2

Trends in Matrix Acidizing

Curtis CroweTulsa, Oklahoma, USA

Jacques MasmonteilEric TouboulSaint-Etienne, France

Ron ThomasMontrouge, France

COMPLETION/STIMULATION

Faced with poor production from a high-permeability reservoir, an operator’s first thought

is a matrix treatment. This commonly involves pumping acid into the near-wellbore region

to dissolve formation damage and create new pathways for production. This article

reviews the state of the art of matrix acidizing and discusses how technical break-

throughs are helping optimize matrix acid jobs.

4

The simple aim of matrix acidizing is toimprove production—reduce skin in reser-voir engineer parlance—by dissolving for-mation damage or creating new pathwayswithin several inches to a foot or twoaround the borehole. This is done by pump-ing treatment fluid at relatively low pressureto avoid fracturing the formation. Comparedwith high-pressure fracturing, matrix acidiz-ing is a low-volume, low-budget operation.

Matrix acidizing is almost as old as oil-well drilling itself. A Standard Oil patent foracidizing limestone with hydrochloric acid[HCl] dates from 1896, and the techniquewas first used a year earlier by the Ohio OilCompany. Reportedly, oil wells increased inproduction three times, and gas wells fourtimes. Unfortunately there was a snag—theacid severely corroded the well casing. Thetechnique declined in popularity and laydormant for about 30 years.

Then in 1931, Dr. John Grebe of the DowChemical Company discovered that arsenicinhibited the action of HCl on metal. Thefollowing year, the Michigan-based Pure OilCompany requested assistance from DowChemical Company to pump 500 gallons of

HCl into a limestone producer using arsenicas an inhibitor. The previously dead wellproduced 16 barrels of oil per day, andinterest in acidizing was reborn. Dowformed a subsidiary later called Dowell tohandle the new business (next page, top).Three years later, Halliburton Oil WellCementing Co. also began providing a com-mercial acidizing service.

Sandstone acidizing with hydrofluoricacid [HF]—hydrochloric acid does not reactwith silicate minerals—was patented byStandard Oil company in 1933, but experi-ments in Texas the same year by an inde-pendent discoverer of the technique causedplugging of a permeable formation. Com-mercial use of HF had to wait until 1940,when Dowell hit on the idea of combiningit with HCl to reduce the possibility of reac-tion products precipitating out of solutionand plugging the formation. The mixture,called mud acid, was first applied in theGulf Coast to remove mudcake damage.1

Oilfield Review

For help in preparation of this article, thanks to A.Ayorinde, Ashland Oil Nigeria Ltd, Lagos, Nigeria; JimCollins, Dowell Schlumberger, Calgary, Alberta, Canada;Harry McLeod Jr, Conoco, Houston, Texas, USA; ArthurMilne, Dowell Schlumberger, Dubai; Carl Montgomery,ARCO Oil and Gas Co., Plano, Texas, USA; GiovanniPaccaloni, AGIP S.p.A., Milan, Italy; and Ray Tibbles,Dowell Schlumberger, Lagos, Nigeria.In this article, CORBAN, FoamMAT, MatCADE,MatTIME, PARAN and ProMAT are trademarks or servicemarks of Dowell Schlumberger; NODAL (productionsystem analysis) and Formation MicroScanner are marksof Schlumberger.1. A classic paper on sandstone acidizing:

Smith CF and Hendrickson AR: “Hydrofluoric AcidStimulation of Sandstone Reservoirs,” Journal ofPetroleum Technology 17 (February 1965): 215-222.

2. For general reference:Economides MJ and Nolte KG (eds): Reservoir Stimu-lation, 2nd ed. Houston, Texas, USA: SchlumbergerEducational Services, 1989.Acidizing: SPE Reprint Series No. 32. Richardson,Texas, USA: Society of Petroleum Engineers, 1991.Schechter RS: Oil Well Stimulation. Englewood Cliffs,New Jersey, USA: Prentice Hall, 1992.

October 1992

nMold of wormholes created by HCl inlimestone from a central conduit. Acid dis-solves the rock as soon as it reaches thegrain surface. Matrix acidizing in carbon-ates aims to create new pathways for pro-duction rather than removing damage.

nEarly acidizingoperations by Dow-ell, a division ofDow Chemicalestablished in 1932.

ChemistryMatrix acidizing of carbonates and silicatesare worlds apart.2 Carbonate rocks, com-prising predominantly limestone anddolomite, rapidly dissolve in HCl and createreaction products that are readily soluble inwater:

CaCO3 + 2HCl → CaCl2 + CO2 + H2OLimestone Hydrochloric Calcium Carbon Water

acid chloride dioxide

CaMg(CO3)2 + 4HCl → Dolomite Hydrochloric acid

CaCl2 + MgCl2 + 2CO2 + 2H2O .Calcium Magnesium Carbon Waterchloride chloride dioxide

The rate of dissolution is limited mainly bythe speed with which acid can be deliveredto the rock surface. This results in rapid gen-eration of irregularly shaped channels,called wormholes (left). The acid increasesproduction by creating bypasses around thedamage rather than directly removing it.

By comparison, the reaction between HFand sandstones is much slower. Mudacidizing seeks to unblock existing path-ways for production by dissolving wellboredamage and minerals filling the interstitial

25

nScanning electron micrographs showing pore-filling clays before and after expo-sure to both regular mud acid and fluoboric acid. In the fluoboric acid micrographs,some clays, lower left, are dissolved while others, kaolinite platelets in the middle ofthe photographs, are partially fused preventing fines migration.

2µ

2µ

Before acid After acid

Mud

aci

dFl

uobo

ric a

cid

pore space, rather than by creating newpathways. The HF reacts mainly with theassociated minerals of sandstones, ratherthan the quartz (right). The acid reactionscaused by the associated minerals—clays,feldspars and micas—can create precipi-tants that may cause plugging. Much of thedesign of a sandstone acid job is aimed atpreventing this (see “HF Reactions in Sand-stones,” below).

The usual practice is to preflush the for-mation with HCl to dissolve associated car-bonate minerals. If these were left to reactwith HF, they would produce calcium fluo-ride [CaF2], which precipitates easily. Thenthe HF-HCl mud acid is injected. Finally,the formation is overflushed with weak HCl,hydrocarbon or ammonium chloride[NH4Cl]. This pushes reaction products farfrom the immediate wellbore zone so that ifprecipitation occurs, production is not tooconstricted when the well is brought backon line.

Another plugging danger is from fine par-ticles, native to the sandstone, dislodged bythe acid but not fully dissolved. To minimizethis eventuality, Shell in 1974 proposedlower pumping rates—less likely to dislodgefines—and, more important, a chemical sys-tem that did not contain HF explicitly,instead creating it through a chain of reac-tions within the formation.3 In principle, thisallows greater depth of penetration andlonger reaction times for maximum dissolu-tion of fines. Since then, several other sys-tems of in-situ generated—so-calledretarded—mud acid systems have been pro-posed. Recently, Dowell Schlumberger

26

introduced a retarded acid system using flu-oboric acid [HBF4]. This hydrolyzes in waterto form HF:4

HBF4 + H2O ↔ HBF3OH + HF .Fluoboric Water Hydroxyfluoboric Hydrofluoricacid acid acid

nConstituents of sandstone, all of which are soluble in

HCl-HF mud acid systems.

Pore-lining clays, e.g. illite

Pore-fillingclays, e.g. kaolinite

Secondary cement:carbonate, quartz

Quartz, feldspars,chert and mica.

As HF is spent, dissolving clays and otherminerals, it is constantly replenishedthrough hydrolysis from the remaining fluo-boric acid. The slow rate of this conversionhelps guarantee a retarded action and there-fore deeper HF penetration. As a bonus, thefluoboric acid itself reacts with the clays and

The reaction of hydrofluoric acid [HF] on the pure

quartz component of sandstone follows these two

equations:

SiO2 + 4HF ↔ SiF4 + 2H2O ,Quartz Acid Silicon Water

tetrafluoride

and

SiF4 + 2F– ↔ SiF62– ,

Silicon hexafluoride

resulting mainly in the silicon hexafluoride anion,

SiF62–.

