High Production Wells Research Articles

Characteristics and Sources of CBM Well-Produced Water in the Shouyang Block, China

The Shouyang Block was selected as the research subject. Comprehensive analysis was conducted using coalbed methane (CBM) well production data, geochemical test data on water produced from the coalbed methane well, and fundamental geological information. The findings reveal the water dynamics in the Shouyang Block are characterized by weak groundwater runoff or retention in most areas. The groundwater head height exhibits a gradual decrease from the north to south, which is closely associated with the monoclinic structure of the Shouyang Block. Overall, water production is relatively high. As the average water production increases, the average gas production gradually decreases. A concentration of high water production wells is observed in the northern part of the Shouyang Block, which gradually increases towards the southeast direction. A comprehensive analysis was conducted on the factors influencing water production, including total water content of coal seams, coal seam porosity, groundwater stability index, groundwater sealing coefficient, D value of the fracture fractal dimension, fault fractal dimension, and sand–mud ratio. The correlation degree was calculated and ranked in order of magnitude through grey correlation analysis. The order of factors that influence water production, from strongest to weakest, is as follows: sand–mud ratio > porosity > fractal dimension of fault > fracture fractal dimension D value > groundwater sealing coefficient > groundwater stability index > total water content of coal seams. The dissolution amounts of carbonate and sulfate are both small, and the water source may mainly come from the sandstone aquifer. Attention should be paid to the distribution and lithological combination of sandstone aquifers in coal-bearing strata in the future exploration and development process of the Shouyang Block. This will help to avoid the potential influence of fault structures and enable the identification of favorable areas for low water and high gas production.

Application of Machine Learning for Productivity Prediction in Tight Gas Reservoirs

Accurate well productivity prediction plays a significant role in formulating reservoir development plans. However, traditional well productivity prediction methods lack accuracy in tight gas reservoirs; therefore, this paper quantitatively evaluates the correlations between absolute open flow and the critical parameters for Linxing tight gas reservoirs through statistical analysis. Dominant control factors are obtained by considering reservoir engineering theories, and a novel machine learning-based well productivity prediction method is proposed for tight gas reservoirs. The adaptability of the productivity prediction model is assessed through machine learning and field data analysis. Combined with the typical decline curve analysis, the estimated ultimate recovery (EUR) of a single well in the tight gas reservoir is forecasted in an appropriate range. The results of the study include 10 parameters (such as gas saturation) identified as the dominant controlling factors for well productivity and geological factors that impact the productivity in this area compared to fracturing parameters. According to the prediction results of the three models, the R2 of Support Vector Regression (SVR), Back Propagation (BP), and Random Forest (RF) models are 0.72, 0.87, and 0.91, respectively. The results indicate that RF has a more accurate prediction. In addition, the RF model is more suitable for medium and high-production wells based on the actual field data. Based on this model, it is verified that the productivity of low-producing wells is affected by water production. This study confirms the model’s reliability and application value by predicting recoverable reserves for a single well.

Controls of strike-slip faults on condensate gas accumulation and enrichment in the Ordovician carbonate reservoirs of the central Tarim Basin, NW China

Uplifiting of the central Tarim Basin has attracted great interests since the discovery of a major condensed natural gas field in Ordovician carbonate successions at a depth of > 6000 m. The formation of the large-scale hydrocarbon reservoirs in reef shoals is typically thought to be influenced by paragenetic accumulation in the karstified reservoirs. However, because of the rapid decline of natural gas/petroleum production and the complex fluid distribution in limestone reservoirs, it is difficult to clarify the controlling factors of hydrocarbon enrichment. We integrate core, seismic, well logging and production data to illustrate the relationship hydrocarbon enrichment and fault system in this paper. First, productive wells are closely associated with major strike-slip fault zones. Second, most productive blocks are distributed in a banded or block-like manner within strike-slip fault sections. Third, strike-slip fault systems do not closely control reservoir quality; however, the enrichment of natural gas is linked to the development of strike-slip fault systems. Finally, all high-productivity wells are distributed around structural highs in major strike-slip fault zones. These lines of evidence suggest that the accumulation and enrichment of hydrocarbons were closely related to strike-slip fault zones rather than kastified reservoirs. Based on this, four models for the accumulation of hydrocarbons were proposed: fault uplift, graben periphery, fault intersection and fault–karst coupling. Large-scale strike-slip fault zones, transtensional segments and local structural highs were the main factors found to be controlling hydrocarbon enrichment and high productivity. Therefore, these three conditions improved the reservoir and provided paths and places for hydrocarbon migration and accumulation. These proposed hydrocarbon accumulation models contribute to a better understanding of these fault systems and further petroleum exploration.

