The Beryl field in UK Block 9/13 was discovered in 1972. The 40-slot, twin drilling rig, Beryl Alpha platform (see photograph Fig. 1) installed in July 1975 was the first concrete Condeep structure installed in the North Sea. The field is heavily faulted and stratigraphically complex, generating numerous drilling opportunities with associated geological uncertainties. Extended reach wells are planned to develop resources beyond the reach of the current platform rig capabilities.
In the current industry environment where costs of semisubmersible rigs have risen dramatically and rig availability is an issue, the traditional concept of subsea satellite development is now problematic in terms of economic viability and control of schedule. The Beryl field has a number of satellite and in-field development opportunities beyond the platform's drilling reach. The concept of upgrading the Alpha drilling rigs to enable these resources to be developed by means of extended reach drilling (ERD) was conceived. The approach taken was to maximize ERD while remaining within the constraints of the existing derrick structures. This involved an innovative approach to retrofitting enhanced drilling capabilities on a 30-year old rig extending horizontal displacement from 15,000 to 25,000 ft (see field map on Fig. 2).
This paper will address project planning from inception through the development of a rig upgrade execution plan and address the well design issues for the ERD program envisaged, including potential new drilling technology applications to reduce torque and enable multiple casing strings below 9-5/8-in. casing. Beryl celebrated its 30th year of production on 11 June 2006. The field life was initially estimated to be 20 years. At the time the Alpha platform was installed, Beryl Field reserves were estimated to be approximately 400 million barrels of oil equivalent, to date over 1.3 billion barrels of oil equivalent have been produced from the Beryl field and associated satellite developments (28% from subsea wells) far in excess of the original Alpha platform funding basis. Innovative approaches to field development characterised the beginning of Beryl's productive life and are being applied today to continue the process of extending field life by reaching out to recover and discover new resources previously thought beyond reach.
ERD Project Planning
When drilling commenced from the Beryl Alpha in 1976, the effective drilling reach, using the drilling technology of that era, was approximately 8,000 ft. Today, with advances in drilling technology including top-drive systems (installed on Alpha in 1995) and rotary steerable drilling systems, the reach has been extended to about 15,000 ft. This increased capability has been instrumental in supporting a campaign of drilling to develop reserves not foreseen in the original field development plan, with the result that to date 81 wells have been drilled from the original 40 slots (see Fig. 3).
In fourth quarter 2005, a study was undertaken to assess the potential benefits of further increasing the drilling reach from the Alpha platform by a small multi-disciplinary team of drilling and reservoir engineers and geoscientists. The background to this study was the sharply increasing trend of semi-submersible rig day rates, and due to the tight North Sea market situation, their lack of availability. The Beryl area has a number of subsea satellite field developments that produce to and are supported from the Alpha platform, including the
Nevis, Ness, Buckland, and Skene fields. In addition, there are a number of accumulations thus far not developed that were considered to be potential future satellite development opportunities. Since near term access to an economically acceptable semi-submersible rig for drilling satellite subsea wells was not foreseen, it was decided to consider the potential for ERD wells to develop these opportunities. A number of potential ERD drilling prospects lay out with the reach of the existing Beryl Alpha platform rigs, and these are shown in
terms of drilling reach requirements on the worldwide ERD wells "nose plot?? (see Fig. 4). The longest reach requirement was 30,000 ft. A "bubble plot?? showing relative reserve size for potential drilling opportunities is also shown as Fig. 5 and this was used to help prioritise drilling candidates.
This paper presents a field study of a carbonate reservoir using geological and numerical simulation models. The paper emphasizes the importance of developing an accurate reservoir description through the joint efforts of geologists and engineers.
The field study (Clive pools, Alberta, Canada) incorporated data from a geological study, interference study, material balance study, field-wide simulation study, and hydrostatic-hydrodynamic pressure analysis. The geological study provided input data for the numerical model and the provided input data for the numerical model and the calculation of the original hydrocarbon pore volume. The interference study helped verify the theory of pressure interference among the producing pools and pressure interference among the producing pools and predict future pressure behavior. Hypothesis and predict future pressure behavior. Hypothesis and deductive reasoning were required in the material balance study to define the aquifer behaviour.
Petrophysical data from recent infill wells have Petrophysical data from recent infill wells have been used to verify and update the existing geological-reservoir model. The model will be used to continuously optimize production strategy and evaluate the technical feasibility of enhanced oil recovery using a hydrocarbon miscible displacement process. process
The Clive Field, located 200 km north-east of Calgary in south-central Alberta (Fig. 1), was discovered in 1951 and developed in three stages. Clive D-2A North encompassing the discovery well was developed on 16 hectare spacing and the initial reservoir pressure was 17.1 MPa. Clive D-2 South was discovered in 1963 and developed on 64 hectare spacing. Pressure in this portion of the reservoir was 16.7 MPa at discovery. Clive D-2B, located immediately south of the D-2A pool, was discovered in 1966 with an initial reservoir pressure of 16.5 MPa. The Clive D-2 pools produce oil from Upper Devonian Nisku dolomites which are separated from the underlying Leduc D-3A oil reservoir by impermeable Ireton shales. Most of the wells are dually completed and produce from both the Nisku D-2 and the Leduc D-3 zones in the Clive Field.
