Yeh, Charles S. (ExxonMobil Upstream Research Co.) | Grueschow, Eric Russell (ExxonMobil Upstream Research Co.) | Bhargava, Peeyush (Exxon Mobil Corporation) | Burdette, Jason (ExxonMobil Upstream Research Co.) | Barry, Mike D. (ExxonMobil Development Co.) | Hecker, Michael Thomas (ExxonMobil Development Co.) | Dale, Bruce A. (ExxonMobil Upstream Research Co.)
Long, multi-zone openhole completions have the benefits of maximizing reservoir contact and reserve captures with fewer wells, particularly for deepwater or remote environments. When producing from loosely consolidated or unconsolidated reservoirs, openhole completions are challenged by well longevity, zonal isolation, and subsurface control. Conventional gravel packs and standalone screen applications, along with the selection and design guidelines are being pushed to the limit. A new generation of sand control technologies is needed to meet these challenges.
This paper highlights ExxonMobil's technology integration and hardware innovation in bringing flexibility, adaptability, and reliability to openhole sand control. Technology integration reduces uncertainties in conventional sand control selection and design guidelines, which have been based on sand prediction, well design, and grain size from selected formation samples. An analytical, log-based grain size analysis was introduced to link a Rosin-Rammler formula to formation properties. A limit-based analysis links formation strength or sanding potential to operating conditions including production rate, influx, drawdown, and depletion. Integrating log-based grain size, limit-based analysis, and conventional guidelines to the entire completion interval enables a more flexible and reliable sand control design. Further integration with Well Operability Limits allows production throughout well life without geomechanical failure of the completion.
A series of innovative, enabling hardware has been developed in collaboration with service suppliers. The internal shunt Alternate Path® technology with true zonal isolation enables gravel packing multi-zones and extended lengths in openholes. The self-mitigating MazeFlo® technology enhances sand screen reliability in standalone screen completions or workovers. Both hardware technologies adapt to downhole uncertainties to achieve more reliable sand control. Emerging technologies like inflow control devices and sliding sleeves can be incorporated to control production flow in selective zones.
ExxonMobil's technology integration and innovation provide a distinguishing platform for openhole sand control. This platform positions openhole sand control completions for extended lengths, multiple zones, as well as production control.
Hsu, Sheng-Yuan (ExxonMobil Upstream Research) | Searles, Kevin Howard (ExxonMobil Upstream Research) | Liang, Yueming (ExxonMobil Corporation) | Wang, Lei (ExxonMobil Upstream Research) | Dale, Bruce A. (ExxonMobil Upstream Research) | Grueschow, Eric Russell (ExxonMobil Upstream Research) | Spuskanyuk, Alexander (ExxonMobil Upstream Research) | Templeton, Elizabeth (ExxonMobil Upstream Research) | Smith, Richard James (Imperial Oil Resources Ltd.) | Lemoing, Daniel R.J. (ExxonMobil Qatar)
The Cold Lake heavy oil development is located in northeast Alberta, Canada. It began commercial operation in 1985 and uses a thermal recovery process called cyclic steam stimulation (CSS). During steaming cycles, the dilation and re-compaction that occur within the reservoir cause the overburden to deform much like the motion of flexing a thick telephone book. At weak overburden layers, shear slip plane(s) can form due to excessive shear stress overcoming the interlayer cohesion. Over multiple steaming/production cycles, the cyclic flexing and associated shear slip may lead to overburden casing fatigue failures.
In this paper, a multi-scale geomechanics modeling methodology is presented to predict the onset of failure due to CSS-related ultra low cyclic fatigue (ULCF). The modeling methodology consists of: (i) converting geological data into a representative finite element model of a single or multiple CSS pads, (ii) constructing a near-well submodel that includes thermal cement and casing, and (iii) constructing a detailed casing and connection submodel to predict the ULCF life of a pipe body or connection.
To predict the ULCF life of the casing and connection, an algorithm based on the concept of cyclic void growth is incorporated into the submodel. It provides the capability to predict the number of steam cycles to failure using the concepts of demand and capacity. This enables studying the effects of alternative steaming practices on overburden shear slip and casing/connection life.
Based on the learning from the multi-scale modeling, it is found that shear displacements on a shear slip plane can be superimposed using a single-well solution. By applying steaming and production scaling functions, the shear slip can be determined at any location and time. Integration of the single-well solution with ULCF algorithm has facilitated development of a new software tool that can be used to manage CSS operations in Cold Lake.
Grueschow, Eric Russell (ExxonMobil Upstream Research Co.) | Dale, Bruce A. (ExxonMobil Upstream Research Co.) | Pakal, Rahul (ExxonMobil Upstream Research Co.) | Haeberle, David (ExxonMobil Development Co.) | Wallace, Jon (ExxonMobil Upstream Research Co.) | Asmann, Marcus (ExxonMobil Upstream Research Company)
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.
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: