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Krüppel-like transcription factor (KLF)13, previously shown to regulate RANTES expression in vitro, is a member of the Krüppel- like family of transcription factors that controls many growth and developmental processes. To ascertain the function of KLF13 in vivo, Klf13-deficient mice were generated by gene targeting. As expected, activated T lymphocytes from Klf13(-/-) mice show decreased RANTES expression. However, these mice also exhibit enlarged thymi and spleens. TUNEL, as well as spontaneous and activation-induced death assays, demonstrated that prolonged survival of Klf13(-/-) thymocytes was due to decreased apoptosis. Microarray analysis suggests that protection from apoptosis-inducing stimuli in Klf13(-/-) thymocytes is due in part to increased expression of BCL-X(L), a potent antiapoptotic factor. This finding was confirmed in splenocytes and total thymocytes by real-time quantitative PCR and Western blot as well as in CD4+CD8- single-positive thymocytes by real-time quantitative PCR. Furthermore, EMSA and luciferase reporter assays demonstrated that KLF13 binds to multiple sites within the Bcl-X(L) promoter and results in decreased Bcl-X(L) promoter activity, making KLF13 a negative regulator of BCL-X(L).

This paper introduces a method to fracture more than 30 zones in a single well per day and also how to fracture low permeability zones when the impermeable barrier(s) to high permeability and high water cut zones are only about 0.5 m thick and not create channels in the cement sheathe. The above methods are used in a large scale in Daqing Oil Field (about 1,000 wells per year since 1980). The results are quite good, cumulative incremental oil production by these fracturing methods is about 60 million tons; the fracturing costs per ton of incremental oil is about $ 6.

Studying zones, geological sediments, oil and water, etc. of different characteristics, suitable ASP systems mainly with alkylbenzene sulfonate, bio-surfactant, NaOH, Na2CO3 and polymer were screened. After getting good results in laboratory studies, five ASP pilot tests have been conducted with different well spacings, zones and at different locations etc. Our aim was to study: 1) the injectivity and productivity of ASP systems; 2) the damage to the reservoir with different kinds of alkaline; 3) the method of lift and how to increase very low productivity; 4) Chromatographic separation with different well spacing; 5) the effect of this EOR method and its potential; 6) its technical and economical benefits. Both laboratory and pilots studies showed that different zones, oil and water, and different surfactant components all require different ASP systems; bio-surfactant is compatible with alkylbenzene sulfonate; and no matter what kind of alkaline where selected in the pilot, theoretically, there is some damage to the zone, but the damage to the reservoir was not significant in the pilots, the same for chromatographic separation. Numerical simulation and pilot results both showed that more than 20% OOIP oil recovery were obtained over that of water flooding. The actual production data was better than numerical simulation. Even in a reservoir with long-term 100% water cut, the chemical cost per ton of incremental oil is around 30$ to 40$. Especially in a very low oil price situation in the world today, this method can obtain good benefits both technically and economically. Over all, the success of these ASP flooding pilots in Daqing Oil Field are good examples on enhanced oil recovery with similar types of reservoir sediment as Daqing, and also provides a new method to achieve sustained development of resource developing companies.

After studying zones, geological sediments, oil and water, etc. of different characteristics, an Alkaline-Surfactant-Polymer flooding formulation mainly with alkylbenzene sulfonate was screened. Pilot investigation with this formulation has been conducted with different alkali and different zones, good results have been achieved both technically and economically.[1,2] Based on former study results,[3,4] screening of ASP formulations to further reduce the usage of surfactants and get better technical and economical results were performed. The interfacial tension behavior between oil and bio-surfactant ASP systems, emulsion characteristics, adsorption, core flooding, as well as numerical simulation, etc. were studied. After success in the laboratory study, the first Alkaline Bio-Surfactant Polymer Flooding Pilot was conducted in the north of the oil field. Both laboratory and pilot studies showed that the Alkaline Bio-Surfactant Polymer Flooding system not only can further reduce the usage of surfactant and dynamic adsorption, but also can further reduce the ultra-low interfacial tension, extend the ultra-low interfacial tension area. Its emulsion phenomenon and chromatographic separation was not significant. After the implementation of the Alkaline Bio-Surfactant Polymer Flooding pilot, good results in terms of daily water cut decrease and incremental oil of the central well were obtained, the actual production data was better than the numerical simulation prediction. Now, the oil recovery of the central area is 21.5% OOIP over that of water flooding, preliminary economic analyses show that the chemical cost per ton of incremental oil is less than 30$. This should be a good bio-chemical flooding method.

