CARBONATE STIMULATION

Carbonate sequences, those comprising limestone and dolomite formations, present some of the most difficult challenges facing field operators. Carbonate reservoirs often have large andhighly variable completion intervals, which can greatly complicate stimulation and productionoperations. In many cases, these reservoirs exhibit marked vertical and lateral heterogeneitycaused by permeability barriers, natural fractures, and complex porosity distributions. Thesevariations can be particularly bewildering for engineers who are trying to devise effectiveworkover and stimulation strategies.

In this article, Steven Davies and Shrihari Kelkar examine the techniques and technologies that field operators can use to stimulate carbonate reservoirs.

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Matrix stimulation in carbonates

Matrix stimulation methods can be applied in clastic orcarbonate rocks. It is designed to remove or bypass damage inthe pore spaces and to leave the zone barriers intact (Fig. 2).In sandstones, matrix treatments are used to restore orimprove the natural formation permeability around thewellbore by removing formation damage. This is accomplishedby dissolving material that is plugging the pores or byenlarging the pore spaces. In carbonates, matrix stimulationcreates new, highly conductive channels (wormholes) thatbypass the damage.

Because of these different requirements, the selectioncriteria for the treating fluid are also distinct. For sandstonerocks, it is vital that the stimulation engineer understands theextent, type, location, and origin of the damage, the reservoirmineralogy, and the compatibility of the treating fluid with theformation. In carbonate treatments, reservoir temperature,pumping rate, and fluid type become more significant becausethese parameters have a direct influence on the reactionbetween the treating fluid and the reservoir rock.

In carbonate reservoirs, hydrochloric acid (HCl) is the mostcommonly applied stimulation fluid. Organic acids such asformic or acetic acid are used, mainly in retarded-acidsystems or in high-temperature applications, to acidizeeither sandstones or carbonates.

Almost two-thirds of the world’s remaining oil reserves arecontained in carbonate reservoirs. Carbonate formations tendto be extremely heterogeneous, with complex porosity andpermeability variations, barriers, and irregular flow paths.

Across the oil and gas industry, geologists, petrophysicists,and reservoir engineers are working to enhance theirunderstanding of carbonate formations and reservoirbehavior. There is a clear commercial focus to these researchefforts; experience has shown that even small improvementsin recovery methods can yield dramatic production results.Schlumberger is focusing its carbonate research andtechnology development on three critical areas:characterization, simulation, and stimulation. This articlefocuses on the last of these—increasing the productivity ofcarbonate reservoirs through better intervention andstimulation treatments.

For many years, reservoir teams have sought to extend theuseful lives of wells in carbonate reservoirs and to avoidearly abandonment when productivity decreases as a resultof formation damage or low natural permeability. In clasticreservoirs, a range of stimulation techniques can be appliedwith a high degree of confidence, and asset teams routinelyintervene to create conductive flow paths. Although manyof these standard stimulation methods can be applied incarbonate reservoirs, it may be difficult for engineers topredict how they will influence subsequent production.

A stimulating environmentAcids play a key role in boosting production or increasinginjectivity in oil and gas fields. Stimulation of carbonaterocks usually involves a reaction between an acid and theminerals calcite (CaCO3) or dolomite CaMg(CO3)2 that isintended to enhance the flow properties of the rock. Modernacid stimulation systems can be controlled and targeted toachieve specific aims for the asset team. Stimulation methodsin carbonate sequences can be divided into two main groups:matrix treatments and acid fracturing treatments.

Matrix stimulation involves pumping acids, solvents, orother treatment chemicals into the formation at less thanthe reservoir fracture pressure. When acids are introducedinto a carbonate formation, some of the minerals in the rockdissolve, which creates intricate, high-permeability channelsor wormholes (Fig. 1). Matrix treatments are often applied inzones with good natural permeability to counteract damagein the near-wellbore area.

