positive reactions in carbonate reservoir...
TRANSCRIPT
28 Oilfield Review
Positive Reactions in Carbonate Reservoir Stimulation
Ealian Al-AnziMajdi Al-Mutawa Kuwait Oil CompanyAhmadi, Kuwait
Nabil Al-Habib Adib Al-MumenSaudi AramcoRas Tanura, Dhahran, Saudi Arabia
Hisham Nasr-El-DinSaudi Aramco Research and DevelopmentDhahran, Saudi Arabia
Oscar AlvaradoVeracruz, Mexico
Mark BradySteve DaviesChris FreddDan FuBernhard LungwitzSugar Land, Texas, USA
Frank ChangRosharon, Texas
Efrain HuidobroPetróleos Mexicanos (PEMEX)Veracruz, Mexico
Mohamed JemmaliMathew SamuelAl-Khobar, Saudi Arabia
Depinder SandhuCairo, Egypt
For help in preparation of this article, thanks to Saad Al-Driweesh, Mohamed Al-Muhareb, Richard Marcinew andMohamed Safwat, Al-Khobar, Saudi Arabia; Salah Al Harthy,Muscat, Oman; Leo Burdylo, Pia-Angela Francini and Zhijun Xiao, Sugar Land, Texas, USA; Keng Seng Chan,Kuala Lumpur, Malaysia; Trevor Hughes and Tim Jones,Cambridge, England; Bipin Jain, Bombay, India; and BruceRieger, Calgary, Alberta.ClearFRAC, FracCADE, InterACT, InTouchSupport.com, MSR (Mud and Silt Remover), NODAL, OilSEEKER, PLT (Production Logging Tool), SDA (Self-Diverting Acid), SXE (SuperX emulsion) and VDA (Viscoelastic DivertingAcid) are marks of Schlumberger.
Carbonate reservoir stimulation has improved significantly with the application
of innovative viscoelastic surfactant chemistry to acidizing. This simple, novel,
nondamaging acid system has been used in both matrix and acid-fracturing
stimulation treatments, and has led to substantial injection and production
increases—in some cases adding millions of dollars of production per month—
in many oil and gas fields worldwide.
Carbonate reservoirs contain about 60% of theworld’s oil reserves and hold huge gas reserves.1
Yet experts believe that over 60% of the oiltrapped in carbonate rocks is not recoveredbecause of factors relating to reservoir hetero-geneity, produced fluid type, drive mechanismsand reservoir management. The quantity oftrapped oil becomes even greater in carbonatereservoirs producing heavy oil—API gravitiesbelow 22°—where untapped reserves exceed70%.2 A considerable percentage of theseresources currently are not accessible becauseof economic and technological barriers.
Limestone and dolomite reservoirs presenttremendous completion, stimulation and production challenges because they commonlycontain thick completion intervals with extremepermeability ranges. Often, they are vertically
and laterally heterogeneous, with natural per-meability barriers, natural fractures and a vastarray of porosity types, from intercrystalline tomassive vugular and cavernous porosity. In thesereservoirs, engineers and geologists know thatthe rock that is penetrated by the drill bit andevaluated through coring and logging may notfully represent the reservoir at a larger scale.
Completion and stimulation engineers mustconsider these complexities during the designstage and when selecting appropriate technolo-gies to optimize production and hydrocarbonrecovery. Carbonate reservoirs are stimulatedusing acid—predominantly hydrochloric acid[HCl]—to create conductive pathways from thereservoir to the wellbore, and to bypass the wellbore region that has been damaged duringdrilling and cementing. Acid-fracturing
1. Akbar M, Vissapragada B, Alghamdi AH, Allen D, Herron M, Carnegie A, Dutta D, Olesen J-R, Chourasiya RD, Logan D, Stief D, Netherwood R,
Russell SD and Saxena K: “A Snapshot of CarbonateReservoir Evaluation,” Oilfield Review 12, no. 4 (Winter 2000/2001): 20–41.
2. Sun SQ and Sloan R: “Quantification of Uncertainty inRecovery Efficiency Predictions: Lessons Learned from250 Mature Carbonate Fields,” paper SPE 84459, pre-sented at the SPE Annual Technical Conference andExhibition, Denver, Colorado, USA, October 5–8, 2003.
3. Skin is the dimensionless factor calculated to determinethe production efficiency of a well by comparing actualconditions with theoretical or ideal conditions. A positiveskin value indicates that some damage or influences are impairing well productivity. A negative skin valueindicates enhanced productivity, typically resulting from stimulation.
Winter 2003/2004 29
techniques are also used in areas where the natural permeability of carbonate reservoirs isinsufficient to promote effective matrix acidstimulations. The goal in carbonate reservoirstimulation is to effectively treat all latent productive zones, reducing formation skin andimproving productivity or injectivity.3
Matrix stimulation is even more complexwhen there are multiple intervals having significantly different permeabilities. High-permeability zones preferentially take the acidand leave zones with lower permeabilityuntreated. These untreated intervals mean lessproduction and lost reserves. This nonuniformstimulation can also lead to high drawdown,
causing early and undesirable gas and water production. For these reasons, acid-divertingtechniques, both mechanical and chemical, havebeen developed and recommended to ensureuniform stimulation of carbonate reservoirs.
However, many placement and performanceproblems complicate the acidizing process. Thisarticle examines the development and use of anew self-diverting acid system based on non-damaging viscoelastic surfactant (VES)technology. Also included is a general discussionof matrix acidizing, acid fracturing and adescription of challenges encountered whenstimulating carbonate reservoirs. Case studiesfrom around the world demonstrate the over-whelming success of this new technology.
Acidizing Is Not BasicAcid stimulation in carbonate rocks involves areaction of hydrochloric acid with the mineralscalcite and dolomite [CaCO3 and CaMg(CO3)2
respectively], producing calcium chloride[CaCl2], carbon dioxide [CO2] and water [H2O]in the case of calcite, and a mixture of magne-sium chloride [MgCl2] and calcium chloride inthe case of dolomite. As live acid is introduced,more CaCO3 dissolves, creating small conductivechannels, called wormholes, which eventuallyform a complex, high-permeability network
(above left). The creation of wormholes can bedescribed by the ratio of the net dissolution rateof the acid to the convective transport of live acidto the wormhole surface, expressed by thedimensionless Damköehler number.4 TheDamköehler number depends on a variety of factors, including the specific rock character-istics, acid-system properties, injection rate and temperature.
Typical matrix treatments often require lowinjection rates, and therefore pure hydrochloricacid cannot be used because rapid acid spending—or consumption—severely limits theacid penetration distance. This causes face dissolution and fails to create a wormhole network long enough to effectively bypass thedamaged zone around the wellbore. For this reason, acid systems often include additives thatdelay, or retard, the acid’s reaction with CaCO3,thus extending the reaction time.
Chemical retardation techniques typicallyinclude emulsification and formation of gels.Depending on the acid concentration and the
pumping environment, an acid-diesel blend, SXE SuperX emulsion for example, can be highlyeffective because it slows reaction times by afactor of 15 to 40 compared with conventionalHCl acid systems.5 The dissolving power—a function of acid strength—of the HCl-baseSXE system, coupled with slower carbonatereaction time—retardation—creates deeperwormholes and makes the emulsion less corro-sive to steel casing and tubing. The corrosionthreat to steel tubulars, especially at highertemperatures, can be reduced further by addinginhibitors to acid systems. Retardation of thereaction and corrosion minimization can also beachieved by using organic acids, but because oftheir cost and lower dissolving capability, theiruse is limited.
Many treatment-design factors must be considered to optimize reaction rate andcleanup, including acid strength, temperature,pressure, leakoff rate and the rock composition.Controlling the acid-reaction rate in the targetformation is critical to the success of acid-stimulation treatments in carbonate reservoirs.The acid system must bypass the damaged zoneto open up reservoir communication to the well-bore but must also minimize damage to tubularsand clean up sufficiently after the acid hasspent. Additives play a key role by limiting fluidloss, minimizing the generation of emulsionsand precipitates, regulating viscosity, decreasingcorrosiveness and improving cleanup.
Even a well-designed matrix-acid fluid system does not guarantee a successful stimula-tion. The stimulation fluid must be properlyplaced in the selected intervals. Acid systemsare generally pumped downhole through the casing or tubing—a technique called
bullheading—or delivered through coiled tubing. In bullheading operations, undesirablepreferential placement of acid into high-permeability zones leaves intervals with lowerpermeability untreated. In some cases, high-permeability water-producing zones take a dis-proportionate amount of acid, increasingundesirable water production and associatedwater-disposal costs.
