Coal-rock gas is a new type of unconventional natural gas resource. In recent years, strategic breakthrough has been achieved,
which has great significance for ensuring energy security in China. The research progress in geological theories, key technologies, and current status of exploration and development of coal-rock gas are systematically discussed, and the development prospects are put forward based on resource potential analysis results. The study results show that: (1) A consensus has basically been reached in the industry on the connotation of coal-rock gas. The coal rock shows a typical dual-pore media reservoir. Coal-rock gas is composed of complex gas components and high content of free gas, which has characteristics of migration and accumulation, and good preservation conditions are required for the formation of effective gas reservoir. (2) The understanding of coal-rock gas accumulation mechanism and the theoretical framework of whole petroleum system of coal measures have primarily been established, forming a “three-field controlling” coal-rock gas accumulation mechanism, and two types of gas accumulation and enrichment models, i.e., “integration of source rock and reservoir, and box-type sealing” and “multi-source supply, and gas enrichment in reservoir at high structural parts”. (3) A series of technologies have initially been developed, such as coa-rock gas resource assessment, geological and engineering sweet spot evaluation, laboratory testing, horizontal well multi-stage fracturing, production capacity evaluation, and production optimization. In addition, technologies such as water-reducing/water-free reservoir reconstruction and stereoscopic development of multi-layer and multi-source gas in coal measures are actively being researched. These technologies have supported the cumulative proven coa-rock gas geological reserves of 5968×10⁸ m³ , and the output reaching 27×10⁸ m³ in 2024. (4) It is preliminarily estimated that the coal-rock gas geological resources exceed 38×10¹² m³, possessing the resource foundation for
achieving an annual output of 300×10⁸ m³ by 2035, which shows a new growth point in the natural gas industry. (5) Three major challenges in coal-rock gas exploration and development are pointed out, and six key theoretical and technological research directions are proposed to promote the high-quality development of coal-rock gas industry in the future.

Based on the exploration and development practice of Daji deep coal rock gas field, the scientific value and the evolution of strategic position of coalbed methane are systematically reviewed, the strategic significance of breakthroughs in deep coalbed methane 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 coalbed methane”. The breakthrough of deep coalbed methane has established the independent position of coalbed methane 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 coalbed methane field has been built, achieving a leading position in coalbed methane. In the future, it is still necessary to conduct research on sweet spot evaluation and high-efficiency capacity construction, high-efficiency 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 coalbed methane 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 deep coal seams (greater than 1500 m) with favorable preservation conditions, which has similar hydrocarbon accumulation conditions to shale gas but different from shallow CBM. There are abundant deep coal-rock gas resources in China. An early understanding of its accumulation conditions and distribution characteristics is crucial for guiding and accelerating the reserve and production growth of deep coal-rock gas. Based on the study of recent exploration wells and trial production data, it is proposed that China’s onshore coal-rock gas was mainly developed in coal seams deposited in tidal flat–lagoon, lake shore swamp, and delta swamp environments, with the main storage space of micro- to nano-scale pores, cleavages and fissures. Deep coal-rock gas accumulated in reservoirs in both free and adsorbed states, with a relatively high proportion of free gas, indicating a major characteristic that distinguishes it from shallow CBM. Based on gas sources, deep coal-rock gas is classified into two types, i.e., selfgeneration and self-storage, and external-source and coal-storage, and the latter has a higher proportion of free gas content. The effective cap rocks and large burial depth are essential conditions for the formation of deep coal-rock gas reservoirs. Furthermore, two types of coal-rock gas reservoirs are classified in China, namely, medium- to high-rank coal (R_o≥1.3%) and low- to medium-rank coal (R_o<1.3%). The enrichment of coal-rock gas in medium- to high-rank coal benefits from the high gas generation potential, low formation water content, relatively stable structure, well-developed cleavages and fissures, and effective sealing conditions of main coal roof and floor. The enrichment of coal-rock gas in low- and medium-rank coal profits from the cumulative enrichment with low gas generation rate, continuous distribution of high-quality coal seams, coupling control of structure and gas sources. In addition, natural gas accumulated in adjacent tight sandstone (limestone) is also an important contributor to the low- and medium-rank coal-rock gas. China has abundant deep coal-rock gas resources, but the exploration remains in its early stage. It is expected that deep coal-rock gas production will increase rapidly in the future and 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 were well developed in Junggar Basin, which served as both good source rock and reservoir. A Well
