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e12-6 Table 1. Reservoir properties resulting from the petrophysical analysis Avg Jeroen van der Molen et al. Table 3. Relative permeability input parameters Avg Gross Interval (mTVT) Avg Net N/G (mTVT) (%) PHIEa (%) Avg Perm (mD) Kv/Khb (-) Parameter Value 0.05 3 0.9 0.2 0.22 6 0.4 1 Critical gas saturation (Sgcr) Corey gas exponent (Cg) Relative permeability of gas at minimum water saturation (Krg@Swmin) Minimum water saturation (Swmin) Critical water saturation (Swcr) Corey water exponent (Cw) Relative permeability of gas at residual oil saturation (Krw@Sorw) Relative permeability of water at a saturation value of unity (Krw@S = 1) Shaly sand 55 19.8 36 10 10 0.01 Sand 150 135 90 15 90 0.01 aEffective porosity. bVertical to horizontal permeability ratio. Table 2. Gas composition used in reservoir simulations Composition Methane (C1) Ethane (C2) Propane (C3) Iso-butane (iC4) Normal-butane (nC4) Iso-pentane (iC5) Normal-pentane (nC5) Hexanes (C6) Heptanes plus (C7þ) Hydrogen sulphide (H2S) Carbon dioxide (CO2) Nitrogen (N2) Concentration (mole fraction) 0.8119 0.0411 0.0155 0 0.0068 0 0.0025 0.0013 0.0009 0 0.01 0.11 Table 4. Capillary pressure (Pcgw) versus water saturation (Sw) Sw Pcgw Results 0.2 2.0 0.4 0.8 0.6 0.4 0.8 0.1 1.0 0.0 The properties are homogeneous for each layer, unless noted otherwise. The top of the model ranges from 2850 to 3280 m true vertical depth (TVD). Boundary faults are considered to be sealing, whereas internal faults are completely open to flow. Cell size of the grid is set to 50 × 50 m horizontally. As layering is proportional to the thickness, cell height varies between 3.5 and 8.5 m. At the GWC (3021 m TVD) the temperature and pressure are 102°C and 345 bar, respectively. A gas density of 0.816 kg m−3 has been used; its composition is given in Table 2. Gas formation volume factor and gas viscosity change with pressure, based on JP Spivey & WD McCain, Jr (unpublished report, 2003) and Carr et al. (1954) respectively. Formation water salinity is 200,000 ppm, with a water density of 1166 kg m−3, a viscosity of 0.4960 cP and a compressibility of 3.056E-5 1/bar. The relative permeability curves of gas and water were modelled using the Corey correla- tion, with the input values given in Table 3. Capillary pressure is given in Table 4. Rock compressibility is modelled using the Newman equation (Newman, 1973), assuming consolidated sandstones. The static gas initially in place (GIIP) of the reference model is 8.5 × 109 Sm3. The gas production well ROD-102 is completed and perforated 68 m in the upper part of the gas cap, 40 m above the GWC. Only one casing of 6-5/8′′ diameter is used in this well during the simulations. For most simulations gas production 3 −1 was fixed to 800,000Sm d , with a maximum water-to-gas ratio (WGR) of 0.00025 Sm3 Sm−3 (200 Sm3 d−1 water production per 800,000Sm3 d−1 gas production). When the simulation reached the maximum WGR, the well was shut in. The minimum BHP was constrained at 15 bar; the gas production rate is adjusted to maintain this minimum BHP threshold. In the base case scenario (without a geothermal doublet), the ROD-102 well produces gas at a rate of 800,000 Sm3 d−1 with a gradually decreasing BHP (Figure 5). The first production of water occurs halfway through 1986, nine years after the start of production. Water production rate increases exponentially, while the decrease in BHP becomes even more substantial. In 1993 ROD-102 is shut in, 16 years after the start of production, having produced 4.68 BCM of gas (Figure 5). Sensitivity to geothermal well configuration Methodology In order to test the impact of the geothermal well configuration on total gas production in the reference model, multiple scenarios are defined using varying horizontal distances between the GWC and geother- mal producer (250, 500 and 750 m; see Figure 6). Simultaneously the horizontal distance between the geothermal producer and -injector is set to alternate between 1000, 1500 and 2000 m for each aforementioned distance between the GWC and the geothermal producer (Figure 6). For each set of distances, the flow rate of the geothermal doublet is varied between 100, 150, 200 and 250 Sm3 h−1 (respectively 2400, 3600, 4800 and 6000 Sm3 d−1). A total of 24 scenarios have been simulated. The geothermal pro- ducer and injector are oriented perpendicular to the GWC and par- allel to the ROD-102 gas producer. Both geothermal wells are represented as vertical wells, both having a casing 8 500 in diameter 8 which is perforated over the entire reservoir interval. The mini- mum BHP was constrained at 100 bar; the flow rate of the geother- mal wells is adjusted to maintain this 100 bar. The results of these simulations are compared with the base case scenario of the reference model, i.e. having no active geothermal system. Downloaded from https://www.cambridge.org/core. IP address: 173.229.12.141, on 13 Jan 2021 at 23:29:16, subject to the Cambridge Core terms of use, available at https://www.cambridge.org/core/terms. https://doi.org/10.1017/njg.2019.11PDF Image | Dual hydrocarbon–geothermal energy exploitation
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