Drilling Fluid Programme for Petromine

DRILLING FLUID PROGRAMME FOR :

WELL TYPE: EXPLORATORY/DEVELOPMENT

Well Name: Offset Wells:

ONGC - X

Date:

Prepared By: Reviewed by: Approved by:

M Manickam

B K Naik

15 June 2010

Index Drilling Fluid Programme : John Energy/ONGC

Well No:

MUD PROGRAMME: WELL NO-

Rig:

17 1/2” Hole: 0 M to 550 M -Spud Mud/Bentonite/CMC/CFLS 1.1 Interval Discussion 1.2 Recommended Fluid Properties 1.3 Operation & Procedures 1.4 Volume and Costs

8 1/2” Hole: 550 M to 1700 M-KCl/PHPA/CPG/POLYAMINE/POLYMER 2.1 Interval Discussion 2.2 Recommended Fluid Properties 2.3 Operation & Procedures 2.4 Volume and Costs

8 ½” Hole: 1700M to 3000M-NON DAMAGING DRILLING FLUID 3.1 Interval Discussion 3.2 Recommended Fluid Properties 3.3 Operation & Procedures 3.4 Volume and Costs

Drilling Fluid Programme : John Energy/ONGC

Well No:

Rig:

ONGC - X DRILLING FLUID PROGRAM SUMMARY Hole

Casing

Casing

Depth

Mud

size

Size

Program

(m)

System Bentonite Gel

17 1/2”

13 3/8”

0m

M Wt: ALAP F/Vis: 50-55sec/qt

550m

YP: 24-30 lb/100ft2 KCl-PHPA-CPG-Poly Amine-Polymer mud

12 1/4”

M Wt: 9-10ppg

9 5/8”

F/Vis: 50-55 sec/qt PV-ALAP YP: 25-30 lb/100ft2 F.Loss : <5ml 1700m

KCl: 33ppb, CPG-14ppb KCl-CPG-Poly AmineCaCO3 ND Mud

8 1/2”

M Wt: 9.5-10.5ppg

7’’ Liner

F/Vis: 50-55 sec/qt PV-ALAP YP: 25-30 lb/100ft2 Floss : <5ml KCl: 33ppb 3000m Drilling Fluid Programme : John Energy/ONGC

CPG: 14ppb Well No:

Rig:

17.5” Interval: 0m – 550 m for 13-3/8” casing INTERVAL DISCUSSION

SPUD MUD FROM 0 M TO 550M Fluid

A Bentonite mud has been programmed for this section. This system is a highly effective and economical fluid for drilling top hole especially in the areas where we are expecting lost circulation problems. This system has been used with success drilling similar wells nearby and it will be most suited for this particular section. Spud the well with 7% prehydrated gel, treat with CFLS TO disperse the mud as drilling continue and add CMC to control the fluid loss. Pump Hi Vis time to time prepared with Guar Gum, add DD for lubrication and avoid bit balling. Keep sufficient quantity of LCM as per plan.

Objectives

 Maintain a clean well-bore with adequate hole cleaning

Concerns

     

Solutions

Hole cleaning / overloading annulus / ECD /losses Losses while running casing Maintain 6 RPM in recommended range Control drilling rate to avoid overloading annulus. Follow a sweep program Adjust fluid properties to minimal rheology prior to cementing


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Key Products and Formulation

1.1 1.2

PRODUCT

FUNCTION

CONCENTRATION CHMICAL NAME

Caustic Soda

Control PH

0.25-0.50 ppb

Sodium hydroxide

Bentonite

Primary viscosifying agent

20.0 ppb

Hydrated Aluminium silicate

CMC

Fluid loss agent(if required)

2.0-3.0 ppb

Carboxy methyl cellulose

DD

Anti bit balling

0.2-0.3 ppb

Drilling detergent

CFLS

Dispersent(if required)

2-4 ppb

Chrome free lignosulphonate

As per wt requirement 1.5

Barium sulphate

Barite

1.3

Weighing material

1.4

Recommended Fluid Properties PROPERTY

PLAN

UNIT

REMARKS

Mud Weight

8.7-9.5

ppg

As hole condition dictate

Funnel Viscosity

50-55

SEC/Qt

To provide laminar flow and minimize chances of losses

PV YP.

ALAP 25-30

cp Ib/100 ft2

To be kept as lowest possible To be calculated for maximum hole cleaning

API Fluid Loss

NC

ml

No control

pH

9-9.5

PREPARATION: 

Fill the tanks with the required amount of drill water, check the total hardness and reduce it to below 150 mg/lt with additions of SODA ASH.



Raise the pH to 9.5 with addition of CAUSTIC SODA.



Mix 7% BENTONITE and allow to hydrate for as long as possible under maximum shear Conditions (at least 6 hours).


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Maintenance: 

As drilling progresses, the viscosity should be maintained with gel as required.



The mud weight and solids content should be maintained as low as possible with water dilution, dumping sand traps and utilizing all solid control equipment.



The primary objective on the section will be to ensure that the hole remains clean during all operations.



The high viscosity pills will help stabilize any exposed sands preventing hole washout and collapse.



Lime could also be added if extra viscosity is required.



The purpose of spud mud is to drill the surface hole section as cheap as possible. Mud volumes should be minimized to maintain treating cost as low as possible.



If hole is circulated for any reason then the bit should be continuously moved as not to washout the hole, which could result in poor cement jobs.



Control drilling rate and maximize annular velocity’s to avoid creating mud rings, pack offs and losses due to an overloaded annulus.



Run all solids control equipments including Desander and Desilter to discard the drill solids.



Dump sand traps as often as possible and employ the finest possible shaker screens.



Due to possible losses, constant observation of pit volumes will be very important and any change should be reported immediately.



If required CMC can be added while drilling down. Also CFLS can be added to disperse the mud and to assist in controlling the water loss and rheology.



Sand traps and header boxes should be inspected regularly and dumped as required during connections.



Mud rings and bit balling are expected to be encountered whilst drilling the surface hole in this area these problems can be minimized by pumping SAPP & DRILLING DETERGENT pills.



