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For this months issue of featured well-stimulation papers, theongoing work in acidizing earns my recognition as the mostenlightening and yet overdue progress. Although the papersspotlighted in this issue are strong presentations on diversesubjects, I was most surprised by the volume of engaging papersfocusing on acids and fracture acidizing. There are great papersin my list with information on horizontal wells, gravel packing,

and viscoelastic fluids; however, each of these technologies is young comparedto acidizing reservoir rock.

In one of the additional-reading selections, Fracture Acidizing: History, PresentState, and Future, we learn that acidizing carbonates dates back to 1895.Therefore, the use of acids to increase production is more than a century old.With many of the modern acidizing theories developed around 1972 by Neirodeand others, it is still a 35-year-old technology that needs a fresh look with mod-ern methods. Whether we are studying etching behavior to forecast conductivityor predicting long-term reductions in performance caused by creep, we still havea lot to learn about this venerable practice.

Therefore, the question becomes: How can acidizing oil wells be more than100 years old, yet we just now are beginning to unravel these fundamentalconcepts? The world produces approximately 85 million BOPD, and assumingjust USD 50/B, we generate more than USD 1.5 trillion/yr in world oil revenue.Whatever the historical disconnect has been between oil revenues and fundingoil science, I am pleased to recommend these compelling technical papers onsubjects vital to our industry, including the common practice of pumping acid

into a formation to increase production.

Charles Hager, SPE, is a senior consultant with NSI Technologies. For the last 17years, he has focused on applying and integrating the sciences of hydraulic-fracturinganalysis and modeling, pressure-transient analysis, and reservoir simulation. Hagerearned a BS degree in petroleum engineering from the University of Alabama, and heserves on theJPT Editorial Committee.

OVERVIEW

WELL STIMULATION

Well Stimulation

additional reading

available at the

SPE eLibrary: www.spe.org

SPE 108075

Horizontal-WellCompletion and StimulationTechniquesA ReviewWith Emphasis on Low-Permeability Carbonatesby Valdo Ferreira Rodrigues,

SPE, Petroleo Brasileiro,et al.

SPE 107772

The Effects of Acid ContactTime and the ResultingWeakening of the RockSurfaces on Acid-FractureConductivity by M.G.Melendez, Texas A&MUniversity, et al.

SPE 107760

Acid Stimulation ofExtended-Reach Wells:Lessons Learnt FromNKossa Field by J.M.Mazel, Total, et al.

SPE 106371

Fracture Acidizing: History,Present State, and Futureby Leonard J. Kalfayan,SPE, BJ Services

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A series of acid-fracture-conductivitytests was conducted that simulated flowin a hydraulic fracture, both in the mainflow direction along the fracture and inthe fluid-loss direction. Three commonlyused acid-fracturing fluids were testedat 200 and 275F. The acid-fracture-conductivity apparatus is similar to astandard American Petroleum Institute

(API) fracture-conductivity cell, but withthe ability to hold core samples that are3 in. thick in the leakoff direction.

IntroductionAcid fracturing, a well-stimulation pro-cess in which acid dissolves reservoirrock along the face of the hydraulicallyinduced fracture, is expected to createlasting conductivity after fracture clo-sure. However, conductivity after frac-ture closure requires that the fractureface be nonuniformly etched by theacid while the strength of the rock ismaintained at high levels to withstandclosure stress. At low closure stress,the etched pattern of the fracture faceshould have a dominant influence onthe resulting fracture conductivity aslong as the rock strength can with-stand the load. As the closure stress isincreased, surface features along thefracture faces may be crushed, whichmakes fracture conductivity moredependent on the rock strength thanon the initial etching pattern.

Success of the acid-fracturing processdepends on the resulting fracture con-ductivity, which is difficult to predictbecause it depends on a stochasticprocess and is affected by a wide rangeof parameters. Most predictions of con-ductivity are made with the empiricalcorrelation developed by Nierode andKruk. This correlation was based on

experiments with 1-in.-diameter, 2- to3-in.-long fractured cores with no fluidloss through the rock samples.

To ensure that laboratory experi-ments represent field conditions, thephenomena that occur in the acid-frac-turing process must be scaled properly.In this study, experimental conditionswere scaled to give the same magnitudeof acid transport along the fracture, acidleakoff, and acid reaction at the fractureface as occurs in field treatments.

AcidsThree acid systems were used in theconductivity tests: a gelled-acid sys-tem with an acid-soluble polymer as agelling agent, an acid-in-oil emulsion,and an acid/viscoelastic-surfactant acidsolution. The polymer-gelled-acid sys-tem contained 15% HCl, 2.5% gell-ing agent, and a corrosion inhibitor.The emulsified acid was a mixture of28% HCl and diesel with an emulsi-fier and a corrosion inhibitor. Thediesel forms the external phase of theemulsion. The viscoelastic-surfactant

acid has unique self-diverting char-acteristics. The fluid viscosity increasessignificantly as the acid spends, whichcreates effective diversion of the acidin matrix acidizing. The same charac-teristics have been found to reduce theacid-leakoff rate and increase stimula-tion effectiveness in acid fracturing.The viscoelastic diverting acid systemused in this study consists of 15% HCl,7.5% viscoelastic surfactant, and a cor-rosion inhibitor.

