Abstract
Coalbed methane (CBM) development faces many challenges, among which in situ stress and permeability are two of the most important and fundamental factors. Knowledge of the characteristics of these factors is crucial to CBM exploration and development. Based on measured injection/falloff and in situ stress well test data of 55 CBM wells in the eastern margin of the Ordos Basin, correlations between parameters including initial reservoir pressure, in situ stress, lateral stress coefficient, well test permeability, and burial depth were determined. The distribution of in situ stress was analyzed systematically and its influence on permeability was also addressed. The results indicate that the maximum horizontal principal stress (σ H 10.13–37.84 MPa, average 22.50 MPa), minimum horizontal principal stress (σ h 6.98–26.88 MPa, average 15.04 MPa) and vertical stress (σ v 12.30–35.72 MPa, average 22.48 MPa) all have positive correlations with coal burial depth. Stress ratios (σ H/σ h, σ H/σ v, and σ h/σ v) and lateral stress coefficient slowly attenuated with depth. With increase of horizontal principal stresses, coal reservoir permeability (0.01–3.33 mD, average 0.65 mD) decreases. The permeability variation is basically consistent with change of stress state at a certain burial depth, the essence of which is the deformation and destruction of coal pore structures under the action of stresses. Three types of stress fields exist in the area: in the shallow coal seam at burial depths <700 m, the horizontal principal stress is dominant, revealing a strike slip regime (σ H > σ v > σ h), with average permeability 0.89 mD; from 700 to 1000 m depths, there is a stress transition zone (σ H ≈ σ v > σ h) with average permeability 0.73 mD; in the deep coal seam with burial depths >1000 m, the vertical principal stress is dominant, demonstrating a normal stress regime (σ v > σ H > σ h) with average permeability 0.11 mD.
Similar content being viewed by others
Avoid common mistakes on your manuscript.
1 Introduction
Coal seams are naturally fractured reservoirs with coalbed methane (CBM) consisting of matrix blocks, where most gas is adsorbed onto coal inner surfaces. A network of cleats, usually saturated with water in an in situ state, provide the major flow paths for gas and water in the coal seams (Clarkson and McGovern 2005; Pan and Connell 2012; Chen et al. 2014; Zhao et al. 2014). The magnitude and orientation of in situ stress can substantially influence coal deformation and destruction (including both cleat and matrix), and with increase of that stress, its role becomes more prominent (Ryan 2003; Bell 2006; Liu et al. 2014). Clearly, in situ stress measurement in the downhole is indispensable for coal and CBM development (Iannacchione et al. 2007; Karacan et al. 2008; Gentzis 2009, 2011a, b; Chatterjee and Pal 2010; Meng et al. 2010; Liu 2011; Talebi et al. 2014).
In situ stress is a type of internal stress in the earth crust, and its formation is closely related to various dynamic actions during historical geologic periods, including gravitational and tectonic stresses (Cai et al. 2010; Kang et al. 2009, 2010). The gravitational stress field caused by rock mass gravity is relatively simple and can be estimated by the specific weight of overburden and buried depth. On the contrary, the tectonic stress field is much more complicated, and is greatly influenced by tectonic movements (especially in the horizontal) and rock geological structures. In addition, the tectonic stress field is extremely irregular in spatial distribution and almost impossible to describe by precise analytical solutions, because it is continually changing with geologic age (Kang et al. 2010). However, at the human scale these stresses (tectonic and gravitational) can be assumed constant. Only local changes in the in situ stress occur caused by the reservoir exploitation (Segall and Fitzgerald 1998; Jeanne et al. 2015).
During CBM development, accurate measurement of in situ stress is particularly important for coal reservoir permeability evaluation and CBM recoverability assessment (Haimson 2005; Paul and Chatterjee 2011; Li et al. 2014). Coal reservoir permeability is determined by the fracture system resulting from the ancient and current tectonic stress fields, which immediately affect fracture aperture, morphology and propagation (direction and dip) (Meng et al. 2011). Moreover, coal reservoir pressure or effective stress, coal matrix swell associated with gas adsorption (e.g., CBM or other gases injected in the coal reservoir), and shrinkage effects during CBM desorption and production also affect fracture aperture (White et al. 2005; Bustin et al. 2008; Kumar et al. 2010, 2012; Wang et al. 2011; Pan and Connell 2012; Singh et al. 2015). A series of permeability dynamic prediction models have been established by considering the aforementioned coal effective stress and matrix shrinkage effects (Palmer and Mansoori 1998; Shi and Durucan 2004; Connell et al. 2010; Pan and Connell 2012; Zhao et al. 2013). Nevertheless, these models are based on stress or strain that can be simulated in the laboratory and cannot be used to analyze the effect of in situ stress on CBM reservoir permeability, because of the contrasting time scales between CBM development and in situ stress variability. Recently, after revelations of successful CBM development in the United States (Johnson and Flores 1998; Nelson 2003; Tonnsen and Miskimin 2010), the government of China has explored and developed CBM with great resource potential in the Ordos Basin. However, the ubiquitous characteristics of underpressured, CBM-undersaturated, low-porosity and low permeability in Chinese CBM reservoirs may cause coal reservoir permeability to be sensitive to stress change (Su et al. 2005; Yao et al. 2008; Keim et al. 2011; Xu et al. 2014). Moreover, both the complex stress conditions and poor reservoir properties could bring little economic benefit and inefficient development (Zhao et al. 2014). Chinese CBM development is mainly aimed at shallow coal seams, usually with depths 700–1000 m (Zhao et al. 2015a; Xu et al. 2015a, b; Lv et al. 2012; Li et al. 2014, 2015; Chen et al. 2014; Liu et al. 2014). Therefore, it is of major and practical significance to analyze the relationship between coal reservoir permeability, in situ stress and burial depth, which is beneficial to determine reasonable operating practice, reduce reservoir damage, improve CBM well productivity as well as guide deep CBM (>1000 m depths) exploration and development.