Acid fracturing stimulations, in contrast, are performedabove the fracture pressure of the formation. A viscous pad (afracturing fluid that does not contain proppant) is pumpedinto the formation at pressures above the fracture-initiationpressure, which fractures the rock. Then an acid stage ispumped to etch the fracture surfaces. The acid also createsconductive wormholes at or near the fracture surfaces. Afterstimulation, the fracture closes, but the increased conductivitybetween the formation and the well remains because of theetching and the creation of wormholes.

When the productivity of a well in a carbonate reservoir decreasesas a result of formation damage or low natural permeability, theproduction team will attempt to increase productivity throughintervention and appropriate treatments. If they decide to workover the well, they must identify and implement a treatmentprogram that creates conductive flow paths between the reservoirand the borehole. This is the essence of carbonate stimulation.

Figure 1: When acids are introduced into a carbonate formation,some of the minerals in the rock dissolve to create intricate, high-permeability channels or wormholes.

Zone barrier

Zone barrier

Figure 2: Matrix stimulation removes or bypasses damage in the pore spaces between grains and leaves the zone barriers withinthe reservoir intact.

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fracture conductivity of 1,600 mD.ft. The analysis of the wellwas based on a permeability model obtained from a builduptest and a stress model built with DSI* Dipole Shear SonicImager data from an offset well. The stress and permeabilitymodels were calibrated by conducting an injection test,including a step-rate test and mini falloff injection tests toestimate permeability and reservoir pressure, before themain acid fracturing treatment.

The DUOFRAC* II acid fracturing technique, which usesacid and gel in alternate stages, was applied. The treatmentwas scheduled in two stages using a ClearFRAC* HT systemas the nonreactive pad, 15% HCl as the main acid, and VDA*Viscoelastic Diverting Acid as the diverter. Engineers pumpeda brine preflush containing a multifunctional surfactant toimprove the post-treatment cleanup. This fluid was pumpedduring the injection test and was followed by a spacerbefore the main treatment. All the fracturing fluids weretested with the formation oil to ensure that there would beno problems with emulsion or sludge. The treatment wassuccessfully pumped to completion.

The acid was recovered within a day of the well beingopened for flowback. This acid fracturing treatmentimproved well performance and reduced pressure drawdown(to eliminate asphaltene deposition) as predicted in theprejob planning and test phase. Detailed production analysisand stress evaluation helped the team to quantify theprobable increase in production that could be achieved. Thisprediction was confirmed in a production test, where thepost-treatment oil rate of approximately 860 m3/d wasalmost double what it had been under the same operatingconditions before stimulation—approximately 460 m3/d.

DiversionDiversion is a technique used in injection treatments, such asmatrix stimulation, to ensure uniform distribution of thetreatment fluid across the treatment interval. Injected fluidstend to follow the path of least resistance, and this may leadto inadequate treatment of the least permeable areas withinthe stimulation interval.

Using diversion methods, engineers can focus treatmenton the areas that require more stimulation. To be effective,the diversion effect should be temporary to enable the fullproductivity of the well to be restored when the treatment iscomplete. There are two main categories of diversion:mechanical and chemical.

Mechanical methods

Mechanical diversion techniques, such as ball sealers, packers,and straddle-packer assemblies, are used to divert reservoirtreatments to the target zone. Ball sealers and solid-particlediverting agents incorporated into the treatment fluid form atemporary plug in the perforations accepting the most fluidflow, thereby diverting the remaining treatment fluid to theless permeable zones (Fig. 4a). Packers and straddle-packerassemblies function by performing several short treatmentsover a longer interval to help ensure even treatment over theentire zone (Fig. 4b).

Though widely used, mechanical diversion methods maynot always be feasible or recommended. They are oftenineffective for stimulation projects in long horizontal orextended-reach wells.

54 Number 8, 2007 Middle East & Asia Reservoir Review

Acid fracturing

Acid fracturing is a hydraulic fracturing treatmentperformed in carbonate formations. The objective is to etchthe open faces of induced fractures using an HCl treatment(Fig. 3). When the treatment is complete and the fracturecloses, the etched surfaces provide high-conductivity flowpaths from the reservoir to the wellbore.