Laboratory ScalingThe acid-fracturing process involves sev-eral different phenomena, including acidtransport along the fracture, acid trans-port into the rock because of leakoff,convective and diffusive mass transfer ofacid to the fracture face, and acid reac-tion on the fracture face. The appropri-ate dimensionless groups that arise from

conservation equations provide a guidefor proper experimental scaling.For a typical field treatment with a

20-bbl/min injection rate into a fracture100 ft high and 0.2 in. wide, the injec-tion rate in the experiments shouldbe approximately 2.2 L/min to createthe same Reynolds number as wouldoccur near the wellbore in the fieldfracture. As the acid moves down thefracture and leakoff occurs, the velocityand Reynolds number will decrease.An injection rate of 1 L/min was usedin the experiments to ensure that thehydrodynamic effects that occur in thefield were simulated in the laboratory.

Fracture-Conductivity ExperimentsThe experimental apparatus and pro-cedure were designed to enable experi-ments to be conducted at conditionsmore closely and accurately represent-ing field treatments than previous stud-ies. The experimental apparatus alsowas designed to accommodate largerrock samples, higher injection rates, andhigher temperatures. The core samples

were placed inside a modified API con-ductivity cell with body dimensionsof 1031/48 in. and a 71/413/4-in.opening, allowing the use of rock sam-ples with thicknesses as great as 3 in.Cylindrical ceramic radiant heaters thatcan heat the fluid to 300F were wrappedaround the flowline to heat the fluidbefore it entered the cell so experimentscould be conducted at temperatures sim-ilar to field conditions. A backpressureregulator was installed on the leakoff line

This article, written by Assistant Tech-nology Editor Karen Bybee, containshighlights of paper SPE 106272, Small-Scale Fracture Conductivity Created byModern Acid-Fracture Fluids, by M.Pournik, SPE, C. Zou, SPE, C.M. Nieto,M.G. Melendez, D. Zhu, and A.D.Hill, SPE, Texas A&M University, andX. Weng, Schlumberger, preparedfor the 2007 SPE Hydraulic FracturingTechnology Conference, College Station,Texas, 2931 January.

A Small-Scale Fracture-Conductivity Study

WELL STIMULATION

For a limited time, the full-length paper is available free to SPE members at www.spe.org/jpt. The paper has not been peer reviewed.

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to control pressure drop across the core.This allowed the leakoff flow rate to becontrolled to represent field conditionsmore accurately. Another backpressureregulator was installed on the cell efflu-ent line to maintain the cell pressureabove 1,000 psi.

Experimental Procedure. An acid-frac-

ture-conductivity experiment consistsof core preparation, acid etching, rock-embedment-strength measurement, sur-face-profile characterization, and con-ductivity measurement. Core sampleswere cut into a parallelepiped shapewith the ends curved to fit the API cell.The cores were approximately 7.11 in.long, 1.61 in. wide, and 3 in. thick. Thecores were covered with a silicone-rub-ber compound to secure a tight fit ofthe core in the API cell and to preventany acid bypass around the core sample.

The cores then were placed in a vacuumdevice for several hours until all air wasremoved from the pore spaces, then thecores were saturated with water.

Conductivity Measurement. Fractureconductivity was measured by flowingnitrogen between the two acid-etchedcore samples and recording the absolutepressure at the midpoint of the fractureand the pressure drop across the frac-ture. The conductivity cell was placedin a load frame that provided closurestresses up to 6,000 psi. A 1,000-psiclosure stress was applied and increasedin 1,000-psi increments to 6,000 psi,changing the load after approximate-ly 60 minutes. Nitrogen flow wasbegun after placing the first load onthe cell. Pressure readings were record-ed at four different flow rates. Flowrates ranged from approximately 5 to20 L/min. Forchheimers equation forflow through a porous medium was usedto calculate the fracture conductivity.

Results and Discussion

Fifteen experiments divided into five dif-ferent sets were conducted to study theeffects of acid type, acid contact time,temperature, and rock type on acid-frac-ture conductivity. For each of the threeacids, three different contact times wereused that ranged from 15 to 60 minutes.Temperature was maintained at 200Ffor most experiments, except for oneset with emulsified acid at 275F. Theexperiments were conducted on Indianalimestone samples except for one set thatused Silurian dolomite. For all experi-

ments, the injection rate was 1 L/min witha 1,000-psi backpressure and leakoff fluxof approximately 0.005 ft/min. The initialfracture gap was maintained at 0.12 in.

The first three sets of experimentswere conducted under the same con-ditions except that each set was per-formed with a different acid. Thesethree sets constitute the basic data set

for comparison and evaluation of acidtype and contact time.