Reaction with the feldspar, chert, mica and clay

components of sandstones also results in this

anion, but, in addition, produces a range of alu-

minum complexes: AlF2+, AlF2+, AlF3, AlF4

–,

HF Reactions in Sandstones

AlF52– and AlF6

3– (left). The concentration of each

aluminum complex depends on the concentration

of free fluoride ions in the dissolving solution.

Some of these products combine with free

sodium, potassium, and calcium ions to produce

four compounds with varying degrees of solubility

in the spending acid:

• sodium fluosilicate [Na2SiF6],

• sodium fluoaluminate [Na3AlF6],

• potassium fluosilicate [K2SiF6],

• calcium fluosilicate [CaSiF6].

Matrix treatments are always designed to prevent

the formation of these compounds, to remove any

risk of precipitation.

Oilfield Review

3. Templeton CC, Richardson EA, Karnes GT andLybarger JH: “Self-Generating Mud Acid,” Journal ofPetroleum Technology 27 (October 1975): 1199-1203.

4. Thomas RL and Crowe CW: “Matrix TreatmentEmploys New Acid System for Stimulation and Con-trol of Fines Migration in Sandstone Formations,”paper SPE 7566, presented at the 53rd SPE AnnualTechnical Conference and Exhibition, Houston, Texas,USA, October 1-3, 1978.

5. Ayorinde A, Granger C and Thomas RL: “The Appli-cation of Fluoboric Acid in Sandstone Matrix Acidiz-ing: A Case Study,” presented at the 21st Annual Con-vention of the Indonesian Petroleum Association,October 6-8, 1992.

Pro

duct

ion,

BLP

D

4000

0 1 2

3000

2000

1000

0Fluoboric acid treatment

Time, yr

Mud acid treatment

nProduction improvement in a Nigerian oil well after fluoboricacid treatment. The well was initially acidized with mud acid andproduced 850 barrels of liquid per day (BLPD) with a 34% watercut. Production then declined almost to zero, most likely due tofines movement. After fluoboric acid treatment, production rose to2500 BLPD, obviating the need for further acid treatments. Oil pro-duction a year after the treatment was 220 BOPD. (From Ayorinde etal, reference 5, courtesy of Ashland Nigeria.)

silt, forming borosilicates that appear to helpbind the fines to large grains (previous page,top). Recent treatments with fluoboric acidfor Ashland Nigeria have confirmed thepower of this technique (right).5

All in all, sandstone acidizing poses agreater challenge than carbonate acidizingand certainly generates more than its fairshare of controversy among both operatorsand service companies.

DiversionA challenge that must be faced in eitherlithology is diversion. As acid is pumped, itflows preferentially along the most perme-able path into the formation. The acid opensthese paths up even more, and less perme-able, damaged zones are almost guaranteednot to receive adequate treatment. Sometechnique to divert the treatment fluidtoward more damaged formation or dam-aged perforations is therefore mandatory.

There is a variety of diversion techniques(next page). Treatment fluid can be directedexclusively toward a low-permeability zoneusing drillpipe or coiled-tubing conveyedtools equipped with mechanical packers.Alternatively, flow can be blocked at indi-vidual perforations taking most of the treat-ment fluid by injecting ball sealers that seaton the perforations. In carbonates, bridgingagents such as benzoic acid particles or saltcan be used to create a filter cake insidewormholes, encouraging the acid to go else-where. In sandstones, microscopic agentssuch as oil-soluble resins can create a filtercake on the sand face. Chemical diverterssuch as viscous gels and foams created with

October 1992

nitrogen are used to block high-permeabilitypathways within the matrix (see “Divertingwith Foam,” page 30).

The requirements on any diverting agentare stringent. The agent must have limitedsolubility in the carrying fluid, so it reachesthe bottom of the hole intact; it must notreact adversely with formation fluids; it mustdivert acid. Finally, it must clean up rapidlyso as not to impede later production. Ballsealers drop into the rathole as soon as

1. Crowe CW: “Precipitation of Hydrated Silica From SpentHydrofluoric Acid: How Much of a Problem Is It?” Jour-nal of Petroleum Technology 38 (November 1986): 1234-1240.

Silicon hexafluoride also combines with water

to produce colloidal silica [H4SiO4]:

SiF62– + H2O ↔ H4SiO4 + 4HF + 2F– .

This precipitate has proved controversial. Experts

agree that it cannot be avoided, but disagree

about whether it damages the formation. Some

believe it does, but work by Dowell Schlumberger

researcher Curtis Crowe suggests that colloidal

silica coats sandstone particle surfaces, actually

limiting the movement of fines that the treatment

would otherwise dislodge.1

Two other aluminum-based compounds—alumi-

num fluoride [AlF3] and aluminum hydroxide [Al(OH)3]

—may precipitate, following these reactions:

27

Al3 + 3F– ↔ AlF3 ,

and

Al3 + 3OH– ↔ Al(OH)3 .

However, these two compounds can generally be

avoided through proper design of preflush and

mud acid formulation.

Often, acidizing can produce ferrous and ferric

ions, either from dissolving rust in the tubulars or

through direct action on iron minerals in the for-

mation. These ions can then produce more pre-

cipitates: ferric hydroxide [Fe(OH)3] and, in sour

wells, ferrous sulfide [FeS]. Various chelating

and reducing agents are employed to minimize

the impact of these two compounds.

Lastly, damage can arise through the precipita-

tion of calcium fluoride [CaF2], when HF reacts

with the carbonate mineralogy of sandstones:

CaCO3 + HF ↔ CaF2 + H2O + CO2 .

The main technique for avoiding calcium fluoride

precipitation is the HCl preflush, designed to

remove carbonate material before HF is injected.

Precipitates and their potential to damage the

formation remain a fact of life for the matrix

acidizer. But their impact can be greatly mini-

mized through use of an adequate preflush, the

correct mud acid formulation, and the avoidance

of any salts except ammonium chloride.

The question that should always be askedbefore any other is “Why is the well under-producing?” And then: ”Will productionincrease with matrix acidizing?” Productionmay be constricted for a reason other thandamage around the borehole. The only wayto find out is through pressure analysis fromthe deep formation through to the wellhead,using production history, well tests andanalysis of the well’s flowing pressures, suchas provided by NODAL analysis.6

The crude maxim that matrix acidizingwill benefit any well with positive skin has

injection halts or, if they are of the buoyantvariety, they are caught in ball catchers atthe surface. Benzoic acid particles dissolvein hydrocarbons. Oil-soluble resins areexpelled or dissolved during the ensuinghydrocarbon production. Gels and foamsbreak down with time.

In practice, acid and diverting agents arepumped in alternating stages: first acid, thendiverter, then acid, then diverter, and so on.The number of stages depends on the lengthof zone being treated. Typically, one acid-diverter stage combination is planned forevery 15 to 25 ft [5 to 8 m] of formation.

DiagnosisIf the principle of matrix acidizing appearsstraightforward, the practice is a mine fieldof complex decisions. Service companiesoffer a vast selection of acid systems anddiverters, and few people would design thesame job the same way. In addition, matrixacid jobs are low budget, typically between$5000 and $10,000 an operation, so thecareful attention given to planning muchmore expensive acid fracturing treatments isoften missing. Matrix acidizing is tradition-ally carried out using local rules of thumb.Worse, jobs are poorly evaluated.

Openhole completion ?

Gravel packed ?Chemical

Chemical

Yes No

Yes No

Yes No

Coiled tubingavailable ?

Staged treatment required ?

Mechanical

Yes No

Flowback of balls a problem, or high shot density ?

Mechanical ball sealers

Yes NoChemical

Chemical

nChoosing a diversion method for matrix acidizing.