Hydraulic fracturing of clastic rocks, in contrast, uses aproppant to hold the fracture open and so create a high-permeability flow path along which fluids flow into the well.

To reduce or prevent leakoff (loss of treatment fluids tothe formation), conventional acid fracturing treatments usemultiple stages of nonreactive fluids and acids. This isdesigned to minimize the leakoff by increasing the fluidviscosity. By increasing the acid’s viscosity, the stimulationengineer can also slow the rate of reaction between the acidand the formation, which helps to improve fracturegeometry. Viscosity can be modified by adding a polymer tothe treatment fluid. This technique has proved successful inmany oil fields, but the polymers form a filtercake that canreduce production, especially in tight formations.

Crosslinking compounds are used to control viscosity.These are usually metallic salts mixed with a base-gelpolymer fluid, such as a guar gel system, to create a viscousgel. The crosslinker reacts with the multiple-strand polymerto couple the molecules and create a fluid with high, butclosely controlled, viscosity. The behavior of the crosslinkers,which enable the polymer system to operate in a narrow pHwindow, can be difficult to predict at high temperatures.Treatments using crosslinkers should take account of theconditions needed to break the gel structure to ensuresatisfactory cleanup and disposal.

When selecting the most suitable fluid for acid fracturing,engineers must take into account factors such as theproposed fracture geometry, the expected leakoff andretardation rates for the acid, rock dissolution, prevention ofsludge or emulsion problems, and the requirements forpostjob cleanup. Engineers must weigh the costs and thesetechnical factors against the benefits of sustainedproduction improvement.

Acid fracturing increases wellproductivity in KuwaitA carbonate reservoir in the Jurassic Marrat formation insoutheast Kuwait had been in production since 1986. Thereservoir had no stimulation history because the oil hadflowed naturally since completion. Recently, however,production had started to decline, and, as a result ofreservoir depletion and the high-pressure drawdown appliedin the formation, asphaltene deposits had affected some ofthe wells.

A production enhancement project was devised toimprove well performance by reducing the pressuredrawdown and so eliminating asphaltene deposition in thenear-wellbore area. After carefully examining the productiondata and reservoir stress characteristics, the asset teamdecided that fracturing would be the best way to achievethese objectives. The team examined all the wells in the fieldand selected four of them for a pilot project.

To gain experience and understanding, the team designedan acid fracturing treatment for one well, based on welldata and an evaluation of well performance. The treatmentwas designed to achieve a 70-ft fracture half-length and a

Acid Acid

Acid is pumped into the fracture Acid etches the fracture Acid creates conductive wormholes

Figure 3: To hydraulically fracture carbonate rocks, the workover team pumps acid to fracture the formation and to create a nonuniformetched pattern on the fracture surfaces.

(a) (b)

Figure 4: Ball sealers and solid-particle diverting agents create a temporary plug in the perforations that are accepting the most fluid flow.This forces the remaining treatment fluid to enter the less-permeable zones (a). Packers and straddle-packer assemblies allow the operatorto perform several short treatments over longer intervals, thereby ensuring that treatment is evenly distributed over the entire zone (b).

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Chemical methods

Conventional chemical diversion methods include nitrogenfoam, bridging agents such as benzoic acid flakes, andcrosslinked polymer gels. These create a temporary plug inhigh-permeability carbonate zones so that the stimulationfluids are diverted into the low-permeability zones thatrequire more treatment.

Polymer-based gels are a well-established chemicaldiversion technique. These systems use reversible, pH-triggered crosslinker additives to alter the viscosity ofthe fluid during the acid treatment. SDA* Self-Diverting Acidis a polymer system mixed with HCl. When combined withfresh acid, the SDA fluid has a low viscosity to facilitatepumping. However, once this fluid enters a carbonate zoneand the acid becomes spent, the polymer crosslinks and thefluid viscosity increases. The higher gel viscosity restricts theflow of fresh acid through the wormholes, and diverts it intothe zones with lower permeabilities and, eventually, to allthe zones requiring treatment (Fig. 5).

