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The objective of this study was to characterize formation water resistivity (
A database with analyzed water sample and log-derived (Dielectric and Conventional logs)
Creating the WSA tool was very important to determine which samples were ionic balanced and were useful for further steps. These samples delivered different salinities which could clarify the water sources for the produced sand intervals. Three main groups of water sources were established based on the salinity; S-sands, T-sands and Cretaceous. Based on this classification, the log derived
Regarding stock tank oil initially in place (STOIIP) in TCA, with the variable
Formation water salinity is a very important input in
Nadeson, Ganesan (Staatsolie Suriname NV) | Harold, Kartoredjo (Staatsolie Maatschappij Suriname N.V.) | Moe Soe Let, Kathleen (Staatsolie Maatschappij Suriname N.V.) | Rekha, Bisshumbhar (Staatsolie Maatschappij Suriname N.V.) | Soerin, Bhagwanpersad Nandlal (Staatsolie Maatschappij Suriname N.V.)
Abstract 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. 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 19. 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.
Abstract Heavy oil refers to oils having an API gravity lower than 20° and viscosity at formation conditions above 100 centipoise (cp). These hydrocarbons generally pose challenging production problems and are marketed at a discounted price. However, the combination of improved technology and higher oil prices make the exploitation of heavy-oil deposits more economically feasible. Besides the quantity of production and processing problems associated with heavy oils, evaluating petrophysical properties from nuclear magnetic resonance (NMR) logging measurements can be problematic because of a number of issues, such as heavy oil NMR responses are similar to signals from capillary-bound water. Additionally, heavy-oil chemistry can be conducive to a wettability alteration that can lead to a misinterpretation of water content from conventional and NMR logs. These phenomena make it difficult to quantify and type fluid volumes in heavy-oil reservoirs from NMR measurements alone. NMR logging instruments sometimes do not fully capture heavy-oil signals because they operate at inter-echo spacings that make them unable to adequately sample important rapid decay components when viscosity exceeds ~1000 cp. This situation causes the indicated NMR porosity to be somewhat small, as though the reservoir fluid had a hydrogen index (HI) smaller than one, as occurs in gas reservoirs. These factors make it necessary to apply advanced interpretation methods to find indications of altered wettability and evaluate petrophysical quantities, such as fluid volumes, permeability, and apparent in-situ oil viscosity. The method consists of combining NMR and conventional wireline logs to measure the signal loss and estimate the oil's viscosity where the in-situ viscosity is larger than a few hundred cp. Additional combinations with conventional logs can be formed with NMR diffusion measurements to infer movable and capillary-bound water volumes. These volumes can then be used to refine interpretations of resistivity logs, indicate altered wettability, and provide an improved estimate of permeability in heavy-oil reservoirs. This paper shows the validation of this method implemented in over 20 wells in the Suriname-Guyana basin. The average well depth is approximately 1,000 ft, bottomhole temperature (BHT) is ~100°F, and gravity is in the range of 10 to 20 API. The results are validated with production data.
Abstract Oil and gas production from unconsolidated sand reservoirs generally requires a production sand screen and usually a gravel pack in the well bore for optimum sand control. Existing criteria such as Tiffin, Saucier and Coberly have provided guidelines for conventional gap based filtration technology. However they do not apply very well to some newer technologies of today. Some of these newer technologies include Premium (2D) screens, with fusion-bonded laminates, or MeshRite (3D) screens with angular compressed metal fibers as Stand Alone Screen (SAS) completions. These screens may use multiple layers of wire mesh and a complex shaped pore opening, which result in retention performance quite different from conventional gap-based systems. Therefore with SAS completions, compatibility with the formation sand size is critical in providing optimum performance. Consequently it might be desirable to adjust existing criteria for specific types of reservoirs, in this case unconsolidated sandstone reservoirs. A combination of SAS lab data with SAS field performance will show that existing criteria need to be adjusted specifically for unconsolidated sandstone reservoirs. A Staatsolie case study in Suriname will be presented to demonstrate the performance of these newer technology screens for specifically unconsolidated shallow-reservoirs. Staatsolie produces heavy oil from shallow, low-pressure, unconsolidated sandstone reservoirs. Wells are mainly completed as vertical open hole gravelpack with production based on progressive cavity pumps. Additional completion methods include cased hole/openhole gravelpacked and or screenless (SAS). In the SAS pilot, 28 wells were completed with Premium or MeshRite screens. Of these, only in 6 wells fine formation sand production was measured. Based on available Particle Size Distribution (PSD) data of 9 wells, a comparison is made between field and lab screen performance. These results will be matched up to Tiffin's criteria . Based on summaries of these screen performance, guidelines for screen type selection for various completion scenarios will be developed for unconsolidated low-pressure shallow reservoirs. Completion types to be covered in the analysis will be open and cased SAS, as the primary focus with respect to 2D and 3D screens applications.
Abstract Wells producing heavy oil (16° API), completed in shallow, high permeability, low-dipping, and very unconsolidated reservoirs experienced very early water breakthrough, short-circuiting significant reserve potential. Wells were completed as vertical open-hole gravel packs and produced 'water-free' at rates 150 - 300 bopd for a few months, then plummeted to 25 - 50 bopd when water broke through. Progressing Cavity Pumps were the primary Artificial Lift method used in 5.5" casing completions. In an attempt to restore some of the lost oil production after water breakthrough, efforts to reduce the flowing BHP were made by using high-volume PC pumps. Fluid withdrawal rates were increased from ±350 bpd to ±700 bpd with no significant change in fluid level (FBHP), watercut, or oil production. The Electrical Submersible Pump (ESP) was then used to reduce the FBHP sufficiently to stimulate increased oil production to the wellbore. Fluid withdrawal rates were taken to ±2200 bpd which achieved approximately 100 psi (25%) reduction in FBHP. Sustained oil production increases between 100% and 400% were realized. Watercuts increased by no more than 3%. Dynamic fluid levels in surrounding wells showed a temporary reduction, but increased and stabilized at original levels after 2–3 months, indicating a very active edge-water drive mechanism. Infill wells with 7" production casings are planned to accommodate larger volume ESP's. No sand production has been observed to date indicating no deterioration of the gravel pack at these elevated extraction rates. At prevailing oil prices, project investments were recovered within 4 months. Under the conditions of low GOR, low dipping, high permeability, edge-water drive, heavy oil reservoirs, increased fluid extraction rates can result in significant increase in oil production rates and producible reserves, even though wells may have experienced early water breakthroughs. Introduction The first oil discovery in Suriname was in 1964. After the establishment of Staatsolie Maatschappij Suriname N.V. (State Oil Company of Suriname) in 1980, the first test well was drilled 19811 which proved the producibility of the field. Full scale development started in November 1982 in the Tambaredjo field, when the production was 250 BOPD from 5 wells. As field development moved further north, the terrain gradually changes from partial swamp to full-scale swamp. Location preparation, interconnecting roads, and facility foundations all required land fill, driving up infrastructural costs sigfnificantly. In 2003, appraisal wells were drilled in an adjacent field, Calcutta. In 2006, full-scale development of this field started as a 'Wet Operation', where wells were drilled and completed using pontoon-based drilling equipment. Well locations are connected by waterways rather than roadways. All pipelines, electric poles, metering and collection facilities, however, are constructed on land-fill dykes.