52 Oilfield Review

Options for High-Temperature Well Stimulation

Salah Al-HarthyHouston, Texas, USA

Oscar A. BustosMathew SamuelJohn StillSugar Land, Texas

Michael J. FullerKuala Lumpur, Malaysia

Nurul Ezalina HamzahPetronas CarigaliKerteh, Terengganu, Malaysia

Mohd Isal Pudin bin IsmailPetronas CarigaliKuala Lumpur, Malaysia

Arthur ParapatKemaman, Terengganu, Malaysia

Oilfield Review Winter 2008/2009: 20, no. 4. Copyright © 2009 Schlumberger.OneSTEP, StimCADE, SXE and Virtual Lab are marks ofSchlumberger.

As wells become deeper and hotter, there is a growing need for high-temperature

matrix acidizing techniques. Newly developed procedures allow acidizing of both

carbonates and sandstones at elevated temperatures. These advances vary from new

chemical agents to simplified fluid-placement techniques.

23810schD8R1.qxp:23810schD8R1 2/25/09 1:55 AM Page 52

Winter 2008/2009 53

Using acids to improve well performance byremoving or bypassing damage has been acommon practice for a long time—nearly as longas the existence of the oil industry itself. In 1895,the Ohio Oil Company used hydrochloric acid[HCl] to treat wells in a limestone formation.Production from these wells increased by severalfold—and unfortunately so did casing corrosion.As a result, acidizing to stimulate productiondisappeared for about 30 years.

Acidizing in limestone reservoirs experienceda rebirth in 1931 with the discovery that arsenicinhibited the corrosive action of HCl on wellboretubulars.1 But acid treatments for sandstonesrequired a different approach. HCl does not reacteasily with minerals that reduce sandstonepermeability, but hydrofluoric acid [HF] does.Early attempts using HF in sandstones failedbecause of plugging from secondary reactions.This problem was overcome in 1940 with acombined HF-HCl treatment. The HF in the acidcombination dissolves mineral deposits insandstones that hinder production, while the HClcontrols precipitates. These acidizing techniqueshave evolved over subsequent years, but the goalhas not changed—create or restore productionpathways close to the wellbore in a new orexisting well.

Well acidizing, more commonly referred to asmatrix acidizing, is one of two interventionmethods used to restore flow in an oil or gasformation. The other route—hydraulic or acidfracturing—creates fractures to allow relativelydistant accumulations of oil and gas to flow to thewellbore. Acidizing works on the formation nearthe wellbore to bypass damage or to dissolve it.The choice of fracturing or acidizing to stimulateproduction depends on a multiplicity of factorsthat include formation geology, productionhistory and intervention goals.

Well-intervention techniques such as matrixacidizing play an important role in helpingoperators produce all they can from their fields.Pressure on acidizing experts to develop newtreating formulations and techniques is comingfrom several directions. One important need isextension of acidizing to high-temperatureenvironments. Use of conventional mineral acidssuch as HCl and HF at higher temperatures—above 93°C [200°F]—leads to reaction rates thatare too rapid. These fast rates cause the acid tobe consumed too early, reducing its effective -ness, and may cause other problems.

Furthermore, as regulations tighten, there is agreater need within the industry for fluids withreduced environmental and safety risks.2

Conventional mineral acids such as HCl and HFare difficult to handle safely, corrosive to well boretubulars and completion equipment, and must beneutralized when returned to the surface.Additionally, as the bottomhole temper atureincreases, corrosion-inhibitor costs rise rapidlybecause of the high concentrations required—particularly with some exotic tubulars currentlyused in well completions. Finally, conventionalsandstone acidizing techniques typically involvemany fluid treatment steps, increasing thepotential for error.

This article will focus on matrix acidizing anddiscuss how this technology has been extendedto higher-temperature environments throughdevelopment of new fluids and techniques. Casestudies from Africa, the USA, the Middle East andAsia demonstrate how these techniques arebeing successfully employed around the world.

Different Formations—Different Acidizing ChemistryThe first consideration in matrix acidizing anyparticular well—high-temperature or not—isformation lithology. Carbonate reservoirs aremostly acid soluble, and acid treatment createshighly branched conductive pathways calledwormholes that can bypass damage. Conversely,in sandstone reservoirs, only a small fraction ofthe rock is acid soluble. The goal of acidtreatment in sandstones is to dissolve variousminerals in the pores to restore or enhance

permeability. The chemistry and physics fortreating both types of reservoir have beenextensively studied and are well-understood.

Carbonate reservoirs—principally limestoneand dolomite—react easily with HCl inmoderate-temperature environments to formwormholes (above). The reaction rate is limitedprimarily by the diffusion of HCl to the formationsurface. Wormholes in carbonate reservoirsincrease production not by removing damage,but by dissolving the rock and creating pathsthrough it.

The formation of wormholes in carbonates isexplained by the manner in which acidizingaffects the rock. Larger pores receive more acid,which increases both their length and volume.Eventually, this extends into a macroscopicchannel, or wormhole, that tends to receive moreacid than the surrounding pores while itpropagates through the rock. The shape anddevelopment of wormholes depend on acid typeas well as its strength, pump rate and temper -ature—plus the lithology of the carbonate.Under the right conditions, worm holes can grow

1. Crowe C, Masmonteil J, Touboul E and Thomas R:“Trends in Matrix Acidizing,” Oilfield Review 4, no. 4(October 1992): 24−40.

2. Hill DG, Dismuke K, Shepherd W, Witt I, Romijn H,Frenier W and Parris M: “Development Practices andAchievements for Reducing the Risk of OilfieldChemicals,” paper SPE 80593, presented at theSPE/EPA/DOE Exploration and Production EnvironmentalConference, San Antonio, Texas, March 10−12, 2003.

> Carbonate acidizing. Limestone and dolomite cores treated with HCldevelop macroscopic channels called wormholes (red). These channelsare the result of the reaction of HCl with the calcium and magnesiumcarbonates in the cores to form water-soluble chloride salts.

