1. Introduction
Carbon dioxide gas (CO
2) is a significant component of greenhouse gases, accounting for more than 50% of all emissions. These emissions have been contributing to climate change and global warming [
1]. The primary source of CO
2 emissions is from the combustion of fossil fuels for power generation and transportation. To address the environmental concerns associated with carbon emissions, carbon capture and storage technology has been developed [
2,
3,
4,
5]. This technology is now being adopted by developing countries, including Thailand, as part of their efforts to achieve carbon-neutrality by 2050 and net-zero emissions by 2065 [
6]. CCS involves two main processes: CO
2 capture and CO
2 storage. CO
2 capture can be carried out at manufacturing industries, such as cement and power plants, before the CO
2 is released, or directly from the air [
7]. The permanent storage of CO
2 in subsurface geological structures can be achieved through various trapping mechanisms, including structural trapping, residual trapping, solubility trapping, and mineral trapping. Among these mechanisms, structural trapping is the most dominant due to the buoyant characteristics of CO
2 in subsurface reservoirs [
8,
9].
Carbon credits are financial instruments that companies use to offset their carbon emissions. These credits represent a certain amount of carbon dioxide or other greenhouse gases that a company is allowed to emit. If a company exceeds its emission limit, it is fined. On the other hand, companies that emit less than their limit can either save the credits for future use or sell them to other companies. The goal of carbon credits is to reduce carbon dioxide emissions and mitigate the effects of global warming. Carbon credits are traded in carbon markets, which can be mandatory or voluntary, allocation or offset, and international or regional. Thailand’s carbon credit market is classified as voluntary, regional, and offset, meaning that it is controlled by companies and projects rather than government quotas. In Thailand, carbon credit trading is facilitated through the Thailand Voluntary Emission Reduction Program (T-VER). Although it is a voluntary market, Thailand’s carbon credit market has been growing steadily. The turnover of carbon credits has increased from THB 0.85 million in 2016 to THB 129 million in 2022, with a total trading volume of 1.19 million tons of carbon dioxide equivalent (tCO
2e). The average price of a carbon credit is around THB 108.2 or USD 3.5 per ton [
10].
The CO
2 injection phase is a key component of carbon geological storage, which also includes the completion and operation of the injection well. Most aspects of drilling and completing CO
2 injection wells are similar to those of conventional gas injection wells or gas storage wells. However, downhole equipment can be upgraded to withstand high pressure and corrosion [
11]. The CO
2 injection phase accounts for a significant proportion of the overall cost of CGS, in addition to the costs of capture and transportation to the injection site. To make a CGS project financially feasible, it has to be subsidized by selling carbon credits. Therefore, the minimum carbon credit cost, or the total cost of injection, will determine the feasibility of a CGS project in a specific area.
The PROSPER
® v17.0 simulation program is used in gas injection design to optimize operating parameters and predict well performance for different cases. This tool is particularly useful for CO
2 injection well design and determining the conditions necessary to sustain gas flow using nodal analysis, which involves selecting a division point or node in the well and dividing the system at that point [
9]. The inflow section includes all components upstream of the node, while the outflow section includes all components downstream. The intersection point on the pressure and flow rate plot between inflow and outflow sections represents the equilibrium condition at the node, typically located at the bottom of the well depth.
Therefore, this study designed the related equipment for CO2 injection wells during both the drilling and injection phases. The cost of the injection well was evaluated, taking into account the capital cost from well equipment selection and the operating cost associated with energy usage for injection, and capture and transport costs. The minimum carbon credit cost for the CGS project was then determined by converting the capital and operating costs into the net present value (NPV), with the carbon credit sale serving as the project income. Furthermore, the study varied key design parameters such as tubing size, wellhead pressure, and injection temperature to analyze their impact on the operating injection rate and the minimum carbon credit cost of the well. This analysis proposes an optimal design for CO2 injection in the Mae Moh basin, which is a potential site for CGS in Thailand.
This article is divided into five sections.
Section 2 explains the methodology used in this study, including information and lithologies of the Mae Moh basin. It also discusses the methodology for well completion and CO
2 injection design, as well as the economic analysis to determine the minimum carbon credit cost for the project breakeven.
