A modeling and numerical simulation study of enhanced CO₂ sequestration into deep saline formation: a strategy towards climate change mitigation

Abstract

The net increase in anthropogenic carbon dioxide (CO₂) emissions from fossil fuel combustion contributes significantly to the global warming and climate change. CO₂ capture and storage (CCS) in geological formations, specifically in deep saline aquifers, is among the very promising strategies to control and mitigate emissions into the atmosphere. Injection of CO₂ into a reservoir may result in the formation of pore pressure which can initiate cracks and trigger fault activities. CO₂ may leak into the atmosphere and invade shallow groundwater sources. Release of CO₂ into the atmosphere has enormous effects on the environment and significantly contributes to global climate change. Therefore, storage safety, injection efficiency, and monitoring remain crucially important considerations in CO₂ injection. This study attempts to establish an optimal CO₂ injection strategy that aims at enhancing CO₂ storage with an increased safety at Ordos basin. Furthermore, it establishes the safety limits of CO₂ plume migration from the central axis of the injection well. In the investigation, injection parameters such as injection rate and bottom hole pressure were analyzed. The CO₂ plume migration analysis was performed, and migration limits were determined. Simulation results revealed that different formation layers have varying storage capacities and pressure withstanding ability. The site maximum storage rate goal of storing 100,000 t of CO₂ per year was attained. It is advised to perform injection at the Majiagou layer due to sufficient storage capacity and greater depth of over 2400 m from the surface. This study recommends that an optimum CO₂ sequestration strategy which does not result into excessive migration of injected CO₂ plume and limit formation pressure buildup should be adopted. Therefore, deep underground storage at an average depth of above 2400 m is optimum, because it has an adequate storage space to accommodate the desired rate of 100,000 t/year. Besides, its geological settings favor storage safety in the event of significant uplift that may cause induced seismicity. Furthermore, it will also limit CO₂ plume that may come into contact with shallow groundwater sources. Likewise, investing in low carbon and carbon-free energy technologies and enhancement of energy efficiency systems around the site is also recommended.

1 Introduction

In recent years, global warming and climate change has been a major global environmental issue. Global change is mainly brought about by increased carbon dioxide (CO₂) emissions into the earth’s atmosphere (Zhang et al. 2016; Maneeintr et al. 2017). The continual consumption of fossil fuel¹ for satisfying the energy need of current industrialized modern economies has led to CO₂ concentration increment of approximately 50% over the pre-industrial records (IPCC 2013)². Its concentration by volume was reported to be 404 parts per million volume (ppmv) in 2016 compared to the pre-industrial era record of 280 ppmv (IPCC 2013). If the current trend of the global CO₂ emission rate continues without an immediate intervention, the future global climate will be highly disrupted. Carbon capture and storage (CCS), a process of capturing and injecting of CO₂ into geological formations deep beneath the earth’s surface as a means of isolating it permanently from the atmosphere, has been proposed as the commercially viable and most promising strategy for mitigating global climate change caused by high levels of anthropogenic CO₂ emissions (IPCC 2005). Geological formations for CO₂ storage are of different types and properties; they include deep saline aquifers, depleted oil and gas fields, unmined coal bed formations, and salt domes (Bahrami et al. 2013; Khan et al. 2018). However, the deep saline aquifers are considered the best of all storage options due to their global abundance, accessibility, and huge storage potential (IPCC 2005; Bachu et al. 2007; Benson and Cole 2008). Globally, a number of CCS commercial projects in deep saline aquifers have been proposed and established; these projects have unique characteristics and are in various phases of operations at different time scale and life spans (Global CCS Institute 2016). Examples of the commercial global projects include the Sleipner, an offshore gas field project in North Sea Norway which was initiated in September 1996, Cranfield project in Mississippi, USA, Snøhvit CO₂ storage scheme in Norway, which was launched in 2008, In Salah CO₂ storage project in Algeria which started in 2004, the Shenhua CCS demonstration project in China, Quest project in Canada, and Gorgon storage project in Australia which started in 2017 (Estublier and Lackner 2009; Eiken et al. 2011; Ringrose et al. 2013; Xiuzhang 2014; Global CCS Institute 2016; IEA 2016)³. To date, with about 15 large-scale commercial CCS projects, annual accommodation of more than 23 million tons of CO₂ in deep geological formations has been achieved (Jin et al. 2017; Khan et al. 2019). Despite the fact that the global community fight against anthropogenic CO₂ emissions into the atmosphere as a means of reducing global warming and its related climatic threats, human population and activities that lead to CO₂ emissions continue to rise. Therefore, more research on innovative emission mitigation strategies has been emphasized and recommended by international communities and agencies (Pachauri et al. 2014).

