Application of Pinpoint Fracturing in the Cooper Basin, Australia

Abstract

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%

Review of Current Fracture Stimulation Techniques for Best Economics in Multilayer, Lower-Permeability Reservoirs

“…One of the few drawbacks of this procedure is the lack of guarantee for a true mechanical seal challenges the application of minifrac testing except for the first zone. Many field applications have proven that they can consistently achieve excellent sealing for minifrac testing before each fracture stage, 25 but this is not assured in advance of proving the process in a specific completion or reservoir. The presence of real-time pressure data often decreases the need for minifrac testing.…”

Perforating for Fracturing—Best Practices and Case Histories

“…In early 2004, such a process was introduced 11 and has seen significant improvements and refinements. [12][13] Vertical wells will often experience significant differentials in fracturing pressures between zones, even when separated by only 10's of meters. In practical applications, it is unusual that stress variations between zones can give adequate zonal isolation for fracturing of multiple zones.…”

“…If jetting continues as the wellbore pressure is increased when formation breakdown is desired, the actual pressure inside this tunnel will be hundreds of psi above the wellbore pressure to assist fracture initiation from the tunnel itself. [5][6][7][8][9][10][11][12][13] This would rarely happen in conventional perforations in hard or very low perm reservoirs.…”

A Review of Design Considerations for Fracture Stimulation of Highly Deviated Wellbores

“…Proper application in deviated wells relates more to understanding fluid loss and properly selecting or applying downhole hardware (Furgier et al 2007) In hard rock formations, and even in some moderate hardness reservoirs, a less damaging perforating technique such as hydrajetting may offer the only currently available effective method for fracture placement control, such as presented by Surjaatmadja (1994), East et al (2005), and Gilbert and Greenstreet (2005). Proper application in deviated wells relates more to understanding fluid loss and properly selecting or applying downhole hardware (Furgier et al 2007) In hard rock formations, and even in some moderate hardness reservoirs, a less damaging perforating technique such as hydrajetting may offer the only currently available effective method for fracture placement control, such as presented by Surjaatmadja (1994), East et al (2005), and Gilbert and Greenstreet (2005).…”