid and lime or caustic soda concentration. H2CO3 CO2 + H2O Carbon Water Carbonic Dioxide Acid Na2CO3 + 2H2O H2CO3 + 2NaOH Carbonic Sodium Sodium Water Acid Hydroxide Carbonate CaCO3 \ + 2H2O H2CO3 + Ca(OH)2 Carbonic Calcium Calcium Water Acid Hydroxide Carbonate (Precipitate) Lime is the most commonly used product and should be added at a rate of 0.0130 lbs/bbl (0.037 kg/m3) lime per epm of carbonates. Thinners may be needed to deflocculate the system after the carbonates have been treated, but the over use of thinners can itself be a problem. BARAFILM™ (a filming agent) is recommended in cases of severe contamination to minimize or reduce corrosion problems by laying a protective film on the drill pipe. Maintain 200 mg/L calcium in the filtrate to buffer the contamination. Avoid overtreatments of soda ash or sodium bicarbonate when drilling cement.

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Drilling Conditions Cement, Drilling

SOP Code: CD Revision Date: 03/05/1997; Amended May 2005

Cement, Drilling Introduction From a mud viewpoint, drilling cement introduces two main contaminants. The major contaminant is calcium ion and the second contaminant which compounds the problem is hydroxide ions. Invert muds are largely unaffected by the flocculating effects of increased calcium content, pH and solids increases. However green cement will reduce base fluid - water ratios and in turn emulsion stability. Whenever possible, drill out cement with seawater or expendable water-base mud prior to displacing to invert muds. water-base muds however can experience severe complications if precautions are not taken. Freshwater systems with a high bentonite content or EZ-MUD™ systems are considered the most sensitive to cement contamination. Generally, the rheological properties, filtration properties and pH will show a dramatic increase as clay particles and polymers are flocculated by the calcium in combination with the high pH. EZ-MUD™ systems will liberate NH3 as the PHPA breaks down. At high temperature (>250oF), severely contaminated bentonite based muds can solidify. Precautions Proper planning and pretreatment will serve to minimize problems associated with high flocculation, plugged flowlines and cement contaminated surface equipment. The following precautions should be made if it is planned to drill cement, particularly when there is a risk that the cement is green. If it is possible, drill out as much of the cement with seawater if a ready supply is available. Pretreat water-base muds with sodium bicarbonate 0.25-0.50 lb/bbl (0.70 - 1.50 kg/m3). Closely monitor mud returns at the shale shakers and immediately dump any green cement or badly contaminated water-base mud. If large cement sections have to be drilled and treatments are not sufficient to counter the effects of the cement, convert to a lime-based system that tolerates high cement levels such as POLYNOX®. Normal Treatments Under normal conditions, if the cement was displaced with a spacer and treated mud, the quantity of cement to be drilled will be manageable. A pretreatment with bicarbonate at 0.75 ppb (2.1 kg/m3) for 20" casing or 0.25-0.5 lb/bbl (0.70 - 1.50 kg/m3) for 13" or 9" casing will be sufficient. SAPP in very low concentration can also be used to effectively deflocculate the mud to reduce flocculation from the cement. Mud returns should be closely monitored to adjust further treatments with additional bicarbonate and water. Conversion to a lime-based system Should it be necessary to convert to a lime-based system, the conversion can be carried out while drilling cement. The first step is to reduce the solids and MBT below 17.5 lb/bbl (50 kg/m3) with heavy dilution, followed by a treatment of 2 ppb (5.7 kg/m3) caustic soda and 3 ppb (8.55 1

Drilling Conditions Cement, Drilling

kg/m3) CARBONOX®. The increased pH of the filtrate will suppress calcium solubility and retard the solidification of the fluid. During the breakover to a lime system, it is possible to experience a "viscosity hump". Lime and caustic additions must be made to continue going over the hump. If the pH is allowed to drop, the conditions will become worse and the mud will remain viscous. A lime mud can be checked for a full breakover by adding more lime. If the fluid takes the lime without a viscosity increase, the mud is considered broken over. (Refer to the Baroid Handbook for guidelines in running lime-base muds) Summary When drilling cement with or without WBM, it is critical to be fully aware of the potential problems. It is prudent to pretreat and be prepared for the worst conditions than attempt to treat after the problem comes to surface. Nothing is certain when preparing to drill cement because of uncontrollable variables such as channeling of cement, varying hardnesses and varying degrees of interface. In many cases, economics will dictate the treatment. It may be more economical to discharge large quantities of contaminated mud and cement than to treat and risk contaminating / recirculating cement through the surface system. Many days have been lost cleaning cement from the bottom of mud pits. The key is preparation and planning for the worst case.

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Drilling Conditions Corrosion

SOP Code: C Revision Date:

02/10/1997; Amended May 2005

Corrosion Introduction The process of corrosion encompasses several phenomena which can be defined as the decomposition of iron or steel - the primary metallic component of drilling equipment. Corrosion is inevitable, but it can be controlled so that it does not happen as rapidly, or does not concentrate in any one area. Corrosion monitoring and treatments for corrosion control will depend to some extent on the type of drilling fluid being used and the causes of corrosion. Preventive treatment should always be considered, a drill string or casing failure can be extremely expensive. Causes Corrosion may be defined as the destruction of metal through electrochemical and mechanical action between the metal and its environment. Corrosion can be accelerated by physical stresses that change the crystalline structure of steel and by the chemical composition of the environment; i.e., drilling fluid. Severe pipe failures are generally caused by a combination of both. The major contributors of chemical corrosion in a drilling operation are: • Oxygen • Hydrogen sulfide • Carbon dioxide • Salts • Mineral scale Oxygen Oxygen is present in every drilling operation and causes a major portion of damage to drilling equipment. Oxygen in the presence of hydrogen sulfide, salts or carbon dioxide, even in small quantities, has a more severe effect. Sources of oxygen in drilling fluids are water additions and air entrapment. Oxygen corrosion can be severe when air drilling or when using aerated drilling fluids. Carbon Dioxide Carbon dioxide is generally present in significant quantities due to degradation of organic additives and from formations which contain a carbon dioxide source. Carbon dioxide acts in several ways, as a catalyst to oxygen, as an acid/corrosive agent (carbonic acid) and as a scale producer, reacting to form carbonates.

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Hydrogen Sulfide Hydrogen sulfide is an extremely toxic and dangerous contaminant that enters the drilling fluid from the formation. Sulfide reducing bacteria present in the drilling mud system can also be a source of hydrogen sulfide. It is extremely corrosive because it is acidic when it is in solution. Hydrogen sulfide corrosion (hydrogen embrittlement or sulfide stress cracking) has a significant corrosive effect on metal. Salts Salts added to the mud system for inhibition may cause some corrosion problems, because they provide a strong electrolytic environment, which accelerates the passage of ions through the drilling fluid. Mineral Scale Mineral scale deposits set up conditions for local corrosion cell activity. Minimizing Corrosion Several steps can be taken to minimize corrosion. These range from proper fluid engineering, avoidance of air entrapment and foaming, maintenance of adequate pH, and the use of specialty products designed to either eliminate the contaminant or to reduce the effects of corrosion. Corrosion prevention products include scavengers that neutralize the corrosive agents, filming agents that protect the metal surfaces, and scale removers. Drill pipe corrosion coupons can be used to monitor type and rate of corrosion. These coupons may be sent to Baroid's laboratory for analysis where the coupon corrosion rate is determined by weight loss and exposure time calculations. Materials and Systems Oxygen Since the prime source of oxygen contamination is from the atmosphere, rheologies should be maintained to minimize air entrapment and defoamers should be available at the rig site. BARASCAV™ D or BARASCAV L (oxygen scavengers) can be used to tie up the active oxygen. BARACOR® 700 is designed to prevent oxygen corrosion in water-based drilling fluids, specifically in mist, air or foam applications. BARACOR® 1635 can also be used in mist, air or foam operations. If drill pipe is to be exposed to air for a long period of time, the use of a filming amine, BARAFILM™, is recommended. Carbon Dioxide Lime can be used as a scavenger for treating low levels of carbon dioxide contamination. BARACOR® 95 is a highly active inhibitor which combats the effects caused by carbon dioxide and carbonate contamination in water-based muds at bottomhole temperatures up to 350°F (177°C). Use BARAFILM (a filming amine) to precoat drill pipe and casing in cases of severe contamination.

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Hydrogen Sulfide Raising the pH of the system whenever hydrogen sulfide is expected or encountered will reduce the corrosion effects, but not solve them. Maintaining the pH above 10.5 allows the H2S to be soluble in the fluid, thus minimizing its embrittlement effects when the H2S physically works into the steel. This does not remove the contaminant from the system. The use of scavengers is recommended. NO-SULF® and BARACOR® 44 can be used in water and oil-based muds. Again in case of severe contamination, precoating drill pipe and casing with BARAFILM is recommended. Salts The system should be pre-treated with the filming agent, BARAFILM. BARAFILM is physically and chemically attracted to a metal surface to form a protective barrier between the metal and its environment. BARACOR® 700 can also reduce corrosion caused by salts. Mineral Scale STABILITE®, an organic phosphonate, at low levels (2-5 ppm) will prevent scale build up.

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Drilling Conditions Depleted Sands/Differential Sticking

SOP Code: DSK Revision Date: 02/10/1997; Amended May 2005

Depleted Sands/Differential Sticking Introduction Many incidents of stuck pipe are caused by differential pressure effects. Excessive differential pressures across lower-pressure permeable zones can cause the drill string, or casing, to push into the filter cake and wellbore where it becomes stuck. Differential Sticking should be properly addressed in the pre-planning stage and proper preventive measures should be taken to avoid substantial cost penalties. Preventive measures include pre-treatment to prevent sticking, and a pre-agreed action plan should sticking occur. Experience has shown that differential sticking can occur with a minimum overbalance and should always be considered a hazard when drilling permeable formations such as sandstone. Causes of Differential Sticking A major cause of differential sticking is excessive overbalance in a permeable zone. The overbalance may be necessary because of an open hole section containing reactive, pressurized shales that require a high mud weight to impart stability. This may be further complicated where wells are deviated, requiring higher mud weights (compared to vertical wells) to stabilize the shales combined with an increase in equivalent circulating density (ECD) and in most cases a lower fracture gradient. Differential sticking may result when the specific requirements for casing design expose sands to excessive overbalance, e.g. deep high temperature - high pressure (HTHP) wells or development wells where the formation changes from shales to reservoir sands. A pressure reversal or depleted zones may cause differential sticking. Excessive overbalance can be a result of poor hole cleaning and/or excessive rates of penetration (ROP) resulting in an increase of annular mud weight. Other causes include poor quality filter cake, excessive fluid loss, poor hydraulics and rheology resulting in high ECDs. Bad drilling practices, such as leaving drill string stationary in a permeable zone and excessive ROPs that lead to high annular mud weights can lead to differential sticking. Preventing and Curing Differential Sticking Bridging Materials Using a high quality properly sized bridging material will effectively bridge across porous sands minimizing filtrate and whole mud invasion, filter cake build up, seepage loss, differential sticking and formation damage. Bridging material type and optimum concentration should be determined through testing with the Particle Plugging Apparatus and FANN® 90 to determine the combination of products that will provide the lowest spurt and fluid loss. It is important to bridge and seal pore spaces with the initial loss of filtrate. This minimizes filtrate loss and filter cake build up.

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Dynamic filtration can be evaluated in the laboratory under a variety of conditions. These include various shear rates, pressures, temperatures and filter medium permeability. The lab requires details about the size and permeability of sand to be drilled. Ideally, the tests should be completed far enough in advance so the treatment can be implemented and the active system tested to confirm the lab results prior to drilling the sands. Filter Cake Quality To minimize undergauge hole, the filter cake must be thin and to help in avoiding stuck pipe it must have some lubricity. In addition, the cake must be erodible as the filtration process is converted from static back to dynamic. These properties require that the filtration products be properly sized, deformable, lubricious and shearable. Hydrated solids such as commercial bentonite and polymers meet these requirements; however drilled solids do not and should be minimized at all times. Reducing Overbalance Mud weights, fluid rheologies and pump rates can be manipulated to reduce any overbalance. Measures to minimize cuttings in the wellbore and keep the weight in the annulus to a minimum include pumping and circulating sweeps prior to drilling sands. Seepage losses are an indication of overbalance in a permeable formation. Drilling Practices Good drilling and tripping practices are vital in avoiding differential sticking. It is very important not to allow the drill pipe to remain motionless for any period of time and to ream any undergauge sections. Communication between all drilling personnel is very important while drilling overbalanced in a permeable zone. A drilling jar and spiral drill collars should be included in the bottom hole assembly. Materials and Systems Preventing Differentially Stuck Pipe BARACARB®, acid soluble, pure ground marble (calcium carbonate) is a superior bridging agent compared to normal limestone. The marble grains resist attrition from shear/dynamic conditions downhole and are available for bridging against the wellbore instead of breaking into smaller particles and penetrating the formation, making removal and acidizing more difficult. BARACARB is available in many grades giving excellent flexibility in particle size distribution. Extensive research on differential sticking has shown that BARACARB can reduce the force required to free differentially stuck pipe by 30%, and reduce filter cake thickness by 33%. BAROFIBRE® can also be used to help prevent differential sticking when drilling through reservoir sections which exhibit low formation pressure. Additions of BAROFIBRE can reduce the permeability of the formation at the wellbore face, minimizing the cake build up and the potential for differential sticking. Spotting a pill containing BAROFIBRE prior to coming out to run casing will aid in the prevention of stuck casing in depleted sands. Some starches such as IMPERMEX®, DEXTRID® and FILTER-CHEK™ have proven very effective at bridging.

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STEELSEAL®, BXR™, BXR L, BARO-TROL® PLUS and in non reservoir sections, MICATEX, may be used in conjunction with BARACARB and BAROFIBRE for some applications. Cloud point glycols such as GEM™ GP and GEM CP have also been used successfully in the field. STICK-LESS® 20 glass beads can be used to reduce the chances of sticking and increase filter cake lubricity. Due to their inherent lubricity, oil or synthetic muds are the best choice for drilling significantly overbalanced through depleted sands, however due to environmental regulations they are not always acceptable. Whenever the differential pressure is greater than 2000 psi, an invert emulsion mud should always be considered. CMO 568™ has been proven to be beneficial in increasing filter cake lubricity in oil and synthetic muds in the North Sea. Freeing Differentially Stuck Pipe When differentially stuck pipe cannot be worked or pulled free within the safe allowable tension limits, there are two techniques that are commonly used to free differentially stuck pipe. • Reduction of Differential Pressure/U-Tubing • Spotting Fluids Reduction of Differential Pressure The reduction of differential pressure by mud weight reduction or U-Tubing techniques has been used to free differentially stuck pipe. It can, however, cause further problems and all factors should be considered before using these techniques. Reducing hydrostatic pressure can cause certain formations, usually shales, to become unstable. Often this leads to packing off and further stuck pipe problems. Reduction of hydrostatic pressure can lead to well control problems. For these reasons many operators will use spotting fluids as their first option to free stuck pipe. Spotting Fluids When differential sticking occurs, spotting fluids can be used to free the pipe. Note: It is critical to have the fluid readily available on the rig and apply it within six hours of the stuck pipe occurrence. Spotting fluids are designed to penetrate and break up the filter cake. EZ SPOT® is a good all purpose, oil-based spotting fluid, suitable for use in many different regions. QUIK-FREE® is a spotting system developed for freeing pipe in water-base muds in environmentally sensitive areas where oil-based spotting fluids cannot be used. It is highly effective and can increase lubricity as much as 35%. Mutual solvent pills have been successfully applied in invert emulsion fluids that contain BARACARB in the North Sea. These pills are built in calcium chloride brine and contain EGMBE an organic solvent and acetic acid. The solvent removes the oil coating from the BARACARB, allowing the acetic acid to breakdown the filter cake. 3

Drilling Conditions DRIL-N Systems

SOP Code: DN Revision Date: 05/03/1999; Amended May 2005

DRIL-N Systems Baroid, in response to the needs of our customers developed seven (7) drilling fluid systems designed to drill production intervals when minimizing formation damage is of primary importance. With the advent of Baroid's DRIL-N™ line of systems, Baroid can furnish all the various drilling fluid systems needed for drilling operations, brines of all types for completion/workover operations and filtration equipment for the brines, all of which culminates in affording you the best possible protection against formation damage. The primary focus for a drill in fluid is to be essentially non-damaging to the producing formation, provide superior hole cleaning, allow easy clean-up and be cost effective. These fluids address the wide range of problems encountered in horizontal drilling, completion and workover operations. Baroid's DRIL-N systems are specifically designed to provide the lowest filtration rate possible in order to minimize or prevent formation damage. In order to accomplish this fluid loss control the use of specially selected polymers and bridging particles are incorporated into our DRIL-N™ systems. Additionally, tremendous amount of testing and research has gone into the selection process to determine the best polymers and their optimum concentrations for our DRIL-N systems. Through this research and testing, specific bridging particles have been selected and sized to provide the best possible bridging results which result in low filtration rates and thin, ultra low permeability filter cakes. After determining the best components to use in a DRIL-N system, a fluid is then prepared with the desired rheological properties as well to produce a thin, ultra low permeability filter cake. The bridging particles used to provide good filtration and this thin filter cake are BARAPLUG® (sized salt) and BARACARB® (sized calcium carbonate). As important as the filtration control and filter cakes are to the various systems, the ability to effectively remove these filter cakes requires special technical attention. Through proper displacements and clean-up procedures this cake is removed, thus, reestablishing the initial return permeability of the formation and enhancing the production of the zone of interest. Again, to accomplish excellent production results and minimize formation damage, one of Baroid's seven DRIL-N systems should be your system of choice. SYSTEMS

DESCRIPTION

BARADRIL-N

Sized calcium carbonate system

BRINEDRIL-N

High density brine based system

COREDRIL-N

All oil drilling / coring system

MAXDRIL-N

Mixed metal silicate system

QUIKDRIL-N

Modified polymer system with LSRV

SHEARDRIL-N

Clay free, modified polymer system

SOLUDRIL-N

Sized salt system

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OVERVIEW OF SYSTEMS BARADRIL-N™ The BARADRIL-N system provides acid soluble drilling, completion and workover fluid compositions. The BARADRIL-N system is designed for non-damaging drilling when fluid loss and formation stability are of primary concern. Return permeabilities are excellent with the BARADRIL-N system and filter cake is easily removed by treating with hydrochloric acid. BRINEDRIL-N™ BRINEDRIL-N is a high density brine system specially designed for drilling, completion, and workover operations. A blend of microfibrous cellulose and polimeric fluid loss control materials provides exceptional rheological, suspension, and fluid loss characteristics in a non-formation damaging, thermally stable fluid. Correctly sized calcium carbonate can be added to promote a thin, low permeability filter cake for drilling permeable formations. COREDRIL-N™ COREDRIL-N fluids are 100% oil/synthetic drilling fluids that have been developed to control the formation damage that could be caused by conventional drilling operations. The COREDRIL-N system contains an optimum concentration of BARACARB (sized calcium carbonate) or BARAPLUG (sized sodium chloride) designed to bridge rock pores, thus providing low filtration rates - minimizing fluid invasion into potential pay zones. COREDRIL-N fluids use passive emulsifiers which reduce the risk of creating emulsion blockage and preserve the wettability of the reservoir rocks. MAXDRIL-N™ The MAXDRIL-N is a mixed-metal silicate system (MMS) designed for drilling, milling and completion operations. MAXDRIL-N provides borehole stability and superior hole cleaning for milling casing and drilling highly deviated/horizontal sections. This fluid is especially effective when drilling in unconsolidated, unstable, stressed or faulted formations. MAXDRIL-N forms a low permeability filter cake that restricts solids and fluid invasions into the formation, thus reducing potential damage to the formation. QUIKDRIL-N™ QUIKDRIL-N systems are solids free systems utilizing modified polymers for viscosity and suspension. This system was specifically designed for Coil Tubing operations and Slim Hole drilling. Through modification of polymer concentrations, circulating pressures can be adjusted while still providing a drilling fluid system with excellent LSRV as well as superior hole cleaning. QUIKDRIL-N also provides for formation damage protection and is shown to have excellent return permeability results. SHEARDRIL-N™ SHEARDRIL-N systems are designed as a solids-free, modified polymer drilling fluid. SHEARDRILN provides maximum penetration rates while effectively minimizing potential formation damage. SOLUDRIL-N™ 2


SOLUDRIL-N fluids are designed for drilling, completion or workover operations in horizontal and vertical wells. SOLUDRIL-N fluids utilize BARAPLUG (sized sodium chloride) and a cross-linked polymer to provide superior rheological properties and filtration control. The SOLUDRIL-N filter cake is readily removed through the use of unsaturated brine.

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Drilling Conditions Filter Cake/Filtration Control

SOP Code: FC Revision Date: 02/10/1997; Amended May 2005

Filter Cake/Filtration Control Introduction Sealing permeable zones in the wellbore is a primary function of a drilling fluid. Filtration control represents a major portion of the mud cost. Traditionally, most of this cost has resulted from controlling the filtration rate as opposed to controlling filter cake quality. This is understandable since a definitive filtration rate is easier to quantify than a subjective evaluation of filter cake quality. Filter cake quality is often difficult to define and communicate. Therefore, a review of some basic principles along with some new and old testing procedures will promote better communication, improved drilling fluid design, and proper product usage. The primary objectives of filtration control are: • Minimize damage to production zones • Reduce hydration of formation clays • Optimize formation evaluation • Avoid differential sticking of pipe • Avoid undergauge hole due to thick filter cakes These objectives are achieved by focusing on important design factors: • Compatibility of filtrate with formation • Thin, impermeable, and deformable filter cakes. • Lubricious and shearable filter cakes • Design Factors for Filtration Control/Filter Cake Filtrate Compatibility with Formation The chemical composition of a drilling fluid is a key design factor that will facilitate the fluid's ability to maintain wellbore stability and minimize damage to productive zones. The specific filtration rate of a fluid is important, but it is just as important to minimize hydration and dispersion of clay solids. Filtrate movement through microfractures in shale is often a capillary action. This spontaneous movement of fluid is not slowed by mere filtration reduction. However, viscosifying the filtrate, sealing the fractures, or adjusting the filtrate chemistry may reduce fluid movement in a fracture.

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Filter Cake Permeability Filter cake permeability is determined by the fluid's solids concentration, particle size distribution, solids deformability, and the electrochemical properties of the solids. Permeability is reduced as solids are deposited on a filter medium. Permeability is also reduced by the bridging of particles of various sizes. Particle sizes one-third the diameter of the pore throat opening are required for bridging. In addition, permeability is reduced by solids that have the ability to deform and compact into void spaces. The water associated with hydrated solids allows these solids to deform much like water balloons. AQUAGEL™ GOLD SEAL is such a solid. Polymeric materials like EZ-MUD™, DEXTRID®, THERMA-CHEK®, and PAC™ products also hydrate. When these hydrated polymers are absorbed by other solids and/or contained in the filter cake, they bond solids together and seal pore spaces within the cake or formation surface. Hydrated solids are also compressible under pressure. Compressibility is the ability to squeeze together, condense, shrink or reduce in size. As a solid is compressed, some of the outer layers of bound water are forced away from the solid thereby reducing its effective surface area. Compression also allows the electrochemical charges on clay surfaces to be placed at a closer proximity to the surfaces of other solids. This increases the adhesion of solids in the filter cake and is the reason why the filter cake nearest the wellbore or filter medium is dehydrated. In other words, filter cake is progressively drier depending on the pressure and temperature. Most drilling fluids are designed to prevent hydration of clay solids. However, maintaining deformability with hydrated AQUAGEL™ GOLD SEAL is difficult in the presence of QUIK-THIN™ thinner, lime, gypsum, sea water, KCl, and other inhibitive chemicals. Even when prehydrated, AQUAGEL™ dehydrates in time and loses its effectiveness. Replacement becomes necessary, but when adding more AQUAGEL™, care must be taken to prevent adverse effects on the fluid's solids content, rheology, and, in turn, mud stability. Lubricious and Shearable Filter Cake A drilling fluid is a "partly solid" lubricant designed to reduce the coefficient of friction between the pipe and the wellbore. This includes the depositing of lubricious solids as filter cake, thereby, reducing pipe drag across permeable sands. Liquid lubricants such as BARO-LUBE™ GOLD SEAL are used to reduce the coefficient of friction between surfaces. Polymers such as EZ-MUD™ function as boundary lubricants as they adhere to the surface of pipe and mud solids. These lubricity characteristics provide lower pipe drag and less adhesion between solids. Toughness and durability have traditionally been desirable filter cake characteristic. However, tests have proven that stuck pipe is often freed as the filter cake shears apart as opposed to metal shearing apart from the cake. This indicates that the so called tough and durable filter cake can actually magnify the problem of stuck pipe. A slick coating on the pipe and on solids within the cake can reduce stuck pipe frequencies by promoting lubrication between the metal and the cake itself.

