A polymer flood pilot has been ongoing since September 2008 in Suriname in the heavy oil Tambaredjo field operated by Staatsolie. Initially, the pilot consisted of one injection well and four producers and was later expanded to three injection wells and nine direct offset production wells (all vertical).The Tambaredjo oil field is the largest oil field in Suriname and has been producing since 1982. The field contains approximately 525 MMSTB STOOIP of 16°API oil with an initial viscosity of 300 -600 cP at reservoir conditions. Primary recovery (Ϯ 30% OOIP) is relatively high given the oil viscosity; this is believed to be due to a combination of compaction drive, edge water drive in the northern part of the field and limited bottom water influx in other areas, and perhaps foamy oil behavior. In spite of this high primary recovery, large quantities of oil remain in the reservoir, making it an attractive target for EOR.Due to the relatively thin pay, thermal methods have not been considered for the reservoir but on the other hand polymer flood was judged suitable. The oil viscosity is high but still lower than in other successful projects for instance in Canada while other reservoir characteristics are also suitable: low reservoir temperature and low water salinity allow the use of standard HPAM polymer, and high permeability is beneficial for injectivity. Moreover, the reservoir is highly heterogeneous, which has presented some challenges to the process.Initially, a polymer viscosity of 45 cP was injected which was later increased, first to 85 cP and then to 125 cP in order to improve the sweep efficiency. The overall response to polymer injection has been positive even if some wells have not responded positively to the injection, and incremental recovery (over primary) to date is estimated at on average 11% STOOIP. Due to the unconfined nature of the pattern some wells adjacent to the pilot have also shown response to injection.Given the success of the project, work is currently under way for an expansion of the polymer flood to encompass 33 additional injection wells.The paper presents the results of the pilot and describes the operations and challenges encountered during the project, in particular during the injection of the higher viscosity polymer. The combination of high reservoir heterogeneity, use of hydraulically fractured vertical wells and high polymer viscosity injected contribute to make this pilot an interesting field case.
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.
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 (16-17° API) fields in Suriname. The latest study that was performed in 2011, indicated that water and carbon dioxide (CO2) or water and nitrogen (N2) injection could be a highly efficient method to extend the life of the fields beyond primary recovery. To validate this conclusion an area of the Tambaredjo heavy oil field was selected for a feasibility study comprising laboratory tests, reservoir simulation studies and ultimately a field pilot trial. This paper presents the results of the laboratory study of the fluid properties of the selected study area. Several oil and gas samples of two wells situated in the study area were collected at the wellhead and at the Multi Phase Flow Meter (MPFM). After quality control, the composition and the physical properties of the samples were determined. Various pairs of oil and gas samples were then recombined based either on assumed bubble point pressure or gas-to-oil ratio (GOR) in an attempt to produce mixtures representing the reservoir fluids. Two recombined samples were subsequently selected based on a comparison with historical data for PVT analysis and swelling study with carbon dioxide and nitrogen. The PVT behavior was found to be qualitatively similar to that of the samples examined in the past except for the viscosity which seems to have increased over a period of ten years of depletion of the reservoir in this part of the field. Most likely this can be attributed to vaporization of the lighter components of the crude oil. CO2 readily dissolved in the heavy crude oil which led to substantial reductions of oil viscosity while N2 could hardly be dissolved in the oil. The challenges met during sampling, recombination of the samples and the PVT analyses will be discussed.
During recent field applications of polymer flooding in unconsolidated reservoirs, questions have arisen concerning the role of compaction and/or dilation on flood performance. The primary goal for this paper was to assess the extent to which the compressible nature of a formation affects polymer flooding. The Tambaredjo field in Suriname (with in-situ oil viscosity ~600 cp) was used as a model for this study. Comparisons were made during simulations where formation compressibility was 5.6 × 10-4 psi-1 versus 1 × 10-6 psi-1. During a simulated 17-year compaction drive with compressibility of 5.6 × 10-4 psi-1 , water cut gradually increased to average 20% (consistent with the actual field performance)-compared to 2% if compressibility was 1 × 10-6 psi-1. Oil recovery during this period was 18% OOIP for the highcompressibility case versus 3% OOIP for the low-compressibility case. Subsequent to the above compaction drive, incremental oil recoveries from waterflooding and polymer flooding were significantly less (about half in our case) when compressibility was 5.6 × 10-4 psi-1 than when compressibility was 1 × 10-6 psi-1-simply because the oil recovery target was less. For the many waterflooding and polymer flooding cases, most incremental oil was recovered within five years of starting injection-regardless of formation compressibility. Water cuts rose to high values within five years of injection, regardless of the viscosity of the injected fluid and the compressibility value. Consistent with the actual field application, the response to polymer injection varied greatly from well to well. However, our analysis indicated that these variations were due to existing heterogeneities within the pattern-not to the high compressibility of the formation. During simulation, polymer injection increased porosity by factors up to 1.5 and permeability by factors up to 2.3. Nevertheless, compaction or dilation had a fairly even (proportionate) effect on porosity and permeability throughout the pattern. If polymer injection was stopped after the simulated peak in porosity was reached (after 4-6 years of injection) and compaction was allowed to resume, a modest level of oil recovery resulted from this second compaction period (25%-38% of the incremental oil during polymer injection). However, substantially longer was required for the recovery (15-17 years versus 4-6 years for polymer flooding). Consequently, relying on re-compaction during this period of low oil prices may not be as profitable as one might hope. Our work suggests that there is an optimum rate, viscosity, and pressure for polymer flooding compressible formations. Flooding too rapidly results in pressures that waste much of the injection energy on dilating the formation-thereby detracting from efficient displacement of the oil. SPE-185851-MS These constraints restrict injection rate, viscosity, and pressure to a greater degree for very compressible formations than for incompressible formations.
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