SPE-106051-MS_Hydraulic Fracturing Down Under

8/20/2019 SPE-106051-MS_Hydraulic Fracturing Down Under

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Copyright 2007, Society of Petroleum Engineers

This paper was prepared for presentation at the 2007 SPE Hydraulic Fracturing TechnologyConference held in College Station, Texas, U.S.A., 29–31 January 2007.

This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to an abstract of not more than300 words; illustrations may not be copied. The abstract must contain conspicuousacknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

AbstractThis paper reviews the fracturing history in the Cooper Basinand summarizes the results of over 650 fracturing treatmentscharacterised by high tectonic stresses, high fracturing pressures, high reservoir temperatures, and stacked reservoirlithologies of sands, shales, and coals. Initial treatmentstargeted multiple moderately high permeability (1-10 md)

formations, while multi-staging operations are now targetingsingle, less extensive, lower quality reservoirs. The paper

discusses the techniques used for predicting and designing fornatural fracture leakoff, high near wellbore pressure losses andhigh fracture gradients. It shows the changes in fracturingideologies and how they have altered the completion

strategies, predicted fracture geometries, fracturing materials,treatment schedules, and post-frac production.

IntroductionHydraulic fracturing began in the Cooper Basin in 1968 andhas been a critical technology in the development of its gasand oil reserves. Although fracturing has been usedextensively in other regions of Australia such as the small to

medium sized oil fields of the Eromanga Basin in CentralAustralia and the Coalbed regions of Eastern Australia, this paper is focused on the fracturing experience in the moreextreme conditions of the Cooper Basin.

Cooper Basin Description. The basin is a Late Carboniferousto Middle Triassic, non-marine sedimentary environment,which underlies the desert region of Eastern-Central Australia(Figure 1). It is characterised as fluvio-lacustrine, with finingupward sandstones, siltstones, interbedded shales and coals.Deposition varies between braided and meandering fluvial

sands & alluvial fans, distributary channels, and crevassesplays

1.

Perth Adelaide Sydney

Brisbane

Hobart

Melbourne

Alice Springs

Darwin

1000 km

Perth Adelaide Sydney

Brisbane

Hobart

Melbourne

Alice Springs

Darwin

1000 km

Figure 1 - Location of Cooper Basin (Blue) and Overlying

Eromanga Basin (Green)

The basin is the primary on-shore producing area in

Australia for natural gas, while also producing significant oiland LPG. It extends over a region of 50,000 sq. miles (130,000km

2) and contains over 120 separate gas fields and 10 oil

fields. Production from Cooper Basin reservoirs is presently600 MMscf/day from 700 gas wells and 2,500 bopd from 50oil wells. Estimates for recoverable oil and gas reserves are

43.9 MMstb and 8.2 tcf, with remaining reserves (as of 1998)of 14.8 MMstb and 3.6 tcf 1. Reservoir depletion effects on

fracturing can be significant and will be presented later in the paper.

A graph of the basement depth structure is presented inFigure 2 and shows the major basin details and fractured welllocations. The primary features are the Nappamerri Troughthat is located in the middle of the basin and the various ridges

that surround the Trough. Most of the significant fields arelocated on the North-West, South, East, and North-East ridges.

Previous publications have been written concerning theTirrawarra field

2-3 which is located in the North-West ridge

and the Kurunda Field4 which is located in the South-East

ridge. Other publications describe general basin reservoircharacteristics and/or fracturing behaviour 5-12.

SPE 106051

Hydraulic Fracturing Down

Under J.M. McGowen, Halliburton, and J.V. Gilbert and E. Samari, Santos Ltd.


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2 SPE 106051

100 km100 km

Figure 2 - Cooper Basin Structure with Fractured Well

Locations

The primary reservoir units are Permian sandstones; theTirrawarra, Patchawarra, Epsilon, Daralingie, and Toolachee.A general stratigraphic column is presented as Figure 3;however variations exist that may include regional erosion ofthe Epsilon, Daralingie, and/or Toolachee formations. Mostwells contain between 5 and 15 sandstone reservoir units witha total gross thickness of 500-2,500 ft. The sandstone units

range in depth from 7,000 to 10,500 ft and have highgeothermal gradients of 2.0-3.4 deg F/100 ft. Initial reservoir pressures are normally pressured (~0.44 psi/ft), with a fewexceptions with slight overpressures (up to 0.52 psi/ft)observed in some isolated deeper fields and overpressures up

to 0.7 psi/ft in the Nappamerri Trough exploration wells.Large tectonic stresses produce maximum horizontal

stresses in the east-west orientation between 2.0-3.6. psi/ft 17.

This results in minimum horizontal stresses of 0.55-1.2 psi/ftand fracture gradients between 0.6-1.4 psi/ft. This impact ofthe stress regime on fracturing will be discussed in more detaillater in the paper.

Tirrawarra. The Tirrawarra is a 75-250 ft thick single fluvialsandstone package that is widespread across the basin. At thelower temperatures it is mainly a volatile oil reservoir, and

where temperatures exceed 300 deg F the reservoir is gas bearing. Gas properties vary from 12-30% CO2 and 3-65 bbl

condensate per MMscf, while the volatile oil has reservoirviscosity of ~0.1 cp. Miscible gas flood projects have been performed on several of the volatile oil fields; however noneare underway at present. Fracturing has been used extensivelyin the past for stimulation of the Tirrawarra and accounts for

11% of fracturing treatments performed within the basin. Anexample log of the Tirrawarra formation in the Swan Lakefield (North-West Ridge) is included as Figure 4. Track 1shows Gamma Ray, Track 2 shows X&Y Caliper, Track 3shows resistivities with separation in yellow, Track 4 showssonic velocity, Track 5 shows gas and water effective porevolumes, Track 6 shows lithologies, and Track 7 shows 4%and 8% effective porosity pay flags.

Figure 3 – Cooper Basin Stratigraphic Column

One 150,000 lb treatment was performed on the reservoirsection highlighted in Figure 4 with the objective to stimulatethe majority of the interval height.

GR

GAPI0 300

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IN11 6

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9850

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m e t r e s

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V/V0 1

QUARTZ

V/V0 1

COALV/V0 1

4 % PAY

8 % PAY

Figure 4 – Example Log of Tirrawarra Formation

Patchawarra. The Patchawarra is the most significant gas

reservoir based on reservoir volume with gross thickness of300-1500 ft. Gas properties vary from 8-40% CO2 and 0.5-45 bbl condensate per MMscf. The Patchawarra is comprised of4-8 sandstone intervals with each interval


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SPE 106051 3

separated by siltstones and coals. The deposition is lacustrinedeltaic and floodplain, multistory fluvial channel, point bar,and crevasse splay. Reservoir permeability varies widely between 0.01-10 md, while fractured intervals have rangedfrom 0.01-2 md. Fracturing of this formation has becomemore common during the last 10 years (especially with newer

multi-staging techniques) and have accounted for 51% of all

fracturing treatments in the basin. Figure 5 shows an examplelog of the Patchawarra formation in the Swan Lake field(North-West Ridge). Log tracks are the same as for Figure 4.Three ~50,000 lb fracturing treatments were performed on thehighlighted sections.

GR

GAPI0 300

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IN11 6

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8 % PAY

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8 % PAY

Figure 5 – Example Log of Patchawarra Formation

Epsilon. If present, the Epsilon is a thin fluvio-deltaic andlacustrine shoreline sandstone interval that rarely exceeds 12 ftthick, with exceptions of 30-45 ft thickness in a few regions.It produces gas with condensate between 4-45 bbl/MMscf and8-24% CO2. Reservoir permeability varies between 0.1-10md, while the fractured intervals have ranged from 0.1-1 md.

