BackgroundThe exploitation of deep coalbed methane (CBM) is accompanied by continuous pressure drawdown. In this case, scaling and blockage are prone to occur in systems where formation water with high total dissolved solids (TDS) and high-concentration CO2 coexist. In the middle to late production stage, the blockage of both wellbore and flow pathways in reservoirs frequently leads to abrupt declines in gas production and bottomhole pressure or even induces the shutdown of natural flowing production, severely restricting the stable production of deep CBM wells. MethodsThis study investigated the Daning-Jixian block in the eastern Ordos Basin. Using multiple techniques including inductively coupled plasma-optical emission spectrometry (ICP-OES), X-ray diffraction (XRD), and scanning electron microscopy-energy dispersive X-ray spectroscopy (SEM-EDS), this study investigated the ionic composition of the water samples, as well as the mineral composition, microscopic morphologies, and element distributions of the scale samples. Accordingly, the mechanisms behind scaling in deep CBM wells were systematically explored. Furthermore, an effective acidic fluid system was developed based on experimental results, and a novel scheme for blockage removal was designed. ResultsThe scale samples were dominated by calcium carbonate (> 90 wt%), and their precipitation was primarily governed by CO2 solubility. Under a relatively constant temperature in horizontal sections of CBM wells, bottomhole pressure was identified as the dominant factor controlling the precipitation of calcium carbonate scale, while continuous pressure drawdown represented the direct cause. The scaling intensified significantly when CBM wells underwent gradual decline in gas production. Additionally, production parameter analysis and borehole televiewer (TV) monitoring revealed perforation hole blockage by scale in CBM wells and sand accumulation in their horizontal sections.ConclusionsA novel philosophy for blockage removal via acidizing is proposed for deep CBM horizontal wells. This philosophy highlights three shifts: a shift from wellbore to reservoirs regarding the treatment target, a shift from a small-scale to a large-scale acidic fluid consumption, and a shift from blockage removal alone to the integration of blockage removal and sand carrying. A comprehensive acidic fluid system for blockage removal is developed, composed of 15% hydrochloric acid, 1% corrosion inhibitor, 1% iron stabilizer, and 0.3% flowback aid. Experimental results reveal that hydrochloric acid delivered high performance in dissolving scale samples, with the dissolution rates of calcium carbonate scale and MgCaCO3 composite scale determined at 100% and 97.8%, respectively. This acidic fluid system effectively addresses the major challenges associated with efficient scale dissolution, corrosion protection, water blocking removal, and the prevention of secondary precipitation. To address heterogeneous blockage across the horizontal sections of CBM wells, a process integrating sand carrying via nitrogen foam with oil blockage removal through coiled tubing drag acidizing is designed, achieving efficient differential blockage removal. The developed process was applied to five wells (three horizontal and two vertical wells) in the Daning-Jixian block. Consequently, the single-well daily gas production increased by 1−5 times, and some wells exhibited distinct pressure recovery, with natural flowing production restored. The integrated process can be further applied to deep CBM wells with scaling risks in the Daning-Jixian block. The daily gas production is expected to increase by 80×104 m³, accounting for 26% of the total production of mature wells across the block. This establishes the process as an important approach to recreating the natural flowing period and achieving enhanced gas recovery of deep CBM horizontal wells in the block. Based on this process, a low-cost, weak acid-based blockage removal process has been developed through preliminary optimization based on the characteristics of medium-to-shallow CBM reservoirs. The resulting technique of differential blockage removal via acidizing will emerge as an effective countermeasure for production growth and potential tapping of mature wells in unconventional gas reservoirs.
ObjectiveDeep coal seams in the Yichuan block of the Ordos Basin are characterized by small thicknesses, vertical multi-layer superimposition, and strong vertical and horizontal heterogeneities. When used to develop these coal seams, multi-stage horizontal well fracturing faces challenges such as uneven fracture propagation across various stages in the horizontal direction and a low production degree of multiple coal seams in the vertical direction, complicating commercial exploitation. To address these issues, this study proposes a multi-round diverting fracturing technology based on a vertical cluster well group. In this technology, vertical layered fracturing using vertical cluster wells is employed to achieve the commingled exploitation of multiple layers; intra-layer multi-round fracturing facilitates fracture network diversion to form uniform and dense fracture networks, while the well factory pattern of the well group contributes to expanded fracture network coverage, reduced costs, and enhanced efficiency. MethodsThis study investigated the G3-1 well group in the Yichuan block. Using fluid-solid coupling and the iteration of fracture propagation dynamics, multiple parameters, including pore pressure, induced stress, and fracture geometry, were updated in each fracturing round, with the stress field evolution, fracture diversion, and inter-well fracture network propagation patterns during multi-round fracturing being analyzed. Based on this, multiple parameters were optimized, encompassing well and row spacings, fracturing fluid combination, proppant ratio, fracturing sequence, and pump-off time between two adjacent fracturing rounds. Consequently, a reservoir stimulation scheme was developed. This scheme, with the synergistic fracturing of a vertical cluster well group as the core, facilitates uniform inter-well fracture propagation horizontally and enhances the joint production of multiple coal seams vertically. ResultsField application results indicate that after multi-round synergistic fracturing using a diamond-shaped well pattern with a well spacing of 400 m and a row spacing of 200 m, the fracture length and stimulated reservoir volume (SRV) of the No. 8 coal seam increased from 320 m in the first round to 480 m and from 15.0 × 104 m3 to 36.6 × 104 m3, respectively. In contrast, the No. 5 coal seam exhibited an average fracture length of 412 m and an average SRV of 13.9 × 104 m3 in various fracturing rounds. The SRV utilization rate of the G3-1 well group increased from 65% to 89%. Compared to wells subjected to conventional single-round fracturing in adjacent areas, the cumulative gas production of the well group increased by 42%. ConclusionsThe dynamic stress induced by multi-round fracturing can alter the subsequent fracture propagation direction. This promotes the interconnection of fractures created in different fracturing rounds across varying coal seams and wells, thereby enhancing both the coverage of inter-well fracture networks and effective SRV. For deep-seated thin coal seams and strongly heterogeneous blocks, it is advisable to comprehensively determine well pattern deployment, fracturing sequence, and the interval between two fracturing rounds based on the dynamic evolution of in situ stress. Furthermore, subsequent fracturing parameters should be adjusted in time as per the fracture propagation results of previous rounds. These efforts will help transform local reservoir stimulation via a single well into overall synergistic stimulation using a well group. The results of this study will provide a reference for the development of blocks with multiple thin coal seams.
