Challenges for Waterflooding in a Deepwater Environment

Abstract

Big reservoirs in deepwater Gulf of Mexico typically produce at world-class rates. The scale of investment is likewise world-class. The energy industry's drive to invest in enhanced oil recovery from deep-water basins is sustainable in a world of volatile oil prices and increasing demand for energy. However, project economics will continue to depend on accurate risk assessment, risk mitigation strategies, and more fundamentally, progressive deployment of evolving technologies in ‘brownfield’ deepwater secondary recovery projects. Details of well geometry and design optimizations may prove to be minor sensitivities in high cost deepwater developments, however rig rate has a major impact on economics. The assessment required to minimize the number of injectors and ensure their proper placement logically takes more time than exotic choices of injection patterns. With such major constraints in mind, an optimal design for wells and materials has to take precedence. Accepting this as a given, additional, more common, challenges would then follow. The waterflood study team for the deepwater Ursa- Princess field, in the Gulf of Mexico, has spent appreciable time and effort evaluating various potential challenges affecting the surface and subsurface aspects of the development plan. The design for an optimum injection rate was a bottom-up process starting from the reservoir up to the topsides injection facilities. Reservoir sweep efficiency and reservoir pressure distribution logically dictated injection well designs and injection pump sizing. Subsurface risks, such as reservoir souring and hydrate formation, dictated materials selection and completions design. This paper addresses the challenges primarily affecting the design of the deepwater subsea injection wells. In addition to the well cost, several other underlying factors have played an influential role in defining the boundary conditions for the injectors design. Background Industry-wide experience in the execution and the operation of waterflood projects in deepwater environments relatively limited. With a relatively few analogues, the Ursa and the Princess fields are set to embark on major facilities expansion and subsea development. The aim is to deliver high rate of specific quality water though four subsea injection wells into a vast and, largely thirsty, reservoir. Ursa and Princess reside 100mi SSE of the Mississippi River mouth in the Mars Basin, Gulf of Mexico (GOM). The Ursa field was discovered in 1990 and has been on production 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 their main reservoirs common and are in pressure communication. The working interest in the Ursa and Princess fields are Shell (45.4% operator), BP (22.7%), ExxonMobil (16%), and ConocoPhillips (16%). The Yellow reservoir is the main reservoir at both Ursa/Princess and Mars, the other major field in the Mars basin. It is a world class Upper Miocene turbidite reservoir that stretches across the Mars Basin, including the Mars Field. This 12,000-acre reservoir is charged with light oil type, though with slight variations in properties as indicated by the analysis results of the abundant PVT samples.

Expandable Tubulars Facilitate Improved Well Stimulation and Well Production

“…Initial injection rates per well (annual average) of 30 to 40 thousand BWPD are required. (Al-Kindi 2007) For gravel pack or frac pack operations typically associated with these deeper and/or more complex wells, larger production conduits, as previously noted, support installation of larger sandface completions that allow for larger workstrings. Larger workstrings support larger gravel packing/frac packing components, higher volumes and better transport of materials, and higher pump rates associated with many of the deepwater projects.…”

Reservoir Souring in a Field With Sulphate Removal: A Case Study

“…All three possibilities could involve sulphate-reducing bacteria (SRB) and/or sulphate-reducing archaea (SRA), together identified as sulphate-reducing prokaryotes (SRP) ). The implementation of sulphate-removal can be expected to greatly reduce the potential for reservoir souring (Alkindi et al, 2007, andWalsh et al, 2008), but is unlikely to entirely prevent it, depending on the level of sulphate reduction achieved by the sulphate rejection membranes (SRM) in the sulphate removal unit (SRU), unless combined with other mitigation factors, e.g. high temperatures and/or the presence of H 2 S-scavenging minerals such as iron carbonate (siderite), within the reservoir rocks.…”