The small Yme oil field offshore Norway was discovered in 1987, but the Plan for Development and Operation (PDO) was first submitted in 1993 due to the field's marginal character. The recoverable oil reserves as basis for the PDO were only 3,4 mill. Sm3. With the field located far from infrastructure, the development decision required a dedicated effort from the license owners. Focus was put on increasing and firming up the reserves basis while maintaining acceptable production costs. Accordingly, a jack-up drilling rig was leased and modified for simultaneous drilling and production. An oil tanker was leased for storage and field off-loading. The time from contract awards to first oil from the main structure, Yme Gamma Vest, in February 1996 was only 13 months. An important part of the development strategy in order to improve profitability was active exploration of mapped prospects in the license area in parallel with field development activities and production. The first subsea satellite development, Yme Beta Ost, was put on production in June 1996. This was only nine months alter submitting the PDO to the authorities and three months after production start for the main field. During the production phase three more exploration wells have been drilled. Overall, these have increased the reserves basis and prolonged the field lifetime. The Yme reservoirs comprise several challenges such as low reservoir pressure and solution gas content, special fluid properties such as high salinity of the formation water with dissolved solids of 190.000 ppm, and high asphaltene content of the oil. Artificial lift using ESPs and subsea gas lift was installed from the start. A compact water injection unit contributes to improved oil recovery. Barefoot open hole multilateral horizontal completions and hydraulic fracturing of vertical wells have also been used to improve drainage from the reservoir which has large permeability contrasts. The Yme field development shows how a marginal offshore field development can be initiated and improved using decision making under risk and application of unconventional techniques. P. 447
Summary Long-term reservoir testing provides an improved understanding of static and dynamic reservoir behavior before full-field development. The long-term test also improves understanding of the geological model and the connected hydrocarbon volumes. The experience gained from long-term testing has strengthened the basis for field development and reservoir management. Introduction The Norwegian Oseberg field came on stream in April 1989. The reserves estimate for the field is 1.45×109 STB [231.6×106 stock-tank m3] of oil and 3.25×1012 scf [92×109 std m3] of gas. Long-term production testing was performed as part of the data gathering for reservoir evaluation before field production startup. The testing program comprised two production wells and four reservoirs during a 20-month period. The production test ship Petrojarl I was used to enable comprehensive data gathering. Revenue from the sale of produced oil covered the cost of the operation. A large portion of the economic risk linked to offshore field developments lies in the forecasted hydrocarbon production profile. Long-term production testing is a major step toward gaining insight into reservoir dynamics and thus reducing reservoir uncertainties. This paper describes the motivation for and process of achieving early information on reservoir features by long-term production testing. The test performed on the Upper Brent sand in Well 30/9-T1 on the Gamma structure is used as a case history. This long-term production test contained several sequences - pressure-buildup tests, a rate sensitivity test, and a resumed test - designed to evaluate and improve the reservoir geometry and flow description. On-line measurements of flow and pressure data together with the long duration of the test enabled reservoir engineers to optimize the testing and data gathering according to the observed reservoir behavior. The experience gained on reservoir and well behavior has improved and strengthened the current basis for field development and reservoir management. Background During evaluation of a field development, the reservoir engineer provides an evaluation of the reservoir, including recommended drive mechanisms, required number of well slots, topside processing and injection capacities, and well locations and timing. This evaluation is used to determine the optimum field development concept and as the design basis for planned installations. The corresponding forecasted field hydrocarbon production profile also is provided to enable an assessment of overall field economics, preferably with risks and uncertainties highlighted and evaluated. Long-Term Production Test Definition. A long-term production test is defined as producing the hydrocarbon discovery at realistic field development rates with extensive data monitoring (rates and pressures) for an extended period (usually at least 4 weeks) to learn more about the long-term reservoir performance. It should be possible to alter the test duration and plan as new information becomes available from the test. A long-term production test often is aimed at reducing reservoir pressure in a larger region than can be reached in a short-term test. This may provide information for material-balance calculations and analyses of future or present communication between wells. Obtaining water or gas breakthrough may also be a testing goal for fields with expected multiphase reservoir flow during field production.1-3 Long-term production testing implies producing a reservoir long enough to activate time- or volume-dependent reservoir phenomena. The testing period should be long enough for proper interpretation techniques to be applied on test results. The testing period necessary to achieve representative data to meet test objectives depends on reservoir type and quality and cannot be stated generally. Bearing in mind the diversity of reservoir properties and flow behavior, we use "long-term" for periods longer than 4 weeks. The term "production testing" is used to indicate that extensive data gathering was performed during production of the well at rates and conditions similar to those of the planned field development. Definition. A long-term production test is defined as producing the hydrocarbon discovery at realistic field development rates with extensive data monitoring (rates and pressures) for an extended period (usually at least 4 weeks) to learn more about the long-term reservoir performance. It should be possible to alter the test duration and plan as new information becomes available from the test. A long-term production test often is aimed at reducing reservoir pressure in a larger region than can be reached in a short-term test. This may provide information for material-balance calculations and analyses of future or present communication between wells. Obtaining water or gas breakthrough may also be a testing goal for fields with expected multiphase reservoir flow during field production.1-3 Long-term production testing implies producing a reservoir long enough to activate time- or volume-dependent reservoir phenomena. The testing period should be long enough for proper interpretation techniques to be applied on test results. The testing period necessary to achieve representative data to meet test objectives depends on reservoir type and quality and cannot be stated generally. Bearing in mind the diversity of reservoir properties and flow behavior, we use "long-term" for periods longer than 4 weeks. The term "production testing" is used to indicate that extensive data gathering was performed during production of the well at rates and conditions similar to those of the planned field development.
Thm papar was salected for prewntation by an SPE ProgramCommittee fol~ng revkw of infomtion mntained "man abstracf submitted by the author(s), tintents of the paper, as presen~d. have not been reviewed by the Sociity of Wtroleum Engineers and are subject to corrdo by the author(s), The material, as pmsanted, does not necessarily reflect anỹ tion of the Wety of Petro!eum Enginmrq i~o~cars, or mmbers. %pars presented at SPE meetings am sub~fo pub~cation re~w by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, diatribu~rr, or storage of any part of this papar for commercial pur~sas Wout the wmen conaant of the Wety of Petroleum Engineers is prohibited. %rmission to reprdu~in print k restricted to an abstract of not more than W wr@ illu~ahns may not k copkd The abstract must wntain umspicuous achMe@mnt of Were and by Mom the paper was presented Wife Librarkn, SW. PO. Sox 833t33e, Richardson, TX~3.3838, Q, fax 01.972.952.9435. AbstractThe small Yme oil field offshore Norway was discovered in 1987,but the Plan for Development and Operation (PDO) was first submitted in 1993 due to the field's marginal character, The recoverable oil reserves as basis for the PDO were only 3,4 milL Sm3. With the field located far from infmtructure, the development decision required a dedicated effort from the license owners.
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