Mechanical-diversion techniques, such as use of ball sealers or coiled tubing with straddlepackers, are widely used, but may not always be feasible or recommended (above right).6
Mechanical methods are not very effective in thestimulation of long horizontal and extended-reach wells. Conventional chemical-diversionmethods include nitrogen foam, bridging agentslike benzoic acid flakes and crosslinked polymer gels. These methods temporarily plug high-permeability carbonate zones to effectively divertthe treatment fluids to zones of lower perme-ability. Chemical-diversion methods vary ineffectiveness. Sometimes temporary plugsbecome permanent, and the reservoir that was meant to be stimulated becomes damaged,diminishing well productivity.
A common chemical-diversion techniqueuses polymer-base gels. These acid systems usereversible pH triggered crosslinker additives toalter the viscosity of the fluid at critical timesduring an acid treatment. For example, SDASelf-Diverting Acid is a polymer system mixedwith HCl. It initially has a low viscosity to alloweasy pumping, but once this fluid enters a car-bonate formation and when the acid spends, thepolymer crosslinks when the pH reaches 2,increasing its viscosity. The increase in gel vis-cosity restricts further flow of new acid through
30 Oilfield Review
> Conductive wormholes. A mold taken aftermatrix acidizing of calcium carbonate shows anintricate network of wormholes created as theacid dissolved the rock. This network greatlyenhances permeability around the wellbore,providing necessary stimulation in manycarbonate reservoirs.
> Mechanical-diversion methods. Ball sealers—nylon, hard rubber or biodegradable balls—are pumpeddown the well during the stimulation treatment (left). They provide mechanical diversion becausethey preferentially block the perforations taking the highest volume of treatment fluid. Straddle packerscan also be deployed on coiled tubing to isolate the preferred treatment interval (right). In this case,the bottom zone was stimulated first and the packer was moved up to the next zone.
Winter 2003/2004 31
the wormholes, thereby diverting fresh acid tozones with lower permeabilities, and eventuallyto other zones. As the acid continues to dissolvethe rock, pH increases. Once the pH rises toabout 3.5, the gelled acid breaks, reducing theviscosity and enabling fluids to flow back andclean up.
Polymer-base acid systems have severaldrawbacks. Independent studies by Stim-Lab,FRAC TECH Services, L.L.C., Saudi Aramco andother companies have shown that conventionalpolymer-base acid systems obstruct wormholesand could damage the formation.7 Cleanup offractured wells was also systematically studiedusing flowback analysis and showed cleanup atless than 45%.8 Because of a narrow pH window,this crosslinking and breaking phenomenon canbe difficult to control, especially in treatmentswith several stages of different fluids. Moreover,the stability of polymer systems degrades as thebottomhole temperature increases. This instabil-ity hinders proper diversion or, at worst,permanently damages the formation to the pointof preventing flow. Complicating matters evenmore, in sour environments where hydrogen sulfide [H2S] is present, formation damage and scaling problems can occur when metalcrosslinker additives react to precipitate sulfides.
A Unique Fluid EmergesThe potential damaging effects of polymer-basestimulation fluids prompted researchers at the Schlumberger Product Center at Tulsa, Oklahoma, USA, to explore the use of visco-elastic surfactants (VES) in hydraulic-fracturingfluids, leading to the introduction of ClearFRACpolymer-free fracturing fluids in 1997.9 Subse-quent R&D led to the development of VESmolecules tolerant to higher temperatures. In2001, the ClearFRAC HT fluid was introduced toextend the practical operating temperature to275°F [135°C].
More recently, Schlumberger applied VESchemistry to produce a polymer-free acid calledthe VDA Viscoelastic Diverting Acid system. Theviscoelastic-surfactant molecule used in the VDAsystem is made up of a hydrophilic head com-posed of positive quaternary ammonium groups,and a negative carboxylate group with a longhydrophobic tail that is a hydrocarbon chain.While being pumped down the tubing or casing,the VDA fluid system—a blend of HCl, viscoelas-tic surfactant and common additives requiredfor acid treatment—maintains a low viscosity. The amount of acid in the mixture determinesthe system’s initial viscosity (above right).
> VDA fluid viscosity response. The mixed HCl concentration largelydetermines the viscosity of the VDA fluid as it is pumped downhole (top).The VDA fluid viscosity decreases when mixed with high concentrations ofacid and is often designed with 20 to 28% HCl, but lower concentrationscan also be used. The reaction of HCl with the carbonate formationincreases pH and provides CaCl2 brine as a reaction product. The brinereacts with the viscoelastic surfactant and viscosifies it (bottom). This in-situ viscosity response effectively diverts new acid to other wormholesand to other zones.
HCl concentration, weight %0 5 10 15 20 25 30
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4. Fredd CN and Fogler HS: “Optimum Conditions for Wormhole Formation in Carbonate Porous Media: Influence of Transport and Reaction,” paper SPE 56995, SPE Journal 4, no. 3 (September 1999): 196–205.
5. Samuel M and Sengul M: “Stimulate the Flow,” MiddleEast & Asia Reservoir Review no. 3 (2003): 40–53.Li Y, Sullivan RB, de Rozieres J, Gaz GL and Hinkel JJ:“An Overview of Current Acid Fracturing Technology with Recent Implications for Emulsified Acids,” paperSPE 26581, presented at the 68th SPE Annual TechnicalConference and Exhibition, Houston, Texas, USA, October 3–6, 1993.Al-Anazi HA, Nasr-El-Din HA and Mohamed SK: “Stimulation of Tight Carbonate Reservoirs Using Acid-in-Diesel Emulsions: Field Application,” paper SPE 39418, presented at the SPE International Symposium on Formation Damage Control, Lafayette,Louisiana, USA, February 18–19, 1998.Navarrete RC, Holms BA, McConnell SB and Linton DE:“Emulsified Acid Enhances Well Production in High-Temperature Carbonate Formations,” paper SPE 50612,presented at the SPE European Petroleum Conference,The Hague, The Netherlands, October 20–22, 1998.
6. Samuel and Sengul, reference 5.7. Nasr-El-Din HA, Taylor KC and Al-Hajji HH: “Propagation
of Cross-Linkers Used in In-Situ Gelled Acids in Carbonate Reservoirs,” paper SPE 75257, presented atthe 13th SPE/DOE Symposium on Improved Oil Recovery,Tulsa, Oklahoma, USA, April 13–17, 2002.Taylor KC and Nasr-El-Din HA: "Laboratory Evaluation ofIn-Situ Gelled Acids in Carbonate Reservoirs," SPEJournal 8, no. 4 (December 2003): 426–434.
8. Willberg DM, Card RJ, Britt LK, Samuel M, England KW,Cawiezel KE and Krus H: “Determination of the Effect ofFormation Water on Fracture-Fluid Cleanup Through FieldTesting in the East Texas Cotton Valley,” paper SPE 38620, presented at the SPE Annual Technical Conference andExhibition, San Antonio, Texas, USA, October 5–8, 1997.
9. Samuel M, Card RJ, Nelson EB, Brown JE, Vinod PS,Temple HL, Qu Q and Fu DK: “Polymer-Free Fluids forHydraulic Fracturing,” paper SPE 38622, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, October 5–8, 1997. Chase B, Chmilowski W, Marcinew R, Mitchell C, Dang Y,Krauss K, Nelson E, Lantz T, Parham C and Plummer J:“Clear Fracturing Fluids for Increased Well Productivity,”Oilfield Review 9, no. 3 (Autumn 1997): 20–33.
As the acid is consumed through the reactionwith calcite or dolomite, the surfactant gels. Twofactors trigger the gelation process. When theacid spends, the increased pH allows the surfac-tant molecules to come together and form longstructures called micelles, in which thehydrophilic heads point outward and thehydrophobic tails point inward.10 Dissolution ofCaCO3 in HCl results in the formation of CaCl2
brine, which further stabilizes the worm-likemicelles. The micelles continue to grow longer
and become entangled above a critical concen-tration of the surfactant, forming a meshstructure and producing a highly viscous, elasticgel (top). The increased viscosity of the gel fur-ther reduces flow into existing wormholes andfissures within the treated zones, thereby pro-viding effective in-situ acid diversion tounstimulated, low-permeability and damagedzones. The viscosity of the spent VDA fluid isrelated to several factors, including tempera-ture, and to the initial percentages of both acidand surfactant (above).
After a treatment, the surfactant gel breaksdown on contact with produced oil, condensateand mutual solvent preflush flowback, or whendiluted with produced formation brine duringflowback. During breakdown, the elongatedmicellar structures are reduced to sphericalstructures, and the fluid system attains a low viscosity because the spherical micelles do notentangle. A preflush or postflush solution ofmutual solvent enhances the breakdown of thegelled surfactant and promotes quick cleanup.
32 Oilfield Review
> Micelles in action. The surfactant, which is in the form of monomers in the initial state, is mixed with diluted acid (left). The acid spends in the formation,producing CaCl2 brine. The monomers react with the brine product, creating long worm-like micelles (middle), which eventually form long, entanglednetworks. This mesh of complex micelles increases the viscosity of the surfactant, which effectively diverts new acid to other locations. After thetreatment, produced hydrocarbon or a mutual solvent contacts the long micelles, transforming them into spherical micelles (right). These smaller and less complex micelles cause the fluid to have a dramatically lower viscosity, facilitating complete break and efficient cleanup.
