Increased deepwater drilling today requires that expensive and risky drillstem testing operations be optimized by other technologies that provide dynamic information about the formations to be tested. Wireline-conveyed interval pressure transient tests (IPTTs) are becoming a common practise today for optimizing and designing these expensive tests. Typically, prior to an IPTT, there is only a limited amount of information available about the reservoir and fluids properties and it tends to be generally probabilistic. Therefore, the optimal design of IPTT tests is a necessary challenge for a successful and reliable test. IPTT is found to be dependent on the noise and on observable flow regimes associated with the pressure buildups. Success and reliability are not only a function of gauge metrology but also of the formation deliverability and geometry. This paper describes a new methodology for IPTT design that allows estimation of the reliability of these transient tests. A normally distributed random noise is superimposed on the analytical pressure profile computed for a given formation, fluid PVT properties, and gauge metrology. The success of an IPTT in a particular environment is estimated based on the theoretical pressure derivative and noise-superimposed pressure derivative. This approach is repeated for a range of rock, and fluid properties and practical limits to identify what is a successful. Two field examples are presented to validate this methodology.
The ultra-high pressure and temperature (HPHT) lower Cretaceous sand-shale layer in Krishna-Godavari basin (KG basin) (Fig. 1), in eastern India offshore shallow water, in the Godavari River interdeltaic region, is currently the world's highest-temperature petroleum reservoir being explored in the marine environment. It is a part of the fluvial sedimentary KG basin, which is recognized as holding India's largest gas reserves. Its area is approximately 50,000 km 2 and it extends from land to the shelf-slope and adjacent deep-sea area along the eastern passive continental margin of India. The bottomhole static temperature of the reservoir ranges from 350 to 450°F at 16,000 to 18,000 ft true vertical depth (TVD), with pore pressure gradient up to 0.85 psi/ft. The hydraulic propped fracturing technique is integral to the completion and well testing program in this typical tight reservoir.The design and delivery of hydraulic propped fracturing in such a complex reservoir and operational environment requires advanced technologies and meticulous planning and execution, including reservoir and geomechanical characterization derived from latest HPHT formation evaluation logging tools, implementation of integrated production simulation and fracturing modeling software, and application of ultra-HT completion and fracturing products. In addition to technical complexity, the limited drilling unit capability also required equipment planning that involved an integrated fracturing and testing wellheadstring-packer system, a project-specific modular HPHT stimulation boat and post-fracture flowback testing plan and equipment that included surface well testing and a coiled tubing nitrogen fleet.Several successful hydraulic fracturing operations were performed in this tight ultra-HPHT reservoir for multiple operators. This paper will describe the case history of the hydraulic fracturing completion campaign for one operator in the basin, in particular describing ultra-HPHT techniques and products that were key to the project delivery:• Basin modeling, reservoir, and geomechanical characterization workflow as an integral part of hydraulic fracturing design in complex frontier reservoir • Installation and preparation of modular HP/HT stimulation vessel custom built for this project • Implementation of synthetic fracturing fluids developed specifically for ultra-HT application up to 450°F in a high-pressure and high-shear environment.
Reservoir-fluid properties play a key role in exploration and field development planning as accurate fluid characterization is important for designing reservoir development strategy, optimizing well completion, optimizingthe production system and efficient reservoir management. Characterization of reservoir fluids with more complex behaviors, such as gas condensates and near-critical fluids can be technically challenging, especially in a deepwater environment as reservoir development planning and production facility design is contingent on getting an accurate description of the reservoir fluid. Fluid characterization begins with the collection of representative formation fluid samples during initial wireline formation testing, bottomhole sampling and during conventional well testing operations. Traditionally these fluid samples are sent to offsite laboratories for sample analysis. However, characterizing a gas condensate fluid system based on a single sample set can be potentially misleading since PVT properties of samples acquired across a reservoir may be different due to spatial variation in their components and compositional grading. In this technical contribution we present a case study to demonstrate that characterizing gas and gas-condensate systems using only a basic set of measurements and from analysis of pressure gradients alone; could lead to potentially ambiguous results, an inappropriate fluid model or misinterpretation. In our study, we describe the practical application of advanced wireline formation sampling and testing techniques in combination with downhole fluid analysis, and their integration with laboratory PVT studies and equation-of-state (EOS) models. We describe the importance of a comprehensive data collection and fluid analysis plan early in the exploration/ appraisal process, and illustrate how high-quality fluid sample data and property measurements from advanced formation sampling and testing tools in combination with conventional well testing techniques can add significant value by helping to reduce uncertainty and aiding better technical decision making.
One goal for oil fields of the future is acquiring continuous and on-demand data as required for field and reservoir management. Synthetic time-lapse production methods are becoming a way of providing this information at and away from wells. Time-lapse production log data acquired over oil fields is used to monitor water sweep in the reservoir. Production logs provide a direct measure of the fluid flowing downhole and detect the unwanted fluid entries. In field applications, this advanced scanning of fluid profiling successfully derisked several infill well locations and identified new workover candidates and drilling opportunities in the fields. Synthetic time-lapse production logging is a useful complement to understanding reservoir heterogeneity and complexity through tailored synthetic and real data integration. A computer-based workflow has been developed to automate the downhole production flow profile. Production performance of the well is assessed, considering the dynamic time-lapse logging data. A synthetic flow profile is constructed to show the change in water production signature, and the well is further examined if it undergoes remedial actions. Reservoir characterization is a continuous process during the life of the oil field. As new data are available, the model is updated and contains more details. The incorporation of all data allows increased accuracy and reduced uncertainty in characterizing the reservoir. The proposed methodology requires the acquisition of dynamic production logging data to establish a solid workflow and validate the model. Uncertainty can be eliminated with the acquisition of additional production logs. Recommendations for improvement of the current well condition can be made to reduce the well water cut and improve oil production from the well. Consequently, well classification and candidate selection for workover can be achieved. The results of this work demonstrate the strength of applying multidisciplinary team efforts to develop automated workflows that are relevant to reservoir and production engineers who deal with complex reservoirs with numerous wells.
One goal for oil fields of the future is acquiring continuous and on-demand data as required for field and reservoir management. Synthetic time-lapse production methods are becoming a way of providing this information at and away from wells. Time-lapse production log data acquired over oil fields is used to monitor water sweep in the reservoir. Production logs provide a direct measure of the fluid flowing downhole and detect the unwanted fluid entries. In field applications, this advanced scanning of fluid profiling successfully derisked several infill well locations and identified new workover candidates and drilling opportunities in the fields. Synthetic time-lapse production logging is a useful complement to understanding reservoir heterogeneity and complexity through tailored synthetic and real data integration. A computer-based workflow has been developed to automate the downhole production flow profile. Production performance of the well is assessed, considering the dynamic time-lapse logging data. A synthetic flow profile is constructed to show the change in water production signature, and the well is further examined if it undergoes remedial actions. Reservoir characterization is a continuous process during the life of the oil field. As new data are available, the model is updated and contains more details. The incorporation of all data allows increased accuracy and reduced uncertainty in characterizing the reservoir. The proposed methodology requires the acquisition of dynamic production logging data to establish a solid workflow and validate the model. Uncertainty can be eliminated with the acquisition of additional production logs. Recommendations for improvement of the current well condition can be made to reduce the well water cut and improve oil production from the well. Consequently, well classification and candidate selection for workover can be achieved. The results of this work demonstrate the strength of applying multidisciplinary team efforts to develop automated workflows that are relevant to reservoir and production engineers who deal with complex reservoirs with numerous wells.
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