Carbonate core

Acidizing in Dolomite: 4HCl + CaMg(CO3)2 MgCl2 + CaCl2 + 2CO2 + 2H2O

Acidizing in Limestone: 2HCl + CaCO3 CaCl2 + CO2 + H2O

23810schD8R1.qxp:23810schD8R1 2/25/09 1:55 AM Page 53

to substantial lengths, resulting in efficient useof acid to bypass damage. In conditions that areless favorable, the acid creates short channelsthat do little to increase production. For anyformation being treated, there is an optimal setof treatment parameters that creates wormholeswith the most efficient use of acid (above).3

In contrast to carbonate formations, thequartz and other minerals that make up mostsandstone reservoirs are largely acid insoluble.Acid treatment for sandstone—HF usuallycombined with HCl—seeks to dissolve thedamaging particulates that block the pores andreduce permeability (below).4 Acidizing in

sandstone targets damage in the first 0.9 to 1.5 m[3 to 5 ft] radially from the wellbore—the areathat experiences the largest pressure drop duringproduction and is critical for flow. This area istypically damaged from migrating fines, swellingclays and scale deposition. Sandstone acidizingreactions occur in areas where acid meetsminerals that can be dissolved. The primarydissolution reactions of the clays and feldsparwith a typical HF-HCl mix form aluminosilicateproducts. Sandstone acidizing chemistry iscomplex, and the initial reaction products canreact further and possibly cause precipitation.These secondary reactions are slow comparedwith the primary dissolution reactions and rarelypresent problems with mineral acids except athigher temperatures (next page, top).

Extension of matrix acidizing to tempera -tures above 93°C presents the operator with bothpossibilities and concerns. The possibilities areobvious—acidizing at higher temperaturesallows stimulation of hot wells using familiarfield procedures. However, at higher tempera -tures, use of HCl causes a host of problems. Incarbonates, the rapid HCl reaction rate atelevated temperature may lead to face attackinstead of wormhole creation and may createacid-induced sludge with high-viscosity crudes.High-temperature problems in sandstones aredifferent. Clay dissolution may be too rapid,decreasing penetration by the acid, andsecondary reactions may cause precipitation.Finally, rapid reaction rates can deconsolidatethe sandstone matrix, creating mobile sand.

Of particular concern in high-temperaturesandstone and carbonate reservoirs is acceleratedcorrosion of tubulars and other wellbore equip -ment. Although increased injection of inhibitorsmay adequately control corrosion rates, thegreater inhibitor loading at higher tempera turesmay itself cause formation damage.5

The challenges of extending matrix acidizingto higher temperatures have led to developmentof new treating fluids and techniques. Treatingfluids include acid-internal emulsions to retardreaction rates in carbonate reservoirs and mild,slightly acidic chemical agents for treating bothcarbonates and sandstones. New techniquesinclude a simplified sandstone-treating systemthat uses laboratory data and predictivesoftware—in combination with new chemicaltreating agents—to arrive at a simplifiedprocedure. These new treatments and tech -niques can be easily understood by examiningsome of the laboratory data that wereinstrumental in their development.

54 Oilfield Review

> Carbonate dissolution patterns. Wormhole structure is related to the efficiency of the acidizingoperation and can be viewed by plotting the number of pore volumes to core breakthrough (PVBT)versus the flow rate. Porosity patterns obtained from a software model calibrated with experimentaldata illustrate how dissolution proceeds with increasing flow rate. The least efficient acidizingoperation is face dissolution—the entire matrix must dissolve in order to advance the reaction front.Slightly more efficient at higher flow rates is the creation of large, conical channels. The mostefficient operation occurs at the curve minimum, with creation of highly dispersed wormholechannels. At even higher flow rates, the curve turns upward and large channels, called ramifiedwormholes, form. Increasing to higher flow rates leads again to uniform face dissolution.

Conical Channels

Face Dissolution

Wormholes

Ramified Wormholes

Face Dissolution

Pore

vol

umes

to c

ore

brea

kthr

ough

Flow rate

1.0

0.2

Poro

sity

> Sandstone matrix. The framework of sandstone reservoirs is typically made up of grains of quartzcemented by overgrowth of carbonates (A), quartz (B) and feldspar (C). Porosity reduction occursfrom pore-filling clays such as kaolinite (D) and pore-lining clays such as illite (E).

A

E

C

B

D

23810schD8R1.qxp:23810schD8R1 2/25/09 1:55 AM Page 54

Winter 2008/2009 55

Laboratory TestingTesting new treatments and techniques in thelaboratory offers many advantages includingsimplicity, cost and avoidance of possibleproblems in the field. Good laboratory data willconfirm treatment models and indicate the rightpath for successful field operations. Properlaboratory testing for acidizing techniques canoptimize treatment volumes and pinpointpotential problem areas as well as confirmtheoretical underpinnings. A strong case in pointis the use of emulsified acids in matrix acidizingof carbonate formations at higher temperatures.

One way to address the problem of fastreaction rates at high temperatures is to useacid-oil emulsions to retard the reaction rate.These emulsions have been applied in both acidfracturing and matrix acidizing of carbonates. Inacid fracturing, the emulsions help enhance andenlarge conductive pathways far from theborehole. Acid fracturing typically employschemical and mechanical diversion techniquesto ensure that the treatment flows to its intendedlocation.6 By contrast, acid-oil emulsions formatrix acidizing are designed to work close tothe borehole and have lower treatment volumesthan those for acid fracturing techniques.

Acid-oil emulsions for matrix acidizing ofcarbonate formations consist of an internal HClphase and an external oil phase. Hydrogen iontransport from the acid droplets to the rocksurface takes place by Brownian diffusion—which dramatically slows the acid reaction rate.7

Laboratory data show that when HCl droplets aresuspended in diesel oil, the reaction rate can beretarded by more than an order of magnitude(right).8 In addition to the slow reaction rate

3. Fredd CN and Fogler HS: “Optimum Conditions forWormhole Formation in Carbonate Porous Media:Influence of Transport and Reaction,” SPE Journal 4, no. 3 (September 1999): 196−205.Panga MKR, Ziauddin M and Balakotaiah V: “Two-ScaleContinuum Model for Simulation of Wormholes inCarbonate Acidization,” AIChE Journal 51, no. 12(December 2005): 3231−3248.

