bluuebunny/crossref_metadata_2025 huggingface dataset:
New Pillar of Mature Field Production Strategy: A Success Story of ESP Upsizing Pilot Project
Authors: Aryanto Agus , Malau Aldani , Hidayat Azis , Nugroho Muhammad Hasto , Yassin Chaidir , Lazuardi Hilman
Published: October 2023

Electric Submersible Pump (ESP) upsizing project has historically an effective tool to optimize oil production. As a mature field, KS field currently was producing with average 97% water cut. Most of the ESPs installed in SK field were designed to produce 1,000 to 2,500 BLPD. Meanwhile, the potential maximum liquid rate of some wells is much higher than the current ESP rate, ranging from 8,000 to 17,000 BLPD. The oil production can then potentially be increased 3 to 5 times higher by upsizing the ESP. Hence, the objective of this study is to accelerate oil recovery from un-optimum oil well.

This optimization can be achieved in 2 ways, either drill new big bore well or optimize existing well. By optimizing existing wells through ESP upsizing pilot project, we can save estimated USD 1.5 MM compared to drill a new well. The ESP upsizing project is planned into 3 phases; phase-1 pilot (2 wells), phase-2 implementation (8 wells) and phase-3 and phase-4 full-scale (33 wells). KS-XXX1 and KS-XXX2 were selected for the pilot project and upsized using ESP pump with recommended operating range 3,500 – 10,500 BLPD at 60Hz. The reservoir simulation, fractional flow evaluation, production network modelling, well performance and nodal analysis were conducted prior phase-1 execution to increase project confident level. To operate these high-rate wells, some improvements in electrical system, flowline safety devices and well test procedure are also required. Therefore, multidiscipline team was involved in this project.

The pilot project phase-1 has successfully executed and currently producing 476 BOPD from initial rate 80 BOPD without significantly increasing of water cut. Estimated cumulative oil gain of these wells are 567 MBO.

The successful phase-1 ESP upsizing will unlock the potency of phase-2, 3 and 4. Through maximizing liquid production and reducing number of active ESP wells, oil production is expected to increase with lower operating cost (by reducing well count). Estimated oil gain from full scale implementation is 4.93 MMBO.

This paper will describe a production optimization in mature field by ESP upsizing. Increasing liquid production is established technology to improved oil recovery in mature reservoir. Application of upsizing in high water cut wells has been proven to improve production decline using low expenditure.
Development of a Unified PVT Model for a Large Heavy Oil Field in Kuwait
Authors: Alali Yacob , Verlaan Marco
Published: October 2023

Field X is an extensive heavy oil field in the North-West of Kuwait with 4 reservoir zones and extensive variation in heavy oil composition and physical properties (10-18 °API). Historically, various PVT models have been developed for various parts of the Field X for different modeling purposes. These models - often developed by different engineers - are not consistent and add another layer of complexity to the understanding of reservoir performance for different regions of the Field. The objective of this study is to develop a unified PVT model for use in the dynamic thermal simulation for the whole Field X.

The model follows the standard procedure for PVT modelling for heavy oil. In this case, however, due to abundance of PVT data, the challenge is selecting/disregarding PVT samples to be used for tuning a global Equation of State (EOS). Most recent, reliable PVT samples (18 samples out of 155) over the whole range of densities with possible different locations were selected. The most complete set of PVT data was used for construction of an EOS which was tuned using the selected 18 samples.

A single 4 component EOS model was regressed on a selection of 18 PVT samples distributed over Field X area. This model matches Saturation Pressure ±14%, GOR ±8%, Oil Density ±0.2%. These models are exported to CMG STARS format to be used in Field X life of field dynamic modelling study. Separately a viscosity model was developed using the Yarranton approach and that matches oil viscosity in all 155 samples with an average deviation of ±17%. To test the robustness of the model, an additional set of 11 samples has been selected in a wider area of the Field X including samples in the South, South-West and West area. The model matches the saturation pressure, GOR and density values reasonably well, with a bit more scatter than the samples used in the model tuning.

The PVT study revealed a strong correlation between the mole fractions of pseudo components and the in-situ oil viscosity and bubble point pressure. This enables calculation of initial oil composition in the dynamic model based on interpolated viscosity maps.
Complex Fluid of South Mahakam: A Fluid Synthesis Case Studies with Overpressure and Gas Striping Phenomena, of Multilayer Reservoirs for Marginal Offshore Gas Field Development in the Manpatu Field
Authors: Fajar Dendy Surya , Rushatmanto Mochamad , Utama Fia Adhi
Published: October 2023

Manpatu Field was discovered in 2022. It will provide a transition to green energy supply for the future capital of Indonesia, which will be located in the same region of East Kalimantan. A fluid synthesis studies methodology of the retrograde gas-condensate with gas striping phenomena on the overpressure multilayer reservoir fluid vertical distribution was introduced to rectify volumetric calculations in both static and dynamic geomodel simulation. This was done to justify the economics of the offshore marginal gas field development.

