DLG_Fluids_WS_(Presentation).pdf

DRILLING FLUIDS AWARENESS CAMPAIGN

“The lifeblood of your well” BASIS OF DESIGN

Drilling Fluids Awareness Workshop Basis of Design

Mission Statement “Raise the level of awareness and competency of Saudi Aramco Drilling Engineers, Rig Foremen and Mud Engineers for the application of drilling and completion fluids technologies to meet our drilling and completion objectives”


Workshop Series Structure

Module I

• Basis of Design

Module II

• Drill-in and Completion Fluids

Module III

• Planning and Logistics • Lessons Learned & Best Practices

Drilling Fluids Awareness Workshop Basis of Design How to get the most out of this workshop •

•

Mobil phones on silent Active Participation – ask questions

•

Return from breaks on time

•

Take workbook back to your office / rig

•

Use it!

•

Share what you have learned

•

When in doubt, call your DTD rep

Drilling Fluids Awareness Workshop Basis of Design Definition: Set of conditions, needs and requirements taken into account in designing a mud program.

What do we need to do? •

Identify needs and requirements

•

Identify drilling problems and technical limits (Offsets)

•

Select the right Drilling Fluid

•

Preparing the Resources and Contingencies

Drilling Fluids Awareness Workshop Basis of Design Example BOD Field Specific Drilling Fluids - Design Criteria

Development Wells Hole Size

Well Schematic

Assumptions and Boundaries

Objectives

Potential Risks/Technical Challenges Potetial lost circulation above RUS formation Unconsolidated sand in the Neogene

M it ig at io ns /Ac ti on s

P ro po se d F lu id

O ff se t Ex pe ri en ce F lu id s R el at ed

Key Performance Indicators

Keep planned density If returns are lost, drill with SW and SPUD MUD Gel slips

KARN 8 - Lost returns while running csg Bbls Mud lost/ft KARN 7 - lost 100% returns at 1047 ft KARN 2 - 100% losses at 830 ft

Drill to 3338 ft i nto Ahmadi 28" Hole Member without problems

Possible water flow and lost if losses are experienced while circulation from UER cementing, pump 50% excess Tigh hole and swelling in Aruma shale

Keep the planned MW to control water flow Add sealing agents to the drilling fluid and keep filtration value low Keep good mud rheology if hole cleaning is an issue due to wellbore instability in Aruma

SPUD MUD

KARN 6 - lost complete returns at 1550 ft KARN 8 - casing got stuck at 3685 ft Bbls mud lost/ft KARN 5 - Total losses at 1689 ft, switch to SW

Drill to 6449 ft without problems 22" Hole Maximie bit HSI to reduce bit balling tendency

Possibility of using a vibration sub Lost c irculation in Wasia Arab formations are expected to Water flow in lower Ratawi be productive Bit balling in Wasia shales Casing point may change if hole problems are experienced

Keep planned MW Keep high dilution rate Add Wallnut and CONDET (Soap) or glycol for bit balling Keep enough volume of fluid

LSND with KCL

KARN 6 - Bit balling at 4120 ft KARN 7 - 100% losses prior to drilling Shu'aiba KARN 4 - Lost 100% returns at 5331 ft

Bbls mud lost/ft Non Productive time allocated to mud losses

KARN 6 - Partial losses at 6964 ft KARN 7 - Well flowed at 9100 ft KARN 1 - Lost Returns with 77 PCF at 6576 ft

Bbls mud lost/ft Non Productive time allocated to mud losses

LSND

KARN 6 - Well flowing at 10248 ft with 112 PCF KARN 7 - No major problems observed

NPT allocated to well control issue

LSND

KARN 6 - Drilling at 10908 ft, well flowed Bbls of mud lost/ft with 95 PCF NPT allocated to stuck KARN 7 - Stuck at 13935 ft while pipe reaming

28x34"

Drill 28" pilot hole and open it to 34" wihtout problems.

None

30"

1145' MD/1145' TVD

24" Casing 3338' MD/3334' TVD

18 5/8" Csg 449' MD/6445' TVD

Casing point planned at 30 TVD

Drill to the kick off point at 660 4 ft into base Jilh Dolomite Hold 52 degrees of inclination to DST data from KARN 1 16" Hole indicated EMW of 69.7 PCF to TD (10672 ft) balance Manifa 13 3/8" Csg 223' MD/8870' TVD

12898' MD/11115' TVD

7" Liner 15500' MD/12704' TVD

Hold 52 degrees inclination to TD, The slurry density and design 12" Hole top of Khuff formation will depend on Jilh pressure Casing will be set at the top of Khuff regardless of high Jilh pressure

8 3/8" Hole

Hold 52 degrees inclination to TD. Vibration data can be used in thsi section for optimizing Run open hole logs without performance problems

Possible lost circulation in Hanifa Possible gas in Jilh Dolomite

Have enough LCM material on location, particulate and cross link polymers. Be ready to pump cement plugs LSND Keep the planned density at all times and monitor mud pit levels closely for any kick

Abnormal gas and /or Have plenty barite on the rig saltwater flow in lower Jilh Have enough LCM materiial on the rig Tigh hole/swelling shales Control fluid rheology when weighting across Kilh, Sudair and Khuff Use lowest practical MW Lost circulation in Khuff Minimize ECD by using low pump reservoirs rates.Karn 6 succesfully drilled with H2S in the Khuff reservoirs Possible tigh hole/sticking in 250 gpm Monitor pressure closely while Khuff formations drilling

BASIS OF DESIGN Saudi Aramco Typical Mud Systems (page 3-15)

GENERAL DRILLING FLUIDS PRACTICES Drilling

fluids are classified by the type of base fluid used : water or oil.



