A sensitivity analysis of factors affecting in geologic CO₂ storage in the Ordos Basin and its contribution to carbon neutrality

1.   Introduction

Carbon neutrality has become an international effort and a commitment of the Chinese government. However, China’s carbon neutrality goal is facing many challenges, such as high total carbon emissions, short time of carbon emission reduction, many challenges in economic transformation and upgrading, and difficult energy system transformation. As the world’s largest developing country, China needs to take tougher measures to reduce carbon emissions in wider areas in a shorter time to achieve carbon neutrality by 2060 (Mallapaty S, 2020; Salvia M, 2021; Xu T et al., 2022). Developing geologic CO₂ storage technologies is a strategy for China to reduce CO₂ emissions and ensure energy security in the future, and it is also an important means to build ecological civilization and to achieve sustainable development (Bachu S, 2000, 2003; Zeng RS et al., 2004; Jiang HY et al., 2007; Li GJ and Zhang J, 2011; Goodarzi S et al., 2012; Chen B et al., 2018; Li Q et al., 2019; Ma X et al., 2021; Wen DG et al., 2014). To select and optimize the design of CO₂ storage areas to ensure that the injected CO₂ is stored underground safely, effectively, and permanently, it is necessary to assess the sensitivity of the influencing factors for CO₂ storage in advance.

Many scholars have studied the influencing factors of geologic CO₂ storage. (Wiese B et al., 2010) conducted a local sensitivity analysis of parameters affecting the CO₂ injection rate of a single well and concluded that permeability has the greatest impact, followed by the injection pressure, while vertical anisotropy has a lower impact. Ershadnia B et al. (2020) use a transition-probability based approach to simulate heterogeneous systems with binary facies distributions and the resulting petrophysical properties at the field scale. Results reveal that for a given volume of injected CO₂, shorter injection times yield higher total amounts of trapped CO₂. In the study of the CO₂ migration law on different scales in Mount Simon aquifers in the Illinois Basin, Zhou QL et al. (2010) found that relatively low permeability and high intake pressure have strong impacts on CO₂ storage. Ke YB et al. (2012) conducted a numerical simulation study of CO₂ storage and injection in saline aquifers in the Jianghan Basin. The sensitivity analysis of salinity in this study showed that the increasingly high salinity of reservoirs corresponds to increasingly strong pressure accumulation. Zhao RR et al. (2012) conducted a simulation study and parameter sensitivity analysis of fluid migration in deep saline aquifers in the Songliao Basin after CO₂ injection. This study showed that residual gas saturation and the anisotropy of saline aquifers have the greatest influence on CO₂ dissolution capture, followed by salinity, while residual liquid saturation and initial CO₂ concentration have the lowest influence. Zheng F et al. (2014) analyzed the effects of parameters (hydrogeological parameters and salinity) of saline aquifers in the Subei Basin on CO₂ storage, migration, and leakage. The results of these studies have strongly promoted the study of geologic CO₂ storage. However, existing literature tends to conduct comparative analyses of partial influencing factors and does not provide comprehensive analyses of influencing factors of geologic CO₂ storage.

To achieve the carbon neutrality goal, geologic CO₂ storage technologies are predicted to reduce CO₂ emissions by 0.6×10⁹‒1.4×10⁹ t in 2050 and by 1.0×10⁹‒1.8 ×10⁹ t in 2060 according to the current technology development. Taking the Upper Triassic Yanchang Formation in the central part of the Shaanbei Slope in the Ordos Basin as a case study, this study investigated the effects of seven factors affecting the CO₂ storage capacity of reservoirs, namely reservoir porosity, horizontal permeability, temperature, formation stress, the ratio of vertical to horizontal permeability (kv/kh), capillary pressure, and residual gas saturation. The purpose of this study is to provide data basis and technical support for the design and implementation of industrial CO₂ storage projects in the Ordos Basin in the future. Moreover, this study presented the actions China has taken in the Ordos Basin to achieve the great carbon neutrality goal.

2.   Regional geology

This study focuses on the Huaziping oil area on both sides of Hezhuanggou District, western Huaziping Town, Ansai County, Shaanxi Province. The Huaziping area is a part of the Xingzichuan Oil Production Plant of the Yanchang Oilfield. In terms of regional tectonics, it is a monoclinal structure inclining from east to west lying in the middle section of the Shaanbei Slope in the Ordos Basin. It is mostly flat but has multiple small nose-shaped structures locally. The strata in the area incline westward, with a dip angle of about 0.6° (Lei XL et al., 2008).

Based on its evolutionary history and its current structural morphology, the Ordos Basin is divided into six major structural units, namely the western margin thrust belt, the Tianhuan Depression, the Yishan Slope, the Jinxi Flexure Belt, the Yimeng Uplift, and the Weibei Uplift (Fig. 1).

Figure  1.  a‒tectonic framework in China showing the spatial location of the Ordos Basin (modified from Groves DI et al., 2020); b‒structure-outline map of the Ordos Basin (modified from Li SX et al., 2017).

