Pellervo Economic Research

Summary This paper introduces an end-to-end in-house development of an AI-assisted subsurface workflow designed for compartmentalized gas fields in the Gulf of Thailand, which faces the challenge of small reservoirs requiring a large number of wells and swift subsurface analysis. The objective is to streamline and automate key subsurface processes—subsurface interpretation (fault, horizon, prospect), well targeting, and production forecasting—to reduce exhaustive effort, improve consistency, and suggest optimal decision-making across the full field development lifecycle. It blends domain expertise with advanced analytics, runs on HPC, and integrates with commercial software, offering a scalable solution for faster, smarter E&P decisions. The overall could streamline the process in GoT and provide benefit from improved investment decisions in all aspects, from seismic interpretation, well targeting, and production optimization.

Summary In mature fields throughout the Gulf of Thailand, although conventional wireline logging is essential, it increases the financial and rig-time constraints. Using a machine learning (ML) approach, it can be mitigated. The availability of legacy well data facilitates the use of an ML-based synthetic logs methodology. This paper presents Log X-Press, a PTTEP’s customized application, designed to produce Neutron-Density curves from Gamma Ray and Resistivity data, hence, reducing logging frequency while preserving subsurface interpretation and decision-making qualities. The trial implementation of 15 gas development wells throughout the study area, with synthetic logs compared to actual measured logs to analyze porosity trends, lithological variations, and net gas pay. The pilot deployment revealed that Log X-Press consistently produced synthetic neutron and density logs that facilitate efficient reservoir assessment. The synthetic logs effectively recorded essential petrophysical indicators and lithological differences in gas zones, well correlating with standard triple combo log data.

Summary Offshore Thailand has the great opportunity for CCS networks and acting as a main hub for CO2 transport and storage activities. However, complex geological features may reduce the capacity coefficient (Cc) and increase the risk, posing challenges to Thailand’s CCS implementation. One of the most important factors in selecting for the best long-term storage location is the lateral continuity of storage reservoir where CO2 could be injected into porous rock formations in deep underground and trapped beneath the widespread impermeable caprock. To seek the most effective long-term storage, seismic attributes analysis could early provide valuable insight for both possible lateral continuity of potential caprock and fault zones that may disrupt the reservoir and contribute to the risk of CO2 leakage. This study aims to demonstrate the conceptual framework for estimating CO2 storage in saline aquifer formations of complex geological structures with staggered sandstones in Gulf of Thailand through a basin-scale assessment to identify the promising storage area potential. This analysis may also be applicable to areas with comparable complicated geological formations and provides guidelines for the implementation of CCS exploration initiatives in Thailand.

Tässä tutkimuksessa tarkastellaan ammatilliseen koulutukseen valmentavissa (VALMA) opinnoissa opiskelevien keskisuomalaisten nuorten opiskelumotivaation, kouluhyvinvoinnin ja heidän saamansa sosiaalisen tuen yhteyttä toisen asteen koulutukseen hakeutumiseen. Analyyseissa hyödynnettiin vuosina 2016 ja 2017 kerättyjä kyselyaineistoja, jotka yhdistettiin Tilastokeskuksen rekisteritietoihin opiskelijoiden päätoimesta ja valtionveronalaisista tuloista vuosi kyselyyn osallistumisen jälkeen. Tulokset osoittivat, että suomenkielisillä opiskelijoilla oli heikompi opiskelumotivaatio vieraskielisiin opiskelijoihin verrattuna, mikä voi johtua suomalaisten opiskelijoiden nuoremmasta iästä. Kun tilastollisissa malleissa vakioitiin opiskelijoiden väliset erot demografisissa taustaominaisuuksissa, erityisesti tehtävää välttelevä suoritusstrategia (epäonnistumisen ennakointi ja tehtävien välttely) ennusti NEET-ryhmään kuulumista vuosi kyselyyn osallistumisen jälkeen, erityisesti miehillä. Opiskelu- ja työuran suunnittelumotivaatio oli myös yhteydessä lisääntyneeseen toisen asteen koulutuksen hakuaktiivisuuteen vieraskielisillä nuorilla.