The new approach is based on generating a specific fluid model - EOS pseudo component methodology for Gas Striping that is in agreement with the geochemistry analysis. It involves integrating the surrounding panel with exploration well data to control the fluid model based on Gas Liquid Ratio (GLR) and hydrocarbon column occurrence in the overpressure vertical distribution of the Manpatu Field compared to other panels of the South Mahakam Field. The aim is to provide a base-minimum-maximum case scenario in reducing uncertainties of the fluid, in order to economically justify the volumetric hydrocarbon calculation in static and dynamic simulations.

A fluid model with 5 pseudo components, following a specific trend based on the geochemistry analysis of the hydrocarbon with gas stripping phenomena, was generated to match all the fluid behavior from the PVT samples. However, this is only half of the journey. Saturation pressure and GLR vertical distribution from the available samples taken from the exploration wells are not sufficient to determine fluid evolution with the overpressure regime in the Manpatu Field. Therefore, combining the data with the surrounding produced panel is taken into account. The result deviated, even contradicted, the classical gravitational segregation vertical fluid distribution. Specific GLR and Saturation Pressure evolution trends vs. depth scenarios and assumptions in the overpressure regime were made to govern fluid vertical distribution and reduce uncertainties in static and dynamic geomodel simulation to mimic the phenomena in the field.

Gas striping and overpressure need to be considered in order to have a reliable multilayer reservoir gas condensate-oil fluid model for reliable OOIP and IGIIP volumetric calculations and development scenarios. Using classical gravitational segregations vertical fluid distributions would lead to misleading conclusions. The results of volumetric calculations and uncertainties are rectified for the justification of the project's economic feasibility for the Manpatu's marginal gas field development FID's.
Success Story in Implementing New Substructure Technology for Offshore Marginal Fields
Authors: Islami Era
Published: October 2023

Medco E&P Indonesia (Medco E&P) operates offshore platform in Natuna Sea. The recent development in Natuna Sea is for marginal field. In case development of marginal field using wellhead platform concept, the challenge in built offshore platform in Natuna sea which has harsh environmental metocean and water depth range from 70 m – 100 m is limitation of crane barge for installation of offshore jacket platform. With metocean criteria and water depth in Natuna Sea, the minimum jacket weight using conventional design is about 1000 ton lifting weight, in 2019 during the Medco E&P Project executed, there is no crane barge with Indonesian flag available in market, the maximum crane barge capacity in Indonesia is 600 MT – 800 MT lift weight. Therefore, Medco E&P team should find substructure new technology for lightweight structure which could be installed by available crane in market to achieve fast track and optimized project cost for marginal field development.

The new technology is required to overcome the challenges for marginal field development which requires fast track and low capital project, modular braced monopod has been selected through qualitative and quantitative assessment done amongst 6 lightweight substructure technologies during select phase. Executing project with this new technology, requiring specific project and construction strategy as well as comprehensive assessment on installation procedure and acceptance criteria. The concept of modular braced monopod has benefit in lower offshore lifting weight so require only small crane barge. The jacket consists of several parts which the maximum lifting weight for jacket component is 380 MT only.

The modular braced monopod platforms for two fields in Natuna Sea has been installed and operated normally since December 2022, the project has successfully installed 1st modular braced monopod platform in Indonesia with maximum offshore lifting weight around 380 tons only for water depth 79 m compare to non-lightweight structure such as 4-legged platform for similar water depth might requires 2000 – 3000 tons crane barge capacity, the technology has supported for project cost optimization and suitable for tight schedule. The installation of modular braced monopod in the project is the fastest installation compared to other zeepod installation. Area of improvement has been documented and some recommendations for future application to be shared so that allowing better project development for other marginal project. The success story from this project will describe journey in technology selection, risk identification and mitigation, managing interfaces, high standard quality of construction and installation work, as well as providing some lesson learned to organization in executing new technology in offshore platform project.
An Intelligent Separated Zone Oil Production Technology Based on Electromagnetic Coupling Principle
Authors: Liao Chenglong , Jia Deli , Yang Qinghai , Pei Xiaohan , Zhu Yingjun , Kong Lingwei , Yu Yang , Du Kai
Published: October 2023

Separated zone oil production technology is an important means to solve the interlayer and planar contradiction, fully develop the middle and low permeability layers, reduce the ineffective water circulation, and realize the remaining oil exploration in the high water cut stage of the oilfield. The existing technologies suffer from many problems, such as unsuitable for pump inspection operation, short working life, and poor communication reliability.