Modern chemical diversion methods can be very effective,but may create problems if incorrectly managed. In somewells, for example, temporary plugs may become permanent,which damages the formation and reduces production fromthe zone that was supposed to be stimulated.

A different direction for diversion

The potential risks of production damage when usingpolymer-based stimulation fluids prompted industryresearchers to explore alternatives. Research led to thelaunch of ClearFRAC polymer-free fracturing fluid, which isbased on viscoelastic surfactant (VES) technology, and ahigh-temperature version of the system that can be used attemperatures to 135degC.

VES surfactant fluids are polymer-free, so they do notdamage the formation. Their enhanced, drag-reducingproperties and significantly lower friction pressure enablethe stimulation team to reduce the pumping requirementsand treat deeper zones. Schlumberger has developed a rangeof VES fluids for various applications. These include VDAdiverting fluid, ClearFRAC hydraulic fracturing fluid, andClearPAC* gravel packing fluid.

The VDA system is a self-diverting, polymer-free acidizingproduct that increases zonal coverage in carbonatereservoirs without residual damage. Unique chemicals reducethe fluid loss. The system enables operators to optimize theremoval of reservoir drill-in fluid deposits and selectivelyplug zones with high water saturation.

VDA fluid prevents the damage caused by solids andpolymers during matrix treatments. It can be used alone orwith other treating acids for total zonal coverage incarbonate reservoirs. The high-viscosity barrier is brokendown by production or dilution with formation fluids. VDAoperations can be conducted at low pressures, and recoveryand well cleanup are simple.

Across the Middle East and Asia, VDA systems have beenused for matrix stimulation and diversion applications invertical, horizontal, and extended-reach gas and oilproducers and water injectors and for acid fracturing in oiland gas producers and water injectors.

pH

Rigid crosslinked gel

Visc

osity

Figure 5: When combined with fresh acid, the SDA fluid has a lowviscosity to facilitate pumping. However, once this fluid enters acarbonate zone and the acid spends, the polymer crosslinks andthe fluid’s viscosity increases.

Success in Saudi ArabiaIn Saudi Arabia, there has been a significant change incarbonate reservoir stimulation techniques, with a shiftaway from polymer-based stimulation fluids towardnondamaging VDA systems. Saudi Aramco has used VESfluids for a range of stimulation applications, includingmatrix acidizing and diversion in production and water-injection wells, and acid fracturing in high-pressure, high-temperature gas wells and water-injection wells.

Before the emergence of VES technology, matrixstimulation of carbonate reservoirs in Saudi Arabia relied onthe use of crosslinked, gelled, and emulsified acid systems.Unfortunately, in sour environments, i.e., those containinghydrogen sulfide, iron-control agents are ineffective againstthe precipitation of iron sulfides. In an effort to improvefluid diversion, reduce damage, and boost production, SaudiAramco decided to test a VDA system for matrix stimulationof wells under challenging conditions.

Some of the candidates chosen for VDA matrix stimulationwere long, horizontal wells with openhole sections rangingfrom 460 to 1,830 m and temperatures approaching120 degC. In many of the wells, there were serious concernsabout a water zone immediately below the targetedhorizontal section. This made effective diversion a vitalfactor in reducing or eliminating water production.

In the extended-reach wells, coiled tubing (CT) was used todeliver the treatment to the reservoir. The treatment compriseda VDA surfactant in 20–28% HCl and a corrosion inhibitor.

In those wells where the CT could not reach total depth,the VDA treatment was bullheaded from the maximumdepth that the CT attained. The pumping rates weresufficient to achieve stimulation and diversion of the entirehorizontal section. Most of the wells used VDA fluidenergized with 30% nitrogen. Treatment rates down the CTwere between 0.15 and 0.24 m3/min. The use of nitrogenaccelerated cleanup, minimized acid leakoff, provided bettercoverage, and reduced acid volume requirements.