NUT PLUG / CAUSTIC pill to overcome the tendency of bit to ball up the BHA.

Hereby the followings options and formulation are commonly used in case of mud rings and bit balling.


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DRILLING DETERGENT PILL: Formulate a pill (± 50 bbl) of active fluid with 2 % DRILLING DETERGENT, spot the bit and allows soaking.

NUT PLUG / CAUSTIC PILL: Mix a 30 - 40 ppb NUT PLUG, 3 - 4 ppb CAUSTIC, 50 - 75 bbl pill and circulate through bit, pill size is dependent on bit balling severity as is product concentrations. No hard and fast rules can be set for this particular problem. CAUSTIC/SPERSENE PILL: If bit balling is suspected, build a 30 bbl caustic pill containing 4.0ppb caustic soda and 2ppb Spersene in fresh water. Spot on bottom and allow to soak for 10minutes.

Volume and Material Estimation VOLUME ESTIMATE

BBL

SURFACE VOLUME

600

CONDUCTOR VOLUME

591

OPEN HOLE VOLUME WITH 15% WASH OUT

1191

TOTAL VOLUME MAINTAINENCE VOLUME

1100 2291 0

TOTAL VOLUME REUIRED Old Mud Received

1191

Mud Remaining Dilution Factor

bbl/m


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Material Estimation PRODUCT

UNIT SIZE

Qty

BENTONITE CAUSTIC SODA SODA ASH BARITE CMC CFLS DD

50 Kg 50 Kg 50 Kg 50 Kg 25 Kg 25 Kg 200 Lt

280 10 6 100 40 40 3


Unit Cost

Well No:

Tot. Cost

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12.25” Interval: 550M – 1700M for 9-5/8” casing INTERVAL DISCUSSION

KCL/GLYCOL/POLYAMINE FROM 550 M to 1700M Fluid

Objectives

Concerns Solutions

The KCL/GLYCOL/POLYAMINE system is an extremely successful filed proven water base mud. the system has been used under severe conditions and it exhibiting stable properties not only while drilling , but also during prolonged static conditions experienced during tripping ,logging , and testing operations , in additions , this system minimizes hole problems , providing excellent shale inhibition as well as resistance contamination . This mud system is considered as the environmental friendly substitute to OBM.  Maintain a clean well-bore with adequate hole cleaning  Provide shale inhibition and maintain well-bore stability to ensure the use of minimum mud weights.  Hole cleaning / overloading annulus / ECD /losses  Losses while running casing  Maintain 6 RPM in recommended range  Control drilling rate to avoid overloading annulus  Maintain thin, tough filter cake  Adjust fluid properties to minimal rheology prior to cementing


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Key Products and Formulation PRODUCT

FUNCTION


Barite

Weighing Material

As per requirement

Barium Sulphate

Soda Ash

Alkanity and Hardness control

0.25-0.5 ppb

Sodium Carbonate

XC-Polymer

Primary Viscosifying agent

0.5-1.0 ppb

PAC-UL

Fluid loss control

3.0-4.0 ppb

PAC_R

Viscosifier and FL reducer

1-2 ppb

Poly anionic cellulose

1.11 Encapsulation of cuttings

1.0 ppb

Glycol

1.8 1.9

1.12 Primary Shale Inhibitor 1.13

14ppb

Poly anionic cellulose Partially Hydrolyzed Polyacrylamide Poly alkaline glycol

Poly amine

1.10

Additional Shale inhibitor

3.5PPB-12PPB

Polyamine

KCL

Secondary Inhibitor

33ppb

Potassium chloride

CaC03

Bridging agent

5-15 ppb

Calcium carbonate

Soltex

Shale stabilizer

5 ppb

Sulphonated asphalt

1.6

PHPA 1.7

Clarified Xanthan gum 1.14


PLAN

UNIT

REMARKS

Mud Weight

9-10.0

ppg


Funnel Viscosity

50-55

SEC/Qt


PV

ALAP

cp

To be kept as lowest possible

YP.

25-30

Ib/100 ft2

To be calculated for maximum hole cleaning

API Fluid Loss

<5

cc

To be minimized as per the hole condition

KCL

33

Ppb

As hole dictates

CP Glycol Polyamine

14

Ppb

Inhibitor

12

ppb

Inhibitor

pH

8.5-9.0


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PREPARATION: 1

Clean thoroughly mud pit with water.

2

Take water in the pit + add soda ash + mix caustic soda to adjust pH to 8.0- 8.5+KCL. Determine calcium ppm and neutralize by adding calculated quantity of sodium-bicarbonate(ca++ ppm * 0.00074 = ppb sodium-bicarbonate) / soda ash (ca++ ppm * 0.00093=ppb soda ash)

3

Treat with 4.0 ppb of PAC-LV, 1.0ppb PAC R, Mix thoroughly.

4

Treat with 1 ppb XC-POLYMER at slow mixing rate.

5

Load CaCO3 and mix barite up to desired weight.

6

Agitate for 6-8 hours.

7

After mixing all the chemicals the mud becomes highly viscous, but the viscosity will come down by thorough intermixing within the tanks.

8

Glycol (14ppb), Polyamine (12ppb) and PHPA (0.75-1ppb) may be added after change over during first circulation. Make sure that, pH is less than 9.5 and Ca++ in the mud is below 200ppm, before addition of the PHPA.

Method of Mixing of PHPA Ensure that the pit is thoroughly clean and that the mix line from the Slug Pit to the Premix Tank has been has been flushed thoroughly with fresh water. Place fresh water in the slug pit to maximum. Have standing by the hopper calculated bags of PHPA to treat the whole system of 1ppb and two competent roustabouts. Start transferring water from the slug pit to the Premix Tank (and continue to fill slug pit from water line). As soon the water transfer starts, add PHPA as rapidly as possible into the hopper while the water is being transferred to the Premix Tank. When all the sacks of PHPA are added close the hopper valve. Fill Premix Tank from the Slug Pit if you need volume. Continue to circulate the pre-solubilised PHPA through the mix line. You can prepare concentration of approximately 10.0 ppb (28.5 kg/m3) by this method. This method of mixing PHPA is known as “slam dunk” and is the most efficient and effective way of mixing powdered PHPA. Then Pre-solubilised PHPA can be bleed to the active system in one or two cycles. Care should be taken, that after every use of mixing or shearing device, lines should be flushed with clean water to avoid chocking of the hopper suction lines and hopper jets.


