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Application of a dual tubing CO2 injection-water production horizontal well pattern for improving the CO2 storage capacity and reducing the CAPEX: A case study in Pohang basin, Korea
International Journal of Greenhouse Gas Control 90 (2019) 102813
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Application of a dual tubing CO2 injection-water production horizontal well pattern for improving the CO2 storage capacity and reducing the CAPEX: A case study in Pohang basin, Korea
T
Min Kim, Hyundon Shin
⁎
Inha University, Inha-ro 100, Incheon, 22212, Republic of Korea
ARTICLE INFO
ABSTRACT
Keywords: A dual tubing CO2-water production horizontal well (DTHW) pattern CO2storage capacity (CSC) CAPEX CCS Performance Pohang basin Korea
Water production is an efficient way of relieving pressure build-up and improving the CO2 storage capacity (CSC) in the carbon capture and storage process. The additional offshore platforms, production wells, pipelines, and pumps required for water production, however, increase the capital expenditure (CAPEX) of the project. Therefore, a CO2 injection method that can both improve the CSC and reduce the CAPEX is needed. This paper proposes a dual-tubing CO2 injection-water production horizontal well (DTHW) pattern for improving the CSC, in which CO2 is injected at the heel of the horizontal well while water is produced at the toe. The CSC and CAPEX of the proposed DTHW pattern were then compared to those of other cases in a saline aquifer in the Pohang basin, offshore Korea. The CCSPerformance (CSC to CAPEX ratio) of the proposed DTHW pattern was larger than that of a typical CO2 injection with a water production pattern for the all CO2 injection-water production rate cases. The proposed DTHW pattern showed promising results in that the maximum CSC was improved by 98.2% compared to a single vertical CO2 injection well pattern and the CAPEX was reduced by 37.1% compared to the typical CO2 injection with a water production pattern. More CAPEX might be saved if a DTHW pattern is used in an onshore platform near a power plant because an additional offshore platform and pipeline are not required.
1. Introduction The CO2 emissions of Korea reached 679.7 million tons in 2017, which was 2.45% higher than that of the previous year and was responsible for 2.03% of global CO2 emissions (world’s seventh largest CO2 emitter) (BP Global, 2018). The Korean government has taken a range of actions to reduce CO2 emissions and has established a strategy for carbon capture and storage (CCS) as one of the alternatives. The Pohang basin was selected as a site for a small-scale pilot project for CCS in 2013 (Choi et al., 2017; Park et al., 2017; Lee et al., 2017). CCS is an important technology for mitigating the global warming and climate change through the permanent storage of CO2 in saline aquifers, unminable coal beds, and depleted oil and gas reservoirs (Metz et al., 2005; Orr, 2018). Among these storage sites, deep saline aquifers provide the largest CO2 storage capacity (CSC) owing to their large worldwide volumetric capacity (Metz et al., 2005). Various research aspects, such as CO2 migration, wettability, temperature, and the capillary, residual, and solubility trapping, of CCS in deep saline aquifers have been studied. Doughty et al. (2009) investigated the long-term behavior (plume migration distance
⁎
and the time evolution of CO2 phase) of a CO2 plume injected into a deep saline formation. Al-Khdheeawi et al. (2017a) studied the impact of reservoir wettability on CO2 plume migration and residual and solubility trapping capacities, and they found that CO2-wet reservoirs had the highest CO2 vertical migration, while water-wet reservoirs best retain CO2. Gershenzon et al. (2017) analyzed the capillary trapping mechanism in heterogeneous fluvial-type reservoir during the CO2 injection period. AlKhdheeawi et al. (2018) studied the effect of wettability heterogeneity and reservoir temperature on the vertical CO2 plume migration and residual and solubility trapping capacities, and concluded that wettability heterogeneity and reservoir temperature are important factors in the CCS. The CO2 injected into a deep saline aquifer will increase the pore pressure above the initial reservoir pressure (Buscheck et al., 2012). This pressure build-up, particularly around the injection well, reduces the CO2 injectivity and storage capacity (Buscheck et al., 2012). In addition, excessive pressure build-up can cause the geological and hydrologic hazards, such as induced seismicity; fault reactivation; caprock failure; and leakage through wells, faults, and fractures (Buscheck et al., 2012; Zoback and Gorelick, 2012; Lu et al., 2012).
Corresponding author. E-mail address: [email protected] (H. Shin).
https://doi.org/10.1016/j.ijggc.2019.102813 Received 20 February 2019; Received in revised form 21 July 2019; Accepted 16 August 2019 1750-5836/ © 2019 Published by Elsevier Ltd.
International Journal of Greenhouse Gas Control 90 (2019) 102813
M. Kim and H. Shin
strategies on the enhancement of CSC and injectivity in a saline aquifer in Pohang basin, Korea. The use of additional offshore platforms, production wells, pipelines, and pumps required for water production, however, increases the capital expenditure (CAPEX) of the project (Noureldin et al., 2017; Buscheck et al., 2012). In addition, the CAPEX of the project would be increased further if the water production well is located in a deep-sea area because an offshore platform of the subsea or semi-submersible types is used. Therefore, it is necessary to develop a CO2 injection method that can improve the CSC and reduce the CAPEX. A few studies have examined the use of a horizontal well for CO2 injection. Yang et al. (2011) and Okwen et al. (2011) studied the effect of completion, orientation, location, and length of a horizontal CO2 injection well on CO2 storage and injectivity in saline aquifers, but their results showed that the use of a horizontal well does not improve the CSC significantly. Al-Khdheeawi et al. (2017b) compared the efficiency of a vertical CO2 injection well and horizontal CO2 injection well on CO2 plume migration and trapping. They concluded that the horizontal CO2 injection well reduces CO2 plume migration and its mobility compared to those of the vertical injection well. In this study, four cases of well patterns (Fig. 1) were generated and simulated, including (1) single vertical CO2 injection well pattern, (2) single horizontal CO2 injection well pattern, (3) typical CO2 injection with water production pattern, and (4) dual-tubing CO2 injection-water production horizontal well (DTHW) pattern. In addition, the CSC and CAPEX of the proposed DTHW pattern were then compared with those of other cases in a saline aquifer in Pohang basin, offshore Korea.
Nomenclature CCS carbon capture and storage CSC CO2 storage capacity CAPEX capital expenditure CCSPerformance CSC to CAPEX ratio Case (1) a single vertical CO2 injection well pattern Case (2) a single horizontal CO2 injection well pattern Case (3) a typical CO2 injection with water production pattern DTHW, Case (4) a dual-tubing CO2 injection-water production horizontal well pattern In recent years, numerous studies on pressure management through water production have been conducted to solve this problem. Buscheck et al. (2011, 2012) introduced active CO2 reservoir management, which combines water production with CO2 injection to relieve the pressure buildup, increase the CO2 injectivity, and manipulate CO2 migration. Buscheck et al. (2014, 2016) also proposed that when CO2 breakthrough occurs in a water production well, the water production well is repurposed for CO2 injection and a deep monitoring well is repurposed for water production because of the continuous CO2 injection and pressure management. Cihan et al. (2015) introduced a constrained differential evolution algorithm to solve global optimization problems involving well placement and water production. Ziemkiewicz et al. (2016) evaluated the potential for removing water to produce an additional CSC at the GreenGen site in Tianjin, China. Hwang et al. (2016) analyzed the effects of water production rates and its
Fig. 1. Four cases of well patterns for CO2 storage in this study. 2
International Journal of Greenhouse Gas Control 90 (2019) 102813
M. Kim and H. Shin
Fig. 2. Geological model constructed by detailed depth conversion and interpretation of 3D seismic data at the Korea Institute of Geoscience and Mineral Resources (KIGAM) (Choi et al., 2017 and Lee et al., 2017).
Fig. 3. 3D cross-section of the reservoir model showing the depth (m) and faults.