Due to the poor reservoir thickness it only accounts for 5% of

all fracturing treatments. An example log of the Epsilonformation in the Coonatie field (North Ridge) is included asFigure 6. Log tracks are the same as for Figure 4. Two~50,000 lb treatments were pumped on the highlightedsections in this example targeting the lower and upper sands.

GR

GAPI0 300

CAL

IN11 6

CAL

IN6 11

9400

9450

DEPT H

m e t r e s

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OHMM0.2 2000

RT

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4 % PAY

8 % PAY

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IN11 6

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IN6 11

9400

9450

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m e t r e s

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OHMM0.2 2000

RT

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V/V0 1

QUARTZ

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COALV/V0 1

4 % PAY

8 % PAY

Figure 6 - Example Log of Epsilon Formation

Daralingie. If present, the Daralingie formation is a lacustrinedelta front bar, beach, and shoreface deposit. It is a thininterbedded sandstone surrounded by siltstone and coal and is5-22 ft thick, but can be as up to 200 ft thick in a few regions.

It produces gas with condensate between 2-45 bbl/MMscf and10-24% CO2. Reservoir permeability varies between 0.1-10md, while the fractured intervals have ranged from 0.1-0.5 md.Similar to the Epsilon, limited reservoir thickness has caused

the Daralingie to make up only 3% of all fracturing treatments.An example log of the Daralingie formation in the Big Lakefield (South-West Ridge) is included as Figure 7. Log tracksare the same as for Figure 4. One 50,000 lb fracture treatment

was performed on the highlighted section.

GR

GAPI0 300

CAL

IN11 6

CAL

IN6 11

7850

7900

7950

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m e t r e s

RS

OHMM0.2 2000

RT

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IN11 6

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m e t r e s

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QUARTZ

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4 % PAY

8 % PAY

Figure 7 - Example Log of Daralingie Formation

Toolachee. The Toolachee is comprised of a large number ofchannels and crevasse splay deposits. While average channel

thickness is 15 ft, the total gross thickness is 200-300 ft. The presence of the Toolachee is widespread across the basin and

contains 25% of the basin gas reserves. It produces gas withcondensate between 0.5-25 bbl/MMscf and 8-42% CO2.


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4 SPE 106051

The Toolachee consists of two units. The lower unit iscarbonaceous shale with interbedded sandstone and coals. Theupper unit is coarse-fine sandstone point bar and channelsandstone with interbedded shales and coals. Reservoir permeability varies between 0.2-50 md, while the fracturedintervals have ranged from 0.2-3 md. Treatments in the

Toolachee make up 30% of all fracturing treatments. An

example log of the Toolachee formation in the Big Lake field(South-West Ridge) is included as Figure 8. Log tracks arethe same as for Figure 4. One 100,000 lb fracturing treatmentwas performed on the highlighted sections with perforations in both sands.

GR

GAPI0 300

CAL

IN11 6

CAL

IN6 11

7600

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m e t r e s

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QUARTZ

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V/V0 14 % PAY

8 % PAY

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IN11 6

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7650

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m e t r e s

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OHMM0.2 2000

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V/V0.3 0

SHALE

V/V0 1

QUARTZ

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COAL

V/V0 14 % PAY

8 % PAY

Figure 8 - Example Log of Toolachee Formation

Fracturing History. Over 650 fracturing treatments have been performed in 400 wells within the Cooper Basin. Figure9 shows the yearly trend in the number of treatments, fracturedwells, and stages per well. While the number of treated wells

peaked in 2001 with 54 wells, the number of treatmentscontinues to rise and is now roughly 90 fracs per year with an

average of over 3 fracs per well.

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Figure 9 - Number of Wells and Fracs

Activity has been limited in scope annually due to lownatural gas prices in Australia, as compared to other

worldwide economies, mainly due to the overabundance ofother power sources (mainly coal), relatively small demand,and large infrastructure costs. The small demand has limited basin development and reduced subsequent fracturing activity.Several significant points affected the overall basindevelopment.

1963 - Discovery of first commercial gas in theMoomba field.

1969 - Gas sales to Adelaide via gas pipeline.1970 - Volatile oil discovered in the Tirrawarra field.1976 - Gas sales to Sydney via gas pipeline.

1982 - Sale of oil via oil pipeline to Port Bonython.1992 - Connection and gas sales from North-East

portion of the basin to existing infrastructure.1997 - Gas sales to Brisbane via gas pipeline.1998 - Gas sales to Mt Isa via gas pipeline.

Several changes in fracturing technology and applicationsoccurred during these phases of the basin development. These

developments centered on improvements in fracturing fluidsand proppants, expansion of fracturing into the volatile oil and

smaller gas fields throughout the basin, and improvedtargeting of treatments to more adequately stimulate the multi-layered intervals. To better describe these changes, thefracturing history will be separated into four sub-groups;“1968-1979 – Initial Fracs”, “1980-1995 – FracturingExpansion within the Basin”, “1996-2002 – Fracturing asStandard Practice”, and “2003-2006 – Target Fracturing”.

1968-1979 – Ini tial F racs. The first Cooper Basin fracturetreatment was conducted in 1968 and established fracturing asa viable stimulation technique. Five additional trials were

performed during this decade with all treatments within theMoomba field (South-East) and in the Toolachee formation

(with some Daralingie intervals also open in two wells). Thefirst three treatments used linear gels and placed ~60,000 lbs

of 20/40 sand, while the next three treatments were performedusing a Titanium crosslinked hydroxyl-propyl guar (HPG) geland placed larger amounts (100,000-240,000 lbs) of mostly10/20 sand. On four of the six treatments, ball sealers wereused to attempt to divert the treatment into multiple intervals(3-13 intervals open per treatment).

1980-1995 – Fractur ing Expansion wi thin the Basin . During

this 15 year period, a total of 106 jobs were performed asfracturing was extended throughout the major fields within the basin and into the Epsilon, Tirrawarra and Patchawarraformations. An expansion of fracturing technology was fueledduring the early 1980’s due to interest in enhancing oil production of the Tirrawarra field. Treatments in theToolachee/ Daralingie formations had 4-13 intervals open,

while treatments in Epsilon, Patchawarra & Tirrawarraformations had 1-5 intervals open. Treatments were performed

using Titanate crosslinked HPG gel and placed between50,000-150,000 lbs of 20/40 sand with tail-ins of ~30,000 lbsof 12/20 or 16/20 bauxite.

1996-2002 – Fractur ing as Standard Practice. A total of 290 jobs were performed as fracturing became an integral part of


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SPE 106051 5

new completions. Nitrogen assisted jobs (up to 30%) wereintroduced in 2000 for treating depleted formations, asfracturing was used to treat formations with as low as 1200 psireservoir pressure. Expansion of fracturing was also observedinto the North-East portion of the field. Treatments were stilldesigned to treat multiple intervals simultaneously and were

performed using Borate crosslinked HPG or Zirconium

crosslinked carboxy-methal-hydroxyl-propyl guar (CMHPG)gels at concentrations of 60-80 lb/Mgal. The use of sand as proppant was discontinued and treatments placed between100,000-200,000 lbs of 20/40 and 16/20 light weight ceramic proppants.

