- Email: [email protected]
Geological characterization and numerical modelling of CO2 storage in an aquifer structure offshore Guangdong Province, China
Available online at www.sciencedirect.com
ScienceDirect Availableonline onlineatatwww.sciencedirect.com www.sciencedirect.com Available Energy Procedia 00 (2018) 000–000
ScienceDirect ScienceDirect
www.elsevier.com/locate/procedia
Energy Procedia Procedia 00 154(2017) (2018)000–000 48–53 Energy www.elsevier.com/locate/procedia
Applied Energy Symposium and Forum, Carbon Capture, Utilization and Storage, CCUS 2018, 27–29 June 2018, Perth, Australia
Geological The characterization and numerical modelling of CO2 storage 15th International Symposium on District Heating and Cooling in an aquifer structure offshore Guangdong Province, China Assessing the feasibility of using the heat demand-outdoor a b , Yunfan Zhanga, *, Di Zhoua, heat Xi Liang temperature Pengchun functionLifor a long-term district demand forecast a
CAS Key Laboratory of Ocean and Marginal Sea Geology, South China Sea Institute of Oceanology, Guangzhou, 510301 China a,b,c a a b c c b UK-China (Guangdong) CCUS Centre, Guangzhou, 510663, China
I. Andrić
*, A. Pina , P. Ferrão , J. Fournier ., B. Lacarrière , O. Le Corre
a
IN+ Center for Innovation, Technology and Policy Research - Instituto Superior Técnico, Av. Rovisco Pais 1, 1049-001 Lisbon, Portugal b Veolia Recherche & Innovation, 291 Avenue Dreyfous Daniel, 78520 Limay, France c Département Systèmes Énergétiques et Environnement - IMT Atlantique, 4 rue Alfred Kastler, 44300 Nantes, France Abstract
The Lufeng (LF) 2-1 structure, which is the largest anticlinal structure developed in the Zhu I depression of the Pearl River Mouth Basin, offers high-quality source-sink matching with onshore CO2 emissions. In this paper, a 3D model using the Abstract TOUGH2/ECO2N tool was developed based on typical formation parameters obtained from a review of well and seismic structural data. Numerical results indicated that doubling the injection quantity does not result in a doubling of the CO2 District heating the literature as one of the most effective for decreasing the The CO2solutions plumes remain within the distribution, whichnetworks suggestsare the commonly presence ofaddressed nonlinear in variations between the two variables. greenhouse gas trap emissions from the building require investments which are returned through thethan heat LF2-1 structural based on injection rates ofsector. eitherThese 1 Mt/ysystems or 2 Mt/y. The high maximum increase in formation pressure is less Due tois the climateformation conditionspressure. and building renovation policies, demand inof the future could decrease, 2sales. bars, which 0.9%changed of the primary Therefore, the reservoir and heat seal properties LF2-1 are optimal, which prolonging the investment return period. suggests that the prospect of injecting and storing a total of 40 Mt of CO2 is good. Overall, the LF2-1 may be used as a suitable The main of this paper is to assess the feasibility using the heat demand – outdoor temperature heat demand deep saline aquifers. Additionally, the findings function can guideforsite selection offshore sitescope for large-scale storage of industrial CO2 in of forecast. inThe district of Alvalade, located in (Portugal), was used as a case study. The district is consisted of 665 decisions Guangdong Province for offshore COLisbon geological storage demonstrations. 2 buildings that vary in both construction period and typology. Three weather scenarios (low, medium, high) and three district ©renovation 2018 The Published by Elsevier Ltd. intermediate, deep). To estimate the error, obtained heat demand values were scenarios wereLtd. developed (shallow, Copyright © Authors. 2018 Elsevier All rights reserved. This is an open access article under the heat CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/) compared with results from a dynamic demand previously developed and validated the authors. Selection and peer-review under responsibility of the model, scientific committee of the Applied Energy by Symposium and Forum, Carbon Selection and peer-review under responsibility of the scientific committee of theofApplied Energy andsome Forum, Carbon The results showedand thatStorage, when only weather change is considered, the margin error could be Symposium acceptable for applications Capture, Utilization CCUS 2018. Capture, Utilization and Storage, CCUS 2018. (the error in annual demand was lower than 20% for all weather scenarios considered). However, after introducing renovation scenarios,CO the error value increased up to 59.5% (depending on the weather and renovation scenarios combination considered). Keywords: 2 storage, saline aquifer, numerical modelling, LF2-1 structrure, offshore Guangdong Province; The value of slope coefficient increased on average within the range of 3.8% up to 8% per decade, that corresponds to the decrease in the number of heating hours of 22-139h during the heating season (depending on the combination of weather and scenarios considered). On the other hand, function intercept increased for 7.8-12.7% per decade (depending on the 1.renovation Introduction coupled scenarios). suggested used to and modify the function for creates the scenarios considered, and ) capture storage (CCS) parameters technologies the opportunity to The developmentThe of values Carbon dioxidecould (CO2be improve the accuracy of heat demand estimations. isolated CO of emission from human activities for long geological time periods [1]. It might, therefore, widely be 2