This paper proposes an intelligent separated zone oil production technology based on electromagnetic coupling principle. The release-sub-involved pipe string structure is adopted, in which the production pipe string from the ground to the pump is connected by external binding cables, and multiple intelligent production allocators (IPAs) of the allocation pipe string are also connected by cables. The electromagnetic coupling principle is used to realize the close-range wireless transmission of power and data between the production and allocation strings. After the docking, the allocation pipe string can be powered from the ground, and two-way communication can be realized. This technology provides a repeatable downhole docking and detaching channel of power and data transmission, which eliminates the need to lift out the allocation pipe string during routine pump inspection operation, effectively increasing the working life of the IPA and reducing operation cost.

The main components of this technology include ground communication controller (GCC), downhole electromagnetic coupling device (DECD), and IPA of each layer. The GCC is used to collect downhole monitoring data and adjust the zonal fluid production. The DECD consists of an inner cylinder tool and an outer cylinder tool. The inner cylinder tool is connected to a tubular pump, while outer cylinder tool is connected to the IPA. The average transmission efficiency and power of the DECD is 94% and 52 W respectively, and the error rate of data transmission is less than 1%. The IPA has the functions of temperature, pressure, flow rate monitoring and zonal fluid production adjusting, with a flow rate measurement range of 5∼100m3/d, an accuracy of ±3% FS and a flow control valve of maximum overflow diameter of 15mm. The field trials of this technology were carried out in Daqing Oilfield and the experimental well was divided into two layers. The results showed that DECD was successfully docked. The measured downhole temperature was about 46°C, the maximum flow rate was 35 m3/d, and the bottomhole flowing pressure was 9 MPa.

This technology has the advantages of suitable for pump inspection operation, high communication reliability, and long working life, providing a new engineering technical means for alleviating the interlayer contradiction and improving reservoir recognition, which is expected to have a broad application prospect.
Well Configuration and Placement Optimisation in Dual Media Systems Through Reservoir Modelling Approach
Authors: Al Mulhim Abdulrahim K. , Alnasser Mohammed H. , Alshubbar Ahmed K. , Hamam Hassan H.
Published: October 2023

During field development, evaluating and integrating various subsurface complexities and flow dynamics enable to generate optimum well placement blueprint. Hydrocarbon sweep efficiency can be enhanced through proper well configuration and layout. The well placement blueprint relies heavily on reservoir modeling to accurately determine well productivity and water encroachment by incorporating the reservoir's unique characteristics. This paper examines various well configurations and layouts that optimize hydrocarbon recovery while taking into consideration various degree of reservoir heterogeneities and uncertainties.

A synthetic dual porosity, dual permeability (DPDP) simulation model is utilized to analyze sweep and water encroachment. Multiple scenarios are developed by including various well configurations and layouts. Vertical, horizontal, and slanted wells are parametrized to evaluate the vertical and areal sweep efficiency. In addition to the well configuration, the role of wells’ spacing and orientation on sweep and well productivity is investigated. Various well landing zone and completion interval are incorporated in the analysis to capture the model's subsurface characteristics.

The DPDP simulation model provides insights on the possible well configurations and layouts to optimize sweep and enhance recovery. In-depth analysis for every scenario was performed to benchmark the impact of parametrizations on sweep efficiency, water breakthrough, and pressure propagation. The developed scenarios demonstrated the effects of well configuration on areal and vertical sweep efficiencies. For instance, slanted wells yield unique sweep signatures compared to vertical wells. Well landing zone and orientation played a major role on the overall recovery where vertical wells that were completed across the top zone can overcome horizontal wells completed in the bottom zone of the reservoir.

This paper reviews a systematic reservoir modeling workflow to optimize well configuration and layout by utilizing a DPDP synthetic model. The approach describes how to optimize hydrocarbon sweep and recovery by incorporating various degrees of subsurface complexities.
Automated Production Enhancement Candidates Screening Powered by Machine Learning Unlocks Untapped Potential in Matured Oil Fields – A Case Study
Authors: Mat Khair Nusheena , Zaizakrani M Farid , Zul Azhar Nur Afrina Inani , A Halim Fatin Liyana , Sidek Sulaiman , Nik Khansani Nik Zarina Suryana , Shafie Shar Kawi Hazim , Mokhlis Mohamad Mustaqim , Hazali Nurdini Alya , Saifuddin M Nabil
Published: October 2023

Field A, located offshore East Malaysia, has been a productive conventional oil field for more than three decades. Being a mature or brown oil field, it encounters several surface and subsurface including sand production, increasing water-cut and reservoir pressure depletion. Consequently, field production declines over the years. These issues have compelled the team to pursue for options to optimize the existing Field A's producing and idle wells in an effort to slow the production decline rates and keep up with field deliverability.