Evaluation of Reconstruction Potential for Low-Production Vertical Wells of CBM in the Southern Qinshui Basin

Production practice has shown that not all low-production coalbed methane (CBM) wells can be reconstructed into high-production wells through secondary stimulation, so it is necessary and timely to establish an evaluation index system, form an evaluation method, and evaluate the reconstruction potential of low-production wells. Based on the development practice of CBM in the southern Qinshui Basin, this paper analyzes the influencing factors of low production in vertical wells from the aspects of coal and rock reservoir conditions, drilling and completion engineering, and drainage engineering. It is proposed that the evaluation of the reconstruction potential of low-production wells should focus on the quality of CBM resources, the difficulty of CBM desorption and diffusion, and the degree of damage to coal reservoirs caused by the initial reservoir stimulation. Twelve parameters, including gas content, gas saturation, reservoir pressure gradient, critical desorption–reservoir pressure ratio, and permeability, were systematically selected as evaluation indicators, and the grading reference values for each evaluation indicator were comparatively given. Then, a multi-factor comprehensive evaluation method for the reconstruction potential of low-production wells based on gray correlation analysis method was established. The reconstruction potential of low-production wells was divided into three levels: high, medium, and low. When reconstructing low-production wells, it is recommended to prioritize the low-production wells with high reconstruction potential, followed by those with medium reconstruction potential, while low-production wells with low reconstruction potential are not recommended for reconstruction. Finally, the evaluation method was used to evaluate the reconstruction potential of five low-production wells in a CBM block, and suggestions for the reconstruction order and reconstruction potential levels for each well were given.

Assessment of Groundwater Potential Zone using Multi-criteria Decision-making Technique: A Case Study in the South-western Part of Yadadri Bhuvanagiri District, Telangana, India

Abstract Groundwater which occurs beneath the earth’s surface is an important natural resource. The study area, part of Yadadri Bhuvanagiri district, Telangana, which is a part of Musi river basin, is a hard rock terrain covering an area of 1107 sq km, part of the eastern Dharwar craton (EDC) of the southern India peninsular shield. Exploration of groundwater in this terrain is difficult because groundwater is confined to weathered and fractured layers. The present study aims to delineate groundwater potential zones using the multi-criteria decision analysis (MCDA) technique. An integrated application of remote sensing and GIS is very effective in mapping features that provide information about groundwater potential zones using several thematic layers such as geology, soil, geomorphology, slope, lineament density, drainage density, rainfall, and land use/land cover maps. The groundwater potential zones of the study area are classified into five categories, namely very high, high, medium, low, and very low and they occupied an area of 116.8, 381.29, 345.15, 149.70, and 115.42 km2 respectively. The results were validated using discharge data from existing wells in the study area, and the majority of the high-productivity wells are located in very high and high groundwater potential zones. The groundwater potential zone mapping using this model will be a very useful improving the groundwater resources of the study area.

The Strike-Slip Fault Effects on Tight Ordovician Reef-Shoal Reservoirs in the Central Tarim Basin (NW China)

The largest carbonate condensate field in China has been found in the central Tarim Basin. Ordovician carbonate reservoirs are generally attributed to reef-shoal microfacies along a platform margin. However, recent production success has been achieved along the NE-trending strike-slip fault zones that intersect at the platform margin. For this contribution, we analyzed the strike-slip fault effects on the reef-shoal reservoirs by using new geological, geophysical, and production data. Seismic data shows that some NE-trending strike-slip faults intersected the NW-trending platform margin in multiple segments. The research indicated that the development of strike-slip faults has affected prepositional landforms and the subsequent segmentation of varied microfacies along the platform margin. In addition, the strike-slip fault compartmentalized the reef-shoal reservoirs into multiple segments along the extent of the platform margin. We show that fractured reef-shoal complexes are favorable for the development of dissolution porosity along strike-slip fault damage zones. In the tight matrix reservoirs (porosity < 6%, permeability < 0.5 mD), the porosity and permeability could be increased by more than 2–5 times and to 1–2 orders of magnitude in the fault damage zone, respectively. This suggests that high production wells are correlated with “sweet spots” of fractured reservoirs along the strike-slip fault damage zones, and that the fractured reservoirs in the proximity of strike-slip fault activity might be a major target for commercial exploitation of the deep Ordovician tight carbonates.