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CHANGE OVER 

Sufficient quantity (csg + hole volume + sand trap+100 bbls) of mud must be ready before change over.



After drilling, 13 3/8” casing shoe sweep hole thoroughly with 50-60 bbl of viscous pill.



Ensure cleaning of all the channels, sand traps thoroughly to avoid cement contamination of polymer mud.



Then a cushion 30 bbl of water plus 1sx soda ash, followed by gel of 50 meter of annulus volume is to be chased by KCL-POLYMER mud. This will ensure minimum calcium contamination.



On surfacing of gel, discard gel. Circulation of mud through bit nozzles helps shearing of all the polymers.



Add Glycol 14ppb V/V in one circulation.



Add 12ppb Polyamine slowly in staged to avoid the flocculation.



Add 0.75-1.0 ppb PHPA after confirmation of pH is less than 9.5 and Ca++ below 200ppm.



Do the pilot test with this formulation, before mixing in the tank.

. KCL/GLYCOL INHIBITION MECHANISM

How Does it wok ?

By plugging shale pores, Glycol a barrier against water migration thereby reducing well bore instability caused by fluid influx


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Inhibition Mechanisms • Primary Mechanism • Water displaced by interaction of polyglycol with potassium ions at clay surfaces. polyglycol complex formed.

• Secondary Mechanisms • Glycol- glycol interactions with some species.

KCL/GLYCOL/POLYAMINE SYSTEM DISCUSSION. Glycol Mud was chosen as one of the preferred possible candidate in this section for the following reason:


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Benefits • In gauge well bores • Lower fluid losses & leak off values. • Lower potential for differential sticking. • Less torque, drag and bit balling problems. • Lower dilution rates. • Slicker, firmer filter cake. • Greater well bore stability. • Allows full use of PDC bits • Provides excellent lubricity characteristics Applications • Reactive shale sequences where a highly inhibitive drilling fluid is required • High-angle or extended-reach wells where well bore stability and lubricities are key factors • Replacement for oil-based muds in environmentally sensitive areas • Cost-effective alternative to pseudo oil-based muds

Polyamines Polyamines are also added with glycol for additional inhibition. Liquid polyamine shale inhibitor is

normaly used in drilling and drilling fluids. Shale inhibition is achieved

by preventing water uptake by clays, and by providing superior cuttings integrity. Polyamines effectively inhibits shale or clays from hydrating and minimizes the potential for bit balling. Benefits: 

Highly inhibitive across a wide range of shale types



Significant reduction in clay dispersion and hydration compared to existing state-of–theart inhibitive systems



Lower risk of accretion and cuttings agglomeration related problems



Environmentally acceptable



Highly flexible in formulation – easily controllable filtration and rheology profiles, and usable with various base brines



Highly solids tolerant


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Fig-1. Shows the accretion characteristic of Polyamine system.

.

Fig-1

So glycol added with polyamine will enhance the accretion suppressant action preventing any buildup of drill solids below the bit, allowing the cutters good contact with new formation for improved rate-of penetration. The component also lowers torque and drag by reducing the coefficient of friction.

Fig-2 Shows the graph of inhibition test with the base fluid.

bentonite

Fig 3 and 4 Shows unconfined shale fracture test of the systems with base fluid.

Fig-2

Fig-3


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Fig-4

KCL/GLYCOL/POLYAMINE SYSTEM DISCUSSION The KCL/GLYCOL/POLYAMINE System is inhibitive water based drilling fluid designed to meet difficult drilling targets with minimal environmental impact. It achieves its unique inhibition through the synergistic action of a polyglycol and the provided Potassium ions, which contribute to cuttings and borehole stability through Cation exchange to provide a more stable non-swelling type of clay.

The KCL/GLYCOL mud system exhibit higher degree of inhibition due to the presence of Glycol Which have an ability to stabilize the swelling clays by preventing and minimizing water absorption to the clays platelet. The GLYCOL is compatible and remains effective over a very wide range of salinities and temperatures. It provides the secondary benefit of improvements in lubricity and filtration characteristics. It also displays extremely low environmental impact. No incompatibilities with other mud additives or contaminants have been found or are predicted.

Wellbore Stability The KCL/Glycol /POLYAMINE system provides outstanding wellbore stability to minimize stuck pipe tendencies and reduce valuable and costly reaming time. The combination of salt, cation, polymer Glycol and polyamine, highly inhibitive fluids to be formulated which minimize the hydration and dispersion of clay minerals. This prevents many common drilling problems such as mud rings, tight hole caused by swelling clays and chemically induced caving or hole washouts. Thus, watersensitive formations can be drilled with a high degree of confidence. The inhibitive nature of the fluid also ensures that cuttings are not dispersed in the annulus. This translates directly to better solids control efficiency and low dilution and maintenance costs.


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Lubricity The KCL/Glycol system has excellent lubricity characteristics, leading to low torque and drag during drilling operations. Figure shows that 3% glycol stabilizer produces a greater torque reduction than KCL Polymer.

. Thesystemhasexcellent lubricityandfiltrationcontrol properties,andisthermally stableandnon-damagingto sensitivereservoirs.Themajor component,Glycolshale stabilizer,is completelybiodegradable.

Reservoir protection The KCL/Glycol/Polyamine system minimizes formation damage in the crucial reservoir section. The system prevents swelling and dispersion of formation clays and has low static and dynamic fluid loss for reduced solids and filtrate invasion. The filter cake is easily removed by conventional acid treatments. The Glycol shale inhibitor remains soluble even at down hole temperatures and, therefore, does not "cloud out" to produce a damaging micro emulsion. The filtrate from the CPG system gave 86% return permeability.

