p3d model description

8/10/2019 p3d model description

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In the 1950s, hydraulic fracturing

was a hit-or-miss proposition.

Through the 60s and 70s, better

data quality and more sophisti-

cated models of rock mechanics

improved control over the fracture

job. Today, with cost-effective,

high-power computing, two-dimen-

sional (2D) models of fracture

propagation are giving way to a

three-dimensional (3D) approach.

Fracture treatment design has

never before been so powerful or

flexible a tool.

4 Oilfield Review

For their help with this article, thanks to Larry Behrmann,Schlumberger Perforating Center, Rosharon, Texas, USA;Simon Bittleston, Schlumberger Cambridge Research,Cambridge, England; CJ de Pater, Delft Technical Univer-sity, The Netherlands; Cor Kenter and Jacob Shlyapober-sky Koninklijke/Shell Exploratie en Produktie Laborato-rium, Rijswijk, The Netherlands; Paul Martins, BPExploration (Alaska) Inc., Anchorage, USA; and GeorgeK. Wong, Shell Bellaire Research, Houston, Texas, USA.

In this article, NODAL, DataFRAC and ZODIAC (ZonedDynamic Interpretation Analysis and Computation) aremarks of Schlumberger. VAX is a mark of Digital Equip-ment Corp. and Sun is a mark of Sun Microsystems, Inc.

The idea of hydraulically creating cracks ina pay zone to enhance production wasdeveloped in the 1920s by R.F. Farris ofStanolind Oil and Gas Corp. He evolved theconcept following a study of pressuresencountered during squeezing of cement,oil and water into formations. In 1947,Stanolind (now Amoco Production Co.) per-

formed the first experimental hydraulic frac-ture in the Klepper #1 gas well in GrantCounty, Kansas, USA. Deliverability of thewell did not improve appreciably, but thetechnique showed promise, and the follow-ing year Stanolind presented a paper on theHydrafrac process.1 Halliburton Oil WellCementing Company obtained a license tothe process and, in 1949, performed the firstcommercial fracturing treatments, raisingproduction of two wells outstandingly.2

Cracking Rock: Progress in Fracture Treatment Design

Barry Brady

Jack ElbelMark MackHugo MoralesKen NolteTulsa, Oklahoma, USA

Bobby Poe

Houston, Texas, USA

COMPLETION/STIMULATION


2/69

4. Warpinski NR: Invited Paper: Rock Mechanics Issuesin Completion and Stimulation Operations, in Tiller-son JR and Wawersik WR (eds): Proceedings of the33rd US Symposium on Rock Mechanics. Santa Fe,New Mexico, USA (June 3-5, 1992): 375-386.

5October 1992

The method took off. By 1955, treatmentsreached 3000 wells per month, and by1968, more than a half-million jobs hadbeen performed. Today, hydraulic fracturingis used in 35 to 40% of wells, and in theUnited States, where the procedure is mostwidespread, it has increased oil reserves by25 to 30%.3 Interest in hydraulic fracturingshows no signs of abating.4 Application ofthe technology is expanding from mainly

1. Clark JB: A Hydraulic Process for Increasing the Pro-ductivity of Wells, Transactionsof the AIME 186(1949): 1-8.

2. Waters AB: History of Hydraulic Fracturing, pre-sented at the SPE Hydraulic Fracturing Symposium,Lubbock, Texas, USA, 1982.

3. Veatch RW Jr, Moschovidis ZA and Fast CR: AnOverview of Hydraulic Fracturing, in Gidley JL,Holditch SA, Nierode DE and Veatch RW Jr (eds):Recent Advances in Hydraulic Fracturing, Monograph12. Richardson, Texas, USA: Society of PetroleumEngineers (1989): 1-38.


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Pressure exerted by the pad initiates andpropagates the fracture. The slurry helpsextend the fracture and transports proppant.The fracture gradually fills until the prop-pant packs into the fracture tip (next page).At this point, the fracture treatment is fin-ished and pumping stops. As pressurewithin the fracture declines, the fracturecloses on the proppant pack, ensuring that it

remains in place, providing a conduit forhydrocarbons. Productivity would be inhib-ited by viscous fluid in the pad and slurrythat remains in the formation. However,when the fluids high viscosity is no longerneeded, the high temperature of the forma-tion or special oxidizers cause the fluidbreak to a lower viscosity, allowing it tobe produced back.5

Hydraulic fracturing lies at the interface offluid mechanics and rock mechanics. In the45 years since the first fracture job, fluid sci-ence has advanced significantly. Treatmentfluids have been diversified to handle many

temperature, chemical and permeabilityconditions (see Rewriting the Rules forHigh-Permeability Stimulation, page 18).Additives control a range of fluid properties,such as viscosity, pH, stability and loss offluid to the formation, called leakoff.6 Manyproppants have been developed, from thestandard silica sand to high-strength prop-pants, like sintered bauxite and zirconiumoxide particles, used where fracture closurestress would crush sand.

low-permeability reservoirs to medium-tohigh-permeability settings (above).

Hydraulic fracturing is the pumping of flu-ids at rates and pressures sufficient to breakthe rock, ideally forming a fracture with twowings of equal length on both sides of theborehole. If pumping were stopped after thefracture was created, the fluids would grad-ually leak off into the formation. Pressureinside the fracture would fall and the frac-ture would close, generating no additionalconductivity. To preserve a fracture once ithas been opened, either acid is used to etch

6 Oilfield Review

the faces of the fracture and prevent themfrom fitting closely together, or the fracture

is packed with proppant (usually sand) tohold it open. This article concentrates onthe latter technique.

Today, a typical fracturing treatment usesthickened fluids pumped in stages. The firststage is a pad of water, a polymer andadditives. Then comes the slurry, which ispad plus proppantgenerally sandin sus-pension. Different concentrations of prop-pant and volumes of slurry are pumped asthe job progresses (below).

N orth Am ericanactivity declines;gas deregulation

M iddle East

im ports toN orth Am erica

Rem ovedam age

Tight gas;goal of 10increase

Im provedm aterials,understanding

Year

Fracture

treatm

ents/yr

O PEC sup ply restrictions

M oderate/highperm ; goalof 2increase

0

1000

2000

3000

4000

1950 1960 1970 1980 1990 2000

n Changing motivation for hydraulic fracturing. The three parts of the graph with posi-tive slope indicate three motivations: initially, to remove damage, then to improve ten-fold the productivity of tight gas sands, and today, to double productivity of medium-to high-permeability formations.

n A typical pumping schedule for ahydrofrac in a gas well in east Okla-homa, USA. Each unit of fluid thatrepresents a change in proppant

concentration or flow rate or both iscalled a stage; a specific sequenceof stages is called a pumpingschedule. This is a pumping sched-ule to produce a 909-foot [277-m]fracture. The pad fractures the rockand helps transport the proppant,which holds the fracture open after

pressure is released. A major com-ponent of fracture design is estab-lishing the volume and chemistry of

pad and slurry. Generally, the pad

is the largest stage, accounting for30 to 50% of fluid, and, rarely, up to70%. Ideally, to optimize the

propped fracture length, the pad is

completely leaked off at themoment the fracture reaches itsintended length. If the pad leaks offtoo soon, the fracture will be tooshort; if too late, the fracture is noteffectively propped. In this well, fiveslurry stages with different proppantconcentrations and volumes areused, but as many as 17 or 20 slurrystages may be used in large frac

jobs. The later slurry stages havehigher proppant concentrationsthan earlier stages because theslurry fluid leaks off as it travelsalong the fracture. Therefore, a

slurry concentration that starts at thewellbore as 2 lb of proppant per gal-lon of fluid [240 kg/m3], may end upas 8 lbm/gal [960 kg/m3] at the end

of pumping, and 44 lbm/gal [5270kg/m3] when the fracture closes. Inthis job, one proppant size is used(20/40 refers to a standard sievemesh size that permits passage of a

particle with an average diameter of0.63 mm [0.025 in.]). A larger prop-

pant is sometimes used near the well-bore to minimize turbulent flow,which would decrease hydrocarbonflow rate.