DownLoad: Full-Size Img PowerPoint

Based on the drilling data of the Huaziping area (Fig. 2), the strata in the study area are divided into the Quaternary loess layer, and the Luohe, Anding, Zhiluo, Yan’an, Fuxian, and Yanchang Formations. Table 1 shows brief lithological descriptions of these strata. The oil reservoir in the Chang 6 Member of the Yanchang Formation serves as both the primary block and stratum developing in the Huaziping area and the principal reservoir for geologic CO₂ storage (Fig. 3). The stable Chang 6 Member is mainly composed of gray and dark gray medium-fine-grained feldspar quartz sandstones and feldspar lithic sandstones (Li B, 2014; Zhang ZM, 2015; Gao ZD, 2017). With a porosity of 7%‒12% (average: 9.4%) and permeability of 0.1×10⁻³‒5×10⁻³ μm (average: about 0.94×10⁻³ μm²), this member is a low-porosity and low-permeability reservoir (Zheng YR et al., 2011; Zhao XS et al., 2019). The formation pressure in the Chang 6 Member is 4.68‒9.46 MPa, with an average of 7.08 MPa (Fig. 4). The average temperature and the geothermal gradient of the member’s oil reservoir are 47.0°C and 2.7°C/100 m, respectively (Zhang TJ et al., 2016). The overlying Chang 4 and 5 members show the development of mudstones and thus are favorable cap rocks. Therefore, factors such as reservoir burial depth, lithological characteristics, the sealing of regional cap rocks, and geological trap conditions suggest that this series of strata are qualified to serve as a site for geologic CO₂ storage.

Table  1.  Geological and lithological characteristics of the Huaziping area.

System	Series	Formation	Symbol	Thickness/m	Lithology
Quaternary			Q	0‒200	Alluvial loess layer, in unconformable contact with underlying strata
Cretaceous	Lower	Luohe Formation	K	300	Variegated conglomerates interbedded with sandstones, mudstone bands, or sandstone lens. They are basal conglomerates of the Zhidan Group
Jurassic	Middle	Anding Formation	J3a	80‒150	Brownish-red mudstones primarily, interbedded with variegated marls in the upper part
		Zhiluo Formation	J2z	300	Interlayers consisting of grey-green and light grey conglomerates and purplish-gray and purplish-red mudstones. Mudstone dominating the upper part and sandy conglomerates occurring at the bottom
	Lower	Yan’an Formation	J1y	300	Bottom: medium-coarse- and fine-grained sandstones; top and upper parts: dark sandstones and interbeds consisting of mudstones and shales; top: dark marls
		Fuxian Formation	J1f		Lower part: grayish-yellow and purple thick-laminated massive sandstones or sandstones; upper part: variegated mudstones and sandy mudstones
Triassic	Upper Series	Yanchang Formation	T3y	> 700	Yellowish-green and grayish-black mudstones and interlayers consisting of sandstones and siltstones, interbedded with coal seams

 | Show Table

DownLoad: CSV

Figure  2.  Geological profile of the Huaziping area.

DownLoad: Full-Size Img PowerPoint

Figure  3.  The histogram of the Chang 6 oil reservoir.

DownLoad: Full-Size Img PowerPoint

The primary sedimentary facies in the study area include the subaqueous distributary channel microfacies and the interdistributary bay microfacies deposited in the delta front subfacies. The subaqueous distributary channel microfacies consists of large composite sand bodies that are distributed in bands in the NE-SE direction. The interdistributary bay microfacies is composed of thin mudstones, silty mudstones, and argillaceous siltstones. The sand body thickness profile of the study area (Fig. 5) shows that the sand bodies parallel to the river channels take the shape of bands and have good connectivity, whereas those perpendicular to river channels are poorly connected and are flat in the upper part and convex in the lower part.

Figure  4.  Profile of the oil reservoir of the Huaziping area (modified from Wang F et al., 2020).

DownLoad: Full-Size Img PowerPoint

Figure  5.  Sand body thickness profile of the Huaziping area.

DownLoad: Full-Size Img PowerPoint

To determine the lithological characteristics of strata in the study area, five core samples were collected from production well H303-14 (Fig. 6) and were sent for testing and analysis. These core samples were taken at depths of 1476.59‒1478.37 m, 1450.77‒1452.52 m, 1430.97‒1432.72 m, 1421.43‒1423.78 m, and 1418.08‒1419.78 m, corresponding to the Chang 6⁴, Chang 6³, Chang 6³, Chang 61^-2, and Chang 6^1-1 submembers of the Chang 6 oil reservoir, respectively. Mineral content analysis and conventional pore permeability tests were carried out on these core samples.

Figure  6.  The core samples of well H303-14, Chang 6, Huaziping.