4. Damaging particulates may include native clays andcarbonates or material from drilling and workovers.Damage may also occur from other mechanismsincluding clay swelling, scale, organic deposits,wettability changes and bacterial growth.

5. Van Domelen MS and Jennings AR Jr: “Alternate AcidBlends for HPHT Applications,” paper SPE 30419,presented at the SPE Offshore Europe Conference,Aberdeen, September 5−8, 1995.

6. Zaeff G, Sievert C, Bustos O, Galt A, Stief D, Temple L andRodriguez V: “Recent Acid-Fracturing Practices onStrawn Formation in Terrell County, Texas,” paper SPE107978, presented at the SPE Annual TechnicalConference and Exhibition, Anaheim, California, USA,November 11−14, 2007.

7. Brownian diffusion or motion is the random movement ofparticles suspended in a liquid or gas.

8. Navarette RC, Holmes BA, McConnell SB and Linton DE:“Laboratory, Theoretical and Field Studies of EmulsifiedAcid Treatments in High-Temperature CarbonateFormations,” SPE Production & Facilities 15, no. 2 (May 2000): 96−106.

> Sandstone acidizing reactions. When sandstone formations are treated withHF and HCl, three sets of reactions occur. Close to the wellbore, the primaryreaction of the acids with the minerals forms aluminum and silica fluorides.These reactions rapidly dissolve the minerals and do not yield precipitates.Farther from the wellbore, these primary products undergo slower secondaryreactions to form silica gel, which can precipitate. Finally, at a somewhatgreater distance from the injection zone, a tertiary set of reactions can occur,forming additional silica gel precipitate. The kinetics of the secondary andtertiary precipitation reactions become exponentially more rapid at highertemperatures and may cause sandstone acidizing treatments to fail.

Distance from wellbore

Prim

ary

Seco

ndar

y

Tert

iary

AIFx + mineral AIFy + silica gel ; x > y

HF + mineral + HCl AIFx + H2SiF6

H2SiF6 + mineral + HCl silica gel + AIFx

> Emulsions. Acid-oil emulsions decrease reaction rates by limiting accessof the HCl droplets to the reservoir face. Each droplet contains HCl plusother components such as emulsifiers, corrosion inhibitors and hydrogensulfide [H2S] scavengers (top). The extent to which the emulsion retards thereaction rate can be expressed as the retardation factor, FR. This factor is afunction of the ratio of the reaction rate with HCl to the reaction rate of theemulsion. Laboratory core data on carbonates using 15% and 28% HCl instabilized emulsions show that reaction rates can be retarded by factors of15 to 19 times in the temperature range 250 to 350°F [121 to 177°C] (bottom).(Retardation data adapted from Navarette et al, reference 8.)

250 300 35015

16

17

18

19

20

Reta

rdat

ion

fact

or, F

R

Reservoir face

Diesel

Emulsifier,corrosion inhibitor,H2S scavenger

HCl

HCl,%1528

23810schD8R1.qxp:23810schD8R1 2/25/09 1:55 AM Page 55

with the carbonate rock, acid-in-oil emulsionshave other advantages. Their relatively highviscosity improves distribution in heterogeneousreservoirs, and since the acid does not havedirect contact with well tubulars, corrosion isreduced. Although emulsified acid systems havebeen commonly used for matrix acidizing ofcarbonates below 93°C, laboratory data indicate

that they can be extended to higher tempera -tures if properly formulated.

The Schlumberger acid-oil emulsionformulation—called the SXE-HT system—wasdeveloped for high-temperature acidizing incarbonate reservoirs. It consists of an acid phase,containing a corrosion inhibitor, and a diesel-oilphase with an emulsifier. These two mixtures arecombined at high shear rates to form an oil-external acid emulsion. Laboratory data on thephysical properties of this formulation show lowcorrosion and pitting for a variety of metals, highviscosity retention even up to 177°C [350°F] andgood emulsion stability. For example, a typicalSXE-HT emulsion is stable for at least two hoursat 149°C [300°F], and this stability time can beprolonged by increasing the emulsifier concen -tration. Tests on limestone cores with theSXE-HT fluid at 135°C [275°F] confirm its abilityto create wormholes at typical injection rates.

Use of a properly formulated acid-oil emulsionis one solution for well stimulation at hightemperature. Another approach is to consider acompletely different type of reservoir acidizingfluid. Data confirm that a different class ofchemicals—chelants—allow well stimulation atconditions that preclude the use of mineral acids.

The term chelation is derived from the Greekword meaning claw, and chelants are often usedto bind, sequester or capture other molecules—typically metals. Although these agents have beenused frequently in the past to control metals or insome cases to dissolve scale, their new focus iswell stimulation at elevated temperatures.

The chelants typically used in oilfield servicesare complex organic acids (left).9 Thesecompounds not only bind metals, but also areactive dissolution agents in acidizing reactions.Well stimulation with chelants yields severaladvantages, including retarded reaction rates,low corrosion rates and improved health, safetyand environmental benefits. While chelants such as ethylenediaminetetraacetic acid (EDTA)have been widely used for control of iron precipi -tation, hydroxyaminopolycarboxylic acid (HACA)chelants have the additional advantage of high acid solubility, and their primary role ismatrix acidizing.