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Controlling Filtration Rates/Cake Quality Filtration Control Mechanisms There are four basic mechanisms for controlling filtration rates and reducing filter cake permeability. Understanding these mechanisms along with how filtration control products function is important. Most products have primary and secondary functions. How a product affects other fluid properties must be considered as part of the product evaluation process. Bridging Bridging reduces filtration rates and permeability by plugging or blocking the pore spaces at the face of the filter medium. It generally requires solids about one-third the diameter of the pore throat opening to form a bridge. AQUAGEL™, CARBONOX®, BARANEX® , DEXTRID, BARACARB®, BAROFIBRE®, STEELSEAL® and other LC materials function as bridging materials. Bonding Bonding is the connecting or binding of solids together. THERMA-CHEK, PAC, CELLEX™, and other high molecular weight polymers function as bonding materials. Secondarily, PAC and CELLEX function by viscosifying the filtrate, reducing its flowability. Deflocculation Deflocculants reduce the electrochemical attraction between solids, allowing solids to be filtered individually, as opposed to flocs. This reduces the void spaces in the cake created by those flocs. LIGNOX® PLUS, CARBONOX, QUIK-THIN™ thinner, and other low molecular weight polymers function as deflocculants. Viscosity Fluid loss decreases proportionally to the increase in viscosity of the filtrate. Temperature alone may change the filtrate viscosity, making filtration control more difficult at high temperatures. Any soluble material added to the fluid will viscosify the filtrate. In most cases, this is a secondary affect of a product. Lignosulfonates and low molecular weight polymers increase the filtrate viscosity slightly while high molecular weight polymers and GEM™'s increase its viscosity to a greater extent. Controlling Filter Cake Quality Filter cake quality is influenced by the degree of hydration and flocculation of the filtered solids. The effectiveness in permeability reduction may be demonstrated by a ranking of clay solids according to their surface characteristics: Dehydrated/Aggregated/Flocculated

(high permeability)

Hydrated/Flocculated

(medium permeability)

Hydrated/Deflocculated

(low permeability)

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Since fluid loss and filter cake quality are important design factors, it is important to understand the predominant electrochemical state of the solids. Initially, cake permeability is reduced as prehydrated AQUAGEL™ GOLD SEAL is added to the system. When these clay particles become flocculated, they promote deformability and permeability reduction from increased pressure. With deflocculation, permeability is further decreased, as the voids created by the flocs are diminished. During drilling operations, hydrated solids eventually become dehydrated as the solids content increases and/or the system is converted to an inhibitive fluid. At this point, a decision must be made on the basis of economic and operational objectives. More prehydrated AQUAGEL™ and/or other products may be added. These other products include CELLEX, PAC, DEXTRID, and FILTERCHEK™. The water content must be increased in conjunction with the additions to allow the products to hydrate and function properly. Monitoring Cake Quality Monitoring Permeability of Static Filter Cakes (API, HTHP) Filter cake deformability is verifiable and can be monitored and recorded daily. Monitoring requires filtration rates at various times and pressures determined with a filter press. Test results are then evaluated based on standard filtration equations. The first equation states that filtration rates through a fixed filter medium will change in proportion to the square root of time. Equation:

Q2 = Q1 Where: Q1 = Filtration rate at 7.5 minutes Q2 = Theoretical rate at 30 minutes T1 = 7.5 minutes T2 = 30 minutes (API) This equation states that a fluid producing 5 cm3 of filtrate in 7-1/2 minutes will produce twice that value of 10 cm3 of filtrate in 30 minutes. However, if deformable solids are deposited with the initial spurt of filtrate, the filtration rate will be less than the calculated value. This means that the filter cake permeability is decreasing with time and pressure. A second monitoring technique requires testing filtration rates at two different pressures and the results evaluated based on the equation below: Equation:

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Where Q1 = Known filtration rate Q2 = Calculated filtration rate P1 = Low pressure, 100 psi P2 = High pressure, 500 psi In the equation above, filtration rates through a fixed filter medium change proportional to the square root of pressure. Therefore, a filtration rate of X at 100 psi would then be 2.2X at 500 psi. However, if the solids provide a deformable filter cake, the ratio of the filtration rates will be less than the calculated value. Permeability is then decreased when pressure increases. Field muds with hydrated/flocculated solids may provide a 500/100 psi filtration ratio of 1.0 or less. A deflocculated fluid with deformable solids may provide a filtration rate of 1.2 or less. The evaluation of filtration rates and filter cakes at varied times and pressures is more informative than the single data point reported on the standard API report form. Monitoring Permeability of Static Filter Cakes (PPA) Permeability under wellbore conditions is somewhat different from the conditions within the API HTHP test cell. However, the principles of filtration and permeability remain the same. The Particle Plugging Apparatus (PPA) simulates downhole conditions at pressures to 3,000 psi, temperature to 500°F (260°C), and varying permeability using aloxite disks that range from 100 md to 100 darcies. To reduce permeability, some of the solids initially deposited at the face of a permeable zone must be of sufficient size to bridge pore throats. If not, whole mud will pass through. In addition to bridging, some solids must be deformable. They compact into void spaces to restrict fluid movement. If the initial spurt loss of the PPA test includes solids or whole mud, the pore throats are not being bridged. This can result in high fluid loss and thick filter cake due to depositing of coarse solids on the filter medium. An efficient filter cake, as defined by PPA, will have the following: •

A low spurt loss with little or no solids in filtrate.

•

Fluid loss values near equal at different pressures.

•

Filter cake thickness near equal at different pressures.

Filtration products should be selected based on temperature stability, particle size, deformability, and bonding ability. A polymer may reduce fluid loss at low pressures; however, it may be blown through the pore space at high pressures. In this case, firm solids like BARACARB or STEELSEAL may be needed to bridge the pore spaces. 5


Monitoring Permeability of Dynamic Filter Cakes (FANN® 90) When the drill bit penetrates a permeable zone, solids are filtered from the fluid as the filtrate is forced into the formation by the differential pressure. Some of these solids are washed or eroded from the face of the wellbore by the circulating action of the drilling fluid. When the rate of solids erosion and the rate of solids deposition reach equilibrium, the filtration rate and cake thickness become constant. As with static filtration, it is important to bridge and seal pore throats with the initial loss of filtrate. This minimizes filtrate loss and filter cake build-up. When the filtrate process is converted from dynamic to static, cake build-up increases and filtration rate decreases. The effectiveness of the initial filter cake will determine the magnitude of the cake build-up under static conditions. To minimize "undergauge" hole, the filter cake must be thin. In addition, the cake must be erodible as the filtration process is converted from static back to dynamic. These properties require that the filtration products be properly sized, deformable, lubricious and shearable. Bound water in hydrated solids such as commercial bentonite and polymers gives these desirable characteristics. In most cases, the dynamic filtration rate will be lower after the static period than during the initial dynamic phase. When solids have low water contents, the electrochemical charges on the surfaces of the solid are placed in a closer proximity to the charges on other solids. The electrical attraction between these solids along with the compaction under pressure makes them very difficult to separate. As a result, a thick and tough filter cake may be formed, resulting in an undergauge wellbore and stuck pipe potential. Dynamic filtration can be evaluated in the laboratory using the FANN® 90 under a variety of different conditions, including various shear rates, pressures, temperatures, and filter medium permeabilities. As with the PPA test, the object is to achieve fluid loss control with thin filter cakes while varying the test parameters. It is important to know the composition of the fluid and the filtration characteristics of all the elements within a fluid to make a logical evaluation of the fluid and recommendations for adjusting filtration rates. The maximum acceptable values for the dynamic filtration rate and cake deposition index (CDI) are shown in the table below. Mud Weight lbs/gal

Rate, ml/min

CDI

9-14

0.16

22

14 or greater

0.12

16

Filtration Control Versus Stuck Pipe Prevention of differential pressure sticking is a primary function of drilling fluids. The formula for differential pressure sticking is: 6


Vertical Pull = (Differential Pressure, psi) (Area of Contact, in2) (Coefficient of Friction) The differential pressure (psi) is the difference between the hydrostatic pressure of the mud column and the formation pressure. To be able to minimize differential pressure, the mud chemistry must have a stabilizing effect on the shale or wellbore. This prevents the need for excessive mud weights to maintain wellbore stability. The area of contact (in2) is determined by pipe and hole diameters along with filter cake quality. Thick and soft filter cakes allow greater contact as the pipe embeds into the cake. As the area of contact increases, the total horizontal force increases as a product of the area of contact and the differential pressure. Effective solids control and a thin impermeable cake on the wellbore will minimize the area of contact. The coefficient of friction defines a lubricity characteristic. As the lubricity of the fluid and cake improves, the vertical pull required to move pipe decreases as a product of the coefficient of friction and the horizontal force. Lubricants and/or lubricious solids allow the pipe to slide past permeable zones. Further, this allows the solids within the cake to shear apart more easily. This facilitates the prevention of stuck pipe as well as the freeing of pipe that has become stuck.

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Drilling Conditions Fluid Displacements

SOP Code: D Revision Date: 03/14/1997; Amended May 2005

Fluid Displacements Introduction When displacing fluid in a wellbore over from one type to another, the most important factor is to create a sharp interface between the two fluids to minimize contamination and waste. Steps must be taken to minimize channeling and ensure as complete a removal of the fluid being displaced as possible. Specially designed spacers are formulated to provide separation of the fluids whether the displacement is mud to mud, brine to mud, or mud to brine. Displacement methods include direct and indirect. Direct displacement is used when the fluid is displaced directly with a displacement fluid. Indirect displacement uses large amounts of water to flush out the wellbore before circulating the displacement fluid. When displacing in cased hole, the densities of the fluids should be considered to determine the best way to line the pumps up for maximum efficiency in displacement. If displacing a heavy fluid with a fluid of significantly lighter density, pump down the annulus and up the work string (reverse). If displacing a light fluid with a significantly heavier one, pump down the string and up the annulus (conventional). These displacement methods will minimize the interface between the fluids and unnecessary costs from fluid waste. Mud to Mud Adjust the rheological properties of the fluid being displaced out of the well to achieve the lowest practical yield point. Formulate a spacer of appropriate volume to provide a minimum of 500 ft of length of the annulus which will be compatible with both fluids and of the appropriate density. All fluids should be similar in rheological profile to minimize the potential for channeling. Flush and clean all surface lines, tanks, and manifolds that will contact the displacement fluid. Secure all water outlets to prevent dilution and/or contamination of the displacement fluid. Displace by pumping down the drill pipe and up the annulus. Once displacement begins, do not stop the pumping operation. Rotate and reciprocate the drillpipe at least one joint every 15 minutes to minimize channeling in the annulus. Always monitor returns and pump strokes in order to confirm break through of the new fluid. After break through occurs, shut down pumping and perform a mud check on a flowline sample for confirmation. Mud to Brine Initial Rig Preparation Cleanliness Clean working practices and good housekeeping cannot be over-stressed when displacing to a completion fluid. All rig pits, ditches, and lines (including gun lines) should be scrupulously cleaned using degreasing solvents and detergents. They should be rinsed out and if possible squeegeed dry. If it is practical, lines should be opened to check for any mud solids that might have settled in them. All the pits, sandtraps, and under the shale shakers should be cleaned out 1


and washed down using high pressure cleaning equipment. In the pit room, all gratings should be cleaned, all the lights and beams should be washed down. If heavy brines will be used, all water hoses should be checked and if not necessary should be blanked off. All cleaning should be done well in advance wherever possible. It is far better to do a little bit of extra cleaning than to have a delayed operation due to dirty tanks. To clean pits and lines, 100 bbl (16 m3) of 2% BARAKLEAN™ NS PLUS should be mixed up and circulated through all lines, gun lines, mixing lines etc. This can also be used to clean the tank system initially. Valves and Seals All dump valves should have the seals and valve seats checked to ensure they are in good order. They should be greased to ensure a good seal and if possible should be manually guided and checked when being closed to ensure a perfect fit. All ditch gates should be sealed with silicon on each side of the gate. This will need to be replaced if the gate is opened. UNDER NO CIRCUMSTANCES SHOULD BARITE, BENTONITE OR POLYMERS BE USED TO SEAL ANYTHING. Potential Leak Situation All pump packing should be examined and if necessary replaced. One barrel of expensive brine buys a lot of pump packing and any suspect packing is best replaced ahead of time. Packing should be lubricated with grease. Water can all too easily leak into the system and can obscure brine leaks. Packing should be lubricated on a regular basis to ensure minimal losses. Displacement If the bond logs and casing strength data indicate that the casing will withstand a calculated pressure differential, an indirect displacement procedure should be used. This procedure uses large quantities of seawater to flush the well resulting in a clean, solids free displacement, reduced spacer costs and lower filtration costs. When applying the indirect method one has to ensure that the pumping pressure will not exceed the collapse or burst strength of the casing. If bond logs indicate that the casing will not withstand the differential pressure, the direct displacement procedure should be used. This method does not obtain a clean displacement and expensive filtering will be necessary. However, undesirable pressure situations are eliminated because the direct method maintains a more constant hydrostatic head. Deviated/Horizontal Concerns For deviated and horizontal wells, particular attention should be paid to the flow regime. The use of weighted push pills will minimize channeling and ensure good cleaning of the low side of the wellbore. The drill pipe should be rotated and reciprocated during the clean out. The push pills should be circulated through the deviated section at a pump rate that will ensure plug flow. When the push pills are out of the highly deviated sections, the pump rate should then be increased as the detergent and flocculant pills pass through the interval to ensure good hole cleaning and scouring/removal of mud adhering to the tubular goods. Preparation of the Mud System The rheological properties of the mud system should be adjusted, to achieve a yield point as low as is practical, before the displacement is started. If the well is deviated, care should be taken not to reduce the values too far as barite sag could then be a problem. With the mud system treated and the surface equipment prepared, the following sequence of pills should be mixed and 2


pumped. To achieve effective cleaning of the casing, this sequence of pills should be pumped and displaced using maximum pump rates, rotating and reciprocating the pipe whenever possible. It is advisable to have at least 500 ft (153 m) of pill/spacer or 3 mins contact time at the highest pump rates. In detail, the sequence of pills should be as follows: 1. Weighted Push Pill 50 bbl (8 m3) BARAZAN® PLUS/Barite/Seawater (or freshwater) To push the mud out of the well, minimizing channeling and contamination. Annular coverage 9 5/8" / 5"

+/- 1,000 ft (350 m)

Time of coverage

±8 mins

Make up: Add 2-3 ppb (8-10 kg/m3) XCD Polymer to seawater (or freshwater), weight up to 0.2 ppb (0.025 SG) greater than the active mud weight. Add 1 drum of BARAKLEAN NS to the pill.

2. Caustic Pill 35 bbl (5.6 m3) Caustic Pill To remove mud from the casing walls. Annular coverage 9 5/8" / 5"

+/- 700 ft (215 m)

Time of coverage

±4 mins

Make up: Add 3 to 4 ppb (8 to 10 kg/m3) of Caustic Soda to 35 bbls (5.6 m3) of sea water (or freshwater). Care should be taken when mixing this as the pill will have a very high pH. Any splashes must be washed off immediately. Full-face masks must be worn when mixing.

3. Solvent/Surfactant Pill 300 bbl (48 m3) BARAKLEAN NS pill To clean and water wet Tubing and Casing Annular coverage 9 5/8" / 5"

±6,000 ft (1,830 m)

3


Time of coverage 10 bpm (1,600 ltr/min)

±30 mins

Make up 8 drums of BARA KLEAN-NS mixed in 290 bbl (46 m3) of sea water (or freshwater).

4. Flocculating Pill 200 bbl (32 m3) BARAKLEAN NS pill To flocculate remaining mud and solids and clean the casing Annular coverage 9 5/8" / 5"

±4,000 ft (1,220 m)

Time of coverage 10 bpm (1,600 ltr/min)

±20 mins

Make up:

5 drums BARA KLEAN FL in 195 bbl (31 m3) of seawater water (or freshwater).

Flow rates should be as high as possible subject to pressure drop limitations, and 10 bpm (1,600 ltr/min) should be achievable. Excessively high pump rates over 13 bpm should be used only when the concentration of chemicals is increased. There is a contact time required for the chemicals to work effectively, and one normally aims to have a minimum of 3 minutes at the maximum pump rates. These pills should be displaced from the well using the appropriate density brine in a direct displacement and seawater/water in an indirect displacement. Pump strokes should be monitored to confirm the break through of the various pills and final completion fluid. Only clean seawater / brine should be pumped into the well, that is to say, returns should not be pumped straight back down the well. They should be taken into one pit and then pumped via the filter unit into the section tank until returns from the well are to the required specification. When the returns have been recorded at the required standard of cleanliness for three consecutive readings with an interval of 15 minutes between each reading the sequence of operations can continue. If the seawater / brine does not clean up to the required standard, a further pill of 100 bbl (16 m3) seawater / water with 2 dms of BARA KLEAN NS should be pumped. Displacement Procedure for Invert Emulsion Muds Invert mud/base fluid should not be brought on board until rig containment measures have been fully discussed with all rig crews and implemented. All surface pits, sand traps and mud lines should be thoroughly cleaned and drained. The following rig modifications / considerations should be made: • Disconnect all water lines located near the surface mud system. • Ensure all wash guns at the shakers are connected to a base fluid supply. 4


• A drain box should be installed around the pipe stacking area. This box should have a connection going to the flowline or bell nipple. • Utilize a pipe wiper to keep the pipe dry and to salvage mud. • If possible, use a flared bell nipple. • Ensure that all elastomers in the circulating system are resistant to the base fluid being used. This includes pump parts, pipe protectors, etc. Prior to displacement, the water-based mud in the hole should be treated to reduce the yield point and gel strengths. This is particularly important if the mud has been used to drill cement. Generally, the cost to condition the water-based mud will be less than reconditioning the invert mud contaminated due to a poor displacement. Prepare a spacer pill by treating 30-50 barrels of the invert mud with GELTONE® to raise the yield point to 50+. This will provide a yield point at the interface great enough to exceed the critical yield needed to flush water mud from the annulus, even where the drill pipe is not concentric relative to the casing. Start displacement by pumping the spacer followed by the invert mud. Water-based returns should be directed from the flowline to a reserve tank if it is to be salvaged, otherwise it should be discarded over the shakers. Sufficient volume of invert mud will be required to displace the hole and enable drilling to proceed without the need to mix new volume. By having sufficient reserve volume of pre-mixed mud available, the mud engineer and the rig crew will be free to concentrate on the maintenance of the active. Reserves of base fluid should be kept on board in storage for dilution, base fluid-water ratio adjustments and weight reductions. The mud should be displaced using normal flow rates for the section while rotating and reciprocating the pipe to reduce channeling. Reciprocate the drill pipe a length of one joint every 15 minutes. Pump rate during displacement should be normal, and continuous, until the displacement is complete. When the spacer is observed at the flowline, returns should be diverted to a reserve pit for future reconditioning, and the invert mud should be diverted to the active system, completing the displacement. No invert mud should be discharged as waste. The hole should be circulated to an even mud weight prior to conducting any shoe bond integrity tests. Invert mud properties are temperature variant. Until the invert mud has been sheared by the bit and its temperature increased, coarse screens should be used in the shale shakers (±80 mesh). As it heats up and becomes less viscous, these should be changed towards the smallest size which can handle the cuttings and flow rates required. Considerations for PETROFREE® Displacement procedures for PETROFREE® will be the same as above with the following exceptions / considerations: All active and reserve mud tanks along with all Ester storage tanks and lines must be thoroughly cleaned out to remove any trace of mineral oils or diesel.. Rubber valve seals and hoses should be checked and replaced if necessary to prevent mud loss or contamination. Every effort should be made to eliminate surface losses of PETROFREE®. Check the layout and operation of all solids control equipment prior to displacing to the PETROFREE®. Special attention should be given to the centrifuge plumbing, etc. System maintenance costs for 5


PETROFREE® will result from volume building due to new hole drilled and surface losses. Normal surface losses can be held to a minimum using the following techniques. • Use a mud saver sub. The use of this will reduce losses on connections. • Use pipe wipers to remove oil mud from the drill pipe during trips. • Install a catch pan on the top of the bell nipple. This must be large enough to extend beyond the edges of the rotary table. This device will catch mud which falls through the table and will divert it into the drilling nipple. • Provide a racking pan for the drill pipe. A return line from this pan must be run to the flowline or into the catch pan as described above. • Use a mud box on trips. A mud box in good condition will prevent serious losses when pulling a wet string. The mud box should be connected to the flowline or catch pan. As with displacing invert muds above, keep water hoses off of the rig floor and away from the mud tanks. Water additions to PETROFREE® mud should be made only upon the recommendations of the fluid engineer. PETROFREE®, when initially mixed and unweighted, will have a low yield point (6-8 lb/100 ft2) until the mud has been sheared through the bit. The mud should be weighted to the desired density and circulated/sheared to help YP development. Do Not add GELTONE® or RM-63™ at concentrations greater than 2.0 lbs/bbl (5.7 kg/m3) and 0.5 lbs/bbl (1.5 kg/m3) respectively at this stage as excessive viscosities may result once the mud is in circulation and sheared. The rheology should be observed after 3-4 circulations and small incremental additions of GELTONE® or RM-63 made to obtain the necessary rheological properties if they have not developed sufficiently. Prepare a 50-75 bbl (8-12 m3) usable volume of high viscosity PETROFREE® spacer using GELTONE® and RM-63 additions to previously weighted up active mud. The YP of this spacer should be >40 lb/100 ft2. A volume of 50-75 bbl (8-12 m3) of seawater should be pumped ahead of the viscous PETROFREE® spacer to ensure a good interface. A sharp interface should be observed between the water-base mud and the viscous PETROFREE®. Divert any contaminated PETROFREE® to a reserve pit for later treatment. For the displacement to PETROFREE®, coarse shale shaker screens (e.g. 60-80 mesh) should be installed. Once the mud has been sheared and warmed up, utilize the finest mesh screens possible. Normally, 120140 mesh screens are used and occasionally up to 200 mesh screens can be employed. Procedure for Displacement of PETROFREE® Out of the Hole Displacement of PETROFREE directly with oil-based muds present significant environmental and logistical concerns due to the risk of contamination of the PETROFREE with the oil-based mud. If oil-based mud is programmed for use after PETROFREE, consideration should be given to first displacing PETROFREE with water and offloading all PETROFREE from the rig prior to taking onboard OBM. To displace the PETROFREE, prepare 50-75 bbl (8-12 m3) usable volume of high viscosity (YP > 40 lb/100 ft2) water-based mud spacer at the same density as the mud used after the displacement, e.g.: 6


Material

Amount

Freshwater

1 bbl

Soda Ash

as req'd

Caustic Soda

0.25 lbs/bbl

Bentonite

25 lbs/bbl

Barite

density equivalent to water-based mud

Prepare 8-12 m3 (50-75 bbl) usable volume of viscosified (YP > 40 lb/100 ft2) PETROFREE ester using GELTONE® and RM-63 additions. This spacer is pumped ahead of the viscous water-based mud spacer. Slow circulation rates are recommended to ensure that the two spacers remain in plug flow throughout the displacement to minimize channeling and mixing. Do not stop circulation once pumping has started.

7

Drilling Conditions Fractured Limestone, Drilling

SOP Code: DFL Revision Date: 02/11/1997; Amended May 2005

Fractured Limestone, Drilling Introduction Fractured limestone formations occur in many areas of the world, from the depleted mature reservoirs of the Middle East and Venezuela, to the more recently developed formations offshore in the Philippines and Vietnam. In all cases, drilling fractured limestone formations may result in problems characterized by: •

Lost Circulation - sudden, from partial to total.

•

Wellbore instability - especially in horizontal development wells of recent years.

•

Formation damage - usually solids blocking from mud invasion. Also, incompatible mud filtrate chemistry can cause precipitates.

•

Differential sticking

•

Acid gases - CO 2 and H 2 S

Lost Circulation Refer to Well Blueprint "Lost Circulation" for further detail. Seepage to Partial Losses Use mixtures of fiber and granular LCM. In reservoirs, mixtures of BAROFIBRE® and BARACARB® have proven most effective. Drill with the BARADRIL-N™ or MAXDRIL-N™ system. Use BARACARB bridging material in the drilling fluid. Severe to Total Losses It is unlikely that conventional LCM pills will be effective. If this is the case, the second treatment level is Diesel-Gel or Diesel-Gel-Cement pills. A BARASIL-S™ sodium silicate pill followed by a CaCl2 pill can be effective in large vugs and fractures. Limestone fractures often contain lining minerals, commonly calcite. Calcite is readily soluble in water below a pH of 11.5. LCM pills should have a pH 12 or greater to reduce the solubility of fracture-lining minerals and thus prevent increased loss. Wellbore Instability In recent years, during horizontal well developments in fractured limestone reservoirs there have been instances of severe wellbore erosion as a result of blocky limestone pieces falling into the wellbore. This condition has led to stuck pipe and the need for side-tracks. In the most severe cases, the well has had to be abandoned. This condition requires a drilling fluid which will carry large pieces of fractured limestone out of the hole, to allow drilling to proceed. The MAXDRIL-N system has been used successfully in these conditions. 1


Formation Damage Solids invasion and blocking will occur if fractures are not properly bridged, leading to production impairment. The correct PSD of bridging materials is best determined from examination of core samples. Modern 3-D logging techniques can also be used to determine fracture size and direction. BARACARB is the preferred bridging material as it is acid-soluble. BARARESIN® oilsoluble resin has also been used successfully. It is important to bridge the fractures at the borehole wall, so that clean-up techniques can be most effective. Carbonates and sulfates are common constituents of connate water in limestone reservoirs. These form precipitates with divalent ions such as calcium and magnesium. The mud should be treated to remove Ca+2 and Mg+2 ions. Differential Sticking Differential sticking is a common occurrence in highly fractured and depleted limestone reservoirs. Differential sticking is dealt with in detail in the appropriate section. To summarize, use FANN® 90 and PPA tests to optimize CDI and PSD. Take the appropriate precautions to minimize the risk of differential sticking. Acid Gases CO2 and H2S are commonly associated with limestone reservoirs. These gases will cause drill string corrosion and failure if they are not dealt with. The presence of H2S is a life-threatening hazard to drilling rig personnel. CO2: Add lime and caustic soda to treat out. At BHST > 250°F, use BARACOR® 95 in place of lime. Raise the mud density to prevent further influx. H2S: Use an H2S scavenger to treat out, NO-SULF®, Chelated Zinc, Ironite Sponge. Maintain a high pH (>10.0) to buffer against minor influxes. Raise the mud density to prevent further influx. Preventive Measures The key to dealing with fractured limestones is to minimize the severity of associated problems through careful planning and good drilling practices. This includes: Casing Seat Selection Set casing as close to the top of the limestone as possible. This will allow the mud density to be run as appropriate for the limestone, without having to adjust density for other troublesome formations. Maintain Minimum Mud Density This will be easier if casings are set as described. It is vital that ECD be monitored and minimized. In many instances, there will be a narrow density window between loss of circulation and influx. Use a mud system which minimizes ECD, such as BARADRIL-N and MAXDRIL-N. 2


Minimize Swab and Surge High pressure surges will contribute to the severity of losses encountered while drilling fractured limestones. Abnormal swabbing pressures can lead to large volumes of gas/liquid influx. These pressures are minimized by: Reducing ECD through optimum fluid design • Breaking circulation (e.g. every 1000 ft) when tripping in the hole • Reducing pipe running speeds - drill pipe and casing • Rotating drill pipe while starting pumps, to help break gels • Adopting slowest practical pump rates while drilling • Control drilling to avoid overloading the annulus with cuttings Be Prepared for Lost Circulation Have a LCM pill containing base mud with appropriately sized LCM ready to pump in reserve. This will reduce the time taken to combat LOC should losses occur. No Squeezes Do not attempt to squeeze LCM into fractured limestone. Squeezing will lead to fracture propagation and result in more severe losses. The correct technique is to speed up the pumps as the LCM pill reaches the bit to get the LCM quickly into fractures, then pull up and allow the pill to soak. Baroid Solutions BARADRIL-N and MAXDRIL-N drilling fluids systems: BARACARB BAROFIBRE STEELSEAL®, BARARESIN BARASIL-S Lost Circulation Materials

