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Pseudo threshold pressure gradient (PTPG) is one of the main factors affecting the oil recovery of heterogeneous low-permeability and tight reservoirs. When the pressure gradient between the supply boundary and the bottom hole is less than PTPG, the crude oil in the formation cannot flow. In order to accurately measure the relationship between PTPG and permeability, a novel experimental device has been designed and a series of core flooding experiments using brine and oil have been carried out. The new experimental device eliminates the influence of rubber sleeve in core holder and core end-effect on the results, and greatly improves the accuracy of pressure measurement. The experimental results show the PTPG has a power function relationship with permeability, and has no obvious relationship with the viscosity of the fluid. Based on the equation for PTPG and permeability of crude oil and brine fitted by the experimental data, a new heterogeneous reservoir mathematical model considering PTPG were established. The influence of the coefficient of permeability variation, average permeability, and the production rate on oil recovery factor have been studied by this model. The results clearly show that the coefficient of permeability variation has the greatest influence on oil recovery factor, which represents inhomogeneity in low-permeability and tight reservoirs. Also, when the coefficient of permeability variation is less than a certain value (about 0.2 when average permeability is 1mD, in our model), there is only a slight decline in oil recovery factor, and when coefficient of permeability variation is larger than this value, the oil recovery factor decreases rapidly. The finding is consistent with oil field production and helpful to determine whether to take EOR(enhanced oil recovery) measures for a low-permeability heterogeneous reservoirs.

It is difficult to predict the flow performance in the nanopore networks since traditional assumptions of Navier–Stokes equation break down. At present, lots of attempts have been employed to address the proposition. In this work, the advantages and disadvantages of previous analytical models are seriously analyzed. The first type is modifying a mature equation which is proposed for a specified flow regime and adapted to wider application scope. Thus, the first-type models inevitably require empirical coefficients. The second type is weight superposition based on two different flow mechanisms, which is considered as the reasonable establishment method for universal non-empirical gas-transport model. Subsequently, in terms of slip flow and Knudsen diffusion, the novel gas-transport model is established in this work. Notably, the weight factors of slip flow and Knudsen diffusion are determined through Wu’s model and Knudsen’s model respectively, with the capacity to capture key transport mechanism through nanopores. Capturing gas flow physics at nanoscale allows the proposed model free of any empirical coefficients, which is also the main distinction between our work and previous research. Reliability of proposed model is verified by published molecular simulation results as well. Furthermore, a novel permeability model for coal/shale matrix is developed based on the non-empirical gas-transport model. Results show that (a) nanoconfined gas-transport capacity will be strengthened with the decline of pressure and the decrease in the pressure is supportive for the increasing amplitude; (b) the greater pore size the nanopores is, the stronger the transport capacity the nanotube is; (c) after field application with an actual well in Fuling shale gas field, China, it is demonstrated that numerical simulation coupled with the proposed permeability model can achieve better historical match with the actual production performance. The investigation will contribute to the understanding of nanoconfined gas flow behavior and lay the theoretical foundation for next-generation numerical simulation of unconventional gas reservoirs.

Polymer gels have received an increasing attention as profile control agents in the heterogeneous reservoir water-flooded layers. The article focus on the profile control mechanism of polymer gels by plugging macropore. The micro-structures of polymer gel and pore were characterized by scanning electron microscopy (SEM). And the core displacement equipment was used to evaluate the properties of plugging properties. The variation of pore structure is measured by SEM, mercury intrusion meter and nuclear magnetic resonance instrument. Investigation results show that the molecules form a network structure with many dense layers after 15 days of cross-linking reaction, which results in the increase of the viscosity of the system from 15.3 to 6325 mPa‧s. After the polymer gel forms a micelle at the middle end of the core and blocks the pores, the plugging rate of the core reaches 99.2%. The results obtained in this paper reveal the mechanism of plugging characteristics of polymer gels, and further prove the great potential of polymer gels to enhance oil recovery in oilfields.

This paper focus on the effect of the pressure and CO2 content on the state of asphaltene in the light crude oil from Changqing oilfield. When the pressure is more than 7 MPa or the CO2 con...

Deep coalbed methane, with its associated shale gas and tight sandstone gas resources in coal-bearing strata has been an area of research focus in China. Identifying gas accumulation potential and reservoir characteristics is therefore of great importance in understanding the co-exploration potential of unconventional gases. Accordingly, comprehensive experimental results, and incorporation with drilling and well-testing data in the mid-eastern Qinshui basin were used and analysed in this paper for the reservoir study. Tests on organic geochemistry, gas storage capacities, petrology and petrophysics, and gas inclusions were performed on massive core samples in the Carboniferous-Permian (C3t-P1s) strata. It is found that coal seams in this area are buried deeply, with the depth (mainly over 1000 m) increasing from east to west, and the gas contents of the coal generally increasing to depths of 400–1600 m, as a result of low-level temperature increment and high reservoir pressure. Dark shales and sandstones are widely distributed, with thicknesses of 12.2–65.9 m and 5–35 m in the Shanxi Formation and 40.5–131.7 m and 5–50 m in the Taiyuan Formation, respectively. Shales are rich in over-mature type II and type III organic matter and are mainly composed of clays (47%) and quartz (36%). Sandstones are mostly tight with low porosity (lower than 5% on average) and permeability (

The low permeability reservoirs is difficult to be economically developed by conventional water flooding. In this work, five enhancing oil recovery (EOR) methods including water flooding, modified water flooding, CO2 flooding, water alternating CO2 flooding (WAC) and surfactant alternating CO2 flooding (SAC) are systematically evaluated by core-injection experiments. In addition, the microscopic oil-displacement mechanism for these EOR methods are revealed by nuclear magnetic resonance (NMR) technique. The experiment indicates that the SAC performs the best among the five flooding methods, which not only effectively improves the oil recovery (recovery factor up to 50%), but also effectively decreases the water cut. By using this method, gas phase can recovery more oil from smaller pores due to the reduction of interfacial tension and easy accessibility of these pores, while surfactant reduces oil-water interfacial tension and generates foam, significantly improving the oil displacement efficiency in larger pores. Therefore, SAC combines the advantage of gas and water which can recovery the oil both within smaller pores and larger pores in a higher proportion. The results of this work provides us fundamental understandings of the mechanisms in enhancing oil recovery of the CO2 associated EOR methods.