© 2017 The Authors. Published by Elsevier Ltd. Peer-review under responsibility of the Scientific Committee of The 15th International Symposium on District Heating and Cooling. * Corresponding author. Tel.: +86-20-89024583; fax: +86-20-84180401. E-mail address: [email protected] Keywords: Heat demand; Forecast; Climate change
1876-6102 Copyright © 2018 Elsevier Ltd. All rights reserved. Selection and peer-review under responsibility of the scientific committee of the Applied Energy Symposium and Forum, Carbon Capture, Utilization and Storage, CCUS 2018. 1876-6102 © 2017 The Authors. Published by Elsevier Ltd. 1876-6102 © 2018 The Authors. Published by Elsevier Ltd. Peer-review under responsibility of the Scientific Committee of The 15th International Symposium on District Heating and Cooling. This is an open access article under the CC BY-NC-ND license (https://creativecommons.org/licenses/by-nc-nd/4.0/) Selection and peer-review under responsibility of the scientific committee of the Applied Energy Symposium and Forum, Carbon Capture, Utilization and Storage, CCUS 2018. 10.1016/j.egypro.2018.11.009
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Pengchun Li et al. / Energy Procedia 154 (2018) 48–53 Pengchun Li/ Energy Procedia 00 (2018) 000–000
49
regarded as an effective and potential approach for large greenhouse gas emitters [2, 3]. From a research point of view, CCS technology is feasible and has already been successfully applied in many projects worldwide such as America, Canada, Germany, Netherland, Norway, Australia, etc.[4]. CCS would be a strategically important technology for Guangdong to achieve large-scale emission reductions now and in the foreseeable future[5]. Unfortunately, the CO2 storage potential of onshore basins in Guangdong is very limited [6-8]. The Pearl River Mouth Basin contains high-quality reservoirs that are large enough to be used for CO2 storage [5, 7]. Most importantly, the large-scale CO2 point sources in Guangdong are predominantly located in the coast areas. Structures in the Pearl River Mouth Basin are located approximately 100-200 km from the coastlines of Guangdong Province, and thus source-sink matching conditions in this area are best. Therefore, it may be possible for Guangdong Province to achieve CO2 emission reductions through the use of Pearl River Mouth Basin storage sites for offshore geological storage. For highly targeted investigation of storage sites within the Zhu I Depression of the Pearl River Mouth Basin, the large Lufeng (LF) 2-1 structure was selected as the subject of this study. 1. Structural characterization LF2-1 is located in the northwest section of the lower uplift in the centre of the Lufeng Sag (Fig.1a), which is part of the Zhu I Depression. The structure is largely controlled by a NW-trending fault. As a result, 3 “lifts in the subsag”, designated A, B and C (Fig. 1b) developed. Lift A is a faulted anticline involving Horizons T50, T60 and T70. The entrapment involving Horizons T50 and T60 of the Zhuhai Formation measures 214.21 km2 by 115 m thick. The reservoir itself is 57 m thick and exhibits a porosity of 20.74%. The trap involving Horizons T60 and T70 measures 100.11 km2 by 110 m thick; this reservoir is 152 m thick and exhibits a porosity of 25.6%. The entrapment of zones beneath Horizon T70 measures 140.34 km2 by 150 m thick; this reservoir is 226 m thick and exhibits a porosity of 22.18%. Being a fault block with a relatively small entrapment area, Lift B spans Horizons T60 and T70. Only one exploratory well, i.e., Well LF2-1-1, currently extends into the LF2-1. This well exhibits no evidence of natural gas, and water is the primary fluid. Based on a preliminary analysis, the source rocks of Enping Formation beneath the structure are immature, and the structure is located far from effective Wenchang Formation source rocks. As a result, natural gas has not migrated from the Wenchang Formation to the LF2-1 structural trap. The reservoir zone within the structure is thus a water-bearing layer. (a)
(b)
Fig. 1. Structural diagram of Lufeng sag of LF2-1 developed (a) and structural contour map of LF2-1 (b). Locations of Well LF2-1-1 and profiles are shown in Fig.2 (from CNOOC).
The reservoirs of LF2-1 consist predominantly of medium- and coarse-grained lithic feldspathic quartz sandstones locally interbedded with feldspathic quartz sandstones; zones of poorly sorted sandstones, fine sandstones and medium-grained sandstones are present locally(Fig.3). The cap rock is thick and laterally extensive. Its physical properties are favourable: the porosity is generally ~20%, and the permeability generally exceeds 200 mD(Fig.3). According to exploration data supplied by the East Corporation of China National Offshore Oil Corporation (CNOOC), water is encountered in Well LF2-1-1 at a depth of 96 m. The water temperature at the bottom of the sea is 21°C, the temperature at the bottom of the well (depth 2483.5 m) is 93°C, and the average geothermal gradient is 30.8°C/km. Based on the high-pressure physical properties for crude oil within the LF 7-2 oil field adjacent to the study area, the formation pressure in the area is normal, and the pressure coefficient is 1.076.