3

Drilling Conditions Gas Hydrates

SOP Code: GH Revision Date: 06/11/1999; Amended May 2005

Gas Hydrates Introduction Gas hydrates are products of a thermodynamic phenomenon where water and gas molecules combine to form crystalline solids. The crystal lattice structure of hydrogen bonded water molecules provides a cage-like framework to host gas molecules. The two common hydrate structures may contain eight or twenty-four cavities with one molecule of gas per cavity. The final composition is approximately 15% gas and 85% water. As much as 184 ft3 of natural gas can be concentrated into 1 ft3 of hydrates. They are commonly associated with deep water drilling operations but have also been observed while drilling permafrost. Gas hydrates formation is a function of pressure, temperature and the composition of both the drilling fluid make up water and the gas itself. Gas hydrates form more readily at high pressure, lower temperature, with higher gravity gases, and in lower salinity waters. These conditions are often at temperatures much above the freezing point of water. For hydrates to form, there must be a large quantity of entrained gas in the mud and the right combination of high pressure and low temperature. The temperature at which hydrates form is a direct function of pressure. As pressure increases with increased water depth, the temperature at which hydrates can form also increases. Problems associated with the formation of gas hydrates in drilling mud include: • Plugging of choke and kill lines, BOP's and the riser. • Interference with drill string movement or BOP operation. • The liberation of large quantities of gas near the surface as the hydrates decompose or melt. Gas Hydrate Problems Temperature, pressure, and gas composition determine conditions favorable for hydrate formation. Solidification occurs as the temperature decreases and/or the pressure increases. A light gas (methane) resists hydrate formation more than the heavier gases (ethane and propane). As the temperature of the fluid is decreased and/or pressure is increased, seed crystals or hydrate nuclei are formed. At the critical pressure/temperature/gas combination, massive nucleation and encapsulation of gas into the hydrate structure occur. Elevated pressures and low temperatures in deepwater drilling promote hydrate formation. The gas hydrate crystals can plug subsurface and BOP equipment during drilling fluid circulation. Conversely, as temperature increases, gas is released through dissociation like gas breakout from oil mud. An uncontrolled sudden release of gas can become a kick. The amount of inhibition required to prevent hydrate formation is determined by the difference between the water temperature at the wellhead and the hydrate formation temperature in fresh water. Hydrate problems can go unnoticed, many cases have been unreported due to an inaccurate diagnosis such as settled barite or mechanical problems. 1


Preventing The Formation Of Gas Hydrates Drilling fluids rarely contain enough gas at the proper pressure and temperature for hydrates to form. In two reported cases of gas hydrates, the problem occurred while dealing with a well control problem. To prevent gas hydrates there are several methods that can be used. These include: • An inhibitive mud system designed for the worst case scenario. • Higher chloride salt polymer muds. Invert emulsions, preferably synthetics as unlatching the riser in deepwater has major environmental implications. • Glycerine/polyglycerine salt muds (GEM™ 2000). water-base muds with crystal-size modifiers such as EXTENSOL. • Polyglycol/salt systems (GEM GP/CP/SP). • Spotting an inhibitive fluid in the kill and choke lines, BOP's and riser prior to shut-in. • Minimize any shut down time. • Remove any entrained gas prior to shut down. The formation of gas hydrates can be calculated by Baroid's Hydrate Prediction model. Requirements include sea bottom temperature and pressure. Various salts and glycerine combinations can be mixed to suppress the gas hydration formation temperature. Use Baroid's Hydrate Prediction model to determine what chloride content (%) is necessary to suppress the hydrates on the well. Prediction data is presented by interval because as mud weight changes (pressure related) the requirements change. As a safety precaution, keep enough GEM 2000 on location to provide 40% by volume of the choke and kill lines volumes - particularly before the mud system has enough chlorides (as mud weight allows) to suppress the hydrates. Be aware of the effect this will have on the hydrostatic head. When plugging and abandoning, pulling casing, etc., keep the chlorides at the levels that gives maximum possible gas hydrate suppression. The dilution cost will be more expensive because drill or seawater cannot be used to reduce mud weights, but it could save days by preventing hydrates from forming. Maximum suppression can be achieved with 22% NaCl. It is not necessary to have more than 22% NaCl by weight in a WBM unless a salt saturated fluid is required. If the NaCl percentage is greater than 22% the extra salt will come out of solution at the sea bed temperatures and the precipitated salt can also accumulate inside the stack. Note: WBM Systems are limited in totally inhibiting gas hydrates at sea floor temperatures with greater than 3,500 ft of water depth and in the higher mud weight ranges. It is important to keep the mud circulating. Do not go for extended periods of time without circulation. The common practice of circulating bottoms up prior to a trip, will help reduce any high concentration or influxes of gases into the wellbore and/or riser.

2


Remedial Action If blockage with hydrates does occur, the main thrust for remediation is removing one or more of the necessary conditions of hydrate formation. The following methods have been successfully used in past situations: Flush out the hydrates with coiled tubing using methanol, a concentrated brine, or a calcium chloride fluid. The calcium chloride will provide inhibition by its exothermic reaction when it goes into solution. Pull the subsea BOP's to a given depth at which the hydrates would become unstable. The depth necessary to decompose the hydrates can be calculated using the thermal gradient of the seawater. The exact formation parameters and configuration of the hydrate mass along with current well conditions and the hydrate characteristics of the drilling fluid will determine the best remediation protocol. WHyP™ – Westport Hydrate Prediction program The Westport Hydrate Prediction software is the recommended tool for gas hydrate modeling and now replaces Baroid's Hydrate Prediction software. The WHyP software allows the user to determine the temperature and or pressure at which hydrates will form for a particular drilling fluid. It will also determine the degree of hydrate suppression imparted to the fluid through the addition of thermodynamic gas hydrate inhibitors. WHyP provides a selection of 8 common salts and 5 glycols for use as inhibitors. In any one fluid formulation, the combined inhibition of up to 3 salts and 1 glycol can be evaluated. The gas used to model hydrate formation can be described in terms of specific gravity, or the actual gas composition can be specified. A default gas composition equivalent to Green Canyon (Gulf of Mexico) gas can also be selected. The inhibitor concentrations can be specified, in terms of weight percent of the aqueous phase, or the program can calculate the required single inhibitor concentration needed to suppress hydrate formation at specified mudline temperature and pressure conditions. The program also allows the user to calculate the hydrate forming conditions for a specific mud based on the filtrate activity or resistivity. Salts should be the first choice as thermodynamic hydrate inhibitors. The most effective salt, allowing for environmental considerations and cost, is sodium chloride. If full hydrate suppression is not possible, then glycols can be added to the mud formulation to improve the inhibition. WHyP provides the ability to model the inhibitive effect of polyalkylene glycol, which is equivalent to Baroid's GEM products. The software does not take into consideration the effect of any other mud components other than salt and glycols on gas hydrate formation. Bentonite, barite, polymers and other mud additives may have a negative effect on hydrate formation conditions, but this effect cannot be modeled with the current available technology. For ultra-deepwater drilling it is recommended that Baroid Technical Service Engineers consult with their regional Technology Manager prior to specifying mud formulations for customers. Gas hydrate modeling performed using the WHyP software is available through the following people. 3


If you need to use this software, please contact the person listed below in your region.

Aberdeen

Charles Cameron, Angus Florence

Asia/Pacific

Peter McNaughton

Latin America

Frank Boswell

New Orleans

Ward Guillot

Nigeria

Donald Cameron

Texas Gulf Coast

Tim Wright

Additional technical support can be obtained through the Global Technology Team in Houston, Texas.

4

Drilling Conditions Gunk Squeezes

SOP Code: GS Revision Date: 02/11/1997; Amended May 2005

Gunk Squeezes Introduction A method called "Gunk Squeeze" may be applied in cases of severe lost circulation. There are several variations of "Gunk Squeezes". Typically a mixture of 300-400 lbs/bbl (8501,150 kg/m3) of bentonite in diesel or synthetic oil is pumped out the end of drill pipe, mixing with mud being simultaneously pumped down the annulus. Bentonite's great affinity for water causes a rapid thickening, or hardening, that is sometimes capable of sealing a loss zone. A 50: 50 mixture of Bentonite-Diesel Oil (BDO) or Bentonite-Synthetic Oil (BSO) and mud, can plug open holes. Because of the near instantaneous setting, BDO/BSO mixtures have been successfully used to shut off underground water flows while other materials would have been washed away before setting up. The more aqueous the fluid added, the thicker the mixture becomes. Squeezes are usually started at a 1 to 4 mixture of mud to BDO/BSO, followed by an increase in mud to BDO/BSO ratio in steps if squeeze pressure is not evident. Large scale laboratory work has shown that more effective mixtures result if a perforated bull plug is used on the end of the drill pipe. A 50/50 bentonite/cement mixture rather than all bentonite is stronger and may be more effective in some cases. BDO/BSO Formulations for Water-Based Muds Bentonite-Diesel/Synthetic Oil • 10 bbl Batch - 11.3 lbs/gal • 7.2 bbls Diesel Oil/Synthetic • 26 sx Bentonite (100 lb sx) • 50 lbs Course Mica • 50 lbs Fine Mica • 10 lbs Fiber Note:

Mixture can be weighted with barite.

Bentonite - Cement - Diesel/Synthetic Oil • 10 bbl Batch - 11.7 lbs/gal • 7.1 bbls Diesel Oil/Synthetic • 14.0 sx Bentonite (100 lb sx) • 14.0 sx Cement (94 lb sx) Note:

Sealing Material if desired.

Mixture can be weighted with barite.

1


BDO/BSO Formulations for Oil-based Muds Invert BDO/BSO formulations mix with oil or oil-base muds are set up like the normal BDO/BSO formulation does with water. Use 10 plus bbls of water or gel mud spacers before and after the squeeze mixture. Invert BDO/BSO Formulations (Water-Organophilic Bentonite) 10 bbl Mixture - 12.0 lbs/gal

10 bbl Mixture - 16.4 lbs/gal

7.14 bbls Water

5.9 bbls Water

33 lbs QUIK-THIN™ Thinner

10 lbs Caustic

16.5 lbs Caustic

5 lbs QUIK-THIN Thinner

50 sx GELTONE® V

32.5 sx GELTONE® V (50 lb sx) 30 sx Barite (100 lb sx)

Note:

Mix caustic and thinner into water, then add GELTONE® V and barite last.

To mix a gunk squeeze, follow these steps: A clean mixing pit is recommended to ensure no contamination occurs while mixing,. If the BDO/BSO mixing uses rig equipment, pits, hoppers, gunlines, etc., they must be completely clean prior to mixing the formulation. Isolate pop-off valves and use cementing line to the drill pipe. Spacers of at least 10 bbls of diesel/synthetic oil must precede and follow the BDO/BSO mixture to prevent contact and plugging in the drill pipe. Unless the BDO/BSO mixture density is more than the drilling mud, a back pressure valve should be run in the string to prevent backflow when pipe is disconnected at the end of the squeeze. The BDO/BSO mix and spacers are pumped through a back pressure valve and displaced with mud to the bit. Then the open-ended pipe (or with a bull-plug) is lowered to 50 ft above the loss zone, drill pipe filled and the squeeze performed. Maximum allowable pressure to be applied should be calculated based on maximum equivalent mud density needed at the casing seat. The casing gauge should be monitored for this purpose. When the mix is displaced to the end of the drill pipe (at 50 ft above the loss), close annular preventers and start pumping on the annulus at 1 or less bpm and on the drill pipe at 1 to 4 bpm (1-4). If after pumping approximately one half (1/2) of the BDO/BSO with no pressure observed, the pump flow on the drill pipe should be slowed to 1 to 2 bpm. After the three quarters (3/4) of the BDO/BSO is pumped, slow to 1 bpm. This will usually plug the open hole. If there is open hole above open-ended drill pipe the formation may break down and the mix will begin to set at the new loss zone. Pipe should be worked slowly through the annular preventer during the squeeze to detect drag. If drag occurs, pull until pipe free and resume squeeze. 2


When final squeeze pressure is obtained, pull drill pipe into casing, re-impose final squeeze pressure and hold for 2-4 hours. If cement is used in the mixture, allow 8 hours before attempting to drill out. Any BDO/BSO remaining in the drill pipe cannot be reversed out without plugging the drill pipe so it must be pumped out in small volumes as pipe is pulled. Pull out, add bit and collars, wash through spilled out BDO slowly and drill out plug. Usually, 1,000-2,000 lbs bit weight is required to drill out the plug. When cement is used in the slurry, as much as 20,000 lbs bit weight has been required to drill out the plug.

3

Drilling Conditions Hole Cleaning

SOP Code: HC Revision Date: 05/07/1999; Amended May 2005

Hole Cleaning Introduction Hole cleaning or cutting transport is a major function of a drilling fluid. Hole cleaning efficiency is the ability of a drilling fluid to transport drilled cuttings to the surface and to suspend the cuttings when the drilling fluid is in a static state. The following factors affect proper hole cleaning: • Flow rates • Rheological properties • Cutting size, shape, and density • Fluid density • Rate of penetration • Hole angle • Hole eccentricity • Pipe rotation, reciprocation Cuttings bed formation can still occur even with mud properties and flow rates optimized. Cuttings bed formation can be detected by excessive drag when the bottom hole assembly (BHA) is tripped out of the hole. However, it is possible to detect the potential problem of cuttings bed formation at an earlier stage by monitoring the standpipe pressure/pump output ratios and correlating the volume of cuttings at the shakers with the rate of penetration (ROP). Computer based hole cleaning models may also be used to detect the cutting bed formation. Solids control equipment, specifically the shakers, capability to handle high flow rates is a factor often not taken into account when considering pump output. This is particularly pertinent when considering invert emulsion muds in highly deviated wells. Invert emulsion muds tend to have high rheology when cold, and after a trip the mud can take 2 -6 hours to thin significantly to allow higher pump outputs. This can be overcome by changing the size of shaker screens, this may require going from 180 mesh to 100 mesh screens, allowing an increase in low gravity solids (LGS). The solution is to have enough shale shakers to handle both the low temperature rheology and the high flow rate. Factors Affecting Hole Cleaning There are many factors which affect cuttings transport and hole cleaning. All the factors that affect cuttings transport cannot be optimized simultaneously, usually some form of compromise is made.

Flow Rates 1


Pump output is the most critical factor for successful hole cleaning. Cutting bed formation is more pronounced as the hole angle increases above 30°. As a rough guide, the annular velocity required for cleaning 50-60° deviated wells is approximately twice that needed for vertical wells. The penetration rate should be controlled so that it does not exceed the pumps' cleaning ability. To ensure the maximum practicable pump rates, all efforts should be made to reduce frictional pressure losses and minimize pressure limitations, both on the surface and down-hole. Factors to be considered for maximizing flow rates are: Mud pumps and surface lines should be large enough to minimize pressure losses, or installation of a third mud pump should be considered. Consider using 5-1/2" or 6-5/8" drill pipe to reduce pressure drops and increase annular velocities. The larger pipe size also allows increased hook pull in long reach or tight holes. These advantages have to be weighed against a reduced resistance to compressive strength, higher drag and the extra time required to lay down the pipe at casing point. Whenever possible, design the BHA for minimum pressure loss in critical wells e.g.: • Utilize a positive displacement motor (PDM) and measurement while drilling (MWD) tools which offer the lowest pressure drop. • In some cases, use tools with bypass valves which will allow higher pump rates. This will allow the pumping of sweeps which contain high concentration of bridging materials i.e., STEELSEAL®, BARACARB®, BARO-SEAL®, BAROFIBRE®, etc. for hole cleaning if required. This type of sweep will create a matting action which aids in cuttings bed removal. • In deviated wells, decrease the number of drill collars and heavy weight drill pipe (HWDP) with depth. Use good hydraulics design and the correct mud density from the outset to minimize hole washouts. Minimize the mud PV. In the case of turbulent flow, reduce the YP whenever possible. Rheological Properties Rheological properties play a significant role in the hole cleaning ability of a fluid. The rheology must be fine tuned to maximize cuttings carrying capability and minimize the frictional pressure losses. Tools such as the FANN® 70 high-pressure/high-temperature rheometer should be used in the planning stages of a well to measure the down-hole rheology of a fluid. There are several rheological models applied in the oilfield, however Baroid believes the best model for predicting hole cleaning is the Herschel-Bulkley model. Particular attention should be paid to the n, K and Tau0 values opposed to the traditional value of yield point. Baroid has developed the DFG™ software package to calculate and monitor these parameters in the field. Hole Angle As hole inclination increases, cuttings removal becomes more difficult. For hole deviation from 0 to 40°, cuttings can usually be suspended by the fluid rheological properties. Hole angles above 40° can cause cuttings to fall downwards out of the fluid stream, forming cuttings beds. Hole angles from 40 - 60° are the most difficult to clean effectively. At these angles, the cuttings beds can slide or avalanche down the wellbore, complicating hole cleaning, and possibly leading to problems such as stuck pipe. 2


The recommended guidelines are: Hole angles from 0 - 40° Laminar flow and increased effective viscosity in the annulus is preferred. The annular slip velocity can be calculated using a variable speed viscometer with rotor RPM's selected to simulate the various annular shear rates. For hole angles up to 40°, the higher the shear stress at annular shear rate , the greater the cuttings carrying ability. All efforts should be made to minimize the plastic viscosity in order to reduce pressure losses and obtain a flatter viscosity profile, resulting in higher annular velocity in the outer portion of the hole at the same pump rate. This is easily achieved for both 17-1/2" and 12-1/4" holes. Hole angles above 40° Turbulent or transitional flow and low rheology mud is most effective in minimizing cuttings bed formation, breaking up cuttings beds and cleaning high angle holes. Remember that hole angles of 40-60° are the most difficult to clean. Lower mud rheologies (at the corresponding annular shear rates) will be required to obtain a Reynolds number above 2,100 and achieve turbulence. In this case, the cuttings and cuttings beds will be removed as ripples or dunes. Turbulent flow is not achievable in most 17-1/2" holes and some 12-1/4" holes due to a variety of reasons, including limitation of surface or down-hole equipment, washouts etc. In this case, a compromise for hole cleaning may be made as follows, using laminar flow: • Use the highest possible pump output to give maximum annular velocity. • Optimize the low shear rheology with BARAZAN® D PLUS or BARAZAN® PLUS in water-based muds and low shear rate rheology modifiers such as RM-63™ in conjunction with GELTONE® or SUSPENTONE™ in invert emulsion muds to suppress the formation of cuttings beds. • Use high initial gel strengths to give rapid suspension of cuttings when the pumps are off during surveys or trips. This should be combined with flatter gel strength development with time. • Use mechanical means (e.g. wiper trips, pipe rotation, reciprocation, and back reaming when top drive is available) and pills pumped in turbulence to assist with hole cleaning. Cuttings Size, Shape, and Density The size, shape and density of cuttings will affect hole cleaning. When cuttings are denser, larger and more rounded they are more difficult to transport out of the well. Hence specific well conditions may dictate bit cutter sizes.

Fluid Density Increasing the mud weight will cause increased buoyancy providing a significant improvement in hole cleaning at any hole inclination. In most cases, the selection of mud weight is usually predetermined by pore pressures, rock mechanics, in-situ tectonic stresses, fracture gradient, and density required to stabilize the hole and avoid cavings at a given hole or dip angle. 3


Rate of Penetration An increase in penetration rate results in a higher concentration of cuttings in the annulus. At hole angles below 40° the annular critical transport velocity and critical flow rate requirement to clean the hole increase with an increase in drilling rate, assuming there is no change in the muds effective viscosity. At hole deviations above 40°, a sub-critical flow rate and an increase in drilling rate will allow a cuttings bed to grow further, due to the increased generation rate of cuttings. Controlling the instantaneous drill rate is better than just averaging the footage made over one hour. If deep cuttings beds are allowed to form in deviated wells, they will be hard to remove and may result in packing-off and increased risk of stuck pipe or lost circulation. Achievable rates of penetration will be dependent on the transport efficiency of the fluid. Baroid uses a mathematical model (MAXROP) to determine the maximum recommended rate of penetration (ROP) in a given hole size at a given angle of deviation and flow rate. Hole Eccentricity Work conducted by Iyoho/Azar and Tomren has confirmed that in vertical holes, cuttings behavior is nearly the same for all hole eccentricities. In an eccentric annulus, there is a noticeable reduction in cuttings velocity in the reduced area of the annulus. Since a corresponding increase in cuttings movement will occur in the enlarged section, the effects appear to cancel out each other. Baroid's engineering software MAXROP clearly demonstrates for holes above 40°, the cuttings build-up is at a minimum when the inner pipe is concentric with the wellbore. The rate of buildup of a cuttings bed is faster with positive hole eccentricity. Preventing and Curing Hole Cleaning Problems When it is not possible to completely remove the drill cuttings from the wellbore with circulation, these additional hole cleaning methods should be implemented: Pipe rotation and reciprocation

Pipe rotation and reciprocation will assist in mechanically disturbing a cuttings bed, allowing better cuttings removal. Field studies indicate that pipe rotation while drilling enhances the hole cleaning efficiency by approximately 25%. If extensive sliding for directional work is being performed, occasional high speed rotation of the drilling assembly will aid in reduction of cuttings bed formation.

Short trips and back-reaming

Periodic short trips and/or back-reaming are used to remove cuttings beds by mechanical agitation. This is very effective when a top drive is available, because the short trip while pumping out, enhances hydraulic and rotational disturbance of cuttings beds. Excessive back-reaming should be avoided to prevent unnecessary hole enlargement.

Hydraulic boost

Use riser booster pumps if required, especially while drilling the 12-1/4", 81/2", or smaller size hole sections.

4


Hole cleaning sweeps Always watch for sweeps return at surface and evaluate effectiveness. Keys to successful sweeps are to ensure that enough is pumped, maintaining pipe rotation and pump rate at all times to avoid packing off the hole with cuttings. High Viscosity For hole or casing sections with a deviation less than 40°, a high viscosity pill can be made by increasing both the YP and the low shear rheology, or only the low shear rheology corresponding to the annular shear rates. Sweep volume should be greater than 300 feet of annular height. High Density Pills High density pills are usually mixed at 2 lb/gal (or more) above the circulating mud density. The buoyancy effect of the higher density will increase the carrying capacity. However this type of pill will have a limited effect in removing existing cuttings beds in highly deviated wells, unless it is preceded by a low-viscosity scouring pill in turbulent flow. A high density pill should not be used if it is likely to cause lost circulation. Low Viscosity Pills A low viscosity pill pumped in turbulent flow has been effective in many high angle wells (above 40°). The injection of a low viscosity pill into an otherwise laminar flow circulation system will usually promote local turbulent flow. A low viscosity pill, combined with pipe rotation, is the most effective method of disturbing the cuttings bed and cleaning the hole. Low viscosity pills are usually water or brine-based in water-based mud systems and base fluid in invert emulsion systems. Tandem Pills Tandem pills typically consist of a low viscosity pill (water or oil-based) followed by a weighted viscous pill. The pills must be pumped in transitional or turbulent flow for maximum benefit and to prevent high-side channeling by the low viscosity pill. A tandem pill might consist of 30-50 bbls base fluid (water, oil or synthetic) followed by a weighted pill, sized to balance out at the circulating system mud weight. The weight should be as high as feasible, taking into consideration rig limitations and formations exposed. Prior to pumping such a pill, the effect on the hydrostatic head and the resultant well bore stability should be carefully examined. The low viscosity pill in turbulent flow will scour cuttings from the cuttings bed into the main annular flow path. The weighted pill with its increased buoyancy will help in lifting the disturbed cuttings out of the hole when they fall out of the low viscosity pill. BAROFIBRE Pills Developments in hole cleaning additives have shown that certain fibrous loss circulation materials (LCM) will effectively clean an angled wellbore by the process of particle interference at the front of the plug flow parabola. BAROFIBRE has been used effectively in many mud systems. BAROFIBRE is composed of processed wood fibers that are treated with an amine to make them 5


preferentially oil wet. BAROFIBRE has five times the surface area of normal LCM and, in hole cleaning applications, acts much like asbestos fibers in water-base muds. Unlike many conventional LCM's, BAROFIBRE does not plug shale shaker screens. Circulating before trips The minimum on-bottom circulation time prior to tripping is influenced by the hole size and inclination. Deviated holes will not be completely cleaned of cuttings if only the theoretical annulus volume is circulated before trips. The minimum recommended guidelines are shown in the following table: Deviation

Circulation Factor 17-1/2/16"

12 1/4"

8 1/2"

Vertical

1.5 x Bottoms Up

1.3 x Bottoms Up

1.3 x Bottoms Up

10-30°

1.7 x Bottoms Up

1.4 x Bottoms Up

1.4 x Bottoms Up

30-60°

2.5 x Bottoms Up

1.8 x Bottoms Up

1.6 x Bottoms Up

60° +

3.0 x Bottoms Up

2.0 x Bottoms Up

1.7 Bottoms Up

The circulation factor applies only to that section of the hole within the deviation ranges specified. To determine the total time required to effectively clean the hole, the deviation of the wellbore along its entire length must be considered. These are only guidelines; the key is to circulate until the hole is clean prior to tripping.

6

Drilling Conditions Hole Stability

SOP Code: HS Revision Date: 02/12/1997; Amended May 2005

Hole Stability Introduction Borehole stability is the basis of any mud program, and all mud systems should be designed with that in mind. Borehole stability is a reflection of both physical and chemical characteristics of the drilling fluid, plus the use of good drilling practices. Once an exposed formation becomes unstable, restabilizing is very difficult and usually expensive. A preventative treatment is always more cost effective than curing a problem after it has occurred. One key to successfully drilling unstable formations is to minimize the time the formation is exposed. Casing should be run as soon as possible. Common indicators of borehole instability are: • Cavings at the shakers • Increased torque and drag • Packing off while tripping or making connections • Hole collapse Note that some of these indicate other problems, such as hole cleaning. Causes Physical Stability Different types of formations can give stability problems. A common problem in surface holes is poorly cemented sands and gravels that can run and quickly fill the wellbore; however, the most troublesome formations are usually shales. Mud density may be a critical factor in controlling the stability of the wellbore. In general, the greater the hole angle, the higher the mud weight required to stabilize formations. It should be noted that on high angle wells there is a convergence between fracture gradient and equivalent circulating density (ECD). Fracture gradient is true vertical depth (TVD) dependent, but ECD is measured depth (MD) dependent. The success in drilling these sections depends a great deal upon the insitu tectonic stresses and formation pressure. Consequently, even with all established drilling parameters optimized, hole instability can still be experienced if these stresses are abnormal. This may be due to the peculiarity of the dip of the formation or to the contact angle of the wellbore to the bedding planes.

