West Sak is a heavy oil accumulation within the Kuparuk River Unit on theNorth Slope of Alaska. It is a Cretaceous, shallow marinesandstone. It contains 7–9 billion barrels of oil in place with an oilgravity that ranges from 10–22 degrees API. Initial oil production beganin 1997 at approximately 3,000 BOPD and has increased to over 16,000 BOPD inMarch 2005. Development plans are in place to achieve a rate of over 40,000 BOPD by 2007. This paper describes the evolving development plan for the West Sak field, with emphasis on the technical advances that have resulted in large-scalecommercial development. Early West Sak development consisted of stimulatedvertical wells on a 40-acre waterflood pattern with typical production rates of150–250 BOPD. Utilizing the evolution in horizontal and multi-lateraldrilling technology, the development plan has progressed to extended reachmulti-lateral injectors and producers with horizontal and undulating slottedliner completions is excess of 8000 feet per lateral. Peak rates of over5000 BOPD and sustained rates of over 1500 BOPD have been achieved. Withthe higher reservoir throughput rates, the distance between wells hasincreased, reducing well count and improving the development cost perbarrel. Significant changes have also been made to the completion design andproduction strategy. These include changing from sand exclusion to sandmanagement, adding intervention capabilities with multi-lateral completionequipment, optimizing the drill-in-fluid, and adding a backup gas lift systemto the standard electrical submersible pump (ESP) completions. Finally, the enhanced recovery process has evolved from waterflood to aviscosity reducing water-alternating-gas (VRWAG) process, improving expectedrecovery by 2–3 percent of OOIP. Application of new technology and optimized development decisions havereduced development cost by approximately 25% in terms of $/BOE and unlockedvalue in a major resource. West Sak Overview The West Sak and Ugnu heavy oil deposits are located within the KuparukRiver Unit (KRU) on the North Slope of Alaska. These deposits are part of alarger heavy oil belt that includes the Orion and Polaris Fields within thePrudhoe Bay Unit, and the Schrader Bluff and Ugnu heavy oil sands within theMilne Point Unit (see Figure 1). The estimated total oil in place within thisheavy oil belt is 20 to 25 billion barrels, with about two-thirds of the oilbeing located within the ConocoPhillips operated KRU.[1] The West Sak formation is a lower shoreface to inner shelf, Cretaceous-agedformation that has an average gross thickness of about 500' and an average netthickness of about 90'. The top of the West Sak reservoir ranges from2400' SSTVD on the western edge of Kuparuk to about 3800' SSTVD on the easternedge. The West Sak Core Area, which is the warmest, best oil quality portion ofthe West Sak reservoir, is located on the eastern edge of the Kuparuk Field(see Figure 2). It contains about 2.5 billion barrels of oil with oil gravitiesranging from 16 to 22 degrees at a reservoir temperature of about 75 degreesF. In this area, live-oil viscosities range from 20 to 100 cp. Thenorthern portion of the Core Area is currently under waterflood development atDrill Sites (DS) 1B, 1C and 1D. The 2004 production rate from the 1B/1C/1Darea was about 8700 BOPD. A new development at DS-1J is planned for thesouthern portion of the West Sak Core Area in 2005.

This paper (SPE 51187) was revised for publication from paper SPE 36457, first presented at the 1996 SPE Annual Technical Conference and Exhibition held in Denver, 6-9 October. Original manuscript received for review 23 October 1996. Revised manuscript received 21 May 1997. Paper peer approved 9 March 1998. Summary Some successful results have been reported for screenless frac-packing methods; however, no scientific guidelines were given regarding the conditions under which a screen can be eliminated from a well. In this paper, we report field data from sand-producing wells and review the onset and the rate of sand production for those wells with and without hydraulic fractures. From these field observations and numerical modeling analysis, we give guidelines for when a screen must be run and when a screen can be eliminated. P. 157

