A Case Study in the Design and Execution of Subsea Production Development Wells in the Captain Field
- G. Rae (ChevronTexaco Upstream Europe) | J. Hampson (ChevronTexaco Upstream Europe) | I. Hiscox (ChevronTexaco Upstream Europe) | M. Rennie (ChevronTexaco Upstream Europe) | A. Morrison (ChevronTexaco Upstream Europe) | D. Ramsay (ChevronTexaco Upstream Europe)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- June 2004
- Document Type
- Journal Paper
- 82 - 93
- 2004. Society of Petroleum Engineers
- 3.1 Artificial Lift Systems, 4.1.9 Tanks and storage systems, 2 Well Completion, 3.2.2 Downhole intervention and remediation (including wireline and coiled tubing), 5.1.5 Geologic Modeling, 1.11 Drilling Fluids and Materials, 1.1 Well Planning, 3 Production and Well Operations, 2.4.3 Sand/Solids Control, 6.1.2 HSSE Reporting, 1.4 Drillstring Design, 5.1.2 Faults and Fracture Characterisation, 2.4.5 Gravel pack design & evaluation, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.6.4 Drillstem/Well Testing, 2.2.3 Fluid Loss Control, 1.6.10 Running and Setting Casing, 3.3.1 Production Logging, 4.5.10 Remotely Operated Vehicles, 4.1.9 Heavy Oil Upgrading, 5.1.1 Exploration, Development, Structural Geology, 4.5.7 Controls and Umbilicals, 3.1.2 Electric Submersible Pumps, 1.7.5 Well Control, 1.12.1 Measurement While Drilling, 1.6.2 Technical Limit Drilling, 1.6.7 Geosteering / Reservoir Navigation, 5.1 Reservoir Characterisation, 4.3.4 Scale, 3.1.3 Hydraulic and Jet Pumps, 1.6.6 Directional Drilling, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 7.3.3 Project Management, 1.10 Drilling Equipment, 5.2.1 Phase Behavior and PVT Measurements, 5.1.8 Seismic Modelling, 4.1.2 Separation and Treating, 1.7 Pressure Management, 4.2.3 Materials and Corrosion, 1.6 Drilling Operations, 7.2.3 Decision-making Processes, 4.5 Offshore Facilities and Subsea Systems, 1.6.1 Drilling Operation Management, 4.1.5 Processing Equipment, 4.5.3 Floating Production Systems
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This paper outlines the challenges presented and the solutions chosen in executing the subsea-production-well construction design for the Captain Area B subsea development (see Fig. 1). It gives an overview of how a blend of proven and emerging technologies can be applied to develop such fields in innovative ways to meet performance metrices.
The Captain field is located in Block 13/22a in the U.K. sector of the North Sea, approximately 130 km northeast of Aberdeen, in a water depth of 369 ft. Because of the high viscosity and low temperature of Captain oil, long, horizontal wells are required to drain the reservoirs effectively (see Fig. 2). Although the field was discovered in 1977, it was not until 1995 that appropriate technology was available and development approval was received. The field was developed as a phased installation of two drilling centers tied back to a centrally located floating production, storage, and offloading (FPSO) vessel (see Fig. 1) by ChevronTexaco and its partner, Korea Captain Co. Ltd. (KCCL), which has 15% equity. The first phase of development consisted of the FPSO vessel and wellhead protection platform (WPP) at the Area A drilling center, 1.5 km west of the FPSO vessel. The second phase is called the Captain Area B expansion and includes a subsea development approximately 2.2 km east of the FPSO vessel to access reserves in the eastern and gas-cap part of the field, called Area B. The process throughput has also been increased by the addition of a bridge-linked platform (BLP) to the WPP (see Fig. 1 for the field layout and Fig. 3 for a Captain field map that highlights areas A and B).
To date, 11 subsea production wells have been drilled from the unitized template manifold (UTM). Two subsea injectors and one delineation well also drilled from the UTM are not covered in this paper. Drilling operations commenced in September 2000 and finished in April 2003. The rig has also worked for other assets during this time.
To meet economic metrics, it was necessary for the Captain expansion to be a subsea development with long drain sections through the unconsolidated sandstone reservoir. Hydraulic submersible pumps (HSPs) with an integral bypass system were also required because they brought good gas-handling characteristics and removed some of the disadvantages associated with subsea electrical submersible pumps (ESPs).1,2 As a result, while these completions have been among the most challenging, through effective risk management of the solutions, they are among the most successful to date in the North Sea. A key milestone in this process was the successful field trial of a prototype HSP on platform well 13/22a-C13, outlined in detail in Ref. 1.
The background information on the geological aspects and the production drivers will outline the requirements for technical solutions, such as extended-reach drilling (ERD), associated long sand-control completions, and state-of-the-art subsea equipment. The impact this had on rig selection and modification is also explained. The performance metrics for the first 11 subsea production wells are testimony to the equipment, design, and execution associated with this development.
Geological Setting and Structure
The Captain field is large [1,000 million bbl of stock-tank oil initially in place (STOIIP)] and shallow [-2,800 ft true vertical depth, subsea (TVDSS)] with heavy oil accumulation. The major reservoirs comprise thin, poorly consolidated, turbiditic sandstones spread over a large (53 km2) area (see Fig. 3). Salient reservoir properties are summarized in Table 1 .
The principal reservoirs belong to the Captain sandstone member of the Carrack formation, which is from the early Cretaceous (Aptian). These are sealed by a very condensed Albian shale sequence, informally referred to as the Sola/Rodby shale, overlain by a thick chalk sequence.
A secondary reservoir is the Ross sandstone member of the Uppat formation, which is of late Jurassic (Oxfordian) age. The Ross is sealed by Kimmeridge clay-formation shales and siltstones.
The reservoir thickness averages 80 ft but ranges from 200 ft in the thickest channels to 0 ft at the southerly pinchout edge. Geological sidetracks are often required to ensure that shale intervals are less than 100 ft at any one spot (see Fig. 4). More details on the geological setting can be found in Refs. 3 through 5, and the wells drilled to date are summarized in Table 2.
Current geophysical mapping is based on an interpretation of a 1990 3D seismic data set. Shallow horizons are generally of good quality in both continuity and character. Below these, the base-chalk horizon forms the principal seismic event used to define the structural form of the underlying Captain sandstone member. Despite the shallow burial depth, Captain reservoirs do not have a clear seismic response because of the thick chalk layer (1,000 to 1,500 ft) that immediately overlies them. This results in a noisy, ambiguous reflection character beneath the strong base of the chalk reflector. Depth-conversion uncertainty is +/-25 ft because of unpredictable variations in the overlying-chalk- and strong lateral-velocity contrasts in the Maureen formation. Reservoir-thickness uncertainty stems from depositional variability.
Early reservoir models5 were driven by the well control, and as the phased development progressed, the long horizontal wells have provided a high-density data set that better constrains sand-body thickness and areal extent.
The data have proved that much of the topographic variation of the base-chalk unconformity reflects sandstone-thickness variation and erosion channels.
Development Areas Within the Captain Field
The stratigraphic element to the trap divides the field into three closure areas - main, eastern, and southern terraces (see Fig. 3). Area B development comprises upper Captain sand (UCS) wells in the eastern part of the main (commonly referred to as the "gas cap") and eastern closures, together with Ross wells along the southern edge of the eastern one.
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