For the successful storage of CO₂ in geological formations⁴ such as saline aquifers, there is a crucial need to perform situation analysis and conduct feasibility study in order to obtain a broader understanding of fluid dynamics as well as pressure changes response of a formation under injection (Lamert et al. 2012; Zhang and Agarwal 2013). Various scientists have worked on CCS projects in deep saline aquifers⁵ providing details on fluid dynamics and its geochemical processes (Xu et al. 2004; González-Nicolás et al. 2011; Liu et al. 2015; Zhu et al. 2015). However, few works have been covered on CO₂ storage enhancement through improved CO₂ injection and pressure control on a global scale. Ozah et al. (2005) investigated horizontal CO₂ injection well in saline aquifer to discover the right placement for enhanced CO₂ injection. It was discovered that deeper bottom placement of CO₂ in horizontal wells favors storage. This was explained by the fact that it reduces the time and possibility of CO₂ plume to come into contact with cap rock. Gupta et al. (2004) studied and compared reservoir pressure buildup between vertical and horizontal wells in the CO₂ injection process and discovered that pressure is more fairly distributed to the horizontal well compared to the vertical well. Thibeau and Mucha (2011) identified that pressure buildup during the injection process in saline aquifers limits the injection process and hence storage.

The Shenhua CCS demonstration project in Ordos basin is the first fascinating Chinese deep saline aquifer project launched in May 2011 with a designed injection rate of 100,000 t of CO₂/year (Zhu et al. 2015; Yang et al. 2017). The project serves as a guide and compass for the future commercial scale project which is expected to be constructed in the same location (Li et al. 2016a). Since the launching of the Shenhua CCS project, a number of scientists have worked on similar research areas such as fluid dynamics and geophysical and geochemical processes, exploring and describing various fundamental mechanisms regarding the safety and long term storage of the injected CO₂ (Xiuzhang 2014; Yu et al. 2017). However, little has been done on CO₂ injectivity and enhanced CO₂ storage for the site (Yang et al. 2017). The Shenhua CCS demonstration project geological strata are highly heterogeneous and the porosity and permeability of its formation are low; therefore, the challenges related to injection and formation pressure buildup are obvious. As mitigation measures to overcome some of the aforementioned challenges, artificially induced fractures and multilayer injection procedures were proposed by different researchers (Liu et al. 2014; Diao et al. 2015). Ling et al. (2013b) analyzed the fluid dynamics and estimated the CO₂ plume longest distance of approximately 350 m within the formation. Moreover, it was revealed that regardless of a low penetrability, Ordos is still appropriate for CO₂ storage and that injection could be highly enhanced when hydraulic fracturing is considered. Liu et al. (2015) revealed that the uppermost layers subjected with relatively low overburden pressure have great ability to store CO₂ in a mineral trapping style compared to the bottom layers. The results were released after analysis done on four samples of sandstones from the reservoir.

In this study, a 3-dimensional (3D) heterogeneous reservoir was built and injection layer storage performance was analyzed based on the site-specific data. The model was numerically simulated for a period of 10 years using LandSim⁶ 3D commercial modeling and simulation package (Tracy Energy Technologies 2016). The package employs unstructured gridding system during modeling. Among the uniqueness of this research work is that most of the previous work done at the area paid little attention on analysis of storage performance and capability of some useful layers in the formation (Wu 2013; Yang et al. 2017). The other key uniqueness is that the model was heterogeneous and considered important features that are representative of the storage site, unlike some earlier work which assumed that the site model was homogeneous (Ling et al. 2013a; Jiang et al. 2014; Xie et al. 2015).

The main objective of the study is to establish the optimal CO₂ injection scheme that will enhance CO₂ storage without jeopardizing the safety of the cap rock⁷ and the formation above it. This will ensure that the mitigation strategy is safe and secure and that no excessive pressure will be allowed to favor leakage of CO₂ to the shallow positioned groundwater sources as well as to the earth’s surface. Moreover, it establishes the safe lateral and vertical extents of CO₂ plume migration from the center of an injection outwards for the entire life of the CCS project. To this end, parameters including injection rates, bottom hole flow pressure, and cumulative amount of stored CO₂ have been analyzed to ensure safe injection of CO₂. The obtained results are useful as they provide additional understanding on CO₂ storage optimization strategies and reservoir performance for the safe storage in deep saline aquifer. Moreover, it provides insight on consideration of low carbon and carbon neutral energy technology as well as enhancement of energy efficiency systems as possible mitigation strategies to lower anthropogenic CO₂ emissions. Further, the study serves as an adjustment plan for future application of the commercial phase of the Shenhua CCS project. Finally, the safe values and technique evaluated may serve as benchmark information for the different CCS projects of similar nature elsewhere in Ordos or worldwide, aimed at establishing effective global climate change mitigation strategy. It is very crucial to perform the CO₂ injection process at limited conditions for fracture opening and reservoir buildup pressures through employment of CO₂ injection best practices and appropriate monitoring. Reservoir heterogeneity and multiphase fluid flow processes are encouraged during modeling for accurate and practical results.

2 Location and geological description of the study area

2.1 Site layout

The Shenhua CCS project is located in the Eastern part of the Northern Yishan Slope in the Ordos basin. The project plant is within Ejin Horo Banner of Ordos city, while the storage site is located at Chenjiacun village, Erdos city, 11 km apart (Fig. 1); both are in the Inner Mongolia Autonomous Region, China (Xiuzhang 2014; Zhang et al. 2016). The location is ideal and recommended for CO₂ geological storage in China (Yu et al. 2017). The site has an injection well known as ZhongShenZhu1 (ZSZ1)⁸ and two other monitoring wells ZhongShenJian1 (ZSJ1)⁹ and ZhongShenJian2 (ZSJ2)¹⁰ at a distance of 70 m and 30 m, respectively, from the ZSZ1 (Fig. 1c) (Li et al. 2016b).