Monomers Worm-like micelle Spherical micelles
Spent acid Hydrocarbon
CaCO3 + 2HCl CaCl2 + CO2 + H2O
> Stimulation with in-situ diversion. The VDA fluid mixed with acid maintains a low viscosity as it is pumped down the well (left). It enters the most permeablezone (light gray) first. As the acid begins to react with the calcite or dolomite in the reservoir rock, the viscoelastic surfactant increases in viscosity. Thehigher viscosity causes new fluid to divert to the next most-permeable zone (medium gray), where the acid stimulates and the surfactant diverts into the nextpermeable zone (dark gray) (center). This process continues until all perforated zones of varying permeability are stimulated. Upon flowback of hydrocarbons(green arrows) or mutual solvent, the viscoelastic surfactant changes its rheology again (right). As long micelles become spherical micelles, the viscositydramatically decreases, allowing complete cleanup during flowback.
Low viscosity High viscosity
Decr
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ng p
erm
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VDA fluid in VDA fluid in Cleanup
Winter 2003/2004 33
The new acid system can be used to stimulatewells that have a bottomhole static temperatureup to 300°F [149°C].
Prior to its first use, the effectiveness of theVDA system in treating carbonate rocks was doc-umented in simultaneous multicore flow tests.11
Schlumberger and Stim-Lab compared severalacid systems for their diversion and retained-permeability characteristics, including straight
hydrochloric acid as a baseline, a polymer-base acid, a foamed acid and the VDA fluid system. The tests showed that the straight acid penetrated only the most permeable core,while the VDA system increased permeability inall cores because it successfully diverted acid tothe lower-permeability cores. Computed tomo-graphic (CT) cross-sectional imaging employedat each inch along the length of the cores
demonstrated the changes in pore structure dueto acidizing (above).
10. A micelle is a colloidal droplet in which the internalphase of the droplet has an opposite affinity for waterthan is present in the external phase. The bounding layerhas both hydrophobic and hydrophilic ends.
11. Chang F, Qu Q and Frenier W: “A Novel Self-Diverting-Acid Developed for Matrix Stimulation of Carbonate Reservoirs,” paper SPE 65033, presented atthe SPE International Symposium on Oilfield Chemistry,Houston, Texas, USA, February 13–16, 2001.
> Multicore testing. Several acid systems were tested for diversion effectiveness at 150°F [67°C]. Each test involvedthe simultaneous treatment of three cores of different initial permeabilities, while measuring the pressure dropacross the parallel assembly of cores. After a core-flow test, a computed tomographic (CT) cross-sectional image ofthe core was obtained at each inch along the length of the cores to assess the changes in pore structure caused byacidizing. Pressure-profile behavior, as a function of pore volume, was plotted for each test to show fluid viscositychanges that lead to diversion. Straight 15% hydrochloric acid, used as a baseline, showed enhanced permeability inonly the most permeable Number 1 core (left). The flat pressure profile indicates that no diversion took place. TheVDA fluid system with 15% acid was tested across cores with low initial permeability contrast (middle) and acrosscores with high initial permeability contrast (right). Permeability was enhanced in all cores, and the increasingpressure profile confirmed that effective diversion was taking place. Once the acid penetrates one of the cores, thepressure drop goes to zero. The increase in pressure drop is an indication of diversion, while a reduced pressuredrop indicates stimulation.
Pres
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15% Straight HCl
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mD
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% of core
66.5
34.5
32.0
>5000
34.3
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VES-Base In-Situ Gelled Acid
Initialpermeability,
mD
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mD
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% of core
35.0
48.7
32.1
47.2
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74.8
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100
60
VES-Base In-Situ Gelled Acid
Initialpermeability,
mD
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% of core
39.0
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26.8
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Compared with the viscosity of polymer-baseacid, the VDA fluid viscosity remained high asthe acid was consumed, while the polymer gelsbroke down when the pH reached 3.5 to 4.0.Examination of the injection core faces showedthat the cores injected with the VDA fluidremained clean and showed no trace of residue.In contrast, cores treated with the polymer-baseacid system clearly had damaging residue on theinjection face and also inside the wormholes.12
From an operational standpoint, the newVDA fluid can be pumped as a one-stage fluid orcombined with other stimulation fluids in stages,depending on the application. By comparison,polymer-base fluids require several stages ofacid and diverter to achieve the desired stimula-tion and diversion. This can be a significantdisadvantage since the more polymer that ispumped into the formation, the greater the for-mation damage. Moreover, laboratory tests have shown better cleanup of spent VDA fluid as
evidenced by lower flow-initiation pressureswhen subsequently injecting mutual solvent intotest cores.13 The excellent performance of thisVDA system is particularly beneficial in low-pressure oil reservoirs.
The importance of laboratory testing of stimulation fluids cannot be overstated. InSchlumberger, this work is done in local labora-tories around the world, supported by threeClient Support Laboratories (CSLs) located inHouston, Texas, USA; Aberdeen, Scotland; andKuala Lumpur, Malaysia.
Diversion in KuwaitThe new VDA system was first used in the north-ern Kuwait Sabriya field, which is operated bythe Kuwait Oil Company (KOC) (below).14 Thesix lithological units within the multilayeredMauddud carbonate reservoir range in perme-ability from 3 to 600 mD. Perforated intervalsrange between 100 and 200 ft [30 and 60 m] in
total length. Reservoir pressure averages2500 psi [17.2 MPa] and typical well tempera-tures reach 170 to 180°F [77 to 82°C]. Duringmatrix stimulation, high-permeability zonestend to take acid and become further stimu-lated, leaving damaged and low-permeabilityzones untreated. This increases the drawdownwithin a limited distance from the wellbore andcould cause production problems. For this rea-son, uniform stimulation of the entire zone withchemical-diversion fluids is critical for produc-tion optimization.
In the past, acidizing long, heterogeneous car-bonate intervals within the Mauddud formationrequired either foam or chemical diverters, mostcommonly crosslinked polymer systems. Acid concentrations of 15% were used for tubular pickling and formation breakdown, whereas acidconcentrations of only 3 to 5% were used withpolymer-base diverter stages.15 The polymerdiverter fluids were crosslinked either at surfaceor in situ, and usually one stage was pumped foreach of four to five sets of perforations. For eachMauddud interval, acid-treatment volumes variedaccording to the formation characteristics. Zoneswith lower permeability and porosity weretreated with up to 200 gal/ft [2.5 m3/m] of perfo-rations, while zones with higher permeability andporosity were treated with 75 gal/ft [0.9 m3/m].Openhole completions were commonly stimu-lated with 10 to 20 gal/ft [0.1 to 0.2 m3/m]. Aftertreatment, the wells were displaced with dieseland, if required, the fluids were lifted with nitro-gen pumped down coiled tubing.
Early in the field test of the VDA system,reservoir experts from KOC and Schlumbergeridentified several potential wells that wouldbenefit from the new VDA technology. Theseincluded newly drilled wells, underperformingolder wells, horizontal wells with openhole completion intervals, wells with shallow anddepleted reservoirs, and high-pressure, high-temperature (HPHT) wells.
Newly drilled wells in the Sabriya fieldrequired acidizing because drilling damage andlow reservoir pressure limit their ability to flownaturally. Many new wells employ dual comple-tions, with the Mauddud intervals completed onthe short string. These completions discouragethe use of coiled tubing for acidizing becausethere is a risk of getting stuck. Without thecoiled tubing option, bullheading the treatmentsfrom surface is required. Proper chemical diver-sion has been deemed critical for the uniformstimulation of the Mauddud carbonates.
34 Oilfield Review
> The Sabriya field, Kuwait.
Sabriyahfield
KUWAIT
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Winter 2003/2004 35
On new wells requiring bullheaded treat-ments from surface, 15 wt% acid concentrationsare used for both tubing pickling and as an HCl preflush containing a mutual solvent. The VDAtreatments typically contain 15% acid, althoughconcentrations up to 28% HCl have been used.The entire completion interval is treated with50 gal/ft [0.6 m3/m]. After the VDA treatment, a15% HCl overflush containing a mutual solvent isbullheaded and then overdisplaced with diesel.In early wells, a one-to-one ratio of HCl to theVDA treatment volumes was pumped. However,subsequent wells have shown better perfor-mance with higher percentages of VDA fluid.