CT1H was drilled in Baijiahai Bulge, and high-yield gas flow was obtained in the Jurassic Xishanyao Formation coal rock reservoir, breaking through the traditional depth forbidden zone for CBM exploration and development at a depth greater than 2000 m, which indicated a new type of natural gas resource for increasing reserves and production on a large scale. Based on the exploration results of the Jurassic coal-rock gas in Junggar Basin, and combined with experimental methods such as casting thin section, scanning electron microscope, and nuclear magnetic resonance, a systematic study has been conducted on the geological characteristics and hydrocarbon accumulation pattern of deep coal-rock gas, and the future exploration orientation has been clarified. The study results show that two sets of main coal rocks, namely, coal rock No.2 in Xishanyao Formation and coal rock No.5 in Badaowan Formation, were developed in Junggar Basin. Xishanyao Formation coal rocks in the basin hinterland are characterized by low rank and primary structure, an average porosity of 17.25%, and poor gas generation capacity, while those in the southern basin margin are composed of medium-rank coal, with good connectivity of pores and a high proportion of free gas. Badaowan Formation coal rocks are characterized by medium rank and primary structure, with an average reservoir porosity of 3.12% and a proportion of adsorption gas of 89.75%. There are three main types of hydrocarbon accumulation patterns of the Jurassic deep coal-rock gas in the basin, i.e., allogenetic structural type, authigenic stratigraphic type, and authigenic structural type. The comprehensive study of geological conditions and gas accumulation control factors indicates that the favorable exploration area of deep coal-rock gas is 2385 km², and the predicted coal-rock gas resources are 4260×10⁸ m³ in Junggar Basin. The future exploration orientation of coal-rock gas includes Xishanyao Formation and Badaowan Formation in Dinan–Baijiahai area in the hinterland basin and Xishanyao Formation in the southern margin of the basin.

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 coal-rock gas using clustered vertical–deviated wells faces challenges such as unclear controlling factors
for production capacity, and significant differences in single-well production, which restrict the high-efficiency utilization of deep coal-rock gas resources in areas with multi-set thin coal rocks developed. In order to enhance the single-well production, a total of 105 clustered vertical–deviated wells in Daning–Jixian block has been studied to systematically identify the controlling factors for production capacity. Through single-factor analysis, law of production capacity control of 11 geological and engineering parameters has been clarified, among which resource abundance and reservoir fracability are the geological foundation for high-yield production. Furthermore, multivariate linear regression analysis and decision tree model have been combined to identify four engineering controlling factors, i.e., total sand volume, construction pressure, well shut-in period, and post-fracturing assisted fluid flowback volume. On this basis, a cultivation pathway for high-yield wells has been established following the strategy of “deployment optimization–intense reservoir reconstruction–damage control–efficiency enhancement”, and the high-efficiency well development technology system has been developed, centered on collaborative geological and engineering sweet spot zone selection, large-scale volume fracturing and reservoir reconstruction, post-fracturing rapid flowback for filtration control, and multi-source energy coupling assisted drainage and pressure release. In addition, the supporting engineering organization strategies have been proposed, including advanced artificial lifting operation, staged surface engineering construction, and multi-process coordinated execution, forming a lifecycle high-efficiency development mode for clustered vertical–deviated wells. This technology system has been applied to Yichuan well area, obtaining significant achievements, with the average single-well gas rate increased from 0.8×10⁴ m³/d to 1.8×10⁴ m³/d, EUR reaching up to 2000×10⁴ m³, significantly improved reservoir pressure release efficiency, and constantly enhanced steady production capacity. The study results provide systematic technical support for the high-efficiency development of deep rock gas in Yichuan well area and offer a reference path and practical basis for large-scale application of the technology system 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 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.