The slower reaction rates exhibited by theHACA chelants at high temperatures haveimportant implications. In carbonates, slowerrates allow efficient wormhole creation, while insandstones there is less possibility of damage tosensitive formations. Low corrosion is anotherimportant characteristic of HACA chelants. Forexample, at high temperature, hydroxyethyl -ethylenediaminetriacetic acid (HEDTA) exhibitscorrosion rates up to an order of magnitude lowerthan those of conventional mineral acids (belowleft).10 Significant health and environ mentalbenefits include lower toxicity, reduced need forreturn fluid neutralization and lowerconcentrations of corrosion products in thesefluids. Of all these advantages of HACA chelants,however, the most important may be slowerreaction rates at elevated temperatures.Coreflood testing in carbonates at elevatedtemperatures demon strates the advantage ofusing a chelant rather than HCl to create anefficient wormhole network (next page).11

Another gauge of chelant effectiveness incarbonates versus that of HCl is the amount ofacid required to penetrate a formation—asmeasured by pore volumes to core breakthrough(PVBT). In one simulation that was scaled upfrom laboratory data, PVBT values for HCl andHEDTA were predicted for acidizing a carbonateformation at a depth of 2,185 m [7,170 ft], abottomhole temperature of 177°C, and withdamage that extended 0.3 m [1 ft] from thewellbore.12 At a pump rate of 0.95 m3/min[6 bbl/min], the simulation predicted that thePVBT for HCl was nearly 100 times that forHEDTA—indicating low acidizing efficiency forHCl at high temperature.

As in carbonates, use of HACA chelants insandstones offers a way to avoid the rapidreaction rates that lead to precipitation.Laboratory tests on West African sandstone withan HACA chelant confirm that proposition.

56 Oilfield Review

> Chelants. Typical chelants used in the oil field include both polyaminocarboxylic acids andhydroxyaminopolycarboxylic acids (HACAs). These compounds consist of one to three nitrogen atomssurrounded by either carboxylic [CO2H] groups (EDTA and DTPA) or carboxylic and hydroxyl [HO]groups (HEIDA and HEDTA). Molecular weights range from 177 for HEDTA to 393 for DTPA.

Polyaminocarboxylicacids

Hydroxyaminopolycarboxylicacids (HACAs)

Ethylenediaminetetraacetic acid(EDTA)

HO2C

HO2C

CO2HN N

CO2H

Hydroxyethyliminodiacetic acid(HEIDA)

NHO CO2H

CO2H

Diethylenetraminepentaacetic acid(DTPA)

HO2C N

HO2C

N CO2H

CO2H

N

CO2H

Hydroxyethylethylenediaminetriacetic acid(HEDTA)

CO2H

HO N

HO2C

CO2HN

> Corrosion testing. Four-hour corrosion tests at350˚F were performed on two metallurgies withthree acid-stimulation components—a 20% byvolume sodium HEDTA chelant, a 15% by volumeHCl and a 9-to-1 mud acid (9% by weight HCl to1% by weight HF). Corrosion rates for the chelantare very low at 0.01 lbm/ft2 [0.049 kg/m2] for bothchrome and nickel steels. In contrast, corrosionrates using conventional HCl and HF treatmentsare 5 to 10 times higher for these metals.

HEDTA HCl Mud acid0

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

0.18

Corro

sion

rate

, lbm

/ft2

80 Nickel steel13 Chrome steel

23810schD8R1.qxp:23810schD8R1 2/25/09 1:55 AM Page 56

Winter 2008/2009 57

The Nemba reservoir is one of a group ofproduction zones lying offshore Cabinda,Angola.13 This layered reservoir consists of varyingthicknesses of sandstone, limestone and shales.Although some high-permeability streaks existdue to fissures and fractures, permeabilityelsewhere is low and temperature is high—149°C. The Nemba formation contains high levelsof native calcium carbonate, making theformation particularly difficult to acidize atelevated temperatures without causing decon soli -dation. Prior treatment and workovers in theNemba formation had caused significant damagerelated to carbonate scale. Nemba sandstonesamples represent good candidates for evaluatingthe use of chelants in high-temperature acidizing.

Ten core samples were taken from the Nembafield over a narrow depth interval at about

3,534 m [11,595 ft] and subjected to a variety ofexperiments with an HEDTA chelant. Theseexperiments measured composition, examinedmetals evolution during reaction and determinedpermeability. The composition of the Nemba coresamples ranged from 5% to 44% calciumcarbonate with significant amounts of feldsparand chlorites. Two different procedures wereperformed in the laboratory to determine theresults of HEDTA treatment—slurry reactortests and coreflood permeability tests.

The slurry reactor tests on the Nembasandstone samples used an isothermal, stirredreactor to measure product composition as afunction of time. Powdered sandstone samplescontaining 24% and 44% carbonate levels weretreated in the reactor with HEDTA at 149°C.Samples of the reaction mix were withdrawn over

time and analyzed by inductively coupled plasmaemission spectrometry. For both carbonate levels,the concentrations of calcium, silicon, aluminumand magnesium rose smoothly over time with nodecreases that would indicate precipitation.

The same slurry reactor test was repeated fora 30% carbonate-containing sample using aconventional 9:1 mud acid.14 In this experiment,concentrations of calcium and other componentsshowed an initial rise followed by a decrease—indicating precipitation—a common cause ofsandstone treatment failure. The slurry reactordata on HEDTA suggest that this chelantdissolves the pore-filling and blocking mineralsat high temperature without causing precipi -tation. These positive results for HEDTA werefollowed by coreflood tests at two carbonatelevels. Results from these tests show that the

9. Frenier WW, Wilson D, Crump D and Jones L: “Use ofHighly Acid-Soluble Agents in Well StimulationServices,” paper SPE 63242, presented at the SPEAnnual Technical Conference and Exhibition, Dallas,October 1−4, 2000.

10. Frenier W, Brady M, Al-Harthy S, Aranagath R, Chan KS,Flamant N and Samuel M: “Hot Oil and Gas Wells CanBe Stimulated Without Acids,” paper SPE 86522,

presented at the SPE International Symposium andExhibition on Formation Damage Control, Lafayette,Louisiana, February 18−20, 2004.

11. Frenier et al, reference 9.12. Frenier et al, reference 10.13. Ali S, Ermel E, Clarke J, Fuller MJ, Xiao Z and Malone B:

“Stimulation of High-Temperature Sandstone Formationsfrom West Africa with Chelant Agent-Based Fluids,”

paper SPE 93805, presented at the SPE EuropeanFormation Damage Conference, Scheveningen, The Netherlands, May 25−27, 2005.

