Laboratory studies of the effect of oxygen content in CO 2 on the minimum miscibility pressure (MMP) are conducted on the n-C 5 H 12 /n-C 16 H 34 model oil and Cottonwood Creek crude oil with three injection gases of different oxygen contents. The results indicate that the MMPs for these oils increase unfavorably with increasing O 2 concentration in the CO 2 stream. The experimental results are also supported by our modeling work using a multiple-mixing-cell model, which is found to capture the effects of compositions and temperature, and is found to be a robust and predictive method for determining the MMP. Our experiments and calculations indicate that the effect of O 2 contamination on the MMP is larger for heavier oil and the effect of N 2 impurity on the MMP is larger than that of O 2 impurity.

Mud acid, which is composed of HCl and HF, is commonly used to remove the formation damage in sandstone reservoirs. However, many problems are associated with HCl acid, especially at high temperatures. In this study, formic acid was used to remove carbonate minerals as a preflush and with the main HF stage. A series of formic acid and HF mixtures with different ratios and concentrations were tested. Sandstone cores featured by different minerologies with dimensions of 1.5 in. x 6 in. were used in the coreflood experiments, which were run at a flow rate of 5 cm3/min and temperatures from 77 to 350°F. The cores were analyzed by CT scan before and after the acidizing to investigate the effect of the acid. The core effluent samples were analyzed to determine concentrations of Ca, Mg, Fe, Si, and Al by ICP. 19F NMR was utilized to follow the reaction kinetics and products. Zeta potentials of clay particles (kaolinite, illite, and chlorite) were measured in various acid solutions Formic acid (9 wt%) damaged sandstone cores. Zeta potential measurements indicated that formic acid can trigger fines flocculation. Addition of 5 wt% ammonium chloride helps to shield negative charges on clay surface. Analysis of core effluent samples indicated that there was CaF2 precipitate in the core when a small volume of preflush was used. Coreflood tests highlighted that formic acid/HF caused loss of core permeability. This paper will discuss the detailed chemical reactions occurred within cores and were followed by chemical analysis of core effluent samples and 19F NMR. Secondary reaction between clay minerals and HF became faster at higher temperature, and decreased the ratio of Si/Al. It was also found that different clay minerals react with HF offering very different concentrations of Al and Si in spent acid.

Recently, new evidences show that the recovery factors of both partially hydrolyzed polyacrylamide (HPAM) and xanthan gum (XA) flooding increase with higher concentration and higher viscosity. However, when the incremental oil recovery of XA flooding in artificial cores reaches about 8.6% OOIP (original oil in place), the displacement efficiency of XA flooding levels of, but an incremental oil recovery of more than 20% OOIP can be obtained from HPAM flooding with a high concentration, the higher the concentration the higher the recovery, the recovery does not level of. The difference in recovery between the two solutions is due to the visco-elastic properties of HPAM. The visco-elastic property of HPAM fluid not only increases the volumetric sweep efficiency but also the displacement efficiency of the pay zone on a micro scale. A novel method has been developed to enhance the oil recovery in highly heterogeneous and high permeable reservoirs. The results on artificial cores with a Dykstra-Parson Coefficient of 0.72 show that an incremental recovery over water flooding of more than 20% OOIP can be obtained by early time injection of the high molecular weight, high concentration polymer solution, the earlier the better. The incremental recovery is comparable to surfactant flooding but at a lower cost. In Daqing Oil Field, a pilot test of high concentration polymer injectivity was conducted on 6 injection wells in August 2002. Three wells are injecting in high permeable pay zones and the other 3 wells in low permeable pay zones. The range of effective permeability (Keff) of the pay zones is 0.354 ~1.06 um2. The results show that high permeable formations (Keff>0.890um2) are suitable for continuous injection of high concentration polymer solutions (concentration 2,000 ppm ~2,500 ppm, molecular weight 17 million Daltons, viscosity 200~250 mPa.S). There were 22 oil wells around the 6 dispersive polymer injection wells. In February 2004, the average fluid production of each well was 90.2 tons per day, the average daily oil production of each well was 21.7 tons and average water cut was 79.5%. Compared to low concentration (1,000 ppm) solution flooding, the fluid production per day of each well remained and the daily oil production of each well increased by 3.4 tons (an increase of 18.6%) and the average water cut decreased by 1.0%.The average water cut decreased by a maximum of 7%.The results show that the injection of high concentration polymer fluid is very effective and the pilot area will be further expanded. Introduction Petroleum, as a kind of non-renewable resource, is the lifeblood of the national economic development. About 60~70% oil is remained in the formation after water flooding. How to produce the remained oil economically and efficiently has become a problem to be resolved by oil reservoir engineers all over the world. According to most literatures,[1–2] when polymer flooding, the capillary numbers, which can only increase about a dozens times, is less than the increment needed to recover the residual oil, therefore, polymer flooding can only improve the swept volume and not the swept efficiency. In recent years, many petroleum engineers[3–4] consider that polymer flooding can also improve microscopic oil displacement efficiency due to the visco-elastic properties of polymer solution. From results on artificial cores, Wang Demin, etc.[5] deemed that an incremental oil recovery over water flooding of more than 20% can be obtained by injecting high concentration polymer solution. The aim in the present research is to find a new technique which can greatly enhance oil recovery efficiencies. The results in labs and fields both show that high concentration polymer flooding can further improve oil recovery. This technique is significant to the increment of recoverable reserves and the sustainable development of oil fields.