Failure to recognize and manage well behaviors may cause producers unable to meet production targets and experience other serious problems, such as well integrity. Hence, Production Enhancement Candidate Generation and Screening (PECGS), a Machine Learning (ML) tool, have been utilized in Field A to identify potential candidates for Production Enhancement (PE) from both active and inactive wells. The system has been able to establish a workflow that is capable of guiding and navigating the engineer through the process of identifying candidates for PE, such as zone changes (ZOC), Behind Casing Opportunities (BCO), add perforations and well stimulations that can be tracked all the way up to the execution stage.

This paper presents the processes of identifying production enhancement opportunities, as well as the methodology utilizes to identify underperforming candidates and analyze well integrity issues. It describes how data science and engineering analyses are integrated, and stresses how collective insights are gained from quantitative and qualitative outcomes, such as production increases, cost savings, operational efficiencies, and overall impact on field performance.

The implementation of well-engineered workflows has significantly aided and enabled users in identifying low-hanging fruit opportunities. This solution has created an efficient working environment, particularly for the team in Field A, empowering them to identify and capitalize on PE and Idle Well Reactivation (IWR) potential opportunities. By emphasizing the overall process flow from identification to results, this paper aims to provide a comprehensive understanding of the PE journey in Field A, showcasing the effectiveness of the approach and its contribution to the field's performance improvement.
Evolution of a Versatile HTHP Water-Based Drilling Fluid Improved Drilling Efficiency Offshore Vietnam
Authors: Moroni Luigi , Fatkullin Kamil , Tran Thanh Bao
Published: October 2023

The fast pace of exploration and production level increase over recent years has led operators to expand the horizon for exploration of hydrocarbons in more complex and exigent reservoirs which includes the high temperature and pressure (HTHP) reservoirs. Typically wells in the North of Vietnam have been drilled using a Non-Aqueous Drilling Fluid (NAF) for their lower and reservoir intervals. The challenges of multi-string design, potential of acid gas contamination, well bore stability, down hole losses and a high temperature environment require a well-engineered NAF to meet the overall well objectives.

Alternatively, Water-Based Fluid (WBM) has significant environmental benefits compared to NAF. This paper presents the technical development, evolution and lessons learned from using a high performance HTHP WBM over a series of extremely challenging HPHT exploration wells Offshore Vietnam, with temperatures expected to reach 170°C (338°F) and pressures over 12,000 psi. These conditions place severe limitations on the drilling fluid design and can often lead to failures in open-hole wireline logging operations, which is probably the most important objective in an exploration well.

To ensure the successful drilling, wireline logging and completion operations under the thermal conditions, the development of the HPHT WBM for these exploration wells needs to address the HTHP filtration control properties, filter cake quality, inhibition and the thermal stability of the drilling fluid. Extensive laboratory testing was performed to optimize the rheological properties for mud weights up to 18.7 ppg to ensure minimal sag tendency after static condition, while also providing excellent filter cake quality, system inhibition and hole condition to allow the well to be fully logged and evaluated.

The enhancements made in the HPHT WBM design led to an improved drilling performance in drilling these challenging exploration wells. Inhibition of the reactive formations was improved with each well drilled, as was the rate of penetration and wellbore stability. Extensive logging was performed with the wellbore remaining in excellent condition throughout the long open-hole time.
Water Injection Efficiency Improvement through UPD and RAM Analysis
Authors: Ali Zalina , Charil M Ayatollah , Mahmood Azizul , Daud Fairoz Irfan , Yusoff Noor Syaffynas , Sy Nadzir Sy Abu Bakar
Published: October 2023

Water Injection (WI) facilities design and operability of the system are crucial aspect in ensuring the treated water is meeting the specification and uptime required in compliance to the Reservoir Management Plan (RMP) target. Inefficient water injection facilities performance can result in lower equipment availability and reliability and pose a threat to injection uptime and impact the production gain. Sustaining injection to meet the target remain a challenge due to various facilities concerns including integrity and reliability resulting in equipment downtime, systemic issues, and operation surveillance and performance monitoring. Despite an integrated approach involving activity workflow and processes to ensure successful performance and operation are in place, less priority to WI facilities as compared to oil or gas production system resulting in lack of focus towards WI operation and maintenance response. This paper aims to demonstrate WI Facilities Performance Improvement via Unplanned Deferment (UPD) events deep dive analysis and Reliability, Availability and Maintainability (RAM) study. The UPD analysis focuses on identifying the UPD underlying root causes and threat for continuous facilities operation, subsequently crafted effective mitigation actions and solutions to overcome the issues. RAM studies were executed to assess the WI module capability in terms of the availability of the system and impact to the production. This is a holistic approach to assess existing WI equipment performance to sustain > 95% uptime and meet the RMP target. Short- and long-term mitigation plans have been identified to elevate WI UPD focus within the organization including categorizing WI deferment category in the Production Deferment Management guideline and quantifying the impact of not injecting to the production gain to ensure WI UPD events can be tracked and high priority are focused on equipment maintenance response. The result from this specialized UPD and RAM study shows that opportunity improvement of 2%-15% based on the solutions in-place can further enhance WI system availability to achieve > 95%.
Lesson Learned from the Hydraulic Fracturing of China's Shale Oil Field
Authors: Li Shuai , Cai Bo , Xin Jin , Yi Xinbin , Li Jianmin , Wang Mingxing , Li Jiacheng , He Chunming , Zhang Haoyu , Yan Xingming , Gao Yuebin
Published: October 2023