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Fig. 2. Cross sections through LF2-1 (section locations are shown in Fig. 1). (1) Section a-a’ structural interpretation in the NW-SE direction; (2) Section b-b’ structural interpretation in the NE-SW direction
2. Modelling Based on the lithological characteristics of the rocks encountered in Well LF2-1-1, the model can be divided into 3 cap rocks and 3 reservoirs(Fig.3). The thick interval of mudstones in the upper section of the Zhujiang Formation (ZF) serves as the uppermost cap rock (Layer 1, depths of 1917-1967 m in the well section). The interbedded sandstones and mudstones in the middle of the lower ZF serve as the second cap rock (Layer 3, depths of 2048.52110 m); this layer is characterised by interbedded sandstones and mudstones. The thin mudstones in the upper part of the ZF serve as the third cap rock (Layer 5, depths of 2262.5-2270 m). The reservoirs include the upper sandstone member of the lower ZF (Layer 2, depths of 1967-2048.5 m), the lower sandstone member of the lower ZF and the sandstone layer in the middle and lower parts of the Zhuhai Formation.
Fig. 3. Synthesis column map of logging interpretation and modelling layers for target formations of LF2-1-1 well (Logging curves come from data of CNOOC)
Rectangular grids were adopted for the model. The X axis of the model was 22.6 km long and was divided into 65 intervals; the edge of each cell is approximately 0.35 km long. The Y axis was 17.6 km long and was divided into 40 intervals; the edge of each cell is approximately 0.44 km long (Fig. 4a). In the vertical direction, each sub-layer was divided into 2 to 8 layers in accordance with their corresponding thicknesses. The total number of layers is 26, and each layer is approximately 10 m thick. Of the 26 layers, Layer 5 is the thinnest. This layer is divided into 2 layers with thicknesses of 3.35 m each. There are 67,600 total cells in the model. There are several faults in the southern and northern parts of Structure LF2-1. However, the upper section of the ZF, which is cut by faults, consists primarily of a thick mudstone layer with fault displacements far less than the
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thickness of the mudstones (Fig. 2). It is also thought that fault gouge may serve as barriers to fluid migration. The faults, therefore, are treated as sealed in the simulation. Although the sealing performance of these faults may not be as good as that of the pure mudstone cap rock, it is far better than that of the sandstone reservoir. The cells corresponding to the positions of faults in the model are assigned the property parameters of the mudstones, i.e., low porosity and permeability, representing closed faults. The grey-green grids in Fig. 4a are those corresponding to these positions of faults. The well LF2-1-1 was selected as the simulated CO2 injection well. The method of integrated injection through multiple layers was adopted as the primary manner of injection, which requires that the injection well is continuously screened throughout the three reservoir layers and that their injection is simultaneous. The overall CO2 injection rates were set to 1 Mt/y (32 kg/s) and 2 Mt/y (64 kg/s). Based on the experience of the CNOOC, 1.5 times the initial formation pressure was used as the upper limit of the injection pressure to avoid the risk of cap rock breakthrough. To observe the buildup of pressure at various distances from the injection well, the 3 positions shown in Fig. 4b were selected as observation points (P1, P2 and P3). The cells corresponding to these observation points in the top parts of Layers 1 and 3 and the middle part of Layer 2 at distances of 0.5 km, 1.5 km and 3 km from Well LF2-1-1 were selected for observation. The data were used to develop a curve representing the changes in the cells with time, thus facilitating the modelling of build ups of formation pressures in the three reservoir strata. (b)
(a)
Fig. 4. Geometric model for structure LF2-1(amplification of 10 in the Z axis) (a) and Map showing locations of Sections AA’ and BB’ and the three observation points (P1, P2, P3) (b), which are located 500 m, 1,500 m and 3,000 m from the well, respectively. The lower map shows the depth contours of Horizon T50.
3. Results and discussion 3.1. Formation pressure buildup Fig. 5 shows that early in the injection process, the pressures near the bottom of the well at various observation points increase rapidly as the groundwater is displaced outward and the injection rate reaches a preset level. The pressure is slightly lower when the rate of injection is constant. The pressure changes slightly during the phase of constant injection as the amount of injected CO2 increases. When the injection is stopped after the 20th year, the pressures at the various observation points rapidly decrease and then slowly reach their stable values. The increase in pressure resulting from the injection range between 0.1-0.4 bar at speed rate of 1MtCO2/y and 0.5-2 bar at 2MtCO2/y, which are less than 0.2% and 0.9% of the minimum initial stratum pressure (~222 bar), respectively. These results indicate that the risk of cap rock breakthrough at LF2-1 site is quite small. (a)
(b)
Fig. 5. Pressure curves of observation points in top of layer 6 in the process of injecting CO2 into LF2-1 at rate of 1 (a) and 2 (b) MtCO2/y.
Pengchun Li et al. / Energy Procedia 154 (2018) 48–53 Pengchun Li/ Energy Procedia 00 (2018) 000–000
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5
3.2. Migration and distribution of gaseous CO2 The planar projection indicates the maximum distribution of the saturation of gaseous CO2 with an injection rate of 1 and 2Mt CO2/y after the 100th years (SG > 0.1). The gaseous CO2 migrates into the upper part of the structure farthest in the south and east directions, with a maximum migration distance of approximately 2.5 km in scenario I and 3km in II by the 100th year (Fig.6). The migration of CO2 is contained within the structural trap and does not reach the spill point and fault of the structure. (a)
(b)
Fig.6.The planar projection figures of CO2 gas saturation (SG>0.1) distribution ranges at 20th and 100th years in the process of injecting CO2 into the sequestration site of LF2-1 structure at the speed rate of 1 (a) and 2 (b) MtCO2/y.