In this work, the data of reservoir pressure, in situ stress and well test permeability from 55 CBM wells were collected in the eastern margin of the Ordos Basin. Through statistics and regression analysis, correlations between stress, permeability and burial depth were determined to reveal the in situ stress distribution and address the impact of that stress on coal reservoir permeability, which is expected to provide theoretical support and guidance to CBM exploration and development.
2 Geological Setting
The eastern margin of the Ordos Basin crosses the Inner Mongolia Autonomous Region, Shanxi and Shaanxi provinces, and is a long and narrow zone along the Yellow River. This zone covers about 2.5 × 104 km2. It is nearly 560 km long in the north–south direction and 50–200 km wide in the east–west direction (Fig. 1). The zone has become the second most successful CBM development base after the Qinshui Basin since the 1980s (Xu et al. 2012a, b; Yang et al. 2013; Zhao et al. 2015b; Feng et al. 2015), and contains an estimated 9.0 × 1012 m3 of total CBM reserves that are buried less than 1500 m deep (Jie 2010). By the end of 2013, nearly 2000 CBM wells had been completed and vertical well productivity exceeded 6000 m3/day; that of horizontal wells reached 16,000 m3/day (Chen et al. 2015).
The eastern margin of the Ordos Basin is composed of three tectonic units, the Jinxi fold, eastern Yimeng uplift, and eastern Weibei uplift (Xue et al. 2011; Tang et al. 2012) (Fig. 1). The area is a large west-dipping monocline with dip angle 3°–10°, where the structures are relatively simple and stable. Only some slight northeast and north–northeast trending folds and small-scale faults are developed, which are beneficial to CBM preservation and exploration (Yao et al. 2009; Jie 2010).
The main coal-bearing sequences in the area are in the Carboniferous Taiyuan and Permian Shanxi Formations. The coal-bearing strata are largely preserved, providing a good basis for CBM generation and accumulation (Chen et al. 2015). Figure 2 shows a geologic cross section of the two formations from south to north. There are more than 20 coal seams of various thicknesses, but their distribution is stable. The Taiyuan Formation is predominantly deposited in a tidal flat and delta system. The number of principal mineable coal seams ranges from 2 to 4 and the total number is between 4 and 8, with net coal thickness 3–40 m. The Shanxi Formation is mainly deposited in a shallow water delta, lagoon-gulf system consisting of three to nine coal seams. There are one to three major mineable coal seams that have general coal thickness approximately 4–15 m in total. Overall, coal thickness in the northern portion is the greatest (20–35 m), followed by 10–20 m in the central portion and <5 m in the south (Jie 2010). Average vitrinite reflectance of coal is from 0.44 to 2.35 % and the roof and floor of the major coal seams consist primarily of mudstone, sandy mudstone and sandstone (Jiang et al. 2012). These generally have low permeability and favorable CBM sealing effects, although the limestone roofs are usually aquifers that can dissolve gases and transport them out of the CBM reservoir in the Liulin block (Xu et al. 2015a).
3 Methodology
After a CBM well is completed and before it is put into production, the coal seam is usually tested to obtain parameters such as reservoir pressure, fracturing pressure, closing pressure, permeability and others, which can provide a reliable basis for regional CBM assessment. Generally, injection/falloff well testing accompanied by in situ stress measurement is done to obtain the above parameters (Li et al. 2014).
Injection/falloff is a type of transient well test that is usually conducted before in situ stress measurement basing on Chinese national standard GB/T 24504-2009 (AQSIO and SAC 2009). Throughout the test, because the formation pressure is always higher than the CBM critical desorption pressure, the fluid just maintains single-phase water flow in the cleats. Permeability of the coal matrix is much lower than that of the cleats, which demonstrates that the measured permeability is mainly from the cleats rather than the coal matrix. Here, two methods are available to examine well test data, including characteristic straight line analysis and chart board matching analysis. Usually, the selected analysis model is determined by the log–log curve characteristic of test data. If the log–log pressure derivative curve appears as a horizontal straight line segment in the middle period, the semi-log method can be used to calculate reservoir permeability. Other cases could be investigated by typical curve fitting (Hopkins et al. 1998). In the present work, to ensure that the parameters are accurate and reliable, pressure history matching curves were compared and verified with measured curves. Figure 3 shows the workflow for the permeability calculation with the injection/falloff data. Figure 4 portrays the injection/falloff curves of an actual CBM well.
It should be noted, however, that the maximum injection pressure at the surface before an injection/falloff well test is usually unknown for a new area or areas with less data. Consequently, a minifrac is typically required to determine that pressure (Meng et al. 2010, 2011; Li et al. 2014). Figure 5 shows minifrac curves of an actual CBM well. During an injection/falloff well test, to reduce damage from stress on reservoir permeability, injection pressure at the surface is initiated at a relatively low value, and the maximum injection pressure at the injection rate is kept lower than fracturing pressure during the designed injection period. The injection period should be longer than the end time of the wellbore storage effect, and the well shut-in time should not be shorter than twice the injection period. In the present study, flow-static injection was continued for 12 h and the well was then shut in for at least 24 h to obtain the curves between temperature, pressure and time. Those curves were used to calculate reservoir permeability and initial reservoir pressure (Fig. 4).
In situ stress is often measured by the multi-cycle hydraulic fracturing method (Hubbert and Willis 1957; Kang et al. 2010; Liu et al. 2014; Li et al. 2014, 2015), according to Chinese earthquake industry standard DB/T 14-2000 (CEA 2000), which is also appropriate for the in situ stress measurement of coal (Kang et al. 2010; Liu et al. 2014), following the injection/falloff well test (Li et al. 2014, 2015). During the in situ stress measurement, the objective of pumping a thin fluid (water) at a certain rate into the target coal seam is to create a small fracture. Initially, pressure in the fracture is less than the fracture closing pressure and the fracture is closed. When the pressure in the fracture is greater than the fracture closing pressure, the fracture opens. Once this occurs, the pumps are shut down and the pressure falloff with time is recorded. When the fracture closes, the fracture closing pressure is equal to the minimum horizontal stress. This is why stresses can be deduced from the fluid injection test. Therefore, through the injection curve, reservoir fracturing pressure can be obtained. With the falloff curve, reservoir fracture closing pressure can be calculated (Zuber et al. 1990). During in situ stress tests, two to three cycles with clear fracturing and closing effects were chosen to calculate in situ stress parameters with the time square root method (Li et al. 2014), and were further verified by the log–log method. Figure 6 reveals the in situ stress measurement curves of an actual CBM well.
