An Evaluation of Prudhoe Bay Horizontal and High-Angle Wells After 5 Years of Production
- J.K. Pucknell (BP Exploration) | W.H. Broman (BP Exploration)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- February 1994
- Document Type
- Journal Paper
- 150 - 156
- 1994. Society of Petroleum Engineers
- 4.1.5 Processing Equipment, 3 Production and Well Operations, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 3.2.8 Well Performance Modeling and Tubular Optimization, 4.3.4 Scale, 1.6.6 Directional Drilling, 1.14.4 Cement and Bond Evaluation, 3.3.1 Production Logging, 5.5 Reservoir Simulation, 5.1.7 Seismic Processing and Interpretation, 5.6.5 Tracers, 4.1.2 Separation and Treating, 5.2.1 Phase Behavior and PVT Measurements, 1.6 Drilling Operations, 1.14 Casing and Cementing, 2.2.2 Perforating, 5.1.2 Faults and Fracture Characterisation, 2 Well Completion, 5.3.2 Multiphase Flow, 5.6.4 Drillstem/Well Testing, 2.4.3 Sand/Solids Control
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Based on 5 years of production history on 14 horizontal and high-angle wells, this paper reviews the performance of these wells compared with conventional offsets, discusses how shales influence GOR's, describes production log and well test in terpretation, gives evidence that only parts of the horizontal section actually produce, and describes the success of coiled-tubing workovers.
The Prudhoe Bay field is the largest Alaskan oil field. BP Exploration operates the western half, which is the subject of this paper. Production is from the Ivishak sand stone, a layered reservoir of variable properties, including high-permeability fluvial conglomerates and lower-permeability sand stones. The average sand/shale ratio is 0.9, and the shales are a major factor controlling well performance.
The first horizontal well in the western area of the Prudhoe Bay field was drilled in Nov. 1985. Since then, BP has drilled a number of horizontal and high-angle wells. This paper discusses the first 14 of these wells. They have been on production for an average of about 5 years. These wells, with deviations greater than 82 , are called non conventional wells (NCW's) and are listed in Table 1.
The wells can be split into two groups: 10 wells located below the original gas cap in the gravity-drainage area, where high GOR's cause problems, and 4 wells in the peripheral and west end areas (see Fig. 1), where water cuts can be significant.
By 1992, a large amount of information had been accumulated. This paper is the result of a review of that information-production histories, production logs, pressure-buildup tests and coiled-tubing workovers. Drilling and reservoir simulation are not covered.
Cumulative Oil Produced by NCW's Compared With Offsets. To establish the benefits of NCW's, the cumulative oil produced by NCW's was compared with that produced by offset conventional wells (0 to 60 ). Offset wells chosen as analogs were completed in the same zone at a similar time and had no known mechanical problems (e.g., cement channels). Table 2 gives the results. These comparisons show that overall the NCW program has been a considerable success, recovering an extra 21 million STB of oil. Although some of this oil may have been produced at the expense of offset wells, it is still a large incremental volume. How ever, 5 of the 14 wells do not currently show any benefit in terms of additional oil produced compared with analogous conventional wells. Efforts were made to establish why some wells were more successful than others.
|File Size||1 MB||Number of Pages||7|