The migration and distribution of the gaseous CO2 plume after leaving the injection well can be observed in Sections AA’ and BB’. As shown in Fig. 7, most of the CO2 that was injected at a constant rate enters the reservoir of Layer 2, which is the thickest reservoir in the area of the well. This reservoir, therefore, exhibits the greatest potential for receiving a large volume injected CO2. During the 20-year injection phase, the CO2 migrates upward while spreading horizontally, and it tends to accumulate along the bottom of the cap rock layer due to the cap rock’s sealing properties. The size of the CO2 gas plume continuously increases with the increasing amount of CO2 injection. When the injection is stopped after the 20th year, the gaseous CO2, driven by its buoyancy, accumulates in the high parts of the structure. Fig. 7 show that there is breakthrough in Seal 3 in the 100th year, which occurs because this third cap rock layer is thin (7.5 m) and its sealing properties are relatively poor. As a result, the CO2 injected into Reservoir 3 can break through Seal 3 and migrate to the upper reservoir later in the CO2 storage period. However, based on the gaseous saturation value of CO2, only a small quantity of CO2 enters Seal 3 (SG < 0.15), which suggests that the sealing properties of this cap rock layer are good overall and do not result in a large quantity of leakage; most of the CO2 gas plume injected into the underlying layer is trapped beneath the cap rock (Seal 3). However, as Seal 2 is relatively thick, no obvious signs of breakthrough occur.
Fig.7. Distribution of CO2 gas plumes at rate of 2MtCO2/y for 10th, 20th and100th years in BB’ profiles of LF2-1.
3.3. Distribution of dissolved CO2 The distribution of the dissolved CO2 is consistent with, but slightly larger than, that of the gaseous CO2, which may be because the dissolved CO2 can flow with the formation water at the rate of 1 and 2 Mt CO2/y as the formation water containing dissolved CO2 flows under the influence of pore pressures. By contrast, the CO2 injected under high pressure during the injection phase (years 0-20) displaces the formation water containing dissolved CO2 in a radial pattern. Therefore, the distribution of dissolved CO2 in the formation water is greater than that of the gaseous CO2. Fig.6 shows that the dissolved CO2 is primarily distributed in the reservoir but is also present in the cap rock, which suggests that there is a certain quantity of dissolved CO2 in the formation water of the cap rock. Later, when the CO2 migrates upward after breaking through the cap rock (Seal 3), the increased interaction between
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the CO2 and water results in dissolution into the formation water of the cap rock or surrounding area, thus enlarging the area of CO2 distribution (Fig. 8). Compared with Scenario I, the distribution of formation water containing dissolved CO2 in Scenario II is not doubled but instead is essentially the same as that observed in Scenario I. This finding indicates that a higher injection rate can result in a corresponding increase in the injection pressure, thus enhancing the dissolution of the CO2 in the water. The quantity of dissolved CO2 is higher in Scenario II, but its distribution is essentially the same in the two scenarios. Results indicate that CO2 dissolves into water from the start of the injection period, and gaseous CO2 is not produced before saturation is reached. During the continuous injection phase, the quantity of dissolved CO2 in the formation water rapidly increases, and the quantity of dissolved CO2 continuously increases after the injection is stopped, although the dissolution rate clearly decreases. Accordingly, the quantity of gaseous CO2 gradually decreases. The dissolved CO2 in the formation water accounts for approximately 22% and 20% of the total injected volume by the 100th year in 2 scenarios, respectively. Compared with 2 scenarios, the total dissolved quantity tends to decrease, which suggests that the dissolved storage volume is restricted by the CO2 solubility.
Fig.8. Distribution of CO2 mass dissolved in formation water (XCO2aq) at rate of 2MtCO2/y in 10th, 20th and100th years in AA’ profiles of LF2-1.
5. Summary The migration and distribution of the injected CO2 in the saline aquifers were simulated and analysed using TOUGH2-ECO2N. The simulation results show that the injection rate, reservoir pressure, CO2 migration distance and quantity of dissolved CO2 in the aquifers exhibit nonlinear variations. The upward leakage of CO2 through the thin seals occurs slowly. The thickness of the cap rock is important in terms of its sealing performance, especially that of the upper regional cap rock, which should have a thickness of at least 50 m. The reservoir and cap rock properties of the structure facilitate potential CO2 injection and safe storage in the saline formations. The structure can therefore be utilised by Guangdong Province for storing offshore carbon in saline aquifers. Acknowledgements We gratefully acknowledge the funding by an open fund (PLC20180801) of State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation (Chengdu University of Technology) and a program of the National Natural Science Foundation of China (No. 41372256). We are also grateful to the CNOOC for their basic data support. References
[1] IPCC. In: Metz, B., Davidson,O., Coninck, H.C., Loos, M., Meyer, L.A. (Eds.), Special Report on Carbon Dioxide Capture and Storage. Cambridge University Press, Cambridge, UK/New York, NY, USA. 2005. [2] Shafeen A, Croiset E, Douglas PL, Chatzis I. CO2 sequestration in Ontario, Canada. Part I: storage evaluation of potential reservoirs. Energy Conversion and Management. 2004;45:2645-59. [3] Li Q, Wei Y-N, Liu G, Lin Q. Combination of CO2 geological storage with deep saline water recovery in western China: Insights from numerical analyses. Applied Energy. 2014;116:101-10. [4] Liu H, Hou Z, Were P, Gou Y, Sun X. Simulation of CO2 plume movement in multilayered saline formations through multilayer injection technology in the Ordos Basin, China. Environmental Earth Sciences. 2013;71:4447-62. [5] Zhou D, Liao CP, Li PC, Huang Y. CCS Can Make Fossil-Fueled Energy Clean in Guangdong Province, China. Advanced Materials Research. 2013;807-809:783-9. [6] Li P, Zhou D, Zhang C, Zhang Y, Peng J. Potential of Sub-seafloor CO2 Geological Storage in Northern South China Sea and its Importance for CCS Development in South China. Energy Procedia. 2013;37:5191-200. [7] Zhou D, Zhao Z, Liao J, Sun Z. A preliminary assessment on CO2 storage capacity in the Pearl River Mouth Basin offshore Guangdong, China. International Journal of Greenhouse Gas Control. 2011;5:308-17. [8] Zhang C, Zhou D, Li P, Li F, Zhang Y, Sun Z, et al. CO2 storage potential of the Qiongdongnan Basin, northwestern South China Sea. Greenhouse Gases: Science and Technology. 2014;4:1-15.
