bluuebunny/crossref_metadata_2025 huggingface dataset:
The Analysis Of Teaching Akidah Akhlak In Madrasah Ibtidaiyah Around Industrial Area
Authors: Kawakip Akhmad Nurul , Mustanil Mustanil , Nurdin Arbain , Hariyanto Bambang , Jinan Miftahul
Published: October 2023

This study aimed to analyze the process of teaching akidah akhlak in the primary level. It was conducted in grade VI, Madrasah Ibtidaiyah Negeri (MIN) 1 Pasuruan. The reason for selecting the research setting because: first, the school quality was considered good in Pasuruan; second, the school was located around industrial area, so it might influence the characteristics of the students; third, teachers keep updating the teaching model through continous evaluation. This study was inteded to: (1) explore the model of teaching akidah akhlak; (2) identify the problem of teaching akidah akhlak; (3) propose the solutions for overcoming the problem of teaching akidah akhlak. It was a qualitative study whose data were collected through observation, documentation, and interviews. They were analyzed by using interactive model of analysis by Miles, Huberman, and Saldana which covered data condensation, data display, and conclusion drawing (verification). This study found that the learning model of akidah akhlak applies blended learning model by YouTube, direct experiential learning, and exemplary methods. There encountered problems, such as abstract learning materials, that teachers were required to use varied methods and need for support from the environment around. To overcome the existing problems, this study suggests that materials put more emphasis on the daily experience of students, teachers attend seminars on media creation, the application of varied teaching methods, strategies, techniques, and evaluation.
Field Wide Intervention-Less Reservoir Pressure Data Acquisition through the Application of Echometer – A Case Study
Authors: Basri Abdul Hakim , M Noordin Fuad , Zainul Zaimi , Hassan Faidzal Haslah , Chin Alvin Zhi Siang , Ho Dylan Zhe Xin , Haslan M Hanif
Published: October 2023

This paper aims to present a field-wide case study that explores the use of Echometer survey as an alternative method for acquiring static reservoir pressure data. In Field X, located in the East Malaysia Region, conventional static gradient surveys (SGS) were typically deployed to measure the static reservoir pressure. However, conducting SGS in Field X posed challenges related to balancing data acquisition with production enhancement activities, limited operation windows availability, and minimizing production deferment. The Echometer application addresses these challenges by offering non-invasive data acquisition with minimal equipment requirements.

The Echometer application employs a non-invasive approach by shooting acoustic waves into the well. As these waves travel downward and encounter any abrupt changes in the well, some of the waves are reflected towards the surface. By analyzing these reflections, which indicate disturbances to the acoustic waves, the fluid level inside the tubing can be determined. By combining this information with shut-in tubing head pressure (SITHP) and fluid gradient measurements, the static reservoir pressure can be estimated. In Field X, 17 surveys targeting 14 different reservoirs were conducted using the Echometer, and the results were compared with available permanent downhole gauge (PDG) data, reservoir pressure trends, and the latest SGS conducted to assess the reliability of the application.

The Echometer campaign has demonstrated its effectiveness and reliability in determining static reservoir pressure. It can be considered as an alternative to SGS in fields with limited wireline windows due to its minimal equipment requirements, minimal production deferment, and absence of invasive well intervention.

A presentation and discussion on the successful outcomes, limitations, best practices, and lessons learned from the Echometer campaign aim to contribute to the repertoire of production surveillance tools in the oil and gas industry by providing alternatives to conventional SGS for data acquisition.
Carbon Tax Regulation for Oil and Gas Industries: Impact and Macroeconomic Effect in Indonesia
Authors: Beryll Trisha Amanda , Inda Alya Putri , Mahendra Andika Rama , Mujahidin Imam Akbar , Ramdhani Muhammad Erzan , Dzahabi Muhammad Fikri
Published: October 2023

