Tecnología anfoterica para pozos profundos en agua.

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Copyright 2002 AADE Technical Conference

This paper was prepared for presentation at the AADE 2002 Technology Conference Drilling & Completion Fluids and Waste Management, held at the Radisson AstrodomeHouston, Texas, April 2 - 3, 2002 in Houston, Texas. This conference was hosted by the Houston Chapter of the American Association of Drilling Engineers. The information presented in this paper doenot reflect any position, claim or endorsement made or implied by the American Association of Drilling Engineers, their officers or members. Questions concerning the content of this paper should bedirected to the individuals listed as author/s of this work.

Abstract

The Deepwater permitting process in highly visible,environmentally sensitive areas, located Offshore Brazilreduces the use of non-aqueous phase drilling fluids.This situation creates the need for high performancewater based drilling fluids. Historically, the chemistry

generally used to control water base drilling fluid (WBM)properties has been anionic in nature. Cationic chemistryhas been used to increase shale inhibition but withlimited success.

Amphoteric chemistry, which has both cationic andanionic functional sites, has increased shale inhibitionand helped impart extremely stable rheologicalproperties in deep water drilling environments. In UltraDeepwater conditions, due to narrow marginconsideration between pore pressure and fracturegradients and borehole stability, the selection of a stabledrilling fluid is one of the key criteria of successful

operations. Drilling fluid monitoring and equivalentcirculation density (ECD) management are critical inorder to reduce fluid losses and maintain formationintegrity. Due to the nature of Ultra Deepwater wells,logistics are difficult, boat trips are long, mud volumesare high (riser), and deck loads are limited.

This paper describes the recent applications of a drillingfluid design using amphoteric chemistry for increasedshale inhibition. This fluid design has been used in UltraDeepwater in Brazil (up to 8,077 feet of water). Theability to control active shales and maintain stable fluidproperties has brought several benefits during drillingoperations and for the planning of future wells:

Well architecture is optimized.

Logistics simplified

Fluid easily transferred to another prospect.

Introduction

Drilling fluid volume management in deepwater wells hasto be controlled and optimized. All transportation, loadingand unloading operations create operational limitationsWhen using synthetic drilling fluids, best logisticpractices have to be in place, spill response plans

HS&E programs, complex displacement procedures, etcEven with good plans in place, misjudgments can occurand a spill can shut down an operation with costlyconsequences.

In order to obtain drilling permits, all operators have tocomply with local environmental regulations. Drilling andcompletion fluids have to pass a series of environmentatests according to regulations in place. Offshore Brazilthe Instituto Brasileiro de Meio Ambiente (IBAMA) isregulating all fluid systems. The tests are performed onthe final fluid composition, usually with componenconcentrations higher than those used in the field.

For WBM, three tests have to be performed:

Acute Test with Mysidopsis Juniae (Shrimp)

Short Term Chronic Test with Lytechinus Variegatus(Sea Urchin)

Short Term Chronic Test with Perna Perna (BivalveMollusk).

These tests have to be performed by a Brazilianlaboratory approved by IBAMA. (Table 1).

The amphoteric drilling fluid system passed alenvironmental tests. For synthetic drilling fluids (SBM)the approval is more complex and longer (toxicity to the

three above species, biodegradability, n-octanopartitioning etc). In most cases the maximum allowabledischarge of Synthetic On Cuttings (SOC) is 10%, whichimplies investment in more costly solids controequipment (centrifuges, dryers), a tighter audit systemand costly seabed surveys. Most Operators wouldtherefore prefer to use a WBM, if they were confidentthat it would deliver stable hole conditions and drillability.

