Over 300 hydraulic fracturing operations have been performed at Prudhoe Bay. The available data have been analysed to examine the effects of well deviation and azimuth on fracture treating pressures, job placement success and, most importantly of all, post-frac well performance. Clear conclusions emerge. Proppant production is an expensive problem at Prudhoe Bay. Factors affecting proppant production are examined, together with the results of a field evaluation of Resin Coated proppant.

When pumped at sufficient rates and pressures, gaseous nitrogen alone has been successfully used as a fracturing fluid in the Ohio Shale Formation of the Devonian shale trend. Enhanced production results have proved that use of nitrogen, even without a propping agent, has outperformed other stimulation systems employed in this lithological area of Ohio and West Virginia. Job design and procedures for nitrogen fracturing are presented in this paper as are production results of five treatments performed in the Ohio Shale Formation.

Nitrogen alone has demonstrated success as a fracturing fluid in reservoirs normally found sensitive to liquid systems. It has proved useful in shales of the Ohio Valley and West Virginia areas, and in similar lithology of the Fort Worth basin located in north central Texas. The fracture efficiency of nitrogen, as related to leakoff and flow capacity testing with no propping agent, has been investigated to analyze the effectiveness of nitrogen stimulation. Also, field data are presented that demonstrate successful results of the nitrogen technique in both oil and gas reservoirs. From the laboratory studies and field results, several conclusions were drawn concerning nitrogen stimulation. Of primary interest is that most of the width reduction in an unpropped fracture will occur in the early stage of production, which indicates a sharp decline of the well flow rate after a relatively short period.

An expert system called ACIDMAN was developed to design matrix acid treatments that remove damage near the wellbore and increase production. Input data can range from unknown formation damage, for which the system designs a conservative treatment based on well history and geological probability, to cases with detailed formation information available, in which very precise treatments are prescribed. The system requests additional specific laboratory tests, when needed, to aid in product selection. Basic input data requested include well type and history, formation-damage mechanism, bottomhole temperature, reservoir pressure, formation permeability, lithology, porosity, interval size, and crude oil gravity. Output includes product selection, additives, treatment volumes, and treatment technique. Phase I of the ACID MAN expert system was delivered in beta test in March 1990, and full implementation of all phases is planned during 1990.

Over 400 wells have been very successfully hydraulically fractured on the Kuparuk Sand for the Kuparuk River Unit Field (KRU)1. Comparatively smaller petroleum deposits of the Kuparuk Sand have recently been developed in the adjacent Prudhoe Bay Field. These satellite pools, namely the Aurora and Borealis, similarly benefit from fracturing. Significant productivity increases from aggressive Tip Screen-out (TSO) fracture designs have delivered over 40, 000 bopd from 11 wells. This paper describes the rationale, events and lessons learned leading up to the final very aggressive TSO designs for these satellite wells. In many cases, fracturing fluid efficiencies measured during datafracs for the satellite wells were approximately two times higher than the Kuparuk Sand analog in the KRU area. Pad volumes during fracturing were as little as 3% of the total treatment volume with modeled proppant concentrations of 5 lbs/ft2 placed. The majority of wells were S-shaped to minimize fracture complexity. Directional drilling costs, NWPL's and production results are shown. Bottom hole pressure gauge data is presented allowing refinement of the designs via net pressure analysis and times to start TSO. Production and pressure transient analysis results are also presented. Introduction Both Aurora &Borealis Pools are located on Alaska's North Slope and produce from the Kuparuk River Formation. (See figure 1). Although the structures were penetrated and proven to bear hydrocarbons in 1969, development did not commence upon until 1999. Reservoir Description The Kuparuk River Formation is stratigraphically complex and is characterized by multiple unconformities, changes in thickness, sedimentary facies, and local digenetic cementation. The Kuparuk Formation is divided into three intervals, the A, B, and C intervals, (from oldest to youngest) with the A and C intervals divided into a number of sub-intervals. See, figure 2 V-200 type log in appendix. An overlying unit, called the Kuparuk D Shale, is locally present in some areas of the Borealis Pool. The uppermost unit, the Kuparuk C sand is the primary reservoir sand. Although both the Aurora and Borealis Pools produce from the same formation and are in close proximity, structurally they are quite different. Kuparuk Aurora. Top Kuparuk structure in the Aurora area is broken up by north-south striking faults with up to 200 feet of down-to-the-west displacement. The faults effectively bisect the Aurora Pool and at least 7 different compartments have been identified based on pressure and fluid data. The Kuparuk thickness at Aurora is highly variable and ranges from 0 feet at the eastern truncation, to 210 feet at the Beechey Point wells in the northwestern portion. Kuparuk Borealis. The Borealis structure is shaped by basement-involved northwest-southeast trending faults that are intersected by a younger set of north-south striking faults. The trending faults were active during deposition of the lower Kuparuk C (C-1), but do not appear to have been contemporaneous with Upper Kuparuk C (C-2 to C-4) deposition. The compartmentalization within the Borealis field, it is not as severe as Aurora due to a relatively higher net and a significantly higher gross reservoir thickness. Kuparuk Aurora. Top Kuparuk structure in the Aurora area is broken up by north-south striking faults with up to 200 feet of down-to-the-west displacement. The faults effectively bisect the Aurora Pool and at least 7 different compartments have been identified based on pressure and fluid data. The Kuparuk thickness at Aurora is highly variable and ranges from 0 feet at the eastern truncation, to 210 feet at the Beechey Point wells in the northwestern portion. Kuparuk Borealis. The Borealis structure is shaped by basement-involved northwest-southeast trending faults that are intersected by a younger set of north-south striking faults. The trending faults were active during deposition of the lower Kuparuk C (C-1), but do not appear to have been contemporaneous with Upper Kuparuk C (C-2 to C-4) deposition. The compartmentalization within the Borealis field, it is not as severe as Aurora due to a relatively higher net and a significantly higher gross reservoir thickness.