Acid Type. For all contact times, theemulsified acid results in the lowestconductivity at all closure stresses. Theviscoelastic-diverting-acid and poly-mer-gelled-acid systems compete forhighest created conductivity, depend-ing on contact time and closure stress.

For a 15-minute contact time, the vis-coelastic diverting acid yielded the high-est conductivity at all closure stresses.

This can be explained from the etchingpattern, which shows a narrow-channeldevelopment with greater roughnessthan the other acid systems. The otheracid types dissolved less rock and thuscreated less conductivity.

However, at the 30- and 60-minutecontact times the polymer-gelled-acidsystem created a rougher etching patternwith a narrow channel, while the visco-elastic-diverting-acid system etched thesurface too much, resulting in a uniformetching pattern. The embedment strengthof the core acidized with viscoelasticdiverting acid is almost half the strengthof the core acidized with polymer-gelledacid. As a result, for a 30-minute contact,while the initial conductivity of the visco-elastic-diverting-acid system at 1,000-psiclosure stress is higher than that createdby the polymer-gelled acid, at higherclosure stresses, the conductivity of theviscoelastic-diverting-acid system is lessthan the conductivity created by thepolymer-gelled-acid system. Similarly,for a 60-minute acid contact, the poly-mer-gelled acid creates higher conduc-

tivity than the viscoelastic-diverting-acidsystem until the 5,000-psi closure stressis applied. Above this closure stress, therock surfaces acidized by either systemhave been crushed, and essentially allfracture conductivity is lost.

Acid Contact Time. The change infracture conductivity with acid contacttime, and the interrelationship betweencontact time and closure stress, is per-haps the most interesting result of thisstudy. There appears to be a trade-off

between increasing initial (low-closure-stress) conductivity as more rock isdissolved with longer contact times andweakening of the rock surfaces withlonger contact times.

The results for the viscoelastic-divert-ing-acid system gave the clearest indica-tion of this effect. At a low closure stressof 1,000 psi, the conductivity increas-

es gradually with increased acid con-tact time, ranging from approximately17,000 md-ft for the 15-minute-con-tact-time experiment to approximately36,000 md-ft for the 60-minute test. Thisbehavior, conductivity increasing withincreasing amounts of dissolution, is thebehavior predicted by the Nierode-Krukcorrelation. In contrast, at 3,000-psi clo-sure stress, the conductivity declinesfrom more than 12,000 to approximately2,000 md-ft for this same range of con-tact times. The longer acid exposure time

weakens the rock, and surface asperitiesare crushed at 3,000-psi closure stress.With 5,000-psi closure stress, only

the samples that were acidized 15 min-utes maintained any appreciable fractureconductivity. With 30 or 60 minutes ofacid contact time, the rock surfacesapparently are so weakened that thefractures closed almost completely. Thegeneral trend of decreasing rock embed-ment strength with increasing acid con-tact time supports this interpretation.

These results suggest that overtreatingwith an acid exposure time that is toolong may yield lower fracture conduc-tivity than can be obtained with shorteracid contact times, and that this effect ismore important at higher closure stress-es. This could be particularly harmful ifthe near-wellbore part of the fracture,which has the longest acid exposuretime, has relatively low conductivity.However, it is possible that these effectsobserved in small-scale laboratory testscould be overcome by larger-scale chan-nel features created at field scale.

Temperature. Experiments with theemulsified-acid system were conductedat 200 and 275F. Temperature hada profound effect on the conductivitycreated with this acid system; the con-ductivity at 275F was approximately anorder of magnitude higher than at 200Ffor the entire range of closure stresses.Higher temperature resulted in muchmore dissolution and roughness on thefracture face compared with the 200Fexperiments, while rock strength wasonly slightly reduced. JPT


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Compressive Failure. The compres-sive strength of the asperities willdetermine the severity of their fail-ure on fracture permeability. The

reduction in conductivity is a resultof the combined effect of elasticresponse and compressive failureof the asperities. Compressive fail-

Fig. 1Fracture surface before acidizing (above) and after acidizing(below).


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ure also generates rock particles andfines that reduce fracture conductiv-ity further.

Creep. The creep (viscous) effect is aslow, time-dependent displacement.The total displacement obtained fromapplying a constant stress is the sumof two components, displacement

resulting from elastic response andthe creep function. The creep func-tion characterizes the rheologicalproperties of the rock formation andis best described experimentally for agiven stress range, temperature, andlithology. Creep models include theelastic response described by Hookeslaw for Hookean substances (springmodel) and the viscous response forNewtonian substances as describedby a dashpot model. Both of theseeffects act when the reservoir pres-

sure decreases: the elastic displace-ment (spring effect) in response tothe increase in effective closure stress,and a time-dependent displacementfunction (dashpot effect). All visco-elastic models include both effects tosimulate a creep phenomenon.

