As a new type of unconventional natural gas resource, the exploration and development of coal-rock gas is of great significance for ensuring China’s energy security. This paper systematically elaborates on the research progress of coal-rock gas geological theories, key technologies, current status of exploration and development, and prospects for its development. The research shows that: ① A consensus has been basically reached in the industry on the connotation of the new type of coal-rock gas. It is clarified that coal rock is a typical dualporosity reservoir, and coal-rock gas reservoirs are characterized by high free gas content, oil-bearing in some reservoirs, and migration and accumulation of coal-rock gas in multi-fractured coal reservoirs. Effective reservoir formation requires good preservation conditions. ② The understanding of coal-rock gas accumulation mechanism and the theoretical framework of the whole petroleum system of coal-measure are taking shape. Based on the particularity of coal dual-porosity reservoirs, the action mechanism of fluid dynamic fields in different media is analyzed, and the understanding of the “three-field control” accumulation mechanism of coal-rock gas is initially formed. Two types of accumulation models, “source-reservoir integration and box-type sealing” and “multi-source co-storage and high-point enrichment”,are established, and the whole petroleum system of coal-measure is initially constructed. ③ In response to the characteristics of coal-rock gas reservoirs, a series of technologies have been initiallyformed, including geological-engineering sweet spot evaluation, experimental testing, horizontal well multi-stage fracturing, productivity evaluation and production optimization. Technologies such as three-dimensional development of multi-layer and multi-gas in coal measures and water-free reservoir reconstruction are actively explored. These technologies have supported the cumulative proven coal-rock gas geological reserves of 596.8×10⁹m³ nationwide, with the 2024 output reaching 2.7×10⁹m³. ④ It is preliminarily estimated that the national coal-rock gas geological resources exceed 30×1012 m3, with the development prospect of achieving an annual output of 30×10⁹ m³ by 2035, which will become a new growth pole of the natural gas industry. The current “three major challenges” in coal-rock gas exploration and development are clarified. It is proposed that future efforts should be made to strengthen theoretical and technological research in six key directions: coal-rock gas accumulation mechanism and construction of whole petroleum system of coal-measure, coal-rock gas selection and sweet spot evaluation technology, fluid seepage mechanism and migration law in coal rock, full-life cycle development optimization of coal-rock gas, coal rock mechanical characteristics and fracture propagation law, and efficient drilling, completion and reservoir reconstruction, so as to promote the high-quality development of the coal-rock gas industry.

Based on the exploration and development practice of Daji deep coal rock gas field, the scientific value and the evolution of strategic position of coal bed (rock) gas are systematically reviewed, the strategic significance of breakthroughs in deep coal rock gas is clarified, and key technological research directions are proposed. The study results indicate that the main theoretical system of coal associated natural gas has gone through three stages of “coal derived gas–shallow coalbed methane–deep coal rock gas”. The breakthrough of deep coal rock gas has established the independent position of coalbed (rock) gas resources and enriched the theoretical system of unconventional natural gas, which has values in four aspects: (1) The exploration depth of coalbed methane has been expanded and the pattern of unconventional resources has been reshaped; (2) The “binary enrichment” mode has been proposed, enriching the theoretical understanding of unconventional oil and gas reservoir accumulation; (3) The core engineering technology system has been constructed such as large-scale volume fracturing, achieving the beneficial development of deep resources; (4) The world’s first deep coal rock gas field has been built, achieving a leading position in coalbed (rock) gas. In the future, it is still necessary to conduct research on sweet spot evaluation and high-efficiency capacity construction, highefficiency drilling and volume fracturing, fine gas production, and intelligent gas gathering and transportation technologies, so as to build a low-cost, intelligent and green development path. The deep coal rock gas has become a new strategic replacement resource of unconventional natural gas in China, which helps to adjust energy structure and achieve the dual carbon strategic goals in China.

