pack in the fracture prior to exiting the perfo- rations. The perforated interval was limited to 6 ft [1.8 m] at zero-degree phasing and oriented at 180 degrees on the low side of the borehole. The perforation entrance-hole size was selected to be less than the designed fracture width.
• In-situ consolidation stabilizes unconsoli- dated rock around the perforations by injecting a resin into the formation.
• Tip-screenout (TSO) fracturing ensures tightly packed proppant from the fracture tip to the wellbore. This is essential for fi ltering any sand from fl uids during production. A key to achiev- ing a TSO fracture is determining fluid efficiency, fluid-loss coefficient and closure pressure, which can be obtained from DataFRAC calibration and step-rate tests. A large difference between the assumed values of fluid efficiency, fluid-loss coefficient and closure pressure compared with the DataFRAC results demonstrated the importance of this calibration to the success of this screenless sand-control method.
• Proppant-flowback control improves the longevity of the packed fracture. For this well, PropNET hydraulic fracturing proppant pack fibers were added to all stages of the proppant.29 At Well SK 74D, the upper and lower B2 zones were completed using the screenless hydraulic-fracturing technique (below). Early results indicate sand-free production. JAPEX operations, completions and reservoir teams considered this a successful application for con- trolling sand production.
Integrating Technologies
The Foinaven fi eld is a faulted anticlinal structure, featuring dip closure, faults and strati- graphic pinchouts as trapping mechanisms. Paleocene reservoir rocks have been classified
Successful sand management requires an integrated approach to problem-solving and appropriate utilization of the latest technology. This was clearly demonstrated by BP and Schlumberger on Well P110 in the deepwater Foinaven field, West of Shetlands (next page, top).30
as channelized, siliciclastic turbidites that formed interbedded to massive sandstones. Reservoirs range in porosity from 20 to 30%, have permeabilities of 500 to 2,000 mD and produce 26° API gravity oil. Reservoir characteristics, such as heterogeneity and varying productivity, contribute to wide-ranging reserve estimates. In the P110 well, the T25 reservoir target was best exploited by completing a 3,075-ft [937-m] hori- zontal openhole section.
Completing the long, horizontal openhole Proppant-flowback control
Proppant grains held in place by PropNET fibers
section remained a challenge; even with precise well placement, unstable shales and sand production can severely impact well and field economics in this area. A major concern for BP and Schlumberger was a 530-ft [162-m] unstable shale section between two sandstone reservoirs. This shale had the potential to slough into the hole during gravel-packing operations, possibly causing screenout or damage to the gravel-pack permeability. In previous wells, to help address stability issues, oil-base mud (OBM) was used to drill horizontal sections, and stand-alone screens were installed for sand control. In certain instances, particularly with high water cut, stand-alone screens required lower production rates to keep sand production manageable and to reduce erosion rates. Also, limited core data from the previously undeveloped T25 reservoir sug- gested these sandstones were much fi ner grained and less sorted than typical sandstones in the Foinaven fi eld. For these reasons, the BP team worked with Schlumberger to improve sand man- agement in the P110 well.
Several techniques contributed to a success- ful completion. To reduce formation damage, part of the solution included the first use of a water-base drilling mud (WBM) in the P110 hori- zontal well. After extensive testing, BP found a WBM that fulfi lled the requirements for drilling the Foinaven reservoirs.
Resin Oil Studies from earlier wells determined that a
stand-alone screen would be inadequate to con- trol sand production from the T25 reservoir, so the new solution also involved an openhole gravel pack (OHGP), the first ever for a deep- water Foinaven fi eld horizontal completion. The
Formation consolidation Formation
sand grain
29. Acock et al, reference 11. 30.Wilson A, Roy A, Twynam A, Shirmboh DN and Sinclair G:
> Screenless hydraulic fracturing for sand control. A combination of technologies is used to create a stable propped fracture that provides sand control with minimal proppant owback. The perforating job was designed to optimize the creation of the fracture. After perforating, injected resin was used to consolidate the formation around the wellbore. A TSO fracture created a tightly packed fracture capable of providing sand control and limiting proppant owback.
“ Design, Installation, and Results from the World’ s Longest Deep-Water Openhole Shunt-Tube Gravel-Pack West of Shetlands,” paper SPE 86458, presented at the SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, USA, February 18– 20, 2004.
31. Naturally occurring sand and synthetic proppants are speci ed according to sieve analysis based on particle- size distributions and percentage of particles retained by screens with standard US mesh sizes.
32. Ali et al, reference 19.
22
Oilfi eld Review
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