For the in situ stress measurement of a vertical well, when the formation pressure increases to the fracturing pressure by injecting water after the perforation is packed, the maximum horizontal principal stress can be expressed as (Bredehoeft et al. 1976):
where, σ H is the maximum horizontal principal stress, MPa; p c is the closing pressure, MPa; p f is the fracturing pressure, MPa; p 0 is the rock pore pressure (initial reservoir pressure); T is tensile strength of the rock around the borehole, MPa.
If the fluid is injected continuously to pressurize the reservoir, the fracture will extend to the deep site. Otherwise, if fluid injection is halted and the fracturing loop is kept closed, the fracture will immediately stop expanding and tend to close. Here, the balance pressure that can just keep the fracture open is called closing pressure and is equivalent to the minimum horizontal principal stress perpendicular to the fracture surface (Haimson and Fairhurst 1970; Haimson and Cornet 2003), i.e.,
where σ h is the minimum horizontal principal stress, MPa.
Similarly, if the injection process is repeated, the fracture will reopen and the refracturing pressure will be attained. Because the rock has been fractured, the rock tensile strength equals 0 and the fracturing pressure can be written as
where p r is the refracturing pressure, MPa.
Substituting Eqs. (2) and (3) into Eq. (1), rock tensile strength is expressed as
The vertical principal stress can be computed according to the weight of overlying rock from 116 in situ stress test results worldwide (Hoek and Brown 1980), yielding the prediction equation of that stress used herein:
where, σ v is the vertical principal stress, MPa; γ is rock bulk density, kN/m3 (1 kN/m3 = 0.001 MPa/m); H is burial depth, m.
During the in situ stress tests, tubing strings are used to lower the bottom-hole pressure gauge, packer and shut-in tools into the well. The packer is installed on an immediate roof that can be identified by logging data. Through the pipelines, underground equipment is connected with the injection system at the surface. In a short time, the injection fluid (formation water or filtered clean water) is pumped into the wellbore at a high rate, which makes the flowing bottom-hole pressure higher than the fracturing pressure of the target strata. Once the target strata fracture, the tested well is shut in and then the falloff curve may be acquired from the falloff data (Fig. 7).
To accurately estimate the in situ stress and eliminate uncertainties in the measurements, four cycles were performed in the hydraulic fracturing and all in situ stress data were calculated on the basis of the hydraulic fracturing test. The general measurement steps are as follows: (1) starting the injection pump at the surface and injecting water into the well at a certain rate with the ladder displacement method; (2) observing change of wellhead pressure until fracture occurrence after pumping 2–6 min continuously, shutting in the well for 20 min and measuring the reservoir pressure drop; (3) opening the well again and recording backflow volume; (4) keeping the injection rate as in the first cycle and running another 2–4 cycles per the designed injection and shut-in time; (5) comparing the measured and pressure gauge data and if the former is qualified, ending the in situ stress test (Fig. 6). Table 1 shows in situ stress measurement data from an actual CBM well in the eastern margin of the Ordos Basin.
4 Results and Discussions
4.1 Results of In Situ Stress and Injection/Falloff Well Tests
The in situ stress data measured by four-cycle hydraulic fracturing of 55 CBM wells in the eastern margin of the Ordos Basin indicates that at coal seam burial depths (H) 455.60–1323.10 m (average 832.46 m), initial reservoir pressure (p 0) is 2.58–12.22 MPa (average 6.73 MPa) and the pressure gradient (δ 0) 0.40–1.42 MPa/100 m (average 0.82 MPa/100 m), which represents an predominant underpressured reservoir. The closing pressure (p c) is 6.98–26.88 MPa (average 15.04 MPa) and the pressure gradient (δ c) 1.22–2.94 MPa/100 m (average 1.83 MPa/100 m). The coal seam fracturing pressure (p f) is 8.17–31.08 MPa (average 16.39 MPa) and the pressure gradient (δ f) 1.32–3.35 MPa/100 m (average 1.99 MPa/100 m) (Fig. 8; Table 2). Overall, the burial depth in this area is greater than that of the Qinshui Basin which is accompanied by lower initial reservoir pressure, closing pressure and fracturing pressure (Fig. 9; Table 2, Meng et al. 2010). Coal reservoir temperature is 16.08–45.37 °C with average 32.01 °C (Fig. 8; Table 3).
With Eqs. (1), (2) and (5), magnitudes of the maximum and minimum horizontal principal stresses and the vertical principal stress were computed. This shows that the maximum horizontal principal stress (σ H) is 10.13–37.84 MPa with average 22.50 MPa [its stress gradient (ε H) is 1.43–4.13 MPa/100 m with average 2.75 MPa/100 m]. The minimum horizontal principal stress (σ h) is 6.98–26.88 MPa with average 15.04 MPa, for which the stress gradient (ε h) is 1.22–2.94 MPa/100 m with average 1.83 MPa/100 m. The vertical principal stress (σ v) is 12.30–35.72 MPa with average 22.48 MPa (Fig. 8; Table 3). Compared with the Black Warrior Basin in the United States (where minimum horizontal principal stress is generally 1–6 MPa, McKee et al. 1988) and the Sydney and Bowen Basins in Australia (minimum horizontal principal stress generally 1–10 MPa, with a few values of 14 MPa, Enever and Henning 1997), in situ stress is greater in the coal seams in the eastern margin of the Ordos Basin. Overall, that stress is moderate to strong, because 85 % of the stresses are 10–30 MPa according to the assessment standard (Kang et al. 2009).
Similar to the Qinshui Basin, the initial reservoir pressure, fracturing pressure, and closing pressure all have a linearly increasing trend with increase of coal burial depth (Fig. 10a–c, Meng et al. 2010). The relevant relationships are as follows.