1


Chemical Stability The interaction of drilling fluid filtrates and the formation can cause chemical instability. The chemical composition of a drilling fluid (and its filtrate) is a key design factor that can facilitate the fluid's ability to maintain borehole stability and minimize damage to potentially productive zones. In shales, the filtrate movement through microfractures is often a capillary action. The spontaneous movement of fluid is not slowed by reducing the rate of filtration. However, viscosifying the filtrate, sealing the fractures, or adjusting the filtrate chemistry may reduce fluid movement in a fracture. Greater borehole stability in some shales can be achieved by maintaining a low pH and alkalinities. Preventing and Curing Borehole Stability Problems A stable hole begins with proper mud density, API/HPHT fluid loss and chemical composition. Other factors such as rheology also play a role. Mud Density The need to pre-empt the development or aggravation of borehole instability problems with higher mud weights is especially important in highly deviated holes. The duration of the "response window", the time between recognizing the existence of hole instability and affecting a corrective response before a hole collapse, is limited. A rule of thumb is to increase mud weight 0.5 lb/gal for every 30° of angle; however, Baroid has developed a borehole stability model that uniquely couples the mechanical and chemical aspects of drilling fluid to shale interactions. The model allows Baroid to determine the optimum drilling fluid parameters (e.g. mud density and salt concentration) to alleviate borehole stability problems with oil, water and synthetic/esterbased drilling fluid systems. A paper detailing this model is available. In some cases excessive mud weight can cause borehole instability problems. The hydrostatic pressure exerted by the column of fluid can cause an increase in near wellbore pore pressure, which may in turn cause a failure of formation integrity. Chemistry of Drilling Fluids1 The chemical properties that affect borehole stability are the same ones that contribute to shale and cutting inhibition. The most effective form of inhibition is to use an invert emulsion system such as oil mud or PETROFREE®. Even with these systems, hole stability problems can occur due to incorrect water phase salinities. In water-based muds, the use of products that retard hydration and dispersion of clays associated with shale formations may be necessary. 1

Borehole Stability Model to Couple the Mechanisms and Chemistry of Drilling Fluid/Shale Interactions F. K. Mody - Baroid Drilling Fluids; A.H. Hale - Shell Development Company

Rheology High viscosities are sometimes used to control poorly cemented, surface formations. Funnel viscosities in the range of 300 seconds per quart and higher have been utilized while drilling highly unconsolidated gravel formations. It is important to have sufficient hole cleaning rheology whenever unstable formations are encountered so that cavings are removed from the wellbore. The hole should always be circulated clean before any trips. 2


Materials and Systems To stabilize a poorly cemented formation, high viscosities can be obtained with AQUAGEL™ GOLD SEAL (premium bentonite) and BARAZAN® PLUS (xanthan gum). BARAZAN PLUS can be solubilized in low pH water without high yield, and then treated with caustic soda to increase the rheology after all the required polymer is mixed. Baroid's MAXDRIL-N™ system uses mixed metal silicate chemistry to give very high rheological properties, but fragile gels. This will cause the mud to act as a solid when left static, holding back loose formations, but will not cause the high swab and surges that could induce hole instability problems. A wide range of products and systems can be used to stabilize troublesome shales. The most inhibitive systems are invert emulsions. In some cases, where interstitial salinities vary widely then the use of an "all oil" system, such as COREDRIL-N™, may be needed. In water-based muds, borehole stability can be improved by maintaining low alkalinities and substituting KOH for caustic soda, or deriving K+ ion content from KCl or K Acetate. Other additives that can be used are: • BARO-TROL® PLUS • EZ-MUD™ • GEM™ • CLAYSEAL® The highly inhibitive BARASILC™/GEM mud system can be used when borehole stability is a concern. This is a soluble silicate based mud system that has been used to stabilize extremely reactive shales and chalk formations. BARASILC/GEM has been demonstrated to reduce the transmission of hydraulic pressures in reactive and tectonically stressed shales.

3

Drilling Conditions Horizontal Drilling

SOP Code: HD Revision Date: 05/14/1999; Amended May 2005

Horizontal Drilling Introduction Horizontal drilling has increased worldwide. It is used to revive production rates in old fields and reduce the required number of wells in new fields. Drilling horizontal wells is more complicated than drilling vertical or near vertical wells; therefore, the pre-well planning phase is more involved. The following areas should be considered when preparing a drilling fluids program: • Reservoir Protection • Borehole Stability • Hole Cleaning • Lubricity • Solids Control • Environmental Regulations Causes of Horizontal Drilling Problems Reservoir Protection Whenever a reservoir is drilled overbalanced, especially a depleted reservoir, there will inevitably be invasion of the formation by mud filtrate and whole mud. This can cause considerable damage and reduce the production rate (and profitability) of the well. Fluid invasion is more critical in long open hole reservoir sections. Adequate return permeability work should be performed on proposed drilling fluids to ensure the formation is adequately protected. Borehole Stability Instability can be induced chemically, mechanically, or both. It is important to determine the correct mud weight required to give mechanical stability when planning horizontal wells. It should be noted that the required mud weight can be significantly higher than the mud weight required to drill a vertical well in the same formation. Mechanical stability is dependent on the rock mechanics of the borehole. Excessive annular velocities can cause erosion of unconsolidated formations. Underbalanced drilling can also cause wellbore instability. The chemical interaction between a reactive formation and the drilling fluid can also be the cause of many problems. The types of formations that can give problems are swelling or dispersive formations, such as shales. Shales weaken when in contact with poorly inhibitive muds. This reduction of strength can lead to mechanical failure. Once a borehole has destabilized, restabilizing it can be very difficult and expensive; therefore, effective pretreatment is always recommended. 1


Hole Cleaning It is important to realize that the horizontal section is not the most difficult to clean. Problems in hole cleaning usually occur when the hole angle is between 40° and 60°, in the build section of the well, further up the annulus, or when sliding / steering. Hole cleaning in horizontal wellbores can be summarized as: Turbulent flow is preferred over laminar flow. Viscous fluids/sweeps do not increase, and can actually decrease, flow rates below the drill string where the cuttings beds accumulate. To clean these cuttings beds will require mechanical agitation by the pumping of low viscosity sweeps and by pipe rotation. The low viscosity sweep is often followed by a high density pill to assist in "floating" cuttings out of the hole. BAROFIBRE® pills are another technique which has been used to follow low viscosity sweeps. The wellbore should be circulated clean on a regular basis. See detailed Hole Cleaning procedures. Lubricity Drilling torque is usually high, caused by a high degree of drill pipe contact with the wellbore and casing. Cuttings accumulation on the low side adds to the torque, and can frequently be seen as drag on trips out of the hole and on connections. Maintaining adequate lubricity can be a problem for medium to long radius wells. Torque and drag are also seen if a formation is not sufficiently inhibited and is swelling or heaving. Maintaining a system in as clean a state as possible will aid in keeping torque and drag values to a minimum. Lubricants treatments can help maintain the ability to slide for directional needs. Torque and drag problems must be identified before the appropriate lubricant treatment can be recommended. Solids Control Solids control is critical in high angle wells, because solids can rapidly build up. This is because build-up is mechanically induced by: • "Mortar and Pestle" effect of drill pipe grinding on the low side of the hole. • Longer transportation time of cuttings from bit to surface • Borehole and cuttings erosion in turbulent flow • Bit design coupled with high RPM mud motors Preventing and Curing Horizontal Drilling Problems Reservoir Damage Tight fluid loss control and additions of bridging materials to the mud system will reduce reservoir invasion by mud and filtrate. Baroid's DRIL-N™ family of fluids offer performance and production zone protection to prevent invasion and damage to the formation.

2


Borehole Stability Correct mud weight and adequate inhibition are the keys to borehole stability in horizontal wells. In unconsolidated formations, annular velocities may need to be controlled. Hole Cleaning Pump output is the key to good hole cleaning. Mud flowrates in conjunction with optimized fluid rheology, that promotes turbulent flow, is recommended. Turbulent flow in the horizontal section promotes good hole cleaning and minimizes the formation of cuttings beds. Fluid rheologies still need to be high enough to transport cuttings out of the vertical section of the well and for the fluid's weighting material to remain suspended. Periodic sweeps of the hole with small volumes of water or base oil, followed by base mud or weighted or viscous sweeps offer a practical way of cleaning both horizontal and vertical sections. Weighted pills rely on buoyancy to lift cuttings and have been successful in the field. Exercise caution when using low weight or high weight sweeps, as they may cause borehole instability and/or lost circulation problems. Lubricity Oil-based or synthetic fluids are often used in horizontal drilling because of their excellent lubricating, and inhibiting properties. Attention to cake quality will contribute to better transfer of weight to bit. Lubricants for water-based fluids can also be used if environmental regulations dictate water-based fluids. The lubricant selected will depend on whether the source of the drag is coming from cased hole metal, the formation, or is caused by high temperature and pressure effects on water-base mud. Inhibitive additives will also reduce torque and drag if a reactive formation is exposed. Solids Control High efficiency flow line shale shakers and centrifuges are a minimum for horizontal drilling. Materials and Systems Baroid's DRIL-N™ family offers selectivity, performance and formation protection with seven unique and specialized systems for horizontal drilling of producing formations. BARADRIL-N BRINEDRIL-N COREDRIL-N MAXDRIL-N QUIKDRIL-N SHEARDRIL-N SOLUDRIL-N Oil-based or synthetic muds such as INVERMUL®, XP-07™, PETROFREE® and PETROFREE® LE, with their excellent inhibitive qualities and inherent lubricity are also recommended for horizontal drilling where environmental regulations, logistics and economics allow. Additions of CMO 568™, an oil mud lubricant, can further improve lubricity and filter cake quality. 3


BARACARB®, STEELSEAL® and BAROFIBRE are additives that can reduce fluid invasion by bridging across porous sands and improve filter cake quality. GEM™, CLAYSEAL®, EZ-MUD™, BAROTROL® PLUS contribute to the inhibition of reactive formations. DRIL-N-SLIDE™, EP MUDLUBE®, BARO-LUBE™ GOLD SEAL, ENVIRO-TORQ® and TORQ-TRIM® are lubricants that can be used in water-based muds.

4

Drilling Conditions High Temperature Wells

SOP Code: HT Revision Date: 02/11/1997; Amended May 2005

High Temperature Wells Introduction Wells with a bottom hole temperature in excess of 300°F are considered high temperature wells. High temperatures can create problems with water-based drilling fluids by altering the behavior of the fluids. Chemical reactions that may affect the performance of drilling fluid additives are accelerated at higher temperatures and there is an increased tendency for thermal flocculation. Thermal degradation of drilling fluid additives may result in unstable rheology, filtration properties and alkalinity. These altered properties can result in reduced penetration rates, swabbing, increased circulating pressure losses, lost circulation, borehole instability and possible stuck pipe. Controlling fluid properties at high temperatures sometimes requires expensive maintenance treatments. Common Problems with Water-Based Systems Lack of Free Water High pressure wells require high density mud. As additional solids (both desirable weight material and undesirable low gravity drilled solids) are incorporated into the system, water requirements become greater. Additional solids increase the surface area to be wet, leaving less free water available. Consequently, the viscosity of the mud increases. Colloidal particles which have a greater specific area are of particular concern because they bind tremendous amounts of water. The free water available in a high density mud can quickly become depleted leading to poor flow properties and gelation. When the mud is subjected to high temperature, free water will be depleted more rapidly due to evaporation at the surface. Replacement of evaporation water is the starting point when determining water addition requirements. Deterioration of Chemicals Under High Temperatures The temperature stability of thinners, filtration control agents, and clays is very important in the planning stages. Degradation of drilling fluid chemicals can result in unstable mud properties resulting in excess circulating and conditioning time. It is common for wells to be drilled successfully using mud additives that degrade at temperatures well below bottom hole temperatures. Mud temperatures approach bottom hole temperature only when circulation is interrupted for extended periods of time. Mud additive degradation may take place near bottom in a hot hole, but the volume of mud affected is usually relatively small. When high viscosities and gel strengths are caused by a break down in a mud systems thermal stability, logging may become difficult, and surge and swab pressures may become a problem. Carbonate contamination, caused by thermal degradation, is sometimes a byproduct when drilling high temperature wells. Carbonate contamination causes increased rheology and fluid loss, with reduced pH, reduced pf and increased mf. Carbonates can be treated out chemically by 1


raising the pH and adding lime or other soluble calcium salts to form insoluble calcium carbonate. BARACOR® 95 is a highly active carbon dioxide inhibitor and is thermally stable up to 350°. Thermal degradation of mud materials may also generate small amounts of hydrogen sulfide. Hydrogen sulfide content can be monitored with a Garrett Gas Train if the presence of sulfides is suspected. BARACOR® 44 or NO-SULF® should be used as hydrogen sulfide scavengers. To limit thermal degradation, use products with a higher temperature stability. Increasing pH to 9.5 - 10.5 and using an oxygen scavenger such as BARASCAV™ D or BARASCAV L can extend the stability of some polymers by up to 25°F by limiting hydrolysis and oxidation. Bentonite/Clay Content AQUAGEL™ GOLD SEAL (3 - 7 lbs/bbl for optimum fluid properties) is recommended for HTHP filtration control and barite suspension. Additions of pre-hydrated AQUAGEL GOLD SEAL should be buffered and completely deflocculated with THERMA-THIN® before adding to the system. At low mud weights, the reactive clay content of the mud should be controlled at less than 20 lbs/bbl. At high mud weights, the reactive clay content should be kept below 12 lbs/bbl. Dilution with water or new whole mud should be done along with the optimum use of all relevant solids control equipment. At high mud weights and high bottom hole temperatures, the important mud parameters affecting gel strength are:

• Concentration and quality of bentonite • Concentration and cation exchange capacity of drilled solids (low gravity solids) • Concentration, thermal stability and effectiveness of deflocculants • Concentration, thermal stability and effectiveness of viscosifiers and other polymers • Contaminants Sepiolite clay is thermally stable to 500°F but it may be unacceptable because of the rod-like nature of the clay particles and consequent poor filtration control. Planning High Temperature Water-based Muds Mud system planning and proper product application is essential for maintaining fluid stability when drilling in high temperature environments. It is important to select the proper drilling fluid and products to control rheology and to provide filtration control under extreme conditions. Lab testing is an essential step in planning high temperature drilling fluids. All potential drilling conditions and any anticipated problems should be specifically addressed prior to encountering a high temperature situation. Drilling conditions can be simulated in the lab using:

2


• HTHP Filtration Conventional static aging cells • FANN® 70 rheometer, which can test rheology under varied conditions up to 500°F and 20,000 psi • FANN 50 rheometer, which can test rheology under varied conditions up to 500°F and 1,000 psi • FANN 90 dynamic filtration under varied conditions up to 500°F and 500 psi Static aging is an effective technique for testing barite sag at high temperatures. The Baroid Fluids Services Houston lab can also evaluate barite sag, in different mud systems at specific well angles, using High Angle Sag Test (HAST) equipment. Specific formulations can be tested first in conventional aging cells at the desired temperature and duration, then checked with the FANN® 70 rheometer. Using consistent test methods is a key to meaningful static aging test results. Baroid recommends the following standard pressures in aging cell tests: Mud Volume and Pressures for High Temperature Aging Coefficient Aging Temp. Water Vapor Expansion for F° Pressure PSI Water

Suggest Applied Pressures PSI

Mud Volume 250 ml cell

In Cell, ml 500 ml cell

300

67

---

100

200

---

350

135

---

150

200

---

400

247

1.16

250

---

350

450

243

1.20

300

---

350

500

680

1.27

375

---

350

550

1100

1.36

500

---

300

600

1513

1.17

580

---

300

Oven temperature versus time must be determined; oven heating times of 16 hours or 24 hours are commonly used, but longer oven times may be used if desired. Cell handling procedures: • Pre-heat oven to desired temperature. • Static age for specified period. • Turn off heat. • Open oven door and allow to cool for 30 minutes. • Remove cell and immerse in water to cool. • Careful visual and odor inspection when opening cell. • Remix after aging, by stirring for 5 minutes at low speed (11,000 rpm) on a FANN® or low setting on a Hamilton Beach blender (13,000 rpm) mixer prior to testing. 3


Note: If cell contains no pressure when opened, the test is invalid and must be repeated. Baroid recommends that similar procedures be used for hot roll aging. High Temperature Water-based Systems Baroid has developed water-based mud systems that provide stable mud properties in high temperature environments. The systems include: • CARBONOX®/AKTAFLO-S™ • HYDRO-GUARD® • Lime/QUIK-THIN™ Thinner • POLYNOX® • THERMA-DRIL™ • THERMA-THIN® HYDRO-GUARD HYDRO-GUARD water-based fluid is a clay-free system designed for maximum shale inhibition in highly reactive formations like those found in the Gulf of Mexico. The HYDRO-GUARD system can provide wellbore stability, high rates of penetration, and acceptable rheological properties over a wide range of temperatures (40°F to 300°F), with the added benefit of allowing cuttings discharge based upon water base environmental restrictions. The HYDRO-GUARD system features two proprietary polymeric additives used in conjunction with GEM in 10% salt or higher salinity. Product

Function

CLAY GRABBER

Flocculant, stable to 300°F (149°C)

CLAY SYNC

Shale stabilizer, stable to 300°F (149°C)

GEM

Shale stabilizer/encapsulator - lubricant

THERMA-DRIL THERMA-DRIL systems are designed for temperatures above 350°F and can be used with inhibiting salts such as NaCl, KCl (up to saturation, depending on the presence of reactive clays and shales in the area), lime and gypsum. THERMA-DRIL muds are usually new mud systems. Existing systems can be converted to a THERMA-DRIL system, however existing muds that are solids laden or contain large quantities of products susceptible to thermal degradation should not be converted.

4


The THERMA-DRIL system is formulated from single purpose, thermally stable products. Product

Function

THERMA-THIN®

Liquid polymeric deflocculant, stable to above 400°F.

THERMA-CHEK®

Filtration control polymer, stable to above 450°F.

THERMA-VIS™

Viscosifier, stable to above 600°F.

BARANEX®

Filtration control polymer, stable to above 380°F.

AQUAGEL™

API bentonite

BARACOR® 95

Carbon dioxide scavenger

BARASCAV™

Oxygen scavenger

Caustic Soda

pH control

THERMA-THIN® THERMA-THIN, an anionic acrylic copolymer, is used in water-based systems to control rheological properties and minimize thermal flocculation. This product deflocculates most waterbased systems and reduces shear strength development. THERMA-THIN is effective in the presence of salt and divalent ions. It is stable at temperatures above 400°F (205°C). THERMATHIN is not pH dependent. When used alone or with lignosulfonates, it will provide a costeffective high performance system for high temperature applications. BARANEX® BARANEX® is a modified lignin powder which provides filtration control in water-based fluids. It is compatible with lignosulfonates and lignites. BARANEX is capable of handling common mud contaminants, particularly calcium and chloride. This product does not require pH to solubilize and functions in wide ranges of pH conditions. BARANEX provides filtration control at temperatures approaching 400°F (205°C) in water-based fluids. BARANEX replaces basic filtration polymers that lose their ability to control HTHP filtration rates at elevated temperatures. THERMA-CHEK THERMA-CHEK is a vinyl amide/vinyl sulfonate copolymer that provides filtration control in water-based fluids at temperatures up to 450°F (232°C).THERMA-CHEK can be used to supplement other filtration control agents beginning at temperatures of 300°F. This product provides filtration control for a wide variety of mud systems. It is tolerant to salt and divalent ions. THERMA-CHEK is not pH dependent. THERMA-CHEK is the primary filtration control agent in the THERMA-DRIL water-based drilling fluid system designed for high temperature stability. THERMA-VIS THERMA-VIS, a synthetic magnesium silicate, is a viscosifier specifically formulated for geothermal wells. It does not thermally flocculate, and provides stable viscosity at temperatures up to 700°F (371°C). THERMA-VIS can be used as a viscosifier in water-based fluids in high temperature applications. The following tables lists Baroid mud systems and their approximate temperature limitations. 5


Water-based Mud Systems

Approximate Maximum Temperature Limitations

CARBONOX/AKTAFLO-S

425-450°F (218-232°C)

CARBONOX/QUIK-THIN

300-325°F (149-163°C)

CAT-I®

300°F (149°C)

Gyp/QUIK-THIN

300-325°F (149-163°C)

HYDRO-GUARD®

300°F (149°C)

KOH/K-LIG®

375-400°F (191-204°C)

Low-pH ENVIRO-THIN™

300-325°F (149-163°C)

POLYNOX

325-350°F (163-177°C)

THERMA-DRIL

475- 500°F ( 246-260°C)

Oil-based Mud Systems


INVERMUL®

425-450°F (218-232°C)

ENVIROMUL™

425-450°F (218-232°C)

INVERMUL RF

325-350°F (163-177°C)

ENVIROMUL RF

325-350°F (163-177°C)

INVERMUL 50/50

300-325°F (149-163°C)

ENVIROMUL 50/50

300-325°F (149-163°C)

BAROID 100

475-500°F (246-260°C)

DRIL-N™ FLUIDS Systems


COREDRIL-N™

375-400°F (191-204°C)

Synthetic-based Mud Systems


ACCOLADE®

350°F (177°C)

ENCORE®

400°F+ (204°C+)

PETROFREE®

325-350°F (163-177°C)

PETROFREE 100

325-350°F (163-177°C)

PETROFREE LE

375-400°F (191-204°C)

PETROFREE LE 100

375-400°F (191-204°C)

XP-07™

375-400°F (191-204°C)

XP-07 100

375-400°F (191-204°C)

6

Drilling Conditions Hydrogen Sulfide (H2S)

SOP Code: H2S Revision Date: 02/11/1997; Amended May 2005

Hydrogen Sulfide (H2S) Introduction Hydrogen sulfide is an extremely dangerous, highly toxic and corrosive acidic gas that occurs naturally in many formations. It is formed primarily by the decomposition of organic matter that contained sulfur. Sources of hydrogen sulfide in drilling operations are: • Formation • Thermal degradation of mud additives • Bacterial degradation of mud additives It is important to monitor sulfide concentration if H2S is suspected. Sulfides should be monitored with the Garrett Gas Train and reported on the daily mud report. Indicators of H2S include: • Iron sulfide detecting solution • Gas analysis • "Rotten egg" odor • Observation of corrosion patterns Characteristics of Hydrogen Sulfide Gas The characteristic odor of H2S is a smell like rotten eggs. However, it is imperative to understand that relatively low concentrations of hydrogen sulfide gas deaden the olfactory nerves, eliminating the sense of smell as a detection tool. Specific gravity of the gas is greater than air; therefore, the gas will tend to settle in low areas such as the substructure cellar and near mud pits. The gas forms an explosive mixture with air in the 4.3% to 45% concentration range. This is particularly dangerous when compared to methane which is combustible in the 5% to 15% range. Hydrogen sulfide has an ignition temperature of 500°F compared to 1,000°F for methane. H2S burns with a blue flame producing sulfur dioxide, another toxic gas. H2S is soluble in water, producing a weak acid. H2S Dangers H2S toxicity is the primary concern with hydrogen sulfide contamination, as shown in the table below.

1


Concentration, %

PPM

Effects

0.001

10, 1/1000 of 1%

Can smell; safe for 8 hours.

0.01

100, 1/100 of 1%

Kills smell in 3 to 15 minutes; may burn eyes and throat.

0.02

200, 2/100 of 1%

Kills smell quickly; stings eyes and throat.

0.05

500, 5/100 of 1%

Loss of balance; respiratory difficulties in 30 to 45 minutes.

0.07

700, 7/100 of 1%

Unconscious in less than 15 minutes; death will occur if not rescued promptly; immediate artificial resuscitation is required

0.1

1,000, 1/10 of 1%

Permanent brain damage. If not rescued, immediate death.

Small amounts of H2S in a drilling fluid can cause flocculation due to a rapid reduction in the pH. Hydrogen sulfide can cause severe corrosion. H2S corrosion is manifested by pitting and sulfide stress corrosion cracking (SSCC) which results in pipe washout and/or catastrophic failure. Close observation will show the pitting form of attack on the surface of the metal. Pitting by H2S attack develops in round edges and round bottom pits. These pits concentrate stress, enhancing stress corrosion failure. Hydrogen sulfide gas is soluble in water if the pH is above 11. After the pH is reduced, H2S will break out of solution. Preventing and Curing H2S Problems The Garrett Gas Train is used to monitor sulfide concentrations. The gas train separates the gas from the liquid, thereby preventing contamination of the gas by the liquid phase. A Draeger tube is the preferred H2S detector for quantitative sulfide analysis, although a lead acetate paper disk can be used in the Garrett Gas Train for determining the presence of H2S. No known mud component or other contaminant causes the same color change in a Draeger tube that H2S does. Two different Draeger tube are available to test for either high or low concentrations of H2S. Prevention and cure of hydrogen sulfide contamination: Remove the cause of H2S entry into the wellbore by weighting up the mud. Raise pH with lime (Ca(OH)2) and/or caustic soda (NaOH). A pH of 11.0+ is recommended. Precipitate H2S or soluble by-products with a sulfide scavenger (NO-SULF®, BARACOR® 44). Remove the deposit with scale inhibitor. Treat the fluid by applying sufficient filming amine to coat all metal surfaces, mitigating sulfide stress corrosion cracking, hydrogen assisted cracking and stress corrosion fatigue. 2


Degasser as an Assist in Controlling H2S When gas cutting of the mud is experienced, the blowout preventers are immediately closed and normal circulation maintained through the choke lines (choke wide open) to the choke trap. Consider the choke line system pressure loss if drilling in a near balance condition. A degasser is a barrel like apparatus suspended upside down in the shaker tank with the lower lip of the barrel below normal mud level. The mud and gas flows into the side of the barrel. A four-inch vent line leads from the top of the barrel to a safe distance from the mud stream in the choke trap and the gas can be vented and flared with safety through the four-inch line. The mud containing residual gas then passes out the bottom of the choke trap and is drawn into the degasser. The degasser operates under a vacuum of 10-20 inches of mercury and is capable of extracting virtually all of the remaining gas by allowing the mud to flow over a series of baffles. Vacuum in the degasser is maintained by a jet on the discharge side of the degasser and by a vacuum pump mounted on the top. The vacuum pump discharge should be vented at a safe distance from the rig and flared if necessary. A partition in the mud tank between the intake and the discharge of the degasser separates the gas cut mud from the degassed mud. The jet is operated by the standby mud pump. Adequate ventilation and air blowers, where necessary, are generally used to keep the rig floor and the area under the rig floor relatively free of any residual H2S gas. Normally, after circulating for a few hours with the blowout preventers closed, the amount of gas will decrease to the point where the BOP's can be opened and drilling operations can be resumed without the use of the choke trap. The degasser will continue to be employed until the mud is gas free. This may require up to one or two days of more or less continuous operation. If the gas cutting exists for periods in excess of this, a small amount of weight material will usually be added to the mud. This will normally eliminate the continuous type of gas cutting although trip gas may still persist. Hydrogen Sulfide Precautions Each worker should be informed of the characteristics of H2S and its dangers, safety procedures to be used when it is encountered or suspected, and recommended first-aid procedures. Install H2S monitors on the rig. Instructions in the use of protective equipment available should be given to all employees. Upon entering area suspected of containing hydrogen sulfide, a test should be made to determine if the gas is present and its concentration. Do not try to determine the presence of H2S by its odor. The sense of smell is rapidly paralyzed by hydrogen sulfide. Personnel should watch out for each other. Where possible, they should work in pairs. Warning signs should be used to warn the uninformed. Adequate ventilation should be maintained to keep the gas removed from the work area if possible. Never enter an enclosed place where H2S may have accumulated without wearing proper respiratory protective equipment. If the worker is over an arm's length away, a safety belt 3


should be secured to a life line and the life line should be held by a responsible person who is in the clear. Protective equipment should be readily available to those who work where H2S may be present. First aid for victims of H2S is based primarily on rescue breathing and includes the following: a)

Move the victim into fresh air at once. Don't jeopardize your own safety. Wear protective equipment.

b)

If the victim is unconscious and not breathing, immediately apply mouth-to-mouth artificial respiration and continue it without interruption until normal breathing is restored.

c)

Call a doctor.