BackgroundInvestigating the adsorption characteristics of coalbed methane (CBM) helps bridge key geological information concerning deep CBM, including occurrence state, free gas proportion, and gas-bearing properties, with the gas production potential and commercial exploitation of CBM wells. Such investigation represents a key component of the evaluation, exploration, and exploitation of CBM reservoirs. MethodsUsing deep coal samples collected from three representative regions, this study designed high-temperature and high-pressure methane isothermal adsorption experiments, together with variable-temperature and variable-pressure methane adsorption experiments, using nuclear magnetic resonance (NMR). The adsorption characteristics of the coal samples derived using the different experimental methods were subsequently compared. Results and Conclusions During high-temperature and high-pressure isothermal adsorption experiments conducted at 30 ℃, 50 ℃, 60 ℃, and 80 ℃, all coal samples exhibited similar bimodal NMR spectra. At a constant temperature, the total gas and adsorbed methane contents of the coal samples varied with pressure according to typical Langmuir curves, whereas the free gas content generally increased linearly with pressure. At the same pressure, the adsorbed, free, and total methane contents in the coal samples were consistently higher at low temperatures than at high temperatures. The experimental results also reveal that the adsorbed methane content was relatively sensitive to variations in pressure. In the variable-temperature and variable-pressure methane adsorption experiments conducted at 20 ℃ and 2.0 MPa, 30 ℃ and 6.0 MPa, 50 ℃ and 12.0 MPa, 60 ℃ and 15.0 MPa, 70 ℃ and 19.0 MPa, and 80 ℃ and 23.0 MPa), the NMR spectra were aligned with those derived from the isothermal adsorption experiments. Specifically, as pressure and temperature increased gradually, the total and adsorbed methane contents of the coal samples increased in accordance with the Langmuir curves, while the free gas content showed a roughly linear growth trend. In both types of experiments, the maximum proportion of free gas emerged at 80 ℃ and 23 MPa. Accordingly, the free gas proportion at a burial depth of approximately 4000 m was estimated to be not greater than 40%, suggesting that deep CBM remains predominantly adsorbed gas and that there are no minimal substantial differences in CBM storage mode between deep and medium-to-shallow coal seams. The total, adsorbed, and free methane contents derived from the variable-temperature and variable-pressure adsorption experiments were consistently higher than those obtained from the isothermal adsorption experiments. However, the results of the isothermal adsorption experiments at the final pressure were very close to those obtained from the variable-temperature and variable-pressure adsorption experiments under corresponding temperature and pressure conditions. Therefore, when conventional isothermal adsorption experiments are employed for a rough analysis of methane adsorption characteristics, the experimental temperature and final pressure are suggested to match the actual reservoir temperature and pressure. In contrast, variable-temperature and variable-pressure adsorption experiments should be used for precise analyses of methane adsorption characteristics and their differences. The results of the variable-temperature and variable-pressure adsorption experiments demonstrate that the methane adsorption rate decreased and even tended to stabilize at approximately 15 MPa, while an inflection point in the free gas content curve also occurred at this pressure. These findings indicate that CBM reservoirs at a burial depth of approximately 1500 m tend to undergo abrupt changes or exhibit unique characteristics. From the perspective of adsorption potential theory, this study elucidated the theoretical basis for identifying the burial depth threshold of deep CBM. Overall, the results of this study provide a significant reference for further understanding the reservoir characteristics, gas-bearing properties, and resource exploitation potential of deep CBM.