1. Initial reservoir pressure:
2. Fracturing pressure:
3. Closing pressure:
Moreover, the fracturing pressure has a clear positive correlation with closing pressure (Fig. 10d), expressed as
The results of the injection/falloff well tests indicate that coal reservoir permeability is 0.01–3.33 mD with average 0.65 mD, and 75 % of values are <1 mD. This reveals that the coal seam is a typical low permeability reservoir (Fig. 8; Table 3).
4.2 Principal Stress Variation with Depth
Figure 11 shows that the maximum and minimum horizontal principal stresses and the vertical principal stress are all positively correlated with buried depth. Because the minimum horizontal principal stress has a strong and even decisive impact on the fracturing pressure and its gradient and limits the expansion of hydraulic fractures, this stress becomes one of the key parameters in CBM well drilling design and coal seam reinforcement (Tang et al. 2011; Hallam and Last 1991; Hubbert and Willis 1957). In a common sedimentary basin, this stress is typically ~70 % of the vertical stress (Meng et al. 2013). However, 70 % of the coal reservoir vertical stress cannot accurately describe the magnitude and variation of the minimum horizontal principal stress in the eastern margin of the Ordos Basin. For example, at depths >1000 m, 70 % of the vertical stress is larger than the minimum horizontal principal stress. Overall, the minimum horizontal principal stress in the coal reservoir is slightly weaker than that of sedimentary rock strata in a common sedimentary basin. This is mainly attributed to coal as the organic matter and its weaker mechanical strength.
Based on the actual data, a general trend of the in situ stress change can be observed and in the vertical direction, stress field types in the study area are as follows. At depths <700 m, the coal reservoir in situ stress state is such that σ H > σ v > σ h, the minimum horizontal principal stress is <19 MPa, and the current in situ stress field type is a strike slip regime. At depths 700–1000 m, the coal reservoir in situ stress state changes to σ H ≈ σ v > σ h, indicating a stress transition zone where the average minimum horizontal principal stress is ~15 MPa. In the deep coal seam with burial depths >1000 m, vertical stress increases conspicuously and is greater than the maximum principal stress, i.e., σ v > σ H > σ h, with the minimum principal stress increasing from 14.80 to 26.88 MPa and averaging 19.88 MPa. These strata show a normal stress regime type, which is advantageous for normal fault activity and indicates an extension zone (Anderson 1951, Fig. 11).
4.3 Principal Stress Ratio Variation with Depth
Generally, when researching the stress field change behavior, the lateral stress coefficient is used to represent the in situ stress state at some point (Brown and Hoek 1978; Hoek and Brown 1980; Han et al. 2012). The lateral stress coefficient is defined as the ratio of average horizontal principal stress to vertical stress, expressed as
where, λ is the lateral stress coefficient.
Measurements of lateral stress coefficient in the eastern margin of the Ordos Basin indicate that this parameter ranges from 0.51 to 1.21 with average 0.84. These values are between the Hoek–Brown inner and outer in situ stress envelopes representing the relationship between the ratio and burial depth worldwide (Brown and Hoek 1978) and those in China (Zhao et al. 2007) (Fig. 12). At depths <700 m, the lateral stress coefficient variation is 0.61–1.21 with average 0.94. The lateral stress coefficient is 0.51–1.12 with average 0.82 for 700–1000 m depths. For depths >1000 m, that coefficient is 0.62–0.98 with average 0.76. The lower limit of the in situ stress transformation depth corresponding to the depth at which the lateral stress coefficient equals 1 appears around 900 m, just within the range 700–1000 m. In other words, at depths <900 m, the horizontal principal stress is dominant and the lateral stress coefficient is large and disperse. The vertical principal stress is primary at depths >900 m where the lateral stress coefficient converges. This result is consistent with the analysis of Brown and Hoek (1978) and Zhao et al. (2007), who discussed lateral stress coefficient variation with depth worldwide and in China, respectively.
Referencing the expression of the Hoek–Brown inner and outer envelopes, the lateral stress coefficient is rewritten in the following form:
where, a and b are undetermined coefficients, respectively.
Equation (11) shows a linear relationship between the lateral stress coefficient and reciprocal of the buried depth. Thus, by regression of the measured lateral stress coefficients after linearizing the data, the trend line and inner and outer in situ stress envelopes of the eastern margin of the Ordos Basin were obtained. From Fig. 12, the outer envelope in the area is basically coincident with the Hoek–Brown outer envelope. The inner envelope is within the Hoek–Brown inner envelope and essentially coincident with the Chinese in situ stress inner envelope, indicating that the in situ stress measurements from the hydraulic fracturing method are credible.
Furthermore, by similar linear regression of the stress ratios and burial depth, trend lines of the ratios and their general ranges at various depths were acquired (Fig. 13). It is seen that the ratios of horizontal principal stresses in the study area are 1.08–1.70 with average 1.48. The ratios of maximum principal stress to vertical principal stress are 0.53–1.53 with average 1.01, and ratios of minimum principal stress to vertical principal stress are 0.45–0.90 with average 0.67. Overall, the three in situ stress ratios slowly decreased with buried depth. At <700 m depths, variation of the three ratios is great and their decrease with burial depth is rapid. For 700–1000 m depths, that decrease slows substantially, and is near zero at depths >1000 m. This general change behavior is consistent with the analysis of Liu et al. (2014), who addressed lateral stress coefficient variation with depth in the Huainan coalfield.
4.4 Permeability Variation Under the Principal Stress
Permeability is one of the key determinants of CBM productivity (Wang et al. 2011, 2013). Coal reservoir permeability is extremely sensitive to in situ stress and with increase of that stress, the permeability decreases exponentially (Somerton et al. 1975). This has been verified by field measurements, e.g., in coal of the Australian Sydney and Bowen Basins (Enever and Henning 1997; Enever et al. 1998), the American San Juan, Piceance and Black Warrior Basins (McKee et al. 1988; Sparks et al. 1995), and the Chinese Qinshui Basin (Meng et al. 2011). Generally, in situ stress has clear effects on coal reservoir permeability. When other factors (e.g., coal pore-fracture structures, petrographic constituents, and engineering operations) are equal, the greater stress could bring the lower the permeability and the poorer the CBM well productivity. In such a case, permeability may be roughly determined based on in situ stress magnitude (Li et al. 2014).