ExperimentalAn experimental procedure wasdesigned to simulate acid- and prop-pant-fracturing processes using arock-mechanics loading frame. Twotypes of geometry were used that sim-ulate radial- and linear-flow regimes,respectively. Whole core sampleswere selected that were 4 in. in diam-

eter and approximately 4 in. long.A 1/4-in.-diameter hole was drilledin the center so radial flow could beestablished through the rock matrixor through an induced fracture. Then,the sample was cut horizontally intotwo pieces to simulate a fracture. Thesurfaces simulating a fracture wereexposed statically to 15% acid byeither dipping the sample in acid orplacing acid on the surface until nomore chemical reaction was observed.Fig. 1 shows the fracture surface

before and after acidizing. The sam-ple was bound together again withthe same alignment before acidizingby matching two lines drawn on thesample before cutting.

The final geometry of the experi-ment was a vertical wellbore with a

horizontal fracture. The same designwas used for a propped fracture; how-ever, a proppant layer was placed onone surface.

The other sample geometry wascreated by splitting a 4-in. whole coreinto two halves longitudinally. Then,the confining pressure was appliedaround the fractured sample and lin-

ear flow was established to deter-mine the conductivity of an etched orpropped fracture.

Creep Test. A creep test was designedby applying in-situ conditions oftemperature and stress for a givensample. Progressive loads simulatinga stress path imposed on a fractureduring production were applied andmaintained constant as the resultingdeformation was measured. Fractureconductivity was calculated for the

progressively applied stresses todetermine its variation resulting fromelastic, plastic, and viscous effects.

CreepAcid-Fracture Sample Test. A creeptest was designed to study rock defor-


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mation under constant stress as afunction of time. This test simulatesthe in-situ reservoir conditions wherea fracture is exposed to the effectiveminimum horizontal stress. A typi-cal test involves loading the sampleto three progressive stresses: 4,000,6,000, and 8,000 psi. At each stresslevel, the elastic and viscous displace-

ments were measured until a trend wasobtained. The creep profile obtainedsuggests that the sample exhibits pri-mary and secondary creeping phasesbut has not shown any sign of ter-tiary creep. This is expected for such ahigh-Youngs-modulus sample.

Creep Modeling. To model the com-plete creep response (primary andsecondary), Burgers substance wasused to describe the axial strain asa function of time for a sample sub-

jected to constant axial stress. Thismodel includes the instantaneousstrain, transient creep, and steady-state creep. The experimental creepdata for 4,000-psi axial stress werematched by Burgers substance. Themodel clearly illustrates the nonlineartime-dependent behavior.

Fracture WidthFracture width varies significantlybetween acid fracturing and proppantfracturing. Fracture width in acidfracturing is created from the etch-ing mechanism, and upon closing,channels are left open because of thenonsmooth surfaces of the createdfracture. In proppant fracturing, afracture closes on a proppant bedleaving a continuous highly perme-able fracture (not channel) connect-ing the reservoir to a wellbore.

The displacement resulting fromcreep compared to elastic responsebecomes significant with time. Thisdisplacement will not close the frac-ture directly, but it is manifested in

stress applied on the contact points(asperities) in acid fracturing or onthe proppant grains of the proppantpack in proppant fracturing.

ConductivityRock A. To evaluate the effect of elas-tic and creep displacements on fractureconductivity, flow testing was con-ducted with mineral oil. Productionrate decreased from 180 cm3/min toapproximately 20 cm3/min as stressincreased from 1,000 to 4,000 psi. The

stress then was maintained at 4,000 psito evaluate the creep effect overtime. The production rate declinedfrom 20 cm3/min to approximately5 cm3/min after 100 hours.

The creep effect can be less dramat-ic if the fracture can transfer the creepforce through contact points withoutfailure. As closure stress increases,

some contact points fail and a con-tinuous production-rate decline isanticipated. In a propped fracture, thecreep force is transferred if the prop-pant-grain strength is sufficient, oth-erwise proppant crushing occurs. Theeffect of creep on proppant-fractureconductivity was not significant. Forthis formation, a proppant fracturewill sustain well productivity whileacid fracturing will suffer a produc-tion decline with time.

Rock B. This sample was from a dif-ferent formation. The effect of stresson permeability was evaluated for thematrix, tensile fracture, 100-mesh layerof 0.12-in. sand, one layer of 30-meshresin-coated proppant (RCP), and anacid fracture. The permeability of onelayer of 30-mesh RCP decreased dras-tically and extensive fines generationoccurred at a 4,000-psi effective con-fining pressure. This is an importantcriterion to consider when decidingon the proppant type to be usedin a proppant-fracturing treatment.In this formation, the acid fractureexhibited only a small decrease inpermeability as a function of increas-ing stress.