DownLoad: Full-Size Img PowerPoint

The types and contents of the minerals in these core samples are shown in Table 2. The main minerals include quartz, potassium feldspar, plagioclase, calcite, dolomite, and clay minerals. The core sample taken from the Chang 6^1-1 Submember has a higher clay mineral content and a lower feldspar content compared to other four core samples, indicating that the Chang 6^1-1 Submember has a higher argillaceous content. The core samples from other submembers have high feldspar content. Despite slightly different contents of various minerals, the overall lithology of the Chang 6 oil reservoir is dominated by sandstones.

Table  2.  Mineral types and contents of core samples.

S.N.	Sampling depth/m	Content of mineral/%
		Quartz	Potassium feldspar	Plagioclase	Calcite	Dolomite	Clay mineral
1	1418.08‒1419.78	37.5	4.7	12.8	2.6	/	42.4
2	1421.43‒1423.78	21.1	8.3	40.5	8.2	2.1	19.8
3	1430.97‒1432.72	19.4	7.7	29.4	10.9	3.8	28.8
4	1450.77‒1452.52	27.7	7.0	26.4	18.4	1.7	18.8
5	1476.59‒1478.37	16.5	11.5	27.2	9.6	2.6	32.6

 | Show Table

DownLoad: CSV

The measured porosity and permeability of the core samples are shown in Table 3. Core samples Nos. 2‒5 are roughly similar to sandstones in the Chang 6 oil reservoir, while the porosity and permeability of core sample No. 1 are more similar to those of the upper Chang 4 and Chang 5 members.

Table  3.  Sample rock porosity and permeability.

S.N.	Stratum code	Sampling depth /m	Confining pressure /MPa	Inlet pressure /MPa	Porosity /%	Permeability /mD
1	61-1	1418.08‒1419.78	2	0.6	1.92	0.07
2	61-2	1421.43‒1423.78	2	0.6	9.29	0.98
3	62	1430.97‒1432.72	2	0.6	11.03	0.70
4	63	1450.77‒1452.52	2	0.6	7.99	0.77
5	64	1476.59‒1478.37	2	0.6	10.28	1.24

 | Show Table

DownLoad: CSV

3.   Simulation principle

The numerical simulation of geologic CO₂ storage in depleted low-porosity and low-permeability oil and gas reservoirs aims to study the gas-liquid-solid multiphase flow consisting of multi-component mixture H₂O-NaCl-CO₂. The fluid migration in depleted oil and gas reservoirs involves constant changes in temperature, salinity, pressure, and heat and is even accompanied by chemical and mechanical changes (Pruess K et al., 1999; Xu T, 2001, 2006; Ling LL et al., 2013; Zhang EY, 2012).

In depleted oil and gas reservoirs, supercritical CO₂ occurs in a single non-wetting phase and forms a multi-component multiphase flow system together with the saline solution in the reservoirs. In this system, the flow of each component satisfies the law of conservation of mass. The system does not consider temperature changes. Its mass conservation equation consists of a mass change item, a flow item, and a source-sink item. The change in the fluid mass in a volume is equal to the sum of the fluid mass flowing into the volume from the volume surface and the fluid mass of the source-sink item (Pruess K et al., 1999; Zhang MY et al., 2017; Zhang ZX et al., 2018).

where, ${M}^{\kappa }$represents the cumulative amount of mass per unit volume in an area; ${F}^{k}$is the mass flux, including convection flux and diffusion amount; ${q}^{k}$is the mass source or energy per unit volume in an area; $n$ is the internal unit normal vector; superscript $k$represents the material component, and $t$ represents the time.

The total mass of all components in a porous media can be expressed using the following equation:

where, $\varphi$ is the porosity; $\;\beta$ represents the phase state; ${S}_{\beta },{\rho }_{\beta },\mathrm{a}\mathrm{n}\mathrm{d}{X}_{\beta }^{\kappa }$represents the saturation, fluid density, and component mass fraction of each phase, respectively, and $\kappa =w,i,g$ is the water, salt, and gas component.

In the process of CO₂ displacing saline water, it is believed that gas and water phases in the reservoirs obey the multiphase Darcy law (Pruess K et al., 1999):

where, $k$represents the absolute permeability coefficient of a porous media; ${{k}_{r}}_{\beta }$ represents the relative permeability coefficient of phase $\;\beta$; ${\;\rho }_{\beta }$ and ${\;\mu }_{\beta }$represents the density and viscosity of phase $\;\beta$, respectively; ${P}_{\beta }$represents the pressure of phase $\;\beta$, and $g$ represents the acceleration of gravity.