In Well 5, a new completion, the Mauddudreservoir was completed on the short string, so abullheaded VDA treatment was planned to treatfive different sets of perforations over a 133-ft[41-m] interval. Severe permeability contrastsbetween zones and the strong possibility of for-mation damage due to an earlier loss of 800 bbl[127 m3] of polymer-base drilling fluid necessi-tated exceptional chemical diversion during
stimulation. To monitor the impact of stimula-tion, the operator decided to run prestimulationand poststimulation PLT Production LoggingTool surveys (above). Before the VDA stimula-tion, the PLT log showed that not all theperforations were contributing to production.The well was also producing below the bubble-point of 1800 psi [12.4 MPa] because of high
drawdown pressure, causing gas to come out ofsolution. The flowing wellhead pressure (FWHP)was only 195 psi [1.3 MPa].
After a successful VDA treatment, oil produc-tion increased from 510 to 1760 BOPD [81 to280 m3/d] at an increased FWHP of 750 psi[5.2 MPa], and the PLT log showed all perfora-tions were contributing to production. The
12. Lynn JD and Nasr-El-Din HA: “A Core-Based Comparisonof the Reaction Characteristics of Emulsified and In-SituGelled Acids in Low Permeability, High Temperature, Gas Bearing Carbonates,” paper SPE 65386, presented atthe SPE International Symposium on Oilfield Chemistry,Houston, Texas, USA, February 13–16, 2001.
13. Lungwitz B, Fredd C, Brady M, Miller M, Ali S and Hughes K: “Diversion and Cleanup Studies of Viscoelastic Surfactant-Based Self-Diverting Acid,”paper SPE 86504, presented at the SPE InternationalSymposium and Exhibition on Formation Damage Control,Lafayette, Louisiana, USA, February 18–20, 2004.
14. Al-Mutawa M, Al-Anzi E, Jemmali M and Samuel M:“Polymer-Free Self-Diverting Acid Stimulates KuwaitiWells,” Oil and Gas Journal 100, no. 31 (August 5, 2002):39–42.Al-Mutawa M, Al-Anzi E, Ravula C, Al Jalahmah F, Jemmali M, Samuel E and Samuel M: “Field Cases of a Zero Damaging Stimulation and Diversion Fluid fromthe Carbonate Formations in North Kuwait,” paper SPE 80225, presented at the SPE International Symposium on Oilfield Chemistry, Houston, Texas, USA,February 5–8, 2003.
> PLT Production Logging Tool surveys before and after VDA stimulation. Before the VDA matrix treatment, Well 5 was not producing from all perforations,and maintained a flowing wellhead pressure (FWHP) of only 195 psi [1.3 MPa] (left). After the VDA stimulation, all perforations contributed to production, thewell produced 1760 BOPD [280 m3/d] with no gas, and the FWHP was now 750 [5.2 MPa] (right). The well was producing gas prior to stimulation because ofexcessive pressure drop. After the VDA treatment, the well no longer produced gas because effective stimulation reduced the pressure drop in the well. Inthe PLT displays: Track 1 contains the gamma ray curve for correlation; Track 2 shows the location of perforations; Track 3 displays the volume of producedfluids and the spinner response; and Track 4 shows the PLT measurements, which include fluid density, temperature and downhole pressure.
0 100API
Gamma Ray
7400
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deg F170 173
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Oil Flow
deg F168 173
Temperature0.7 1.2
Fluid Densitygm/cm3
Pressurepsi2700 2900
15. The pickling procedure uses an inhibited acid to removescale, rust and similar deposits from the internal surfacesof equipment such as treating lines, pumping equipmentor the tubing string through which an acid or chemicaltreatment is to be pumped. The pickling process removesmaterials that may react with the main treatment fluid tocreate undesirable secondary reactions or precipitatesdamaging to the near-wellbore reservoir.Nasr-El-Din HA, Al-Mutairi SH and Al-Driweesh SM:“Lessons Learned from Acid Pickle Treatments ofDeep/Sour Gas Wells,” paper SPE 73706, presented atthe SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, USA,February 20–21, 2002.
comparison of well tests, before and after thetreatment, further demonstrated the success ofthe VDA system (right). The prestimulation well-test analysis showed high drawdown pressureand a skin factor of +170, while the post-stimulation well test showed a significantlyreduced pressure drop and a greatly improvedskin factor of –3. Higher downhole pressuresminimized drawdown and eliminated the unde-sired gas production.
Successful treatments in the initial wellsprompted KOC to stimulate Wells 11, 12 and 13on the flanks of the Sabriya field structure.These wells, which produce heavier oil—17 to20°API gravity—had not produced for 6 to10 months.16 Coiled tubing was used when acidiz-ing these three older wells that would notproduce even after initial, and sometimes multiple, conventional acid treatments andnitrogen-lift techniques. These wells contain single-string completions, so coiled tubing oper-ations pose less of a risk. A disadvantage ofpumping conventional acids and divertersthrough coiled tubing was the inherent reduc-tion in pumping rate caused by high frictionlosses because of the smaller tubing diametersand high fluid viscosities. However, as it ispumped down coiled tubing, the VDA system hasdrag-reducing characteristics that significantlyreduce the friction, allowing higher pumpingrates. After the VDA treatments, all three wellsbegan flowing naturally, adding a cumulativeproduction gain of 3280 BOPD [521 m3/d].
Shallow and depleted reservoir zones in theEocene carbonate rocks have been stimulatedwith VDA fluid alone, with 5% mutual solventadded in the postflush, with excellent results.With reservoir pressure down to 400 psi[2.8 MPa], these wells are produced throughsucker-rod pumps. Well 7 was identified as astimulation candidate well because it had anupper zone with extremely high permeability andmultiple lower zones of lower permeability thathad not been stimulated in the past because of alack of acid diversion. A 50-gal/ft treatment of15% VDA fluid was successfully bullheadedthrough a dual packer (next page). When theVDA system is pumped as a single fluid, it entersthe high-permeability zones, stimulates themand then diverts the treatment to lower perme-ability zones. This behavior can be observedrepeatedly on the treatment plot as more zonesare stimulated. Production from Well 7 increaseddramatically, from 300 BOPD [48 m3/d] with awater cut of 11% before the VDA treatment to1300 BOPD [207 m3/d] with a water cut of 15%two months after VDA stimulation.
Another beneficial application of VDA tech-nology for KOC is in HPHT wells wherebottomhole temperatures reach 295°F [146°C]and reservoir pressure is 10,000 psi [69 MPa].Two HPHT wells, Well 14 and Well 17, have beenstimulated with the VDA system. Here, the reservoir is extremely tight, so KOC and Schlumberger have found it beneficial to spotHCl using coiled tubing. Next, a staged treat-ment consisting of a 28% breakdown acid, a 20%VDA fluid and then 28% HCl is bullheaded from
surface. One stage of each has yielded excep-tional results; Well 14 production increased from2760 to 9029 BOPD [439 to 1445 m3/d], andWell 17 production increased from 3140 to5242 BOPD [499 to 833 m3/d] with a substantialincrease in FWHP—from 2914 to 3930 psi [20.1to 27.1 MPa].
The VDA system also proved successful in aKuwait Oil Company horizontal well. Well 13contained a 2000-ft [610-m] horizontal open-hole-completion interval in the Mauddud
36 Oilfield Review
> Buildup tests. Buildup tests conducted before and after the VDAstimulation demonstrate remarkable changes in well productivity. Analysisof the prestimulation buildup data shows a damaged reservoir exhibiting alarge pressure drop and a skin factor of +170 (top). The poststimulationbuildup analysis confirms that the reservoir was successfully stimulated(bottom). The pressure drop had improved significantly, and the skin factorwas –3.
10-2
10-1
100
101
102
Delta
P a
nd d
eriv
ativ
e of
pre
ssur
e, p
si
10-5 10-4 10-3 10-2 10-1 100 101 102 103
Before VDA Treatment
Delta T, hr
Permeability = 44.4 mDSkin = 170
Modeled delta P derivativeModeled delta PMeasured delta P derivativeMeasured delta P
10-2
10-1
100
101
102De
lta P
and
der
ivat
ive
of p
ress
ure,
psi
10-5 10-4 10-3 10-2 10-1 100 101 102 103
After VDA Treatment
Delta T, hr
Permeability = 59.6 mDSkin = –3.1
Modeled delta P derivativeModeled delta PMeasured delta P derivativeMeasured delta P
Winter 2003/2004 37
reservoir and was flowing 1037 BOPD [165 m3/d]naturally at a FWHP of 320 psi [2.2 MPa].NODAL production system analysis before stimu-lation indicated a +10 skin factor, suggestingthat the well had been damaged during drilling.KOC and Schlumberger decided that severalacidizing stages might be needed to effectivelytreat the long openhole interval. The acidizingteam pumped a combination of 10 gal/ft VDAfluid, and 10 gal/ft of 15% regular, emulsifiedacid, or HCl containing additives to combat high mud and silt percentages. Ultimately, onlytwo stages were required to reach the desiredproductivity. A production test conducted afterthe VDA stimulation showed a substantial production increase to 3800 BOPD [604 m3/d] ata FWHP of 275 psi [1.9 MPa].
