The successful discovery of petroleum exploration primarily depends on the understanding of the basin evolution and sedimentary filling though geological time. Well data also play a key role for reservoir presence and quality analysis; however, none of well fully penetrated the Oligocene Syn-rift sequence in the West Arthit area. Therefore, this study aims to overcome the challenge of limited well information by performing the Forward Stratigraphic Modeling (FSM) to determine basin evolution, depositional setting, and reservoir distribution in this area. The FSM model is constructed with the inputs of paleo-bathymetry, subsidence, sediment supply, water level, and climatic cycle. In addition, the stratigraphic sequence is reproduced based on field observations such as rock samples, seismic mapping, well-log responses, and publications from nearby areas. The main uncertainty of building the FSM model is the initial age of rifting phase due to a lack of well penetration that fully covered the Syn-rift sequence and the limited biostratigraphic data. Therefore, two different age scenarios are examined in this study analogue from the age model as it was published in the Malay Basin locating to the south of study area. Once the FSM model was built, the last step was to calibrate the prediction result with the actual well result and the conventional seismic data to achieve the best accuracy and to increase the confidence on using the model. The FSM model was successfully reproduced the stratigraphic successions of the Syn-rift sequence in West Arthit area. The base case model was chosen from the age scenario of 27.0-23.1 Ma which exhibited four major cyclicities and matched with seismic mapping. The study area had two depocenters, one in the northwest and another one in the southeast. The northern sub-basin was deepened earlier during the first rifting phase whereas the southern sub-basin was subsided later after the second rifting period. With the increase in sedimentation rate and subsidence rate during the third rifting phase, both depocenters were shallowed up and then become a shallow lake covering the whole study area. The last lifting phase coincided with the thermal subsidence that occurred and affected across the region; therefore, the regional extensive lacustrine accumulated in the study area. The results from this study provided a crucial information on petroleum system especially depositional architecture, reservoir distribution, and potential source rock identification, which were incorporated into the planning of future exploration targeting in this field. This study demonstrates the new innovative approach to determine the basin evolution and to understand the variation on depositional setting in the study area with limited well data. This approach also creates the project value by supporting the planning of future exploration and development wells. Furthermore, this technique can be applied to all projects to increase the discovery rate and to add the field reserves.
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.
The objective of this study is to characterize sand reservoirs by using seismic inversion technique, the results were used to support CO2 storage potential identification and reservoir modeling works (storage volume calculation). The key storage targets are the saline aquifers and depleted reservoirs. These main targets were interpreted as a deposition of distributary channels occurring in the Paleo Chao Praya delta plain during Miocene. The results of this project contribute to a more accurate volume calculation for CO2 storage capacity. A rock physics feasibility analysis was carried out to understand a link between the observed seismic responses and the rock properties. Based on conclusions made in the rock physics analysis, P-Impedance could be used to delineate sand reservoir from shale, thus, a post-stack deterministic seismic inversion was selected for this reservoir characterization. Bayesian litho-classification method justifies lithology types by Probability Density Function (PDF) of P-Impedance, the resulting PDF was then applied to the inverted relative P-Impedance to create sand probability and lithology (most probable) volumes. Then, posterior validation of the lithology classification results was performed by investigating the match between the actual upscaled lithology log and pseudo lithology log from the Bayesian classification. Furthermore, the sand probability maps of the target reservoirs show an acceptable sand distribution response to the distributary channels in lower coastal plain environment that is consistent with the well results. The results of this work demonstrate how quantitative interpretation (QI) can successfully improve confidence in sand reservoirs mapping, in an area of complex faulted reservoir interval. The results presented here are beneficial for storage potential identification and reservoir modeling part, which can provide a more precise estimation of CO2 storage volume. The final results of the QI study provide good quality seismic inversion products and lithology cube, which enabled sand delineation at the target CO2 storage level. The key contributors have been ensuring optimal seismic input data, being in this case achieved through using a PSDM seismic processing technology, careful parameterization of seismic inversion process, and utilization of Bayesian classification method for lithology classification.
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.
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