the FlowStimulate

Well productivity can be adversely affected byformation damage in the near wellbore or by low natural permeability of the reservoir rock.Damage may be caused by drilling operations or the effects of long-term production. Carbonateminerals dissolve readily in acids, and acidizinghas for years been a method of stimulatingproduction in carbonate reservoirs. MathewSamuel and Mahmut Sengul explain some of the situations that benefit from carbonate wellstimulation, and how techniques such as matrixacidizing and acid fracturing are evolving toensure optimum production and injection.

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T he carbonate reservoirs of the Middle East and Asia contain about

69% of the world’s oil and gas reserves.To sustain global oil and gas demands,the effective stimulation of carbonatereservoirs, therefore, is very important in this region. Moreover, the complexitiesof carbonates that are due to theirheterogeneous structure, includingnatural barriers and fractures, presentsome of the greatest challenges toreservoir stimulation.

For many years, reservoir teamshave sought ways to avoid earlyabandonment of oil and gas wells as a result of formation damage and lownatural permeability in carbonatereservoirs. Such abandonments havecaused incalculable loss of revenueresulting from the hydrocarbons leftbehind. Recovery can often beimproved using stimulation techniquesfor removing or bypassing theformation damage in the near-wellborearea, or by partly increasing theformation’s natural permeability, or, in many cases, both. Formationdamage—plugging or partial pluggingof perforations, or plugging of the rockmatrix by debris from the well andfrom well operations—restricts theflow of hydrocarbons into the wellbore.

Identifying the causes of formationdamage and preventing it fromhappening have been the subjects ofmuch research. Well operations still,however, continue to cause somedegree of damage to the formation in the near-wellbore region.

Thousands of well stimulation jobsare performed in the region everymonth, using treatments that rangefrom pumping hydrochloric acid intothe formation to dissolve and/orfracture the rock, to very advancedtechnologies that use viscoelasticsurfactant-based (VES) fluids to helpacid placement and control leakoff.

Carbonate stimulationThe main objective in carbonatestimulation is to create a conductiveflow path and bypass the damage. Thedissolution of the rock matrix leads to the formation of highly conductiveflow channels, known as wormholes(see boxed article Working withwormholes, page 46). Bypassingformation damage, therefore,

improves connectivity between thewell and the reservoir rock. Thisincreases the well’s productivity orinjectivity index by reducing skin.

Using acid to dissolve the carbonateminerals may also help to remove thedamage that blocks perforations andpores in the near-wellbore area.

Hydrochloric acid is commonly usedfor fracturing and matrix acidizing incarbonate reservoirs. This acid ishighly reactive with carbonates,relatively inexpensive and availableglobally. It can be easily inhibited tominimize damage to tubulars, orreduce surface tension, allowingsubsequent control of penetration,wetting properties and frictionpressure. Most of the reactionproducts of hydrochloric acid andcarbonate are water soluble and areeasily removed. Although hydrochloricacid is considered to be the bestoilfield acid for most applications, thesystem can be very costly, particularlyin high-temperature environmentsthat require additives to controlreaction rates.

Prolonged contact of hydrochloricacid with steel pipe at hightemperatures can cause severecorrosion. In high-temperature wells,effective inhibition can be difficultand costly. Consequently, with theirslower reaction rates, organic acidscan be more effective. They also havelower corrosion potential and areeasier to inhibit at high temperaturesthan hydrochloric acid.

Hydrochloric acid reacts so quicklywith limestone that by the timeplacement is complete, the acid isalready spent, regardless of thedownhole temperature and pressure.Chemical retardants, such asemulsifiers and gelling agents, may be added to extend the reaction time.The damage and various impurities in limestone that are not dissolved by the acid can plug the formation if they are allowed to settle after a

matrix treatment. This means thatthe spent acid must be removedalmost immediately.

The use of SXE* SuperX acid-in-oilemulsion offers significant advantagesover both hydrochloric and organicacids. The SXE system is a 70:30hydrochloric acid:diesel blend,stabilized with an emulsifier.Retardation of SXE systems can be 15 to 40 times greater than that ofconventional hydrochloric acidsystems, depending on temperature,acid concentration, flow regime androck type. The dissolving power ofSXE systems is comparable to thatachieved with regular hydrochloricacid, but creates deeper wormholes,and has much lower corrosion rates.

Organic acids such as acetic, formicor citric are less commonly used incarbonate stimulation because of their high cost and relatively poorperformance in dissolving carbonatematerial at low temperatures. Table 1shows a comparison of the solubility ofcalcium carbonate in different acids.

Other possible treatment fluidsinclude combinations of hydrochloricacid with one or more organic acids.These are sometimes used for acidizing high-temperature carbonateformations. They combine the fracture-face etching power of hydrochloric acidwith the deeper formation penetrationof organic acids. They can be furtheremulsified to get the additional benefitsof SXE systems. However, thesesystems are expensive and requirecareful evaluation before use.

Optimizing acid reaction rates is a key factor in obtaining the desiredeffects on the formation at downholeconditions. Sufficient acidization mustbe achieved without overtreatment,which could cause the collapse of porestructures, and may reduce wellproductivity (Figure 5.1). Acid strength,temperature, pressure (Figure 5.2),pumping rate, leak-off control and rockcomposition are among the factors that

Acid Dissociation Relative solubility constant, Ka, of carbonateat 77°F (lb/1000 gal of acid)

Hydrochloric 10 3500Formic 1.77 x 10-4 700Acetic 1.75 x 10-5 400

Table 5.1: Relativesolubility ofcalcium carbonatein various acids

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influence reaction rates. Additives,especially fluid-loss additives,viscosifiers and surfactants, help to ensure the requisite performanceduring and after spending time.