2. Methodology
the depth of the aquifer varied from 611 m to 866 m due to the concave geological structure. The corner point grid was used to model the study area. The model is consisted of 95, 152, and 36 grids in the x-, y-, and zdirections, respectively. Each grid block was approximately 20 m in the x- and y-directions. Two target reservoirs were placed in the geological model. The vertical thickness of reservoir A (upper aquifer) and reservoir B (lower aquifer) was approximately 10 m and 14 m, respectively, and both were divided vertically into 12 layers (reservoir A = layer 1 to 12 and reservoir B = layer 25 to 36). The faults located in Pohang basin were included in the geological model, such as fault A (WF2), fault B (EF2), and fault C (EF1) (Park et al., 2017; Lee et al., 2017). In addition, it was assumed that the top, bottom, and lateral boundaries of the aquifers were closed because there is no geological information of southwest and northeast (Choi et al., 2017; Park et al., 2017, 2019). The numerical simulations were conducted using the GEM reservoir simulator by the Computer Modelling Group (CMG’s GEM) for modelling CO2 storage in a saline aquifer (CMG’s, 2017; Kumar et al., 2005; Nghiem et al., 2010; Wriedt et al., 2014). Table 1 lists the properties of the reservoir model for the numerical simulation. The reservoir pressure was calculated assuming a formation pressure gradient of 10 MPa/ km. As shown Fig. 4, the relative permeability and capillary pressure of gas/liquid used in simulation were based on the special core analysis (SCAL) results of Donghae-1 gas field in the southeastern Sea of Korea
2.1. Design of well patterns for CO2 storage Numerical simulations were performed for four well patterns (Fig. 1), which involved injecting CO2 into a saline aquifer in Pohang basin, offshore Korea as follows: (1) single vertical CO2 injection well pattern, (2) single horizontal CO2 injection well pattern, (3) typical CO2 injection with water production pattern, and (4) DTHW pattern. This study proposes a DTHW pattern for improving the CSC and decreasing the CAPEX, in which CO2 is injected at the heel of the horizontal well while water is produced at the toe of the horizontal well (Fig. 1d). The CSC of a DTHW pattern is expected to be larger than those of cases (1) and (2) because of absence of pressure management through water production. In addition, it can be expected that the CAPEX of a DTHW pattern would be lower than that of case (3) because of the reduced costs of an offshore platform and pipeline. 2.2. Model description and numerical simulation The geological model of a saline aquifer in Pohang basin, offshore Korea (Fig. 2), was constructed using Petrel software by the Korea Institute of Geoscience and Mineral Resources (KIGAM) (Choi et al., 2017; Park et al., 2017; Lee et al., 2017; Park et al., 2019). As shown Fig. 3, 3
International Journal of Greenhouse Gas Control 90 (2019) 102813
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breakthrough, and the minimum bottom hole pressure at water production was assumed to be 7 MPa. The CO2 injection and storage periods were 50 years in total. The perforations of the vertical well of cases (1) and (3) were set in all layers. Because the layer 33 is in low porosity zone such as flow barrier, the horizontal wells of cases (2) and (4) were located vertically on the layer 32, which has good reservoir properties in reservoir B (Fig. 5). In addition, the perforations of dual tubing of case (4) were set to 50 m each at the heel and toe of the horizontal well (Fig. 5). Also, the tubing size at the heel and toe of the horizontal well was assumed to be 1.5 and 1.0 in., respectively.
Table 1 Properties of the reservoir model for numerical simulation. Reservoir Properties
Reservoir A (Upper Aquifer)
Between reservoir A and reservoir B
Reservoir B (Lower Aquifer)
Porosity
0.010–0.340 (Average: 0.157) 0.0001–38.69 (Average: 6.75)
0.010–0.213 (Average: 0.071) 0.0001–1.43 (Average: 0.085) 0.1
0.010–0.284 (Average: 0.204) 0.0001–11.23 (Average: 3.24)
Vertical permeability (md) Vertical-horizontal permeability ratio Reservoir temperature (°C) Pressure at the 750 m (Mpa) Salinity (mol NaCl/kg H2O)
55
2.3. Well placements of various well pattern cases
7.5
In this study, the location of the offshore platform and well for CO2 injection of all the well pattern cases was assumed to be same, and the length and direction of the horizontal well or the distance between injection/production wells and their location were designed, as shown in Figs. 6 through 8. The CO2 injection well of case (1) used a vertical well drilled for the CCS in the Pohang basin, offshore Korea (Figs. 2 and 3) (Choi et al., 2017; Park et al., 2017; Lee et al., 2017). As shown Fig. 6, a single horizontal CO2 injection well pattern was designed in 6 scenarios according to the length and direction of the horizontal well and faults. The horizontal length of cases (2A), (2B), and (2C) was 500 m, and that of cases (2D), (2E), and (2 F) was 700 m. In this study, the toe of the horizontal well of case (2) was assumed to be in the same position as the water production well in case (3). Furthermore, the
0.1
(Kim et al., 2018). The maximum residual gas saturation was assumed to be 0.4 for the hysteresis effect in gas relative permeability in this study (Juanes et al., 2006; Nghiem et al., 2010). The CO2 and water were injected/produced concurrently at a constant flow rate of 20, 35, 50, or 65 tons/d. The CO2 injection was stopped when the injection pressure reached 14 MPa or when the reactivation pressure of faults A, B, and C reached 13 MPa (Park et al., 2017; Lee et al., 2017). In addition, the water production was stopped when the gas production rate exceeded 10 m3/d due to CO2
Fig. 4. Relative permeability and capillary pressure curves of simulation model (Kim et al., 2018).
Fig. 5. J–K plane of simulation model for applying a DTHW pattern (case (4)). 4
International Journal of Greenhouse Gas Control 90 (2019) 102813
M. Kim and H. Shin
Fig. 6. Various lengths and directions of a single horizontal CO2 injection well pattern (case (2)): horizontal well length of 500 m (left) and horizontal well length of 700 m (right).
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International Journal of Greenhouse Gas Control 90 (2019) 102813
M. Kim and H. Shin
Fig. 7. Various locations and distances of a typical CO2 injection with water production pattern (case (3)): distance between injection/production wells of 500 m (left) and distance between injection/production wells of 700 m (right).
horizontal well length in case (2) was assumed to be equal to the length of the horizontal well with the dual tubing in case (4). Therefore, the various locations/directions and distances/lengths of cases (3) and (4) were designed in the same pattern, as shown in Figs. 7 and 8.
2.4. Performance measures To compare the various well patterns, the following indicator based on the CSC and CAPEX was implemented: 6
International Journal of Greenhouse Gas Control 90 (2019) 102813
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Fig. 8. Various lengths and directions of a DTHW pattern (case (4)): horizontal well length of 500 m (left) and horizontal well length of 700 m (right).
CCSPerformance =
CSC CAPEX
(kton). The CAPEXs of all the well pattern cases were calculated considering the estimated costs of the offshore platforms, drilling, pipelines, and pumps (Table 2). The costs of the horizontal injection well and horizontal well with dual tubing were estimated using the
(1)
where CSC has the same meaning as the cumulative injection gas 7
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Table 2 Estimated costs of offshore platforms, drilling, pipelines, and pumps for CO2 storage projects. Symbol
Description and cost ($MM)
Comments
a
A B C D E F G
Offshore platform only Vertical injection wellb Horizontal injection well (length: 1200 m)b Horizontal injection well (length: 500 m) Horizontal injection well (length: 700 m) Vertical production wellb Horizontal alternating water/gas (WAG) injection well (length: 1200 m)b
16.15 7.9 12.9 10 10.84 6.7 14
H
Horizontal well with dual tubing (CO2 injection-water production) (length: 1200 m) Horizontal well with dual tubing (CO2 injection-water production) (length: 500 m) Horizontal well with dual tubing (CO2 injection-water production) (length: 700 m) CO2 transport pipelineb Water transport pipelineb CO2 and water transport pipeline with dual tubing CO2 pumping station at injection siteb Water pumping station at injection siteb Water pumping station at disposal siteb
15
– C = B + (cost per horizontal length × 1200 m) Cost per horizontal length = 0.42 ($MM/100 m) D = B + (0.42 × 5) = 10.00 ($MM) E = B + (0.42 × 7) = 10.84 ($MM) – Assume that the cost of horizontal well with dual tubing (H) is similar to horizontal alternating water/gas (WAG) injection well (G) H = B + (cost per horizontal length with dual tubing × 1200 m) Cost per horizontal length with dual tubing = 0.59 ($MM/100 m)
10.85
I = B + (0.59 × 5) = 10.85 ($MM)
12.03
J = B + (0.59 × 7) = 12.03 ($MM)
37.6 14.3 40 5.3 4.9 4.2
Assume that the length of CO2 and water transport pipeline with dual tubing (M) is equal to the length of CO2 transport pipeline (K) Cost of M is assumed considering the K and L – – –
I J K L M N O P a b
Kim and Choi (2017). Noureldin et al. (2017).