Modeling of two-phase flow of high temperature geothermal production wells in the Yangbajing geothermal field, Tibet

Two-phase flow (flow of water in both liquid and gas phase, containing a non-condensable gas such as CO2) in the wellbore is one of the most important processes in the production performance and wellbore scaling evaluations of high temperature geothermal wells. This paper first describes the discharge tests in the Yangbajing geothermal field, Tibet. Next, a simple model for governing the two-phase flow in the presence of CO2 in the wellbore is constructed and a robust calculation method is presented. The model is applied to three production wells in the Yangbajing geothermal field. The results show that the velocity difference between the gas and liquid phase should be included in the model. Ignoring this difference (i.e., homogeneous model) would result in a significant deviation between measurements and calculations. A drift flux model (DFM) describes the velocity difference, where the specifics of the particular model can have significant effects on the results for the pressure and temperature profiles in the wellbore. Three commonly used DFMs are compared to estimate their performance. The calculated wellhead pressure and temperature are in the range of 2,3 bar and 125°C–135°C for all three wells at a production rate of about 20 kg/s. The estimated wellhead gas mass fraction is between 3% and 8%. Considering CO2 content, three different scenarios were evaluated, although the effect on the pressure and temperature profiles were limited. However, CO2 content has a much more significant effect on the flash depth, which is an important parameter for the estimation of calcite scaling.

Heat Accumulation Mechanism of the Gaoyang Carbonatite Geothermal Field, Hebei Province, North China

From 2019 to 2021, we constructed two high-productivity geothermal wells with wellhead temperatures of 109.2 and 123.4°C in the Gaoyang geothermal field. Based on the two wells, it was proved that Gaoyang is a medium-temperature carbonate geothermal field with great development potential. The article reported the latest exploration achievements of deep buried hill geothermal resources in the geothermal field. The productivity of D34 and D35 geothermal wells were evaluated by James end-pressure method: the total flow of steam–water mixture was 234.59–331.92 (t/h), the dryness was 1.36–2.03%, and the single-well power generation potential was 2.10–2.55 MW. Combined with those results, the heat control factors and heat accumulation mechanism of the deep carbonatite geothermal field were confirmed. The westward subduction of the Pacific plate caused obvious damage to the eastern North China Craton and greatly reduced the thickness of the lithosphere and crust. This process facilitated the conduction of mantle-derived heat to shallow crust. Deep strike-slip faults (e.g., Maxi fault) cut through the lithosphere, leading the deep mantle-derived heat and magma to migrate into the crust. The heat accumulated from the depression with low thermal conductivity to the uplift with high thermal conductivity. Groundwater was heated up by deep cycle and convection along faults. The catchment of regional karst groundwater also had a certain effect on the heat accumulation. The Gaoyang geothermal field was formed by these factors.

Solid Phase Deposition Pattern Concerning Formation Oil in YD 7 Reservoir of Tarim Oilfield and Its Application: A Case Study

Yudong (YD) 7 reservoir in the Yingmaili area of Tarim Oilfield is one of the key areas of oil and gas exploration in the Tarim Basin. However, due to the serious plugging problem caused by solid phase precipitation particles such as wax and paraffin, it is necessary to study the well flow phase behavior and solid phase precipitation law of typical high-production wells in this block to obtain the phase enveloping line and provide theoretical support for preventing solid phase precipitation of formation crude oil. In this study, the PVT tester and the self-designed microscopic solid deposition tester are used to obtain the phase enveloping line of formation crude oil, and the change law of the “gas–liquid–solid” phase behavior when the formation crude oil changes with temperature and pressure is observed. The morphological process of solid precipitation is recorded and analyzed through a microscopic visualization window. Finally, the solid phase precipitation point of formation crude oil is verified using a laser solid phase deposition tester. The experimental results show that under atmospheric pressure, the solid phase precipitation temperature point of surface crude oil is 34.05 °C, the maximum instantaneous precipitation is 0.01178%, and the maximum cumulative precipitation is 8.34%. The solid phase precipitation point of formation crude oil changes under different temperatures and pressures. Under different pressures and temperatures, it shows multiphase changes such as liquid–solid, liquid phase, gas–liquid–solid, gas–liquid, and gas phases. Limited by equipment, we can only observe the first four phase behaviors in the laboratory. In the process of solid phase precipitation, formation crude oil shows a fine needle shape at the initial stage and finally adhesions and aggregations in the form of an increasing crystal nucleus as the center, thus blocking the formation or wellbore. Combined with the analysis of production data, it can be seen that there is a solid precipitation problem in well YD 702 over 1200 m in the wellbore and the solid phase precipitation problem from the wellbore to the surface pipeline. This study provides theoretical support for preventing solid phase precipitation in the YD 7 reservoir and provides a reference for other oil fields with solid phase precipitation blocking problems.