${F}_{k}$ in equation (1), which represents the mass flux of each phase, can be deduced in the multiphase flow form of Darcy’s law:

4.   Design and establishment of the geological model

Based on the typical lithological characteristics and physical parameters of the Chang 6 Member in the Huaziping oil area, the area to be modeled was generalized into a cylinder, and a geological model of a 140 m thick two-dimensional homogeneous sandstone system was established (Fig. 7). RZ2D was adopted for mesh generation of the model. This model was divided into seven simulated reservoirs with the same thickness (20 m) in the vertical direction. In the horizontal direction, the model was 100000 m long and was divided into 130 radial grids in total. The radius of the injection wellbore was set to 0.3 m. The hydrogeological parameters of the homogeneous model are listed in Table 4. For the sandstones in the simulated reservoirs, the average porosity was set to 12% and the average horizontal permeability was set to 3 mD. Given that the general ratio of horizontal to vertical permeability is 10∶1, the average vertical permeability was set to 0.3 mD. The vicinity of the injection well was the critical area for CO₂ diffusion and transport, and the outermost cells was set as boundaries with an infinite volume. CO₂ was injected into the reservoirs from the bottom of the injection well, with an injection depth of 20 m. It was assumed that the CO₂ injection was an isothermal process. The initial conditions of the model were calculated using the average formation pressure coefficient and the empirical formula of the geothermal gradient in the study area (Li C et al., 2011).

Figure  7.  A diagram of the CO₂ perfusion radial well flow model (modified after Wang F et al., 2020).

DownLoad: Full-Size Img PowerPoint

Table  4.  Hydrogeological parameters in geological model.

Parameter			Parameter
Permeability/m2	Horizontal direction	3.0×10−15	Relative permeability of injected CO2	${k}_{lr}=\sqrt{{S}^{*}}{\left\{1-{\left(1-{\left[{S}^{*}\right]}^{\frac{1}{m}}\right)}^{m}\right\}}^{2}$ ${S}^{*}=({S}_{lr}-S)/(1-{S}_{lr})$
	Vertical direction	30×10−15
Porosity		0.12	Residual water saturation	${S}_{lr}=0.30$
rock grain density /(kg·m−3)		2.6×103	Relative permeability of gas	${k}_{rg}=(1-\widehat{S}{)}^{2}(11{\widehat{S}}^{2}),$ $\widehat{S}=({S}_{l}-{S}_{lr})/({S}_{l}-{S}_{lr}-{S}_{gr})$
Thermal conductivity of rock formation/(W·m−1·°C−1)		2.51
Specific heat capacity /(J/kg°C)		920	Residual gas saturation	${S}_{gr}=0.05$
Temperature/°C		47	Capillary pressure	${P}_{cap}=-{P}_{0}({\left[{S}^{*}\right]}^{-\frac{1}{m}}-1{)}^{11m},$ ${S}^{*}={(S}_{l}-{S}_{lr})/\left({S}_{ls}-{S}_{lr}\right){P}_{0}={P}_{wg}/\alpha$
Salinity ωB/%		0.06
Compression factor /Pa−1		45×10−9	Experience index	$m=0.457$
Pressure /MPa		7.08

 | Show Table

DownLoad: CSV

5.   Similar simulation of geologic CO₂ storage

To conduct a parallel comparison of the effects of various physical parameters of reservoirs on CO₂ capture in gas and dissolved forms, the standard, reduced, and magnified values of seven influencing factors (i.e., porosity, horizontal permeability, temperature, formation stress, the ratio of vertical to horizontal permeability, capillary pressure, and residual gas saturation) were set (Table 5). In the simulation, the capillary pressure and residual gas saturation were set at empirical values. The CO₂ injection rate and injection time were set at 0.15 kg/s and 100 years, respectively, in order to keep the total CO₂ injection amount in the reservoirs consistent.

Table  5.  Parameters for sensitivity analysis of the model.

	Porosity/%	Horizontal permeability /mD	Temperature /°C	Formation stress/MPa	Ratio of vertical to horizontal permeability (kv/kh)	Capillary pressure/MPa	Residual gas saturation/%
Reduced value	0.05	1	45	4.68	1:10 1:1	5.1×10−6	0.01
Standard value	0.12	3	47	7.08	10:1	5.1×10−5	0.05
Magnified value	0.20	10	70	9.46	/	/	0.1

 | Show Table

DownLoad: CSV

Numerical simulation was carried out according to the parameters selected in the table, taking porosity as an example, and the results are shown in Fig. 8. The last six sets of simulation results were obtained by the same method.

Figure  8.  Distribution of saturation and the concentration of CO₂ dissolved in water after 100 years of CO₂ storage.

DownLoad: Full-Size Img PowerPoint

5.1   Porosity

Porosity greatly affected the distribution of gas saturation Sg and the concentration of dissolved CO₂ XCO₂ (aq) after 100 years of CO₂ storage. The spreading scope of the CO₂ diffusion halo decreased as the porosity increased. This is because a high porosity indicates a high water content in strata, which is conducive to the dissolution and capture of CO₂. However, this limited the migration and distribution scope of the CO₂ diffusion halo, thereby reducing the chance of wide contact between CO₂ and water.

5.2   Horizontal permeability

Permeability is one of the influencing factors of geologic CO₂ storage. Its effects on CO₂ saturation were difficult to identify, but it had distinct effects on the concentration of CO₂ dissolved in water XCO₂ (aq). Theoretically, the CO₂ diffusion halo is distributed in an increasingly wide area as the horizontal permeability increases. Thus, CO₂ can contact water more widely. Therefore, the increase in the horizontal permeability is beneficial to the dissolution and capture of CO₂, but it decreases the concentration of CO₂ dissolved in water.

