Brae Field Extended Reach Drilling - A Case History
- George C. Lumsden (Marathon Oil U.K. Ltd.) | Jeff R. Parker (Marathon Oil U.K. Ltd.)
- Document ID
- Society of Petroleum Engineers
- SPE/IADC Drilling Conference, 19-21 February, Amsterdam, Netherlands
- Publication Date
- Document Type
- Conference Paper
- 2003. SPE/IADC Drilling Conference
- 6.5.3 Waste Management, 1.6.1 Drilling Operation Management, 1.14 Casing and Cementing, 1.7.7 Cuttings Transport, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.14.1 Casing Design, 4.5 Offshore Facilities and Subsea Systems, 3.1.6 Gas Lift, 1.12.2 Logging While Drilling, 1.10 Drilling Equipment, 1.6.6 Directional Drilling, 3.2.2 Downhole intervention and remediation (including wireline and coiled tubing), 1.11 Drilling Fluids and Materials, 4.1.9 Heavy Oil Upgrading, 1.12.1 Measurement While Drilling, 2 Well Completion, 5.4.2 Gas Injection Methods, 2.1.7 Deepwater Completions Design, 1.6.5 Drilling Time Analysis, 1.9 Wellbore positioning, 1.6 Drilling Operations, 2.2.2 Perforating, 4.3.1 Hydrates, 5.8.8 Gas-condensate reservoirs, 5.2.1 Phase Behavior and PVT Measurements, 1.5 Drill Bits, 4.2 Pipelines, Flowlines and Risers, 1.11.4 Solids Control, 3 Production and Well Operations, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.6.2 Technical Limit Drilling, 1.1 Well Planning, 5.1.7 Seismic Processing and Interpretation
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This paper describes the experiences from drilling an extended reach well in February 2002 from a North Sea production platform constructed to develop a gas condensate reservoir, into an adjacent mature black oil field that had been previously developed with subsea facilities. The background to the project meant that a new conventional subsea type well tied into the existing infrastructure would not be able to deliver some of the key elements in developing reserves from the field.
Conceptual drilling engineering studies indicated that an extended reach well would be viable with a relatively minimal upgrade to the existing platform drilling facilities. The experiences of numerous other ERD (extended reach drilling) projects are well documented and whereas most issues are described as "good drilling practices" and are aligned company best practices, other issues were new to the organisation and required thorough review before deciding whether utilise that experience. Given this was the first such type of well for the company many of these issues were encountered.
HES (Health, Environmental and Safety) issues were particularly relevant to this project given the magnitude of the well, the human challenges with using unfamiliar equipment, and the environmental regulations governing the handling of drill cuttings.
Ultimately the project was sanctioned and after the numerous problems that were encountered, including three sidetracks and two lost BHA (bottom hole assemblies), the well successfully achieved it objectives attaining a final well TD (total depth) of 25,852 ft (7,880 m), a TVD (true vertical depth) of 13,810 ft (4,209 m) and a lateral displacement of 20,150 ft (6142 m). This paper presents the interpreted critical design considerations, details of the operational successes and failures, a summary of the lessons learned and the resulting developed best practice.
The Brae fields are located in Block 16/7a in the North Sea, some 160 miles north east of Aberdeen, Scotland, Figure 1. The chronological development has the South Brae field being developed first in 1983, North Brae in 1988 and Central Brae in 1989. Subsequently, East Brae was brought on stream in 1993 and West Brae in 1997. South, North and East Brae have been developed with production platforms that include drilling facilities. Central and West Brae fields are subsea developments that have been tied back to the South Brae platform.
The Central Brae field was discovered in 1976 and is a black oil reservoir of Upper Jurassic age. Following appraisal drilling, a plan of development was submitted to the UK government in 1987, whereby the field would be developed as a subsea satellite to the South Brae platform some 4.3 miles (7 km) away. By the end of 1992 a total of 9 development wells had been drilled into the reservoir .
Subsequent well re-entry projects were performed with mobile offshore drilling units. The objective was to increase oil recovery by perforating, reperforating and isolating watered out intervals. Post operation economics from these interventions revealed that the CAPEX for these projects were significant primarily because of high rig day rates coupled with the time intensiveness of the subsea operation. Due to decreasing reserve potential around the existing wells, the economics of future re-entry projects are deemed unattractive.
In the latter half of the 1990's several reservoir engineering studies had indicated the potential for further development work at Central Brae. To be able to improve recovery within the reservoir a new development well would be required. A prioritized list of requirements for the well was identified with three main requirements: a cost effective well and completion, the capability for economical well intervention and continuous gas lift.
These criteria were the basis for a conceptual study to evaluate the merits of drilling and completing a conventional subsea type well versus an ERD well from an existing platform.
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