Waste minimization is a common goal in the drilling

AADE 02-DFWM-HO-06

Amphoteric Technology for Deep Water Wells

Luc Leoni, Cesar Misino, Bill Halliday of Baker Hughes INTEQ Drilling Fluids, Daniel Rouat of TotalFinaElf


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2 LEONI, MISINO, HALLIDAY, ROUAT AADE-02-DFWM-HO-06

industry. Due to the highly inhibitive properties ofamphoteric chemistry, the dilution rates are minimizedand consequently the volume of waste discharged isminimized. In one example of the wells drilled offshoreBrazil, the dilution rates were 1.34 bbls

per foot drilled in

the 17 interval to 1.93 bblsper foot drilled in the 8

interval. This is up to 50% less than the dilution rates

required on wells drilled using a PHPA mud.

Amphoteric Chemistry

Amphoteric (or Zwitterionic) chemistry has both cationicand anionic charged sites on the molecular structure.The inhibition of the clays is achieved by cationicexchange upon clay sites that are reactive to water. Bysatisfying these sites, the clays become hydrophobicand water is unable to attach by hydrogen bonding. Thisprocess generates unitary hydrogen bonds and staticelectric force. The clay particles' integrity are stronglymaintained by electrical forces. The other group, theanionic group, will form hydration layers and create a

steric barrier to prevent further hydration of the shalesparticles

1. The net effect is that the clay exhibits

significantly less swelling and dispersion. (Figure 1)

Due to the unique chemistry of this amphoteric amine, italso acts as a hydrophobic metal wetter; this reduces bitballing and gumbo sticking to the BHA. A typicalAmphoteric molecular structure is as follows:

Since increased inhibition for these deepwateroperations was desired, the decision to use amphotericchemistry to control shale and clay hydration anddispersion was implemented. The amphoteric additivechosen is a water soluble hydration and dispersionsuppresser for water based drilling fluids. This impartsunique attributes to this drilling fluid not the least ofwhich is increased inhibition. Another feature of thischemistry includes compatibility in fresh up to saturated

salt water systems for stabilizing shale and prevention ofgumbo associated drilling problems. The material isreadily water soluble therefore no special mixingprocedures or equipment is necessary. The amphotericattributes of this chemistry allow wide compatibility withmost of the additives used in water based fluids. Atesting procedure has also been developed in order tomeasure the amount of amphoteric product present inthe drilling fluid filtrate.

2

ECD and Low Temperature

In designing the drilling fluid for the deepwater wellsOffshore Brazil, shale inhibition resulting in stablerheological properties and stable borehole conditionswas one of the prime requirements. When drilling theyounger shales encountered in most deepwater drillingareas, the highly reactive clay content can cause shale

hydration, shale dispersion, and shale sloughing. Thesetroublesome shale sections can cause subsequenproblems such as stuck pipe, hole enlargement, bit andBHA balling, and lost circulation. High equivalentcirculating densities (ECDs) can be caused by excessiveshale and drilled cuttings being incorporated into thedrilling fluid system. This can cause several operationaproblems including lost circulation and subsequentlyuncontrolled formation influx and/or excessive fluid costsdue to dilution requirements of the mud system.

Borehole stability is extremely important when drilling adeepwater well. The control of fluid density has to be

one of the criteria to achieve good drilling practices. Thefirst parameter to control wellbore integrity is thepressure applied by the drilling fluid. The mud weighhas to be adjusted between the pore gradient and thefrac pressure. Then the additional physico-chemicaproperties of the fluid help prevent shale destabilization.

It is well known and documented that as the water depthincreases, the formation fracture gradient isproportionally weaker. The fracture gradient typicallydefines the pressure (or mud weight) required to fracturethe formation or rock versus depth. Pore and fracturegradient calculations must be taken into account by

drilling engineers for a successful well drilling and casingprogram. Improper fracture gradient prediction can resulin expensive and potentially disastrous consequencessuch as multiple casing strings, lost circulation, reservoirinvasion and/or formation influx. A deepwater weldesign must include the following items: optimumlithology prognosis, accurate prediction of pore and fracgradients, casing and cementing programs withcontingency, choice of mud system, proper evaluation ofhazards, pre-calculations for optimum hydraulics, gashydrate formation risk analysis, temperature modelingand kick tolerance evaluation.

