Search

Shale oil development in the Yanchang Oilfield is characterized by rapid production decline and low productivity, and supplementing the energy requirements and enhancing the recovery of oil are major challenges for shale reservoir development. In this study, physical simulations of cyclic water flooding, CO2immiscible huff and puff, CO2miscible huff and puff, and gas–water alternate drive processes were conducted on Chang 7 shale reservoir samples from the Yanchang Oilfield. The mechanism behind micro-displacement was analyzed by online NMR detection technologies, which showed that the displacement should be kept above the minimum miscible pressure during CO2huff and puff. Furthermore, our analyses showed the highest recovery rate was that of water–gas alternate flooding is due to its higher utilization of small pores. Overall, CO2–water alternating flooding or CO2miscible huff and puff is recommended to obtain higher recovery rates, based on our results. Considering the economic benefits and construction conditions, cyclic water flooding can be used first and then converted to other modes. This study can provide theoretical support for different ways of supplementing energy and provides scientific guidance for gas injection pilot test in similar reservoirs.

One challenge to the effective development of coalbed methane and shale gas is the complexity of their migration mechanism and production characteristics. Recognizing this, our study has devised an indoor experimental simulation system for production characteristics of coalbed methane or shale gas with a consideration of the effect of adsorbed gas. Firstly, we carried out a theoretically-informed quantitative identification of adsorbed gas, pore-confined gas, and free gas in the production process. Then, the theory was combined with experiments to quantitatively evaluate the production rates of these gases in different occurrence states and their contribution to the yield. This paper presents an application of this new method to coal-seam samples from the Da Ningji County Block. Our research suggests that during the extraction process, a higher gas production rate would lead to a higher pressure in the eventually abandoned formation, and ultimately a lower recovery rate. Specific findings include, firstly, that before extraction, the proportion of adsorbed gas in the samples is 80%, which then gradually increases during the extraction process, eventually reaching 90% at the end of production, with an average contribution of 70% to yield. Secondly, a greater contribution of adsorbed gas to production leads to a higher ultimate recovery rate. Thirdly, the desorption rate shows an upward trend in the stable production phase, gradually decreasing during the depletion production period, but the rate of decrease slows down as the development progresses. Fourthly, a higher desorption rate in the later stage of extraction is positively correlated with a higher ultimate recovery rate. Lastly, the contribution of pore-confined gas and free gas to production exceeds 70% in the early stage before gradually declining as extraction progresses, and no relationship of significance has been found between the production rate and recovery rate in the later stage. It is hoped that our study can provide theoretical underpinning for the optimization of coalbed methane and shale gas development.

Determination of the lower limit of flowing porosity for oil recovery from tight oil reservoirs is the key to promoting scientific and economic development of tight oil reservoirs. This study performed a comprehensive analysis based on pore-throat radius distribution measurements, low-temperature nitrogen adsorption measurements, and centrifugation and nuclear magnetic resonance measurements to establish a method for calculating the bound water film thickness and, in turn, the lower limits of pore-throat radius and permeability. The method was applied on rock samples from typical tight oil reservoirs in the Daqing and Changqing oil regions in China. The results indicated that for a given reservoir, bound water film thickness tends to be constant. With decreasing permeability, bound water film thickness showed an L-shaped distribution curve due to the changes in the pore-throat structure and the impact of molecular forces. The flat segment of the distribution curve corresponded to the lower limit of pore-throat radius, while the curve inflection point corresponded to the lower limit of permeability. The pore-throat radius and permeability limits were 22 nm and 0.08 mD for the Daqing tight oil reservoir and 18 nm and 0.03 mD for the Changqing tight oil reservoir, respectively.

Complex fracture systems including natural fractures and hydraulic fractures exist in shale gas reservoir with fractured horizontal well development. The flow of shale gas is a multi-scale flow process from microscopic nanometer pores to macroscopic large fractures. Due to the complexity of seepage mechanism and fracture parameters, it is difficult to realize fine numerical simulation for fractured horizontal wells in shale gas reservoirs. Mechanisms of adsorption–desorption on the surface of shale pores, slippage and Knudsen diffusion in the nanometer pores, Darcy and non-Darcy seepage in the matrix block and fractures are considered comprehensively in this paper. Through fine description of the complex fracture systems after horizontal well fracturing in shale gas reservoir, the problems of conventional corner point grids which are inflexible, directional, difficult to geometrically discretize arbitrarily oriented fractures are overcome. Discrete fracture network model based on unstructured perpendicular bisection grids is built in the numerical simulation. The results indicate that the discrete fracture network model can accurately describe fracture parameters including length, azimuth and density, and that the influences of fracture parameters on development effect of fractured horizontal well can be finely simulated. Cumulative production rate of shale gas is positively related to fracture half-length, fracture segments and fracture conductivity. When total fracture length is constant, fracturing effect is better if single fracture half-length or penetration ratio is relatively large and fracturing segments are moderate. Research results provide theoretical support for optimal design of fractured horizontal well in shale gas reservoir.