Summary The Arthit gas field, located offshore of Thailand has planned to re-inject the separated CO2 back into the identified storages. Time-lapse seismic is the primary technique planned to observe the CO2. The identified storages of the field are a stack of thin sandstone. The storage site is a combination of depleted reservoirs and aquifers. This study determined the feasibility of using seismic to monitor CO2 in a complexed 2-types storage. Synthetic seismic data is generated from 3D elastic models (Vp, density) using full-waveform modeling. The elastic models were previously transformed from dynamic reservoir models using rock physics equations. The final seismic was then calculated into time-lapse seismic attributes. The attributes have shown the potential of using seismic to monitor CO2. Strong time-lapse effect from CO2 was detected at the shallow aquifer. While the effect is less apparent in deeper depleted reservoirs. Despite low visibility in deeper sections, the time-lapse seismic is considered an essential technology to ensure operation success as the shallow CO2 plume is still detectable. Any unplanned migration or early shallow leakage is likely to be detected. A small-scale seismic operation can be cost-effectively achieved by optimizing seismic acquisition and processing to match observation from this feasibility.

Abstract One of a key responsibility for oil and gas industry is to ensure the balance between energy sustainability and minimizing the net carbon footprint to the environment. PTTEP, Thai national oil and gas company, has aligned this goal to achieve net zero greenhouse gas emission in 2050. Therefore, the scope of this project is to utilize carbon capture and storage (CCS) technology by injecting CO2 into the depleted reservoirs in the Gulf of Thailand. To evaluate the feasibility of the project, the simulation model was required to mimic the physics behaviors, including free gas structural storage, residual trapping, soluble gas in water and mineralization, when the CO2 was injected into many layers of depleted reservoirs. This is to obtain the optimized scenario for CO2 injection. However, the key step for reservoir simulation is the history matching by calibrating the model with production data. First, the static model was built by integrating geological understanding, well data, logging data and petrophysical interpretation, core data, and quantitative interpretation (QI) from seismic data. Then, the subsurface uncertainties were captured and transferred to dynamic model for history matching step. The sensitivity analysis was performed to understand causes and effects and determine the significant uncertain parameters. Then, the assisted history matching was performed to explore the possible solutions using evolutionary algorithm. Lastly, multiple realizations of history matching solutions were obtained. From sensitivity analysis, the key parameters to be calibrated with production data and routine shut-in bottomhole surveys are gas-water contacts, porosity and permeability correlation and relative permeability endpoint parameters. From history matching solutions, we narrowed down the range of uncertainty of uncertain parameters during history matching. The pressure, gas and water production could be matched. Obtaining the calibrated model from history matching is the critical step because this will determine the feasibility of the project in terms of injection strategy and CO2 storage volume. This study was the first history matching task performed for Thailand CCS project. The practical and robust history matching workflow used in this CCS project could be set as a milestone and provides the guideline how to implement assisted history matching technique for any future CCS projects.

Abstract Ageing fields are often in a race against depreciating Net Present Value (NPV) and decreasing production, advent of rising water contacts threatening daily and cumulative production. Static geological models form the primary input model into dynamic models which define and determine the development strategy of fields. Typically, dynamic models built from incipient seismic and geological models comprising of well data from early appraisal wells. In time, incorporation of production data refines the dynamic behaviors of field and in turn, these dynamic models are then used for subsequent re-development of the ageing fields. However, the incipient seismic models rarely receive similar updates as seismic acquisition are too costly to justify in an ageing asset with ever-depreciating NPV. This paper illustrates the process undertaken by subsurface team in identifying potential sites constraints by seismic and geological studies, in comparison with initial oilfield production incorporating pressure data to identify sweep efficiency. Starting with understanding a reservoir that experienced poor injection support, has led to unearthing the presence of faults that were not identified in previous seismic interpretations, and thus compartmentalizing the reservoir. The presence of the ‘unseen’ barriers in between an injector and an oil producer has hampered the injection effort towards the producer, and thus has been detrimental to the health of the reservoir. In lieu of the renewed understanding of the reservoir with regards to field compartmentalization which is recognized as key threat to water injection performance in Reservoir-L, usage of artificial intelligence machine-learning generated fault volumes helped define compartments better. The results indicate the NNW-SSE conjugate (shear) faults formed during the Mid-Late Miocene times which were not clearly demarcated on earlier seismic, play key contributing role with regards to connectivity and intra-field communication. This in turn led to revised understanding on areas of reduced production that led to model updates in line with production behaviors. Based on the new model, well location optimizations were undertaken for two water injectors in the infill drilling campaign for shallower Reservoir-K of Field S to avoid potential compartmentalization that would impact the sweep efficiency. Relocation of the water injectors into the same reservoir compartment as the target oil producer was expected to improve the EUR by ensuring direct sweep and good injectivity to the producer. In summary, by revisiting field models in advent of updating and recalibrating the dynamic model in view of historical production data, the team was able to update the model contributing towards field revitalization and field management in ensuring the field model delivers to the field development plan. The hard work from the team has paid out through the recent production performance of the reservoir.