Table 3 Simulation results and calculated CAPEX for a single vertical CO2 injection well pattern. Well Patterns
CO2 Inj. Rate (ton/ d)
CO2 Inj. Period (years)
Calculated CAPEX using estimated cost with symbol in Table 2 ($MM)
CSC (kton)
CCSPerformance (kton/$MM)
Case (1)
20 35 50 65
17.30 9.94 6.96 5.38
CAPEX1 = A + B + K + N
126.29 126.94 127.09 127.75
1.886 1.896 1.898 1.908
CSC (kton)
CCSPerformance (kton/$MM)
66.95
Table 4 Simulation results and calculated CAPEX for a single horizontal CO2 injection well pattern. Well Patterns
CO2 Inj. Rate (ton/ d)
CO2 Inj. Period (years)
Calculated CAPEX using estimated cost with symbol in Table 2 ($MM)
Case (2A)
20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65
16.12 8.85 5.94 4.34 16.21 8.94 5.94 4.34 16.21 8.94 5.94 4.34 16.29 8.94 5.94 4.34 16.21 8.94 5.94 4.34 16.21 8.94 5.94 4.34
CAPEX2_500m = A+D + K + N
69.05
CAPEX2_700m = A + E + K + N
69.89
Case (2B)
Case (2C)
Case (2D)
Case (2E)
Case (2F)
following equation: (a) cost of the horizontal injection well = cost of the vertical injection well + (cost per horizontal length × horizontal length) and (b) cost of the horizontal well with dual tubing = cost of the vertical injection well + (cost per horizontal length with dual
117.68 113.12 108.40 103.02 118.30 114.21 108.40 103.02 118.30 114.21 108.40 103.02 118.92 114.21 108.40 103.02 118.30 114.21 108.40 103.02 118.30 114.21 108.40 103.02
1.704 1.638 1.570 1.492 1.713 1.654 1.570 1.492 1.713 1.654 1.570 1.492 1.702 1.634 1.551 1.474 1.693 1.634 1.551 1.474 1.693 1.634 1.551 1.474
tubing × horizontal length). The processing cost of produced gas was not considered because the volume of produced gas during CO2 breakthrough was small in this study.
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Table 5 Simulation results and calculated CAPEX for a typical CO2 injection with a water production pattern. Well Patterns
CO2 Inj./ Water Prod. Rate (ton/d)
CO2 Inj. Period (years)
Time of CO2 breakthrough (years)
Calculated CAPEX using estimated cost with symbol in Table 2 ($MM)
Case (3A)
20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65
20.01 11.51 8.09 6.31 21.56 11.95 8.34 6.40 20.14 11.85 8.38 6.62 32.82 17.28 11.80 8.98 32.05 16.72 11.44 8.73 24.11 14.03 10.09 7.90
4.53 2.60 1.82 1.41 7.19 3.36 2.15 1.65 4.86 3.12 2.36 1.92 28.02 12.59 7.97 5.89 26.64 11.59 7.49 5.53 11.90 6.94 5.21 4.17
CAPEX3 = 2 × A + B + F + K + L + N + O + P
Case (3B)
Case (3C)
Case (3D)
Case (3E)
Case (3 F)
113.20
CSC (kton)
CCSPerformance (kton/$MM)
146.08 147.02 147.65 149.67 157.36 152.60 152.16 151.84 146.96 151.41 152.97 156.94 239.53 220.78 215.28 213.11 233.96 213.58 208.85 207.15 176.00 179.25 184.20 187.36
1.290 1.299 1.304 1.322 1.390 1.348 1.344 1.341 1.298 1.338 1.351 1.386 2.116 1.950 1.902 1.883 2.067 1.887 1.845 1.830 1.555 1.583 1.627 1.655
Table 6 Simulation results and calculated CAPEX for a DTHW pattern. Well Patterns
CO2 Inj./Water Prod. Rate (ton/d)
CO2 Inj. Period (years)
Time of CO2 breakthrough (years)
Calculated CAPEX using estimated cost with symbol in Table 2 ($MM)
Case (4A)
20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65
20.95 11.37 7.68 5.60 19.86 10.94 7.43 5.52 19.10 10.77 7.43 5.35 34.69 16.12 10.77 8.09 31.89 15.53 10.60 8.09 22.90 12.90 9.09 6.85
7.94 4.00 2.69 2.00 6.18 3.31 2.27 1.80 4.92 3.02 2.28 1.77 31.13 11.62 7.57 5.55 26.47 10.69 7.24 5.77 11.37 6.51 4.87 3.87
CAPEX4_500m = A+I + M + N + O + P
81.40
CAPEX4_700m = A + J + M + N + O + P
82.58
Case (4B)
Case (4C)
Case (4D)
Case (4E)
Case (4F)
3. Results
CSC (kton)
CCSPerformance (kton/ $MM)
152.90 145.21 140.25 132.86 144.96 139.79 135.60 130.84 139.38 137.62 135.60 127.00 253.23 205.97 196.59 191.94 232.76 198.39 193.51 191.94 167.15 164.74 165.95 162.63
1.878 1.784 1.723 1.632 1.781 1.717 1.666 1.607 1.712 1.691 1.666 1.560 3.066 2.494 2.381 2.324 2.819 2.402 2.343 2.324 2.024 1.995 2.010 1.969
(1) with case (2) revealed a vertical well for CO2 injection to be more effective than a horizontal well considering the CSC and CAPEX (Tables 3 and 4). In addition, as shown in Tables 3, 5 and 6, the CCSPerformance for case (1) was higher than that of cases (3A), (3B), (3C), (3F), (4A), (4B), and (4C). Therefore, the unoptimized pressure-management well pattern through water production may less effective than case (1).
3.1. Single vertical CO2 injection well pattern- case (1) For case (1), the CO2 injection rate was assumed to be 20, 35, 50, and 65 ton/d. Table 3 lists the simulation r esults and calculated CAPEX for case (1) related to the CO2 injection rate. As the CO2 injection rate for case (1) increased, the CSC increased slightly, and the CO2 injection period decreased because the pressure of fault A quickly reached the reactivation pressure of 13 Mpa. The maximum CCSPerformance for case (1) was 1.908 at a CO2 injection rate of 65 ton/d. A comparison of case
3.2. Single horizontal CO2 injection well pattern- case (2) The CO2 injection rate for case (2) was assumed to be 20, 35, 50, and 65 ton/d. Table 4 lists simulation results and calculated CAPEX for 9
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contact area than the vertical well and reduces CO2 plume migration and CO2 mobility compared to the vertical well (Al-Khdheeawi et al., 2017b). The difference in CSC according to the assumed lengths and directions of case (2) was not large (Table 4). For case (2), the maximum CCSPerformance was 1.713 at a horizontal length of 500 m, direction B and C, and the CO2 injection rate was 20 tons/d. Moreover, the CCSPerformance of case (2) was the lowest of all cases. 3.3. Typical CO2 injection with a water production pattern- case (3) For case (3), the CO2 injection/water production rate was assumed to be 20, 35, 50, and 65 tons/d. Table 5 lists the simulation results and calculated CAPEX for case (3) related to the CO2 injection/water production rate and various locations and distances. As the CO2 injection/ water production rate for case (3) was increased, the CSC of cases (3A), (3C), and (3F) increased, as in case (1), but the CSC of cases (3B), (3D), and (3E) decreased. Because this geological model is inclined from the south to the north, as shown Fig. 3, the location of the CO2 injection/ water production wells in cases (3B), (3D), and (3E) can be interpreted as a typical CO2 injection with a water production pattern in a dipping reservoir. In addition, after CO2 breakthrough, the gas production rate at the water production well for cases (3B), (3D), and (3E) increased slowly compared to the gas rate of the other cases (Fig. 10) because a dipping reservoir has the effect of delaying the movement of a CO2 plume to the water production well (Buscheck et al., 2012). In addition, as the CO2 injection/water production rate for cases (3B), (3D), and (3E) decreases constantly, the period until the gas production rate at the water production well exceeds 10 m3/d is exponentially longer (Fig. 10). Therefore, the CSC of cases (3B), (3D), and (3E) increases with decreasing CO2 injection/water production rate for the above reasons. The maximum CCSPerformance for case (3) was 2.116 at a 700 m distance between injection/production wells, direction D, and a CO2
Fig. 9. Comparison of the well bottom-hole pressure for case (1), case (2D), and CO2 injection rate of 20 and 50 ton/d.
case (2) related to the CO2 injection rate and various lengths and directions. As the CO2 injection rate for case (2) was increased, the CSC decreased, which is opposite to that observed with case (1) because the pressure build-up of case (2) was faster than that of case (1), as shown in Fig. 9. The reason is that the horizontal CO2 injection well has a large
Fig. 10. Comparison of the gas production rate at the water production well for case (3) and CO2 injection rate: 500 m between the injection/production wells (top) and 700 m between the injection/production wells (bottom). 10
International Journal of Greenhouse Gas Control 90 (2019) 102813
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Fig. 11. Effect of the CO2 injection/water production rate for various directions of cases (3) and (4) on the CSC.