5.3   Temperature

The distribution of the CO₂ saturation and the concentration of CO₂ dissolved in water after 100 years of CO₂ storage at 45°C, 47°C, and 70°C indicated that the migration scope of CO₂ increased as the temperature increased. This occurred because the CO₂ solubility decreased as the temperature increased, causing more CO₂ to continue to migrate in the form of gas at a higher temperature instead of dissolving in formation water.

5.4   Stratum stress

As revealed by the distribution of the CO₂ saturation and the concentration of CO₂ dissolved in water after 100 years of CO₂ storage under formation stress of 4.68 MPa, 7.08 MPa, and 9.46 MPa, the spreading scope of the CO₂ diffusion halo increased under formation stress of 4.68 MPa compared to that under formation stress of 9.46 MPa. This occurred because more CO₂ vertically migrated and then accumulated and diffused at the bottom of cap rocks under lower formation stress.

5.5   Ratio of vertical to horizontal permeability (kv/kh)

Reservoir heterogeneity is an important influencing factor in CO₂ migration, distribution, and storage, and the ratio of vertical to horizontal permeability (kv/kh) is an important parameter reflecting reservoir heterogeneity. This study investigated the effects of the ratio of vertical to horizontal permeability on CO₂ storage by changing vertical permeability.

According to simulated result, a decrease in the ratio of vertical to horizontal permeability corresponded to an increase in the vertical and horizontal migration capacity of CO₂ and a decrease in the direction scope of CO₂ gas. When kv/kh=10∶1, CO₂ rapidly migrated in the vertical direction in homogeneous reservoirs while migrating and diffusing in the horizontal direction. As a result, massive amounts of CO₂ migrated to cap rocks in a short time and laterally migrated under the cap rocks due to the blockage of the cap rocks. Since CO₂ migrated and diffused in a large scope, the contact area of CO₂ with fresh formation water grew. This increased contact was conducive to the conversion of free CO₂ into other stable CO₂ storage forms. When kv/kh = 1∶10, CO₂ migrated more rapidly in the vertical direction. In this case, CO₂ first migrated in the vertical direction along the injection well and then horizontally migrated along the bottom of cap rocks. As a result, the CO₂ gas had only a small influencing scope and a limited contact area with formation water. This was not conducive to the conversion of free CO₂ into other storage forms such as irreducible or dissolved states.

With a decrease in the ratio of vertical to horizontal permeability, the horizontal dissolution scope of CO₂ gradually increased, the scope of the dissolved gas pocket of CO₂ constantly shrank, and the transition zone with a decreasing CO₂ molar mass fraction decreased. When kv/kh=10∶1, highly dissolved CO₂ distributed in the form of an inverted triangle occurred in large areas, and more CO₂ was stored in strata in a relatively stable state. This is conducive to the dissolution of CO₂. In contrast, when kv/kh=1∶10, highly dissolved CO₂ distributed in the form of an inverted triangle occurred in only small areas, and there was less CO₂ stored in strata in a relatively stable state. This is inconducive to the conversion of free CO₂ into a dissolved form.

5.6   Capillary pressure

Capillary pressure plays an important role in geologic CO₂ storage, especially in the storage of irreducible gas. Therefore, a comparative study was conducted to determine the effects of capillary pressure on geologic CO₂ storage under the presence of capillary and in the absence of capillary pressure (i.e., minimum capillary pressure model).

The grids right above the top of the injection well were selected to observe the effects of capillary pressure on CO₂ dissolution in water and CO₂ gas saturation of the reservoirs. As shown in Fig. 9a, capillary pressure has almost no effect on CO₂ dissolution in water. The reason is as follows. The sequestration amount of dissolved CO₂ is mainly affected by the salinity of formation water and temperature and pressure conditions. Therefore, as an important influencing factor in the sequestration of irreducible gas, capillary pressure has no direct influence on the sequestration of dissolved CO₂. Fig. 9b shows the CO₂ saturation curves of the reservoirs. After CO₂ injection stopped, the CO₂ saturation curve under the presence of capillary pressure became stable, while the CO₂ saturation curve of the minimum capillary force model slowly decreased until it was finally relatively stable. The reasons are as follows. After CO₂ injection stopped, CO₂ was sequestrated in stratum pores as irreducible gas under the action of capillary forces. In contrast, the minimum capillary pressure model had a relatively weak capacity to sequestrate irreducible gas, and thus the corresponding CO₂ saturation decreased.

Figure  9.  a‒curve of dissolved CO₂ in water; b‒curve of CO₂ gas saturation.

