TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper demonstrates where alternate approaches to BHTP analysis and modeling can provide significantly differing potential stimulation treatment geometries, outcomes, and goforward strategies. We will illustrate this conundrum using cases from the greater Cooper/Eromanga Basin of Central Australia; these cases commonly indicate an interrelationship between production outcomes, the magnitude of in-situ stress and the onset pressure or severity of pressure-dependent leakoff. Historically, treatments can be placed in these environments either after performing numerous diagnostic injections, by increasing pad volumes or by increasing injection fluid viscosity. However, these repeated injections and design alterations may only serve to stabilize the injection environment potentially masking the problem or causing production damage.We offer recommendations and explore different methods to mitigate these effects in cases where high stress and pressure-dependent behavior are indicated. We demonstrate how strain-corrections are used to correct log-derived rock mechanical properties to history-match initial BHTP responses. The cases presented use either: (1) increases in near-wellbore or near-fracture reservoir pressure; (2) changes in stress due to fracture propagations or horizontal loading; or (3) reductions in pressure-dependent leakoff coefficients to history match subsequent injections over multiple days. Finally, we indicate for each of these complex cases where production results or the desired treatment outcomes may have been altered by repeated diagnostic injections or a job changes. Cooper/Eromanga Basin BackgroundMost Basin wells target the predominant Permian sandstone reservoirs-the Patchawarra, Epsilon, and Toolachee Formations. This study discusses stimulation treatments in the Toolachee and Patchawarra sandstones in several differing areas of the greater Cooper/Eromanga Basin. Development Strategy.Hydraulic fracturing is a core technology used to reduce development costs within the Basin. Particular sub-reservoir units are chosen for fracture

Cooper Basin reservoirs commonly contain low-permeability reservoirs that require stimulation to flow. However, conventional multi-layer stimulation techniques has been shown to leave some sands untreated and not contributing, leaving potential to further increase flow rate and reserves through the use of new technology. Pinpoint fracturing technology allows multiple precisely-targeted fracs to be economically treated, which can increase flow rates and reserves, reduce incremental per-frac costs and significantly shorten cycle time compared to multi-stage conventional treatments Eight wells in the Cooper Basin of Australia have been Pin-Point stimulated using coiled tubing producing a 30% increase in well productivity compared with AFE expectations. Production logs run over the fractured zones show markedly improved completion efficiency with production from the majority of Pin-Point fractured zones. Introduction. The Cooper Basin extends over 130,000 sq kms in the north eastern corner of South Australia and the south western corner of Queensland.The basin is Australia's largest onshore producing area, currently producing 600 MMscf/day from 700 gas wells and 12 Mbbl/day from 400 oil wells.Hydraulic fracturing has been a critical technology in the basin for over 40 years.To date, over 600 individual treatments have been pumped with up to three stages per well.The fracturing environment throughout the basin is very challenging from a number of perspectives.The producing zones for fractured wells are typically between 7500 ft to 10000 ft depth with temperatures ranging from 250 to 400 °F.Multiple reservoir intervals are found interbedded with shales and coals. Fracture gradients are between 0.9 and 1.25 psi/ft with near wellbore pressure losses between 500 and 2500 psi.The basin is normally pressured with only a few isolated cases of overpressure being recorded.A typical well could have up to 1500 ft of gross interval with multiple fracture targets.Traditionally, this has been accomplished by blanket fracturing multiple zones in one treatment with up to 3 treatments in a wellbore isolated by sand plugs. Analyzing the effectiveness of this blanket fracturing technique with production logging suggests that significant pay has been bypassed by grouping multiple sands together in one treatment.For blanket treatments targeting multiple zones, production logging showed only one zone flowing.With the increasing differential depletion seen across fields within the Cooper Basin, grouping more than one sand package in a fracture treatment has become ineffective.Pin-Point fracturing was introduced to effectively stimulate more than three zones in a wellbore quickly and economically. This paper discusses the details of the fracturing process and operational methods plus presents two case histories with treatment examples, analysis and results.Pre-frac diagnostic injection tests were performed on all treatments using downhole pressures obtained through the use of the coiled tubing as a dead-string.Post-frac production logs show the additional production and reserve contribution from the fracture treatments, with observable production from almost every fractured interval. Well Selection Criteria. Initially, a trial group of four wells was targeted to trial the Pin-Point technique.The wells were selected based on reservoir, mechanical and logistical constraints.The wells required a minimum of at least three individual targets.New drill wells with 4 ½" 15.1 lb/ft P110 casing were selected due to the size restrictions on the mechanical packer and downhole equipment.This configuration limited the maximum pumprate to 15 bpm due to erosional velocity constraints in the wellhead and coil BHA.After the first four wells, the Pin-Point technique was changed from isolation by packer to isolation by sand plugs and another four wells were targeted to further refine the technique.A summary of the well parameters is given in Table 1 with the two case study wells highlighted.

TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract.Cooper Basin reservoirs commonly contain low-permeability reservoirs that require stimulation to flow. However, conventional multi-layer stimulation techniques has been shown to leave some sands untreated and not contributing, leaving potential to further increase flow rate and reserves through the use of new technology.Pinpoint fracturing technology allows multiple preciselytargeted fracs to be economically treated, which can increase flow rates and reserves, reduce incremental per-frac costs and significantly shorten cycle time compared to multi-stage conventional treatments Eight wells in the Cooper Basin of Australia have been Pin-Point stimulated using coiled tubing producing a 30% increase in well productivity compared with AFE expectations. Production logs run over the fractured zones show markedly improved completion efficiency with production from the majority of Pin-Point fractured zones. Well Selection Criteria.Initially, a trial group of four wells was targeted to trial the Pin-Point technique. The wells were selected based on reservoir, mechanical and logistical constraints. The wells required a minimum of at least three individual targets. New drill wells with 4 ½" 15.1 lb/ft P110 casing were selected due to the size restrictions on the mechanical packer and downhole equipment.This configuration limited the maximum pumprate to 15 bpm due to erosional velocity constraints in the wellhead and coil BHA. After the first four wells, the PinPoint technique was changed from isolation by packer to isolation by sand plugs and another four wells were targeted to further refine the technique. A summary of the well parameters is given in Table 1 with the two case study wells highlighted. Well Isolation Technique Zone Depth Pin Point Zones 1 packer 9384 -9756 ft 4 2 packer 7869 -9579 ft 6 3* packer 9218 -9350 ft 3 4 packer 9275 -9851 ft 4 SPE 97004 Applications of Pinpoint Fracturing in the Cooper Basin, Australia J. Gilbert and C. Greenstreet, SPE, Santos Ltd. PHIs 9.4% 9.0% PAY 1 3.2 f 1 6.0 f PHIp 9.4% 9.1% SWT 41% 43% PAY LDG SAND 18.8f 21.5f PHIs 9.6% 9.3% PAY 1 8.8 f 2 1.2 f PHIp 9.6% 9.3% SWT 29% 29% SAND 3.2 PHIs 10.0 PAY LDG SAND 8.0f 22.8f PHIs 9.6% 7.4% PAY 8.0f 20.5f PHIp 9.6% 7.7% SWT 24% 34% PAY LDG SAND 6.5f 7.0f PHIs 9.8% 9.6% PAY 6.5f 7.0f PHIp 9.8% 9.6% SWT 19% 19% PAY LDG SAND 1.2f 9.2f PHIs 8.3% 6.2% PAY 1.2f 8.8f PHIp 8.3% 6.3% SWT 27% 37% PAY LDG SAND 5.2f 7.0f PHIs 11.3% 10.1% PAY 5.2f 7.0f PHIp 11.3% 10.1% SWT 17% 20% PAY LDG SAND 20.0f 22.5f PHIs 10.2% 9.8% PAY 2 0.0 f 2 2.2 f PHIp 10.2% 9.8% SWT 26% 27% PAY LDG SAND 12.0f 18.5f PHIs 10.9% 9.2% PAY 1 2.0 f 1 8.5 f PHIp 10.9% 9.2% SWT 19% 24% PAY LDG SAND 1.8f 6.2f PHIs 9.3% 7.0% PAY 1.8f 4.5f PHIp 9.3% 7.8% SWT 41% 45% PAY LDG SAND 5.8f 7.2f PHIs 9.5% 8.8% PAY 5.8f 7.2f PHIp 9.5% 8.8% SWT 41% 41%

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper demonstrates where alternate approaches to BHTP analysis and modeling can provide significantly differing potential stimulation treatment geometries, outcomes, and goforward strategies. We will illustrate this conundrum using cases from the greater Cooper/Eromanga Basin of Central Australia; these cases commonly indicate an interrelationship between production outcomes, the magnitude of in-situ stress and the onset pressure or severity of pressure-dependent leakoff. Historically, treatments can be placed in these environments