Challenges of Waterflooding in a Deepwater Environment
- Karen Bybee (Assistant Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- June 2007
- Document Type
- Journal Paper
- 50 - 51
- 2007. Offshore Technology Conference
- 1 in the last 30 days
- 157 since 2007
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This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18523, "Challenges for Waterflooding in a Deepwater Environment," by Azhar Alkindi, SPE, Shell; Robert Prince- Wright, Riskbytes; and Wesley Moore, SPE, John Walsh, Lee Morgenthaler, and Cor Kuijvenhoven, SPE, Shell, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.
The waterflood study team for the deepwater Ursa/Princess field evaluated various challenges affecting the surface and subsurface aspects of the development plan. The design for an optimum injection rate was a bottom-up process from the reservoir to the topside injection facilities. Reservoir-sweep efficiency and reservoir-pressure distribution dictated injection-well designs and injection-pump sizing. Subsurface risks, such as reservoir souring and hydrate formation, dictated material selection and completion design.
Ursa and Princess fields are 100 miles south-southeast of the Mississippi River mouth in the Gulf of Mexico (GOM) Mars basin. The Ursa field was discovered in 1990 and has been producing since 1999. The Princess field was discovered in 2000 and has been producing since December 2003 through a subsea tieback to Ursa. The fields have common main reservoirs (the Yellow) and are in pressure communication.
Because of limited tension-leg-platform (TLP) well availability, high cost of subsea wells, and the limitations of the subsea system to handle large water cuts, the waterflood will use relatively few injectors. The proposed base plan has four water injectors: two into Princess and two into Ursa. Producing wells will include three Princess subsea wells and four Ursa TLP wells.
High injection rates are required to replace voidage and maintain reservoir pressure above bubblepoint. Initial injection rates per well (annual average) of 30,000 to 40,000 BWPD are required.
Because the original operating health, safety, and environmental (HSE) case for the asset did not include the potential threat of reservoir souring after seawater injection, well-casing and -tubular materials have limited resistance to sulfide stress corrosion cracking (SSCC). This resulted in the need to recomplete the Ursa TLP direct-vertical-access (DVA) wells with qualified tubing. Princess producers already have C100 sour-resistant casing and will not require tubing change out.
The number of wells was optimized during a number of vital reviews. Sweep efficiency and return on investment were the main optimization criteria for the required total water-injection rate per day. Approximately 50% of the total project capital expenditure is related to drilling and well completion. Because economics is the dominating decision criterion for injector number, optimizing the fine details of the well bottomhole locations, well geometry, and well-completion designs retains prime importance.
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