Fig. 1

The map of the Chenjiacun site in Ordos basin showing the Shenhua CCS demonstration project plant and sequestration site (a and b), and (c) is the relative location of injection and monitoring wells (modified after Li et al. (2016b) and Zhang et al. (2016))

2.2 Geological description

The Shenhua storage site is located at the largest sedimentary and intracratonic basin known as Ordos, which has an area of approximately 37 × 10⁴ km² in North-Central China (Carr et al. 2011). Taking Yishan slope ranges of the Ordos basin as a reference, Shenhua is located in the East section of the Northern massive Yishan Monoclines, which have been identified as high potential geological structures for large-scale CO₂ sequestration in China (Zhu et al. 2015; Yu et al. 2017). Because of its nature of being a large-scale craton sedimentary basin, Ordos has multicycle sedimentary layer sequences over the Archaeozoic to Proterozoic metamorphic rock series (Li et al. 2016a). The sedimentary layers at the basin from the old to the younger in a succession are as follows: the Middle Ordovician Majiagou subsurface layer, Benxi upper Carboniferous and Tiyuan formations, the lower Permian Shanxi formation, Shihezi formation (Middle Permian), and the upper Permian Shiqianfeng subsurface layer and lower Triassic Liujiagou and Heshanggou formations, as shown in Fig. 3. The basin has promising tectonic stability and has some simple structures showing historic occurrence of tectonic events (Li et al. 2016a; Diao et al. 2018). The general structural characteristics of the subsurface environments of the site have been described based on the seismic survey conducted in 2010 for a formation depth of 500 to 3000 m which resulted into a recommendation of four possible blends of reservoir and seal in the Triassic and Permian systems favorable for CO₂ sequestration (He et al. 2010). The general formation of the basin at the Shenhua site has low porosity and low permeability with a very slow movement of groundwater ideal for CO₂ storage. The composition of saline water is mainly Cl–Ca.Na, with total dissolved solids (TDS)¹¹ of 65.1 and 31.2 g per liter water (g/L) at Liujiagou and Shiqianfeng formations, respectively, whereas Shihezi and Majiagou formations have much lower salinity of about 9.5 g/L and 7.1 g/L, respectively (Diao et al. 2018). The basin contains huge reserves of oil, gas, and coal resources which has attracted energy investment in China. Environmental challenges which are encountered in and around the basin seems to be manageable due to stable development of late Triassic and Permian layers of sandstone that have attracted attention for CO₂ geological storage and sequestration in deep saline aquifers (Yu et al. 2017).

China is in the early stages of carbon storage, though in terms of carbon capture technology it has reached a considerably matured phase (Zhang et al. 2016). The Shenhua CCS demonstration project planned to safely inject 100,000 t/year of CO₂ in a saline aquifer consisting of multiple geological units at a depth ranging from 1576 to 2453 m below the earth’s surface (Zhang et al. 2016). As mentioned in a previous paragraph, earlier researchers have identified Liujiagou, Shiqianfeng, Shihezi, Shanxi, and Majiagou reservoir-cap rock assemblages as the main formation rocks in the storage site. In this study, Liujiagou, Shihezi, and Majiagou have been selected as the target formation layers for simulation, as they have major impacts on CO₂ storage (Wu 2013; Yu et al. 2017). The descriptions of the selected formations have been reported in a number of literatures (Yang 2012; Zhang et al. 2016; Yu et al. 2017). Liujiagou, which has a total thickness 123 m, extends from a depth of 1576 to 1699 m. It has inter-bedded sealing rocks of thickness of 39 m and 10 m at the starting of the 1576-m and 1680-m depths, respectively. The cap rock is spatially discontinuous with a varying thickness of 5–15 m, mainly composed of localized relatively permeable rock of arkoses and lithic feldspathic sandstone. Shihezi is another formation layer having a total thickness of about 242 m at a depth range of 1990–2232 m. The formation is composed of a high amount of mudstone at the top as a regional seal of the thickness of about 116 m. The remaining thickness of 126 m serves mainly as a reservoir; it is predominantly composed of feldspathic litharenite and feldspathic quartz sandstone. Majiagou is the deepest formation layer at a depth of 2367 m. The layer extends to more than 2820 m below the ground surface. Its composition is mainly fractured limestone and dolostone. The coal bed strata thickness of approximately 81 m (at depths of 2286–2367 m) has been serving as the seal of the reservoir in the Majiagou region. Interbedded muddy siltstones and mudstones have also been observed at depths between 2426 and 2512 m.

It is important to understand that the Shenhua CCS project is a vital global project due to the fact that China and USA signed the joint contract in November 2014 to collaborate on major environmental issues related to clean energy and global climate change, and that by the end of 2020, the two countries should have carried out major CCS projects in China as part of efforts towards mitigating emission of greenhouse gases into the atmosphere (Zhang et al. 2016). Therefore, this project serves as a guide for large-scale CCS projects to be established in China to support international efforts towards mitigating greenhouse gases emission and combat global climate change.

