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Frontiers of Earth Science

Front. Earth Sci.    2015, Vol. 9 Issue (2) : 286-299
CO2 geological storage into a lateral aquifer of an offshore gas field in the South China Sea: storage safety and project design
Liang ZHANG1,*(),Dexiang LI1,Justin EZEKIEL1,Weidong ZHANG1,Honggang MI2,Shaoran REN1
1. School of Petroleum Engineering, China University of Petroleum (Huadong), Qingdao 266580, China
2. Zhanjiang Branch Company of China National Offshore Oil Corporation, Zhanjiang 524000, China
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The DF1-1 gas field, located in the western South China Sea, contains a high concentration of CO2, thus there is great concern about the need to reduce the CO2 emissions. Many options have been considered in recent years to dispose of the CO2 separated from the natural gas stream on the Hainan Island. In this study, the feasibility of CO2 storage in the lateral saline aquifer of the DF1-1 gas field is assessed, including aquifer selection and geological assessment, CO2 migration and storage safety, project design, and economic analysis. Six offshore aquifers have been investigated for CO2 geological storage. The lateral aquifer of the DF1-1 gas field has been selected as the best target for CO2 injection and storage because of its proven sealing ability, and the large storage capacity of the combined aquifer and hydrocarbon reservoir geological structure. The separated CO2 will be dehydrated on the Hainan Island and transported by a long-distance subsea pipeline in supercritical or liquid state to the central platform of the DF1-1 gas field for pressure adjustment. The CO2 will then be injected into the lateral aquifer via a subsea well-head through a horizontal well. Reservoir simulations suggest that the injected CO2 will migrate slowly upwards in the aquifer without disturbing the natural gas production. The scoping economic analysis shows that the unit storage cost of the project is approximately US$26?31/ton CO2 with the subsea pipeline as the main contributor to capital expenditure (CAPEX), and the dehydration system as the main factor of operating expenditure (OPEX).

Keywords DF1-1 gas field      CO2 storage      lateral saline aquifer      storage safety      project design     
Corresponding Author(s): Liang ZHANG   
Online First Date: 12 December 2014    Issue Date: 30 April 2015
 Cite this article:   
Liang ZHANG,Dexiang LI,Justin EZEKIEL, et al. CO2 geological storage into a lateral aquifer of an offshore gas field in the South China Sea: storage safety and project design[J]. Front. Earth Sci., 2015, 9(2): 286-299.
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Dexiang LI
Weidong ZHANG
Honggang MI
Shaoran REN
Fig.1  Location of DF1-1 gas field (left) and the six candidate aquifers (right) for CO2 storage
Saline aquifers DF1-1N DF1-1S LT19-1 LT13-1 LT1-1 DF1-1 IIdown lateral aquifer
Trapping type Lithologic Lithologic Lithologic Lithologic Lithologic Structural
Structural feature Monocline+small anticline Monocline+small anticline Monocline Monocline Monocline Anticline+faults
Sealing Uncertain Good General Good General Good
Faults No No No No Yes Yes
Buried depth/m 1,015–1,560 1,458–2,026 2,812–3,770 2,000–2,700 2,000–3,000 1,375–1,550
Bearing area/km2 115–340 28–102 107–259 66–171 257 406.5
Thickness/m 18–26 56–118 315–803 16–69 150–200 20–45
Porosity/% 18.4–40.3 8.8–28.5 22 21 10–25 12–32
Permeability/md 7–220 1–12 55–607 22 10–100 0.3–160
Heterogeneity high high weak weak weak high
Salinity/ppm 4,000 38,632 4,000 40,642 19,676 32,161
Temperature/oC 72–77 82–101 128–143 112 94 83–91
Pressure/MPa 13–15 14–20 53–69 23–24 25 14–16
Caprock lithology Mudstone+sandy shale Mudstone+silty shale Mudstone+silty shale Mudstone+silty shale Mudstone+silty shale Mudstone+silty shale
Caprock thickness/m 36–70 45–103 57 100–251 106–433 64–116
Storage capacity/Mt 330 166 7,721 292 497 163
Tab.1  Geological features of candidate offshore aquifers around DF1-1 gas field
Saline aquifers Advantages Disadvantages Rank