Section 3 presents the results of the well completion and injection design, including the specifications for casing, cementing, and tubing, as well as the economic analysis for the base case design.
Section 4 discusses the sensitivity analysis for tubing diameter, wellhead pressure, and injection temperature, and how they affect the operating injection rate and minimum carbon credit cost. Finally,
Section 5 provides the conclusions drawn from the study, summarizing the research findings concisely.
4. Discussion
This study performed sensitivity analysis to examine the impact of wellhead pressure, tubing or pipe diameter, and injection temperature on the flow condition of the well and the total injection cost, specifically in terms of the minimum carbon credit cost. The results from the sensitivity analysis are shown in
Figure 6. The discussions for the effect of each studied parameter are as follows:
Effect of tubing diameter. The effect of tubing diameter to the CO
2 injection rate and minimum carbon credit cost is shown in
Figure 6a. The results indicate that increasing the tubing diameter from 2 1/2 to 3 1/2 inches leads to an increment in the injection rate from 29,500 to 29,900 tons of CO
2 per year. This increase is attributed to a reduction in frictional pressure loss within the tubing, allowing the energy from the wellhead pressure to support the higher injection rate. Consequently, the minimum carbon credit cost slightly decreases from USD 72.52 to 72.47 per ton of CO
2e as the tubing size increases. This reduction is a result of a larger proportion of CO
2 being injected. However, it is important to note that the well casing size poses a limitation, as a larger tubing diameter may not fit within the designed casing size of this particular well.
Effect of wellhead pressure. The injection rate increases from 17,000 to 63,200 tons of CO
2 per year when the wellhead pressure is increased from 700 to 1000 psi, as shown in
Figure 6b. This trend is comparable to study of the effect of wellhead pressure on the gas injection rate from Liu et al. [
33] and Bai et al. [
34], as more energy is supplied from the pressure pumping equipment, allowing for a higher injection rate. As a result, the minimum carbon credit cost decreases from USD 75.18 to around USD 71 per ton of CO
2e with the increment in wellhead pressure. The minimum value of carbon credit cost is reached at a wellhead pressure of 900 psi. However, the trend reverses at a wellhead pressure of 1000 psi due to the increase in both values of CAPEX and OPEX resulting from the higher injection rate. Additionally, the well fracture pressure is serving as the limitation, as a larger wellhead pressure results in the increment of bottomhole pressure, and exceeding the formation fracture pressure (~1000 psi) when the wellhead pressure exceeds 800 psi.
Effect of injection temperature. When the injection temperature is decreased from 95 to 59 °F, the injection rate increases from 28,000 to 36,200 ton/year per well, as shown in
Figure 6c. This trend is comparable to a study of the effect of injection temperature on the gas storage capacity by Jing et al. [
35], as the increase in injection temperature leads to a larger amount of CO
2 in the gas phase and a higher formation pressure [
35]. As a result, more energy is required from the pumping equipment to inject a higher volume of gas. Consequently, the minimum carbon credit cost decreases from USD 72.74 to 70.77 per ton CO
2e with the lower injection temperature. This reduction is due to both the higher rate of CO
2 injected and the lower operating wellhead pressure required.
Implementation in the Mae Moh basin. Even supposing that the geological characteristics of the Mae Moh basin are feasible for implementation of the CGS operation, there are limitations and concerns that need to be further investigated. Firstly, the characteristics of the proposed well in the basin need to be considered. The basin, which encompasses the location of the currently operated mine and spans approximately 132 km
2, may lead to increased capital costs during the installation period of the CCS system. Secondly, by the 2030s, the mining pit, which could serve as the injection site, is projected to reach a depth of approximately 400 m. This will result in increased logistic and management costs compared to the current values. According to the reference price from EGAT [
36], the estimated price for area and pit preparation can be up to approximately USD 1.36 per m
3 of soil and sediment removal. Moreover, it is necessary to address the stability issues associated with the groundwater system in this area, particularly at the basin within a coal mine. Therefore, development of the drilling and injection of CO
2 in the area must be closely monitored to prevent failure in the operation [
37].
