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Delek Group agreed to buy nearly all of Chevron's holdings in the UK North Sea for $2 billion. For the Israeli independent, the acquisition of stakes in 10 fields, four of which it will operate, is part of its program to build an international oil company focused on offshore production. The company recently bought Shell's 22.45% stake in the Caesar-Tonga field in the US Gulf of Mexico for $965 million. "We see exciting growth opportunities in the North Sea," said Asi Bartfeld, chief executive officer for Delek Group. The North Sea acquisition will increase Delek's production by 80,000 BOE/D, 60% of which is liquids, and adds 225 MMboe to its 2P reserves, according to the announcement.
Chemical flooding is one of the classical EOR methods, together with thermal methods and gas injection. It is not a new method; indeed, the first polymer flood field pilots date back to the 1950s while the first surfactant-based pilots can be traced back to the 1960s. However, while both gas injection and thermal methods have long been recognised as field proven and are being used at a large scale in multiple fields, it is not the case for chemical EOR.
Although there have been over 500 polymer flood pilots recorded, and almost 100 surfactant-based field tests, large scale field applications are few and far between. This situation seems to be evolving however, as more and more large scale chemical projects get underway. This paper proposes to review the status of chemical EOR worldwide to determine whether it is finally coming of age.
The status of chemical EOR projects worldwide will be reviewed, focusing on recent and current large-scale field developments. This will allow to establish what is working and where the industry is still encountering difficulties. This review will cover North America, South America, Europe, the Middle East, Asia and Africa.
It is clear that polymer flooding is now indeed becoming a well-established process, with many large-scale projects ongoing or in the early stages of implementation in particular in Canada, Argentina, India, Albania and Oman in addition to China. Strangely enough, the US lags behind with no ongoing large-scale polymer flood.
The situation is more complex for surfactant-based processes. At the moment, large-scale projects can only be found in China and – although to a lesser extent – in Canada. The situation appears on the brink of changing however, with some large developments in the early stages in Oman, India and Russia. Still, the economics of surfactant-based processes are still challenging and there is some disagreement between the various actors as to whether surfactant-polymer or alkali-surfactant polymer is the way to go.
This review will demonstrate that polymer flooding is now a mature technology that has finally made it to very large-scale field applications. Surfactant-based processes however, are lagging behind due in part to technical issues but even more to challenging economics. Still there is light at the end of the tunnel and the coming years may well be a turning point for this technology.
Rae, G. (ChevronTexaco Upstream Europe) | Hampson, J. (ChevronTexaco Upstream Europe) | Hiscox, I. (ChevronTexaco Upstream Europe) | Rennie, M. (ChevronTexaco Upstream Europe) | Morrison, A. (ChevronTexaco Upstream Europe) | Ramsay, D. (ChevronTexaco Upstream Europe)
Summary 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. Introduction 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). 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 km) 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. Geological Uncertainty. 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 models 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.