A treatment protocol for controlling gas oil ratio in heterogeneous carbonate reservoirs by foam injection: Case study simulation

In this study, foam is selected to treat production wells of heterogeneous reservoirs that are suffering from high amounts of gas oil ratio (GOR). To this end, a numerical study is carried out by injecting foam through the perforations that produce high amounts of gas to block the gas path and allow much more oil to be simultaneously produced from the remaining perforations by applying a new technology in well completion. For this purpose, three heterogeneous synthetic base sectors are simulated in which large amounts of injected gas are produced from the upper, middle and lower perforations of the producing well, known as gas overriding, gas channeling-midriding and gas channeling-underriding, respectively. Since Kv/Kh is an important, decisive and effective parameter, different values of it have been considered for each of three base sector models including 0.001, 0.01, 0.1, 0.3, 0.5, 0.7, 0.9 and 1.0. Then, depending on the magnitude of Kv/Kh, the most optimal treatment method is sensitivity analyzed. In the following, foam injection parameters, e.g. surfactant concentration, depth of packer set, foam injection sequence and foam injection rate are sensitivity analyzed. Also, the phenomenon of gas cross-flow during the treatment process is investigated. The simulation results show that if after some time following well treatment, the GOR level increased, it is suggested to take a production test to determine what length of the production well below the packer produces lots of gas to set the packer at the lower depth and inject a larger volume of foam to block that gas path so that the GOR is reduced. The results also conclude that the magnitude of Kv/Kh on one hand and the location of gas entry to the production well on the other hand play a key role in the selection of the best treatment scenario in heterogeneous reservoirs. This has led to presenting a protocol for treatment of high GOR production wells in a wide range of reservoirs based on anisotropy ratios. Finally, in order to validate the protocol, a real specific sector of a heterogeneous carbonate reservoir located in the Middle East, in which the GOR level has increased, is simulated and treated. The results indicate that the protocol is efficient and causes a reduction in GOR by 60%. • A comprehensive treatment protocol for high GOR production wells is presented. • The effect of different anisotropy ratios is investigated. • A new method of foam injection/oil production is used at the simulation scale.

Study of Well Pattern Optimization Techniques in High Dip Angle Fault Block Reservoir

The study area is a narrow complex fault block reservoir, which is characterized by large strata dip, large reservoir thickness and strong interlayer heterogeneity. At the initial stage of development, a set of stratigraphic series is adopted for development. At present, there are problems of unbalanced utilization between layers and rapid rise of water cut. In order to meet the needs of overseas oilfields to improve the oil production rate during the development period, this paper analyses the geological and development affecting factors of high productivity wells through the study of fine reservoir geological body, the quantitative characterization and distribution of remaining oil. Moreover, the optimization of the development pattern of small well spacing is studied. Through changing the development mode, adjusting the well pattern layer series, and deploying a set of well pattern in the fault area and enrichment area with remaining oil inter well in three dimensions to develop the oil layers with poor production of old wells, stereoscopic potential tapping can be attained. The method of layer by layer upward development is adopted, and the production is carried out in batches vertically, so as to reduce the contradiction between layers and increase the degree of reserve production, improve the oil production rate and recovery degree during the development period of the oilfield finally.

