Risking fault reactivation induced by gas injection into depleted reservoirs based on the heterogeneity of geomechanical properties of fault zones

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1 Thematic set: Fault and top seals Published Online First Petroleum Geoscience doi: /petgeo Risking fault reactivation induced by gas injection into depleted reservoirs based on the heterogeneity of geomechanical properties of fault zones Lingdong Meng 1*, Xiaofei Fu 1*, Yanfang Lv 1, Xianli Li 1, Yabin Cheng 2, Tingwei Li 3 & Yejun Jin 1 1 Science and Technology Innovation Team of Universities of Fault Deformation, Sealing and Fluid Migration, Northeast Petroleum University, Daqing, Heilongjiang , PR China 2 Exploration and Development Research Institute of Dagang Oilfield Company, PetroChina, Tianjin , PR China 3 State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum, Beijing , PR China * Correspondence: fuxiaofei2008@sohu.com Abstract: Predictions of fault reactivation and the hydraulic seal of cap rock are integral parts of the seal integrity research programme of the Banzhongbei gas storage facility (BGS) to ensure the safe storage of natural gas in subsurface reservoirs. We attempt to combine the heterogeneity of geomechanical properties, including frictional coefficient and cohesive strength, into a workflow to estimate fault reactivation risk and the maximum sustainable fluid pressure that will not induce failure of trapbounding faults and cap rock. Based on the Griffith Coulomb Failure criterion, fault failure modes including tensile failure, shear failure and hybrid failure may occur under conditions of the same in situ stress field as a result of the strength heterogeneity of fault rocks, which plays a key role in the estimation of integrity of the entire fault trap. The juxtaposition of the seal on the BQ Fault with high shale gouge ratio (SGR) values makes a significant contribution to the high fluid pressure buildups during gas injection, and its low strength properties lead to a higher reactivation risk for the Banqiao (BQ) Fault than for the B816 Fault. The increased pore-fluid pressure adjacent to the BQ Fault induced by gas injection should be lower than 9.7 MPa in order to avoid failure. Furthermore, the maximum sustainable fluid pressure of the cap rock is approximately 13.9 MPa at the locations of the injection wells. Received 13 February 2016; revised 18 June 2016; accepted 26 June 2016 The original fault seal capacity may be breached by reactivation (Wiprut & Zoback 2002; Gartrell et al. 2006; Langhi et al. 2010) resulting from fluid injection into reservoirs (Nicholson & Wesson 1990; Guha 2000; Cornet 2012; Evans et al. 2012; Keranen et al. 2013; McGarr et al. 2015). Research on the maximum sustainable fluid pressure of trap-bounding faults is an integral part of the programme to ensure the safe storage of gas, such as CO 2 (Streit & Hillis 2004; Richey 2013). Increased pore-fluid pressure due to gas injection can potentially cause the failure of pre-existing fractures or slip on faults in a reservoir (Grasso 1992). This would create or enhance fracture permeability, while the formation of networks of interlinked open fractures and rough fault surfaces could provide conduits for the escape of gas-rich fluid from a reservoir. In light of this, one of the key steps in the evaluation of any potential site being considered for geological gas storage is the risk of fault reactivation induced by gas injection. Evaluation methods of fault reactivation have been established, such as slip tendency (Morris et al. 1996), dilation tendency (Ferrill et al. 1999), Coulomb failure function (Castillo et al. 2000), critical pressure perturbation (Wiprut & Zoback 2002) and fault analysis seal technology (Mildren et al. 2005). In addition, significant work has been carried out to quantify the risk of fault reactivation (Dewhurst & Jones 2002; Reynolds et al. 2003; Streit & Hillis 2004; Çiftçi 2013). However, the effects of strength heterogeneity of fault zones on fault stability remain poorly constrained. The focus of the present work is to establish a geomechanical model of strength heterogeneity of fault zones to estimate the maximum fluid pressure that faults can sustain in gas storage. It is thus essential to study how geomechanical properties