Hydrocarbon gas flooding/Huff-n-Puff (HNP) can improve the oil recovery in the unconventional reservoirs. Here, the mechanisms accounting for fluid flow in the low-permeability and ultra-low permeability reservoirs were experimentally and theoretically investigated. Core plugs collected from a typical China oilfield were utilized for the experiments. Additionally, methane was used as the injection agent to conduct natural gas HNP/displacement experiments. The results indicated that the use of natural gas as an energy supplement agent and the HNP development method can effectively improve the recovery efficiency of the aforementioned two types of reservoirs. During the HNP process, the oil recovery is effectively enhanced mainly in the first round and second round. Meanwhile, during gas injection and HNP, natural gas can evidently weaken the extraction and reduce the precipitation of heavy components. However, the natural gas injection can establish an effective driving pressure system in low-permeability core plugs, and the interaction between natural gas and oil can change the mobility ratio. Furthermore, it aids in avoiding viscous fingering and premature breakthroughs. Moreover, the oil can be sandwiched between the interface of the gas and water phases to form a slip channel in a hydrophilic core sample, which can quickly produce oil. Finally, a numerical model was developed by considering the reservoir parameters of Changqing Oilfield, China. The oil recovery after eight rounds of CH4 HNP was 80% higher than that achieved via depletion development. Additionally, the oil recovery curves are especially similar in the previous three HNP rounds. These curves show obvious differences from the fourth round onwards, which indicates that the asphaltene deposition and CH4 diffusion slightly affect the oil recovery factor during the initial production period.

Because of a large amount of natural gas dissolved in the formation water of high-temperature and high-pressure (HTHP) water-soluble gas reservoirs, the water vapor content in water-soluble gas reservoirs is generally maintained under a supersaturated state; meanwhile, natural gas has a high carbon dioxide fraction, which significantly affects the water vapor content. Application of the conventional method to calculate the water content of HTHP water-soluble gas reservoirs leads to errors. In this work, the water content of HTHP water-soluble gas reservoirs was studied through laboratory experiments and theoretical research, and the main factors affecting water content were studied. Results show that the water content of water-soluble gas reservoirs decreases as pressure increases. The water content decreases faster in the low-pressure stage, while the decease of water content in the high-pressure stage is relatively steady. The water content of gas reservoirs increases with increasing temperature. When the temperature is lower than 100 °C, the change is slow; when the temperature is higher than 100 °C, the change is fast. The water content of gas reservoirs is affected by temperature during the low-pressure stage. The water content in the high-temperature stage is obviously affected by pressure; the water content of the gas reservoir is also affected by the carbon dioxide content of the natural gas component and the salinity of the formation water. Higher carbon dioxide content and lower formation water salinity yield higher water content. Furthermore, error analysis of the conventional water content prediction method and the measurement shows inconsistency in measurement and calculation. The error between the two methods is large, with an average of 54.88%. Based on the experiment, a mathematical model for calculating the water content of HTHP water-soluble gas reservoirs was established considering pressure, temperature, salinity, and natural gas composition. The predicted water vapor content of natural gas is close to the experimental value with a high precision. The average relative error between the measured and model calculated value is about 8.72%.

The water invasion property and water drive gas displacement efficiency of water drive gas reservoirs are studied under different displacement pressure gradients by using nuclear magnetic resonance (NMR) online detection technology to better guide the scientific exploration of these reservoirs. The breakthrough pressures of the water seal and water lock are also analyzed. The results show that low-permeability gas reservoir water bodies pass through large pores preferentially and then pass through holes and small pores. The remaining gas is mainly distributed in holes and small pores. In contrast, high-permeability gas reservoir water bodies pass through large pores and holes preferentially, and the remaining gas is mainly distributed in large pores and small pores. As the permeability increases, the water drive gas displacement efficiency decreases. As the displacement pressure gradient increases, the displacement efficiency initially increases and then decreases. The breakthrough pressures of the water seal and water lock are highly affected by the permeability. Large permeability results in easy water breakthrough. Variations in the water invasion and water drive gas displacement efficiency are consistent with the variations of the breakthrough pressure and accurately reflect the properties of water drive gas reservoirs.

To study the flow mechanism under different displacement modes of low permeability carbonate reservoir in the Middle East and to improve the utilization of various types of reservoirs, the physical simulation experiments of water flooding by different displacement methods were carried out. Selecting two types of rock samples with different permeability levels, two-layer coinjection and separated production experiments by samples I and III and conventional water flooding experiments by samples II and IV were carried out. In addition, by using low magnetic field nuclear magnetic resonance, the development effect of microscopic pore structure under the different injection-production models was analyzed. Results show that, compared with the coinjection, the recovery rate of sample I was higher than II, 19.30%; sample III was lower than IV, 23.22%; and the comprehensive recovery degree reduced by 3.92%. NMR data also show that the crude oil is mainly distributed in the large pore throat; after water flooding, the displacement is also within the large pore throat, whereas the small pore throat is mainly obtained by the effect of infiltration absorption. The above studies provide a laboratory basis and foundation for the further development of low permeability carbonate reservoir in different Middle East strata.