With the gradual deterioration of oil and gas resources quality, more companies are targeting the unconventional reservoirs. In China, unconventional reserves have accounted for more than 80% in total newly found proven reserves, taking tight oil for an example, China has tight oil geological resources of more than 12 billion tons.

In this paper, we firstly introduced the main geology and reservoir characteristics of the target block, the strong formation heterogeneity, low permeability, low abundance, etc. This kind of reservoir has no economical production without hydraulic fracturing, while the stimulation operation still faced with difficulties such as un-predicate fracture propagation, high cost and low efficiency.

Aiming to solve these difficulties, we summarized the status, experience and field application of the main hydraulic fracturing technologies in this area. (1) Horizontal well multi-stage fracturing (HWMF) technologies, featured with small well spacing, dense cutting, large fracture stages and small clusters, were widely used and applied as the main hydraulic fracturing method. (2) Widely used soluble sleeve bridge-plugs and soluble ball seats in the P’N’P completion wells, saving working time and reducing the construction cost. (3) Multi-functional fracturing fluids, featured with imbibition mechanism and increase oil recovery. (4) Replacement of ceramsite by low-cost quartz sand. (5) Factory-fracturing construction model, with maximum 12 well in one well platform.

The integrated technologies have been applied in more than 200 wells, the daily oil production per well has increased from 3-5t/day to 15-25t/day. Application of the integrated technologies and the experience can be references for the efficient development of similar tight oil reservoirs.
An Onshore to Offshore Conceptual Model to Characterise Structural Domain in West Timor Basin
Authors: Andaru Arkanu , Wiranatanagara Muhammad Budisatya , Madjid Muhammad Yusuf Abdul , Ardiansyah Nugraha , Kristian Jonathan
Published: October 2023

Despite its complex geological and structural conditions, West Timor holds great potential for petroleum exploration. However, a lack of data on the onshore area has made it challenging to fully understand the geological conditions that extend from offshore to onshore. This study aims to develop a geologic conceptual model that unravels the geological and structural complexity in West Timor by extending the geological understanding from onshore to offshore.

To achieve this goal, a play-based exploration methodology is employed, which includes geological field mapping and fluid sample analysis in the onshore area, and subsurface mapping using well and seismic data, 2-D palinspastic analysis, and basin modeling in the offshore area. A combination of land and satellite gravity data analysis is used to make basement depth estimations in both onshore and offshore areas, validated by well and seismic data. The geological analysis in the onshore area is then integrated with the analysis in the offshore area to obtain a complete geological understanding that extends from onshore to offshore and differentiates structural domains in the study area.

This study is able to construct a comprehensive geologic conceptual model and differentiate four structural domains (SD) in West Timor. These structural domains provide insight into the stratigraphical succession, basement depths, and other structural features that can help explain petroleum systems in the region. SD-1 is a normal horst-graben system, while SD-2 is thin-skinned deformation with a slightly deformed horst-graben system below imbricate thrust-fold system with a detachment surface penetrating Early Jurassic sediment (detachment surface in this domain is Aptian Early Cretaceous-shale of Darwin Fm.). SD-3 is similar to SD-2, but the detachment surface penetrates deeper into Triassic sediment (distal shale as part of prograding toe from Triassic sediment). Lastly, SD-4 is a highly deformed zone where the detachment surface penetrates the basement, resulting in a thick-skinned structure. The onshore area has the most deformed structure zones (SD-4 and SD-3) linked to fold-thrust belt geometry, making it more challenging for petroleum exploration. Meanwhile, the near-shore and offshore areas (SD-2 and SD-1) have less structural deformation. They are considered the most promising areas for hydrocarbon accumulation below imbricate thrust fold system (subthrust), as they still preserve the structural conditions and stratigraphic succession needed for accumulation.

The conceptual model constructed in this study offers a deeper understanding of the geologic and structural complexity in West Timor by integrating onshore and offshore data. By characterizing these structural domains, geoscientists can better identify areas with potential for petroleum accumulation and help synthesize a petroleum play concept in this area.
Assessment of CO2 Hydrate Generation During Sequestration in Depleted Hydrocarbon Reservoirs
Authors: Mousavi Mirkalaei Seyed Mousa , Rofieq Shodiq Khoirur , Bin Abdullah Ahmad Shahzwan , Khanifar Ahmad , Edmondson Mark Douglas
Published: October 2023

Carbon sequestration is the process of capturing and storing of atmospheric carbon dioxide (CO2) in the subsurface. The objective of any carbon sequestration project is to store CO2 safely for hundreds or thousands of years with a goal of reducing global climate change and net carbon emission. Based on preliminary studies depleted oil and gas reservoirs are considered good storage sites because they are well understood have already proven capacity to store hydrocarbons over millions of years.