of fault rocks in potential gas storage sites can be determined, and the relationship between fault zones and the present-day stress field. In both cases, a geomechanical model can be used to derive the maximum sustainable pressures for the bounding faults, and can help in evaluating the pressures and rates of injection needed to reach the critical value in more a accurate way. Geology of the Banzhongbei gas storage facility The Banzhongbei gas storage facility (BGS for short) is bounded on the NE by two normal faults, named the Banqiao Fault (BQ Fault for short) and the B816 Fault, of which trap-bounding segments dip approximately NE (Fig. 1). It is part of the Dagang gas storage facilities, located approximately in the centre of the Bohai Bay Basin, which acts as a swing supplier to meet the peak demand for natural gas used for heating in Beijing, Tianjin and Hebei province. A practical analysis for increasing the upper limit of injection pressure is necessary in order to improve the efficiency of the injection wells without causing fault reactivation and failure of the cap seal. On the hanging wall of the B816 Fault, there is a trap, named 814 Block, from which hydrocarbons have been recovered and depleted for years (owned by Dagang Oilfield Group Limited Company). Hence, one of the key steps in the evaluation of the seal integrity for the BGS is to predict the seal capacity of the B816 Fault. In the cross-section of R R in Figure 1, the BQ Fault is well defined in the seismic data and cuts Oligocene sedimentary rocks with throws ranging from 140 to 290 m at trap-bounding segments. The minimum throw on the NE tip of the B816 Fault is about 6 m, based on the stratigraphic correlation of well B813 and adjacent wells, such as Bz15 and B14. In the BGS area, the Ban-II Formation reservoir is of Oligocene age, and comprises strata of turbidite sediments with an average net 2016 The Author(s). Published by The Geological Society of London for GSL and EAGE. All rights reserved. For permissions: permissions. Publishing disclaimer:

2 L. Meng et al. Fig. 1. Location and depth-structure map of the BZB gas storage facility. The storage is located in the centre of the Bohai Bay Basin, and is bounded by the BQ and B816 faults, with a structural crest of 2650 m and a spill point of 2680 m. A hydrocarbon trap, 814 Block, is located on the hanging wall of the B816 Fault. The cross-section of R R on top of the Ban-II Formation passes through BQ Fault, well Bz13 and the B816 Fault. thickness of 29.6 m, porosity of 18.3%, permeability of md and a temperature of approximately 85 C. There is approximately 30 m of structural closure at Top Ban-II (the vertical distance from the structural crest of 2650 m to the spill point of 2680 m), covering an area of about 2.7 km 2. The Ban-II Formation is divided into six intervals, of which Ban-II-1 to Ban-II-4 Sandstone is the main producer and the proposed storage interval for this study. The spill point of Ban-II-4 is 2750 m, which constrains the lower limit of the fault-bounded depth range of interest. Overlying the Ban-II Formation there is approximately m of shale, which provides an excellent cap seal for the storage facility. CH 4 and CO (which make up more than 96% of the total gas volume) comprise the main natural gases injected into the BGS, with an average density of approximately 700 kg m 3 at reservoir conditions. Risks of fault reactivation induced by gas injection Mechanisms of fault reactivation induced by injection Numerical simulations of stress perturbation and evidence of wellbore-casing failure suggest that increasing pore-fluid pressure caused by injection could induce microearthquakes or fault slip (Scotti & Cornet 1994; Calò et al. 2011). Laboratory experiments also show that increasing the pore-fluid pressure in rocks and faults reduces their strength and can induce brittle failure (Blanpied et al. 1992). Failure occurs because increasing pore-fluid pressure leads to low effective stresses. Increasing gas injection is illustrated in Figure 2a, and leads to abnormally high fluid pressures adjacent to faults which reduce the effective normal stress, eventually reaching a maximum sustainable fluid pressure on the faults (Fig. 2b), and shifting the Mohr circle towards failure envelopes of both incohesive and cohesive