GLYCOL Shale Stabilizer Glycol Shale Stabilizer is the major ingredient of this System, added at typically 3 to 6% by volume of mud. It is a polyalkylene glycol used to stabilize hydratable and dispersible shales and to improve fluid loss and lubricity. The product is completely water soluble so that high concentrations of organic material are not expected to accumulate with the cuttings on the sea floor (as occurs with oil based and synthetic based fluids). It does not contain oil and demonstrates very low aquatic toxicity. The product is also completely biodegradable and will not bioaccumulate.


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RHEOLOGY Any premium grade Xanthan gum is recommended to provide shear-thinning viscosity for the Glycol system. It provides minimal plastic viscosity and a shear thinning Rheological profile with high LSRV’s for optimum cuttings transport and suspension. The 6-RPM and 3 RPM specifications are dependent on the hole size, the well geometry and the effective annular velocity. FLUID LOSS CONTROL

Maintain Fluid Loss control by treatment with PAC material. However, all conventional fluid loss polymers can be used with the Glycol system. Treatment concentrations are dependent on the fluid loss specification. Note that the freshly prepared solids-free fluid will exhibit relatively high fluid loss values, until drill solids have been incorporated. KCL CONCENTRATION

Maintain KCL concentration within the recommended range with additions of brine concentrate or the direct addition of powdered KCL. Monitor and record the “in and out” potassium concentrations on a regular basis while drilling to determine depletion rate and treatment requirements. Increase the KCL concentration as per hole condition dictate. BACTERIAL DEGRADATION

The KCL/Glycol system uses conventional polymers (biopolymers, poly-anionic cellulose polymers, and starches) to maintain fluid properties. The use of a bactericide is recommended to prevent bacterial degradation of the polymers. SOLID CONTROL

The inhibition of the glycol system contributes to optimum performance from the solids control equipment. Solids removal is enhanced as a consequence of the large inhibited cuttings that are generated with the Glycol system, and the shear-thinning nature of the Xanthan-base polymer system. Use all available Solids Control Equipment as efficiently as possible to minimize undesirable mud weight increase from drilled solids accumulation and to reduce dilution requirements. Use the finest shaker screens, which can handle the circulation mud on shale shakers. Run other solids control equipment’s as and when required.


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Maintenance: 1. The appearance of cuttings at the shale shakers should be closely monitored to ensure there is Sufficient inhibition. The effects on other drilling parameters such as tight hole, torque, etc. should also be considered. Maintain constant inspection of cuttings integrity at the shaker. Glycol & KCL concentrations should be altered according to firmness and increased as hole condition dictate.

2. Selecting the proper fluid density is critical. The mud weight required for the system is based on the pore pressure and tectonic stress of the formation(s). Fluid density is a key element contributing to the effective borehole stability of the system and also is a critical requirement for effective inhibition performance. . This is particularly critical in high angle wells or in areas where tectonic stress is a key factor.

3. Any premium grade Xanthan Gum, is recommended to provide shear-thinning viscosity for the KCL/Glycol system. Minimum hydraulics is achieved through the low plastic viscosity and shearthinning rheology profile. Optimum cuttings transport and solids suspension is provided with the proper low-shear rheology values. The 6 RPM and 3 RPM specification depends on hole size, well geometry, the bottom hole assembly and drill-string design, and the annular velocity.

4. The prudent use of wiper trips is important to facilitate cuttings transport and to ensure the caliper of the well bore. This is especially important when using a stiff BHA. Monitor over-pull on trips for indications of inadequate hole cleaning or tight hole. If over-pull is a major problem, then consideration should also be given to a change in the BHA assembly.

5. Before pulling out of the hole it is critical to remove all the cuttings from the well bore. This is especially important because of the gauge well bore and larger cuttings typically obtained with glycol fluids. The circulation time can be determined based on hole cleaning algorithms, but the ultimate observation is at the shaker. If any over-pull is observed on a trip, then additional circulation time and/or wiper trips are recommended.

6. Calcium carbonate must be added at concentration 5-10 ppb to ensure a good external filter cake across the sand faces and provide good bridging for these sand which will reflect in minimizing down hole losses and formation damage.


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7. HOLE CLEANING – MUD RHEOLOGY. Proper rheology is extremely important. The system uses biopolymers to provide optimum low-shear-rate-viscosity (LSRV) for superior hole cleaning, wellbore stability and optimum hydraulics. The inhibitive, non-dispersed glycol/polyamine fluid maintains the integrity of the cuttings and the LSRV values are maintained higher than conventional polymer fluids to provide adequate hole cleaning performance. Elevated flat, fragile gel strengths are important to ensure suspension of solids. Proper rheology is even more critical in high angle wells to prevent the formation of cuttings beds and the degradation of the large, inhibited cuttings. The use of high density-viscous sweeps should only be used to ensure adequate hole cleaning; proper rheology is the key to efficient solids removal.

8. HOLE CLEANING - DRILLING PRACTICES. Controlled ROP, maximum circulation rates, maximum pipe rotation, and LSRV mud rheology – all of these factors are critical to ensure drill solids removal from the wellbore in vertical and especially in a high angle wellbore. This is critical because of the improved cuttings integrity.

9. WIPER TRIPS. This fluid will provide a gauge hole and, therefore, it is important to utilize wiper trips. The prudent use of wiper trips is important to facilitate cuttings transport and to ensure the caliper of the wellbore. This is especially important when using a stiff BHA. Monitor over-pull on trips for indications of inadequate hole cleaning or tight hole. If over-pull is a major problem, then consideration should also be given to a change in the BHA assembly.

10. SOLIDS CONTROL. Optimum solids removal and minimum system dilution are characteristic of the Glycol fluid. It is important to ensure that the solids removal system is properly designed and sized to ensure optimum performance. The key with regard to solids removal is the primary solids removal equipment – the shale shaker system. An adequate number of high performance shale shakers to process the required flow rates and to handle the required rheology is mandatory. . 11. While drilling this section attention should be paid to maintain the solids content within

programmed limits by; upgrading shakers screen size & installing the finer mesh, and dumping sand trap periodically beside running all the solids control equipment with its full efficiency continuously and diluting the system with fresh mud to reduce the effects of high concentration of low gravity solids. Shaker screens should be inspected regularly, and damaged screen has to be changed immediately to keep the solid content as lowest possible.