2003-2006 – Target F ractur ing. A total of 244 jobs were

performed as treatments became more focused with mosttreatments targeting single sands. A pivotal part of thisstrategy change was the introduction of annular coiled tubingfracturing, termed pin-point fracturing (PPF), in 2004.Treatments were still performed using Borate crosslinked HPGor Zirconium crosslinked CMHPG gels; however jobs were

performed with significantly reduced gel loadings and moreaggressive breaker schedules. As fracturing began targeting

smaller intervals, job sizes were reduced and treatments placed between 30,000-150,000 lbs of 20/40 and 16/30 ceramic proppants. As increases in near wellbore pressure losses andfracture gradients were observed, proppant types wereadjusted to use intermediate-strength and bauxite proppantswhen stress > 7000 psi for 20/40 and > 6000 psi for 16/30sizes.

Fracturing Statistics. Average well production response is presented as Figure 10 which shows a trend of decreasing well production per year for conventionally fractured wells,

especially in the last decade. Improved well responses have been observed with the introduction of PPF in the last 2-3years. The decreasing well production observed inconventional fracs was caused by depletion effects in the moreestablished fields and movement into more marginal areas.The production per well for the PPFs is significantly largerthan the conventional wells due to increasing the numbers of

treatments per well. Detailed discussion of the PPF results are presented by Gilbert and Greenstreet11 and Beatty ET al12, plus

a review of multi-staging strategies will be discussed later inthe paper.

The average well recovery for the fractured wells is presented in Figure 11 and shows a trend of decreasing wellrecovery per year. Estimated recoveries for years 2004-6 areapproximations based on initial rates due to limited productionhistory. The decreasing well recovery is caused by depletioneffects in the more established fields and the need to target

smaller, less extensive reservoirs. The impact of expandingmulti-staging operations is difficult to determine at this timedue to limited extended production time, however initial ratesare indicating that the multi-staging is developing roughlytwice the reserves per well.

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A v e r a g e P r o d u c t i o n ( M M s c f / d a y ) Conventional Fracs Pin-Point Fracs

Figure 10 - Average Production per Well

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Conventional Fracs Pin-Point Fracs

Figure 11 - Estimated Recovery per Well

A plot of the fracturing production increase for the

intervals with pre-frac production is presented in Figure 12.An average productivity increase of 2.5-4.5 folds is observed;however it should be noted that this graph only represents 90treatments out of the 650 performed. Many intervals are notable to adequately produce without fracture stimulation orwere not prefrac tested (due to operational efficiency –especially the PPFs) and are not reflected in this illustration.

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Figure 12 - Average Fracturing Folds of Increase

Average fluid and proppant quantities are presented inFigure 13. It shows that average treatment prior to 2003 was

~60,000 gallons of fluid and ~100,000 lbs of proppant. After


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6 SPE 106051

2002, the average treatment size was reduced to ~40,000gallons of fluid and ~50,000 lbs of proppant. The reason forthe reduction in job size is apparent when the data is shown asa function of the amount of productive pay interval (Figure14).

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Figure 13 - Treatment Volumes and Proppant Amounts

Treatments prior to 2004 averaged 2,000-3,000 gal/ft and3,000-8,000 lb/ft, while treatments from 2004-2006 averaged5,000-11,000 gal/ft and 4,000-18,000 lb/ft. The reduction in productive pay interval per treatment was due to a philosophychange toward limiting the amount of intervals targeted pertreatment, plus the targeting of previously bypassed pay.

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Figure 14 - Fluid & Proppant Amount per Net Footage

Discussion. The paper will be divided into the followingsections for more in-depth discussion: 1) Stress Regime, 2)Diagnostic Fracture Injection Tests, 3) High ReservoirTemperatures, 4) Depletion, 5) Completion Designs, and 6)Multi-Staging Strategies. Each of these sections will brieflysummarize the history of experience within the Cooper Basinand describe the item’s impact on treatment designs, placement, and post-frac production performance.

Stress RegimeThe contemporary stress regime in the Cooper Basin has beenextensively studied

13-25 using density logs, well tests and

wellbore deformation modelling. The stress regime is strike-

slip (σH > σv > σh) in the shallower regions of the basin and

can transition with increasing depth to the boundary between

reverse and strike-slip (σH > σh = σv) and then into the reverse

faulting regime (σH > σh > σv). The maximum horizontal stressis in the east-west orientation as shown in Figure 15

19 with

orientation rotating gradually in the western portion of the basin.

Figure 15 - Hydraulic Fracture Orientation from Borehole

Deformation Analysis19

The magnitude of the maximum horizontal stress isestimated to be between 2.0 and 3.6 psi/ft

17. This large

tectonic stress causes elevated fracturing pressures that varysignificantly within the basin and follow local trends due tofaulting and reservoir quality. An example of the averagefracture gradient from injection shut-in pressures for the

Patchawarra formation is shown in Figure 16. This figure

illustrates that the fracture gradient varies between 0.6 and 1.4 psi/ft, with the lower gradients observed in the West, South,and South-East portions of the basin. High stresses have beenobserved on the border or within the Nappemerri Trough.Similar plots are observed with the interpreted closure pressures (not shown), although the variations in stresses areless dramatic than the variations of observed fracture

gradients.


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SPE 106051 7

100 km100 km

Figure 16 – Frac Gradients for Basin in Patchawarra

The stress variations are easier to observe when plotted fora particular field, as displayed in Figure 17 for the Big Lakefield (South-East Central Area). This figure shows the

variation in the fracture gradient for the lower section of thePatchawarra formation. The gradient is observed to vary

between 0.88 and 1.26 psi/ft, with an obvious low stressregion in the middle of the field adjacent to the main fault.Within the areas shaded between purple and green (alsosegregated by dashed line), the gradients are less than 1.05 psi/ft and conventional gelled treatments can be placedsuccessfully and provide excellent post-frac production.

Outside of this low stress area, conventional gel treatment placement is more difficult and rarely results in significant post-frac production. Although not present in this figure, thislow stress region is also observed for treatments in theTirrawarra formation (with a significant shrinkage of the sweetspot) or in the upper portion of the Patchawarra formation(with a significant expansion of the sweet spot). No apparentlow stress region has been observed within this field for theToolachee formation treatments as fracture gradients are

almost always less than 0.95 psi/ft.

++

Figure 17 - Frac Gradients for Big Lake Field in the Lower

Patchawarra Formation – Well for Figure 19 Highlighted

The impact of these stress variations within the basin isdramatic on the ability to obtain good post-frac production.Previous experience in the basin has shown that it has been

rare to obtain significant post-frac production when fracture


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8 SPE 106051

gradients have exceeded 1.05 psi/ft7-8

. To illustrate the trend ofreservoir quality versus fracture gradient, the after closureanalysis KH values from fracturing diagnostic injections are plotted versus the fracture gradient in Figure 18. With theintroduction of more targeted fracturing treatments, the trendof “acceptable” post-frac production has been extended to

~1.15 psi/ft, however there remains a strong trend of reduced

reservoir quality versus fracture gradient.The major factors controlling localised stress variations

remain unclear; however are most likely a combination ofstructural features as illustrated in the previous figures, andvariations in reservoir quality. Regions of lower stress

coincide with regions of higher formation porosity and permeability, while higher stresses are normally indicative of

poor reservoir quality. It is uncertain however which of thesefactors is the dominating influence – i.e. whether lowerreservoir quality translates to more tectonic stresses or whetherhigher tectonic stresses have caused reduction of reservoirquality. Irrespective of which is the dominate influence, theunderstanding of the regional stress variations have lead to

improved risking of new prospects, concentration of new wellsin more benign stress regions, and the use of waterfracs type

treatments in regions of high stress (discussed below).