Fig. 12. Effect of the CO2 injection/water production rate for the various directions of cases (3) and (4) on CCSPerformance.
injection/water production rate of 20 ton/d.
is used in an onshore platform near a power plant, more CAPEX might be saved because an offshore platform and pipeline are not required, as shown in Fig. 13.
3.4. DTHW pattern-case (4) The CO2 injection/water production rate for case (4) was assumed to be 20, 35, 50, and 65 ton/d. Table 6 lists the simulation results and calculated CAPEX for case (4) related to the CO2 injection/water production rate and various lengths and directions. As the CO2 injection/ water production rate for case (4) is increased, the CSC decreases, as in case (2). A comparison of the CSCs of cases (3) and (4) revealed the CSC of case (3) to be larger than that of case (4) at a CO2 injection/water production rate of 35 ton/d or more (Fig. 11). On the other hand, for the CCSPerformance, considering the CAPEX, case (3) was smaller than case (4) at all CO2 injection/water production rates (Fig. 12). In addition, if the CO2 injection/water production rate was 50 ton/d, the CSC of case (4D) would be 91.3% of that of case (3D), but the CAPEX of case (4D) was $30.62 MM lower than that of case (3D). The maximum CCSPerformance for case (4) was 3.066 at a horizontal length of 700 m, direction D, and a CO2 injection rate of 20 ton/d. The proposed DTHW pattern is recommended because the maximum CSC of case (4D) has been improved by 98.2% compared to case (1) and the CAPEX was reduced by 37.1% compared to case (3). In addition, if a DTHW pattern
4. Conclusions The proposed DTHW pattern for improving CSC and reducing CAPEX was studied in a saline aquifer in Pohang basin, offshore Korea. The following conclusions were drawn. This paper proposed a DTHW pattern for improving the CSC and reducing the CAPEX, in which CO2 is injected at the heel of the horizontal well while water is produced at the toe. The CSC of the proposed DTHW pattern was expected to be larger than that of a single well pattern because of absence of pressure management through water production. In addition, the proposed DTHW pattern has the advantages of cost reduction compared to a typical CO2 injection with a water production pattern. A comparison of the single well patterns (vertical and horizontal well) revealed a vertical well for CO2 injection to be more effective than a horizontal well, considering the CSC and CAPEX. In addition, CCSPerformance for a single vertical CO2 injection well pattern was higher than that of cases (3A), (3B), (3C), (3 F), (4A), (4B), and (4C). 11
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M. Kim and H. Shin
Fig. 13. DTHW pattern for CO2 storage in offshore saline aquifer using onshore platform.
Therefore, the unoptimized pressure-management well pattern through water production may less effective than a single vertical CO2 injection well pattern. A comparison of the pressure-management well patterns through water production (vertical well and horizontal well with dual tubing) revealed the CCSPerformance of a DTHW pattern to be larger than that of a typical CO2 injection with a water production pattern at all CO2 injection/water production rates. If the CO2 injection/water production rate is 50 ton/d and in the D direction, the CSC of a DTHW pattern is 91.3% of that of a typical CO2 injection with a water production pattern. In contrast, the CAPEX of a DTHW pattern is $30.62 MM lower than that of a typical CO2 injection with a water production pattern. The proposed DTHW pattern showed promising results in that the maximum CSC of DTHW pattern had been improved by 98.2% compared to a single vertical CO2 injection well pattern and the CAPEX was reduced by 37.1% compared to a typical CO2 injection with a water production pattern. More CAPEX might be saved if a DTHW pattern is used in an onshore platform near a power plant because an additional offshore platform and pipeline are not required.
2017.01.012. Al-Khdheeawi, E.A., Vialle, S., Barifcani, A., Sarmadivaleh, M., Iglauer, S., 2017b. Influence of injection well configuration and rock wettability on CO2 plume behaviour and CO2 trapping capacity in heterogeneous reservoirs. J. Nat. Gas Sci. Eng. 43, 190–206. https://doi.org/10.1016/j.jngse.2017.03.016. Al-Khdheeawi, E.A., Vialle, S., Barifcani, A., Sarmadivaleh, M., Iglauer, S., 2018. Effect of wettability heterogeneity and reservoir temperature on CO2 storage efficiency in deep saline aquifers. Int. J. Greenh. Gas Control. 68, 216–229. https://doi.org/10. 1016/j.ijggc.2017.11.016. Global, B.P., 2018. BP Statistical Review of World Energy. June. . https://www.bp.com/ content/dam/bp/en/corporate/pdf/energy-economics/statistical-review/bp-statsreview-2018-full-report.pdf. Buscheck, T.A., et al., 2011. Combining brine extraction, desalination, and residual-brine reinjection with CO2 storage in saline formations: implications for pressure management, capacity, and risk mitigation. Energy Procedia 4, 4283–4290. https://doi. org/10.1016/j.egypro.2011.02.378. Buscheck, T.A., et al., 2012. Active CO2 reservoir management for carbon storage: analysis of operational strategies to relieve pressure buildup and improve injectivity. Int. J. Greenh. Gas Control. 6, 230–245. https://doi.org/10.1016/j.ijggc.2011.11.007. Buscheck, T.A., et al., 2014. Pre-injection brine production for managing pressure in compartmentalized CO2 storage reservoirs. Energy Procedia 63 (C). https://doi.org/ 10.1016/j.egypro.2014.11.565. Buscheck, T.A., et al., 2016. Pre-injection brine production in CO2storage reservoirs: An approach to augment the development, operation, and performance of CCS while generating water. Int. J. Greenh. Gas Control. 54, 499–512. https://doi.org/10.1016/ j.ijggc.2016.04.018. Choi, B.Y., Shinn, Y.J., Park, Y.C., Park, J., Kwon, Y.K., Kim, K.Y., 2017. Simulation of CO2 injection in a small-scale pilot site in the Pohang Basin, Korea: effect of dissolution rate of chlorite on mineral trapping. Int. J. Greenh. Gas Control. 59, 1–12. https://doi.org/10.1016/j.ijggc.2017.02.001. Cihan, A., Birkholzer, J.T., Bianchi, M., 2015. Optimal well placement and brine extraction for pressure management during CO2 sequestration. Int. J. Greenh. Gas Control. 42, 175–187. https://doi.org/10.1016/j.ijggc.2015.07.025. CMG’s, G.E.M., 2017. User’s Guide (Version 2017.10). Computer Modelling Group Ltd., Calgary, AB, Canada. Doughty, C., Myer, L.R., Oldenburg, C.M., 2009. Predictions of long-term behavior of a large-volume pilot test for CO2 geological storage in a saline formation in the Central Valley. California. Energy Procedia 1 (1), 3291–3298. https://doi.org/10.1016/j. egypro.2009.02.115. Gershenzon, N.I., Ritzi Jr., R.W., Dominic, D.F., Mehnert, E., Okwen, R.T., 2017. Capillary trapping of CO2 in heterogeneous reservoirs during the injection period. Int. J. Greenh. Gas Control. 59, 13–23. https://doi.org/10.1016/j.ijggc.2017.02.002. Hwang, J., Baek, S., Lee, H., Jung, W., Sung, W., 2016. Evaluation of CO2 storage capacity and injectivity using a relief well in a saline aquifer in Pohang basin, offshore South Korea. Geosci. J. 20 (2), 239–245. https://doi.org/10.1007/s12303-015-0038-x. Juanes, R., Spiteri, E.J., Orr Jr., F.M., Blunt, M.J., 2006. Impact of relative permeability hysteresis on geological CO2 storage. Water Resour. Res. 42 (12). https://doi.org/10. 1029/2005WR004806. Kim, J., Choi, J., 2017. A preliminary estimation of CCS injection cost with recycling injection equipments. J. Korean Soc. Miner. Energy Resour. Eng. 54 (5), 533–540. https://doi.org/10.12972/ksmer.2017.54.5.533. Kim, N., et al., 2018. The stability assessment of an aquifer in Pohang Yeongil Bay due to CO2 injection. J. Eng. Geol. 28 (2), 183–192. https://doi.org/10.9720/kseg.2018.2. 183.