The type of acid selected for astimulation treatment depends onmany factors, including the severity of the damage, the type of rock, itsnatural permeability and on downholeconditions. A number of options areavailable for acid-stimulationtechniques, including■ wellbore cleanup■ matrix acidizing■ acid fracturing.

Wellbore cleanupDamage, or potential damage toperforations, tubing and the areaimmediate to the wellbore caused byformation fines, mud or cement filtrate,scale and debris from well operationsmay be removed by exposing the wellto acid over a period of time (soaking),followed by some form of agitation.

Acid can be circulated across theopenhole or perforated interval usingcoiled tubing, allowing a short soakingperiod. The coiled tubing string isworked up and down through theinterval, and the spent acid isreturned through the annulus. Asecond method is to apply pressureagainst the perforations, followed byrapid release of pressure by openingthe bleedoff valve at the pumpingunit—a method known as backsurging. This technique is primarilyeffective when the reservoir pressureis greater than the fluid hydrostaticpressure. A further approach involvesspotting acid across the perforationsand swabbing back, either throughtubing or casing.

Matrix acidizing Matrix acid treatments are pumped at pressures lower than the formationparting, or fracturing, pressure toensure removal or bypass of thedamage in the pore spaces and toleave zone barriers intact. Thesetreatments are applied primarily toremove skin damage and to improveformation permeability by dissolvingacid-soluble solids. The factors thatidentify a well as a candidate for

Figure 5.2: Using high volumes ofhydrochloric acidwithout retardationor without the use ofdiverter can causecollapse of the porestructure. This resultsin significantreduction ofpermeability. Theseeffects increase withtemperature andpressure. The use ofan emulsified acidsystem eliminatesthese problems and allows thedevelopment ofextended wormholes

Effects of Temperature and Pressure on Permeability Improvement

Cumulative acid throughput (gal/ft)0 10 20 30 40 50 60

Acid: 15% HCIPressure gradient: 110 psi/in.

Net overburden pressure: 5460 psig

Perm

eabi

lity

100

10

1.0

perature 80perature 80º psigF, pressure 500 F, pressure 500

Temperature 225m º psigF, pressure 2440

Figure 5.1: The data are indicative of tests performed under controlled laboratory conditions on a 10-in. carbonate core. Overtreatment of the core with uninhibited acids can lower the permeability of the core. Attention must be given to factors such as temperature and overburden pressure whencalculating throughput. If this is excessive, the resulting pore collapse can decrease permeability

Cumulative throughput (gal/ft)

0 50 100 150 200 250 300 350

100

200

300

400

500

600

700

Perm

eabi

lity

(md)

Acid: 15% HCITemperature: 215ºF

Injection pressure: 2500 psigOverburden pressure: 8200 psig

Pressure gradient: 35 psi/in.

The Effects of Overtreatment

Preflush tttAcid treatment PostPostPostPost flush

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matrix treatment include a high skinfactor, high natural permeability and a shallow depth of damage (generallyconfined to a zone less than 3 ft fromthe wellbore). Matrix stimulation of severely damaged limestone ordolomite reservoirs can increase wellproductivity. However, if there was noskin damage, a matrix treatment inlimestone or dolomite would stimulatenatural production by no more thanone and a half times. If the natural,undamaged permeability is low (lessthan 10 md for oil wells), then fracturestimulation is more appropriate.

Most carbonate reservoirs are matrix acidized with hydrochloric acid,although it is not suitable for high-porosity (more than 35%) or chalkreservoirs. Careful treatment designand execution are required to minimizeentry of the acid into the highlypermeable sections of the formation, as this could create a high-conductivitychannel breaking into unwanted gas- orwater-producing zones.

The first steps in a matrix-acidizingprogram are to examine the history of the well and the formation, and toquantify formation damage using well and/or production testing. Core-level examination is important fordetermining the mineral composition,permeability, and acid solubility. Usingthis information, a suitable recipe forthe remedial acid treatment can bedetermined. Once the formulation hasbeen identified, the treatment fluidneeds to be checked for compatibilitywith reservoir fluids.

To avoid secondary damage duringtreatments caused by emulsions andundesirable precipitates produced byreactions in the wellbore or rockmatrix, additives such as surfactants,scale inhibitors and iron control agentsare necessary. Mutual solvents thatprevent adsorption of dissolvedmaterial onto the rock surfaces orprevent precipitate entering the porespaces may also be needed.

In addition, iron compoundsproduced by the reaction may alsoresult in formation damage when theyprecipitate as the acid spends. Thiscan be minimized using iron controladditives—chelating or reducingagents—or avoided by usingformulations that are less corrosive.Significant corrosion may occur if

Figure 5.3: StimCADE well simulation software allows stimulation treatments in production andinjection well completions to be optimized. The acidizing process, including fluid flow for each zone,reaction kinetics, cool down and diversion can be modeled

there is contact between acid andsteel pipe. The use of suitablecorrosion inhibitors can prevent aciddamage to tubulars. Use of an SXEsystem reduces the contact betweenthe acid and well tubulars. Thisminimizes the tendency for corrosionand hence less inhibition is required.

Putting acid in its placeAccurate acid placement is a majorconcern in matrix acidizing ofcarbonates, as the acid tends to flowpreferentially where the permeabilityis highest, further increasingpermeability and leaving the low-permeability regions of rockuntreated. Industry experience showsthat around 35% of matrix treatmentsaround the globe do not meetexpectations because of improper jobdesign. In some cases, huge increasesin water production are observedafter a stimulation job because acidmay have preferentially stimulatedthe high-permeability sectionsassociated with water. Once a highlypermeable water zone has beenstimulated, the chance of acid getting

into the pay zones is reduced and the result is the production of morewater. Proper use of diversiontechniques can avoid such disasters.

