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Abstract Shale reservoirs have complex mineral compositions and are rich in micro-scale pores. It is of great scientific and engineering significance to explore the mechanism of external fluids on the pore throat structure of shale. In this paper, pure carbonaceous shale is taken as the research object, and the mechanism of the influence of slip water and reflux fluid on the pore throat structure is analyzed by using nuclear magnetic resonance (NMR) technology. Then, the sensitivity of different types of shale to external fluids is comparatively analyzed and summarized. The results show that (1) the oil slick has a certain effect on the total porosity of different types of shale. The rate of change is shown as carbonaceous shale (− 7.1%) > pure shale (− 1.6%). (b) For slickwater, the average reduction of macro- and micro/nanopores in carbonaceous shale is 90.0% and 5.0%, respectively, while the average reduction of macro- and mesopores in pure shale is 17.7% and 6.8%, respectively. (c) Total porosity of different shale types is insensitive to refluxing fluids. The average increase in macro-, meso-, and small pores of carbonaceous shale is 31.8%, 23.6%, and 20.2%, respectively; the average increase in macro- and small pores of pure shale is 17.1%.

With the temperature and pressure effect, the composition change and oxygen consumption law of light crude oil and discoxidation air in Tahei North Block were studied. The static oxidation experiment of crude oil was carried out in a high temperature and high pressure reactor indoors to systematically study the oxidation effect of crude oil by disoxidation air with different oxygen content and different gas injection volume; the hydrocarbon was analyzed by chromatographic analysis, and the reaction gas was collected for gas analysis. The results showed that: ① The low-temperature oxidation reaction between crude oil sample and disoxidation air decreased the components above C21 and increased the content of light components below C13; ② The oxidation effect of crude oil increased with the increase of oxygen content, and the components in the reaction process corresponded to the "inflection point" in the front; ③ When the oxygen content was constant, the "inflection point" corresponding to the reaction remained unchanged by changing the oil-gas ratio; In the overall reaction process, the oxygen content decreased and then tended to be flat; ④ CO2 was generated in the process of low-temperature oxidation, and the CO2 content tended to be flat after increasing; ⑤At reservoir temperature (160℃), crude oil mainly involves two reaction thermal cracking and oxygenation reactions. The thermal cracking reaction is not related to the oxygen content, but to the temperature. The main reaction temperature is 160-200℃. Heavy components such as high-carbon asphaltene will be decomposed into saturated hydrocarbons. The oxygenation reaction is mainly aromatic hydrocarbon, and the resin oxygenation reaction will also produce asphaltene. When the two reactions exist at the same time, the content of asphaltene participating in thermal cracking is greater than the quality of asphaltene generated by oxygenation reaction aromatic hydrocarbon, which will lead to the decrease of asphaltene content.

The retention of gel system in porous media results in the reduction of porosity and permeability. However, the length of the current experiment models (sandpack or core sample) are in the range of centimeter scale, which is too short to track the full movement path of gel particles. In this work, a series of gel flooding experiments were conducted on 2.5-m long slim sandpack models. Seven fluid collection/pressure monitoring points were equally distributed along the length of the slim sandpack to track the movement of gel particles during the flooding process. We quantified the adsorption capacity, adsorption velocity, and mechanical shear effect of polymer/cross-linking agent along the flowing direction. In addition, we also employed scanning electron microscope (SEM) equipment to observe the morphology of the gel and the pore structure along the flooding direction, which provides good evidences of the adsorption retention and mechanical shear effects. Results show that most of the polymers and cross-linking agent were adsorbed on the region near the inlet. We emphasized the advantages of using long sandpack/core to track the full movement path of the gel system. In addition, the morphology of the original gel system showed a network characteristic of hexagonal structure, which was dragged to an elongated structure or even totally broke when it was transported through the porous medium. This work provides the fundamental understandings of the dynamic adsorption behaviors of gel system, which could be useful for optimizing the components of gel system, selection of target oil reservoirs and their operational parameters during gel flooding in enhancing oil recovery.