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe North Slope of Alaska has billions of barrels of heavy oil residing in largely undeveloped reservoirs. Despite this large volume of heavy oil in place, the majority of reserves development on the slope to date has been focused on light crude. However over the past 20 years Arco, BP, Conoco and now ConocoPhillips have begun to develop the North Slope's vast heavy oil resource base. Recently a sand/solids control study was undertaken by ConocoPhillips and BP in order to determine the most economic strategy for solids control and well design in future heavy oil developments.The study was integrated across companies, organizations and discipline boundaries in order to include completion, rock mechanics, laboratory research, drilling, reservoir, geological, operations, facilities and field personnel. With this diverse team, actual solids production and solids predictions were investigated from a number of different perspectives. Solids production predictions were made based on core measurements, log analysis, simulators that predict formation failure and sand production rate, laboratory core flow tests, 2 years of field shakeout data, and multiple field measurements of solids production. Probabilistic predictions were then generated based on these investigations rather than deterministic "best guesses" for the economic analysis. These different methods for predicting solids production will be discussed and illustrated in this case study.The study and ensuing strategy determined that sand management or using non-sand exclusion slotted liners and sand tolerant facilities was the highest value development scenario over the life cycle of the North Slope Heavy Oil Developments.

Within the sand-control-technology sector today, there are many sand-exclusion screen options available for use in completion design. Sand-control screens have steadily improved with the introduction and enhancement of metal sand-retention-mediabased sand-exclusion products in the early 1990s. However, recent catastrophic sand-exclusion failures have led some operators and independent laboratories to perform additional testing and quality control checks on sand-exclusion products to ensure full life cycle field value.This paper describes a process to select sand-exclusion products by uniquely qualifying an individual product design, which includes retention media, metallurgy, subcomponents, manufacturing process, and the final assembled product. The technical evaluation is based on a two-tier qualification process that "uniquely qualifies" products for purchase consideration.Step 1 of the process tests the sand-retention media for plugging potential and solids retention.Step 2 then tests full-joint screens manufactured using media qualified during Step 1 for burst and collapse to ensure the product meets downhole performance specifications.Recent testing has illustrated a range of significant conclusions that the industry should be aware of:• Published screen burst and collapse ratings are not always equivalent to actual screen performance.• Burst and collapse pressures are not equivalent to basepipe rating.• Welds can vary by plant; therefore, screens may vary by manufacturing location.• Excessive drainage layer gap leads to premature burst or collapse failure.• Not adjusting screen design for changes in metallurgy may lead to premature failure.• Delamination has been observed in some sintered retention media.• Scaling a product design up or down without conducting a detailed engineering analysis may lead to premature failures.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe North Slope of Alaska has billions of barrels of heavy oil residing in largely undeveloped reservoirs. Despite this large volume of heavy oil in place, the majority of reserves development on the slope to date has been focused on light crude. However over the past 20 years Arco, BP, Conoco and now ConocoPhillips have begun to develop the North Slope's vast heavy oil resource base. Recently a sand/solids control study was undertaken by ConocoPhillips and BP in order to determine the most economic strategy for solids control and well design in future heavy oil developments.The study was integrated across companies, organizations and discipline boundaries in order to include completion, rock mechanics, laboratory research, drilling, reservoir, geological, operations, facilities and field personnel. With this diverse team, actual solids production and solids predictions were investigated from a number of different perspectives. Solids production predictions were made based on core measurements, log analysis, simulators that predict formation failure and sand production rate, laboratory core flow tests, 2 years of field shakeout data, and multiple field measurements of solids production. Probabilistic predictions were then generated based on these investigations rather than deterministic "best guesses" for the economic analysis. These different methods for predicting solids production will be discussed and illustrated in this case study.The study and ensuing strategy determined that sand management or using non-sand exclusion slotted liners and sand tolerant facilities was the highest value development scenario over the life cycle of the North Slope Heavy Oil Developments.