Low abandonment pressure in these reservoirs provide an additional voidage-replacement potential for CO2 and allows for a low surface pump pressure during early period of injection. However, the injection process poses several challenges including the potential for hydrate formation.

This work aims to raise awareness of hydrate formation, which is a key operational challenge related to CO2 injection in depleted gas reservoirs. Hydrates, specifically CO2 hydrates, can significantly impact the efficiency and safety of CCS operations. This work provides a new approach to assess and anticipate the CO2 hydrate formation in the near wellbore region. A method for coupling a compositional dynamic simulator with flow assurance code using python is introduced to address the phase behavior of CO2 near wellbore under different operational conditions.

The proposed approach helps the reservoir engineer to anticipate hydrate formation in the early stage of project and plan to take necessary mitigation actions to avoid injectivity issue due to CO2 Hydrate formation. This work will also address the challenges associated with the numerical modeling of hydrate formation and dissociation, such as accurate thermodynamic modeling and phase equilibrium predictions.

The results from this work were identified several important parameters affecting hydrate formation during CO2 injection, namely injection temperature, reservoir pressure and thermal properties of the rock and fluid. It is important to pay attention to these key parameters to ensure accurate prediction of hydrate formation and dissociation phenomena. A sensitivity analysis was conducted to identify their effects on hydrate formation during the CO2 injection. The resulting tornado plot helped the study team to understand how quickly the hydrate can form after the start of injection. This helped the team to perform the necessary operational risk assessment.
Pre-Drill Geomechanical Modelling and Wellbore Stability Analysis for Successful Drilling in a Highly Overpressured Shale Zone and Potential Losses Carbonate Zone - A Case Study from West Tuban Block, East Java, Indonesia
Authors: Mikhael Chrislianto Reynaldi , Sagita Romi , Ghosh Amitava , Meidiya Putra Riko , Hisanah Nabilah
Published: October 2023

A high pressure well with a high risk of encountering a loss zone is a challenging drilling operation and requires a proper pre-drill study incorporating drilling practices, an understanding of the subsurface, and geomechanical modelling. This paper presents a case from the West Tuban Block. This block is within the East Java Basin, one of the prolific basins in Indonesia and a proven hydrocarbon reserve. The major challenge is drilling through the shale overpressure zone and the carbonate loss zone safely and successfully. This paper describes the building of a pre-drill geomechanical model, the subsequent wellbore stability analysis and how the results and recommendations were applied during drilling.

The geomechanical model was built using data from seven offset wells and also incorporated regional knowledge. The offset well review of the drilling experiences showed that the key challenges that will need attention are significant drilling problems such as pack-off and tight hole while POOH, RIH with casing and while wireline logging. Added to this are instances of losses and gains while drilling the carbonate reservoir section.

The geomechanical modelling process involves using petrophysical, geological, geophysical and drilling data to constrain the magnitudes of the overburden, pore pressure, rock mechanical properties and the two horizontal principal stresses. It is also important to constrain the azimuth of the maximum horizontal stress. The final model is verified using stress-related drilling problems and observations of wellbore failure in shale interpreted from caliper data.

The resultant geomechanical model suggests that the planned well is associated with a strike-slip stress regime. The magnitudes and azimuths of the stresses play an important role in successful drilling because the well is directional in the reservoir section with a maximum inclination ∼26°. The wellbore stability analysis was used to optimise mud weights for each hole section of the planned well. Recommendations were also made regarding additional data gathering (cores for conducting rock tests, extended leak-off tests, full suite of logs, etc.) to reduce uncertainty in the geomechanical model.

The mud weight and drilling practice recommendations, that were an outcome of the study, were followed meticulously by the drilling team so the well was able to safely overcome the overpressure zone and the loss zone. The effort contributed to the operator's success in the onshore development campaign with timely execution within budget and no reported HSE events.
Analysis of Accidents and Efficacy of Risk Management Practices of E&P Sector and Outlining More Pragmatic Approaches for the Management & Energy Regulators
Authors: Gaikwad Dheerendra Ajabrao
Published: October 2023

Accident patterns suggest, E&P sectors are struggling to professionally manage the EHS *(environment, health & safety related) hazard and associated risks emanating from their core businesses.

