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Alkaline-surfactant-polymer (ASP) flooding is a combination process in which alkali, surfactant, and polymer are injected in the same slug. Because of the synergy of these three components, ASP is the current worldwide focus of research and field trial in chemical enhanced oil recovery (EOR).This paper is to provide a comprehensive review of the ASP process. The reviewed topics include the following: ASP MECHANISMSBefore presenting the synergy of ASP process, the mechanisms of each individual component are discussed first. Mechanisms of polymer floodingThe process of polymer flooding is same as waterflooding except that polymer is added in the water so that the solution viscosity is increased. Sometimes, it is called thickened waterflooding. It is well known that when the Screening criteria for broader EOR processes were discussed by several researchers, e.g. Lake et al., [21] Taber et al., [22,23] Al-Bahar et al., [24] Dickson et al., [20] and Al-Adasani and Bai (2010). [25] Some of the Asia-Pacific Journal of Chemical Engineering A COMPREHENSIVE REVIEW OF ASP FLOODING 473 S o ÀS or 1ÀS or ÀS wc : Here S o , S or, and S wc are oil saturation, residual oil saturation, and connate water saturation, respectively. The proposed mobility control requirement provides a criterion for mobility control design for an ASP project. PROBLEMS ASSOCIATED WITH ASP FLOODINGCommon operational problems in an ASP project are low injectivity, polymer degradation, difficulty to separate J. J. SHENG Asia-Pacific Journal of Chemical Engineering 482 produced water from oil, pump failures, bacterial growth, corrosion, problems related logistics, and handling, especially in an offshore environment. [84] This section discusses issues resulting from ASP applications, including produced emulsion, chromatographic separation, precipitation and scaling, and others.

Low oil recovery in shale oil reservoirs and vast shale reservoir volumes stimulate our efforts to investigate the application of enhanced oil recovery methods in shale oil reservoirs. A recent numerical study has indicated that cyclic gas injection could be an effective method to increase the oil recovery of shale oil reservoirs, and gas channeling can be mitigated. This paper presents our experimental verification and quantification of the potential to improve oil recovery by cyclic gas injection in shale oil reservoirs. Core plugs of Barnett, Marcos and Eagle Ford shales were used. The oil used was Mineral oil (Soltrol 130) and the gas used was Nitrogen. Unfractured cores were used in the experiments. The effects of cyclic time and injection pressure on oil recovery, among other parameters, were investigated. Our results also showed that cycle gas injection could increase the recovery from 10 to 50% depending on the injection pressure and shale core type. This study shows that one of the important mechanisms of cyclic gas injection is the pressure effect that causes a large pressure drawdown during the production phase. The cyclic gas injection provides an effective and practical method to improve oil recovery in shale reservoirs because the gas needed is available in liquid-rich shale plays.

In CO 2 injection, there is a minimum miscibility pressure (MMP) above that CO 2 can be miscible with oil, so that oil recovery will be high. This paper is to investigate the effect of the injection pressure on enhanced oil recovery in shale oil cores under huff-n-puff CO 2 injection, when the pressure is above and below the MMP. We first estimated the MMP for a Wolfcamp oil using slimtube tests. The slimtube test results showed that the estimated MMP for the CO 2 −Wolfcamp crude oil system was about 1620 psi at 104 °F. After that, we conducted 15 CO 2 huff-n-puff experiments using three different Wolfcamp shale cores at pressures below and above the MMP. These pressures were 1200, 1600, 1800, 2000, and 2400 psi. Each huff-n-puff test has 7 cycles. The huff-n-puff experiments for three cores showed that, below the MMP, the injection pressure had a significant effect on enhancing oil recovery. Higher than the MMP, the increased pressure further increased the oil recovery until the injection pressure was about 200 psi higher than the MMP. In the extremely low-permeability shale oil cores, additional pressure is needed to push gas into the deeper core to be miscible with the crude oil inside the core. The results indicated that, to have a high oil recovery in shale oil reservoirs during the CO 2 huff-n-puff process, the injection pressure should be higher (at least 200 psi in this case) than the MMP estimated from slimtube tests.

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Shale oil production has increased rapidly in the past decades, especially in the United States, and results in a revolution in the energy landscape. However, one main problem existing in the shale reservoir development is the sharp decline of liquids production in all the hydraulically fractured wells. In recent years, CO2 huff-n-puff injection has been proved to be a potential method to enhance the oil recovery. In this study, the effects of injection pressure and imbibition water on CO2 huff-n-puff performance were further investigated. Eagle Ford core samples and Wolfcamp dead oil were used in this experimental study. The microscopic pore characteristics of Eagle Ford shale core samples were analyzed, and the results show that 98.08% of the pore sizes are distributed between 3 nm and 50 nm. The experimental results demonstrate the great potential of CO2 huff-n-puff EOR. The cumulative oil recovery can reach 68% after seven huff-n-puff cycles. The oil recovered in each cycle deceases as injection cycle number increases due to the permeability damage caused by asphaltene precipitation, oil saturation reduction, and low injected CO2 sweep efficiency. The effect of injection pressure was studied by injecting CO2 at both immiscible and miscible conditions. CO2 huff-n-puff has better performance (more than 9.1% EOR) under miscible conditions than immiscible conditions. After that, a novel experiment was designed to saturate the core samples with both water (15 wt % KCl) and Wolfcamp dead oil to investigate the influence of imbibition water on CO2 huff-n-puff EOR performance. The existence of imbibition water impedes oil production in shale core samples. The oil recovery decreased about 45.3% after seven huff-n-puff cycles compared to the condition without water. A simulation study provides a better understanding of CO2 huff-n-puff application in liquid-rich shale reservoirs, which is fundamentally important for applying and optimizing CO2 huff-n-puff in field production.

There are many core flooding studies showing that the liquid-measured permeability is lower than the Klinkenberg-corrected gas permeability. The flow velocity in a low pressure gradient regime is lower than what is estimated from Darcy's law. This phenomenon is considered as low-velocity non-Darcy flow in the literature. Besides, many researchers believe that there is a threshold pressure gradient (TPG) that needs to be overcome before the fluid flow can occur. The related results in the literature are critically reviewed in this paper. By analyzing the flow mechanism, considering boundary effect, and presenting counter examples, we conclude that the low-velocity non-Darcy flow regime consists of a nonlinear flow part and a linear flow part. The nonlinear flow part starts from the zero pressure gradient instead of TPG. Based on this observation, a non-Darcy model is introduced and the corresponding correlation parameters are derived by fitting the available experimental data. This model is used to estimate the well performance of a vertical well and a multi-fractured horizontal well. For a vertical well, the production rate of non-Darcy flow is much smaller than that of Darcy flow, and the ultimate oil recovery of non-Darcy flow is approximately 48% of the Darcy flow. The production rate of a multi-fractured horizontal well if non-Darcy flow is considered is smaller in the beginning but greater than the corresponding Darcy flow rate after about some time (in our example model, 2700 days). The ultimate recovery factor of non-Darcy flow is 80% of Darcy flow, which indicates that multi-fractured wells are less affected by the low-velocity non-Darcy phenomenon compared with the vertical wells. Multi-fractured horizontal wells exhibit a significant advantage in developing shale and tight reservoirs, and low velocity non-Darcy flow plays a significant impact on the well production performance in tight and shale reservoirs.