Different drilling fluids are selected based on technical and environmental requirements to achieve the required objectives of the well/project. Finally,

drilling fluid selection and design is optimize for cost. project.

DRILLING FLUIDS CLASSIFICATION

More than 75% of wells drilled used WBM in Saudi Aramco

Drilling Fluids OBM

All Oil

Invert Emulsion

WBM

Direct Emulsion

Polymer-Based

Brine based

Drill Water Based

Clay-Based

Dispersed

Non-Dispersed

WATER-BASED DRILLING FLUIDS

KCl

OIL-BASED DRILLING FLUIDS

TYPICAL MUD SELECTION CRITERIA ONSHORE e.g. Manifa ERD Wells Onshore 22”

Hole

Section

Spud Mud

17”

Hole

Section

KCl LSND

12-1/4”

Hole

Section

OBM (hole stability &

8-1/2”

Hole

Section

6-1/8”

Hole

Section

lubricity in long reach sections)

NaCl based Reservoir DIF

DIRECT OIL-IN-WATER EMULSION DIRECT OIL-IN-WATER EMULSION • • • • •

Oil emulsified in water Utilizing simple oil-in-water emulsifier Oil volume percentage up to 45% Fluid density can be as low as 56 - 58 pcf. Minimize potential losses across typically Weak formations in Wasia and Shuaiba by getting lower densities.

ALL OIL SYSTEM • •

•

Designed to protect the Reservoir Ensures proper reservoir rock protection especially for horizontal drain holes in clastic reservoirs. Fluid density can be as low as 56 pcf and can be increased with sized calcium carbonate or barite for non-payzone drilling.

RESERVOIR DIF OBJECTIVES

•

Protect the reservoir from formation damage

• • •

•

Bridging the pore throats/fractures Low residue mud additives Acid soluble mud additives

Build an external filter cake with low lift off pressure for complete clean up.

RESERVOIR DIF DESIGN

•

Particle Size distribution must be matched to the size of the porosity • For unknown pore diameters use the square root of the permeability (md) to estimate pore throat size in microns • Base fluid selection is driven by mud weight requirements and formation sensitivity • Mud additives are selected for premium performance and minimum damage for the wellbore conditions • For water/brine base fluids, base fluid should be the same as the completion fluid (this is also true in many cases for oil base DIF)

Rule of thumb : Minimum solids content is a design criteria

“THE COMPLETION STARTS WHEN THE BIT HITS THE RESERVOIR.”

WB Reservoir Drill In Fluid BRINE: Brines are aqueous solution at

Water

XC Polymer

Modified Starch 90 – 94% BRINE

any concentration of any combination of typical salts generally used to achieve solids free density or shale inhibition (can be single salt, 2 salt or 3 salt fluids) SALT: it is not just as sodium chloride (NaCl), but as any type of salt us ed to build drilling or completion fluids.

NaOH or MgO

There are 2 classes of salts commonly used in our industry: NaCl or other salt

Sized CaCO3 blend

1) Inorganic salt – Sodium, potassium, calcium, or ammonium chloride; sodium, calcium or zinc bromide 2) Organic salt – Sodium, potassium or cesium formate;

“THE COMPLETION STARTS WHEN THE BIT HITS THE RESERVOIR.”

Oil Base Reservoir Drill In Fluid

Mineral Oil Primary Emulsifier Secondary Emulsifier Organophilic clay Organophilic lignite Lime CaCl2 CaCO3 f Water

RESERVOIR DIF SYSTEM MAINTENANCE Maintaining particle size distribution and fluid loss properties is the main objective Solids control equipment Proper measurement equipment (PPA, etc) Regular bridging solids additions •

• • •

Do not use asphaltic products (Soltex, Blacknite, etc.) in the reservoir and avoid or minimize bentonite or barite is possible in the mud. Avoid typical grease pills containing diesel, mineral oil, bentonite, and barite in the reservoir. Glycol pills are preferred first steps in freeing the pipe along with reducing mud weight if possible to minimize formation damage. •

•

“THE KEY TO GOOD DRILL IN FLUID AND MINIMUM FORMATION DAMAGE IS

GOOD WELLSITE MUD ENGINEERING.”

A note about brine drilling fluids

•

Different brines for different densities

•

Brine compatibilities •

•

Monovalent vs Divalent

Completion fluid must match the drilling fluid Do not forget crystallization temperature

•

OVERBALANCE DRILLING FLUIDS •

•

•

Prevent Differential Sticking of Drill String.

Key method is creation of tight filter cake and minimize fluid loss.

How much differential pressure is high overbalance? It depends on permeability, inclination, etc. etc.