0.1

1

10

100

1000

0.5 0.7 0.9 1.1 1.3 1.5

Frac Gradient (psi/ft)

A f t e

r C l o s u r e A n a l y s i s K H ( m d - f t )

Figure 18 - Fracture Injection Test KH from After Closure

Analysis vs. Fracture Gradient

Treatment Designs for High Stressed Formations. The

designs strategies for treating high fracture gradient intervalshave evolved from trials to remediate the high apparentgradient (values > 1.05 psi/ft) with the belief that fracture

complexities (multiple fractures, re-orientation, etc.) werecausing the elevated pressures. Techniques that have obtainedlimited or no success in remediating or preventing theapparent high gradients are 1) ball-out treatments, 2) acid breakdowns, 3) gel slugs, 4) proppant slugs, 5) changing

perforating gun types between deep penetrating and big holecharges, 6) oriented perforating, or 7) abrasive jetting(including slotting). The only techniques that have shown anysignificant ability in reducing fracturing gradients have been prolonged injection volume (particularly with low viscosityfluids) or reservoir pressure depletion.

Contemporary strategy is based on the acceptance that

little can be done to alleviate the high apparent fracture

gradients and the high gradients are indications of inherent

shear failure mechanisms that can not be altered withoutreservoir depletion. Treatments can be placed successfullyusing conventional crosslinked fluids, however post-frac production results are usually poor for these treatment types.The best results in high gradient formations have been the useof waterfracs treatments to provide reservoir permeability

improvement. An example of a waterfrac treatment in an

8500 ft Patchawarra interval in the Big Lake field is presentedin Figure 19. This well was in the known high stressed regionof the field as shown in Figure 17. A crosslinked minifrac(shown at the start of the graph) was pumped with the hopethat a convention frac would be appropriate. Once the high

fracturing pressures (1.25 psi/ft) and high near wellbore pressure loss (2900 psi @ 27 bpm) were observed, the main

treatment was altered to a waterfrac treatment (shown at theend of the graph). The treatment used 125,000 gallons offriction reduced water to place 20,000 lbs of 30/60 bauxite.

0 60 120 180 240 300

Time (minutes)

0

2000

4000

6000

8000

10000

12000

14000

16000

A

0

4

8

12

16

20

24

28

32

B

0

1

2

3

4

CTubing Pressure (psi) Calc'd BHPressure (psi)Slurry Rate (bpm) Bottomhole Proppant Conc (lb/gal)

A AB C

Minifrac &

Frac

Separated

by 1 Day

Figure 19 - X-Linked Minifrac & Main Treatment

Waterfrac in 8500 ft Big Lake Lower Patchawarra

Interval

The post-frac response of this interval was approximately 1MMscf/day (determined from post-frac production log), whichis a satisfactory result based on the after closure analysis KHof 2.9 md-ft. Previous experience would indicate that this

result is better than what would be observed using aconventional crosslinked treatment.

Extension of the waterfrac technology into large volume“shear dilation” treatments has been proposed26-27 and trialled

recently in a hot dry rock project28

in the basement granite below the Cooper Basin. This type of treatment is now beingconsidered for the sedimentary rock in the Cooper Basin

29.

These treatments are large volume water injections conductedto enhance reservoir permeability through shear displacementsof natural fractures. Treatment volumes for the granite

treatments have been very large (3-5 million gallons) andrequire several days of injection. This technology may beespecially applicable for formations in which conventionalgelled fracturing treatments are unsuccessful due to naturalfractures and unfavourable stress regimes.


9/18

SPE 106051 9

Diagnostic Fracture Injectivity Tests (DFITs)To date over 700 individual injections for diagnostic purposeshave been pumped in the Cooper Basin. Table 1 gives asummary of the formations and some general statistics of theinjection output parameters. From this table it is evident thatthe most injections have been performed on the Toolache and

Patchawarra formations with a general increase in fracturing

difficulty with depth. The Tirrawarra formation whichtypically has a much thicker more homogenous sand packagedoesn’t fit this trend. The design and execution of the injectiontests fall into two main categories that are driven by theassumptions and ideologies of the time. These two categories

can be separated into pre and post 2002.

Formation

Frac Grad

(psi/ft)

Clos Grad

(psi/ft)

NWBPL

(psi)

#

Analyzed

# Not

Analyzed

ACA KH (md-

ft)

PI

(Mscf/day/psi)

Toolachee 0.93 0.77 867 100 125 10.9 1.36

Daralingie 0.94 0.82 434 5 22 2.2 1.32

Epsilon 0.94 0.80 1129 16 20 5.6 1.03

Patchawarra 0.96 0.79 1039 222 124 6.7 1.01

Tirrawarra 0.90 0.77 657 58 41 13.8 1.44 Table 1 - DFIT Analysis Sorted by Formation

Pre-2002 DFITs. At least two injections into the formation before the main fracture treatment has been a standard procedure up to 2002. This consisted of a large crosslinked gelminifrac (13,000-27,000 gallons) followed by a slickwaterstep rate test (SRT). From the minifrac the frac gradient, NWBPL and leakoff values were determined. From the SRTan extension pressure was determined to give assistance in picking the closure pressure. General guideline was to pick the

closure pressure 200 psi below the fracture extension value. Ifthe NWBPL was deemed to be excessive (>900psi), gel slugs

and/or proppant slugs where pumped to mitigate the NWBPLto below 900 psi. Above a fracture gradient of 1.05 psi/ft no

remediation of NWBPL was attempted and either a veryconservative fracture treatment was pumped (termed atolerance design) or the treatment was aborted depending onthe magnitude of the NWBPL. The gel slugs to remediate the

NWBPL were 2000 gallon injections (plus displacement) withgel loadings of 80 to 110 lb/Mgal. Almost all DFITs prior to2002 had bottomhole memory gauges that had to be recoveredvia slickline before pumping the main treatment. The mainemphasis of the DFITs prior to 2002 was to minimize placement risk.

Post 2002 DFITs. The main philosophy change post 2002was to use the DFIT to characterize the reservoir rather than to

condition the wellbore for the main treatment. The prefracinjection for non-PPF treatments consisted of 2000-5000 galsof crosslinked gel followed by a step down test to categorisethe near wellbore region. For PPF treatments, the DFIT was at5000 gal injection of 40 lb linear gel/Mgal most often placingthe abrasive jetting sand slurry (composed of 40 lb linear

gel/Mgal plus 1 lb/gal 20/40 sand) into the formation. The fracgradient, leakoff type, closure pressure, reservoir permeability

and reservoir pressure were determined to assess the reservoirquality. The step down test was used to characterize the nearwellbore region for tortuosity and perforation friction.Typically post-2002 attempts to mitigate NWBPL were onlyattempted when NWPBL exceeded 2000 psi as compared to a

pre-2002 cutoff of 900 psi. Figure 20 shows graphically the

change in ideology with regards mitigating NWBPL thatoccurred in 2002.

0

200

400

600

800

1000

1200

1400

P r e 1

9 9 7

1 9 9 7

- 1 9 9

8

1 9 9 8

- 1 9 9

9

1 9 9 9

- 2 0 0

0

2 0 0 0

- 2 0 0

1

2 0 0 1

- 2 0 0

2

2 0 0 2

- 2 0 0

3

2 0 0 3

- 2 0 0

4

2 0 0 4

- 2 0 0 5

2 0 0 5

- 2 0 0

6

2 0 0 6

- 2 0 0 7

N W B P L ( p s

i )

Figure 20 - History of NWBPL

Near-Wellbore Pressure Loss (NWBPL). Conventionalwisdom would suggest that NWBPL and stress would beintertwined. Review of the fracturing data within the CooperBasin, however, does not show any relationship between the NWBPL and stress as illustrated in Figure 21. This figure plots the values of the NWBPL versus the fracture gradientsfor both conventionally perforated intervals and abrasive jettedintervals, with no apparent observable trends. Additionally,

no trend was observed between after closure analysis (ACA)KH values from fracturing injection data and NWPBL (Figure22), confirming the lack of relationship between NWBPL andmagnitude of in-situ stress.

