Success Rate Of Wells Research Articles

Resource assessment of the Copahue geothermal field

This paper assesses the electrical generating capacity of the Copahue geothermal field. Because it plays a critical role in driving financial support, we discuss these results in terms of its geothermal project. We performed a set of estimates, including the volumetric method and wellhead output calculations. The former was supported by a 3D-geological model that allowed us to subdivide the reservoir into blocks to constraint the parameters to each zone better. The probability models estimate that the proved resource can produce more than 10.2 MWe and 13.5 MWe at 90 % and 50 % confidence level, respectively. The wellhead power output calculations were supported by long- and short- period discharge test performed at three production wells and one slim hole and by the analysis of its decline paths. We estimate 10 MWe in the most optimistic prediction ruling out the identified power plant decline, above 5 % per year. Regardless of the method, our results support less than half of the previously calculated proven power output (i.e., 30 MWe) used to scale the offered tenders to develop a power plant. Overestimation cases worldwide invite us to be even more restricted over our power capacity estimations. Moreover, a tighter characterization of the reservoir volume (e.g., Chilean ranking) could redefine it from proven to probable, increasing the uncertainty over the resource. Throughout its 50 years of history the Copahue Geothermal Project reached significant milestones (first power plant on South America, a district –heating system, and four drilled wells). However, an in-depth review of the project history revealed several setbacks (closure of the power generation and direct use projects because of technical issues, developer retreatments, inadequate tenders) that partially explain its current on-hold status. We concluded that more work is needed before advancing towards the development stage of the project. The vast heat storage at Copahue is beyond doubt, but it is mandatory to improve the estimations of the steam supply, enhance the success rate of wells by a new drilling exploration stage, resize the projected power plant and perform a more accurate feasibility report. New attempts to attract investors and future developers should consider these goals and the project history to avoid new setbacks.

Spatial mapping of seismic facies variations to mitigate reservoir risk in coal prone fluvial-deltaic settings

Seismic facies classification has been used to reduce risk in laterally heterogeneous reservoir prediction. Studies were focused on the Barrolka/Coolah/Durham Downs Trend in the south-west Queensland sector of the Cooper Basin. The primary reservoir targets are the fluvial channel sediments of the Toolachee Formation. Historically, well success rates across the area have been low, with highly variable reservoir development and connectivity identified as the limiting factors influencing well performance.Conventional seismic attribute analysis has typically yielded inconclusive results, often associated to the presence of thick coals that dominate the seismic response. However, recent drilling campaigns utilised seismic waveform classification mapping, which resulted in an increase in technical success rate of wells. This study aims to investigate the concepts behind the success of the waveform classification method and to determine alternate techniques to further delineate reservoir presence.Key outcomes f...

Oil and Gas Developments in North Mid-Continent in 1982

In Kansas, completions reported in 1982 reached an all-time high of 9,166 wells. This is an increase of 34% over the 6,865 wells reported in 1981. Part of the increase can be attributed to the large carry-over of 1981 wells. Exploration and development drilling of oil reservoirs continued to dominate, with 4,108 oil completions compared to 810 gas completions. Both were up 33% from the 1981 figures. Total footage drilled came to 29,614,751. The average well depth was 3,221 ft, 219 ft less than the 1981 average well depth of 3,440 ft. The drop was more evident in exploratory holes, which averaged 3,770 ft or 293 ft shallower than in 1981. The average development well was 3,065 ft, off 195 ft. Exploratory drilling resulted in 245 discoveries, of which 197 were oil and 48 ga . Approximately 23% of all holes were exploratory, 75% were development, and 2% were stratigraphic and miscellaneous tests. The success rate for all classes of exploratory wells increased from 21% in 1981 to 26% in 1982, while the success rate of development wells remained about the same at 65%. The overall success rate of all wells drilled for oil or gas in Kansas in 1982 was 55%. Drilling operations in Nebraska declined 25% from a record high of 607 tests in 1981 to 453 in 1982. Over the same period, exploratory tests were off only 10%. There were 42 oil and 3 gas discoveries in 1982. All were classified as new-field wildcats. Total footage amounted to 2,059,439, off 31% from 1981. Consequently, the average well depth was 4,537 ft, or 373 ft shallower than in 1981. The overall success rate for oil and gas wells was up slightly to 43.9%. In Missouri, drilling activity continued its upward trend with 469 tests, up 18% from 1981. Total footage increased a surprising 39%, from 133,531 to 186,385 ft. The average well depth in 1982 was 397 ft. Much of the drilling in the state continued to be along the western border, although recent activities in western Illinois are spurring interest in the pre-Mississippian rocks in northeastern Missouri.