KOC has treated more than 75 wells with thisinnovative fluid. The VDA system’s unique rheo-logical behavior allows for higher pumping ratesfor operations using coiled tubing, while offeringthe superior diversion capability required forbullheading operations in more complex comple-tion scenarios. It uses less equipment for mixingand fewer chemicals at the wellsite, and requiresno crosslinkers that can lead to damaging precip-itates in the reservoir. Quality assurance andquality control on location were also easier andreproducible when using the new fluid. The eco-nomic impact of viscoelastic surfactanttechnology is immense; on the first 10 VDA wells
alone, KOC realized an additional $4.4 millionper month in oil revenues above that expectedusing conventional technology.
A Summary of Saudi SuccessesSaudi Aramco started moving from polymer-basestimulation fluids to VES alternatives in 2001with the introduction of OilSEEKER acid divertertechnology. A significant shift towards the non-damaging VDA system has similarly occurred incarbonate reservoir stimulation. Saudi Aramcohas successfully used VES fluids in numerousstimulation applications, including matrix acidiz-ing and diversion in production wells andwater-injection wells, and acid fracturing inHPHT gas wells and water-injection wells.17
Conventional matrix stimulation of carbon-ate reservoirs in Saudi Arabia used crosslinkedgelled and emulsified acid systems. Unfortu-nately, iron-control agents do not prevent theprecipitation of iron sulfides in sour environ-ments—those containing H2S.18 Interested inways to improve diversion, lessen damage andincrease production, Saudi Aramco decided totest the VDA system on matrix-stimulation wellsunder challenging conditions.
Some candidate wells for VDA matrix stimu-lation were long horizontal wells with openholehorizontal sections ranging from 1500 to 6000 ft[460 to 1830 m] and temperatures approaching250°F [120°C]. In many cases, there were seri-ous concerns about a water zone immediately
below the targeted horizontal section, makingproper diversion extremely important for reduc-ing or eliminating water production. On theextended-reach wells, coiled tubing was used todeliver the treatment to the reservoir, whichconsisted of VDA surfactant in 20 to 28% HCl anda corrosion inhibitor. In the event that the coiledtubing does not make it to total depth, the VDAtreatment can be bullheaded from the coiledtubing from that point. The lower pumping rateswould still be sufficient to achieve stimulationand diversion of the entire horizontal section.Most of the wells used VDA fluid energized with 30% nitrogen. Treatment rates down coiledtubing remained between 1.0 and 1.5 bbl/min[0.15 to 0.24 m3/min]. The use of nitrogen accelerated cleanup and minimized acid leakoff,provided better coverage and reduced acid-volume requirements.
Saudi Aramco and Schlumberger engineersfound poststimulation production rates of thefirst five VDA wells to be much greater than the
16. Al-Mutawa et al, 2002, reference 14.Lyle D: “Cleaner Wells Produce Cleaner Results,” Hart’s E&P (July 2003): 43.
17. Nasr-El-Din HA, Samuel E and Samuel M: “Application ofa New Class of Surfactants in Stimulation Treatments,”paper SPE 84898, presented at the SPE InternationalImproved Oil Recovery Conference in Asia Pacific, Kuala Lumpur, Malaysia, October 20–21, 2003.
18. Nasr-El-Din et al, reference 7.
> Treatment plot showing pumping rates and bottomhole pressure (BHP) in Well 7. When thebullheaded VDA fluid hits the formation, the bottomhole pressure decreases, indicating stimulation istaking place. When the surfactant viscosifies in the formation, diversion starts, as indicated byincreases in bottomhole pressure. This occurs several times throughout the treatment as indicatedby the pressure (blue) and pump rate (red) curves.
Botto
mho
le p
ress
ure,
psi 1000
200
400
600
800
1200
1400
Set dual packer andstart injecting
1.5
Pum
ping
rate
, bbl
/min
2.0
2.5
1.0
0.5
035
0
Cumulative volume pumped, bbl0 5 10 15 20 25 30
Pumping rateBottomhole pressure
average production from 11 offset wells that were stimulated without the VDA system(top). Water cut in the wells treated with theVDA fluid is much lower than in wells treatedwith other systems, primarily because the highviscosity in water zones is not broken, whereasgel formed in the hydrocarbon zones is brokenand allows the acid to migrate further into thematrix. Therefore, these hydrocarbon-bearingzones are more effectively stimulated and pro-duce higher volumes of oil or gas.
Recently, Saudi Aramco stimulated sevenwater-injection wells using foamed VES fluid asthe diverter system, a combination of 20% HClregular acid and 20% HCl diesel-emulsified acid,and a mutual solvent overflush.19 These injection
wells are crucial for maintaining reservoir pres-sure. The injection zone is 200 ft [60 m] thickand contains widely varying permeabilitystreaks. When stimulating this section withoutproper diversion, all of the acid goes into themost permeable zone and does not treat thedamaged zone and zones with lower permeabil-ity. Treatments have been bullheaded fromsurface or delivered through coiled tubing, andhave improved injectivity when compared withwells treated with a combination of emulsifiedacid and gelled polymer-base acid systems(above). Polymer-base systems also requirecrosslinker and breakers. Furthermore, the VES diversion fluid has eliminated the need toflow back for cleanup because it does not useany polymers.
Acid Fracturing in Saudi ArabiaIn some Saudi Arabian water-injection wells,conventional matrix-acid treatments do not generate the required injection rates, so thesewells need to be acid-fractured.20 An initial padis pumped at pressures exceeding the fracturepressure of the formation; a hydraulic fracture isinitiated and propagated by continuedinjection.21 In conventional hydraulic fracturing,proppant is used to hold the fracture open andto create a conductive pathway for flowback andproduction. However, in carbonate rocks, acid isused to create nonuniform etched patterns onthe fracture surfaces. This gives the fracture sufficient conductivity after closure. In acid frac-turing, the effective hydraulic-fracture length isthat portion of the fracture that has been suffi-ciently etched (next page, top).
To combat fluid leakoff, conventional acid-fracturing treatments use multiple stages ofpolymer and acid. The objective of these systemsis to limit leakoff by increasing fluid viscosity.The increased viscosity and emulsified acidsreduce the rate at which the acid reacts with thecarbonate formation, helping to reduce leakoffand improve fracture geometry. This techniquehas been successful. However, polymers form filter cake that, if left in the fracture, can hinderproduction, especially in tight formations.22
Additionally, crosslinkers function within a nar-row pH range and their behavior can be difficultto predict at high temperatures. They can alsocause precipitates that damage the formation.23
The reactivity of the acid to the rock, whichhelps create a permeable fracture, also promotesundesired fluid loss during pumping. This leakoffnegatively impacts fracture growth and hindersthe creation of wormholes along the length of thefracture.24 There are several ways to limit fluidloss during acid fracturing, including pumpingintermittent viscous pads that deposit filter caketo reduce acid leakoff and using two-phase fluids,such as foams, emulsions and crosslinked gels.These techniques can be effective but can dam-age the permeability of both the formation andthe fracture. The acid can also destabilize com-monly used fluids that are high in pH and canhydrolyze the pad making it less effective. Forthis reason, several large-volume pads arepumped. When using foam, foam-stability problems can negatively impact acid-fracturingoperations, especially in the presence of hydro-carbons at high temperatures.
In Saudi Arabia, the combination of ClearFRAC fluid, emulsified acid, VDA fluid anda mutual solvent has proved to be an effectivetreatment. This combination eliminates the
38 Oilfield Review
> A telling comparison. Production from five VDA treatment wells wascompared with the average production from 11 wells treated withconventional stimulation systems. The five VDA wells showed significantincreases in oil production, with no produced water.
Oil rateWater cut
Oil p
rodu
ctio
n ra
te, B
/D
4000
5000
6000
7000
3000
Wat
er c
ut, %
0
10
20
30
40
1 2 3 4 5
Wells treated with VDA fluidAverage productionfrom 11 offset wells
> Injectivity index comparison of foamed VES fluid versus gelled polymer-base fluids. Throughout the long-term injection history, the injectivityindex—injectivity after stimulation divided by injectivity before stimulation—of the VES fluid treatments remained higher than that of the polymer-basefluids. This finding is directly attributed to improved acid diversion duringthe treatment and to the nondamaging nature of the VDA fluid.
Inje
ctiv
ity in
dex
2.5
3.0
3.5
4.0
2.0
1.5
1.0
0.5
00 1 2 3 4 5 6 7 8
Injection volume, million barrels
Polymer 1Polymer 2VES
Winter 2003/2004 39
operational difficulties of using polymers, pro-vides sufficient leakoff control for optimalfracture creation and does not require flowbackfor cleanup after treating water-injector wells. Apostfracture injectivity test of a vertical injection well showed that the initial injectionrate was 58% higher—29 million B/D [4.6 m3/d]versus 18.4 million B/D [2.9 m3/d]—than themaximum injection rate of a nearby horizontalinjector, both having approximately the samewellhead-injection pressures.25 This operationmarked the first use of the VDA fluid in acidfracturing, producing results that exceededSaudi Aramco expectations.