0

1000

2000

3000

0.5 0.7 0.9 1.1 1.3 1.5

Frac Gradient (psi/ft)

N e a r W e l l b o r e P r e s s u r e L o s s ( p s i ) Pin-Point

Conventional

Figure 21 - Variation in NWBPL versus Frac Gradient


10/18

10 SPE 106051

0.1

1

10

100

1000

0 500 1000 1500 2000 2500 3000

NWPBL (psi)

A f t e r C l o s u r e K H ( m d - f t )

Figure 22 - Fracture Injection Test KH from After Closure

Analysis vs. NWBPL

A recent study by Nelson et al 31-33

indicated that rockfabric and high rock tensile strength were major predictors forhigh near-wellbore pressure loss. Borehole image logs wereused to determine the presence of existing rock fabric such as

natural fractures or open bedding planes. Presence of thesetypes of rock fabric correlated well for intervals that exhibited

high NWBPL behaviour. Additionally, tensile strength fromCopper Basin sandstone cores were determined to be between500 and 2200 psi, with increasing values with decreasing porosity. Problematic rock fabric was found to coincide withhigh tensile strength formations, indicating shear failure andslippage were likely occurring in these formations under

elevated pressure conditions.

Leakoff Type Definition. Determination of the leakoff typehas played an important role in fracture treatment design withthe advent of the diagnostic G-Function plot with

superposition as detailed by Barree30. The breakdown ofleakoff types is spread evenly amongst the three major types

with the exception of tip extension of which only 5 cases have been identified (Figure 23). Of the leakoff types present, tip

extension and pressure dependent leakoff (PDL) are mostindicative of increased placement risk through NWBPL andlower eventual production. The normal leakoff and heightrecession give very similar results in terms of NWBPL andeventual PI. The KH derived from ACA tends to understatethe productivity of the zone for height recession (see Table 2).

Height Rec.

38%

Normal

33%

PDL

27%

Tip Ext.

2%

Figure 23 - Leakoff Types from Diagnostic Fracture

Injections

Leakoff Type

Frac Grad

(psi/ft)

Clos Grad

(psi/ft)

NWBPL

(psi)

#

Analyzed

# Not

Analyzed

ACA KH (md-

ft)

PI

(Mscf/day/psi)

Unknown 0.92 0.79 651 149 394 4.9 1.39

Normal 0.91 0.77 957 78 12.9 0.86

Height Rec. 0.92 0.75 732 79 6.2 0.95

PDL 1.02 0.80 1532 62 5.7 0.61

Tip Ext. 1.21 0.95 2306 5 1.2 0.17 Table 2 - Sorting of DFITs by Leakoff Type

The mechanism for picking closure has changed with theadvent of the superposition G-Function. An illustration of thedifferent “picks” is most evident in a height recession casewhere previously an early pick would have been made at theintersection of two straight lines (Figure 24). This early pick

leads to a lower fluid efficiency and a more conservativeeventual treatment design. Using the G-Function plot a moreconsistent closure determination is now possible dispensingwith the need for a separate step rate test. Reanalysing previous large gelled minifracs with the updated techniquesuggests that a large proportion of injections have not reached

closure at the termination of the test making any ACAimpossible.

Minifrac - G Function

1 2 3 4 5 6 7

G(Time)

4000

5000

6000

7000

8000

9000

10000

A

0

1000

2000

3000

4000

5000

6000

D

(0.002, 0)

(m = 1573)

(3.815, 5995)

(Y= 0)

(0.056, 8645)

(m = -388)

(7.795, 5642)

(Y= 8666)

(Y= 5640)

(0.763, 9999)

(m = -1521)

(4.672, 4053)

BHP (psi)

1st Derivative (psi)

G*dP/dG (psi)

A

D

D

21

1

2

Pre 2002

Post 2002

Time

2.18

2.95

CBP

7678

6671

SP

7681

6681

DP

1041

2048

FE

53.43

60.90

StimWin v4.8.201-Dec-06 09:42

Figure 24 - Picking Closure

After Closure Analysis (ACA). Previously the DFITinjection was used to calibrate the fluid leakoff number so amatch of the net pressure was possible. With the advent ofafter closure analysis an assessment of the reservoir KH and pressure was possible. The ACA process of taking the pressure

decline after closure and plotting against the radial timefunction is shown below (Figure 25).


11/18

SPE 106051 11

Stage 1 (Jets at 9352 ft)ACA - Cartesian Pseudoradial

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8

Radial Flow Time Function

3500

4000

4500

5000

5500

6000

6500

7000

(m= 5151.1)

Bottom Hole Pressure (psi)

ResultsReservoir Pressure = 3782.67 psiTransmissibility, kh/µ = 191.18247 md*ft/cpkh = 4.69420 md*ftPermeability, k = 0.4602 md

StimWin v4.8.120-Jul-05 08:19

Figure 25 - ACA example

The correlation between ACA KH and productivity index isshown below (Figure 26) and while the scatter is large,qualitatively ACA gives the correct prediction. Therefore theanalysis has not given either false positive or false negativeresults. An issue highlighted by the data is that ACA KHresults are affected by the leakoff type with height recession

leading to under prediction of the eventual production.

0.001

0.01

0.1

1

10

100

0.1 1 10 100 1000

After Closure KH (md-ft)

P r o d u c t i v i t y I n d e x ( M s c f / p s i )

Figure 26 - Correlation of After Closure Analysis versus

Productivity Index

Present DFIT Strategy. There has been a transition away

from large gelled injections and step rate tests to smaller lessviscous injections. The emphasis has also changed frommitigating NWBPL to reduce placement risk toward reservoirevaluation. In moving to smaller injections and not mitigating NWBPL it might be expected that the screenout frequency

should increase. Looking at the screenout percentage overtime it is apparent that the proportion of screenouts increasedin the 2004-2005 timeframe (see Figure 27). This correspondsto the targeting smaller zone with PPF and not the change in

minifrac design. During the first year after instituting thesmaller injections without pumping remedial injections thescreenout frequency of the main treatment actually decreased.

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

P r e 1 9 9 7

1 9 9 7

- 1 9 9

8

1 9 9 8

- 1 9 9 9

1 9 9 9

- 2 0 0 0

2 0 0 0

- 2 0 0 1

2 0 0 1

- 2 0 0 2

2 0 0 2

- 2 0 0 3

2 0 0 3

- 2 0 0 4

2 0 0 4

- 2 0 0 5

2 0 0 5

- 2 0 0 6

2 0 0 6

- 2 0 0 7

S c r e e n o u t %

0

20

40

60

80

100

120

140

160

180

G

r o s s H e i g h t ( f t )

%screenouts Gross

Figure 27 - Historical Screenout % and Grass frac height

High Reservoir TemperaturesThe Cooper Basin has an average geothermal gradient of 2.55

°F / 100 ft. This corresponds to an average 300 °F at 9000 ft.The gradients can be as high as 3.42 °F/100ft in the

Nappamerri Trough and as low as 2.02 °F/100ft in thePatchawarra Trough (see Figure 28). The elevated

temperatures at moderate depth are due to the accumulation ofradioactive granites beneath the producing intervals.