14. A conventional 9:1 mud acid is 9% by weight HClcombined with 1% by weight HF.

> Carbonate core tests. A coreflood test was performed on Indiana limestone with 15% HCl at 150°F[65°C]. A photograph of the core face shows dissolution ending in a single dominant wormhole (topleft ). A longitudinal CT scan of this core indicates that this single wormhole extended the entirelength of the sample (top right ). Similar testing was carried out on a limestone sample with HEDTA at350°F and the same flow rate (bottom left ). Use of a chelant resulted in a complex network ofwormholes at the higher temperature level (bottom right ).

CO2H

HO N

HO2C

CO2HN

HCl

23810schD8R1.qxp:23810schD8R1 2/25/09 1:55 AM Page 57

chelant significantly increases permeability inthe damaged cores (left).

In aggregate, the laboratory results oncarbonate and sandstone samples provide anadvance in overcoming problems associated withacidizing in high-temperature environments. Incontemplating the scale-up of laboratory data toactual field operation, treating carbonates repre -sents a more direct extension of the tech nologysince secondary precipitation reactions are notpresent. Complex, multilayer sandstone forma -tions present a more difficult problem since bothcomplicated mineralogy and precipitationreactions must be considered. Job success insandstones can be improved by using a geo -chemical simulator package called Virtual Labsoftware that optimizes stimulation parameters fora variety of fluids and bottomhole conditions (nextpage, left).15

Field results from the application of theseadvances in high-temperature acidizing confirmtheir potential.

Acidizing High-Temperature Carbonate WellsThe carbonate reservoirs of the Smackoverformation, located in the southeastern USA, havebeen prolific producers of oil and gas since theirinitial discoveries in 1937.16 Although interest inthis formation continues, many of the wellsdrilled years ago now require stimulation toboost declining production. High-temperaturegas wells drilled in Alabama Smackover dolomite20 years ago have been acidized with good resultsusing oil-HCl emulsions.17 These retrogradecondensate wells reach a depth of 18,500 ft[5,640 m] and can attain bottomhole tempera -tures of 320°F [160°C] and static bottomholepressures of 2,500 to 4,000 psi [17.2 to 27.6 MPa].The treatment and production history of one ofthese wells illustrates application of retardedemulsions at high temperature in carbonates.

The gas well treated in the AlabamaSmackover field with a retarded oil-HCl emulsionwas drilled and completed in 1986. By 1998, gasand condensate production from the well haddeclined significantly. Prior to treating the wellwith the emulsion, two workover operations wereperformed. First, withdrawal of a chemicalinjection string allowed additional perforations.Next, tubular scale was removed using 15% HCl.This well was then treated with nearly 214 bbl[34 m3] of an HCl-diesel emulsion at a rate of9 bbl/min [1.43 m3/min].18 Immediately aftertreatment with the retarded emulsion, gasproduction more than doubled, with a smaller but

58 Oilfield Review

15. Ali S, Frenier WW, Lecerf B, Ziauddin M, Kotlar HK,Nasr-El-Din HA and Vikane O: “Virtual Testing: The Keyto a Stimulating Process,” Oilfield Review 16, no. 1(Spring 2004): 58−68.

16. “The Smackover Formation,” http://www.visionexploration.com/smackover.htm (accessed October 20, 2008).

17. Navarette et al, reference 8.18. The composition of the emulsion as % by volume was

30% of an HCl solution (20% by weight HCl in water)mixed with 70% diesel oil.

19. Nasr-El-Din HA, Solares JR, Al-Mutairi SH andMahoney MD: “Field Application of Emulsified Acid-Based System to Stimulate Deep, Sour Gas Reservoirs in Saudi Arabia,” paper SPE 71693, presented at the

SPE Annual Technical Conference and Exhibition, New Orleans, September 30−October 3, 2001.

20. Cocoalkylamine is a cationic surfactant that includeshigh concentrations of several long-chain acids thatinclude lauric, myristic, palmitic and caprylic varieties.

21. Nasr-El-Din HA, Al-Dirweesh S and Samuel M:“Development and Field Application of a New, HighlyStable Emulsified Acid,” paper SPE 115926, presented at the SPE Annual Technical Conference and Exhibition,Denver, September 21−24, 2008.

22. Like the cocoalkylamine, tallow amine acetate is acationic mixture of acids. However, this emulsifier haslonger carbon chains and contains some double bonds.

23. Frenier et al, reference 10.

> Sandstone and chelants. Laboratory permeability tests were carried outon Nemba sandstone cores with varying carbonate levels before and aftercoreflood treatment with sodium HEDTA at 149°C (bottom). In the 24%carbonate sample, the chelant increased permeability (k) by a factor of 25.In the 12% carbonate sample, permeability increased by 35%. Samples ofthe cores were photographed using a scanning electron microscope beforeand after treatment with an HEDTA chelant. Before treatment, the sandstoneshows pore blocking as a result of dolomite and chlorite particles in additionto quartz overgrowth. After treatment, the sample shows significant removalof the pore-blocking minerals.

24% carbonatesample

12% carbonatesample

Perm

eabi

lity,

mD

0

1

2

3

4

5

k (final)k (initial)

Pretreatment

Posttreatment

CO2H

HO N

HO2C

CO2HN

23810schD8R1.qxp:23810schD8R1 2/25/09 1:55 AM Page 58

Winter 2008/2009 59

still significant increase in condensate production(right). Two other nearby gas wells were alsotreated with the retarded emulsion and experi -enced similar production increases.

Although acid-oil emulsions have beenemployed for many years, additional focus on thedetails of the technique has yielded significant

improvements. A case in point is their use intreating a group of deep, high-temperature wellsin the Middle East. These wells are located ineastern Saudi Arabia and produce nonassociatedsour gas at a depth of about 3,500 m [11,500 ft].The producing zone lies in the Khuff formationand is composed of dolomite layers intermingledwith limestone. Bottomhole temper atures are inthe range of 127° to 135°C [260° to 275°F].