DF1-1N No faults; low burial depth; good combination of reservoir and caprock Uncertainties about lateral sealing; strong heterogeneity; far from Hainan Island; thin reservoir thickness 3
lDF1-1S Shallow depth of burial; good seal, some natural gas locally; sizeable reservoir thickness Too many small sandbodies; low permeability, strong heterogeneity; far from Hainan island; small storage capacity 4
LT19-1 Large storage potential; sizeable reservoir thickness; no faults Deep burial depth; over pressured formation; inadequate data; high leakage risk 6
LT13-1 Good sealing; good combination of reservoir and caprock; moderate burial depth; no faults; moderate reservoir thickness; close to Hainan Island Inadequate data 2
LT1-1 Moderate burial depth; sizeable sandbody thickness; close to Hainan Island. Existing faults; poor sealing property 5
DF1-1 IIdown lateral aquifer Proven seal; substantial good data; lower geological leakage risk; large storage capacity of associated aquifers and top depleted gas reservoirs Far from Hainan island; strong heterogeneity 1
Tab.2  Ranking of the six saline aquifers based on their advantages and disadvantages for CO2 storage
Fig.2  Structure map of Group IIdown of DF1-1 gas field. (a) Top view of Group IIdown; (b) Cross well profile
Components H2O CO2 N2 CH4
Critical pressure/MPa 22.03 7.38 3.38 4.58
Critical temperature/°C 374.0 31.1 -147.0 -82.6
Critical volume/(cm3·mol-1) 56 94 89.5 99
Molecular weight/(g·mol-1) 18.02 44.01 28.01 16.04
Henry constant/MPa 0.0684 577.8467
Partial molar volume in aqueous phase/(cm3·mol-1) 18.4964 35.9131
Diffusion coefficient in aqueous phase/(10-9 m2·s-1) 2
Diffusion coefficient in gas phase/(10-4 m2·s-1) 2
Natural gas composition/% mol 1.0 20.1 78.9
Injected CO2 gas composition/% mol 99.6139 0.0777 0.3084
Tab.3  Component properties set in fluid model
Fig.3  Curves of relative permeability (a) and capillary pressure (b) used in the simulation model
Scenarios Distance to gas cap/km Injection well type Perforating horizons Perforating length/m Fracturing pressure/MPa Note
1 No well Only gas production
2 10.4 Vertical 1–3 60 23.53 With gas production
3 10.4 Horizontal 3 400 23.53 With gas production
4 10.4 Horizontal 3 800 23.53 With gas production
5 10.4 Horizontal 3 1,200 23.53 With gas production
6 6.4 Horizontal 3 1,200 22.68 With gas production
7 2.4 Horizontal 3 1,200 22.24 With gas production
8 10.4 Horizontal 3 1,200 23.53 Without gas production
Tab.4  Designs of CO2 injection scheme
Fig.4  Injector locations in different CO2 injection scenarios (Kh contour map)
Fig.5  Distribution of CO2 gas (saturation) with time after injection in different scenarios. (a) Gas saturation distribution in Scenario 5; (b) Gas saturation distribution in Scenario 6; (c) Gas saturation distribution in Scenario 7
Fig.6  Proportions of dissolved/residual CO2 gas to the total amount of CO2 injected with time. (a) Proportion of dissolved CO2; (b) Proportion of residual CO2 gas
Fig.7  Distribution of formation pressure in different injection scenarios. (a) Distribution of formation pressure in Scenario 5; (b) Distribution of formation pressure in Scenario 6; (c) Distribution of formation pressure in Scenario 7
Fig.8  Gas saturation distributions with time in Scenarios 5 and 6 (with no trapping mechanisms). (a) Gas saturation distribution in Scenario 5; (b) Gas saturation distribution in Scenario 6
Fig.9  Sensitivity results of the well bottom-hole pressure (the fracturing pressure is 22.68 MPa). (a) Length of perforated interval; (b) Injection rate
Fig.10  Process of CO2 transportation and injection
Nodes Option 1 Option 2 Nodes Option 1 Option 2
P/MPa T/°C P/MPa T/°C P/MPa T/°C P/MPa T/°C
1 0.14 40 0.14 40 10 9 40 9 40
2 1 243.82 1 243.82 11 16 70.28
3 1 15 1 15 12 16 40
4 1 15 1 15 13 7.68 26.17 14.74 26.40
5 3.20 124.23 3.20 124.23 14 12.63 37.24 12.63 24.68
6 3.20 15 3.20 15 15 12.63 28.13 12.63 28.13
7 3.20 15 3.20 15 16 12.54 26.53 12.54 26.53
8 3.15 15 3.15 15 17 20.38 90.74 20.38 90.74
9 9 114.41 9 114.41
Tab.5  Operating parameters at key nodes in the CO2 disposal process
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