Deep coal-rock gas in China generally refers to the combination of free gas and adsorbed gas stored in coal seams deeper than 1500m and with a favorable preservation conditions. It is a type of natural gas resource with condition characteristics similar to shale gas but different from shallow coalbed methane. China shows great potential for deep coal-rock gas resources. An early understanding of its formation conditions and distribution characteristics is crucial for guiding and accelerating the reserve and production growth of deep coal-rock gas.Based on limited exploration well and trial production data, this study proposes that China’s onshore coal-rock gas mainly develops in coal seams formed in tidal flat-lagoons, lakeside swamps, and delta swamps; Micro- to nano-scale pores and cleavage fractures serve as the main storage spaces for coal-rock gas; Deep coal-rock gas accumulates into reservoirs by means of free and adsorbed states, with a relatively high proportion of free gas being an important characteristic that distinguishes it from shallow coalbed methane; Deep coal-rock gas can be divided into two categories based on gas sources: self-generated and self-stored, and externally-sourced and self-stored, with the latter exhibiting a greater proportion of free gas; Effective sealing layers and deep burial depth are essential conditions for the formation of deep coal-rock gas.Furthermore, this study identifies two major types of coal-rock in China: medium- and high-rank coal (R_o ≥ 1.3%) and low- and medium-rank coal (R_o < 1.3%). In medium- and high-rank coal, the enrichment of coal-rock gas benefits from the high gas generation potential, low formation water content, stable structure, well-developed cleats, and effective sealing conditions from the roof and floor. In low- and mediumrank coal, the enrichment of coal-rock gas is attributed to the cumulative enrichment of low gas generation rate, continuous distribution of high-quality coal seams, coupling of structure and gas sources. In addition, natural gas accumulated in adjacent tight sandstone (limestone) is also an important contributor to low- and medium-rank coal-rock gas. China’s deep coal-rock gas resources are abundant, yet exploration remains in its early stages. In the future, deep coal-rock gas production will rise rapidly, and is expected to reach its peak around 2040.

The Permian marine shale is widely distributed in (northeastern) Sichuan Basin, and the high-yield gas flow has been obtained in Well Tiebei 1 L-HF, with a daily gas rate exceeding 30×10⁴ m³ at a depth of greater than 5000 m in the northeastern basin, marking a major breakthrough in the exploration field of the ultra-deep shale gas. Based on the latest exploration results of Well Tiebei 1 L-HF, the regional sedimentary characteristics of the Permian Dalong Formation in the study area has been analyzed, and the geological characteristics of Dalong Formation shale gas has been studied. In addition, main controlling factors for shale gas enrichment and high-yield production in ultra-deep formation has been discussed, clarifying the further exploration orientation of Dalong Formation in the northeastern Sichuan Basin. The comprehensive study and evaluation show that the ultra-deep shale in the Permian Dalong Formation in the northeastern Sichuan Basin has the typical geological characteristics of “one multiplicity, three highs and one medium”, namely the development of multiple shale facies types,high TOC, high gas content, high brittleness and medium porosity. The reservoir space of Dalong Formation ultra-deep shale is dominated by nanoscale organic pores and microfractures, and the coupling distribution of “organic pores + microfractures” significantly enhances physical properties and fracability of ultra-deep shale gas reservoir. The main controlling factors for the enrichment and high-yield production of ultradeep shale gas have been identified, that is, the development of contiguous carbon-rich lithofacies is the foundation, the coupling control of organic pores and microfractures over reservoir is the key, and favorable preservation conditions (ultra-high pressure sealing) are the external manifestation of gas enrichment. By adopting seismic imaging technology for the sub-salt steep structures and reservoir stimulation method of “175 MPa equipment for enhanced net pressure, multi-size grading strong proppants, and high-viscosity/high pumping rate for transverse fracture penetration”, it has achieved an 100% drilling rate of sweet spots and large-scale effective reconstruction of ultra-deep shale gas reservoir. This breakthrough marks that the shale gas exploration in China has stepped into the field of ultra-deep formation. It further confirms that there are abundant shale gas resources in ultra-deep formations in Sichuan Basin, which is an important replacement field for natural gas exploration and development in China.