Fracture characteristics and logging identification of lacustrine shale in the Jiyang Depression, Bohai Bay Basin, Eastern China

Fracture has a vital effect on the storage and seepage ability of oil and gas in shale reservoirs, and its effective identification and evaluation is of great significance for shale oil and gas development. To analyze and evaluate fracture development characteristics in the lower sub-member of the third member of the Eocene Shahejie Formation (Es3L) and the upper sub-member of the fourth member of the Eocene Shahejie Formation (Es4U) in the Jiyang Depression, Bohai Bay Basin, core observations, thin sections, field emission scanning electron microscopy (FE-SEM), and well logging were performed. After data analysis, fracture types in the study area were characterized, relationships between shale oil types and shale oil production were discussed, and a new method was proposed to identify fractures using only conventional logging curves by combining discrete wavelet transform (DWT) and box fractal dimension with sliding window approach (SW box fractal dimension). Our results indicated that the fracture types according to geologic genesis are structural fractures (structural tension fractures, structural shear fractures, and structural tension-shear fractures), non-structural fractures (abnormal pressure fractures, diagenetic contraction fractures, bedding fractures, and dissolution fractures), and organic matter-related fractures. A close relationship occurs involving the types of shale oil and shale oil production, and fractured shale oil usually has the highest initial production. The fracture identification method using the DWT and SW box fractal dimension has good effects, and its accuracy is verified by Fullbore Formation MicroImager (FMI) logging in L69 well. Two high-production wells of shale oil in the study area (wells FY1 and Y187) were used to identify fracture development sections using the DWT and SW box fractal dimension, and excellent application results were obtained. In general, it is an efficient way to fully evaluate fracture development sections in shale reservoirs in logging profiles, and also provides new ideas for the fracture identification method using conventional logging curves in other shale oil regions.

Design and Implementation of the Array Logging Tool on Horizontal Production Logging

The measuring instruments have some errors in the measurement of high water cut production wells, and many domestic oil fields are also in high water cut state. The measured data from the conventional production logging instrument are all almost inaccurate. This project has designed a staggered probe array flow meter well logging apparatus based on the characteristic of electromagnetic wave specific retention meter that can fully cover the wellbore fluid and improve flow measurement accuracy. According to the application in horizontal wells, the accuracy of this measuring instrument now has been proved to be more than 90% and can meet the requirements of production logging interpretation in horizontal wells.

Gas detecting of the Lower Permian dolomite reservoirs in Sichuan Basin using amplitude ratio attribute of PP-wave to PS-wave

At present, multi-wave multi-component seismic exploration has a good effect in the gas-bearing structural imaging improvement, fracture detection, clastic rock lithology description, reservoir monitoring, etc., but in gas detection, especially for the deep carbonate reservoir, there are not many successful cases. The paper takes the 5000m deep Lower Permian Qixia Formation dolomite gas reservoir in the central part of Sichuan Basin as the research target. Aiming at the differences in gas production characteristics of different wells and difficulty in gas detection, based on the high-precision matched 3D multi-wave seismic data by seismic processing and fine horizon interpretation of target formation, the differences between the PP- and PS-wave reflection amplitudes of high-production wells, low-production wells and poor gas wells are compared and analyzed, and multi-wave forward modelling and analysis are carried out. It is clear that the high production gas layer has the characteristics of strong PP-wave reflection and weaker PS-wave reflection. With the gas production decreasing from high to low, the reflection amplitude of PP gradually weakens, while that of PS change little and nearly have no obvious abnormalities. Finally, attribute of amplitude ratio of PP to PS were extracted for gas detection, which is in good agreement with the gas characteristics of the known wells and consistent with current geological understanding. The amplitude ratio attribute of PP to PS could provide a quick and reliable gas detection method for the deep dolomite reservoir.

Case Study: Effect of Natural Fracture on Stimulation Strategy in Keshen Tight Gas

Aimed at problems of poor fracturing effects of fracture-network acid fracturing in three wells in the Keshen 5 block, a fractured and tight gas reservoir in Tarim Oilfield, the mechanical activity of natural fractures was studied. The fractures in this block were divided into three types: fully-filled, semi-filled, and unfilled. The analysis of the correlations showed that the correlation of the number of fully-filled fractures and absolute open flows (AOF) is poor, while the correlation between the number of unfilled and semi-filled fractures and AOF is the best. Core samples with different types of fractures were tested using conventional triaxial compression methods, and the experimental results showed that the friction coefficient of the fully-filled fracture is close to that of semi-filled fracture, while the cohesion of fully-filled natural fractures is close to that of intact rocks, which is much greater than that of semi-filled fractures. The effective stress test results shows that the effective stress coefficient of fully-filled natural fracture rock samples is lower than that of semi-filled fractures. Using Mohr–Coulomb theory to calculate the natural fracture mechanics of high-production wells and low-production wells, the results show that low-production wells are mainly fully-filled fractures, most of which are not activated, so the production is low; while high-production wells are semi-filled and unfilled fractures, most of which can be activated, so the production is high. Based on this, for a well dominated by fully-filled fractures, it is recommended to use conventional gel fracturing to replace the fracture-network acid fracturing process. The stimulation practice of two wells has proven the validity of this strategy. The filling degree of natural fractures affects the increasing production and choice of stimulation process. This may be a relatively new understanding and may provide insights to stimulation strategy decisions for other fractured tight reservoirs in the world.