Materials and Systems Caustic soda and lime can be used to increase the pH. Zinc-based scavengers such as NOSULF® and BARACOR® 44 should be used to treat out hydrogen sulfide in both water-based and oil-based muds. NO-SULF contains zinc carbonate, so lime should be added to prevent a potential carbonate problem. Other sulfide scavengers include zinc chelate and Ironite sponge. BARAFILM™ can be used in cases of severe contamination to coat and protect the drill string and rig equipment from corrosion. STABILITE® can be used to remove scale deposits.

4

Drilling Conditions Lost Circulation

SOP Code: LC Revision Date: 04/23/04 Revision v1.0; Amended May 05

Lost Circulation Introduction Lost circulation or the loss of mud returns describes the complete or partial loss of whole mud to a formation as a result of hydrostatic and/or annular pressure exerted by a drilling fluid. Losses can result from natural or induced causes. They are identified by a reduction in the rate of mud returns from the well compared to the rate at which the mud is pumped down hole (flow out < flow in). This causes a decrease in the mud volume and impairment of drilling operations. In extreme cases, lost circulation can lead to well control problems, including blowouts. Losses can add extensively to the overall well cost, both in time and in mud requirements. Better planning, preparation, and having proven solutions on hand before a loss of circulation occurs can reduce or eliminate substantial lost time and cost. In the past the chief response to lost circulation was the use of cheap lost circulation material (LCM) that were commonly used in the area and easily available. With the rise in the costs of both drilling fluids and rig time a more pro-active approach is required, and the current emphasis is to study the particular area and recommending the materials, techniques, and methods for prevention of the loss prior to beginning drilling operations. Potential Types of Lost Circulation Zones Lost circulation is classified into four basic types: • • • •

Highly permeable formations Naturally fractured formations Cavernous formations Induced fractures due to a pressure imbalance

Permeable Zones (Pores/Matrixes) Loss rates to permeable zones may range from a slight seepage to several percent of the pumped volume as more of the zone becomes uncovered. A permeable zone typically consists of coarse sands and/or gravel, and is more often found in surface intervals. Shell beds, gravel beds, reef deposits and depleted reservoirs can also be classified as permeable formations. The hole may or may not stand full with the pumps off. Naturally Fractured Formations Losses to naturally fractured formations can be up to a 100% loss of returns with no preceding gradual losses. These losses may occur at overbalances as low as 50 psi. The hole normally will not stand full. Natural fractures and fault zones can be encountered at any depth but are most likely to occur in tectonically-stressed areas at shallow to intermediate depths. Cavernous/Vugular Formations Losses to cavernous/vugular formations are normally the easiest type to recognize. Immediate 100% loss of returns takes place, accompanied by loss of weight on bit. They are caused by the dissolution of limestones, dolomites, and salts by ground water; this creates caverns that vary in 1


size. The likelihood of success in regaining returns is limited. The most common solution is to drill blind for several feet below the zone, then to run casing. Induced Fractures Loss of mud to induced fractures is the most common type of lost circulation. These losses can be slow, moderate or complete, at any depth. Induced fractures generally occur when the ECD exceeds the local fracture gradient, causing the formation to break down. These losses can also occur during pressure surges, i.e. during connections or during trips. Induced fractures often occur during routine increases of mud weight or during a kick and kill operation. The hole may stand full or drop to an equilibrium point. Wellbore breathing is a particularly troublesome type of induced fracturing. Here the fractures take fluid while the well is circulating, but once the pumps are shut off some to all of that lost fluid returns to the wellbore. The fluctuating mud volume requires time to stabilize to insure that it does not represent a true kick and risk a well control incident. Once initiated, the cycle of wellbore breathing often remains for the life of the interval, and although mitigation is possible, prevention is by far the best solution. The hole will flow with the pumps off until equilibrium is reached, although this may take hours to stabilize. Classification of Losses The correct treatment of lost circulation depends on the rate of mud loss and the type of loss zone encountered. Five primary loss types occur in drilling operations: Treatment Options: General Recommendations only - engineering judgment based on available information and experience may increase or decrease the estimated severity consequences and subsequent treatments. Loss1

Producing Formation

Permeable Zone

Impermeable Zone

<10 bph

BARACARB 25 & 50

STEELSEAL FINE + BARACARB 25 & 50

STEELSEAL - 100 ppb

BARACARB 25 & 50 + N-SEAL

STOP-FRAC D

EZ-PLUG

STEELSEAL + BARACARB 150 & 600 + BAROFIBRE SF

N-SQUEEZE3

STEELSEAL - 100 ppb

MAXSEAL3

STOP-FRAC S

10 - 30 bph

HYDRO-PLUG

EZ-PLUG / MAX-SEAL >30 - 50 bph

K-MAX3

HYDRO-PLUG2

FlexPlug W or BDF-376 (WBF) - Flex Plug OBM

FlexPlug W or BDF-376 (WBF) Flex Plug OBM >50 - 200 bph

Therma Tek3

Therma Tek

Therma Tek

High Fluid Loss Cement

Thixotropic Cement

Flex Plug3 >200 bph

Low Fluid Loss "Acid Soluble" Cement

1. Measured at flow rate required to drill ahead. 2. BDF-370 for PARCOM Regulated Countries. 3. Check temperature limitations.

2


Important Note: Prior to assuming that mud loss to the formation has taken place, all surface equipment must be examined for leaks or breaks, i.e. mud pits, solids control equipment, mud mixing system, riser slip joints, and/or incorrectly lined up pumps or circulating lines. Determine also if losses occurred during a recent fluid transfer. Seepage Losses Seepage losses usually begin slowly and in some cases can be difficult to identify. The loss may simply be filtrate loss due to poor fluid loss control. Seepage losses may be economically acceptable if there are high rig rates with a relatively low cost drilling fluid. If pressure control is critical, safety demands that the losses be cured. These losses can usually be controlled or prevented with an appropriate LCM treatment alone. Seepage losses may be treated with: • • • • • • •

BAROFIBRE / STEELSEAL / BARACARB pre-treatments of the mud system AQUAGEL GOLD SEAL additions to invert emulsion systems MICATEX can be used in surface holes (discontinued product – JELFLAKE instead?) Pills containing high concentration of LCM, spotted frequently Spot LCM pills prior to tripping out of hole Increased AQUAGEL content of water-based muds (unless DRIL-N) LCM with a particle size distribution (PSD) matched to the sand being drilled

Partial Losses Partial losses are more serious than seepage losses, and usually require significant LCM treatments or changes to the current drilling parameters to cure or to reduce the losses. Often drilling must be slowed or suspended because the drilling fluid cannot properly clean the hole. The cost of the mud and rig time becomes important in deciding the response to partial losses. Logistics and the rig’s mud building capabilities may be limited, and it may be necessary to take rig time to cure these losses. Partial losses may be treated with: •

• •

STEELSEAL additions have been shown to increase fracture initiation pressures. While it can be mixed up to 100 ppb in water-based mud, best results are often seen when mixed with a firm LCM (BARACARB) in an equal volume LCM mixture, i.e. 5 bbls STEELSEAL with 5 bbls BARACARB 50. Spot pills with a wide range of particle sizes sand a mixture of granular/fiber and flake LCM Mixtures of BARACARB 150/BAROFIBRE C & F, up to 80 lb/bbl in water-based mud

Wellbore Breathing Wellbore breathing can range from an almost complete return of all fluid lost, to severe losses. If not recognized early, continued fracture propagation can increase the severity of the losses and may result in failure to complete the drilling of the well. Depending on the severity the losses may not represent a large portion of the mud bill, but the time lost waiting for the well to stabilize after each connection can have a major impact on the overall well cost. In areas know for wellbore breathing, controlling the ECD through drilling practices, fluid properties and LCM use can prevent the problem from occurring. This complex issue can be treated with the following: •

The best cure is to prevent the cause of the problem – induced fractures. 3


o

o

•

In areas known for breathing, controlling the ECD and surge pressures are vital in preventing the problem. Once started the breathing may continue until the interval is cemented behind casing. If the fracture gradient is known, use DFG modeling and if possible real-time PWD to monitor and control the ECD while drilling. In high risk areas it is helpful to circulate LCM. BARAFIBRE and STEELSEAL (preferable) have proven effective when strung into the active system at ca. 10 ppb concentrations while drilling.

Once breathing has been initiated several methods can help control it. Paramount is to control the annular pressures that will continue to open the fractures and increase the severity of the breathing phenomenon. Modeling with DFG can identify areas to address, i.e., flow rate, ROP and fluid properties. The minimum ECD can be achieved with a balance of mud and drilling parameters. In high angled wells it is critical to maintain a sufficient flow rate to clean the hole and to minimize cuttings bed formation. At the same time maintain sufficient equivalent mud weight at the borehole wall to maintain stability to avoid pack-off and stuck pipe. Controlling the ROP may be unavoidable to minimize annular cuttings loading, and careful drilling practices are vital in avoiding high surge pressures – circulating prior to connections, controlling pipe running and pulling speeds, rotating the drill pipe to break gels before starting the pumps, and staging the pump speed on start-up. •

STEELSEAL has proven to be one of the best products to use for wellbore breathing. In some areas it is the only LCM that has proven effective. The breathing is usually helped with STEELSEAL additions because it prevents the pressure transmission to the fracture tip which will extend the fracture. A 30-50 ppb STEELSEAL/BARACARB blend with the product concentration ratio based upon volume not weight, appropriately sized for wellbore coverage – can be spotted across the loss zone. If spotting STEELSEAL pills alone are not sufficient, then the addition of a background concentration of STEELSEAL to the active system (minimum 10 ppb is recommended) should be considered. An adequate loading of STEELSEAL (or a STEELSEAL/BARACARB blend) can produce fracture tip “screen out” the instant the fractures are re-opened as the pumps are brought up to speed.

Severe Losses Severe losses can have a serious impact on drilling operations. Large volumes of expensive mud may be lost in very short periods of time. This can result in a well control situation as the fluid level falls in the annulus and hydrostatic pressure is reduced. Severe losses can also cause hole stability problems. While experiencing severe losses the hole must be kept full to the equilibrium point with water or base oil. An accurate record of all volumes and pills pumped must be kept so that hydrostatic head can be calculated. Severe losses may be treated with: • • • • • • •

A mixture of coarse materials with a wide size distribution in as high a concentration as the rig equipment will allow to be pumped. Consider a mixture of fiber/flakes/granular material. STEELSEAL can be mixed up to 100 ppb in water-based mud, but best results are often seen when mixed with a firm LCM (BARACARB) in an equal volume LCM mixture, i.e., 5 bbls STEELSEAL with 5 bbls BARACARB 50. BARARESIN pill works well if no oil in system and with high overbalance. MAXDRIL-N thixotropic pill has reduced losses. LCM can be added. FLEXPLUG OBM spotted in or near the loss zone. Gunk1 squeezes Cement/sodium silicate squeezes 4


• • •

Cement/STEELSEAL squeezes Diaseal-M squeezes If invert emulsion is being used, spot a water-based LCM pill.

Complete Losses Complete lost circulation occurs when no returns come to surface. The fluid level in the wellbore may drop out of sight. When a complete loss occurs, the annulus should be kept full with monitored volumes of lighter mud and/or water or base oil. Determine the reduction in hydrostatic head and reduce the active system to this calculated equivalent mud weight. The hole must be monitored very closely for possible well control problems. While a risky operation, some wells are drilled to the interval TD without returns to surface at all. This assumes that all cuttings are transported well away from the wellbore through fractures, with no risk of a well control incident. Total losses may be treated with: • • • • • • • •

Coarse materials, big size distribution, mixed as thick as rig will allow to be pumped FLEXPLUG OBM spotted in or near the loss zone. Gunk1 squeezes Cement/sodium silicate squeezes Cement/STEELSEAL squeezes Diaseal-M squeezes Mud Cap drilling Drill blind until a casing point can be reached

In a cross-flow situation with simultaneous kicking and lost circulation, some disagreement exists as to the correct response. Some believe that curing the higher-risk problem of a kick should take priority and that a barite plug2 should be used where possible. Others believe that curing the losses is the more important task and that products like FLEXPLUG should be used. It is important to realize that if the decision is made to cure losses first, then the potential exists for the LCM response to plug the drillstring and complicate the task of killing the well. 1 2

Refer to Well Blueprint Gunk Squeezes for further detail. Refer to Well Blueprint Barite Plugs for further detail.

Causes of Lost Circulation Virtually all causes of lost circulation are due to the pressures induced by the drilling fluid onto the loss zone, pushing fluid away from the wellbore. These excess pressures can either fill existing openings in the formation (sand/gravel), or they can induce the propagation of new fractures. Some contributing factors to losses are: •

Inappropriate mud properties can increase the pressures on the formations: Higher than needed mud weights place greater pressures on the formation. Higher than needed rheologies increase the ECD and thus pressure. High gel strengths increase the pressure required to initiate circulation after trips or when running casing. Lower than needed rheologies limit hole cleaning and can result in excessive cuttings loads in the annulus, increasing the hydrostatic pressure. Inadequate shale inhibition can cause a restricted annulus, raising the ECD. 5


Inadequate surfactant concentration can lead to bit balling and mud ringing, restricting the annulus and raising the ECD. •

Poor drilling practices can increase the pressures on formations: High tripping speeds can cause high surge pressures. Excessive ROP can “weight up” the annulus with cuttings, increasing the hydrostatic pressure. Bringing the pumps on too rapidly can cause a pressure spike. Surging the hole when setting the string in the slips on connections can cause pressure spikes of over 2 ppg. Long periods of sliding followed by rapid drill string rotation can overload the annulus with cuttings and increase the hydrostatic pressure.

Preventing Lost Circulation Advanced planning can help prevent lost circulation. To successfully tackle the challenges of drilling formations without incurring losses, consideration needs to be given to the potential causes of losses and the location of potential loss zones. Baroid’s hydraulics software DFG can aid operators in determining the correct drilling practices to be employed in each operation. The following points should be considered: •

Reduce Mechanical Pressures - In many cases, a reduction in the mechanical processes involved in drilling a well can successfully minimize, if not cease lost circulation.

•

Casing Points - Whenever possible, casing should be set in the geopressure transition zone to reduce induced fractures.

•

Pre-Treat Mud with LCM as a Bridging Agent - When excessive overbalance is unavoidable, pre-treating the mud with bridging material can effectively bridge porous zones and minimize seepage losses. With the correct particle size distribution, bridging materials can also slow down the filtrate invasion, reducing wall cake build up.

The prevention of lost circulation is the best answer to this costly drilling problem. In developed drilling areas the potential causes and locations of losses are often known and allow advanced planning. In many wells the loss zones are not encountered when the bit is in newly drilled rock but instead are at or near the last casing shoe. Typically this is the weakest exposed rock in the wellbore and has the lowest exposed fracture gradient. Losses to previously drilled formations are almost always induced, and are a result of hydrostatic overpressures caused by excessively high ECD, poor drilling/tripping practices, or unplanned mud density increases. If it can be established from available evidence whether losses are due to porous, cavernous or fractured formations, an appropriate treatment can be recommended. If a reduction of mud weight or pump rate is not possible, or does not achieve the desired results, then some type of LCM must be used to help seal the thief zone. Prior to drilling, the rigsite drilling team should be fully aware of the potential loss zones to allow a proactive approach to preventing or reducing the magnitude of loses. These will include controlling drilling parameters and mud properties to minimize the potential for inducing losses.

6


Reduce Mechanical Pressures A few of the numerous possible mechanical reduction procedures are shown below. In practice, these methods cannot all be used simultaneously and some form of compromise is necessary. • • • • • •

• • • • • • •

•

Control the ROP based on DFG calculations of the effective increase in annular mud weight from cuttings loading. Exceeding the last LOT pressure increases the risk of losses. Agree on pre-set ECD limitations based upon DFG modeling. Choose the minimum practical mud weight to maximize the allowable annular pressure loss. Choose the minimum mud rheologies to reduce ECD, surge and swab pressures while allowing adequate hole cleaning and formation stabilization. Maintain the minimum annular flow rate to allow adequate hole cleaning. Use good hole cleaning practices to avoid losses due to overloading of the annulus with cuttings: o Use weighted/high viscosity sweeps to augment hole cleaning rather than viscosifying the entire system. o Use care when pumping sweeps; they can increase the hydrostatic pressure when unloading the hole. o Use pipe rotation to augment hole cleaning, but be aware that after periods of sliding, pipe rotation may cause a marked increase in annular cuttings loading/hydrostatic pressure. Keep pipe movements slow to minimize surge and swab pressures. Reduce the pump rate by 15% when lowering the pipe and by 25% when rotating and lowering the pipe to reduce surge pressures. Break circulation - slowly - several times before reaching bottom during a trip, especially after logging. Run formation integrity tests (FIT) rather than a leak-off test (LOT). Do not exceed the calculated equivalent mud weight for kick tolerance. Avoid bit balling and sloughing shale. These cause increased pressure on formations if the annulus is overloaded or restricted. Control surge pressures while running casing by reducing the fluid density and the mud’s gel strengths as low as practical (within the limits of barite sag) prior to tripping out for the casing. Control the casing running speeds - base these speeds on DFG hydraulics calculations so as not to exceed the existing casing shoe’s LOT value with surge pressures. Ensure that the recommended casing running speed is the maximum, not the average running speed. The final casing slack off generates the largest surge pressure. For this reason, the driller should slow the casing down near the end of each joint to reduce the risk of breaking down the formation. A major contributor to not losing returns while running casing is to have the drilling foreman or mud engineer on the rig floor watching the running speed. An experienced, steady-handed driller who understands the importance of controlling surge pressures is vital to the successful running and cementing of the casing string.

Choose Deep, Strong Casing Points Whenever possible, casing should be set in non-porous formations with high fracture gradients. By setting casing as deep as possible, some formations with higher pore pressures may be drilled safely. A formation of high matrix strength is recognized by one or more of the following: • • •

Reduction in penetration rates Mud Logging data MWD Data

7


Pre-Treat Mud with Lost Circulation Material as a Bridging Agent When excessive overbalance is unavoidable, pre-treating the mud with bridging material can effectively bridge porous zones and minimize seepage losses. With the correct particle size distribution, these bridging materials can also slow down the filtrate invasion and help reduce wall cake build up. Losses when running casing are common and can result in a poor cement job and inadequate zonal isolation. The casing running speed should be based upon DFG hydraulic calculations to control surge and swab pressures below the LOT/FIT value. Always slow the running speed as the bottom of the casing being run passes through the existing shoe. Spotting an LCM pill below and across the shoe can strengthen the shoe and reduce the risk of losses; ca. 20 ppb BARAFIBRE or STEELSEAL pills of a STEELSEAL/BARACARB mix are recommended. The pill should be spotted across any weak zones below the shoe and up to the shoe itself. If mud or cement losses are likely during cementing or displacement, consider adding STEELSEAL to the cement slurry. The cementing group has a number of successful case histories using this technique. Treatments for Lost Circulation There are numerous approaches to curing lost circulation, and many treatments have proven successful in the field. One or more may be suitable for any given situation. The well interval has a major bearing on the choice of the response to lost returns. Losses in the payzone may require the use of acid-soluble LCM to reduce formation damage. Downhole tools and motors may restrict the concentrations of LCM which can be pumped without plugging the tools, or they may not allow the use of certain LCM at all. Whenever losses are encountered, the first approach should be to lessen the effective pressure on the loss zone by reducing the flow rate and/or mud weight where possible. Lost Circulation Decision Tree Cementing LCM Flowchart Lost Circulation Materials TYPE

PRODUCT NAME

Fibrous Materials

BAROFIBRE, HY-SEAL, PLUG-GIT

Flake Materials

JELFLAKE

Granular Materials

STEELSEAL, WALNUT, BARACARB

Mixture of Types

BARO-SEAL, HYDRO-PLUG, EZ-PLUG

Active Materials

N-SEAL, N-SQUEEZE, STOP-FRAC

LCM Guidelines • • •

Cellulose fibrous material will absorb water and weaken the stability of an invert emulsion oil mud. Use only oil-wettable material e.g. BAROFIBRE. When pumping LCM pills through the bit, be careful to avoid blocking the jets. When using fibrous and flake materials, the concentration of LCM should be less than twice the jet size (e.g., if 12/32 jets used, do not exceed 24 ppb L.C.M.) Higher concentrations of 8


•

granular marble and salts can be used, but the largest size should not exceed one third of the jet size. Also consider down-hole tools, such as motors, MWD etc. Remember to remove filter screens from mud pumps if pumping medium or coarse LCM through open-ended drill pipe.

Lost Circulation Checklist To successfully fight lost circulation, prepare in advance. • • • • •

Research offset well data in the Wellsight 2000 Database. Plan for appropriate equipment, and sufficient materials. Ensure that drilling personnel are aware of the drilling conditions that cause losses and what to do if losses occur. Tailor procedures to each individual well, with potential lost circulation zones identified beforehand.

1. Refer to available offset well recaps/reports and lithology columns • Identify potential loss zones. • Review previous LCM treatments - success or failure? • Evaluate previous LCM used. 2. Draft a planned procedure for lost circulation. Standardize procedures for action to be taken in the event of: • Seepage Losses (< 1-10%) • Partial Losses (10-50%) • Severe Losses (50-100%) • Complete Losses 100%/No returns) 3. Identify type, amount and storage place of all LCM on location • Ensure materials are well marked and easily accessible. 4. Discuss requirements of standby LCM treatments with rig and office personnel • Confirm compatibility with MWD and downhole motors, etc. • Prepare LCM pills and agitate prior to drilling a potential thief zone. 5. Identify all possible areas of surface loss • Monitor mud loss/gain from processing equipment. • Check gains/losses with equipment operating and not operating. 6. Set up a communication network and instructions between: • Drilling Foreman/Mud Engineer/Tool Pusher/Directional & MWD and Rig Personnel • Inform relevant personnel prior to LCM additions. 7. Maintain accurate records of all Lost Return responses • Check inventory before and after lost returns to allow accurate records and billing. • Record all fluid additions and losses accurately. • Record success or failure of each response for well recap.

9

Drilling Conditions Mechanical Sticking

SOP Code: MS Revision Date: 02/12/1997; Amended May 2005

Mechanical Sticking Introduction The drill string or casing can become mechanically stuck for any of the following reasons: • Key Seating • Packing Off • Undergauged Hole • Causes of Mechanical Sticking Key Seating During drilling operations, weight is applied to the bit by the drill collars with the drill pipe normally kept in tension. The amount of tension increases upward from the top of the drill collars toward the top of the string. If the hole deviates from the vertical and drilling continues, the portion of the pipe opposite the curved hole is in tension and there will be a tendency for the pipe to wear a slot into the wall of the hole. This is called key-seating because the hole in cross section assumes the shape of a key hole. The parts of the drill string with the largest outside diameter (OD) are the parts of the drilling assembly particularly susceptible to getting stuck in a key seat. This type of sticking is not normally a problem in holes that are kept vertical with no severe changes in inclination or direction. Packing Off This may occur if drill cuttings are not effectively transported out of the hole. Sloughing formations may cause the hole to load up around the drill string and can result in stuck pipe. Particles too big to pass freely through the annulus may wedge around the drill collars or stabilizers and stick the pipe. The phenomenon occurs more often when drilling with a packedhole assembly. Foreign objects like bit parts, hand tools or other junk can also cause stuck pipe. Five specific subsurface conditions can cause wellbore packing off: • Drilling underbalanced • Tectonically stressed and brittle shale • Shale hydration • Unconsolidated formations • Insufficient hole cleaning/annular loading

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Undergauged Hole An undergauged hole is a hole of lesser diameter than the diameter of the bit used to drill it. It can result from a number of causes or reasons: • Weight of overburden • Abnormal pore pressure • Adhesion between cuttings and the drilling assembly or the wall of the hole • Shale hydration • Drilling salt domes or sections • Poor filtration control with thick filter cake • Mechanical origins, such as undergauged bits, reamers, stabilizers, etc. Hole closure from the weight of overburden may occur in plastic shales or other deformable formations. Gumbo shales have a very high water content and can flow into the hole causing severe problems. Shale hydration is related to the active clay content of the shale formation. Active clays, such as montomorillonite will absorb/adsorb water and expand, reducing hole diameter. This can happen at any depth, and can sometimes be corrected by increasing the mud weight. When drilling salt domes or salt sections, the overburden stress may cause the salt to flow into the hole resulting in undergauged hole. Poor filtration control can quickly lead to thick wall cake and resulting undergauge hole. A hard, abrasive formation, such as a siliceous sand, can wear down the bit and the stabilizers' OD, making it impossible to get to bottom with a new bit without reaming. Preventing and Curing Mechanical Sticking The following practices should be followed, where applicable, to minimize the potential for becoming mechanically stuck: The depth of tight spots and amount of overpull and depth of overpull should be recorded. A common tight spot on two successive trips out of the hole with the overpull on the second trip greater than the first, is indicative of a key seat forming. Consider picking up a key seat wiper on the next time out of the hole. Do not force the drill string up or down through a tight spot on trips. Consider circulating, rotating and working the pipe through the restriction. As a rule of thumb a drill string slack off weight of 100,000 lbs could require three times that amount to pull it free. Ensure that optimum hydraulics are used. Use controlled penetration rates where applicable in large hole sizes. Diamond bits are slightly different size and configuration than rock bits. Caution should be taken when running back in the hole after changing from one type to another. Run jars in the drill string whenever possible. 11


Key Seating Once a key seat is formed, the small diameter part must be reamed to a diameter large enough to allow all parts of the drill string to pass through it. Various tools called key seat wipers are used for this purpose. The rate at which a key seat may form in a deviated hole is influenced by the type of formation, string tension, pipe rotation and frequency of trips. The drill pipe will wear into the side of the hole more slowly when the lubricity of the mud is increased. In deviated holes it is recommended that lubricants be used to reduce the chances of forming a key seat. Packing Off Primary considerations to avoid sticking the drill string by packing off may include the following: • Maintain adequate rheology to insure sufficient hole cleaning. • In high angle wells, close attention to Tau0, n and K is required to avoid forming cuttings beds. • If extensive sliding for directional work is being performed, occasional high speed rotation of the drilling assembly will aid in the reduction of cuttings beds. A hole opener run may be necessary after extensive sliding. If packing off problems start to develop, drilling should cease and a determination should be made of the cause so that appropriate remedial action can be taken. Potential remedies include: • Control rates of penetration • Adjust fluid rheologies • Sweep the wellbore • Increase flow rates By controlled hoisting, rotating or lowering of the drill string, and by starting and stopping the pumps, fragments may fall to bottom where they can be broken up by the bit. Start pumping, when possible, before picking up on the drillstring. Undergauge Hole Reaming the last 100 ft of new hole when tripping back into the well is advisable to insure a full gauge bottom hole assembly (BHA) is not being forced into a under gauge hole. This is particularly important in situations where a bit that is pulled is under gauge or there has been a significant change in the BHA configuration. A regular program of short tripping tailored to local conditions and based on experience, in an area, will aid in avoiding tight hole due to swelling formations. Inhibition of reactive shale formations and adequate mud weight should minimize tight hole due to swelling shales. The use of suitable filtration control agents and bridging agents should improve filter cake quality and reduce cake thickness.

