Two new methods were developed for anaerobically sampling polymer solutions from production wells in the Sarah Maria polymer-flood-pilot project in Suriname. Whereas previous methods indicated severe polymer degradation, the improved methods revealed that the polymer propagated intact more than 300 ft through the Tambaredjo formation. Our results may help explain the inconsistency between good production responses and highly degraded polymer observed in many past field projects. Analysis of produced salinity, polymer concentration, and viscosity indicated that the polymer banks retained low salinity and, therefore, high viscosity for much of the way through the Sarah Maria polymer-flood-pilot pattern. A strong shear-thickening rheology was observed for 1,000 ppm and 1,350 ppm hydrolyzed polyacrylamide (HPAM) solutions in porous media, even though the salinity was only 500 ppm total dissolved solids (TDS). Examination of injectivities revealed that these solutions were injected above the formation parting pressure in the Sarah Maria polymer-injection wells. Injectivity was insufficient until fractures were initiated hydraulically; however, the fractures propagated a distance of only approximately 20 ft and did not jeopardize sweep efficiency. In contrast, the short fractures greatly improved polymer injectivity and reduced concern about polymer mechanical degradation.The Sarah Maria Polymer-Flood Pilot Reservoir Description. Staatsolie's Sarah Maria polymer-flooding-pilot project in the Tambaredjo field (Fig. 1) currently has
Relatively high oil prices, modest polymer prices, and advances that promote higher injectivity for polymer solutions have allowed polymer flooding to be applied in reservoirs with notably more viscous oils than in previous years. This paper describes a polymer flooding pilot project in the Tambaredjo field in Suriname. The average viscosity of the produced oil is ~1,700 cp, but solution gas reduces the effective oil viscosity in the reservoir to 400-600 cp (through the "foamy oil" mechanism). Interestingly, the primary drive mechanism in the pilot area is compaction-leading to ~20% OOIP recovery. Because various restrictions preclude application of thermal methods, polymer flooding was explored as a means to enhance oil recovery. The average permeability of the sand exceeds 4darcys, but the level of heterogeneity is significant (>10:1 permeability contrast is common). The first simulation efforts suggested that injection of 25-40-cp polymer solutions might be optimum, considering both displacement and injectivity. Consequently, ~40-cp polymer solutions were injected during the first part of the pilot. However, later analysis revealed that sweep efficiency could be improved significantly using polymer solutions up to 160 cp. Although injection was done at pressures below what was believed to be the formation parting pressure, injectivity data from several water injection cycles shows that partition of the formation followed by partial sustenance of the fracture did occur. Analysis of produced water salinities, polymer and tracer concentrations, water/oil ratios (WOR), and inter-well pressure responses all indicated that severe channeling (i.e., through fracture-like features) did not occur. Instead, analysis of the project response indicated that (1) sweep could benefit from injecting more viscous polymer solutions, (2) injectivity for more viscous polymers would not be a problem because of controlled (i.e., not detrimental) fracture extension, and (3) oil production rates could be enhanced (without sacrificing WOR) by increasing injection rates. Consequently, these ideas are currently being field tested in our project. This paper details results to date for this polymer pilot.
Two new methods were developed for anaerobically sampling polymer solutions from production wells in the Sarah Maria polymer flood pilot project in Suriname. Whereas previous methods indicated severe polymer degradation, the improved methods revealed that the polymer propagated intact over 300 ft through the Tambaredjo formation. This finding substantially reduces concerns about HPAM stability and propagation through low- and moderate-temperature reservoirs. Analysis of produced salinity, polymer concentration, and viscosity indicated that the polymer banks retained low salinity and therefore high viscosity for much of the way through the Sarah Maria polymer flood pilot pattern. A strong shear- thickening rheology was observed for 1000-ppm and 1350-ppm HPAM solutions in porous media, even though the salinity was only 500 ppm TDS. Examination of injectivities revealed that these solutions were injected above the formation parting pressure in the Sarah Maria polymer injection wells. Analysis suggested that the fractures extended only a short distance (~20 ft) from the injection wells and did not jeopardize sweep efficiency. In contrast, the short fractures greatly improved polymer injectivity and reduced concern about polymer mechanical degradation.