faults (Fig. 2c). The intersection of porefluid pressure with maximum sustainable fluid pressure in Figure 2b and the intersection of the Mohr circle with the failure envelopes of both cohesive and incohesive faults in Figure 2c, both indicate fault failure. A represents one point on a fault surface in the 3D coordinate system of principal stresses shown in the inset in Figure 2c. The shear and effective normal stresses that act on the fault surface A can be given as equations (1) and (2) (Scotti & Cornet 1994). The horizontal distances, ΔP (A A1) and ΔP (A A2), between the pole of A and the fault-failure envelopes are the Fig. 2. (a) Schematic illustration of the changes of pore-fluid pressure in the reservoir; (b) depth pressure profile; and (c) critical conditions indicated by the Mohr circle (c). The inset in (c) shows the coordinate system for stress calculation on one element of the fault surface, with the effective maximum principal stress (S 1 ), the intermediate principal stress (S 2 ) and the least principal stress (S 3 ). Angles between principal stresses and the normal direction of the pole of the grid surface are α n, β n and γ n in degrees. The shear and effective normal stresses that act on the fault surface are indicated by the Mohr circle. ΔP A A1 and ΔP A A2 represent the maximum sustainable fluid pressures of incohesive and cohesive faults, respectively, above original pressure.

3 Reactivation risk based on strength heterogeneity maximum sustainable fluid pressures above the original pressure: s 0 n ¼ S 1 cos 2 a n þ S 2 cos 2 b n þ S 3 cos 2 g n (1) qffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi t ¼ S1 2cos2 a n þ S2 2cos2 b n þ S3 2cos2 g n (2) where s 0 n and τ are normal stress and shear stress, respectively (in MPa); S 1, S 2 and S 3 are maximum, intermediate and minimum principal stress, respectively (in MPa); and α n, β n and γ n are angles between the principal stresses and the normal of the fault surface A. For intact rock or a cohesive fault, tensile fracturing can only occur with increasing pore-fluid pressure, if differential stress (σ 1 σ 3 ) is relatively low. Shear fracturing occurs where differential stress is 6 times higher than the tensile strength, based on the Griffith Coulomb failure criterion. Hybrid tensile-shear failure (considered to be multiple jointing events rather than tensile fractures with a shear component: Engelder 1999) is predicted under conditions of 4T < (σ 1 σ 3 ) < 6T, where T is the tensile strength in MPa (Sibson 1996; Mildren et al. 2005). Only shear fracturing can occur for an incohesive and non-vertical fault or fracture. Effects of fault-rock geomechanical properties on fault reactivation For incohesive and cohesive faults in Figure 2c, the sustainable fluid pressures, ΔP (A A1) and ΔP (A A2), suggest that cohesive strength and friction coefficient are key factors in controlling the fault stability, besides the stress state itself. Numerous scientific contributions have emphasized the role of clay content in the frictional coefficient (Shimamoto & Logan 1981; Bos & Spiers 2000; Takahashi et al. 2007; Tembe et al. 2010; French et al. 2015; Giorgetti et al. 2015), and also in healing and restrengthening of the fault rocks (Bos & Spiers 2002). Published data from previous work on geomechanical properties of fault rocks show that the friction coefficient decreases monotonically with increasing clay content, with a non-linear trend (Fig. 3) (Lupini et al. 1981; Shimamoto & Logan 1981; Logan & Rauenzahn 1987; Brown et al. 2003; Takahashi et al. 2007; Crawford et al. 2008; Tembe et al. 2010). Moreover, cohesive strength decreases with decreasing granularity or increasing clay content in the absence of cementation or pressure solution (Donath 1972; Barthélémy et al. 2013). Both of these observations indicate that the clay content may strongly influence the strength of the fault rock. Furthermore, conclusions that quartz pressure solution may strengthen fault rocks have been drawn from geomechanics experiments on both natural and synthetic fault rocks (Fredrich & Evans 1992; Tenthorey et al. 2003; Yasuhara et al. 2005; Tenthorey & Cox 2006; Niemeijer et al. 2008). Thus, the test result of one type of fault rock cannot be used as representative of the geomechanical properties of an entire