Declaration of Competing Interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper. Acknowledgements This study was supported by the Demonstration-scale Offshore CO2 Storage Project in Pohang Basin, Korea (20162010201980) and Development of State-of-the-Art Characterization and Assessment Methods for Shale Gas Plays in Western Canada (20178510030880) by The Ministry of Trade, Industry and Energy (MOTIE). The research was conducted through the Department of Energy Resources Engineering at Inha University, Korea. The authors also thank Schlumberger for granting the Petrel Software. References Al-Khdheeawi, E.A., Vialle, S., Barifcani, A., Sarmadivaleh, M., Iglauer, S., 2017a. Impact of reservoir wettability and heterogeneity on CO2-plume migration and trapping capacity. Int. J. Greenh. Gas Control. 58, 142–158. https://doi.org/10.1016/j.ijggc.
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M. Kim and H. Shin Kumar, A., Noh, M.H., Ozah, R.C., Pope, G.A., Bryant, S.L., Sepehrnoori, K., Lake, L.W., 2005. Reservoir simulation of CO2 storage in aquifers. Spe J. 10 (3), 336–348. https://doi.org/10.2118/89343-PA. Lee, H., Shinn, Y.J., Ong, S.H., Woo, S.W., Park, K.G., Lee, T.J., Moon, S.W., 2017. Fault reactivation potential of an offshore CO2 storage site, Pohang Basin, South Korea. J. Pet. Sci. Eng. 152, 427–442. https://doi.org/10.1016/j.petrol.2017.03.014. Lu, C., Sun, Y., Buscheck, T.A., Hao, Y., White, J.A., Chiaramonte, L., 2012. Uncertainty quantification of CO2 leakage through a fault with multiphase and nonisothermal effects. Greenh. Gases Sci. Technol. 2 (6), 445–459. https://doi.org/10.1002/ghg. 1309. Metz, B., Davidson, O., De Coninck, H.C., Loos, M., Meyer, L.A., 2005. IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage. Prepared by Working Group III of the Intergovernmental Panel on Climate Change, Cambridge, United Kingdom and New York, NY, USA, pp. 442. https://www.ipcc.ch/pdf/special-reports/srccs/ srccs_wholereport.pdf. Nghiem, L., Shrivastava, V., Kohse, B., Hassam, M., Yang, C., 2010. Simulation and optimization of trapping processes for CO2 storage in saline aquifers. J. Can. Pet. Technol. 49 (8), 15–22. https://doi.org/10.2118/139429-PA. Noureldin, M., Allinson, W.G., Cinar, Y., Baz, H., 2017. Coupling risk of storage and economic metrics for CCS projects. Int. J. Greenh. Gas Control. 60, 59–73. https:// doi.org/10.1016/j.ijggc.2017.03.008. Okwen, R., Stewart, M., Cunningham, J., 2011. Effect of well orientation (vertical vs. horizontal) and well length on the injection of CO2 in deep saline aquifers. Transp.
Porous Media 90 (1), 219–232. https://doi.org/10.1007/s11242-010-9686-5. Orr Jr., F.M., 2018. Carbon capture, utilization, and storage: an update. Spe J. 23 (6), 2–444. https://doi.org/10.2118/194190-PA. Park, Y.C., Shinn, Y.J., Lee, H., Choi, B.Y., 2017. Assessing CO2 Storage Capacity of a Steeply Dipping, Fault Bounded Aquifer and Effect of Impurity in CO2 Stream. Energy Procedia 114, 4735–4740. https://doi.org/10.1016/j.egypro.2017.03.1611. Park, Y.C., Kim, S., Lee, J.H., Shinn, Y.J., 2019. Effect of reducing irreducible water saturation in a near-well region on CO2 injectivity and storage capacity. Int. J. Greenh. Gas Control. 86, 134–145. https://doi.org/10.1016/j.ijggc.2019.04.014. Wriedt, J., Deo, M., Han, W.S., Lepinski, J., 2014. A methodology for quantifying risk and likelihood of failure for carbon dioxide injection into deep saline reservoirs. Int. J. Greenh. Gas Control. 20, 196–211. https://doi.org/10.1016/j.ijggc.2013.10.021. Yang, F., Bai, B., Dunn-Norman, S., 2011. Modeling the effects of completion techniques and formation heterogeneity on CO2 sequestration in shallow and deep saline aquifers. Environ. Earth Sci. 64 (3), 841–849. https://doi.org/10.1007/s12665-0110908-0. Ziemkiewicz, P., et al., 2016. Opportunities for increasing CO2 storage in deep, saline formations by active reservoir management and treatment of extracted formation water: case study at the GreenGen IGCC facility, Tianjin, PR China. Int. J. Greenh. Gas Control. 54, 538–556. https://doi.org/10.1016/j.ijggc.2016.07.039. Zoback, M.D., Gorelick, S.M., 2012. Earthquake triggering and large-scale geologic storage of carbon dioxide. Proc. Natl. Acad. Sci. 109 (26), 10164–10168. https://doi. org/10.1073/pnas.1202473109.
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Application of a dual tubing CO2 injection-water production horizontal well pattern for improving the CO2 storage capacity and reducing the CAPEX: A case study in Pohang basin, Korea
T
Min Kim, Hyundon Shin
⁎
Inha University, Inha-ro 100, Incheon, 22212, Republic of Korea
ARTICLE INFO
ABSTRACT
Keywords: A dual tubing CO2-water production horizontal well (DTHW) pattern CO2storage capacity (CSC) CAPEX CCS Performance Pohang basin Korea
Water production is an efficient way of relieving pressure build-up and improving the CO2 storage capacity (CSC) in the carbon capture and storage process. The additional offshore platforms, production wells, pipelines, and pumps required for water production, however, increase the capital expenditure (CAPEX) of the project. Therefore, a CO2 injection method that can both improve the CSC and reduce the CAPEX is needed. This paper proposes a dual-tubing CO2 injection-water production horizontal well (DTHW) pattern for improving the CSC, in which CO2 is injected at the heel of the horizontal well while water is produced at the toe. The CSC and CAPEX of the proposed DTHW pattern were then compared to those of other cases in a saline aquifer in the Pohang basin, offshore Korea. The CCSPerformance (CSC to CAPEX ratio) of the proposed DTHW pattern was larger than that of a typical CO2 injection with a water production pattern for the all CO2 injection-water production rate cases. The proposed DTHW pattern showed promising results in that the maximum CSC was improved by 98.2% compared to a single vertical CO2 injection well pattern and the CAPEX was reduced by 37.1% compared to the typical CO2 injection with a water production pattern. More CAPEX might be saved if a DTHW pattern is used in an onshore platform near a power plant because an additional offshore platform and pipeline are not required.
1. Introduction The CO2 emissions of Korea reached 679.7 million tons in 2017, which was 2.45% higher than that of the previous year and was responsible for 2.03% of global CO2 emissions (world’s seventh largest CO2 emitter) (BP Global, 2018). The Korean government has taken a range of actions to reduce CO2 emissions and has established a strategy for carbon capture and storage (CCS) as one of the alternatives. The Pohang basin was selected as a site for a small-scale pilot project for CCS in 2013 (Choi et al., 2017; Park et al., 2017; Lee et al., 2017). CCS is an important technology for mitigating the global warming and climate change through the permanent storage of CO2 in saline aquifers, unminable coal beds, and depleted oil and gas reservoirs (Metz et al., 2005; Orr, 2018). Among these storage sites, deep saline aquifers provide the largest CO2 storage capacity (CSC) owing to their large worldwide volumetric capacity (Metz et al., 2005). Various research aspects, such as CO2 migration, wettability, temperature, and the capillary, residual, and solubility trapping, of CCS in deep saline aquifers have been studied. Doughty et al. (2009) investigated the long-term behavior (plume migration distance
⁎
and the time evolution of CO2 phase) of a CO2 plume injected into a deep saline formation. Al-Khdheeawi et al. (2017a) studied the impact of reservoir wettability on CO2 plume migration and residual and solubility trapping capacities, and they found that CO2-wet reservoirs had the highest CO2 vertical migration, while water-wet reservoirs best retain CO2. Gershenzon et al. (2017) analyzed the capillary trapping mechanism in heterogeneous fluvial-type reservoir during the CO2 injection period. AlKhdheeawi et al. (2018) studied the effect of wettability heterogeneity and reservoir temperature on the vertical CO2 plume migration and residual and solubility trapping capacities, and concluded that wettability heterogeneity and reservoir temperature are important factors in the CCS. The CO2 injected into a deep saline aquifer will increase the pore pressure above the initial reservoir pressure (Buscheck et al., 2012). This pressure build-up, particularly around the injection well, reduces the CO2 injectivity and storage capacity (Buscheck et al., 2012). In addition, excessive pressure build-up can cause the geological and hydrologic hazards, such as induced seismicity; fault reactivation; caprock failure; and leakage through wells, faults, and fractures (Buscheck et al., 2012; Zoback and Gorelick, 2012; Lu et al., 2012).
