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Stimulation of high-permeability formations has long been the domain of matrix treatments.

Now, short, wide fractures are being created

18 Oilfield Review

up to 1 in. [2.5 centimeters] wide after clo-sure (above). To appreciate how short, widefractures stimulate high-permeability forma-tions, one must examine the factors govern-ing postfracture productivity.

The permeability contrast between theformation and the propped fracture is a keydeterminant of the optimum fracture length.In low-permeability formations there is alarge contrastand therefore a high relativeconductivityand increased fracture lengthcan yield improved productivity (next page).

In high-permeability formations, relativeconductivity is about two orders of magni-tude smaller. Increasing the length of con-ventional fractures offers only minimalimprovement in productivity and cannot bejustified economically. However, the pro-ductive performance of the fracture is deter-

mined by the dimensionless fracture con-ductivity which is directly proportional tothe fracture width.1 Conductivity can beraised by increasing fracture width; in high-permeability formations, this offers signifi-cant potential improvements in productivity.

Damage

Undamaged reservoir

Short, wide fracturen Short, wide fractures bypass widespreadformation damage and link undamagedrock with the wellbore.

A classic fracture stimulation creates nar-row conduits that reach deep into a forma-tiontypically, about 1/10 in. [2.5 millime-ters] wide and up to 1000 ft [300 m] long.Since the 1940s, relatively low-permeabil-ity formationsless than 20 millidarcies

(md)have been successfully fractured togive worthwhile increases in productivity.However, as formation permeability

increases, creating and propagating frac-tures become more difficult and economi-cally less necessary. In high-permeabilityreservoirs, formation damage is usuallydiagnosed as the major restraint on produc-tivity and matrix acidization treatments areprescribed as the solution (see Trends inMatrix Acidizing, page 24).

But matrix acidization cannot solve everyproblem. The volume of damaged rocksometimes requires uneconomically large

quantities of acid. The damage may bebeyond the reach of the matrix treatment.Diverting acid into the right parts of the for-mation may also be difficult. Additionally,the aqueous treatment fluid or the aciditself may threaten the integrity of the well-bore by dissolving cementing material thatholds particles of rock together.

An alternative strategy for stimulatinghigh-permeability wells has thereforeemerged: the creation of fractures that aretypically less than 100 ft [30 m] long and

Bob HannaBP Exploration Inc.Houston, Texas, USA

Joseph AyoubNew Orleans, Louisiana, USA

Bob CooperHouston, Texas, USA

Rewriting the Rules for High-Permeability Stimulation

For help in preparation of this article, thanks to PaulMartins, BP Exploration (Alaska) Inc., Anchorage,Alaska, USA; and Jack Elbel and Richard Marcinew,Dowell Schlumberger, Tulsa, Oklahoma, USA.

COMPLETION/STIMULATION

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where: Cfd is the dimensionless fracture conductivity,Kf is the permeability of the proppant pack, W is thewidth of the fracture, Kis the permeability of the for-mation and Xf is the length of the fracture.

2. Hannah RR and Walker EJ: Fracturing a High-Perme-ability Oil Well at Prudhoe Bay, Alaska, paper SPE14372, presented at the 60th SPE Annual TechnicalConference and Exhibition, Las Vegas, Nevada, USA,September 22-25, 1985.

19October 1992

reach beyond wellbore damage and provide a conduit to undamaged reservoir rock.

Pinpointing the birthplace of high-perme-ability fracturing is difficult, but it is clearthat work carried out by Sohio PetroleumCo. (now BP Exploration Inc.) inspiredmuch of todays thinking. In 1984, in Prud-hoe Bay, Alaska, USA, Sohio fractured a

well with a permeability of about 60 md.The overriding aim of the exercise was tostimulate the well while avoiding fracturinginto the oil/water contact (OWC) about 115ft [35 m] below the lowermost perforation.2

In a relatively small fracturing treatment,some 15,000 gal [57 m3] of gelled fluidwere pumped at 45 bbl/min, placing 12,000lb [5440 kg] of proppant in the fracture.This treatment was calculated to be suffi-cient to create a fracture with a proppedlength of 43 ft [13 m], which, based on theassumption that one foot of lateral exten-sion would result in one foot of downward

fracture migration, left the fracture easilyshort of the OWC. The treatment was amechanical success and productionincreased by 133%versus a theoreticalmaximum of 160%.