fault, such as the friction coefficient value of (Mildren et al. 2005; Jacquey et al. 2015) and zero cohesive strength (Ferrill et al. 1999). Therefore, it is preferred that a more refined geomechanical model of faults should be incorporated into the prediction in fault reactivation. Types and geomechanical properties of fault rocks Fault-rock types and their geomechanical properties Consideration of the weakening effect of clay content on fault rocks could make the analysis of fault reactivation analysis more accurate in zones that show variations in clay content along the fault plane. In particular, it could help locate the points of at-risk fault segments (Barthélémy et al. 2013). We apply an algorithm of clay content in faulted sedimentary rocks that is described in terms of the shale gouge ratio (SGR) (Yielding et al. 1997), and is often used as a proxy for fault-zone heterogeneity to evaluate the heterogeneous permeability of faults and to predict the hydrocarbon column height sealed by faults (Manzocchi et al. 1999; Bretan et al. 2003; Yielding 2012). Hence, we use the SGR as a guide to clay content and, therefore, as an indicator of fault-rock types. Combined with previous work on the relationship between fault-rock classification and their clay content (Sibson 1977; Wise et al. 1984; Killick 2003; Woodcock & Mort 2008), we simplified the main fault-rock types that could control the strength of the fault plane as follows: SGR 20% disaggregation zone formed in unlithified sandstone or sandstone breccias, cataclasites that are incohesive in the absence of cementation. Post-deformation quartz cementation or pressure solution may occur under conditions of burial to >90 C, which could strengthen fault rocks (Fisher & Knipe 1998; Dewhurst & Jones 2002). 20% < SGR 40% phyllosilicate-framework fault rocks that are a mixture of phyllosilicate material derived from the host sediment with sand grains or sandstone breccias (Fisher & Knipe 1998). SGR > 40% clay smears and clay breccias that have geomechanical and petrophysical properties similar to the host clay sediments (Fisher & Knipe 1998). The simplified geomechanical properties of different fault rocks, including cohesion strength and friction coefficient, used in this study come from the published data summarized in Table 1 (Dewhurst & Jones 2002, 2003; Dewhurst & Hennig 2003). We use well B12-24 to represent the bulk characteristics of the sediment column. In addition, a method for fault-seal analysis, called a triangle diagram (or juxtaposition/seal diagram) discussed in detail by Knipe (1997), is used to help in analysing the juxtapositions and fault-plane properties. As shown in the triangle diagram of well B12-24 (Fig. 4), the stratigraphy of the footwall and hanging wall are plotted using horizontal solid lines and inclined dash lines, respectively, and the juxtaposition types are shown in the triangle area with discretized SGR values. Separation of the stratigraphic units (indicated in the upper left and lower right) increases as the throw increases towards the right of the figure, along the abscissa. SGR values displayed on reservoirs are mainly throw-dependent in Figure 4. Minimum SGR values increase with increasing throw. Low SGR values are mainly present at a low throw. Following the fault-rock classification shown in Table 1, sandstone breccias, cataclasites or disaggregation zones are present at low throw values on the fault surface. However, the main fault-rock type becomes clay smears and clay breccias as throw increases. Low SGR values are shown in the target reservoir depth range of m in well B12-24 at a throw of 6 m, where self-juxtaposition of reservoirs occurs on the B816 Fault, indicating a leakage of fluid flow (Meng 2016). All SGR values are higher than 40% in the throw range of m, where upthrown reservoirs completely juxtapose to the upper regional seal across the BQ Fault, contributing to an excellent fault seal capacity. Geomechanical properties are heterogeneous, resulting from the different fault-rock types according to the SGR variations, as displayed on the two trap-bounding faults in Figure 5. This figure shows three 3D projections: the first displaying SGR; and the second and third exhibiting the frictional coefficient and cohesive strength based on the classification of the fault rocks shown in Table 1. The solid and dashed lines denote the cutoff lines of footwall and hanging-wall reservoirs, respectively. Figure 5 shows that fault surfaces with low cohesive strength and frictional coefficient correspond to high SGR values. Trapbounding segments of a fault with reservoir cap rock juxtaposition and high SGR values are likely to act as a seal for fluid flow. However, their corresponding low strength properties may lead them to be more at risk of fault reactivation. Meanwhile, abnormal