–

•

Generally speaking, normal mud can handle up to 500 psi without special efforts.

OVERBALANCE DRILLING DIFFERENTIAL STICKING PREVENTION MECHANISM

• Utilizing mud pressure isolation technique. • Create an ultra-low permeable, finely packed and slick filter cake across zones of different pressure regimes. • An overbalanced drilling fluid can also be designed for drilling in the reservoir – the additives will be different.

High Performance Water-Based Mud Technology •

New alternative to oil based fluids for environmental

reasons. •

Strictly targeted at environmentally sensitive areas.

•

The best system system is still an oil-based oil-based drilling drilling fluid. fluid.

5-STEP PATH TO SUCESS 1.

Planning

2.

Planning

3.

Planning

4.

Execution

5.

Post well audit/lessons learned

Mud repres represents ents 5 - 15 % of drilling drilling costs but but can cause 100% of drilling problems


Risk Assessment, Contingencies and Mitigations

Drilling Fluids Awareness Workshop Basis of Design Identified Wellbore Risks Aquifers

HP Water Flow

Lost Circulation

Hard, abrasive Sandstone

Unstable Hole, Caving

Sour Gas

Swelling Shales

Reactive Shales

Hard Anhydrites

Oil Flows

Tectonics, Bit Sticking

Gas

Drilling Fluids Awareness Workshop Basis of Design Identified Wellbore Risks By Formation Type Sandstone

• • • •

Mud losses Differential Sticking Tight Hole Formation fluid influx (Kick)

Shale

• • • •

Bit balling Wellbore Instability Torque & drag Tight Hole

Carbonates

• Severe Mud Losses • Differential Sticking • Formation Fluid Influx (Kick)

Anhydrite Siltstone

• Mud Contamination • Low ROP’s • Low ROP • Tight Hole

Drilling Fluids Awareness Workshop Basis of Design Drilling Problems related to drilling fluids Bit Balling

Mud Losses

Hole Cleaning

Wellbore Stability

Stuck Pipe

Drilling Fluids Awareness Workshop Basis of Design Drilling Problems – Mud Losses

Prevention

Identification

Curing

Drilling Fluids Awareness Workshop Basis of Design Drilling Problems – Mud Losses Prevention

Set casing in the right place • Cover high pressure zones • Cover unstable zones • Set it in competent formations

LCM Pre-treatment • Background concentration • Hourly additions

• As pills • BHA limitations • Screen selection

Minimize Downhole pressure • Cuttings load in the annulus • Mud rheology • Surge pressures • ECD management

Drilling Fluids Awareness Workshop Basis of Design Drilling Problems – Mud Losses Identification & Curing Locate the loss Zone Formation Information

Operational Information

Logging Methods

Identify loss mechanism and Assess the severity Invasion

Fracturing

Assessing the severity

Cure the losses applying the available solutions Choose LCM recipe as per loss severity assessment

LCM size and concentration will depend on BHA limitations

Spotting technique is critical for success

Drilling Fluids Awareness Workshop Basis of Design Drilling Problems – Mud Losses Choosing the LCM

Porous & permeable sands Coarse sands and Gravel Fractures, Vugs, faults, caverns

• Fine Fibers • Fine Particles • Fine Flakes

• Coarse and Medium fibers, particles, flakes and marble chips • • • • •

Cross link polymers Gunk plugs Flash set plugs Cement plugs Foam cement

Drilling Fluids Awareness Workshop Basis of Design Drilling Problems – Mud Losses Applying the LCM

Direct Additions As LCM pills or plugs

• Load the active system up to 30-40 ppb with LCM • Check the impact of the LCM on the fluid rheology and density • Using coarse shaker screens to maintain the LCM

• Concentrations used up to 200 ppb with OEDP (particles, fiber and flakes) • Cross link polymers, gunk plugs, polymer plugs, chemical sealants • Cement plugs

Drilling Fluids Awareness Workshop Basis of Design Drilling Problems – Mud Losses Mud Cap Drilling

Do not regain circulation Use the mud cap to cover zone of risk at all times Discontinue use of LCM Mud cap can be an inhibitive fluid

Drilling Fluids Awareness Workshop Basis of Design Drilling Problems – Stuck Pipe Identification

Mechanical Hole pack off and bridges Hole geometry Differential Excessive mud weight Depleted zones

Drilling Fluids Awareness Workshop Basis of Design Drilling Problems – Stuck Pipe Prevention Mechanical

Differential

Design well with optimum trajectory

Minimize overbalance

Hole cleaning

Design BHA for minimum wall contact

Control wellbore instability

Control filtercake quality

Minimize backreaming

Keep the pipe moving

Monitor torque & drag closely

Use bridging agents in the mud

Drilling Fluids Awareness Workshop Basis of Design Drilling Problems – Stuck pipe Spotting Fluid - Functions

Attack the filtercake Create channels through the filter cake (between DP & wellbore) Lubricate (between the DP & wellbore) Lower the hydrostatic Dissolve acid soluble solids, like CaCO3 (using acids)

Drilling Fluids Awareness Workshop Basis of Design Drilling Problems – Stuck pipe Spotting fluid options

Drilling Fluids Awareness Workshop Basis of Design Drilling Problems – Stuck pipe Curing

Drilling Fluids Awareness Workshop Basis of Design Drilling Problems – Stuck pipe The surest way to free stuck pipe is

A LWAYS BE

P REPARED

Drilling Fluids Awareness Workshop Basis of Design Drilling Problems – Stuck pipe Soaking Time

Question: If you are stuck in the hole, how much time do you have? Answer: all day and more! Spotting pills take time to penetrate the filter cake. Each pill should be allowed to soak 12 – 18 hrs *except surfactant and acid pills This could mean one pill train is in the hole 36 hrs or more. Believe it, it works!