Fracture pressures on land are a function of the

overburden pressure exerted by the formation. Inoffshore applications the overburden pressure exertedby seawater is less than that exerted by sand-shaleformations. For example if a land well is drilled to 3,000ft with 10 lb/gal mud, there exists a static hydrostaticpressure at TD of 1,560 psi or a pressure gradient of0.52 psi/ft. In an offshore well located in 3,000 ft of waterthat is drilled to 3,000 ft below the sea bed with a 10lb/gal mud, the same 0.52 psi/ft pressure gradient from

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AADE-02-DFWM-HO-06 Amphoteric Technology for Deep Water wells 3

the mud column exists. On the overburden side,however, the static hydrostatic pressure at TD will be thesum of 3,000 ft of 1.04 g/cc seawater and 3,000 ft of 2.5g/cc formation at 6,000 ft below sea level. In effect, thelighter seawater column dilutes or reduces theoverburden pressure gradient. Therefore, theoverburden pressure in psi/ft or apparent fracture

gradient in the offshore well will be less than in the landwell. As we know today, no basic calculation modelshave been run to estimate the deepwater wells fracgradient worldwide, local data from previous offsetcampaigns must always be used as a guide. Settingadditional casing strings or carrying lower mud densitiesmust offset this low fracture gradient and leak off test. Indeepwater drilling a substantial amount of hole must bedrilled riserless with returns going to the sea floor beforea suitable casing shoe can be established and thedrilling fluid be pumped from bottom of the hole to the rigfloor (some 80 to 100 feet above sea level).

3

Water does not change volume with temperature andpressure. However, the rheological profile can changewhen temperature increases or decreases. Table 2illustrates the rheological properties of the amphotericfluid staying consistent with changes in pressure. Thecontrol and stabilization of rheological properties underthese changing conditions is very important (Figure 2).Due to the low temperature at the seabed and thecooling effect of the riser (Table 3 and Figure 3) thecirculating temperature is lower than the geothermalgradient indicates (Table 4). The drilling fluid should bedesigned to achieve a stable rheological profile whiledrilling in order to minimize the pressure losses (ECD) atthe low temperatures encountered in drilling thesedeepwater wells. Drilling fluid gellation effects due to thelow temperatures experienced during long periodswithout circulation or while tripping drill pipe must beminimized.

Due to the compressible nature of SBMs/OBMs, it isimportant to correct for the fluids density when predictingdownhole pressures. In addition, temperature andpressure have a dramatic effect on SBMs rheologicalcharacteristics. For accurate downhole pressurepredictions a good hydraulics model must consider theseeffects and make the correction to these parameters.Fluid PVT data can be utilized to correct for density. For

rheological correction, Fann 70 data is generated underthe expected downhole pressure and temperatureconditions. The most important variable on both densityand rheology, is temperature. In contrast to the SBMs,WBMs are not as susceptible to the dramatic densityand rheology changes under the same conditions.

In deepwater drilling, ECD predictions can be importantto the success or failure of the project, therefore

accuracy in these predictions is mandatory. Moshydraulics software used to predict downhole pressuresuse a steady state temperature model to define acirculating temperature profile. With this profile therheology is then corrected throughout the wellbore andfrictional pressure losses are then calculated with thelocal properties. Also, the local density of the fluid is

corrected due to the pressure and temperature effectsand the overall downhole pressure prediction aregenerally accurate. Unfortunately, the temperaturemodels are steady state and are more reflective ofextended circulating periods. This is not always thecase, such as breaking circulation after extended noncirculating periods. Therefore, inaccuracys in ECDpredictions with SBMs can lead to pump rates highenough to fracture the formation causing severe lossesWith the amphoteric water based system ECDpredictions under these same conditions are moreaccurate and the operator is better informed as to theflow rates achievable without fracturing occurring. The

lower impact of pressure and temperature on theamphoteric mud system compared to a synthetic oibased system is an advantage in designing the drillingfluid for ultra deep water conditions.