J ob Description Information

Stage

Name

P a d

Slurry

Slurry

Slurry

Slurry

Slurry

Pump

Ratebb l/min.

35

35

35

35

35

35

Fluid

Name

YF140

YF140

YF140

YF140

YF140

YF140

Stage Fluid

Volumeg a l

5000

9000

14,000

23,000

15,000

13,200

Proppant

Concentrationlbm/ga l

0

2

4

6

8

0

Proppant Type

+ Mesh

INTERP ROP + 20/40

INTERP ROP + 20/40

INTERP ROP + 20/40

INTERP ROP + 20/40

INTERP ROP + 20/40

Estimated Surface

Pressureps i

5630

4610

3760

3080

2460

6170


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25% slurry volume pumped

H

eight,m

30

15

0



D istance, m0 50 100

H

eight,m

30

15

0

H

eight,m

30

15

0

n An investigational proppant transportmodel, showing variation of proppantconcentration at three times during frac-turing. This simulation, by Simon Bittle-ston at Schlumberger CambridgeResearch in England, predicts the finaldistribution of proppant, used for quanti-fying fracture conductivity. Yellow is no

proppant, green to dark blue is low tohigh proppant concentrations, respec-tively, and red is packed proppant. Slurryis denser than pad so it tends to slump,called gravity current. After 50% of the

slurry volume is pumped, a shower of set-tling proppant appears as a light blue fognear the tip of the propagating slurry.Falling proppant results in a packed bed(red)along the bottom of the fracture. This

packed bed restricts downward growth ofthe fracture. As a result of this proppantdistribution modeling, the pumpingschedule can be modified to optimizefracture design. Although still a researchtool, it may later be integrated into frac-ture design programs.

5. Gulbis J, Hawkins G, King M, Pulsinelli R, Brown Eand Elphick J: Taking the Brakes off Proppant-PackConductivity, Oilfield Review3, no. 1 (January1991): 18-26.

6. Overviews of fracturing fluids:

Constien VG: Fracturing Fluid and Proppant Charac-terization, in Economides MJ and Nolte KG (eds):Reservoir Stimulation, 2nd ed. Englewood Cliffs, NewJersey, USA: Prentice Hall (1989): 5-15-23.

Ely JW: Fracturing Fluids and Additives, in GidleyJL, Holditch SA, Nierode DE and Veatch RW Jr (eds):Recent Advances in Hydraulic Fracturing, Monograph12. Richardson, Texas, USA: Society of PetroleumEngineers (1989): 130-146.

Until recently, advances in rock mechan-ics lagged somewhat behind those in fluidtechnology. In the 1950s, there was no needfor a rigorous theory of fracture propagation,the backbone of fracture treatment design.Low-volume, low-rate and low proppantconcentration fracture stimulation suc-ceeded without careful design. But as treat-ments grew in size and complexity, opera-

tors needed more control. Today more thanever, the expense of hydraulic fracturingrequires that the operator knows how theformation will respond to treatment, andwhether the treatment designthe selectionof pump rates, fluid properties, pumpingschedule and fracture propagation modelwill create the intended fracture (see ToFrac or Not to Frac? next page).

Pivotal to designing the treatmentand todeciding whether to do one at allis cost-benefit analysis, relating cost of the fracturejob to increased well productivity. The morefracture length for a given fracture conduc-

tivity, the more productivity, but also themore costly the fracture job. This analysis,called net present value, is done with simu-lators that find the optimum fracture lengthand conductivity for a given payback sched-ule. Too short a fracture, or too low a con-ductivity, and the increase in well produc-tivity wont cover the cost of the fracturetreatment; too long, and the extra fracturelength will add significantly to cost but neg-ligibly to production. Some simulatorsmodel fracturing economics in longer terms;they tell, for example, for a well with agiven deliverability, amortized at a certain

rate, how much should be spent onhydraulic fracturing given a future oil price.In the past few years, improvements in

fracture design have come from develop-ments in several areas:Fracture geometry modeling. Mathemati-

cal models today can better predict howin-situ rock responds to fracturing.

Relationship of perforation design andfracture initiation (see The Shape of Per-foration Strategy, page 54). Carefuldesign of perforations can minimize pres-sure drop at the borehole.

Fracture treatment evaluation. Mathemati-

cal advances have also made evaluationtools more powerful. There is a growingpractice of testing the validity of the frac-ture geometry model against postfracturewell test data, then refining the model.This back analysis permits prediction offracture parameters, particularly fracturelength and conductivity, to be comparedwith independent field measurements.

7October 1992

Initialfracturegeom etryat w ellbore

P

roppantconcentration,vol%

0

5

10

15

20

25

30

35

65


5/69

Maximum be nefit a chieved forrecompletions only?

Maximum be nefit a chieved a fter

matrix treatment only?

Is maximum benefit ac hieved

after fracturing only?

Is ma ximum benefit achieved a fter

fracturing with recompletion?

No

No

No

No

No

Pe rform recompletion.



Yes

Yes

Yes

Yes

Yes

Determine if the w ell is providing the maximum b enefit, indica ted

by return on investment and net present value.

Determine b enefit using NODALana lysis for various

combinations of:

Reco mpletions (tubing size,

perforations, s urface

eq uipment, artificial lift)

a nd

Matrix treatments

(different materials and sizes)

or

Frac ture treatme nts

(different ma terial a nd s izes).

Perform matrix

treatment

(se e Trend s in Ma trix

Acidizing, page 24).

Perform fracture

treatment.

Evaluate permea bility and s kin (nea r well da ma ge ) from w ell test.

7. Hubbert MK and Willis DG: Mechanics of HydraulicFracturing, Transactions of the AIME 210 (1957):153-166.

8. Barree RD: A New Look at Fracture Tip Screenout

Behavior, paper SPE 18955, presented at the SPEJoint Rocky Mountain Regional/Low PermeabilityReservoirs Symposium and Exhibition, Denver, Col-orado, USA, March 6-8, 1989;Journal of PetroleumTechnology 43 (February 1991): 138-143.

Clifton RJ and Abou-Sayed AS: A VariationalApproach to the Prediction of the Three-DimensionalGeometry of Hydraulic Fractures, paper SPE/DOE9879, presented at the SPE/DOE Low-PermeabilityGas Reservoirs Symposium, Denver, Colorado, USA,May 27-29, 1981.