In our study, a negative exponent was used to analyze the relationship between coal reservoir well test permeability and in situ stress (Seidle et al. 1992; Zhao et al. 2015b), as
where, k is permeability of a given stress condition, mD; k 0 is permeability of the initial stress condition, mD; ∆σ is the effective stress difference between an initial and a given stressed state, MPa; α is a coefficient dependent on the principal stress type.
Figure 14 shows that a decreasing behavior can describe the relationship between the maximum horizontal principal stress and coal reservoir permeability. The same applies to the minimum horizontal principal stress. This result is in accord with correlations between the measured permeability of coal seam and in situ horizontal stresses in the Hancheng and Liulin blocks in the eastern margin of the Ordos Basin, found by Tang (2001) and Li et al. (2014), respectively. After ~20 MPa in Figs. 14a and 15 MPa in Fig. 14b, high permeability data disappears. In contrast, the relationship between permeability and vertical principal stress is relatively complicated. With increasing stress, the permeability shows a tendency of decrease (<20 MPa), increase (20–25 MPa) and decrease (>25 MPa). When that stress is >30 MPa, the permeability is extremely low. This permeability change is in accord with Li et al. (2014, 2015).
In fact, the above permeability variation with vertical principal stress represents the relationship between permeability and burial depth, as that stress is calculated by Eq. (5). Figure 15 indicates that the permeability has three distinct vertical bands with increase of buried depth. At depths <700 m, the permeability decreases with buried depth and is 0.01–3.33 mD with average 0.89 mD. For 700–1000 m depths, permeability increases with depth and is 0.01–3.26 mD with average 0.73 mD. At depths >1000 m, permeability is very low, at 0.01–0.42 mD with average 0.11 mD.
Taking the stress variation into consideration, coal reservoir permeability inflection points at various depths are basically consistent with transition points of the stress field types and states at corresponding depths (Meng et al. 2011). In this work, for coal seams at burial depths <700 m, the horizontal principal stress is dominant. There, coal fractures gradually close and permeability decreases gradually with burial depth, corresponding to increase of the in situ stresses. During in situ stress state transitions (700–1000 m), with further increase of those stresses, both elastic and some inelastic deformation may occur. This results in part of the pores and fractures opening, because of friction and slide of the fractures or even coal destruction. Therefore, in this in situ stress transition zone, the stress-dependent permeability somewhat increases. Nonetheless, permeability of the coal seams buried more than 1000 m deep decreases rapidly instead of continuously increasing, although it is an extensional stress regime where the rock is in a compressive state but the vertical compressive stress is higher than the horizontal compressive stress. The main reason for this is that under the stronger vertical principal stress in a deep coal seam, the coal reservoir pore and fracture system tends to close again and cannot be effectively connected which results a rapid permeability reduction. Obviously, the essential influence of deep burial on permeability is its control by in situ stress control, i.e., the deformation and destruction of coal pore structures under in situ stress. This is consistent with Li et al. (2014, 2015), who discovered the same situation.
Finally, in the eastern margin of the Ordos Basin, optimizing the relationships among buried depth, in situ stress and permeability is very important for improvement of CBM productivity. Moreover, deep-level (>1000 m) CBM development faces the extreme challenge of “extremely low permeability and extremely high in situ stress,” which is the current problem in need of urgent solution for CBM development in China.
5 Conclusions
Through the regression of measured injection/falloff and in situ stress well test data for 55 CBM wells in the eastern margin of the Ordos Basin, the distribution of in situ stress and its effect on permeability were analyzed systematically.
-
1.
The maximum and minimum horizontal principal stress and vertical principal stress are all positively correlated with buried depth. Stress ratios and the lateral stress coefficient have a slow attenuation trend with burial depth.
-
2.
Overall, there are three in situ stress states in the eastern margin of the Ordos Basin. At burial depths <700 m, the in situ stress state is σ H > σ v > σ h, revealing a strike slip regime. From 700 to 1000 m depths, σ H ≈ σ v > σ h, showing a stress transition regime. At depths >1000 m, the in situ stress state changes to σ v > σ H > σ h demonstrating a normal stress regime.
-
3.
Well test permeability decreases with horizontal principal stress but has a decrease–increase–decrease trend with increased vertical stress. This is basically consistent with the change of stress state at a certain burial depth, whose essence is the deformation and destruction of coal pore structures under the action of stresses.
-
4.
With increase of buried depth, the vertical principal stress gradually dominates. A state of “extremely low permeability and extremely high in situ stress” means that it is very difficult to develop the deep-level CBM resource (>1000 m depths).