The author studied and analyzed the reported accidents from the last 8 years, along with their causes. It was observed that the root causes of accidents are very common, mere repetitions, and can be avoidable. This raises serious questions about the effectiveness of the existing EHS management practices/systems and also causes concern for management and other stakeholders. The author collected and relied on data from Tier-1* EHS (Environment, Health & Safety) accidents (1,808 incidents from the exploration and production sector worldwide) on a sample basis, which were reported and investigated.

The author analyzed the data and observed that the root causes of accidents are more associated with management and less with technical factors. Taking this into consideration, the author attempted to find a solution for the existing problems by utilizing appropriate management methodologies/approaches such as 6 sigma and Survivorship bias. Accidents occur due to coincidental failures of preventive/protective barriers at multiple levels, and the repeated patterns of these failures are a major concern for all stakeholders. By using strategic management tools/methodologies, the author ended up suggesting additional approaches/means to address the gaps in EHS management practices and achieve the desired EHS results.
Intelligent Detection of SEM Mineralogy Using Dynamic Segmentation Algorithm in Geothermal Sedimentary Reservoir: Case Study with Quantification of Quartz Overgrowth
Authors: Andaru Arkanu , Sausan Sarah
Published: October 2023

Quantifying quartz overgrowth in sedimentary geothermal reservoirs can provide vital information about reservoir quality and drilling success rates. The traditional process, which involves manual inspection of numerous Scanning Electron Microscope (SEM) images, is tedious and time-consuming. This paper introduces an automated approach using computer vision and random forest algorithms to streamline the process, providing a more efficient method for noise reduction, multi-level thresholding, machine learning (ML) model training, and application to SEM images for quartz overgrowth detection.

Our approach employs a dynamic segmentation algorithm that integrates noise suppression, multi-level auto-thresholding, and dynamic overlaying. This enables automatic mineral identification from lower-quality images, accommodating varying brightness and contrast levels. Additionally, the algorithm effectively handles overlay shifting in cathodoluminescence (CL) and backscattered electron (BSE) images. We use a Random Forest technique to train the algorithm using comprehensive ground truth data and CL image features like Gabor, Canny Edge, and Roberts Edge. The resultant ML model helps refine the image segmentation predictions, acting as a more precise mineralogy predictor.

Our model training achieved an encouraging 75% accuracy score, demonstrating its effectiveness in distinguishing between quartz grains and overgrowth, as well as identifying porosity and other minerals. However, due to the vast data size, further model improvement necessitates additional training data and usage of a High Performance Computing (HPC) cluster. After training, the model showed enhanced detection capabilities, particularly a reduction in false porosity detections associated with internal cracks. Future improvements could involve applying morphology detection principles and allowing user input for parameters like overlay shifting. The program was designed for easy use by individuals with minimal coding experience, and further development into a web app is suggested for increased accessibility.

In summary, this method significantly enhances the efficiency and accuracy of mineralogy analysis using SEM images, providing a quick and accurate method for geoscientists to determine mineral composition.
Fracturing New Wells in Mature Field – Tenares Tight Sand Development Evolution of Kotabuana Field Infill Drilling Initial Completion
Authors: Yogasugama Mario Andre , Prasetio Mario Hadinata , Nataliawati Nurul Ayu , Putra Rendy Maylana , Kusumaningsih Hapsari Wahyu , Sutyastomo Dwiyanto , Irfan Muhamad , Makmun Areiyando
Published: October 2023

Since the Tenares infill drilling campaign started in 2021, Fracturing has become Kotabuana field new well primarily Initial Completion (IC) method. The design was set based on the best practice that evolved throughout time since 2018, starting with typically 1300 bbls fracturing fluid, 80,000 lbs of proppant with a typical 7 PPA pumping schedule. During the execution campaign, the fracturing initial completion design and execution was improved by evaluating the post job result correlation towards well property and production result.

A key factor in the successful fracturing job is the fracturing model. In improving the fracture modelling, Temperature log was run to validate the 1D Mechanical Earth Model (MEM) by seeing the change in temperature post mini fract to detect the fract height growth. By doing so, the risk of having a premature screen out could be minimized, improving the overall job effectiveness. The necessary additives was also introduced to control the height growth.

The type and volume of fracturing fluid and proppant was also improved according to the lessons learned to gain improvement and progression on the optimal fracture design in each execution. Start with one and two-size proppants to get optimal conductivity and decrease fracturing fluid gel loading which can reduce residual fracturing gel. The job performance also highlighted in the aggressiveness of fracturing that compare the PAD ratio used in the execution towards the design by increasing the amount of proppant injected and pad cut. This progression makes the pumping execution reach up to 130.000 lbs of proppants and stage 12 PPA pumping schedule.

Numerous improvements were observed during the IC fracturing process. During the sand clean out operation, a more direct approach to the cleaning up operation was employed by maintaining the pressure in the string annulus during 4 of 5 screen-out occasions which successfully reduces the needs for Coiled Tubing Unit (CTU). There are also accumulative works and efforts which successfully optimized the cycle time of fracturing operation by year of execution. Another improvement was the decisive action to conduct re-fracturing execution when a premature screen-out was encountered, improving the total cycle time and workflow.