The Carboniferous–Permian coal measure strata are widely distributed in Ordos Basin. There are abundant deep coal rock gas resources, showing a solid material basis for large-scale capacity construction, so it is crucial to systematically understand the geological characteristics and exploration methods of deep coal rock gas. Based on review of exploration history, and combined with well drilling,logging, and laboratory test data, the coal accumulation environment, coal quality, reservoir physical properties, and gas accumulation conditions of the Upper Paleozoic coal measure strata at the basin scale have been analyzed. By integrating with geological and engineering data from typical wells in recent years, the resource potential, enrichment patterns, and key development technologies have been summarized,and future exploration orientations have been determined. The study results show that: (1) No.8 coal seam in Benxi Formation and No.5 coal seam in Shanxi Formation are the main target layers for deep coal rock gas exploration, which are featured by thick coal seams, consistent distribution, relatively high maturity, high vitrinite content, and high gas generation capacity; (2) The coal rock reservoirs are dominated by primary structure coal, with bimodal pattern of pore structure, well-developed micropores and cleat–fracture system, and high proportion of free gas; (3) Hydrocarbon retention rate is generally high, which is about 40% in the central basin and exceeding 50% in the eastern basin,providing a material basis for gas accumulation; (4) Three types of reservoir and cap rock combinations were formed by coal rocks and the overlying strata, including coal–mudstone, coal–limestone, and coal–sandstone, which effectively controlled the distribution of free gas and formed a favorable hydrocarbon accumulation pattern of “continuous hydrocarbon generation, integration of source rock and reservoir, and box-type sealing”; (5) Based on field practice, a series of key engineering technologies applicable for deep coal rock gas have been developed, including differentiated geosteering, two-section wellbore structure optimization, high-displacement fracturing, and pressure-controlled production, significantly improving the drilling encounter rates, reservoir reconstruction efficiency, and single-well production capacity. The research results support the goal of deep coal rock gas development with “accurate identification, successful drilling, and steady production”, and demonstrate the feasibility and practical value of large-scale capacity construction promoted by integration of geology and engineering.

The Jurassic coal measures in the Junggar basin are well developed and can be used as a good source reservoir series.The CT1H well drilled in the Baijiahai uplift of the basin achieved high-yield gas flow in the coal rock reservoir of the Jurassic Xishanyao formation,breaking the traditional depth exclusion zone for coalbed methane exploration and development of over 2000 meters. It indicates that the deep coal rock gas is expected to become a new type of natural gas resource that can increase reserves and production on a large scale. Based on the exploration results of Jurassic coal rock gas in the Junggar basin, combined with cast thin section, scanning electron microscope, nuclear magnetic resonance and other experimental methods, this paper conducts a systematic study on the geological characteristics and resource potential of deep coal rock gas, and further defines the direction of coal rock gas exploration. According to the research, two sets of main coal rocks, namely, Xishanyao formation②and Badaowan formation⑤, are developed in the the Junggar basin. Xishanyao formation in the hinterland is low rank primary structural coal with an average porosity of 17.25% and poor gas generating capacity. The Xishanyao formation in the southern margin is composed of medium rank coal, with good reservoir pore connectivity and a high proportion of free coal rock gas.The Badaowan formation is a coal with a medium primary structure, with an average reservoir porosity of 3.12% and an adsorbed coal rock gas ratio of 89.75%. The Jurassic deep coal and rock gas in the basin mainly develop three types of reservoir formation models: deep non source structure type, deep self source extensive coverage type, and deep self source structure type. Combined with geological conditions and reservoir control factors, it is considered that the favorable area of various types of deep coal rock gas in the Junggar basin is 2385km² in total, and the predicted coal rock gas resource is 4260×10⁸m³. Xishanyao formation, Badaowan formation in Dinan-Baijiahai area and Xishanyao formation in the southern margin of the basin are favorable exploration directions for coal rock gas in the the Junggar Basin in the future.