Mechanical Strengthof Fracture SurfaceLong acid-contact time may not bebeneficial to fracture conductivitybecause it can weaken the fracturesurface and make it more vulnerable tocreep and contact-point compressivefailure. It was shown that conductiv-

ity created by a 20-minute acid-con-tact time was higher than that createdby 40-minute contact for both dolo-mite and limestone samples. The acidexposure weakened the rock structurealong the fracture surface, resultingin greater sensitivity to closure stress.The fracture surface becomes moreplastic, and the contact points will failat higher closure stresses. This effectis more pronounced near the wellborebecause that is where the acid-contacttime is the maximum. JPT

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Successful acid stimulation requires amethod to distribute the acid betweenmultiple hydrocarbon zones. Becausealmost all producing wells containsections of varying permeability, thiscan be a problem. Because acid is anaqueous fluid, it tends to enter thezones with the highest water satu-ration. These water zones also are

often the highest-permeability zones,so acid stimulation often will resultin large increases in water produc-tion. The full-length paper describesuse of a new low-viscosity systemthat reduces formation permeabilityto water with little effect on hydro-carbon permeability and also divertsacid from high-permeability zones tolower-permeability zones.

IntroductionIn matrix-acidizing treatments, theacid tends to enter the highest-per-meability layers and bypass the most-damaged (lower-permeability) layers.Various placement techniques havebeen used in attempts to achieveuniform placement of acid across alllayers. The most reliable method usesmechanical isolation devices (suchas straddle packers) that allow injec-tion into individual zones until theentire interval is treated. However,this technique often is not practical,cost-effective, or feasible. Without a

packer, some type of diverting agentmust be used. Typical diverting agentsinclude ball sealers, degradable par-ticulates, viscous fluids, and foams.Although these agents have been usedsuccessfully, all have potential disad-vantages, and none address the prob-

lem of increased water productionthat often follows acid treatments.

One method of controlling waterproduction uses dilute polymersolutions to decrease the effectivepermeability to water more than tooil. These treatments are referred

This article, written by AssistantTechnology Editor Karen Bybee, con-tains highlights of paper SPE 103771,A New Method for Acid StimulationWithout Increasing Water Production:Case Studies From Offshore Mexico,by G.H. Reza, Pemex, and E. Soriano,SPE, L. Eoff, SPE, and D. Dalrymple,SPE,Halliburton, prepared for the 2006SPE International Oil Conference andExhibition, Cancun, Mexico, 31 August2September.

A New Method for Acid Stimulation

Without Increasing Water Production

WELL STIMULATION

Fig. 1(a)Nonmodified-polymer adsorption, (b) hydrophobically modi-fied polymer adsorption, and (c) hydrophobic interactions.



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to as relative permeability modifiers(RPMs), disproportionate-permeabil-ity modifiers, or bullhead treatments.RPM systems are thought to performby adsorption onto the pore walls ofthe formation flow paths.

Previous papers have described thedevelopment of and laboratory stud-ies of an RPM based on a hydro-phobically modified, water-solublepolymer, referred to as an associative

polymer (AP). This group of poly-mers was selected for study becausetheir properties can be altered in waysthat render them valuable for oil-field applications. Another paper hasdescribed a laboratory study of thispolymer for use as an acid diverter.

AP PropertiesThe solution properties of both ionicand nonionic, water-soluble poly-mers are uniquely modified whenhydrophobic groups are introducedinto the polymer chains. The pri-mary factor responsible for the prop-erty modification is the associativetendency between the hydrophobicgroups when placed in an aqueousmedium. Previous testing has showna unique shear-thickening phenom-enon for the AP used in the currentwork. However, the solutions usedin diversion operations show verylow viscosity (less than 2 cp) atsurface conditions.

The adsorption behavior of hydro-philic water-soluble polymers also

can be modified in a unique mannerby the introduction of hydrophobicgroups. Rather than reaching pla-teau adsorption, as is common forhydrophilic polymers, hydrophobicmodification appears to produce acontinued growth in adsorption withincreased polymer concentration.This behavior is attributed to associa-tive adsorption of polymer chains onpreviously adsorbed layers of poly-mers. Fig. 1 illustrates the adsorptionof a nonmodified and a modified

polymer onto a surface. In general,hydrophobic modification of water-soluble polymers adds new propertieswhile retaining features typical forhydrophilic polymers.

Viscosified or foamed fluids com-monly used for acid diversion canresult in high frictional pressure lossand require special manifolding and/or pumping equipment. The low vis-cosity of the AP diverting system

results in ease of mixing, low-fric-tional pressure losses, and no specialmanifolding or pump requirements.The diversion of aqueous fluids occursonly after the material enters theporous media, whether it is naturallyfractured carbonate/dolomitic rock orsandstone matrix. It is theorized thatthe increased shear encountered uponentering the rock matrix, coupledwith polymer adsorption, results inan apparent viscosity increase thatmay be responsible for the pressureincreases seen during the treatment.

Job ResultsMore than 30 wells have been acidizedwith the AP diversion system in theChuc, Caan, and Pol fields. Thesefields are primarily dolimitic, andthe acid has consisted of hydrochlo-ric/acetic blends formulated specifi-cally to avoid sludging problems.Results from nine of these jobs areshown in Table 1 in the full-lengthpaper. The oil- and water-produc-tion numbers shown are the approxi-

mate values just before and afteracid stimulation.