2.3 Formation conditions

The Shenhua deep saline aquifer is characterized as low porosity and low permeability formation (Yan et al. 2014). The average geothermal gradient¹² of the basin is 0.025 °C per meter, and the basin surface temperature is 10 °C. Pressure gradient is at an average of 9.74 kPa/m. This pressure gradient is for both Paleozoic saline aquifers and gas reservoirs at the site. As far as the geothermal and pressure gradient of the basin is concerned, it has been estimated that the injected CO₂ will be in supercritical state at the depth range starting at around 850 m from the surface (Jiao et al. 2011). The temperature and pressure variations with depth which was recorded from the logging data showed the trend stipulated in Fig. 2. However, in this study the temperature was assumed to be isothermal¹³ at an average of 56 °C as was the case for Liu et al. (2016) (Fig. 3).

Fig. 2

Formation wellbore pressure and temperature initially recorded from log data, adopted from (Liu et al. 2016)

Fig. 3

Formation lithology and stratigraphy in the Ordos basin, describing main formation layers and their respective profile and geological characteristics (Li et al. 2013; Yu et al. 2017)

2.4 Carbon dioxide injection status

As at the end of 2015, the project injected 0.302 million tons of CO₂ which was a cumulative of 0.1 million tons per year for three consecutive years of CO₂ injection since it started in 2010 (Kuang et al. 2015; Li et al. 2016b). It was predicted that the injected formations will be subjected to an increased pressure buildup. To forestall the risks of pressure buildup and to have an increased CO₂ injectivity, the pre-injection geological assessments of the formation were conducted (Raziperchikolaee et al. 2013). The results revealed that there was a need to employ multilayer injection procedures and perform hydraulic fracturing (Wang et al. 2010; Diao et al. 2015; Li et al. 2016a) as the single storage layer would not be able to accommodate the planned injection rate over a targeted time period (Li et al. 2016a). However, the hydraulic fracturing operation option may result in two opposing scenarios. It can optimize CO₂ sequestered in the formation but may also initiate or create a risk of CO₂ leakage to the surface through fractures. Therefore, it is of utmost importance to maintain cap-rock integrity for safety in the entire period of the project. Liu et al. (2016) used a simplified heterogeneous 2-dimensional (2D) model to study thermal evolution of aquifer and wellbore during injection. Their results revealed that heterogeneity has great impact on CO₂ flow rate and that the overburden layers variations have significant contribution to the fluid flow rates. In this paper, with the utilization of formation heterogeneity, formation layers, injection rates, amount of cumulative CO₂, and bottom hole pressure variations, an optimum injection strategy was proposed and reservoir performance was analyzed for safe storage in the deep saline aquifer. Further, global CO₂ emission mitigation strategies including injection into the deepest layer, carbon free and low carbon energy technologies, and enhancement of energy efficiency were recommended.

3 Methods

3.1 Modeling approach

A regional 3D heterogeneous geological model was constructed with the utilization of well logging reports, 3D baseline seismic records, isopach maps¹⁴, bore hole information, time-lapse vertical seismic profile (VSP) interpretations and geological data gathered from public resources such as published books, reports, and articles (Yang et al. 2005; Jiao et al. 2011; Wu 2013; Xie et al. 2015; Diao et al. 2018). The constructed geological model comprises structural and stratigraphic profiles, temperature, pressure, and lithologic properties such as porosity and permeability.

The size of the geological model in terms of length, width, and depth is approximately 13 km, 9.5 km, and 1.1 km, respectively (Fig. 4a, b). The model was built by using the commercial software LandSim, through its inbuilt modeling package LandMod¹⁵. The package has a capability of modeling complex structures in high accuracy and quality. It can handle and speedily generate large numbers of geological grids in a considerable short time. The optimized Kriging algorithms in the software helped in maximization of a multicore central processing unit and the graphics processing unit resources that supported quick calculation of petro-physical properties of the reservoir model (Tracy Energy Technologies 2016). The geological model grid sizes for the x, y, and z axes were set to 130 × 95 × 47, respectively.

Fig. 4

3D reservoir model with an injection well: a field porosity and b field permeability

Once the regional geological model was completed, an extraction of 3D geological model 7 km × 7 km centered at the injection well (Fig. 5b) was done in order to produce an effective computational mesh for the CO₂ injection simulation and analysis. The main reasons for the model extraction were to enhance simulation accuracy and improve modeling efficiency through local grid refinement¹⁶ close to the injection. Referring to the location of the CO₂ injection well ZSZ1 as is seen in Fig. 5a, the well is slightly near the northeast border of the model (Li et al. 2016b). It was predicted that injection of CO₂ in the constructed regional 3D geological model would not be effective enough to spread to a greater distance to allow for safe storage as intended. The model size was practically large, and with low permeability (Liu et al. 2016). The boundary conditions were retained at their constant initial values, implying that the system was infinitely behaving, and that the effect would not reach the model boundary. This approach had been previously adopted by some researchers such as Yang et al. (2017). The challenge encountered in a 7 km × 7 km model was the border effect during modeling and simulation. To address the effect, a geo-statistical method was employed in assigning attributed properties of the model in the extended area. Petro-physical properties such as porosity and permeability of the region of unknown properties were interpolated by using the optimized Kriging method (Fig. 6).