28 Oilfield Review

nTypes of damageand where theycan occur. Diag-nosing locationand type of dam-age is the key tosuccessful matrixacidizing.

nAnalyzing causes of poor production in a gas well using NODALanalysis of well pressures, from downhole to wellhead. In eachfigure, well performance is presented by the intersection of a tub-ing-intake curve—upward-sloping lines, one for each wellheadpressure—and an inflow-performance curve—downward-slopinglines, one for each skin value.

The top NODAL analysis shows inflow performance assumingthe well was perforated at two shots per foot, the bottom analysisassuming 12 shots per foot. The tubing-intake curves are the samein both NODAL figures.

At two shots per foot, decreasing skin with matrix acidizingoffers only marginal production improvement. At 12 shots per foot,matrix acidizing will offer substantial production improvement.

2 shots per foot

3000B

otto

mho

le fl

owin

g pr

essu

re, p

si ×

103

5

12 shots per foot

Gas production rate, Mscf/D

1000100

150001000050000

4

3

2

1

0

5

4

3

2

1

0

3000

1000100

01530

50

030

50

skin

p wellhead

psi

29

several exceptions. Too low a perforationdensity, multiphase flow, and turbulent gasflow are some factors that cause positiveskin in wells that otherwise may be undam-aged. Stimulation expert Harry McLeod ofConoco has established a checklist of warn-ing indicators (see“Causes of High Skin,Other Than Damage,” top, right).7

NODAL analysis, which predicts a well’ssteady-state production pressures, refinesthis checklist. For example, by comparingtubing-intake curves—essentially theexpected pressure drop in the tubing as afunction of production rate—with the well’s

inflow-performance curve—expected flowinto the well as a function of downhole wellpressure—one can readily see if the wellcompletion is restricting flow (top, left).Comparing a NODAL analysis with actualmeasured pressures also helps pinpoint thelocation of any damage. Damage does notoccur only in the formation surrounding theborehole. It can occur just as easily insidetubing, in a gravel-pack or in a gravel-packperforation tunnel (above).

6. Mach J, Proano E and Brown KE: “A Nodal Approachfor Applying Systems Analysis to the Flowing and Arti-ficial Lift Oil or Gas Well, paper SPE 8025, March 5,1979, unsolicited.

7. McLeod HO: “Significant Factors for SuccessfulMatrix Acidizing,” paper NMT 890021, presented atthe Centennial Symposium Petroleum Technologyinto the Second Century, New Mexico Institute ofMining and Technology, Socorro, New Mexico, USA,October 16-19, 1989.

Scales

Organic deposits

Bacteria

Silts and clays

Emulsion

Water block

Wettability change

TubingGravel pack/perforations Formation

Causes of High Skin, Other Than Damage(from McLeod, reference 7.)

High liquid/gas ratio in a gas well > 100 bbl/MMscfHigh gas/oil ratio in an oil well > 1000 scf/bblThree-phase production: water, oil and gasHigh-pressure drawdown > 1000 psiHigh flow rate > 20 B/D/ft

> 5 B/D/shotLow perforation shot density < 4 shots per footWell perforated with zero-degree phasingWell perforated with through-tubing gun, diameter < 2 in.Reservoir pressure > bubblepoint pressure > wellbore pressure

October 1992

Foam, a stable mixture of liquid and gas, has

been used as a diverter in sandstone acidizing

since 1969.1 By the usual criteria, it is almost

perfect. It is cheap to produce; it does a decent

job diverting; it does not interact adversely with

the formation and formation fluids; and it cleans

up rapidly. Foam is produced by injecting nitro-

gen into soapy water—typically, nitrogen occu-

pies 55 to 75% of foam volume. The soapy water

is a mixture of water and small amount of surfac-

tant, or foamer. Injected downhole, foam pene-

trates the pore space where the cumulatively vis-

cous effect of the bubbles blocks further entry of

the treating fluid.

Foam’s only drawback is that with time the

bubbles break and diversion ceases. This can be

seen in laboratory experiments, in which foam is

injected simultaneously through two long sand

packs, one with high permeability mimicking a

thief zone, the other with low permeability mim-

icking a damaged zone (above, right). The cores

are preflushed and then injected with foam. Then,

acid is injected. At first, diversion works fine, with

the low-permeability sand pack taking an

increasingly greater proportion of the acid. But

after about one hour, the foam has broken and the

thief zone starts monopolizing the treatment fluid.

Researchers at the Dowell Schlumberger engi-

neering center at Saint-Etienne, France discov-

ered that this breakdown can be postponed by

saturating the formation with a preflush of surfac-

tant before injecting the foam and also injecting

surfactant with every subsequent stage in the

acid process. The surfactant adheres to the rock

surface and minimizes adsorption of surfactant

contained in foam, preserving the foam.

As before, the foam progressively diverts treat-

ment fluid to the damaged zone, but now the

diversion holds for at least 100 minutes (next

page, top). If necessary, damaged formation can

first be cleaned with mutual solvent to remove oil

in the near-wellbore region—oil destroys

foam—and to ensure the rock surface is water-

wet and receptive to the surfactant.

Yet further improvement to foam diversion can

be achieved by halting injection for about 10 min-

utes after foam injection. The diversion of treat-

ment fluid to the damaged sand pack now takes

effect almost immediately, rather than almost 50

minutes. It seems that given a 10-minute quies-

cent period, foam in low-permeability sand pre-

maturely breaks down—scientists are not sure

why. The combination of surfactant injection and

10-minute shut-in comprises the new FoamMAT

diversion service that has seen successful appli-

cation in the Gulf of Mexico and Africa (see “Field

Case Studies,” below).2

The FoamMAT technique also provides excel-

lent blockage of water zones in high water-cut

wells. In a laboratory simulation, two sand packs

were constructed with the same permeability but

saturated with different fluids, water and oil (next

page, bottom). The preflush injection of surfactant

can be seen to favor, as expected, the water zone.

Then foam was injected into both packs. When

acid was injected, most went into the oil zone

confirming an almost perfect diversion.

30 Oilfield Review

Aci

d

Foam

Thief zone

Damaged zonePre

flush

Flow

rat

e, b

bl/m

in/2

0-ft

zone

0.75

0.5

0.25

0

1

0 10 20 30 40 50 60 70 80 90 100Time, min

1.25

Fluid N2

P P

Thie

f

Dam

age

nLaboratory setup forinvestigating foam diver-sion, using two sandpacks, one with highpermeability mimickinga thief zone, the otherwith low permeabilitymimicking a damagedzone. Conventional foamdiversion works fine fora while—60 minutes inthis example—but thenbreaks down.

Diverting with Foam

Field Case StudiesWell type

High water-cutoil well

Gas well

Oil well

Low-perm gas well

9600

6600

11200

11,900

51

16

40

200

190

175

240

245

433 BOPD41% water cutGas lift

2 MMscf/D3 BOPDFTP: 1000 psi

0

1.8 MMscf/DFTP: 250 psi

855 BOPD38% water cutFTP: 2100 psi @ 2 months

5.6 MMscf/D17 BOPDFTP: 2100 psi @ 2 months

860 BOPDFTP: 220 psi @ 1 week

4.0 MMscf/DFTP: 400 psi @ 1 month

Depthft

Intervalft

Temperature°F

Productionbefore after

nImprovement in stay-ing power of foam diver-sion, using a preflush ofsurfactant and furthersurfactant injection withthe acid (top). Furtherimprovement in foamdiversion is obtained byhaving a shut-in periodfollowing foam injection(bottom). During thisquiescent period, foamin low-permeability sandsbreaks down and diver-sion becomes immediate.

nEfficacy of FoamMATdiversion in high water-cut wells, proved in alaboratory experimentusing two sand packsof the same permeabil-ity, but initially saturatedwith oil and water,respectively.

