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.

No abstract

A polymer flood pilot has been ongoing since 2008 in Suriname in the heavy oil Tambaredjo field operated by Staatsolie. The pilot started with one injection well and four producers and was subsequently expanded to three injection wells and nine producers. Initially, a polymer solution with a viscosity of 45 cP was injected and this was later increased, first to 85 cP then to 125 cP in order to improve the sweep efficiency. The response to polymer injection has been positive even though some wells have not responded as expected to the injection. The incremental recovery (over primary) to date is estimated at 11.3% STOOIP. Additionally, some wells outside the pilot have also shown response to injection. The performance results of the pilot have already been presented in previous paper SPE-180739-MS (Delamaide, Moe Soe Let, Bhoendie, Jong-A-Pin, & Paidin, 2016). The current paper focuses on the interpretation of the performance of the pilot. Several factors have contributed to make this interpretation challenging: the reservoir heterogeneity with permeability of up to 30 darcy (to air) measured in cores and in pressure transient tests; the characteristics and contribution of a water-bearing formation of Cretaceous age below the main reservoir which remains not very well understood. But also the fact that the pilot patterns are not confined; the increases in injected polymer viscosity over the course of the pilot and the role of induced fractures or pseudo-fractures created during the injection of the polymer solution. Salinity data recorded over the whole production history of the wells was invaluable for the analysis thanks to differences in salinity between the reservoir, the water-bearing Cretaceous and the injection water. The results of the interpretation of the pilot performance have given a higher confidence for possible future expansion of polymer flood in the Tambaredjo field. Contrary to the common practice of using reservoir simulations to interpret pilots, this work has been conducted with classical reservoir engineering techniques and calculations, and thus presents an interesting case study. Some main conclusions for this project are: Polymer injection has generated an incremental recovery of 11.3% OOIP; Polymer Utilization Factor ranges between 0.41 bbl/kg and 0.57 bbl/kg of polymer.Fluid movement outside the patterns has been observed; it was due to the unconfined nature of the pilot patterns and was probably exacerbated by the limited drawdown imposed on the pattern wells. It is likely that incremental recovery would have been higher had the wells been produced more aggressively.A first response to polymer injection was obtained when a viscosity of 45 cp was injected. Increasing the viscosity further did not result in any obvious increase in oil recovery. For the future polymer expansion, it is recommended to maximize well drawdown and to reduce injected polymer viscosity to improve the economics (Polymer Utilization Factor).

The Tambaredjo field was discovered in 1968, near the Calcutta village, by a wildcat well C9. A production test was carried out in the appraisal well TA-4, which proved the find to be semi-commercial at the time of the discovery[1]. After the establishment of Staatsolie Maatschappij Suriname N .V., the State Oil Company of Suriname, South America, on December 13, 1980, another well TA05 was drilled and tested in 1981. This well proved the producibility of the field. Oil production started on November 25, 1982 and the production was 250 BOPD from 5 wells. As of May 2006, the average oil production is 13,000 BOPD from 914 production wells in the two fields, Tambaredjo and Calcutta. The coastal plain of Suriname, together with that of both French Guyana and Guyana, form the onshore part of the Guyana sedimentary basin. Progressively, older beds overlap the basement in northern direction. The reservoirs are of coastal and non-coastal depositional environment (fluvial to shore-face) presenting erratic sand development. Reservoir continuity and heterogeneity within these shallow thin fluvial related sands pose great uncertainty even within a grid drilling of 10 to 30 acres spacing. This is uniquely challenging for field development and reservoir management. Oil production in Tambaredjo comes from a number of unconsolidated sands, especially the T-sands with thickness from 3 to 45 ft, at average depths of 900 (275 m) to 1200 ft (400m) with a formation temperature of 98°F (37°C). Reservoir pressures are hydrostatic. It has an average porosity and water saturation of 39.0 and 25.0 percent respectively. The oil has a viscosity of 600 cp and an API degree of 17. Developing and producing this 600 cp heavy oil within thin sand with low reservoir pressure warrants the use of artificial lifting by means of progressive cavity pumps (PCP). This adds to the difficulties of getting valuable wireline survey or sub-surface data acquisition. Reservoir performance prediction utilizing the production data history has always been challenging. Efforts are being made to increase recovery and reserves by applying EOR processes (polymer flood and in-situ combustion) and infill drilling to increase production within these thin sands with high geological uncertainties and early water breakthrough problems. Hence, this paper presents some of these unique challenges in developing, producing and managing these onshore shallow reservoirs in Suriname. Introduction Traces of Petroleum-like substances were reported at several places along the coastal plain of Suriname in the early 19th. century. However, the first analyses that confirmed the presence of hydrocarbons were carried out in 1928 on samples from a 30 ft shallow well, drilled in Nickerie district. As a result, Esso drilled two "deep" exploration wells in Nickerie respectively in 1929 and 1942. One well had oil traces on the basement and the other one was dry. It was not until the sixties, under the Colmar agreement, that systematic hydrocarbon exploration started. This agreement, signed in 1957 with the Colmar group lasted till 1981. The Colmar concession area consisted of essentially all the coastal onshore area and the offshore area to and beyond the continental shelf. Under this agreement, several multinationals as Shell, Esso and Elf carried out exploration programs in offshore Suriname. Until 1980, seven offshore wells were drilled and 20,000 km of marine seismics were acquired. From 1981 to 1983, under a service contract signed with Staatsolie Maatschappij N.V., Gulf Oil acquired approximately 3000 km of marine seismic data and drilled 9 wells in the offshore area. Oil was encountered in some wells but was non-commercial at that time. During 1986 through 1987, under a nearshore service contract, Energy World Trade Group (EWT) carried out additional exploration on the 1982 discovery of Gulf Oil. Within this contract, EWT drilled 5 wells but the openhole tests were proven unsuccessful.

No abstract

No abstract