Cyclic CO 2 huff 'n' puff process in diverse reservoir conditions, such as immiscible, near-miscible, and miscible, has been tested in the laboratory and applied in the fields as a viable secondary or tertiary means to recover the residual oil in water flooded reservoirs or pressure depleted reservoirs. Recently, petroleum operators have shown increasingly interest in taking CO 2 huff 'n' puff process as a preferred option to extract light oil in low-pressure and low-permeability reservoirs.In this paper, experimental results from a series of coreflood tests are presented and operation strategies for cyclic CO 2 injection are optimized to maximize the light oil recovery factor in a low-permeability reservoir with low original reservoir pressure and while, minimize CO 2 utilization. 6 cyclic coreflood tests, 20 cycles in total, are conducted in a 973 mm-long composite core with an average porosity of 9.6% and an average permeability of 2.3mD. The reservoir pressure is 12.9MPa, far below the measured MMP value of 23MPa, which indicates that the reservoir has no sufficient energy support to do primary production. The impacts of primary operational parameters, such as slug size, injection pressure, chasing gas (N 2 ) and CO 2 injection rate on the performance have been investigated.It is concluded that, on the basis of experimental data, 0.1PV seems to be an optimal slug size for the first cycle, with a cycle recovery factor as high as 14.52% when reservoir pressure depleted to 8MPa. The recovery factor is suggested to be sensitive to the maximum pressure and the maximum pressure should be built up to as high as formation permits. In the following cycles, injecting N 2 as chasing gas after CO 2 injection seems to improve the cycle performance significantly and concurrently reduce the CO 2 utilization. The optimal operation should have three cycles and the ultimate recovery factor for these three cycles could reach above 30%. The findings of this paper extend the understanding of cyclic CO 2 operation and may be employed as technique reference for cyclic CO 2 process operations in low-pressure and low-permeability closed boundary reservoirs.

CO2 Huff 'N' Puff has been used on a shallow light oil field to add value to existing oil producing wells by increasing the ultimate oil recovery. Testing was initiated in 1985 with a more continuous program starting in 1989. The application of CO2 Huff 'N' Puff has increased oil production 180,000 bbls above the primary recovery with the use of 210 MMCF (12,200 tons). The CO2 treatments have been relatively small with 390 treatments performed on 240 wells. Introduction The Huff 'n' Puff or Cyclic W2 Process is a type of production well stimulation which involves a) injecting CO2 (either as a gas or a liquid) into a well, b) shutting in the well to allow the CO2 to dissipate and dissolve, and c) producing the well back. While each phase of the process is unique, each phase inter-relates mechanically as well as in the reservoir. Field results, reservoir analysis, and computer simulation and matching, indicate that the primary recovery mechanisms in this immiscible CO2 application appear to be 1) a shift in the CO2 saturated water/oil relative permeability, and 2) the forming of a trapped gas saturation, namely within the water phase, which results in a strong decrease of water relative permeability end point. P. 505^

Two highly successful polymer pilot experiments were carried out between 1987 and 1993 on the Daqing oil field (People Republic of China) after favorable laboratory results and preliminary reservoir studies. The Daqing oil field is a fluvio-deltaic formation with several sand beds and great heterogeneities. The oil is slightly viscous (9.5 cp), water is fresh and the temperature is 45°C, making the conditions favorable for polymer injection. Each pilot consisted of 4 injectors and 9 producers. One pilot was devoted to one reservoir, whereas simultaneous injection into two reservoirs was performed in the second pilot. Polymer injection was started in 1990 with a 915-ppm-solution of Polyacrylamide. Approximately 0.6 PV of solution was injected in each pilot, yielding a significant decrease in the water-cut and a respective oil production of 73 120 m3 and 1 1 8 950 m3 in April 1993. The results of the pilots were matched with a numerical simulator and interpreted in terms of reservoir description. The injection parameters were optimized in terms of viscosity and slug size, in order to extend the process to the whole field. The sensitivity of the process to the reservoir heterogeneity was also considered.

Reservoir descriptioninherent in polymer is dependent on the severity of the reservoir heterogeneity and varies from 7.5 % in stratified areas to 12% when the formation is more homogeneous.This indicates a better polymer efficiency to reduce the detrimental water-oil mobility ratio than to correct the rock permeability profile. The paper ends by a presentation of the first field production results of the pilots that were put in stream in 1989.

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