Optimized Operations

The case histories on which this paper is based arewells drilled by three different companies operatingoffshore Brazil.

Operator 1:

The first application for the amphoteric mud systeminvolved two ultra deepwater wells (>8,000 of water)

drilled in the Campos Basin, with the following drillingprogram:36CP, 26, 17, 12 and 8 intervals to a totadepth of 14,515 ft. RKB. For the 36 jetting section, highviscosity bentonite sweeps were pumped after each drilpipe joint to facilitate hole cleaning. The 26 section wasalso drilled with sea water and high viscosity sweeps. Acasing depth, the 20 was set with no problems. For thesubsequent hole sections the amphoteric/KCl drillingfluid was utilized down to total depth. Averageformulation and flow properties for the amphoteric fluidare presented in Table 4. For these intervals thepotassium chloride content was kept around 19 - 22

lbs/bbl. Cellulosic fiber and fine calcium carbonate wereadded as supplemental bridging agents to help controseepage losses to the formation. Excellent cuttingsintegrity was observed at the shakers while using 84mesh screens in the 17 and 12 sections and 140mesh screens while drilling the 8 section.

Rheological modeling of the amphoteric water base fluidwas conducted prior to spud, under deepwaterconditions, whereby accurate data could be entered into


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the hydraulics software (Fann 75 values and SG werechecked and re-checked carefully).During the drilling ofthese subsequent intervals the plastic viscosity, yieldpoint and gels strengths remained very stable (Figure 5)while using the amphoteric drilling fluid. The stablerheology achieved under the conditions of coldtemperature and pressure resulted in maximum pump

output that optimized drilling and hole cleaning. The mudweight and rheology were controlled to maintain theECDs as low as possible. An example of the stableECDs achieved is presented in Figure 6.

After the excellent results of the first well the operatordecided to change the well architecture for the secondwell and drill the 12 interval to 15,175 ft. removing the8 hole section from the well design. This considerablysimplified logistics and removed the necessity of a 9-5/8casing string, which resulted in substantial operationalsavings.

During the entire drilling phase, no centrifuge was used.Due to the inhibitive and stable condition of theamphoteric drilling fluid the rig shale shakers efficiencywere optimized keeping the solids content very low:On well 1 the maximum low gravity solids content did notexceed 2.6% in the 8 interval. On well 2, after reusing4,095 bbls of fluid from the previous well, the MethylenBlue Test (MBT) did not exceed 20 lb/bbl after drilling2,625 ft. of 12 hole to TD. The dilution rate for thisinterval was 1.82 bbls per foot drilled.Logistics: The total chemicals required to build mud forall the well sections were sent to the rig at the beginningof the operations to minimize logistics. No problemswere reported regarding the mixing process. A senior

drilling fluid engineer with experience in deep offshoresituation emphasized the need for well planned logisticsas well as mud mixing procedures.

Operator 2:

Operator 2 had originally planned to use a PHPA fluid todrill a well with a very similar profile to Operator 1, thiswell being drilled in the Santos Basin. After hearing ofthe success of the amphoteric/KCl system used byOperator 1, the Fluids program was changed and theamphoteric system was used. Using the same drillingrig, the well was drilled re-using 8,497 bbls of amphotericdrilling fluid transferred from the previous drilling

operation. The fluid imparted the same stable rheologicalbehavior experienced in the previous campaign. Onceagain, excellent hole stability was experiencedthroughout the drilling of the well. There were noincidents of stuck pipe, bit balling, hole enlargement orlost circulation.

An additional benefit of the system was evident when2,297 ft. of cement was inadvertently set inside the 13-

3/8 casing string. Because of casing collapseconsiderations, the cement could not be drilled out usingseawater, but had to be drilled using the amphotericdrilling fluid. The fluid's physical properties remainedremarkably stable, despite an increase in pH from 9.0 to12.8. Rheological properties remained within theprogrammed parameters, while the API filtrate slipped

only slightly, from 4.5 ml to 5.6 ml/30min. The pH wassuccessfully lowered by treatment with citric acid. Thesubsequent 12-1/4 section was successfully drilledusing the treated mud system.