ScienceDirect Availableonline onlineatatwww.sciencedirect.com www.sciencedirect.com Available Energy Procedia 00 (2018) 000–000
ScienceDirect ScienceDirect
www.elsevier.com/locate/procedia
Energy Procedia Procedia 00 154(2017) (2018)000–000 48–53 Energy www.elsevier.com/locate/procedia
Applied Energy Symposium and Forum, Carbon Capture, Utilization and Storage, CCUS 2018, 27–29 June 2018, Perth, Australia
Geological The characterization and numerical modelling of CO2 storage 15th International Symposium on District Heating and Cooling in an aquifer structure offshore Guangdong Province, China Assessing the feasibility of using the heat demand-outdoor a b , Yunfan Zhanga, *, Di Zhoua, heat Xi Liang temperature Pengchun functionLifor a long-term district demand forecast a
CAS Key Laboratory of Ocean and Marginal Sea Geology, South China Sea Institute of Oceanology, Guangzhou, 510301 China a,b,c a a b c c b UK-China (Guangdong) CCUS Centre, Guangzhou, 510663, China
I. Andrić
*, A. Pina , P. Ferrão , J. Fournier ., B. Lacarrière , O. Le Corre
a
IN+ Center for Innovation, Technology and Policy Research - Instituto Superior Técnico, Av. Rovisco Pais 1, 1049-001 Lisbon, Portugal b Veolia Recherche & Innovation, 291 Avenue Dreyfous Daniel, 78520 Limay, France c Département Systèmes Énergétiques et Environnement - IMT Atlantique, 4 rue Alfred Kastler, 44300 Nantes, France Abstract
The Lufeng (LF) 2-1 structure, which is the largest anticlinal structure developed in the Zhu I depression of the Pearl River Mouth Basin, offers high-quality source-sink matching with onshore CO2 emissions. In this paper, a 3D model using the Abstract TOUGH2/ECO2N tool was developed based on typical formation parameters obtained from a review of well and seismic structural data. Numerical results indicated that doubling the injection quantity does not result in a doubling of the CO2 District heating the literature as one of the most effective for decreasing the The CO2solutions plumes remain within the distribution, whichnetworks suggestsare the commonly presence ofaddressed nonlinear in variations between the two variables. greenhouse gas trap emissions from the building require investments which are returned through thethan heat LF2-1 structural based on injection rates ofsector. eitherThese 1 Mt/ysystems or 2 Mt/y. The high maximum increase in formation pressure is less Due tois the climateformation conditionspressure. and building renovation policies, demand inof the future could decrease, 2sales. bars, which 0.9%changed of the primary Therefore, the reservoir and heat seal properties LF2-1 are optimal, which prolonging the investment return period. suggests that the prospect of injecting and storing a total of 40 Mt of CO2 is good. Overall, the LF2-1 may be used as a suitable The main of this paper is to assess the feasibility using the heat demand – outdoor temperature heat demand deep saline aquifers. Additionally, the findings function can guideforsite selection offshore sitescope for large-scale storage of industrial CO2 in of forecast. inThe district of Alvalade, located in (Portugal), was used as a case study. The district is consisted of 665 decisions Guangdong Province for offshore COLisbon geological storage demonstrations. 2 buildings that vary in both construction period and typology. Three weather scenarios (low, medium, high) and three district ©renovation 2018 The Published by Elsevier Ltd. intermediate, deep). To estimate the error, obtained heat demand values were scenarios wereLtd. developed (shallow, Copyright © Authors. 2018 Elsevier All rights reserved. This is an open access article under the heat CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/) compared with results from a dynamic demand previously developed and validated the authors. Selection and peer-review under responsibility of the model, scientific committee of the Applied Energy by Symposium and Forum, Carbon Selection and peer-review under responsibility of the scientific committee of theofApplied Energy andsome Forum, Carbon The results showedand thatStorage, when only weather change is considered, the margin error could be Symposium acceptable for applications Capture, Utilization CCUS 2018. Capture, Utilization and Storage, CCUS 2018. (the error in annual demand was lower than 20% for all weather scenarios considered). However, after introducing renovation scenarios,CO the error value increased up to 59.5% (depending on the weather and renovation scenarios combination considered). Keywords: 2 storage, saline aquifer, numerical modelling, LF2-1 structrure, offshore Guangdong Province; The value of slope coefficient increased on average within the range of 3.8% up to 8% per decade, that corresponds to the decrease in the number of heating hours of 22-139h during the heating season (depending on the combination of weather and scenarios considered). On the other hand, function intercept increased for 7.8-12.7% per decade (depending on the 1.renovation Introduction coupled scenarios). suggested used to and modify the function for creates the scenarios considered, and ) capture storage (CCS) parameters technologies the opportunity to The developmentThe of values Carbon dioxidecould (CO2be improve the accuracy of heat demand estimations. isolated CO of emission from human activities for long geological time periods [1]. It might, therefore, widely be 2