Rather than quantify fracture width, con-ventional terminology uses proppant con-centrationmost commonly stated aspounds of proppant per square foot of frac-ture [lbm/ft2]which is directly proportionalto the width. A conventional, long and nar-row fracture may contain 0.5 lbm/ft2 ofproppant. The Sohio job was designed toplace 1 lbm/ft2modest by todays stan-

dards, which aspire to place 4 lbm/ft2 or more.After this job, attention shifted to the

North Sea. The Valhal field, offshore Nor-way, has a soft chalk reservoir. Amoco Pro-duction Co. found that, although the forma-tion was not highly permeable (about 2 md)

n Increase in posttreatment productivity versus relative fractureconductivityproportional to the permeability contrast betweenthe formation and propped fracturefor a variety of fracturelengths (shown as fracture length/drainage radius). In these curvesfor steady-state production, a normal, low-permeability fracturetreatment has a relative conductivity on the order of 105. Conse-quently, there is scope to increase productivity by increasingfracture length.

But for high-permeability formations, relative conductivity isabout 103, and an increase in fracture length makes virtually nodifference. However, if a wider fracture can be created, fractureconductivity is increased, yielding a higher relative conductiv-ity. This increases productivity for a given fracture length andoffers the chance of raising productivity by increasing the frac-ture length.

Adapted from McGuire WJ and Sikora VJ: The Effect of VerticalFractures on Well Productivity, Transactions of the AIME 219 (1960):401-403.

High-permeabilityformations

Low-permeabilityformations

Relative conductivity

Lengthoffrac

ture,

fracturelength/drainag

eradius(xf/re)1.0

0.9

0.8

0.7

0.6

0.5

0.4

0.3

0.2

0.1

102 103 104 105 106

Increasingproductivity

Cfd=KfW

KXf

1.

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However, following some tip-screenouttreatments, proppant flowed out of thefracture during posttreatment production.This is caused by factors such as low effec-tive stress in the proppant pack or dragforces due to high-velocity flow in the con-ductive pack. Proppant flowback leads toreduced fracture conductivity or blockagesat the fracture-wellbore interface. If the

proppant is flowed to surface, damagingerosion of the production equipment canalso occur.

Sand-control techniques have beenemployed after fracturing to prevent prop-pant flowback. The two main techniquesuse resin-coated proppant or gravel pack-ing. Proppant coated with a curable resinconsolidates once the proppant has beenplaced in the fracture and resists drag duringproduction. Alternatively, the fracture treat-ment can be followed by a gravel packusing a conventional screen to retain theproppant within the fracture (see Sand

Control: Why and How? page 41).In Indonesia, more than 30 treatmentshave been carried out that combine tip-screenout fracturing with either resin con-solidation or a gravel pack. These wells hadhigh skin factors but undamaged permeabil-ities in excess of 100 md. Following treat-ment, many now produce with low skin fac-tors while adjacent conventionally-completed wells have skins of 20 to 40 (seeAverage Data From Three Types of Treat-ment, next page, below left).6

Tip-screenout fracturing and gravel pack-ing treatments are also being used in combi-

nation in the Gulf of Mexico, USA. Over thepast 12 months, more than a dozen com-bined treatments in formations with perme-abilities as high as 1 darcy have realizedtwo- to threefold improvements in produc-tion (next page, below right).

Experience around the world has enableddevelopment of a methodology for selecting

n Tip-screenout treatments place a highproppant concentration and create frac-tures that are usually less than 100 ft longand up to 1 in. wide.A) The fracture is propagated to itsdesired length just as the proppant inthe slurry begins to bridge off near thetip of the fracture, preventing further

propagation.B) Additional slurry is pumped into the

fracture increasing the net pressureinside the fracture, causing it to widen.

C) Further dehydration of the slurry cre-ates a pack of proppant that gradually

evolves from the tip toward the wellbore.