Stimulation efforts have been conducted on aregular basis by the operator to enhance perme -ability and remove drilling mud damage. Bothstraight HCl and acid-in-diesel emulsions havebeen used for stimulation of gas wells in thisformation with varying results. HCl is an effectivestimulation agent but is highly corrosive at thehigher temperatures encountered in these wells.An acid-oil emulsion was found to be effective inproviding stimulation without corrosion, but fieldapplication showed the need for optimization ofthe emulsifier formulation.19 Work to improve theemulsifier was concentrated on two areas—reduced quantities and improved field operations.

Earlier field tests of acid-in-diesel emulsionsto stimulate wells in the Khuff formation used28% by weight HCl in a 30% by volume acid and70% by volume diesel emulsion. The emulsifierwas a cocoalkylamine at 0.08 to 0.11 m3 [0.48 to 0.71 bbl] per 3.78-m3 [23.8-bbl] emulsionloading.20 The field application showed thatalthough the emulsion was effective atstimulating production, further improvements

were needed. Emulsifier loadings were high, andthe emulsion often broke at ambient conditionsin the field, necessitating remixing and qualitycontrol in the field before use. Both of thesecocoalkylamine emulsifier attributes meantlonger operation times and higher cost.

The operator, therefore, embarked on aprogram to develop and test an improvedemulsion for use in stimulating the deep, high-temperature gas wells in this formation.21 Resultsfrom laboratory testing of more than 10 differentemulsifiers showed that beef-tallow amine acetatewould be more effective than the coco alkyla mineformu lation.22 This new emulsifier could be usedat 25% of the previous loading to make stableemulsions with no remixing at both ambient fieldconditions and high temperatures. In a four-wellpilot campaign, the new tallow amine emulsifierwas successfully employed. Mixing times in thefield were reduced by 25% and poststimulationproduction rates exceeded expectations.

Acid-in-oil emulsions are not the only optionfor hot carbonate well stimulation; chelants canalso be used successfully, as illustrated by a well ina Middle Eastern carbonate reservoir.23 Aftercompletion, the well was not flowing, and drillingmud filtrate damage in the formation wassuspected. Despite the need to stimulate the wellto start production flow, the operator had concernsabout the high bottomhole temperature—110°C[230°F]—and the formation lithology at ameasured depth of 2,620 m [8,600 ft]. At this

> Reaction simulations in sandstone. Virtual Labsoftware is a prediction system that determinesoptimal acidizing parameters for sandstonetreatment. This semiempirical system is based onlaboratory data taken from samples of theformation being considered for treatment. In thefirst step, slurry reactor tests are carried outusing acid and crushed solids (top). Analysis ofeffluent solutions allows determination ofreaction kinetics and identification ofprecipitates. In the second step, coreflood testsdetermine permeability and porosity at reservoirconditions (middle). In the final step, all the dataare combined with radial-flow simulations todetermine the best acidizing treatment (bottom).

Slurry Reactor Tests

Reservoir Coreflood Tests

Radial-Flow Simulations

> Smackover well production history. Gas and condensate production from this well declined steadilyover time reaching levels of 3.4 MMcf/d [96,200 m3/d] of gas and 150 bbl/d [23.8 m3/d] of condensatein August 1997, immediately before treatment. After treatment with an acid-oil emulsion, gas productionincreased to more than 9 MMcf/d [255,000 m3/d] while condensate rose to 200 bbl/d [31.7 m3/d]. Sixmonths after treatment, gas production had fallen off somewhat but was still more than twice thevalue prior to treatment. In the same time period, condensate production fell slightly but retainedmost of the treatment-related production increase.

Gas

prod

uctio

n, M

Mcf

/d

Cond

ensa

te p

rodu

ctio

n, b

bl/d

10

0

1

2

3

4

5

6

7

8

9

0

50

100

150

200

250

300

350

400

450

500

January1996

July1996

January1997

July1997

January1998

GasCondensate

Emulsified-acid treatment

23810schD8R1.qxp:23810schD8R1 3/4/09 4:07 PM Page 59

depth, the limestone-dominated formation hasdolomite streaks containing significant amounts ofentrapped gas. Surface facilities were limited inthe amount of gas that could be handled to agas/oil ratio (GOR) of 440 m3/m3 [2,500 ft3/bbl].Any stimulation to initiate flow in the well had to avoid gas production and keep the GOR below this limit by minimizing stimulation of thedolomite streaks.

A chelant from the HACA family was theobvious choice for the stimulation job. Chelantsin the HACA group exhibit enhanced reactionrates with limestone and more limited reactionwith dolomites—an important factor for thesuccess of this treatment due to the entrappedgas. A treatment plan for this well was developedusing the Schlumberger StimCADE software foracid placement. This plan called for using coiledtubing to place an HACA chelant into a narrowzone of the limestone matrix at 2,620 m. Thesoftware predicted a 1.5-m radial pene tration bythe HACA chelant.

Stimulation treatment was carried outwithout incident. A preflush of a solvent mixedwith water preceded the chelant to aid flowbackby making the formation water-wet. Treatmentpressure averaged 8.3 MPa [1,200 psi], and thechelating injection rate was 0.056 m3/min[0.35 bbl/min]. After treatment was complete,the operator displaced the well with diesel andpulled the coiled tubing. Positive results from thetreatment with the chelant were immediatelyapparent. Oil production increased from theinitial nonflowing state to 96 m3/d [600 bbl/d].This oil production increase was accompanied bya GOR increase of only 264 to 299 m3/m3 [1,500 to1,700 ft3/bbl]—well within the operator’s limits.

Results from these cases confirm thatchelants are useful for stimulation of hotcarbonate reservoirs. This capability is alsopresent for sandstones.