Without Diverter. Two acid jobswere performed on Well Caan 53.Following the first job in August1999, the water cut began to increase,followed by a decline in the oil rate.A second acid job was performedon a different interval in December2003, again followed by an eventualincrease in the water cut. So, whilethe acid jobs performed on this well


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increased oil production, increases inwater production also were seen.

On Well Caan 51, the interval from12,687 to 12,737 ft showed an increasein water cut in March 2001, with a con-current decrease in oil production. Anacid-stimulation job in September 2003did not increase the oil rate, althoughthe water rate continued to increase.

This interval was isolated, and theinterval from 12,255 to 12,333 ft wasperforated and acid stimulated. Thisresulted in an increase in oil, althoughapproximately 1 year later the water cutalso began to increase rapidly.

On Caan 96, an acid-stimulationtreatment was performed in March2003 and resulted in no increase inoil production. In December 2005, thewater cut on this well began a sharpincrease.

On Well Pol 388, the interval from

13,715 to 13,796 ft was producing2,800 BOPD at approximately 50%water cut in August 1992. The well wasshut in until November 2003, at whichtime the interval from 13,715 to 13,796ft was perforated and acid stimulated.Initial production was appproximately

800 BOPD with 50% water cut, andthese levels were holding steady morethan 2 years later.

In Well Chuc 173, the original per-forated interval began to show an oilproduction decline in mid-2002. InNovember 2005, the interval from14,020 to 14,108 ft was perforated andacidized. While there was an immedi-

ate increase in oil production, therealso was an onset of water production.These results are typical of acid-stimu-lation jobs in the Caan, Pol, and Chucfields. Other diverters were used in thisfield, such as ball sealers and foam,but with no real benefit. Also, becauseof the close proximity of water zonesin many wells, the acid volumes werereduced in an attempt to avoid theonset of water production.

With Diverter. In Well Caan 73A,

the interval from 13,190 to 13,222 ftshowed a sharp increase in water pro-duction in January of 2003, along witha sharp decrease in oil production. Thisinterval was isolated, and the intervalfrom 13,098 to 13,131 ft was perforatedand acidized with the AP diverter. Even

with the close proximity of a water-pro-ducing zone, this interval has producedwater-free for more than 2 years.

In the Chuc 63 well, the ini-tial production was approximately1,000 BOPD, with a 16% water cut.After 1 month, production was approx-imately 1,800 BOPD with the samewater cut. However, less than 1 month

later, oil production dropped dramati-cally. The well was acid stimulated inFebruary 2005 with the AP diverter.The increase in oil production wasexcellent. One year later, the oil produc-tion appeared to be remaining steady atalmost 3,600 BOPD. In addition, ratherthan increasing the water production,the water cut fell from the initial levelof 16% to approximately 4% and alsowas holding steady 1 year later.

In Chuc 192, oil production began todrop rapidly with a concurrent increase

in water production in February 2005.This interval was isolated and a newinterval perforated and acid stimulatedwith the AP diverter. Oil productionincreased along with an approximately2% water cut, which fell to zero withina few months. The increased oil pro-duction with no water has held steadyfor almost 1 year.

Out of nine wells acidized with theAP diverter, the average increase in oilproduction was 231%. In addition, 22%showed a decrease in the water cut fol-lowing the job, and 67% showed nochange in the water cut following thejob. For the five wells acidized withoutthe AP diverter, four showed substantialincreases in water cut following the jobs.In fact, one well went from producing nowater to producing 3,273 BWPD. Also,three of the wells showed decreased oilproduction following the jobs.

Conclusions1. Laboratory tests have shown

that the AP diverter can divert acidfrom predominantly water-saturated

zones to predominantly oil-saturatedzones in both sandstone and carbon-ate lithology.

2. In sandstone and carbonate, theAP diverter can provide acid diver-sion and permanent water-permeabil-ity reduction.

3. Results from the Chuc, Caan,and Pol fields show that use of the APdiverter results in lower water pro-duction and increased oil productioncompared with control wells acidizedwithout the AP diverter. JPT


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The full-length paper presents anoverview of the evolution of openholegravel-packing practices and expe-rience after 200 wells have beencompleted successfully with this tech-nique in the Campos basin. A com-prehensive description of the mainsteps taken to improve horizontal-openhole gravel-packing (HOHGP)

practices in unconsolidated oil-bear-ing turbidites is presented. Since thefirst HOHGP job in 1988, comple-tions have moved progressively fromshallow- to ultradeepwater scenarios.Along this path, a series of innovationshas been incorporated into the sand-face-completion practices.