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BBL

SURFACE VOLUME

600

9 5/8 ” casing VOLUME

279

OPEN HOLE VOLUME WITH 10% WASH OUT

605 1484

TOTAL VOLUME MAINTAINENCE VOLUME

2300 3784 0


3784

New Mud Built Mud Remaining Dilution Factor

1484 bbl/m


UNIT SIZE

Qty

Baryte Soda ash XC-Polymer PAC_LV PAC_R PHPA GLYCOL SOLTEX BIOCIDE KOH EPLUBE POLYAMINE CaCO3 KCl

50 Kg 50 Kg 25 Kg 25 Kg 25 Kg 25 kg 200 Lt 25 KG 20 LTS 50 Kg 200 lt 200 lt 50Kg 50Kg

1200 19 79 316 79 79 131 343 17 30 4 103 515 1279


Unit Cost

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Tot. Cost

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8.5” Interval: 1700M – 3000M Non Damaging Fluids

Common Causes of Limited Producing Rate      

High oil viscosity Formation damage Wellbore design restrictions Low reservoir pressure Low reservoir permeability Inadequate or improper artificial lift

Some of the most common ways of damaging a formation include pay zone invasion and plugging by fine particles, formation clay swelling, commingling of incompatible fluids, movement of dislodged formation pore-filling particles, changes in reservoir rock wettability, and formation of emulsions or water blocks. Once one of these damage mechanisms diminishes the permeability of a reservoir, it is seldom possible to restore it to its original condition. Except when drilling underbalanced, the hydrostatic pressure in the wellbore is greater than the reservoir pressure. When the drill bit penetrates and crushes the permeable pay zone, the drilling fluid is forced to move into the rock pores, carrying with it the fine drilled solids and the suspended weighting materials, clays, polymers, lost circulation materials, cement particles, rust, pipe dope, or precipitates. Any of these contaminants can wreak havoc upon the productivity of oil and gas wells. Suspended particles larger than the formation pores are generally swept away in the mud stream and lifted out of the well; smaller-than-pore particles tend to invade the formation and can become trapped on the face of the wellbore, forming a permeable wall cake that allows fluids to filter through. This wall cake can allow fluids to continuously filter through as long as a deferential pressure is applied towards the formation. Simply, any subsurface permeable zones should be considered as effective depth filters for any wellbore fluids.


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Loss of large volumes of fluids to permeable producing formations (lost circulation) is one of the most common problems encountered when drilling or completing a well. Lost circulation can severely impair productivity and undermine profitability. Production can be seriously impeded if all the invading fluid is not produced back into the wellbore. Design criteria for non-damaging fluids.

Fundamentally, a non-damaging fluid is a clean fluid that causes little or no loss of the natural permeability of the pay zone targeted for development, while providing superior hole cleaning and easy clean-up. In addition to being safe and economical for the application, it must be compatible with the reservoir's native fluids, so as to avoid precipitation of salts or production of emulsions. A suitable non-damaging fluid should establish a filter cake on the face of the formation, but not penetrate too far into the formation pore pattern. This can be accomplished by the addition of sized particles of a durable bridging solid into the fluid system. Generally speaking, the median size of the bridging solids should be equal to at least one-third of the diameter of the mean porethroat diameter and the size distribution of the particles should be wide. Optimal particle size distribution and tight filtration control also help significantly reduce differential sticking forces while drilling. Another factor that should be considered when formulating a drill-in fluid is achieving a low filter cake lift-off pressure as the well is flowed in the production direction. The fluid filtrate should inhibit or prevent swelling of reactive clay particles within the pore throats. Important factors for optimum filtration control are low spurt loss, low total filtrate loss, and maintenance of a thin cake to avoid excessive erosion and to reduce the risk of stuck pipe.

Non-damaging KCl-Glycol-Polyamine Polymer Mud system As a general rule, monovalent and divalent salts should not be mixed together. However, monovalent salts and some two-salt combinations-for example, sodium chloride and potassium chloride, sodium chloride and sodium bromide, potassium bromide and potassium chloride, and sodium bromide and potassium bromide-may be blended as brine-salt solutions to densities of up to 13 pounds per gallon (ppg). Looking into all the above criteria, we are proposing a non damaging KCl-Glycol-Polyamine Polymer mud system to drill the 8.5” hole by using two salts KCl and NaCl, acid soluble polymers, filter cake, weighing materials etc.


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INTERVAL DISCUSSION

CLAY FREE MUD SYSTEM FROM 1700 M TO 3000M Fluid

The utilization of CLAY FREE SYSTEM to obtain minimum reservoir damage and to enhance the fluid capability to inhibit the drilled shale’s as well as providing an enhanced environment for mechanical and chemical bore stabilization and control formation characteristics for the entire section.

Objectives

 Maintain a clean well-bore with adequate hole cleaning  Provide shale inhibition by chemically and mechanically and maintain well-bore stability to ensure the use of minimum mud weights.  Hole cleaning / overloading annulus / ECD /losses  Losses while running casing/Formation damage  Maintain 6 RPM in recommended range  Control drilling rate to avoid overloading annulus  Maintain thin, tough filter cake  Maintain the bridging material to avoid formation damage

Concerns Solutions


Well No:

Rig:

Key Products and Formulation PRODUCT

FUNCTION


CaCO3

Bridging Material, Weighing

20-50ppb

XC-Polymer

Primary Viscosifying agent

1.0 ppb

Sized Calcium carbonate Clarified Xanthan gum 1.15

PG STARCH

Fluid loss control

7.0 ppb

Modified starch

PAC-LV

Fluid Loss Control

4ppb

Polyanionic Cellulose

Inhibitor

33 ppb

Potassium chloride

Weighing material

20-50 ppb

Sodium chloride

Inhibitor

14PPB

Glycol

Inhibitor

12ppb

Polyamine

KCL SODIUM CHLORIDE CP Glycol Polyamine


PLAN

UNIT

REMARKS

Mud Weight

9.5-10.5

ppg


Funnel Viscosity

50-55

SEC/Qt


PV YP.