DamageScales, organic deposits and bacteria arethree types of damage that can cause havocanywhere, from the tubing to the gravelpack, to the formation pore space. Scalesare mineral deposits that in the lower pres-sure and temperature of a producing wellprecipitate out of the formation water, form-ing a crust on formation rock or tubing.With age, they become harder to remove.The treatment fluid depends on the mineraltype, which may be a carbonate deposit,sulfate, chloride, an iron-based mineral, sili-cate or hydroxide. The key is knowingwhich type of scale is blocking flow.

Reduced pressure and temperature alsocause heavy organic molecules to precipi-tate out of oil and block production. Themain culprits are asphaltenes and paraffinicwaxes. Both are dissolved by aromatic sol-vents. Far more troublesome are sludgesthat sometimes occur when inorganic acidreacts with certain heavy crudes. There isno known way of removing this type ofdamage, so care must be taken to avoid itthrough use of antisludging agents.

Bacteria are most commonly a problem ininjection wells, and they can exist in anamazing variety of conditions, with andwithout oxygen, typically doubling theirpopulation every 20 minutes or so.8 Theresult is a combination of slimes andassorted amorphous mess that blocks pro-duction. An additional reason for cleansingthe well of these organisms is to kill the so-called sulfate-reducing bacteria that live offsulfate ions in water either in the well orformation. Sulfate-reducing bacteria pro-duce hydrogen sulfide that readily corrodestubulars. Bacterial damage can be cleanedwith sodium hypochlorite and it is as impor-tant to clean surface equipment, whenceinjection water originates, as it is to cleanthe well and formation.

Two further types of damage can con-tribute to blocked flow in gravel pack andformation—silts and clays, and emulsions.Silts and clays, the target of most mud acidjobs and 90% of all matrix treatments, canoriginate from the mud during drilling andperforating or from the formation when dis-lodged during production, in which casethey are termed fines. When a mud acidsystem is designed, it is useful to know thesilt and clay composition, whatever its ori-gin, since a wrongly composed acid canresult in precipitates that block flow even

31October 1992

No shut-in

Foam

Pre

flush

Flow

rat

e, b

bl/m

in/2

0-ft

zone

0.75

0.5

0.25

0

1

0 10 20 30 40 50 60 70 80 90 100Time, min

1.25

Shu

t-in

A

cid

Foam

Thief zone

Damaged zone

Pre

flush

Flow

rat

e, b

bl/m

in/2

0-ft

zone

0.75

0.5

0.25

0

1

1.25

Shut-in

Aci

d

Thief zone

Damaged zone

AcidFoam

Oil zone

Water zone

Preflush

Flow

rat

e, b

bl/m

in/2

0 ft

zone

0.75

0.5

0.25

0

1

0 5 10 15 20 25 30 35 40 45 50Time, min

1.25

8. “Bacteria in the Oil Field: Bad News, Good News,”The Technical Review 37, no. 1 (January 1989): 48-53.

1. Smith CL, Anderson JL and Roberts PG: “New DivertingTechniques for Acidizing and Fracturing,” paper SPE2751, presented at the 40th SPE Annual CaliforniaRegional Meeting, San Francisco, California, USA,November 6-7, 1969.A recent case-study paper:Kennedy DK, Kitziger FW and Hall BE: “Case Study of theEffectiveness of Nitrogen Foam and Water-Zone DivertingAgents in Multistage Matrix Acid Treatments,” SPE Pro-duction Engineering 7, no. 2 (May 1992): 203-211.

2. Zerhboub M, Touboul E, Ben-Naceur K and Thomas RL:“Matrix Acidizing: A Novel Approach to Foam Diversion,”paper SPE 22854, presented at the 66th SPE AnnualTechnical Conference and Exhibition, Dallas, Texas, USA,October 6-9, 1991.

more. Emulsions can develop when waterand oil mix, for example when water-basemud invades oil-bearing formation. Emul-sions are highly viscous and are usuallyremoved using mutual solvents.

The interplay of oil and water in porousrock provides two remaining types of dam-age occurring only in the formation—wetta-bility change and water block. In theirnative state, most rocks are water-wet,which is good news for oil production. Thewater clings to the mineral surfaces leavingthe pore space available for hydrocarbonproduction. Oil-base mud can reverse thesituation, rendering the rock surface oil-wet,pushing the water phase into the pores andimpeding production. A solution is to injectmutual solvent to remove the oil-wettingphase and then water-wetting surfactants toreestablish the water-wet conditions.

Finally, water block occurs when water-base fluid flushes a hydrocarbon zone socompletely that the relative permeability tooil is reduced to zero—this can occur with-out a wettability change. The solution isagain mutual solvents and surfactants, thistime to reduce interfacial tension betweenthe fluids, and to give the oil some degreeof relative permeability and a chance tomove out.

DesignAssessing the nature of the damage is diffi-cult because direct evidence is frequentlylacking. The engineer must use all availableinformation: the well history, laboratory testdata, and experience gained in previousoperations in the reservoir. The initial goal,of course, is selecting the treatment fluid.Later, the exact pumping schedule—vol-umes, rates, number of diverter stages—must be worked out.

Since carbonate acidizing with HCl cir-cumvents damage, the main challenge offluid selection lies almost entirely with sand-stone acidizing where damage must beremoved. Laboratory testing on cores andthe oil can positively ensure that a givenHF-HCl mud acid system will perform asdesired—it is particularly recommendedwhen working in a new field. These testsfirst examine the mineralogy of the rock tohelp pick the treating fluid. Then, compati-bility tests, conducted between treating fluidand the oil, make sure that mixing themproduces no emulsion or sludge. Finally, anacid response curve is obtained by injectingthe treating fluid into a cleaned core plug,under reservoir conditions of temperatureand pressure, and monitoring the resultingchange in permeability. The acid response

curve indicates how treating fluid affects therock matrix—the design engineer strives fora healthy permeability increase.

Most treatment fluid selection for sand-stone acidizing builds on recommendationsestablished by McLeod in the early 1980s.9The choice is between different strengths ofthe HCl-HF combination and depends onformation permeability, and clay and siltcontent (below). For example, higherstrengths are used for high-permeability rockwith low silt and clay content—high strengthacid in low-permeability rock can createprecipitation and fines problems. Strengthsare reduced as temperature increasesbecause the rate of reaction then increases.

McLeod’s criteria have since beenexpanded by Dowell Schlumberger.10

Recently, this updated set of rules has beenmerged with about 100 additional criteriaon the risks associated with pumping com-plex mixtures of fluids into the matrix, andincorporated into a computerized expertsystem to help stimulation engineers pickthe best treatment system.11 The systemactually presents several choices of treatingfluid and ranks them according to efficiency.When the engineer chooses, the genericallydefined fluids are mapped on to the catalogof products offered by the service company.

32 Oilfield Review

nEvolution of acidsystem guidelinesfor sandstones tomaximize damageremoval and mini-mize precipitates.The first guidelinesin 1983 consisted ofa few rules. Thesewere expanded tomore complextables in 1990.Now, knowledge-based systemsincorporate hun-dreds of rules onfluid choice.