© 2017 The Authors. Published by Elsevier Ltd. Peer-review under responsibility of the Scientific Committee of The 15th International Symposium on District Heating and Cooling. * Corresponding author. Tel.: +86-20-89024583; fax: +86-20-84180401. E-mail address: [email protected] Keywords: Heat demand; Forecast; Climate change
1876-6102 Copyright © 2018 Elsevier Ltd. All rights reserved. Selection and peer-review under responsibility of the scientific committee of the Applied Energy Symposium and Forum, Carbon Capture, Utilization and Storage, CCUS 2018. 1876-6102 © 2017 The Authors. Published by Elsevier Ltd. 1876-6102 © 2018 The Authors. Published by Elsevier Ltd. Peer-review under responsibility of the Scientific Committee of The 15th International Symposium on District Heating and Cooling. This is an open access article under the CC BY-NC-ND license (https://creativecommons.org/licenses/by-nc-nd/4.0/) Selection and peer-review under responsibility of the scientific committee of the Applied Energy Symposium and Forum, Carbon Capture, Utilization and Storage, CCUS 2018. 10.1016/j.egypro.2018.11.009
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Pengchun Li et al. / Energy Procedia 154 (2018) 48–53 Pengchun Li/ Energy Procedia 00 (2018) 000–000
49
regarded as an effective and potential approach for large greenhouse gas emitters [2, 3]. From a research point of view, CCS technology is feasible and has already been successfully applied in many projects worldwide such as America, Canada, Germany, Netherland, Norway, Australia, etc.[4]. CCS would be a strategically important technology for Guangdong to achieve large-scale emission reductions now and in the foreseeable future[5]. Unfortunately, the CO2 storage potential of onshore basins in Guangdong is very limited [6-8]. The Pearl River Mouth Basin contains high-quality reservoirs that are large enough to be used for CO2 storage [5, 7]. Most importantly, the large-scale CO2 point sources in Guangdong are predominantly located in the coast areas. Structures in the Pearl River Mouth Basin are located approximately 100-200 km from the coastlines of Guangdong Province, and thus source-sink matching conditions in this area are best. Therefore, it may be possible for Guangdong Province to achieve CO2 emission reductions through the use of Pearl River Mouth Basin storage sites for offshore geological storage. For highly targeted investigation of storage sites within the Zhu I Depression of the Pearl River Mouth Basin, the large Lufeng (LF) 2-1 structure was selected as the subject of this study. 1. Structural characterization LF2-1 is located in the northwest section of the lower uplift in the centre of the Lufeng Sag (Fig.1a), which is part of the Zhu I Depression. The structure is largely controlled by a NW-trending fault. As a result, 3 “lifts in the subsag”, designated A, B and C (Fig. 1b) developed. Lift A is a faulted anticline involving Horizons T50, T60 and T70. The entrapment involving Horizons T50 and T60 of the Zhuhai Formation measures 214.21 km2 by 115 m thick. The reservoir itself is 57 m thick and exhibits a porosity of 20.74%. The trap involving Horizons T60 and T70 measures 100.11 km2 by 110 m thick; this reservoir is 152 m thick and exhibits a porosity of 25.6%. The entrapment of zones beneath Horizon T70 measures 140.34 km2 by 150 m thick; this reservoir is 226 m thick and exhibits a porosity of 22.18%. Being a fault block with a relatively small entrapment area, Lift B spans Horizons T60 and T70. Only one exploratory well, i.e., Well LF2-1-1, currently extends into the LF2-1. This well exhibits no evidence of natural gas, and water is the primary fluid. Based on a preliminary analysis, the source rocks of Enping Formation beneath the structure are immature, and the structure is located far from effective Wenchang Formation source rocks. As a result, natural gas has not migrated from the Wenchang Formation to the LF2-1 structural trap. The reservoir zone within the structure is thus a water-bearing layer. (a)
(b)
Fig. 1. Structural diagram of Lufeng sag of LF2-1 developed (a) and structural contour map of LF2-1 (b). Locations of Well LF2-1-1 and profiles are shown in Fig.2 (from CNOOC).
The reservoirs of LF2-1 consist predominantly of medium- and coarse-grained lithic feldspathic quartz sandstones locally interbedded with feldspathic quartz sandstones; zones of poorly sorted sandstones, fine sandstones and medium-grained sandstones are present locally(Fig.3). The cap rock is thick and laterally extensive. Its physical properties are favourable: the porosity is generally ~20%, and the permeability generally exceeds 200 mD(Fig.3). According to exploration data supplied by the East Corporation of China National Offshore Oil Corporation (CNOOC), water is encountered in Well LF2-1-1 at a depth of 96 m. The water temperature at the bottom of the sea is 21°C, the temperature at the bottom of the well (depth 2483.5 m) is 93°C, and the average geothermal gradient is 30.8°C/km. Based on the high-pressure physical properties for crude oil within the LF 7-2 oil field adjacent to the study area, the formation pressure in the area is normal, and the pressure coefficient is 1.076.