ALAP 25-30

cp Ib/100 ft2

To be kept as lowest possible To be calculated for maximum hole cleaning

LSRV(6 RPM)

8-9

API Fluid Loss

<5

ml

To arrest formation invasion

KCL pH

33 9-9.5

ppb

For inhibition

For better hole cleaning


Well No:

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PREPARATION: All pits and flow lines should be thoroughly cleaned prior to mixing the CLAY-FREE system using base fluid. All dump valves should be checked and secured. The shale shaker system should be fitted with new screens keeping in mind that initial sizing should avoid excessive loss of polymer and carbonate which will occur from the fluid being cold and not fully sheared. 84 mesh is recommended. Add Defoamer if required and biocide before any other mud products. Always check the pH of brines before mixing other products. 1. Fill up desired drill water in the pit and then add salt in drill water. Check pH and reduce to between pH 7 and 8. 2. Add the PG Starch, through the hopper using maximum shear. 3. Add the XC Polymer at 10 minutes per sack or slower to avoid forming fish eyes. 4. Add KCl. 5. Add Cloud Point Glycol slowly 6. Add the CaCO3 fine as fast as possible to required weight. 7. Add Polyamine slowly to avoid the flocculation Note: Finally add the caustic Soda to adjust the pH to 9.5 or slightly higher if require. Normally Polyamine system does not require addition of caustic soda. The polymers will fully yield in the higher pH and after some temperature from shearing.

Mixing Products while drilling In order to maximize product yield and avoid sub-standard mud properties the following guidelines should be followed when adding products to the system: 

Adjust pH to the correct range before adding XC Polymer as low or high pH reduces yield, adjusting the pH after the addition of a polymer may result in a viscosity hump.



Always add viscosifiers to the system at 30 minutes per sack to avoid viscosity humps. Maintain the micronized CaCO3 concentration by continuous slow addition to the active while drilling rather than let it deplete, by removal on the solids control equipment.

CHANGE OVER The procedure is designed for displacing the casing from a water based mud used to drill the previous hole section. The previous mud system or water should be used to drill the cement and float equipment down to 2 meters above the shoe. General Consideration The aims of a successful displacement are to remove completely the previous drilling fluid prior to use of CLAYFREE, or the removal of CLAYFREE fluid and associated solids in the case of completion brine. To do this efficiently whilst maintaining the integrity of the CLAYFREE or brine, taking into consideration rig


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time and environmental impact. Displace conditioned WBM with the following pills in sequence using conventional circulation. Rig Site Execution Execution of displacement and clean up requires good preparation at the rig site. Review the planned procedure with the rig crew and adjust as necessary based on their recommendations. Floaters have special design considerations, simple pit logistics and maintaining the required pump rates are the most important factors to ensure the job is carried out successfully. Write a detailed plan with contingencies for contaminated returns; also indicate the most important aspects of the job such as pump rate etc. Get the mud loggers (If available) to record the displacement and to indicate when the pills return to surface. Make sure the sequence and timing of events is communicated during the job. Check spacer properties after mixing and before pumping. Check all valves and connections involved as well as pit condition prior to the job. Procedure sequence 1) 50 BBL dense, viscous pill built using water. Weighted with Barite to a 10% higher density than the mud to be displaced. Viscosified using XC Polymer so the 100 Fann RPM reading is 20% greater than the mud to be displaced. 2) 50 BBL caustic surfactant pill (3 lb/bbl caustic soda). 3) 50 BBL viscous pill (2.5 ppb of XC Polymer in water) pumped ahead of the CLAYFREE fluid. Do not stop pumping while displacing old mud to CLAYFREE. Flow rates should be high enough to ensure turbulence of the second pill and water pumped. Rotation and reciprocation should also be employed throughout the displacement. Over displacement is recommended to minimize contamination. Return fluid density should be within 0.25 ppg/0.03gm/cc of mud weight before taking returns back to the system.

MAINTAINANCE 

Drill out cement with water (if possible), or pre-treat the CLAYFREE mud with Soda ash and Sodium bicarbonate to eliminate Calcium contamination.



Ensure all solids control equipment is working efficiently, as maintaining the low gravity solids content and MBT equivalents will be extremely important through the reservoir section.



The appearance of cuttings at the shale shakers should be closely monitored to ensure there insufficient inhibition. The effects on other drilling parameters such as tight hole, torque, etc. should also be considered. Maintain constant inspection of cuttings integrity at the shaker. The KCL concentrations should be altered according to firmness and increased as hole condition dictate.


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

The mud density should be kept as lowest possible whilst drilling the 8 ½ “ section to minimize the chance of differential sticking



HOLE CLEANING – MUD RHEOLOGY. Proper rheology is extremely important. The system uses biopolymers to provide optimum low-shear-rate-viscosity (LSRV) for superior hole cleaning, wellbore stability and optimum hydraulics. Elevated flat, fragile gel strengths are important to ensure suspension of solids. Proper rheology is even more critical in high angle wells to prevent the formation of cuttings beds and the degradation of the large, inhibited cuttings. The use of high density-viscous sweeps should only be used to ensure adequate hole cleaning; proper rheology is the key to efficient solids removal.



HOLE CLEANING - DRILLING PRACTICES. Controlled ROP, maximum circulation rates, maximum pipe rotation, and LSRV mud rheology – all of these factors are critical to ensure drill solids removal from the wellbore in vertical and especially in a high angle wellbore. This is critical because of the improved cuttings integrity.



WIPER TRIPS. The CLAYFREE fluid will provide a gauge hole and, therefore, it is important to utilize wiper trips. The prudent use of wiper trips is important to facilitate cuttings transport and to ensure the caliper of the wellbore. This is especially important when using as stiff BHA. Monitor over-pull on trips for indications of inadequate hole cleaning or tight hole. If over-pull is a major problem, then consideration should also be given to a change in the BHA assembly.