Drilling Fluids Awareness Workshop Basis of Design Drilling Fluid Contamination 

Carbonates/bicarbonates



Salt



Calcium from cement



Calcium from other sources



Magnesium



H2S



Low Gravity Solids



Air entrapment



Bacterial Degradation



Corrosion



Foaming



Hydrocarbon Influx



Thermal Instability



Emulsion breaking



Water wetting



Iron

Drilling Fluids Awareness Workshop Basis of Design Drilling fluid contamination – H2S Contaminant Hydrogen Sulfide

Compound/ Ion H2S / H+, S

Source H2S from formation gas, thermal degradation of organics, bacterial action.

Method of measurement Garret Gas Train (quantitative). Automatic rig H2S monitor. Lead acetate test

Possible effect on fluid High Yield point High fluid loss Thick filter cake pH decrease pm decrease Ca increase

Course of action Increase Ph > 11 with Ca(OH)2 , or NaOH Condition fluid to lower gels for minimum retention of H2S Operate degasser Displace with oilbase fluid. Add excess Ca(OH)2 to precipitate = S

Drilling Fluids Awareness Workshop Basis of Design Drilling fluid contamination – H2S Pounds SourScav required to remove H2S 20 19 18 17 16 15 14 v a13 c S r12 u o11 S l10 l e r 9 r a B 8 r e 7 p s 6 d n 5 u o 4 P 3 2 1 0 0

250

500

750

1000

1250

1500

1750

2000 2250 ppm H2S

2500

2750

3000

3250

3500

3750

4000

Drilling Fluids Awareness Workshop Basis of Design Drilling fluid contamination – H2S Pounds Zinc Oxide Required to Remove H2S 6 Calculation Method: Conversion Factor to remove H2S with Zinc Oxide =0.000836 H2S amount X 0.00836 X 1.5 = Lbs per Bbl Zinc Oxide Required to remove H2S

5

*Due to dangers associated with H2S, the treatment level to remove H 2S is increased 1.5 times the calculated amount as a minimum to ensure excess for total removal.

4

e d i x O c n3 i Z l b B r e2 p s b L

1

0 0

500

1000

1500

2000 mg/l H2S

2500

Lbs ZnO required to remove

3000

3500

4000

Solids Control The Key to Improved Drilling Performance (Page 107-142)

Solids Classification•

see page 110 for details

1) Solids are classed according to their density: Low or High 2) Particles are also classed according to size API definition • Clay < 2 m • Silt 2 - 74 m • Barite spec. 97% < 74 m • Sand 74 - 1000 m

Solids less than 1 m are 12 times more detrimental to drilling rates than those greater than 1 m 3) Solids can also be classed according to t heir chemical reactivity: Reactive or Inert

Generally Speaking, solids are like actors in a movie: “The Good” – Commercial Solids – Solids added to give specific effects e.g. bentonit e, polymers, weighting agents, LCM plus several more. “The Bad” – Sand Size Solids – Drilled Solids produce negative effects & the easiest to remove. “The Ugly” – Colloidal Size Solids – The greatest challenge.

Size does matter 

Assume that a 1 ” square DRILL SOLID is allowed to be re-circulated.



Surface area = ?? sq. in.



There are 6 faces exposed to the fluid.

1 inch

SOON YOU WILL HAVE THIS IF NOTHING IS DONE!



Every time a solid is re-circulated, it will get smaller and smaller and smaller!

Solids Control THE SINGLE MOST IMPORTANT DRILLING FLUID ISSUE AFTER DESIGN, IS SOLIDS CONTROL !! •

•

The efficiency of solids control equipment at removing unwanted solids is at best ~75% This means 25% of solids are re-circulated and ground down •Reduced •ROP

•Excess •Wear to the •Pumps

•Excess •Drag & •Torque

•Downhole •Tool Failure

•Increased •Viscosity

•Excess •abrasion

•Stuck Pipe

•Rig •Downtime

Solids Control OPTIONS FOR CONTROLLING SOLIDS •

•

•

•

Dump and Dilute. Effective but very expensive. Usually a part of a solids control plan.

High efficiency solids control equipment. Remove LGS without excessive loss of HGS Inhibitive Drilling Fluid. Reduces dispersion of solids and improves efficiency of solids control equipment. Efficient solids control reduces costs  Lower dilution rates  Less mud treatment Rule of Thumb: Every one (1) barrel of solids removed by mechanical means saves twenty (20) barrels of dilution / displacement fluid to maintain 5% Low Gravity Solids.