Saudi Aramco also relies on acid fracturingin vertical HPHT gas wells that exploit thedolomitic Khuff formation at depths from 11,000to 12,000 ft [3350 to 3660 m].26 Bottomhole statictemperatures can reach 280°F [138°C] and theKhuff reservoir produces gas condensate andsometimes up to 10 mol% of H2S. Pressure, temperature and fluid-composition factors substantially complicate stimulation-fluid selection and treatment design.
Khuff reservoir porosity ranges from less than 1 to 25%. Natural fractures make it espe-cially susceptible to leakoff during hydraulicfracturing. Making matters worse, the high temperatures greatly increase acid reactivity.High leakoff rates lower the net pressure in thehydraulic fracture, thereby reducing fractureextension and conductivity, as well as productiv-ity. Another problem in this high-temperatureenvironment is that the acid is more corrosive, sohigher concentrations of inhibitor additives arerequired. Once production starts, condensatebanks can form because of a pressure drop in thenear-wellbore region, lowering the permeabilityto gas. This can be avoided by ensuring that thenear-wellbore region is sufficiently stimulated.
In 2003, Saudi Aramco acid-fractured eightKhuff gas wells using a combination ofcrosslinked gel and new viscoelastic surfactant
technology (above). The pad stage used a high-temperature borate gel to initiate and extendthe hydraulic fracture, with emulsified acid to
19. Safwat M, Nasr-El-Din HA, Dossary K, McClelland K andSamuel M: “Enhancement of Stimulation Treatment ofWater Injection Wells Using a New Polymer-Free Diversion System,” paper SPE 78588, presented at theSPE International Petroleum Exhibition and Conference,Abu Dhabi, UAE, October 13–16, 2002.
20. Al-Muhareb MA, Nasr-El-Din HA, Samuel E, Marcinew R and Samuel M: “Acid Fracturing of Power Water Injectors: A New Field Application UsingPolymer-Free Fluids,” paper SPE 82210, presented at the SPE European Formation Damage Conference, The Hague, The Netherlands, May 13–14, 2003.
21. Pad refers to the fluid used to initiate hydraulic fracturingthat does not contain proppant.
22. Taylor KC and Nasr-El-Din HA: “Laboratory Evaluation of In-Situ Gelled Acids for Carbonate Reservoirs,” paper SPE 71694, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA,September 30–October 3, 2001.
> Acid fracturing in carbonate reservoirs. During an acid-fracturing job, a viscous pad is first pumped at pressures above the fracture-initiation pressureand fractures the rock (left and second from left). Next, an acid stage is pumped to differentially etch the hydraulic fracture (second from right). The acidalso creates conductive wormholes at or near the fracture surfaces, further aiding stimulation (right). After the acid-fracturing operation, the fracturecloses but retains conductivity because of the etching and wormhole creation.
Acid
Acid etches the fracture.Ac
idAcid is pumped into fracture.Rock is hydraulically fractured. Acid creates conductive wormholes.
< Typical acid-fracturingtreatment schedule forHPHT Khuff gas wells.The first few pad stagesincluded high-tempera-ture borate gel to initiateand extend the hydraulicfracture, and then emul-sified acid to etch thefracture. In the finalstages, VDA fluid con-taining 5 to 6% surfactant,was pumped to limit fluidloss and minimize thetotal amount of polymerpumped into the fractureand formation.
FluidStage Pump Rate,bbl/min
Volume,gal
HCl,wt%
Treatment Schedule
40.0
40.0
40.0
45.0
45.0
50.0
50.0
55.0
55.0
60.0
55.0
30.0
25.0
Linear gel
Crosslinkedgel
Crosslinkedgel
Crosslinkedgel
SXE acid
SXE acid
Linear gel
VDA fluid
VDA fluid
VES pad
HCl
Water
Water
1000
9000
20,000
5000
18,000
5000
9000
7000
10,000
13,000
10,000
20,000
12,394
0
0
28
0
28
0
28
0
28
0
28
0
0
Prepad
Pad
Acid-1
Pad-2
Pad-3
Acid-1
Acid-2
Pad-4
Acid-2
Overflush-1
Inhibited acid
Overflush-2
Flush
Taylor KC and Nasr-El-Din HA: “Coreflood Evaluation of In-Situ Gelled Acids,” paper SPE 73707, presented at the SPE International Symposium and Exhibition onFormation Damage Control, Lafayette, Louisiana, USA,February 20–21, 2002.
23. Lynn and Nasr-El-Din, reference 12.Nasr-El-Din et al, reference 7.
24. Samuel and Sengul, reference 5.25. Al-Muhareb et al, reference 20.26. Nasr-El-Din HA, Al-Driweesh S, Al-Muntasheri GA,
Marcinew R, Daniels J and Samuel M: “Acid FracturingHT/HP Gas Wells Using a Novel Surfactant Based FluidSystem,” paper SPE 84516, presented at the SPE AnnualTechnical Conference and Exhibition, Denver, Colorado,USA, October 5–8, 2003.
sufficiently etch the fracture along its length.The viscous borate gel also cooled the formation,controlled leakoff and stabilized the bottomholepressure. Acid pumped after the high pH borategel destabilizes the filter cake and increasesleakoff. To minimize this, acid was followed bygelled fluid that helped finger the next acidstage. Importantly, VDA fluid, containing28% HCl and 5% to 6% surfactant, was pumped inthe final stages when the leakoff became exces-sive. If a leakoff-control acid is not used, at highleakoff rates, the fracture will close and will nottake any more fluid.
Since the operation was performed downtubing, significant steps to pickle the tubingwere taken by pumping HCl across the tubingand connecting lines. This removes pipe dope,corroded iron, corrosion-inhibitor additives andscale from the tubing and connecting lines toensure that only the intended fluids are pumpedinto the formation during acid fracturing.
Prior to designing and pumping the job, theemulsified acid and the VDA fluids were testedin Schlumberger and Saudi Aramco laboratoriesto determine their respective viscosity profilesunder demanding temperature conditions. Laboratory testing determined that both theVDA fluid and emulsified acid could be used inthe Khuff wells. Additionally, a systematic studyon the influence of various additives on the rheology of live and spent VDA system hasrecently been published.27
In the eight Khuff candidate wells, the per-meabilities in the completion intervals variedfrom 0.001 to 2.8 mD and the porosities rangedfrom 0.1 to 15%; typical perforated intervalswere approximately 70 ft [21 m]; reservoir pressures were around 7500 psi [52 MPa]; andfracture gradients ranged from 0.976 to1.06 psi/ft [22 to 24 kPa/m]. Before the acid-fracturing jobs, each well was flow-tested todetermine a prefracture production rate andFWHP. This information was used later to assessthe effectiveness of the stimulation treatments.All wells responded positively to the acid-fracturing treatments, surpassing Saudi Aramcoexpectations (above right). In addition, all of thestimulated wells cleaned up quickly, saving timeand reducing the volume of flared gas before thewells could be put on line.
Normally, because of the high fluid loss whenacid fracturing with conventional systems, thepumping rate needs to increase substantially tokeep the fracture open. However, with the VDA fluid, the leakoff rate is reduced becausethe in-situ viscosification dramatically lowers pump rates and hence horsepower
40 Oilfield Review
> Gas production (top) and flowing wellhead pressures (FWHPs) (bottom)before and after VDA acid-fracturing treatments. In all cases, an increasein gas production rate and FWHP were observed using the new treatments.
W-1 W-2 W-3 W-4 W-5
Wells
PrefracturingPostfracturing
Gas
prod
uctio
n ra
te, M
Mcf
/D
40
20
0
60
80
W-1 W-2 W-3 W-4 W-5
Wells
Flow
ing
wel
lhea
d pr
essu
re, p
sig
3000
2000
0
4000
5000
1000
PrefracturingPostfracturing
> Location of the Matapionche and Mecayucan fields, Veracruz basin, Mexico.
Mexico City
U N I T E D S T A T E S
C E N T R A L A M E R I C A
M E X I C O
Veracruz
Matapionche field
Mecayucan field
300
km0 300
miles0
Winter 2003/2004 41
requirements. The success of these treatmentsin deep, sour HPHT environments demonstratesthe extended operating range of this new fluid.
Acid Fracturing in MexicoPEMEX has employed acid fracturing in the Veracruz basin, Mexico, since 1995 and attributesthe last decade’s increased gas production in thebasin to these techniques. The Veracruz basincovers an area of 18,000 km2 [6950 sq miles] andis located approximately 40 km [25 miles] south-west of Veracruz City (previous page, bottom).Here, attempts to divert treatments using ballsealers and to control leakoff using gelled oil-base pads were frequently unsuccessful. Theintroduction of self-diverting acid containingpolymers improved diversion in 1997, but con-cerns regarding the damaging effects of polymersled to the use of VES technology in 1999.