Abbreviations
- α :
-
Coefficient depended on the principal stress type
- a :
-
Undetermined coefficient
- b :
-
Undetermined coefficient
- CBM:
-
Coalbed methane
- H :
-
Burial depth
- ISIP:
-
Instantaneous shut-in pressure
- k :
-
Permeability of a given stress condition
- k 0 :
-
Permeability of the initial stress condition
- p :
-
Pressure
- p 0 :
-
Rock pore pressure (initial reservoir pressure)
- p c :
-
Closing pressure
- p f :
-
Fracturing pressure
- p i :
-
Injection pressure
- p i,max :
-
Maximum injection pressure at the surface
- p r :
-
Refracturing pressure
- γ :
-
Rock bulk density
- δ 0 :
-
Initial reservoir pressure gradient
- δ c :
-
Closing pressure gradient
- δ f :
-
Fracturing pressure gradient
- ε h :
-
Minimum horizontal principal stress gradient
- ε H :
-
Maximum horizontal principal stress gradient
- λ :
-
Lateral stress coefficient
- t :
-
Time
- T :
-
Tensile strength of the rock around borehole
- t i :
-
Injection time
- t lp :
-
Last pumping time
- t s :
-
Well shut-in time
- ∆t :
-
Time interval between the two adjacent cycles
- Temp:
-
Temperature
- V i :
-
Total injection volume
- v i,ave :
-
Average injection rate at the surface
- V r :
-
Backflow volume
- σ h :
-
Minimum horizontal principal stress
- σ H :
-
Maximum horizontal principal stress
- σ v :
-
Vertical stress
- ∆σ :
-
Effective stress difference changed from initial to some stressed state
References
Anderson EM (1951) The dynamics of faulting and Dyke formation with application to Britain, 2nd edn. Oliver & Boyd, Edinburgh
AQSIO, SAC (2009) GB/T 24504–2009 The method of injection/falloff well test for coalbed methane well. Beijing: Standards Press of China, 1–8 (in Chinese with an English abstract)
Bell JS (2006) In-situ stress and coal bed methane potential in Western Canada. Bull Can Petrol Geol 54:197–220
Bredehoeft JD, Wolf RG, Keys WS, Shutter E (1976) Hydraulic fracturing to determine the regional in situ stress field in the Piceance Basin, Colorado. Geol Soc Am Bull 87:250–258
Brown ET, Hoek E (1978) Trends in relationships between measured in situ stresses and depth. Int J Rock Mech Geomech Abstr 15:211–215
Bustin RM, Cui X, Chikatamarla L (2008) Impacts of volumetric strain on CO2 sequestration in coals and enhanced CH4 recovery. AAPG Bull 92:15–29
Cai M, Qiao L, Li C, Ji H, Tan Z, Ren F, Peng H (2010) New development of in situ stress measurement in Chinese mines. In: International symposium on in-situ rock stress, 25–27 August, Beijing, China
CEA (2000) DB/T 14–2000 Code of hydraulic fracturing and overcoring method for in-situ stress measurement. Beijing: Standards Press of China, 753–766 (in Chinese with an English abstract)
Chatterjee R, Pal PK (2010) Estimation of stress magnitude and physical properties for coal seam of Rangamati area, Raniganj coalfield, India. Int J Coal Geol 81:25–36
Chen D, Shi JQ, Durucan S, Korre A (2014) Gas and water relative permeability in different coals: model match and new insights. Int J Coal Geol 122:37–49
Chen Y, Tang DZ, Xu H, Li Y, Meng YJ (2015) Structural controls on coalbed methane accumulation and high production models in the eastern margin of Ordos Basin, China. J Nat Gas Sci Eng 23:524–537
Clarkson CR, McGovern JM (2005) Optimization of coalbed-methane-reservoir exploration and development strategies through integration of simulation and economics. SPE reservoir evaluation and engineering. December, SPE 88843, pp 502–519
Connell LD, Lu M, Pan ZJ (2010) An analytical coal permeability model for tri-axial strain and stress conditions. Int J Coal Geol 84:103–114
DB/T 14-2000 (2000) Code of hydraulic fracturing and overcoring method for in situ stress measurement (in Chinese with an English abstract)
Enever JR, Henning A (1997) The relationship between permeability and effective stress for Australian coal and its implications with respect to coalbed methane exploration and reservoir modelling. In: Proceedings of the 1997 international coalbed methane symposium 1997, pp 13–22
Enever JR, Casey D, Bocking M (1998) The role of in situ stress in coal bed methane exploration. In: Proceedings of international conference of coal seam gas and oil. Brisbane
Feng D, Deng HW, Zhou Z, Gao XP, Cui LT (2015) Paleotopographic controls on facies development in various types of braid-delta depositional systems in lacustrine basins in China. Geosci Frontiers 6:579–591
GB/T 24504-2009 (2009) The method of injection/falloff well test for coalbed methane well (in Chinese with an English abstract)
Gentzis T (2009) Stability analysis of horizontal coalbed methane well in the Rocky Mountain Front Ranges of southeast British Columbia, Canada. Int J Coal Geol 77:328–337
Gentzis T (2011a) Stability analysis of a horizontal coalbed methane borehole in the San Juan Basin, USA. Energy Sources Part A 33:1969–1984
Gentzis T (2011b) Stability analysis of two horizontal CBM wells drilled in the deep Mannville coals, Alberta Basin, Canada. Energy Sources Part A 33:2281–2290
Haimson BC (2005) Pre-excavation in situ stress measurements and rational design of coal mines. In: ISRM international symposium—EUROCK 2005, 18–20 May, Brno, Czech Republic
Haimson BC, Cornet FH (2003) ISRM suggested methods for rock stress estimation-part 3: hydraulic fracturing (HF) and/or hydraulic testing of pre-existing fractures (HTPF). Int J Rock Mech Min Sci 40:1011–1020
Haimson BC, Fairhurst C (1970) In-situ stress determination at great depth by means of hydraulic fracturing. In: Somerton WH (ed) Rock mechanics—theory and practice. AIME, New York, pp 559–584
Hallam SD, Last NC (1991) Geometry of hydraulic fractures from modestly deviated wellbores. SPE Journal, SPE 20656
Han J, Zhang HW, Li S, Song W (2012) The characteristic of in situ stress in outburst area of China. Saf Sci 50:878–884