Operator 3:

This well was not drilled in the deepwater Campos orSantos fields, but in the Potiguar basin offshorenortheast Brazil. The Operator had been drilling offsewells using a PHPA system. However, severe holeenlargement resulting from shale dispersion, especiallyin the reservoir cap-rock shale was experienced on all ofthe wells drilled using PHPA. The 12-1/4 hole interva

was washing out up to 20 diameter, making dataacquisition from e-logs near impossible. As a correctiveaction, the Operator planned to drill an 8-1/2 pilot holeto allow e-logs to be run, before opening the hole to 12-1/4.

After discussions with the Operator, it was decided toutilize the amphoteric/KCl system on the next well, usingconventional hole sizes. The 12-1/4 section drilled hada maximum washout of 14, with an average of 12.8 forthe section. The logging campaign was successful. Animportant additional benefit imparted by the stability othe well was a reduction of 4 drilling days compared to

the previous offsets.The Operator intends to use the amphoteric/KCl systemon future drilling campaigns offshore Brazil.

Conclusions

Increased shale inhibition has been achieved usingan amphoteric shale inhibitor as compared totraditional PHPA systems. The system has impartedextremely stable borehole and rheological propertiesduring the drilling of a series of deepwater wellsoffshore Brazil .

Well architecture can be optimized and a longeintermediate section can be drilled, in some cases

eliminating a casing string

The fluid design employed is environmentallyacceptable for discharge offshore Brazil.

ECD management was achieved with the use of aninhibitive and stable water base fluid design.


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AcknowledgmentsThe authors wish to thank the management of BakerHughes INTEQ and TotalFinaElf for permission topresent this paper.

References

1. Luo Pinya, Li Jian, Niu Yabin, Zhang Daming and XuiTongtai: Improved Inhibition and Rheological Propertiesare observed in Amphoteric Polymer Mud System, SPE29943, Presented at the International Meeting onPetroleum Engineering, China, 1995

2. Walker et al., US Patent No. 6,194,216 Method ofDetermination of Amine-Based Additives in Drilling FluidFiltrates, Feb. 27, 2001

3. Halliday, W. S., Clapper, D. K., Smalling, M., NewGas Hydrate Inhibitors for Deepwater Drilling Fluids,IADC/SPE 39316, Dallas, TX, March 1998.


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Table 1: Environmental Testing for Offshore Brazil

DRILLING FLUID ACUTE TESTLC 50-96H(Mysidopsisjuniae)

SHORT TERMCHRONIC TEST(Lytechinus variegatus)

SHORT TERMCHRONIC TEST(Perna perna)

SHRIMP SEA URCHIN BIVALVE MOLLUSK

SEA WATER/BENTONITESWEEPS

248000 ppm SPP CENO = 6.000 PPMCEO = 30.000 PPMVC = 13.416 PPM

CENO = 600 PPMCEO = 1250 PPMVC = 866 PPM

6 % CATIONIC POLYMER 41900 ppm SPP CENO = 1200 PPMCEO = 6000 PPMVC = 2683 PPM

CENO = 2500 PPMCEO = 5000 PPMVC = 3535 PPM

6% KCL - AMPHOTERIC 161000 ppm SPP CENO = 1200 PPMCEO = 6000 PPMVC = 2683 PPM

CENO = 10000 PPMCEO < 10000 PPMVC < 10000 PPM

Synthetic 1 269700 ppm SPP CENO = 5000 PPMCEO = 100000 PPM

VC = 22361 PPM

CENO = 25% Hydrosol. frac.CEO = 50% Hydrosol. frac.

VC = 35.3 Hydrosol. frac.Synthetic 2 191500 ppm SPP CENO = 5000 PPM

CEO = 100000 PPMVC = 22361 PPM

CENO =12.5% Hydrsol.frac.CEO = 25% Hydrosol. frac.VC = 17.7 Hydrosol.frac.