In carbonates, because of theirrapid reaction with acid, matrix acidmay create dominant wormholesthrough which the acid flows withease, leaving most of the pay zoneunstimulated. This cannot be avoidedif the acid is simply bullheaded intothe well and allowed to find its ownroute naturally. Some form ofdiversion or temporary plugging is necessary to attain effectiveplacement of the stimulation fluidsThis can be achieved by chemical ormechanical diversion.

Computer modelling can determinethe best method of placement for a particular stimulation treatment.StimCADE* well simulation softwarehelps to optimize matrix stimulationtreatments in both production andinjection wells. StimCADE software(Figure 5.3) models all aspects of theacidizing process, including the fluidflow for each zone, reaction kinetics,temperature changes such as cooldown, and diversion.

Mechanical diversionMechanical diversion is achieved bypumping the necessary amount of acidin front of the intervals to be treated.Coiled tubing has been increasinglyused to achieve diversion in the last two decades. Where the use of coiledtubing is impracticable, other methodsof diversion may be considered. Themost common method of mechanicaldiversion uses ball sealers (Figure 5.4).Before injecting the stimulation fluid,balls (made of nylon, hard rubber,biodegradable materials such ascollagen, or combinations of thesematerials) in the treatment fluid are used to plug and shut off theperforations that are taking most of thetreatment fluid. Mechanical diversioncan also be achieved by using a straddlepacker arrangement (Figure 5.5) toisolate the required interval.

Stimulation in multilayer reservoirswith zones having wide injectivitycontrasts and heterogeneity isresulting in a combination ofmechanical and chemical diversionmethods becoming more popular.

Chemical diversionTemporary plugging of selected zonescan also be achieved using a chemicaldiverter. It is usual practice to pumpin the diverter and the acid inalternating stages. The number ofstages depends on the height of thezone being treated. This is typicallyone acid–diverter combination forevery 15 to 25 ft of zone height. Morerecent methods involving VEStechnology eliminate the need for a multistage process.

Chemical diversion can also beaccomplished by careful use of bridgingagents such as rock salt or benzoic acidflakes. Rock salt is water soluble andkeeps its mechanical integrity in the oilphase, while benzoic acid is oil soluble.Both chemicals are used to createtemporary plugging against high-permeability fractures, channels, vugsand fissures while the acid is divertedto low-permeability zones. Rock salt isvaluable for plugging high-permeabilityoil-bearing zones. When the treatmentis complete, the spent acid dissolvesthe salt, restoring permeability. Benzoicacid retains its integrity in the acid but

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when production is resumed, it isdissolved in the hydrocarbon.

Foam is also effective in divertingacid from a high-permeability zone to the zone of interest (normally an oil–gas zone). Foam is generallyproduced by injecting nitrogen intofluid containing a surfactant. Foamedfluids break down and becomeineffective quite quickly (usually inless than an hour), so they are oftenmixed with polymer gelling agents to increase stability and improverheology. Foam is even less stable at high temperatures and also in thepresence of hydrocarbons. However,techniques have recently been

developed for postponing breakdown,including using a preflush ofsurfactant. The surfactant is injectedwith each subsequent stage in the acid treatment process. Diversiontechniques, such as FoamMAT*diversion services are very effective,but are more commonly used insandstone formations.

Other advanced diversiontechniques include the use of thepolymer-based SDA* Self-DivertingAcid. This is an in-situ gelled acidsystem that changes viscosity duringthe acidization process. Fresh SDAfluid has a low viscosity beforereacting with the formation. As the

Figure 5.4: Forisolating a zone with the ball sealerdiversion method,nylon, hard rubber orbiodegradable ballsare mixed with thetreatment fluid. Theballs block theperforations that aretaking most of thetreatment fluid andcan result indiversion

Figure 5.5: Pumpingtreatment fluidsusing coiled tubing isnot always feasible.A straddle packerarrangement willensure that thetreatment isrestricted to the zone of interest

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acid spends, the polymer crosslinks at about pH 2, and the viscosityincreases dramatically, forcing freshacid into untreated lower-permeabilityintervals (Figure 5.6). Between pH 2and 4, the SDA gel forms a temporarybarrier in wormholes created by aprevious acid stage or in acidizednatural fractures, halting channelgrowth and reducing the loss ofincoming fresh fluid to the wormholeor fracture. At around pH 4, thegelled acid breaks and the viscosityreduces. Like particulate diverters orfoams, SDA systems are also pumpedin several stages, alternating withstages of regular or retardedhydrochloric acid. Good results arereported in long, open intervals wherebenzoic acid flakes or precrosslinkedgelled acid have not providedeffective fluid diversion. Figure 5.7shows the schematic of a typical SDAtreatment and the pressure response.

In-situ acid-viscosity developmentcan also be achieved with VDA*Viscoelastic Diverting Acid technologythat uses a nonpolymeric surfactantsystem for gellation. This gelled acidsystem can attain viscosity increasesbetween two and over 100 times as itleaks off into the formation. Thisdiverts the subsequent lower-viscosity, acid/fluid stages into thelower-permeability zones.

Acid fracturingAcid fracturing (Figure 5.8) describesthe creation of highly conductivefractures by pumping acid atpressures exceeding the minimumstress in the rock, in the same way as propped hydraulic fracturing. Thismethod is usually preferred where thenative permeability of the formation isvery low.

