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The latest advancement of CO2 flooding and sequestration theory and technology in China is systematically described, and the future development direction is put forward. Based on the geological characteristics of continental reservoirs, five theories and key technologies have been developed: (1) Enriched the understandings about the mass transfer characteristics of components between CO2 and crude oil in continental reservoirs, micro-flooding mechanism and sequestration mechanism of different geological bodies. (2) Established the design method of reservoir engineering parameters, injection-production control technology and development effect evaluation technology of CO2 flooding, etc. (3) Developed a series of production engineering technologies such as separated layer CO2 injection technology, high efficiency lifting technology, on-line wellbore corrosion monitoring and protection technology. (4) Innovated a series of surface engineering technology including CO2 capture technology, pipeline CO2 transportation, CO2 surface injection, and production gas circulation injection, etc. (5) Formed a series of supporting technologies including monitoring, and safety and environmental protection evaluation of CO2 flooding reservoir. On this basis, the technological development directions in the future have been put forward: (1) Breakthrough in low-cost CO2 capture technology to provide cheap CO2 gas source; (2) Improve the miscibility technology between CO2 and crude oil to enhance oil displacement efficiency; (3) Improve CO2 sweeping volume; (4) Develop more effective lifting tools and technologies; (5) Strengthen the research of basic theory and key technology of CO2 storage monitoring. CO2 flooding and sequestration in the Jilin Oilfield shows that this technology has broad application prospects in China. Key words: continental reservoirs, CO2 flooding and sequestration, enhanced oil recovery, reservoir engineering, injection and production engineering, surface engineering, development direction

Predicting well performance in low-permeability reservoirs has attracted attentions in the last decades. Decline curve analysis is treated as the most convenient and efficient approach to forecast production. However, each single decline model has its own limitations due to the low permeability and porosity. Hence, we cannot directly apply these models in the low-permeability reservoirs, especially the dramatically drop in the early period. In this study, based on the analysis of conventional production decline models and the development characteristics of low-permeability reservoirs, a new production decline model was proposed, which can quickly and accurately predict the future performance of horizontal wells. Three fitting parameters were employed representing the production performance in early, middle and late-life period respectively. A decline exponent parameter of n was also included in the proposed model. Subsequently, the proposed model was validated, and good agreement was obtained with the production data of a low-permeability block in China. The comparison between new method and other models are analyzed in detail, which illustrates that this proposed approach is more flexible and confident. This work can give a useful insight into accurately and efficiently predicting well performance in low-permeability reservoirs.

Oil production prediction model and water flooding characteristic curves are generally applied to production performance analysis. However, these two methods have some limitations especially in predicting water cut. Growth model can predict oil production and cumulative oil production, but it cannot predict water cut. Water flooding characteristic curves can predict water cut and cumulative oil production, but it cannot establish the relationship between production indexes and time. The Morgan–Mercer–Flodin (MMF) growth model is a kind of production prediction model. This study analyzed features of MMF growth model, then Hu–Chen (HC) model was deduced on the base of MMF growth model. Theoretical basis of HC model was improved and solution of parameters was simplified. Then combining it with water flooding characteristic curve, a new combined solution model was built. This new combined solution model can predict water cut versus time and it overcame deficiencies of production prediction model and water flooding characteristic curves. The applications of field case selected from the Block-A in Daqing Oilfield indicated that the prediction accuracy of this new combining model can meet the demand of production performance analysis and it can guide the determination and adjustment of the development programs in water flooding hydrocarbon reservoirs. It has features of higher prediction accuracy, easier to use and widely practicable compared with other combined models.

In this paper, the sensitivity factors of CO2 huff-n-puff for multifractured horizontal wells (MFHWs) in tight oil reservoirs were investigated through an experimental test and numerical simulation. The pressure-volume-temperature (PVT) experiment and the slim tube experiment are used to understand the interaction mechanism between CO2 and crude oil, and the minimum miscibility pressure (MMP) of the CO2-crude oil system is 17 MPa. The single-well model was firstly established to analyze the sensitivity factors on production performance of MFHWs by using CO2 huff-n-puff. The controlling factors of CO2 huff-n-puff for MFHWs in tight oil reservoirs were divided into three categories (i.e., reservoir parameters, well parameters, and injection-production parameters), and the impact of individual parameter on well performance was discussed in detail. The range of reservoir parameters suitable for CO2 huff-n-puff of MFHWs is obtained. The reservoir permeability is from 0.1 mD to 1 mD, the reservoir thickness changes from 10 m to 30 m, and the reservoir porosity is from 7% to 12%. Based on the reservoir parameters of the target reservoir, the reasonable well and fracture parameters are obtained. The sensitivity intensity was followed by the horizontal well length, fracture conductivity, fracture spacing, and fracture half-length. CO2 injection-production parameters are further optimized, and the sensitivity intensity was followed by the single-cycle cumulative CO2 injection rate, the soaking time, the injection rates, and the production rates. It provides a reference for parameter optimization of CO2 huff-n-puff for MFHWs in tight oil reservoirs.