Abstract Daqing Oil Field has already successfully implemented two alkaline/surfactant/polymer (ASP) floods with dense well spacing. To further confirm the feasibility of ASP flooding at industrial well spacing, confirm "absolute incremental oil" (incremental oil after the pay zone reaches 100% water cut by water flooding, and not incremental oil over 98% water cut as is normally calculated in China) and to further confirm the magnitude of chromatographic separation of the injected chemicals on condition of large well spacing, two ASP field tests with a larger well spacing (200m to 250m) are in progress in Daqing now, the results of one of the field tests in a more advanced stage (i.e. a larger portion of chemicals have been injected) is presented in the this paper. This larger well spacing field test consists of 4 injectors and 9 producers forming 4 inverted five spot patterns. The distance between producers (or injectors) is 28Om and between producer and injector 200m. By the end of 1995, 7 new wells were drilled. The data from these wells showed that, on the average, 92.5% of the pay zone (PI33) were already water flooded. In these 7 new wells, 5 producers (including the center well) had a water cut of 100% for 9 months from the start of production to the time the ASP flood lowered the water cut. The average water cut of the 9 producers was 98.4%. Single well tracer logging at the center well obtained a residual oil saturation of 18+3%. By numerical simulation, the water flood recovery was already 67.2% before the ASP flood. Core tests were performed to optimize the sequence and quantity of chemicals to be injected. The results showed that, on condition of constant quantity of polymer and surfactant injected, injecting a polymer slug before the ASP slug and injecting a tapered ASP slug can increase the recovery of the flood; increasing the viscosity of the ASP slug can offset the effect of the heterogeneity of the pay zone. The injection scheme was optimized according to the above tests, the characteristics of the pilot area and by numerical simulation. According to the optimized program, it was predicted that the ultimate recovery of the ASP field test would be 77.2% OOIP, about 10% higher than the 100% water cut recovery and 25% OOIP higher than the 98% water cut recovery. The polymer slug was injected during the period Sept. 18 to Nov. 2, 1996. After that, the ASP slug started to be injected. After injecting 0.09 PV of ASP, the surrounding wells started to respond by lower water cuts. The water cut of the center well dropped from 100% to 46.9%. now the cumulative incremental oil production of the center well is 7,494 t, equivalent to 12.8% OOIP increase in recovery, much better than that predicted. It is estimated that the ultimate incremental recovery will be 16 to 17% OOIP over that of 100% water cut by water flooding. Preliminary economic analyses show the chemical cost per barrel of incremental oil is around $6.5 When the water cut dropped to 50%, the produced fluid was completely emulsified, this condition was maintained for a long period of time (0.123 PV). At reservoir temperature, the viscosity of the emulsion was 140 mPa S, and it could further emulsify oil and water. The emulsion was very stable, but it could be broken easily by a de-emulsifier developed in Daqing. The field test shows that by optimized designing, ASP flooding of ultra-high pay zones can obtain very good technical and economical results. Large amount of emulsified fluids is an important factor for good results of ASP flooding. The results of this field test should be of important reference for ASP flooding of 100% water cut pay zones. P. 305

Abstract Several papers on polymer flooding pilot test in Daqing have been published previously, they stress on enhancing oil recovery by polymer flooding in thick pay zone of major reservoirs with high permeability and heterogeneity. This paper presents the polymer flooding pilot test results in thin layers of non-essential reservoirs with medium-low permeability and heterogeneity. The purpose is to:study the feasibility of polymer flooding in such thin pay zones;test separate injection techniques;provide data for further extending polymer flooding potentials. The pilot has 4 injectors and 9 producers in inverted five spot patterns. The polymer flooding through Putaohua P I 1–3 formation had been finished in this pilot in 1990, then S II 10–16 was plugged and S II 10–16 was perforated to perform polymer flooding by dual-pipe separate injection. S II 10–16 formation includes 5 sedimentary time units and has complex geometry of sandbody and some layers pinch out in a few wells in the pilot. Its microstructure relief is large, the deference in depth of the formation is 3 7 meters. The net thickness of a single layer is 0.4 to 4.0 meters. Its average permeability is 0.342 m2 and Dykstra-Parson coefficient is 0.6. Polymer injection started in December of 1993 and 0.35 PV of polymer solution has been injected by the end of 1995. When 0.025 PV polymer solution was injected, the producers responded one after another. The average water cut of the pilot decreased from 94.5% to 80.1% and daily oil production increased from 37 tons to 95 tons maximum. The water cut of the central well decreased from 95.1% to 63.1%, daily oil production increased from 8 tons to 33 tons. Up to now the oil recovery for the central well has increased 10.84% OOIP over water flooding with the polymer flooding efficiency of 151 tons of oil per ton of polymer. The measurements of injection and production profile showed that the heterogeneity of the reservoir is adjusted and that separate injection technique by dual-pipe is feasible. P. 431

In the last few years horizontal wells are becoming increasly important. This paper presents a hydrodynamic method for solving the flow problem of areal water–flooding systems of combinations of vertical and hprizontal wells( 5–spot well pattern and 7–spot well pattern). The potential function, production rate, breakthrough time, areal sweep efficiency and stream functions are derived respectively. Also, the flow resistance method is used for getting the equations of horizontal well production for all the areal floods. Finally, the equations of oil productions derived by the two methods are compared.