Engineering Guide lines Formation Damage The most important parameter of the system that will require regular monitoring is the fluid loss across a porous medium in particular the ‘spurt volume’ measured after 20 seconds. If the values indicate a rising trend then additions of micronized CaCO3 should be added. PG Stach and PAC LV should be added to reduce the final filtrate value. Pilot testing is recommended prior to any system treatment. Addition of Barite considered only if require and after confirmation from the ONGC.

Solids Control To minimize formation damage it is necessary to retain carbonate particle size up to 200 microns in the active system. Based on screen opening size this would mean shaker screens finer than 84 meshes could not be used while drilling. With 84 mesh shaker screens however 90% of the micronized CaCO3


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will be retained but only 60% of the formation sand will be removed, possibly allowing sand content of the drilling fluid to affect surface equipment. With 140 mesh shaker screens 85%of the formation sand will be removed but only 80% of the micronized CaCO3 will be retained, below the effective particle size required to effectively bridge the formation sand. It is recommended to run the shaker screens as fine as possible – preferably 120 mesh screens – while replacing the top cut calcium carbonate removed by the shakers with additions of Gel white. This will help to maintain the correct particle size distribution without compromising filter cake quality. It is not recommended that centrifuges be used with this system as they will remove all the bridging material. Drilling rates can be high in reservoir sections. If shales of a dispersible nature are encountered this may result in a deterioration of the filter cake properties from incorporation of plastic clays. Clay content as measured by MBT should be kept less than 5 ppb. Potassium content should be measured at regular intervals and sufficient reserve volume and mixing capability should be available at all times. Consider increasing the KCl content of the brine phase or in pre-mix if depletion occurs with clay hydration. Regular monitoring of the drilled solids content and type is essential. Maintaining a drilled solid target of 3% maximum with 7% bridging material (160 kg/m3) will mean a total LGS solid content of 10%. The sand content of the fluid should be monitored to check that it contains carbonate as well as silica. The CaCO3 coarse bridging carbonate will appear as ‘sand’ in this test but is acid soluble. Volume percent carbonate measured in the sand tube can be multiplied by 2700 to give kg/m3 of coarse bridging material. There should be at least 2% carbonate in the sand content to maintain the correct bridging concentration. Lost Circulation: Loss of whole fluid will most likely be related to encountering highly permeable zones with an overbalance. Bridging with the correct range of particle sizes will reduce losses. A NON DAMAGING pill composed of all the grades of carbonate(140-215 kg/m3 (50-75 ppb) CaCO3) ranging from super fine (< 5 micron) to coarse (350 micron) particle sizes should be pumped to reduce losses. Hole Cleaning: If the hole angle is more than 45 degrees hole cleaning will become more challenging. The excellent rheological profile of CLAYFREE makes it an excellent choice for deviated wells, as the high low shear rate viscosity (LSRV) inherent in this fluid helps to ensure excellent hole cleaning. By maintaining the program rheological profile, providing sufficient annular velocity and rotating the pipe should ensure cuttings removal. However, high instantaneous ROP’s may lead to poor hole cleaning. Poor hole cleaning may also be observed after periods of sliding. Ream and circulate connections prior to re-orienting. In the event that poor hole cleaning is suspected and correct rig procedures have been followed, then consider pumping a high viscosity pill (50 bbl). Monitor returns for signs of increased returns. This would be an indication that higher viscosity is required for cleaning the low angle section of the hole.


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Note: Low viscosity pills are not recommended as generally they require large volumes to be effective and are counterproductive if pipe rotation and pumping is stopped even for a short period. Avoid pumping several hi-vis sweeps, as this will affect the rheological profile of the mud. The pipe must be rotated and pumping should not stop while circulating pills. Before pulling out for a trip circulate the hole clean with rotation. Cuttings transport will take longer than expected for the high angle sections, a clean shaker does not necessarily mean a clean hole. Be aware of the possibility of cuttings beds further up the hole in hole angles between 50 and 60 degrees, backream out if necessary with high pipe rotation. Since the main viscosifier is a biopolymer and the solids content is relatively low the rheological behavior of the system is best predicted by the Power Law model. The fluid exhibits shear thinning behavior at annular and pipe shear rates as well as visco-elastic behavior at shear rates below 1 sec-1. This results in low system pressure loss, flatter flow profile in the annulus with higher wall shear rates and sufficient solids suspension at very low shear rates. In order to preserve these advantages the ‘n’ and ‘K’ indices of the system should be monitored and controlled by addition of XC Polymer. Adding XC Polymer will increase K at the same time as lowering n, enhancing Power Law behavior. Since PAC R also contributes to K its use should be restricted to controlling fluid loss. The n should be kept in the range 0.2 to 0.5 by addition of XC Polymer. Calculating n and K from 200 and 100 Fann 35 readings will increase accuracy of fluid characterization. A check on the ECD value while circulating and the swab value while tripping is recommended as a safety precaution as the system rheology is higher than conventional reservoir fluids. After drilling to TD circulate bottoms up with 50-60 RPM rotation. Perform a wiper back to the shoe and circulate bottoms up. Run back to TD and circulate the hole clean with rotation. It is important to ensure the hole is clean of cuttings to prevent damage to the completion when it is run in the hole.