DownLoad: Full-Size Img PowerPoint

5.7   Relative permeability

Studies (Wei L and Saaf F, 2009; Wang L, 2014) have revealed that the relative permeability of water has a small effect on the migration and distribution scopes of CO₂ and the amount of CO₂ storage. Therefore, this paper focuses on the effects of the relative permeability of gas on CO₂ storage. The relative permeability of gas is one of the important factors affecting CO₂ storage capacity, and a slight change in the morphology or value of the relative permeability curve may significantly affect the simulation results. However, there are no relevant data about the relative permeability curve and the capillary pressure curve of the study area since it is difficult to obtain capillary pressure and its relevant parameters on site. Given this, this study referred to the capillary pressure setting adopted in previous studies (Alkan H et al., 2010).

With a decrease in the residual gas saturation (S_gr), CO₂ stored in an irreducible state decreased, the permeability (K_rg) of gas increased, the migration and distribution capacity of CO₂ increased, and the influencing scope of CO₂ constantly expanded accordingly. As shown in simulated result, when the residual gas saturation (S_gr) was as small as 0.01, highly dissolved CO₂ distributed in the shape of an inverted triangle had a small area, and a small amount of CO₂ was stored in strata in a relatively stable state. In this case, CO₂ showed a high migration and diffusion capacity and can diffuse up to a maximum distance of 504 m. When the residual gas saturation (S_gr) was 0.05, the highly dissolved CO₂ had a larger area compared to the case of the residual gas saturation (S_gr) of 0.01, and CO₂ diffused up to a maximum distance of 446 m. When the residual gas saturation (S_gr) was 0.1, the highly dissolved CO₂ distributed in the form of an inverted triangle has the largest area, and a large amount of CO₂ was stored in strata in a relatively stable state. In this case, CO₂ showed the lowest migration and diffusion capacity and can diffuse up to a maximum of 395 m. In the model of this study, the total storage amount of irreducible CO₂ increased with an increase in the residual gas saturation. In the case of low residual gas saturation of CO₂, the relative permeability of gas was high, and the CO₂ had high migration and diffusion capacity. As a result, more CO₂ was dissolved in the process of contact with formation water in a large scope.

6.   Comparative analysis of the sensitivity of physical property parameters of CO₂ reservoirs

6.1   Changes in capture amount under different capture mechanisms

For hydrodynamic capture, CO₂ exists in the form of gas in reservoir pores. Dissolution capture refers to the dissolution of CO₂ in formation water. Mineral capture means that CO₂ is sequestrated through precipitation as carbonate minerals in the process of CO₂-water-rock interactions. The calculation formulas of capture amount under different capture mechanisms are as follows (Yang GD, 2015):

where, $M_{{\rm{CO}}_{2}gas}$, $M_{{\rm{CO}}_{2}aqueous}$, and $M_{{\rm{CO}}_{2}\min \;eral}$ are the total amount of CO₂ captured in the form of CO₂ gas, dissolved CO₂, carbonate minerals, kg; n_max is the total number of grids; V_n is the volume of the nth grid, m³; ${\varphi }_{n}$ is the porosity of the nth grid, dimensionless; $S{\mathrm{g}}_{n}$ and $S{l}_{n}$ are gas saturation and liquid saturation, dimensionless; $D{\mathrm{g}}_{n}$ and $D{l}_{n}$ are gas density and liquid density, kg/m³; $X{{\rm{co}}}_{2}$is the mass fraction of dissolved CO₂ in liquid, dimensionless; $SM{{\rm{co}}}_{2}$ is the amount of captured carbonate minerals, kg/m³.

6.2   Analysis and comparison of effects of various parameters on CO₂ capture amount

The total gas and dissolution capture amounts of CO₂ after 100 years of CO₂ storage can be calculated using formulas 5 and 6, as shown in Tables 6 and 7. According to these tables, with a gradual increase in the temperature, formation stress, capillary pressure, and residual gas saturation, the total gas capture amount of CO₂ increased, while the total dissolution capture amount of CO₂ decreased. Moreover, with a gradual increase in porosity, horizontal permeability, and the ratio of vertical to horizontal permeability (kv/kh), the total gas capture amount of CO₂ decreased, while the total dissolution capture amount of CO₂ increased.

Table  6.  Effects of various parameters on gas capture amount of CO₂.

	Porosity/%	Horizontal permeability/mD	Temperature/°C	Formation stress/MPa	Ratio of vertical to horizontal permeability (kv/kh)	Capillary pressure/MPa	Residual gas saturation/%
Reduced parameter value /kg	275×106	296×106	269×106	230×106	311×106	258×106	257×106
					300×106
Standard parameter value /kg	270×106	270×106	270×106	270×106	270×106	270×106	270×106
Amplified parameter value /kg	266×106	253×106	280×106	334×106	/	/	290×106

 | Show Table

DownLoad: CSV

Table  7.  Effects of various parameters on dissolution capture amount of CO₂.