A l l u

n g a

T r o u

g h

Nappamerri

Trough

W o o l o o

T r o u g h

G i d

g e a l p a

M u r t e r e e

H o r s t

Patchawarra

Trough

A l l u

n g a

T r o u

g h

Nappamerri

Trough

W o o l o o

T r o u g h

G i d

g e a l p a

M u r t e r e e

H o r s t

Patchawarra

Trough

Figure 28 - Variation in Geothermal Gradient for South &

Central Portion of the Basin

Throughout the development of the Cooper basin differentgel types, loading, breakers and fluid additives strategies have been used to cope with the high static formation temperature.

The development of these strategies has been driven by theassumptions made about fluid and proppant transport,injection profiles and fluid heat up rates. The assumption prevalent in the early 90’s was that the fluid heated rapidly tostatic formation temperature once it entered through the perforations. A rule of thumb used in fluid design used at thetime was >100cp for the job duration at a shear rate of 170sec-1. This resulted in high gel loadings, use of gel stabiliser’s

and low or even no breakers being run in the fluid. From thelate 90’s onwards more emphasis was placed on reducing gelloadings to minimize polymer damage and moving to moreaggressive break schedules to maximize the potential for fracfluids to cleanup. The trend in reducing gel loadings


12/18

12 SPE 106051

eliminating the use of gel stabilizer and increasing breakerloadings is seen in Figure 29.

30

40

50

60

70

1 9 9 8

1 9 9 9

2 0 0 0

2 0 0 1

2 0 0 2

2 0 0 3

2 0 0 4

2 0 0 5

2 0 0 6

P o l y m e r L o a d i n g ( l b

/ M g a l )

0

5

10

15

20

S t a b i l i z e r a n d M a x B r e a

k e r C o n c .

( l b / M g a l o r g a l / M g a l )

Polymer Loading

Gel Stabilizer

High Temp Oxidizing Breaker

Figure 29 - History of Fracturing Fluid Changes

During this period there has not been a significant increase

in screenout frequency suggesting that the previousassumptions with regards the heat up of frac fluids lead tooverly conservative fluid design. The current philosophy

assumes that near fracture, the temperature cools to 20 °Fabove base fluid surface temperature after displacing 2 tubingvolumes. Using this criterion frac jobs have been placed at 325

°F for a fluid that is rated to 300 °F. The maximum breakerloading has also been increased in both the pad fluid and theslurry stages to assist in frac cleanup. The early productionresults of this initiative are difficult to assess but it has notresulted in increased screenouts.

Depletion

Depletion of the various horizons in the Cooper Basin is acertainty throughout the existing producing fields. Pore pressures in the basin can be as low as 500 psi, correspondingto pore pressure gradients as low as 0.07 psi/ft. As many of theformations are damaged, fracturing these formations presentssignificant challenges such as low fluid recovery, water blocking, and proppant pack damage due to excessive leakoff.

On the other hand, one advantage of fracturing depletedreservoirs in this high stress environment is that stressdecreases with depletion and hence helps with fracture placement success and height containment.

Historically, energised and foamed fluids have beenglobally effective to reduce the negative impacts of depletion

in hydraulic fracture treatments. In the Cooper Basin, similarsuccess has been obtained with the use of nitrogen energisedtreatments. These treatments were introduced in late 2000 withthe introduction of nitrogen commingled borate fluids. Thirty-seven intervals have now been treated using this fluid system,with the amount of nitrogen varied based on the level ofdepletion. The pore pressure gradient is used to decide on thequality of nitrogen to add to the fracturing fluids as shown inthe Table 3.

Pore Pressure

Gradient (psi/ft)

N2Quality

> 0.25 Not Energised

0.2-0.25 20%

0.15-0.20 30%


13/18

SPE 106051 13

expected that the zone with the lowest pore pressure will takemost or all of the treatment. Standard multi-staging techniquesare not typically suitable for many of the depleted wells,especially the older 7” completions or newer 2 7/8” monobores.The use of mechanical flapper valves that are run on casingand located in between zones of interest are planned for trials

in 2007 for multi-staging of depleted zones.

Completion TypeA history of the completion types during the basindevelopment is presented in Figure 31. Completions from1968 to mid-late 1990’s consisted of 5 ½” or 7” casing, while

the fracturing treatments were performed using either 3 ½” or4 ½” frac strings. With declining reservoir quality and

depletion, chrome 3 ½” monobore completions wereintroduced in 1997 as a way to reduce well costs, plusminimise post-frac kill operations

34. The benefit of the 3 ½”

monobores is shown in Figure 32. The wells in this figurewere all from the same formation in the same field and showthe benefit from preventing post-frac kill operations. The

chrome monobores were further reduced in size to 2 7/8”strings in 2002 as a further effort to reduce job costs in more

marginal areas. Additionally, 4 ½” completions were alsointroduced in 2002 and have gradually grown to become the preferred casing size for new multi-staged completions.Present completion strategy is 4 ½” casing for multi-stagewells and 2 7/8” chrome monobores for single fraccompletions.

0

10

20

30

40

50

60

1 9 6 9

- 1 9 7

9

1 9 8 5

- 1 9 8

8 1 9

9 0 1 9

9 2 1 9

9 4 1 9

9 6 1 9

9 8 2 0

0 0 2 0

0 2 2 0

0 4 2 0

0 6

N u m b e r o f W e

l l s

2 7/8 3 1/2 4 1/2 5 1/2 7

Figure 31 - History of Fractured Well Completion Types

0

1

2

3

4

5

6

7

8

910

W e l l

# 1

W e l l

# 2

W e l l

# 3

W e l l

# 4

W e l l

# 5

W e l l

# 6

W e l l

# 7

W e l l

# 8

W e l l

# 9

W e l l

# 1 0

W e l l

# 1 1

W e l l

# 1 2

W e l l

# 1 3

I n i t i a l D e l i v e r a b i l i t y ( M M s c f / D )

Conventional Completions(Rig Assisted Fracs)

Monobore Completions

(Rigless Fracs)

Figure 32 - Impact of Limiting Workover Operations

The initial and average production for each completiontype is summarised in Figure 33; however it is difficult toseparate the completion effects from the reservoir qualityvariations (apparent by the change in average gross heights).Although the highest production rates were obtained from the5 ½” or 7” casings, most of these treatments were performed

during the early basin development in better quality reservoirs.

Performance continues to trend the dates of completion designchanges and targeted gross height with the 3 ½” monobores(introduced in 1997) outperforming the 2 7/8” monobores(introduced in 2002) and 4 ½” casing (also introduced in2002). This explains the move to smaller wellbores from a

cost reduction standpoint as the reservoirs became depletedand more marginal intervals were being targeted.

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5 1 / 2 "

& 7 "

3 1 / 2 "

2 7 / 8 "

4 1 / 2

" - N o n

P P F

4 1 / 2

" - P P F

A v e P r o d p e r F r a c ( M M s c f / d )

0

20

40

60

80

100

120

140

160

A v e .

G r o s s H e i g h t ( f t )

Initial 1 Month Rate

Ave. 12 Month Rate

Ave.Gross Ht.

Figure 33 – Production vs. Completion type

The major drawbacks of the smaller wellbores are theinability to perform rapid multi-staging operations and thelimitations in treatment rates. The 3 ½” monobores are no

longer recommended due to the need to install siphon stringsas the rate to lift liquids is excessive for many wells. The 4 ½”

casing completions present the most desirable configurationfor new fractured well completions, however the costdifferential between a 4 ½” casing with 2

3/8” chrome tubing

and the 2 7/8” chrome monobores provides economic justification for use of the monobores in marginal projects.

