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Abstract This paper presents a successful re-development and production acceleration project of Intisar E Field, Upper Girs A, B & C reservoirs of the Zueitina Oil Company in Libya. The project was implemented from 1999 to 2002 on the bases of a simulation modelling study. The re-development plan comprised drilling 6 vertical injectors and 6 horizontal producers, and re-completion of existing 8 wells as commingled and/or dual producers. As a result of this project, the oil production potential of Upper Gir reservoirs was increased almost by three folds from average of 6,400 STB/D in 1999 to 20,000 STB/D in September 2002. The incremental reserves are predicted at 33.4 MMSTB until the year 2022. Introduction Intisar 103E Field is located approximately 350 km to the South of Benghazi in the Sirte Basin, Concession 103. The field was discovered in 1968 by drilling well E1โ103 down to a total depth of 10,890 ft in Upper Sabil. The well was drilled on a structure similar to the giant reef fields at 103A and 103D. In 103E field, however, the reef proved to be wet. As of December 2002, a total of 40 wells were been drilled in the field. Among these wells, 23 are vertical producers, 6 horizontal producers and 11 water injectors. The following figure illustrates the current field vertical and horizontal well locations. The Intisar 103E Field comprises seven separate producing reservoirs, from top down designated as Elgiza A&B, Upper Girs A, B&C, Lower Girs and Shoal. The reservoir structures are four way-dipping anticlines with varying closures from 50 ft to 150 ft. All reservoirs are carbonates, particularly limestones, stacking on top of each other. The cross-section shown in Figure 3 depicts all reservoir units from Elgiza down to Shoal (Upper Sabil).
ABSTRACT Tyrihans is an oil and gas-condensate field offshore Mid-Norway. Oil reserves are 29 million Sm3 and gas reserves are 35 billion Sm3. The field will be developed as a subsea project with 5 templates having 9 producers and 3 injectors. Production start-up is July 2009. The field development is innovative in the following aspects:Cost effective development with a 43 km tie-back to the Kristin platform through an 18โณ pipeline. Tie-back is possible because the pipeline will have direct electrical heating to prevent formation of hydrates and to preserve temperature. Pressure support with both gas injection and raw sea water injection. This is feasible by installing two water injection pumps subsea and using available power and compressor capacity at neighbouring fields. Extensive use of advanced wells. The oil producers are dual-lateral with approx. 1.5 km horizontal reservoir sections, equipped with down-hole ICVs (Inflow Control Valves) and gas lift. Both main bore and laterals will have 8.5โณ hole diameter, made possible by using 8โณ expandable liners Important reservoir management and simulation issues are:Tyrihans consists of two structures, which cannot be produced independently. Handling gas and water coning in a two-front system and keeping track of fluid contacts are challenging. The northern structure consists of an 18 m thin oil zone with a gas cap. To simulate recovery from thin oil zones is challenging. The simulation model has horizontal grid, in order to have the required vertical resolution of the oil zone. Correct modelling of pipeline flow and flow assurance. The long, single pipeline tie-back makes well testing difficult. Reservoir monitoring and management must then be based on subsea flow meters and gauges. Production optimization will be performed from an onshore support centre. With the chosen reservoir development strategy high recovery is obtainable. The simulated oil recovery in the southern part is 52%, and the gas recovery in the northern part is 80%. INTRODUCTION Tyrihans is an oil and gas condensate field offshore Mid-Norway (Figure 1). Tyrihans Sรธr (South) was discovered by well 6407/1โ2 in 1982 as the first discovery on Haltenbanken offshore Mid-Norway. The well test showed a rich gas-condensate. Tyrihans Nord (North) was discovered the following year, proving a gas cap with a thin oil zone. An appraisal well in Tyrihans Nord in 1996 was drilled through the OWC and proved an 18 m thick oil column. In 2002, an appraisal well in Tyrihans Sรธr showed a 35 m oil column below the gas cap. With total in-place volumes of 71.4 million Sm3 oil and 57.4 billion Sm3 gas, an independent development of Tyrihans was not economical feasible. In the meantime, the neighbouring gas-condensate field Kristin was under development. It was decided to develop Tyrihans as a subsea (SS) field, tied back to the Kristin platform. A subsea development makes investments in a platform/vessel unnecessary. However, long tie-backs are challenging with respect to oil recovery and flow assurance. This paper will focus on the SS development facilities and how high oil recovery will be obtained on Tyrihans.