In the late 1990s, large amounts of low permeability resource plays in the south of Songliao basin have been discovered and made a great contribution to regional development, so far most of them need to be made efforts to improve recovery factors by tertiary method, CO2 flooding has an effective way for this kind of reservoir. CO2 injection pilot was implemented in 2008, it provided invaluable information for extensive areas to make gas injection and production scheme including produced gas recycling. Most low permeability reservoirs in Song Liao basin have no nature flow, the economic productivity could not be obtained except fracturing. Therefore, it leads to CO2 breakthrough early and produced gas profile variation greatly during the CO2-EOR process. CO2 is from the deeper natural gas field with CO2 concentration over 20%, after separation, the CO2 purity reaches 99% for injection. So how to treat the EOR produced gas is an environmental and economic issue to achieve zero emissions for the whole operations. According to the actual field test data, the vast majority of composition of produced gas are lighter hydrocarbon and CO2. This paper will analyze the composition of gas samples from Jilin oil field, understanding the components of the output gas variation with time. The phase behavior and mass transfer will be characterized by the minimum miscibility pressure (MMP) test and core flood experiment, and the quantitative description method will be obtained through the relationship between the individual component or segment components and sweep efficiency. Consideration the effect of CO2 impurities on MMP and displacement efficiency, the critical value of CO2 concentration of produced gas is 85%~95%, according to this study, all the produced gas can be reinjection without separation, the value for field application is approximately 90%. That means it would require mixing with pure CO2 for reinjection when CO2 concentration of produced gas is below 90%, otherwise, it could re-inject to oil field directly. All these results have been applied to achieve reasonable CO2 recycle.

Abstract Multiple transverse fractures are hydraulically created to enhance the productivity of horizontal wells drilled along with the minimum principal stress. The fracture properties, such as fracture number, length, conductivity, etc, are very important factors affecting the horizontal well productivity. Therefore, a reliable and practicable method for predicting and optimizing the productivity of horizontal wells is essential to reservoir engineering designation. However, existing mathematical models and evaluation methods did not include the impact of the threshold pressure gradient and the pressure-sensitive effect which cannot be ignored in ultra-low permeability reservoirs. The objective of this paper is to present a method considering the threshold pressure gradient and the pressure-sensitive effect, thus predicting and optimizing the productivity of multiple transverse fractured horizontal wells (MFHW) in ultra-low permeability reservoirs becomes available. The new method couples the non-Darcy elliptical flow, which considers the threshold pressure gradient and the pressure-sensitive effect in the reservoir region, the Darcy linear flow in the fractured region, and the Darcy radial flow to the horizontal wellbore in the fractured region respectively. Based on the equality radius mode and the pressure superposition theory, the evaluation methods for the productivity of multiple transverse fractured horizontal wells are presented. In addition, the new method is validated by comparing with field data, results confirm that those formulas are precise and practical, and the evaluation method is reliable. Based on an example of productivity analysis for a multi-fractured horizontal well, the effects of some factors, such as threshold pressure gradient, coefficient of deformation and fracture parameters (fracture number, fracture length, conductivity, uniformity of fractures length and intervals), on the productivity were studied. The results show that the greater the threshold pressure gradient, the greater the effect of it on multi-fractured horizontal well productivity, so the threshold pressure gradient must be accounted to evaluate the MFHW productivity in ultra-low permeability reservoirs. Also, the greater the coefficient of deformation, the greater the effect of it on MFHW productivity, and the affection of coefficient of deformation on productivity is related to producing pressure drop, and the greater the pressure drop, the larger the influence of deformation coefficient on producing rate, thus for strongly pressure-dependent reservoir, we'd better conduct an optimization design for feasible producing pressure drop. In the given condition, the optimal fracture number of the horizontal well is 4~5, the half length of fracture is about 120 m, and the conductivity is 4.8 D•cm. The fractures with longer length, lower conductivity, variable length and placed in unequal interval are favorable for homogeneous oil reservoir. This paper provides reservoir engineers with a reliable and practical method to predict and optimize the productivity of multiple transverse fractured horizontal wells in ultra-low permeability reservoirs.

The parameters influencing gas alternative water (WAG) for CO2 flooding in the low permeability block of the Jilin oil fields in China were investigated using the numerical simulation software, Eclipse. The minimum miscibility pressure was first determined based on slim tube tests. Comparisons were made between continuous water flooding, continuous CO2 flooding, and WAG flooding methods. The oil recovery ratio of “gas injection first method” was higher than that of “water injection first method” and the mechanism of CO2 displacement was analyzed. The optimum parameters for WAG flooding were 7 for the number of slugs, 0.3845 PV for the total injection volume, approximately 0.5742 for the gas/water slug ratio, and 120 days for the stewing time. The optimum injection timing of the switching depletion development to the WAG injection was 0.25 years and the earlier switching to the WAG injection after water flooding was more suitable for enhanced oil recovery. The maximal cumulative water injection by water fl...