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Fig. 2. Cross sections through LF2-1 (section locations are shown in Fig. 1). (1) Section a-a’ structural interpretation in the NW-SE direction; (2) Section b-b’ structural interpretation in the NE-SW direction
2. Modelling Based on the lithological characteristics of the rocks encountered in Well LF2-1-1, the model can be divided into 3 cap rocks and 3 reservoirs(Fig.3). The thick interval of mudstones in the upper section of the Zhujiang Formation (ZF) serves as the uppermost cap rock (Layer 1, depths of 1917-1967 m in the well section). The interbedded sandstones and mudstones in the middle of the lower ZF serve as the second cap rock (Layer 3, depths of 2048.52110 m); this layer is characterised by interbedded sandstones and mudstones. The thin mudstones in the upper part of the ZF serve as the third cap rock (Layer 5, depths of 2262.5-2270 m). The reservoirs include the upper sandstone member of the lower ZF (Layer 2, depths of 1967-2048.5 m), the lower sandstone member of the lower ZF and the sandstone layer in the middle and lower parts of the Zhuhai Formation.
Fig. 3. Synthesis column map of logging interpretation and modelling layers for target formations of LF2-1-1 well (Logging curves come from data of CNOOC)
Rectangular grids were adopted for the model. The X axis of the model was 22.6 km long and was divided into 65 intervals; the edge of each cell is approximately 0.35 km long. The Y axis was 17.6 km long and was divided into 40 intervals; the edge of each cell is approximately 0.44 km long (Fig. 4a). In the vertical direction, each sub-layer was divided into 2 to 8 layers in accordance with their corresponding thicknesses. The total number of layers is 26, and each layer is approximately 10 m thick. Of the 26 layers, Layer 5 is the thinnest. This layer is divided into 2 layers with thicknesses of 3.35 m each. There are 67,600 total cells in the model. There are several faults in the southern and northern parts of Structure LF2-1. However, the upper section of the ZF, which is cut by faults, consists primarily of a thick mudstone layer with fault displacements far less than the
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thickness of the mudstones (Fig. 2). It is also thought that fault gouge may serve as barriers to fluid migration. The faults, therefore, are treated as sealed in the simulation. Although the sealing performance of these faults may not be as good as that of the pure mudstone cap rock, it is far better than that of the sandstone reservoir. The cells corresponding to the positions of faults in the model are assigned the property parameters of the mudstones, i.e., low porosity and permeability, representing closed faults. The grey-green grids in Fig. 4a are those corresponding to these positions of faults. The well LF2-1-1 was selected as the simulated CO2 injection well. The method of integrated injection through multiple layers was adopted as the primary manner of injection, which requires that the injection well is continuously screened throughout the three reservoir layers and that their injection is simultaneous. The overall CO2 injection rates were set to 1 Mt/y (32 kg/s) and 2 Mt/y (64 kg/s). Based on the experience of the CNOOC, 1.5 times the initial formation pressure was used as the upper limit of the injection pressure to avoid the risk of cap rock breakthrough. To observe the buildup of pressure at various distances from the injection well, the 3 positions shown in Fig. 4b were selected as observation points (P1, P2 and P3). The cells corresponding to these observation points in the top parts of Layers 1 and 3 and the middle part of Layer 2 at distances of 0.5 km, 1.5 km and 3 km from Well LF2-1-1 were selected for observation. The data were used to develop a curve representing the changes in the cells with time, thus facilitating the modelling of build ups of formation pressures in the three reservoir strata. (b)
(a)
Fig. 4. Geometric model for structure LF2-1(amplification of 10 in the Z axis) (a) and Map showing locations of Sections AA’ and BB’ and the three observation points (P1, P2, P3) (b), which are located 500 m, 1,500 m and 3,000 m from the well, respectively. The lower map shows the depth contours of Horizon T50.
3. Results and discussion 3.1. Formation pressure buildup Fig. 5 shows that early in the injection process, the pressures near the bottom of the well at various observation points increase rapidly as the groundwater is displaced outward and the injection rate reaches a preset level. The pressure is slightly lower when the rate of injection is constant. The pressure changes slightly during the phase of constant injection as the amount of injected CO2 increases. When the injection is stopped after the 20th year, the pressures at the various observation points rapidly decrease and then slowly reach their stable values. The increase in pressure resulting from the injection range between 0.1-0.4 bar at speed rate of 1MtCO2/y and 0.5-2 bar at 2MtCO2/y, which are less than 0.2% and 0.9% of the minimum initial stratum pressure (~222 bar), respectively. These results indicate that the risk of cap rock breakthrough at LF2-1 site is quite small. (a)
(b)
Fig. 5. Pressure curves of observation points in top of layer 6 in the process of injecting CO2 into LF2-1 at rate of 1 (a) and 2 (b) MtCO2/y.
