cracking rock: progress in fracture treatment...

Cracking Rock: Progress in Fracture Treatment Design

COMPLETION/STIMULATION

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

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.

Barry BradyJack ElbelMark MackHugo MoralesKen NolteTulsa, Oklahoma, USA

Bobby PoeHouston, Texas, USA

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 the“Hydrafrac” 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

Oilfield Review

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.

1. Clark JB: “A Hydraulic Process for Increasing the Pro-ductivity of Wells,” Transactions of 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.

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

5October 1992

North Americanactivity declines;gas deregulation

Middle Eastimports to North America

Removedamage

Tight gas;goal of 10×increase

Improvedmaterials,understanding

Year

Frac

ture

trea

tmen

ts/y

r

OPEC supply restrictions

Moderate/highperm; goalof 2×increase

0

1000

2000

3000

4000

1950 1960 1970 1980 1990 2000

nChanging 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.

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

nA typical pumping scheduhydrofrac in a gas well in eahoma, USA. Each unit of fluirepresents a change in propconcentration or flow rate orcalled a stage; a specific seof stages is called a pumpinschedule. This is a pumpingule to produce a 909-foot [27fracture. The pad fractures tand helps transport the propwhich holds the fracture opepressure is released. A majoponent of fracture design is lishing the volume and chempad and slurry. Generally, t

Stage Name

Pad

Slurry

Slurry

Slurry

Slurry

Slurry

Pump Ratebbl/min.

35

35

35

35

35

35

the faces of the fracture and prevent themfrom fitting closely together, or the fractureis 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 proppant—generally sand—in sus-pension. Different concentrations of prop-pant and volumes of slurry are pumped asthe job progresses (below).

le for ast Okla-

d thatpant both isquenceg sched-7-m]he rockpant,n afterr com-estab-

istry ofhe pad

is the largest stage, accounting fo30 to 50% of fluid, and, rarely, up 70%. Ideally, to optimize thepropped fracture length, the pad icompletely leaked off at themoment the fracture reaches itsintended length. If the pad leaks otoo soon, the fracture will be tooshort; if too late, the fracture is noteffectively propped. In this well, fislurry stages with different proppaconcentrations and volumes areused, but as many as 17 or 20 slurstages may be used in large fracjobs. The later slurry stages havehigher proppant concentrationsthan earlier stages because theslurry fluid leaks off as it travelsalong the fracture. Therefore, a

Job Description InformationFluid Name

YF140

YF140

YF140

YF140

YF140

YF140

Stage FluidVolume

gal

5000

9000

14,000

23,000

15,000

13,200

ProppantConcentration

lbm/gal

0

2

4

6

8

0

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 itremains 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 fluid’s high viscosity is no longerneeded, the high temperature of the forma-tion or special oxidizers cause the fluid“break” 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 manytemperature, 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.

Oilfield Review

rto

s

ff

vent

ry

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 endof 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 aparticle 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.

Proppant Type+ Mesh

INTERPROP + 20/40

INTERPROP + 20/40

INTERPROP + 20/40

INTERPROP + 20/40

INTERPROP + 20/40

—

Estimated SurfacePressure

psi

5630

4610

3760

3080

2460

6170

25% slurry volume pumped

Hei

ght,

m

30

15

0



Distance, m

0 50 100

Hei

ght,

m

30

15

0

Hei

ght,

m

30

15

0

nAn 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 noproppant, 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 theslurry 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. Thispacked 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 Review 3, 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): 5-1–5-23.Ely JW: “Fracturing Fluids and Additives,” in GidleyJL, Holditch SA, Nierode DE and Veatch RW Jr (eds):Recent Advances in Hydraulic Fracturing, Monograph

Initialfracturegeometryat wellbore

Pro

ppan

t con

cent

ratio

n, v

ol %

0

5

10

15

20

25

30

3565

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 design—the selectionof pump rates, fluid properties, pumpingschedule and fracture propagation model—will create the intended fracture (see “ToFrac or Not to Frac?” next page).

Pivotal to designing the treatment—and todeciding whether to do one at all—is 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 won’t 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 certainrate, how much should be spent onhydraulic fracturing given a future oil price.

In the past few years, improvements infracture 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.

12. Richardson, Texas, USA: Society of PetroleumEngineers (1989): 130-146.

7October 1992

Maximum benefit achieved forrecompletions only?

Maximum benefit achieved aftermatrix treatment only?

Is maximum benefit achievedafter fracturing only?

Is maximum benefit achieved afterfracturing with recompletion?

No

No

No

No

No

Perform recompletion.



Yes

Yes

Yes

Yes

Yes

Determine if the well is providing the maximum benefit, indicatedby return on investment and net present value.

Determine benefit using NODALanalysis for variouscombinations of:•Recompletions (tubing size,

perforations, surfaceequipment, artificial lift)

and•Matrix treatments(different materials and sizes)

or•Fracture treatments (different material and sizes).

Perform matrixtreatment (see “Trends in MatrixAcidizing,” page 24).

Perform fracturetreatment.

Evaluate permeability and skin (near well damage) from well 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 ScreenoutBehavior,” 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 ModelingThe 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.7They reasoned that because a fracture is aplane of parting in rock, the rock will openin the direction of least resistance. At thedepth 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? Howdoes 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 orset 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 Journal 12(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 AIME 222.

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 Technology 19(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): 10-1–10-13.

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 maximum benefit achieved aftermatrix treatment with recompletion?

Fracturing not needed.

To Frac or Not to Frac?

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), Young’smodulus, 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 realisticbecause 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)

nStresses 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, S r, and tangential, S t. 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 paylayer 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 user’s 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 fracturelength 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 Models

Fractureheight fixed

Fractureheight not

fixed

Pre

ssur

e re

quire

dto

ext

end

fract

ure

PKN

KGD

Radial

• Elliptical cross section• Width ∝ height• Width < KGD; length > KGD• More appropriate when fracture length > height

• Rectangular cross section• Width ∝ length• More appropriate when fracture length < height

• Appropriate when fracture length = height

Time

Pre

ssur

e re

quire

dto

ext

end

fract

ure

Time

Pre

ssur

e re

quire

dto

ext

end

fract

ure

Time

nThe family ofbasic 2D fracturemodels—PKN,GDK and radial.

Sv

St

Sr

Verticalstress

Min.horiz.stressMax

horiz.stress

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 ofPetroleum 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): 3-1–3-31.

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 model—high, known stresscontrasts—the P3D model height predictionmay be more accurate than the estimatedheight 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 stressmeasurement 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 l’Institut Français du Pétrole 47, 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.

nA 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.

Wel

l dep

th, f

t

Logderived

Microfrac test

Minimum horizontal stress, psi

4200

4600

5000

5400

58002200 2600 3000 3400

nStress 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

High contrast

High contrast

High contrast

High contrast

Low contrast

Low contrast

2D versus P3D/3D Fracture Modelsfor Different Bed Boundary Stress Contrasts

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

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 tofracture 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 use—they requireaccurate stress contrast data—and so are notwidely 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 integral”along the total fracture length and height. Inthe P3D model, the pressure-width relationis 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 thefully 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 don’t include it.Mathematically, lateral coupling puts back agross approximation of the pressure integralalong the fracture length. This poor-man’sintegral 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 inorder 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

Bot

tom

hole

pre

ssur

e, p

si

Pressure decline

Fracture closeson proppant

ReservoirpressureClosure pressure =

minimum horizontal rock stress

9000

8000

7000

6000

500038 40 42 44 46 48 50 56 58

Time, hr

Fractureclosing

Fracturetreatment

Pre

ssur

e re

quire

d to

ext

end

fract

ure,

psi

Lateralcoupling

PKN

KGD

Time, min

300

250

200

150

100

500 20 40 60 80

nEffect 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.

nPressure versustime for lateralcoupling com-pared with tradi-tional fracturemodels.

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 asingle 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 perforating—varying 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 asfor P3D: stress profile, Young’s 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 fracture—if length exceedsheight, it’s PKN; if length is less than height,it’s 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: What’s 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

Gammaray Layered beds 2D P3D MLF

Per

fsP

erfs

Shale Sand

nComparison 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. Young’s 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 Young’s Modulus. As with other 2D models, height isselected for each layer, here by lithologic boundaries. The next generation MLF model will adapt P3D modeling.

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 PetroleumTechnology 43 (May 1991): 608-615.

19. Ahmed U, Newberry BM and Cannon DE: “HydraulicFracture Treatment Design of Wells with MultipleZones,” 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 perforatingtechnique: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.

Pro

ppan

t wei

ght,

lb ×

106

Trea

tmen

t cos

t, $

×106

Frac

ture

con

duct

ivity

, md-

ftFr

actu

re p

enet

ratio

n, ft

Fracture half-length, ft


Fluid volume, gal

KGD

PKN

0

0.25

0.50

0.75

1.0

0

500

1000

1500

2000

0 750 1500 2250 3000


KGD

PKN

0

0.5

1.0

1.5

2.5

0 750 1500 2250 3000

2.0

KGD

PKN

0 80,000 160,000 240,000

KGD

PKN

400

900

1400

1900

2400

2900

0 750 1500 2250 3000

nComparison 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

Pad 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

Average sand concentration, lbm/gal

Total amount of sand, lbm

Viscosity after pad, cp

Created fracture length, ft

Effective fracture length, ft

Created fracture width, in.

Effective fracture width, in.

Effective fracture height, ft

Average fracture conductivity, darcy-ft

Adapted from Veatch RW Jr, et al, reference 3.

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 nearestthis 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

October 1992

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 AlaskaInc. 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-son’s 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.

13

Conventionalpostfracture well test

ZODIAC / P3D

nPostfracture 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.

Enhanced Fracture Treatment EvaluationFracture 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 BP’s 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 ofbottomhole 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 reservoirconditions—homogeneous and isotropicformations, uniform fracture width and con-ductivity and absence of skin damage.24

To get away from assuming ideal reservoirconditions, 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-

14

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.

age.25 It also does not link fracture heightwith bed thickness (above), but uses a P3Dapproach 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 MechanicsToday, 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.

26. Shlyapobersky J, Walhaug WW, Sheffield RE andHuckabee PT: “Field Determination of FracturingParameters for Overpressure Calibrated Design ofHydraulic Fracturing,” paper SPE 18195, presentedat 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 GasReporter 35, 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.

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 isthought 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 viscosity—that 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, becausetoughness 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 determinedmainly 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

Oilfield Review

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, NewMexico, USA (June 3-5, 1992): 827-836.

27. Elbel J and Ayoub J: “Evaluation of Apparent FractureLengths 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-neering 43 (September 1991): 1147-1155.

15October 1992

Design of an Ideal Fracture Treatment

Obtain stress magnitude and Young’sModulus1 versus depth from logs, cores.Also collect other well and formationinformation: lithology, natural fracturelocations, porosity. Check offset well data.

Select fluids and additives that minimizeformation and proppant damage andenvironmental impact.

If not done earlier, perform microfrac todetermine correct model, fluid losscoefficient and treatment efficiency (volumeof fluid pumped versus volume of fracture,determined mainly by leakoff).

Is well producing as expected?

Yes

Yes

Finalize pump schedule with PLACEMENTprogram. The program gives pressurerequired during job, frac length at end ofjob and distribution of proppant.

Execute job.

No

No

1. Young’s Modulus is the ratio of stress (force per unit area) to strain (displacement per unit length).

Fracture treatmentdesign is optimal.

Was bottomhole pressureduring execution as expected?

Obtain permeability and reservoir pressurefrom well test; porosity from logs.

Test for different fracturemodel or less length.

Improved or expanded stressand modulus data.

Use net present value (NPV) calculation toselect proppant, optimize pump scheduleand fracture length, and predict production.

Iteration for revisions.

Str

ess

revi

sion

.

Frac

mod

el r

evis

ion.

Flui

d r

evis

ion.

If appropriate fracture geometry model notknown, do microfrac (1/3 to 1/2 length ofactual job, no proppant) to select fracturegeometry model (2D, P3D, MLF).

Do well test and use ZODIACprogram to evaluate fracturetreatment and reservoircharacterization.

Analyze bottomhole pressureduring execution with variousfracture models.

Different fracture geometrymodel or length?

Different reservoir modelpermeability? Is reservoiranisotropic? Layered? Stress sensitive?

Fracture skin or lower fractureconductivity?

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 arefar 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 WellsField 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 thatreduced 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

16

Continuoussolid

Elastic/brittle orelastoplastic

Fract

nSeveral modes of robrittle failure, disconttic yield of heavily frathey use elastic conti

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/φ shots/ft for φ°phasing.

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

Conceptual Deformation Model

Planes ofcontinuous weakness

Db

Elastic and discontinuous plas

C O N T I N U U M

ure

ck response to stress. In rock mechanical terminuous deformation of block-jointed rock, andctured rock. Current theories of fracturing an

nuous deformation and brittle failure almost e

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 willbe 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 proppantassociated with pressure drops of multiple,small fractures (next page).

An evolving capability is triaxial boreholeseismic imaging—listening from three direc-tions to sound emitted by the fracture as itcloses, then triangulating its location to find

Oilfield Review

s

iscretelocks

Randomfractures

tic Plastic

s, they are elastic continuous deformation, pseudocontinuous deformation and plas-d treatment design are limited becausexclusively.

Max.horizontalstress

Min.horizontalstress

Max.horizontalstress

Min.horizontalstress

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 technicalimprovements 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 data—it 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 engineerto 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 Review 2, 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 HydraulicFractures 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, Shlyapobersky

J, 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.

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

17October 1992

Minimumhorizontal stress

Time 1 Time 2 Time 3

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

Now, short, wide fractures are being created to

18

Dam

age

Undamaged reservoir

Short, wide fracture

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

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.


A classic fracture stimulation creates nar-row conduits that reach deep into a forma-tion—typically, about 1/10 in. [2.5 millime-ters] wide and up to 1000 ft [300 m] long.Since the 1940s, relatively low-permeabil-ity formations—less than 20 millidarcies(md)—have been successfully fractured togive worthwhile increases in productivity.

However, as formation permeabilityincreases, 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 largequantities 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

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 contrast—and therefore a high relativeconductivity—and 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.

Oilfield Review

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

2. Hannah RR and Walker EJ: “Fracturing a High-Perme-

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

nIncrease in posttreatment productivity versus relative fractureconductivity—proportional to the permeability contrast betweenthe formation and propped fracture—for 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

Leng

th o

f fra

ctur

e,fra

ctur

e le

ngth

/dra

inag

e ra

dius

(x f

/re)1.0

0.90.80.7

0.6

0.5

0.4

0.3

0.2

0.1

102 103 104 105 106

Incr

easi

ng p

rodu

ctiv

ity

Cfd = Kf WKXf

1.

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 today’s thinking. In 1984, in Prud-hoe Bay, Alaska, USA, Sohio fractured awell 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 downwardfracture 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-centration—most 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/ft2—modest by today’s stan-dards, which aspire to place 4 lbm/ft2 or more.

After this job, attention shifted to theNorth 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)

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

nTip-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 furtherpropagation.

B) Additional slurry is pumped into thefracture increasing the net pressureinside the fracture, causing it to widen.

C) Further dehydration of the slurry cre-ates a pack of proppant that graduallyevolves from the tip toward the wellbore.

20

Proppantbridgesat tip

Proppant

Fluidleakoff

Proppantfillsfracture

A

B

C

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 fractureusing 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 mdhigher than gas wells that are normally frac-tured, but BP found that conductivity oflong, conventional fractures limited thereservoir’s 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 be“lost” 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 thedesigned 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

3. Smith MB, Miller WK and Haga J: “Tip ScreenoutFracturing: A Technique for Soft, Unstable Formations,”SPE Production Engineering 2 (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,” paperSPE 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.

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 theproppant 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 “SandControl: 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 (see”Average 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

Oilfield Review

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.

Proppant

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

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 reservoirwith 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-sion—gaining an insight into the formation’snatural permeability before damage, thedepth of invasion, the presence of zones

October 1992

Average Data From Three Types of

Average data

Total vertical depth, ft

Zone thickness, ft

Zone permeability, md

Pad volume, gal

Slurry volume, gal

In-situ proppant concentration, lbm/ft2

Propped fracture length, ft

Propped fracture conductivity, md-ft

Pretreatment oil production, BPD

Posttreatment oil production, BPD

Pretreatment skin

Posttreatment skin

Type A

7240

68

72

1600

685

3.8

28

5670

1040

2140

Tr

Treatment Type AA series of six Indonesianwells fractured using thetip-screenout technique.Although all the wells werepotential sand producers nospecial sand-controltechniques were employed.

Treatment Type BTwo Indonesian wellsfractured with tip-screenouttreatments performedthrough gravel-pack toolsand screens to place asmall, highly conductivefracture and a gravel packin a single step.

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.

nPredicted andico, USA, well stfracturing.

Treatment

Type B

3560

32

53

5100

2000

2.1

18

2.3

Type C

4400

48

60

3500

1740

1.2

115

156

1313

eatment Type

Treatment Type CSeries of treatmentsperformed on two offshoreexploration wells to createvertical communicationbetween several thin, high-permeability zones thatwere believed to be water-and acid-sensitive.

Pro

duct

ion

rate

, B/D

103

102

0

After a candidate well has been identified,the next stage is to design the treatment, aprocess that relies on knowledge of therock’s mechanical properties and an esti-mate of the stresses in the reservoir andadjacent rock (see “Cracking Rock: Progressin Fracture Treatment Design,” page 4).

21

real productivity increase in a Gulf of Mex-imulated in early 1992 using tip-screenout

Fractured

Nonfractured

Production time, days

30 60 90

SimulationData

nFracturing high-permeability formationsin Indonesia. A specially modified twin50-bbl mixer is capable of mixing andpumping 18 lbm/gal slurries at more than20 bbl/min. A centralized control stationallows one operator to control and monitorthe complete treatment—essential as pump-ing times can be as short as 2 minutes.

22 Oilfield Review

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 compressionaland 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 relativelysmall volume of ungelled fluid without

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-

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 tests—which frac-ture the formation usually using gelled fluidwithout proppant—enables 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-ing—fluid flow in the fracture and leakoff,proppant transportation and settling, androck response—to describe the relationship

23October 1992

nComparing 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.

Net

pre

ssur

e, p

si

Production time, days

SimulationData

1000

500

100

2 5 10 20 50 100

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 proppantpack. If closure stress is less than antici-pated, the proppant pack could becomeunstable during production—unless 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 byincreasing the viscosity of the fracturingfluid or enhancing the fluid’s 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 tipscreenout, 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 smaller—and therefore of lower con-ductivity—than 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-cess—“Has 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-

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 fracture’s communica-tion with the perforated interval along thewellbore by tracing cooling anomalieswhere the fluid has entered the formation.

However, the most important indicators ofsuccess are the well’s 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

2

Trends in Matrix Acidizing

Curtis CroweTulsa, Oklahoma, USA

Jacques MasmonteilEric TouboulSaint-Etienne, France

Ron ThomasMontrouge, France


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

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

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

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

throughs are helping optimize matrix acid jobs.