Synthetic 3 291600 ppm SPP CENO < 6 PPMCEO = no calculvelVC = no calculvel

CENO = 50% Hydrosol. frac.CEO = 100% Hydrosol. frac.VC = 70.7 Hydrosol. frac.

Figure 1: Inhibition of the Amphoteric System

0123456789

1011121314151617181920

0 1 2 3 4 5 6 7 8

Amphoteric Concentration, lb/bbl


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Table 2: Fann 35 and Fann 70 Data

Fann 35 Fann 70Pressure 3000 3500 5000

Temp 45F 100F 122F Temp 45F 100F 122F

600 112 60 48 600 114 58 50

300 80 40 32 300 80 38 32200 64 32 25 200 65 30 26100 44 21 16 100 44 19 17

6 9 4 3 6 9 4 33 7 3 2 3 6 2 2

PV 32 20 16 PV 34 20 18YP 48 20 16 YP 46 18 16

Figure 2: Fann 35 and Fann 70 Pressure and Temperature Data

Well 1 - Fann 35 / Fann 70 Comparison

0

20

40

60

80

100

120

0 100 200 300 400 500 600

Fann - RPM

ShareStress-lb/100ft2

7C / 1bar

38C / 1bar

50C / 1bar

7C / 210 bars

38C / 245bars

50C / 350bars

7C

38C

50C


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Table 3: Campos Basin Brazil Sea Water Temperature

Depth ft Sea Level TemperatureC

Depth m Sea Level

300 26.19 91.44

600 25.56 182.88

900 24.42 274.32

1200 22.42 365.76

1500 20.35 457.2

1800 18.38 548.64

2100 16.68 640.08

2400 13.62 731.52

2700 11.97 822.96

3000 10.16 914.4

3300 8.47 1005.84

3600 7.28 1097.28

3900 6.36 1188.72

4200 5.58 1280.16

4500 4.91 1371.6

4800 4.46 1463.04

5100 4.31 1554.48

5400 4.24 1645.92

5700 4.17 1737.36

6000 4.13 1828.8

6300 4.09 1920.24

6600 4.02 2011.68

6900 3.94 2103.12

7200 3.87 2194.56

7500 3.68 2286

7800 3.5 2377.44

8100 3.42 2468.88

8170 3.38 2490.216


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Figure 3: Well 1 Sea Water Temperature Profile Figure 4: Well 1 Temperature Recording

Table 4: Typical Properties for Amphoteric System, Lower Intervals, Well A, Offshore Brazil

PROPERTY UNITS Range

Mud Weight SG 1.06 1.11

PV Cp 24 30

YP lbs/100 sq. ft. 22 37

6 rpm value Reading 8 17

Gels lbs/100 sq. ft. 2/4 8/12

Low Gravity Solids lbs/bbl 20 30

API Fluid Loss ccs/30 min 4.0 8.2

WELL 1 TEMPERATURE RECORDING

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

100.00

2450 2650 2850 3050 3250 3450 3650 3850 4050 4250 4450 4650 4850

Depth m RKB

TemperatureC

P redi cted static T C P re dicted cir c T C Recor de d static T C Recor de d circ T C

Temperature gradient : 3,2C/100m

Estimated temperature gradient : 4C/100m

Recorded Circ. TC

Predicted Circ. TC

Well 1 - Seawater Temperature Profile

0

250

500

750

1000

1250

1500

1750

2000

2250

2500

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28

TEMPERATURE C

DEPTHm-

SEABEDLEVE

3,38C at 2490m

Thermocline : 1200m


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Figure 5: PV/YP/RPM6 vs Depth at 50C and 14C

Table 5: Variations in Mineralogy

Mineralogy 1 Mineralogy 210-15 % Quartz 10-15 % Quartz


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Figure 6: ECDs for the 12 section.

Tecnología anfoterica para pozos profundos en agua.

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