Fracture Geometry Modeling

The need to understand hydraulic fracturingstimulated advances in basic rock mechan-ics. A key finding was of Hubbert andWillis, in 1957, showing that fractures in theearth are usually vertical, not horizontal.7

They reasoned that because a fracture is aplane of parting in rock, the rock will openin the direction of least resistance. At the

depth of most pay zones, overburden exertsthe greatest stress, so the direction of leaststress is therefore horizontal (next page,top). Fractures open perpendicular to thisdirection and are therefore vertical. In shal-low wells, or where thrusting is active, hori-zontal stress may exceed vertical stress andhorizontal fractures may form.

By the 1960s, fractures created below1000 or 2000 ft [300 to 600 m] wereaccepted as vertical. Operators then posedsome difficult questions: How high does thefracture grow? How can we prevent it fromextending into the gas or water zone? How

does fracture height relate to fracture widthand length? And how do we optimize frac-ture dimensions?

A major task of rock mechanics becamethe prediction of fracture height, length andwidth for a given injection rate, duration ofinjection and fluid leakoff. Needed for thisprediction is a model of how a fracturepropagates in rock.

Today, a number of models occupy a con-tinuum from 2D to pseudo-three-dimen-sional (P3D) and fully 3D. The basic differ-ence between 2D and P3D/3D models isthat in 2D models, fracture height is fixed or

set equal to length (that is, a semicircularshape), whereas in P3D and 3D models,fracture height, length and width can allvary somewhat independently. Two-dimen-sional models have been around for about30 years; three-dimensional for about tenyears. Increased computing power hasrecently made pseudo-3D models practicalfor routine design. Fully 3D models have

Clifton RJ: Three-Dimensional Fracture-PropagationModels, in Gidley JL, Holditch SA, Nierode DE andVeatch RW Jr (eds): Recent Advances in HydraulicFracturing, Monograph 12. Richardson, Texas, USA:

Society of Petroleum Engineers (1989): 95-108.Hongren G and Leung KH: Three-DimensionalNumerical Simulation of Hydraulic Fracture Closurewith Application to Minifrac Analysis, paper SPE20657, presented at the 65th SPE Annual TechnicalConference and Exhibition, New Orleans, Louisiana,USA, September 23-26, 1990.

9. The PKN model is from the work of Perkins and Kern,revised by Nordgren to account for flow rate gradientsin the fracture.

Nordgren RP: Propagation of a Vertical HydraulicFracture, Society of Petroleum Engineers Journal12(August 1972): 306-314; Transactions of the AIME 253.

Perkins TK and Kern LR: Widths of Hydraulic Frac-tures,Journal of Petroleum Technology 13 (Septem-ber 1961): 937-949; Transactions of the AIME222.

8 Oilfield Review

10. Khristianovic SA and Zheltov YP: Formation of Ver-tical Fractures by Means of Highly Viscous Liquid,Proceedings, Fourth World Petroleum Congress,Rome, Italy, section 2 (1955): 579-586.

Geertsma J and de Klerk FA: Rapid Method of Pre-dicting Width and Extent of Hydraulically InducedFractures,Journal of Petroleum Technology19(December 1969): 1571-1581; Transactions of theAIME 246.

11. Ahmed U: Fracture-Height Predictions and Post-Treatment Measurements, in Economides MJ andNolte KG (eds): Reservoir Stimulation, 2nd ed.Englewood Cliffs, New Jersey, USA: Prentice Hall(1989): 10-110-13.

12. Van Eekelen HAM: Hydraulic Fracture Geometry:Fracture Containment in Layered Formations, paperSPE 9261, presented at the 55th SPE Annual Techni-cal Conference and Exhibition, Dallas, Texas, USA,September 21-24, 1980.

Is ma ximum benefit achieved a fter

matrix treatment with recompletion?

Frac turing no t needed .

To Frac or Not to Frac?


6/69

limited use because of lengthy computationtime, but they are the way of the future.State-of-the-art fully 3D models simulatenonplanar fractures, but most commercialversions are planar.8

Most 2D models are based on three com-mon models: the Perkins-Kern-Nordgren9

(PKN) model, the Khristianovic-Geertsma-deKlerk10 (KGD) model and the radial model

(below). The PKN and KGD models assumefracture height is constant along the lengthof the fracture; height is usually picked bylithologic boundaries. Fracture length andwidth are then calculated from height(which may be estimated using acoustic logdata combined with modeling of fracturemechanics and elastic properties11), Youngsmodulus, fluid viscosity, injection rate andtime and leakoff. In the radial model, frac-ture length and height are equal and arejointly allowed to vary. Width is alsoallowed to vary.

The 3D approach is more realistic

because fracture height is not determined bylithology but by vertical variation in themagnitude of least principal stresses, whichoften but not always follow lithologic units.(The greater the vertical contrast in leastprincipal stresses, the better fracture heightis contained.12)

n Stresses in the earth act in three princi-pal directions, one vertical, and two hori-zontal, a maximum and a minimum. Atthe borehole wall, these are vertical, Sv,radial, Sr, and tangential, St. Verticalstress induced by overburden usuallyexceeds the two horizontal components.This means a fracture will have the leastresistance to opening along a plane nor-mal to the smallest principal stress.Because this stress is horizontal, the frac-

ture will orient vertically. In areas ofactive thrusting, and in some shallowwells, a horizontal stress may exceedoverburden and the fracture will formhorizontally. Regional tectonic forcesdetermine the azimuthal orientation of theleast principal stresses and thus of thefracture wings.

The emergence of 3D models has noteclipsed 2D models. Two-dimensional mod-els work where:The fracture grows in a formation of homo-

geneous stress and mechanical propertiesso that fracture height is small comparedto formation layer thickness. The radialmodel is appropriate in this setting.

Stress contrasts are high between the pay

layer and neighboring formations andthese contrasts follow lithologic bound-aries. The PKN or KGD models, whichassume constant height, are appropriate inthis setting.

When these conditions are absent, use of2D models requires estimation of fractureheight based on the users experience andknowledge. The consequences of underesti-mating fracture height, for example, rangefrom disastrous to troublesome but manage-able. The fracture may extend into a gas orwater leg, which can ruin a well. Underpre-dicting fracture height overpredicts fracture

length because, for a given pump rate,unanticipated doubling of fracture heightdecreases length by about 50%, dependingon leakoff. If the fracture is shorter than pre-dicted, it may not be as productive as fore-cast. The pump schedule may be inappro-priate, further cutting fracture conductivity.

9October 1992

2D Fracture M odels

Fractureheight fixed

Fractureheight not

fixed

Pressur

erequired

toexten

d

fracture

PKN

KGD

Radial

Elliptical cross section

W idth height

W idth < KG D ; length > KG D

M ore appropriate w hen fracture length > height

Rectangular cross section

W idth length

M ore appropriate w hen fracture length < height

Appropriate w hen fracture length = height

Tim e

Pressurerequired

toextend

fracture

Tim e

Pressurerequired

toextend

fracture

Tim e

n The family ofbasic 2D fracturemodelsPKN,GDK and radial.