4

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

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

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

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

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

Oilfield Review

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

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

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

October 1992

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

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

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

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

acid chloride dioxide

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

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

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

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

25

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

2µ

2µ

Before acid After acid

Mud

aci

dFl

uobo

ric a

cid

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

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

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

26

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

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

nConstituents of sandstone, all of which are soluble in

HCl-HF mud acid systems.

Pore-lining clays, e.g. illite

Pore-fillingclays, e.g. kaolinite

Secondary cement:carbonate, quartz

Quartz, feldspars,chert and mica.

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

The reaction of hydrofluoric acid [HF] on the pure

quartz component of sandstone follows these two

equations:

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

tetrafluoride

and

SiF4 + 2F– ↔ SiF62– ,

Silicon hexafluoride

resulting mainly in the silicon hexafluoride anion,

SiF62–.

Reaction with the feldspar, chert, mica and clay

components of sandstones also results in this

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

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

–,

HF Reactions in Sandstones

AlF52– and AlF6

3– (left). The concentration of each

aluminum complex depends on the concentration

of free fluoride ions in the dissolving solution.

Some of these products combine with free

sodium, potassium, and calcium ions to produce

four compounds with varying degrees of solubility

in the spending acid:

• sodium fluosilicate [Na2SiF6],

• sodium fluoaluminate [Na3AlF6],

• potassium fluosilicate [K2SiF6],

• calcium fluosilicate [CaSiF6].

Matrix treatments are always designed to prevent

the formation of these compounds, to remove any

risk of precipitation.

Oilfield Review

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

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

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

Pro

duct

ion,

BLP

D

4000

0 1 2

3000

2000

1000

0Fluoboric acid treatment

Time, yr

Mud acid treatment

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

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

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

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

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

October 1992

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

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

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

Silicon hexafluoride also combines with water

to produce colloidal silica [H4SiO4]:

SiF62– + H2O ↔ H4SiO4 + 4HF + 2F– .

This precipitate has proved controversial. Experts

agree that it cannot be avoided, but disagree

about whether it damages the formation. Some

believe it does, but work by Dowell Schlumberger

researcher Curtis Crowe suggests that colloidal

silica coats sandstone particle surfaces, actually

limiting the movement of fines that the treatment

would otherwise dislodge.1

Two other aluminum-based compounds—alumi-

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

—may precipitate, following these reactions:

27

Al3 + 3F– ↔ AlF3 ,

and

Al3 + 3OH– ↔ Al(OH)3 .

However, these two compounds can generally be

avoided through proper design of preflush and

mud acid formulation.

Often, acidizing can produce ferrous and ferric

ions, either from dissolving rust in the tubulars or

through direct action on iron minerals in the for-

mation. These ions can then produce more pre-

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

wells, ferrous sulfide [FeS]. Various chelating

and reducing agents are employed to minimize

the impact of these two compounds.

Lastly, damage can arise through the precipita-

tion of calcium fluoride [CaF2], when HF reacts

with the carbonate mineralogy of sandstones:

CaCO3 + HF ↔ CaF2 + H2O + CO2 .

The main technique for avoiding calcium fluoride

precipitation is the HCl preflush, designed to

remove carbonate material before HF is injected.

Precipitates and their potential to damage the

formation remain a fact of life for the matrix

acidizer. But their impact can be greatly mini-

mized through use of an adequate preflush, the

correct mud acid formulation, and the avoidance

of any salts except ammonium chloride.

Openhole completion ?

Gravel packed ?Chemical

Chemical

Yes No

Yes No

Yes No

Coiled tubingavailable ?

Staged treatment required ?

Mechanical

Yes No

Flowback of balls a problem, or high shot density ?

Mechanical ball sealers

Yes NoChemical

Chemical

nChoosing a diversion method for matrix acidizing.

28 Oilfield Review

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

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

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

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

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

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

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

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

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

2 shots per foot

3000B

otto

mho

le fl

owin

g pr

essu

re, p

si ×

103

5

12 shots per foot

Gas production rate, Mscf/D

1000100

150001000050000

4

3

2

1

0

5

4

3

2

1

0

3000

1000100

01530

50

030

50

skin

p wellhead

psi

29

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

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

Scales

Organic deposits

Bacteria

Silts and clays

Emulsion

Water block

Wettability change

TubingGravel pack/perforations Formation

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

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

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

October 1992

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

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

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

30 Oilfield Review

Aci

d

Foam

Thief zone

Damaged zonePre

flush

Flow

rat

e, b

bl/m

in/2

0-ft

zone

0.75

0.5

0.25

0

1

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

1.25

Fluid N2

P P

Thie

f

Dam

age

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

Field Case StudiesWell type

High water-cutoil well

Gas well

Oil well

Low-perm gas well

9600

6600

11200

11,900

51

16

40

200

190

175

240

245

433 BOPD41% water cutGas lift

2 MMscf/D3 BOPDFTP: 1000 psi

0

1.8 MMscf/DFTP: 250 psi

855 BOPD38% water cutFTP: 2100 psi @ 2 months

5.6 MMscf/D17 BOPDFTP: 2100 psi @ 2 months

860 BOPDFTP: 220 psi @ 1 week

4.0 MMscf/DFTP: 400 psi @ 1 month

Depthft

Intervalft

Temperature°F

Productionbefore after

Foam, a stable mixture of liquid and gas, has

been used as a diverter in sandstone acidizing

since 1969.1 By the usual criteria, it is almost

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

job diverting; it does not interact adversely with

the formation and formation fluids; and it cleans

up rapidly. Foam is produced by injecting nitro-

gen into soapy water—typically, nitrogen occu-

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

is a mixture of water and small amount of surfac-

tant, or foamer. Injected downhole, foam pene-

trates the pore space where the cumulatively vis-

cous effect of the bubbles blocks further entry of

the treating fluid.

Foam’s only drawback is that with time the

bubbles break and diversion ceases. This can be

seen in laboratory experiments, in which foam is

injected simultaneously through two long sand

packs, one with high permeability mimicking a

thief zone, the other with low permeability mim-

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

are preflushed and then injected with foam. Then,

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

the low-permeability sand pack taking an

increasingly greater proportion of the acid. But

after about one hour, the foam has broken and the

thief zone starts monopolizing the treatment fluid.

Researchers at the Dowell Schlumberger engi-

neering center at Saint-Etienne, France discov-

ered that this breakdown can be postponed by

saturating the formation with a preflush of surfac-

Diverting with Foam

tant before injecting the foam and also injecting

surfactant with every subsequent stage in the

acid process. The surfactant adheres to the rock

surface and minimizes adsorption of surfactant

contained in foam, preserving the foam.

As before, the foam progressively diverts treat-

ment fluid to the damaged zone, but now the

diversion holds for at least 100 minutes (next

page, top). If necessary, damaged formation can

first be cleaned with mutual solvent to remove oil

in the near-wellbore region—oil destroys

foam—and to ensure the rock surface is water-

wet and receptive to the surfactant.

Yet further improvement to foam diversion can

be achieved by halting injection for about 10 min-

utes after foam injection. The diversion of treat-

ment fluid to the damaged sand pack now takes

effect almost immediately, rather than almost 50

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

cent period, foam in low-permeability sand pre-

maturely breaks down—scientists are not sure

why. The combination of surfactant injection and

10-minute shut-in comprises the new FoamMAT

diversion service that has seen successful appli-

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

Case Studies,” below).2

The FoamMAT technique also provides excel-

lent blockage of water zones in high water-cut

wells. In a laboratory simulation, two sand packs

were constructed with the same permeability but

saturated with different fluids, water and oil (next

page, bottom). The preflush injection of surfactant

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

Then foam was injected into both packs. When

acid was injected, most went into the oil zone

confirming an almost perfect diversion.

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

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

31October 1992

No shut-in

Foam

Pre

flush

Flow

rat

e, b

bl/m

in/2

0-ft

zone

0.75

0.5

0.25

0

1

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

1.25

Shu

t-in

A

cid

Foam

Thief zone

Damaged zone

Pre

flush

Flow

rat

e, b

bl/m

in/2

0-ft

zone

0.75

0.5

0.25

0

1

1.25

Shut-in

Aci

d

Thief zone

Damaged zone

AcidFoam

Oil zone

Water zone

Preflush

Flow

rat

e, b

bl/m

in/2

0 ft

zone

0.75

0.5

0.25

0

1

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

1.25

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

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

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

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

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

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

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

32 Oilfield Review

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

Acid Guidelines for Sandstones

1983Condition

HCl solubility (> 20%)

High permeability (>100 md)

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

High feldspar (> 20%)

High clay (> 10%)

High iron chlorite clay

Low permeability (< 10 md)

Low clay (< 5%)

High chlorite

1990Mineralogy

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

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

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

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

< 200°F

> 200°F

Permeability

> 100 md

12% HCl, 3% HF

7.5% HCl, 3% HF

10% HCl, 1.5% HF

12% HCl, 1.5% HF

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

4% HCl, 0.5% HF

6% HCl, 0.5% HF

8% HCl, 0.5% HF

4% HCl, 0.5% HF

6% HCl, 0.5% HF

8% HCl, 0.5% HF

6% HCl, 1% HF

8% HCl, 1% HF

10% HCl, 1% HF

20 to 100 md

10% HCl, 2% HF

6% HCl,1% HF

8% HCl,1% HF

10% HCl,1% HF

< 20 md

6% HCl, 1.5% HF

4% HCl, 0.5% HF

6% HCl, 0.5% HF

8% HCl, 0.5% HF

Main Acid

Use HCl only

12% HCl, 3% HF

13.5% HCl, 1.5% HF

6.5% HCl, 1% HF

3% HCl, 0.5% HF

6% HCl, 1.5% HF

3% HCl, 0.5% HF

Preflush

15% HCl

15% HCl

Sequestered 5% HCl

Sequestered 5% HCl

7.5% HCl or 10% acetic acid

5% acetic acid

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

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

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

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

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

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

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

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

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

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

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

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

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

Damage type

Fluid descriptionFluid sequence

VolumesNumber of diverter stagesInjection rates

Flow profile evolutionSkin evolutionRate/pressure plots

Production ratesPayout time

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

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

Damage removalmechanism

3% HF,12% HCl

Risk analysis

Product mapping

Well completion data

Formation damage mineralogyDiagnostics

Fluid selectionadvisor

Pumping scheduleadvisor

Simulator

Productionprediction

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

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

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

HCI 4%

RMA 13/31

Pumping Schedule for a Two-Stage Job

Stage 1

Stage 2

1

2

3

4

5

6

7

8

9

10

Preflush

Main fluid

Overflush

Overflush

Diverter slug

Preflush

Main fluid

Main fluid

Overflush

Tubing displ.

HCI 15%

HCI 4%

HCI 15%

RMA 13/31

HCI 4%

J237A2

RMA 13/31

NH4Cl brine 3%

17.3

68.2

20.7

17.3

55.6

33.0

33.0

3.1

12.6

53.7

2.2

2.2

4.8

4.8

1.1

1.2

2.4

4.8

4.8

1.1

7.9

13.8

0.6

2.6

48.8

31.0

4.3

3.6

50.5

27.5

Step Fluid Volumebbl

Flow ratebbl/min

Timemin

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

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

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

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

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

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

Harry McLeod,senior engineering pro-

fessional in the drilling

division, production

technology department,

Conoco Inc. Houston,

Texas, USA.

Commentary: Harry McLeod

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

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

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

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

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

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

Diverter deposition at perfoInjectionpoint

Fluids intermixing while progre

Well

Fa

PressDarcy

Acid a

M

Poro

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

34

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

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

pumped down the tubing, taking intoaccount differing hydrostatic and frictionlosses

• movement of fluids through the porousformation

• dissolution of damage and/or matrix byacid

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

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

rations

ssing

or each block nd each time step...

ure and flow rate using 's law

nd diverter transportation

ineral dissolution

Diverter deposition

sity/permeability change

Next time step

Gravity in welland layers

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

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

Oilfield Review

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

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

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

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

0 60 120 180 240 300

Volume, bbl

1

2

Two-stage

1

2

Tota

l ski

n

0

Volume, bbl

2

4

Flow

rat

e, b

bl/m

inS

kin

per

laye

r

2

6

10

0

10

20

30

20 40 60 80 100 120 1400

1

2

Layer 1

Layer 2

14

18

HC

l 4%

One-stage

HC

l 15%

RM

A 1

2/3

Div

erte

r sl

ug J

237A

HC

l 15%

HC

l 4%

RM

A 1

2/3

HC

l 4%

HC

l 15%

RM

A 1

2/3

Div

erte

r sl

ug J

237A

NH

4Cl b

rine

3%

HC

l 15%

RM

A 1

2/3

HC

l 15%

HC

l 4%

RM

A 1

2/3

HC

l 4%

Div

erte

r sl

ug J

237A

HC

l 15%

RM

A 1

2/3

Div

erte

r sl

ug J

237A

HC

l 4%

NH

4Cl b

rine

3%

HC

l 15%

RM

A 1

2/3

HC

l 15%

NH

4Cl b

rine

3%

HC

l 4%

RM

A 1

2/3

HC

l 4%

Div

erte

r sl

ug J

237A

HC

l 15%

RM

A 1

2/3

Div

erte

r sl

ug J

237A

HC

l 4%

Commentary: Giovanni Paccaloni

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

October 1992

Giovanni Paccaloni, head of production

optimization technologies

department at

AGIP headquarters in

Milan, Italy

• the relatively low operational cost compared tothe economic benefits

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

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

• the lack of exhaustive studies matching lab andfield results

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

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

35

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

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

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

Ski

n

Mud acid treatment Slug diversion

HC

l

Mud

aci

d

Ove

rflus

h

Auxiliary measurements

Fluid density Flow rate Treating pressure Annular pressure

Aci

d

Div

erte

r

Div

erte

r

Aci

d

Aci

d

Real-time skin value

Wellsite

Time

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

1. For general reading:

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

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

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

36

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

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

California, USA, March 20-22,1991.

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

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

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

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

(continued on page 39)

The key issue in matrix acidizing horizontal wells

is acid placement, since both damaged and thief

zones can be hundreds of feet long.1 The two

techniques used are bullheading and coiled-tub-

ing placement.

Acidizing horizontal wells by bullheading fol-

lows conventional practice, with alternating

stages of acid and diverter. Coiled tubing, on the

other hand, allows accurate placement of diverter

into thief zones before acid is pumped—thief zones

can be identified from production logs, Formation

MicroScanner images or mud logs. After the thief

zones have been treated by positioning the coiled

tubing opposite them and injecting diverter, the

coiled tubing is run to total depth and gradually

withdrawn as acid is pumped. Simultaneous with-

drawal and injection provides the most even cov-

erage. If inadequate data are available to identify

thief zones, acid and diverter stages can be alter-

nated as the coiled tubing is withdrawn.

Simulations illustrate the effectiveness of the

coiled-tubing technique over bullheading. The

horizontal well used for the simulations has a

1000-ft producing section drilled in sandstone

with severe bentonite drilling-mud damage along

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

Bullheading 25 gallons of half-strength mud

acid removes damage in the first 400 ft of the

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

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

thief zone initially accepts about one-half of the

treatment fluid, and with time the upper section

becomes a second thief zone. The section beyond

the thief zone takes only 20% of the treatment

fluid, resulting in poor damage removal.

Oilfield Review

n

i

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

October 1992

Time, hrs

0.4

1 2 3 4 5

Rat

e, b

bl/m

in

Thief zone

Lower section

Upper section

14

12

10

8

6

4

2

0

-2

Ski

n

Upper section

Lower section

Thief zone

0.6

0.8

1.0

1.2

Thief zone200 ft

Upper section400 ft

Lower section400 ft

Time, hrs

0.4

1 2 3 4 5

Rat

e, b

bl/m

in

14

12

10

8

6

4

2

0

-2

Ski

n

0.6

0.8

1.0

1.2

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

14

12

10

8

6

4

2

0

-21 2 3 4 5

Time, hrs

Ski

n

Upper section

Lower section

Horizontal Wells: Bullheading Versus Coiled Tubing

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

Bullheading acid and diverter in a series of

ine alternating stages provides a dramatic

mprovement (above). The flow rate into the thief

zone decreases dramatically once the first

diverter stage is pumped, and practically equal

flows then go into the lower and upper zones

resulting in uniform skin improvement.

By using coiled tubing to inject diverter into the

thief zone before pumping acid, virtually uniform

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

tion, both upper and lower damaged zones are

nearly restored to their natural permeability.

Such effective diversion occurs less readily in

carbonates acidized with HCl, where the rapid

reaction tends to counter the effectiveness of

most diversion techniques. However, field exam-

37

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

38 Oilfield Review

800

600

400

200

00 6000B/D

Flow RateAfter-Acid

0 6000B/DFlow RateBefore-Acid

Dep

th, f

t

Horizontal section, mProduction log

Pre-acid temperature log

1403

1404

1405

1406

True

ver

tical

dep

th, m

Tight zone

Fractured zone

100 150 200 250 300

Stimulation targets

Postacid temperature log

p =2000 psi

p =1200 psi

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

ples show the benefits of using coiled tubing,

rather than simple bullheading of the acid.

In a 1500-ft long horizontal injector in a Middle

East limestone reservoir, most of the 4000 B/D

injected was entering the first 450 ft of the hori-

zontal trajectory and none was entering beyond

900 ft—see the production log made before acid

treatment (right). A treatment was then performed

by running coiled tubing to the end of the well and

pumping 15% HCl at the rate of 10 gallons per

foot as the tubing was withdrawn. When the

coiled tubing had been withdrawn to the begin-

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

additional HCl were bullheaded into the formation.

Injection was subsequently 5500 B/D. The post-

treatment production log shows most of the

increase is entering the first 450 ft of well. But

there is some increase between 800 and 900 ft,

probably the result of using coiled tubing. There

is still no injection beyond 900 ft. Incidentally, no

diverters were used in the treatment. Experience

in nearby limestone reservoirs using conven-

tional benzoic flake and rock salt diverting agents

did not improve coverage significantly.

A second example comes from a horizontal

well drilled in fractured dolomite in Shell Canada

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

tially, this pumping well produced 240 BLPD with

water cut rising to near 99%.

Logs made with coiled tubing suggested that

the well probably intersected the desired frac-

tured dolomite at three separate points—at the

heel, midpoint and toe of the horizontal trajec-

tory. Otherwise, it strayed into an overlying tight

zone. Production logs, obtained using nitrogen lift

with the coiled tubing, showed that the heel zone

at low pressure (1200 psi) was not producing,

while the toe zone at high pressure (2000 psi)

was producing water—probably from the field’s

waterdrive scheme. An acid treatment was there-

fore planned to improve oil production from the

heel and minimize treatment of the water zone.

Initially, the entire horizontal section was cir-

culated with foamed gel, resulting in a 90%

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

foot of 15% HCl was injected across two zones

near the end of the well while withdrawing the

coiled tubing. More diverting foam was then

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

then injected over a long zone at the heel of the

well, again while withdrawing coiled tubing, fol-

lowed by more diverter and then a repeat injec-

tion of acid across the same zone.

The effect of this treatment can be seen by

comparing pre- and posttreatment temperature

profiles (below). These were obtained by pumping

water into the well for a period and then record-

ing temperature along the horizontal trajectory. A

temperature decrease with depth indicates

acceptance of the cool, injected water; no

decrease indicates that no water was accepted

and that the zone is unlikely to produce. In this

example, considerable improvement can be seen

in both the heel and targeted stimulation areas.

