Some Petroleum Engineering Considerations in the Changeover of the Rough Gas Field to the Storage Mode
- Andrew P. Hollis
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- May 1984
- Document Type
- Journal Paper
- 797 - 804
- 1984. Society of Petroleum Engineers
- 4.1.3 Dehydration, 5.2.1 Phase Behavior and PVT Measurements, 5.7.5 Economic Evaluations, 4.1.2 Separation and Treating, 6.1.5 Human Resources, Competence and Training, 4.5 Offshore Facilities and Subsea Systems, 7.4.5 Future of energy/oil and gas, 4.1.6 Compressors, Engines and Turbines, 5.1.2 Faults and Fracture Characterisation, 4.6.2 Liquified Natural Gas (LNG), 5.5.8 History Matching, 5.5 Reservoir Simulation, 5.6.4 Drillstem/Well Testing, 5.1.5 Geologic Modeling, 4.2 Pipelines, Flowlines and Risers, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.1.5 Processing Equipment, 1.6 Drilling Operations, 4.6 Natural Gas
- 3 in the last 30 days
- 207 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 12.00|
|SPE Non-Member Price:||USD 35.00|
Hollis, Andrew P., SPE, British Gas Corp.
The paper presents a reservoir engineering case history of the Rough field development. An initial description is given of the reservoir, field performance, and facilities as they were when Rough was under consideration for purchase as a potential gas storage field. The field's role purchase as a potential gas storage field. The field's role in the supply/demand match is described and the reliability and production requirements are derived. Setup of the finite-element-method reservoir and facilities model is described in detail. The estimation of gas in place and history matching are reviewed. Special attention is given to the difficulties in ascribing values to well and field performance in both production and injection modes, including an assessment of the uncertainties. The modeling of surface facilities in the development of an overall scheme is outlined. The interaction of practical drilling concerns with the overall development practical drilling concerns with the overall development scheme and reservoir performance is considered. The need to make the scheme flexible enough to cover changes in program and facilities is emphasized. The main results of the reservoir simulation are presented and include the history match and the field presented and include the history match and the field production/injection profile. Some details of the unusual production/injection profile. Some details of the unusual finite-element reservoir modeling techniques are provided. The concluding remarks summarize a method for provided. The concluding remarks summarize a method for conceptual design of an offshore gas storage scheme.
In 1978, British Gas Corp. identified a need for gas storage greater than that provided by salt cavities, liquid natural gas (LNG), and local facilities. A broad study was conducted of the depleted southern North Sea basin gasfields to see whether any were suitable for gas storage. The operators of those fields meeting our requirements were approached with a view to purchase. This paper covers the studies leading to the development basis for the selected field. It outlines basic design decisions made in planning the development of this first major offshore gas storage facility. Like all developments of this sort, many false trails were followed before a firm plan was chosen, so I will concentrate on the central plan plan was chosen, so I will concentrate on the central plan referring to abortive ideas only to indicate the planning logic.
The Rough field is situated in Blocks 47/8b and 47/3d of the southern North Sea, about 20 miles [32 km] off the Yorkshire coast and near the city of Hull. The discovery well was drilled by Gulf Oil Co. in 1968 and was followed by an appraisal well. Both were tested and then plugged and abandoned. In 1973, the license was plugged and abandoned. In 1973, the license was transferred to the Gas Council/Amoco Group. In 1975, production from the field began, and six wells were production from the field began, and six wells were drilled, completed, and commissioned by 1977. In 1980, British Gas Corp. purchased the field with about one-third of the reserves depleted, leaving 253 billion scf [7.24 x 10 9 std m3] out of a recoverable reserve of 384 billion scf [11 x 10 9 std m3]. Reservoir pressure had declined from an original 4,535 psia [31 MPa] to about 2,800 psia [19 MPa]. The combination of the field's depletion, size, and reservoir characteristics made it a particularly suitable candidate for conversion to a gas particularly suitable candidate for conversion to a gas storage role.
While under normal depletion, the field was on a plateau production rate of 104 MMscf/D [3 x 106 std plateau production rate of 104 MMscf/D [3 x 106 std m 3/d] with a planned winter peak capacity of 146 MMscf/D [4.18 x 106 std m3/d]. The six producing wells were drilled from a 12-slot drilling platform. This platform is bridge-linked to a similar eight-legged platform is bridge-linked to a similar eight-legged production platform on which the plant provides for glycol production platform on which the plant provides for glycol dehydration of a maximum of about 200 MMscf/D [5.72 x 10 6 std m3/d] gas. The gas is produced through a 16-in. [40.6-cm] pipeline to a shore terminal at Easington on the Yorkshire coast where the associated condensate is removed. Had normal depletion continued, compressors would have been installed on the production platform. A twin Rolls Royce Avon-type compressor platform. A twin Rolls Royce Avon-type compressor train was under construction. Fig. I shows the field production profile and the P/Z vs. cumulative production production profile and the P/Z vs. cumulative production plot for the field. Even with compression, the contractual plot for the field. Even with compression, the contractual field capacity associated with the plateau production rate could be maintained for only a few years more. At that stage the average maximum production rate from each well was 30 MMscf/D [0.86 x 10 6 std m3/d]-the best well giving 48 MMscf/D [1.37 x 10 6 std m3 /d] and the worst only 21 MMscf/D [0.6 x 10 6 std m3/d]. A further significant limitation to deliverability is the 16-in. [40.6-cm] sealine, which is operated at 750-psia [5171-kPa] outlet pressure. The line is nearing its maximum capacity in the region of 200 MMscf/D [5.72 x 10 6 std m3/d], and appreciable pressure drops occur at the peak production rate of 146 MMscf/D [4.18 x 106 std m3/d].
|File Size||555 KB||Number of Pages||8|