12


Materials and Systems Key Seating Baroid has a wide range of lubricants to reduce friction between the formation and drill string, minimizing the chances of keyseating. In water-based mud these include: BARABLOK™

EP MUDLUBE®

BARO-LUBE™ GOLD SEAL

EZ-MUD™

BARO-TROL® PLUS

GEM™

BXR® L

TORQ-TRIM® 22

DRIL-N-SLIDE™

TORQ-TRIM II

ENVIRO-TORQ® Solid beads can also be used: STICK-LESS® 20

Solid glass beads

TORQUE-LESS®

Solid glass beads

LUBRABEADS®

Plastic beads

In invert emulsion systems CMO 568™ should be used. Packing Off Hole cleaning and suspension can be improved in water-based muds with the addition of BARAZAN® PLUS. In invert systems, RM-63™ in conjunction with GELTONE® or SUSPENTONE™ can be used. Undergauge Hole Inhibition of swelling and reactive formations will help reduce tight hole. In water-based muds inhibition can be improved by maintaining low alkalinities and substituting KOH for caustic soda, or deriving K+ ion content from KCl or potassium acetate. Other additives that can be used are: BARO-TROL PLUS

EZ-MUD™

BARABLOK

GEM

CLAYSEAL®

The highly inhibitive BARASILC™/GEM™ mud system can also be used. 13


Freeing Mechanically Stuck Pipe A key to freeing pipe successfully in the minimum amount of time is to ascertain where and how the pipe is stuck. Before deciding to use a free point and back-off, the following routine steps should be taken: • Attempt to circulate. • Attempt to work-jar and rotate the drill pipe. • Jar up if the pipe became stuck running into the hole. • Jar down if the pipe became stuck pulling out of hole. If the pipe is stuck by caving or sloughing formations, a method often proven successful is to place a straight upward strain on drill pipe while observing the weight indicator for weight bleed off, rather than jarring the pipe.

14

Drilling Conditions Permafrost, Drilling

SOP Code: DP Revision Date: 02/12/1997; Amended May 2005

Permafrost, Drilling Introduction The majority of wells penetrating permafrost formations have been drilled on the North Slope of Alaska and Siberia in North Russia. Permafrost is a highly unconsolidated formation with ice serving as the matrix structure. The permafrost sections of these wells occur in the surface interval and are characterized by having heavy gravel in the upper sections which can range in size from large sand to fist size or greater. Large pieces of wood are often associated with the gravel cuttings as well. In addition to the gravel sections, sticky clays are often encountered in the lower sections of the interval. For the most part, temperatures of the permafrost formations range from just below 32°F (0oC) to 15°F (-10oC). Depths of the permafrost formations vary and may range to as deep as 2,000 ft (610 m) true vertical depth (TVD). Potential Problems The most troublesome problems encountered in drilling of permafrost formations are hole cleaning and caving in the gravel sections due to poor cementation. Extremely high penetration rates (up to 600 feet [183 meters] per hour) contribute to the hole cleaning problems that are inherent in permafrost drilling. Formations which contain heavy concentrations of wet clays can cause extremely high viscosity, screen blinding, and bit and stabilizer balling as secondary problems in the surface interval of wells having permafrost. These formations are generally encountered in the transition zone just below the permafrost sections and may continue for several hundred feet. Occurrences of gas hydrates have been observed during the drilling of permafrost formations and those formations just below permafrost. Solutions Standard spud muds for drilling surface intervals which will contain permafrost usually consist of fresh water extended bentonite slurries. If it is known that large gravels will be encountered, the funnel viscosity of the fluid should be targeted for the 300 second per quart range with yield points in the 50 to 60 range. Formulating the fluid will consist of treating the hardness of the makeup water to less than 100 mg/L with Soda Ash and then mixing 20 - 25 ppb (57 - 70 kg/m3) of AQUAGEL™ with approximately 0.1 ppb (0.3 kg/m3) of X-TEND® II. Approximately 0.25 ppb (0.8 kg/m3) of caustic soda in the initial makeup of the fluid will aid in increasing the yield of the AQUAGEL™. Generally, no maintenance of pH is required after the initial mixing of the fluid. Drilling in areas where the gravel size is known to be small in size can be accomplished with viscosities in the 100 to 150 seconds per quart range. In wells which have large gravels, maintain the viscosity in the 250 to 300 second per quart range until all of the permafrost has been drilled. It is advised that under no circumstances allow the viscosity to fall below 200 seconds per quart in this section. It is prone to serious problems from tight hole, swabbing, and packing off. Maintain the system with AQUAGEL™ with X-TEND II. 1

Drilling Conditions Permafrost, Drilling

Close attention to the solids control system is of primary importance due to the very high viscosity of the fluid and the high penetration rates encountered drilling permafrost. Run shaker screens as fine as possible and use all of the hydrocyclones in the solids control system to maintain the abrasive solids content below one percent, if possible. Fast drilling in the large diameter gravel sections can result in sand contents of 10% if this phase of the program is neglected. Due to the fast penetration rates and heavy solids buildup, high dilution rates are usually required to control the density of the fluid. Prior to drilling the base of the permafrost formation, treat the system with approximately one percent by volume of CON DET® to combat the effects of screen blinding and bottom hole assembly balling caused by the wet, sticky clays which will be encountered in the formations just below the permafrost. These formations are generally recognized as being mud making zones that raise the viscosity of the fluid. For this reason, the dilution rates will remain high and the rig site engineer will then be fighting viscosity increases. Due to fast penetration rates and the large diameter holes, it is advisable to run the maximum pump rates possible to ensure good hole cleaning. If annular loading is extreme it may require controlled drilling to minimize the severity of the problem. Prior to the last trip out of the hole before running surface casing, adequate circulation time should be allowed to ensure that the hole is clean, particularly in situations of high deviation of the wellbore. Reduce the viscosity of the fluid to the 150 seconds per quart range to minimize surge pressures while running the casing and to avoid problems with cement channeling through thick fluid.

2

Drilling Conditions Quality Assurance

SOP Code: QA Revision Date: 03/05/1997

Quality Assurance

1

Drilling Conditions Quality Assurance

Baroid Drilling Fluids, Inc. is proud to announce that it has achieved ISO-9001 Quality System Certification of its Houston, Texas Headquarters facility. ISO certification assures our customers that Baroid conducts all quality-related activities in an effective, uniform, and continuous fashion. The following features of our ISO-9001 Quality Program are routinely audited by an independent ISO registrar to verify Baroid's proper implementation: (1) Management Responsibility

(11) Calibration of Laboratory Test Equipment

(2) Quality System

(12) Inspection and Test Status

(3) Customer Contract Review

(13) Control of Nonconforming Products

(4) Research & Development

(14) Corrective/Preventive Action & Customer Complaint Handling

(5) Document and Data Control

(15) Product Handling, Storage, Packaging, Preservation, and Delivery

(6) Purchasing/Vendor qualification

(16) Control of Quality Records

(7) Control of Customer-Supplied Product

(17) Internal Quality Audits

(8) Product Identification and Traceability

(18) Training

(9) Process Control

(19) Servicing

(10) Inspection and Testing

(20) Statistical Techniques

Since product quality is of particular concern, customers can breathe easier knowing that ALL Baroid products are inspected and tested prior to delivery. In addition, laboratory equipment used for quality control and R & D testing at the Houston Headquarters facility is regularly calibrated against recognized national and/or international standards.Baroid maintains certified quality programs at many of its major offices and plants, and is adding new certifications regularly. Currently, the following facilities are certified to ISO-9001, ISO-9002, or API Q1 quality standards: Houston HQ; Lake Charles, LA plant; New Orleans, LA plant; Dunphy, NV plant; Aberdeen, U.K. offices, Peterhead, U.K. stockpoint; Great Yarmouth, U.K. stockpoint; Lerwick U.K. stockpoint; Tenanger, Norway stockpoint; Bergen, Norway stockpoint; and Pamatacuality, Venezuela plant. Compare us with the competition - You'll see the difference in quality!

2

Drilling Conditions Safety

SOP Code: S Revision Date:

08/21/1997

Safety I. Philosophy Safety is of primary importance in Baroid's operations. The Company believes that, while risks exist, accidents and injuries are preventable. There is no business objective so important that it will be pursued at the sacrifice of safety. Safe conduct of operations is a condition of employment for all Baroid employees. This objective is fundamental to employees' well-being and to the efficient operation of the business. A job is done well only if it is done safely. Safety awareness extends beyond the workplace. Employees and their families are encouraged to make safety an everyday priority in their personal lives. II. Scope All employees of Baroid Drilling Fluids and its domestic and foreign subsidiaries, and its affiliated companies in which Baroid Drilling Fluids has a direct or indirect controlling interest. III. Responsibilities Management Responsibilities Provide healthy and safe working conditions through programs, facilities, equipment, products and services consistent with the known and recognized health and safety practices, standards, laws and regulations. Establish and enforce safe working rules and safe work practices Comply with all laws regulating safety and health in the workplace Provide competent direction to employees in the safe performance of their duties Analyze all accidents or incidents resulting in, or having potential for, loss or injury Recognize outstanding achievements in safety performance. Supervisor Responsibilities Ensure that health, safety and environmental processes developed are being implemented by competent personnel Ensure that all employees have received adequate orientation, instruction and training in health, safety and environmental matters Ensure appropriate emergency and first aid programs are in place Promote safe work practices at each work site Promote and encourage safe driving for all vehicle operations Ensure that appropriate equipment operation, inspection and maintenance programs are in place Perform periodic review of programs to ensure they are being implemented and are obtaining desired results Require all health, safety and environmental practices, standards, laws and regulations be observed Ensure that accidents are investigated and appropriate action is taken to prevent reoccurrence Keep abreast of changing rules and regulations promulgated by governmental entities and customers.

1

Drilling Conditions Safety

Employees Responsibilities • Maintain a positive personalsafety awareness and state of mind • Observe all posted safety rules • Question your supervisor if a rule is unclear • Report unsafe conditions or acts immediately and take corrective action • Follow company procedures regarding equipment operation and maintenance, including vehicles • Immediately report work-related injuries and/or illness • Practice the principles taught in safety training • Comply with all laws regulating safety and health in the workplace • Utilize required protective equipment devices at all times. Integrate safety into the performance requirements of every job. • Maintain all equipment guards and shields as designed. Removing or disabling safety devices or operating "tagged out" equipment is prohibited. • Complete education and training for safe use of equipment or hazardous materials prior to their operation or handling, e.g. forklifts, overhead cranes • Attend scheduled safety meetings and safety training sessions • Maintain work areas in a clean and orderly fashion • Become familiar with the location and use of fire extinguishers and other emergency equipment in your area, and the routes to be taken for emergency evacuation from your work area • Know proper lifting techniques, and do not attempt to lift a load that is too heavy • Operate automobiles, trucks and other equipment in a safe manner and in compliance with all federal, state and Baroid's rules and regulations. Use seat restraints at all times. The Company reserves the right to amend all or any part of this policy. The interpretation of the Company concerning any part of this policy shall be binding and conclusive. Although adherence to this policy is considered a condition of continued employment, nothing in this policy alters an employee's status and shall not constitute nor be deemed a contract or promise of employment.

2

Drilling Conditions Salt Drilling

SOP Code: DS Revision Date: 02/12/1997; Amended May 2005

Salt Drilling Introduction Drilling in salt and evaporite sequences is a common condition in many parts of the world. Because salt and evaporite sequences are impermeable, they form an excellent cap rock for hydrocarbon reservoirs. In addition, the salt, being lighter than surrounding rocks, tends to rise up, producing dome structures which are ideal traps for hydrocarbons. Sodium, calcium, magnesium and potassium salts can dissolve into the water phase of a drilling fluid system and result in large wellbore washouts. This can cause two significant problems; hole cleaning and cementing. Other problems include salt "squeezing" or "salt creeping" and saltwater influxes that require high mud weights to control. Causes A major problem with salt formations is their solubility in the water phase of drilling fluids. This is further complicated by: • Mixed salts • Plastic salts • Saltwater influxes • Subsalt shales Washing out halite and anhydrite salt formations can occur even with mud systems saturated with sodium chloride. Although on surface these systems are saturated, under downhole conditions the temperature of the mud is higher and the concentration of salt drops slightly below saturation. This means that more salt can dissolve, leading to wellbore washouts. Once the hole has begun to washout, annular velocities decrease and hole cleaning problems such as torque, drag and packing off may develop. It is more difficult to get a good cement job in a washed out formation, and this is especially important when drilling a plastic salt formation. When the mud system cools on surface, the formation salts dissolved downhole may precipitate out. These salts can be abrasive and a nuisance to drilling operations by reducing the life of pump parts and other rig equipment, as well as blinding shaker screens. Mixed Salts Evaporite sections can contain very soluble potassium and magnesium salts as well as the common sodium and calcium salts, halite and anhydrite. Conventional drilling fluids for salt sections are usually saturated only with sodium chloride, but due to the different solubilities they still dissolve the potassium and magnesium salts, leading to large overgauge sections and washouts. One of the best known examples of a complex evaporite section is the Zechstein formation, found in the Southern North Sea and Northern Europe.

1


Plastic Salts Salt formations are sometimes in a plastic state and can be "squeezed" into the wellbore by the pressure of overlying formations, causing the drill string to become stuck. However, the most significant problem can occur after the well has been drilled. If the hole is washed out and the casing is poorly cemented, "plastic" salt formations can squeeze in causing the casing to collapse. Many wells have been lost this way. Improvements in casing design and mud technology have reduced casing collapse incidents considerably in recent years. Saltwater Influxes Influxes of various saltwaters and brines from formations can have a very detrimental effect on fluid properties. These influxes are invariably pressured, requiring high mud densities to stabilize them. Subsalt Shales In the Gulf of Mexico, there is often a zone below the salt formation known as the "rubble" or "rafted" zone. This consists of an unconsolidated formation, destabilized by the intrusion of the salt above, which will tend to fall into the wellbore. It is very important to remove this rubble efficiently to prevent packing off and mechanically stuck pipe. If the salt zone above is washed out, removing this debris becomes a lot more difficult with much higher flow rates required to clean the hole than in gauge or near-gauge holes. Other problems can be foaming and carbonate contamination from anhydrite sequences. Hydration of polymers in saturated salt systems is difficult and requires higher product concentrations and subsequent higher fluid costs. Preventing and Curing Salt Problems An invert emulsion is the most feasible system to choose if economic and environmental concerns allow. It is much easier to prevent washout of the salt section with an oil-based or synthetic-based fluid. Water-based systems have to be saturated to prevent washout. Use either sodium chloride for drilling halite or anhydrite sequences, or a mixture of magnesium chloride and potassium chloride salts for drilling mixed salt formations. Salt inhibitors will prevent recrystallization of salts on surface and allow super saturation of the drilling fluid, keeping it from falling below saturation downhole. If plastic salts are a problem, increased mud weight may be required to stabilize the formation. Initial stress relief after the salt is drilled is common. If the drill string becomes stuck, a freshwater pill can be pumped to dissolve the salt. The pill should be large enough to cover the drill collars with enough excess left to cover the entire bottom hole assembly (BHA for several hours while jarring the pipe. It should be noted that massive halite dissolution in water is slow and enough time (3-4 hours) should be allowed for the pill to work. Allow the water to soak around the BHA, pumping only a few strokes every hour or half-hour to move the pill slightly. If saltwater influxes are a possible hazard, enough weight material should be kept at the rigsite to allow a rapid increase in mud weight. Water flows can require densities 3 lbs/gal greater than the salt formation would require under normal conditions. 2


Materials and Systems Invert emulsion systems can successfully drill salt sections without causing washout due to solubilization of the salt. EXTENSOL salt inhibitor should be added to saturated sodium chloride drilling fluids, to prevent recrystallization of salt when temperatures decrease at surface. If subsalt reactive shales are a concern, additions of GEM™ and/or CLAYSEAL® can improve inhibitive capability of a saturated sodium chloride system. BARAVIS® can be used as a viscosifier in mixed salt systems, while BARAZAN® or BARAZAN D may be used in sodium chloride or potassium chloride systems. Use IMPERMEX®, DEXTRID®, CELLEX™, PAC™-L or PAC-R for fluid loss control.

3

Drilling Conditions Shale Drilling

SOP Code: SD Revision Date: 03/05/2001

Shale Drilling Introduction Shales are defined as clay mineral-rich sedimentary rocks. Shales are generally classified according to the relative methylene blue titration (MBT) values they produce, and the amount of water they contain. Soft shales usually have MBT values in the 20-40 meq/100g range, while brittle shales may have values as low as 0-3 meq/100g. Soft shales are normally encountered at shallow depths, whereas harder, brittle shales are older and found at greater depths. Shales may be affected by mechanical action and the chemical environment surrounding them. It is helpful to anticipate what types of shales will be drilled, and how they might react when exposed to a particular fluid type, and what can be done to minimize the problems associated with them. Shales types behave differently, and the shale type can often be related to a potential wellbore problem. Soft Shales Soft shales, sometimes referred to as "Gumbo", usually contain large amounts of water and have densities in the range of 1.2-1.5 g/cc. They contain large amounts of smectite and/or illite, and can be associated with problems such as bit balling, mud rings, plugged flow lines and hole washout. They are usually dispersible shales. When soft shales are encountered, problems may be seen in the form of balled bottom hole assembly (BHA) and/or bit. This is sometimes detected following trips, often severe enough to cause loss of rig time in cleaning the shale from the drilling assembly. A plugged flowline is one of the common problems encountered when drilling soft shales, and is often the limiting factor in how fast a particular interval can be drilled. Economic considerations are obvious. Other symptoms may include reduced rate of penetration (ROP) due to balled bit, shaker screens blinding, increased pump pressures, excessive overpull on trips, washouts and stuck pipe. Some shales are pH sensitive and/or time sensitive. In these cases, the section may be drilled with few problems, but may subsequently swell or begin to slough. Soft shales are encountered in nearly every well drilled. A great amount of study has been done to minimize the severity of shale problems. Pre-well planning is important, and mud type and bit selection can often reduce the problems associated with drilling shales. A comparison among wells drilled previously in an area is often productive when deciding what drilling practices will be followed. Running MAX-ROP hole cleaning programs in advance can be useful in determining the rate that a formation should be penetrated. Inhibitive mud systems are known to have a significant affect on the severity of problems. Additives such as KCl, NaCl, glycols (GEM™ GP, GEM CP), silicates (BARASILC™) and encapsulating polymers (PAC™, EZ-MUD™), have been used to improve performance. Bit selection is a key factor; tooth length, bearing type, and design (PDC vs. roller-cone) will affect the degree of success in drilling particular zones. Film forming chemicals can help retard bit balling, thus enhancing the rate of penetration.

1


Drilling Practices Good drilling practices are important when drilling soft shales. By reducing the weight on bit, penetration rates can be reduced to prevent annular over-loading, and the possible formation of aggregations of shale (mud rings). The formation of mud rings can lead to restricted mud flow in the annulus and to pack-offs. Short trips should be part of a drilling program. They serve to wipe the wellbore clean, and to assist removing packed shale or clay from the drilling assembly. Circulating the hole clean prior to tripping is essential. Rig modifications such as larger flowlines or flowlines fitted with jets, may help reduce downtime. Viscous sweeps followed by low viscosity sweeps can be used to help clean the hole of cuttings which could accumulate, causing pack-offs or fill on bottom after trips. Fluid Selection Cores, cuttings and information from offset wells, or wells in a certain area, can sometimes be used to decide on a mud type for optimum performance. Modifying the salinity or concentration of fluid additives in a system will make it acceptable for use in an area. Mud systems suited to drilling reactive shales include: • BARASILC™ • K-LIG®/KOH • EZ-MUD™ • PAC™/ DEXTRID® • POLYNOX® • CLAYSEAL® Salt additives and/or GEM™s can be added to controlled salinity invert emulsion systems to enhance inhibition. Salt Additives KCl has been proven to be effective in inhibiting shales. NaCl is less effective but may be adequate if large quantities of highly reactive shales are not anticipated. Other salts such as CaCl2 and CsHCO2 (cesium formate), although inhibitive, are generally not recommended due to economic or environmental considerations.Optimum concentrations vary among salts. GEMS have been demonstrated to work synergistically with potassium chloride and with other salts. EZ-MUD has also been used in recent years to successfully drill soft shales, both in saline and non-saline systems. Calcium-based fluids (lime and gypsum) provides excellent inhibition for smectite-rich formations. Erosion Hole erosion and washout are concerns when drilling shale formations. They are important because they can lead to associated problems with hole cleaning, tripping, and cementing. Laboratory testing, such as Capillary Suction Times (CST), Linear Swelling, and Shale Erosion Testing are used to predict which fluids will offer the best erosion stability.

2


Symptoms of Erosion Symptoms of erosion/enlargement may be increased amounts of cuttings, excess in LGS in the drilling fluid, an increase in bottoms-up time, poor hole cleaning, and problems controlling direction. Hole enlargement often occurs simultaneously to shales swelling and sloughing, with the former masking symptoms of the latter. If the events are noticed early enough, changes to the fluids program or drilling program can be made to minimize the problem. Fortunately measures for minimizing bit balling and tight hole often work to minimize hole enlargement. Although the primary function of additives may not be to reduce hole enlargement, salts, detergents, lubricants, polymers and glycols may all work to lessen hole enlargement. Hard/Brittle Shales Hard shales are normally older than soft shales and may contain lesser amounts of water with increased amounts of illite, kaolinite, and/or chlorite. These shales typically have densities in the range of 2.2-2.7 g/cc and may have a water content of two percent or less. MBT values are usually low. They present a different set of problems than softer shales do. Tight Hole Tight hole can be a problem when drilling hard shales, although the problem is usually a result of downhole stresses or pressure imbalances rather than swelling. Tight hole may also be a result of elliptical holes (which may be detected using 4-arm caliper), especially in the case of deviated wellbores. Tectonic forces are more significant when drilling hard shales than they are when drilling soft shales. Sloughing, caving and packing-off can again be problems, but the underlying causes are different. Wellbore Caving Wellbore caving can be a problem when drilling harder shales. Drilling parameters should be monitored carefully to predict when caving might occur. Wellbore caving may be detected at an early stage by examining cuttings at the shale shakers. The appearance of large pieces of shale or shale that has smooth curved surfaces may be evidence that a problem exists. Another indication might be trouble running the drillstring into the hole, with ledges being encountered. If the hole is not being cleaned because of excessive amount of shale, packing-off may occur. This can be indicated by high torque and drag, or increased pump pressure. Mud Density In harder shales, mud weight becomes more of a critical factor. The examination of electric logs and well histories from offset wells may help to determine required mud densities. Electric logs can provide important insight into not only pore pressures, but formation tops and important sand/shale sequences. Fluid Selection Again, laboratory testing of cores or shale samples can assist in the selection of the optimal fluid. X-ray diffraction can establish the distribution of various clays and minerals, and when used in conjunction with CST, linear swelling and shale erosion data, make the task of mud selection more reliable. Scanning cores for microfractures is often useful in determining which additives 3


may be most effective for sealing fractures and minimizing the penetration of fluid into the formations surrounding the wellbore. Tectonic forces often directly affect wellbore stability. Studying of geological models may help to determine the optimum direction for penetrating formations relative to bedding planes. Mud weight is an important factor, and research indicates that fluid selection plays an important role in drilling tectonically stressed formations. Where oil-based muds are typically thought to be superior to waterbase muds with respect to inhibition and borehole stability, evidence suggests that oilbase mud may actually lubricate bedding planes causing slippage and resulting tight hole as the formation slides into the wellbore. Fragmentation is more of a problem with hard shales than with soft shales, with pieces becoming separated from the formation and entering the wellbore. Where packing-off may occur when drilling both soft and hard shales, the root causes are usually different; sloughing versus fragmenting. Highly stressed formations are more likely to cause problems associated with fragmenting, borehole enlargement and packing-off. These problems can be difficult to predict and control, however, careful planning offers the best chance for successfully drilling formations prone to stress-related problems. Casing Point Selection Casing point selection is a critical factor when designing wells where the transition from softer to harder (and possibly brittle) shales is not well-defined. Trend logs and formation top determination often form the basis for casing point selection, and whether or not a well is drilled successfully depend on this selection. Generally the intermediate casing point is determined by the depth at which transition occurs. As softer shales play out and more compacted formations are encountered, rock strength increases, providing the integrity necessary for using higher mud densities. If this transition can be accurately determined, and the casing set properly, the mud system may be converted or displaced to a fluid which is better suited for drilling stressed formations. Fracturing Often harder shales are found fractured in their native state. If whole mud or even filtrate is allowed to penetrate the fractures, the shales may hydrate, disperse and slough. This will ultimately lead to borehole enlargement and potential problems cleaning the hole. To minimize penetration of fluid into the formation, particle size distribution of solids should be monitored and modified if necessary. Additives such as BAROTROL® PLUS, BARACARB®, BARABLOK™ and BXR®, are useful in modifying particles size distribution, and sealing the pore throats of sands or fractures in shales. Normally an acceptable distribution can be achieved using a combination of asphaltines, gilsonites, mica, and/or calcium carbonate. Several laboratory tests when used in conjunction may form a basis for recommendations for mud additives. These lab tests include, but are not limited to, Particle Plugging Tests, Particle Size Analysis, and FANN® 90. Steps can be taken to minimize the effects of wellbore caving if it should become a problem. Initially, a careful analysis of pore pressure versus mud weight should be done. If the formation is naturally fractured, mud weight increases may aggravate the problem, as fluid may be forced into the fractures, destabilizing the shale. However, if it can be determined that fractures probably do not exist, or they may be adequately sealed, mud weight increases may actually reduce caving. Hole cleaning should be monitored carefully. Increasing the low end rheology, or simply raising the yield point and gel strengths, may improve hole-cleaning efficiency. This is especially important in deviated wellbores. Additionally, extending circulation times prior to trips, 4


making frequent wiper trips, and tripping slowly to minimize surge and swab pressures, may all have a positive impact.

