Acidification oxidation reagent system optimization on coal seams and stimulation effect evaluation

China has abundant coalbed methane (CBM) resources, and most of them are low-permeability and tight reservoirs, with generally low production rate and small recovery factor. Existing technologies face great challenges to meet the demand on CBM in China. It is desirable to develop new methods to improve the production rate and enhance recovery factor. In addition to physical stimulation methods such as hydraulic fracturing and open-hole cave completion, the use of chemical methods to improve physical properties of coal reservoirs has also been a hot research topic in recent years. Coal reservoir acidification and oxidation technology can promote desorption of gas and enlarge permeability of reservoir. But for different coal rank coal reservoirs, the acidification and oxidation agents need to be optimized and their performance evaluated. Laboratory experiments are conducted to compare and analyze the physical properties coal samples from Baode, Mu’ai, and Xinjiang blocks, including coal rank, texture, macroscopic characteristics, quality, porosity, permeability, element, and mineral composition. The optimal concentration of hydrochloric acid is determined through pre-dissolution experiment of coal powder in acid solution. Then a five-factor and three-level orthogonal experiment for acid solution optimization is designed and performed by using Design-Expert software, which identifies the sensitive factors affecting the dissolution. For the coal samples in Baode, Mu’ai, and Xinjiang blocks, the oxidant types and the corresponding acidification and oxidation agent systems are optimized. Applying these acidification and oxidation agent systems to coal samples from Baode, Mu’ai, and Xinjiang blocks, the change of porosity, permeability, and wettability are compared and analyzed. Finally, through numerical simulation, the gas production is predicted for acidification and oxidation in typical well group in Block Mu’ai. Results show that the acid solution has the best dissolution at a concentration of hydrochloric acid of 3 mol/L to 4 mol/L; Top factors played in the experiment are soaking time, acid type, soaking temperature, coal sample type, and acid concentration, in descending order of importance; The optimal oxidant is a hydrogen peroxide solution with a concentration of 3%; the mixed acidification oxidant formula in Baode block is 10% HCl + 2% CH3COOH + 2% HF + 3% H2O2; The optimal mixed acidification oxidant formula in Mu’ai block is 8% HCl + 2% CH3COOH + 4% HF + 3% H2O2; the optimal mixed acidification oxidant formula in Xinjiang block is 12% HCl + 1% CH3COOH + 1% HF + 3% H2O2; The higher the coal rank, the greater the HF content in the optimal acidification oxidant system. Both acidification and oxidation improve the porosity and permeability of coal samples to some extent, and the improvement in low-rank coal is more significant than that in high-rank coal. Acidification and oxidation have different effects on the wettability of coal: Acidification increases the hydrophilicity of coal, whereas oxidation reduce the hydrophilicity of coal; and the hydrophilicity of coal samples treated by the optimized acidification and oxidation system is weakened. Reservoir simulation results show that acidification and oxidation lead to a recovery factor of 64.64% after 10 years of production, which is 19.72% higher than that without acidification and oxidation. The advantage of acidification and oxidation is 0.97% after 18 years of production. However, the acidification and oxidation saved 8 years of production time to achieve a close final recovery factor, which greatly reduces the operating costs. The optimized acidizing oxidation agent systems for CBM reservoirs with low, medium, and high ranks improved the desorption and permeability of the target reservoirs, and increase well production and recovery factor. This research provides technical support for stimulation practices of CBM reservoirs in the aforementioned blocks in China, as well as similar coal reservoirs in the world

Reconsideration of the Adsorption/Desorption Characteristics with the Influences of Water in Unconventional Gas Systems

The exploration and development of unconventional resources have been of growing interest in the industry in recent years. It is widely known that the adsorption and desorption mechanisms of unconventional gas have great significance for gas accumulation and exploration. However, major researches based on the mechanism of solid-gas interface have failed to reveal it completely, which introduce large discrepancies between actual and predicted production. In this paper, the mechanism of solid-liquid-gas adsorption and desorption interface is enlightened to describe the characteristics of unconventional gas. The validity of the proposal was verified preliminarily by building a conceptual model which redefines the gas-water distribution. Furthermore, the possibility of production of gas trapped in micropores was first investigated. The findings of this study can help for better understanding of the adsorption, desorption, and production mechanisms and in unconventional gas system. Accordingly, the explanation of variation between experiment result and actual production rate even with physical parameters was reasonable in theory. Therefore, this work should provide a basis for improving the accuracy of production predictions in actual reservoirs and should assist analysts in determining reasonable unconventional gas target