	Porosity /%	Horizontal permeability/mD	Temperature /°C	Stratum stress/MPa	Ratio of vertical to horizontal permeability (kv/kh)	Capillary pressure/MPa	Residual gas saturation/%
Reduced parameter value /kg	197×106	176×106	203×106	242×106	163×106	214×106	214×106
					173×106
Standard parameter value /kg	201×106	201×106	201×106	201×106	201×106	201×106	201×106
Amplified parameter value /kg	205×106	219×106	194×106	139×106	/	/	181×106

 | Show Table

DownLoad: CSV

6.3   Sensitivity analysis

The degree of the influence of a parameter on the model can be expressed by the sensitivity of the model to this parameter. Sensitivity refers to the degree of influence of the change in a factor on other factors. To quantify the sensitivity of the capture amount of CO₂ to physical property parameters of reservoirs, the sensitivity of each physical property parameter of the reservoirs was calculated using the following formula (Xue YQ and Xie CH, 2007):

where, subscript i is the time observation point; H_i is the CO₂ capture amount ${M}_{{{\rm{CO}}}_{2}}$ calculated at the ith time observation point when the kth reservoir physical property parameter is taken as ${\alpha }_{k}$ (kg); ${\alpha }_{k}$ is the value of the kth physical property parameter; $\Delta {\alpha }_{k}$ is the increment of ${\alpha }_{k}$; ${\;\beta }_{i,k}$ is the sensitivity of H_i to the kth reservoir physical parameter at the ith time observation point.

Because the physical parameters of reservoirs have different dimensions, their sensitivity cannot be compared directly. Therefore, the above formula was transformed into a dimensionless form:

Since sensitivity parameter ${\beta }_{i,k}$changes greatly with time, H_i of the kth reservoir physical parameter calculated at the ith time observation point was taken as the average value $\overline{H}$ of the kth reservoir physical parameter over the entire time interval.

The sensitivity of gas and dissolution capture amounts to various physical parameters can be calculated using formulas 9 and 10, as shown in Tables 5 and 6. Since these formulas do not apply to the sensitivity calculation of capillary pressure and the ratio of vertical to horizontal permeability (kv/kh), these two parameters were excluded from the parallel comparison.

As can be seen from Table 8, the standard sensitivity (i.e., the sensitivity calculated using standard parameter values) of factors affecting the gas capture capacity of CO₂ decreased in the order of formation stress, temperature, residual gas saturation, horizontal permeability, and porosity (0.573 > 0.072 > 0.067 > 0.052 > 0.024). Moreover, the gas capture amount of CO₂ had a positive correlation with the temperature, formation stress, and residual gas saturation but had a negative correlation with the porosity and horizontal permeability. According to Table 9, the sensitivity of factors affecting the dissolution capture capacity of CO₂ decreased in the order of formation stress, residual gas saturation, temperature, horizontal permeability, and porosity (0.763 > 0.09 > 0.086 > 0.072 > 0.032). Furthermore, the dissolution capture capacity CO₂ was positively correlated with the porosity and horizontal permeability but was negatively correlated with the temperature, formation stress, and residual gas saturation.

Table  8.  Sensitivity of various parameters to gas capture of CO₂.

	Porosity/%	Horizontal permeability/mD	Temperature/°C	Formation stress/MPa	Residual gas saturation/%
Reduced parameter value	0.01	0.016	0.069	0.445	0.014
Standard parameter value	0.024	0.052	0.072	0.573	0.067
Magnified parameter value	0.041	−0.186	0.103	0.618	0.125

 | Show Table

DownLoad: CSV

Table  9.  Sensitivity of various parameters of dissolution capture of CO₂.

	Porosity/%	Horizontal permeability/mD	Temperature/°C	Formation stress/MPa	Residual gas saturation/%
Reduce parameter value	0.014	0.027	0.082	−0.419	0.017
Standard parameter value	0.032	0.072	0.086	−0.763	0.09
Magnify parameter value	0.053	0.219	−0.134	−1.479	0.11

 | Show Table

DownLoad: CSV

7.   Carbon neutrality-measures in the Ordos Basin

As the second largest sedimentary basin in China, the Ordos Basin enjoys extremely rich natural resources and is the most important energy production and supply base in China. The proven resources of coal, natural gas, and coalbed methane in the basin all rank first in China, and the proven reserves of petroleum in the basin rank fourth in the country. However, CO₂ emissions in the basin have sharply increased and account for a large proportion of China’s total CO₂ emissions due to the rapid development of the energy, chemical industry, and coal-fired power in the basin, as well as the CO₂ emissions from industries such as petroleum, natural gas, cement, and iron and steel. Therefore, decarbonization is crucial in the energy field, and further actions are urgently needed to reduce carbon emissions and mitigate the impacts of carbon emissions on climate change.

The sensitivity analysis of factors affecting geologic CO₂ storage conducted in this study is practically significant for achieving carbon neutrality, constructing ecological civilization, and obtaining sustainable development in the Ordos Basin. Based on the sensitivity analysis of factors affecting geologic CO₂ storage, the CO₂ storage areas in the Ordos Basin can be optimized. For example, the sensitivity analysis revealed that formation stress has more prominent effects in the process of CO₂ gas capture. Table 10 shows the changes in the gas capture amount of CO₂ induced by different formation stress in this study.