Corresponding author. E-mail address: [email protected] (H. Shin).
https://doi.org/10.1016/j.ijggc.2019.102813 Received 20 February 2019; Received in revised form 21 July 2019; Accepted 16 August 2019 1750-5836/ © 2019 Published by Elsevier Ltd.
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strategies on the enhancement of CSC and injectivity in a saline aquifer in Pohang basin, Korea. The use of additional offshore platforms, production wells, pipelines, and pumps required for water production, however, increases the capital expenditure (CAPEX) of the project (Noureldin et al., 2017; Buscheck et al., 2012). In addition, the CAPEX of the project would be increased further if the water production well is located in a deep-sea area because an offshore platform of the subsea or semi-submersible types is used. Therefore, it is necessary to develop a CO2 injection method that can improve the CSC and reduce the CAPEX. A few studies have examined the use of a horizontal well for CO2 injection. Yang et al. (2011) and Okwen et al. (2011) studied the effect of completion, orientation, location, and length of a horizontal CO2 injection well on CO2 storage and injectivity in saline aquifers, but their results showed that the use of a horizontal well does not improve the CSC significantly. Al-Khdheeawi et al. (2017b) compared the efficiency of a vertical CO2 injection well and horizontal CO2 injection well on CO2 plume migration and trapping. They concluded that the horizontal CO2 injection well reduces CO2 plume migration and its mobility compared to those of the vertical injection well. In this study, four cases of well patterns (Fig. 1) were generated and simulated, including (1) single vertical CO2 injection well pattern, (2) single horizontal CO2 injection well pattern, (3) typical CO2 injection with water production pattern, and (4) dual-tubing CO2 injection-water production horizontal well (DTHW) pattern. In addition, the CSC and CAPEX of the proposed DTHW pattern were then compared with those of other cases in a saline aquifer in Pohang basin, offshore Korea.
Nomenclature CCS carbon capture and storage CSC CO2 storage capacity CAPEX capital expenditure CCSPerformance CSC to CAPEX ratio Case (1) a single vertical CO2 injection well pattern Case (2) a single horizontal CO2 injection well pattern Case (3) a typical CO2 injection with water production pattern DTHW, Case (4) a dual-tubing CO2 injection-water production horizontal well pattern In recent years, numerous studies on pressure management through water production have been conducted to solve this problem. Buscheck et al. (2011, 2012) introduced active CO2 reservoir management, which combines water production with CO2 injection to relieve the pressure buildup, increase the CO2 injectivity, and manipulate CO2 migration. Buscheck et al. (2014, 2016) also proposed that when CO2 breakthrough occurs in a water production well, the water production well is repurposed for CO2 injection and a deep monitoring well is repurposed for water production because of the continuous CO2 injection and pressure management. Cihan et al. (2015) introduced a constrained differential evolution algorithm to solve global optimization problems involving well placement and water production. Ziemkiewicz et al. (2016) evaluated the potential for removing water to produce an additional CSC at the GreenGen site in Tianjin, China. Hwang et al. (2016) analyzed the effects of water production rates and its
Fig. 1. Four cases of well patterns for CO2 storage in this study. 2
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Fig. 2. Geological model constructed by detailed depth conversion and interpretation of 3D seismic data at the Korea Institute of Geoscience and Mineral Resources (KIGAM) (Choi et al., 2017 and Lee et al., 2017).
Fig. 3. 3D cross-section of the reservoir model showing the depth (m) and faults.
2. Methodology
the depth of the aquifer varied from 611 m to 866 m due to the concave geological structure. The corner point grid was used to model the study area. The model is consisted of 95, 152, and 36 grids in the x-, y-, and zdirections, respectively. Each grid block was approximately 20 m in the x- and y-directions. Two target reservoirs were placed in the geological model. The vertical thickness of reservoir A (upper aquifer) and reservoir B (lower aquifer) was approximately 10 m and 14 m, respectively, and both were divided vertically into 12 layers (reservoir A = layer 1 to 12 and reservoir B = layer 25 to 36). The faults located in Pohang basin were included in the geological model, such as fault A (WF2), fault B (EF2), and fault C (EF1) (Park et al., 2017; Lee et al., 2017). In addition, it was assumed that the top, bottom, and lateral boundaries of the aquifers were closed because there is no geological information of southwest and northeast (Choi et al., 2017; Park et al., 2017, 2019). The numerical simulations were conducted using the GEM reservoir simulator by the Computer Modelling Group (CMG’s GEM) for modelling CO2 storage in a saline aquifer (CMG’s, 2017; Kumar et al., 2005; Nghiem et al., 2010; Wriedt et al., 2014). Table 1 lists the properties of the reservoir model for the numerical simulation. The reservoir pressure was calculated assuming a formation pressure gradient of 10 MPa/ km. As shown Fig. 4, the relative permeability and capillary pressure of gas/liquid used in simulation were based on the special core analysis (SCAL) results of Donghae-1 gas field in the southeastern Sea of Korea
2.1. Design of well patterns for CO2 storage Numerical simulations were performed for four well patterns (Fig. 1), which involved injecting CO2 into a saline aquifer in Pohang basin, offshore Korea as follows: (1) single vertical CO2 injection well pattern, (2) single horizontal CO2 injection well pattern, (3) typical CO2 injection with water production pattern, and (4) DTHW pattern. This study proposes a DTHW pattern for improving the CSC and decreasing the CAPEX, in which CO2 is injected at the heel of the horizontal well while water is produced at the toe of the horizontal well (Fig. 1d). The CSC of a DTHW pattern is expected to be larger than those of cases (1) and (2) because of absence of pressure management through water production. In addition, it can be expected that the CAPEX of a DTHW pattern would be lower than that of case (3) because of the reduced costs of an offshore platform and pipeline. 2.2. Model description and numerical simulation The geological model of a saline aquifer in Pohang basin, offshore Korea (Fig. 2), was constructed using Petrel software by the Korea Institute of Geoscience and Mineral Resources (KIGAM) (Choi et al., 2017; Park et al., 2017; Lee et al., 2017; Park et al., 2019). As shown Fig. 3, 3
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breakthrough, and the minimum bottom hole pressure at water production was assumed to be 7 MPa. The CO2 injection and storage periods were 50 years in total. The perforations of the vertical well of cases (1) and (3) were set in all layers. Because the layer 33 is in low porosity zone such as flow barrier, the horizontal wells of cases (2) and (4) were located vertically on the layer 32, which has good reservoir properties in reservoir B (Fig. 5). In addition, the perforations of dual tubing of case (4) were set to 50 m each at the heel and toe of the horizontal well (Fig. 5). Also, the tubing size at the heel and toe of the horizontal well was assumed to be 1.5 and 1.0 in., respectively.
Table 1 Properties of the reservoir model for numerical simulation. Reservoir Properties
Reservoir A (Upper Aquifer)
Between reservoir A and reservoir B
Reservoir B (Lower Aquifer)
Porosity
0.010–0.340 (Average: 0.157) 0.0001–38.69 (Average: 6.75)
0.010–0.213 (Average: 0.071) 0.0001–1.43 (Average: 0.085) 0.1
0.010–0.284 (Average: 0.204) 0.0001–11.23 (Average: 3.24)
Vertical permeability (md) Vertical-horizontal permeability ratio Reservoir temperature (°C) Pressure at the 750 m (Mpa) Salinity (mol NaCl/kg H2O)
55
2.3. Well placements of various well pattern cases
7.5
In this study, the location of the offshore platform and well for CO2 injection of all the well pattern cases was assumed to be same, and the length and direction of the horizontal well or the distance between injection/production wells and their location were designed, as shown in Figs. 6 through 8. The CO2 injection well of case (1) used a vertical well drilled for the CCS in the Pohang basin, offshore Korea (Figs. 2 and 3) (Choi et al., 2017; Park et al., 2017; Lee et al., 2017). As shown Fig. 6, a single horizontal CO2 injection well pattern was designed in 6 scenarios according to the length and direction of the horizontal well and faults. The horizontal length of cases (2A), (2B), and (2C) was 500 m, and that of cases (2D), (2E), and (2 F) was 700 m. In this study, the toe of the horizontal well of case (2) was assumed to be in the same position as the water production well in case (3). Furthermore, the
0.1
(Kim et al., 2018). The maximum residual gas saturation was assumed to be 0.4 for the hysteresis effect in gas relative permeability in this study (Juanes et al., 2006; Nghiem et al., 2010). The CO2 and water were injected/produced concurrently at a constant flow rate of 20, 35, 50, or 65 tons/d. The CO2 injection was stopped when the injection pressure reached 14 MPa or when the reactivation pressure of faults A, B, and C reached 13 MPa (Park et al., 2017; Lee et al., 2017). In addition, the water production was stopped when the gas production rate exceeded 10 m3/d due to CO2
Fig. 4. Relative permeability and capillary pressure curves of simulation model (Kim et al., 2018).