Acid fracturing of carbonates notonly creates long wormholes, but alsoetches irregular channels on thefracture face. The irregularity of theetched channels ensures that there isstill communication with the wellborewhen pressure is released and thefractures close after the treatment.This eliminates the need for proppantin acid fracturing. The effective lengthof the fracture is determined by thelength that has been sufficientlyetched and is accessible for flow.

The main factor that adverselyaffects acid fracture growth andwormholing is fluid loss. Acid leakoffis not uniform, resulting in theenlargement of some wormholes andnatural fractures. This greatlyincreases the area from which fluid lossoccurs, making fluid-loss control

difficult and preventing acid reachinguntreated parts of the fracture. Oneway to control this, is to pump viscousfluid slugs (pads) intermittentlythroughout the acid treatment. Theinitial pad is used to initiate thefracture and to deposit a filter cake in it that forms a temporary barrier

Figure 5.6: The SDA system crosslinks as the pH reaches around 2 when the acid is spent. Theviscosity developed returns to its initial low value at around pH 4 when the breaker is activated .Thegelled acid forms a temporary barrier in wormholes or in acidized natural fractures, preventing furtherloss of incoming, fresh acid. This helps divert the incoming acid to low-permeability zones

Visc

osity

(cp)

pH

20 4 6 8

The Effect of pH on the Viscosity of SDA Systems

Figure 5.7: SDAsystems areapplicable only forcarbonates. Thissnapshot of a typicalSDA treatmentshows where thefluid has migratedand reacted with thehigh-permeabilitycarbonate formation,resulting in anincrease of pH thattriggers the in-situgellation. This allowsthe following acidstages into the otherproducing zones

High

Permeability

Low

Acid tanks

Injection pump(acid)

Coiled tubingunit

Mixing

Injection pump(diverter acid)

Coiled tubing

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to prevent acid leakoff. With time, aciddissolves and erodes the filter cake,resulting in increasing leakoff. In orderto minimize leakoff further, polymerfluid stages are pumped to reestablishcontrol of fluid loss.

Fluid-loss control can also beachieved using two-phase fluids in the form of foams or emulsions, andcrosslinked leakoff control acids suchas LCA* leakoff control acids.Recently, VES-based gelled acids suchas ClearFRAC* AC systems have beenfound to be very effective in leakoffcontrol in acid-fracturing applications.The most popular fluid for acidfracturing of high-temperaturecarbonate formations is an SXEsystem. This is for the same reasonsthat these systems are suited to high-temperature matrix acidization.

Getting it right Matrix acidizing, because it is a low-cost treatment compared with acidfracturing, may not benefit from thesame level of execution and evaluation.Laboratory testing is needed forproper assessment of the damage,reactions with the formation fluids andthe effectiveness of the treatment toensure the desired results.

Diagnosing formation damagearound the borehole can only be donesuccessfully by analyzing a completepressure profile from deep in thereservoir up to the wellhead. NODAL*production system analysis helps toachieve this using production history,well-test data and flowing pressuresto predict a well’s steady-stateproduction pressures. Comparing aNODAL analysis with actual measuredpressures helps to pinpoint andquantify the skin.

Job design and real-time job controlare key elements in a successfulstimulation operation. They require a geological model based on knownreservoir characteristics, such aspermeability, porosity, lithology,pressure and production data, obtainedfrom logging, core data from thecurrent well and offset wells, and fromother sources such as outcrops. Localoperating companies and integratedservice companies can also share dataand experiences from their intimateknowledge of the fields and reservoirs

under consideration to achieveoptimum design. As the number ofstimulated wells in a field increases, thegeological model and the stimulationdesigns can be refined to continuouslyoptimize the stimulation model.

In acid fracturing, job design,monitoring and evaluation are morecomplex and are best understood by3D representations. FracCADE*fracturing design and evaluationsoftware achieves this by giving aphysical description of acid diffusionpaths and the two-dimensionalpressure gradients, combined withfracture length and height evolutionalgorithms, complete fluid leakoffinformation and the effects ofmultiple fluid injections, includingtemperature changes.

It is possible to modify thetreatment during the job using real-time monitoring. Moderncommunication systems enableexperts worldwide to contribute inreal time while a job is in progress.The MatTIME* matrix treatmentevaluation software within StimCADEallows monitoring of skin evolutionduring treatment. Once skin evolutiondecreases, the next stage is pumped.The effectiveness of the chemicaldiverter can also be determined usingthis software. FracCADE* softwareuses a net pressure plot to determineif fracture extension is occurring, andto determine fluid efficiency so real-time decisions can be made, allowingchanges to pumping schedules duringtreatment (Figure 5.9).

Figure 5.8: Acid fracturing is applicable only in carbonates. This diagram showed the sequence ofevents in an acid fracturing treatment. A viscous pad followed by acid stages is pumped into thewell above the natural fracture pressure of the rock to create a fracture (1). The acid continues topenetrate the open fracture and create etched patterns on the inside surfaces. These patterns aremore prevalent near the opening of the fracture (2). The acid also penetrates the rock further,forming a network of wormholes (3). When the pressure is released, the fracture closes, leaving theetched paths and wormholes open as an outlet for spent acid and later for produced gas or oil

1

23

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Post-treatment analysis is key A comprehensive post-treatmentanalysis is essential to validate theacidizing model, understand theresults of treatment and improvefuture designs. A good match betweenactual and predicted bottomholepressures indicates that the reservoirwas described properly and that theentire process modelled accurately.Similarly, the predicted pressureresponse during stage diversion can be compared to the observedpressure changes to verify divertereffectiveness. In fracturing, the netpressure plot obtained from FracCADEsoftware during fracturing can be usedto quantify fracture extension, heightgrowth and fluid leakoff.