Abstract Two Riser hoses attached with FSO2 (Floating, Storage & Offloading) has estimated service life (9.3 years). The next replacement is required before July 2022. Thus, in June 2022 Project team had planned to disconnect and reinstall two newly riser hoses with approach to comingle production stream enable to continue production without any shutdown. The overall execution plan has learnt best practices from previous operation since 2013. For 15 days offshore execution, collaboration between Project team, Operation & Maintenance, Marine team and specialized contractor is essential. The offshore execution began with preparation steps which include tank offloading, heading control system, pre-installation visual survey, before comingling to operate one riser hose and flushing another. Then, the 5 days operation per hose to disconnect, replace the newly hose. After leak test and hydrotesting all connections was performed, Production team will switch the production via this new hose and repeat similar replacement steps with another hose. On technical aspects, the riser hose replacement may consider not a complicated task. Although advance preparation prior commencing offshore installation in conjunction with experiences contractor are critical and important. Collaboration with various stakeholders requires full attention to address those concerned areas with mitigation and measures especially on HSE aspects resulted from risk assessment and several workshops. Strategic approach to perform the riser hoses replacement without interrupting the production is a challenge. Applying comingle strategy requires effort to breakdown related activities and sequential analysis to ensure all the execution will be smooth without jeopardizing the HSE issues. Also, during the contractor selection stage Project team had selected national qualified contractor. It turns out that national contractor also has similar capability to manage and deliver this scale of project with very acceptable quality but competitive price. Even this is not PTTEP first riser hoses replacement project though the Project team would like to remark great achievement which could only arise from effective teamwork, good collaboration among all relevant stakeholders and benchmarked best practices from our expertise and learned from previous experiences. In addition, it is worth to mention that the offshore execution was performed safely without interrupting the environment and the ongoing production.

Abstract As a part of the company's digitalization project, the Well Delivery Process (WDP) software solution was successfully developed and launched in early 2021. By using this solution, engineers benefit from the project objectives like process standardization, well design quality, and well planning cycle time reduction. The WDP software consists of a series of integrated well delivery workflows including well design, drilling execution monitoring, and closeout reports within a single cloud-based platform. The system also provides users with many automation features such as well design rules validation, offset well analysis, risk analysis, automated calculations, and digital reports (drilling programs). Through this paper, we share our experiences and observations on the system development and implementation, and also challenges and limitations that we faced to roll it out successfully. In our conventional practices before the digital transformation, drilling engineers had their individual practices/formats to perform the well delivery process using various applications and techniques. Computer applications were used to generate and compile a drilling program, but there was no standard way of performing this process. In situations where the design parameters and/or subsurface information change, engineers should have repeated the entire process to revise the design and/or the drilling program manually. To standardize the process, minimize repetitive tasks, and provide engineers with all required digital tools, the first solution (a prototype computer program) was developed in-house to prove the concept. After multiple peer reviews and trials, we used the prototype program to specify user requirements for generating the WDP software solution. An agile methodology was utilized to engage all drilling engineers in each sprint of the WDP development phase to ensure that their requirements are fulfilled. Upon completion of the development phase, a comprehensive User Acceptance Test (UAT) was conducted followed by training sessions before the cut-off date for switching from the manual process to the WDP digital workflow. Switching from existing practice to a new way of work is always challenging especially when it comes to introducing new software. There was some resistance at the start-up period due to users' unfamiliarity with the software and also software bugs that were not found during testing periods and UAT. A support team was set up to ensure immediate action on users' requirements and any technical issues with the software. During the challenging transition period, all users were fully supported until make sure they are enough familiar with the system to complete the task effectively. The support team deployed hotfixes (bug fixing) as quickly as possible with no major impact on the drilling programs' timeline, monitored the system performance on daily basis, and gathered feedback for further improvements. At present, the WDP is the primary system used by all drilling engineers in the company's domestic assets as an integrated end-to-end well delivery workflow that provides an improved design quality in a shorter planning time. More than 200 well design workflows have been initiated and approved through the system since it is being used. Based on the recent users' satisfaction survey and feedback, an overall rating of 4.2 from 5 shows the WDP solution's effectiveness with many popular and useful features especially offset well analyzer and well design dashboards. As one of the first end-to-end workflow generations in the drilling engineering process, the WDP could save the working time up to 35-40% (voted by users) through a centralized dataset platform and its holistic approach to process standardization/automation. Besides design quality and cycle time improvement, the system also enables advanced data analytics for further automation and enhancements.