Acid Guidelines for Sandstones

1983Condition

HCl solubility (> 20%)

High permeability (>100 md)

High quartz (80%), low clay (< 5%)

High feldspar (> 20%)

High clay (> 10%)

High iron chlorite clay

Low permeability (< 10 md)

Low clay (< 5%)

High chlorite

1990Mineralogy

High quartz (> 80%), low clay (< 10%)

High clay (> 10%), low silt (< 10%)

High clay (> 10%), high silt (> 10%)

Low clay (< 10%), high silt (> 10%)

< 200°F

> 200°F

Permeability

> 100 md

12% HCl, 3% HF

7.5% HCl, 3% HF

10% HCl, 1.5% HF

12% HCl, 1.5% HF

10% HCl, 2% HF 6% HCl, 1.5% HF 6% HCl, 1% HF

4% HCl, 0.5% HF

6% HCl, 0.5% HF

8% HCl, 0.5% HF

4% HCl, 0.5% HF

6% HCl, 0.5% HF

8% HCl, 0.5% HF

6% HCl, 1% HF

8% HCl, 1% HF

10% HCl, 1% HF

20 to 100 md

10% HCl, 2% HF

6% HCl,1% HF

8% HCl,1% HF

10% HCl,1% HF

< 20 md

6% HCl, 1.5% HF

4% HCl, 0.5% HF

6% HCl, 0.5% HF

8% HCl, 0.5% HF

Main Acid

Use HCl only

12% HCl, 3% HF

13.5% HCl, 1.5% HF

6.5% HCl, 1% HF

3% HCl, 0.5% HF

6% HCl, 1.5% HF

3% HCl, 0.5% HF

Preflush

15% HCl

15% HCl

Sequestered 5% HCl

Sequestered 5% HCl

7.5% HCl or 10% acetic acid

5% acetic acid

9. McLeod HO: “Matrix Acidizing,” Journal of Petro-leum Technology 36 (December 1984): 2055-2069.

10. Perthuis H and Thomas R: Fluid Selection Guide forMatrix Treatments, 3rd ed. Tulsa, Oklahoma, USA:Dowell Schlumberger, 1991.

11. Chavanne C and Perthuis H: “A Fluid SelectionExpert System for Matrix Treatments,” presented atthe Conference on Artificial Intelligence inPetroleum Exploration and Production, Houston,Texas, USA, July 22-24,1992.

12. The ProMAT system calls on two software packages:the MatCADE software for design and postjob eval-

Damage type

Fluid descriptionFluid sequence

VolumesNumber of diverter stagesInjection rates

Flow profile evolutionSkin evolutionRate/pressure plots

Production ratesPayout time

Preflush 15% HCl, Surf, Cor. Inh.Main flush 3% HF, 12% HCl, Surf.Overflush 5% HCl, Surf, Cor. Inh.

Preflush 15% HCl, F78, A260Main flush RMA, F78, A260Overflush 5% HCl, F78, A260

Damage removalmechanism

3% HF,12% HCl

Risk analysis

Product mapping

Well completion data

Formation damage mineralogyDiagnostics

Fluid selectionadvisor

Pumping scheduleadvisor

Simulator

Productionprediction

nFive essential steps in designing a matrix acidizing job, as incorporated in the DowellSchlumberger ProMAT software package. Detail (right) shows breakdown of fluid selec-tion—with initial choice of main treating fluid, design of all fluid stages and mapping ofgeneric fluids to service company products.

1. Brannon DH, Netters CK and Grimmer PJ: “Matrix Acidizing Designand Quality-Control Techniques Prove Successful in Main PassArea Sandstone,” Journal of Petroleum Technology 39 (August1987): 931-942.

nA pumping schedule computed with ProMAT software, listing for each stage the fluidvolume, pump rate and pump time. This schedule can be input to a simulator to predictdetailed outcome of the matrix acid job, such as skin improvement.

HCI 4%

RMA 13/31

Pumping Schedule for a Two-Stage Job

Stage 1

Stage 2

1

2

3

4

5

6

7

8

9

10

Preflush

Main fluid

Overflush

Overflush

Diverter slug

Preflush

Main fluid

Main fluid

Overflush

Tubing displ.

HCI 15%

HCI 4%

HCI 15%

RMA 13/31

HCI 4%

J237A2

RMA 13/31

NH4Cl brine 3%

17.3

68.2

20.7

17.3

55.6

33.0

33.0

3.1

12.6

53.7

2.2

2.2

4.8

4.8

1.1

1.2

2.4

4.8

4.8

1.1

7.9

13.8

0.6

2.6

48.8

31.0

4.3

3.6

50.5

27.5

Step Fluid Volumebbl

Flow ratebbl/min

Timemin

1. Regular Mud Acid, 13% HCl, 3% HF. 2. Four-micron particulate oil-soluble resin, usable up to 200°F.

This fluid selection advisor forms onemodule of the ProMAT productive matrixtreatment system that Dowell Schlumbergerrecently introduced to improve the some-times unacceptable results of matrix acidiz-ing (top). The ProMAT system provides com-puter assistance for every step of welldiagnosis, and the design, execution andevaluation of matrix acidizing.12 The pack-age begins with the previously described

uation, and the MatTIME package for job executionand real-time evaluation.October 1992

NODAL analysis for diagnosing why a wellis underproducing, then follows with theexpert system for fluid selection.

The third component develops a prelimi-nary pumping schedule to ensure a skinvalue of zero—how many stages of treatingfluid, how many diverting stages, howmuch to pump in each stage, etc. (above).The fourth component is a detailed simula-tion of the acidization process. Given apumping schedule, it provides detailed

Matrix acidizing is generally suc-cessful in a damaged formation solong as the well is properly pre-pared and only clean fluids enterthe perforations during treatment.

Harry McLeod,senior engineering pro-

fessional in the drilling

division, production

technology department,

Conoco Inc. Houston,

Texas, USA.

Commentary: Harry McLeod

In carbonate formations, scale is the most com-mon damage. In sandstone formations, the mostcommon damage occurs during or just after perfo-rating and during subsequent workovers as a resultof losing contaminated fluids to the formation.

When wells are not properly evaluated with acombination of NODAL analysis, and either core ordrillstem test data, treatments are often unsuc-cessful because restrictions other than formationdamage are present, as discussed in this article.Only in recent years has proper attention beengiven to well preparation and on-site supervision.

Improvements in Conoco matrix treatment oper-ations have been obtained by either pickling theproduction tubing or avoiding acid contact with theproduction string through the use of coiled tubing.The best results are obtained with effective divert-ing procedures that ensure acid coverage andinjection into every damaged perforation. In 1985,Conoco achieved a 95% success ratio in a 37-welltreatment program using a complete quality con-trol program and effective diversion.1

More effective diverter design and improvedmodels of dissolution and precipitation based onrock characterization are still needed, especiallyin sandstones with less than 50-md permeabilityand for downhole temperatures above 200°F[93°C].

forecasts of injection flow profiles, of theimprovement in skin per zone as the jobproceeds and of the overall rate/pressurebehavior to be expected during the job.This information either confirms the previ-ously estimated pumping schedule or sug-gests minor changes to guarantee optimumjob performance. The fifth and final moduleuses the results of the simulation to predictwell performance after the operation andtherefore the likely payback, the acid testfor the operator.

At the heart of both the pumping scheduleadvisor and simulator are models of how anacidizing job progresses. In most of thedetails, the advisor’s model is simpler thanthe simulator’s, and even the simulatormodel is simple compared with reality.Acidizing physics and chemistry are highlycomplex and provide active research for oilcompanies, service companies and universi-ties alike.13 For job design, simple modelshave the advantage of requiring few inputparameters but the disadvantage of cuttingtoo many corners. Complex models may

Diverter deposition at perfoInjectionpoint

Fluids intermixing while progre

Well

Fa

PressDarcy

Acid a

M

Poro

nSimulating a matrixacid job, stage bystage, using a radiallysymmetric model of theformation and analysisof the main controllingfactors in matrixacidizing: acid anddiverter flow, formationdissolution, diverterdeposition, and poros-ity and permeabilitychange. This sequenceof computations ismade simultaneouslyfor all blocks and insmall time steps.

34

mimic reality better, but they introduce moreparameters, some of which may be unmea-surable in the field or even in the laboratory.

Whatever their level of sophistication,acidizing models must deal with four pro-cesses simultaneously: • tracking of fluid stages as they are

pumped down the tubing, taking intoaccount differing hydrostatic and frictionlosses

• movement of fluids through the porousformation

• dissolution of damage and/or matrix byacid

• accumulation and effect of diverters. All four phenomena are interdependent.Diverter placement depends on the injec-tion regime; the injection regime dependson formation permeability; formation per-meability depends on acid dissolution; aciddissolution depends on acid availability;acid availability depends on diverter place-ment; and so on.