Sv

S t

Sr

Verticalstress

M in.horiz.stressM ax

horiz.stress


7/69

13. Nierode DE: Fracture Treatment Design, in GidleyJL, Holditch SA, Nierode DE and Veatch RW Jr (eds):Recent Advances in Hydraulic Fracturing, Mono-graph 12. Richardson, Texas, USA: Society of

Petroleum Engineers (1989): 223-244.14. Ben-Naceur K: Modeling of Hydraulic Fractures,

in Economides MJ and Nolte KG (eds): ReservoirStimulation, 2nd ed. Englewood Cliffs, New Jersey,USA: Prentice Hall (1989): 3-13-31.

For example, proppant concentrations maybe excessive, causing proppant to plug thefracture before flowing its full length, andleaving some fracture length unpropped.13

The evolutionary step after 2D modelingis P3D modeling.14 When conditions areideal for a 2D modelhigh, known stresscontraststhe P3D model height predictionmay be more accurate than the estimated

height of the 2D model (below). The advan-tage of the P3D approach is that it does notrequire estimating fracture height, but it

does require input of the magnitude of mini-mum horizontal stress in the zone to befractured and in the zones immediatelyabove and below. (It calculates height usingthis stress and the fluid pressure within thefracture.) The stress values may be estimatedfrom a mechanical properties log, an indi-rect measurement.

On a small scale, the best direct stress

measurement is from several microfracs,15

in which small fractures are created at sev-eral wellbore locations (below). Fracturingfluid is usually water without proppant. Onthe reservoir scale, determination of stressand fluid loss is accomplished by a calibra-tion treatment, in which a fracture is createdwithout proppant that is up to one-third thelength of the planned fracture. The engineeranalyzes the curve of pressure decline ver-sus time after the rock has been fractured(next page, top). Finding the fracture closure

10 Oilfield Review

15. Daneshy AA, Slusher GL, Chisholm PT and MageeDA: In-Situ Stress Measurements During Drilling,Journal of Petroleum Engineering 38 (August 1986):891-898.

Sarda JP, Detienne JL and Lassus-Dessus J, Recom-mendations for Microfracturing Implementationsand the Interpretation of Micro- and Pre-Fractur-ing, Revue de lInstitut Franais du Ptrole47, no.2 (March-April 1992): 179-204.

16. Nolte KG: Fracture Pressure Analysis: Deviationsfrom Ideal Assumptions, paper SPE 20704, pre-sented at the 65th SPE Annual Technical Confer-ence and Exhibition, New Orleans, Louisiana, USA,September 23-26, 1990.

n A P3D fracture propagating from the borehole (top) and comparison of 2D, P3D/fully3D models for high and low contrast in minimum horizontal stress between beds. A lowstress contrast is on the order of a 100 psi [690 kilopascals (kPa)]; a high stress contrastis greater than 1000 psi [6895 kPa]. Here, if one assumes that fracture height of the 2Dmodel is selected based on lithology, not on stress contrast, then the 2D fracture modelstays within the beds. In the low-contrast case, the 2D model will probably overesti-mate fracture length and underestimate height, compared to the P3D/fully 3D models.In the low-contrast case, there would be a slight length and height difference betweenthe P3D and fully 3D models. In the high-contrast case, the P3D and fully 3D modelswould predict about the same geometry.

W

elldepth,ft

Logderived

M icrofrac test

M inim um horizontal stress, psi

4200

4600

5000

5400

58002200 2600 3000 3400

n Stress profile measured bymicrofrac and derived from wire-line log data. Most correlationsbetween log-derived and mea-sured stresses are linear andshow more deviation than thisexample.

Low contrast

Low contrast

H igh contrast

H igh contrast

H igh contrast

H igh contrast

Low contrast

Low contrast

2D versus P3D /3D Fracture M odelsfor D ifferent B ed B oundary Stress C ontrasts

2D

P3D/3D

P3D Fracture

17. Martins JP, Bartel PA, Kelly RT, Ibe OE and Collins PJ:Small Highly Conductive Hydraulic Fractures NearReservoir Fluid Contacts: Application to PrudhoeBay, paper SPE 24856, presented at the 67th SPE

Annual Technical Conference and Exhibition, Wash-ington DC, USA, October 4-7, 1992.


8/69

pressure, which equals the minimum hori-zontal stress, requires interpretation of theslopes, which is open to ambiguity.16 Thedrawback of the microfrac method is itshigh cost and insensitivity to stress variationfrom well to well and across a field. Theleakoff estimation is also complicated whenfractures grow into impermeable layers,where leakoff will not be proportional to

fracture area.P3D models assume a simplified repre-sentation of fluid flow in the fracture. Thisassumption is made mainly to shorten com-putation time, but it may result in inaccurateestimation of fracture height. This is becausepressure distribution in the fracture, whichcontrols growth of fracture height, is gener-ated by the fluid flow.

Although this problem seems simpleenough to solve, it requires the leap to fully3D modeling of fracture geometry. Fully 3Dsimulators are difficult to usethey requireaccurate stress contrast dataand so are not

widely employed, but the theory permits theclosest approximation of what fracturesreally do. The two main differencesbetween fully 3D and P3D are in how theyhandle fluid flow and pressure calculationalong the fracture. Fully 3D geometry mod-els use a fully 2D model of fluid flow,whereas P3D models approximate the 2Dfluid flow. In a fully 3D geometry model,pressure everywhere is used to calculatefracture width at any point. Width is gener-ally calculated using the pressure integralalong the total fracture length and height. Inthe P3D model, the pressure-width relation

is simplified to improve efficiency, usuallyby considering only particular shapes, suchas ellipses, or by neglecting variation ofpressure along the fracture length.

At BP, fully 3D models are not used rou-tinely because of lack of appropriate input

data. They are used to understand fracturepropagation in a particular field.17 Wherefracture containment is poor, 3D modelshave been used to assist microfrac interpre-tations and to generate simple models forroutine fracture design. These simple mod-

els are refined by posttreatment evaluation.The pressure integral advantage of the

fully 3D model has been introduced to PKNand P3D models using a method called lat-eral coupling. This is a way to introduce 3Delasticity to models that dont include it.Mathematically, lateral coupling puts back agross approximation of the pressure integralalong the fracture length. This poor-mansintegral couples pressures at points alongthe fracture, instead of considering them inisolation. Compared with conventional PKN

and P3D modeling, it doubles or triplescomputation time, but improves estimationof fracture height and fracture pressure dur-ing treatment (above).

A third evolutionary stage, multilayer frac-ture (MLF) modeling, takes one step back in

order to take two steps forward. The MLFsimulator is a revision of PKN modeling thatpermits describing the geometry of morethan one fracture forming in more than onelayer and then planning the appropriate

11October 1992

B

ottom

holepressure,psi

Pressure decline

Fracture closeson proppant

R eservoirpressureC losure pressure =

m inim um horizontal rock stress

9000

8000

7000

6000

500038 40 42 44 46 48 50 56 58

Tim e, hr

Fracture

closing

Fracture

treatm ent

Pressurereq

uired

toextend

fracture,psi

Lateralcoup ling

PKN

K G D

Tim e, m in

300

250

200

150

100

500 20 40 60 80

n Effect of closurestress on a pres-sure/time curve. Inthis idealizedexample, interpre-tation of the slopeto find horizontalstress is straightfor-ward. Changes incurve slope are notalways so clear.

n Pressure versustime for lateralcoupling com-

pared with tradi-tional fracturemodels.