Acidizing High-Temperature Sandstone WellsA West African well drilled in 1984 typifies thechoices an operator must make when confront -ing the need for acidizing a high-temperaturesandstone formation.24 This well, completed at adepth of 2,360 m [7,743 ft] in a deltaic sandstoneformation with 15% carbonates, had a bottomholetemperature of 128°C [263°F]. During a nearly20-year period, oil production had declined from490 m3/d [2,500 bbl/d] to 224 m3/d [1,408 bbl/d]with a corresponding increase in water output.The water, first noted in 1991, had increased to30% by 2003. The effect of the water on comple -tion equipment had been observed during a prior

60 Oilfield Review

> Tiong field. The offshore Tiong field is located 260 km [162 mi] off thecoast of central Malaysia. This sandstone field covers an area of about 20 km2 [7.7 mi2] and, along with nearby Kepong and Bekok fields, producesoil and associated gas (inset bottom). These fields send oil and gas bypipeline to a gathering point at Kerteh on the mainland. From Kerteh, oiland gas are sent by pipeline to Kuala Lumpur, Singapore and otherprocessing facilities (not shown).

Kuala Lumpur

Kerteh

Singapore

Kepong/Tiong/Bekok

MALAYSIA

1000 mi

0 100km

Kepong

Tiong

Bekok

GasOil

> Tiong field stimulation results. The OneSTEP procedure performed on the Tiong well in April 2007had immediate positive results from the chelant treatment. Oil production increased from about 16 m3/d [101 bbl/d] to more than 70 m3/d [440 bbl/d]. Similarly, gas production increased from less than 20,000 m3/d [0.7 MMcf/d] to about 85,000 m3/d [3 MMcf/d].

January 2007 April 2007 June 20070

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

0

10

20

30

40

50

60

70

80

Oil flowGas flow

Gas

flow

, m3 /

d

Oil f

low

, m3 /

d

23810schD8R1.qxp:23810schD8R1 2/25/09 1:55 AM Page 60

Winter 2008/2009 61

well intervention to replace gas lift systemcomponents. The scale deposits on the gas liftmandrels were so severe that a 71-mm [2.8-in.]gauge cutter could not pass below 875 m [2,870 ft].

Faced with concerns about corrosion andpossible damage to the formation using conven -tional acidizing, the operator chose to treat thescale problem with an HACA chelant. Thetreatment goal was to use a mild fluid that wouldremove carbonate scale and not damage thesandstone formation. The well was treated withthe HACA chelant using coiled tubing with arotating jet to spray and soak the areascontaining the gas lift components. Followingtreatment, the fluids used in the operation weredisplaced with water and the gas lift system wasrestarted. A gauge cutter was run through theentire length of the wellbore and encountered noobstructions. After treatment, oil productionincreased to 402 m3/d [2,528 bbl/d], indicatingremoval of scale and possible stimulation of the sandstone.

As illustrated by the treatment in this WestAfrican well, using chelants in sandstones withconventional fluid placement plans is often quiteeffective. Schlumberger has extended the utilityof these new chemicals in sandstones with itsOneSTEP technology. This technology uses aunique chelant fluid and simplified placementtechniques to stimulate production with less riskof damage and precipitates. This fluidsubstantially reduces the number of requiredstages during acidizing. Petronas Carigalirecently employed this technology to stimulateone of its offshore wells in Southeast Asia.

The Tiong field lies off the western coast ofMalaysia in 77 m [253 ft] of water (previous page,top). Discovered in 1978, the field beganproducing oil and gas in 1982. Tiong is asandstone formation with a high bottomholetemperature—109°C [228°F]. After experiencingdeclining production and noting a high skin valuefor the formation, Petronas evaluated severalTiong wells as candidates for acidizingtreatment.25 Tests on core samples from the

candidate wells indicated formation damage fromkaolinite fines and calcite. Petronas selected awell for the acidizing tests and chose theOneSTEP system for its operational simplicityand use of chelants (below).26 This combinationmarries a low risk of secondary and tertiaryreactions that might cause precipitation withfewer fluid stages and simplified logistics. Otherbenefits accrue from low corrosion rates and agood health, safety and environmental footprint.

24. Frenier et al, reference 10.25. Skin is a dimensionless factor calculated to determine

the production efficiency of a well by comparing actualconditions with theoretical or ideal conditions. A positiveskin value indicates some damage or influences that areimpairing well productivity. A negative skin valueindicates enhanced productivity, typically resulting from stimulation.

26. Tuedor FE, Xiao Z, Fuller MJ, Fu D, Salamat G, Davies SNand Lecerf B: “A Breakthrough Fluid Technology inStimulation of Sandstone Reservoirs,” paper SPE 98314,presented at the SPE International Symposium andExhibition on Formation Damage Control, Lafayette,Louisiana, February 15−17, 2006.

> OneSTEP technique. Conventional sandstone acidizing—usually with HF—is a complex processinvolving several pieces of equipment and many sequential steps (left ). As many as six acid tanks andtwo brine tanks may be employed, and five stages with 25 steps may be carried out, depending on thetype of diversion technique. In conventional treatment, brine preflush removes and dilutes acid-incompatible components. Similarly, HCl preflushing removes calcites prior to the main HF treatment. Incontrast, OneSTEP treatment typically uses only two acid storage tanks and one brine tank andrequires significantly fewer treatment steps (right ). This treatment simplicity is a result of twofactors—use of a chelant instead of HF and employment of Virtual Lab predictive software before thejob is started. The chelant eliminates problems with secondary and tertiary reactions, while Virtual Labtesting ensures that any potential problems are addressed before the job begins.

Conventional Fluid Placement

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25Displacement

Stage 1

Stage 2

Stage 3

Stage 4

Stage 5

Brine preflush

Acid preflush

Main treatment

Overflush

Diverter

Brine preflush

Acid preflush

Main treatment

Overflush

Diverter

Brine preflush

Acid preflush

Main treatment

Overflush

Diverter

Brine preflush

Acid preflush

Main treatment

Overflush

Brine

Brine preflush

Acid preflush

Main treatment

Overflush

Diverter

Step Fluid TypeTreatment Stage

1

2

3

4

5

6

7

8

9

10

OneSTEP Fluid Placement

Stage 1

Stage 2

Stage 3

Stage 4

Stage 5

Displacement

Diverter

Brine

Main treatment

Diverter

Main treatment

Diverter

Main treatment

Diverter

Main treatment

Main treatment

Step Fluid TypeTreatment Stage

Prior to carrying out the treatment,Schlumberger calibrated the Virtual Lab modelusing results from well testing before runningsimulations. The well tests determinedformation dissolution kinetics, measuredphysical proper ties of the rock and comparedtreatment options in radial-flow tests. The finalchoice for the treatment fluid at Tiong was achelant plus other additives. With this chelantfluid, the OneSTEP treatment was carried out atthe Tiong well in April 2007. No operationalproblems were encountered and the test wassuccessful—oil production increased by a factorof four and gas production by a similar amount(previous page, bottom).