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

tion increased to 300 BLPD, the pumping limit,

and oil production increased from 3 to 48 BOPD.

39October 1992

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

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

Sur

face

inje

ctio

n ra

te, B

/D

2000

1600

1200

800

400

0

0 0.4 0.8 1.2 1.6 2Time, hr

Bot

tom

hole

pre

ssur

e, p

si

2125

2000

1875

1750

1625

1500

Simulated Measured

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

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

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

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

HSE Developments for Acidizing

Health, safety and environment issues are being

seriously addressed in every corner of explo-

ration and production technology. Laws are tight-

ening and the industry’s obligation to public

health and environmental protection cannot relax.

Matrix acidizing is no exception.

The technique obviously cannot dispense with

dangerous and toxic acids such as HCl and HF,

but other fluid additives may be rendered much

safer to both the public and the environment. Cur-

rent examples are inhibitors used to prevent cor-

rosion of tubulars as acid is pumped downhole,

and solvents used to clean residual oil deposits

and pipe dope from the tubulars.

When acidizing began, it was discovered that

arsenic salts could inhibit corrosion. But arsenic

is highly toxic and its use was discontinued more

than 20 years ago. Less toxic but still harmful

inhibitors were substituted. Recently, Dowell

Schlumberger introduced the first environmen-

tally friendly inhibitor system, CORBAN 250ECO,

that functions up to 250°F [120°C].

CORBAN 250ECO is one of several so-called

ECO pumping additives that have reduced toxicity

and increased biodegradability. For example, the

key inhibiting chemical in CORBAN 250ECO is

cinnamaldehyde, a common cinnamon flavoring

additive for gum and candy.

Another ECO product made from natural

sources is the recently introduced PARAN ECO

additive for cleaning oil deposits and pipe dope

solvent from tubulars. This is intended to replace

aromatic and organic halide solvents that are

toxic and that also can damage refinery catalysts

if produced with the oil.

40 Oilfield Review

Carl Montgomery,technical coordinator

of well stimulation for

ARCO Oil and Gas

Company in Plano,

Texas, USA.

Commentary: Carl Montgomery

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

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

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

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

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

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

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

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

Sand Control: Why and How?

Jon CarlsonChevron Services Co.Houston, Texas, USA

Derrel GurleyHouston, Texas, USA

George KingAmoco Production Co.Tulsa, Oklahoma, USA

Colin Price-SmithTulsa, Oklahoma, USA

Frank WatersBP Exploration Inc.Houston, Texas, USA


Sand production erodes hardware,

blocks tubulars, creates downhole

cavities, and must be separated

and disposed of on surface. Com-

pletion methods that allow sand-

prone reservoirs to be exploited

often severely reduce production

efficiency. The challenge is to

complete wells to keep formation

sand in place without unduly

restricting productivity.

October 1992

nPerils of sand production. At worst, sandproduction threatens a well. Voids can formbehind the pipe, causing formation subsi-dence and casing collapse. The well mayalso fill with sand and cease flowing. Orthe surface equipment may be catastroph-ically damaged by erosion or plugging.

For help in preparation of this article, thanks to: BobElder, Chevron UK Ltd., London, England; David Wag-ner, Chevron Exploration and Production Services Co.,Houston, Texas, USA; Mike Mayer, Dowell Schlumber-ger, Montrouge, France; Roger Card, Loren Hauglandand Ian Walton, Dowell Schlumberger, Tulsa, Okla-homa, USA.In this article, NODAL (production system analysis) andIMPACT (Integrated Mechanical Properties Analysis &Characterization of Near Wellbore Heterogeneity) aremarks of Schlumberger; PacCADE, ISOPAC andPERMPAC are trademarks or service marks of DowellSchlumberger.

1. Veeken CAM, Davies DR, Kenter CJ and KooijmanAP: “Sand Production Prediction Review: Developingan Integrated Approach,” paper SPE 22792, presentedat the 66th SPE Annual Technical Conference andExhibition, Dallas, Texas, USA, October 6-9, 1991.

2. Anderson R, Coates G, Denoo S, Edwards D andRisnes R: “Formation Collapse in a Producing Well,”The Technical Review 34, no. 3 (October 1986): 29-32.

Unconsolidated sandstone reservoirs withpermeability of 0.5 to 8 darcies are mostsusceptible to sand production, which maystart during first flow or later when reservoirpressure has fallen or water breaks through.Sand production strikes with varyingdegrees of severity, not all of which requireaction. The rate of sand production maydecline with time at constant productionconditions and is frequently associated withcleanup after stimulation.

Sometimes, even continuous sand pro-duction is tolerated. But this option maylead to a well becoming seriously damaged,production being killed or surface equip-ment being disabled (left). What constitutesan acceptable level of sand productiondepends on operational constraints likeresistance to erosion, separator capacity,ease of sand disposal and the capability ofartificial lift equipment to remove sand-laden fluid from the well.1

This article reviews the causes of sanding,and how it can be predicted and controlled.It will examine the four main methods ofsand control: one that introduces an artifi-cial cement into the formation and threethat use downhole filters in the wellbore.The article then focuses on gravel packing,by far the most popular method of complet-ing sand-prone formations.

Causes of SandingFactors controlling the onset of mechanicalrock failure include inherent rock strength,naturally existing earth stresses and addi-tional stress caused by drilling or produc-tion.2 In totally unconsolidated formations,sand production may be triggered duringthe first flow of formation fluid due to dragfrom the fluid or gas turbulence. Thisdetaches sand grains and carries them into

41

Casing

Cement

Bef

ore

clea

nup

Afte

r cl

eanu

p

Perforation tunnelCompacted zone

Debris Compacted zone

nDebris and damage in the perforationtunnel. Before cleanup, a perforationtunnel may be filled with pulverizedsand and shaped-charge debris. First

Perforation tunnel

Formation sand

Fluid inflow

Cement

Fluid inflow

Fluid inflow

nDoorway to the wellbore. A stable arch isbelieved to form around the entrance to aperforation cavity. This arch remains sta-ble as long as flow rate and drawdown areconstant. If these are altered, the arch col-lapses and a new one forms once flow sta-bilizes again.

the perforations. The effect grows with higherfluid viscosity and flow rate, and with highpressure differentials during drawdown.3

In better cemented rocks, sanding may besparked by incidents in the well’s produc-tive life, for example, fluctuations in produc-tion rate, onset of water production,changes in gas/liquid ratio, reduced reser-voir pressure or subsidence.4

Fluctuations in the production rate affectperforation cavity stability and in somecases hamper the creation and maintenanceof sand arches. An arch is a hemisphericalcap of interlocking sand grains—like thestones in an arched doorway—that is stableat constant drawdown and flow rate, pre-venting sand movement (above). Changesin flow rate or production shut-in may resultin collapse of the arch, causing sand to beproduced until a new arch forms.5

Other causes of sanding include waterinflux, which commonly causes sand pro-duction by reducing capillary pressurebetween sand grains. After water break-through, sand particles are dislodged byflow friction. Additionally, perforating mayreduce permeability around the surface of aperforation cavity and weaken the formation(right). Weakened zones may then becomesusceptible to failure at sudden changes inflow rate.

42

Predicting Sanding PotentialThe completion engineer needs to know theconditions under which a well will producesand. This is not always a straightforwardtask. At its simplest, sand predictioninvolves observing the performance ofnearby offset wells.

In exploratory wells, a sand flow test isoften used to assess the formation stability.A sand flow test involves sand productionbeing detected and measured on surfaceduring a drillstem test (DST).6 Quantitativeinformation may be acquired by graduallyincreasing flow rate until sand is produced,the anticipated flow capacity of the comple-tion is reached or the maximum drawdownis achieved. A correlation may then beestablished between sand production, welldata, and field and operational parameters.

Accurately predicting sand productionpotential requires detailed knowledge of theformation’s mechanical strength, the in-situearth stresses and the way the rock will fail.Laboratory measurements on recoveredcores may be used to gather rock strengthdata. Field techniques like microfracturingallow measurement of some far-field earthstresses (see “Cracking Rock: Progress inFracture Treatment Design,” page 4). Thisinformation may then be used to predict thedrawdown pressure that will induce sanding.7

Although these techniques provide directmeasurement of critical input data, they arerelatively expensive to acquire and are onlyavailable for discrete depths—in some of the

flow may remove this debris, but acompacted zone can remain aroundthe surface of the cavity that is weak-ened and likely to suffer tensile failure.

zones of some of the wells. Downhole wire-line log measurements provide continuousprofiles of data. However, no logging toolyields a direct measurement of rock strengthor in-situ stress. This has given rise to inter-pretation techniques that combine directmeasurements with sonic and density logs toderive the elastic properties of rock and pre-dict from these the sanding potential.8

A example is IMPACT Integrated Mechan-ical Properties Analysis & Characterizationof Near Wellbore Heterogeneity, recentlydeveloped by Schlumberger Well Services,Houston, Texas, USA. The IMPACT analysispredicts formation sanding potential usingvalues for formation strength obtained bycorrelating logs and cores, in-situ stressparameters derived from geologic modelsthat employ log and microfracture data andone of two rock failure models.

Despite the fact that cores may be signifi-cantly altered during the journey from well-bore to laboratory, rock strength measure-ments gathered from core tests are crucial tothe IMPACT analysis computation of rockstrength. In a uniaxial compressive test, acircular cylinder of rock is compressed par-allel to its longitudinal axis, and axial andradial displacements are measured. Thedynamic elastic properties—in particularYoung’s Modulus and Poisson’s ratio—anduniaxial compressive strength may then becomputed. Triaxial tests make the samemeasurements at different confining pres-sures and give a more complete picture ofthe rock’s failure envelope as a function ofconfining stress.

Because there is no unifying theory thatrelates log measurements to rock strength,using the laboratory core data, empiricalcorrelations are derived to obtain thedesired rock strength parameters from log-derived elastic properties. The IMPACT soft-ware has several empirical correlations tochoose from.

The earth’s in-situ stresses are due tomany factors including the weight of theoverburden, tectonic forces and pore pres-sure. While the vertical stresses may be esti-mated using bulk density logs, horizontalstresses are more problematic. In IMPACTprocessing, accurate estimates of horizontalstresses are integrated with logs and, using ageologic model, a continuous profile ofearth stresses is created. Various geologicmodels have been developed to cope withthe different environments encountered.Reservoir pore pressure information is alsoneeded and this may be estimated usingwireline formation testing tools or DSTs.

Oilfield Review

3. Morita N and Boyd PA: “Typical Sand ProductionProblems: Case Studies and Strategies for Sand Con-trol,” paper SPE 22739, presented at the 66th SPEAnnual Technical Conference and Exhibition, Dallas,Texas, USA, October 6-9, 1991.

4. Winchester PH: “The Cardinal Rules of Gravel Pack-ing to Avoid Formation Damage,” paper SPE 19476,presented at the SPE Asia-Pacific Conference, Sydney,Australia, September 13-15, 1989.

5. Bratli R K and Risnes R: “Stability and Failure of SandArches,” paper SPE 8427, presented at the 54th SPEAnnual Technical Conference and Exhibition, LasVegas, Nevada, USA, September 23-26, 1979.Tippie DB and Kohlhaas CA: “Variation of Skin Dam-age with Flow Rate Associated With Sand Flow or Sta-bility in Unconsolidated-Sand Reservoirs,” paper SPE4886, presented at the 44th SPE Annual CaliforniaRegional Meeting, San Francisco, California, USA,April 4-5, 1974.Morita N, Whitfill DL, Massie I and Knudsen TW:“Realistic Sand-Production Prediction: NumericalApproach,” SPE Production Engineering 4, no. 1(February 1989): 15-24.

6. Deruyck B, Ehlig-Economides C and Joseph J: “TestingDesign and Analysis,” Oilfield Review 4, no. 2 (April1992): 28-45.

7. Morita and Boyd, reference 3.8. Santarelli FJ, Ouadfel H and Zundel JP: “Optimizing

the Completion Procedure to Minimize Sand Produc-tion Risk,” paper SPE 22797, presented at the 66thSPE Annual Technical Conference and Exhibition,Dallas, Texas, USA, October 6-9, 1991.Tixier MP, Loveless GW and Anderson RA: “Estima-tion of Formation Strength From the Mechanical Prop-erties Log,” Journal of Petroleum Technology 27(March 1975): 283-293.Stein N: “Determine Properties of Friable FormationSands,” World Oil 206, no. 3 (March 1988): 33-37.

9. Massie I, Nygaard O and Morita N: “Gullfaks SubseaWells: An Operator’s Implementation of a New SandProduction Prediction Model,” paper SPE 16893,presented at the 62nd SPE Annual Technical Confer-ence and Exhibition, Dallas, Texas, USA, September27-30, 1987.Unneland T and Waage RI: “Experience and Evalua-tion of Production Through High-Rate Gravel-Packed Oil Wells, Gullfaks Field, North Sea,” paperSPE 22795, presented at the 66th SPE Annual Tech-nical Conference and Exhibition, Dallas, Texas,USA, October 6-9, 1991.

10. Pelgrom J and Wilson RA: “Completion Develop-ments in Unconsolidated Oil-Rim Reservoirs,” paperOSEA 90123, presented at the Eighth Offshore SouthEast Asia Conference, Singapore, December 4-7,1990.

11. Davies, DR: “Applications of Polymers in Sand Con-trol,” paper presented at Use of Polymers in Drillingand Oilfield Fluids, organized by the Offshore Engi-neering Group of the Plastics and Rubber Institute,London, England, December 9, 1991.

Finally, rocks either fail in tension whenthey are pulled apart or they fail in shearwhen they are crushed. IMPACT analysisenables the interpreter to pick the mostlikely failure mechanism. From this, theprogram predicts sanding potential.

Completion OptionsOnce it has been established that at plannedproduction rates sand is likely to be pro-duced, the next step is to choose a comple-tion strategy to limit sanding. A first optionis to treat the well with “tender loving care,”minimizing shocks to the reservoir bychanging drawdown and production rateslowly and in small increments. Productionrate may be reduced to ensure that draw-down is below the the point at which theformation grains become detached. Moresubtly, selective perforation may avoidzones where sanding is most likely. How-ever, both options reduce production, whichmay adversely affect field economics.9

The most popular options for completingsand-prone reservoirs physically restrainsand movement. The four main classes ofcompletion are resin injection, slotted linersand prepacked screens, resin-coated gravelwithout screens and gravel packing.

Resin Injection: To cement the sand grainsin situ, a resin is injected into the formation,generally through perforations, and thenflushed with a catalyst. Most commerciallyavailable systems employ phenolic, furan orepoxy resins. They bind rock particlestogether creating a stable matrix of perme-able, consolidated grains around the casing.

Clay concentration can hinder the effec-tiveness of the consolidation process, so aclay stabilizer is often used as a preflush.Residual water may also interfere with thedevelopment of consolidation strength andmay necessitate use of increased quantitiesof resin.10 The quantity of resin injected is acompromise between enhancing consolida-tion strength and reducing permeability. Forexample, if an 8-darcy unconsolidated sandis resin treated to give a compressivestrength of up to 3300 psi, permeability maybe reduced by 25% and productivity cut byup to 10%.11

Further, sand production will not be pre-vented if chemical injection is uneven andsome exposed sand is uncoated. Because ofthis, the technique tends to be reserved forshort intervals, up to 10 to 15 ft [3 to 4 m].Complete coverage of larger zones is diffi-cult unless selective placement tools areused. Although resin consolidation is usedsuccessfully, it accounts for no more thanabout 10% of sand-control completions.

October 1992

Slotted Liners and Prepacked Screens: Slot-ted pipes, screens and prepacked screensoffer the lowest-cost downhole filtering.Slotted liners have the largest holes, wire-wrapped screens have smaller openings,while screens prepacked with resin-coatedsand offer the finest filtering. Each type canbe run as part of the completion string andare particularly suited for high-angle wells,which cannot be easily completed other-wise (see “Screening Horizontal Wells,”page 45).

Slots are typically sized to cause bridgingof the largest 10% of the formation particles,filling the annulus between the screen andcasing, or open hole, with formation sandcreating a filter for remaining particles.However, production can be restricted bythis relatively low-permeability, sand-packed annulus. Also, production of even asmall amount of fines can plug manyscreens, particularly prepacked screens,within a few hours of installation.

Slotted liners and screens are best suitedto formations that are friable rather thancompletely unconsolidated. They are mostlyused in California, USA, and some Gulf ofMexico, USA fields where permeabilitiesare greater than 1 darcy. Slotted liners andprepacked screens are used in only about5% of sand-control completions.

Resin-Coated Gravel Without Screens:Resin-coated gravel may be used as adownhole filter without installing a screen.The gravel is circulated into position as aslurry, either inside casing or open hole andthen squeezed to form a plug across theproduction zone. Adjacent particles arebonded together by the resin, strengtheningthe pack.

In cased hole, the plug may be com-pletely drilled out to leave gravel-filled per-forations. Alternatively, the pack may bedrilled out to the top of the perforations/open hole so that hydrocarbons are pro-duced through the pack. A narrow hole canbe drilled through the pack to provide aconduit to reduce drawdown through thepack. This can be achieved using coiledtubing if a conventional rig is not available.

Resin-coated gravel has the advantage ofneeding no special hardware. But the packcreates significant additional drawdown thatmay affect productivity. If the drillout tech-nique is employed to reduce drawdown, allperforations must be evenly packed and theresulting pack may be fragile. Completecoverage of intervals longer than about 20 ft[6 m] is difficult to achieve. The techniquerepresents about 5% of sand-control treat-ments, mainly concentrated on low-costonshore markets.

43

Oil

prod

uctio

n ra

te

Water breakthrough

Water breakthrough

Gravel packNatural completion

Time, yr0 5 10 15

nAssessing the viability of a gravel pack.The oil production rate for natural comple-tion—unstimulated and not gravel packed—is compared with that for a gravel pack inan intermediate-strength rock that is sensi-tive to water breakthrough.

Effe

ctiv

e/in

itial

pa

ck-p

erm

eabi

lity

ratio

0 4 8 12 160

.2

.4

.6

.8

1.0

Gravel Packing: Gravel packing has beenused by the oil industry since the 1930s.Today, it is the most widely employed sandcontrol measure, accounting for aboutthree-quarters of treatments.12 A slurry ofaccurately sized gravel in a carrier fluid ispumped into the annular space between acentralized screen and either perforatedcasing or open hole. The gravel also entersperforations if a cased-hole gravel pack isbeing performed. As pumping continues,carrier fluid leaks off into the formation orthrough the screen and back to surface. Thegravel pack creates a granular filter withvery high permeability—about 120 dar-cies—but prevents formation sand enteringthe well (below).

Gravel packs are not without their draw-backs. During installation, carrier fluid isinjected into the formation which may dam-age the reservoir permeability and restrictproduction. The pack then tends to trap thedamage in the perforations, preventingclean up. Once in place, the pack in perfo-ration tunnels increases drawdown whichmay seriously affect productivity.13 Gravelpacks reduce the operating wellbore diame-ter, usually necessitating artificial lift equip-ment to be set above the zone. Completingmultiple zones with gravel packs is difficult,and almost all well repairs involve theremoval of the screen and pack.