The Calcutta field in Suriname is comprised of shallow, low-pressure, heavy-oil sandstone reservoirs that are being produced by progressive cavity pumps. These reservoirs are difficult to characterize because of the complexity of the depositional environments encountered in the wetlands of Suriname.The unconsolidated nature of these reservoirs makes it virtually impossible to recover any core successfully; hence, petrophysical parameters were originally derived from well-log analyses. Completions consist of gravel pack with screens to control the unconsolidated sands. Initial quality checks with surface liquid samples for PVT analysis routinely involve measurement of the bubble point pressure at ambient temperature. However, the emulsified water in the heavy oil made it difficult to conduct such PVT analysis.The inability to obtain reliable core or fluid samples, made pressure-transient testing an essential tool for characterizing these reservoirs. After the initial operational and mechanical restrictions were resolved, a field-wide program was implemented in 2008. However, the quality of the recorded pressure data was adversely affected by frequent power failures that resulted in unplanned pressure buildup periods. The pressure transient analysis was also influenced by limitations in production data gathering during the flow periods. Additionally, uncertainty in fluid properties and problems with mechanical and pumping equipment caused undesirable pressure disturbances during the well testing periods.Analyses of the tested wells showed better formation properties than suggested by the initial well-log-derived potentials, i.e., wells suspected to have formation damage proved to have negative skin, instead. Formation permeability was also found to be higher than the log-derived permeability values; this difference could have been caused by the gravel pack.The geological interpretations were improved and uncertainties regarding completion efficiency have largely been eliminated. The results have contributed to a better understanding of reservoir performance and have led to increased production optimization efforts.The field examples presented here illustrate the unique challenges experienced while applying pressure-transient testing in pumping wells to characterize the geologically complex reservoirs of the Calcutta field. This paper also describes the mechanical issues, well preparations, water production problems, and installation of permanent gauges in these wells.
Staatsolie conducted several screening studies in the past decade to explore the potential of enhanced oil recovery (EOR) for its heavy oil fields in Suriname. The latest screening study was performed in 2011. It indicated that combined gas and water injection could be a highly efficient method to extend the life of the fields beyond primary recovery. To validate this conclusion further, an area of the Tambaredjo heavy oil field was selected for a feasibility study comprising laboratory tests and field scale reservoir simulation studies. This paper presents a series of core-flood tests done to evaluate the potential of several CO2 and N2 injection schemes and to gather data for the further numerical simulations. CO2, N2, and brine were injected either (1) on continuous mode or (2) in a water-alternating-gas (WAG) mode into Bentheimer sandstone cores previously saturated with Tambaredjo heavy oil, having a viscosity in the range of 650 to 1,100 cP and a density ranging from 16 to 17 °API. The injection strategies tested resulted in substantial incremental oil recovery (relative to OIIP), but values hereof varied from strategy to strategy. The core-flood test with continuous CO2 injection following extensive water flooding resulted in an incremental recovery of 31.1% over tertiary CO2 flooding stage. Continuous N2 and CO2 injection in a secondary mode resulted in incremental recoveries of respectively 14.8% and 24.5% over secondary drainage stage. Subsequent long water slugs resulted in both cases in further increase of the recovery by 48.1% and 29.2%. N2 and CO2 WAG with WAG ratios and slug sizes chosen based on optimized reservoir simulations resulted in similar recovery factors. Overall recoveries for five schemes used in core-floods were in the range of 49.6 to 65.9%. The paper discusses the mechanism responsible for the oil displacement for each injection strategy and presents how the core-flood tests can be used to model gas injection for a sector of the heavy oil reservoirs of Suriname.
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