Potential of carbon dioxide storage from petroleum industries in the Gulf of Thailand for green production

Recently, climate change and global warming are the global concern because of an increase in the huge amount of carbon dioxide (CO2) in the atmosphere. This gas comes from energy activities and industries like petroleum industries. Carbon capture and storage (CCS) is the practical technology to reduce and storage CO2. In Thailand, one of the main potential sites for storage is the Gulf of Thailand. However, the research on this issue is very rare in Thailand. Consequently, this work is aiming on the potential study of CO2 geological storage in formations in the Gulf of Thailand by using simulation. The CO2 storage capacity, pressure buildup and plume migration have been estimated. Also, this study has been simulated with various conditions. CO2 injection is used from 1,000-4,000 tons per day with the depth from 2,200-2,330 meters and the results are studied for 50 years as a monitoring period. The results present that with the formation characteristics, CO2 storage in this area has potential. Moreover, pressure buildup and plume migration are illustrated for the period of 50 years. As a fundamental knowledge, this study can contribute to CO2 storage in an offshore area in Thailand.


Introduction
Nowadays, climate change and global warming are the main global problem because of an increase in the huge amount of carbon dioxide (CO2) in the atmosphere [1]. This gas comes from energy activities and industries like power generation and petroleum industries [2,3]. Carbon capture and storage (CCS) is the practical technology to reduce CO2 emitted to the atmosphere and to store it in the potential area.
CCS technology is consisting of three processes. The first process is CO2 capture. CO2 will be captured from emission sources [4]. The second process is CO2 transportation mainly by pipeline and the third process is CO2 storage especially geological storage [5].
In Thailand, one of the main potential sites for storage is the Gulf of Thailand particularly the depleted oil and gas reservoirs. However, the research on this issue is very rare in Thailand. Consequently, the objective of this work is focusing on the study of the potential sites of CO2 geological storage in the formations oil and gas fields in the Gulf of Thailand by using simulation. Also, it is aimed to observe the characteristic of CO2 storage behaviour with the fundamental data in this area.

Method
The method of this study is to use the CMG software to set up and simulate the 3D model of CO2 geological storage and to evaluate the behaviour of injected CO2 in the formations. Also, the change of pressure and storage capacity of injected CO2 can be simulated and investigated with the injection rate of CO2 ranging from 1,000 to 4,000 tons/day and time period of observation is 50 years. Furthermore, the selected site of this study is Malay basin in the Gulf of Thailand as shown in figure 1.
In this study, Malay basin is selected because this area is not limited by faults and compartment boundaries comparing to adjacent areas in the Gulf of Thailand. Therefore, the pressure can be increased while CO2 injected. However, CO2 injection can affect the shale in the formations because of caprock breaking before CO2 injection is accomplished [7]. The effective of CO2 storage would be limited by pressure buildup [8]. Furthermore, while CO2 is injected, it moves up to the top of the formation and expand radially for the plume migration. Also, the top area are limited by faults and some fined-grained such as shale.

Fundamental data of formations
The actual, fundamental data to create 3D model is obtained from the literature [6] and the Department of Mineral Fuels, Ministry of Energy as shown in table 1. In this case, the single well consists of 3 layers. Each layer has the characteristics as presented in table 1. The first layer is the bottom sand. The 2 nd layer is in middle sand and the 3 rd layer is the top sand.
The important condition while injects CO2 is pressure buildup. The fracture pressure is calculated and used to determine the maximum pressure as well as the storage capacity. However, the maximum injection pressure should not exceed to fracture pressure in each well. The fracture pressure that will be fractured rock formation is assumed to use as the limitation of injection pressure. When the pressure is exceeding to minimum principal stress, rock formation will be fractured [9,10]. The maximum pressure is limited at 90% of fracture pressure [9] to storage CO2 without caprock breaking. The fracture pressure is calculated from Hubbert and Willis Equation [10] as shown in equation (1).
Where Fmin is fracture gradient and P/D is pore pressure gradient or pressure per depth (psi/ft).