How To Evaluate Solids Content Of Mud?

MUD PROPERTIES

•

• It requires proper mud analysis at location and calculation of the different solids components.

•The best way is to rely on experience, refer to prepared rule of thumb graphs or require a competent mud engineer with computer software to produce the numbers.

• A solids analysis for the mud in use is reported on the Daily Mud Report.

Sample Source Time Flow Line Temp. Depth Mud Weight Mud Gradient Funnel Viscosity 600 RPM 300 RPM 200 RPM 100 RPM 6 RPM 3 RPM Rheology Temp. PV YP LSYP Gel Strength(10s) Gel Strength(10m) API Fluid Loss HTHP Filtrate Cake API/HTHP Sand Content Retort Oil Retort Water Retort Solids Alkalinity Mud (Pom) Excess Lime Emulsion Stability Oil Water Ratio Cl-

F ft lb/ft3 psi/ft sec/Qrt

5,430.00

83.00 0.58 73 99 61 47 30 10 8 120 38 23 6 11 17

F cP lb/100ft2 lb/100ft2 lb/100ft2 lb/100ft2 ml/30min ml/30min 1/32nd in Vol %

2 1 52 23 25 4 6 950 69/31 310 k

ppb V mg/l

BIT HYDRAULICS

Flow Line 1:58 160

SOLIDS ANALYSIS

Vol % 3.63 % wt 36.2 mg/l 488,763 0.3771 / 4.6 Av.sp.Gr.Solids 2.62 0.6982 / 0.8 Corrected Solid Vol % 21.37 hp/in2 0.97 Avg. Sp. Gr. of Salt W 1.35 BIT PRESSURE LOSS psi 267.2 LGS Vol % 1.72 NOZZELS VELOCITY ft/sec 173.4 LGS ppb 15.34 ECD @ Bit lb/ft3 83.93 HGS Vol % 19.66 ECD @ Casing Shoe lb/ft3 83.75 HGS ppb 189.46

AV / DP AV / DC AV / RISER na / ka np / kp BIT HHSI

ft/min 134.98 CaCl2 ft/min 200.01 CaCl2 ft/min CaCl2

How To Evaluate Solids Content Of Mud? Solids Content Definitions •

•

•

•

Retort Solids – Represents the total solids in the mud as read directly from the retort tube and includes soluble solids (salt). Corrected Solids – Represents the total solids in the mud MINUS the soluble solids (salt). Low Gravity Solids (LGS) – Represents the corrected solids in the mud MINUS high gravity weight material. This value also includes low density weight material added such as calcium carbonate (CaCO3). Drill Solids – Represents the total solids in the mud MINUS soluble salt, any weight material and chemical additives.

Rule of Thumb: Low Gravity Solids = 5 – 8% for a barite mud. 3 – 4%

for a reservoir drill in fluid

How To Evaluate Solids Content Of Mud? Suggested Tools Recommended Solids Charts: •

•

Target Solids Percent for Muds that Don't Contain Barite- page 112 Mud Weight versus Total Solids % for OBM with No Drill Soldis-CaCO3 as a weighting material- page 113

•

Density of Water & Diesel Emulsion with 3% LGS- page 114

•

Solids Content versus Mud Density (Barite & Hematite)- page 115

•

Recommend Trend Charts – page 116

•

A simple tool to check on DIH and find similar muds to see how mud solids compares to other wells- page 117

Solids Control Equipment Function

Reduce overall well costs through the efficient removal of drilled solids while reducing and minimizing the loss of drill fluids. Strategy The design objective of any SCE is removal of progressively finer drilled solids. Types •Shale Shakers (vibrating screens) •Settling Pits (sand traps) •Large hydrocyclones >8 in diam. (desanders) •Smaller hydrocyclones <6 in diam. (desilters) •Mud cleaners (desilters with fine screens underneath) •Centrifuges

Solids Control Equipment When to run SCE and what equipment to run? (pg 119)

Shakers: ALL SHAKERS ALL THE TIME. There is no such thing as a spare shaker. Screen Coverage by the mud pool at 75 – 80% Hydrocyclones: Spud mud only, any other time is throwing away good drilling fluid and grinding solids Mud Cleaners: their only value is another shaker screen , do not use the hydrocyclones

Centrifuges: when in use, run almost continuously (even after achieving the target mud properties – pg 134)

Shale Shakers • • • •

•

•

Most important solids removal equipment on rig. Cheapest way to remove drill solids. Only equipment that actually removes solids by particle size. Process entire circulating volume Screen Selection is a Compromise Between:  Amount of solids to be removed  Circulation rate  Screen life expectancy

Flowrate across a shaker is dependant on:  Cuttings loading of the mud (ROP)  Mud temperature  Shaker design  Mesh type and size

Shale Shakers- Best Practices •

The most common error in running shakers is not running a full pool of mud on the screens. The pool of mud should cover at least 75% of the total screen area.

•

Best practices must be tailored to specific conditions

•

Minor mud losses over the screen are acceptable and often beneficial.