The analysis of the concentrations of polymers, surfactants, inhibitors andkey cations and anions in fluids flowedback to surface after treatment willcontribute significantly to the successof future stimulation treatments. Inthe process of treatment optimization,output from the post-treatmentanalysis of the current and precedingjobs produces valuable input for thenext job. This approach tooptimization has been successfullydemonstrated in the PowerSTIM* well

optimization process, currently in usein Saudi Arabia and elsewhere(Middle East & Asia Reservoir

Review, Number 3, 2002, pages16–21).

The way ahead The use of nonpolymeric andnondamaging VES systems (such asthe ClearFRAC system) has provedvery successful in hydraulicfracturing applications. This uniquetechnology is now extended toapplications in wellbore cleaning(MudSOLV* filter-cake removal),matrix stimulation (VDA systems),diversion (OilSEEKER* aciddiverter), lost circulation (ClearPILLsystems) and in acid fracturing(ClearFRAC AC systems). Thesetechnologies will be presented indetail in future issues of Middle East

& Asia Reservoir Review.

Extensive research has been carriedout on the use of chelating agents(chelants) in carbonate stimulation.Laboratory studies indicate that thesefluids are highly retarded and canform extended wormholes. They are particularly useful in high-temperature applications because of their less-corrosive nature and slow dissolution of carbonates in

Figure 5.9: FracCADE software allows treatment design and real-time modification of stimulationtreatment by continuously monitoring net pressures

What is formationdamage?Formation damage occurs in theformation adjacent to the wellbore.It is characterized by a reduction in permeability for a given damageradius and causes an additionalpressure drop that decreases theproduction rate. Since it is difficultto determine the radius and thepermeability of the damaged zone,it is usually represented by a termcalled skin. The effect of formationdamage on production is taken intoaccount in Darcy’s equations by the addition of a skin factor. This is a dimensionless number that is positive when the formation isdamaged or some other factor hasincreased the pressure drop in the well during production, andnegative where the pressure drop is reduced, for example, because of induced fractures or otherstimulation processes.

High skin can also occur for many reasons other than formationdamage. These include partialcompletion, mechanical restrictions,three-phase production and high-pressure drawdown. Acidstimulation is only used to removeskin that is associated withformation damage.

Well operations can damage theformation from the moment thedrill bit first penetrates a permeableformation, and this will continueuntil the end of its productive life.Damage reduces the formation’snatural permeability. The extent of this reduction depends on theamount of damage and the depth towhich it occurs. Invasion of thenear wellbore by mud solids andmud filtrate can cause pore-throatplugging, either during drilling, or,for example, when it is pushedahead of cement (Figure 5.10).Unfiltered fluids transported duringwell killing, clay swelling, debrisfrom completions, sand-consolidating material and finesmigration during production canalso plug the formation. The actionof the drill bit itself can physicallyalter the pore structure in the nearwellbore, and adverse fluid-to-fluid

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chemical reactions can lead toemulsion–water blockages andinorganic scaling. Table 5.2summarizes the extent of formationdamage attributable to various welloperations.

Many horizontal wells do notproduce any more than vertical wellsunder the same conditions. This maybe due to formation damage havinggreater impact in horizontal wellsthan in vertical wells. Drilling long,horizontal boreholes leaves thereservoir exposed to potentiallydamaging drilling mud for a muchlonger time than short, verticalintervals. Long openhole sections or lengthy perforation intervalsmean greater opportunities forformation damage. It is much more difficult and costly to removeformation damage from a horizontalwellbore. For this reason,consideration of potential formationdamage and its prevention are keyfactors in the completion design.

Formation water Quartz grains Oil Mud

1 2

3 4

Figure 5.10: Formation damagecan occur for several reasons.During drilling, hydrostatic orcirculating pressure forces mudfiltrate or mud solids into porethroats in the near-wellbore rock(1 to 4). Invasion and pore throatplugging can also occur when,for example, mud is pushedahead of cement. Unfilteredfluids transported during wellkilling, clay swelling and debrisfrom completions can also plugthe formation

Mud solids plugging

Damage severity

Drill

ing

and

cem

entin

g

Wel

l com

plet

ion

Wor

kove

r

Stim

ulat

ion

Drill

ste

m te

sts

Prim

ary

prod

uctio

n

Supp

lem

enta

l flu

id in

ject

ion

Well construction and intervention Reservoir exploitation

Fines migration

Clay swelling

Emulsion/water block

Wettability alteration

Reduced relative permeability

Organic scaling

Inorganic scaling

Injected particulate plugging

Secondary mineral precipitation

Bacteria plugging

Sanding

0 1 2 3 4

Table 5.2: The severity of formationdamage attributed to some of themost common well operations

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comparison to acids. As the oilindustry explores deeper and hotterreservoirs, the use of chelants formatrix stimulation and acid fracturingwill become more widespread.

The era of real-time reservoirmanagement offers new opportunitiesfor stimulation. Automated candidateselection, computer-aided operations atthe wellsite and remote witnessing andevaluation of the stimulation treatmentwill bring new opportunities for the

engineers to increase the productivityand injectivity of carbonate reservoirs.Middle East and Asia region hassuccessfully tested the InterACT*system that allows real-time wellmonitoring and control by datatransmission from the field using theInternet. It allows users to see a jobfrom anywhere, from any computer.Future developments will include livevideo transmissions from the field toease communications.