9/69

pumping schedule.18 (below). Multilayermodeling was needed as more reservoirswere exploited in which conventional mod-eling has limitations. This is often the casewhen stress barriers prevent the coalescingof fractures in multiple zones or where lay-ers of varying thicknesses and stress magni-tudes are to be fractured.

The MLF approach indicates whether a

single treatment or separate treatments areneeded to achieve optimum geometry offractures in multiple zones. If separate treat-ments are needed for the desired penetra-tion in each layer, the MLF simulator maybe used to determine how many arerequired. It can also help in planning lim-ited entry perforatingvarying the numberof perforations in each layer, depending onlayer thickness and stress state, to achievethe desired fracture geometry. (Fewer perfo-rations in the layer taking the most fluidrestricts flow and diverts it into other layers.)

Inputs to the MLF model are the same as

for P3D: stress profile, Youngs Modulus andleakoff for each formation. The model dif-fers from existing descriptions of multilayerfracturing in that it quantifies transient fluidpartitioning during pumping as a function offracturing fluid and formation properties.Existing models calculate partitioning only

at a single time or for a limited number offormation characteristics.19

The MLF model also allows the predictionof crossflow between fractures after pump-ing stops and before all the fractures close.Matching the predicted and measured cross-flow permits a more accurate prediction ofthe parameters that determine fluid volumethat enters each zone, and the resulting frac-

ture length and height.With the arrival of the MLF model, theengineer can choose from five general typesof fracture propagation models. Selection ofthe right model is critical. Even slight differ-ences between modeled and actual fracturedimensions can translate to dramatic differ-ences in required proppant concentrationand weight, and pad volume (next page).Usually, PKN, KGD and radial models arechosen with a chain of empirical deduc-tions. The engineer estimates the shape ofthe induced fractureif length exceedsheight, its PKN; if length is less than height,

its KGD. This value is based the sand thick-ness to be fractured, proximity to gas, wateror other fractures and estimation of thestress contrast between the reservoir sectionand abutting formations, usually shales. Thestress contrast estimate is often valid whenthe well has clean sands and clean shales.

The estimate becomes tenuous in silty shale,which may have the same stress magnitudeas sand but may poorly contain fractureheight. Again, the best measurement ofstress is obtained from a microfrac.

The Perf and the Frac: Whats the Link?

Field wisdom holds that the ideal perfora-tion lies in the plane normal to the mini-

mum far-field stress direction. This perfora-tion links most directly with the inducedfracture, minimizing pressure drop near theborehole. Other perforations probably con-nect with the fracture indirectly, if at all. Butbecause fracture azimuth is generally notknown and because alignable perforatingguns are not readily available, conventionalguns shooting at closely spaced anglesaround 360 are generally used. These arecalled phased guns. The closer the angle(phasing) between perforations, the betterchance of having more perforations in ornear the ideal plane. Not until recently,

however, were large-scale experiments per-formed to evaluate the relationship betweenperforations and hydraulic fractures.

Behrmann and Elbel of Schlumberger andDowell Schlumberger, respectively, usedfull-scale perforators on steel casingcemented into sandstone blocks placed in a

12 Oilfield Review

G am m aray Layered beds 2D P3D MLF

Perfs

Perfs

Shale Sand

n Comparison of 2D, P3D and multilayer fracture (MLF) models in a multilayer setting. In the 2D model, fractureheight is selected to be limited by the top of the upper sand and bottom of the lower sand. The fracture is consid-ered to grow simultaneously from both sands and to be of uniform length. Youngs Modulus is averaged for thetwo sands and the shale between them. In the P3D model, the fracture grows from one sand to the other, but notsimultaneously as in the 2D model. In both the 2D and P3D models, fracture lengths are equal for both the thickand thin sands. In the MLF model, which uses a modified PKN model, fracture lengths and heights are unequal.Length depends on fracture height, stress magnitude and Youngs Modulus. As with other 2D models, height isselected for each layer, here by lithologic boundaries. The next generation MLF model will adapt P3D modeling.


10/69

triaxial stress cell.20 They made severalobservations about the relationship betweenperforation orientation and stress direction.They found that fractures initiate from thewellbore wall in the optimum hydraulicfracture direction, from perforations nearest

this direction, or both. Fractures tend not toform at other perforations.

The best perforation-to-fracture communi-cation is achieved when perforations arewithin 10 of the far-field minimum hori-zontal stress. This means that perforationsnot optimally oriented may result in a largepressure drop, or proppant bridging, when

pad and slurry flow around the annulus tothe fracture. As expected, the maximumnumber of perforations in communicationwith the fracture is achieved with a perforat-ing gun having the smallest possible anglebetween shots.

Another finding of Berhmann and Elbelconcerns pump rate and viscosity of theprepad, a low-viscosity fluid sometimespumped ahead of the pad. It has been longrecognized that a prepad can increase porepressure, and thereby decrease fracture initi-ation pressure. The lower the initiation pres-sure, the lower the pressure required.Behrmann and Elbel, after cutting apart the

sandstone blocks, found that slow pumpingof low-viscosity prepad has another effect: itmaximizes the number of fractures initiatedat perforations suboptimally aligned. Morework is needed to determine whetherincreasing suboptimally aligned fracturesreduces pressure drop at the well, whichwould improve deliverability.

Pearson and colleagues at ARCO Alaska

Inc. aligned perforations normal to the min-imum far-field stress in deviated wells. Theyused perforating guns with a downhole ori-entation motor in conjunction with real-time navigation tools. This enabled place-ment of larger, more productive fractures.21

Pearson and colleagues suspect that post-treatment skin damage may be associatedwith pressure drops from poor communica-tion between the main fracture and frac-tures from perforations that are not alignednormal to the minimum far-field stress.Analysis of the ARCO results by CJ de Paterand colleagues at Delft Technical Univer-

sity in The Netherlands suggests that Pear-sons results may be inconclusive.22 Pear-son and colleagues changed a number ofparameters (such as multiple zone to singlezone perforation and gun size) that mayhave equally explained their ability to placelarger treatments.

13October 1992

18. Elbel JL, Piggott AR and Mack MG: NumericalModeling of Multilayer Fracture Treatments, paperSPE 23982, presented at the SPE Permian Basin Oiland Gas Recovery Conference, Midland, Texas,USA, March 18-20, 1992;Journal of PetroleumTechnology43 (May 1991): 608-615.

19. Ahmed U, Newberry BM and Cannon DE: HydraulicFracture Treatment Design of Wells with Multiple

Zones, paper SPE/DOE 13857, presented at theSPE/DOE 1985 Low Permeability Gas Reservoirs Sym-posium, Denver, Colorado, USA, May 19-22, 1985.