Table  10.  Analysis of gas capture amount CO₂ under different formation stress.

Stratum stress /MPa	Gas capture amount of CO2/kg	Difference in formation stress/MPa	Difference in gas capture amount of CO2 /kg
4.68	230×106	2.4	40×106
7.08	270×106
		2.38	64×106
9.46	334×106

 | Show Table

DownLoad: CSV

As can be seen, the gas capture amount of CO₂ increased by 40×10⁶ kg when the formation stress increased from 4.68 MPa to 7.08 MPa and increased by 64×10⁶ kg when formation stress increased from 7.08 MPa to 9.46 MPa. This indicates that the gas capture amount of CO₂ increased exponentially with an increase in the formation stress. In this case, CO₂ gas capture at the storage site can be further improved by increasing formation stress, which can be obtained by appropriately increasing CO₂ injection amount on the premise of no leakage of cap rocks, adequate storage capacity of the reservoirs, and given injection pressure or rate of the storage site.

Meanwhile, based on the analysis of the factors affecting geologic CO₂ storage, a reasonable assessment can be made from the following aspects for the CO₂ storage site in the Ordos Basin: (1) Whether the potential storage site can provide the required storage capacity; (2) Whether the potential storage site can provide given injection pressure or rate; (3) Whether the sequestrated CO₂ can be safely and permanently trapped at the potential storage site.

8.   Conclusions

A study on geologic CO₂ storage was conducted in the Ordos Basin, China, aiming to achieve the goal of carbon neutrality. Based on the geological conditions of the low-permeability oil reservoirs in the Chang 6 Member of the Upper Triassic Yanchang Formation in the central part of the northern Shaanxi Slope in the Ordos Basin, this study systematically explored the effects of seven influencing factors (i.e., reservoir porosity, horizontal permeability, temperature, formation stress, the ratio of vertical to horizontal permeability, capillary pressure, and residual gas saturation) on the main capture mechanisms (including gas capture and dissolution capture) after CO₂ injection into the reservoirs. The primary understandings obtained are as follows.

(i) The Ordos Basin is a large-scale regional energy and chemical industry base in China, where a large amount of CO₂ is intensively emitted. Based on available data and studies, the Ordos Basin has ideal reservoir - cap rock assemblage and potential strata for geologic CO₂ storage. Meanwhile, there are relatively complete well networks and sufficient basic data of this basin. The Huaziping area in the Ordos Basin is close to Yulin and Jingbian areas, where many large-scale energies and chemical enterprises lie nearby. The CO₂ emitted during the industrial production of these enterprises can be used as sufficient gas sources of in-situ CO₂ storage. Therefore, the Huaziping area is an excellent place for geologic CO₂ storage.

(ii) For the study area, the standard sensitivity of factors affecting the gas capture capacity of CO₂ decrease in the order of formation stress, temperature, residual gas saturation, horizontal permeability, and porosity (0.573>0.072>0.067>0.052>0.024). Among them, the standard sensitivity of the formation stress is as high as 0.57. The sensitivity of factors affecting the dissolution capture capacity of CO₂ decreased in the order of formation stress, residual gas saturation, temperature, horizontal permeability, and porosity (0.763>0.09>0.086>0.072>0.032). Among them, the standard sensitivity of the formation stress is up to 0.76.

(iii) As one of the effective means to achieve carbon neutralization, geologic CO₂ storage technology still needs to be further studied. In this study, only the physical parameters of the reservoirs were studied and analyzed as the influencing factors of geologic CO₂ storage. Subsequently, the fracture pressure of reservoirs and the sequestration safety of cap rocks will be further investigated. The systematical study of a series of scientific problems of geologic CO₂ storage will allow for enriching the theoretical basis of geologic CO₂ storage in low-permeability reservoirs, developing China’s geologic CO₂ storage technologies, and achieving net zero emission of greenhouse gases such as CO₂ for sustainable development.

Credit authorship contribution statement

Shi-xin Dai conceived the presented idea, Shi-xin Dai, Feng Wang, and Yan-jiao Dong prepared the manuscript. Feng Wang, Yan-jiao Dong, Zhen-han Xing, Pan Hu, and Fu Yang drew all the figures. Feng Wang and Yan-jiao Dong supervised the findings of this work. All authors discussed the results and contributed to the final manuscript.

Declaration of competing interest

The authors declare no conflicts of interest.

Acknowledgment

This study was jointly supported by the National Key R&D Program of China (2018YFB0605503), the National Natural Science Foundation of China (51804112), the National Key R&D Program of China (2018YFC0807801), the Open Foundation of Key Laboratory of Coal Exploration and Comprehensive Utilization of Ministry of Natural Resources (KF2021-5), and the Natural Science Foundation of Hunan Province of China (2018JJ3169).