Hoek E, Brown ET (1980) Underground excavations in rock. The Institution of Mining and Metallurgy, London
Hopkins CW, Frantz JH, Flumerfelt RW, Spivey JP (1998) Pitfalls of injection/falloff testing in coalbed methane reservoirs. In: SPE Permian Basin oil and gas recovery conference. Society of Petroleum Engineers, Midland, Texas, pp 9–24
Hubbert MK, Willis DG (1957) Mechanics of hydraulic fracturing. Trans AIME 210:153–163
Iannacchione A, Bajpayee T, Prosser L (2007) Methods of determining roof fall risk. In: SME annual meeting, February 25–28, Salt Lake City, Utah (preprint 07-090, 8)
Jeanne P, Rutqvist J, Dobson PF, Garcia J, Walters M, Hartline C, Borgia A (2015) Geomechanical simulation of the stress tensor rotation caused by injection of cold water in a deep geothermal reservoir. J Geophys Res Solid Earth 120:8422–8438
Jiang B, Xu J, Zhu K, Wang J, Wang J, Qu Z (2012) Structural and hydrogeological controls of coalbed methane preservation in the eastern Ordos Basin. Geol J China Univ 3:438–446 (in Chinese with an English abstract)
Jie MX (2010) Prospects in coalbed methane gas exploration and production in the eastern Ordos Basin. Nat Gas Ind 30:1–6 (in Chinese with an English abstract)
Johnson RC, Flores RM (1998) Developmental geology of coalbed methane from shallow to deep in Rocky Mountain basins and in Cook Inlet-Matanuska basin, Alaska, USA and Canada. Int J Coal Geol 35:241–282
Kang H, Zhang X, Si L (2009) Study on in situ stress distribution law in deep underground coal mining areas. In: ISRM international symposium on rock mechanics—SINOROCK 2009, 19–22 May. The University of Hong Kong, China
Kang H, Zhang X, Si L, Wu Y, Gao F (2010) In-situ stress measurements and stress distribution characteristics in underground coal mines in China. Eng Geol 116:333–345
Karacan CÖ, Ulery JP, Goodman GVR (2008) A numerical evaluation on the effects of impermeable faults on degasification efficiency and methane emissions during underground coal mining. Int J Coal Geol 75:195–203
Keim SA, Luxbacher KD, Karmis M (2011) A numerical study on optimization of multilateral horizontal wellbore patterns for coalbed methane production in Southern Shanxi Province, China. Int J Coal Geol 86:306–317
Kumar H, Elsworth D, Marone CJ, Mathews JP (2010) Permeability evolution of shale and coal under differential sorption of He, CH4 and CO2. In: American Geophysical Union Fall meeting, San Francisco, p 1042
Kumar H, Elsworth D, Liu J, Pone D, Mathews JP (2012) Optimizing enhanced coalbed methane recovery for unhindered production and CO2 injectivity. Int J Greenh Gas Con 11:86–97
Li Y, Tang DZ, Xu H, Yu TX (2014) In-situ stress distribution and its implication on coalbed methane development in Liulin area, eastern Ordos basin, China. J Petrol Sci Eng 122:488–496
Li S, Tang DZ, Xu H, Tao S, Shao GL, Ren PF (2015) Evolution of physical difference in various burial depth of coal reservoirs under constraint of stress. Acta Petrolei Sinica 36:1–7
Liu CR (2011) Distribution laws of in situ stress in deep underground coal mines. Proc Eng 26:909–917
Liu QQ, Cheng YP, Yuan L, Tong B, Kong SL, Zhang R (2014) CMM capture engineering challenges and characteristics of in situ stress distribution in deep level of Huainan coalfield. J Nat Gas Sci Eng 20:328–336
Lv YM, Tang DZ, Xu H, Luo HH (2012) Production characteristics and the key factors in high-rank coalbed methane fields: a case study on the Fanzhuang block, Southern Qinshui Basin, China. Int J Coal Geol 96–97:93–108
McKee CR, Bumb AC, Koenig RA (1988) Stress dependent permeability and porosity of coal and other geologic formations. SPE Form Eval 3:81–91
Meng ZP, Tian YD, Li GF (2010) Characteristics of in situ stress field in Southern Qinshui Basin and its research significance. J China Coal Soc 35:975–981 (in Chinese with an English abstract)
Meng ZP, Zhang JC, Wang R (2011) In-situ stress, pore pressure, and stress-dependent permeability in the southern Qinshui Basin. Int J Rock Mech Min Sci 48:122–131
Meng ZP, Lan Q, Liu CL, Ji YM, Li SN, Zhang XM (2013) In-situ stress and coal reservoir pressure in Southeast margin of Ordos basin and their coupling relations. J China Coal Soc 38:122–128 (in Chinese with an English abstract)
Nelson CR (2003) In deep coalbed gas plays in the U.S. Rocky Mountain Region. AAPG Annual Convention and Exhibition, Denver: American Association of Petroleum Geologists, 2003
Palmer I, Mansoori J (1998) Permeability depends on stress and pore pressure in coalbeds, a new model. SPE Reserv Eval Eng 1:539–544
Pan Z, Connell LD (2012) Modelling permeability for coal reservoirs: a review of analytical models and testing data. Int J Coal Geol 92:1–44
Paul S, Chatterjee R (2011) Determination of in situ stress direction from cleat orientation mapping for coal bed methane exploration in south-eastern part of Jharia coalfield, India. Int J Coal Geol 87:87–96
Ryan B (2003) Cleat development in some British Columbia coals. Geology fieldwork 2002, Paper 2003-1, pp 165–183
Segall P, Fitzgerald SD (1998) A note on induced stress changes in hydrocarbon and geothermal reservoirs. Tectonophysics 289:117–128
Seidle JP, Jeansonne MW, Erickson DJ (1992) Application of matchstick geometry to stress dependent permeability in coals. In: SPE rocky mountain regional meeting, Casper, Wyoming
Shi JQ, Durucan S (2004) Drawdown induced changes in permeability of coalbeds: a new interpretation of the reservoir response to primary recovery. Transport Porous Med 56:1–16
Singh PK, Singh VK, Rajak PK, Singh MP, Naik AS, Raju SV, Mohanty D (2015) Eocene lignites from Cambay basin, Western India: an excellent source of hydrocarbon. Geosci Frontiers. doi:10.1016/j.gsf.2015.08.001
Somerton WH, Soylemezoglu IM, Dudley RC (1975) Effect of stress on permeability of coal. Int J Rock Mech Geomech Abstr 12:129–145
