One of the major decisions in managing mature oil fields is to look for opportunities to maximize recovery, such as investigating on the most feasible Improved Oil Recovery (IOR) techniques, especially in the today's volatile oil prices. This paper demonstrates a closed loop, integrated workflow using algorithm-assist reservoir simulation to evaluate the viability of an IOR project by optimizing all essential parameters in waterflood/polymer flood projects and calculate the project economics for all possible options. The outcome of the work results in the best scenario for deciding if the investment in IOR can be paid off. The possible causes on pressure depletion were thoroughly investigated in the well completion towards the geological concept. Both downhole pressure gauge and open-hole gravel pack design were validated to ensure their reading accuracy and performance. Apart from well investigation, the geological concept was analyzed by utilizing all cores, well-logs, seismic data as well as the regional understanding in deepwater setting. Once the possible root cause of pressure drop was identified, the hypothesis was integrated into the static model and tested by reservoir simulation study. Lastly, an appropriate solution will be proposed to optimize recoverable gas resources and prolong production plateau. The investigation over the well completion showed that the pressure depletion was not associated with downhole pressure gauge and well completion design. Whereas the geological setting of deepwater suggested that sheet sand deposit in this field containing several hemipelagic shales. Regarding outcrop analogue, the hemipelagic shales are laterally widespread and can potentially be the primary cause for the unexpected pressure drop. Therefore, the presence of extensive hemipelagic shales as observed in both core and well-log information was included into static model. The updated static model was then calibrated with actual production data and the result showed a good history matching, which supported the presence of extensive hemipelagic shales and their negative impacted on production pressure. Moreover, our investigation also unraveled the fact that water channeling and undrained gas resources below these shale layers were the main reasons of shorter plateau period and lower recoverable gas resources. Consequently, we proposed an optimal solution by drilling infill wells in the up-dip position to access the undrained gas and to avoid water channeling in the down-dip position. With this new development plan, this study can increase the additional gas recoverable resources and extend the production plateau. This project demonstrates a robust workflow of among multi-disciplinary team from a well-founded geological concept, more accurate and justifiable reservoir model inputs, and hypothesis testing by reservoir modeling approach to achieve the optimal field development plan. In addition, this is an excellent opportunity for PTTEP company to demonstrate our technical capability to overcome the challenging and create the additional value by increasing the recoverable gas resources to the field.

Interest in CCS project development is accelerating in SE Asia, driven by the need to monetize emission-intensive assets in the region while complying with increasingly ambitious GHG emissions targets. Depleted hydrocarbon fields represent an attractive storage option for early CCS project due the enhanced understanding of the reservoir, its dynamic behavior, and proven storage capability. Re-use of existing infrastructure also presents the potential to reduce both project costs and time to first injection, however, these brownfield sites also carry significant risk to the long-term, safe containment of injected CO2 through risk of leakage via legacy wells. A methodology is presented in this paper to investigate the risk-reward balance of developing a depleted gas field as a storage site in the Gulf of Thailand. A screening process to assess all abandoned, suspended, and active wells is used to identify wells with re-use potential as CO2 injectors or CO2 plume monitoring wells, and those which represent a leakage risk to the project. A set of legacy well risk identifiers is generated for the field based on well construction records, descriptions of current well barriers, well utilization history, and current best practice guidelines. Southeast Asia has significant remaining reserves of oil and gas, and coal, and an active liquefied natural gas (LNG) export industry. The region's energy demand is increasing rapidly and is forecast to continue to grow over the next decades (World Economic Forum, 2019). To date, fossil fuels have supplied nearly 90% of this growth in the demand for energy in the region (IEA, 2021). To meet this growing energy demand, several new gas projects are under development across Southeast Asia, but many of these are associated with high CO2 gas fields where the produced gas contains significant (up to 70% by volume) CO2 (GCCSI, 2020). In Thailand, where nearly 94% of the primary energy is met by fossil fuels (BP Statistical Review, 2022), the energy sector represents the biggest contributor (74% in 2013) to the country's greenhouse gas emissions (GHG; UNFCCC, 2020). However, as per the nationally determined contribution to the United Nations Framework Convention on Climate Change (UNFCCC), Thailand intends to reduce its GHG emissions by at least 20% from projected business as usual levels by the year 2030 (UNFCCC, 2020). Carbon capture and storage (CCS) represents one option to help meet this increased demand in fossil energy while also reducing GHG emissions. An approach which is gaining traction across the region is to utilize the high concentrations of CO2 stripped out of the raw gas streams at gas processing plants and, instead of venting to atmosphere, the CO2 can be compressed, dehydrated, and transported to suitable long-term storage locations. Depleted oil and gas fields form an attractive opportunity for long-term storage of CO2 due to the wealth of both static and dynamic knowledge available from appraisal through production activities. Depleted fields also have the advantage that they have a working primary seal for hydrocarbons, which has been proven over geological time and so can be considered, in general, to carry low risk of leakage through geological means. Brownfield sites can, however, also represent a challenge to project success through an increased risk to the containment of the injected CO2 due to the presence of legacy wells. These existing wells represent a variable risk to containment depending on well age and type, well history, well design, and plug and abandonment methodology applied. This paper presents the outcomes of a CO2 storage feasibility study for a depleted gas-condensate field in the Gulf of Thailand. The main aims of the study were to:1) identify the project risk associated with the integrity of the field legacy wells, and 2) to evaluate the potential for well re-use for the CO2 injection project. Reusing an existing field offers new life to an otherwise end-of-life asset, inching towards decommissioning and site closure. As commercial scale CO2 storage in depleted hydrocarbon fields represents a ‘First of a Kind’ project, the feasibility study is designed to evaluate the current status of the field and surface facilities with respect to CO2 injection and long-term storage. As a feasibility study, the focus of the technical work was to identify any ‘showstoppers’ which might indicate that the selected site was not suitable for long-term CO2 storage and, if sufficient positive storage indicators were identified, to select the most appropriate options for progression into a Concept Selection study in which more detailed engineering studies will be completed.