•

•

•

Have your shakers checked by a vendor representative on a regular basis. Shale shakers should be inspected regularly:  Screen wear  Flow handling  Cuttings transport Increase in flowline mud weight can be due to:  Worn screens  Incorrectly fitted screens

Sandtraps •

Sand traps are essentially settlement tanks.

•

Normally located directly beneath the shale shakers.

•

Should be fitted with baffles to increase flowpath.

•

Usually a minimum of 2 tanks.

•

With WBM, good practice is to dump the contents when performing whole mud dilutions or on trips.

Centrifuges Modes of operation 

Reduce Mud Weight - (1 or 2 Centrifuges - discharge barite) 



Total Solids Removal Mode – (1 or 2 Centrifuges – Reduce drill solids and viscosity/PV)  



High feed/low speed to maximise mud weight reduction

Total solids removal (as much as possible) Low feed/high speed to remove all solids

Dual Stage Mode ( 2 Centrifuges – Reclaim barite and base fluid / discharge drill solids)  



Centrifuges work in tandem 1st centrifuge run as high feed/low speed to separate coarse barite which is returned to the active system. Liquid discharges to a holding tank. 2nd centrifuge fed from holding tank. Run as low feed/high speed to separate fine solids which are discharged. Liquid returns to active system.

Note: Centrifuges do not process the entire circulating volume – (10-15% of total)

Without a Centrifuge and Using Typical SCE, Finer Solids are left in the system

20 x 4” Desilter

3 x 10” Desander

e g a % l a c i p y T

Mudcleaner(s)

Solids remaining in the mud system •150 Mesh

3ea. Linear Motion shale shakers

12•300 •44 3074 • 44 • 74150 • 105 250• 150 • 400•900600900 •0• •5•08 •512•8 20 105 400• 250 600 Particles Remaining in the Mud (microns)

Optimum Solids Removal is Achieved by use of Multiple Current Generation Shakers and Centrifuges •Dual RT 362 HeviJet •centrifuge

e g a % l a c i p y T

•Triple VSM 300 •Balanced Elliptical •Shale Shakers •Removing this amount •200 mesh • of additional solids •from the current system

0 5 8 12 20 30 44

74 105 150

250

400

600

900

Particles Remaining in the Mud (microns)

RECOMMENDATIONS

 Mud Cleaners were introduced in the 1980 ’s to remove finer solids  Technology has moved forward and shaker performance has improved to such a level that Mud cleaners are not normally used  The only equipment that will removed fine & Ultra fine solids from the mud after being processed by the shakers is a High Speed Centrifuge  The Optimum System consists of:

• An adequate number of shakers to handle the full circulating volume • High efficiency centrifuges to control fine solids and to facilitate barite recovery

• A typical may include hydrocyclones. These must ONLY be used when absolutely necessary

Drilling Fluids Awareness Workshop Basis of Design Health/Safety and Environment H2S Awareness Concentration %

Concentration ppm

Effect

0.001

10

Can smell, "safe" for up to 8 hours

0.01

100

Kills sense of smell in 3-15 minutes; may burn eyes and throat

0.02

200

Kills sense of smell quickly; stings eyes and throat

0.05

500

Loss of balance; respiratory difficulty in 30-45 minutes, leading to pulmonary edema

0.07

700

Unconscious in less than 15 minutes; immediate artificial respiration needed, otherwise death will occur

0.1

1000

Permanent brain damage inflicted in single breath; If not rescued, death will occur quic kly

Drilling Fluids Awareness Workshop Basis of Design Health/Safety and Environment Material Safety Data Sheet Information Identification of the substance/preparation and the company Composition/information on ingredients Hazards Identification First Aid Measures Fire fighting measures Accidental release measures Handling and storage Exposure controls and personal protection Physical and chemical properties Stability and reactivity Toxicological information Ecological information Disposal consideration Transport information Regulatory information

Drilling Fluids Awareness Workshop Basis of Design Health/Safety and Environment Material Safety Data Sheet Information

Drilling Fluids Awareness Workshop Basis of Design Health/Safety and Environment Chemical Hazard Bulletins

Drilling Fluids Awareness Workshop Basis of Design Health/Safety and Environment

Drilling Fluids Awareness Workshop Basis of Design ENVIRONMENTAL GUIDELINES ENVIRONMENTAL STANDARDS, PROCEDURES AND GI’s RELATED TO DRILLING AND WORKOVER FLUIDS ACTIVITIES Description

G.I. or SAES or D &

Web Sites

WOSD Procedures

Government Environmental Standards

Document No. 1409-0

http://epd.aramco.com.sa/epd/epd.home.do

Corporate Environmental Protection Policy

INT-5


Corporate Environmental Protection Policy Implementation

GI- .2.714


EPA Procedures

SAEP - 32


Land Use Permit Procedures

GI. – 2.716


Waste Management – This doc provides direction and

GI- 430.001

Borrow Pit Requirements

SAES – A- 111

http://epd.aramco.com.sa/epd/epd.home.do Company Standards  Environmental Protection  Waste Management  http://epd.aramco.com.sa/epd/epd.home.do

Solid Waste Landfill Standard

SAES-S-007


Ambient Air Quality & Source Emission Standard

SAES – A-102


Processing and Handling of Hazardous Material

CU 22.01


Handling Bulk/Non-Bulk Chemicals

CU 22.05

Discharge to the Marine Environment

SAES-A-103

guidance to Company organizations on the proper handling and disposal of wastes.