IntroductionThe most prolific reservoirs in theCampos basin are the Upper Cretaceousand Tertiary turbidites. The high-per-meability (approximately 1,000 to8,000 md) stacked and amalgamatedreservoirs are spread over shallow, deep,and ultradeep water within the basin.Dictated by the depositional modelassociated with turbidites, the sand uni-formity of these poorly- or unconsoli-dated sand lenses varies significantly.The presence of reactive-shale streaksis recurrent in some of these turbi-

dites. As in many other offshore basinsin the world, the first oil discoveries(early in the 1980s) were in shallowwaters. These good exploratory resultspropelled the move progressively fromshallow to ultradeep water. However,since the original oil discoveries, it hasbeen realized that a sand-managementstrategy was necessary to achieve desir-

able production levels.Sand control is an umbrella termcomprising different approaches todealing with sand-production prob-lems. Sand-control methods includefrac pack, chemical consolidation,screens, and gravel packing. ThePetrobras philosophy is one of zerotolerance for sand production. Shouldthere be the slightest chance of sandproduction, a sand-control method isinstalled in wells. This preventativeapproach stems from wellbore-integ-rity concerns, prohibitively high well-intervention costs, the need to maxi-mize production rates, safety concerns,and the inability of topside equipmentto handle sand.

Gravel packing is considered the bestalternative for sand control in hori-zontal-openhole wells with good verti-cal permeability, nonuniform sands,and no lamination. In addition, fill-ing the screen/wellbore annulus of anopenhole horizontal well with properlysized gravel creates a secondary bar-rier to the migrating sand grains, thus

increasing the longevity of the gravel-pack screens.

Sand-Control HistoryThe ability to achieve reliable sandcontrol and high completion-effi-ciency indices is the result of a phi-losophy of teamwork that integratesdrilling and completion practices. Useof sand-control advances provided bythe sand-control industry has enabledPetrobras to set the pace in sand-con-

trol and completion practices in deepand ultradeep water. These include useof premium screens and tailor-madedrill-in fluids, application of absolutefiltration standards for completion andgravel-pack fluids, use of improvedwellbore-cleanup procedures, extensiveuse of core-flow studies to minimizeformation damage by drill-in fluid,

optimization of bridging-material sizedistribution, use of drillpipe with inter-nal plastic coating to prevent rust frombeing carried to the formation face,achieving a better understanding of therock mechanics necessary for horizon-tal-openhole-well construction, use ofstainless-steel gravel-packing pumpingequipment, use of low-density gravel,and use of modern geosteerable tools toreduce wellbore tortuosity and to drillin-gauge wells.

In the early 1980s, only shallow-water cased wells were completed withthe gravel-packing technique. Theachieved completion-efficiency indiceswere quite low and posed a major threatto the economic feasibility of ongoingprojects in deep waters. Because of this,a sensitivity analysis was run to bracketthe effect of different variables on theproduction impairment observed.

Frac Packs. The frac-pack techniquewas the first sand-control option usedto complete vertical and low-angledeviated cased wells with no mechani-

cal restriction and with no gas/oil orwater/oil contacts nearby. As predict-ed by a suite of studies, use of the frac-pack technique in the Marlim field hasproduced completion-efficiency indi-ces as great as 100% in several situa-tions as the result of creating a highlyconductive fracture in the formationthat balances flow restrictions thatoccur in the perforations. However,HOHGP wells have been adopted asthe best-in-class well architecture for

This article, written by Assistant TechnologyEditor Karen Bybee, contains highlightsof paper SPE 106364, The 200th

Horizontal-Openhole Gravel-PackingOperation in Campos Basin: A Milestonein the History of Petrobras CompletionPractices in Ultradeep Waters, by L.C.C.Marques, SPE, L.C.A. Paixo, V.P.Barbosa, M.O. Martins, A. Calderon,

SPE, C.A. Pedroso, SPE, L.H.C.Fernandes, J.A. Melo, C.M. Chagas,

and N.J. Denadai, Petrobras, preparedfor the 2007 SPE European FormationDamage Conference, Scheveningen, TheNetherlands, 30 May1 June.

Horizontal-Openhole Gravel-Packing Operations

in the Campos Basin

WELL STIMULATION


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58 JPT JULY 2007

the newest sand-control projects inthe Campos basin. Because of this, fracpacks have been limited to some veryspecific cased-well applications.

Expandable Sand Screens (ESSs).Since the early 2000s, ESSs have beeninstalled in horizontal-openhole injec-tiors and producers in the Campos

basin. Unexpectedly poor results wereobtained from this initial experience.Premature sand failure occurred inmost of the producers completed withESSs. ESS longevity in producers didnot meet expectations.

Gravel-Packing SimulatorsAlthough gravel placement in hori-zontal wells is a mature technology,the commercially available numericalgravel-packing simulators are empiricaland not fully validated for ultradeep-

water applications where low fracturegradients dictate a narrow operationalwindow. Neither have they been vali-dated for lightweight gravel materialsnor for Newtonian solids-free syntheticfluids used as gravel-carrier fluids.