Economic opportunities in Thai carbon market. In Thailand, the rules and regulations regarding emissions reductions are enforced through the Thailand Voluntary Emission Reduction (T-VER) program, which is managed by the Thailand Greenhouse Gas Management Organization (TGO). As a result, the carbon market in Thailand primarily operates on a voluntary basis. As per the prescribed T-VER-S-METH-14-01 guideline for capturing, storing, and utilizing greenhouse gases (GHGs), the measurable GHGs must be obtained by calculating the difference between the baseline GHG emissions and the reduction in GHGs resulting from both direct operations and auxiliary activities. Based on the research conducted by Win et al. [
38], the Electricity Generating Authority of Thailand (EGAT) has reported total emissions of 31.382 MtCO
2e or 0.515 kg CO
2eq/kW.h. Consequently, the coal power plant in the basin emits 6.57 MtCO
2e annually. Given that the annual capture rate of greenhouse gases (GHGs) from the study is only 0.29 MtCO
2e, it can be concluded that the project is not valuable due to the low rate of carbon reduction (refer to
Table A1 in
Appendix A). To enhance the economic prospects of the area, it is imperative to promote a policy aimed at reducing greenhouse gas emissions in conjunction with other supplementary activities. This will help mitigate the high emission levels in this area.
In conclusion, the minimum carbon credit costs for the CGS project are found to be much higher than the current market price of carbon credit in Thailand, which is only around USD 3.5 per ton CO
2e and the capture rate is far lower than those produced from the emission. However, it is found that the amount of CO
2 storage achieved by the CGS project is significantly higher than the carbon sequestration achieved through planting [
16]. Therefore, if the market value of carbon credit costs is improved, the CGS project in the Mae Moh basin of Thailand can be economically feasible.
5. Conclusions
The economic analysis of CO2 injection in Mae Moh basin area was implemented in this study to estimate the total costs of carbon geological storage. The well completion design was employed to specify the necessary well equipment and materials for the determination of CAPEX while the CO2 injection design was performed by nodal analysis in the PROSPER® simulation program to estimate the operating injection rate and costs. The completion of a CO2 injection well is similar to that of a conventional petroleum well, with the exception being that CO2-resistant equipment and materials are required for casing, cementing, and tubing. Based on these considerations, the calculated value of the CAPEX for constructing a well to the target depth of 1600 ft is approximately USD 756,600. In addition to the CAPEX, the study estimated the total OPEX for CO2 capture, transport, and injection. The annual OPEX is approximately USD 2,030,000 per well, with an injecting capacity of 29,530 tons of CO2 per year. To make this project financially feasible, the minimum carbon credit cost required is USD 72.50 per tCO2e, which is significantly higher than the market value of carbon credit in Thailand. This breakeven point can be reduced by increasing the tubing diameter or wellhead pressure, as this would increase the injecting capacity and reduce the cost per injected unit. However, it is noted that higher injection costs are required when the injection temperature is increased due to a larger proportion of CO2 in the gas phase.
However, this study has several limitations that need to be considered. Firstly, the capital and operating costs of carbon geological storage were estimated specifically for the Mae Moh basin area. Therefore, these values may vary in other locations and need to be recalculated on a case-by-case basis. Another limitation is that the carbon storage cost, in terms of capture cost, was chosen based on a conservative estimate from the literature related to coal power plants. If CO2 is generated from a different energy source, the actual cost may differ from the value selected in this study, impacting the economic analysis of carbon geological storage costs. Hence, this factor also needs to be taken into account on a case-by-case basis.
Since the beginning of the 2020s, Thailand has seen a growing awareness of the Sustainable Development Goals (SDGs) and greenhouse gas emissions. This has prompted both the government and private sector to step up and play their part in reducing emissions. Consequently, the carbon market in Thailand has a tendency of growth, leading to an expansion of incentives and regulations. This upward trend could potentially drive up the price of carbon, making it financially feasible to pursue the operation of CGS projects. However, since the regulatory framework is still in its early stages of development, Thailand’s capacity of carbon trading in the global market is not verified. Therefore, Thailand’s full engagement in the global carbon market is still uncertain because of this limitation.