With the determination towards sustainable growth, PTTEP has a commitment to achieve Net Zero Greenhouse Gas Emissions by 2050. Therefore, the Carbon Capture Utilization and Storage (CCUS) project in the Gulf of Thailand was initiated to evaluate the CO2 storage capacity in Bongkot and Arthit fields. Three categories of storage potential were considered including shallow aquifers and depleted gas reservoirs together with storage potential in oil rim reservoirs by using CO2 enhanced oil recovery (CO2-EOR) method. The storage potential in shallow aquifer was targeted on porous rock located between seabed and top producing reservoirs which were identified in seismic and/or well data and reached by existing platforms. For the inventory of depleted gas reservoirs, the cumulative gas production volume was allocated to an individual reservoir, which signified storage size and injectivity of reservoir. The depleted gas reservoirs were focused on ones where a great amount of gas has been produced. For the CO2-EOR candidates, all oil rim reservoirs were reviewed and included in the study. The calculation of oil gain, CO2 injection requirement, and CO2 storage potential were based on the statistical data of Water-Alternating-CO2 fields. The inventory of CO2 storage potential from three categories were compiled with the information of 1) platform name, 2) remaining reserves, 3) distance from processing platforms, and 4) CO2 storage volume. After considering the CO2 storage potential, two platforms were considered as the most suitable for two fields equipped with CO2 removal units. In addition, the CCS development study considered an option to improve CO2 removal performance of the membrane in order to recover more hydrocarbon from flared gas. After the preliminary technical evaluation, the detailed study with reservoir simulation will be conducted in order to ensure the injectivity at reservoir level, the optimization of injection well number, and the integrity of containment. The injection plan will be formulated, and the investment cost estimation of CCS project can be refined accordingly. This CCUS study was initiated to reduce the CO2 emission from production fields under PTTEP. Currently, there are more than 20 CCUS projects around the world with only a few projects at the stage of CO2 injection. It requires good collaboration among subsurface and surface teams to increase confidence in storage suitability assessment. This project provides an example of multi-disciplinary integration and robust workflow starting from CO2 storage identification, volume calculation, to candidate ranking for further detail study.

Field A is an onshore oil field in Thailand. This area contains biodegraded medium-heavy crude reservoir; 19°API oil gravity and 144 cp viscosity. Therefore, the field suffers from a low recovery factor due to high crude viscosity. On one hand, bacteria have exerted an adverse effect on production, on the other hand, it means that the condition of the reservoir is suitable for implementing Microbial Enhanced Oil Recovery (MEOR). The MEOR is a technology that utilizes microorganisms (mainly bacteria), to enhance oil production, especially for medium-heavy oil. By feeding nutrients to bacteria, several metabolites were produced that would be useful for oil recovery. This technique is well known for its low investment cost, hence, high return. The technical screening confirmed that the reservoir and fluid properties are suitable for MEOR. Consequently, sixteen core samples and three water samples were collected for indigenous bacteria analysis. Although the laboratory indicated there are countless bacterial strains in the reservoir, the nitrate-reducing biosurfactant-producing bacteria group was identified. This bacteria group belongs to the Bacillus genus which produced biosurfactant and reduced crude viscosity by long-chain hydrocarbon degradation. Therefore, the treatment design aimed to promote the growth of favorable bacteria and inhibit undesirable ones. Consequently, a combination of KNO3 and KH2PO4 solutions and a specialized injection scheme was tailored for this campaign. The pilot consisted of two candidates those were well W1 (76% water cut), and well W2 (100% water cut). The campaign was categorized into three phases, namely, 1.) baseline phase, 2.) injection and soaking phase, and 3.) production phase. Firstly, the baseline production trends of candidates were established. Secondly, KNO3 and KH2PO4 solutions were injected for one month then the wells were shut-in for another month. Lastly, the pilot wells were allowed to produce for six months to evaluate the results. The dead oil viscosity of well W1 was reduced from 144 cp to 72 cp which led to a 6.44 MSTB EUR gain or 1.3% RF improvement. On the other hand, the productivity of well W2, the well with 100% water cut, was not improved. This was expected due to insufficient in-situ oil saturation for a bacteria carbon source. Considering the operational aspect, there was no corrosion issue or artificial lift gas-lock problem during the pilot.