Now, the combination of the ClearFRAC fluidand the new VDA system provides PEMEX withanother technique to further enhance the
production gains already realized from the acid-fracturing technique in this basin. Fracturingtreatments use three fluids and the steps arerepeated until the designed fracture parametersare achieved.
First, a viscous nonacid ClearFRAC pad initi-ates the hydraulic fracture and creates fracturelength and width. Second, an alcohol-acid stage,containing 20% methanol or isopropanol and80% acid at 15 wt% HCl concentration, etches aportion of the fracture and create wormholes,which eventually lead to the loss of fluid. Third,a VDA fluid stage is pumped to fill the worm-holes. The VDA fluid extends these establishedwormholes far more efficiently because the previously stimulated zones take less fluid, andthe next volume of alcohol-acid is diverted tonew zones. There is evidence from laboratorytests of the Edwards limestone that this fluidalso differentially etches fracture surfaces.28
Using multiple fluids promotes viscous fingeringof the fluids, which alters the path of the acid
and creates differential etching patterns on the fracture surfaces.
This fracture-creation process is repeated.After treatment, a solvent flush or flowback ofhydrocarbons from the reservoir reduces the viscosity of the gelled acid and facilitatescleanup. Because the fracture surfaces are differentially etched, the fracture maintains itsconductivity after the fracture closes.
Within the Veracruz basin, this fracturingdesign has been used by PEMEX in the Matapionche and Mecayucan fields to stimulatethe Orizaba limestone formation. Candidatewells were selected after analysis of bottomholepressure-buildup data to determine reservoirpermeability, reservoir pressure and skin factor,and NODAL analysis to forecast the productionafter acid fracturing. Two wells in the Matapionche field were identified as promisingcandidates for the proposed acid-fracturingtreatment using ClearFRAC fluid, alcohol-acidand VDA fluid.
The first well, the Matapionche Well 2181,was drilled in November 2002 and was subse-quently perforated across three carbonateintervals between 9235 and 9416 ft [2815 and2870 m] and then matrix stimulated. Porosity inthe intervals ranged from 7 to 11% and the reservoir temperature averaged 180°F [82°C].After the stimulation, the well produced1.1 MMcf/D [31,504 m3/d] at a pressure of420 psi [2.9 MPa] on a 1⁄2-in. choke. The well wasnot producing prior to the matrix stimulation.Buildup-test analysis determined an averagepermeability of 0.069 mD, a reservoir pressure of3300 psi [22.8 MPa] and a skin factor of +1, indi-cating that the formation was slightly damaged(top left).
The buildup-test results were then used in aNODAL analysis and produced an inflow performance relationship (IPR) that matchedthe initial production results, verifying the reser-voir parameters.29 Another IPR was constructedthat incorporated the proposed acid-fracturetreatment, in the form of a lower skin factor.This analysis predicted that gas productionwould increase to 3.0 MMcf/D [85,920 m3/d] if askin of –5 were achieved through stimulation(above left).
27. Al-Ghamdi AH, Nasr-El-Din HA, Al-Qahtani AA andSamuel M: “Impact of Acid Additives on the RheologicalProperties of Viscoelastic Surfactants and Their Influence on Field Application,” paper SPE 89418, to be presented at the SPE/DOE Symposium on ImprovedOil Recovery, Tulsa, Oklahoma, USA, April 17–21, 2004.
28. Lungwitz et al, reference 13.29. Inflow performance relationships (IPR) are mathematical
tools used in production engineering to assess well performance by plotting the well production rate againstthe flowing bottomhole pressure (FBHP).
< Buildup-test analysisfrom Matapionche Well2181. The average per-meability was 0.069 mD,reservoir pressure wasmore than 3300 psi[22.8 MPa], and the for-mation was slightlydamaged with a skin of+1. These results wereused in a subsequentNODAL analysis todetermine the likelyeffects of an acid-frac-ture treatment.
10
Elapsed time, hr
1
100
1000
0.01 0.1 1 10 100
Delta
P a
nd d
eriv
ativ
e of
pre
ssur
e, p
si
Modeled delta P derivativeModeled delta PMeasured delta P derivativeMeasured delta P
Permeability = 0.069 mDSkin = 1Pi = 3323.5 psia
> NODAL analysis on Matapionche Well 2181. Using the prestimulationproduction figure, inflow performance relationship (IPR) curves (red) andthe representative tubing intake curve (green), NODAL analysis confirmedthe buildup-test results. It also predicted that the Matapionche Well 2181was capable of producing 3 MMcf/D [85,920 m3/d] of gas if the estimatedpoststimulation skin factor of –5 was achieved (blue curve).
4000
3000
2000
1000
04.03.02.01.00
Pres
sure
, psi
g
Gas production rate, MMcf/D
Inflow aftermatrix stimulation
Inflowat sandface
Predicted inflowafter acid fracturing
Tubing intake curve
Once the Matapionche Well 2181 was selectedas a potential candidate, laboratory tests wereperformed to ensure the proper viscosityresponse of the VDA fluid at both room tempera-ture and the expected bottomhole temperature of180°F. Break tests evaluated the effectivenessand the amount of the mutual solvent proposed inthe design. In this test, gelled VDA fluids at pHvalues of 5 and 6—highly viscous after the acidspends—were mixed with the mutual solvent. Asignificant decrease in viscosity resulted, indicat-ing a quick and effective cleanup would occur inthe reservoir.
The final treatment was designed using localexpertise and input from the SchlumbergerInTouchSupport.com online support and knowl-edge management system. Hydraulic-fracturebehavior was simulated in FracCADE fracturingdesign and evaluation software to optimize thedesign and obtain fracture parameters. The
FracCADE simulation predicted that the optimaljob in this case would yield an etched fracturehalf-length of 61.0 ft [18.6 m], an average etchedfracture width of 0.33 in. [8.4 mm] and an aver-age fracture conductivity around 133,500 mD-ft.
The treatment—16,000 gal [60 m3] of ClearFRAC fluid, 16,000 gal of alcohol-acid and12,500 gal [47 m3] of VDA fluid—was bullheadedthrough 3 1⁄2-in. casing at a rate of 20 bbl/min[3.2 m3/min] (above). Throughout the job, nitrogen was pumped at a constant rate toenhance well cleanup. The acid stages wereradioactively tagged and a postfracture gammaray survey was run to evaluate the effectivenessof the stimulation.
Gas production after the acid-fracturingtreatment exceeded PEMEX expectations; theMatapionche Well 2181 produced 5.2 MMcf/D[148,928 m3/d] at a FWHP of 1420 psi [9.8 MPa]on a 1⁄2-in. choke just after well flowback. Afterone week, the well stabilized to 3.3 MMcf/D
[94,512 m3/d] at 700-psi [4.8-MPa] FWHP,matching the 300% increase seen in the NODAL forecast.
The postfracture gamma ray log showed thatall three zones had been properly stimulated withacid (next page). Well cleanup has exceededexpectations; it is estimated that 70% of the treat-ment volume will be recovered. Another well inthe Matapionche field, Well 1002, experiencedsimilar results using the same methodology andthe new acid-fracturing treatment.
In the Mecayucan field, PEMEX chose twoadjacent candidate wells to acid fracture. On theMecayucan Well 415, the company employed thesame analysis, design and execution techniquesused in the Matapionche field. This well con-tained five intervals of around 7% porosity,making this bullheaded stimulation down 3 1⁄2-in.casing a challenging task. After successful bull-heading of the fracturing treatment, which
42 Oilfield Review
> Matapionche Well 2181 treatment plot. The plot shows the bullheaded acid-fracturing treatment,including the treating pressure (red), the annulus pressure (green) and the pump rate (blue). Stagesincluded a ClearFRAC fluid pad, alcoholic acid and the VDA fluid.
8000
6000
2000
012510585
Pres
sure
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Treatment time, min95 115 135 145 165
4000
Treating pressureAnnulus pressurePump rate
0
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p ra
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in
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10
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25
155
Winter 2003/2004 43
included the VDA fluid for diversion, the wellproduced 2.5 MMcf/D [71,600 m3/d] of gas,matching the NODAL prediction. After the wellstabilized, the well produced 2.0 MMcf/D [57,280m3/d] of gas, a 100% increase in gas production from that recorded after the initialmatrix treatment.
Nearby Well 411, a second candidate well foracid fracturing, contained four intervals to bestimulated, ranging in porosity from 3 to 7%.VDA fluid was not used in this well. After acidfracturing, this well significantly underper-formed against the NODAL prediction, and thepostfracture gamma ray log indicated that onezone was unstimulated and another zone wasunderstimulated, clearly showing that properdiversion was not achieved.
The VDA system has proved highly effectivefor diversion in the Veracruz basin, even whentreatments are bullheaded from surface to multiple zones of varying reservoir quality.