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > Norway > Norwegian Sea > Ile Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Bank Area > Block 6407/1 > Tyrihans Field > Ile Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Bank Area > Block 6407/1 > Tyrihans Field > Garn Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Information Technology > Modeling & Simulation (0.88)
- Information Technology > Communications (0.69)
Abstract Since 1950s In-Situ Combustion (ISC) has been applied to mainly heavy-oil reservoirs. In recent years, High Pressure Air Injection (HPAI) which is a displacement process categorized as ISC, is applied to light-oil reservoirs. And it has proven to be a valuable Enhanced Oil Recovery (EOR). Reduction of oil viscosity is very important for ISC process. In contrast, it is not so essential for HPAI because original viscosity of light-oil is not as high as that of heavy oil. HPAI is considered as flue gas injection, since a flue gas sweep is one of the most important recovery factors of HPAI. However a flue gas sweep recovery factor is not effective for highly water saturated light-oil reservoirs, while thermal effects become an important recovery mechanism. This paper discribed the feasibility study of HPAI for watered out light-oil reservoirs, oil recovery mechanism and several simulation studies to establish maximum oil recovery factor. For the feasibility study, Combustion Tube tests (CT tests) and simulation studies were conducted. The oil recovery was observed in the CT test with crushed core which was flooded out by water. This result suggests that HPAI can be applied to highly water saturated light-oil reservoir. The results of simulation studies also indicate its feasibility. They also made clear that distillation process that was one of thermal effects of HPAI was a main recovery factor for a HPAI in this case. In order to maximize the oil recovery, controlling a channeling of injected air is important because early breakthrough of the air reduces oil production period significantly. The results of our studies show that not only a design of well completion but also an adjustment of air injection rate enable to increase vertical sweep efficiency and that line drive injection is effective to increase areal sweep efficiency. Introduction High Pressure Air Injection for light-oil reservoirs. HPAI is one of EOR techniques applied for light-oil reservoirs which is a displacement process with air injection into a reservoir, such as ISC. In the reservoir, oxygen contained in the air reacts with hydrocarbon to create a high temperature combustion front that is propagated through the reservoir. In recent years, HPAI has been drawn attention as an effective EOR technique in virtue of the many successful projects located on Williston Basin,[1โ4] and some HPAI projects are planned for waterflooded reservoirs in North Sea[5] and Argentina.[6] In comparison with ISC, reduction of oil viscosity which is a significant recovery factor of ISC is less important for HPAI, because the original viscosity of light-oil is not as high as heavy oil. In addition, there is a difference in the combustion behaviors between light-oils and heavy-oils, those of light-oils are preferable for successful air injection process. According to Moore et al.,[7] oxidation processes of both light-oils and heavy-oils have two temperature regions and two reaction pathways. Figure 1 shows the temperature regions of both oils, these two regions are Low Temperature Oxidation (LTO) and High Temperature Oxidation (HTO). In the case of light-oil, oxygen uptake rate becomes high in LTO, while it occurs in HTO for heavy-oil case. Two reaction pathways of oxidation process mean oxygen addition process and combustion process. The former is that the oxygen atoms chemically bound into the molecular structure to produce various oxygenated compounds which further react and polymerize with each other. It results in not only increasing oil viscosity, density and boiling range but also shrinking vapor phase significantly. The latter is that the oxygen breaks up the hydrocarbon molecules to principally produce carbon dioxide and water, about 15% of carbon dioxide is generally observed in production gas while the process successfully occurs in reservoirs. Therefore, oxygen addition process is harmful to air injection process, and combustion process is a critical to successful air injection EOR. In the case of light-oils, the oxygen addition process occurs at the temperature below 150ยฐC, the combustion process principally occurs in the temperature range of 150โ300ยฐC. Both processes occur in LTO where oxygen uptake rate of light-oil is high, the oxidation process favorably changes to and reacts in combustion process. In the case of heavy oils, combustion process will not be dominant at the temperature below 450ยฐC where HTO occurs. Once LTO occurs in heavy-oil reservoirs, oxygen addition process become dominant, and it is difficult to change to combustion process occurring in HTO. Indeed, the history of ISC without much success arises from operation with oxygen addition process in LTO. In the case of HPAI, combustion process is a favored reaction pathway, and successful displacement process is highly expected.