Sparks DP, McLendon TH, Saulsberry JL, Lambert SW (1995) The effects of stress on coalbed reservoir performance, Black Warrior Basin, USA. In: Proceedings of 1995 SPE annual technology conference and exhibition, Dallas, Paper SPE 30743
Su XB, Lin XY, Liu SB, Zhao MJ, Song Y (2005) Geology of coalbed methane reservoirs in the Southeast Qinshui Basin of China. Int J Coal Geol 62:197–210
Talebi MH, Heidari S, Moosavi M, Rahimi M (2014) In situ stress measurements of two hydropower projects in Iran by hydraulic fracturing method. Arab J Geosci 8(9):7073–7085
Tang SH (2001) Probe into the influence factors on permeability of coal reservoir. China Coal Geol 13:28–30
Tang SH, Zhu BC, Yan ZF (2011) Effect of crustal stress on hydraulic fracturing in coalbed methane wells. J China Coal Soc 36:65–69 (in Chinese with an English abstract)
Tang X, Zhang J, Shan Y, Xiong J (2012) Upper Paleozoic coal measures and unconventional natural gas systems of the Ordos Basin, China. Geosci Front 3:863–873
Tonnsen RR, Miskimin JL (2010) A conventional look at an unconventional reservoir: coalbed methane production potential in deep environments. In: AAPG annual convention and exhibition, New Orleans, Louisiana, 11–14 April 2010
Wang S, Elsworth D, Liu J (2011) Permeability evolution in fractured coal: the roles of fracture geometry and water-content. Int J Coal Geol 87:13–25
Wang S, Elsworth D, Liu J (2013) Mechanical behavior of methane infiltrated coal: the roles of gas desorption, stress level and loading rate. Rock Mech Rock Eng 46:945–958
White CM, Smith DH, Jones KL, Goodman AL, Jikich SA, LaCount RB, Schroeder KT (2005) Sequestration of carbon dioxide in coal with enhanced coalbed methane recovery a review. Energy Fuel 19:659–724
Xu H, Tang DZ, Liu DM, Tang SH, Yang F, Chen XZ, Deng CM (2012a) Study on coalbed methane accumulation characteristics and favorable areas in the Binchang area, southwestern Ordos Basin, China. Int J Coal Geol 95:1–11
Xu H, Zhang JF, Tang DZ, Li M, Zhang WZ, Lin WJ (2012b) Controlling factors of underpressure reservoirs in the Sulige gas field, Ordos Basin. Petrol Explor Dev 39:70–74
Xu H, Tang DZ, Tang SH, Zhao JL, Meng YJ, Tao S (2014) A dynamic prediction model for gas-water effective permeability based on coalbed methane production data. Int J Coal Geol 121:45–52
Xu H, Tang DZ, Tang SH, Zhang WZ, Meng YJ, Gao LJ, Xie SZ, Zhao JL (2015a) Geologic and hydrological controls on coal reservoir water production in marine coal-bearing strata: a case study of the Carboniferous Taiyuan Formation in the Liulin area, eastern Ordos Basin, China. Mar Petrol Geol 59:517–526
Xu H, Tang DZ, Zhao JL, Tao S, Li S, Fang Y (2015b) Geologic controls of the production of coalbed methane in the Hancheng area, southeastern Ordos Basin. J Nat Gas Sci Eng 26:156–162
Xue C, Chi G, Xue W (2011) Effects of hydrocarbon generation on fluid flow in the Ordos Basin and its relationship to uranium mineralization. Geosci Front 2:439–447
Yang C, Zhang J, Tang X (2013) Microscopic pore types and its impact on the storage and permeability of continental shale gas, Ordos Basin. Earth Sci Front 20:240–250
Yao YB, Liu DM, Tang DZ, Huang WH, Tang SH, Che Y (2008) A comprehensive model for evaluating coalbed methane reservoirs in China. Acta Geol Sin 82:1253–1270
Yao YB, Liu DM, Tang DZ, Tang SH, Che Y, Huang WH (2009) Preliminary evaluation of the coalbed methane production potential and its geological controls in the Weibei Coalfield, Southeastern Ordos Basin, China. Int J Coal Geol 78:1–15
Zhao DA, Chen ZM, Cai XL, Li SY (2007) Analysis of distribution rule of geostress in China. Chin J Rock Mech Eng 26:1265–1271 (in Chinese with an English abstract)
Zhao JL, Tang DZ, Xu H, Meng YJ, Lv YM (2013) A permeability model for undersaturated coalbed methane reservoirs considering the effect of coal matrix shrinkage. Adv Mater Res 807–809:2413–2420
Zhao JL, Tang DZ, Xu H, Meng YJ, Lv YM, Tao S (2014) A dynamic prediction model for gas-water effective permeability in unsaturated coalbed methane reservoirs based on production data. J Nat Gas Sci Eng 21:496–506
Zhao JL, Tang DZ, Xu H, Lv YM, Tao S (2015a) High production indexes and the key factors in coalbed methane production: a case in the Hancheng block, southeastern Ordos basin, China. J Petrol Sci Eng 130:55–67
Zhao JL, Tang DZ, Lin WJ, Xu H, Li Y, Tao S, Lv YM (2015b) Permeability dynamic variation under the action of stress in the medium and high rank coal reservoir. J Nat Gas Sci Eng 26:1030–1041
Zuber MD, Sparks DP, Lee WJ (1990) Design and interpretation of injection/falloff tests for coalbed methane wells. In: SPE Annual technical conference and exhibition. Society of Petroleum Engineers, New Orleansa, pp 425–434
Acknowledgments
This work was financially supported by the National Natural Science Foundation Project (Grant Nos. 41272175, 41530314), the Special Funds for Scientific Research on Public Causes of the Ministry of Land and Resources of the People’s Republic of China (Grant No. 201311015), the Key Project of the National Science & Technology (Grant No. 2016ZX05042-002), the Beijing Higher Education Young Elite Teacher Project and the Fundamental Research Funds for the Central Universities (Grant 2652015331). The authors are grateful to anonymous reviewers and the editor Dr. Giovanni Barla for their careful reviews and detailed comments that helped to substantially improve the manuscript.
Author information
Authors and Affiliations
Corresponding author
Rights and permissions
About this article
Cite this article
Zhao, J., Tang, D., Xu, H. et al. Characteristic of In Situ Stress and Its Control on the Coalbed Methane Reservoir Permeability in the Eastern Margin of the Ordos Basin, China. Rock Mech Rock Eng 49, 3307–3322 (2016). https://doi.org/10.1007/s00603-016-0969-1
Received:
Accepted:
Published:
Issue Date:
DOI: https://doi.org/10.1007/s00603-016-0969-1