Fig. 5

2D reservoir geological model showing a ZSZ1 well location in a permeability model and b a new proposed working boundary (the square boundary)

Fig. 6

New model porosity, permeability distribution

To intensify the degree of accuracy in the analysis of the extracted geological model (7 km × 7 km), an additional grid refinement of 25 m × 25 m was performed in an area of 140 m × 140 m, which comprised monitoring well ZSJ1 (Fig. 7). The refinement led to the enhanced observations of the pressure front during the injection process and the CO₂ leading edge for the model.

Fig. 7

Well area grid refinement

Based on the re-drawn geological model (140 m × 140 m), numerical simulation of CO₂ storage was conducted. The influence of various operating conditions such as injection rate and reservoir bottom hole pressure to achieve the annual storage target of 100,000 tons of CO₂ in the well ZSZ1 were performed.

3.2 Numerical model for simulations

As previously described in the modeling process, the numerical simulation model used in this study was an extract from a regional 3D geological model with its center being at ZSZ1. The model boundaries and dimensions on the east–west side and north–southern side were 1441 m and 1456 m, respectively. The top surface of the reservoir and its bottom depth from the ground were set at 1540 m and 2558 m, respectively, from the ground surface. The total number of grids was 15 × 15 × 43 (9675 grids), and the final refined grid system model had porosity values ranging from 0.017 to 20.52% and permeability values ranging from 0.001 to 11.48 mD. Figure 8 shows the setup, well positions, porosity, and permeability fields.

Fig. 8

Geological setup, well placement (70 m apart): a porosity field and b permeability field

3.3 Numerical simulation method

LandSim, the detailed 3D reservoir simulator with an unstructured gridding system from Tracy Energy technologies, has been used to perform simulations in this study. The simulator has great ability to model all important complex flowing mechanisms involved in CO₂ storage as well as enhanced recovery processes. It has a very high resolution and can simulate accurately fluid dynamic processes such as diffusion, slippage, desorption, and turbulence (Tracy Energy Technologies 2016).

3.4 Mathematical fluid flow models

The dynamics of CO₂ flow and transport and its interaction with porous media are governed by mass and momentum conservation laws. The equations governing the dynamic multiple phase flow under the isothermal condition are governed by a combination of partial differential equations (Liu et al. 2014).

$$ \frac{\partial {M}^{\kappa }}{\partial t}=-\nabla .{F}^{\kappa }+{q}^{\kappa } $$

(1)

where M is the mass buildup in the system [ML⁻³], F is the mass flux [ML⁻²T⁻¹], q is the source or sink [ML⁻³T⁻¹], t is time [T] in seconds, ∇ is the divergence, and κ is one of the mass components such as CO₂, air and water. If Eq. (1) involves the water component in the fluid system, the governing equation becomes

$$ \frac{\partial }{\partial t}\left[\phi \left({\mathrm{X}}_l^w{S}_l{\rho}_l+{X}_g^w{S}_g{\rho}_g\right)\right]=-\nabla .\left\{{X}_l^w{\rho}_l\left(-k\frac{k_{rl}}{\mu_{\mathrm{l}}}\left(\nabla {P}_l-{\rho}_lg\right)\right)+{X}_g^w{\rho}_g\left(-k\frac{k_{rg}}{\mu_g}\left(\nabla {P}_g-{\rho}_gg\right)\right)\right\}+\left({q}_l^w+{q}_g^w\right) $$

(2)

where ϕ is the porosity, X_l with superscript w is the mass fraction of component w in phase l; S is the saturation; g is the gravitational acceleration [LT⁻²]; w represents water; k is permeability [L²]; ρ is a density [ML⁻³]; k_rg represents relative permeability; P stands for pressure [ML⁻¹T⁻²]; l, g, and s stand for liquid, gas, and solid phases, respectively; and μ is the viscosity [ML⁻¹T⁻¹].

The governing equations for the CO₂ component in the multiple phase fluid systems can be rewritten as

$$ \frac{\partial }{\partial t}\left[\phi \left({\mathrm{X}}_l^c{S}_l{\rho}_l+{X}_g^c{S}_g{\rho}_g\right)\right]=-\nabla .\left\{{X}_l^c{\rho}_l\left(-k\frac{k_{rl}}{\mu_{\mathrm{l}}}\left(\nabla {P}_l-{\rho}_lg\right)\right)+{X}_g^c{\rho}_g\left(-k\frac{k_{rg}}{\mu_g}\left(\nabla {P}_g-{\rho}_gg\right)\right)\right\}+\left({q}_l^c+{q}_g^c+{q}_s^c\right) $$

(3)

X_l with superscript c represents the mass fraction of component c in phase l, while c represents CO₂.

Equation (3) is the key governing equation describing the composition of CO₂ in multiple-phase fluid systems.

3.5 CO₂ injection strategies and input parameters

3.5.1 Injection strategies

Three injection strategies were investigated for both layered formation and unified formation. CO₂ injection strategies performed involve a constant bottom hole pressure¹⁷ (BHP) injection, a constant CO₂ flow rate injection, and a constant flow rate injection with a fixed BHP. Therefore, a total of six injection scenarios were simulated to analyze the injectivity and storage performance of the reservoir.

3.5.2 Input parameters

A 3D heterogeneous site-based model was used to perform investigations at the Shenhua CCS demonstration project. The reservoir model dimensions were 1456 m long, 1441 m wide, and 1018 m deep. Porosity and permeability values ranged from 0.017 to 20.52% and 0.001 to 11.48 mD, respectively. The top surface depth of the reservoir is 1540 m, and the bottom surface is at a depth is 2558 m. Table 1 provides hydrogeological data, and Table 2 gives additional reservoir layer parameters used in this study.