Ben-Naceur K and Roegiers J-C: Design of Fractur-ing Treatments in Multilayered Formations, SPEProduction Engineering 5 (February 1990): 21-26.

20. Berhmann LA and Elbel JL: Effect of Perforations onFracture Initiation, paper SPE 20661, presented atthe 65th SPE Annual Technical Conference andExhibition, New Orleans, Louisiana, USA, Septem-ber 23-26, 1990.

21. Pearson CM, Bond AJ, Eck ME and Schmidt JH:Results of Stress-Oriented and Aligned Perforatingin Fracturing Deviated Wells, paper SPE 22836,presented at the 66th SPE Annual Technical Confer-ence and Exhibition, Dallas, Texas, USA, October 6-9, 1991.

For details of the aligned and oriented perforating

technique:Yew CH, Schmidt JH and Yi L: On Fracture Designof Deviated Wells, paper SPE 19722, presented atthe 64th SPE Annual Technical Conference and Exhi-bition, San Antonio, Texas, USA, October 8-11, 1989.

22. de Pater CJ, personal communication, 1992.

Proppantw

eight,lb

106

Treatm

entcost,$

106

Fractureconductivity,m

d-ft

Fracturepenetration,ft

Fracture half-length, ft


Fluid volum e, gal

KG D

PK N

0

0.25

0.50

0.75

1.0

0

500

1000

1500

2000

0 750 1500 2250 3000


KG D

PKN

0

0.5

1.0

1.5

2.5

0 750 1500 2250 3000

2.0

KG D

PK N

0 80,000 160,000 240,000

KG D

PK N

400

900

1400

1900

2400

2900

0 750 1500 2250 3000

n Comparison of fracture properties for PKN and KGD fractures (top four graphs)and forthree fracture models (bottom).

Comparison of Fracture-Design Calculations for Different Fracturing Models

KGD Perkins-Kern Nordgren

P a d volume, bbl 750 1,350 1,650

650 350

2.5 3.5

68,350 51,000

36 36

804 845

240 185

0.17 0.16

0.16 0.16

94 85

6.5 6.5

1,250

3

157,500

36

698

486

0.22

0.20

98

7.1

Proppant-laden fluid volume, bbl

Averag e sa nd co ncentration, lbm/ga l

Tota l amount of s and , lbm

Viscosity after pad, cp

Created fracture length, ft

Effective frac ture length, ft

Created fracture width, in.

Effective frac ture w idth, in.

Effective frac ture he ight, ft

Averag e frac ture c onduc tivity, da rcy-ft

Adapted from Vea tch RW Jr, et al, reference 3.


11/69

Enhanced Fracture Treatment

Evaluation

Fracture design may be fine-tuned by care-ful postjob evaluation. This tells whether thejob went as planned, and tests the validityof the plan and the variables on which itwas based (see Design of an Ideal FractureTreatment, next page). Postfracture evalua-tion requires a drawdown and buildup test,

which indicates fracture skin and whetherthe actual fracture length and conductivitymatch those planned. This testing is not acommon procedure because operators areusually hesitant to stop production for the10 to 14 days required for the buildup. Butin some fields, the practice is becomingmore common in a few, select wells. Forexample, in BPs Ravenspurn South field inthe UK sector of the North Sea, an extensiveprogram of data collection and analysis wasperformed on the first six developmentwells. This included extensive pre-and post-frac well testing, logging and recording of

bottomhole pressures during job execution.The program helped optimization of jobdesign for the remainder of the field, leadingto significant reduction in the number ofwells required.23

A typical problem is that posttreatmenttransient pressure analysis shows the frac-ture is shorter than indicated by the volumeand leakoff of pumped fluid. There could beseveral reasons for the disparity. A commonreason, however, is that most postfractureevaluation models assume ideal reservoirconditionshomogeneous and isotropicformations, uniform fracture width and con-

ductivity and absence of skin damage.24To get away from assuming ideal reservoir

conditions, Schlumberger has made severalimprovements to the ZODIAC ZonedDynamic Interpretation, Analysis and Com-putation program. This program improvesevaluation by accounting for variation infracture conductivity and width along thefracture length, for reservoir permeabilityanisotropy and for fracture face skin dam-

age.25 It also does not link fracture heightwith bed thickness (above), but uses a P3D

approach to permit variation in proppedfracture height and width in the analysis.Compared to conventional postfracturepressure transient analysis, the programtakes 10 to 15% more computer time on aVAX or Sun workstation. In the future, it willinclude capabilities to model the effects ofreservoir boundaries and high-velocity flowon fracture length and conductivity esti-mates. The effects of reservoir boundariesare often observed in transient tests of longduration. These effects can be used to esti-mate the area and shape of the drainagearea of the well.

The Fracture Frontier: Rock Mechanics

Today, the center of controversy in fractur-ing is a fundamental concept called fracturetoughness, a measure of energy dissipatedby fracture growth. Established thinkingholds that fracture toughness is a materialproperty that is independent of fracture size.The focus is on energy dissipated at the frac-ture tip, considered to be a very small zone.

Another school of thought, led by investiga-tors at Shell, mainly Jacob Shlyapobersky,maintains that fracture toughness is not amaterial property, and that it increases withfracture size.26 This point of view holds thatfracture toughness is the release of energynot at the fracture tip but within a largezone of irreversible deformation around thefracture tip. The volume of this zone is

thought to increase with fracture size.These two views lead to different explana-tions for the creation of fracture width,which is directly related to net pressure(fracture propagation pressure minus closurepressure). The size-dependent school saysfracture width is larger and only weaklyaffected by fracture fluid viscositythat is,that net pressure is not sensitive to viscosity.This is because net pressure, in order toovercome the large, size-dependent tough-ness, creates a fracture width large enoughto make viscous flow effects negligible.According to established thinking, because

toughness is not size-dependent and has aconventional magnitude, pressure gradientsfrom viscous flow dominate the toughnesseffect and fracturing, and create smallerfractures than those modeled by the size-dependent toughness school.

The two schools, therefore, have differentcalculations of fracture length and requiredpad volume. The size-dependent schoolmaintains that the established view willunderestimate width and therefore overesti-mate fracture length for a given fracture vol-ume. This is because net pressure, accord-ing to the established view, is determined

mainly by viscosity and not, as the sizeschool holds, by viscosity and increasingfracture toughness. The established viewmaintains that apparent error in estimationof fracture length and width does not resultfrom size-dependent toughness but from useof an inappropriate fracture geometry orreservoir model.27

Another area of investigation concerns theassumption that rock behaves as a purely

14 Oilfield Review

23. Martins JP, Leung KH, Jackson MR, Stewart DR andCarr AH: Tip Screen Out Fracturing Applied to theRavenspurn South Gas Field Development, paperSPE 19766, presented at the 64th SPE Annual Tech-

nical Conference and Exhibition, San Antonio,Texas, USA, October 8-11, 1989.

24. Walsh DM and Leung KH: Post Fracturing Gas WellTest Analysis Using Buildup Type Curves paper SPE19253, Offshore Europe 1989, Aberdeen, Scotland,September 5-8, 1989.