Working with wormholesAs acid dissolve carbonate minerals,the area open to flow increases,causing linking, or collision of thepores. This creates highlyconductive channels in the rock that are referred to as wormholes(Figure 5.11).

As fresh acid is introduced, thechannels interconnect, eventuallyforming a wormhole network. In acidfracturing, a high injection rate isused to generate enough pressure to fracture the rock. The acid thenirregularly etches the fracture faceso that a high-conductivity channelremains open after the pressure isreleased. How acid etches fracturefaces and how wormholes developare shown in Figure 5.8.

Live acid penetration is limited by the reaction rate of the acid. Hightemperatures cause the hydrochloricacid to spend so quickly that it isused up before it moves out of thearea near the wellbore. Controllingreaction rate and fluid loss are thekeys to successful acid fracturingtreatments. Reaction rate can be reduced by using acid-in-oilemulsions, which delay theinteraction between acid dropletsand the carbonate. Fluid loss isgenerally controlled by increasingacid viscosity (surface or in-situgellation) and optimizing thepumping rate.

The nature of the wormholenetwork depends on factors thatinclude fluid properties, rock material,injection rate and temperature.

Figure 5.11: Wormholes formed by the dissolution of carbonate intohighly conductive flow channels

13:57:00

14:24:00

14:51:00

15:18:00

15:45:00

16:12:00

16:39:00

17:06:00

17:33:00

Timehh:mm:ss13:30:31

17:47:46

Tubing pressure

Hydrochloric acid

(psi)0 600

Annulus pressure

(psi)0 65

SDA fluid

SDA fluidHydrochloric acid

SDA fluid

SDA fluid

SDA fluid

SDA fluid

SDA fluid

SDA fluid

Hydrochloric acid

Hydrochloric acid

Hydrochloric acid

Hydrochloric acid

Hydrochloric acid

Hydrochloric acid

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Stimulating times in Indonesia

The results from an acid stimulationjob conducted for the ChinaNational Offshore Oil Co. at the RX field in Indonesia underlines the value of acid-diversion methods.The job aimed to boost total oilproduction, extend the working lifeof the pump, maintain a low watercut and remove any scale depositsthat had formed during production.The removal of scale would help toenhance pump performance andensure continued operation.

Well RX-8 has a maximum holeangle of 63° and six perforationzones in a 90-m interval where the hole angle is 56°. The well wastreated with eight stages of 20%hydrochloric acid for stimulation.Each hydrochloric acid stage wasfollowed by two stages. First, anSDA stage for diversion and, second,a small mutual-solvent stage beforethe next hydrochloric acid stage. Inthe final stage, the treatment fluidwas displaced by ammoniumchloride solution.

Careful planning, and properdesign and execution ensured thatall of the objectives were met. Thejob was pumped at 4.0 bbl/min andthe pressure chart indicated thatthe desired stimulation anddiversion were achieved(Figure 5.12). Production increasedfrom 60 BFPD to 170 BFPD—anincrease of around 200%. The post-treatment oil rate showed anincrease of 300% (Table 5.3).Production data indicated that thehydrochloric acid and SDAcombination provided effectivediversion and stimulation of theentire interval (Table 5.3).

Table 5.3: Following stimulation, the oil ratewas increased by 300% and tubing pressurerose from 210 to 870 psi

Well RX-8 Production Data

Date Fluid Oil Water Shut-in Producing PI Tubing production production cut (%) bottomhole bottomhole pressure

(BFPD) (BOPD) pressure pressure (psi)(psi) (psi)

Prestimulation

23 December 102 75 26 702 671 3.29 2403 January 141 71 50 702 671 4.55 34025 January 60 30 50 702 671 1.93 210

Poststimulation

23 April 167 127 25 702 627 2.25 870

Gain/loss of production

23 April +109 +97 -25 702 -44 +0.31 +660

Figure 5.12: The pressure response when the SDA treatment fluid hit the formationindicated that stimulation and diversionhad occurred

100

80

60

40

20

00 30050 100 150 200 250

Time (min)

Sepa

rate

d ac

id (%

tota

l SXE

flui

d vo

lum

e)Acid

Diesel

Thermal Stability of SXE Fluid (70:30) at 96ºC

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A slow reaction isimportant in Saudi ArabiaAttempts were made to restoreproduction to an oil-producing well(Well A) in a carbonate reservoir inSaudi Arabia. Initially, the well wasacidized using 15% hydrochloric acid.Because of the rapid reaction rate, theacid spent quickly and only causeddissolution of the rock face or surface washout, instead of therequired wormholes. The wellremained unproductive after thehydrochloric acid matrix treatment. Athorough laboratory study was thenconducted to evaluate the use of theemulsified acid SXE system as ameans of retarding the reaction of theacid with carbonates in this well,which had several tight zones. Thediesel in the system would act as adiffusion barrier between the acid andthe rock, slowing down the reactionand allowing the acid to penetratedeeper into the formation by formingmultiple, penetrating wormholes.

Getting to the core of the problem

The laboratory study aimed todetermine the rheological propertiesof the SXE system, measure thethermal stability of the emulsifiedacids at reservoir temperature,analyse the propagation of emulsifiedacid into the tight carbonate reservoircores, and design a stimulationtreatment to improve oil productionfrom the low-permeability producingzones. Core-flood tests wereconducted with an SXE volume ratioof 70:30 acid:diesel (15% hydrochloricacid). Rheology, thermal stability,compatibility and reactivity withreservoir rocks tests were also carriedout on the SXE system (Figure 5.13).