Table 1 Reservoir hydrogeological parameters

Table 2 Reservoir layer parameters used for three injection strategies

Figure 9 provides additional information on the position and locations of the layers perforated for CO₂ injection; also, the shown layers are related to those stipulated in Table 2.

Fig. 9

a Location of injection well; blue lines are the seismicity surveyed area (b) layers injected with CO₂ and their relative depth— layers 1, 2, and 3 representing Liujiagou, Shihezi, and Majiagou, respectively. c Permeability and Northing of the formation (modified after Zhang et al. (2016))

Scenarios simulated to investigate the reservoir layers performance and CO₂ injectivity¹⁸ of the Shenhua CCS demonstration project are as stipulated in Table 3.

Table 3 Combination of simulated parameters

3.6 Rock-fluid properties

The rock permeability properties such as water-gas relative permeability are necessary information during modeling, as they serve in guiding the fluid movement in the reservoir. Moreover, they have an effect on injectivity as in most cases the region around the well bore is highly saturated with water (Liu et al. 2010). Van Genuchten (1980) and Corey (1954) functions in sandstone and mudstone were employed to compute aqueous and gas relative permeability. Furthermore, the capillary pressure curve was calculated based on van Genuchten functional form (Akaku 2008; Liu et al. 2010). Figure 10 shows the relative permeability curves for the rock-brine-CO₂, and its use in the simulation.

Fig. 10

a Relative permeability curve. b Capillary pressure curve for a reservoir

4 Results and discussions

Global climate mitigation policy has constantly recommended and emphases on the safe operations of CCS projects. Therefore, a high level of project monitoring during and after the injection process is very crucial. Pressure buildups and possible CO₂ leakage¹⁹ into the shallow portable water sources and to the Earth’s surface are of concern to life. However, the risk becomes more severe when the cap rock is highly fractured, as it will allow huge quantities of CO₂ to escape to the environment. To have prior information on the behavior of the reservoir upon CO₂ injection and storage, simulation analysis is vital. Different injection scenarios need to be analyzed and assessed for safety assurance and efficiency of a CCS project. In this study, a total of six CO₂ injection scenarios were performed to investigate storage performance and injectivity of the deep saline aquifer at the Shenhua CCS site model, and the results were analyzed as follows;

4.1 Scenario 1: constant BHP injection at 150 % original formation pressure,: unified formation injection

In scenario 1, the bottom hole pressure was maintained at 150% of the original formation pressure, as the injection pressure should not exceed one half of the original formation pressure (Carr et al. 2011). The injection process was investigated for a period of 10 years with the aim of assessing CO₂ injectivity and reservoir storage performance. Simulation results revealed that a three-layer unified injection system with 150% of original formation pressure achieved an average injection rate of about 160,000 t/year. However, the injection rate process encountered a pronounced obstruction at the start of the injection process which lasted for a short period of approximately 3 months (Fig. 11a). Soon after breaking through the obstruction, the injection rate began to rise rapidly to a maximum of 270,000 t/year within a period of 3 years. Thereafter, at the end of the 3rd year of injection, the injection rate slowly decreased to less than 60,000 t/year towards the 10th year of simulation. Furthermore, observations revealed that the cumulative injected amount of CO₂ for a period of 10 years was 1,580,000 t (Fig. 11b).

Fig. 11

CO₂ injection curve characteristics: a injection rate curve and b cumulative injection curve

4.2 Scenario 2: a constant injection rate of 100,000 t/year: unified formation injection

In this scenario, the CO₂ injection rate was fixed at the rate of 100,000 t/year and the rate of change of BHP was investigated. The idea was to analyze the response of the reservoir on storage under the CO₂ injection rate of 100,000 t/year.

Simulation results revealed that, at a constant injection rate of 100,000 t/year, the BHP increased rapidly to over 150% of the original formation pressure. The peak value of BHP attained was 56 MPa which occurred in the initial period of CO₂ injection (Fig. 12). However, soon after reaching its BHP peak value, it sharply dropped to 30 MPa in the 3rd year of the injection process; it then started to slowly rise again from the middle of the 3rd year to the end of the simulation period (10th year). The rise in pressure of more than 150% of the original formation pressure may trigger initiation of the cap-rock fracture which can lead to CO₂ leakage to the environment. Therefore, scenario 2 has little viability as a CO₂ storage strategy towards curtailing CO₂ emission.

Fig. 12

BHP flow characteristics curve under a constant injection rate of 100,000 t/year

4.3 Scenario 3: a constant injection rate of 100,000 t/year and a constant BHP of 150% original formation pressure: unified formation injection

In scenario 3, the pressure of the formation was maintained to not more than 150% of the original formation pressure; further, the injection rate was set to a level that did not exceed 100,000 t/year. Simulation results showed that the maximum pressure of the bottom hole rose abruptly in the initial year of the injection from approximately 30 MPa to over 35.5 MPa in the first year. It then maintained a constant pressure for a year before it sharply dropped to a minimum pressure of 29.5 MPa in the 4th year. It again peaked up from the start of the 4th year to a pressure of 32.5 MPa at the end of the 10th year. Figure 13 shows the BHP curve characteristics from the time of injection to the end of the simulation.

