Many current deepwater and high rate wells are being completed in an openhole environment as openhole completions provide the greatest opportunity to maximize reservoir flow potential. Current technology, however, lacks the subsurface control necessary to effectively manage the reservoir in situations where sand control is required. ExxonMobil is pioneering technologies to model well performance more accurately and to provide subsurface control during completion and production operations. The first hardware developments within this initiative build on the success of Alternate Path® and NAFPacSM gravel packing technologies and address water or gas breakthrough in openhole, multi-zone gravel pack completions. ExxonMobil affiliates collaborated with third party suppliers to design and qualify new hardware to facilitate zonal isolation, extend gravel pack reach, and simplify rig site operations. This process included engineering design, component testing, and full-scale prototype evaluation. First application of this technology is targeted for early 2008. This paper discusses newly developed sand control screen hardware that is enabling technology to perform openhole gravel packs with true zonal isolation. The equipment provides the ability to seal off bottom water, selectively complete or gravel pack targeted intervals, perform a stacked openhole completion, or isolate a gas/water-bearing sand following production. Application of the technology is expected to extend well life and ultimately increase volumes and reserves capture. Background Continued economic success in remote or deepwater environments requires delivery of high rate, high capacity, and long-life wells. In these developments, it is often necessary to drill and complete high angle wells, penetrating multiple pay intervals and incorporate sand control technologies. Reservoir conditions, wellbore geometry, and production performance expectations can all introduce significant cost and complexity that frequently limit application of traditional cased hole sand control techniques. Openhole gravel pack completions are now commonly installed to connect multiple payzones over long intervals and improve well productivity. Because openhole completions have no perforation tunnels, formation fluids can converge on the wellbore radially from 360 degrees, thus eliminating the additional pressure drop associated with converging flow and then linear flow through gravel filled perforation tunnels. The reduced pressure drop, associated with an openhole sand control completion, virtually guarantees that it will be more productive than an unstimulated, cased hole gravel pack in the same formation. Operationally, openhole techniques eliminate the need for costly cementing, perforating, and clean-up operations, the complexity of stacked completions, and in some areas an additional casing string or liner. The downside, however, is that openhole completions do not have the same level of installation flexibility and subsurface control to manage geologic and reservoir uncertainty versus traditional cased hole gravel pack techniques. Operators are particularly challenged in their ability to manage fluid inflow along the wellbore in openhole completions, including avoidance of watered-out or depleted zones during installation and shutting off unwanted water and gas during production.

The Erha field is a deepwater subsea oil development located in OML 133 off the coast of Nigeria. Erha North is a satellite of the Erha Field and is characterized by multiple unconsolidated sand intervals separated by shale sections. Due to the potential for reservoir compaction and early water breakthrough in these multi-layered Erha North reservoirs, high rate water injection is an important element of primary production through pressure support and is considered critical to project economics and reserves capture. This paper presents a case history of a successful field application of an innovative water injector completion technique addressing the issue of long-term injection conformance. Standalone screens with flow-control devices (i.e., downhole chokes) and openhole packers were utilized on the two most challenging water injectors in the Erha field. The completion objectives were:(a) target multiple intervals to reduce well count and cost,(b) sustain target injection rates and allocations, and(c) install sand control to prevent wellbore fill. Traditional water injector completion techniques, such as frac packs or openhole standalone screens, were judged to be incapable of meeting all the completion objectives. Unfractured completions, such as openhole standalone screens, have been reported to lose injectivity over time due to plugging and require fracturing to sustain injection rates (Sharma 2000). Fracturing may result in poor injection conformance and has the potential for broaching cap shale. Application of stacked completions or intelligent well systems would have added significant cost and complexity. Detailed completion simulations and fracture modeling were conducted to design the completions to their unique geologic settings. It is expected that this completion technique will maintain the desired injection allocations to the multiple target intervals over the well life in the matrix and fracture injection regimes. Upfront planning, communication, and alignment between reservoir, subsurface, and drilling functions enabled a successful real-time completion design and resulted in an operational success with less than 5% completion non-productive time (NPT). Performance of the injectors is being monitored by downhole pressure and temperature gauges. Introduction Water injection has been a successful secondary recovery technique in the oil industry for many years. In the past 10 to 15 years, however, projects have been developed where high-rate water injection is a primary recovery method because completion reliability and economic constraints require early voidage replacement and pressure support. As water injection becomes integral to the economic justification for capital intensive (i.e., offshore, subsea) projects, considerable attention to the design and performance of the water injectors is required. Regardless of rock cementation, there are very few documented cases of long-term, high-rate water injection without some form of continual or periodic stimulation. In well cemented rock formations, successful high-rate water injection programs rely on continual formation fracturing. Highly compressible, uncemented sands such as those found in many deepwater reservoirs, including those in the Erha North Field, do not easily fracture. High-rate water injection into such sands has been very difficult for some operators even when these sands have multi-Darcy permeability. In Yemen, one operator has experienced a "check valve phenomena" when attempting to inject water into an uncemented formation. Formation water was produced at a productivity index of 400 bwpd/psi, but later attempts to reinject that same water resulted in an injectivity index of less than 10 bwpd/psi (Wilkie 1996).

Physics-based well performance modeling technology has been developed that establishes Well Operability Limits (WOLs) to mitigate well failures due to the complex geomechanical loads resulting from compacting reservoirs. This new technology assists in active reservoir management by both limiting the producing drawdown pressure on wells most susceptible to failure and providing confidence in increasing drawdown pressure on wells determined not to be susceptible. In 2000–2001, ExxonMobil experienced three unexpected reservoir compaction well failures during the start-up of the deepwater Diana/Hoover project in the Gulf of Mexico. This experience led to the development of advanced well performance modeling technology which was used to assess ExxonMobil's worldwide portfolio for potential compaction related well failures. WOLs have now successfully been used to manage nearly 100 deepwater wells without failure since 2001 and are actively used to establish completion and production strategies for wells in many other types of producing assets worldwide. Implementation of this technology has not only prevented well failures and associated production disruption due to reservoir compaction, but also enabled safe increases in well drawdown and accompanying increases in production rates beyond previous industry experience. This paper focuses on the application of WOL technology to ExxonMobil deepwater wells. The general methodology and development of the reservoir compaction WOL technology will be introduced. Selected case studies will highlight the successful application of the technology as well as illustrate the operating strategies and the subsequent production benefits. WOL technology has significantly improved ExxonMobil's ability to operate wells without incurring costly well failures by more clearly defining the complex limits of compacting reservoirs. Background Ensuring long-term well integrity and optimum completion performance is important for the economic development of any field. As fields are developed with fewer wells and in more technically challenging environments, analysis is required to deliver reliable wells that can be operated at the high rates required to meet today's aggressive production targets. Long-term well integrity is essential for commercial deepwater field development. Operators cannot rely on historical industry practices based on aggregate historical data, anecdotal evidence, and simplified analytical models to prevent well failures while simultaneously maximizing well production and reservoir recovery. This is especially true in deepwater environments, where reservoir characteristics are significantly different than in the fields that serve as the basis for historical practices and the cost of well intervention to recover from a failure is substantial. Well failures due to compaction and subsidence have been experienced for decades in various environments and are summarized briefly below:Wilmington Field - One of the first ExxonMobil experiences with subsidence occurred at the Wilmington field located onshore California. Production began in 1936, and 7 feet of subsidence occurred by 1947, the time of the earliest casing failures. Horizontal movements of 9 inches were documented in three weak shale layers above the producing reservoir (Allen, 1959).

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