Storage Capacity and Pressure Buildup.
The result of storage capacity is shown in table 2 with the injection rate ranging from 1,000 to 4,000 tons/day. The storage capacity is related with pressure buildup and the amount of injected CO2. Because the amount of injected CO2 results in an increase in pressure. When increasing pressure meets the maximum pressure; then the CO2 injection is stopped and the formation is set to shutin to prevent caprock breaking. From the results, it is shown that 1 st layer can store maximum amount of CO2 from 0.76 to 0.82 Mt because it has a thicker formation and it is located in the deeper formation or higher pressure. Also, the density of CO2 at this formation is higher than other formations. Therefore, this formation can have higher CO2 storage capacity. With these reasons, the best one is 1 st layer followed by 2 nd and 3 rd layers. Moreover, the results of pressure buildup are presented in figures 2 to 4 including the maximum pressure. The results are monitored for the period of 50 years with injection rate from 1,000-4,000 tons/day. Figure a is for the period of 50 years. While figure b is for the period of the first 10 years of simulation and expands the scale from figure a. From figure 2, with 1,000 ton/day injection rate, the pressure is gradually increasing until it can meet to the highest pressure but the pressure with 2,000-4,000 ton/day injection rate are sharply increased to the highest pressure without caprock breaking. After shutin time, pressure is little higher for a while and then pressure is gradually decreasing in every injection rates due to the expansion of CO2. The reason is that when CO2 is injected to the formation, it pass through the small pores. Therefore, the effect of pressure buildup becomes gradually increased. When CO2 injection is stopped, the effect is still continues, thus making the pressure going up. However, it continues for short period of time and the pressure falls down as presented in figure 2-4. Other layers have the same trend with the first layer. According to table 1, the second and third layers have lower maximum pressure at 30.02 and 29.65 MPa, respectively. Therefore, with the same injection rate, they can reach the maximum pressure faster than the first layer.

Plume migration
The results of plume migration in all layers at the 1000 ton/day injection rate for 50-year period are shown in figure 5 (a-f). CO2 migrates both horizontally and vertically. Even CO2 injection is stopped. CO2 migration still continues. Moreover, the velocity of migration is controlled by the degree of the permeability of the formation [11,12]. From the figures, it is clear that CO2 is injected from the bottom layer. Then CO2 is arising to the top part of each layer and expand horizontally even though CO2 injection is stopped. After reaching to highest pressure, the shutin is performed. However, CO2 is still expanding for a while and decreasing gradually. The results of all layers have the same tendency in every injection rates. The plume migration at injection rate of 1,000 tons/day is expanding to obtain the largest area.

Summary
This work is studying the potential of CO2 storage sites in depleted oil and gas reservoir in the Gulf of Thailand by using 3D simulation model of 3 formations created by CMG program with the various conditions such as injection rate ranging from 1,000 to 4,000 tons/day and 50-year period of CO2 monitoring. The real field data are obtained and applied to this study such as the formation depth of 2,200-2,330 meters, permeability, and porosity and so on. The behaviour of CO2 movement, storage capacity, pressure buildup and plume migration are simulated for 50-year period. The results present that pressure is increased until it is close to maximum pressure without caprock breaking and the injection is terminated or shutin. Therefore, CO2 storage capacities can be calculated. Also, the injection rate of 2,000-4,000 tons/day are increasing sharply meanwhile the injection rate of 1,000 tons/day is gradually increasing. For the plume migration, at the beginning, CO2 is injected into the bottom part of each layer and then CO2 is arising to top part because of the density. Then plume migration is expanding horizontally. Plume migration of CO2 is still expanding after shutin time. Therefore, the radius of plume migration can be calculated. This preliminary study can be used as a basic knowledge and applied to the higher level for the CO2 storage in the Gulf of Thailand in the future.