20 Oilfield Review

it was very unstable and conventional stim-ulation was difficult. After acid fracturing,the acid-etched channels quickly collapsedas pore pressure was reduced. And after aconventional propped fracture, the proppantbecame embedded in the soft rock, destroy-ing fracture conductivity.

In 1986, Amoco opted to place a highconcentration of proppant in a wide fracture

using a technique it called tip screenout.In normal fracturing, the tip should be thefinal part of the fracture to be packed withproppant. But in tip screenout, the proppantforms a pack near the end of the fractureearly in the treatment. When additionalproppant-bearing slurry is pumped into thefracture, its length cannot grow, so the widthincreases (left).3

At about the same time, in the UK sectorof the North Sea, BP Petroleum Develop-ment Ltd. was applying tip screenout tech-niques to stimulate gas wells in the Raven-spurn South field. Permeability was 2 md

higher than gas wells that are normally frac-tured, but BP found that conductivity oflong, conventional fractures limited thereservoirs high rate of production, givingonly a threefold increase in production.

Laboratory tests showed that up to 0.5lbm/ft2 of proppant in the fracture can belost largely through embedment. To com-bat this loss in conductivity, stimulation pro-grams were designed to create wide frac-tures, typically placing 3 to 4 lbm/ft2 ofproppant. This excess of proppantensured that enough remained in the frac-ture after embedment to deliver the

designed conductivity. Subsequent treat-ments in Ravenspurn South, using highproppant concentrations, posted increasesin production of up to sevenfold.4

Tip screenout also returned to PrudhoeBay. Since 1989, BP and ARCO Alaska Inc.have employed tip-screenout treatments andreport considerable success.5

P roppantbridgesat tip

P roppant

Fluidleakoff

P roppantfillsfracture

A

B

C

3. Smith MB, Miller WK and Haga J: Tip ScreenoutFracturing: A Technique for Soft, Unstable Formations,SPE Production Engineering2 (May 1987): 95-103.

4. Martins JP, Leung KH, Jackson MR Stewart, DR andCarr AH: Tip Screen-Out Fracturing Applied to theRavenspurn South Gas Field Development, paper

SPE 19766, presented at the 64th SPE Annual Techni-cal Conference and Exhibition, San Antonio, Texas,USA, October 8-11, 1989.

5. Reimers DR and Clausen RA: High-PermeabilityFracturing at Prudhoe Bay, Alaska, paper SPE 22835,presented at the 66th SPE Annual Technical Conferenceand Exhibition, Dallas, Texas, USA, October 6-9, 1991.

Martins JP, Bartel PA, Kelly RT, Ibe OE and Collins PJ:Small Highly Conductive Hydraulic Fractures NearReservoir Fluid Contacts: Applications to PrudhoeBay, paper SPE 24856, presented at the 67th AnnualSPE Technical Conference and Exhibition, WashingtonDC, USA, October 4-7, 1992.

6. Peters FW, Cooper RE and Lee B: Pressure-PackStimulation Restores Damaged Wells Productivity,paper IPA 88064, Proceedings Indonesian PetroleumAssociation 17th Annual Convention, Jakarta, Indone-sia, October 1988.

Peters FW and Cooper RE: A New Stimulation Tech-

nique for Acid-Sensitive Formations, paper SPE19490, presented at the SPE Asia-Pacific Conference,Sydney, Australia, September 13-15, 1989.

7. Ayoub JA, Kirksey JM, Malone BP and Norman WD:Hydraulic Fracturing of Soft Formations in the GulfCoast, paper SPE 23805, presented at the SPE Forma-tion Damage Symposium, Lafayette, Louisiana, USA,February 26-27, 1992.

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After a candidate well has been identified,the next stage is to design the treatment, aprocess that relies on knowledge of therocks mechanical properties and an esti-mate of the stresses in the reservoir and

adjacent rock (see Cracking Rock: Progressin Fracture Treatment Design, page 4).

thinner than 5 ft (1.5 m) and the formationstrength. Specialized techniques likemicroresistivity logging may then be used todetect thinner layers of interbedded sand-shale laminae. Logs also detect water-bear-

ing zones which must be considered duringthe design. Pressure transient analysis isused to identify wellbore damage and quan-tify the production potential of the well.

wells for tip-screenout treatments.7 Thereare three classes of candidate:Reservoirs with significant wellbore dam-

age, perhaps caused by formation col-lapse as the pore pressure reduces duringdepletion. Past matrix treatments havefailed, and short, wide fractures aredesigned to bypass the damage and con-nect the undamaged part of the reservoir

with the wellbore.Reservoirs with fines migration. A short,wide fracture can alleviate this by reduc-ing pressure losses and velocities in thereservoir sand near the wellbore.