4 L. Meng et al. Fig. 3. Frictional coefficient of quartz or anhydrite mixed with various clay minerals, such as kaolinite, montmorillonite, chlorite and illite. Data are summarized from previous studies. high fluid pressure can form adjacent to sealing fault segments during gas injection, although this will not tend to occur at a leaky fault. This implies that a sealing fault may be at a higher risk of fault reactivation than a leaky fault as a result not only of the difference in seal capacity but also the difference in strength properties between them. The state of present-day in situ stress Information from the XMAC log of well K5-9 The K5-9 borehole was drilled close to the BQ Fault in 2013 with the purpose of gas injection and production, and in order to analyse the rock mechanical properties, stress magnitudes, the orientation of the maximum horizontal stress (S H ) and the pore pressure using the Cross Multipole Array Acoustic Log (XMAC Baker Atlas). A composite log of the azimuthal anisotropy map, maximum horizontal stress, fracture closure pressure, rock density, porepressure gradient, tensile strength and shale content in this well in the depth range m is give in Figure 6. The horizontal shear-wave splitting and the azimuth of the fast shear wave within the XMAC log are indicators of stress-induced anisotropy. In the seminal paper by Crampin (1978), it is proposed that shear-wave splitting is highly sensitive to the crack distribution and orientations in response to the applied stress system. In addition, the orientation of the polarization of fast shear waves generally provides information about the anisotropic symmetry and stress directions (Crampin & Peacock 2005; Zhang et al. 2008), and is approximately parallel to the orientation of S H (Gao et al. 2012). Based on this correspondence, the interpreted orientation of S H is summarized in the rose diagram on the left in Figure 7. The mean orientation of the maximum horizontal stress from the interpretation of the XMAC log in the depth interval m is 70 ± 10, which is in accordance with the ENE WSW direction of the regional stress field (Ma et al. 2002). Orientation and magnitudes of stresses and pore-fluid pressure In Figure 6, interpretation of the XMAC log provides the magnitude of the maximum horizontal principal stress and the fracture closure pressure, which approximately equals the minimum horizontal principal stress (S h ). The S H and S h magnitudes indicate gradients of 22.1 and 17.3 MPa km 1, respectively. The average pore-pressure gradient interpreted from the XMAC log is 9.3 MPa km 1 in the reservoir interval m of well K5 (Fig. 7). Vertical stress (S V ) can be obtained by integrating the density log shown in Figure 6 over depth, according to equation (3)(McGarr & Gay 1978). The relationship between the average density of 24 wells shown in Figure 1 and their corresponding depth can be given as equation (4), integration of which gives a vertical stress magnitude with a gradient of 23.1 MPa km 1 (see equation 5 and Fig. 7). The stress magnitudes clearly indicate a normal faulting regime in the BGS, such that S h < S H < S v. This result is in accordance with regional analysis of the stress-field evolution in the Huanghua Depression where the gas storage site is located (Ma et al. 2002): S V ¼ 10 6 ð r(d)g dd (3) r ¼ 0:153D þ 1961:1 (4) S V ¼ 0:0231D 3:94 (5) where S V is the vertical stress (MPa), ρ is the density of the overlying rock column (kg m 3 ), D is depth (m) and g is acceleration due to gravity (m s 2 ). Table 1. Geomechanical properties of different fault rocks, including the internal friction coefficient and cohesion strength (Dewhurst & Jones 2002, 2003; Dewhurst & Hennig 2003) Range of the SGR value (%) 0 < SGR < SGR 40 SGR > 40 Fault-rock types Disgregation zone Cataclasite Cemented catalasite Phyllosilicate fault rocks Cemented pyllosilicate fault rocks Clay smear Frictional coefficient Cohesive strength (MPa) Smectite-rich smear