either after performing numerous diagnostic injections, by increasing pad volumes or by increasing injection fluid viscosity. However, these repeated injections and design alterations may only serve to stabilize the injection environment potentially masking the problem or causing production damage.We offer recommendations and explore different methods to mitigate these effects in cases where high stress and pressure-dependent behavior are indicated. We demonstrate how strain-corrections are used to correct log-derived rock mechanical properties to history-match initial BHTP responses. The cases presented use either: (1) increases in near-wellbore or near-fracture reservoir pressure; (2) changes in stress due to fracture propagations or horizontal loading; or (3) reductions in pressure-dependent leakoff coefficients to history match subsequent injections over multiple days. Finally, we indicate for each of these complex cases where production results or the desired treatment outcomes may have been altered by repeated diagnostic injections or a job changes. Cooper/Eromanga Basin BackgroundMost Basin wells target the predominant Permian sandstone reservoirs-the Patchawarra, Epsilon, and Toolachee Formations. This study discusses stimulation treatments in the Toolachee and Patchawarra sandstones in several differing areas of the greater Cooper/Eromanga Basin. Development Strategy.Hydraulic fracturing is a core technology used to reduce development costs within the Basin. Particular sub-reservoir units are chosen for fracture

The Cooper Basin is Australia’s leading onshore producing hydrocarbon province, having produced more than 6 Tcf of natural gas since 1969. The basin is undergoing renewal 45 years later, driven by the emerging growth of east coast LNG export-driven demand. Following North America’s shale gas revolution, the Cooper Basin’s unconventional potential is now widely appreciated and it is believed to hold more than 100 Tcf of recoverable gas. This resource potential is held in four stacked target unconventional lithotypes, each having demonstrated gas flows: tight sands—heterogeneous stacked fluvial sands; deep coal—porous dry coals, oversaturated with gas; shales—thick, regionally extensive lacustrine shales; and, hybrid shales—mixed lithotype containing interbedded tight sandstones, shales and coals. Industry activity initially focused on the Nappamerri Trough, where more than 25 contemporary exploration wells have been drilled, proving up an extensive basin-centred gas play with >1,000 m of continuous overpressured gas saturated section outside of structural closure. Santos has had a team focused on unconventional resources for nearly 20 years and successful results have been quickly tied into the producing infrastructure. This has been demonstrated with the Moomba–191 REM shale success, Moomba–194 and the recent Moomba–193H connection, one of the basin’s first fracture-stimulated horizontal wells. Prospective geology, existing infrastructure and market access makes the Cooper Basin well positioned for unconventional success. Each resource play is unique and commercial success requires considered adaptation of established technologies and workflows, based on a understanding of local geological and reservoir conditions. Commercialisation activity now seeks to define play fairways, characterise and prioritise reservoir targets and determine appropriate drilling and completion approaches.