Multiple pay zones in laminated sand-shale sequences. The thin sand laminaemay not communicate efficiently with thewellbore until a fracture provides a con-tinuous connection to the perforations(above, right).

Candidate selection is a multidisciplinarytask. Basic openhole logs detect sands andtheir bounding shales, and indicate their rel-

ative permeability and degree of inva-siongaining an insight into the formationsnatural permeability before damage, thedepth of invasion, the presence of zones

21October 1992

n Predicted and real productivity increase in a Gulf of Mex-ico, USA, well stimulated in early 1992 using tip-screenoutfracturing.

P roppantn Laminated pay zone with sand-shale sequences. The sand lam-inae may be connected to the wellbore by short, wide fractures.

Average Data From Three Types of Treatment

Average data

Tota l vertica l depth, ft

Zone thickness, ft

Zone permea bility, md

Pa d volume, gal

Slurry volume, gal

In-situ proppa nt conc entra tion, lbm /ft2

Propped fracture length, ft

Propped fracture conductivity, md-ft

Pretreatment oil production, BPD

Po sttreatment o il production, BP D

Pretreatment skin

Po sttreatment skin

Type A

7240

68

72

1600

685

3.8

28

5670

1040

2140

Type B

3560

32

53

5100

2000

2.1

18

2.3

Type C

4400

48

60

3500

1740

1.2

115

156

1313

Treatment Type

Treatment Type A

A series o f six Indone sian

wells fractured using the

tip-screenout technique.

Although a ll the w ells were

potential sand producers no

special sand-co ntrol

techniques were employed.

Treatment Type B

Two Indonesian we lls

fractured with tip-screenout

treatments performed

through gravel-pack tools

and sc reens to place a

sma ll, highly conduc tive

fracture and a gravel pack

in a single step.

Treatment Type C

Series of treatments

performed o n two offshore

exploration wells to create

vertical communication

between several thin, high-

permeability zones that

were believed to be w ater-

and acid-sensitive.

Productionrate,B/D

Fractured

Nonfractured

Production time, days

103

102

0 30 60 90

Simulation

Data

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Mechanical properties can be derivedusing cores, logs and direct in-situ measure-ments. In many cases, however, retrievinggood cores and then accurately testing themin the laboratory are difficult. Log-derivedmechanical properties rely on density andsonic measurements. Both compressional

and shear sonic measurements work well inconsolidated, fast formations. But in soft,slow formations, conventional sonic toolscannot measure shear wave velocity. How-ever, a recently introduced dipole sonic toolcan now make these shear wave velocitymeasurements in any formation.8

In practice, there is rarely a comprehen-sive collection of core and log data withwhich to build a model predicting fractureshape, used for treatment design. To plugthis knowledge gap, data are collected usingstress tests.

Stress tests consist of pumping a relatively

small volume of ungelled fluid without

ments are used to determine the minimumin-situ stress, which equals the closure pres-sure of the fracture.

Analysis of data from stress tests andlarger-volume calibration testswhich frac-ture the formation usually using gelled fluidwithout proppantenables choice of themost suitable fracture geometry model andconfirmation of the fluid leakoff coefficient.Fracture geometry models of varying sophis-tication are available. All of them use thebasic processes that occur during fractur-ingfluid flow in the fracture and leakoff,

proppant transportation and settling, androck responseto describe the relationship

n Fracturing high-permeability formationsin Indonesia. A specially modified twin50-bbl mixer is capable of mixing and

pumping 18 lbm/gal slurries at more than20 bbl/min. A centralized control stationallows one operator to control and monitorthe complete treatmentessential as pump-ing times can be as short as 2 minutes.

