Summary Big reservoirs in deepwater Gulf of Mexico (GOM) 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 deepwater 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 GOM 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 is relatively limited. With relatively few analogs, the Ursa and Princess fields are set to embark on major facilities expansion and subsea development. The aim is to deliver a high rate of specific-quality water through four subsea-injection wells into a vast and, largely thirsty, reservoir. Ursa and Princess reside 100 miles south/southeast of the Mississippi River mouth in the Mars basin, 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 in common and are in pressure communication. The working interest in the Ursa and Princess fields are Shell (45--operator), BP (23%), 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 pressure-volume-temperature measurement samples. Because of limited TLP well availability, the 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. Five TLP wells are to be sidetracked updip or recompleted at a later stage. High injection rates are required to replace voidage and maintain reservoir pressure above bubblepoint. Initial injection rates per well (annual average) of 30 to 40 thousand BWPD are required. This injectivity can only be maintained by creating fractures. With the wide well spacing relative to fracture length, this is not expected to negatively impact sweep efficiency. However, because of the uniqueness of well spacing and reservoir volumes, there is a lack of analog-data points to calibrate the outcomes. Parallel evaluation of the viability of artificial lifting has shown that TLP waterflood producers would benefit from gas lifting. The base plan for waterflood wells thus includes the requirement for gas-lift completions and facilities. The original Operating Health Safety and Environmental (HSE) case for the asset did not include the potential threat of reservoir souring after seawater injection. The well casing and tubular materials, therefore, have limited resistance to sulfide-stress corrosion cracking. This resulted in the need to recomplete the Ursa TLP direct-vertical access (DVA) wells with Shell-qualified tubing. Princess producers already have Shell-qualified C100 sour-resistant casing, and will not require pre-emptive intervention for tubing change out.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn the last few years, Shell has implemented three deepwater waterflood systems. They are all on floating installations, employ relatively compact and light weight facility designs and are roughly the same capacity. While their overall designs are similar, important details of the designs are different, and the project management strategies were significantly different as well. The startup and initial run time experience of these waterfloods facilities differed greatly, ranging from significant downtime for the first project to nearly complete success for the last one. Shell is in the process of sanctioning a forth deepwater waterflood system that is larger and more complex than the previous three. Obviously, Shell has already learned a great deal about how to successfully implement a deepwater waterflood project. Before we develop the new project however, we are capturing our waterflood experience to date.

This paper will discuss the review, integration assessment, engineering analysis, and process safety analysis carried out prior to installing a managed pressure drilling (MPD) system on a classed floating mobile offshore drilling unit (MODU). MPD techniques have proven cost-effective, reliable, and safe when drilling difficult onshore wells, as well as drilling from MODUs with a surface blowout preventer (BOP). However, the implementation of MPD on deepwater wells has been hampered by industry inertia and questions about reliability, barriers, riser gas management (RGM), and general riser interface issues. This paper will focus on those distinctly different aspects introduced by MPD while drilling from a floating MODU. The primary objective will be to highlight how innovative application of MPD can enhance safety when drilling challenging wells in deep water.Additional insights are provided regarding experience from several MPD installations on deepwater rigs around the world that have been tasked with drilling challenging wells.The process employed in these discussions are mainly centered on the following major categories of MPD equipment and methods:• Installing and operating a rotating control device (RCD) below the ocean's surface, including integration with a riser gas handling device. • Redundancy and fail-safe considerations for valving, both for flow lines and control lines. • Piping, umbilicals, and hoses in the moon pool area. • Nodal safety assessment of the system. • An Operator-Contractor-Service Company 'bridged' well control philosophy.The procedures will recount safety considerations of equipment classifications and system certification for MPD systems used on deepwater rigs.The lessons learned during this project help to establish a baseline for standardizing MPD drilling equipment and systems for global applications. The knowledge gained also was instrumental for the classification society certifying this equipment and system to develop safety and certification requirements aimed at improving MPD safety on deepwater drilling units. This paper will outline the core steps taken to achieve classification of an MPD system for a MODU, as well as enable increased utilization of MPD methods in deepwater wells worldwide. Class and certification can provide greater confidence to offshore operators that they can commission drilling equipment and systems capable of delivering safer, more dependable MPD wells, some of which may be considered un-drillable using conventional methods.