Abstract Recently, as the demand for fossil and renewable energy continuously increases, enhancing oil recovery has become one of the key methods to meet the increased requirement. However, most of the oilfields are facing serious problems, including formation heterogeneity and low recovery factor. Therefore, further analysis is required to study the distribution of remaining oil and how to enhance oil recovery effectively. In this study, the core samples of different reservoir types were employed and characteristics of pore structure were measured by a high‐pressure mercury porosimeter. The recovery factor and distribution of remaining oil with different reservoir types were determined by core flooding experiments and nuclear magnetic resonance tests. According to the results, the heterogeneity of pore structure becomes weaker as the permeability of the reservoir increases. The recovery during different periods improved as the core permeability increased. The distribution of remaining oil in different pore sizes has an obvious difference. The contribution of the recovery factor is highest in smallpores and mesopores for type II reservoir while is greatest in mesopores and macropores for type III reservoir. These results can provide theoretical and technical support for further enhancing oil recovery.

Over the past decades, CO 2 flooding in low-permeability porous media has continued to grow. Furthermore, propelled by the current movement toward CO 2 sequestration, the flooding of CO 2 is expected to further increase. Thus, it is of scientific significance to study the mechanism of displacement of CO 2 flooding as well as the CO 2 storage characteristics. In this study, CO 2 miscible/immiscible flooding experiments were conducted on two low permeability samples to study the difference between them. Specifically, the effect of oil displacement and CO 2 storage coefficient for different displacement models were measured and compared. In addition, nuclear magnetic resonance (NMR) tests and frozen pelleting experiments were conducted. The NMR tests clarified the lower limit of pore throat where oil can be displaced by CO 2 miscible/immiscible flooding. Furthermore, the frozen pelleting experiments analyzed the distribution characteristics of the remaining oil before and after CO 2 miscible/immiscible flooding. The investigation showed that the development efficiency of CO 2 miscible flooding is higher than CO 2 immiscible flooding in low permeability reservoirs. The results also indicated that CO 2 miscible flooding increases the recovery of hard-to-produce semi-bound oil phase and CO 2 storage coefficient with CO 2 miscible displacement is more significant than that with CO 2 immiscible flooding. The data from this study is a critical input for reservoir simulation, which sheds light on the CO 2 miscible/immiscible flooding in low permeability reservoirs.

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.

Alkali/surfactant/polymer (ASP) combines the advantages of each of the chemical in the blend. ASP has shown to be an effective and practical method to enhance oil recovery. Compared with vertical wells, fluid flooding by using horizontal wells is believed to be infeasible due to easier fluid breakthrough and subsequent low sweeping efficiency. However, good responses observed in field applications (Daqing oil field, China) show the promising future of ASP flooding using horizontal wells. In this study, a combination of laboratory-scale core displacement experiments and reservoir-scale numerical simulations was used to study the performances of ASP flooding by using horizontal injection/production wells and vertical injection/production wells to reveal the mechanisms responsible for the favorable responses observed in the field. Firstly, displacement experiments in evaluation of ASP flooding using vertical wells and horizontal wells were conducted. The effects of well type on ASP flooding performances were further evaluated by numerical simulation based on a realistic reservoir. The results show that, horizontal well injection/production pattern facilitates a better oil displacement performance due to the higher sweeping volume. This is because horizontal injection/production pattern weakens both the effects of surface heterogeneity and vertical inter-layer heterogeneity during ASP flooding performance. Although horizontal injection/production well pattern is not suitable for water flooding due to the higher chances for water breakthrough, the profile-control characteristic of ASP system blocks the high permeable channels to some extent, providing a better performance in combination with horizontal injection/production well pattern. This work systematically studied the effects of well type on ASP flooding performance at core scale and reservoir scale, and it provides theoretical and practical implications for the application of ASP flooding in enhancing oil recovery for high water cut reservoirs.