5 Reactivation risk based on strength heterogeneity Fig. 4. Triangle diagram of well B12-24 in which three key throw values of 6, 140 and 290 m are highlighted by the vertical blue lines. Juxtaposition types and SGR variations are shown in the throw range of m to indicate fault-rock types and their seal capacity. The orange and pink formations represent the target reservoir and the sand layer. The grey formation denotes shale layer. Maximum sustainable pore-fluid pressure of the BGS Analysis of failure mode for the fault rocks and cap rock Differential stress (S d ) can be calculated by subtracting S h from S v, and can be expressed as equation (6): S d ¼ 0:0085D 3:966 (6) When considering fault-rock strengthening caused by quartz solution under conditions of T >90 C (Fisher & Knipe 1998), the quartz solution in fault rocks would not be present in the depth range of m based on a geothermal gradient of 30 C km 1 (Chen & Deng 1990). Thus, the cohesive strength of the fault rocks is their inherent strength without quartz cementation. In addition, the average tensile strength of cap-rock shale with a shale content of > 50% is 1.2 MPa, obtained from a tensile strength log with V sh >50%(Fig. 6). When comparing the tensile strength and differential stress at the depth of interest for all the fault-rock types mentioned above, and also for the cap rock, the minimum differential stress of 18.6 MPa is 6 times higher than the tensile strength, indicating that shear failure will occur for the two bounding faults and the intact cap-rock shale based on the failure mode (Phillips 1972), if the pore-fluid pressure is high enough. The frictional coefficient is derived from Table 1 for fault rocks and is assumed to be the same as the clay smear (0.45) for the cap-rock shale. Maximum sustainable pore-fluid pressure for the fault and cap seal As shown in the Mohr diagram in Figure 8a, the increase in pore pressure needed to cause failure (ΔP S-max ) is different for the three faultrock types because of their different geomechanical properties and different failure envelopes. Values of ΔP S-max are, in practice, calculated for all possible fault orientations at a particular depth of 2650 m and are illustrated in lower-hemisphere polar diagrams (Fig. 8a). The optimum orientation for failure on the BQ Fault is indicated by point A on the Mohr diagram. The corresponding positions in stereograms of ΔP S-max are points A1, A2 and A3, respectively, shown with small solid circles in Figure 8a. Values of ΔP S-max for A1, A2 and A3 are 19.6, 12.9 and 9.7 MPa, respectively, under conditions of the same stress state. Pronounced differences in ΔP S-max between the three points indicate that the geomechanical properties of the fault rocks play a key role in the risk of fault reactivation. In situ stress fields, in combination with fault strength data and structural geometries ascertained from 3D seismic interpretation,

6 Downloaded from at Heriot-Watt University on September 24, 2016 L. Meng et al. Fig. 5. Attribute heterogeneity displayed on the two trap-bounding faults (viewed looking from the footwall towards the NW). (a), (b) and (c) show the heterogeneity of the SGR, friction coefficient and cohesive strength, respectively. can be used to calculate ΔPS-max on 3D fault surfaces. As shown in Figure 9, the predicted risk of fault reactivation is given as ΔPS-max (in MPa) between the top and bottom of the reservoir marked on the fault surfaces. The lowest value of ΔPS-max represents the highest risk of reactivation. High-risk trap-bounding segments of the BQ Fault are located at the top of the structure, with ΔPS-max values of 9.7 MPa (corresponding to SGR values of up to 91.3% in Fig. 5). Considering the location of at-risk fault segments with respect to the trap as a whole, reactivation may lead to breaching of the entire storage area. However, faults will not be prone to reactivate if pore pressure is kept low by leakage associated with fault juxtaposition issues or where buoyancy pressure exceeds capillary pressure