The Fracturing result has been proven to stimulate the productivity index (PI) of the well with a fold of production. Some key lessons learned during the executions were documented which highlight the importance of several key aspects such as temperature log utilization to validate 1D MEM, proppant tapering strategy in pumping schedule, well placement towards the fracturing design and the existence of injector well to provide pressure support in sustaining the well production.
Challenging the AWCA Annular Wash Cement Assurance Acceptance Norm
Authors: Damasena Edwin
Published: October 2023

Annular Wash Cement Assurance (AWCA) has been used for several years as a cost-effective tool for Permanent Abandonment (P&A) of oil/gas wells to remediate cement behind casings in lieu of Section milling to establish a rock-to-rock barrier. In order to verify AWCA result in the annulus, originally the cement in the casing is drilled out and the casing re-log with a bond log then a cement plug re-set in the casing. With experience gained in AWCA, Companies become more and more bolder and accept the performance of the AWCA without further annulus verification. A Qualification matrix, also called Verification Matrix (VM) is used instead to justify avoiding cement drill out – cement bond log and cement plug re-set in the casing.

One of the criteria of the VM is a ‘track record’ as per NORSOK, is a minimum of three successful AWCA jobs. The definition of "successful" means verification of the annulus cement by drilling out (cement) followed by a bond log. Ref. NORSOK D10-2021 EAC Table 61.

The following AWCA jobs with similar parameters as the track record jobs (casing/lithology/fluid etc) are verified without drill-out and bond logging, i.e non destructive verification, claiming that the track record guarantees the AWCA will be satisfactory.

Other Companies do not establish track record at all, instead they use the VM as the only verification means.

The VM matrix is non other than a table comparing the job design & operational parameters vs the actual data.

The paper discusses possible short comings with the use of VM alone to justify avoiding drilling out and logging the annular cement to verify it's integrity.

Recent events have shown cases where Sustained Casing Pressure (SCP) develop several years after the AWCA job.

Also, several cases are known where the AWCA job performance were given the thumbs up passing the VM with flying colours, however when the cement was drilled out and a cement bond log ran, it shows evidence the annulus void of cement or poor cement bond.

The reluctance to do destructive verification is understood as it seems to be such a time waste. Not only do you need to drill the plug you just set, you also will need to run a scraper and wait a minimum of 48 hrs before logging the cement in the annulus. Once all done, you will need to reset the cement plug in the casing then wait for cement to harden to verify the cement barrier by tagging and pressure testing.

An alternative verification process is proposed to verify the annulus barrier as a proper barrier.
Hyperbaric Welding and Wire Arc Additive Manufacturing for Downhole Applications in the Oil and Gas Industry
Authors: Leon Escobar Sharen Monserrat , Walzl Alexander , Ravi Krishna , Prohaska Michael , Stockinger Martin , Richardson Ian Malcolm , Fateh Nazanin , Hönig Stefan
Published: October 2023

A large and increasing number of wells must be abandoned or repurposed in the next decades. Additionally, there are many wells to be re-entered and repaired due to problems and conditions such as casing leaks, corrosion, annular communication, patch placement, zonal isolation, closing perforations, etc.; therefore, the development of more efficient and cost-effective methods to address these issues is paramount. The main objective of this research includes the proof of concept (POC) of a Wire Arc Additive Manufacturing (WAAM) process under hyperbaric conditions for downhole applications in the Oil and Gas (O&G) industry. This POC will enable the development of a potential downhole WAAM technology that could place corrosion-resistant steel barriers as well as closing holes in the wellbore. Well plugging and abandonment (P&A), and well integrity re-establishment operations are costly and often associated with a low probability of long-term success. Available conventional technologies and techniques mostly use cement as a plugging material. However, steel has several advantages over cement, such as a higher tensile strength, enabling stronger structures with less material; cement is a brittle material while steel is ductile, steel can also resist higher thermal loads. Additionally, steels can be engineered to withstand harsh environments and resist corrosion. Corresponding lab-scale experiments, simulated in an autoclave solely constructed for the proof of concept of hyperbaric WAAM, are carried out to investigate the fundamentals of this process and material properties for downhole applications. The general project description, laboratory set up and design, including process requirements such as voltage, current, shielding gases, and material properties, are presented. With this proof of concept, an alternative technology will be enabled with the potential to revolutionize wellbore P&A. Once this POC has been proven, the deployment method will be assessed. It is foreseen that some of the benefits of developing such tool will be the introduction of rigless or with smaller workover units P&A operations. Additionally, an entirely new way of applying additive manufacturing is proposed to solve compelling challenges in the O&G industry.