Saudi Aramco and Schlumberger engineers found that theproduction rates of the 5 wells after stimulation with VDAfluid were much greater than the average production from11 offset wells that had been stimulated without the VDAsystem (Fig. 6). Water cut in the VDA-treated wells wasmuch lower than in wells treated with other systems. Thiswas because the high-viscosity gel in the water zonesremained intact, whereas the gel formed in the hydrocarbonzones had broken and enabled the acid to migrate furtherinto the matrix. This led to more effective stimulation of the hydrocarbon-bearing zones and higher rates of oil or gas production.

Avoiding damage to the wellWhen operators place acid or other treatment chemicals intheir wells, they have to be sure that any reactions occurringwill be beneficial. If a stimulation job is performed incorrectly,there are potential risks to the oil production, to the well, andto the surface equipment. To optimize the performance of oiland gas wells, the stimulation team should• avoid stimulating water-bearing zones• prevent or treat the development of emulsions or sludges• remove insoluble reaction products• prevent acid damage to the well and the surface equipment.

Water-bearing zones

One of the fundamental requirements for any stimulationprogram is that the increase in conductivity is restricted tothe hydrocarbon zone. Acid or fracture stimulation of water-bearing layers adjacent to the reservoir would lead to asharp rise in water production with the associated issues offluid handling, separation, and disposal. In extreme cases,stimulation of the water zone could end the economic lifeof the well.

1100

800

950

650

500

40

20

30

10

01 2 3 4

Wells treated with VDA fluid

Oil flow rateWater cut

Average productionfrom 11 offset wells

Oilp

rodu

ctio

nra

te,m

3 /d

Wat

ercu

t,%

5

Figure 6: Saudi Aramco and Schlumberger engineers found that thepost-stimulation production rates of the five wells stimulated withVDA fluid were much greater than the average production rates from11 offset wells that had been stimulated without the VDA system.

The VDA system is a self-diverting,

polymer-free acidizing product that

increases zonal coverage in carbonate

reservoirs without residual damage.

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Emulsions and sludges

During fracturing and matrix acidizing, the acid may comeinto direct contact with produced crude oil or well fluids.This may result in the formation of emulsions or sludges.Emulsions can be viscous and may block the treatedformation and reduce oil production. Reservoir engineerscan add anti-emulsifying and antisludging agents to preventthese emulsions forming and demulsifiers to break emulsionsonce they have formed.

Insoluble reaction products

When operators anticipate that a formation will containlarge amounts of acid-insoluble silts or other fines thatcould be released during acidizing, they should treat the acidwith a silt-suspending agent. If left untreated, these solidscan cause severe plugging of pore throats during flow back.By keeping these solids in suspension, the operators canproduce them out of the formation and avoid damaging thewell’s performance.

Most silt-suspending agents are also foaming agents thatadd to the dispersibility of insoluble materials and aid thespeed of cleanup, particularly in gas wells and when usedwith nitrogen or carbon dioxide.

The MSR mud and silt remover is an acid solutioncontaining a clay dispersing-suspending agent and an ironchelating agent. This combination of additives provides gooddispersion of drilling muds and formation silt, and unusuallyeffective suspension properties.

The MSR service is designed to remove drilling muddamage in both carbonate and sandstone formations. It canrestore fracture conductivity in workover operations andreopen clogged perforations. The service also removesdamage from the critical matrix during matrix acidizing andrestores the natural permeability in fissured or fracturedreservoirs after mud losses. The value of combining the MSRservice with SDA technology was underlined in acomparative test of treatments for an injection well (Fig. 7).

Preventing acid damage to well and surface equipment

Corrosion inhibitors prevent acid damage to equipment bothat the surface and in the well. Typically organic compoundsthat adsorb onto metal surfaces, inhibitors are chosen on thebasis of exposure time and temperature. The initial cost ofcorrosion inhibitors may seem very high—they are the singlemost expensive component of the materials used—but thecost of damage to pumping equipment and tubulars if theywere not to be used would be even higher.