The computation proceeds fluid stage byfluid stage (below). The time taken for each

rations

ssing

or each block nd each time step...

ure and flow rate using 's law

nd diverter transportation

ineral dissolution

Diverter deposition

sity/permeability change

Next time step

Gravity in welland layers

stage is subdivided into a series of smalltime steps and this chain reaction is evalu-ated for each step. The results after one timestep serve as the input to the next. In addi-tion, for the more sophisticated simulation,the formation is split into a mosaic of radi-ally symmetric blocks. At each time step,the evaluation must be performed for allblocks simultaneously. The simulator pro-vides a detailed prediction of how the acidjob will progress and the expected improve-ment in skin and productivity (next page,above). This helps decide the bottom line,which is time to payback.

Execution and EvaluationSophisticated planning goes only part wayto ensuring the success of a matrix acidizingoperation. Just as important is job executionand monitoring. In a study of 650 matrixacidizing jobs conducted worldwide forAGIP, stimulation expert GiovanniPaccaloni estimated that 12% were outrightfailures, and that 73% of these failures weredue to poor field practice.14 Just 27% of thefailures were caused by incorrect choice offluids and additives. Success and failurewere variously defined depending on thewell. Matrix acidizing a previously dryexploration well was judged a success if theoperation established enough production topermit a well test and possible evaluation ofthe reservoir. The success of a productionwell was more closely aligned with achiev-ing a specific skin improvement. Havingidentified the likely reason for failure, AGIP

Oilfield Review

13. University of Texas:Walsh MP, Lake LW and Schechter RS: “A Descrip-tion of Chemical Precipitation Mechanisms andTheir Role in Formation Damage During Stimulationby Hydrofluoric Acid,” Journal of Petroleum Tech-nology 34 (September 1982): 2097-2112.Taha R, Hill AD and Sepehrnoori K: “Simulation ofSandstone-Matrix Acidizing in HeterogeneousReservoirs,” Journal of Petroleum Technology 38(July 1986): 753-767.Dowell Schlumberger:Perthuis H, Touboul E and Piot B: “Acid Reactionsand Damage Removal in Sandstones: A Model forSelecting the Acid Formulation,” paper SPE 18469,presented at the SPE International Symposium onOilfield Chemistry, Houston, Texas, USA, February8-10, 1989.Shell:Davies DR, Faber R, Nitters G and Ruessink BH: “ANovel Procedure to Increase Well Response toMatrix Acidising Treatments,” paper SPE 23621, pre-sented at the Second SPE Latin American PetroleumEngineering Conference, Caracas, Venezuela, March8-11, 1992.

14. Paccaloni G and Tambini M: “Advances in MatrixStimulation Technology,” paper SPE 20623, pre-sented at the 65th SPE Annual Technical Conferenceand Exhibition, New Orleans, Louisiana, USA,September 23-26, 1990.

nSimulation resultsshowing the differ-ence between one-and two-stagematrix acid jobs ona damaged oil wellknown to producefrom two layers.The one-stage job(left) fails to removedamage from layer2, which is left witha skin of 10. Thetwo-stage jobdiverts the secondacid stage towardthis layer, bringingthe skin of theentire well to zero.

Assuming a$15/barrel price foroil, the paybackafter 30 days is$330,000 for theone-stage job and$520,000 for theslightly moreexpensive two-stage job. The prop-erly designed, morecomplex operationappears a reason-able option.

0 60 120 180 240 300

Volume, bbl

1

2

Two-stage

1

2

Tota

l ski

n

0

Volume, bbl

2

4

Flow

rat

e, b

bl/m

inS

kin

per

laye

r

2

6

10

0

10

20

30

20 40 60 80 100 120 1400

1

2

Layer 1

Layer 2

14

18

HC

l 4%

One-stage

HC

l 15%

RM

A 1

2/3

Div

erte

r sl

ug J

237A

HC

l 15%

HC

l 4%

RM

A 1

2/3

HC

l 4%

HC

l 15%

RM

A 1

2/3

Div

erte

r sl

ug J

237A

NH

4Cl b

rine

3%

HC

l 15%

RM

A 1

2/3

HC

l 15%

HC

l 4%

RM

A 1

2/3

HC

l 4%

Div

erte

r sl

ug J

237A

HC

l 15%

RM

A 1

2/3

Div

erte

r sl

ug J

237A

HC

l 4%

NH

4Cl b

rine

3%

HC

l 15%

RM

A 1

2/3

HC

l 15%

NH

4Cl b

rine

3%

HC

l 4%

RM

A 1

2/3

HC

l 4%

Div

erte

r sl

ug J

237A

HC

l 15%

RM

A 1

2/3

Div

erte

r sl

ug J

237A

HC

l 4%

Commentary: Giovanni Paccaloni

After several decades of field practice, countless lab studies and theoretical investigations,matrix acidizing technology is today one of the most powerful tools available to the oil indus-try for optimizing production. There is still much room for improvement, however. Reasons are:

October 1992

Giovanni Paccaloni, head of production

optimization technologies

department at

AGIP headquarters in

Milan, Italy

• the relatively low operational cost compared tothe economic benefits

• the great complexity of the physicochemistryphenomena involved, as yet only partially mod-eled

• the low attention paid so far to the evaluationand to the understanding of actual field acidresponse, the evolution of skin with treatmentfluid injected

• the lack of exhaustive studies matching lab andfield results

• the negligible amount of lab work with radialcores, which may provide skin evolution datathat linear cores cannot

• the low attention paid so far to validating acidiz-ing techniques using pressure build-up tests andflowmeter surveys

35

• the small degree of integration between differentdisciplines— lab scientist, field engineer, pro-duction/petroleum engineer, and academia

• the prevailing attitude to preserve consolidated“rules” based more often on the microscalesimulation of reality than on the study of reality,i.e., actual well response.

All of the above are receiving intense attention atAGIP. R&D efforts are directed to improving thesuccess ratio and lowering costs, with the underly-ing idea that any new technique must be validatedwith field results. Much attention is given to theinterdisciplinary approach, to improved training,and to finalized R&D projects. Three expert sys-tems dealing with matrix acidizing design, forma-tion damage diagnosis and well problem analysishave been recently released to our operating dis-tricts. New matrix acidizing technologies, devel-oped in-house, are currently under field test. Thelaboratory study of skin evolution simulating actualfield conditions is one of our major concerns.

Ski

n

Mud acid treatment Slug diversion

HC

l

Mud

aci

d

Ove

rflus

h

Auxiliary measurements

Fluid density Flow rate Treating pressure Annular pressure

Aci

d

Div

erte

r

Div

erte

r

Aci

d

Aci

d

Real-time skin value

Wellsite

Time

nMonitoring skin in real time using Dowell Schlumberger’s MatTIME wellsite measure-ment and analysis system. The general principle (top) is to continue pumping acid forany given stage while skin continues decreasing and change to the next fluid stage onlyafter skin has levelled off for a while. When diversion is used, skin increases (bottom).Final effective skin can be estimated by subtracting the net increases due to diversionfrom the value indicated at the end of the job.

1. For general reading:

Frick TP and Economides MJ: “Horizontal Well DamageCharacterization and Removal,” paper SPE 21795, pre-sented at the Western Regional Meeting, Long Beach,

followed up almost all the failures with asecond acid job. This not only resulted inimproved production, but also confirmedthe failure diagnosis in each case.

Reasons for poor field operation centeredon the technique of bullheading, in whichacid is pumped into the well, pushing dirtfrom the tubing and whatever fluids arebelow the packer, often mud, directly intothe formation. Bullheading can be avoidedby using coiled tubing to place acid at theexact depth required, bypassing dirt and flu-ids already in the well. Paccaloni recom-mends use of coiled tubing whenever possi-ble—its benefit for acidizing horizontalwells has been well documented (see “Hori-zontal Wells: Bullheading Versus CoiledTubing,” next page).

