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Abstract China's Liaohe Oilfield is the country's largest heavy oil field and contains numerous smaller, individually named, reservoirs (oilfields) with oil viscosity ranging from 100 cp to over 50,000 cp. Because of pressure depletion, steam huff-n-puff (cyclic steam) has reached its economic limit in a number of the heavy oil reservoirs in Liaohe. Recently, a flue (exhaust) gas-steam slug process has been tested in an attempt to improve recovery of medium heavy oil, oil with a viscosity less than 1,000 cp. Pilot tests, which started in September 1998, used one injection well and 9 production wells. The pilot test conducted in the eastern part of Block Du-66 of Shuguang Oilfield showed encouraging results. Average oil production increased from 1.8 t/d before the test to 20 t/d after more than 65 days production, with a peak oil rate of 29.2 t/d. The water-cut dropped from 84% to 39%. Drop in watercut reduced operating and water disposal costs. Cost of the entire operation of the flue gas-steam is about half of the cost of steam generated by a boiler. This paper describes the design, construction and operation of gas-steam slug project. The economics of the project and success to date are encouraging. This has prompted application of the gas-steam process to recover lower viscosity heavy oil from other Chinese reservoirs. Background The heavy oil reservoirs in Liaohe Oilfield belong to terrestrial positive rhythm deposition systems (fluvial cyclic deposition with each cycle fining upward). The reservoirs in this region are very complex. Faults are well developed and divide the reservoirs into many blocks. Within a fault block, the cyclic deposition shows highly heterogeneous layers (vertical) which exhibit great differences in fluid and rock properties. Liaohe has large reserves of the medium heavy oil (viscosity of less than 1,000 cp). To recover the medium heavy oil, steam huff-n-puff has been applied in most cases. Steam huff-n-puff is a pressure depletion recovery process. As the number of steam huff-n-puff cycles increase, the formation pressure and oil/steam ratio drop, substantially. At present, the average oil/steam ratio is 0.57 after an average 6.7 cycles of steam huff-n-puff. Formation pressure has dropped 70 to 90%. Pressure in major blocks is about 1–3 MPa (at 1,000 - 1,500 m vertical depth). Oil/steam ratio in a number of wells has fallen to less than 0.3. Parts of the reservoir have reached the economic limit of thermal recovery by steam huff-n-puff. Some wells have had to be shut-in. New recovery methods need to be found, tested, and the successful methods need to be implemented to reduce declining oil production and improve the field's economics.
- North America > United States (1.00)
- Asia > China > Liaoning Province (0.55)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.50)
SPE Members A selective profile modification process was studied to improve volumetric sweep efficiency. This method involved adding alcohol to brine to reduce solubility of salt, which caused the salt to precipitate. For this process, a concentrated brine preflush was injected. This was followed by the injection of a water-soluble alcohol, such as ethanol. permeability of highly watered-out cores. Using about 7% PV of reagent grade ethanol for salt precipitation, oil recovery with parallel corefloods of high and low permeabilities was increased by about 20% of the OOIP or about 60% above that of conventional waterflooding. For CO2 coreflooding experiments, the injection of ethanol and NaCl-saturated brine slugs resulted in 12% additional oil recovery of the OOIP or 45% higher oil recovery compared to that of CO2 floods without salt precipitation. The salt precipitation method has several potential advantages over other profile modification methods such as polymer gels. Profile modification by salt precipitation is not affected by adsorption, and other reservoir conditions, such as, fluid pH and temperature. These are conditions that may affect the gelation process and stability of polymer gels. For applications with CO2 floods, the solid salt is stable to subsequent CO2 flooding. Carbon dioxide flooding can lower the pH of reservoir fluids, a condition which may adversely affect the stability of some polymer gels. Almost all formations are heterogeneous. Reservoir heterogeneities and permeability variations can cause early breakthrough of injected fluid and significantly affect the sweep efficiency of oil recovery processes. Because of channeling, portions of the reservoir are bypassed. Therefore, a selective permeability plugging method to block the more permeable channels would improve volumetric sweep efficiency and increase ultimate oil recovery. Laboratory experiments indicated that the permeabilities of cores treated by salt precipitation were resistant to subsequent waterfloods with low-salinity brines. Core permeabilities recovered only 5 to 10% of the original permeability after injecting several pore volume of low-salinity brine. Also, corefloods demonstrated the feasibility of the new process to plug high-permeability regions. In parallel coreflooding experiments, the injection of alcohol and NaCl-saturated brine selectively reduced the Numerous methods have been studied to plug highly water-invaded regions including foams, polymers, and microbes. However, each of these methods has limited application because of some inherent problems. For example, foams often decay too rapidly to have a substantial effect on sweep efficiency. For profile modification treatments with microbes, most plugging tends to occur near the injection well due to adsorption and attraction of the injected microbes on the reservoir rock, and to the injected nutrients. P. 487^
- North America > United States > Oklahoma (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)