The apparent viscosity of the SXEsystem decreased as the shear rateincreased, indicating that it was anon-Newtonian fluid. The fluid hadseveral-fold viscosity at ambient andbottomhole temperatures whencompared to regular hydrochloricacid. Thermal stability testsindicated that the SXE system wasstable for several hours under thehigh-temperature downhole

two-fold by 15% acid (facedissolution only). The results alsoshowed that increasing the flow rateof the emulsified acid led to fasterpropagation of the SXE system inthe core. The number of wormholesand the wormhole diameters on theinlet and outlet faces of the core alsoincreased with the increasinginjection rate.

conditions in the well, and wouldnot separate out before reaching the formation.

Compatibility tests showed that,while the system was compatible with crude oil and the acid additives,it broke down on contact with themutual solvents or demulsifiers.These additives, therefore, were notused with the SXE system.

Reactivity tests, in which theweight loss in samples of reservoirrock was measured for the SXEsystem and for 15% hydrochloricacid at 24°C, indicated that thereaction rate of the emulsified acidwas slower than the 15% hydrochloricacid by a factor of 45. The retardationalso depended on the temperature,the rate at which the fluid waspumped and the type of fluid flow.

Measuring the calcium ionconcentrations in the core effluentduring core flood experiments onthe carbonate cores at 96°Cconfirmed that propagation of theSXE system was slower than thepropagation of regular hydrochloricacid, and that the SXE fluidpenetrated deeper into the rock.Core permeability was increasednine-fold by the SXE system, whichcreated deep wormholes, but only

Figure 5.13:Thermal stabilitytests indicated thatthe SXE system isvery stable underhigh-temperatureconditions

Table 5.4: Well A has four producing zones

Depth of Producing Zones in Well A

Zone Depth (ft)

Zone 1 X564–X575Zone 2 A X575–X626

B X626–X704Zone 3 A X704–X770

B X770–X833Zone 4 X833–X880

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Putting it into practice

Well A was drilled in a carbonatereservoir as an openhole oil producerin 1973. The formation is divided intofour main zones (Table 5.4). Zone 2is the main productive zone, whilezones 3 and 4 are tight carbonatezones. The second workoveroperation was completed in February1995 to isolate a high-permeabilityinterval at the top of zone 2B, whichincreased water production.Following the workover, a total of15 m was perforated in zones 2B, 3A and 3B. The perforated intervalswere acidized with 3000 gal of 15%hydrochloric acid using coiled tubing.This did not sustain flow to thegas–oil separation plant. In July 1995,a further 4.5 m of perforations weremade in zone 2A and acidized withhydrochloric acid, but this did notincrease well productivity.

Following various diagnosticstudies, it was decided to stimulatezones 2A, 3A and 3B using anemulsified acid to improvepermeability of the formation (Table 5.5).

Nitrogen lift was used to clean upthe well while flowing into the flarepit. Two hours after the backflow,the well flowed at a wellheadpressure of 360 psi without nitrogenlift. Acid return samples werecollected during flowback for about4 hr and analyzed for key ions.

Return to production

Emulsified acid treatment for Well A was successful in increasingthe productivity significantly in thestimulated intervals, especially inzone 3, which generally has a lowpermeability. Flowmeter testsconfirmed that the production ratemore than doubled from 14 to 29%in zones 3A and 3B.

There was a significant reductionin iron concentration in the acidreturns (Figure 5.14). The source of iron is acid reacting with coiledtubing, mixing tanks and corrosionproducts. In Well A, the total ironconcentration in the backflowreached 237 mg/l after 1.8 hr, fallingto 1 mg/l after 4.0hr.

By comparison, the ironconcentration in Well B (another oilproducer), which was acidized withregular 15% hydrochloric acid,reached 6000 mg/l. In an emulsifiedacid system, the diesel minimizes thecontact between the tubing andcasing surfaces and the acid, as it

Figure 5.14: The amount of total iron recovered in the flowback fluid. When using an SXEsystem, acid is the dispersed phase. It has less interaction with reactive surfaces and showssignificant reduction of iron concentration in the acid returns, even at higher temperatures

Pumping Stages in Stimulation of Well A

Stage Volume (bbl) Fluid Remarks

1 2 15 % HCl To improve injectivity while acidizing the intervals below the gel

2 2 High-pH spacer To separate acid and gel plug3 1.5 PROTECTOZONE* fluid To isolate the interval X627 to X710 ft4 2 High-pH spacer5 Diesel The volume was adjusted to have a

hydrostatic head inside the coiled tubingequal to reservoir pressure to avoid the plug movement during the gel-setting period

6 15.5 15 % HCI A preflush for the interval below the gel plug

7 3 Diesel8 69 SXE fluid To acidize zones 2A and 3 (A and B).9 12 SDA fluid To minimize the downward movement of

the plug while acidizing the interval above the gel

10 8 15 % HCI As a preflush for the interval above the gel plug

11 2 Diesel12 36 SXE fluid To acidize the interval above the gel plug

Table 5.5: Stimulation was carried out with SXE acid-in-dieselemulsion system and SDA fluid for diversion

is the dispersed phase and has lessinteraction with these surfaces. TheSXE system significantly reducedcorrosion and the potential forsludge formation.

1000

800

600

400

200

02 3 41

Time (hr)5

Tota

l iro

n co

ncen

tratio

n (m

g/l)

Nitrogen liftNitrogen liftNitrogen liftNitrogen lift

Well A at 220ºF (SXE)Well B at 140ºF (HCI)

Iron Concentration in Acid Returns

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T he Research Institute of KFUPM was created in 1978 to help solve

industry’s problems through our appliedresearch. It has about 350 full-timeresearchers and support staff.