44

Gravel/grain-size ratio

C

S

G

C

P

F

Scr

een

nAnatomy of a cased-hole gravel pack.

The technique is also a relatively expen-sive method of completion. A sophisticatedway of establishing the viability of a gravelpack is to construct well performancecurves for a range of completion methodsusing a reservoir simulator and predictionsof sand movement and how this affectsdrawdown (above).

Although gravel packing has these draw-backs, it is the most effective method ofstopping sand movement and permittingproduction, albeit at a reduced rate.Because of this, gravel packing is the pre-dominant method in use today and warrantsa detailed examination.

asing

creen

ravel pack

ement

erforation

ormation sand

Per

fora

ted

casi

ng

Cem

ent

Form

atio

n sa

nd

Gra

vel-p

acke

d pe

rfora

tions

Gra

vel-p

acke

d an

nulu

s

Designing Gravel PacksFor a gravel pack to maintain long-termproductivity, the gravel must be clean,tightly packed and placed with the mini-mum damage to the formation. Theserequirements depend on the correct selec-tion of gravel, carrier fluid and placementtechnique. They also rely on scrupulouscleanliness during placement operations toprevent the contamination of the gravelpack by small particles that significantlyreduce pack permeability.

Minimizing the pressure drop in the per-foration tunnels is vital to successful gravelpacking and this requires gravel that is aslarge as possible. But since the pack mustact as an effective filter, the gravel also hasto be small enough to restrain formationparticles. This depends on the size of theformation sand, which is usually measuredusing sieve analysis.

nChoosing gravel size range. The ratio ofthe effective pack permeability and theinitial pack permeability represents theeffect of the formation sand particles asthey partially plug the gravel pack. Whenthe gravel size/grain-size ratio reachesabout six, the particles can enter the packand seriously diminish pack permeability.

Formation samples from cores are passedthrough successively smaller sieves to sepa-rate particles into a number of size groupsthat are then weighed and plotted. If the sam-ples are aggregated, they need to be brokenup before the analysis—clay and silt particlesbinding the rock together may be removedby washing with chemicals. The resultingsand grains may then be dried and sieved.

There are various methods for translatingthe formation sand size distribution into adesign size for the gravel. One of the mostwidely used methods is based on work car-ried out by R.J. Saucier that recommendsthe median gravel size should be up to sixtimes the median formation grain size butno more (above).14

(continued on page 47)

12. Winchester, reference 4.13. Welling R and Nyland T: “Detailed Testing of Grav-

elpacked Completions” paper OSEA 90121, pre-sented at the Eighth Offshore South East Asia Confer-ence, Singapore, December 4-7, 1990.

14. Saucier RJ: “Considerations in Gravel Pack Design,”Journal of Petroleum Technology 26, (February1974): 205-212.

nHorizontal well com-pletion design for theAlba field.

1. Forrest JK: “Horizontal Gravel Packing Studies in a Full-Scale Model Wellbore,” paper SPE 20681, presented atthe 65th SPE Annual Technical Conference and Exhibition,New Orleans, Louisiana, USA, September 23-26, 1990.

Sparlin DD and Hagen WH Jr: “Gravel Packing Horizontaland High-Angle Wells,” World Oil 213, no. 3 (March1992): 45-49.

2. Wilson DJ and Barrilleaux MF: “Completion Design andOperational Considerations for Multizone Gravel Packs inDeep, High-Angle Wells,” paper OTC 6751, presented atthe 23rd Annual Offshore Technology Conference, Hous-ton, Texas, USA, May 6-9, 1991.

Zaleski TE Jr: “Sand-Control Alternatives for HorizontalWells,” Journal of Petroleum Technology 43 (May 1991):509-511.

430-ft water depth

30-in. casing, 800 ft MD/TVD

20-in. casing, 1200 ft MD/TVD

103/4-in. casing, 1500 ft MD/TVD

133/8-in. casing set between: 2500 ft -4000 ft MD2500 ft -3500 ft TVD

95/8-in. casing set ± 200 ft into horizontal:

7000 ft–9500 ft MD6200 ft–6400 ft TVD

81/2-in. open holewith prepacked screen

1000 ft–2600 ft

Eocene

45October 1992

Screening Horizontal Wells

Studies generally conclude that the most effec-

tive technique for excluding sand in high-angle

and horizontal wells is gravel packing.1 Although

there have been some notable operational suc-

cesses, the technical complexities of high-angle

gravel packing and its relatively high cost mean

that alternative techniques are often considered.2

A case in point in the UK North Sea is the Alba

field which is operated by Chevron UK Ltd. The

350-ft [107-m] thick Eocene sand reservoir is

completely unconsolidated and currently under

development. Most of the field’s production wells

will have horizontal sections of up to 2600 ft.

When the field comes onstream, each well will

produce up to 30,000 B/D using electric sub-

mersible pumps.

Water breakthrough is expected after only two

months of production and 40% water cut is

expected by the end of the first year. Early water

production will exacerbate sand production by

reducing the interstitial tension between sand

grains, making sand control a major factor of the

development plan.

Initial plans called for horizontal cased-hole

gravel packs. However, the company continued to

study alternative solutions and concluded that

prepacked screens could successfully keep sand

at bay (right). Prepacked screens cost signifi-

cantly less than gravel packs and are simpler to

install. What convinced Chevron was not the cost

but the increased internal diameter (ID) afforded

by the prepacked screens—4.4 in. [11 cm] as

opposed to the 2.9 in. [7.4 cm] of the planned

gravel packs.

Larger ID reduces the pressure drop along the

horizontal length of the well, leading to a better

inflow distribution—when the pressure drop is

high, production from the near end of the well-

bore is favored. In the field’s conventionally devi-

ated wells, where pressure differential will not

significantly affect inflow performance, Chevron

will employ conventional gravel packs.

The prepacked screens will comprise 5-in. pipe

wrapped with two layers of screen with an out-

side diameter of 6 5/8-in. [16.8-cm]. Between the

screen will be a 1/2-in. [1.3 -cm] thick pack of

resin-coated gravel. The screens will be inserted

into open hole, 8 1/2-in. [22-cm] diameter, so

there is a likelihood of sand sloughing around the

screens. Chevron tested the effects of sloughing

on permeability around the wellbore. At worst, it

reduced permeability from 3 darcies to 1, not

enough to significantly limit production.

On the downside, the longevity of the screens

is uncertain and there is a lack of zonal isolation

afforded by an openhole completion. In an effort

to combat this, blank sections with internal seals

will be deployed every 400 ft [120 m] of screen,

allowing fluids to be spotted, and plugs and

straddle packers to be set using coiled tubing.

nThe four positions for gravel packing. Insqueeze position, the service tool seals intothe packer and does not allow circulation.When slurry is pumped in this mode, allthe carrier fluid leaks off into the formation.

In upper circulating position, slurry ispumped down the casing-screen annulusand the carrier fluid can be squeezedthrough any part of the screen, into thewashpipe at the bottom of the service tooland back to surface via the service tool-casing annulus above the packer.

In lower circulating position, slurry isalso pumped down the casing-screenannulus, but returns of carrier fluid have topass through the bottom of the pack wherethe washpipe is sealed into the lower tell-tale—a sealbore with a short piece ofscreen below—located below the mainscreen. The aim is try to maintain flow inthe casing-screen annulus and ensure thatthere is not a void in the gravel in theannulus below the screen.

However, if the interval being packed islonger than 25 ft [8 m], backpressure onthe fluid may cause the fluid to bypass thepack and pass down the well via thescreen/washpipe annulus, which mayencourage bridging off higher up the well.

Reverse circulation involves pumpingfluid through the washpipe, up the screen/washpipe annulus and back up to surface.

46 Oilfield Review

Service tool

Permanent-retrievable packer

Ported housing

Sealbore housing

Locating collars

Blank pipe

Primary screen

‘O’ ring seal sub

Lower telltale

Sump packer

Seal unit

1. Squeeze position 3. Lower circulating position2. Upper circulating position 4. Reversing position

47October 1992

15. According to American Petroleum Institute recom-mended practices (RP 58), the designation 40/60indicates that not more than 2% of the gravel shouldbe smaller than the 40-mesh sieve and not morethan 0.1% should be larger than the 20-mesh sieve.

16. Hainey BW and Troncoso JC: “Frac-Pack: An Inno-vative Stimulation and Sand Control Technique,”paper SPE 23777, presented at the SPE InternationalSymposium on Formation Damage Control,Lafayette, Louisiana, USA, February 26-27, 1992.

17. Gurley DG and Hudson TE: “Factors AffectingGravel Placement in Long Deviated Intervals,” paperSPE 19400, presented at the SPE Formation DamageControl Symposium, Lafayette, Louisiana, USA,February 22-23, 1990.

Recently, work by B.W. Hainey and J.C.Troncoso of ARCO points to the possibilityof using larger gravel, offering higher packpermeability.15 To explain this, Hainey andTroncoso argue that in some cases formationsand grains move as larger agglomeratesrather than as individual grains.16

Average grain size is not the only determi-nant of gravel-pack permeability. The bestgravel-pack sands are round and evenlysized. The most common way of estimatingroundness and sphericity is by examiningthe gravel through a 10- to 20-power micro-scope and comparing the shapes with a ref-erence chart. Gravel-size distribution can bemonitored by sieve analysis.

The next decision facing the engineer iswhether the completion should be cased oropenhole. Openhole gravel packs have noperforations and therefore offer the mini-mum pressure drop across the pack. Butplacement may be time-consuming. Caremust be taken to remove the filter cakedeposited on the formation by drilling fluidand to avoid abrading the formation andcontaminating the gravel. Cased-hole gravelpacks present the additional challenge ofproperly packing the perforations.

To check that a well is suitable for cased-hole gravel packing, productivity may becalculated using NODAL production systemanalysis. This models the pressure drop asreservoir fluid flows through the perforationsinto the completion hardware to surface.

Pressure drop in perforation tunnels is amajor impediment to production and varieswith tunnel length, perforation area, packpermeability, viscosity of the produced flu-ids and reservoir pressure (see “Choosing aPerforation Strategy,” page 54). The gravelsize range determines pack permeability—the smaller the grains, the more the packrestricts formation flow—and is fixed by thesize of the formation sand. Formation fluidviscosity and reservoir pressure are alsofixed. To reduce pressure drop, inflow areamay be raised by increasing perforationdiameter and/or increasing the number ofperforations. If the well is perforated withtubing-conveyed perforating (TCP), highshot density guns, gravel packs can nearlymatch the inflow performance of openholepacks for many reservoirs. Pressure dropmay also be reduced by increasing thediameter of casing in which the gravel packis to be placed. If sufficient inflow area can-not be achieved through perforation, open-hole completion is required.

Once the method of completion isselected, the hardware may be chosen. Atits simplest, a packer and screen assemblywith a washpipe inside are usually run inhole with a service tool. However, whenmultiple zones are to be completed instages, the hardware becomes a complexseries of screens and packers.

The service tool is then used to set thepacker above the zone to be completed.Thereafter, the positions of the service toolin the packer and washpipe in the screenassembly determine the flow direction offluids pumped downhole. Sophisticated sys-tems have four positions: squeeze, uppercirculating, lower circulating and reversecirculating and therefore allow single-triptreatments (previous page).

In a single-trip gravel-pack treatment, theperforation guns are fired and lowered intothe rathole. The perforations may be filledwith gravel with the packer in the squeezeposition and the annulus is filled with it ineither the upper or lower circulating posi-tions. Excess gravel is then reversed out.

However, the hardware used in manygravel-pack operations does not permit sin-gle-trip operations. For a cased-hole gravelpack, the TCP guns must be retrieved andthen the workstring must removed aftergravel packing so that the completion stringmay be run. During these trips, the servicetool and the washpipe are withdrawn fromthe packer, exposing the relatively high-per-meability formation to the hydrostatic pres-sure of the completion fluid above thepacker. This usually causes fluid to be lostinto the formation.

To reduce losses, particulate loss controlmaterial (LCM) suspended in a viscous fluidis commonly pumped downhole beforeeach trip. The LCM plugs the completionfluid’s flow path into the formation. After thetrip, the LCM is removed. Common LCMsinclude marble chips (calcium carbonate,removable with acid), oil-soluble resins orsalt pills (see “Gravel Packing Forth FieldExploration Wells,” next page).

Each time LCM is used, there is a dangerof incomplete removal damaging the reser-voir. To avoid the need to pump LCM whenthe washpipe and workstring are removedfrom the packer, a flapper valve can beemployed below the packer. This valve iscapable of accommodating a large-diameterwashpipe to direct flow to the casing-screenannulus. It closes after the service tool andwashpipe are removed, preventing comple-tion fluid from passing through the pack andinto the permeable formation. When thecompletion string is run, the flapper valve isopened—either mechanically, with wirelineor using pressure.

Wire-wrapped screens are usually used toretain the gravel. Selection of wire spacingis not subject to any hard and fast rules, buta common rule of thumb calls for the slotsto be 75% of the smallest gravel diameter.Screen diameter depends on the inlet area,the pack thickness and the ability to fish thescreen out of the hole. This normally leadsto using screens with at least 1-in. [2.5 cm]annular clearance. Screens are normallyrun 5 ft [1.5 m] above and below the pro-ducing zone and centralized every 15 ft [5m] to improve the chances of a consistentgravel fill.

Transporting gravel into the perforationsand annulus is the next consideration.Gravel can sometimes bridge off prema-turely, leaving voids in the annulus. In verti-cal wells, incomplete fill may be rectifiedwhen pumping stops and gravel in theannulus collapses into the voids. This ceasesto be the case in wells deviated more than50°, where voids below a bridge are likelyto remain. Transport is a function of the sus-pension properties of the fluid and theenergy required to move the slurry. Impor-tant factors determining settling are pumprate, the relative densities of the gravel andthe carrier fluid, gravel diameter and theapparent viscosity of the fluid whenpumped downhole.17

There is also a relationship betweengravel concentration and carrier fluid vis-cosity when it comes to “turning the corner”in the annulus and entering perforations.Fluid viscosity must increase if gravel con-centration in the slurry increases, otherwisethe gravel will tend to sink to the bottom ofthe well. Packing efficiency is also affectedby the rate the carrier fluid leaks off into theformation. If leakoff is rapid, the gravel islikely to be carried to the perforation tunnel-formation interface and held there as thefluid leaks off. If leakoff is slow, the gravelhas more time to settle and will not effec-tively pack the perforations.

1. Gilchrist JM and Gilchrist AL: “A Review of Gravel Pack-ing in the Forth Field,” paper SPE 23128, presented at theOffshore Europe Conference, Aberdeen, Scotland,September 3-6, 1991.

48 Oilfield Review

Gravel slurry

Prepack gravel

Formation

Cement

Casing

Gun fish Settled excess gravel

Loss control material

Loss control material pill

nPrepacking the perfo-rations. Prepacking theperforations preventsloss control material fromentering the perforationtunnels; this improvessubsequent cleanup andreduces damage. Tub-ing-conveyed perforatingguns were dropped,gravel was bullheadedinto the perforations andloss control materialspotted across the tun-nel entrances.

Gravel Packing Forth Field Exploration Wells

There is no such thing as a typical gravelpack;

each is a complex combination of relatively sim-

ple operations. This example is based on a

gravel-packing procedure used on several verti-

cal appraisal wells in the Forth field in the UK

North Sea operated by BP Exploration. Forth, dis-

covered in 1986, has an Eocene reservoir com-

prising massive, clean sand located at a depth of

about 5500 ft [1675 m]. Permeability is 6 to 12

millidarcies and porosity is 35%.1

Cleanliness is fundamental to gravel packing

efficiency. Any contaminants that may plug the

gravel pack and decrease productivity must be

removed. In preparation for the gravel packing,

the mud pits were cleaned and the mud changed

to brine completion fluid. Tubulars were exter-

nally shot blasted, internally jetted and steam

cleaned before being run in hole. Because the

dope used to lubricate pipe joints is a serious

contaminant, it was applied sparingly to the pin

end only.

Cement for the production casing was dis-

placed with seawater. The cement scours the cas-

ing, but to further clean the wellbore, scrapers

were run and seawater circulated at high pump

rates. Cleanup pills of detergent, scouring pills

with gel spacers and flocculants were also circu-

lated. The well was then displaced to brine. Ini-

tial returns of seawater-contaminated brine were

discarded before the system was closed and sur-

face filters employed to reduce the maximum

particulate size to less than 2 microns [µm].

Solids in the brine were monitored to ensure that

there were fewer than 10 parts per million.

Perforation was carried out using tubing-con-

veyed perforating (TCP) guns with an underbal-

ance of about 300 psi. A short flow of 2 ft3/ft of

perforation was performed to remove debris. The

TCP guns were then dropped off. BP decided to

prepack the perforations with gravel prior to run-

ning the screen assembly. This strategy was used

to limit formation damage and prevent loss con-

trol material from entering the perforation tun-

nels (above).

Gravel in gelled carrier fluid was circulated

into place and then squeezed into the perfora-

tions. This was repeated two or three times to

ensure that all the perforations were packed. An

LCM pill of sodium chloride in xanthan gum and a

modified starch was then spotted across the

packed perforations to prevent loss of completion

fluid while the tubing was pulled.

A sump packer was set below the zone to be

completed and above the dropped TCP guns. The

main packer, service tool and screen assembly

were then run and the packer set.

The LCM pill was dissolved by circulating

unsaturated brine and the main gravel pack circu-

lated into place. A second LCM pill was then

spotted across the screen to allow recovery of the

service tool without losing completion fluid into

the formation (next page, left). The final comple-

tion hardware was run and the LCM dissolved.

nDissolving the loss control material and circulatingan annular gravel pack.

49October 1992

Main gravelpack screen

Tell tale screen

Washpipe bottom

‘O’ ring seal sub

Sump packer

Packer

Gravel pack extensionwith sliding sleeve

Crossover

Washpipe

Blank pipe

Logging reference screen

Wireline reentry guide

Sliding sleeve closed

18. Hudson TE and Martin JW: “Use of Low-Density,Gravel-Pack Material Improves Placement Effi-ciency (Part 2),” paper SPE 18227, presented at the63rd SPE Annual Technical Conference and Exhibi-tion, Houston, Texas, USA, October 2-5, 1988.Bryant D, Hudson T and Hoover S: “The Use ofLow-Density Particles for Packing a Highly Devi-ated Well,” paper SPE 20984, presented at Europec90, The Hague, The Netherlands, October 22-24,1990.

Low-density ceramic core

Polymer coating to resist acid

Pac

king

effi

cien

cy, %

Particle density/carrier fluid density, Dp:Dc

0.8 1.8 2.8

100

70

90

80

2.21.2

Par

ticle

s flo

at

Particles sink

ISOPAC particle

Optimum Dp:Dc ratio using ISOPAC particles

Standard Dp:Dc ratio using gravel

nEffect of particle-carrier fluid density ratioon perforation-pack efficiency—percentvolume of perforation filled with gravel.Efficient packing may be achieved with adensity ratio between 1.05 and 1.8. Thisrange may be designed using low-densityISOPAC particles. ISOPAC particles have apolymer coating with a low-densityceramic core. Conventional gravel pro-vides a ratio of about 2.4.

