No abstract

Characterization of complicated reservoir architecture with multiple compartments, baffles and tortuous connectivity is critical; additionally, reservoir fluids undergo dynamic processes (multiple charging, biodegradation and water/gas washes) that lead to complex fluid columns with significant property variation. Accurate understanding of both reservoir and fluids is critical for reserve assessment, field management and production planning. In this paper, a methodology is presented for reservoir connectivity analysis, which integrates reservoir fluid property distributions with an asphaltene Equation of State (EoS) model developed recently. The implications of reservoir fluid equilibrium are treated within laboratory experimentation and equation of state modeling. In addition to cubic EoS modeling for light end gradients, the industry's first asphaltene EoS the Flory-Huggins-Zuo EoS is successfully utilized for asphaltene gradients. This new EoS has been enabled by the resolution of asphaltene nanoscience embodied in the Yen-Mullins model. Specific reservoir fluid gradients, such as gas-oil ratio (GOR), composition and asphaltene content, can be measured in real time and under downhole conditions with downhole fluid analysis (DFA) conveyed by formation tester tools. Integration of the DFA methods with the asphaltene EoS model provides an effective method to analyze connectivity at the field scale, for both volatile oil/condensate gas reservoirs with large GOR variation, and black oil/mobile heavy oil fields with asphaltene variation in dominant. A field case study is presented that involves multiple stacked sands in five wells in a complicated offshore field. Formation pressure analysis is inconclusive in determining formation connectivity due to measurement uncertainties; furthermore, conventional PVT laboratory analysis does not indicate significant fluid property variation. In this highly under-saturated black oil field, measurement of asphaltene content using DFA shows significant variation and is critical for understanding the reservoir fluid distribution. When integrated with the asphaltene EoS model, connectivity across multiple sands and wells is determined with high confidence, and the results are confirmed by actual production data. Advanced laboratory fluid analysis, such as two-dimensional gas chromatography, is also conducted on fluid samples, which further confirms the result of the DFA and asphaltene EoS model.

No abstract

Characterization and understanding of compaction and fines migration, through integration of laboratory and field data, identified the need for stimulation treatments which proved to be very successful. Pressure transient testing was used to assess performance of wells in the Ewing Bank Block 873 field, which produces from Gulf of Mexico deepwater turbidite sands. Analysis of cores from delineation wells clearly indicated that significant permeability reduction can be expected due to compaction as the reservoir pressure depletes. Of particular interest was the effect of permeability reduction and suspected fines migration on long-term well productivity. A sequence of pressure buildups obtained during the first 2.5 years of production indicated continual decline of reservoir permeability. Trends measured in the field were similar to those observed from core analysis. However, permeability reduction, as inferred from calculated skin values, appeared more severe near the wellbore. To validate this interpretation, a single-well numerical model was constructed to examine the effects of compaction in the near-wellbore region. Skin factors calculated from simulated buildups were consistently lower than determined from field data. The difference was attributed to fines migration which was not included in the numerical model. Based on model simulation results, in conjunction with detailed evaluation of mineralogy, stimulation treatments were designed and successfully implemented. The resultant reduction in skin factor provided further support for the identification of fines migration as the damaging mechanism. This paper demonstrates that routine pressure buildup testing is effective in monitoring the dynamic changes in well productivity in turbidite sands. Introduction The Ewing Bank Block 873 field is located approximately 200 miles south of New Orleans, Louisiana in the Gulf of Mexico and was discovered in late 1991. Three delineation wells were drilled over the following 12 months to define the productive limits of the Pliocene age Bulminella (Bul-1) reservoir. The hydrocarbon-bearing sands in this over- pressured reservoir are located at an average depth of 11,000 ft subsea. Oil gravities range between 15 and 26 API. The production platform, located in 775 ft of water, was installed during the summer of 1994 with first oil production occurring in August of that same year. Rock compaction and resulting fines migration can negatively affect production rates and ultimate recovery. This is especially true for poorly consolidated sands as found in the Ewing Bank Block 873 field. Production withdrawals from the reservoir cause pore pressure to decrease which allows the weight of the overlying formations to compact the reservoir sands. Changes in sand grain packing and pore geometry along with grain crushing can lead to fines generation, reduction in reservoir permeability, and declines in well productivity. During early field evaluation, it is crucial to determine if sands in the newly discovered reservoir are susceptible to this phenomenon. An understanding of this relationship can only be developed through laboratory core testing. Trends from these compaction studies should be integrated into the various development scenarios being considered. The economic viability of a project is directly linked to the production forecast and resulting cash flow. Overly optimistic production schedules may be inadvertently generated if the negative effects of rock compaction are not properly taken into consideration. Based on these concerns, a comprehensive evaluation program was implemented during early delineation of the field. Laboratory experiments performed on whole core samples were designed to provide insight into both rock compaction and relative permeability behavior. Literature is readily available which discusses laboratory experiments and the theory behind rock compaction measurements; however, actual case histories are limited. P. 289^