The Clive D-2A and D-29 pools were unitized in 1970. A fresh water injection scheme was initiated in September, 1970 in an attempt to maintain the reservoir pressures which had declined from the initial 17.1 Mpa to 15.6 Mpa in 1970. However, the water injection scheme has not been able to maintain reservoir pressures despite a cumulative reservoir voidage replacement of eighty percent (Fig. 2).
A comprehensive geological-engineering study was initiated in order to a) more accurately define the reservoir characteristic, b) evaluate the effectiveness of the water injection scheme, c) optimize production strategy, and d) evaluate the technical feasibility of enhanced oil recovery using a hydrocarbon miscible displacement process.
The Clive Field lies on a major northeast trending, carbonate complex (Bashaw-Duhamel Reef Complex, Fig. 1) composed of dolomitized, shallow water shelf and reef deposits of the Upper Devonian Leduc Formation (Fig. 3). The Bashaw-Duhamel reef complex (also known as the Innisfail-Clive-Nevis reef complex) in the Clive area, is cut by a shallow, narrow channel which isolates the Clive Field from the Alix Field to the northeast. The Leduc carbonates are founded on the widespread, Cooking Lake platform (Fig. 3) which acts as a common aquifer to Leduc reservoirs throughout the area. The lateral and top seal for these reservoirs is provided by the shales of the Ireton Formation (Fig. 3).
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This paper was prepared for the Rocky Mountain Joint Regional Meeting in Denver, Colo. May 27-28, 1963, and is considered the property of the Society of Petroleum Engineers. Permission to published is hereby restricted to an abstract of not more than 300 words, with no Illustrations, unless the paper is specifically released to the press by the Editor of the Journal of Petroleum Technology or the Executive Secretary. Such abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request providing proper credit is given that publication and the original presentation of the paper.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.
Industrial shale-oil operations in North America and Europe predated the Drake discovery, but, since then, most have succumbed to competition from petroleum. However, the existence of enormous oil-shale resources in the Green River formation of Colorado, Utah and Wyoming [estimated at over a trillion bbl of shale oil in place] and the advancement of United States oil-shale technology by research and development programs of government and industry during the past 15 years point to a natural partnership of petroleum and oil shale to meet the accelerating energy demands of the future. The utilization of oil shale is not a question of limited petroleum supplies, but one of economics. Two factors are expected to improve the economic outlook for industrial shale-oil production a rise in petroleum replacement cost and further advances in oil-shale technology.
The production of oil from oil shale dates back to the 17th century, when medicinal oils were produced from bituminous shales in England. Shale-oil industries started in France in 1838; in Scotland in 1850; in Australia in 1860; in Estonia, Spain and Manchuria in the 1920's; and in South Africa and Sweden in the 1930's. A small shale-oil industry was operating in Canada and the eastern United States in 1860 but disappeared when petroleum became plentiful following the Drake discovery in Pennsylvania. Industrial operations in other countries generally have had similar experiences; that is, when petroleum became readily available at reasonable, cost, the oil-shale operations could not compete without sizable subsidies. Industrial operations are presently conducted only in Spain, Sweden, Estonia, Manchuria and the U.S.S.R.
Oil shales do not contain oil; instead, they consist of solid, largely insoluble, organic material intimately associated with a mixture of minerals that make up about 85 per cent of an average shale yielding 25 gal of oil per ton. Oil shales are widely distributed throughout the world in sedimentary rocks fray. Cambrian to Recent, but by far the largest known deposit is in the Green River formation in Colorado, Utah and Wyoming.
Lewis G. Weeks in 1959 published a comprehensive analysis and forecast of demand and sources of supply of energy for the next 100 years. He estimated that, in addition to imported petroleum, the United States would use 490 billion bbl of the 570-billion-bbl ultimate reserve of domestic petroleum [including natural gas energy in equivalent bbl of petroleum and oil from tar sands] and 600 billion bbl of shale oil from 1960 to 2059. Although Weeks considered all of the oil-shale deposits throughout the U. S. as sources of shale oil, the 1.132 trillion bbl of potential oil in place in the Green River formation, as estimated by Donald Duncan of the Federal Geological Survey, constitutes almost twice the supply required to meet the need estimated by Weeks.