There is no industry consensus on govern-ing choice of fluid viscosity and gravel con-centration, but the following three combina-tions are the most common:•In conventional, circulating gravel packs,

most of the carrier fluid squeezed out ofthe slurry is circulated back to surface.The slurry usually has a low-viscosity car-rier fluid of less than 50 centipoise (cp)and ungelled water is a common carrier.Gravel concentration can range from 0.25to 15 lbm/gal depending on the carrierfluid viscosity and company preference.The technique is generally employed forintervals of more than 50 ft [15 m] anddeviated holes up to horizontal. Fluidleakoff is essential to ensure that perfora-tions are packed, but excessive leakoffmay lead to bridging.

•High-density circulating gravel packs areused for medium to long intervals—25 ft[8 m] to more than 100 ft [30 m]. Theslurry usually has a viscosity of more than50 cp and a gravel concentration of 7 to15 lbm/gal.

•Squeeze packs, in which all the carrierfluid leaks off into the formation, are usedfor short intervals of less than 25 ft.

The conventional approach to controllingsettling—decreasing gravel concentrationand increasing carrier-fluid viscosity—hasdrawbacks. To place an equivalent quantityof gravel, more carrier fluid must be lost,increasing the potential for formation dam-age. However, increased viscosity slows therate of leakoff—a 250-cp fluid will leak offmore than six times slower than a 40-cpfluid.18 Increasing carrier-fluid viscosity mayalso increase formation damage.

Sometimes, in an effort to improve place-ment, carrier-fluid viscosity and gravel con-centration are both increased to create aplug of slurry. But increased slurry viscosityraises friction pressure and may increase thepossibility of bridging in the annulus.

Another way of reducing settling, helpinggravel to turn the corner and efficiently packperforations is to use a gravel and carrierfluid of closely matched densities—not thecase when using conventional gravels orlow-density brines. For this purpose, DowellSchlumberger has developed ISOPAC low-density, high-strength particles. Because set-

tling is not a major problem when the densi-ties are matched, the pump rate can beslowed, improving tightness of the pack andincreasing the time available to pack all theperforations (below and next page). Thereduced viscosity increases the rate ofleakoff and reduces the potential for forma-tion damage.

ISOPAC particles have been used in over30 Gulf of Mexico and North Sea jobs sinceintroduction in 1991. The efficiency withwhich perforations have been packed can-not be measured directly. One indirect diag-nostic method is based on the average vol-ume of gravel placed per foot of interval(ft3/ft). Rules of thumb derived from experi-ence consider the placement efficiency ofabout 0.25 ft3/ft of conventional gravel asbeing satisfactory for intervals of less than60 ft [18 m]. For longer intervals it is moredifficult to fill all the perforations equallyand, if the interval is 100 ft or so, an averageplacement efficiency of only about 0.1 ft3/ft

1.000.50

0−0.50−1.00

8427 8460 8493 8526 8559 8592 8625 86588427 8460 8493 8526 8559 8592 8625 8658

8427 8460 8493 8526 8559 8592 8625 8658 8427 8460 8493 8526 8559 8592 8625 8658

0

1.000.50

−0.50−1.00

Time to pack, min

11.67

15.26

13.27

16.25

14.26

17.24

Gravel concentration, %

0 - 6

24 - 36

6 -12

36 - 48

12 - 24

Packed

Measured depth, ftMeasured depth, ft

Crossover Crossover Sump packer

Treatment B

Sump packer

Treatment A

Measured depth, ft

8427 8460 8493 8526 8559 8592 8625 8658

Measured depth, ft

8427 8460 8493 8526 8559 8592 8625 8658

Annular Packing Perforation packing

1.000.50

0−0.50

−1.00

Nor

mal

ized

rad

ius

Final gravel concentration

Nor

mal

ized

rad

ius

Final pack efficiency

Gravel deposition

Downhole hardwareE

ffici

ency

, %

Measured depth, ft

Time to pack, min

16.61

26.09

20.35

28.96

23.22

31.83

Measured depth, ft

50 Oilfield Review

nComparing conventional (treatment A) and ISOPAC particle (treatment B) placement. To aid the design of gravel-pack treatments, Dow-ell Schlumberger has developed PacCADE computer-aided design and evaluation software that can simulate gravel-packing opera-tions. Plots of gravel deposition time to pack, final gravel concentration and final pack efficiency—all versus depth—may be used tocompare proposed gravel-pack treatment designs. In treatment A using conventional gravel, the lowermost perforations have not beencompletely packed. In treatment B using lightweight ISOPAC particles in a prepack, good perforation packing efficiency has beenmaintained for the whole interval.

Surfactant

PERMPAC fluid in brine environment PERMPAC fluid in oil environment

Hydrophilic Hydrophobic+

Time, min

Volu

me

of fl

uid

thro

ugh

core

, ml 160

40

80

120

00 10 20 30

Xanthan polymer 36 lbm/1000 gal

40

PERMPAC fluid2.5% by volume

HEC 40 lbm/1000 gal

+

+ + + + + + + + +++

++++ +

++++++

++

+ + + + + + + + +++

++++ +

++++++

++

++ +

++

++

++

++

++ +

++

++

+

++

++

Activator

--

-

+

Hydrocarboncore

-

Water

--

Oil

-- -

-

--

+

+

+

+

+

+

+

+

+

+

+

+

+ +

+

+ +

+

+

+

+

+++

+

++

+ + +

nLeakoff tests (left) for different carrierfluids. The leakoff for three fluids—containing respectively the PERMPACsystem, hydroxyethyl cellulose (HEC)and xanthan polymer, in concentra-tions that give equivalent viscos-ity—were tested on Berea sandstonecores with nominal air permeabilitiesof 300 millidarcies. The PERMPACfluid shows an enhanced leakoff,because contact with oil causes thefluid’s micelles to break up (above).Final leakoff rate becomes constantas contact with oil is reduced.

19. Gulbis J, Hawkins G, King M, Pulsinelli R, Brown Eand Elphick J: “Taking the Breaks Off Proppant-PackConductivity,” Oilfield Review 3, no. 1 (January1991): 18-26.

20. Penberthy WL Jr and Echols EE: “Gravel Placementin Wells,” paper SPE 22793, presented at the 66thSPE Annual Technical Conference and Exhibition,Dallas, Texas, USA, October 6-9, 1991.

has been found to be common using con-ventional gravel. However, long-intervalgravel packs using ISOPAC particles haveeasily exceeded these figures. For example,in the Norwegian North Sea, a 400 ft [122m] interval was packed with an efficiency of0.64 ft3/ft.

While gravel and placement techniqueare being selected, the carrier fluid mustalso be chosen. In some cases, plain wateris used. In others, additives are used toincrease carrier-fluid viscosity. High-viscos-ity fluids are commonly water-base,although oil-base fluids are used forseverely water-sensitive formations. Water-base fluids are gelled with familiar stimula-tion chemicals like hydroxyethyl cellulose(HEC) or xanthan polymer. To reduce theconcentration of nonhydrated polymer thatmay damage the formation, fluids gelledwith these polymers are often sheared usinga pump and filtered prior to blending withthe gravel.

Breaker is added to reduce fluid viscosityonce the job is complete and therefore min-imize formation damage.19 HEC is normallythe polymer of choice because it has lowresidue after breaking and does not build afilter cake on the formation, minimizing per-meability damage.

A radically different type of gelling agent,developed by Dowell Schlumberger, usesPERMPAC viscoelastic surfactant-based car-rier fluid. This fluid forms rod-shapedmicelles that have a high viscosity in low-concentration aqueous solution. It showshigh rates of leakoff into the formation, andhas good suspending capabilities comparedto conventional polymers. Unlike HEC,PERMPAC fluids do not require a breakerbecause they are thinned by temperatureand shear, and by crude oil or organic sol-vents, all of which tend to increase as thefluid penetrates deeper into the formation(above, right).

To improve perforation packing, bothconventional and high-density circulatinggravel packs may be preceded byprepacks—where the perforations are filledwith gravel either before the screen hasbeen run in hole or as a separate operationprior to packing the casing-screen annulus.Perforations can be prepacked effectively

October 1992

21. Matherne BB and Hall BE: “A Field Evaluation of aGravel-Diverted Acid Stimulation Prior to GravelPacking,” paper SPE 19741, presented at the 64thSPE Annual Technical Conference and Exhibition,San Antonio, Texas, USA, October 8-11, 1989.

using either water or gelled fluid providedfluid loss into the formation is finite.20

Prepacking prior to running the screen, asoutlined in the Forth field example (see“Gravel Packing Forth Field ExplorationWells,” page 48), is used to limit the pene-tration of LCM into the perforation tunnelsduring tripping. Determining the prepackvolume is important. Too little gravel willresult in the LCM penetrating unpacked per-forations. Too much may necessitate a tripto clean out the excess in the sump andcovering perforations. Volume depends on anumber of factors, such as the competenceof the formation, the quality of the cementjob, the design and size of the perforationcharges, the extent of cleanup flow afterperforation and the formation permeability.

Prepacking with the screen in place is car-ried out with the service tool in the squeezeposition before the annular pack is circu-lated into place. The process takes less timethan the alternative prescreen technique.

The prepack may be pumped as severalstages of gravel slurry interspersed withstages of acid to clean up damage aroundthe perforations. The gravel slurry not onlyprepacks the perforations but also acts as adiverter, probably because of pressure that

results when the higher viscosity carrierfluid leaks off into the formation. Diversionensures that more perforations are acidizedand then prepacked than would normallybe the case.21

Sometimes acidization is carried out as aseparate stage, prior to the gravel pack. Theprimary aim of this treatment is to increasethe rate at which the carrier fluid will leakoff during the subsequent gravel pack,although the acid also stimulates the well.When stimulation is required that matrixtreatments cannot deliver, one alternative isto create short, wide fractures by carryingout a tip-screenout fracturing treatment fol-lowed by a circulating gravel pack (see“Rewriting the Rules for High-PermeabilityStimulation,” page 18).

51

Iridium

Multiple Isotope Log

5550

5600

Dep

th, f

t

Cumulative ScandiumCumulativeCompletion schematic

5630

nIsotope logging ofa prepack usingISOPAC particlescontaining scan-dium and iridium.The initial slurrywith particles con-taining scandiumtracer packed thethree high-perme-ability zones. Then aslurry with particlesincorporating iridiumwas pumped thatfilled in the zone at5630 ft and divertedto the remainder ofthe perforated inter-val. The cumulativetracks—the superpo-sition of scandiumand iridium— indi-cate 100% perfora-tion packing over

Evaluating the Gravel PackWith the gravel pack in place, there are twoelements to be evaluated: that gravel hasbeen packed everywhere it was supposed togo, and that the well is producing hydrocar-bons satisfactorily.

Since voids in the pack may lead to earlycompletion failure, postpack evaluation isessential to detect incomplete fill and allowrepairs to be undertaken. Prior to place-ment, gravel may be coated with radioac-tive isotopes and the pack assessed usinggamma ray logging. However, the coating isusually inconsistent and may wash off, mak-ing quantitative analysis unreliable.

One way to improve the accuracy of suchlogs is to use ISOPAC particles that havebeen manufactured with isotope encapsu-lated within each particle’s resistant shell.This also offers increased subtlety throughuse of multiple isotopes. The perforationsmay be prepacked using particles contain-ing scandium followed by particles contain-ing iridium. Packing placement efficiencycan be monitored, using a multiple-isotope,gamma spectroscopy tracer log (right).

Alternatively, the effectiveness of fill maybe gauged using nuclear density logging toestimate the density of material in the annu-lus. However, not all changes in density arerelated to changes in gravel-pack quality—changes in the screen, pipe base, casing,tubing and formation sand all affect thereading. A base log run prior to the gravelpacking can iron out these discrepancies(next page, left). In addition, a referencescreen may be set below the sump packer toregister zero pack response.22

Density measurement is not appropriatewhen the completion fluid has a high den-sity (more than 14 lbm/gal) or where low-density particles have been employed. Inthese cases, neutron activation logging can

52

22. Gilchrist JM and Gilchrist AL: “A Review of GravelPacking in the Forth Field,” paper SPE 23128, pre-sented at the Offshore Europe Conference,Aberdeen, Scotland, September 3-6, 1991.

23. Watson JT, Carpenter WW, Carroll JF and Smith BC:“Gravel Pack Field Examples of a New Pulsed Neu-tron Activation Logging Technique,” paper OTC6464, presented at the 22nd Annual Offshore Tech-nology Conference, Houston, Texas, USA, May 7-10, 1990.

24. “Jim Carroll: The Gulf Coast WID Kid,” The Techni-cal Review 35, no. 2, (April 1987): 19-26.

25. Deruyck B, Ehlig-Economides C and Joseph J: “Test-ing Design and Analysis,” Oilfield Review 4, no. 2(April 1992): 28-45.

26. Unneland and Waage, reference 9.

be used. The neutron activation loggingtechnique uses a pulsed-neutron loggingtool modified to allow a gamma ray deviceto be mounted below it. The pack is bom-barded with fast neutrons. Silicon and alu-minum in the gravel are activated andgamma rays are emitted as the elementsreturn to their natural stable state. The num-ber of gamma rays is proportional to theamount of silicon and aluminum activated,and pack quality may be inferred. 23

In openhole packs, a compensated neutronlog can be used to detect hydrogen-rich flu-ids in the gravel-pack pore space, making itsensitive to changes in pack porosity. Thetool’s near and far detectors are used to partlyeliminate the effects of hole conditions. Thecurves of the two detectors are scaled tooverlay in areas of low porosity—good pack.Areas of high porosity—poor pack—are indi-cated by a shift of the curves, especially the

5650

5700

High-pe

near-detector curve, toward decreasing countrate (next page, top right).

Once voids in the pack are identified, awireline shaking device attached to theevaluation tools may be used to break upbridges and allow the pack to settle. Theshakes create local turbulence in the fluidwhich agitates the bridged gravel until it set-tles into the void.24

The other main strategy for testing gravelpacks centers on assessing performanceusing well tests and production logging. Inassessing gravel pack performance a num-ber of diagnostics are available, includingskin factor (which measures formation dam-age as a function of its permeability) andmultirate flow tests.25

Differentiating between the effects of theformation and the gravel pack, oftenrequires a DST prior to packing. With thesedata it is possible to identify the pressure

Oilfield Review

rmeability zones

the entire interval.

4300

4400

Near detector

26.667 3877

Far detector

75 300 Pack %

0 100

9-5 /

8 in

. cas

ing

7-3 /

4 in

. lin

er

25 125

Gamma ray

API

Compensated Neutron Log

CPS

drop caused by the gravel pack. Productionlogging may be used to evaluate each layerin the formation assessing the flow profileacross the interval.26 Gravel-pack perfor-mance versus time is another indication ofperformance. Pressure drop across the packis one measure. An increase could indicatethat fines like kaolinite have migrated intothe pack and around the gravel or thatunpacked perforations have collapsed.

In the past, the successful accomplish-ment of a gravel-packing operation hasoften been the main criterion used to judgeits success. This judgement often fails toconsider that the treatment may have dam-aged the well. Today, more attention isbeing paid to performance, and completionengineers are increasingly seeking ways ofstopping formation sand without seriouslyrestricting productivity. —CF

nCompensated neutron log of a gravel pack using near and far detectors. The neardetector is affected mostly by the screen and wellbore fluids. The far detector is affectedby the gravel pack, the casing, and in some cases the formation and its fluids.

53October 1992

Gamma ray after

Gamma ray before

Top of sand

Base run

Top of screen

After gravel pack run

5700

5800

2000 4000CPSDep

th, f

t

nNuclear density logging of a gravel pack.Running a base log prior to gravel packingallows the density effects of the bottomholeassembly to be taken into considerationand the gravel pack to be evaluated.

4500

4600

4700

Scr

een

Top of partial sand pack

5

Charlie CosadSchlumberger Testing ServicesAberdeen, Scotland

Choosing a Perforation Strategy


The ultimate success of the

well—its productivity and life

expectancy—rests on making the

best possible connection between

the wellbore and formation. This

update reports on what we know

today about selecting a perfora-

tion strategy best suited to the

reservoir and the completion.

4

For their help in preparation of this article, thanks toLarry Behrmann, Klaus Huber, Tom Lebsack and TonyVovers, Schlumberger Perforating Center, Rosharon,Texas, USA; Bill Bell, Huntsville, Texas, USA; Dick Ellis,Pennzoil, Houston, Texas, USA; George King, AmocoResearch, Tulsa, Oklahoma, USA; Randy Saucier, Man-deville, Louisiana, USA; and Stephan Turnipseed, TriTechServices, Montgomery, Alabama, USA.In this article, Enerjet, HEGS (High-Efficiency Gun Sys-tem), HSD (High Shot Density gun system), S.A.F.E.(Slapper-Actuated Firing Equipment), Selectric, SPAN(Schlumberger Perforating Analysis), Pivot Gun, IMPACT(Integrated Mechanical Properties Analysis & Characteri-zation of Near-Wellbore Heterogeneity), MSRT (Multi-Sensor Recorder/Transmitter) and LINC (Latched Induc-tive Coupling) are marks of Schlumberger.1. Gravel is rounded particles of diameter typically

greater than 2 mm [0.8 in.].

The fate of a well hinges on years of explo-ration, months of well planning and weeksof drilling. But it ultimately depends on per-forming the optimal completion, whichbegins with the millisecond of perforation(above). Profitability is strongly influencedby this critical link between the reservoirand wellbore.

Perforations form conduits into the reser-voir that not only allow hydrocarbon recov-ery, but influence it. Each of the three maintypes of completions—natural, stimulatedand sand control—has different perforatingrequirements. In the natural completion (inwhich perforating is followed directly byproduction) many deep shots are most effec-tive. In stimulated completions—hydraulicfracturing and matrix acidizing—a smallangle between shots is critical to effectivelycreate hydraulic fractures and link perfora-tions with new pathways in the reservoir.And in gravel packing, many large-diameterperforations effectively filled with gravel1

are used to keep the typically unconsoli-dated formation from producing sand andcreating damage that would result in largepressure drops during production.

To meet the broad requirements of perfo-rating, there many perforating guns and gunconveyance systems. Optimizing perforatingrequires selection of hardware best suited tothe job. A good place to start, therefore, iswith the basics of perforating hardware.

The Language of PerforatingThere was a time when describing the perfo-ration operation defined the perforator: run-ning through-tubing guns, shooting casingguns or tubing-conveyed perforating (TCP)(next page). Not so with the present varietyof completion methods and gun systems.

Oilfield Review

55October 1992

nThree conveyance methods for perforating guns: through-casing and through-tubing, and tubing-conveyed systems.The through-tubing gun shown is held against the casing magnetically. The others hang free.

nUp in smoke. Sur-face detonation of astandard 4-in. gun,staged during themaking of a safetytraining video.Destruction of themannequin at left,positioned about 1foot [30 cm] fromthe end of the gun,shows the poten-tially devastatingeffect of a surfacedetonation, empha-sizing that safetyforms the essentialfoundation for per-foration operations.aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaCasing

Casinggun

Through-casing perforation

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaThrough-tubing perforation

TubingPacker

Through-tubing gun

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaWorkstring

Firinghead

Guns

Packer

Flow entryports

Safety spacer

Tubing-conveyed perforation

5

nMajor geometrical parameters thatdetermine flow efficiency in a perforatedcompletion. Four key factors are shotdensity, phase angle, perforation penetra-tion into the formation and perforationdiameter. Productivity of a well alsodepends on the size of the crushed zone,whether the perforation extends beyondthe damaged zone and how effectivelythe crushed zone and charge debris areremoved from the tunnel.