5

Drilling Conditions Sliding

SOP Code: SLD Revision Date: 02/12/1997; Amended May 2005

Sliding Introduction The ability of the drill string to slide is of critical importance when drilling directional wells, especially horizontal. If the ability to slide is impaired, the transfer of weight to the bit is reduced, resulting in reduced penetration rates. In the case of horizontal applications, the inability to slide negates the advantage of using steerable assemblies and results in the rig having to make repeated trips for bottom hole assembly changes to maintain proper orientation of the wellbore in the production zone. The end result to the operator is added expense in drilling the well. Causes of Sliding Problems Cuttings bed development can cause significant problems with the ability to slide and increases in torque and drag. The problems associated with efficient hole cleaning while drilling highly deviated and horizontal wells is a contributing factor to the problem. High degrees of deviation, extremely high build rates within a short radius, and aggressive changes in azimuth to reach isolated fault blocks result in high tortuosity in the wellbore and a corresponding high degree of pipe to borehole wall contact. The frictional forces resulting from this wall contact can be great enough to eliminate the ability to slide. The quality of the mud filter cake can contribute to problems with sliding. A tough and durable cake has traditionally been thought of as desirable. However, tests have shown that shearability of the filter cake facilitates sliding and the ability to pull free in the event of differential sticking. A slick coating on the pipe and on the solids within the filter cake is desirable in terms of enhancing the ability to slide without becoming differentially stuck. Drilling through underbalanced zones can reduce the ability to slide because of the differential pressure forces acting on the drilling assembly and the wellbore. Solutions To avoid sliding problems associated with cuttings bed development, use measure to prevent the development of cuttings beds or mechanical means of disturbing them after they have formed. Use fluids designed with optimum rheological properties to ensure efficient cuttings removal. Low viscosity sweeps should be pumped while drilling to induce turbulence that disturbs the developing cuttings beds, then the low viscosity sweeps should be followed by high viscosity sweeps to carry dislodged material to the surface. Occasional drill string rotation may also assist in disturbing the cuttings beds, along with a regular program of short tripping to dislodge cuttings beds that have formed. EZ-MUD™ PHPA polymer has primary functions as a viscosifier and shale stabilizer. It also functions as a boundary lubricant as it adheres to the pipe surfaces and muds solids, increasing the lubricity of the solids in the mud filter cake. 1

Drilling Conditions Sliding

Liquid lubricants are used to reduce the coefficient of friction between the surfaces of the pipe and borehole wall and also to reduce metal on metal friction between the drill string and casing wall. Combinations of lubricants have been successful in reducing frictional forces in high deviation wells. Combinations of EP MUDLUBE®, TORQ TRIM® II, DRIL-N-SLIDE™, and BAROLUBE™ GOLD SEAL have achieved coefficient of friction factors as low as .03. These lubricants have effectively extended, by several thousand feet, the ability of water-base muds to drill high angle extended reach wells. Combinations of Graphite, STICK-LESS® 20 glass beads, EZ-MUD™, and other lubricants have been used effectively to enhance the ability to slide. When drilling underpressured sandstones, BAROFIBRE® and/or STEELSEAL® can help reduce the effects of differential sticking while attempting to slide. Adding the materials into the active system or pumping high concentration sweeps are both effective.

2

Drilling Conditions Slim Hole Drilling

SOP Code: SH Revision Date: 02/12/1997; Amended May 2005

Slim Hole Drilling Introduction Slim hole drilling applications have increased in recent years. Applications vary from entire wells, to single intervals and remedial work on existing wells. This type of drilling can be done with specialized slim hole rigs, coiled tubing units and conventional oil field drilling rigs. Slim hole drilling has been defined as any hole from <6"to <8.5". Certainly anything less than 6" should be considered slim hole. A limiting factor has always been the availability of downhole tools and motors, but there is now improved availability of the very small diameters. Slim hole drilling is very common in mineral exploration and other non oil-field applications. Baroid's Industrial Drilling Products group has served this industry for years, giving Baroid significant experience in this field with a range of products developed exclusively for those applications. Advantages of Slim Hole Drilling Economics The primary reason for using slim hole techniques is to reduce well costs. Coiled tubing units can be used in some situations, eliminating the requirement for a drilling rig. Sidetracks can be made in existing, small diameter production intervals, increasing productivity without the need for a sidetrack higher up the wellbore. Exploration costs are reduced by using smaller rigs and crews, less materials, etc. Lower Cost of Consumables The cost of drilling materials can be reduced when using slim hole techniques, with less steel required for casing, less drilling fluids for volume etc. However it should be noted that specialized equipment and tubulars required can offset other cost savings. Less Environmental Impact Less fluids disposal means that the environmental impact and removal costs are reduced. A specialized slim hole rig requires less space and less site preparation than a conventional oilfield rig, resulting in less clean up. Disadvantages of Slim Hole Drilling Hydraulics Smaller hydraulic diameters will result in high pressure drops and equivalent circulating densities (ECD's), causing lost circulation and differential sticking problems to be a concern. Lost circulation of only a few barrels can cause a significant drop in annular volume and hydrostatic head, resulting in potential well control and hole stability problems.

1


Stuck Pipe The chance of stuck pipe increases significantly in slim holes. The high ECD can result in high differential pressures, and the slim diameters mean that there will be increased contact between the wellbore and the drill string. Packing off is more likely in a small annulus. The chances of freeing stuck pipe are reduced because the string used will not be strong enough to withstand physical stresses generated while trying to work the drill string loose. Well Control With very small annular volumes, the response time to a well control situation is reduced dramatically. A hydrocarbon influx can be at surface in a matter of minutes or even seconds. Careful monitoring of volumes is essential. Torque and Drag The large amount of contact between the wellbore and drill string, torque and drag can cause high levels of torque and drag in slim holes. Any buildup of cuttings beds in deviated holes can increase the severity of the problem. Materials and Systems for Slim Hole Drilling Baroid has developed the first drilling fluid specifically designed for slim hole and coiled tubing drilling, QUIKDRIl-N™. Hydraulics can be improved in drilling fluids for slim hole drilling by minimizing the solids content. The use of high density brines such as bromides or formates can provide higher density fluids without the addition of solids. Careful monitoring of pressure drops is required. The conventional rheological models, Bingham Plastic and Power Law can give very different results (5 lb/gal + variance) when calculating ECD's in a slim hole. Hershel-Bulkley is the recommended rheological model. The filter cake should be as thin as possible to help minimize stuck pipe. FANN® 90 and Particle Plugging Apparatus (PPA) testing should be conducted, if possible, to ensure optimum additions of filtration control and bridging additives. Volumes and flow in versus flow out should be monitored very closely. It may be prudent to measure volumes in smaller units than conventional oilfield drilling; i.e., use gallons or liters instead of barrels. Appropriate steps should be taken at the first sign of a volume increase. The use of lubricants such as BAROLUBE™ GOLD SEAL will also reduce frictional pressure losses in small diameter tubing and should be added even if conventional torque and drag are not an issue. Baroid's line of lubricants include: BARO-LUBE™ GOLD SEAL

EP MUDLUBE®

BARO-TROL® PLUS

EZ-MUD™

BXR® L

GEM™

DRIL-N-SLIDE™

TORQ-TRIM® 22

ENVIRO-TORQ®

TORQ-TRIM II

2


Solid beads have been used successfully to reduce torque in coiled tubing applications: LUBRABEADS®

Plastic beads

STICK-LESS® 20

Solid glass beads

TORQUE-LESS®

Solid glass beads

In some areas, combinations of lubricants have proven more successful than single products. DRIL-N-SLIDE has improved the performance of the more conventional lubricants (EP MUDLUBE and TORQ-TRIM II) of reducing the foaming and blinding of screens that is commonly seen with these products. CMO 568™ has been successfully used in invert emulsion systems in the North Sea. For reducing torque, due to metal on metal contact, EP MUDLUBE and TORQ-TRIM 22 have been proven successful. Baroid Industrial Drilling Products' CORE-LUBE™ lubricant is useful in slim hole applications, particularly with drilling rods.

3

Drilling Conditions Solids Control

SOP Code: SC Revision Date: 02/25/1998; Amended May 2005

Solids Control Introduction The importance of minimizing undesirable solids in drilling fluids cannot be overstated. Close monitoring and maintaining a minimum of drilled solids have been determined to save both time and money. Savings come from: • Increased drilling rate - less days per well • Increased bit life - fewer bits per well • Increased life of pump parts • Reduced mud maintenance costs • Reduced non-productive time • Reduced incidence of stuck pipe • Causes of Solids Control Problems Solids are an unavoidable component of all drilling fluids. Solids may be added as commercially processed materials or as a result of the drilling operation. Drilled solids include salts, silts, sand, carbonates and clays. Accumulation of these solids can present problems in maintaining desired mud properties, especially viscosity and mud weight, and can decrease the drilling rate, bit life and life of mud pump parts. Small amounts of drilled solids incorporated into a drilling fluid cannot be avoided and are not generally considered to be detrimental. However, if these small quantities are allowed to accumulate and continuously recirculate, serious problems can develop. Solids gradually decrease in size, as a result of bit regrinding, and mechanical breakage caused by surface pumps and solids control equipment. The resulting smaller solids have an increased total surface area. This means that although the actual solids content has not changed, much more fluid is required to coat the exposed surfaces. When this occurs, there will be increases in viscosity, fluid loss, filter cake and gel strengths. This leads to increased chemical costs and higher dilution rates. Eventually the solids become so small that they cannot be removed by any means other than whole mud dilution. These fine solids can also cause formation damage in producing formations, severely limiting the production and the profitability of the well. Chemical, as well as mechanical, effects can result in solids control problems, especially when drilling reactive shale formations. Preventing and Curing Solids Control Problems Preventing or curing solids control problems may include several methods: • Chemical treatment • Dilution • Mechanical treatment 1


Chemical treatment involves using flocculants to congregate and drop unwanted solids out of the mud. However this type of treatment is not recommended for many mud systems because of adverse effects on mud properties and possible hole stability problems. Inhibitive water-based mud systems and invert emulsion systems can improve primary solids removal because drilled shale and clay cuttings do not breakup and disperse within the fluid. This allows them to be removed by mechanical or centrifugal means before they are recirculated. In some cases, maintaining the pH of a fluid can have a dramatic effect on the solids content of the fluid. Optimum pH will vary with mud type, but excessive pH tends to disperse certain formation clays making them impossible to control except through dilution. Excessive chemical dispersant use can also cause solids control problems by breaking up and dispersing some types of solids before they can be removed. Dilution Dilution lessens the solids concentration without actually removing the solids. Mud weight and rheology problems will reappear as more solids build up during drilling. Dilution is often expensive because: • Increased consumption of products is required to maintain desired properties • Large scale dilution often leads to discarding of large volumes of valuable drilling fluid due to lack of storage space. • In environmentally sensitive areas, extra expenses must be incurred in removal and clean-up of discarded mud. Mechanical Treatment of solids build up by mechanical means is often the most practical and cost effective of the methods available. Unwanted alterations of mud properties are avoided and more savings are realized due to lower dilution. Generally speaking, the greater the unit cost of a mud, the greater the savings in using mechanical treatments to prevent mud problems. The simplest way is to allow unwanted solids to settle out, however this sometimes is not very efficient and may require large surface volumes. The key to effective mud engineering is efficient and comprehensive solids removal equipment and technique. One effective solids removal equipment system may consist of: • Scalping shakers • Linear motion high speed shakers • Desander • Desilter Mud cleaner • Two centrifuges with the capability to run in solids removal and/or barite recovery modes The Baroid Solids Removal System consists of: • Baroid Super 8 Linear Motion Shaker – This shaker utilizes a single deck, three screen design and can adjust between 5 to 8 "g"s. 2


• Baroid Mud Conditioner - a hydrocyclone unit designed to accommodate all hydrocyclone operations including a mud conditioner configuration. • Centrifuges - Baroid 1434 Barite Recovery unit and the Baroid 1458 (a 5 speed back drive centrifuge capable of 4000 rpm) • Baroid Progressive Cavity Pumps - mechanically sealed pumps capable of 0 to 220 gpm at 10 hp. The number of shakers required will vary, but there should be enough to handle maximum flow rates anticipated for the well. Proper sequencing of the solids control equipment is a primary consideration for obtaining maximum efficiency. Not all the pieces of equipment are relevant in every situation, but all utilized equipment must be rigged up and maintained so that it operates at peak efficiency. Anything less may not be cost effective and can even contribute to solids problems. Periodic analysis of equipment efficiency should be performed and reported. Any problems with solids control equipment should be brought to the customers attention and noted on daily mud reports. Particle size distribution (PSD) of drilling fluids can indicate solids control problems due to deterioration and build up of fine solids. Solids control equipment should be considered as a total removal system and therefore each individual piece of equipment must be working efficiently for overall system efficiency. For optimum efficiency each piece of the system must be a) Properly selected b) Properly sized c) Properly installed, and for continued effectiveness they need to be d) Properly maintained by competently trained and motivated personnel. The API 13-C (March 1996) Standard for Evaluation of System Efficiency is: Data: Base Fluid Added:

Vbf = ___________bbl

Average Base Fluid Fraction: Interval Length: Bit Diameter:

Fbf = ___________

L = ___________ft

D = ___________in

Washout as % increase in hole volume: Average Drill Solids Concentration:

W = ___________%

Fds = ___________

Calculations: Volume of Mud Built: Vmb = Vbf / Fbf ___________bbl Volume of Drilled Solids: Vds = [(D2)*(1 + W/100)* (L)] / 1029.4 ___________bbl 3


Dilution Volume required if no solids were removed: Dt = Vds / Fds ___________bbl Dilution Factor: DF = Vmb / Dt ___________ Solids Removal Performance: SP = (1 – DF) * 100 ___________% Baroid Solids Control Equipment Evaluation Data Mud Cost per Barrel (Mud Report): Cb = ___________$/bbl (Daily Mud Cost / bbl of Dilution for the day) Fraction Drill Solids (Mud Report): Equipment Discharge rate: Equipment Cost:

Fds = ___________

td = ___________sec/qt

Ce = ___________$/day

Calculations Barrels per Day of Discard: Vf = 514.2857 / td ___________bbl Barrels of Dilution: Dt = Vf / Fds ___________bbl Cost to treat and Dilute Solids: Ct = Dt * Cb ___________$ Savings by using the equipment: Cs = Ct – Ce ___________$/day Shale Shaker Selection Basically two types of shale shakers are in use today. The performance of each type varies with field use but can be summarized as follows: Elliptical Motion Lower "g" forces and coarse screens reduce the solids separation. Generally, screen life is longer due to the lower forces and coarser screens run. The elliptical motion and screen sizes are more conducive to removing "sticky" material such as hydrated clays and shales. The units are mechanically unsophisticated and easily maintained 4


Linear Motion (e.g. Baroid Super 8 Linear Motion Shaker) Higher "g" forces (up to 8 g) generally result in excellent solids separation and reduced invert emulsion fluid retention values on cuttings. Very fine screens can be used with 200+ mesh being common. The coupling of the finer screens and higher forces from the shaker do not generally promote a long screen life. The linear motion and finer screens are most efficient when drilling consolidated formations or when using invert emulsion fluids that inhibit the clays and produce discrete cuttings. Shale shakers should be regularly maintained according to manufacturers maintenance schedules. Bed rubbers, shock mounts, tension bolt assemblies, pneumatic bladders, hydraulic lines, etc. should all be regularly inspected and replaced when worn or damaged. Failure to do this will impair performance and probably result in having to run coarser screens for a given flow rate and ROP. Bypassing Most header boxes have a bypass valve or valves. As the name suggests, this permits circulation to bypass the shakers and may serve as a dump valve to dump cuttings from the header box. Shakers should never by bypassed when drilling. This rapidly fills the sand trap with cuttings and leads to overload or blockage of the hydrocyclones by coarse solids. Dumping of the header box can be avoided by installing jetting lines to agitate the tank and circulate cuttings over the shakers. Jetting should be done during connections in order to avoid flooding of the screens and whole mud loss. Shaker Hand Shakers should always be attended when drilling in order that any malfunction or screen damage can be quickly rectified. A member of the rig crew should be assigned to the job of "shaker hand" and should be fully trained on the actions to be taken if problems occur. Screen Tension and Condition Screens should be correctly stored and handled, and should always be tensioned in accordance with manufacturers recommendations. Incorrectly tensioned screens have impaired separation efficiency and vastly reduced working life. Shaker Screen Selection A good variety of screen sizes should be kept on location. Use the finest mesh screens the flow rate will allow without whole mud losses realizing that 175 and finer mesh screens can remove some barite, proving to be uneconomical. Three dimensional corrugated screens can be used to increase effective operating area but in many instances the new Baroid XR mesh screens will allow increased flowrates. Anytime new mud is displaced into the hole, coarser mesh screens may have to be used until the mud shear thins. In the case of Invert based muds, a measure of the screen efficiency is the reduction in the amount of mud retained on cuttings. This is now being tightly monitored for environmental and economic reasons. As a general rule, 75 to 80% of the screen should be covered with mud. This allows for surges and rig heave when offshore. Angled single deck units are designed to operate 5


with a horseshoe shaped pond of mud, concave towards the front edge. Ramped screens, e.g., Thule VSM 100 or Alfa Laval Eagle, operate with a mud pond on the horizontal rear lower screens, and a dry beach on the front lower screens. Blinding Screen blinding is caused by a reduction in the fluid transmission capability of the screens which leads to whole mud overscreen losses. There are two main reasons for this: a) Coating The coating of screen wires by dried or sticky solids reduces aperture size and can drastically reduce the screen's conductance. Screens should always be thoroughly washed down with a pressure wash gun if the shakers are to be turned off for a period of time. If coating is occurring due to sticky solids during drilling then a pressure gun should be constantly available at the shakers. This should have a base invert feed for invert emulsion mud and water for water-based mud. The best way to deal with this problem is to have a set of clean screens standing by ready to change at connection time. The screens removed should be thoroughly cleaned ready for changing at the next connection. If it is necessary to use the pressure gun while the screens are fitted it should not be blasted down perpendicular to the screen since this breaks down the solids and forces them through the screen. If this problem is very severe, it may be necessary to change to coarser screens until the problem formation has been drilled. Rectangular mesh screens may also alleviate this problem. In general, spray bars should not be used since they cause a break down of the solids. b) Plugging As the name suggests, this problem occurs due to the plugging of the screen apertures by particles of about the same size, often referred to as near sized particles. The problem is most likely to occur with plain square weave screen cloths in unconsolidated sand formations. Rectangular or layered screens will not suffer so severely from this problem. When screens blind many people have a tendency to fit a coarser mesh. This does alleviate the problem but is very poor solids control practice since the sand is then allowed through the screens. The best solution is to reduce the flow rate if at all possible and to fit finer mesh screens for which the particles will no longer be near sized. Screen Size Information With the number of screen mesh designs available today it is important to research screen specifications carefully. It cannot be simply assumed that because a shaker is fitted with a "200 mesh" screen that all particles < 74 mm will pass through the screen with the mud and that all particles >74 mm will be discharged. Variations in manufacture such as wire thickness, oblong mesh design and layered screens complicate the issue. The screens can experience blinding, or the wire mesh can become wet, reducing the open area. This may considerably reduce the particle sizes passing through the screen. A full analysis of the underflow from the shakers is the only valid way to evaluate the particle sizes being carried through the screens. With different screen sizes on the shakers at the same time, it is important to sample immediately before the flow enters the shaker pit and after the flow from each shaker has become homogenized. Sample Point Data Required: Homogenized Mud Weight 6


Under flow PV / YP PSD Retort Solids Conventional Square Mesh Screen Data Mesh

Open Size (mm)

Open Size (in)

Open Area (%)

8x8

2464

0.0974

60.2

10 x 10

1950

0.0750

56.3

12 x 12

1524

0.0600

51.8

14 x 14

1295

0.0510

51.0

16 x 16

1130

0.0445

50.7

18 x 18

955

0.0376

45.8

20 x 20

863

0.0340

46.2

30 x 30

515

0.0203

37.1

40 x 40

381

0.0150

36.0

50 x 50

279

0.0110

30.3

60 x 60

234

0.0092

30.5

80 x 80

178

0.0070

31.4

100 x 100

140

0.0055

30.3

120 x 120

117

0.0046

30.5

150 x 150

104

0.0041

37.4

170 x 170

89

0.0035

35.1

200 x 200

74

0.0029

33.6

250 x 250

61

0.0024

36.0

325 x 325

44

0.0017

30.0

Mesh Designation

d50 Cutpoint (mm)

Baroid XR Mesh Conductance

Square Mesh Conductance

84

169

4.23

3.62

Baroid XR Mesh Screen Data

7


110

153

3.53

2.89

140

127

3.11

2.32

175

98

2.53

1.90

210

86

2.27

1.67

250

68

1.49

1.23

As can be seen from the above table, the new Baroid XR screens have significantly more conductance than square mesh with comparable cut points. This is achieved through the use of an oblong mesh design. With these screens the wires are actually thicker without reducing the overall free area. This design reduces blinding and promotes a longer screen life making them an extremely attractive economical and labor reducing choice. Hydrocyclones Hydrocyclones and centrifuges work to remove solid particles from the mud system by using centrifugal forces. The two most common hydrocyclones are the desander (can remove larger "sand" sized particles of > 40 mm) and the desilter (used to remove "silt" sized particles of > 20 mm). With the use of 200 mesh (74 mm) shaker screens there is no need to run a desander. The rate of separation of the solid from the liquid phase increases with particle diameter and density but decreases with increasing mud viscosity. The use of shear thinning fluids are important for good solids control as at the high shear rates created by the hydrocyclones, the particles will separate out faster. There should be sufficient cones to process between 125 to 150% of the maximum anticipated flow rate. The centrifugal pump must be sized correctly for the mud weight and flow rates to provide sufficient horsepower to maintain the required head. Hydrocyclone Operation Fluid is fed tangentially, via a centrifugal pump, into the top of the cone at a constant head pressure of 75 ft. Circular motion produces high centrifugal forces within the cone. Solids in suspension are accelerated towards the wall of the cone and then move downwards. The solids move to the bottom of the cone and are discharged from the cone. Lighter, solids free, liquid moves upward in the cone and the overflow is returned to the system. Balance the cones with water prior to the start of a well and when operating, ensure that a spray discharge is maintained. A heavier discharge is not necessarily better than a lighter one. Hydrocyclones remove the fine particles that increase viscosity and gel strengths. The finer the particle, the more surface area, therefore the more liquid on the cuttings produces a lighter discharge from a correctly operating cone. The performance of a hydrocyclone is affected by cone diameter, pressure, cone condition, and system pipework. Desanders are not run with invert emulsion muds due to the high liquid 8


content discharged with the solids. Similarly, desilters are generally only run with invert emulsion muds when they are combined with fine mesh screens to become a mud cleaner. Mud Cleaners A mud cleaner is a hydrocyclone that processes the discharge over vibrating fine mesh screens. It is generally only used for invert emulsion muds or for weighted muds as savings can be achieved by reducing barite and invert emulsion losses. A mud cleaner is ideal for rigs that have poor shakers or when screen blinding occurs. The disadvantage is that a mud cleaner returns the finest particles to the active system and can therefore sometimes not be economical. Centrifuges The Baroid centrifuges work by applying increased gravitational forces to particles of differing mass and can remove solids to 2 mm. A centrifuge cannot distinguish between drilled solids and barite and will therefore remove a drilled solid of 15 mm as readily as a 10 mm barite particle. By varying the feed rate, the bowl speed, and scroll speed (retention time) of the centrifuge, the d50 value of the processed mud can be changed to suit requirements. The decanting centrifuge is the one used almost exclusively and there are two basic types: Fixed Speed e.g. Baroid 1434 – Generally set at a pre determined speed. The unit can be modified to run at a different set speed but this is a fairly complex and time consuming procedure. Variable Speed e.g.. Baroid 1458 – Can be easily modified to run at infinite speeds up to a maximum of 4000 rpm. The centrifuge is not designed to process the whole circulating system. As with the other equipment working with centrifugal forces, barite is preferentially removed due to its higher density. When using water-based muds with only one centrifuge, it is operated in solids removal mode while with weighted muds it is run in barite recovery mode. When there are two centrifuges on the rig, there are three main configurations being: Parallel: The two units are each run independently and in solids removal mode. The purpose of this configuration is to double the proportion of mud that is processed. Series – Solids Removal: After the mud has processed through the shakers and hydrocyclones, it is fed into a high volume low speed centrifuge (Baroid 1434 Barite Recovery) to remove barite and the larger drilled solids. The underflow from this unit is then discharged while the overflow is used as the feed for a second centrifuge. The second unit (Baroid 1458 Centrifuge) runs with a low volume high speed and the increased "g" forces remove the low gravity fines and ultra-fines. This system is used when it is undesirable to discard the liquid phase separated from low weight muds. Series – Barite Recovery: The first centrifuge is a high volume low speed unit (Baroid 1434 Barite Recovery Centrifuge) that again separates the barite and larger drilled solids into the underflow where it is returned to the circulating system. The overflow is processed through a low volume high speed unit (Baroid 1458 Centrifuge) to remove the fines and ultra-fine solids. This system is used when savings can be made by recovering the barite in a weighted mud system and when it is preferred not to discard the solids and the associated liquid component from the first centrifuge.