For Petronas, stimulation of oil and gasproduction was not the only benefit of theOneSTEP technique. This simplified acidizingoperation saves significant rig time, resulting inlower cost. In the Tiong treatment, theoperational time saved was measurable—

23810schD8R1.qxp:23810schD8R1 2/25/09 1:55 AM Page 61

conventional treatment was estimated at 45 hours in contrast to 24 hours for the OneSTEPtechnique—a 21-hour savings. This time savingis a direct result of fewer fluid stages and fasterflowback. Other benefits were also realized. Lessequipment and chemical inventory equates toless deck space required, and fewer chemicalsreduce the operational risks of chemical spillsassociated with handling and lifting.

New Fields—Severe ConditionsGreat strides have been made in acidizing at hightemperature in the past few years. Treatment withacid-oil emulsions and chelants allows operatorsto acidize formations at elevated temperatureswith reduced corrosion rates and less risk ofsecondary damage. As promising as this pictureseems for acidizing, more improve ments intreating agents and procedures will be required tomeet difficult conditions in the future.27

Current world demand for energy is expectedto grow—it is estimated that 40% more energywill be required in 2020 than in 2007.28 As thesearch for new reserves continues, exploration isturning to deeper reservoirs; operations in theUSA illustrate this trend. In 2007, wells deeperthan 15,000 ft [4,572 m] accounted for about 7%of domestic production; this is forecasted to growto 12% in 2010. The deep gas resource beingproduced by this type of well is large and couldbe as high as 29% of production in the future.

One defining characteristic of deeper basinsis that they are hot. Deep gas wells in the Gulf ofMexico and Brazil have average bottomholetemperatures of 204°C [400°F], and even highertemperatures have been reported. To help opera -tors focus on the implications of drilling andoperating deep, hot wells, several classi ficationsystems have been developed.29 Many of thesedeep, hot wells will require matrix acidizing atsome point in their life span, and currenttechnology covers only part of the temperaturerange (above left). This trend toward increasinglyhigher temperatures will demand improvementsin all aspects of acidizing, from corrosion rates totreatment-fluid stability.

In spite of the difficulty in acidizing atextreme conditions, some early successes havebeen reported. For example, a South Americanhigh-pressure, high-temperature sandstone wellwith significant damage was treated with acombination of acetic acid and HF, resulting in adoubling of oil production.30 Keys to success inthis operation at high temperature included amild acid—acetic—associated with HF, andinclusion of a phosphonic acid stabilizer to keepproducts in solution. Another example ofinnovative solutions to acidizing in high-temperature environments is the use of an in situacid system.31 The treatment fluid in this systemcontains an acid precursor that delivers time-controlled release for long-interval wells.

In the final analysis, successful acidizing ofhigh-pressure, high-temperature wells will placegreater demands on both treatment fluids andprocedures. Fluids will be required that havecontrolled reaction rates, low corrosion andacceptable health, safety and environmentalfootprints—chelants are a good example of astep in this direction. In addition to thedevelopment of new fluids, treatments like theOneSTEP technique that emphasize simplicityand minimize operational time will be at apremium. Taken together, future developmentsin both treating fluids and procedures thatemploy them will ensure that matrix acidizingkeeps pace with difficult conditions as new fieldsare developed. —DA

62 Oilfield Review

> Acidizing deep, hot reservoirs. Acidizing withHCl and HF is typically effective at reservoirtemperatures below 200°F, and use of chelantscan extend this temperature range to about400°F. Recent deepwater gas discoveries aregood examples of hot reservoirs and can reachtemperatures of 250 to 550°F [288°C]. Chelantscould be considered for acidizing fields betweenUrsa at 250°F and Egret at 350°F, but to acidizefields above 400°F, such as West Java, Deep Alexand Mobile Bay, new technology will be required.

HCl-H

FCh

elan

ts

200

300

400

500

Stat

ic re

serv

oir t

empe

ratu

re, °

F600

Deep Alex

Mobile BayShearwater

Egret, Heron

E. Cameron, Sable

Asgard

BruneiThunder HorseUrsa

Gulf of Thailand

Khuff

West Java

100

27. DeBruijn G, Skeates C, Greenaway R, Harrison D,Parris M, James S, Mueller F, Ray S, Riding M, Temple L and Wutherich K: “High-Pressure, High-Temperature Technologies,” Oilfield Review 20, no. 3(Autumn 2008): 46−60.

28. Aboud R, Smith K, Forero L and Kalfayan L: “EffectiveMatrix-Acidizing in High Temperature Environments,”paper SPE 109818, presented at the SPE AnnualTechnical Conference and Exhibition, Anaheim,California, November 11−14, 2007.

29. Payne ML, Pattillo PD, Miller RA and Johnston CK:“Advanced Technology Solutions for Next GenerationHPHT Wells,” paper IPTC 11463, presented at theInternational Petroleum Technology Conference, Dubai,December 4−7, 2007.DeBruijn et al, reference 27.

30. Aboud et al, reference 28.31. Al-Otaibi MB, Al-Moajil AM and Nasr-El-Din HA:

“In-Situ Acid System to Clean up Drill-In-Fluid Damage in High-Temperature Gas Wells,” paper SPE 103846,presented at the IADC/SPE Asia Pacific DrillingTechnology Conference and Exhibition, Bangkok,Thailand, November 13−15, 2006.

23810schD8R1.qxp:23810schD8R1 3/4/09 3:17 PM Page 62