Perforationvaries with

shotdensity

Phaseangle

Damaged zone

Perforationdiameter

Perforationpenetration

Crushedzone

Wirelinethrough-tubing

Wirelinethrough-casing

Tubingconveyed

Gun System

Application

Exposedgun

Strip

Pivot

x

x

The two broad categories of guns areexposed and hollow carrier guns (bottom).These can be used in two types of perforat-ing operations: through-tubing, in whichguns are run through a production or teststring into larger diameter casing; andthrough-casing, in which guns are largerdiameter and run directly into casing.

Exposed guns are run on wireline andhave individual shaped charges sealed incapsules and mounted on a strip, in a tubeor along wires. The detonator and detonat-ing cord are exposed to borehole fluids.These guns are used exclusively throughtubing and leave debris after firing. Theyinclude two designs, “expendable,” (chargesand mounting assembly become debris) and“semiexpendable” (mounting is recovered).For a given diameter, exposed guns carry alarger, deeper penetrating charge than a hol-low carrier gun. But exposed gun outerdiameter is generally not larger than about21/2 in. [6 cm], because above this size, thecasing, or hollow carrier design, becomesmore practical, allowing use of largercharges, optimal angle betweenshots—called phasing2 —and increasednumber of shots per linear foot—called shotdensity (above, right).

Hollow carrier guns have shaped chargespositioned inside pressure-tight steel tubes.This design is available for most tubing andcasing sizes. It is used through tubing whendebris is unacceptable and in hostile condi-tions that preclude exposed guns. There arefour main types of hollow carrier guns: •Scallop guns, so-called because charges

shoot through dished out areas in the car-rier, which is recovered and junked. Scal-lop guns are wireline-conveyed and shot

6

Hollowcarrier gun

Scallop

Port plug

Highefficiency

High shotdensity

x

x

x

2. The nomenclature of phasing may be a source of con-fusion. A 60° phasing means one shot every 60°azimuthally; a 180° phasing means one shot every180°. Phasing of 0° has all shots in one line, meaningthe angle between shots is actually 360°. Speaking of“reduced phasing” or “reduced phase angle” meansthe angle between shots is smaller. A 45° phasing istherefore “reduced” compared to a 90° phasing.

nA taxonomy of perforating

only through tubing. They are usedmainly in hostile environments or wheredebris is unacceptable.

•Port plug guns, in which charges shootthrough replaceable plugs in a reusablecarrier. These are wireline conveyedmainly for deep penetration and where 4shot-per-foot (spf) density is acceptable.

•High shot density guns, which aredesigned for each casing size to optimizeshot density, hole size, penetration andphasing. The majority of sand controlcompletions use high shot density gunsloaded with charges designed to providelarge entrance holes. All TCP is performedwith high shot density guns.

•The HEGS High-Efficiency Gun System,which is a wireline-conveyed alternativeto port plug guns, with longer carriers thatare faster to load and run. The HEGS sys-tem is available in 31/8- in. and 4-in. outerdiameter. It is rated to 210°F [99°C] and4000 psi, making it useful in many shal-low wells. A big hole charge is availablefor the 4-in. size.

To determine the type of perforation andgun system best suited to the well, a practi-cal first step is to consider the general inter-action of the perforation and reservoir. Asecond step is to look at how perforationdesigns vary for each of the three maintypes of completions: natural, stimulatedand sand control.

Oilfield Review

xx

x

x

guns and systems.

nProgression of shaped-charge detonation. The

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaPrimer

Liner

Detonatingcord

Case Explosive

0 µsec

4 µsec

9.4 µsec

16.6 µsec

A Perforation Glossary

Big hole charge: A shaped charge that gives prior-ity to entrance hole over depth of penetration, usedexclusively in sand control completions. A “bighole” has an entrance diameter of 0.5 to 1.2 in. [13to 30 mm], usually about twice that of a deep pene-trator charge of similar size. Conventional deeppenetrators have an entrance hole diameter of 0.3to 0.5 in. [8 to 13 mm].

Booster: A secondary explosive attached to the endof the detonating cord, used to assure passage ofinitiation between the detonator and detonatingcord or between detonating cords.

Carrier: In hollow carrier guns, a steel tube thatcarries a loading tube and protects it from the well-bore environment. The loading tube secures andaligns the detonating cord and shaped charges. Thedetonator is housed in a firing head attached to thecarrier.

Completion: Work required to make a well ready toproduce oil or gas. It generally includes—not nec-essarily in this order—running and cementing cas-ing, perforating, stimulating the well, running tub-ing and installing control and flow valves. In apermanent completion, the well is not killed afterperforating underbalance and is ready for immedi-ate production. In TCP, the guns remain downholeafter firing. In a temporary completion, the well iskilled after perforating and the workstring retrievedbefore installing the permanent completion.

Deep penetrating charge: A charge design thatgives priority to penetration depth instead ofentrance hole diameter.

Detonating cord: A secondary explosive containedin a protective flexible outer sheath. The detonatoris connected to the detonating cord, which trans-mits the detonation to each shaped charge. It mayalso pass detonation along to another gun via abooster.

schematic at 0 µsec shows the charge components.The volume of explosive is greatest at the apex of theliner and least near its open end. This means that asthe detonation front advances, it activates less explo-sive, resulting in a lower collapse speed near theliner base. The subsequent drawings show the casedeforming as the detonation front advances, thrust-ing the liner into a jet along the shaped-charge axis.The fully formed jet, at 16.6 µsec, is moving at about21,300 feet/sec [6500 m/sec].

October 1992

Detonator: A primary explosive that initiates thedetonating cord. Detonators can be fired electricallyor by impact.

Drillstem test (DST): A temporary completion inwhich a downhole shut-in valve, controlled fromsurface, is incorporated in the workstring, usuallywith a retrievable packer. The well can then beflowed in a test program, either recording data indownhole memory or conveying them to surface inreal time to analyze reservoir properties such aspermeability and reservoir boundaries.

Explosive: There are two types used in well perfo-rating, primary and secondary explosives. The maindifference is in their sensitivity. A primary explo-sive, used in the detonator, detonates from heat(applied by electric power) or impact (from a dropbar or a pressure-driven firing pin). A secondaryexplosive, used in detonating cord, shaped chargesand boosters, is detonated only by another detona-tion, from either a primary explosive or electricallygenerated shock, such as from the S.A.F.E. system.

Limited entry perforating: Varying the number ofperforations in each layer, depending on layerthickness and stress state, to achieve the desiredfracture geometry. Fewer perforations in the layertaking the most fluid restrict flow and divert it intoother layers.

Primer: A small amount of higher sensitivity sec-ondary explosive at the base of the shaped charge,which ensures correct initiation of the charge bythe detonating cord.

Proppant: Material pumped into a hydraulic frac-ture to prevent closure and provide a conduit forproduction once pressure is released. The mostcommon proppant is sand. High-strength prop-pants, like sintered bauxite and zirconium oxideparticles, are used where fracture closure stresswould crush sand.

Shaped charge: A precisely engineered cone ofpressed metal powder, or drawn solid metal, sur-rounded by a secondary explosive and case, andinitiated by detonating cord. Detonation collapsesthe cone into a jet that penetrates the completionand formation (right).

Strip gun: An expendable gun in which individualcharges in capsules are secured and aligned alonga strip of metal.

57

Sand Control

Consolidated

Stimulated

PerforationGeometry

AnisotropyIsotropic

PermeabilityPerforationGeometry

NaturalFractures

WellboreDamageOf Any

CauseLaminar

Shale

Natural

Unconsolidated

Completion Type

Shot density

Perforationdiameter

Perforationphasing

Perforationlength

2

3

1

4

2

1

3

4

1 or 2

3 or 4

3 or 4

1 or 2

Shot density

Perforation diameter

Perforationphasing

Perforationlength

1

3

4

2

2

4

3

1

1

4

3

2

3

4

2

1

2

4

3

1

nRelative impor-tance of four maingeometrical factorsin the three com-pletion types,where 1 is greatestand 4 is least. Theoptimum perfora-tion design estab-lishes the propertradeoff of thesefactors. The lowerpart of the figureshows commonconsiderations forperforating naturalcompletions. Whennatural fracturesare present, phas-ing becomes moreimportant thandensity to improvecommunicationbetween fracturesand perforations.

58

3. Stylolites, common in carbonates, function like shalelayers in sandstones, inhibiting vertical migration ofhydrocarbons. They are interlocking wave- or tooth-like seams that often parallel bedding, and containconcentrations of insoluble rock constituents, such asclay and iron oxides. They are thought to be causedby pressure solution, a process that increases contactarea between grains and reduces pore space.

4. The American Petroleum Institute (API) publishes rec-ommendations for testing shaped charges in a docu-ment, API RP-43. Section 1 specifies the length andentrance hole diameter produced by a gun system(charges and carrier) in a steel and concrete target.Section 2 gives this information for single shots into astressed Berea sandstone target. As of this writing, theavailability of target material for Section 2 is underreview by the API.

5. Halleck PM, Saucier RJ, Behrmann LA and Ahrens TJ:“Reduction of Jet Perforator Penetration in RockUnder Stress,” paper SPE 18242, presented at the 63rdSPE Annual Technical Conference and Exhibition,Houston, Texas, USA, October 2-5, 1988.

6. Behrmann LA and Halleck PM: “Effect of Concreteand Berea Strengths on Perforator Performance andResulting Impact on the New API RP-43,” paper SPE18242, presented at the 63rd SPE Annual TechnicalConference and Exhibition, Houston, Texas, USA,October 2-5, 1988.Halleck PM and Behrmann LA: “Penetration ofShaped Charges in Stressed Rock,” in Hustrulid WAand Johnson GA (eds.): Rock Mechanics Contribu-tions and Challenges: Proceedings of the 31st USSymposium. Rotterdam, The Netherlands: A.A.Balkema (1990): 629-636.

7. Karakas M and Tariq S: “Semianalytical ProductivityModels for Perforated Completions,” paper SPE18271, presented at the 63rd SPE Annual TechnicalConference and Exhibition, Houston, Texas, USA,October 2-5, 1988.Economides MJ and Nolte KG (eds): Reservoir Stimu-lation, 2nd ed. Englewood Cliffs, New Jersey, USA:Prentice Hall (1989): 1-17.

8. Pucknell JK and Behrmann LA: “An Investigation ofthe Damaged Zone Created by Perforating,” paperSPE 22811, presented at the 66th SPE Annual Techni-cal Conference and Exhibition, Dallas, Texas, USA,October 6-9, 1991.

Perforation-Reservoir Interactions— Get-ting StartedFlow efficiency of a perforated completionand stimulation success are determinedmainly by how well the perforation programtakes advantage of the reservoir properties.The program includes determination of twomain factors:•The proper differential between reservoir

and wellbore pressure (The usual prefer-ence is for underbalance, meaning well-bore pressure is less than reservoirpressure at time of perforating).

•Gun selection, which determines penetra-tion tunnel length, shot phasing, shot den-sity and perforation entrance hole diame-ter. The relative importance of thedifferent components of shot geometryvaries with the completion type (below).

The main reservoir property that affects flowefficiency is permeability anisotropy fromwhatever cause—in sandstone, typicallyfrom alignment of grains related to theirdeposition; in carbonates, typically fromfractures or stylolites.3 Shale laminations,natural fractures and wellbore damage,which can cause permeability anisotropy,

are considered separately because they areso common. In most formations, verticalpermeability is lower than horizontal. In allthese cases, productivity is improved by useof guns with high shot densities.

Natural fractures are common in manyreservoirs and may provide high effectivepermeability even when matrix permeabilityis low. However, productivity of perforatedcompletions in fractured reservoirs requiresgood hydraulic communication betweenthe perforations and fracture network. Tomaximize the chances of intersecting a frac-ture, penetration length is the highest prior-ity, with phase angle second. Shot density isless important because fractures form planesand increasing density does not increasecontact with a fracture system. In fracturedformations, a popular gun configurationuses 60° phasing with 5 spf. A Schlumber-ger version of this gun has a large chargethat penetrates 30 in. [76 cm] into the stan-dard API test target.4

An important geometric consideration ofa perforation is how deeply it penetrates—whether it reaches beyond the zone dam-aged during drilling or connects with exist-

ing fractures. The penetration of variousshaped charges is documented in surfacetests and in tests under stress with API targets.Penetration in surface tests is different thanunder stress in the well.5 Unconfined com-pressive strength of test targets is a minimumof 3300 psi, representing only low-strengthreservoir rock (reservoir rock strength rangesfrom 0 to 25,000 psi). To estimate depth ofpenetration into a rock of arbitrary strengthunder a given stress, data measured atunstressed surface conditions have to betransformed. Because rock penetration dataexist for only a few combinations of charges,rock strengths and stresses, a semiempiricalapproach is used that combines experimentaldata with penetration theory.6

Schlumberger calculates penetrationchange caused by formation stress usingexperimental data for three generic chargedesigns after first calculating the change dueto formation strength at zero stress. Thesedata provide transforms implemented in theSPAN Schlumberger Perforating Analysisprogram. The SPAN program consists of twomodules: penetration length calculation andproductivity calculation. In the penetration

nRelationship of perforation phasing and depth to productivity (left) and to wellbore skin (right). Curveson the left are for undamaged conditions. Damage would reduce their absolute values, but they wouldmaintain the same position relative to each other. For 0° phasing perforation, skin is higher at thewellbore because flow follows a less direct path to the perforation than for the 90° phasing case.Perforations with lower skin distribute the pressure drop over a greater distance from the wellbore,yielding a higher production rate for a given wellbore pressure. The left figure shows the increase inproductivity with perforation length. In the theoretical case of no damage, a 9-in. [23-cm] perforationat 0° phasing has the same productivity as a 3-in. [8-cm] perforation of 90° phasing.

nHow a damaged zone near a perforatedcompletion affects productivity, for a 9-in.perforation with 0° phasing and 4 shotsper foot. The influence of loweredeffective permeability in the damagedzone can be combated by perforationsthat extend into the virgin formation. Inthis example, there is no crushed zone, socrushed zone permeability, kcz, equalsvirgin formation permeability, k. Butpermeability of the damaged zone, kdz, is60% lower than that of the virgin zone.

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aIncreasing pressurePro

duct

ivity

rat

io

Wel

lbor

e

Incr

easi

ng p

rodu

ctiv

ity

Incr

easi

ng s

kin

Perforation length, in. Distance from wellbore

Reservoirpressure

Wellborepressure

Damagedzone

90° 4 spf

0° 4 spfA

B

A

B

1.1

1.0

0.9

0.8

0.7

0.60 3 6 9 12 15

59

Pro

duct

ivity

rat

io

Open hole

Effect for 9-in.perforation

Damaged zone thickness, in.

1.0

0.9

0.8

0.7

0.6

0.50 3 6 9 12 15

No crushed zonekcz/k=1kdz/k=0.4

nPhotomicrographs of rock thin sections, showing the effect of perforation. The leftimage is from rock near the perforation tunnel, showing microfracturing. The right thinsection is undamaged rock. (From Pucknell and Behrmann, reference 8.)

October 1992

1 mm

module, perforation length and diameterestimates are calculated under downholeconditions for any combination of gun,charge and casing size. It can also calculatepenetration in multiple casing strings. Theseparameters are used in the productivitymodule to evaluate the anticipated produc-tivity of the perforated completion.

Another influence on flow efficiency isformation damage, usually considered inthe context of skin, an index of flow effi-ciency related to properties of the reservoirand completion. Skin comprises a variety ofinfluences: flow convergence, wellboredamage, perforation damage, partial pene-tration (perforation of less than the totalheight of the reservoir) and the anglebetween the perforation and bedding plane.The goal is to design perforations that mini-mize skin and therefore maximize flow effi-ciency (top).

Formation damage is caused by invasionof mud filtrate and cement fluid loss into theformation, creating a zone of lower effectivepermeability around the wellbore (above,right). Extending the perforation beyond thedamaged zone may reduce this skin signifi-cantly, enhancing productivity.7 But even forperforations that do penetrate farther, thewellbore damage zone reduces the effectivetunnel length.

During perforating, a “crushed zone” ofreduced permeability is created around theperforation. In laboratory experiments, thethickness and permeability damage of the

crushed zone are influenced by all vari-ables to varying degrees: the type of shapedcharge, formation type and stress, underbal-ance and cleanup conditions. Pucknell andBehrmann found that permeability near theperforation is reduced because microfrac-turing replaces larger pores with smallerones (above). The current rule of thumb isto assume a crushed zone 1/2 in. [13 mm]

thick with permeability reduced by 80% to90%. Recent experimental data, however,cast some doubt on this assumption, withcrushed zone thickness a function of chargesize, pore fluid type, and the preservation ofpermeability when perforating underbal-ance.8

60 Oilfield Review

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aDamagedzone

Virgin formation

Chargedebris

Cement

CasingCrushed (low-permeability)zone still exists

Overbalanced perforating before flowing

Part of low-permeabilityzone still exists

Perforation partially pluggedwith charge debris

Overbalanced perforating after flowing

Crushed zone and chargedebris expelled by surgeimmediately after perforating

Ideal underbalanced perforating

nThree idealizedconditions in aperforation tunnel:overbalance perfo-ration before flow-ing, overbalanceperforation afterflowing andunderbalance per-foration. The topfigure indicatesthat withoutcleanup, the perfo-ration tunnel isplugged bycrushed rock andcharge debris. Inthe second case,flow has removedmost chargedebris, but some ofthe low-permeabil-ity crushed zonecreated by the jetremains. In thethird figure, suffi-cient underbal-ance during perfo-rating removeddamage—bothcharge debris andcrushed rock.nThree views of perforating with a

135°/45° phased gun: the gun fired incasing, phasing viewed from the top, andwith the perforated casing unrolled andlaid flat. The 135°/45° designation meansthe angle between successive shots is135°, resulting in an overall phasing of45°. There is 1 vertical inch [2.5 cm]between shots, making 12 shots per foot.In the natural completion, this phasingprovides hydrocarbons with the mostdirect path to the wellbore.

Gun incasing

Phasing from top

Casing unrolled (7 in.)

45°

135°1

5

4

7

28

3

6

0 45 90 135 180 225 270 315 360

1

4

7

2

5

8

6

1

4

72

6

1

2

5

8

3

6

3

6

8

The Natural Completion—Perf and ProduceThe natural completion is often defined asthat in which little or no stimulation isrequired for production. This approach isusually chosen for reservoirs that are lessprone to damage, have good transmissibil-ity, and are mechanically stable.

Of primary importance in selecting theperforating gun are its depth of penetrationand effective shot density (see “NaturalCompletion,” next page). Depth is importantbecause the deeper the perforation, thegreater the effective wellbore radius; alsoflow is less likely to be influenced by forma-tion damaged during drilling. In the contextof well productivity, a deep penetratorshoots to a depth 1.5 times that of the well-bore damage.