New Life for Egyptian Oil FieldsIn the oil fields of eastern Egypt, much of theproduction comes from heterogeneous dolomiticreservoirs. Commonly, these formations are layered, naturally fractured and mineralogicallycomplex, containing dolomite, calcite, glauconiteand various clays. Reservoir permeabilities arevariable and formation damage caused by drillingand stimulation fluids can be severe. In addition,reservoir temperatures are low—less than 130°F[54°C]—and produced oil is heavy.
Historically, these characteristics have com-plicated conventional stimulation efforts andlimited their effectiveness because conventionalacids are less reactive to low-temperaturedolomite. The use of polymer diversion systems,which use breakers and metal crosslinkers, hasled to reservoir damage and lower productionvolumes. Moreover, iron from tubing can inducepolymers to crosslink prematurely, increasingfriction pressure and thus requiring more horse-power during pumping. Consequently, operatorsin Egypt are investigating new stimulation methods for both new and old wells, and evenwells that have been temporarily abandoned.
The Schlumberger CSL in Kuala Lumpurplayed a key role in the development of a cus-tomized treatment to address the specific
> A postfracture gamma ray log survey on Matapionche Well 2181, showing good acid coverage across all perforated intervals.Acid stages were tagged using antimony, scandium and iridium. Track 1 displays three gamma ray log passes; Tracks 2, 3 and 4show a graphical representation of the wellbore and isotope occurrence; and Tracks 5, 6 and 7 display a breakdown of each ofthe tracer isotopes. Perforated intervals are identified by white ovals.
Scandium
Antimony
Iridium ScandiumAntimony Iridium
Gamma Ray
Gamma Ray Pass 1
Dept
h, m
2850
28000 150API
Gamma Ray Pass 2
0 150API
0 150API
3000 0API
3000 0API
3000 0API
Scandium
Antimony
Iridium
30000 API
30000 API
30000 API
0 3000 0 3000API API 0 3000API
stimulation challenges in this region. First, thecomplicated reservoir mineralogy was definedthrough extensive petrographic studies (below).Next, multiple laboratory tests were performed tooptimize the treatment fluid.
Given the low reservoir temperature, thehigh risk of formation damage and precipitatedevelopment, and the reservoir heterogeneity,an intensified VDA fluid was recommended toprovide the most effective diversion and stimula-tion. Moreover, the high quantity of formationsilt and clay suggested that the MSR Mud andSilt Remover system should be incorporated intothe treatment schedule. The MSR system hasbeen used successfully to disperse drilling-fluiddamage and help in the suspension of formationsilts so that they can be removed from the well-bore. The combined VDA-MSR treatment was thoroughly tested on formation samples andwith different additives at simulated reservoirtemperatures to ensure the optimum chemicaldissolution rate and to minimize formation damage. Heavy-oil samples from the reservoirwere also tested for potential emulsion problems.
The treatment design called for alternatingstages of the MSR and intensified VDA fluids,with each fluid being batch-mixed before pump-ing. Operational challenges were overcomethrough the innovative use of available technolo-gies. For example, a dual-injection technique
was used to treat heavy-oil-producing intervalson dual completion. Other wells producing heavyoil were completed openhole and required a different method to administer the treatment. Inthese cases, the VDA-MSR treatments weredelivered to the reservoir through 11⁄2-in. coiledtubing. The VDA fluid is especially suited forpumping down small tubing since it maintains alow viscosity during pumping and does not viscosify until it reacts with the formation. As aresult, the lower friction pressure made thistechnique feasible.
The VDA-MSR treatments have been per-formed on more than 100 wells with excellentresults. Effective diversion was clearly demon-strated during pumping (next page). The newtechnique has been responsible for an increasein production ranging from 400 to 800%. Thewells clean up faster and production-declinerates are notably slower than with conventionaltreatments. The operator experienced quick pay-back of the stimulation costs, ranging from oneday to just over a month. Most of the treatmentspaid out in less than one week. The overwhelm-ing success of this program is having a sizableimpact on drilling and development plans inEgypt’s eastern desert, and has made VDA tech-nology an important element in the stimulationof new, old, and even abandoned wells.
The Right ChemistryVDA treatment successes have been reportedaround the world. In September 2003, Transmeridian Exploration, Incorporated, Houston, Texas, USA, attributed significantlyhigher rates from their South Alibek 1 well in theCaspian Sea, offshore Kazakhstan, to improvedstimulation and cleanup using the VDA system.This helped bolster the South Alibek field’s esti-mated reserve potential of more than 300 millionbarrels [47.6 million m3].30 In Bahrain, the VDAsystem was used to matrix stimulate dry gasreservoirs in two wells, leading to 82% and 65%increases in gas production rates over the initialrates.31 During 2003, impressive results have alsobeen documented in Canada, Indonesia, UnitedArab Emirates, Pakistan, Venezuela, Russia,West Africa, Tunisia and the USA, including thehighly depleted, low-pressure dry gas reservoirsin the Permian Basin, Austin Chalk and the Gulfof Mexico.
These successes have been the result ofextensive research, uncompromising supportfrom stimulation experts around the globe,Schlumberger CSLs and through the InTouch-Support.com system. Research on carbonatereservoirs continues at Schlumberger-DollResearch in Ridgefield, Connecticut, USA, and atSchlumberger Dhahran Carbonate Research inAl-Khobar, Saudi Arabia, because thorough
44 Oilfield Review
> Photomicrograph of a rock sample. The photomicrograph shows the different types of rockfragments and bioclastic debris in a typical rock sample from a field in eastern Egypt. Knowledge ofthis complex mineralogy was crucial in the design of an optimal treatment at the Client SupportLaboratory in Kuala Lumpur, Malaysia.
Dolomitic limestone
Claystone
Bioclastic fragment
500 µm
Winter 2003/2004 45
knowledge of the reservoir is the first step ineffective stimulation. The knowledge gainedfrom these research activities is exploited everyday at the Schlumberger CSLs and other labora-tories around the world. A vast field-supportnetwork is crucial for proper fluid selection,treatment design and quality control, anddirectly benefits the operating companies thatuse this technology. Real-time monitoring ofstimulation jobs using InterACT real-time monitoring and data delivery from remote locations brings more expertise to the wellsite,facilitating rapid evaluation of both the stimula-tion treatment and the results.
Recent VDA treatments for Rosetta Exploration, Incorporated, in Canada demon-strate the important role of the CSL when wellconditions are harsh and the stakes are high. Ahigh-temperature 4600-m [15,000-ft] deep wellin Canada had failed to produce to expectationsafter a 30,000-liter [7925-gal] energized-acid
treatment. The well was producing at 2 MMcf/D[57,270 m3/d] at 2 MPa [290 psi] FWHP andthen subsequently scaled off. Coiled tubing wasrequired to clear the pyritic scale and to delivera new treatment to the reservoir. Unfortunately,the well was known to contain 22% H2S and 8%carbon dioxide [CO2], making it a difficult envi-ronment for coiled tubing operations. At thisdepth, high temperatures and the combinationof corrosive gases and acid meant the treatmentwould require careful selection of inhibitor addi-tives to ensure a safe and successful treatment.
The CSL in Houston, Texas, working with thecoiled tubing team in Red Deer, Alberta,Canada, determined the optimal combinationand concentration of compatible additives. A21,000-liter [5550-gal] VDA treatment, carefullydesigned by experts, provided sufficient diver-sion at the required low injection rates andsuccessfully stimulated this problematic well.After the VDA treatment, the well produced6.5 MMcf/D [186,160 m3/d] at 7 MPa [1015 psi]FWHP and has now stabilized at a productionrate 50% above the previous rate.
The quest for better stimulation fluids continues. At Schlumberger CambridgeResearch (SCR), new molecules are designedand tested to continue the momentum begun byprevious breakthroughs. Scientists at SCR andthe Sugar Land Product Center continue theirdrive to expand the capabilities of existing fluidsystems and to develop new fluid systems thatovercome current challenges.
The enormous success of the VDA system isdue to the combination of innovative chemistry,far-reaching technical support, uncompromisingquality control during the design and operationstages, and the willingness of operators to applynew technology. This development in carbonatestimulation is making a clear and positiveimpact on production and injection rates, fromthe smallest wormholes to the largest fields.
—MGG
> Pressure versus time plot taken from a well treated with the VDA system. The treating pressureresponse of a typical candidate well treatment shows diversion during treatment.
15% MSR fluidat formation
Spacer (NH4Cl) at formation20% VDA fluid at formation
15% MSR fluidat formation
Circ
ulat
ing
pres
sure
, psi
3000
2500
2000
1500
1000
500
000:01:30 00:39:00 01:16:30 01:54:00 02:31:30
0
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essu
re, p
si
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Treatment time, hr:min:s
Total pump rateTotal pump volumeWellhead pressureCirculation pressure
30. http://www.tmei.com/news/PressRel_03_09_09_Successful_Test.htm (accessed October 14, 2003).
31. Lyle, reference 16.