Summary Cyclic in-situ combustion (ISC) is a novel process with great potential for thermal enhanced oil recovery (EOR). In this study, a 3D physical simulation experiment of cyclic ISC after cyclic steam stimulation (CSS) was carried out for the first time. The mass loss during heavy oil oxidation was studied by thermogravimetry (TG) and the preheating temperature of sandpack was determined by differential scanning calorimeter (DSC). The oxidation process of heavy oil in a porous medium was investigated by a heavy oil static oxidation experiment. The development characteristics and EOR mechanism of cyclic ISC after CSS were studied through 3D physical simulation experiments and the characteristics of the coking zone was studied by scanning electron microscope (SEM) and computed tomography (CT). The results of the thermal analysis indicate that three different regions were observed with increasing temperature: low-temperature oxidation zone (LTO), fuel deposition zone (FD), and high-temperature oxidation zone (HTO). When the temperature reaches 480°C, the mixed oil sand has the most exothermic effect and the high-temperature oxidation reaction is the most vigorous. The results of the 3D physical simulation show that steam channeling and steam overlay in CSS reduced the swept volume of steam and heat usage rate. During the cyclic ISC, the oil bank can overcome the heterogeneity of the oil reservoir caused by steam channeling and steam overlay, which makes the combustion front move forward smoothly. Cyclic ISC can greatly increase the temperature of the zone near the well, and upgrade the crude oil through cracking to reduce the viscosity of heavy oil. The foaming oil formed by the dissolution of flue gas improves the fluidity of the crude oil. The oil recovery of CSS is 19.3%, and the oil recovery of cyclic ISC increased by 13.2%. SEM and CT show that flake black solid coke was attached to the surface of the sand at the coking zone. The coking zone is a porous medium structure with a porosity of 35.14%, which has little effect on the oil recovery in the process of cyclic ISC.
SAGD (Steam Assisted Gravity Drainage) is commercially adopted as a main development methods for heavy oil reservoirs and oil sands. Improving recovery rate and heat efficiency of SAGD process is the main pursuit of all researchers. This paper aims to utilize a new additive with carbamide to reduce the steam consumption and lower down the residual oil saturation, hence to improve the recovery efficiency of this method. Study on improving recovery efficiency of SAGD with carbamide in super heavy oil reservoir was carried out. 1-D flooding experiment were carried out at 50°C and 150°C to compare the sweep efficiency between different additives including carbamide, CO2 and alkali. Then simulation were run to evaluate the influence of carbamide to SAGD process. Different additives were compared and influences of different products from carbamide were analyzed in detail. Study reveals that SAGD process can be greatly influenced by carbamide. Carbamide can gradually decompose into ammonia and CO2 in steam chamber. Great solubility of ammonia in water can effectively increase PH value of reservoir liquid and decrease residual oil saturation. The core flooding test results show that the oil displacement efficiency can be improved by 17.7% when 25% mass percent of carbamide was added at 150°C. And at 50°C, NH4OH showed 9% improve of sweep efficiency comparing to water. Solution of CO2 into oil can improve oil water mobility ratio. And in the simulation case the oil saturation in the core part of steam was reduced to 0.12 by ammonia (this value is 0.2 for steam). Distribution of CO2 and ammonia shows that oil drainage maybe start with viscosity reduction with CO2 solution and ends with ammonia flooding in steam chamber. With the result of this paper, the recovery factor of SAGD process can be improved by 15.4% and SOR can be improved by 20% when carbamide was co-injected with steam.
Guantao formation in Du 84 block, Liaohe oilfield is a typical massive extra-heavy oil pool with top-water. The oil viscosity is 23.2×104mPa.s (@50') and the average formation thickness is 106m. Bitumen shell of 3–4m thick exists between the top-water layer and oil column. If bitumen is softened when heating in the steam injection recovery process, the top-water will flow down. Moreover, the field production showed that conventional steam stimulation recovery with vertical well is poor. Experiment and simulation results have shown that the injection of N2 as an additive can be effective in inhibiting the breakup of bitumen shell hence to prolong the life of SAGD. Also the recovery factor can be improved. After series of simulation, the injection of N2 and steam is optimized as follows: steam injection rate for single well: 100t/d, steam quality: higher than 70%, volume ratio of N2/Steam (Cold water Equivalent) at downhole conditions: 0.5, effective thickness of N2 layer: 10–15m. Under such operating conditions, the life of SAGD can be prolonged by 3–4 years and the recovery factor can be improved by 11.4%. Introduction China has abundant extra-heavy oil resource, which is mainly distributed in Liaohe Oilfield, Karamay Oilfield of Xinjiang and Shengli Oilfield. Up to now, about 200×106 tons of super-heavy oil reserves have been put into production. But for the extra-heavy oil reservoirs with top water, it is first time to be developed with steam injection. Steam Assisted Gravity Drainage (SAGD) has been pilot tested in Du-84 Block, Liaohe Oil field. But the main technical challenges existing in the test are how to avoid flow down of top water and prolong life of SAGD hence to improve production performance. This paper has proposed a new method based on the research results and reservoir characteristics, that is injecting non-condensable gas (N2) into SAGD steam chamber. N2 accumulates at the top of steam chamber and forms a heat-insulating layer, inhibiting the heat conduction of steam chamber to cap rocks. It can delay the down flow of top water during the life of SAGD. Reservoir Description The study case is Guantao Formation in Du 84 Block, Liaohe Oilfield, which is a extra-heavy oil reservoir. Guantao Formation is a monocline structure which dip 2o~3o to the southeastern direction. The Formation is a massive block reservoir with top and edge water aquifer, with the depth of between -530~-649m. The formation thickness is between 150 and 210m. The initial reservoir temperature is 28~32?, and the initial pressure is 6.14MPa. Guantao Formation is a shallow, unconsolidated reservoir. The average porosity is 36.2%, and the average permeability is 5539´10–3mm2, so it is a high porosity and high permeability formation. There are no continuous mud barriers in the formation. The reservoir directly contacts with top and bottom water. Especially, the top-water exists upon all the reservoir and the bottom-water exist partly. Thus, these unfavorable conditions have caused great difficulty for the development of the reservoir. The properties of Guantao oil are as follows: ?high oil density: 1.007g/cm3 at 20', ?high oil viscosity: dead oil viscosity is 16´104mPa.s. at 50', ?high gel and asphaltene content: up to 52.9%. ? high pour point: 27'; the wax content is 2.44%. According to the screening criterion of the heavy oil, it is extra-heavy oil.
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