400

320

160

240

80

0A B A B

ZoneA B A B

Post-treatmentPretreament

Well 1CT placement with

no diversion

Well 2CT placement with

foam diversion

Well 3Bullhead using gelled acid with

no diversion

Well 4 (Schlumberger treatment)

CT placement with mud and silt removal acid and

temporarily crosslinked acid diversion

Wat

erin

ject

ion

rate

,m3 /d

Egypt: VDA treatment for a dolomitereservoir in EgyptMore than 70 VDA treatment projects have been conductedacross Egypt to date. A specially formulated MSR-dol acidwas used to stimulate the Alamein dolomite formation in adiscovery well, Well 1, in Egypt’s Western Desert.

Well-1 did not flow following perforation and CT lifting withnitrogen. The operator decided to perform an acid treatment.ELANPlus* advanced multimineral log and core analyses hadindicated the presence of pyrite within the pay zone;consequently, the matrix acidizing treatment had to bedesigned to avoid precipitation of iron compounds.

After the treatment program, Well 1 produced oil at around380 m3/d. Encouraged by this, the operator decided to apply asimilar stimulation procedure in two more wells that wereonly producing a few hundred cubic meters of oil per dayfrom the Alamein dolomite. The treatments in wells 2 and 3were enhanced by the addition of VDA polymer-free fluid.

In Well 2, where the MSR-dol acid formula was divertedwith polymer-free VDA fluid, oil production rose to around500 m3/d. The results from Well 3 were even moreimpressive—oil production increased to 1,100 m3/d.

The overall result for this three-well campaign was anincrease in the field’s oil productivity of 1,300 m3/d (Fig. 8).

Figure 7: Combining the MSR* mud silt remover with an iron chelating agent provides gooddispersion of drilling muds and formation silt.

Current challengesIn many countries across the Middle East and Asia,horizontal wells have become the preferred approach fordeveloping carbonate reservoirs. The long sections in someof these wells present major problems for operators whowant to stimulate their wells.

Tailored treatments for long horizontal wells

The efficient placement of conventional acids is critical,especially in long horizontal sections. Owing to their fastreaction rates, acids have to be placed using CT or foam, gel,or other diversion methods. Significant care has to be takenover treatment design when using diversion methods, andthere may be a problem with gel residues.

Applying HCl in extremely long horizontal producingintervals to uniformly remove drilling damage has beenidentified by several operators as being very challenging—the result is usually disappointing well productivity.

Long, openhole horizontal wells provide an efficient wayto develop complex carbonate reservoirs, but there arechallenges in attempting to stimulate these wells.Schlumberger has proposed a new method to optimize thestimulation and boost the production in these wells.

Gas flow

Oil flow

Water flow

Pyrite

Dolomite

Oil

Water

Moved water

Bound water

Lit

0 190m3/d0

Low

0 360240120

Orientation northAmplitude image

High

1,200%ELANPlus volumes

Gas

0

DEFT bubb.

1

Water

Oil

0 1,600m3/d

Figure 8: Increased production following VDA treatment in an Egyptian field.

Notches for even distribution of stimulation fluids

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Mechanical isolation and individual treatments

Carbonate reservoirs can be extremely variable, andtherefore the reservoir zones within a long horizontal wellmay have very different petrophysical characteristics.

Each of the zones would respond in a different way to astandard stimulation treatment. The most effectivestimulation program would treat each zone in the mostappropriate way. Matching the needs of the interval to themost appropriate stimulation technique would seepermeable intervals treated with a scheme of matrixacidizing, while tight zones in the same well could beoptimized with acid fracturing (Fig. 9).

Once all the zones had been optimized in this way, thewhole well could be opened up for production. This pinpointstimulation method has been used in North America and hasclear applications in the Middle East and Asia.

As operating companies continue to produce more advancedand effective strategies for field development, the servicecompanies must respond by generating technology to meetthe new completion methods.

CT is a well-established method for delivering stimulationfluids in horizontal wells. However, in very long openholewells, the CT stimulation method may not be feasible. Forexample, in Saudi Arabia where some of the world’s longesthorizontal wells are being drilled, CT systems cannot reachtotal depth for the well.

