Two CO 2 huff 'n' puff projects were conducted in the 4,900-ft [l495-m] Reservoir (BA) Sand Unit [4900' R(BA)SU], Timbalier Bay field, Louisiana. This reservoir is a bottomwater-drive reservoir with a 26 0 API [0.9-g/cm 3 ] oil gravity and 18% primary oil recovery. Before CO 2 injection, both project wells were gas lifting more than 1,000 BFPD [160 m 3 /d fluid] with 99% water cuts. After CO 2 injection, the production from each well increased to 200 BOPD [32 m 3 /d oil]. This paper discusses the CO 2 huff 'n' puff process, specific reservoir characteristics, and project evaluation. IntroductionWhen properly administered, the CO 2 huff 'n' puff process provides quick payout with a low capital investment. These are important factors when oil prices are difficult to forecast. Timbalier Bay field was chosen to test the injection process because existing CO 2 pipeline and facilities 1 would reduce the investment. The 4900' R(BA)SU was chosen for the huff 'n' puff because of its high residual oil saturation and relatively low API oil gravity. Process DiscussionLimited references are available on the CO 2 huff 'n' puff process despite voluminous publications on CO 2 miscible and immiscible recovery. Khatib et al. 2 summarized the evolution of immiscible CO 2 injection in light and heavy crudes. Monger and Coma's3 research work concentrated on applying the CO 2 huff 'n' puff process on light oils. From their laboratory work on cores at waterflood residual oil saturations and their data base of actual field test results, Monger and Coma concluded that residual oil can be displaced by the cyclic CO 2 injection process. Patton et al. 4 and Haskin and Alston 5 have developed the only two correlations for estimating production responses from the CO 2 huff 'n' puff process. Patton et at. defined two efficiencies to use in evaluating the success of· a huff ' n' puff project. One efficiency is defined as the ratio of incremental oil produced to CO 2 injected. This efficiency should range from 0.5 to 0.8 STB/Mcf [2.8xlO-3 to 4.5xlO-3 stocktank m 3 /m 3 ], with a value of 1 STB/Mcf [5.6x 10-3 stock-tank m 3 /m 3 ] representing ideal conditions. The second efficiency is defined as the CO 2 injection volume per foot of sand. This efficiency should range from 0.1 to 0.2
Individual well performance in the Marcellus Shale of northeastern Pennsylvania varies markedly, even in areas where the lithology, fluid composition, and completion design are consistent. A primary reason for this is the natural fracture system, which influences hydraulic fracture growth, dynamic fluid flow, reservoir pressure and stress behavior. Chief Oil and Gas (Chief) contracted Schlumberger to conduct an integrated study using an innovative modeling approach to quantify the impact of these natural fractures and optimize field development. Working together, the team created an approach that consisted of constructing and coupling three models: a 3D geomechanical model, an unconventional fracture model (UFM), and a 3D dynamic dual-porosity model. The geomechanical model is composed of a discrete fracture network (DFN) containing both regional (J1 and J2 sets) and tectonic fractures. These are interpreted from seismic attributes (anisotropy azimuth, seismic velocity anisotropy) and ant tracking. The UFM model simulates the growth of hydraulic fractures and their interaction with natural fractures in the DFN. Portions of the natural fracture network are assumed to be open tectonic fractures, and their flow properties are adjusted (porosity and permeability) to match well performance. Adjustments are also made to account for production-related perturbations in dynamic stress magnitude and azimuth, which impact later wells. These modifications to the fracture network are critical for history matching the dual-porosity model. The production history match showed that hydraulic fractures and open tectonic natural fractures are key production drivers in the study area, and that the spatial variability of the natural fracture network exerts more influence on well performance than initially thought. The connection between the hydraulic fracture network and portions of the open tectonic natural fracture system enhances parent well access to larger drainage areas. This controls the strongly variable well production observed in the study area. Subsequent stress perturbation resulting from parent well depletion is detrimental to the completion efficiency of the child wells, even even though they have better frac designs with higher proppant loading. The modeling work also shows that the gas-in-place is consistent with volumetric and rate transient analysis (RTA) estimates. The coupling of the three models reasonably approximated changing reservoir conditions and created a nexus of domain expertise including geology, geophysics, geomechanics, stimulation, completions engineering and reservoir engineering. This enabled an understanding of the complex reservoir behavior of the naturally-fractured Marcellus Shale and generation of an optimized fit-for-purpose development plan. Chief was already implementing changes in spacing and increasing the distance between offset PDP (Proved Developed Producing) wells and this study affirmed that revised development plan.
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