Shot density also ranks high becausemore holes mean more places for hydrocar-bon to enter the wellbore and a greater like-lihood that perforations will intersect pro-ductive intervals of an anisotropic reservoir.After shot density and depth of penetration,

most important is phasing because, whenproperly chosen, it provides hydrocarbonswith the most direct path to the wellbore(below, left). Under typical flow conditions,perforation diameter does not adverselyaffect flow once it exceeds 0.25 in. [6 mm],which today is provided by nearly all gunsused in natural completions.

A key consideration in perforation designof natural completions is the selection ofoverbalance versus underbalance perforat-ing. Overbalance means the pressure ofwellbore fluids exceeds reservoir pressure atthe time of perforating. Under this condi-tion, wellbore fluids immediately invade theperforation. For this reason, clean fluidswithout solids are preferred to prevent plug-ging of perforations. Cleanup can occuronly when production begins.

Increasingly, wells that have sufficientreservoir pressure to flow to surface unas-sisted are completed in underbalance con-ditions. Underbalance is the trend becauseof wider recognition that it provides cleanerperforations—therefore better produc-

tion—and because of greater availability ofgun systems that allow it. Underbalanceperforating can provide large gains in reser-voir productivity. The question is, howmuch underbalance is appropriate? Exces-sive underbalance risks mechanical damageto the completion or test string by collapsedcasing or a packer that becomes damaged,stuck or unseated. It can also encouragemigration of fines within the reservoir,reducing its permeability. Insufficient under-balance, however, doesn’t effectively cleanthe perforations. Production may thereforebe hindered, mainly by lack of removal ofthe crushed zone and, secondarily, by lackof removal of debris. The crushed zone isthe damaged rock in and around the perfo-ration tunnel; debris is mainly the linermaterial of the spent shaped charge, plusfragments of cement and rock (below).

The optimal underbalance, whichremoves both debris and the crushed zoneand does not damage the formation, accom-plishes virtually all cleanup during the por-tion of initial production that is dominated

61October 1992

Natural CompletionPerforation Technique Selection

No

No

No

No

No

No

No

No

Casing guns(wireline conveyed only)

Run guns and packeron wireline.

Stab guns throughpermanent packer.Select guns, firingsystem and TCPhardware.(Tubing conveyed)

Run guns and packeron tubing.

Do packer/gun assembly weight and welldeviation allow setting by wireline?

Pivot Gun (perforatesmaximum of 15 feet[5 m] per run)

Is deeper penetration important?or

Is selectivity not required?

Conventional strip guns

Production Test

Exposed gunsHollow carrier guns(scallop or HSD guns,depending on tubingsize)

Run guns belowproduction packer.Select guns, firingsystem and TCPhardware.

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

TCP (high shot density guns)

Does improvement in well cleanup from underbalance perforating justify added operational complexity?

Is the well ≤ 4000 psi, < 210°F [99°C]?

•Is there sufficient rathole for dropping guns, if subsequent remedial operations are required?

andDo any of the following apply?•Shot density > 6 shots per foot•Deviation ≥ 60°•Simultaneous perforation needed for a single, long zone or multiple zones, exceeding what can be perforated in one wireline run

•Two or fewer zones to be shot selectively for a multizone test.

Through-tubing guns(wireline conveyed)

•Will gun or charge debris be a problem for downhole equipment?

or•Are more than two zones to be perforated selectively?

Does completion benefit from high shot density or reduced phase angle?

Port plug guns

Select correctdiameter high shotdensity guncompatible withdownholerestrictions; selectphasing and shotdensity.

HEGS (wireline

conveyed only)

Perforate underbalance. Perforate overbalance with high shot density or casing guns.

Select TCP firingsystem andaccessories tointegrate withDST string.

Is the option of gun retrieval required?or

Are guns with diameter less than the maximumallowed by casing size acceptable?

Drillstem test

Boxes in red outline denote final decision points.

nA family of through-tubing, wireline-conveyed guns. From left, the 0° phased Enerjet(a semiexpendable strip gun); the phased Enerjet, with two rows of charges at 90° (anexpendable strip gun); and the 60° phased scallop gun (a retrievable gun). Unlike theEnerjet, the scallop gun has negligible debris and can be run in hostile environments.

62 Oilfield Review

60° phasedscallop gun

± 45° phasedEnerjet

0° phasedEnerjet

by surge of reservoir fluids into the perfora-tions. Cleanup after this point is negligiblebecause hydrocarbon follows the alreadycleaned paths of least resistance. Duringproduction, pressure drop across damagedareas is insufficient for further cleanup.Recent experiments have shown that if asuboptimal underbalance is used, somecleanup will take place during production,but productivity never reaches that achievedwith optimal underbalance.9

When well testing is planned, underbal-ance perforating has become the standard,particularly when a drillstem test (DST) isincluded. Underbalance perforating is ide-ally suited because a DST includes hard-ware that allows establishing underbalanceand running high shot density guns. Thissetup provides excellent well control andoften saves time because the perforatingguns are run below the test string. Pressuremeasurements can be recorded eitherdownhole or in real time at surface, and areavailable for decision-making during thetest. The MSRT MultiSensor Recorder/Trans-mitter and LINC Latched Inductive Couplingequipment allow real-time measurementand surface readout of downhole pressure.The main advantage of this system is theadded mechanical and safety reliability ofmeasuring pressure below the DST shut-invalve. In addition, memorized data can beread out at surface when LINC equipment isrun, eliminating the need for the cable inthe test string while the well is flowing.

From an operations viewpoint, underbal-ance perforating by wireline-conveyed gunscauses a surge that lifts cable and guns. Thehigh flow rate or liquid slugs associatedwith this surge can blow the guns and cableup the well. A common limit on underbal-ance when perforating via wireline is 700psi, although this is often higher in tightreservoirs, which are not capable of deliver-ing a substantial surge.

The choice of underbalance may bebased on data collected since the early1980s from laboratory and field studies andfrom increasing use of underbalance com-pletions (primarily tubing-conveyed perfo-rating).10 More recently, computer programshave been developed. The IMPACT Inte-grated Mechanical Properties Analysis &Characterization of Near-Wellbore Hetero-geneity interpretation program computes avalue of safe underbalance based on themechanical properties of the formation esti-mated from sonic and density logs. Local

1.69 in. 3.79 in.

Deploymenthead

9 shotsper foot

Run in Hole Deployed

nThe Pivot Gun system in the run-in anddeployed positions. Charge performancein surface tests exceeds that of most cas-ing guns—25-in. [64-cm] penetration and0.33-in. [8-mm] entrance hole diameter inan API RP-43 section 1 target (see footnote4). Shot density is fixed at 4 shots/ft with180° phasing. The Pivot Gun system givesthe deepest possible penetration whenperforating through tubing. The mainlimitation is the maximum gun length of10 feet [3 m]. It is rated to 330°F [165°C]and 12,000 psi.

9. Berhmann LA, Pucknell JK, Bishop SR and Hsia T-Y:“Measurement of Additional Skin Resulting fromPerforation Damage,” paper SPE 22809, presentedat the 66th SPE Annual Technical Conference andExhibition, Dallas, Texas, USA, October 6-9, 1991.Hsia T-Y and Behrmann LA: “Perforating Skin as aFunction of Rock Permeability and Underbalance,”paper SPE 22810, presented at the 66th SPE AnnualTechnical Conference and Exhibition, Dallas, Texas,USA, October 6-9, 1991.

10. Bell WT: “Perforating Underbalance—Evolving Tech-niques,” Journal of Petroleum Technology 36 (Octo-ber 1984): 1653-1662.King GE, Anderson A and Bingham M: “A FieldStudy of Underbalance Pressures Necessary toObtain Clean Perforations Using Tubing-ConveyedPerforating,” paper SPE 14321, presented at the 60thSPE Annual Technical Conference and Exhibition,Las Vegas, Nevada, USA, September 22-25, 1985.

11. King et al, reference 10.

experience also helps guide the selection ofoptimal underbalance.

Overbalance perforating still has a role,however. Often significant are its speed forshort intervals and the availability of larger,high shot density guns compared to thosefor through-tubing underbalance perfora-tion. The selection of overbalance versusunderbalance rests on weighting economicversus production variables.

A long-recognized disadvantage ofthrough-tubing gun systems is their trade-offbetween phasing and depth of penetra-tion—either 0° phasing with good penetra-tion, or improved phasing with less penetra-tion because of smaller shaped charges(previous page). A recent innovation thataddresses this problem is the Phased Enerjetgun, which provides two rows of charges at

October 1992

90° phasing. A second is the Pivot Gun sys-tem, which delivers casing gun performancewith 180° phasing but can be run throughdiameters as small as 1.78 in. To do this, thegun is inserted into the tubing with thecharges aligned along the axis of the gun.Once in casing, a deployment head is usedto rotate charges 90° to the firing position.The charges then reach the full 3.79-in.outer diameter (left ). In case of a misrun,each pivot charge assembly is designed tobe broken, returning the gun to its original1.69-in. diameter. This allows retrieval ofthe gun with deployed charges. Only thedeployment head is recovered after success-ful perforation; the carrier and fired chargesbecome debris that settles to the bottom ofthe well.

The Stimulated Completion—Getting Morefrom LessStimulated completions fall into two cate-gories, acidizing and hydraulic fracturing(see “Stimulated Completion,” next page).Occasionally, the two are combined in anacid-frac, which improves productivity byusing acid to etch surfaces of hydraulicallyinduced fractures, preventing full closure.

Success of stimulation depends largely onhow well the perforation allows delivery oftreatment fluids and frac pressures into thereservoir. Because these fluids and pressure-induced fractures are intended to movebeyond the perforation, shot phasing, den-sity and hole diameter are of higher prioritythan depth of penetration. Underbalanceperforating is often used because cleanerperforation tunnels give fluids more directpaths to the reservoir. In some cases, such asTCP with high shot density guns, underbal-ance can be increased to where stimulationis not required to improve productivity.11

However, stimulated reservoirs are usuallyof low permeability, greatly limiting thesurge available to clean the perforations.Further increases in underbalance mayachieve no improvement in cleaning.

When stimulating long intervals—oftenconsidered more than 40 or 50 feet [12 to15 m]—or multiple zones, the perforationstrategy may change. Delivering treatmentfluid to all perforations may be difficult.Once fluid enters a zone of higher perme-ability, a path is established that preventsstimulation of zones of lower permeability.Here, limited entry perforating can help. Bymaking a lower number of perforationsthroughout the zone, stimulation can beapplied more uniformly across zones ofvarying permeability. High-permeabilityzones may take more fluid than low-perme-ability zones, but because there are fewer

holes, a high enough pressure can be main-tained to encourage treatment of low-per-meability zones. After stimulation, perfora-tions are often added to optimally producethe zone.

Uniformity of perforation diameter isessential to accurately determine the cumu-lative area of the casing entrance holes.Knowing this area and pumping pressureallows calculation of flow rate into the for-mation, needed to monitor progress of thestimulation. Uniformity and smoothness ofperforation diameter also provide consis-tently sized seats for ball sealers. These areballs of nylon or hard rubber pumped totemporarily block perforations with highfluid intake, thereby diverting injection.

Limited entry perforating is usually donevia wireline. The Selectric system isdesigned specifically for this application. Itconsists of any number of short (1-foot [30-cm]) single-shot guns fired selectively fromthe bottom up, providing uniform entryholes. Unlike other systems, in which a mis-fire terminates the operation, this system haselectrical switches, rather than mechanicalswitches, between guns. These allow firingthe next gun even when there is misfire.

Perforation plays a key role in the successof hydraulic fracturing. Hydraulic fracturinghas two main steps: fracture creation byapplication of pressure, and injection offluid carrying proppant, which holds openthe fractures to allow production (see“Cracking Rock: Progress in Fracture Treat-ment Design,” page 4). Once the fracture iscreated, perforations provide the entrance tothe fracture for the proppant. Perforationdiameter must be sufficient to prevent“bridging,” accumulation of proppant thatblocks the entrance hole, preventing furthertreatment. To quantify causes of bridging,Gruesbeck and Collins performed experi-

63

64 Oilfield Review

Stimulated CompletionPerforation Technique Selection

No

No

No

Are uniform and circularentrance holes a high priority?

andIs 12-in. API section 3penetration acceptable?

Is limited entry perforatingrequired?

Is the well ≤ 4000 psi, < 210°F [99°C]?

Port plug guns

Port plug gunsSelectricsystem

HEGS

Yes

Yes

Yes

Yes

Select correctdiameter of scallopor high shot densitygun compatiblewith downholerestrictions; selectphasing and shotdensity.

It is undetermined whether the well needs stimulation. Could underbalance perforating eliminate the need for stimulation?or

Stimulation is required. Is any added operational complexity of underbalance perforating justified by the likely improvement in well cleanup and stimulation?

No

No

Exposed guns

Through-tubing guns(wireline conveyed)

•Will gun or charge debris be a problem for downhole equipment?

or•Are more than two zones to be perforated selectively?

Will perforation be performed through workstring?

Perforate overbalance.Perforate underbalance(see underbalance perforatingin Natural Completionflowchart).

NoYes

NoYes

No

Select correct diameter high shotdensity gun compatible withdownhole restrictions; selectphasing and shot density.

Casing guns(wireline conveyed)

Wirelineconveyed

Tubingconveyed

Yes

Yes

Will stimulation benefit from high shot density or reduced phase angle?

Is well deviation ≥ 60° or is theinterval long enough to justifyrunning on tubing?


aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aa aaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa aaaCasingWellbore

Hydraulic fracturenormal to least

stress

Area offlow restriction

60° phasing-never > 30° fromfracture

Channel to fracture wings

0° phasingperforatiion

nThe importance of shot phase angle to maximizing communi-cation between perforations and stimulated fractures. Studies offracture and perforation orientations show that for optimumwell productivity, the two lie within 30°, preferably 10°. Thisminimizes fracture initiation pressure and the length of thechannel between the perforation and fracture wings, andincreases the likelihood the fracture will initiate along a perfora-tion. Perforating guns with small phase angle and high shotdensity achieve this optimum angle most effectively. The figureshows that a 0° phasing could place the perforation far from thefracture, which initiates along the plane normal to the leaststress. But in reality, wells to be fractured are often perforated

ments to determine the minimum allowableratio of perforation diameter to proppantdiameter for varying proppant concentra-tions12 (below). They found that the perfora-tion must always be at least twice the prop-pant diameter. When perforation diameter isat least six times proppant diameter, prop-pant concentrations can increase withoutrisk of bridging.

A number of studies have investigated therelationship between perforation phasingand the development of hydraulic fractures.In general, hydraulic fractures propagatenormal to the minimum stress in the portionof the reservoir undisturbed by the presenceof the wellbore. The general conclusion isthat for an ideal fracture job, perforationsare aligned with the maximum stress direc-tion, so fractures extending from the perfo-ration will lie in the plane that has the leastresistance to opening. Methods for align-ment of perforations with hydraulic fracturesare still under investigation. A method indeviated wells was reported by Pearson and

12. Gruesbeck C and Collins RE: “Particle TransportThrough Perforations,” paper SPE 8006, presented atthe 3rd Symposium on Formation Damage Controlof the SPE of AIME, Lafayette, Louisiana, USA,February 15-16, 1978.

13. Pearson CM, Bond AJ, Eck ME and Schmidt JH:“Results of Stress-Oriented and Aligned Perforatingin Fracturing Deviated Wells,” Journal of PetroleumTechnology 44 (January 1992): 10-18.

14. Daneshy AA: “Experimental Investigations ofHydraulic Fracturing Through Perforations,” Journalof Petroleum Technology 25 (October 1973): 1201-1206.

15. Warpinski NR: “Investigation of the Accuracy andReliability of In-Situ Stress Measurements UsingHydraulic Fracturing in Perforated Cased Holes,”Proceedings—Symposium on Rock Mechanics 24(1983): 773-786.

16. Behrmann 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.

17. Nolte KG: “Application of Fracture Design Based onPressure Analysis,” SPE Production Engineering 3(February 1988): 31-42.

18. Screenout occurs when the fluid carrying proppant islost to the rock matrix, interrupting fracture growth.It results in rapid increase in pumping pressure.

Tap water100-cp HEC solutionP

erfo

ratio

n di

amet

er/

aver

age

part

icle

dia

met

er

Maximum particle concentration, vol/vol

Bridging region

No bridging region

Maximum gravel content, lbm/gal

0 0.15 0.27 0.58

0

2

4

6

8

10

0 2 4 6 8 10 30

nImportance of selecting perforationentrance hole diameter to prevent bridg-ing of proppant in the perforation. Toavoid bridging, the ratio of the perfora-tion diameter to average diameter of theproppant must lie above the curve.These are data for tap water and car-boxymethyl hydroxyethyl cellulose (HEC),a water-based polymer. (After Gruesbeckand Collins, reference 12.)

with guns of 60° phasing or less (dashed lines). This means theperforation is never more than 30° from the fracture. (See Warpin-ski, reference 15.)

colleagues.13 Alignment of 180° phasedshots with the known fracture planereduced perforation friction and signifi-cantly improved fracture treatment. Gunswere aligned by mounting them on bearingsthat allowed rotation. Gun angle was con-trolled by a steering tool or, on TCP jobs,with a weighted half-cylinder that seeks thelow side of the hole. This practice, however,is not widespread. The most practical wayto approach this today is by perforating witha phase angle that increases the likelihood

October 1992

of having shots parallel to the induced frac-ture plane.

Laboratory experiments by Daneshy showthat fracture initiation pressures are higherwhen the fracture and perforation are notparallel and do not intersect.14 Later,Warpinski reported that hydraulic fracturesmay not lie in the same plane as the perfo-ration.15 This observation was based on in-situ mineback experiments in which a shal-low, perforated wellbore was excavated tosee how the fracture propagated. Warpinskialso found that if the perforation and mini-mum stress planes differ by more than 30°,the fracture may initiate in a plane differentfrom that of the perforation. This indicatesthe phase angle should be 60° or less so theperforation is always within 30° of a frac-ture. Minimum phasing of 60° is further sup-ported by recent work of Behrmann andElbel, who showed that minimum fractureinitiation pressure and maximum fluid com-munication between perforations and frac-tures are achieved by minimizing “annularflow”—slurry traveling an annular patharound the casing to communicate with thefracture.16 This occurs when the fractureplane and perforation lie within 30°, prefer-ably 10° (top). Nolte17 previously pointed outthat if the hydraulic fracture does not initiateat the perforations, annular flow may causepremature screenout18 and asymmetric pen-etration of the fracture wings.

65

Standoff as a percent of gun diameter

45°Gunpositioned

in casing

Casing

Nor

mal

ized

ent

ranc

e ho

ledi

amet

er, %

0

40

80

120

0 10 20 30

nCross section of a gun in casing (top) andthe effect of gun/casing standoff on entrancehole diameter for a bighole charge.

The Sand Control Completion—Home ofBig HolesSanding is a problem in weak or unconsoli-dated sandstones. The objective of a sandcontrol completion is to eliminate sandingwhile maintaining a production rate that iseconomic, minimizes reservoir damage andthus maximizes recovery. Near the well-bore, sand movement can reduce perme-ability locally. Produced sand can erodedownhole and surface equipment and itsremoval can be costly. In sufficient quanti-ties, sand can plug the completion or sur-face facilities.