Improvements are still needed inpressure-behavior analytical tools tosimulate gravel-packing operations. Ifthe appropriate simulation capabili-ties were available, they would enablereal-time decision making and runningpost-job analyses to match the predict-ed pressure-behavior profile with actu-al field measurements. A faster solutioncould be to upgrade existing gravel-packing simulators in such a way as toaccomplish this. Occasionally, down-hole-pressure gauges have been run inthe hole during gravel-packing opera-tions to gather data to calibrate andtune the gravel-packing simulator.

Drill-In Practice ImprovementsOne the keys to achieve damage-freeHOHGP is the correct choice of the drill-in-fluids program. A comprehensive

well-engineered drill-in-fluids programmust consider all the steps between themoment the drill bit tags the pay zoneand the moment at which the solids-laden drill-in fluid is replaced by asolids-free fluid before the gravel-pack-ing operation. An in-house researchprogram was created to investigate theinfluence of different variables on drill-in-fluids performance.

The stability of a horizontal-open-hole well is dependent on maintain-ing an adequate hydrostatic head on

the formation, creating a resistantmudcake on the formation face beingdrilled, and inhibiting shales. In someshallow-water situations, the mudcakemust be able to resist a very high dif-ferential pressure (more than 1,000 psifrom wellbore to formation) and stillhave good leakoff control to preventdeep formation invasion by the par-

ticles. This is particularly importantbecause of the high permeability of theCampos basin turbidites. In addition,the mudcake particles must be sizedto flow through the gravel pack, acrossthe screens, and into the wellborewhen the well is put on stream.

Gravel-Carrier-FluidsFiltration ImprovementsThe importance of clean fluids toprevent in-flow formation damage iswell established. Since the early 1990s,

absolute filtration guidelines wereestablished for gravel-carrier fluids. Aminimum beta ratio of 5,000 (at 2 m)is the filtration-efficiency level stipu-lated for these fluids. Typically, somethousand barrels of filtered brine arespent in the drill-in fluids replacement,wellbore cleanup, and gravel-packingoperations. The offshore logistics ofpreparing such a large volume of fluidposes enormous practical problems.Small rig-pit capacities for ultradeepwater are common. Therefore, it ismore feasible to produce these fluids[saturated sodium chloride (NaCl)brine] in an offshore facility (fluidprocessing plant) and ship them justin time for the operations. Once on therig, the brine then is absolute filtered,blended with chemicals, and eventu-ally diluted with filtered seawater.Good transportation logistics is neces-sary to prevent fluid contaminationand delays.

Drill-In-Fluid ImprovementTailored Drill-In Fluids. The use

of water-based fluids has been a rulein these horizontal-openhole drill-inoperations. These tailor-made fluids arecomposed of an NaCl brine, a shear-thinning biopolymer, a lubricant, aloss-control additive, a biocide, an alka-linizer, a temperature-activated enzymebreaker, and HCl-soluble aragonite par-ticles sized to prevent deep invasion ofthe formation pores.

A current drilling practice in theCampos basin is to drill the 121/4-in.phase with a synthetic oil-based mud

(SOBM) to target. A pilot well is firstdrilled to obtain geological data on thesand layers, thus helping to define thehorizontal-well trajectory. Then, the95/8-in. casing shoe is set and cementedat the top of the uppermost layer ofthe turbidites. Once the 121/4-in. drill-ing phase is finished, all the SOBMis replaced by a water-based drill-in

fluid. The major drawbacks of such afluid-replacement practice are potentialformation damage, complex logistics,and time required.

SOBM for Drill-In Fluids. UsingSOBM to drill the 81/2-in. phase toconstruct a horizontal-openhole wellto be gravel packed presents the fol-lowing advantages over the currentfield practice of replacing this fluidwith a water-based drill-in fluid: supe-rior wellbore stability, better lubricity,

higher rate of penetration, better shaleinhibition, and rig-time optimization.Laboratory experiments and full-scalesimulations were performed to spec-ify the SOBM formulation to drill the81/2-in. phase.

Bottomhole-Pressure ReductionLightweight Gravel. Commerciallyavailable high-permeability syntheticproppants [16/20- and 20/40-mesh,specific gravity (SG) from 2.65 to 2.73]have a good record as a gravel mate-rial in conventional HOHGP opera-tions. Where concerns exist in termsof conventional gravel placementtheexistence of a washed-out zone, a lowfracture gradient, long open hole tobe completed, and fluid-returns prob-lemsuse of lightweight proppant(1.25 SG) as a gravel material haswidened the operational window ofHOHGP operations.

Fluid Returns. Another solution tothe low-fracture-gradient problem wasuse of a new flow path for gravel-car-

rier-fluid returns that resulted in a500-psi pumping-pressure reduction at8 bbl/min. Fluid returns to the surfacewere routed into the flowline instead ofinto the small-diameter chokeline andkill line. Once at the surface, the returnfluid is not diverted to the trip tank tomeasure the flow rate but through aflowmeter installed in the flowline justbefore the gravel-packing operation.Flowmeters that are not affected bysea heave were designed to operate onthese floating rigs. JPT

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