25. Poe BD, Shah PC and Elbel JC: Pressure TransientBehavior of a Finite Conductivity Fractured WellWith Spatially Varying Fracture Properties, paperSPE 24707, presented at the 67th SPE Annual Tech-nical Conference and Exhibition, Washington DC,USA, October 4-7, 1992.

26. Shlyapobersky J, Walhaug WW, Sheffield RE andHuckabee PT: Field Determination of FracturingParameters for Overpressure Calibrated Design ofHydraulic Fracturing, paper SPE 18195, presented

at the 63rd SPE Annual Technical Conference andExhibition, Houston, Texas, USA, October 2-5, 1988.

Shlyapobersky J, Wong GK and Walhaung WW:Overpressure Calibrated Design of Hydraulic Frac-turing, paper SPE 18194, presented at the 63rd SPEAnnual Technical Conference and Exhibition, Hous-ton, Texas, USA, October 2-5, 1988.

Lewis PE: Analysis of Treatment Data Yields Cost-Effective Fracturing, The American Oil and GasReporter35, no. 1 (January 1992): 32-34, 36-38.

Shlyapobersky J: Energy Analysis of Hydraulic Frac-turing, Proceedings of the 26th US Symposium onRock Mechanics, Rapid City, South Dakota, USA(June 26-28, 1985): 539-546.

Shlyapobersky J and Chudnovsky A: FractureMechanics in Hydraulic Fracturing, in Tillerson JRand Wawersik WR (eds): Proceedings of the 33rdUS Symposium on Rock Mechanics. Santa Fe, New

Mexico, USA (June 3-5, 1992): 827-836.27. Elbel J and Ayoub J: Evaluation of Apparent Fracture

Lengths Indicated From Transient Tests, paperCIM/AOSTRA 91-44, presented at the CIM/AOSTRATechnical Conference, Banff, Alberta, Canada, April21-24, 1991; Canadian Journal of Petroleum Tech-nology(in press).

Nolte KG and Economides MJ: Fracture LengthDetermination and Implications for TreatmentDesign, paper SPE 18979, presented at the SPERocky Mountain Regional/Low Permeability Reser-voir Symposium and Exhibition, Denver, Colorado,USA, March 6-8, 1989;Journal of Petroleum Engi-neering43 (September 1991): 1147-1155.

C onventionalpostfracture w ell test

ZO D IAC / P3D

n Postfracture interpretation of fracturegeometry by conventional pressure tran-sient analysis and with the ZODIAC pro-gram. The main difference is that con-ventional analysis does not account forspatial variation in fracture conductivityand width, assumes fracture heightequals bed thickness, and ignores frac-ture face skin damage. The blue area isignored in the conventional analysis.


12/69

15October 1992

Design of an Ideal Fracture Treatment

Obtain stress mag nitude a nd Youngs

Modulus 1 versus d epth from logs, cores.

Also co llect o ther well and forma tion

information: lithology, natural fracture

loca tions, porosity. Check offset w ell data .

Select fluids and additives that minimize

formation and proppant damage and

environmental impact.

If not do ne ea rlier, perform microfrac to

dete rmine c orrect mod el, fluid loss

co efficient and treatment e fficiency (volume

of fluid pumped versus vo lume o f frac ture,

dete rmined ma inly b y leakoff).

Is w ell producing a s expec ted?

Yes

Yes

Finalize pump s ched ule w ith PLACEMENT

program . The program gives press ure

required during job, frac length at end of

job and distribution of proppant.

Execute job.

No

No

1. Youngs Modulus is the ra tio of stres s (force per unit area ) to strain (displace ment pe r unit length).

Fracture treatment

design is optimal.

Was bo ttomho le pressure

during exec ution a s e xpected?

Obta in permeab ility a nd rese rvoir press urefrom well test; porosity from logs.

Tes t for d ifferent fra ct ure

model or less length.

Improved or expanded stress

and modulus da ta .

Use net prese nt va lue (NP V) ca lculation to

select proppant, optimize pump schedule

and fracture length, and predict production.

Iteration for revisions .

Stressrevision.

Fracmodelre

vision.

Fluidrevision.

If appropriate fracture geometry model not

known, do microfrac (1/3 to 1/2 length of

actual job, no proppant) to select fracture

geo metry mo del (2D, P 3D, MLF).

Do w ell test a nd us e ZODIAC

program to evaluate fracture

treatment and reservoir

characterization.

Analyze bottomhole pressure

during e xecution w ith various

fracture models.

Different frac ture g eome try

model or length?

Different reservoir mod el

permea bility? Is rese rvoir

anisotropic? Layered?

Stress sensitive?

Fracture skin or lower frac ture

conductivity?


13/69

elastic continuum, meaning that deforma-tion short of fracturing is fully reversible.There is evidence that high-permeability/high-porosity formations may be elastoplas-tic, meaning they have some component ofirreversible deformation (below). Furtherwork on this is becoming possible with theincrease in computer power needed to solveequations for nonelastic behavior, which are

far more complex than those for elasticbehavior. Significant nonelastic behaviorwould affect the prediction of fracturegeometry and the analysis of fracture pres-sure data.

The Fracture Frontier: High-Angle Wells

Field experience in highly deviated and hor-izontal wells shows that it is possible to per-form hydraulic fracturing in these settings,but the effect on well performance is stilluncertain. Little has been published on theeffect of fracturing on deviated well perfor-mance.28 Shell investigators found that

reduced productivity is expected from afractured deviated well compared to a frac-tured vertical well.29 This is because the axisof the wellbore may not lie in the preferredfracture plane and may intersect the fractureover only a small reservoir interval. This

results in limited communication to theborehole during fracturing and a pressuredrop that inhibits productivity. In the Prud-hoe Bay field, BP has found that fracturingcan impair the performance of highly devi-ated wells.30

Nevertheless, the increasing number ofdeviated and horizontal wells has inspiredwork on fracture modeling in these settings.

Today, fracture treatment design in thesewells is largely by rule of thumb. But severalobservations have been made by Hallamand Last of BP that can enhance treatmentdesign in deviated wells:31

When perforation tunnels are not normalto the minimum stress, fractures reorientin the preferred direction. If tunnels areshort compared to their spacing, the frac-tures will curve before linking up, result-ing in further pressure drop. Perforationlength should therefore be at least one-third to one-half tunnel separation, that is,4 to 6 in. [10 to 15 centimeters (cm)].

Perforation densities should be 6 shots/ftat 60 phasing and 360/ shots/ft for phasing.

A single large fracture is more productivethan several smaller ones that may notlink up. Hallam and Last constructed an

empirical curve showing the maximumborehole deviation that will allow devel-opment of a single fracture.