An objective of perforating in these highlyproductive and often unconsolidated sandsis to reduce the near-wellbore pressure gra-dient during production (see “Sand ControlCompletion,” next page). There are twoschools of thought on the best way do this.The established method is to perforate in away that takes advantage of protectionafforded by subsequent gravel packing. The-oretical studies show that perforation geom-etry can sometimes be optimized to obviategravel packing.19

For gravel packing, many large-diameterperforations are preferred to few smallholes. This is because larger holes provide alarger area open to flow and therefore lesspressure drop on production. To achievethis, perforators producing large diameterholes and high shot density are used. A uni-form shot distribution further reduces forma-tion stress in addition to preserving casingstrength (below). Because of the high pro-ductivity of the reservoir, deep penetration is

66

Rem

aini

ng c

asin

g st

reng

th

1

0.9

0.8

0.7

0.6

0.5

0.4

0.30 0.25 0.5 0.75 1.0 1.25 1.5

Entrance hole diameter, in.

• 5 shots per foot, 60° phasing• 6 spf, 60° phasing• 12 spf, 135° phasing• 12 spf, 120° phasing• 12 spf, 120° phasing

nRelationship between perforationentrance hole diameter and phasing oncasing strength. The 135°/45° phased HSDguns achieve the greatest area open to flowwhile maintaining maximum casingstrength. Here, casing strength is normalizedto 1, the strength of unperforated casing.

a lower priority. Depth of penetration is suf-ficient if it assures good communicationwith the reservoir.

To create large, clean perforation tunnels,these wells are typically shot underbalancewith TCP using high shot density guns. Theideal underbalance will sufficiently cleanperforation tunnels without breaking downthe formation. Sand control could perhapsbe provided by maintaining productionrates low enough to prevent collapse of theperforation tunnel’s stable arch—interlock-ing grains, like a keystone arch over a door-way. But such a low production rate is gen-erally uneconomical and arches areunstable when flow conditions change.Instead, the arch is usually stabilized by fill-ing the perforation with gravel (see “SandControl: Why and How?” page 41).

In gravel packing, a wire-wrapped screenor slotted liner is positioned along the perfo-rated interval. A slurry of thickened brinecarrying gravel of closely controlled size ispumped downhole. The gravel fills the per-foration tunnels, creating a “pack.” One keyto tightly packing the perforations is use of afluid that rapidly leaks off into the perfora-tions so the gravel slurry continues flowinguntil the perforation is completely full. Thisslurry is followed by an additional slurry tofill the screen-casing annulus with gravel.The pressure drop during production cannow be distributed across both the near-wellbore area and the gravel pack, whichhelps to reduce stress at the formation.

Clearance between gun and casing has asignificant effect on entrance hole size ofbig hole charges (see “A Perforation Glos-sary,” page 57). Adverse effects of standoffare much less for deep penetrating charges.Running the largest gun size practical for thewell casing provides entrance holes thatminimize the differential pressure across for-mation and pack (left).

Optimizing Perforation Operations—Envi-ronment and SafetyEach perforating system has ratings intendedto ensure safety and minimize operatingrisk. Foremost are ratings for maximum andminimum pressure and “time-at-tempera-ture”—the duration of exposure at a giventemperature. The time-temperature rating isdetermined by the explosive material,which degrades at elevated temperaturesand extended exposure times. This degrada-tion results in a loss of sensitivity—leadingto a potential misfire—and loss of strength—leading to reduced charge performance.Today’s ratings have been established byboth laboratory tests and extensive fieldexperience.

The most common explosives in currentuse are cyclotrimethylene trinitramine, RDXfor short, and cyclotetramethylene tetran-itramine, HMX for short. When conveyedby wireline, RDX is limited to exposure of 1hour at 330°F [166°C], or when tubing con-veyed, to 100 hours at 200°F [93°C]. Simi-larly, HMX survives 1 hour at 400°F[204°C], and 100 hours at 300°F [149°C].At higher temperatures or longer exposures,explosives and special elastomers and lubri-cants are available to perforate reliably at upto 500°F [260°C] for wireline-conveyedapplications and up to 460°F [238°C] forTCP. Explosives for high temperatures,called HNS and PYX, are much more expen-sive and generally stocked only in areaswhere high-temperature wells are common.

It is generally recognized that guns have amaximum pressure rating. Exceeding thisvalue can cause the gun to collapse or fluidto enter, possibly splitting the gun and stick-ing it in the casing if detonation occurs. Lesswell-recognized are gun limitations whenperforating in gas. Not all guns that can befired in a liquid-filled borehole can toleratethe higher shock associated with firing in agas-filled borehole, which lacks the damp-ing effect of wellbore fluid. Some guns must

Oilfield Review

Sand Control CompletionBig Hole Perforation Technique Selection

No

No

No

Wireline-conveyed guns.Select TCP firing systemand accessories.

Select largest high shotdensity gunsrecommended forcasing size.

To minimize risk ofsticking guns, selectguns of reduceddiameter.

Select largest high shot density guns recommended for casing size.

Yes

Yes

Yes

Select TCP firing system and accessoriesto integrate with DSTstring.

Select TCP firingsystem andaccessories to provideperforation surging.

Does improvement in well cleanup from underbalance perforating justify added complexity?

Surge Perforation(Brief, high-intensity flow toclean perfs; no rateinformation collected.)

Drillstem test

Are downhole pressure/flow rate measurementsrequired?

Is well deviation ≥ 60° or is the interval long enough to justify running on tubing?

Perforate underbalance with high shot density gunsand big hole charges

(tubing conveyed).

Perforate overbalance with high shot density guns and big hole charges

(tubing conveyed).

NoYes

Is a significant amount of sand production expectedregardless of underbalance choice?


be supported by liquid at atmospheric pres-sure or higher. Special carriers are availablefor some guns for use in gas and high-pres-sure settings.

Although perforating guns are sometimesexposed to hostile environments, ratings arerarely specified. The reason is both practicaland technical. A hostile environment com-

October 1992

prises many variables—wellbore tempera-ture, pressure, hydrogen sulfide [H2S], treat-ment acid, carbon dioxide [CO2], durationof exposure and stress during exposure. Notall can be quantified to determine if seriousrisk exists. Because of the demands of perfo-rating, hardware must be robust and of highquality steel, well suited to hostile environ-ments. For wireline-conveyed guns, expo-sure time is minimal. In TCP, where gunsand accessories may be exposed for an

extended period, H2S-resistant accessoriesare available.

Each perforating system has a number offeatures, often redundant, to ensure safe

19. Santarelli FJ, Ouadfel H and Zundel JP: “Optimizingthe Completion Procedure to Minimize Sand Pro-duction Risk,” paper SPE 22797, presented at the66th SPE Annual Technical Conference and Exhibi-tion, Dallas, Texas, USA, October 6-9, 1991.

67

nA variation of the monobore completion,using a permanent packer. Monoborecompletions are most common in theNorth Sea and Venezuela.

68 Oilfield Review

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aa aaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaa a a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa aaaaaaaaWireline latch/anchor setting

tool

Safety spacer

High shotdensity gun

Anchorgripping

casing

wellsite operations. Guns themselves con-tain only secondary explosives (charges,detonating cord, boosters) and are armedwith the primary explosive (detonator) justprior to running in the well. This allows forsafe loading and handling. Guns are com-monly transported to the wellsite loaded, butarmed only just before being run in the hole.Firing assemblies are designed to protect thedetonator and position it to initiate the deto-nating cord. In the event guns are retrievedunfired, disarming is simple and may beperformed immediately.

In wireline-conveyed perforating, electri-cal detonators are used, fired by applyingpower from surface. The detonators are dis-abled if fluid floods the gun, preventingaccidental detonation.

Surface equipment is shut off andgrounded prior to running and pulling theguns, eliminating accidental application ofpower. In addition, radio transmission,welding and cathodic protection systemsare shut down to eliminate possible strayvoltages. This requirement can be a seriousoperational limitation, for example, elimi-nating radio communication to offshoreplatforms. To safely overcome this limita-tion, the S.A.F.E. Slapper Actuated FiringEquipment system has been developed.20 Inthe S.A.F.E. system, a special initiator is usedthat fires only from a very high voltage pulseof short duration—a pulse not produced byroutine rig operations. The S.A.F.E. initiatorcontains no primary explosive and initiatesonly from a specific signal from surface.

TCP has safety features common to manyother techniques. In Schlumberger systems,firing heads are connected to the top of thegun string with a blank interval of at least 10feet [3 m] above the top shot. This allowsarming of guns only after the charges arebelow the rig floor, away from personnel.Firing pins require a minimum of 150 to300 psi to drive into detonators, ensuring nopossibility of firing until below surface.

The Trigger Charge Firing system allowsrunning and positioning the TCP guns in thewell with no detonator. The firing head issubsequently run on wireline. This providesadditional safety while running the guns andretrieving the firing head prior to pullingmisfired guns.

New Completion Methods—Access for BigGunsEfforts of well operators to be more cost-effective have led to variations in comple-tion techniques, and concomitant innova-tions in perforating. A completion that hasgained popularity in the North Sea andVenezuela is called the monobore. As thename implies, a monobore completion hasa production string of uniform diameter,from the reservoir to surface. Casing is setwell above the reservoir, up to half the welldepth. Then, a smaller diameter hole isdrilled to total depth and a long liner run(Liner is any casing that doesn’t reach sur-face). Once the liner is set, production tub-ing of the same diameter as the liner is runand engages a sealing assembly on top ofthe liner. The well now has a “monobore,”with the liner serving as both casing, provid-ing protection, and as tubing, conveyingproduction. This approach has the advan-tage of requiring a less expensive, smallerhole with lower tubular costs, yet provides alarge-diameter production string. The well isthen perforated with high shot density guns,either wireline conveyed or anchored in theliner after running on wireline or tubing.The guns are then dropped, either automati-cally upon firing or mechanically via a wire-line trip.

Variations of the monobore technique arealready in use. One is to set a permanentpacker on production tubing at the top ofthe liner with guns suspended below (left).This allows use of the largest possible highshot density guns, while retaining the eco-nomic advantage of the monobore tech-nique. Underbalance is established and awireline assembly is then run in and latchedto the guns, which are lowered to targetdepth. They are set using an anchor thathangs them in the casing. The wireline isthen pulled out and the guns fired by pres-sure actuation. The guns are then released

20. Huber K, Pousset M and White D: “New Technol-ogy for Saving Lives,” Oilfield Review 2, no. 4(October 1990): 40-52.

nHigh shot density guns run below awireline-set packer. This permanent com-pletion allows underbalance perforatingwith the largest possible diameter guns ina permanent completion. Guns are usu-ally dropped after firing.

nA dual-string completion that allowsunderbalance perforating of both strings.In this instance, the lower zone is perfo-rated with high shot density gunsstabbed through a packer. The upperzone is perforated with high shot densityguns suspended below a dual stringpacker. These guns are loaded and ori-ented to perforate the half of the casingopposite the adjacent long string.

69October 1992

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aa aaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaa a a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa aaaaaaaaWireline

Casing collarlocator

Permanentpacker

Productionports

High shotdensity gun

Wirelinepressuresetting tool

Firing headaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aa aaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaa a a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa aaaaaaaaDual stringpacker

Oriented highshot density

guns

High shotdensity guns

Casing

Productionports

as in the standard monobore method, eitherautomatically or by wireline trip. In perforat-ing long intervals, where gun string weightexceeds the wireline limit, the guns can berun and anchored in the monobore prior torunning the permanent packer and produc-tion tubing.

Another type of completion allows largerdiameter guns than could be stabbedthrough a permanent packer or run throughtubing (left). To achieve this, a permanentpacker is set on wireline, with high shotdensity guns suspended below. Then, tubingis run, underbalance established and theguns fired and dropped.

A third perforation system is used for dual-string completions—two tubing strings runadjacent to each other to isolate productionfrom two zones (right). This allows under-balance perforating of the upper intervalwithout killing the well prior to production.

Developing a perforation strategy involvesanalyzing the reservoir using all data avail-able to design the job for the anticipatedconditions. A common pitfall is to bypassthis process, repeating what is consideredtried and true or what worked last time. Thisresults in some wins and some losses. Thebest approach is to arrive at a perforationstrategy by combining both field and operat-ing experience. Only this approach allowsthe operator to duplicate what went right inprevious jobs, avoid repeating mistakes, andtest new techniques that hold promise.

—JMK

a

70

F O C U S

In oil exploration, knowing where you are plays just as

important a role as knowing where the oil is. For posi-

tioning and navigation data, explorationists are now

looking skyward toward an orbiting constellation of satellites

to execute seismic surveys, position rigs and locate machinery.

The Navstar Global Positioning System (GPS), introduced

in 1983 as a tool for enhancing US military capabilities, is a

satellite-based radio navigation system (next page, top).

When fully operational at the end of 1993, GPS will comprise

24 satellites, including three spares, each orbiting the earth

every 12 hours at an altitude of 20,200 km [12,500 miles].

Equipped with four atomic clocks, each satellite broadcasts

precise time, satellite position and condition data 24 hours a

day. At least five satellites will be visible to users anywhere

in the world. So far, 18 satellites are in orbit.

The fundamental measurement of GPS is the time

required for a signal to travel from a satellite to the

receiver—often a portable, hand-held device—which gives

the satellite-receiver distance. Measurements collected

simultaneously from four satellites, each distinguished by a

unique code, are processed at the receiver to determine in

real time the receiver’s longitude, latitude, altitude and veloc-

ity, if the receiver is moving. Error is 3 to 100 meters [10 to

330 feet], depending on the amount of error correction

applied during processing and type of signal being processed.

GPS is not the first satellite-based system used for navi-

gation. The Transit system, developed by the US Navy in

1960, contained fewer satellites in tighter orbits. To calculate

a position with Transit, a receiver measured the Doppler

effect, or frequency shift, detected in signals emitted by a

satellite of known trajectory. Errors were as high as 150 m

Talking Satellites

[490 ft] and Transit provided a fix only about once an hour to

locations near the equator.

Throughout the transportation industry, research is under-

way to harness GPS for managing air traffic, train routing,

and ship navigation, for dispatching delivery truck fleets and

reducing gridlock. Scientists use GPS to track continental

drift (using sophisticated analysis techniques), predict earth-

quakes and monitor changes in the atmosphere caused by

the greenhouse effect. For oil patch applications, GPS is

more accessible, more accurate and less expensive than

conventional land-based radio navigation systems.

Accessibility to GPS is worldwide and continuous—a

boon to underdeveloped areas and far offshore regions

where no other effective system exists. GPS can accommo-

date an infinite number of users whereas land-based sys-

tems used in marine seismic restrict the number of users.

For oil exploration, most of the cost savings from GPS

stem from its global coverage. Crews on land conducting a

seismic survey or positioning a rig must sight between sur-

vey points, which often requires massive and costly clearing

of vegetation. GPS demands only enough clearance to view

the satellites from each survey point. In marine seismic, the

operator frequently foots the expense of establishing the

navigation chain, operating it and demobilizing equipment

when the survey is completed. Even in locations with a land-

based system in place, operators rely on time-consuming

and costly licensing negotiations with local authorities.

With conventional radio navigation, operators at the start

of a survey install job-specific equipment that takes at least a

day to calibrate and verify. GPS receivers, once installed, are

permanent, and calibration and verification takes minutes.

Conventional radio navigation may also be limited by inter-

Oilfield Review

The GPS system, with world-wide, continuous coverage,provides useful navigation andpositioning data for land andmarine seismic operations.

DGPS improves the accuracyof GPS measurements bycomparing the known coordi-nates of a nearby referencewith its GPS fix.

ference from nearby vessels and aircraft, the shape of the

shoreline, elevation of onshore beacons and vegetation that

deflects signals. These limitations are absent from GPS.

The global accessibility of GPS proves a double-edged

sword to the originator of the system, the US Department of

Defense (DOD). To maintain US military advantage with GPS,

DOD offers two GPS services: precise positioning service

(PPS) and standard positioning service (SPS). PPS signals

can fix a position to within 10 m [33 ft], but are encrypted to

prevent unauthorized access. Only users who satisfy national

security requirements have access to PPS signals. The SPS

signals, on the other hand, are available to everyone but

have been degraded through a technique known as selective

availability (SA). With SA activated, accuracy plummets an

order of magnitude to 100 m, unacceptable for surveying

and marine navigation.

SA limitations can be circumvented, however, by a tech-

nique called differential GPS or DGPS, first developed in the

late 1980s by scientists studying the shape of the earth

(above, right). DGPS compares known coordinates of a

71October 1992

Placement of GPS receiverson a marine seismic surveyand (inset) a GPS receiver ona front buoy.

Tail buoy

GPS receiverMagnetic compass

Frontbuoy

Air gunarray

nearby fixed reference receiver with the receiver’s GPS fix.

The error from the GPS signal can then be transmitted to the

user, who applies the corrections to the received signals or

computed position. In the North Sea, for example, compa-

nies offering DGPS services claim an accuracy of 3 to 5 m

[10 to 16 ft] at distances up to 2000 km [1240 miles] from a

reference station.

Much controversy surrounds the continued US enforce-

ment of SA, especially during peacetime. Civilian users point

to the success of DGPS and the development of a similar

satellite system by the former Soviet Union called GLONASS.

However, SA is here to stay as long as the current GPS sys-

tem affords the US and its allies a military advantage, even

by forcing hostile nations to develop DGPS capabilities.

From an oil industry perspective, DGPS would be utilized

with or without SA to meet the stringent positioning require-

ments of seismic surveys (accuracy to within 5 m).

The most elaborate use of GPS in oil exploration is marine

seismic, which marries the new technology with conven-

tional navigation and positioning techniques. During a sur-

vey, GPS receivers may be located on the survey vessels, the

front buoys and the tail buoys (right). Satellite-to-vessel and

satellite-to-buoy ranges are computed to derive the position

of the front and tail buoys relative to the vessel. Acoustic

positioning devices called transponders are located on the

survey vessels, source arrays, streamers and tail buoys. (Tran-

sponders are still needed because GPS receivers do not oper-

ate underwater.) The position of the transponder relative to a

survey vessel or buoy is determined by measuring the time

it takes acoustic pulses emitted from one transponder to

reach another. In addition, laser ranges measure the distance

between the vessel and source arrays, and compasses

spaced along each cable monitor the streamer shape.

Typically, a backup positioning system is desired in a

marine seismic survey in case the primary one fails. Conse-

72

quently, DGPS will not replace, but rather integrate with,

existing systems. Use of DGPS as a primary positioning sys-

tem has grown in the North Sea because its greater reliability

minimizes the risk of operational failure. Improving software

that can integrate DGPS data with existing measurements

will secure the cost savings promised by the new technology.

—TAL

Acknowledgements and Further Reading

For help in preparing this focus, thanks to Erik Vigen,GECO-PRAKLA R&E, Sandvika, Norway and BruceKing, GECO-PRAKLA, Stavanger, Norway.For further reading:Jensen MHB: “Quality Control for Differential GPS inOffshore Oil and Gas Exploration, ” GPS World 3, no.8 (September 1992): 36-48.

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