36

15. McLeod HO and Coulter AW: “The StimulationTreatment Pressure Record—an Overlooked Forma-tion Evaluation Tool,” Journal of Petroleum Technol-ogy 21 (August 1969): 951-960.

16. Paccaloni G: “New Method Proves Value of Stimula-tion Planning,” Oil & Gas Journal 77 (November 19,1979): 155-160.

California, USA, March 20-22,1991.

Economides MJ and Frick TP: “Optimization of HorizontalWell Matrix Stimulation Treatments,” paper SPE 22334,presented at the SPE International Meeting on PetroleumEngineering, Beijing, China, March 24-27, 1992.

What helped AGIP identify and correctthe failures, though, was reliable real-timemonitoring of each job, particularly thetracking of skin. If skin improves with time,the job is presumably going roughly asplanned and is worth continuing. If skinstops improving or gets worse, then it maybe time to halt operations. The problem ini-tially was the poor quality of field measure-ments, traditionally simple pressure charts.Then in 1983, digital field recording of well-head pressures was introduced. Today, fluiddensity, injection flow rates, wellhead andannulus pressures are recorded and ana-lyzed at the wellsite (above).

Three methods have been proposed tomonitor skin. In 1969, McLeod and Coultersuggested analyzing the transients createdbefore and after treatment fluid injection.15

The analysis was performed after job execu-tion and therefore not intended to be a real-time technique. In 1979, Paccaloni formu-lated a method that assumes steady-stateflow and ignores the transients, but that pro-vides a continuous estimate of skin in realtime.16 Paccaloni used this method to suc-cessfully analyze causes of failure in his sur-vey of AGIP matrix jobs.

(continued on page 39)

The key issue in matrix acidizing horizontal wells

is acid placement, since both damaged and thief

zones can be hundreds of feet long.1 The two

techniques used are bullheading and coiled-tub-

ing placement.

Acidizing horizontal wells by bullheading fol-

lows conventional practice, with alternating

stages of acid and diverter. Coiled tubing, on the

other hand, allows accurate placement of diverter

into thief zones before acid is pumped—thief zones

can be identified from production logs, Formation

MicroScanner images or mud logs. After the thief

zones have been treated by positioning the coiled

tubing opposite them and injecting diverter, the

coiled tubing is run to total depth and gradually

withdrawn as acid is pumped. Simultaneous with-

drawal and injection provides the most even cov-

erage. If inadequate data are available to identify

thief zones, acid and diverter stages can be alter-

nated as the coiled tubing is withdrawn.

Simulations illustrate the effectiveness of the

coiled-tubing technique over bullheading. The

horizontal well used for the simulations has a

1000-ft producing section drilled in sandstone

with severe bentonite drilling-mud damage along

all of it except for a 200-ft long thief zone.

Bullheading 25 gallons of half-strength mud

acid removes damage in the first 400 ft of the

hole, but fails to make much impact on the sec-

tion beyond the thief zone (next page,top). The

thief zone initially accepts about one-half of the

treatment fluid, and with time the upper section

becomes a second thief zone. The section beyond

the thief zone takes only 20% of the treatment

fluid, resulting in poor damage removal.

Oilfield Review

n

i

nBullheading with diverter in a series of nine stages. Once the firstdiverter stage is pumped, flow into the thief zone is arrested and practi-cally equal flows go into the upper and lower sections. Skin decreaseseverywhere.

October 1992

Time, hrs

0.4

1 2 3 4 5

Rat

e, b

bl/m

in

Thief zone

Lower section

Upper section

14

12

10

8

6

4

2

0

-2

Ski

n

Upper section

Lower section

Thief zone

0.6

0.8

1.0

1.2

Thief zone200 ft

Upper section400 ft

Lower section400 ft

Time, hrs

0.4

1 2 3 4 5

Rat

e, b

bl/m

in

14

12

10

8

6

4

2

0

-2

Ski

n

0.6

0.8

1.0

1.2

nUse of coiled tubing to pump diverter into thief zone and then acidiz-ing the well by gradually withdrawing the tubing ensure skin reductioneverywhere in the horizontal section.

14

12

10

8

6

4

2

0

-21 2 3 4 5

Time, hrs

Ski

n

Upper section

Lower section

Horizontal Wells: Bullheading Versus Coiled Tubing

nSimulation of bullheading acid into a horizontal well with a thief zone.Lower section receives little acid and shows poor skin improvement.

Bullheading acid and diverter in a series of

ine alternating stages provides a dramatic

mprovement (above). The flow rate into the thief

zone decreases dramatically once the first

diverter stage is pumped, and practically equal

flows then go into the lower and upper zones

resulting in uniform skin improvement.

By using coiled tubing to inject diverter into the

thief zone before pumping acid, virtually uniform

penetration can be achieved (left). In the simula-

tion, both upper and lower damaged zones are

nearly restored to their natural permeability.

Such effective diversion occurs less readily in

carbonates acidized with HCl, where the rapid

reaction tends to counter the effectiveness of

most diversion techniques. However, field exam-

37

ples show the benefits of using coiled tubing,

rather than simple bullheading of the acid.

In a 1500-ft long horizontal injector in a Middle

East limestone reservoir, most of the 4000 B/D

injected was entering the first 450 ft of the hori-

zontal trajectory and none was entering beyond

900 ft—see the production log made before acid

treatment (right). A treatment was then performed

by running coiled tubing to the end of the well and

pumping 15% HCl at the rate of 10 gallons per

foot as the tubing was withdrawn. When the

coiled tubing had been withdrawn to the begin-

ning of the horizontal section, 15 gallons-per-foot

additional HCl were bullheaded into the formation.

Injection was subsequently 5500 B/D. The post-

treatment production log shows most of the

increase is entering the first 450 ft of well. But

there is some increase between 800 and 900 ft,

probably the result of using coiled tubing. There

is still no injection beyond 900 ft. Incidentally, no

diverters were used in the treatment. Experience

in nearby limestone reservoirs using conven-

tional benzoic flake and rock salt diverting agents

did not improve coverage significantly.

A second example comes from a horizontal

well drilled in fractured dolomite in Shell Canada

Ltd’s Midale field, Saskatchewan, Canada. Ini-

tially, this pumping well produced 240 BLPD with

water cut rising to near 99%.

Logs made with coiled tubing suggested that

the well probably intersected the desired frac-

tured dolomite at three separate points—at the

heel, midpoint and toe of the horizontal trajec-

tory. Otherwise, it strayed into an overlying tight

zone. Production logs, obtained using nitrogen lift

with the coiled tubing, showed that the heel zone

at low pressure (1200 psi) was not producing,

while the toe zone at high pressure (2000 psi)

was producing water—probably from the field’s

waterdrive scheme. An acid treatment was there-

fore planned to improve oil production from the

heel and minimize treatment of the water zone.

Initially, the entire horizontal section was cir-

nPre- and postacid production logs from the first900 ft of a 1500-ft long horizontal injector in a Mid-dle East limestone reservoir. Small improvementsin injection beyond 450 ft are probably due to usingcoiled tubing for acid placement. There was no sig-nificant injection beyond 900 ft either before orafter treatment.

38 Oilfield Review

800

600

400

200

00 6000B/D

Flow RateAfter-Acid

0 6000B/DFlow RateBefore-Acid

Dep

th, f

t

Horizontal section, mProduction log

Pre-acid temperature log

1403

1404

1405

1406

True

ver

tical

dep

th, m

Tight zone

Fractured zone

100 150 200 250 300

Stimulation targets

Postacid temperature log

p =2000 psi

p =1200 psi

nPre- and posttemperature profiles, after injecting cool water, confirm matrix acid success usingcoiled-tubing deployment in a Shell Canada well in Saskatchewan.

culated with foamed gel, resulting in a 90%

decrease in injection rate. Then, 10 gallons-per-

foot of 15% HCl was injected across two zones

near the end of the well while withdrawing the

coiled tubing. More diverting foam was then

injected. Seven gallons-per-foot of 15% HCl were

then injected over a long zone at the heel of the

well, again while withdrawing coiled tubing, fol-

lowed by more diverter and then a repeat injec-

tion of acid across the same zone.