Geological characteristics and high production control factors of shale gas reservoirs in Silurian Longmaxi Formation, southern Sichuan Basin, SW China

Abstract Marine shale gas resources have great potential in the south of the Sichuan Basin in China. At present, the high-quality shale gas resources at depth of 2000–3500 m are under effective development, and strategic breakthroughs have been made in deeper shale gas resources at depth of 3500–4500 m. To promote the effective production of shale gas in this area, this study examines key factors controlling high shale gas production and presents the next exploration direction in the southern Sichuan Basin based on summarizing the geological understandings from the Lower Silurian Longmaxi Formation shale gas exploration combined with the latest results of geological evaluation. The results show that: (1) The relative sea depth in marine shelf sedimentary environment controls the development and distribution of reservoirs. In the relatively deep water area in deep-water shelf, grade-I reservoirs with a larger continuous thickness develop. The relative depth of sea in marine shelf sedimentary environment can be determined by redox conditions. The research shows that the uranium to thorium mass ratio greater than 1.25 indicates relatively deep water in anoxic reduction environment, and the uranium to thorium mass ratio of 0.75–1.25 indicates semi-deep water in weak reduction and weak oxidation environment, and the uranium to thorium mass ratio less than 0.75 indicates relatively shallow water in strong oxidation environment. (2) The propped fractures in shale reservoirs subject to fracturing treatment are generally 10–12 m high, if grade-I reservoirs are more than 10 m in continuous thickness, then all the propped section would be high-quality reserves; in this case, the longer the continuous thickness of penetrated grade-I reservoirs, the higher the production will be. (3) The shale gas reservoirs at 3500–4500 m depth in southern Sichuan are characterized by high formation pressure, high pressure coefficient, well preserved pores, good pore structure and high proportion of free gas, making them the most favorable new field for shale gas exploration; and the pressure coefficient greater than 1.2 is a necessary condition for shale gas wells to obtain high production. (4) High production wells in the deep shale gas reservoirs are those in areas where Long11– Long13 sub-beds are more than 10 m thick, with 1500 m long horizontal section, grade-I reservoirs penetration rate of over 90%, and fractured by dense cutting + high intensity sand injection + large displacement + large liquid volume. (5) The relatively deep-water area in the deep-water shelf and the area at depth of 3500–4500 m well overlap in the southern Sichuan, and the overlapping area is the most favorable shale gas exploration and development zones in the southern Sichuan in the future. With advancement in theory and technology, annual shale gas production in the southern Sichuan is expected to reach 450×108 m3.

Research on the Production Decline Law of Junlian Coalbed Methane Development Test Well

Considering the production decline law of coal-bed methane wells, production decline can be divided into three types: exponential decline, hyperbolic decline, and harmonic decline. Research on the production decline law is very important for evaluation of CBM productivity. In this paper we have studied the law of production decline in Junlian region and established the production decline type for low, medium, and high production wells. The paper also describes the dynamic reserves calculation and recovery evaluation methods and steps using FAST-CBM coal-bed methane reservoir analysis system software.