- North America > United States (1.00)
- North America > Canada > Alberta (0.34)
- Europe > United Kingdom > North Sea (0.24)
- (3 more...)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- North America > Canada > Saskatchewan > Williston Basin (0.99)
- North America > Canada > Manitoba > Williston Basin (0.99)
- North America > Canada > Alberta > Williston Basin (0.99)
- Asia > Indonesia > East Kalimantan > Kutei Basin > Mahakam Block > Handil Field (0.99)
Abstract In a naturally fractured carbonate reservoir in Oman, three injector-producer pairs were identified for fracture shut-off treatments to improve on their oil production. For these well pairs, the oil production process was inefficient due to short-circuiting of injection water to production wells along fracture paths. The field-observed response on fracture shut-off by gel injection into the water injectors provided a excellent good opportunity to learn more on get a detailed picture of the fracture geometry, aiming for the formulation of general guidelines for an efficient water flood in naturally fractured reservoirs. The fracture shut-off job was analysed by the combined use of a fracture growth simulator and a reservoir simulator. The response was explained by the combination of an induced fracture in the water injector in the direction of the main fracture trend, in which the gel is destroyed after resumption of water injection and a natural fracture in the direction of a secondary fracture trend, which remains shut-off by the gel. For such fracture geometries water floods can be optimized by minimization of the risk of short-circuits between injectors and producers. This can be achieved by using injection and production patterns, aligned with the dominating fracturing direction and by keeping induced fractures small to prevent or minimise intersections with natural fracture corridors by proper management of injection rate and water quality. The analysis of the fracture shut-off treatment provided a view of the fracture network, which confirmed the existing development of aligning wells in the dominant fracture orientation in combination with the use of clean aquifer injection water as optimum.demonstrates the technical potential of analysis of field performance by combination of fracture growth models and reservoir simulation. Introduction Water injection is a well-recognized oil recovery process, aiming for sweep efficiency and pressure maintenance. In naturally fractured reservoirs however, water flooding is often less efficient than in non-fractured reservoirs. This is because the fractures provide fast flow paths for water to the producers, which leads to large amounts of bypassed oil in the matrix blocks. Water injection without inducing fractures is not possible[1,2] and the induced fractures may connect at some point in the reservoir to a natural fracture and then provide a short circuit between an injection and production well. In the worst case, all injected water is immediately produced at the connected producer, while the oil in the matrix in between the injector and producer is bypassed. Then water injection only leads to cycling of water without any improvement in oil production. A number of options exist to improve on such situation. The simplest one is just to stop water injection and produce the oil by depletion. The disadvantage of this "do nothing situation" is that it will result in a gradual decrease in reservoir pressure, with as a consequence a continuous decline in oil production rate and a significant increase in producing gas-to-oil ratio once the reservoir pressure has fallen below the saturation pressure. If therefore continuation of water injection is preferred, one could think of remedial work, such as sidetracking of the wells. However, this is not always successful because there is a substantial risk of renewed intersection of the fracture network, which could lead to new short circuits. Moreover, it is a costly option. Another possibility is to close the fractures downhole, either by mechanical or chemical means. Mechanical shut-off is definitely an option but it may be a complicated operation, while chemical shut-off is easier and cheaper. Looking through the previous work that was conducted worldwide using specific chemicals there exists a 50% possibility of success.
- North America > United States > Texas (0.46)
- Asia > Middle East > Oman (0.35)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)