22 Oilfield Review

proppant into the formation at sufficientpressure to fracture the well. In normal,low-permeability stress tests pumping isthen stopped and the pressure can be moni-

tored during flowback. However, in high-permeability formations, the fluid normallyleaks off into the formation rather than flow-ing back. Stress test are repeated severaltimes and the resulting pressure measure-

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between pressure and fracture shape andproduce criteria for fracture propagation.

The models assume that rock is an elasticmaterial, meaning that its deformation isreversible. Dowell Schlumberger is cur-rently examining whether this assumptionholds for soft formations, as it is an impor-tant factor when looking at the fracture clo-sure and the stress it exerts on the proppant

pack. If closure stress is less than antici-pated, the proppant pack could becomeunstable during productionunless thetreatment has included a gravel pack.

Calibration tests also provide a moreaccurate way of measuring fluid-loss char-acteristics of the fracturing fluid than can bedevised in a laboratory. Fluid loss dependson the viscosity and wall-building capabilityof the fracturing fluid, the viscosity andcompressibility of the reservoir fluid, andthe permeability and porosity of the forma-tion. In a formation with high porosity andpermeability, fluid loss can be controlled by

increasing the viscosity of the fracturingfluid or enhancing the fluids wall-buildingcapability on the fracture face by the addi-tion of polymers and properly sized fluid-loss control agents.

Once the choice of fracturing fluid is con-firmed, the next step is to design a pumpingschedule capable of delivering the neces-sary high proppant concentrations. The datagenerated by stress and calibration tests arefed into the chosen fracture geometrymodel, which calculates the volumerequired to initially propagate the fracture toa predetermined length. To ensure tip

screenout, proppant concentration in thefracture fluid is gradually increased duringthe treatment from zero at the start, to morethan 16 lbm/gal at the end.

Continuous mix and batch mix treatmentsusing high concentrations of proppant havebeen executed fairly smoothly. In the largercontinuous mix jobs maintaining high con-centrations of sand may require specializedblending equipment (previous page).

Choice of proppant size depends on theultimate fracture conductivity needed andwhether the treatment is being carried out inconjunction with a gravel pack. The larger

the proppant size, the greater the fracturepermeability. In gravel packs, the sand musthave intergranular spaces small enough tokeep formation sand at bay.

To date, most wells have been treatedusing the same size proppant for the fractureand the gravel pack. This simplifies proce-dures but in most cases, proppant size tendsto be smallerand therefore of lower con-

ductivitythan would ideally have beenemployed if fracturing had been carried outalone. ARCO has been performing treat-ments with larger than normal sand sizes.9

After the job is completed, the first perfor-mance yardstick is its mechanical suc-cessHas everything gone according toplan? The effectiveness of the treatmentmay then be assessed by comparing theoret-ical net pressures (fracture propagation pres-sure minus closure pressure) with pressuresmeasured during the treatment by down-

23October 1992

n Comparing simulated pressures with the real thing. Theeffectiveness of a treatment can be judged by comparingtheoretical net pressures with pressures measured duringthe job using downhole gauges. This plot of a tip-screen-out fracturing job shows excellent agreement betweenthe simulated and actual pressures.

8. Taking Advantage of Shear Waves, Oilfield Review4, no. 3 (July 1992): 52-54.

9. Hainey BW and Troncoso JC: Frac-Pack: An Innova-tive Stimulation and Sand Control Technique, paperSPE 23777, presented at the SPE International Sympo-sium on Formation Damage Control, Lafayette,Louisiana, USA, February 26-27, 1992.

hole memory gauges (below). Other place-ment evaluation techniques include use ofmultiple-isotope tracers in the sand andtemperature logs to estimate the fractureheight and assess the fractures communica-tion with the perforated interval along thewellbore by tracing cooling anomalieswhere the fluid has entered the formation.

However, the most important indicators of

success are the wells production responsesboth immediately after treatment and duringthe rest of its productive life. To date, theseindicate that the traditional guidelines rulingout fracturing for high-permeability forma-tions have been successfully rewritten.CF

Netpressure,psi

Production time, days

Simulation

Data1000

500

100

2 5 10 20 50 100