Fig. 13

Bottom hole flow pressure characteristics curve under a fixed injection rate of 100,000 t/year and constant pressure of 150% of the original formation pressure

The CO₂ injection rate and its cumulative injected amount for the entire simulation period were studied in this scenario. Observations showed that, at the early stages of the injection processes, the injection rate dropped abruptly from 100,000 to 36,000 t/year within a period of approximately 4 months. It then peaked up to 100,000 t/year at the end of the 1st year of the injection process. The fall of the injection rate was probably caused among other factors by the formation pore volume originally in place and immediate dissolution of CO₂ in the brine. The increase in injection rate happened after saturation of the formation pores which subsequently rose to the targeted amount of 100,000 t/year. After achieving the constant rate of 100,000 t/year, the amount of cumulative CO₂ injected reached 980,000 t in the 10th year of simulation (Fig. 14). These simulation results ascertain that it is practically possible to achieve the CO₂ storage target of 100,000 t/year at the Shenhua CCS site using this injection strategy. The CO₂ plume distribution and migrations were also investigated. Figure 15 shows the plume distribution after 3 and 10 years of CO₂ injection, respectively.

Fig. 14

CO₂ injection curves characteristics: a injection rate curve and b cumulative injection curve

Fig. 15

CO₂ plume distribution: a after 3 years of injection and b after 10 years of injection

Investigations revealed that 3 years of CO₂ injection led to lateral migration of CO₂ that did not exceed 500 m of which its vertical rise was limited to 130 m. However, longer periods of injection time revealed more CO₂ plume accumulation in the reservoir and its migration is laterally dominated compared to vertical migration. This might be due to the presence of mudstone layers which serve as barriers or seals that restrict vertical migration of the CO₂ plume. This observation is similar to that of other researchers such as Akaku (2008). The fact that there was heterogeneity which involved low permeability layers and restricted flow system has led to increased advantage in the storage safety of CO₂ in the reservoir. In this study, it was observed that for 10 years of CO₂ injection, the plume lateral movement did not exceed 600 m and the vertical rise was less than 200 m.

4.4 Scenario 4: constant BHP injection of 150% of the original formation pressure: layered formation injection

In scenario 4, individual layer performance was evaluated during the injection process. As it was previously stated, the layers that were investigated involve Liujiagou, Shihezi, and Majiagou. Simulation results revealed that under the given injection strategies and conditions, Liujiagou showed the lowest injectivity capability and storage performance of the three layers tested. On the other hand, Majiagou had the best storage ability and the highest injectivity as compared to Shihezi and Liujiagou seen (Fig. 16a, b).

Fig. 16

CO₂ injection curves characteristics: a injection rate of each layer and b cumulative injected amount

4.5 Scenario 5: constant flow rate injection of 100,000 t/year: layered formation injection

During the early stage of CO₂ injection, the BHP reached 130 MPa, 123 MPa, and less than 100 MPa respectively for Majiagou (2423–2426 m), Shihezi (2205–2208 m), and Liujiagou (1690–1699 m) formation layers. The BHPs for both layers are intolerable as they can pose a great danger to the cap rocks and their successive overburdened layers; this may have great potential for the risk associated to CO₂ leakage. However, the BHP dropped to less than 40 MPa for both layers within the initial 2 years of injection, before it started to rise gently in the 3rd year towards the end of simulation process (Fig. 17). The increased BHP at the start of the injection process was attributed to the depth of each individual layer; the deeper layer Majiagou experienced the highest pressure and the shallowest layer the Liujiagou experienced lower overburden pressure.

Fig. 17

Bottom hole flow pressure curve for scenario 5

4.6 Scenario 6: the constant injection rate of 100,000 t/ year and a constant BHP 150% of the original formation pressure, layered formation injection

With scenario 6, different injectivities were experienced in three layers simulated under constant CO₂ injection rate and fixed BHP (150% of the original formation pressure). The Majiagou formation recorded the highest BHP of about 35.8 MPa, a pressure which was maintained for 2 years before it decreased sharply to 31 MPa in the third year of CO₂ injection. The BHP rose again continuously up to the end of the simulation period. The Shihezi layer (2205–2208 m perforated section) maintained a uniform BHP of 33 MPa for 4 years before it dropped to 30 MPa in the 6th year, though in the middle of the 6th year the pressure increased to 33 MPa at the end of the simulation period. The behavior was different for the Liujiagou formation (injection layer 1690–1699 m), where the lowest BHP of 26.4 MPa was recorded from the start of the injection period to the end. Figure 18 shows the pressure changes with time during the injection process for scenario 6.

Fig. 18

Bottom hole flow pressure curve for three injected layers

The layer which showed great ability to store the largest amount of CO₂ compared to others was Majiagou, which at the end of 10 years was able to cumulatively store more than 900,000 t of CO₂; Shihezi and Liujiagou formations were the second and third with the capacities of 780,000 and 300,000 t, respectively (Fig. 19a). The injection rate was high during the entire simulation period for both Majiagou and Shihezi formations, though Majiagou was able to reach a peak of 100,000 t/year before Shihezi. It peaked in less than 2 years, while Shihezi reached the peak in the 4th year of injection. In contrary, Liujiagou formation did not attain the peak injection rate at all (Fig. 19b). This implies that Majiagou has the best injectivity properties compared to Shihezi and Liujiagou.