Polymer gel has attracted extensive attention as an effective agent for profile control as development enters middle and late stage. However, formation heterogeneity and the unclear mechanism of gel profile with different strength severely limits the displacement effect. In this work, microstructure and viscosity of polymer gels with different concentrations were characterized. The injection behavior experiments were carried out to calculate breakout pressure and plugging rate. The core flooding experiments were performed to obtain the remaining oil saturation field and recovery rate. The results illustrated that the gel viscosity increased and the plugging ability enhanced as the polymer concentration increased; Meanwhile, type C was determined as the best strength for displacement in heterogeneous formation; From oil displacement results, the gel fluidity decreased and blocking formed in high permeability reservoir, which forcing subsequent water divert to the low permeability reservoir. As a result, the swept volume expanded and the oil recovery enhanced. The fruitful works throw light on the mechanism of gel profile control and provide strong technical support for enhanced oil recovery in heterogeneous formation.

AbstractMiscible CO2 flooding gains rising popularity due to high displacement efficiency and potential carbon negativity. It is well documented that pore-level heterogeneity is one of the dominant mechanisms responsible for the variation in oil recovery efficiencies of miscible CO2 flooding. However, owing to a lack of understanding of miscible CO2 displacement behaviors at pore level, quantitative analysis of the mechanisms for the influence of pore-level heterogeneity on the oil recovery efficiency of miscible CO2 flooding remains problematical. Recently, NMR has been widely used to investigate microscopic residual oil distribution and pore-level displacement behaviors of various agents. Nevertheless, current NMR-based methods for determining microscopic residual oil distribution require the use of fluorinated oil, Mn2+ solution, or heavy water for eliminating the mutual interference of oil and water NMR signals. The differences in properties of reservoir fluids and additional agents could give rise to the change in displacement characteristics and consequently affect the analysis results on pore-level displacement behaviors. In this study, a method to determine microscopic residual oil distribution in sandstone during gas floodings based on NMR T2 spectrum without additional agents except reservoir fluids is proposed. Using the method, we can avoid the possible changes in the displacement characteristics caused by additional agents. Miscible CO2 flooding experiments are conducted with ultra-low and extra-low permeability cores. The T2 spectra of cores before and after flooding are measured using a 23 MHz low-field NMR instrument. Residual oil distributions in cores are quantitatively characterized using the proposed method, and then, oil recovery efficiencies from different-sized pore throats are evaluated. It is found that for both cores about 60% of the residual oil is distributed in pore throats with 0.03 μm radius is displaceable for miscible CO2 flooding, which indicates that the thickness of the raffinate layer in the pore should be less than 0.015 μm. More than 30% of the residual oil is distributed in unswept areas, and thus, the sweep efficiency improvement is expected to effectively enhance the oil recovery of miscible CO2 flooding. The sweep efficiency is negatively affected by the pore-size heterogeneity. For the ultra-low and extra-low permeability cores, the standard deviation of pore size is 0.39 and 1.15, respectively, and correspondingly, the sweep efficiency is 84.33% and 72.84%, respectively. In the core, the oil recovery efficiencies from swept pore throats with 3 μm radius can form a preferred flow path, which will significantly reduce the oil displacement efficiency from swept pore throats with

AbstractThe bottom-hole flow pressure is an important factor affecting the production of the unconventional tight oil well. The reasonable bottom-hole flow pressure has a positive effect on enhancing the production capacity of oilfields and improving the production efficiency of oilfield enterprises. Therefore, a robust method is proposed to determine the reasonable bottom-hole flow pressure in unconventional tight oil reservoirs, sharing the advantages of coupling geological feature and fluid flow behavior. In this method, the geological model and numerical reservoir simulation based on ECLIPSE software are developed firstly. The effects of the stress sensitivity, the PVT properties, permeability damage, fracturing fluid leak-off, and skin coefficient on the single-well productivity are then discussed. The reasonable variation range of the bottom-hole flow pressure in different production stages is then determined. Results show that crude oil viscosity, formation damage, and stress sensitivity are the most sensitive factors to the recovery degree. And, desirable tight oil production performance can be achieved with the application of the optimized bottom-hole pressure.