Fig. 5. J–K plane of simulation model for applying a DTHW pattern (case (4)). 4
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Fig. 6. Various lengths and directions of a single horizontal CO2 injection well pattern (case (2)): horizontal well length of 500 m (left) and horizontal well length of 700 m (right).
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Fig. 7. Various locations and distances of a typical CO2 injection with water production pattern (case (3)): distance between injection/production wells of 500 m (left) and distance between injection/production wells of 700 m (right).
horizontal well length in case (2) was assumed to be equal to the length of the horizontal well with the dual tubing in case (4). Therefore, the various locations/directions and distances/lengths of cases (3) and (4) were designed in the same pattern, as shown in Figs. 7 and 8.
2.4. Performance measures To compare the various well patterns, the following indicator based on the CSC and CAPEX was implemented: 6
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Fig. 8. Various lengths and directions of a DTHW pattern (case (4)): horizontal well length of 500 m (left) and horizontal well length of 700 m (right).
CCSPerformance =
CSC CAPEX
(kton). The CAPEXs of all the well pattern cases were calculated considering the estimated costs of the offshore platforms, drilling, pipelines, and pumps (Table 2). The costs of the horizontal injection well and horizontal well with dual tubing were estimated using the
(1)
where CSC has the same meaning as the cumulative injection gas 7
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Table 2 Estimated costs of offshore platforms, drilling, pipelines, and pumps for CO2 storage projects. Symbol
Description and cost ($MM)
Comments
a
A B C D E F G
Offshore platform only Vertical injection wellb Horizontal injection well (length: 1200 m)b Horizontal injection well (length: 500 m) Horizontal injection well (length: 700 m) Vertical production wellb Horizontal alternating water/gas (WAG) injection well (length: 1200 m)b
16.15 7.9 12.9 10 10.84 6.7 14
H
Horizontal well with dual tubing (CO2 injection-water production) (length: 1200 m) Horizontal well with dual tubing (CO2 injection-water production) (length: 500 m) Horizontal well with dual tubing (CO2 injection-water production) (length: 700 m) CO2 transport pipelineb Water transport pipelineb CO2 and water transport pipeline with dual tubing CO2 pumping station at injection siteb Water pumping station at injection siteb Water pumping station at disposal siteb
15
– C = B + (cost per horizontal length × 1200 m) Cost per horizontal length = 0.42 ($MM/100 m) D = B + (0.42 × 5) = 10.00 ($MM) E = B + (0.42 × 7) = 10.84 ($MM) – Assume that the cost of horizontal well with dual tubing (H) is similar to horizontal alternating water/gas (WAG) injection well (G) H = B + (cost per horizontal length with dual tubing × 1200 m) Cost per horizontal length with dual tubing = 0.59 ($MM/100 m)
10.85
I = B + (0.59 × 5) = 10.85 ($MM)
12.03
J = B + (0.59 × 7) = 12.03 ($MM)
37.6 14.3 40 5.3 4.9 4.2
Assume that the length of CO2 and water transport pipeline with dual tubing (M) is equal to the length of CO2 transport pipeline (K) Cost of M is assumed considering the K and L – – –
I J K L M N O P a b
Kim and Choi (2017). Noureldin et al. (2017).
Table 3 Simulation results and calculated CAPEX for a single vertical CO2 injection well pattern. Well Patterns
CO2 Inj. Rate (ton/ d)
CO2 Inj. Period (years)
Calculated CAPEX using estimated cost with symbol in Table 2 ($MM)
CSC (kton)
CCSPerformance (kton/$MM)
Case (1)
20 35 50 65
17.30 9.94 6.96 5.38
CAPEX1 = A + B + K + N
126.29 126.94 127.09 127.75
1.886 1.896 1.898 1.908
CSC (kton)
CCSPerformance (kton/$MM)
66.95
Table 4 Simulation results and calculated CAPEX for a single horizontal CO2 injection well pattern. Well Patterns
CO2 Inj. Rate (ton/ d)
CO2 Inj. Period (years)
Calculated CAPEX using estimated cost with symbol in Table 2 ($MM)
Case (2A)
20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65
16.12 8.85 5.94 4.34 16.21 8.94 5.94 4.34 16.21 8.94 5.94 4.34 16.29 8.94 5.94 4.34 16.21 8.94 5.94 4.34 16.21 8.94 5.94 4.34
CAPEX2_500m = A+D + K + N
69.05
CAPEX2_700m = A + E + K + N
69.89
Case (2B)
Case (2C)
Case (2D)
Case (2E)
Case (2F)
following equation: (a) cost of the horizontal injection well = cost of the vertical injection well + (cost per horizontal length × horizontal length) and (b) cost of the horizontal well with dual tubing = cost of the vertical injection well + (cost per horizontal length with dual
117.68 113.12 108.40 103.02 118.30 114.21 108.40 103.02 118.30 114.21 108.40 103.02 118.92 114.21 108.40 103.02 118.30 114.21 108.40 103.02 118.30 114.21 108.40 103.02
1.704 1.638 1.570 1.492 1.713 1.654 1.570 1.492 1.713 1.654 1.570 1.492 1.702 1.634 1.551 1.474 1.693 1.634 1.551 1.474 1.693 1.634 1.551 1.474
tubing × horizontal length). The processing cost of produced gas was not considered because the volume of produced gas during CO2 breakthrough was small in this study.
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Table 5 Simulation results and calculated CAPEX for a typical CO2 injection with a water production pattern. Well Patterns
CO2 Inj./ Water Prod. Rate (ton/d)
CO2 Inj. Period (years)
Time of CO2 breakthrough (years)
Calculated CAPEX using estimated cost with symbol in Table 2 ($MM)
Case (3A)
20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65
20.01 11.51 8.09 6.31 21.56 11.95 8.34 6.40 20.14 11.85 8.38 6.62 32.82 17.28 11.80 8.98 32.05 16.72 11.44 8.73 24.11 14.03 10.09 7.90
4.53 2.60 1.82 1.41 7.19 3.36 2.15 1.65 4.86 3.12 2.36 1.92 28.02 12.59 7.97 5.89 26.64 11.59 7.49 5.53 11.90 6.94 5.21 4.17
CAPEX3 = 2 × A + B + F + K + L + N + O + P
Case (3B)
Case (3C)
Case (3D)
Case (3E)
Case (3 F)
113.20
CSC (kton)
CCSPerformance (kton/$MM)
146.08 147.02 147.65 149.67 157.36 152.60 152.16 151.84 146.96 151.41 152.97 156.94 239.53 220.78 215.28 213.11 233.96 213.58 208.85 207.15 176.00 179.25 184.20 187.36
1.290 1.299 1.304 1.322 1.390 1.348 1.344 1.341 1.298 1.338 1.351 1.386 2.116 1.950 1.902 1.883 2.067 1.887 1.845 1.830 1.555 1.583 1.627 1.655
Table 6 Simulation results and calculated CAPEX for a DTHW pattern. Well Patterns
CO2 Inj./Water Prod. Rate (ton/d)
CO2 Inj. Period (years)
Time of CO2 breakthrough (years)
Calculated CAPEX using estimated cost with symbol in Table 2 ($MM)
Case (4A)
20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65 20 35 50 65
20.95 11.37 7.68 5.60 19.86 10.94 7.43 5.52 19.10 10.77 7.43 5.35 34.69 16.12 10.77 8.09 31.89 15.53 10.60 8.09 22.90 12.90 9.09 6.85
7.94 4.00 2.69 2.00 6.18 3.31 2.27 1.80 4.92 3.02 2.28 1.77 31.13 11.62 7.57 5.55 26.47 10.69 7.24 5.77 11.37 6.51 4.87 3.87
CAPEX4_500m = A+I + M + N + O + P
81.40
CAPEX4_700m = A + J + M + N + O + P
82.58
Case (4B)
Case (4C)
Case (4D)
Case (4E)
Case (4F)
3. Results
CSC (kton)
CCSPerformance (kton/ $MM)
152.90 145.21 140.25 132.86 144.96 139.79 135.60 130.84 139.38 137.62 135.60 127.00 253.23 205.97 196.59 191.94 232.76 198.39 193.51 191.94 167.15 164.74 165.95 162.63
1.878 1.784 1.723 1.632 1.781 1.717 1.666 1.607 1.712 1.691 1.666 1.560 3.066 2.494 2.381 2.324 2.819 2.402 2.343 2.324 2.024 1.995 2.010 1.969
(1) with case (2) revealed a vertical well for CO2 injection to be more effective than a horizontal well considering the CSC and CAPEX (Tables 3 and 4). In addition, as shown in Tables 3, 5 and 6, the CCSPerformance for case (1) was higher than that of cases (3A), (3B), (3C), (3F), (4A), (4B), and (4C). Therefore, the unoptimized pressure-management well pattern through water production may less effective than case (1).
