The West Sak reservoir on the north slope of Alaska has original oil in place (OOIP) of between 10 and 20 billion barrels. Although this resource has been widely recognized for over 15 years, it has remained essentially undeveloped, with total production of less than 0.1 percent of OOIP. A wide variety of complex issues - technical, financial and political - have made West Sak development appear too risky for even the major north slope operators. This paper presents a project management approach used to build a development plan that addresses the areas of uncertainty, minimizes the risk and will likely lead to a phased, "pay-as-you-go" West Sak development. The approach used to build the West Sak development plan applied some techniques commonly accepted in the business community to break some old paradigms that were built and cemented into place by years of traditional North Slope engineering thinking. Carefully scrutinizing the range of uncertainty of the project variables (both controllable and uncontrollable) using a tornado plot and quantifying the risk-versus-return using a cumulative probability plot provided clarity that enabled the resource owners to shift to a new paradigm. This new paradigm has identified value realization possibilities previously unrecognized. The expected outcome is a profitable West Sak development. Reservoir Description As shown in Fig. 1, the West Sak reservoir has a large areal extent - 30 miles north to south and 20 miles east to west, from the western area of Prudhoe Bay Field across the Kuparuk Field. The West Sak dips from west to east with the top of the West Sak found at approximately 4500 ft SS in the East and approximately 2000 ft SS in the West. Inspection of Fig. 2 shows that the West Sak is a highly stratified and poorly consolidated sandstone with gross thickness of 400 ft and net pay of only 90 ft. Two Upper West Sak and one Lower West Sak intervals have been designated. Complex faulting breaks the reservoir up further. With the wide variation in depth also come wide variations in temperature, pressure, oil gravity and oil viscosity. Temperature ranges from 60 to 100 degrees F, pressure ranges from 1000 to 1800 psi. oil gravity ranges from 10 to 22 degrees API, and viscosity ranges from under 30 to over 3000 centipoise. Only a small portion of the West Sak is seen as producible with current technologies. This "sweet spot" of the reservoir, shown in Fig. 3, overlies the eastern part of the Kuparuk Field and is found at an average depth of 3500 feet. To the east the West Sak is wet and to the west the oil is too viscous to flow. In the "sweet spot" of the West Sak the temperature is 75 F, the reservoir pressure is 1450 psi, the oil gravity ranges from 17 to 21 API, and the viscosity ranges from 26 to 27 cp. History A flurry of exploratory activity between 1969 and 1978 revealed the shallow heavy oil potential in the Kuparuk area, and Kuparuk Field delineation and development between 1979 and 1981 verified the large areal extent of the resource. In 1982 ARCO Alaska, Inc. (AAI) identified the West Sak as a reservoir with near-term production potential and in 1983 initiated a West Sak pilot waterflood that operated for 2-1/2 years. The pilot was viewed as a technical success because it confirmed that the sweet spot of the West Sak could be developed by conventional waterflooding methods, demonstrated sustained well rates of over 200 BOPD, and evaluated a variety of completion strategies. However, the pilot was viewed as a business failure for a variety of reasons. First, it was felt that production rates needed to be much higher than 200 BOPD. However, the completion innovations explored had not proved that these higher rates were achievable. It was felt that the success of West Sak would rely on undeveloped or unproven technologies. Second, it was recognized that the expected West Sak volumes could not support the high development and operating costs experienced at Prudhoe Bay and Kuparuk at the time and the pilot had not adequately investigated cost reduction strategies for the West Sak. P. 109^

With an active drilling program that was generating over 90,000 barrels of drilling waste each year, the THUMS Long Beach Unit in Wilmington Field, California, was spending over 3.5 million dollars per year to dewater and ship these solid wastes to on-shore landfills for disposal. In 1994, THUMS implemented an environmentally safe and economic program of hydraulic fracturing for the long-term, onsite disposal of drilling mud, drill cuttings, and tank bottoms. By reinjecting the drill cuttings downhole, transportation, the major portion of drilling waste disposal costs, was eliminated. This paper reviews the regulatory permitting process and addresses injection interval assessment, well candidate selection, fracture containment, and offset well seismic monitoring. The equipment, injection history, and economics of disposing over one million barrels of slurry over a 3-yr period are detailed.