Fig. 19

CO₂ injection curves characteristics: a injection rate of each layer and b cumulative injected amount

It was discovered that for the 6 simulation scenarios in 10 years of CO₂ injection, only one injection strategy was the safest and effective mitigation strategy to be adapted. This was detected after the assessment of its total cumulative CO₂ stored to the end of the project, and also on its safety in terms of pressure buildup and CO₂ leakage. Therefore, it is highly recommended that detailed feasibility studies or early assessment of the CCS projects should be performed, so as to avoid problems related to CO₂ leakage to the atmosphere, which is highly linked to the global climate change.

5 Conclusions

The CCS method is a very attractive strategy for global climate change mitigation. However, it is associated with the risk of geological and environment hazards, such as leakage of injected CO₂, seismicity, and fault activities. In this study, a 3D numerical model was developed and then simulated to analyze the CO₂ injectivity and reservoir performance for enhanced CO₂ storage at the Shenhua CCS demonstration project site in the Ordos basin. Reservoir heterogeneity was considered during model construction and simulation. LandSim, a detailed 3D reservoir simulator from Tracy Energy Technologies, was used to perform simulation analysis of the study. CO₂ injection rate, bottom hole formation pressure²⁰, and CO₂ plume movement in the reservoir were investigated. The impact of relative layer depths with their respective porosity and permeability on injectivity and reservoir storage capability were explored. The following were found during the investigation.

• All layers have significant contribution to the CO₂ spatial distribution and fluid flow which in turn affect reservoir CO₂ injectivity and storage performance. Higher injection rates in low permeable formations have significant effects on pressure buildup in the reservoir. The higher pressure buildup may lead to cap-rock fracture initiations and cause leakage of CO₂ to the groundwater sources and eventually the surface. The release of CO₂ to the atmosphere from the leaks may have a significant contribution on global climatic changes.

• Injectivity increased with the increase in pores and pore connectivity. Permeable layers allowed more CO₂ to be injected and stored as compared to less or non-permeable layers. The injection rate was higher in more permeable layers, particularly the deeper layers of the reservoir indicating that less injection time was used in those layers.

• The vertical and horizontal migration of the injected CO₂ plume requires special attention and control. Establishment of the maximum CO₂ migration distance serves as a control or guide for establishment of a safe and acceptable migration distance during injection. Movement of CO₂ plume to the shallow groundwater sources or communicable cracks and faults with a pathway to the surface may result into CO₂ leakage and release to the atmosphere, hence impacting on global climatic conditions. The optimum CO₂ sequestration strategy which does not result into excessive migration of injected CO₂ plume and limit formation pressure buildup is recommended. In this study, migration limits were safe.

• The CCS in deep saline aquifer is the most favorable global strategy for curtailing anthropogenic CO₂ release into the atmosphere. With the adoption of this mitigation strategy, the international community may afford the time for extended use of fossil fuel before viable cleaner and sustainable energy source alternatives are developed. Although the study was performed at the Shenhua site, it may have considerable impacts on understanding safe and optimized CO₂ storage processes and exploration of effective climate change mitigation strategies. However, investments in low carbon energy, carbon free technologies, energy efficiency enhancements, and changing human behavior to reduce energy consumption are other important mitigation strategy options to be taken into consideration.

It was revealed that out of the 6 scenarios in 10 years of CO₂ injection, only 1 of the injection strategies was considered safe and effective for adoption. The selection criterion of the effective strategy was arrived after an assessment of its total cumulative CO₂ stored and its related fluid flow dynamics during the project lifespan. Therefore, it is recommended that the CO₂ injection process should be undertaken at the Majiagou layer. This is due to the fact that the layer is a very deep underground at an average depth of above 2400 m and has an adequate storage space to accommodate the desired rate of 100,000 t/year. Moreover, its geological settings (large overburden) favor storage safety in the event of significant uplift that may cause induced seismicity. It will also limit CO₂ plume that will come into contact with shallow groundwater sources. Hence, efforts to develop and implement the commercial-scale CO₂ storage project at the Shenhua facility is encouraged to significantly increase and speed up CO₂ emission reduction. Therefore, to guarantee a conducive and successful sequestration process, the injection pressure formation stability study was carried out to establish the necessary value parameters for the injection process. The safe injection parameters estimated in this study may serve as benchmark information for CCS projects of similar nature elsewhere. However, it is recommended that a detailed feasibility study should be undertaken prior to the implementation of any new CCS projects to avoid problems related to CO₂ leakage to the atmosphere and seismicity that might contribute to global climate change.

This study further recommends that an optimum CO₂ sequestration strategy which limit formation pressure rise and control excessive CO₂ plume migration should be adopted. This is because it was discovered that deep underground storage at an average depth of over 2400 m has optimum storage capacity due to its adequate storage space to accommodate the desired rate of 100,000 t/year. Additionally, its geological settings favor storage safety in the event of formation uplift that may lead to induced seismicity. Not all, it will also limit CO₂ plume that may come into contact with shallow groundwater sources. Finally, energy efficiency systems and low carbon or free carbon technologies are also recommended.