Discharges o

from Drilling Operations Guidelines on the discharges of OBM, alternative OBM and water base drilling fluids and cuttings.


Clause 4.5,



Sub-Clauses 4.5.1,



4.5.2, 4.5.3, 4.5.4,



Company Standards Wastewater & Marine Protection Discharges to the Marine Environment

4.5.5. Offshore Oil Spill Contingency Plan

G.I. 2-400


Leak and Spill Reporting-Arabian Gulf

G.I. 2.104

Wastewater Treatment, Reuse and Disposal

SAES-A-104

Company STandards Wastewater & Marine Protection http://epd.aramco.com.sa/epd/epd.home.do

Onshore Wellsite Environmental Management Operations

D&WOSD

http://eccweb.enp.aramco.com.sa/drilling/NewDIH/DWOSD_web/WebPage/DwosdPro.

Procedure

Environmental

html

 

This

doc provides guidelines for handling /disposal of drilling wastes including spent drilling fluids, cutting solids –sands, clays, limestone, mud sludge, drilling supply water and flare pit material, associated with onshore D&WO activities. Inland Oil Spill Contingency Plan

Procedure June 2006.

G.I.2.401


Ionizing Radiation Protection

G.I. 150.003

http://epd/epd/epd/contentAction.do?name=COMPANYSTANDARD

Fishing For Radioactive Tools

Chapter 5 Section C

Drilling Manual

Abandonment Guidelines For Radioactive Tools

Chapter 2 Section G

Drilling Manual

Sub-section 3.0 Radiation Protection Requirements for Downhole Well Logging Incidents

Draft

Drilling Fluids Awareness Workshop Basis of Design Knowledge Management

Drilling Fluids Awareness Workshop Basis of Design Knowledge Management MUD PHASE REPORT Well : Depth MD

Rig : TVD

Deviation

Phase : Drilled feet

12 1/4"

Volume drilled

Phase duration

From

To

11386 ft

7879 ft

62.00

5281

770 bbl

10 days

29-Jun-07

9-Jul-07

Last CSG Dia.:

13 3/8"

Shoe :

6072 ft

Current CSG Dia.:

9 5/8"

Shoe :

11373 ft

End phase status: FLUID TYPE Depth Pit temp. Flo-line temp.

Check Temp Mud weight Solids Oil Water O/W ratio Sand out Sand in Marsh Visc. Fann 600 rpm Fann 300 rpm Fann 200 rpm Fann 100 rpm Fann 6 rpm Fann 3 rpm Gel 0 Gel 10 min. Gel 30 min. App. Visc. Plastic Visc. Yield value n. K Filtrate API HP/HT Filtrate PPA Spurt pH Pm Pf Mf -

Cl

++

Ca Mg++ MBT Excess sulfide H2S Conqor 404 Hach Hole Angle Oil SG K+ NaCl KCl CaCl2 LGS HGS Solids (corr.)

ft °F °F

Completion 30-Jun-07 6105 100 n/a

3-Jul-07 9286 130 142

5-Jul-07 11386 125 138

Abandonment

6-Jul-07 11386 110

7-Jul-07 11386 110

°F

9.4 8

92

9.4 8 1 91

65

62

65

65

68 52 44 34 14 11 12 16 18

77 63 56 46 18 16 17 21 23

75 61 54 44 17 15 18 20 22

75 61 54 44 17 14 16 19 21

37.5 19

34.0 16

38.5 14

37.5 14

37.5 14

37 0.42 4.05

36 0.39 4.66

49 0.29 10.37

47 0.30 9.52

47 0.30 9.52

4.8

5.8

6.1

6.6

6.6

10.2 2.2 0.5 1.7

10.1 2.8 0.4 2

10.1 2.5 0.5 1.6

10.2 3.8 0.7 2.5

10.2 3.6 0.7 2.5

mg/l

23000

2 3000

2400 0

25000

250 00

mg/l

600

720

640

400

400

mg/l

200 7.5 50 n/a

291 5 150 n/a

48 5 150 n/a

121.5 5 150 n/a

121.5 5 150 n/a

1500 n/a 58

1200 n/a 60

2000 n/a 58

1800 n/a 58

1800 n/a 58

1.1

1.1

1.1

1.1

1.1

4.3 0.3 7.0

6.7 1.0 5.9

6.5 0.4 6.9

5.9 0.9 6.8

6.5 0.3 6.8

lb/gal %

9.2 6

9.4 8

94

9.25 8 1 91

75 75 56 47 35 11 9 11 13 15

% %

92

% % s/qt

lb/100ft² lb/100ft² lb/100ft² cP cP lb/100ft² lb·s^n/100ft² cc 500 psi - 230° F (35µ) Total Vol.

ppb mg/l mg/l deg

% % %

Suspension

Solids treatment Shaker screens : 170 x Shaker screens : 200 x Shaker screens : 170 x Shaker screens: 200 x Mud cleaner n/a