Sixty-five percent of the reserves of the Kuparuk River field, the second-largest producing oil field in the U.S., is contained in a 20-to 80-md-permeability sandstone. This paper provides details of stimulation design advances made over the past 3 years in this formation. The design steps for optimizing fracture treatments in a moderate-permeability formation require primary emphasis on fracture conductivity rather than on treatment size or fracture length. This philosophy was used for the 140 new wells documented in this paper. Treatment size was gradually increased once a commensurate increase in fracture conductivity was obtained. Applying the new design to the refracturing of 88 producing wells in the field resulted in an incremental 40,000 BOPD, a significant portion of the field's 300,000 BOPD.

The North Slope of Alaska has significant accumulations of low API-gravity oil in unconsolidated formations. The combination of low-productivity wells in relatively unconsolidated formations in the arctic environment presents many challenges. Consequently, both formation stimulation (for economic production rates), and sand control (for acceptable operating costs) are required. A fracturing technique for sand control (FSC) with a resin-coated proppant (RCP) for proppant-flowback control proved feasible in laboratory testing. The initial attempts at field implementation were an investment in learning that resulted in a large number of first-order failures resulting from proppant and formation flowback. With these early failures, these attempts were not commercially viable. Laboratory investigations and field tests revealed the source of the problems, and led to design changes and improvements in implementation procedures. Field results have demonstrated that the FSC completion is a viable technique within certain formations on the North Slope that can achieve the stated goals of effective stimulation, proppant-flowback control, and sand control.

Summary More than 100 billion lbm of proppant are placed annually in wells across the globe, with the majority in unconventional reservoirs. The location of the proppant in these horizontal wells and formations is critical to understanding reservoir drainage, well spacing, and stage spacing. However, for many years proppant detection has primarily been limited to near-wellbore measurements. A novel method to detect proppant in the far field has been developed and is the subject of this paper. The proppant-detection method developed uses electromagnetic (EM) methods. This technology entails using a transmitter source and an array of electric- and magnetic-field sensors at the surface. A current signal with a unique wave form and frequency is transmitted to the bottom of the wellbore via a standard electric-line (E-line) unit. In addition, an electrically conductive proppant is pumped into the stage(s) of interest. The electric and magnetic fields are measured both before and after the detectable proppant stages, and a novel analysis method is then used to process and invert these differenced data to create an image of the propped reservoir volume (PRV). This technology is the product of years of development of computer models capable of forward modeling this technique. Once this modeling was completed, an initial field test was performed in west Texas (WTX), with a preliminary analysis of this work presented in a previous paper (Palisch et al. 2016). Since that paper, however, additional processing of the data has yielded a much-more-detailed image of the proppant location in this Bone Springs well. In addition, a subsequent field application has been performed in a major basin in the northeastern US. Multiple stages received detectable proppant of varying stage volumes, and the analysis has also shown a detailed image of the proppant location in that wellbore. Furthermore, the initial field test in WTX used only electric-field sensors, whereas this latest test used both electric- and magnetic-field receivers. The authors’ numerical simulations coupled with the field results indicate the percentage difference between prefracture and post-fracture results is two times higher using magnetic- vs. electric-field sensors. This paper will review the technology development and methods, will present the latest imaging from the initial WTX test, and will describe the latest learnings from the most-recent field test. This paper should be beneficial to all completions and development personnel who are interested in knowing where proppant is in their fractures. This technology has the potential to assist in understanding well drainage and spacing, stage and perforation-cluster spacing, vertical fracture coverage, and the effect of fracture-design changes.