9


Centrifuge Selection Fixed speed units are cheaper but do not allow the versatility that the variable speed offers. For expensive water-based muds and for invert emulsion muds which are generally expensive but also have severe legislative and environmental restraints imposed on them, it is important to ensure the solids being discharged from the system are as dry as possible. Water-Based Muds: For low weight muds it is preferred to use high volume units and if possible to run two in parallel. With each unit running at 200 gpm and 2000 rpm, they combine to process a large percentage of the circulating system. For heavier muds, a barite recovery system should be evaluated. Invert Emulsion Fluids: Due to economic or legislative limitations on the dumping and discharge of the fluid, two units are almost always required for effective solids removal. These need to be arranged so that they can be run in either series or parallel modes and at least one unit must be variable speed. A high speed unit is required if running in barite recovery mode to process the overflow from the first unit to remove all the fines and ultra-fines. Baroid Progressive Cavity Pumps These pumps are capable of supplying a flow of between 0 and 220 gpm. These pumps must be filled with liquid before starting. The initial filling is not for priming purposes, but to provide the necessary lubrication of the stator until the pump primes itself. When the pump is stopped, sufficient liquid will normally be trapped in the rotor / stator assembly to provide lubrication upon re-starting. If, however, the pump has been left standing for an appreciable time, moved to a new location, or has been dismantled and re-assembled, it must be refilled with liquid and given a few turns before starting. The pump is normally somewhat stiff to turn by hand owing to the close rotor / stator fit. However, this stiffness disappears when the pump is running normally against pressure. Always ensure the pump is not run against a closed inlet or outlet valve. Pressure relief valves should be installed where there is the possibility of pressure build up. Depending upon the temperature of the fluids, these pumps can become hot and due care is required. The pumps are designed not to exceed a sound pressure level of 85 dB at 3 ft but in some instances they may be operating at 95 dB so sufficient hearing protection should be worn. Solids Removal Techniques in High Density Muds In an unweighted mud, money is spent controlling or reducing mud weight. In a weighted system, a significant amount of money is spent in keeping the density high. Solids control for weighted and unweighted muds varies due to the cost of large scale dilution and the reduced efficiency of solids removal systems when high density muds are in use. As the concentration of barite increases, the level of free liquid phase in the system decreases, as does the mud's ability to accommodate drilled solids. As drilled solids are picked up and along with barite decrease in size and increase in surface area, rapid increases in viscosity and gel strength occur. The essential purpose of the solids control equipment is to remove as many drilled solids as possible before they degrade to fines and ultra-fines.

10


Shale Shakers: A barite that meets API specifications can contain particles as much as 3.0 % by weight greater than 74 mm. Take an example of a 16 ppg mud that has 410 lb/bbl barite. At 3%, this would be 12.3 lb/bbl. For a 2000 bbl circulating system, this indicates that 11.16 MT of barite would theoretically be removed by a 200 mesh shaker screen. Initial screen selection is obviously critical when drilling with high density muds. Removal of the coarse end in barite will benefit mud properties and reduce wear on mechanical parts however if the screens are initially chosen to allow these particles to circulate, the majority will break down and then finer screens can be run. This method prevents a density drop and reduces costs associated with barite replacement. Screens should initially be no finer than 150 mesh (105 mm) and the amount of barite retained on the screen used in the sand content test will be a guide for when finer screens can be used. Hydrocyclones: An efficient hydrocyclone can reduce the barite content of a mud by up to 60%. With 12.5 ppg mud, the rapid density drop will cause major problems and the cones will also become blocked. This will only get worse as mud weight is increased. Barite will be preferentially removed and all but the biggest drilled solids will be returned to the active system. The recirculated drilled solids will degrade to produce undesirable increases in viscosity and gel strengths. The only efficient method of using hydrocyclones with 18 ppg mud is to dilute the slurry before it enters the cone which is not practical when using invert emulsions and an expensive option with water-based muds. A centrifuge can be used to treat the diluted overflow and can then sometimes make this approach viable for water-based muds. The centrifuge can be used to concentrate the solids in the overflow and discard the dilution water. This approach is not viable with invert emulsions because of the amount of invert base fluid that would be required. Centrifuges: Although the feed rate for centrifuges is relatively low, these are the only real alternative for solids control in high density muds. When the first (Baroid 1434 Barite Recovery Centrifuge) is run in barite recovery mode, the majority of the barite is removed and can be fed back to the system. The deweighted overflow from the first centrifuge is then fed into a second centrifuge via a small holding tank. The second is a high speed unit (Baroid 1458 Centrifuge) operating at > 2500 rpm and the discharge from it is a mixture of fine barite and low gravity solids. The solids are discharged and the clean overflow is returned to the active system. Materials and Systems In certain situations BARAFLOC® can be added to flocculate and settle out dispersed formation solids. EZ-MUD™ and X-TEND® II can be used to flocculate solids and improve solids control equipment efficiency. Shale inhibitors can be used to improve solids removal in water-based muds. These can be used to prevent dispersion of reactive clays into the drilling fluid. Products such as EZ-MUD™, BAROTROL® PLUS, GEM™, CLAYSEAL®, and encapsulating polymers such as PAC™ and DEXTRID® can be used this way. As stated earlier, the use of inhibitive water-based mud systems and invert emulsion systems can improve primary solids removal as drilled shale and clay cuttings are stabilized and removed on the surface. Baroid's soluble silicate-based mud system BARASILC™ has proved very effective at preventing the dispersion of shales and chalk formations, making their removal easier.

11

Drilling Conditions Stuck Pipe

SOP Code: SP Revision Date: 02/12/1997; Amended May 2005

Stuck Pipe Introduction Stuck pipe is an expensive and time consuming occurrence. Expensive because specialized technical services and equipment must be ordered and time consuming due to lost drilling time. Stability of uncased hole may deteriorate in the time required to free the stuck pipe and get back to drilling. A review of recent industry studies reveals the following information concerning stuck pipe: • Hole Angle: Low angle holes had the best success rates for freeing stuck pipe • Hole Size: Success rate for freeing stuck pipe was slightly higher for larger than smaller holes. • Mud Weight: The chance of freeing stuck pipe is higher in wells requiring lower mud weights. • Spotting Time: The quicker the spot is applied, the higher the chance of success. • Open Hole: Open hole length did not consistently affect the success rate for freeing stuck pipe. Causes of Stuck Pipe Drill strings or casing strings can become stuck by basically two mechanisms: Differential Sticking Mechanical Sticking

1

Drilling Conditions Torque and Drag

SOP Code: T/D Revision Date: 02/12/1997; Amended May 2005

Torque and Drag Introduction The drilling of wells with high angles of inclination, tortuous directional plans, and greater horizontal displacements place a strong demand on the lubricity characteristics of drilling fluids. Frictional resistance to rotation of the drill string is called torque, and frictional resistance to hoisting or lowering the drill string is called drag. Torque and drag can cause: • Drilling equipment (engines) to overheat and/or become damaged • Parting of the drill string and/or bottom hole assembly (BHA) • Reduction in the rate of penetration • Steering and orienting down hole tools may be difficult and time consuming • Reduction in effectively applied weight on bit • Wear on drilling equipment and tubulars • Reduction in ability to slide • Causes of Torque and Drag Friction between drill string and borehole is expected when drilling a deviated wellbore. Many factors can cause torque and drag problems: • Inadequate hole cleaning • Highly deviated holes • Direction or formation changes Undergauged hole • An increase in differential pressure • Bit or bottom hole assembly balling • Metal to metal contact • Cuttings bed on the low side of a high angled hole • Excessive build up of filter cake • Reactive, swelling formations (shale) • Dogleg severity Preventing and Reducing Torque and Drag Torque and drag may be anticipated from problems on offset wells. If possible, the cause should be identified (i.e. hole cleaning, high angle, etc.) and recommendations for that particular problem addressed. Response to the problem may vary, based on the cause. Analyze the directional profile of the well to determine if there are areas of high dog leg severity. Consider the casing design of the well to determine if the problem is in open hole or cased hole. Analyze fluid properties to determine if it might be a hole cleaning or differential pressure problem. 2


If the problem is related to dog leg severity, several approaches could provide relief. Adequate treatments with lubricants properly applied for cased hole conditions, open hole conditions or both. The use of drill pipe rubbers (rotating or non rotating) can provide stand off for the drill string through the problem section, or while performing reaming operations through high dogleg sections. Mud considerations besides lubricants include maintaining a good quality filter cake, and proper solids content to minimize the effect of differential pressures on the drill string. Proper hole cleaning is vital to maintaining acceptable torque and drag levels. The presence of cuttings beds can exert a great amount of friction on a drill string. A program of regularly scheduled wiper trips will aid in minimizing frictional effects on the drill string in the wellbore. Baroid Fluid Services Lubricity Tester/EP Tester may be used to evaluate and optimize the effectiveness of different products in reducing the lubricity coefficient. A lubricity co-efficient of +/-0.2 is reasonably good for water-based muds. Invert emulsion systems generally test at values less than 0.1. The Lubricity tester helps to screen products, but use in the field is the only true measure of success. FANN® 90 testing can be performed to determine the quality of a filter cake and how it erodes under dynamic conditions. If torque and drag is due to reactive, swelling formations, the addition of inhibitive products may be required to prevent them from hydrating. Materials and Systems With water-based muds, the choice of lubricant will depend on results of lab tests or field experience. Baroid's product line includes many lubricants that have been successfully applied in the field: BARO-LUBE™ GOLD SEAL

EP MUDLUBE®

BARO-TROL® PLUS

EZ-MUD™

BXR® L

GEM™

DRIL-N-SLIDE™

TORQ-TRIM® II

ENVIRO-TORQ®

TORQ-TRIM 22

Solid beads can also be used to reduce torque: STICK-LESS® 20 Solid glass beads TORQUE-LESS® Solid glass beads LUBRABEADS® Plastic beads In certain areas, combinations of lubricants have proved more successful than a single product. The use of DRIL-N-SLIDE has improved the performance of the more conventional lubricants EP 3


MUDLUBE and TORQ-TRIM II. CMO 568™ has been used in invert emulsion systems in the North Sea. BARACARB®, BAROFIBRE® and other bridging materials can bridge porous formations and reduce the chance of differential sticking that may be indicated by torque and drag at the surface. BAROFIBRE has been used for torque reduction in invert systems on large ERD wells in the UK. For metal on metal, EP MUDLUBE and TORQ-TRIM 22 have proven successful in reducing torque.

4

Drilling Conditions Well Control

SOP Code: WC Revision Date: 06/06/1997; Amended May 2005

Well Control Introduction Controlling formation pressures is one of the most important functions of a drilling fluid. Hydrostatic pressure exerted by a drilling fluid column is commonly considered the preferred method for controlling formation pressures. It is important to predict abnormal pressures during pre-well planning stages, so that provision can be made for the appropriate drilling fluid type and products, e.g. BAROID® and BARODENSE® weighting agents, as well as essential equipment such as surface blowout preventers, mud monitoring equipment, de-gassers, and mud mixing systems. Each of these items and the actions listed below are essential for developing an efficient, flexible drilling plan. • Geologic structure maps and cross sections. • Type of formations, the expected formation pressure gradients, and a review of the fracture gradient history of the area to be drilled. • Planning sessions with those who generated the prospect, so they can explain the expected geology and pressures. • The type of rig and equipment needed to drill the well. • A preliminary meeting, prior to spud, between the operators drilling group and service companies to discuss expected well services. Causes and Detection of Abnormal Pressure Formation fluids (gas, oil, and/or water) must be trapped for abnormal pressures to exist. These abnormal pressures are confined in closed formations where they are caused by the fluid bearing some of the weight of the overlying rock. If escape routes are available and fluids can move to the surface, then only normal, or even subnormal, pressures will be present. Reasons for abnormal pressures include: • Tectonic movement • Rapid deposition • Reservoir structure • Re-pressuring of shallow reservoirs • Paleo-pressures • Clay diagenesis • Salt domes and salt deposition Tectonic Movement Tectonic movement is the movement of formations where the position of one formation changes relative to another. Fluids may be trapped and squeezed by faulting. Volume in the reservoir is compressed, which increases the pressure on the fluid. 1


Rapid Deposition Silts and sands may be deposited rapidly in a basin due to the action of rivers or other forms of land mass erosion. The water in pore spaces becomes trapped by the rapid deposition, and the fluid is forced to support part of the increasing overburden as deposition continues. Reservoir Structure Abnormal pressure due to reservoir structure is where a permeable formation, such as a sand lens, lies at an angle (not absolutely horizontal). If the formation is not level with respect to the surface, then the depths at which its top is encountered varies. This means that its pressure gradients are different at different point. Higher pressures gradients will be noted at higher points along of these reservoirs because the same formation pressure is encountered at shallower depths. Re-pressuring of Shallow Reservoirs A shallow formation may develop communication with a deeper formation through faulting or as a result of a drilling operation. A pressure that may have been normal at its original depth is now encountered in a shallower formation. Paleo-Pressures Paleo pressures occur when a formation surrounded by impermeable barriers is uplifted intact to a shallower depth. This causes the pressure gradient in the uplifted formation to increase because the same formation pressure is now at a shallower depth relative to the surface. Clay Diagenesis The chemical change and resulting release of water from montmorillonite under conditions of high temperature is called clay diagenesis. If water from montmorillonite undergoing diagenesis becomes trapped and can migrate no further, abnormal pressures will develop. Salt domes and salt deposition Rock salt has two unusual properties: • Impermeability to fluids • Ability to dissolve and re-crystallize in a different shape Formations directly under rock salt contain abnormal pressures because fluids trying to escape those formations as a result of compacting forces were trapped by the salt. Preventing Well Control Situations One of the basic and very important functions of a drilling fluid is to prevent formation fluids from entering the wellbore. In order to do this, the pressure exerted by the fluid column must be greater than, or equal to, the pressure exerted by the formation fluid. Logically, it follows that when the formation pressure exceeds the pressure exerted by the mud column, an influx of formation fluid enters the wellbore and potential exists for a blowout. 2


Pressure Balance Maintaining a pressure balance while drilling a well can be delicate and complex, an overbalance by the fluid column can result in loss of returns, decreased drilling rates, differential sticking, and possible formation damage. An underbalance can result in a well control situation that can lead to fire or injury, and is a very costly problem to the operator. The pressure balance consists of: • Over burden pressure. • Formation fluid pressure. • Static fluid column pressure. • Equivalent circulating density. • Pressure surge and swab due to pipe movement. Overburden Pressure Overburden pressure is simply the weight of the earth above any given point expressed in pounds per square inch of area. Normal overburden pressure is considered to be 1.0 pounds per square inch per foot of depth, but actual overburden pressures vary in different areas of the world. Formation Fluid Pressure As layer upon layer of sediments are deposited from a marine environment, the grains of the sediments at the lower layers will normally compact and support the weight of the upper layers. As the compacted water associated with the sediments is squeezed out, it will find its way back to the surface or sea bottom. The only pressure on this fluid is from its own weight (hydrostatic pressure). If in some way an impermeable barrier is placed in the path of water normally expelled, it will no longer be free to migrate as overburden is added. Since water is essentially incompressible, the sediment will not be able to compact and the water will begin to support part of the weight of the overburden. Static Pressure of a Drilling Fluid Column The static pressure exerted by a column of fluid, its hydrostatic pressure, is a function of the height of the column and the density of the fluid. It is the weight of the fluid in the column above any given point expressed as pressure in pounds per square inch. Equivalent Circulating Density of a Drilling Fluid Column Movement of a fluid column requires energy. Energy is expanded to satisfy frictional pressure losses within the circulating system. The circulating pressure losses in the annulus must be added to the hydrostatic pressure of the drilling fluid. This is a more accurate measure of the actual pressure exerted on the bottom of the hole during circulation. The total pressure is expressed in mud density units and is called equivalent circulating density (ECD).

3


Pressure Surges Due to Pipe Movement Any movement of a fluid column, whether by a pump or movement of a drill string, causes additional pressure on the walls of the wellbore. In the case of pipe movement, the induced pressure surge could be negative (swab) with upward movement and positive (surge) with downward movement of the pipe. Detection of an Underbalanced Condition When the pressure of a formation exceeds the fluid column pressure, a well control situation results. A blowout is an uncontrolled flow of formation fluids. If an influx of formation fluids reaches a blowout condition, well control specialists are sometimes called in to remedy the situation. A kick is the result of a short duration underbalanced condition. Formation pressure is balanced before the formation fluid influx reaches blowout proportions. The key to successful kick control is early detection. Kick detection and control equipment is usually, but must be used at the appropriate time. There are several indications that a kick has occurred. Regardless of the operation in progress, some or all of these indicators will be evident: • The first indication of a kick when drilling is a drilling break (or reverse drilling break). • An increase in return flow rate with no corresponding increase in pump rate. • An increase in pit volume. • A circulating pressure decrease that results from an underbalanced mud column in the annulus. • A reduction in return mud weight when the intruding fluid reaches the surface. Examine a kick that occurs during a connection. The sequence of events is similar to those observed when drilling, but there are some differences. The well flows with the pump not operating. This indicates the equivalent circulating density (ECD) is enough to provide a small overbalance while pumping. A second indication is an increase in pit volume. After resuming circulation, loss of pump pressure occurs as the annular mud column becomes lighter than that inside the drill string. The loss becomes greater after successive connections, each of which allows more formation fluid into the wellbore. Reduction in mud weight will eventually be seen at the flowline. Well kicks during a trip provide the greatest potential danger. The most effective blowout control procedures require that the bit be near the bottom of the hole. A common practice when pulling drill pipe out of the hole is to stop every three to five stands and fill the hole with enough mud to replace the displacement volume of the drill pipe withdrawn. The hole not requiring the appropriate volume of mud to fill is an indication that formation fluid 4


is replacing the drill string displacement from somewhere downhole. Displacement of the drill pipe or collars may be calculated by: 0.000367 (wt/ft) (depth) = displacement in barrels. The well control process can only begin after a kick has been recognized. The pressure balance is initially restored by shutting the well in. This balances the formation pressure by confining it to the annular space and inside the drill string. The desired result is to exert the additional pressure required with the mud column rather than by confining it with surface equipment. This involves replacing the combination of formation fluid and mud in the hole with whole mud of sufficient density to balance the formation fluid pressure. The replacement has to be accomplished while maintaining sufficient back pressure with the surface choke equipment to slightly overbalance formation pressure. The objective is to maintain a constant bottom hole pressure sufficient to prevent further influx of formation fluids while the replacement is accomplished. Kick Killing Procedures Differences in well control procedures arise from the methods used to monitor bottom hole pressure and maintain back pressure on the well. The following well control procedures presume that the drilling rig is equipped with an adjustable choke. Wait and Weight Method The most commonly used well control technique is the wait and weight method. This method is so named because the required mud weight is achieved, then pumped down at the same time the kick fluid is brought to the surface. This method may also be called the Engineer's Method or the One Circulation Method. The steps in the wait and weight method are: • Read and record shut in pressures, pit gain, time and date. • Calculate the required kill mud weight and weight up the surface mud system to this weight. • Fill out the drill pipe pressure schedule: • Calculate the strokes, barrels, or minutes required to displace the drill string with kill weight mud. • Calculate the initial and final circulating pressure values. • Mathematically develop a table listing of the strokes, barrels, or minutes to displace the drill string versus the total pressure decrease, which is initial circulating pressure less final circulating pressure. • Graphically plot back up initial and final circulating pressures. Note: Kill rates should be taken every day using at least two kill rate speeds per pump including back up pump. Determine minimum casing pressure value, then hold it constant by manipulating the choke and bring pump up to kill rate speed. 5


Once the pump has been brought up to kill rate speed, go to drill pipe gauge. The drill pipe gauge must read the initial circulating pressure value. Follow the drill pipe pressure schedule while the drill string is being displaced with kill weight mud. When kill weight mud reaches the bit, the drill pipe gauge must read the final circulating pressure value. Maintain the final circulating pressure until kill weight mud reaches the surface. When the kill weight mud reaches the surface, stop the pump and close the choke. All shut in pressures should read zero. Open the choke and visually check for flow. Drillers Method In the second kill method, the influx is pumped out of the wellbore after recording the shut-in pressures and pit volume increase, but before weighting up the drilling fluid. Once the influx has been pumped out of the well, the well is shut-in and the surface mud system is weighted up to the required kill weight. This procedure is also called the two-circulation method. It allows the quickest removal of intruding fluid from the hole, but subjects the wellbore to greater stress than the wait and weight method. Note: Most kicks require a one pound per gallon or less weight increase, so this method is feasible in most cases. The steps in the drillers method are: • Read and record shut in pressures, pit gain, time and date. • Calculate kill weight mud and initial circulating pressure. • Hold the casing pressure constant at minimum value by manipulating the choke and bring the pump up to kill rate speed. • Once the pump has been brought up to kill rate speed, use the drill pipe gauge. The drill pipe gauge must read the initial circulating pressure value. • Maintain initial circulating pressure until the kick is out of the hole. • Once kick is out of the hole, stop the pump and close the choke. • Weight up the surface mud system to kill weight. • Hold the casing pressure constant and bring the pump up to kill rate speed. • Continue holding the casing pressure constant while the drill string is being displaced with kill weight mud. • Once kill weight mud reaches the bit, observe and record the final circulating pressure on the drill pipe pressure gauge. • Maintain the recorded final circulating pressure until kill weight mud reaches the surface. When the kill weight mud reaches the surface, stop the pump and close the choke. All shut in pressures should read zero. Open the choke and visually check for flow. 6


Concurrent Method A third method requires weighting up the surface system while circulating out the influx. Once kill weight mud has reached the bit, final circulating pressure is maintained on the drill pipe gauge until the influx is out of the wellbore and kill weight mud is returning to the surface. The steps in the concurrent method are: • Read and record shut in pressures, pit gain, time and date. • Calculate the kill weight mud value, initial and an final circulating pressure values. • Calculate the mud weight required to balance formation pressure using the following formula:

Where: WR = Weight required to balance Wi = Weight in use SIDPP = Shut In Drill Pipe Pressure TVD = True Vertical Depth Note: A safety factor should be added for a trip. A safety margin of 0.2 to 0.5 pounds per gallon additional mud weight is usually sufficient. Calculate the Final Circulating Pressure using the following formula:

Where: FCR = Final Circulating Pressure WR = Weight required to balance Wi = Weight in use • Calculate the strokes, barrels, or minutes required to displace capacity of the drill string. • Calculate the hydrostatic pressure increase for 0.1 lb/gal increase in mud weight. • Based on a 0.1 lb/gal increase per drill string capacity displacement, calculate the number of capacity displacements needed to place kill weight mud at the bit. • Calculate the minimum drill pipe pressure for every 0.1 lb/gal increase that is pumped to the bit. Start by subtracting the hydrostatic pressure increase that was calculated in step 4 from the initial circulating pressure and continue for every drill string capacity displacement. • Set up a table listing the density increments, drill string displacements, and minimum drill pipe pressure values. Example: Density Increments

Drill String Displacements

Drill Pipe Pressure

Hold casing pressure constant at minimum value, while bringing the pump up to kill rate speed. When the pump reaches kill rate speed, go to the drill pipe gauge. The drill pipe gauge must read initial circulating pressure. 7


Follow the table listing until the kill weight mud reaches the bit. When the kill weight mud reaches the bit, the drill pipe gauge must read final circulating pressure. Hold final circulating pressure value until kill weight mud reaches the surface. When the kill weight mud reaches the surface, stop the pump and close the choke. All shut in pressure must read zero. Open the choke and visually check for flow. Well control drills must be held weekly, and the entire crew must participate so that every crew member knows exactly what is expected of him in the event of a well control situation. Slow pump rates must be taken and recorded at the earliest opportunity on each tour. Drilling fluid density must be maintained at a value that will provide a safety margin of at least the drilling annular pressure loss above expected formation pressures. Adequate supplies of barite must be maintained on the rig at all times. All pit volume totalizer and flow sensors should be accurately calibrated and maintained so that they can be counted on to provide an early warning in the event of a kick. All personnel must be aware that when a formation containing gas is penetrated, regardless of the mud weight, a substantial increase in background gas will be experienced. This is due to the fact that the gas contained in the pore space of the formation rocks will expand as it is circulated up the annulus. It will be twice its original volume when it gets to half the depth that it was penetrated. It will continue to expand at this rate until it reaches the surface. Thus, what started out as a small volume of gas at total depth can end up being a very significant volume of gas at the surface. Ballooning The phenomenon called ballooning can manifest itself in several different ways. One is when a permeable formation is either balanced or slightly overbalanced by the drilling fluid while circulating. The formation can take a noticeable amount of fluid in the form of seepage. When the pumps are shut off, however, the formation in question will push all or part of the seeped fluid back into the wellbore. If, when the pumps are shut off, the well flows for a short period of time and then ceases to flow, "Ballooning" should be suspected. If there is any questions that this is what is happening, bottoms up should be circulated to verify that no influx of formations fluids has been incurred. Pit volume totalizer equipment should be maintained on the rig along with a trip tank that has both electronic and mechanical systems for measuring fluid volumes during tripping procedures. The fluid density should be checked at both the flow line and suction pit every half hour while circulating. The section from the well plan detailing mud weight vs. depth should be posted both in the rig dog house and the mud pit area. Well control drills must be conducted for all rig crews at least once per week and the B.O.P. and degassing equipment must be tested according to regulations. Circulating bottoms up prior to coming out of the hole should be standard practice for all trips and after any unexpected drilling breaks. The well should be checked for flow periodically on trips, particularly if there is any reason to suspect that swabbing might have occurred.

8


A supply of weighting material sufficient to increase the system density to a value exceeding the maximum anticipated mud weight for an interval should be maintained on location at all times. A supply of mud products sufficient for replacing the entire system, should loss of returns be experienced should also be maintained at the rig site. The flow properties of a drilling fluid can effect the efficiency of the degassing equipment. If a situation develops where a fluid with very high concentrations of polymers is hindering the efficiency of the equipment, it may be necessary to relax the rheology to allow the gas break out, then readjust the fluid properties after the situation is under control.

9

Baroid SOPs

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