Well No:

Rig:


BBL

SURFACE VOLUME

600

9 5/8” casing VOLUME

408 329

OPEN HOLE VOLUME WITH 10% WASH OUT TOTAL VOLUME

1338

MAINTAINENCE VOLUME

1300 2638


600

New Mud Built

2038 1338

Mud Remaining Dilution Factor

bbl/m


UNIT SIZE

Qty

Xanthum Gum KCL Soda Ash Mod.Starch Salt Calcium carbonate Biocide PAC LV C P Glycol Polyamine Soltex EP Lube Biocide

25 Kg 50 Kg 50 Kg 25 Kg 50 Kg 50 Kg 200 Lt 25Kg 200Lt 200Lt 25Kg 200Lt 20Lt

61 657 8 282 1237 600 15 172 71 61 185 4 20


Unit Cost

Well No:

Tot. Cost

Rig:

Contingencies: 1. Lost circulation:

Losses of partial or whole mud to subsurface formations

is called lost

circulation or lost returns. Lost circulation has historically been one of the primary contributors to high mud costs. Other hole problems such as wellbore instability, stuck pipe and even blowouts have been the result of lost circulation. Besides the obvious benefits of maintaining circulation, preventing or curing mud losses is important to other drilling objectives such as obtaining good quality formation evaluation and achieving an effective primary cement bond on casing. Lost circulation occurs in one of two basic ways: 1. Invasion or mud loss to formations that are cavernous, vugular, fractured or unconsolidated. 2. Fracturing which is mud loss due to hydraulic fracturing from excessive induced pressures. It is important to have a good stock of both fibrous flake & granular NON DANAGING LCM available on the rig at all times. The volumes in the pits must be monitored closely at all times, and losses understood quickly to avoid breaking down any formations down-hole. This section is provided to give guidance on the best remedial action to stem down-hole losses. I t is recommended loss treatments based on the severity of down-hole losses; these can be ranked as Seepage Losses, Partial Losses, or Severe/Total Losses. It is recommend using conventional lost circulation products initially, but should these fail to cure the losses, special pills may be tried and at last cement plug is the final solution.

Seepage Losses: Losses of up to 10 bbl/hr are normally considered as seepage losses. Seepage type losses are frequently cured by the simple action of reducing or stopping the pump rate and allowing the formation to heal and become sealed off by the development of a filter cake. The pump rate can be gradually increased after the losses have stopped. Seepage losses can sometimes progress to partial or total losses if remedial action is not taken. If seepage losses are expected during drilling through a certain formation, treating the whole mud system with LCM before entering the loss zone can be recommended. Such a treatment will depend on pore/fracture size distribution in the actual formation, not to mention the tolerance to LCM of down-hole tools. Partial losses: Losses from 10 bbl/hr to 25 bbl/hr are referred in this particular case as partial losses. The situation will usually require treatment. The LCM pill should be spotted in the thief zone, and allowed to soak: If this pill does not heal the losses, the pill given under “total losses of returns” should be pumped. If that one also fails, one of the soft plugs or reinforcing plugs should be pumped. Total Losses of Returns: The priority will usually be well control, so the annulus must be filled from the top with either drilling fluid, base oil or other lightweight liquid. Unless the fracture is induced, losses can normally not be stopped by pumping conventional LCM pills. However, a pill of LCM is often the first choice since it gives quick response if it works and it is easy to do. Recommended pill to pump should contain as much LCM as possible, but not more than 75 ppb total LCM concentration If this pill does not heal the fracture, a specialized pill (cross-linking or reinforcing plug) should be set across the loss zone containing a mixture of fine particle sizes to plug deep fractures, faults, and vugular formations. The flow chart below shows the generalized course of action recommended in the event of down-hole losses. Drilling Fluid Programme : John Energy/ONGC

Well No:

Rig:

Recommended Course of Action Based on Severity of Down-Hole Losses

Losing fluid while drilling

Stop drilling and observe levels Yes

No

Losses on surface Yes

Locate and stop osses

Well flowing? No

Record shut in pressure. Kill the well

Measure rate of loss

Seepage losses < 10 bbl/hr Premix 10 ppb mica in the whole system. If no reduction in loss rate spot pill:

Partial losses 10-25 bbl/hr

Total loss

Spot pill:

Spot pill:

No success

No mica

10 lb/bbl 20 lb/bbl

micaI

15 lb/bbl

wallnut

wall nut

15 lb/bbl

saw dust 20 lb/bbl

success 20

wallnut lb/bbl

20

saw dust 20 lb/bbl

Volume:

If no reduction in loss rate go to partial losses recommended tratment.

mica lb/bbl

100 bbl mimimum Spot specialized pill:

No success

Volume: Losses Stopped? 100 bbl minimum Drill Ahead.


Well No:

Rig:

Differential Sticking

The vast majority of stuck pipe problems arise from differential pressure

sticking. Differential pressure sticking can be defined as the force that holds pipe against the wall of the hole, due to the differential between formation pressure and hydrostatic pressure. In order for differential pressure to exist, certain criteria are required:  Hydrostatic pressure must exceed formation pressure.  A zone of permeability must exist, over which a thick filter cake has been deposited.  There must be contact area between the pipe and the filter cake.

Since formations with permeability will be encountered, differential sticking is a possibility. The following information will deal with the remedies available to free differential pressure stuck pipe. The area of contact increases as the filter cake thickens with time, thus producing greater sticking forces. Because of this, a quick determination of the cause followed by an immediate remedial step is imperative. 2.1 Work pipe by tripping the jars both up and down if possible. 2.2 Attempt to rotate. 2.3 Spot a Pipe -Lax soak solution quickly. The probability of freeing differentially stuck pipe with a soak solution is inversely proportional to the time between actual sticking and final spotting of the solution. Reduce mud weight if possible. 2.4 Run a drill stem test tool and relieve pressure. 2.5 Pump a slug of water down the drill string then let it U-Tube. 2.6 Pump some air to reduce the hydrostatic head. PIPE-LAX (NW) FORMULATION: 1 2 3 4 5

Dump the slug pit Take Diesel Mix 3-4% PIPE LAX spotting Fluid, shear. Displace around the stuck point against DC. Assuming that the stuck point is against the D/C, enough Sp. Fluid should be prepared to cover the twice the DC. Displace and keep 1M3 in D/string. Work on string.

PIPE-LAX (Weighted) FORMULATION: for 1M3 Sp. Gr Pipe-Lax-W HSD Water

1.20 115Lts 545Lts 295Lts

1.44 115Lts 490Lts 270Lts

1.68 115Lts 455Lts 245Lts

1.72 115Lts 485Lts 135Lts

Baryte

354Kg

663Kg

950Kg

1280Kg

Note: Before Pipe-lax is mixed, make sure that the tank is agitated completely to ensure no settling. Drilling Fluid Programme : John Energy/ONGC

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Drilling Fluid Programme for Petromine

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