Biogeochemistry and the associated redox signature of co-produced water from coalbed methane wells in the Shizhuangnan block in the southern Qinshui Basin, China

To meet the global energy demands, the exploitation of coalbed methane has received increasing attention. Biogeochemical parameters of co-produced water from coalbed methane wells were performed in the No. 3 coal seam in the Shizhuangnan block of the southern Qinshui Basin (China). These biogeochemical parameters were firstly utilized to assess coal reservoir environments and corresponding coalbed methane production. A high level of Na+ and HCO3– and deuterium drift were found to be accompanied by high gas production rates, but these parameters are unreliable to some extent. Dissolved inorganic carbon (DIC) isotopes δ13CDIC from water can be used to distinguish the environmental redox conditions. Positive δ13CDIC values within a reasonable range suggest reductive conditions suitable for methanogen metabolism and were accompanied by high gas production rates. SO42–, NO3– and related isotopes affected by various bacteria corresponding to various redox conditions are considered effective parameters to identify redox states and gas production rates. Importantly, the combination of δ13CDIC and SO42– can be used to evaluate gas production rates and predict potentially beneficial areas. The wells with moderate δ13CDIC and negligible SO42– represent appropriate reductive conditions, as observed in most high and intermediate production wells. Furthermore, the wells with highest δ13CDIC and negligible SO42– exhibit low production rates, as the most reductive environments were too strict to extend pressure drop funnels.

Hydrogeological control and productivity modes of coalbed methane commingled production in multi-seam areas: A case study of the Bide–Santang Basin, western Guizhou, South China

Coalbed methane (CBM) commingled production is an important measure to increase the CBM productivity in multi-seam areas. However, multiple superimposed CBM systems are widely developed in multi-seam areas and the difference in the hydrogeological conditions between CBM systems significantly influences the CBM commingled production. In this study, the Bide–Santang Basin in South China was used as an example and hydrogeological data analysis, production data analysis, and rock and coal sample tests were used to investigate variable hydrogeological conditions of superimposed CBM systems and their implications for the CBM production. The hydrogeochemical closed index (HCI) is proposed based on the ion compositions of the groundwater in the coal-bearing strata, which is a new parameter that can be used for the quantitative discrimination and description of superimposed CBM systems based on the determination of the groundwater environment. The hydrodynamics of the upper CBM system are stronger at a lower HCI value, and thus susceptible to shallow groundwater interference during the CBM production. The predicted daily water production based on the unit water inflow of the pumping test boreholes is generally lower than 1 m3/(d · m) when the median depth of the coal seam group exceeds 150 m. When the daily water production per unit drawdown (DWPPUD) of the producing fluid level in the CBM well is less than 1 m3/(d · m), high CBM production can be achieved in the well due to the absence of shallow groundwater interference in the Zhucang Syncline. Finally, three productivity modes of CBM commingled production wells in the Bide–Santang Basin were discriminated: shallow groundwater interference wells, high production wells, and fracturing fluid-contaminated wells. Numerical simulation shows that upper CBM system limits the production of middle and lower CBM systems. Suggestions are made for the CBM development in the Bide–Santang Basin based on the variable hydrogeological conditions and in situ stress of the superimposed CBM systems.

Shale pore structure characteristics of the high and low productivity wells, Jiaoshiba shale gas field, Sichuan Basin, China: Dominated by lithofacies or preservation condition?

Abstract Both the characteristics of lithofacies and tectonic movements are important factors in controlling the development, destruction, and preservation of pores in shale reservoirs. However, the main factors that control the structure of shale pores are complex and highly disputed, restricting the understanding of the mechanisms that lead to the accumulation of shale gas. In this study, mineral composition and geochemical analyses, high resolution field emission scanning electron microscopy (FE-SEM), and low-pressure gas adsorption (N2 and CO2) were conducted to evaluate the pore systems of different types shale in the Jiaoshiba area, Sichuan Basin. A total of three shale groups, including silica-rich high production shales, clay-rich low production shales, and silica-rich low production shales were identified on the basis of lithofacies and gas-bearing characteristics. The highest values of TOC, pore volume, and specific surface area are found in the silica-rich high production shales, with an average of 4.182%, 33.04 × 10−3 cm3/g, and 38.71 m2/g, respectively. The total pore volume and specific surface area in the clay-rich low production shales are 19.85% and 28.62% lower than that of silica-rich high production shales. This suggests that the types of lithofacies have a more prominent influence on the specific surface area of the shales, while the pore volume plays a smaller role. However, the pressure in silica-rich low production shales is often released due to strong tectonic deformation. The OM pores in the silica-rich low production shales therefore tend to be both compressed and closed, with low surface porosity and of round shape. The total pore volume and specific surface area of silica-rich low production shales are 34.63% and 22.0% lower than that of the silica-rich high production shales. This indicates that tectonic movement has a significant influence on the shale pore volume, while specific surface area has a smaller influence.