Transport mechanism of desorbed gas in coalbed methane reservoirs

The gas-liquid two-phase flow and mass transfer principle shows that the diffusion caused by concentration difference only happens in a single-phase fluid; gas-liquid two-phase diffluent solution happens in the way of dissolution; and gas-liquid two-phase insoluble or semi- soluble solution flows under differential pressure driving. These facts demonstrate that the transport of desorbed gas through matrix pores is the flow, and it doesn't conform to Fick law. The dissolution, diffusion, nucleation and bubble processes of desorbed gas through depressurization are studied, and the nonlinear flow model of free gas from matrix pores to the cleat and fracture system is established based on force analyses of the gas bubble and the gas column. Research shows that a small amount of desorbed gas diffuses by dissolution; most of them becomes nucleation and bubble, and then flows to the coal cleat and fracture system under the pressure difference driving; considering the existence of the pressure difference between the matrix pores and cleats, the pressure in coal matrix will reduce more slowly, the investigated radius will be shorter, and the outflow lag phenomenon of desorbed gas will appear. The dynamic reserve should be calculated not by using cleat pressure but by the pressure in coal matrix. The mechanism of enhanced methane recovery by CO2 injection is not only replacement but displacement. Improved methane recovery can be obtained by optimizing the production pressure difference, it is not reasonable that the lower formation pressure gives higher methane recovery. Key words: coalbed methane, diffusion, desorption, percolation, developmen

An abnormality of productivity indicative curves of multi-layer gas wells: Reason analysis and correction method

An abnormality tends to occur in the productivity indicative curves in the process of productivity test interpretation of multi-layer gas wells, resulting in the failure of solutions to their productivity equations and absolute open flow rates. To figure out the reasons for such an abnormality, we established a full-hole calculation model considering the coupling of wellbore variable mass flows and reservoir seepages to calculate a gas production profile and wellbore pressure distribution of a multi-layer productive gas reservoir. Then, based on the analysis of the gas production profile and wellbore pressure distribution characteristics of gas wells at different gas production rates, the root cause for the abnormality in the productivity indicative curves of multi-layer gas wells was analyzed, and a corresponding correction method was proposed and validated based on some examples. And the following research results were obtained. First, there are two reasons for the abnormal productivity indicative curves of multi-layer gas wells. On the one hand, there is a variable mass pipe flow in the wellbore of multi-layer sections and a flowing pressure gradient decreases with the increase of well depth. And the flowing pressure in the middle of the reservoir which is converted based on the flowing pressure gradient above the pressure gauge is higher than the real value. On the other hand, the pressure in the multi-layer producing sections doesn't realize a balance after well shutdown for a short time, so the measured static pressure is greater than the one measured when the pressure of each layer gets balanced after well shutdown for a long time. Second, the flowing pressure obtained from the productivity test interpretation of multi-layer gas producer shall be converted based on the pressure measured by the pressure gauge within 200 m above the reservoir top and it is necessary to adopt the static pressure measured after the balance of wellbore pressure. Third, the reliability of the model, the rationality of the abnormality reason analysis and the validity of the correction method are verified based on calculation examples and cases. It is concluded that the research results provide a technical support for the productivity evaluation of multi-layer gas wells. Keywords: Multi-layer gas reservoir, Commingling, Productivity test, Indicative curve, Variable mass flow, Abnormality correction, Flowing pressure, Static pressur

Simulation of Water Influx and Gasified Gas Transport during Underground Coal Gasification with Controlled Retracting Injection Point Technology