4 4 4 4

Drilling: Tripping: Logging: Casing: Rig Up/Service: Condition Hole:

Drilling data 3.13 day 1.92 day 0.08 day 0.75 day

Desander : Desilter : Centrifuge 01 : Centrifuge 02 : LOT@ last csg shoe: Max. temp. at TD : Initial hole vol.: Initial tank vol.: Received vol.: Made up vol.:

hrs. 71 hrs. 83 hrs. Reaming: 83 hrs. Condition Mud: 0.58 day 13 EMW 180 °F D il ut io n Fa ct or : 1 b bl s/ bb l of f or ma ti on bbls bbls Formation bbls Dumped Sweeps 2 10 b bl s 1 01 2 b bl s Dumped 3 60 3 b bl s 5 90 7 b bl s Trip Loss 1 28 b bl s SCE: 1 43 3 b bl s Cuttings Retention 2 72 b bl s Abandon bbls bbls Left in Hole Tot handled vol.: 6919 bbls Total lost vol.: 5646 bbls Transferred volume (out of rig): n/a bbls Reusable volume (well+tanks): 1276 bbls Cost and consumption Currency: US$ Products Amount Unit Price Total Cost ppb 41 1. MT $20.00 $5,432.50 13.06 Barite 2 1. MT $20.00 $270.40 0.64 Bentonite Gel 45 100. LB $20.00 $517.50 0.65 Bentonite Wyoming 162 25. KG $20.00 $3,418.20 1.29 Caustic Soda 5 25. LT $20.00 $353.00 0.04 Defoam 48 25. LT $20.00 $3,189.60 0.42 Biocide 210 25. KG $20.00 $14,836.50 1.67 Pac UL Polysal 472 25. KG $20.00 $11,092.00 3.76 Soda Ash

2 259

25. KG 25. KG

$20.00 $20.00

$85.80 $3,651.90

0.02 2.06

Sodium Bicarbonate XCD

40 190

25. KG 25. KG

$20.00 $20.00

$496.00 $37,297.00

0.32 1.51

SAPP

Vsalt %salt wt. SG INTERVAL OVERVIEW The mud system, used for this section was a Seawater bassed, PHB, polymer system. 1012bbls of mud was carried over from xxx-1, and reconditioned for use in this section. New mud was also built at program specs, and once initial displacement begain, mud warmed and sheared through the bit, then the tweaking of mud properties was addressed. Initialy shakers were dressed with 110mesh, and 140 mesh Total Product Cost: $148,715.85 screens, then later swaped to 170's and 200's which handled the flow rather well. No FIT was conducted UNIT COSTS Per bbl mud Per ft drilled Per bbl drilled due to hard cement, so drilling ahead comensed.Highler then normal Calcium levels were noted from the US$ 21.49 28.16 193.10 begining and constant increaesd concnetrations of Soda Ash was needed to control this. Caustic was used for alkalinityand maintaining the PH at 10-10.2 was achieved through contiunous additions of caustic Soda. 70bbl Seawater Sweeps were pumped every 200ft drilled, and brought up between 200-300% increase in cuttings for upwards of 2 minutes at a time. ROP increased substantialy while drilling through the Arab formations, with averagess of 200-300ft hr. 2469ft was drilled in 24 hrs, which was a success, however maintainining PH, and Ca levelels while drilling anhydrite was a challange, and maintaining Mud weight at 9.2ppg, difficult. Constant dillution rates of 40-70bbl/hr of premix was needed and periodic dumping of sandtraps, for volume and weight control, needed. The centrifuges were run non-stop while drilling this section, with a flow rate of 70gal/min, and 3200RPM bowl speed. They worked well, cutting the mud weight from 9.3ppg, to 8.9ppg, with a discarded weight of 15.6ppg, on average. The corrosion program was followed with the istalation of 1 corrosion ring in the drill string, and regular mud maitnence of Conqor 404, and Os1-L. High torque was expereinced early on so initialy 1% volume of starglide was added to the mud, then increased to 2 % once drilling into the ARL formation. Proved to ease torque, and maintain ROP. MBT was brought down to 5lb/bbl, and XCD used as the main source for Rheology control, with average 6RPM reading kept between 17-18. Drilled to 11297ft, and expereinced tight hole. Worked pipe and jarred free, increased starglide concentration, and also increased mud weight to 9.4ppg, and weight kept at 9.4ppg to TD. ROP slowed down to 10-15ft/hr and the desion was made at 11386ft, to establish TD, casing point. Circulated BU, pumping 2.0lb/bbl SAPP sweep at td, and circulated out. Wiper trip to shoe, then back to bottom were 3 x BU was pumped along with 2 60bbl Seawater sweeps then POOH for running 9 5/8'' liner. Liner was run succssessfully, no fill on bottom and cemented at 11373ft , with TOL set at 5565ft. Cement job was succssessfull, with excess cement Dumped at surface.

Reminder Include:Comments, Solids Control, Problems, Reccomendations, and Lessons Learned

Mud contractor :

Made on:

9-Jul-07

By:




END OF PART I

DLG_Fluids_WS_(Presentation).pdf

Recommend Documents