A variation of the 4 ½”completion design has been used to

recomplete older wells when new stimulation opportunitieshave been identified. Most of these wells have a 7” casing

which is not rated to withstand fracturing. In these cases, a 4½” casing string is cemented inside the existing completion toallow follow-up fracturing operations. Successful treatments

have been performed following perforating or abrasive jettingthrough the dual 4 ½” & 7” casings.

Multi-Staging StrategiesStimulating multiple sand intervals and formations has been achallenge since fracturing began in the basin. This is mostapparent in areas with tandem completions from multipleformations or when producing from multiple Patchawarra orToolachee sands. The need was recognised from the onset asthe first treatments used ball sealers to attempt treat multipleToolachee & Daralingie Sands with one operation. All multi-

stage fracturing operations prior to 1996 were performed using

dedicated frac strings, while isolation for multi-stage


14/18

14 SPE 106051

operations used sand plugs or temporary bridge plugs. Majordrawbacks of these multi-stage treatments were the cost forworkover rig operations, damage caused by workoveroperations (especially from placement of sand plugs or fluidloss pills), and the ineffective cleanup caused by delay in production until installation of the production tubing.

Introduction of 3 ½” monobores in 1996 and the 27/8”

monobores in 2002 alleviated many of the problems associatedwith previous multi-staging operations. The major drawbackof the monobore multi-staging was use of sand plugs fortreatment isolation. If each treatment was cleaned up and produced separately, then damage was created placing the

sand plug plus increased costs and cycle times from multiplefracturing rig-ups and coil tubing operations. If treatments

were performed back-to-back without cleaning up each job,then there was potential ineffective cleanup due to long shut-intimes of initial stages plus coordination of concurrent welloperations (logging, coil tubing, fracturing, etc). Theintroduction of composite bridge plugs in 2003 removed thedamage caused by placing sand plugs; however these plugs

have only been available for the 3 ½” and larger casing sizes.Additionally, the composite bridge plugs did not address the

larger costs and cycle times from multiple fracturing rig-upsand coil tubing operations.

Recognition in 2003 that fracture height growth wasinsufficient to stimulate multiple sand intervals fostered thedesire to perform a larger number of targeted treatments. Thisrecognition was based on review of previous post-frac production logging (PLT) data coupled with industry

acceptance that fracture height growth is often much smallerthan predicted from conventional linear-elastic fracturingsimulators. An example post-frac PLT conducted 12 monthsafter a 2002 Toolachee fracturing treatment is included as

Figure 34. The 100,000 gallon treatment placed 140,000 lbs of20/40 and 16/20 light weight ceramic proppant at a rate of 25

bpm in this 27/8” monobore. Track 1 displays the original

open hole gamma ray, the cased hole gamma ray, area fill for

increased radioactivity, and compressional sonic time. Track 2and 3 display the open hole calipers. Track 4 displays the deepand shallow resistivities with area fill for filtration effects.Track 5 shows gas and water effective porosities, and Track 6shows the lithologies. The last track displays the temperatureand average spinner velocity during the well production at~3.5 MMscf/day. Although nine perforated intervals (all shotat 6 spf) were open during this treatment (shown as the black

area fills next to the depth track and outlined in black box), thespinner shows that the fracture initiated from the middle perforations (red box) with no fracture initiation from the topor bottom intervals.

SONIC

US/F140 40

PEN HOLE GAMMA

GAPI0 200

ASE HOLE GAMMA

GAPI0 200

CALIPER

IN11 6

CALIPER

IN6 11

PERF ORAT I ON S

8000

8050

8100

8150

8200

8250

8300

8350

8400

DEPT H

m e t r e s

RS

OHMM0.2 2000

RT

OHMM0.2 2000

WATERV/V0.3 0

GAS

V/V0.3 0

SHALEV/V0 1

QUARTZ

V/V0 1

COALV/V0 1

SPINNERS

RPS-10 110

TEMPERATURE

300 350DEGF

SONIC

US/F140 40

PEN HOLE GAMMA

GAPI0 200

ASE HOLE GAMMA

GAPI0 200

CALIPER

IN11 6

CALIPER

IN6 11

PERF ORAT I ON S

8000

8050

8100

8150

8200

8250

8300

8350

8400

DEPT H

m e t r e s

RS

OHMM0.2 2000

RT

OHMM0.2 2000

WATERV/V0.3 0

GAS

V/V0.3 0

SHALEV/V0 1

QUARTZ

V/V0 1

COALV/V0 1

SPINNERS

RPS-10 110

TEMPERATURE

300 350DEGF

Figure 34 - Post-Frac Production Log Showing Limited

Fracture Height Coverage

The result of the previous figure is inconsistent with the predicted fracture geometry that was obtained after treating pressure matching (Figure 35) using an industry pseudo-3D

linear-elastic fracturing simulator. Although fracture growthmay have occurred that is not in communication with the top

or bottom perforations, it is more likely that the fracturegrowth was more contained in the middle sands. This issupported by production history matching results (not shown)that indicate a post-frac production rate of ~50% of the pre-frac expectation.

Fracture Penetration (ft)100 200 300

99.17 min

8000

ft

TVD

8100

8200

Stress (psi)6000 6500 7000 7500 8000

C o a l

0.000

0.393

0.787

1.180

1.573

1.967

2.360

2.754

3.147

3.540

3.934

P r o p p a n t C o v e r a g e l b

/ f t ^ 2

Figure 35 – Predicted Geometry from Linear-Elastic

Simulator – Post-Frac Match of Figure 34 Treatment


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SPE 106051 15

Similar analysis for all available post-frac PLTs thatsummarize the analysis of post-frac production of 80treatments is included as Figure 36. This figure shows that prior to 2003, the average ratio of fracs/perforated intervalswas ~25% and the average gross height (top perforation to bottom perforation) was ~120 ft. This means that the average

treatment targeted four sand intervals over a gross height of

120 ft. The figure also shows that prior to 2003, only 40-50%of the perforated intervals would have significant post-frac production (greater than 500 Mscf/day). After 2003, theaverage treatment targeted only 1 interval over a gross heightof 35 ft resulting in 70-90% of the intervals contributing

greater than 500 Mscf/day. The 10-30% failures after 2003are due to poor reservoir quality rather than poor fracture

height coverage.

0%

20%

40%

60%

80%

100%

1 9 9 6

1 9 9 7

1 9 9 8

1 9 9 9

2 0 0 0

2 0 0 1

2 0 0 2

2 0 0 3

2 0 0 4

2 0 0 5

2 0 0 6

R a t i o

0

60

120

180

240

300

G r o s s H e i g h t p e

r F r a c ( f t )

Producing Intervals/Perforated Intervals

Fracs/Perforated Intervals

Avg Gross Ht per Frac

Figure 36 - Analysis of Post-Frac PLTs When Treating

Multiple Perforation Intervals

Since many of the perforated intervals would be expected

to produce without fracturing, this low percentage of producing intervals suggests that multiple fracturing initiation

points are not being created. This is also observed whenreviewing the average production rates of the perforatedintervals as seen in Table 5. For each multiple interval fracturetreatment, the intervals with the maximum production rates isdenoted as the 1st interval, the interval with the 2nd largest production is denoted as the 2nd interval, while the remaining

intervals open during the treatment are denoted as the 3rd+interval. Additionally, non-fractured intervals that were

perforated after the treatment are denoted as “Post-Frac”interval. Table 5 shows that on average, the main fractureinitiation point contributes 2/3

rdsof the treatment production,

while it is rare that a 2nd

fracture initiation point was created.