AbstractCombination flooding, which performs well on both sweep efficiency and displacement efficiency, is being extensively utilized in Daqing Oilfield. Surfactant-polymer (SP) flooding and alkaline-surfactant-polymer (ASP) flooding are two of the most used combination flooding techniques. According to the findings, alkaline lowers the oil-water interfacial tension and reduces the other component’s adsorption. Nevertheless, alkaline also has negative effects like scaling and cost increasing. Therefore, the use of alkaline in combination flooding is still disputed. In order to clarify the role of alkaline on combination flooding, SP and ASP flooding comparative tests are conducted with typical formula in Daqing Oilfield. A 3000-centimeter long model is built to simulate long distance migration for the property change study. During the flooding, fluid samples are obtained along the model, and the properties of the samples such as viscosity, interfacial tension (IFT), and components concentration are measured. According to the findings, the 3.60 percent higher recovery rate caused by ASP flooding compared to SP flooding is primarily due to the near inlet area. In ASP flooding, alkaline reduces polymer and surfactant near inlet dynamic retention by 20.16% and 13.43%, respectively, when compared to SP flooding. Besides, alkaline also maintains viscosity at a higher level and IFT at a lower level in the first third of the well spacing in ASP flooding. Consequently, the effects of alkaline are noticeable in the near inlet area and fade as distance increase.

Abstract A novel multilateral well for coalbed methane extraction was proposed in the study. There is a main wellbore at the longitudinal center of coal seam and four lateral wells at the horizontal center in the multilateral-well system. Compared with traditional drainage holes, multilateral-well system has a better performance on coalbed methane development. A hydraulic-mechanical coupling model of multilateral well was established, the pressure and permeability ratio distribution of the gas extraction process were analyzed comprehensively. The sensitivity analysis of lateral number, length distribution and intersection angle of multilateral-well system were studied. The results indicate that there is a minimum gas pressure distribution around the multilateral well and the overall permeability of coal seams increases with production time and the permeability around the multilateral well is larger than the area away from the multilateral well which induced by the gas desorb and matrix shrink. The quantity of lateral wells has a positive effect on cumulative production. When the total length of lateral wells is equal, the uniformity and symmetry of lateral length distribution are two key factors on the gas extraction performance. The minimum intersection angle has a positive effect on cumulative production. This study provides a better alternative for traditional drainage hole to obtain greater coalbed methane performance.

Abstract The shale gas reservoir is regarded as a dual medium consisting of fracture (hydraulic fracture and discrete natural fracture network) and rock matrix, the seepage process in the fracture and rock matrix is fully considered and a mathematical model of seepage flow in accordance with Darcy's law was established. The results show the influence order of hydraulic fracture geometry on the cumulative production. Compared with the hydraulic fracture aperture of 10–4 m, when the aperture is 10–5 m and 10–6 m, the cumulative production is reduced by 88.0% and 99.7%, respectively. Compared with the hydraulic fracture length is 100 m, when the length is 200 m and 300 m, the cumulative production is increased by 38.2% and 62.4%, respectively. The increase in the natural fracture aperture increases the fracture permeability, which make it more conducive to gas flow into the fracture, thereby increasing the cumulative production. The increase in the number of natural fractures makes the connectivity of the shale reservoir becomes better and the cumulative production increases more.