CO2 based water-alternating-gas (WAG) injection and surfactant-alternating-gas (SAG) injection have shown to be two effective and practical methods to enhance oil recovery, which, also achieves carbon sequestration as well. In this study, a combination of experiment and numerical simulation was used to evaluate the performances of WAG and SAG flooding in low-permeability reservoir. Core drainage experiments were conducted, and NMR equipment was used to reveal the microscopic fluid distribution and explain the macroscale drainage results for each of the enhancing oil recovery (EOR) technique. In addition, the two EOR techniques were further evaluated in a realistic low-permeability reservoir, Yushulin oil field from Songliao Basin, China. The results show that, gas phase can lower gas-oil interfacial tension (IFT) in WAG process which contributes the oil displacement from smaller pores. Besides that, the surfactant in SAG process can also improve the oil displacement efficiency in larger pores due to the generation of foams. The optimal WAG and SAG ratios (1.25–1.5) in the realistic reservoir are all higher than the typical ratio (equal to 1) from the core experimental results and that in the most conventional oilfields due to the higher heterogeneity in low-permeability reservoir with easier gas breakthrough. Furthermore, the CO2 utilization efficiency for SAG is higher than WAG.

After depletion development stage, the well-utilized approach to enhance recovery of tight oil reservoirs is fluid-injection, involving nitrogen, water, and CO2. Although a great deal of research efforts has been devoted to relevant scope, it is still challenging to identify the appropriate fluid type which can achieve favorable recovery efficiency. Also, the oil-water distribution feature in tight oil reservoirs from the microscopic view is rarely investigated, especially for that after fluid-injection. Moreover, inherent TPG (threshold pressure gradient) will make a great difference on the assignment of well-spacing, which have not well investigated. Given the current situation, this work expects to bridge up the knowledge gap. First, the original oil-water distribution feature and that after fluid-injection are revealed through laboratory experiments, in which different kinds of fluid are measured. Then, the relationship between TPG and fluid type is quantified based on another set of experiments. After that, considering the pressure distribution characteristics in whole tight oil reservoirs, the optimization plate for well-placing under different fluid types is concluded. Results show that (1) Gas-flooding shares advantages compared with water-flooding, displacement efficiency for gas-flooding is over 40% and that for water-flooding is 36% on average; (2) the main pore types initially occupied by oil consists of pore-throat, cluster, corner and intergranular, which account for 9.51%, 26.42%, 15.51%, and 13.82% respectively. And the major contributor to oil recovery comes from cluster pore-type; (3) gas-flooding approach is recommended as for the low-permeability case, and the water-flooding approach becomes favorable as for the high-permeability case.

Summary In this article, a more-general flow-pattern classification of oil/water two-phase flow in the horizontal wellbore is proposed first according to the theoretical analysis and previous research achievements, on the basis of which a simplification is then performed through reasonable incorporation, and the ultimate flow patterns considered for modeling are reduced to two categories containing only six standard patterns. By use of the classical two-fluid and homogeneous modeling methodologies stemming from oil/water two-phase flow in conventional pipes, combined with the simplified classification, a mechanistic model is developed to predict the flow characteristics including the flow patterns and pressure losses for oil/water two-phase variable-mass flow in the horizontal wellbore. Model implementation is performed on the basis of the universal principle that a system will stabilize to the equilibrium state of minimum energy. Overall performance of the mechanistic model is then validated against the new data sets measured upon a large-scale experimental apparatus at the China University of Petroleum (CUP), which is designed and constructed to simulate the gas/oil/water multiphase flow in horizontal wellbores with wall mass transfer. Results show that the model developed in this paper can not only properly predict the flow patterns of oil/water two-phase flow in the horizontal wellbore, but also has high prediction accuracy for the pressure drops. Compared with the new experimental data for oil/water two-phase variable-mass flow that covers a series of input water-volumetric fractions ranging from 10 to 90%, the highest absolute average percentage error of the new unified model is 12% and the whole error is 9.2%, which demonstrates an acceptable performance. Investigations conducted in this study further enrich and develop the theory of hydrodynamic calculation for oil/water flow in the horizontal wellbore with wall influx.

The flow law near polymer flooding wellbores under the condition of perforation is very complex and there are many types of shaped charges. In this study, a non-Darcy flow model near polymer flooding wellbores was given, and a flow experiment was carried out to measure the resistance coefficient, residual resistance coefficient, and flow viscosity of the polymer solution in porous media under the conditions of different permeability and different polymer molecular weight. According to the results of numerical simulation, this paper calculated the flow efficiency of different types of shaped charges and evaluated the adaptability of different charges under polymer flooding condition. The results of this study have an important significance for guiding the optimization of shaped charges and the optimization design of perforating parameters.