BackgroundDeep coalbed methane (CBM) holds an important strategic position in China's unconventional natural gas system. However, concerning deep CBM occurrence, there remains a lack of systematic quantitative understanding of the underlying mechanisms and the controlling effects of pore structure. MethodsThis study investigated high-rank coal samples collected at a burial depth of approximately 2000 m from the No. 8 coal seam in the Daning-Jixian block along the eastern margin of the Ordos Basin. Using multiscale pore characterization techniques, including low-temperature liquid nitrogen adsorption, high-pressure mercury injection, and low-temperature CO2 adsorption, the full-scale pore size distribution of the coal samples was determined. In combination with computed tomography (CT) scanning and gas content measurement through pressure-retaining coring, this study conducted a quantitative analysis of the mechanisms underlying the coexistence of multiphase gas in deep coal reservoirs. Results and Conclusions The deep coal reservoirs in the study area showed a highly heterogeneous pore structure, characterized by a dumbbell-shaped pore volume distribution. Specifically, micropores (<2 nm) and macropores (>50 nm) constituted the primary reservoir spaces, while mesopores were underdeveloped. The specific surface area of pores exhibited a highly concentrated, unimodal distribution pattern, with over 99% attributed to micropores. This finding highlights the dominant role of adsorbed gas in the coal reservoirs. Pore structure is identified as the fundamental factor controlling the binary occurrence pattern of adsorbed and free gas. Micropores store adsorbed methane due to the high potential energy of adsorption, while macropores and partial mesopores provide reservoir spaces and migration pathways for free gas. Consequently, adsorbed and free gas jointly form a stable synergistic equilibrium system under deep high-pressure conditions. Based on the theory of volume filling of micropores (TVFM) and the gas equation of state, a quantitative calculation method for gas content was developed. The calculation results are highly consistent with the measured data, validating the reliability and applicability of the method. The proposed method, grounded in the CBM occurrence mechanisms controlled by pore structure, is primarily affected by the differential pore structure of coal seams. This method enables the theoretical assessment and analysis of gas content in deep coal reservoirs, thereby providing a theoretical basis and technical support for the resource potential assessment, optimal development zone selection, and production system optimization of deep CBM.
Objective and Methods Conventional fracturing struggles to achieve the long-term effective propping of complex fracture networks during the development of deep coalbed methane (CBM) reservoirs. To address this challenge, this study developed a novel ceramic micro-proppant suitable for the volumetric microfracture propping and, through numerical simulations, verified its performance when it was applied to reservoir stimulation in conjunction with the technology of fracturing with three-dimensional full-scale fracture network propping. First, a novel ceramic micro-proppant with a core-shell structure was designed according to the requirements of microfracture propping. Its key properties, including compressive strength, settling behavior, hydraulic conductivity, and stability, were assessed through physical experiments, and its transport behavior and localized dispersed placement patterns in fractures were analyzed using computational fluid dynamics (CFD). Subsequently, MShale discrete fracture network (DFN) models were constructed based on the geological and engineering parameters of a well in the Kubai coalfield located along the northern margin of the Tarim Basin. Using these models, three fracturing schemes, namely conventional fracturing (Case 1), fracturing with micro-proppant placement (Case 2), and fracturing with three-dimensional full-scale fracture network propping (Case 3), were compared in terms of the range of propped fractures and the effective stimulated reservoir volume (ESRV). Results and Conclusions Under a pressure of 60 MPa, the prepared micro-proppant exhibited a crushing rate of 1.84%, which was lower than that of the SiO2 particles used as the raw materials. The 300-mesh-size samples settled to the 100 mL graduation mark after 888 s. Their hydraulic conductivity remained above 40 × 10−3 μm2·cm under high-pressure conditions, with an average permeability of 84.81×10−3 μm2. Transport simulations indicate that as the inlet velocity increased from 0.04 m/s to 0.10 m/s, the average proppant bank heights in the primary and branch fractures increased by 37.6% and 50.4%, respectively. Compared to a branch fracture oriented at 30° relative to the primary fracture, a branch fracture oriented at 90° was more favorable for the entry of micro-proppant particles, resulting in 7%‒9% increases in the micro-proppant volume within the branch fracture. These results demonstrate that the novel ceramic micro-proppant shows excellent transportability in suspension and a strong capacity to maintain high hydraulic conductivity. These characteristics are fundamental to enabling the proppant, transported by fracturing fluids, to enter microfractures and form dispersed propping structures. Under the geological and engineering conditions of the target interval, cases 1, 2, and 3 produced fracture lengths of 275.5 m, 287.3 m, and 328.0 m, respectively. Compared to Case 1, Case 3 increased the ESRV by 50.1%. The simulation results indicate that the synergetic effect of the volumetric microfracture propping by the novel ceramic micro-proppant and channels with high hydraulic conductivity within primary fractures can enhance both the range of propped fractures and the effective connectivity of complex fracture networks. The technology of fracturing with three-dimensional full-scale fracture network propping is particularly applicable to deep CBM reservoirs with high in situ stress and a rapid decline in fractures’ hydraulic conductivity, providing a technical reference for optimizing fracturing schemes for deep, steeply dipping CBM reservoirs. However, the applicability of this fracturing technology to other unconventional reservoirs is yet to be further verified through field tests based on specific geological conditions.