The deep coal rocks are widely distributed in Ordos Basin, showing a major replacement field for natural gas exploration and development. However, with the increasing burial depth, the temperature, field stress and hydrogeological conditions of deep formations vary greatly, resulting in great differences in gas accumulation law between deep coal rocks and shallow coal rocks. Regarding the particularity of gas accumulation in deep coal rocks, there are insufficient studies on pore structural characteristics and genesis, gas accumulation types and enrichment characteristics. The experimental analysis on coal rock marcels and scanning electron microscopy have been conducted. The results show that No.8 coal seam in Benxi Formation was mainly deposited in lagoon–tidal flat sedimentary environments, with a thickness of 8–22 m in the northeast and 2–6 m in the southwest, a high vitrinite content of 78.5% on an average, and an increasing maturity from northeast to southwest. The porosity of deep coal reservoir ranges in 3.65%–5.84%. The formation of vesicles was controlled the type of coal swamps, and it was affected by formation water vaporization and rapid hydrocarbon generation of coal rocks. There are multiple types of coal rock gas reservoirs in deep formations, such as microstructural gas reservoir and anticlinal gas reservoir. The gas content of coal rocks increases from northeast to southwest, with a critical point at a depth of about 2000 m. The gas content distribution of coal rocks was affected by coal-forming swamp facies zones. The gas content of coal rocks with a silty mudstone roof is better than those with limestone and sandstone roofs. In addition, it is proposed that a geological evaluation system for deep coal rock gas with the core of pore development, a geophysical prediction technology with the core of pore development zone and gas enrichment zone, and a horizontal well fracturing design and targeted production technology for vesicle developed reservoir should be researched and developed, so as to accelerate the beneficial development of deep coal rock gas.

The deep No.8 coal seam in Daning–Jixian block in the eastern Ordos Basin demonstrates promising exploration potential. However, there is unclear understanding of the distribution characteristics and influence mechanisms on production capacity of the well-developed coal gangues. The high-precision identification and characterization of gangues in No.8 coal seam have been conducted by full-diameter spiral CT scanning for core section from eight wells in the study area, as well as coal rock laboratory data such as proximate analysis, pore structure, and mineral composition. Furthermore, a comprehensive evaluation has been performed on the development characteristics of gangues and their relationship with gas content, reservoir sensitivity, and production capacity. The results indicate that gangues in No.8 coal seam are extensively distributed in Daning–Jixian block, with a thickness proportion of approximately 25.16% in individual wells, a density of about 2.3 layers/m, a single-layer thickness of 0.02–1.57 m (generally <1 m), and the cumulative thickness of 0.20–2.66 m. The gangues are featured by low carbon content, low proportion of micropores, and poor adsorption performance, resulting in weaker gas generation and adsorption capacity compared to coal seams. The average clay mineral content in gangues is 61.61%, dominated by illite/montmorillonite mixed-layer minerals, kaolinite,and illite, which are prone to water and velocity sensitivity, adversely affecting the stability and effectiveness of post-fracturing flow pathways.It shows distinctly negative correlation between gangue content, average thickness, maximum single-layer thickness, and daily gas production.The study concludes that the gangues not only reduce the overall organic content of coal seams but also enhance reservoir heterogeneity and sensitivity, ultimately reducing well production capacity. These findings provide a scientific basis for optimizing hydraulic fracturing design and rational drainage strategy of deep coalbed methane in Daning–Jixian block.

The development of deep coalbed methane using clustered vertical–deviated wells faces several challenges, including unclear productivity-controlling factors and significant variation in single-well production, which constrain the efficient utilization of deep coalbed methane resources in areas with multiple thin coal seams. To enhance single-well production, this study investigated 105 clustered vertical–deviated wells in the Daning–Jixian Block and systematically identified the key factors controlling productivity. Through single-factor analysis,11 geological and engineering parameters influencing productivity were clarified, among which resource abundance and reservoir fracability served as the geological foundation for high productivity. Multiple linear regression and a decision tree model were subsequently applied to identify four engineering-dominant factors: total proppant volume, fracturing pressure, shut-in duration, and post-fracturing assisted fluid flowback volume. Based on this, a high-productivity development pathway was established following the strategy of “deploy optimally–stimulate effectively –mitigate damage – boost efficiency.” An efficient development technology system was developed, centered on integratedgeological–engineering sweet spot identification, large-scale volume fracturing, rapid post-fracturing flowback, and multi-source energy synergy for enhanced drainage and pressure drawdown. This was supported by engineering organization strategies such as early-stage artificial lift deployment, staged surface facility construction, and multi-process coordinated execution, forming a full-lifecycle development model for clustered vertical–deviated wells. Field tests conducted on 9 wells in the Yichuan area demonstrated the effectiveness of this technology system, with average daily gas production per well increasing from 0.8×10⁴ m³ to 1.8×10⁴ m³, and EUR reaching 2000×10⁴ m³. Reservoir pressure drawdown efficiency was improved significantly, and stable production capacity was notably enhanced. The results provide systematic technical support for efficient development of deep CBM in Yichuan and offer a reference path and practical basis for large-scale application of the technology in similar blocks.