In the absence of a CT-based delivery mechanism, someoperators have no option but to bullhead the acid bypumping it from surface at a high rate. Unfortunately, thisapproach tends to concentrate the acid in the heel or toesection of the well and leave the remainder of the holeuntreated (Fig. 10a).

When Saudi Aramco raised this issue at a workshop, aRapidResponse* project was initiated to address the problem.Engineers devised a tool that creates notches in the

1. Low-permeability sandstone reservoir—hydraulic fracturing2. High-permeability carbonate reservoir—matrix fracturing3. Low-permeability carbonate reservoir—acid fracturing

1

2

3

Figure 9: The stimulation techniques used must be matched tothe needs of the various intervals in long horizontal wells foroptimum production.

Acid stimulation restricted to heel or toe of the well

(a)

Slots created with CT and abrasive brine

Acid stimulation along full length of the well

(b)Figure 10: Bullheading acid into a horizontal well tends to concentrate the acid in the heel or toe section of the well and leave theremainder of the hole untreated (a). Notches created along the length of the borehole wall tend to fill with acid, which distributes the effects of the treatment along the well (b).

formation within the borehole. The tool pumps an abrasivefluid through a special nozzle to create a series of long, widenotches that penetrate approximately 35 cm into theformation. Acid treatments will tend to flow into thesenotches, and this will, if the notches are distributed alongthe length of the borehole, spread the effects of thetreatment fluid along the well (Fig. 10b). This technique hasbeen extensively tested, and it is hoped that field trials willbe conducted soon.

Acid stimulation restricted to heel or toe of the well

(a)

Slots created with CT and abrasive brine

Acid stimulation along full length of the well

(b)

As operating companies continue to produce more advanced andeffective strategies for field development, the service companiesmust respond by generating technology to meet the newcompletion methods.

Horizontalsection

Horizontalsection

Horizontalsection

Horizontalsection

Horizontalsection

Horizontalsection

Horizontalsection

Horizontalsection

Number 8, 2007 63Middle East & Asia Reservoir Review62 Number 8, 2007 Middle East & Asia Reservoir Review

(A) Solid acid at surface reduces HSE impact.

(B) Fluid pumped at high pressurewith solid entrained.

Solid acid acts as proppantin hydraulic fracture.

Acid etches fracture surfaceand creates wormholes.

(C) Solid becomes liquid andstarts to react with the reservoir.

Reservoir zone

No leakoff

Figure 11: The acid is pumped as a solid, and chemical reaction only begins once it has found its way into the fracture. While actingas a proppant to hold the fracture open, the solid hydrolyzes and reacts to etch the fracture surface.

The futureThe high degree of heterogeneity encountered in

carbonate reservoirs makes them very difficult to

manage. As more of the world’s large carbonate oil

reservoirs mature, operators are turning to stimulation

methods to optimize water or gas injection and extend

the productive life of the field.

Efforts to enhance the stimulation of carbonate

reservoirs will depend to a large extent on what is

achieved in other technical areas. Advances across a

range of disciplines, from petrophysical analysis to

geophysical imaging, will help asset teams to manage

their carbonate reservoirs more effectively. The key to

improving oil and gas production from carbonate fields

is a clear understanding of the reservoir—its structure,

lithology, and petrology—combined with an effective

array of stimulation technologies.

Solid acid system to increase fracture length

The effectiveness of a hydraulic fracturing program in tightcarbonate formations depends to a large extent on thelength of the fracture that is created. Pumping HCl into theformation at pressures sufficient to fracture rock typicallycreates fracture lengths in the range 15 to 30 m. In a tightcarbonate reservoir, engineers would like to increase theaverage length of the fractures created to 60 or even 90 m.

A range of techniques to increase fracture length has beenexamined. One of these involves a new acid system that aimsto combine the effectiveness of mechanical fracturing withthe stimulation benefits of an acid fracture treatment. Theacid is pumped as a solid, and only starts to react once it hasfound its way into the fracture (Fig. 11).