7 Reactivation risk based on strength heterogeneity Fig. 6. Composite log of the azimuthal anisotropy map, maximum horizontal stress, fracture closure pressure, rock density, pore-pressure gradient, tensile strength and shale content measured and calculated in well K5-9. Red lines represent the orientations of the horizontal anisotropy, which is approximately parallel to the orientation of S H. (Mildren et al. 2002). As shown in Figure 4, reservoirs that completely juxtapose the upper regional seal across the BQ Fault contribute to an excellent fault seal capacity. Conversely, low SGR values of 10.6% are shown on the trap-bounding segment of the B816 Fault at the top of the structure, with the ΔP S-max reaching values of up to MPa (Fig. 9). This indicates that high fluid-pressure build-ups induced by gas injection at the top of the structure may lead to the BQ Fault being at more risk of reactivation than the B816 Fault. Hence, pore-fluid pressure adjacent to at-risk segments of the BQ Fault should be kept at levels below 9.7 MPa to reduce the risk of breaching the entire trap. The failure risk of an intact cap rock may be greater than that of reactivating misorientated faults where the intact cap rock is weaker (Streit & Hillis 2004). Hence, the failure risk of the intact cap rock must be considered, as well as the risk of fault reactivation, especially at the location of the injection well where the increasing pore-fluid pressure is highest. ΔP S-max for cap-rock shale, which is the horizontal minimum distance between the Mohr circle and the Fig. 7. The rose diagram on the left summarizes the results concerning the orientation of the S H of 70 ± 10 provided by the azimuthal anisotropy map (Fig. 6). The stress pressure profile on the right is based on well logging data from the BZB gas storage facility. Estimates for S H and S h are based on XMAC logging. The estimate for S V was obtained by integrating data from density logs. The curve fit is linear for in situ stress and pore-fluid pressure (P p ). The relationships between stress pressure and depth are marked on the diagram. TVD, total vertical depth.

8 L. Meng et al. Fig. 8. Mohr diagram and stereogram of ΔP S-max for (a) all fault orientations and (b) the cap rock at a depth of 2650 m. Point A in the Mohr diagram corresponds to points A1, A2 and A3 on the stereograms for different fault rocks (solid circles). ΔP S-max for fault rocks of A1, A2 and A3 are 19.6, 12.9 and 9.7 MPa, respectively, under conditions of the same stress state, and the minimum ΔP S-max for the cap rock is B1 at 13.9 MPa. failure envelope (ΔP B B1 in Fig. 8), can be given as equation (7), according to which the minimum ΔP S-max in the depth range of m is MPa. This value should be considered as the upper bound of the injection pressure under the cap seal at the corresponding depth in order to reduce the risk of gas escaping, caused by failure of the cap rock: DP B B1 ¼ S0 v þ S 0 Hmin 2 S0 v S 0 Hmin þ C cot u (7) 2 sin u where ΔP B B1 is ΔP S-max for the cap rock (in MPa), S 0 V and S0 h are the maximum and minimum effective principal stress, respectively (in MPa), θ denotes the internal friction angle in degrees, and C is the cohesive strength of fault rocks (in MPa). Discussion The simplified model that considers the clay content within fault rocks is used to analyse the effect of fault-rock types on fault reactivation, but there are still many other important factors that control the frictional coefficient and cohesive strength of fault rocks, such as clay mineral constituents, fault-rock particle size, diagenesis, cementation, geothermal conditions and effective normal stress. Hence, the quantitative model of fault strength is such a complex issue that some particular value of frictional coefficient and cohesive strength cannot be used to represent the geomechanical properties of an entire fault. In particular, more errors will occur in the evaluation of fault stability if fault-rock strength heterogeneity is not considered. The evaluation of the fault seal capacity requires the selection of more appropriate parameters Fig. 9. The predicted risk of fault reactivation is given as ΔP S-max (in MPa) in the reservoir interval marked on the fault surfaces (viewed looking from the footwall towards the NW). High-risk trap-bounding segments of the BQ Fault with ΔP S-max values of 9.7 MPa are located at the top of the structure.