In recent years, major breakthroughs have been achieved in deep coalbed methane (CBM) development. However, gas production varies significantly among deep CBM wells across various blocks and even in various well areas in the same block. One of the reasons lies in the differences in dynamic permeability changes of deep coal reservoirs in different blocks, while the permeability stress sensitivity and velocity sensitivity properties remain unclear. The full-diameter coal core plugs taken from deep formations in Linxing-Shenfu block have been used to conduct porosity–permeability measurements, stress sensitivity experiments, and velocity sensitivity experiments, obtaining permeabilities under different effective stresses and flow velocities. Based on the measured stress sensitivity data, the applicability of exponential, power-law, and logarithmic stress sensitivity models has been compared and evaluated, which enables to select the optimal permeability stress sensitivity model and establish a new standard for stress sensitivity evaluation. Additionally, the measured velocity sensitivity data has been applied to determine the parameters of permeability velocity sensitivity model, revealing the deep coal permeability velocity sensitivity property in Linxing-Shenfu block. The study results indicate that: (1) The deep coal seams in Linxing-Shenfu block exhibit typical characteristics of low porosity and low permeability, with the porosity range of 3.9%–9.1% (average of 6.5%) and gas permeability under low pressure of 0.9–2.1 mD (average of 1.63 mD). (2) The dynamic permeability changes with pressure follow an exponential trend,with the stress sensitivity index of 0.33–0.52 MPa-1. Based on the new stress sensitivity evaluation criteria (which classify stress sensitivity into six levels—none, weak, moderately weak, moderately strong, strong, and extremely strong using stress sensitivity boundaries of 0.01 MPa^-1, 0.08 MPa^-1, 0.15 MPa^-1, 0.23 MPa^-1, and 0.45 MPa^-1), the stress sensitivity degree of deep coal seams is classified as strong or extremely strong, so special consideration should be given to stress sensitivity effects in the process of optimization design of production regimes. (3) As the fluid flow rate increases, permeability decreases sharply initially and then declines slowly. The fitted critical plugging velocity (v_cr2) ranges in 0.01– 0.11 m/d, the maximum damage degree (D_v,max) is 0.81–0.96, and the damage rate index (n) is 0.40–1.05. Furthermore, the lower the original coal permeability, the lower the critical plugging velocity, the higher the maximum damage degree, and the smaller the damage rate index. The research findings provide a theoretical basis for production capacity evaluation and production regime design of deep CBM wells.

There are abundant coal rock resources in Benxi Formation coal seam No.8 in Ordos Basin, which is a realistic replacement field for increasing unconventional gas reserves and production in China. Compared with shallow coalbed methane, deep coal rock gas has the characteristics of “tight matrix, high proportion of isolated pores, well developed cleavages and fissures, coexistence of free gas and adsorbed gas”. Therefore, the large-scale fracturing is an effective means to reduce free gas flow resistance and promote the desorption of adsorbed gas in deep coal rocks. The experiments such as triaxial mechanical compression, in-situ stress test and large physical simulation on fracture propagation have been conducted, which have identified the well-developed cleavages, mechanical properties of low Young’s modulus, high Poisson’s ratio, large longitudinal stress difference of coal rock No.8, and fracture propagation characteristics given the fracturing modes of high displacement low viscosity and low displacement high viscosity. By applying multi-parameter geology–engineering sweet spot identification method and multi-stage and multi-cluster differentiated fine fracture layout technology, the economic and large-scale fracturing technology has been formed with the core of “multi-stage and few clusters, alternating fluid injection, and combined sand addition”. The key points of the technology include: (1) Few clusters in one stage to concentrate energy at the fracture opening and initiate cleavages and fissures; (2) Alternating injection of high and low viscosity fluids to expand fracture propagation zone and increase the fracture complexity; (3) Combined sand addition to increase flow capacity, so as to achieve the effective support of multi-scale fractures. The technology has been applied to 19 wells, with an initial daily gas rate of 4.9×10⁴ m³/d, showing good gas production test results, which has provided important technical support for beneficial development of deep coal rock gas.