PerforationInterval

Average Production(Mscf/d)

ProductionPercentage

1st 1252 67%

2nd

430 23%

3rd

+ 187 10%

Post-Frac 173

Table 5 - Post-Frac PLT Production Breakdown

It should be noted that limited entry perforating has never been trialled in the Cooper Basin, so it is not surprising thatmultiple fracturing initiations were uncommon. Standard

practice has been to perforate each interval using 3 or 6 shot per foot (spf) with 20+ perforations per interval.

The analysis of the post-frac PLTs, coupled with post-frac production history matching, gave justification expandingmulti-staging efforts. Luckily this realization coincided withinitial trials of PPF that were ongoing in the United States.

This technology introduction into the Cooper Basin has been

described in detail previously11-12, so only a brief descriptionwill be presented here. The application involves pumpingdown 1 ¾” coiled tubing to abrasive jet three perforations (120deg phased), immediately followed by pumping the fracturingtreatment down the annulus between the coil and the 4 ½”

casing. This technology has enabled the ability to performrapid multi-staging with a lower per treatment cost.

Contemporary multistage completions are now performedroutinely using this technology with as many as 7 fracturingtreatments per well completed in 5-6 days. An example of a post-frac PLT from a well with three PPF treatments over agross interval of 150 ft is included as Figure 37. Tracks are thesame as for Figure 34; however the production rate at the time

of the PLT was ~6 MMscf/day. Additionally, the locations ofthe jetted perforations are displayed with the red arrows. In

this example, three treatments were performed at 15 bpm, placing a total of ~130k lbs of 20/40 intermediate strength proppant. Analysis of the post-frac PLT indicated significantcontribution from each of the treatments, a result that issuperior to the pre-2003 ideology of performing a singletreatment with multiple perforated intervals.

SONIC

US/F140 40

PEN HOLE GAMM

GAPI0 200

ASE HOLE GAMM

GAPI0 200

CALIPER

IN11 6

CALIPER

IN6 11

9200

9250

9300

9350

9400

DEPT H

m e t r e s

RS

OHMM0.2 2000

RT

OHMM0.2 2000

WATER

V/V0.3 0

GAS

V/V0.3 0

SHALE

V/V0 1

QUARTZ

V/V0 1

COAL

V/V0 1

TEMPERATURE

DEGF245 255

SPINNERS

-10 110

SONIC

US/F140 40

PEN HOLE GAMM

GAPI0 200

ASE HOLE GAMM

GAPI0 200

CALIPER

IN11 6

CALIPER

IN6 11

9200

9250

9300

9350

9400

DEPT H

m e t r e s

RS

OHMM0.2 2000

RT

OHMM0.2 2000

WATER

V/V0.3 0

GAS

V/V0.3 0

SHALE

V/V0 1

QUARTZ

V/V0 1

COAL

V/V0 1

TEMPERATURE

DEGF245 255

SPINNERS

-10 110

Figure 37 - Post-Frac PLT of Well with 3 Pin-Point Fracs

Contemporary multi-staging challenges are inidentification of how much gross height can be covered byindividual treatments, plus candidate selection criteria to prevent treating uneconomic intervals. Present viewpoint is tocontinue with PPF of 4 ½” completions when 3+ fracturingtargets are identified. In cases with only two stimulation

targets, trails of stimulation flapper valves in 27/8” monobores


16/18

16 SPE 106051

are planned for 2007. These flapper valves will replace the useof sand plugs for these applications.

Future Improvements Ideas1. Better integration of fracturing data with 3-D

visualisation to improve understanding of localised

reservoir quality and stress regimes.2. Expansion of zone coverage of abrasive jetting to

reduce near wellbore pressure loss and improvetreatment placement.

3. Improve design guidelines for use of 100 mesh for pressure dependent leakoff cases and guidelines forheight recession leakoff cases.

4. Implement CO2 energised fluids to improve flowbackof treatments for depleted and normally pressuredintervals.

5. Trial treatment diversion techniques to attempt toimprove ability to treat multiple sand intervals inmarginal areas.

6. Implement stimulation flapper valves in 2 7/8”monobores for energised multiple treatment

operations.7. Use fracture mapping technology to confirm fracture

growth behaviour for calibrating fracturingsimulations.

8. Improve predictability of post-frac production usingfracturing database of past fracturing performancedata.

Conclusions1. Fracture gradients within the Cooper Basin vary

significantly. Gradients are controlled by acombination of structural features and reservoir

quality. Poor post-frac production is observed whengradients are greater than 1.1 psi/ft.

2. Mapping of frac gradients and stresses are helpful toidentify problem areas for risking future wellopportunities.

3. Near wellbore pressure loss values are caused by rockfabric and high tensile strength, with no observabletrend with frac gradient or stress.

4. Waterfrac treatments are the recommendedstimulation procedure for formations with fracture

gradients greater than 1.1 psi/ft. Although manytechniques have been attempted, reservoir depletionis the only successful techniques for preventing orreducing fracture gradients greater than 1.1 psi/ft.

5. Diagnostic fracture injection tests are routinely usedto determine leakoff type and fracture complexity.Data from the basin indicate a predominance of

height recession (38%), normal leakoff (32%), and pressure dependent leakoff (28%).

6. After closure analysis determined KH is a useful toolfor predicting reservoir quality and post-frac performance. A significant amount of scatter isobserved especially when the KH values areinterpreted to be below 5 md-ft.

7. Diagnostic fracture injection volumes have beensignificantly reduced as compared to previous designmethodology. After closure KH values are now usedas the primary design parameter for predicting fluidloss taking the place of using the injection fluidefficiency.

8. Fluid polymer concentration has been dramatically

reduced and aggressive high temperature oxidiser breaker concentrations dramatically increased. Fluidformations take advantageous of the large cool-downthat is occurring due to confined fracture growth andsmall fluid residence times within the fracture.

9. Nitrogen energised crosslinked fluids arerecommended whenever pore pressure gradients are

below 0.25 psi/ft and show significant improvementsin post-frac performance due to improved fractureclean-up in depleted formations.

10. Recommended completion designs for future well are2 7/8” monobores for single fracture completions or 4½” completions for multi-stage operations.

11. Results from PPF operations have confirmed that previous fracturing practices were inadequate for

stimulating multiple sand intervals. Evidence from post-frac PLTs and production matching indicate thatfracture growth is much less than predicted fromsimplistic linear elastic fracturing simulators.Fracture height must be confirmed using independentmeans other than fracture pressure matching.

Nomenclature

σv = Vertical overburden stress

σH = Maximum horizontal stress

σh = Minimum horizontal stressPPF = Pin-point fracturing (annular coiled tubing fracturing)

AcknowledgementsThe authors would like to thank the managements of bothHalliburton, Santos Ltd., and the JV partners (Origin Energyand Delhi Petroleum) for permission to publish this material.We would like to expressly thank Adam Hill and Sarah Howiefor assistance in creating some of the excellent graphics andCarl Greenstreet, Simon Chipperfield, and Stuart Carnell for

proof reading drafts and providing suggestions. We would also

like to thank the many people and companies that have beeninvolved in the development of the fracturing technologywithin the Cooper Basin.

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SPE 106051 17

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25. Reynolds, S.D., Mildren, S.D., Hillis, R.R., Meyer,J.J. & Flottmann, T. 2005b. Maximum horizontalstress orientations in the Cooper Basin, Australia:Implications for plate scale tectonics and local stresssources. Geophysical Journal International , 150, 331- 343.

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