9 Reactivation risk based on strength heterogeneity Fig D diagram of gas injection into a fault-bounding trap showing the failure mechanisms of the fault and cap seal, and the upper limits of the injection pressure constrained by the maximum fluid pressure that both the fault rocks and cap rock can sustain. from mechanical test results or empirical strength data of fault rocks before we can estimate fault reactivation. A database of fault-rock geomechanical properties, which could be built via mechanical tests of natural and synthetic fault gouge, is necessary not only to better constraint fault-rock geomechanical heterogeneity, but also to more precisely estimate the risk of fault reactivation. Pressure variation due to gas injection is another issue with a practical impact on increasing the upper limit of injection pressure. Better constraints on the drops in pressure from injection wells to faults could help quantify the permissible injection pressure. As shown in Figure 10, the injection pressure (P Injection ) should be lower than the maximum fluid pressure that the cap rock can sustain (ΔP S-max ) at the location of the injection well, regardless of any pressure loss in the wellhole. Furthermore, the pressure calculated by subtracting the pressure drop (ΔP d ) from the injection pressure (P Injection ) should also be lower than the maximum fluid pressure that the fault rocks can sustain (DP 0 S-max ). Both of the two conditions are essential prerequisites for preventing natural gas from escaping via hydraulic fractures in the cap rock or by fault reactivation, and for a complete workflow of risk in a fault-bounding trap with liquid injection, such as water-flooding recovery and waste injection. Conclusions This study attempts to combine the heterogeneity of geomechanical properties into a workflow to estimate the risk of fault reactivation in trap-bounding faults at the Banzhongbei gas storage site (BGS). The frictional coefficient and cohesive strength are considered in the heterogeneity of geomechanical properties. The following conclusions can be drawn: Based on the Griffith Coulomb Failure criterion, different fault-failure modes, including tensile failure, shear failure and hybrid failure, may occur under conditions of the same in situ stress field according to the strength heterogeneity of the fault rocks. Strength heterogeneity of the fault also strongly influences the predicted results of fault reactivation. It plays a key role in the estimation of the integrity of an entire fault trap. More experiments may be needed in order to establish a database of geomechanical properties of faults under more subsurface conditions. Low cohesive strength and frictional coefficient correspond to high SGR values on a fault surface, which is more likely to be a seal for across-fault fluid flow. Such faults may be more at risk of fault reactivation owing to the combination of the formation of abnormal high fluid pressures adjacent to sealing fault segments with the intrinsically lower strength of the fault. The juxtaposition seal of the BQ Fault with high SGR values makes a significant contribution to the high fluid-pressure build-ups during gas injection, and the low strength properties lead to a high risk of reactivation for the fault. As the at-risk fault segments occur at the top of the structure and control the breaching risk of the entire storage, the increased pore-fluid pressure adjacent to the BQ Fault induced by gas injection should be kept lower than 9.7 MPa. Not only will the risk of capillary leakage or fault reactivation increase during gas injection, but also the failure of the cap rock. A major difference between faults and the cap rock is that the location of the risk for the latter is focused at the position of the injection well because the highest increase in pore-fluid pressure occurs there. Thus, the injection pressure must be kept lower than MPa, based on the Griffith Coulomb failure criterion for the cap rock. Acknowledgements and Funding We thank RIPED for providing invaluable software and staff time support. The National Natural Science Foundation of China (grants , and ) and Natural Science Foundation of Heilongjiang Province of China (grant D201406) are thanked for financial support of this research. Review comments by Graham Yielding, Peter Bretan and one anonymous reviewer are much appreciated. Badley Geoscience Ltd is thanked for use of the TrapTester software. Mingxing Bai is thanked for help with editing the manuscript. 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