Injectability of the polymer solution is a very important factor that determines the effectiveness of polymer flooding for enhanced oil recovery. Here, the medium and low permeability oil reservoir was taken as a research object, and effects of relative molecular weight, concentration and core permeability on the flow and injection performance of a partially hydrolyzed polyacrylamide (HPAM) solution with and without anionic-nonionic surfactant (ANS) were studied by indoor outcrop core physical model experiments. It was found that the influence of HPAM concentration on the flow performance was related to the core permeability. When the core permeability was lower than 59 mD, the resistance factor and residual resistance factor of HPAM increased with increasing the concentration. High molecular weight and low core permeability were not conducive to the injectability of HPAM solutions. The addition of ANS was beneficial in enhancing the injectability of HPAM solution by reducing the critical value of injectability of HPAM solution, which was elucidated by the Hall curve derivative method. In the presence of ANS, the flow pressure gradient and the residual resistance factor of the HPAM solution decreased. It is believed that the injectability of HPAM solution improved by ANS in the medium and low permeability reservoirs can be attributed to decrease in fluid viscosity and competitive adsorption on the surface of porous media. The study provides a new idea and theoretical basis for improving the injectability of an HPAM solution and the application of polymer flooding and a polymer/surfactant binary flooding system in medium and low permeability reservoirs.

Hydraulic fracture initiation and propagation are extremely important on deciding the production capacity and are crucial for oil and gas exploration and development. Based on a self-designed system, multi-perforation cluster-staged fracturing in thick tight sandstone reservoir was simulated in the laboratory. Moreover, the technology of staged fracturing during casing completion was achieved by using a preformed perforated wellbore. Three hydraulic fracturing methods, including single-perforation cluster fracturing, multi-perforation cluster conventional fracturing and multi-perforation cluster staged fracturing, were applied and studied, respectively. The results clearly indicate that the hydraulic fractures resulting from single-perforation cluster fracturing are relatively simple, which is difficult to form fracture network. In contrast, multi-perforation cluster-staged fracturing has more probability to produce complex fractures including major fracture and its branched fractures, especially in heterogeneous samples. Furthermore, the propagation direction of hydraulic fractures tends to change in heterogeneous samples, which is more likely to form a multi-directional hydraulic fracture network. The fracture area is greatly increased when the perforation cluster density increases in multi-perforation cluster conventional fracturing and multi-perforation cluster-staged fracturing. Moreover, higher perforation cluster densities and larger stage numbers are beneficial to hydraulic fracture initiation. The breakdown pressure in homogeneous samples is much higher than that in heterogeneous samples during hydraulic fracturing. In addition, the time of first fracture initiation has the trend that the shorter the initiation time is, the higher the breakdown pressure is. The results of this study provide meaningful suggestions for enhancing the production mechanism of multi-perforation cluster staged fracturing.

A full size perforated casing of 139.7 mm in external diameter was adopted to simulate the horizontal wellbore. The influences of perforation parameters and injection rate on the pressure drop in horizontal wells were investigated by experiments. The results show that: (1) With the increase of perforation density, perforation diameter and perforation phase, both the frictional pressure drop and the total pressure drop increase and the mixture pressure drop decreases. (2) When the mainstream Reynolds number at the perforated casing exit remains constant, with the increase of injection rate, the total pressure drop and mixing pressure drop increase. When the injection rate is less than the critical injection rate (0.05%–0.10% under the study conditions), the mixing pressure drop is less than 0. When the injection rate is greater than the critical injection rate, the mixing pressure drop is greater than 0. The acceleration pressure drop can be neglected when the injection rate is less than 0.10%, otherwise the acceleration pressure drop rises significantly with the increase of injection rate. (3) With the increase of injection rate, the proportion of frictional pressure drop to total pressure drop decreases while that of acceleration pressure drop to total pressure drop increases. When the injection rate is less than 1.00%, the proportion of mixing pressure drop to total pressure drop tends to rise with the increase of injection rate. When the injection rate is greater than 1.00%, the proportion of mixing pressure drop to total pressure drop almost remains unchanged. Key words: horizontal well, perforated completion, wellbore complex flow, pressure drop rule