3.1. Single vertical CO2 injection well pattern- case (1) For case (1), the CO2 injection rate was assumed to be 20, 35, 50, and 65 ton/d. Table 3 lists the simulation r esults and calculated CAPEX for case (1) related to the CO2 injection rate. As the CO2 injection rate for case (1) increased, the CSC increased slightly, and the CO2 injection period decreased because the pressure of fault A quickly reached the reactivation pressure of 13 Mpa. The maximum CCSPerformance for case (1) was 1.908 at a CO2 injection rate of 65 ton/d. A comparison of case
3.2. Single horizontal CO2 injection well pattern- case (2) The CO2 injection rate for case (2) was assumed to be 20, 35, 50, and 65 ton/d. Table 4 lists simulation results and calculated CAPEX for 9
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contact area than the vertical well and reduces CO2 plume migration and CO2 mobility compared to the vertical well (Al-Khdheeawi et al., 2017b). The difference in CSC according to the assumed lengths and directions of case (2) was not large (Table 4). For case (2), the maximum CCSPerformance was 1.713 at a horizontal length of 500 m, direction B and C, and the CO2 injection rate was 20 tons/d. Moreover, the CCSPerformance of case (2) was the lowest of all cases. 3.3. Typical CO2 injection with a water production pattern- case (3) For case (3), the CO2 injection/water production rate was assumed to be 20, 35, 50, and 65 tons/d. Table 5 lists the simulation results and calculated CAPEX for case (3) related to the CO2 injection/water production rate and various locations and distances. As the CO2 injection/ water production rate for case (3) was increased, the CSC of cases (3A), (3C), and (3F) increased, as in case (1), but the CSC of cases (3B), (3D), and (3E) decreased. Because this geological model is inclined from the south to the north, as shown Fig. 3, the location of the CO2 injection/ water production wells in cases (3B), (3D), and (3E) can be interpreted as a typical CO2 injection with a water production pattern in a dipping reservoir. In addition, after CO2 breakthrough, the gas production rate at the water production well for cases (3B), (3D), and (3E) increased slowly compared to the gas rate of the other cases (Fig. 10) because a dipping reservoir has the effect of delaying the movement of a CO2 plume to the water production well (Buscheck et al., 2012). In addition, as the CO2 injection/water production rate for cases (3B), (3D), and (3E) decreases constantly, the period until the gas production rate at the water production well exceeds 10 m3/d is exponentially longer (Fig. 10). Therefore, the CSC of cases (3B), (3D), and (3E) increases with decreasing CO2 injection/water production rate for the above reasons. The maximum CCSPerformance for case (3) was 2.116 at a 700 m distance between injection/production wells, direction D, and a CO2
Fig. 9. Comparison of the well bottom-hole pressure for case (1), case (2D), and CO2 injection rate of 20 and 50 ton/d.
case (2) related to the CO2 injection rate and various lengths and directions. As the CO2 injection rate for case (2) was increased, the CSC decreased, which is opposite to that observed with case (1) because the pressure build-up of case (2) was faster than that of case (1), as shown in Fig. 9. The reason is that the horizontal CO2 injection well has a large
Fig. 10. Comparison of the gas production rate at the water production well for case (3) and CO2 injection rate: 500 m between the injection/production wells (top) and 700 m between the injection/production wells (bottom). 10
International Journal of Greenhouse Gas Control 90 (2019) 102813
M. Kim and H. Shin
Fig. 11. Effect of the CO2 injection/water production rate for various directions of cases (3) and (4) on the CSC.
Fig. 12. Effect of the CO2 injection/water production rate for the various directions of cases (3) and (4) on CCSPerformance.
injection/water production rate of 20 ton/d.
is used in an onshore platform near a power plant, more CAPEX might be saved because an offshore platform and pipeline are not required, as shown in Fig. 13.
3.4. DTHW pattern-case (4) The CO2 injection/water production rate for case (4) was assumed to be 20, 35, 50, and 65 ton/d. Table 6 lists the simulation results and calculated CAPEX for case (4) related to the CO2 injection/water production rate and various lengths and directions. As the CO2 injection/ water production rate for case (4) is increased, the CSC decreases, as in case (2). A comparison of the CSCs of cases (3) and (4) revealed the CSC of case (3) to be larger than that of case (4) at a CO2 injection/water production rate of 35 ton/d or more (Fig. 11). On the other hand, for the CCSPerformance, considering the CAPEX, case (3) was smaller than case (4) at all CO2 injection/water production rates (Fig. 12). In addition, if the CO2 injection/water production rate was 50 ton/d, the CSC of case (4D) would be 91.3% of that of case (3D), but the CAPEX of case (4D) was $30.62 MM lower than that of case (3D). The maximum CCSPerformance for case (4) was 3.066 at a horizontal length of 700 m, direction D, and a CO2 injection rate of 20 ton/d. The proposed DTHW pattern is recommended because the maximum CSC of case (4D) has been improved by 98.2% compared to case (1) and the CAPEX was reduced by 37.1% compared to case (3). In addition, if a DTHW pattern
4. Conclusions The proposed DTHW pattern for improving CSC and reducing CAPEX was studied in a saline aquifer in Pohang basin, offshore Korea. The following conclusions were drawn. This paper proposed a DTHW pattern for improving the CSC and reducing the CAPEX, in which CO2 is injected at the heel of the horizontal well while water is produced at the toe. The CSC of the proposed DTHW pattern was expected to be larger than that of a single well pattern because of absence of pressure management through water production. In addition, the proposed DTHW pattern has the advantages of cost reduction compared to a typical CO2 injection with a water production pattern. A comparison of the single well patterns (vertical and horizontal well) revealed a vertical well for CO2 injection to be more effective than a horizontal well, considering the CSC and CAPEX. In addition, CCSPerformance for a single vertical CO2 injection well pattern was higher than that of cases (3A), (3B), (3C), (3 F), (4A), (4B), and (4C). 11
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Fig. 13. DTHW pattern for CO2 storage in offshore saline aquifer using onshore platform.
Therefore, the unoptimized pressure-management well pattern through water production may less effective than a single vertical CO2 injection well pattern. A comparison of the pressure-management well patterns through water production (vertical well and horizontal well with dual tubing) revealed the CCSPerformance of a DTHW pattern to be larger than that of a typical CO2 injection with a water production pattern at all CO2 injection/water production rates. If the CO2 injection/water production rate is 50 ton/d and in the D direction, the CSC of a DTHW pattern is 91.3% of that of a typical CO2 injection with a water production pattern. In contrast, the CAPEX of a DTHW pattern is $30.62 MM lower than that of a typical CO2 injection with a water production pattern. The proposed DTHW pattern showed promising results in that the maximum CSC of DTHW pattern had been improved by 98.2% compared to a single vertical CO2 injection well pattern and the CAPEX was reduced by 37.1% compared to a typical CO2 injection with a water production pattern. More CAPEX might be saved if a DTHW pattern is used in an onshore platform near a power plant because an additional offshore platform and pipeline are not required.
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Declaration of Competing Interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper. Acknowledgements This study was supported by the Demonstration-scale Offshore CO2 Storage Project in Pohang Basin, Korea (20162010201980) and Development of State-of-the-Art Characterization and Assessment Methods for Shale Gas Plays in Western Canada (20178510030880) by The Ministry of Trade, Industry and Energy (MOTIE). The research was conducted through the Department of Energy Resources Engineering at Inha University, Korea. The authors also thank Schlumberger for granting the Petrel Software. References Al-Khdheeawi, E.A., Vialle, S., Barifcani, A., Sarmadivaleh, M., Iglauer, S., 2017a. Impact of reservoir wettability and heterogeneity on CO2-plume migration and trapping capacity. Int. J. Greenh. Gas Control. 58, 142–158. https://doi.org/10.1016/j.ijggc.
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