The effect of this treatment can be seen by

comparing pre- and posttreatment temperature

profiles (below). These were obtained by pumping

water into the well for a period and then record-

ing temperature along the horizontal trajectory. A

temperature decrease with depth indicates

acceptance of the cool, injected water; no

decrease indicates that no water was accepted

and that the zone is unlikely to produce. In this

example, considerable improvement can be seen

in both the heel and targeted stimulation areas.

When the well was put back on a pump, produc-

tion increased to 300 BLPD, the pumping limit,

and oil production increased from 3 to 48 BOPD.

Most recently, Laurent Prouvost andMichael Economides proposed a methodthat takes into account the transients andcan be computed in real time using theDowell Schlumberger MatTIME job-execu-tion system.17 Their method takes the mea-sured injection flow rate and, using transienttheory, computes what the injection bottom-hole pressure would be if skin were fixedand constant—it is generally chosen to bezero. This is continuously compared withthe actual bottomhole pressure. As the twopressures converge, so it can be assumedthat the well is cleaning up (right). Finally,the difference in pressures is used to calcu-late skin.

The key to real-time analysis is accuratelyknowing the bottomhole pressure. This canbe estimated from wellhead pressure or, ifcoiled tubing is used, from surface annuluspressure. The most reliable method, how-ever, is to measure pressure downhole. Thiscan now be achieved using a sensor pack-age fixed to the bottom of the coiled tubing.

Evaluation should not stop once the oper-ation is complete. The proof of the puddingis in the eating, and operators expect torecoup acidizing cost within ten to twentydays. From the ensuing production data,NODAL analysis can reveal the well’s newskin. This can be compared with new pre-dictions obtained by simulating the actualjob—that is, using flow rates and pressuresmeasured while pumping the treatment flu-ids—rather than the planned job. Under-standing discrepancies between design andexecution is essential for optimizing futurejobs in the field.

Just about every area of matrix acidizing,from acid systems to diverters to additives tocomputer modeling to environmentallyfriendly fluids has been researched andincorporated into mainstream technique(see “HSE Developments for Acidizing,” farright). The remaining challenge for bothoperators and the service industry is gainingthe same level of sophistication in fieldpractice and real-time monitoring. The toolsfor improving field operations now appearto be in place. There seems no reason whyall matrix acidizing jobs should not be prop-erly designed and executed. The days of therule-of-the-thumb are over.—HE

39October 1992

17. Prouvost L and Economides MJ: “Real-Time Evalua-tion of Matrix Acidizing Treatments,” Journal ofPetroleum Science and Engineering 1 (November1987): 145-154.

nPressure comparison used to assess skinin real time, following the method of Prou-vost and Economides. Pressure predictedfrom measured injection rates, assumingthe well has zero skin, is compared withmeasured wellhead pressure. As the pres-sures converge, damage is being removed.

HSE Developments for Acidizing

Health, safety and environment issues are being

seriously addressed in every corner of explo-

ration and production technology. Laws are tight-

ening and the industry’s obligation to public

health and environmental protection cannot relax.

Matrix acidizing is no exception.

The technique obviously cannot dispense with

dangerous and toxic acids such as HCl and HF,

but other fluid additives may be rendered much

safer to both the public and the environment. Cur-

rent examples are inhibitors used to prevent cor-

rosion of tubulars as acid is pumped downhole,

and solvents used to clean residual oil deposits

and pipe dope from the tubulars.

When acidizing began, it was discovered that

arsenic salts could inhibit corrosion. But arsenic

is highly toxic and its use was discontinued more

than 20 years ago. Less toxic but still harmful

inhibitors were substituted. Recently, Dowell

Schlumberger introduced the first environmen-

tally friendly inhibitor system, CORBAN 250ECO,

that functions up to 250°F [120°C].

CORBAN 250ECO is one of several so-called

ECO pumping additives that have reduced toxicity

and increased biodegradability. For example, the

key inhibiting chemical in CORBAN 250ECO is

cinnamaldehyde, a common cinnamon flavoring

additive for gum and candy.

Another ECO product made from natural

sources is the recently introduced PARAN ECO

additive for cleaning oil deposits and pipe dope

solvent from tubulars. This is intended to replace

aromatic and organic halide solvents that are

toxic and that also can damage refinery catalysts

if produced with the oil.

Sur

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2000

1600

1200

800

400

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0 0.4 0.8 1.2 1.6 2Time, hr

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2125

2000

1875

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Simulated Measured

40 Oilfield Review

Candidate well selection is based on productionor water injection history. The design and fluidselection are based on experience—rules ofthumb. Job quality control and monitoring oftenconsist of a mechanical pressure gauge and abarrel counter. The current state of technologyresults in a one-in-three failure rate, with failuredefined as the well producing the same or lessthan before treatment.

It appears that technology advances are moti-vated by the job cost rather than the potential pro-ductivity benefits. What can be done to improvethis technology without adding a lot of cost to thetreatment?

Candidate Selection and Job DesignWe need a generic matrix design program that willdiagnose the degree and type of damage, recom-mend a fluid type, expected treatment rate andpressure, pump schedule and predict the economicimpact of the treatment. The program must makedo with the few log data that are generally avail-able for economically marginal wells. A key part ofthe diagnosis is predicting type and degree of dam-age based on the formation mineralogy, formationfluid composition and injected stimulation fluidchemistry. Physicochemical models exist, but theydo not take into account reaction kinetics and howthis affects permeability.

Treatment PlacementTechniques for ensuring placement into a particu-lar zone must be advanced. The current divertertechnologies work sporadically and many times domore harm than good. Recent work has shown thateven when a positive diversion technique such asball sealers is used, over one third of the perfora-tions become permanently blocked because theballs permanently lodge in the perforation. Chemi-cal diverters are many times misused or do notmeet expectations—rock salt is sometimes usedby mistake with HF acid producing plugging precip-itates, and so-called oil-soluble resins are usuallyonly partially soluble in oil. We need positive, eco-

nomic, nondamaging diversion techniques whoseeffectiveness can be documented. Foam and theuse of inflatable packers on coiled tubing areviable techniques for positive diversion.

On-site Quality Control and Job ProfilingTo improve treatment efficiency, we need moremonitoring and controlling of the job on loca-tion—a few service companies provide this optionfor a nominal fee. This should include testing of thefluids to be pumped—to ensure concentration,quality and quantity. To profile job effectiveness,digitized data are required for real-time, on-sitedata interpretation and postjob analysis. This datashould be used to determine the evolution of skinwith time, radius of formation treated and theheight of the treated interval.

Continuous Mixing of AcidAll matrix treatments are currently batch mixed. Ifreal-time job monitoring becomes widely avail-able, it will give the operator an idea of the mosteffective volumes of fluid to pump, when to dropdiverters, what the diverter efficiency is, and thedepth of damage and height of treated interval. Totake advantage of this information, the servicecompany must have the capability and be ready tocustom blend the required treatment in real timeusing continuous mixing. Service companies knowhow to continuous mix, but so far have not providedthe technology for matrix treatment.

Commentary: Carl Montgomery

Over half the wells ARCO stimulates each year receive matrix treatments.But this consumes only 17% of the total ARCO stimulation budget.Because of the relatively low cost of a matrix treatment—ARCO’s averageis $5,500 in the lower 48 states of the US—there has been very littleincentive to improve matrix treatment technology. While there are morethan six sophisticated design programs for hydraulic fracturing availablefor purchase, there is not a single matrix design program for sale.

Carl Montgomery,technical coordinator

of well stimulation for

ARCO Oil and Gas

Company in Plano,

Texas, USA.