Underground coal gasification (UCG) may change the energy consumption structure from coal-dominated to gas-dominated in the years to come. Before that, three important problems need to be solved, including failure of gasification due to large amounts of water pouring into the gasifier, environmental pollution caused by gas migration to the surface, and low calorific value caused by poor control of the degree of gasification. In this study, a geological model is first established using the computer modeling group (CMG), a commercial software package for reservoir simulation. Then, the inflow of coal seam water into the gasifier during the controlled retracting injection point (CRIP) gasification process is simulated based on the geological model, and the maximum instantaneous water inflow is simulated too. Meanwhile, the migration of gasified gas is also simulated, and the migration discipline of different gases is shown. Finally, the pressure distributions in two stages are presented, pointing out the dynamic pressure characteristics during the UCG process. The results show that (a) the cavity width, production pressure, and gasifier pressure are negatively correlated with the maximum instantaneous water inflow, while the initial formation pressure, injection pressure, coal seam floor aquifer energy, and temperature are positively correlated; (b) CO2 is mainly concentrated near the production well and largely does not migrate upward, O2 migrates upward slowly, while CH4, CO and H2 migrate relatively quickly. When the injection–production pressure difference is 2 MPa, it takes 33.5 years, 40 years, and 44.6 years for CH4, CO, and H2 to migrate from a depth of 1000 m to 200 m, respectively. When the pressure difference increases to 4 MPa, the gas migration rate increases about two-fold. The aquifer (3 MPa) above a coal outcrop can slow down the upward migration rate of gas by 0.03 m/day; (c) the pressure near the production well changes more significantly than the pressure near the injection well. The overall gasifier pressure rises with gasifier width increases, and the pressure distribution always presents an asymmetric unimodal distribution during the receding process of the gas injection point. The simulation work can provide a theoretical basis for the operation parameters design and monitoring of the well deployment, ensuring the safety and reliability of on-site gasification

Simulation of Water Influx and Gasified Gas Transport during Underground Coal Gasification with Controlled Retracting Injection Point Technology

Underground coal gasification (UCG) may change the energy consumption structure from coal-dominated to gas-dominated in the years to come. Before that, three important problems need to be solved, including failure of gasification due to large amounts of water pouring into the gasifier, environmental pollution caused by gas migration to the surface, and low calorific value caused by poor control of the degree of gasification. In this study, a geological model is first established using the computer modeling group (CMG), a commercial software package for reservoir simulation. Then, the inflow of coal seam water into the gasifier during the controlled retracting injection point (CRIP) gasification process is simulated based on the geological model, and the maximum instantaneous water inflow is simulated too. Meanwhile, the migration of gasified gas is also simulated, and the migration discipline of different gases is shown. Finally, the pressure distributions in two stages are presented, pointing out the dynamic pressure characteristics during the UCG process. The results show that (a) the cavity width, production pressure, and gasifier pressure are negatively correlated with the maximum instantaneous water inflow, while the initial formation pressure, injection pressure, coal seam floor aquifer energy, and temperature are positively correlated; (b) CO2 is mainly concentrated near the production well and largely does not migrate upward, O2 migrates upward slowly, while CH4, CO and H2 migrate relatively quickly. When the injection–production pressure difference is 2 MPa, it takes 33.5 years, 40 years, and 44.6 years for CH4, CO, and H2 to migrate from a depth of 1000 m to 200 m, respectively. When the pressure difference increases to 4 MPa, the gas migration rate increases about two-fold. The aquifer (3 MPa) above a coal outcrop can slow down the upward migration rate of gas by 0.03 m/day; (c) the pressure near the production well changes more significantly than the pressure near the injection well. The overall gasifier pressure rises with gasifier width increases, and the pressure distribution always presents an asymmetric unimodal distribution during the receding process of the gas injection point. The simulation work can provide a theoretical basis for the operation parameters design and monitoring of the well deployment, ensuring the safety and reliability of on-site gasification

Proppant transport in rough fractures of unconventional oil and gas reservoirs

A method to generate fractures with rough surfaces was proposed according to the fractal interpolation theory. Considering the particle-particle, particle-wall and particle-fluid interactions, a proppant-fracturing fluid two-phase flow model based on computational fluid dynamics (CFD)-discrete element method (DEM) coupling was established. The simulation results were verified with relevant experimental data. It was proved that the model can match transport and accumulation of proppants in rough fractures well. Several cases of numerical simulations were carried out. Compared with proppant transport in smooth flat fractures, bulge on the rough fracture wall affects transport and settlement of proppants significantly in proppant transportation in rough fractures. The higher the roughness of fracture, the faster the settlement of proppant particles near the fracture inlet, the shorter the horizontal transport distance, and the more likely to accumulate near the fracture inlet to form a sand plugging in a short time. Fracture wall roughness could control the migration path of fracturing fluid to a certain degree and change the path of proppant filling in the fracture. On the one hand, the rough wall bulge raises the proppant transport path and the proppants flow out of the fracture, reducing the proppant sweep area. On the other hand, the sand-carrying fluid is prone to change flow direction near the contact point of bulge, thus expanding the proppant sweep area