On average, more than 70 facultymembers from various universitydepartments participate in industry-funded research projects in theinstitute. If they are interested incertain projects, they can becomeinstitute members or projectmanagers. Their graduate studentscan also come in and do part of theirresearch on some aspects of ourwork. The Center for Petroleum andMinerals within the institute hasabout 40 multidisciplinary, full-timeresearchers and support staff.

The upstream oil and gas companiessponsor our contract research work.Saudi Aramco has been our majorclient for more than 24 years,accounting for more than 90 percent of our contract work. We are alsocooperating with Japan National OilCorporation in a joint, five-year projectin fluid-flow visualization, and we haveworked with regional clients such asBahrain National Oil Corporation andAramco Gulf Operations Company.

Schlumberger is now partnering withus, as well as receiving our consultancyand laboratory services, and it is aboutto become a member of our reservoircharacterization consortium.

Focus on the practicalWithin the center, we have four focusareas. The first is petroleum and gasengineering. This includes reservoirand production engineering, andpetroleum-related rock mechanics.Reservoir simulation and fluid flowvisualization are also part of thisfocus area. For example, we areengaged in a major program with a client to help develop a gascondensate reservoir.

We are also working on processdevelopment and testing newtechnology for another client to controlsand production from sandstonereservoirs. This technology wasinvented here in the university and hasa US patent. The client and KFUPM arealready in the final stages of conductinga pilot test to evaluate it. If the fieldtests are successful, the technology willbe applicable to sandstone reservoirsoutside the Kingdom.

Dr Abdulaziz Al Kaabi is director of the Center for Petroleum and Minerals in theResearch Institute of King Fahd University of Petroleum & Minerals (KFUPM),Saudi Arabia. Established in 1963, the KFUPM campus occupies an impressive6-km2 site in Dhahran. The university has six colleges, with 700 facultymembers and 8000 students. Schlumberger is building its new carbonateresearch center on the campus. In this article, Al Kaabi describes his greathopes for active partnership between industry and academia.

Active Partnership

“

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Rock mechanics is anotherimportant activity. We are drilling very deep, hot gas wells with huge,underground, in-situ stresses whererock behavior has been critical tosuccessful drilling. Rock mechanics isalso important in horizontal and highlydeviated wells where we need to beaware of in-situ stresses.

Our second focus is on petroleumgeology and geophysics, and includes work on many reservoircharacterization projects involving our consortium on reservoircharacterization. Schlumberger willsoon join this consortium. Seismicprocessing and interpretation is animportant activity that we hope toexpand in the near future.

Petrophysics is part of this focusarea. We measure many electricalparameters, and we take core samples,that are subjected to reservoirconditions of high pressure andtemperature. We look at the electricalconductivity of the rock when it issaturated with reservoir fluids, and theinformation we gather can be used forestimating reserves. This information s part of an integrated study thatincludes geology and physics. It’sanother area in which our experiencedgeologists have been active.

Our third focus is on remotesensing. Our laboratory was the firstto be established in the Kingdom. Itprovides images to help geologists andenvironmentalists with explorationand environmental monitoring.

Our fourth focus area is minerals.The Kingdom is putting more emphasison mineral resources development, andwe have a fairly new unit that is tryingto set the direction for helping theminerals industry in the future.

In summary, we provide high-quality research and development(R&D) and consulting services to the oil, gas and minerals industries,focusing, at present, on industrieswithin the Kingdom. We are hoping to eventually extend this cooperationinternationally.

The right support, at theright timeOur vision is tied to what the industrywants to do. It is dynamic and itsuffers from instability when it comesto setting long-term strategies. Somost of our activities have to supportwhat the industry really wants at aparticular time.

I would like to be involved with theindustry on medium- and long-range,strategic projects. Currently the focusis short term and the researcherschange direction quite frequently.That’s really becoming a characteristicof the oil and gas industry. So I hopethat good planning with our localindustry could help to move awayfrom the short term and try to putemphasis on medium- and long-termR&D. I think we can do it.

This is especially important, as some of our oil fields are beginning to

mature. New techniques can be usedon our current fields for reevaluation ofreservoirs. What we need to do in themedium and long term is to evaluatetechniques for maximizing recovery,reducing the cost of development, andfor recovering that extra oil and gasfrom the ground. We need to minimizethe risk in our operations and bemindful of how can we lessen theimpact on the environment.

Another vision is to form a realpartnership with industry, so they canlook on this center as a place that canadd value to their operations. This canonly be done through long-termcommitment between the industry andan academic institution like ours.

Positive cultureI definitely see the proximity of theSchlumberger Dhahran CarbonateResearch Center (SDRC) to theuniversity as a step forward.Schlumberger is top of the list for R&Dfunding and expenditure. It investsabout five percent of its sales revenuein R&D. I am hoping that the SDRCand the company’s R&D culture willinfluence the students, the faculty andthe partnership with the university in aunique way.

The university will benefit from thecenter by enabling talented facultystaff and students to interact withindustry experts. This could bethrough research and industrialtraining. The institute will be able toparticipate in technology developmentand consulting projects with theSDRC, where our scientists work as ateam with the Schlumberger scientists.

We are already seeing this happen.Dr Kamal Babour, for example, isadvising a graduate student in thepetroleum-engineering departmenton examining reservoir fluid tracking.This work is at the frontier of newtechnology.

This partnership shows industryhow it can work closely with academiaand create an environment that allowsuniversities to contribute to thecommunity. So, I am very happy tosee this kind of cooperation. It will bea good example for others to follow.”

The Center for Petroleum and Mineral’s computer-aided-tomographyscan facility for fluid-flow visualization in rocks