Hallam and Last made these observationsbased on studies in which they cemented orcast a liner in a block of rock, then loadedit. Work by CJ de Pater and colleaguesshows that if the block is first loaded, thenthe liner is cemented, fracture geometry will

be different.32

Work by Hugo Morales at DowellSchlumberger, using a 3D fracture simulatorthat permits curved fractures, shows thatfracture initiation pressure can be calculatedfor deviated wells, given well inclination,azimuth and direction of principal stresses.But once the fracture starts, there is not yet acalculation for propagation pressure. This isbecause fracture propagation models do notaddress how multiple fractures affect near-borehole stresses. A general recommenda-tion, however, is that flow rate should behigh enough to reduce bridging of proppant

associated with pressure drops of multiple,small fractures (next page).An evolving capability is triaxial borehole

seismic imaginglistening from three direc-tions to sound emitted by the fracture as itcloses, then triangulating its location to find

16 Oilfield Review

C onceptual D eform ation M odels

C ontinuoussolid

Planes ofcontinuous w eakness

D iscreteblocks

Randomfractures

Elastic/brittle orelastoplastic

Elastic and discontinuous plastic Plastic

C O N T I N U U M

Fracture

n Several modes of rock response to stress. In rock mechanical terms, they are elastic continuous deformation,brittle failure, discontinuous deformation of block-jointed rock, and pseudocontinuous deformation and plas-tic yield of heavily fractured rock. Current theories of fracturing and treatment design are limited becausethey use elastic continuous deformation and brittle failure almost exclusively.


14/69

fracture length.33 This would provide valu-able feedback in development of fracturepropagation models. Still, the weakest linkin the models is probably stress magnitudedetermination. A confident measurement ofstress, by an economical and practicalmethod, would provide the required datafor evolving a fracture propagation model.

Probably as important as technical

improvements is a change in the engineer-ing mindset. If only I had a fully 3D model,all my problems would go away is perhapsjust half true. Often, the most sophisticatedfracture propagation models and fracturetreatment designs are undermined by some-thing as simple and elusive as bad perme-ability data. In 3D modeling, major limita-tions remain in input datait is still difficultto obtain valid stress profiles, fluid-loss pro-files and fracture conductivities.

Today, fully 3D models help generate sim-pler models for routine application. Carefulpostfracture evaluation allows the engineer

to tune fracture design, yielding the mostfrom the simplest approaches. Tomorrow,increased computer power may place thecurving fracture of varying height and widthwithin reach of engineers in the field. JMK

28. One notable paper on the subject to date: Ovens J:The Performance of Hydraulically Fractured Stimu-lated Wells in Tight Gas Sands: A Southern NorthSea Example, paper SPE 20972, presented atEuropec 90, The Hague, The Netherlands, October22-24, 1990.

An overview of fracturing horizontal wells:

Soliman MY, Hunt JL and El Rabaa AM: FracturingAspects of Horizontal Wells, paper SPE 18542, pre-sented at the SPE Eastern Regional Meeting,Charleston, West Virginia, USA, November 1-4,1988;Journal of Petroleum Technology 42 (August1990): 966-973.

Brown E, Thomas R and Milne A: The Challenge ofCompleting and Stimulating Horizontal Wells, Oil-field Review2, no. 3 (October 1990): 52-62.

29. Veeken CAM, Davies DR and Walters JV: LimitedCommunication Between Hydraulic Fracture and(Deviated) Wellbore, paper SPE 18982, presentedat the SPE Joint Rocky Mountain Regional/Low Per-meability Reservoirs Symposium and Exhibition,Denver, Colorado, USA, March 6-8, 1989.

30. Martins JP, Dyke GC, Abel JC, Ibe OE, Stewart G,Bartel PA and Hanna RR: Analysis of a HydraulicFracturing Program Performed on the Prudhoe BayOil Field, paper SPE 24858, presented at the 67thSPE Annual Technical Conference and Exhibition,

Washington, DC, USA, October 4-7, 1992.31. Hallam SD and Last NC: Geometry of Hydraulic

Fractures From Modestly Deviated Wellbores,paper SPE 20656, presented at the 65th SPE AnnualTechnical Conference and Exhibition, New Orleans,Louisiana, USA, September 23-26, 1990.

32. de Pater CJ, personal communication, 1992.

33. Vinegar HJ, Willis PB, DeMartini DC, ShlyapoberskyJ, Deeg WFJ, Adair RG, Woerpel JC, Fix JE and Sor-rells GG: Active and Passive Seismic Imaging ofHydraulic Fractures in Diatomite, paper SPE22756, presented at the 66th SPE Annual TechnicalConference and Exhibition, Dallas, Texas, USA,October 6-9, 1991.

n Orientation of hydraulic fractures in horizontal wells as a function of stress directions(top)and, in a deviated well, evolution of small, multiple fractures that may contributeto pressure drop at the wellbore (bottom). In the horizontal well example, only one largefracture forms if the wellbore axis is normal to the minimum horizontal stress. If thewellbore axis parallels the minimum horizontal stress, fractures form at each perfora-tion. The end fractures are highest because they are affected on only one side by thecompressive stress exerted by the opening of the neighboring fracture. Height of these

end fractures tends not to exceed 2 to 3 borehole diameters. The time-lapse view (bot-tom)shows fractures developing tails that reach up and down the wellbore. By time 3,they coalesce into one fracture. In so doing, rhomboids of rock are isolated between the

perforations. Small fractures develop here that may contribute to pressure drop at thewellbore and early bridging of proppant.

17October 1992

M ax.horizontalstress

M in.ho rizontalstress

M ax.ho rizontalstress

M in.horizontalstress

M inim umhorizontal stress

Time 1 Time 2 Time 3


15/69

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.

Dam

age

U ndam aged reservoir

Short, w ide fracture

n 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.



16/69

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 fracture

conductivityproportional 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.

H igh-perm eabilityform ations

Low -perm eabilityform ations

R elative co nductivity

Lengthoffrac

ture,

fracture

length

/drainag

eradius

(xf

/re)1.0

0.9

0.8

0.7

0.6

0.5

0.4

0.3

0.2

0.1

10 2 10 3 10 4 10 5 10 6

Increasingproductivity

Cfd=KfW

KXf

1.


17/69

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 its

desired 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

Proppantbridgesat tip

Proppant

Fluidleakoff

Proppantfillsfracture

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.


18/69

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.

Proppant

n 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 prop pa nt co nce ntration, 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 of six Indonesian

wells fractured using the

tip-screenout technique.

Although all the we lls 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 screens to place a

small, highly conductive

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.

P

roductionrate,B

/D

Fractured

N onfractured

Prod uction tim e, days

10 3

10 2

0 30 60 90

Sim ulation

D ata


19/69

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-


20/69

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

N

etpressure,psi

Prod uction tim e, days

Sim ulation

D ata1000

500

100

2 5 10 20 50 100


21/69

Faced with poor production from a high-permeability reservoir, an operators 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.

24 Oilfield Review

Trends in Matrix Acidizing

The simple aim of matrix acidizing is toimprove productionreduce skin in reser-voir engineer parlanceby 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. Compared

with 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 snagtheacid severely corroded the well casing. Thetechnique declined in popularity and laydormant for about 30 years.

Then in 1931, Dr. John Grebe of the Dow

Chemical 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 hydrofluoric

acid [HF]hydrochloric acid does not reactwith silicate mineralswas 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 the

Gulf Coast to remove mudcake damage.1

Curtis CroweTulsa, Oklahoma, USA

Jacques MasmonteilEric TouboulSaint-Etienne, France

Ron ThomasMontrouge, France



22/69

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 service

marks 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 Technology17 (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.

25October 1992

n Mold 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.

Chemistry

Matrix 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

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