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3.2. Migration and distribution of gaseous CO2 The planar projection indicates the maximum distribution of the saturation of gaseous CO2 with an injection rate of 1 and 2Mt CO2/y after the 100th years (SG > 0.1). The gaseous CO2 migrates into the upper part of the structure farthest in the south and east directions, with a maximum migration distance of approximately 2.5 km in scenario I and 3km in II by the 100th year (Fig.6). The migration of CO2 is contained within the structural trap and does not reach the spill point and fault of the structure. (a)
(b)
Fig.6.The planar projection figures of CO2 gas saturation (SG>0.1) distribution ranges at 20th and 100th years in the process of injecting CO2 into the sequestration site of LF2-1 structure at the speed rate of 1 (a) and 2 (b) MtCO2/y.
The migration and distribution of the gaseous CO2 plume after leaving the injection well can be observed in Sections AA’ and BB’. As shown in Fig. 7, most of the CO2 that was injected at a constant rate enters the reservoir of Layer 2, which is the thickest reservoir in the area of the well. This reservoir, therefore, exhibits the greatest potential for receiving a large volume injected CO2. During the 20-year injection phase, the CO2 migrates upward while spreading horizontally, and it tends to accumulate along the bottom of the cap rock layer due to the cap rock’s sealing properties. The size of the CO2 gas plume continuously increases with the increasing amount of CO2 injection. When the injection is stopped after the 20th year, the gaseous CO2, driven by its buoyancy, accumulates in the high parts of the structure. Fig. 7 show that there is breakthrough in Seal 3 in the 100th year, which occurs because this third cap rock layer is thin (7.5 m) and its sealing properties are relatively poor. As a result, the CO2 injected into Reservoir 3 can break through Seal 3 and migrate to the upper reservoir later in the CO2 storage period. However, based on the gaseous saturation value of CO2, only a small quantity of CO2 enters Seal 3 (SG < 0.15), which suggests that the sealing properties of this cap rock layer are good overall and do not result in a large quantity of leakage; most of the CO2 gas plume injected into the underlying layer is trapped beneath the cap rock (Seal 3). However, as Seal 2 is relatively thick, no obvious signs of breakthrough occur.
Fig.7. Distribution of CO2 gas plumes at rate of 2MtCO2/y for 10th, 20th and100th years in BB’ profiles of LF2-1.
3.3. Distribution of dissolved CO2 The distribution of the dissolved CO2 is consistent with, but slightly larger than, that of the gaseous CO2, which may be because the dissolved CO2 can flow with the formation water at the rate of 1 and 2 Mt CO2/y as the formation water containing dissolved CO2 flows under the influence of pore pressures. By contrast, the CO2 injected under high pressure during the injection phase (years 0-20) displaces the formation water containing dissolved CO2 in a radial pattern. Therefore, the distribution of dissolved CO2 in the formation water is greater than that of the gaseous CO2. Fig.6 shows that the dissolved CO2 is primarily distributed in the reservoir but is also present in the cap rock, which suggests that there is a certain quantity of dissolved CO2 in the formation water of the cap rock. Later, when the CO2 migrates upward after breaking through the cap rock (Seal 3), the increased interaction between
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the CO2 and water results in dissolution into the formation water of the cap rock or surrounding area, thus enlarging the area of CO2 distribution (Fig. 8). Compared with Scenario I, the distribution of formation water containing dissolved CO2 in Scenario II is not doubled but instead is essentially the same as that observed in Scenario I. This finding indicates that a higher injection rate can result in a corresponding increase in the injection pressure, thus enhancing the dissolution of the CO2 in the water. The quantity of dissolved CO2 is higher in Scenario II, but its distribution is essentially the same in the two scenarios. Results indicate that CO2 dissolves into water from the start of the injection period, and gaseous CO2 is not produced before saturation is reached. During the continuous injection phase, the quantity of dissolved CO2 in the formation water rapidly increases, and the quantity of dissolved CO2 continuously increases after the injection is stopped, although the dissolution rate clearly decreases. Accordingly, the quantity of gaseous CO2 gradually decreases. The dissolved CO2 in the formation water accounts for approximately 22% and 20% of the total injected volume by the 100th year in 2 scenarios, respectively. Compared with 2 scenarios, the total dissolved quantity tends to decrease, which suggests that the dissolved storage volume is restricted by the CO2 solubility.
Fig.8. Distribution of CO2 mass dissolved in formation water (XCO2aq) at rate of 2MtCO2/y in 10th, 20th and100th years in AA’ profiles of LF2-1.
5. Summary The migration and distribution of the injected CO2 in the saline aquifers were simulated and analysed using TOUGH2-ECO2N. The simulation results show that the injection rate, reservoir pressure, CO2 migration distance and quantity of dissolved CO2 in the aquifers exhibit nonlinear variations. The upward leakage of CO2 through the thin seals occurs slowly. The thickness of the cap rock is important in terms of its sealing performance, especially that of the upper regional cap rock, which should have a thickness of at least 50 m. The reservoir and cap rock properties of the structure facilitate potential CO2 injection and safe storage in the saline formations. The structure can therefore be utilised by Guangdong Province for storing offshore carbon in saline aquifers. Acknowledgements We gratefully acknowledge the funding by an open fund (PLC20180801) of State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation (Chengdu University of Technology) and a program of the National Natural Science Foundation of China (No. 41372256). We are also grateful to the CNOOC for their basic data support. References
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