The urgency of mitigating the effects of climate change has now become a global agenda, influencing policy implementation in a variety of countries, including Indonesia. Carbon tax or carbon tax is one of the economic types of evidence to support the reduction of carbon emissions in Indonesia. A carbon tax is a policy that taxes carbon-generating activities to reduce greenhouse gas emissions. Because the oil and gas industry are a major contributor to greenhouse gas emissions, it is the primary target of carbon tax policies. The purpose of this research is to assess the impact and macroeconomic effects of carbon tax policies on the Indonesian oil and gas industry. To assess the overall impact of a carbon tax, this study employs a qualitative approach combined with two research techniques. In the oil and gas industry. The findings show that carbon tax policies can significantly reduce greenhouse gas emissions from Indonesia’s oil and gas industry, but they also have a negative impact on the industry’s profitability and investment. For optimal results, a mature strategy is required.
The Success Story of the First Application of High Performance Water Base Mud (HPWBM) in Corridor Block: Case Study in Suban Field
Authors: Permana Budi R , Widyaningsih Ratih , Hamid Fadia , Isa Boga
Published: October 2023

The Suban field’s gas reservoir, located at approximately 2000 mTVDSS, is composed of Pre-Tertiary rocks including Igneous and Metasediments, as well as Tertiary sedimentary rocks like LTAF (Lower Talang Akar Formation) and BRF (Baturaja Formation). Before accessing the gas reservoir, drilling activities must navigate through overburden formations, predominantly shale-based Palembang and Telisa Formations. A particular challenge encountered within the Telisa Formation is the presence of overpressure conditions.

Historically, drilling through overpressure-prone formations has posed formidable obstacles. Earlier approaches employed water-based mud (WBM) for drilling, which encountered issues such as shale instability and slow rate of penetration (ROP), necessitating the use of multiple drilling bits.

In 2012, a shift was made to Synthetic Oil-Based Mud (SOBM) to address these challenges and enhance hole stability. The outcome was not only improved hole stability but also a noteworthy surge in the rate of penetration (ROP). Consequently, SOBM applications have been employed for drilling gas-fractured reservoirs in the Suban and Sumpal regions since 2012. However, the adoption of synthetic oil-based mud (SOBM) presented its challenges, including significantly higher costs compared to water-based mud (WBM) and challenges in handling and disposing of non-environmentally friendly drilling waste associated with SOBM.

Recent developments have introduced High-Performance Water-Based Mud (HPWBM) as an alternative to Synthetic Oil-Based Mud (SOBM) for drilling. While HPWBM is not a complete replacement for SOBM, it aims to match its performance in terms of shale inhibition, wellbore stability, and rate of penetration (ROP). Additionally, HPWBM offers the potential for cost reduction and improved drilling performance.

To incorporate HPWBM into the Suban field, a meticulous technical review and analysis were conducted to align the formulation with the reservoir’s mineralogy. The implementation was initially carried out in a specific Suban well, focusing on the 12.25" hole section due to overpressure.

Key goals in designing the HPWBM included achieving superior shale inhibition, countering clay swelling and dispersion, and maintaining stability at high application temperatures. This alignment was particularly critical in the 12.25" section to minimize standpipe pressure (SPP) and Equivalent Circulating Density (ECD) and avoid formation fractures. A comprehensive laboratory testing process led to the development of 134 HPWBM formulations, with Formula 134 emerging as the optimal choice to fulfill the required objectives.

The successful implementation of HPWBM, specifically formula 134, in the Telisa Formation marked its efficacy in delivering performance on par with SOBM. This achievement not only demonstrated cost-efficiency but also streamlined and effective drilling operations.
Uncovering the Actual Safety Integrity Level (SIL) of Critical Safeguards in Aging Hydrocarbon Facilities as the Basis for the Development of a Performance-Based Maintenance Strategy of Critical Safeguards; Lessons Learned from Rokan Block
Authors: Safrudin Safrudin , Yudhy Muhammad Riandhy Anindika , Joelianto Endra
Published: October 2023

Equipment aging is one of the main challenges faced by companies operating oil and gas processing facilities with a brownfield engineering approach. As equipment ages, it breaks down more quickly, making it more susceptible to failure. The consequences of equipment failure can be disastrous, especially if the equipment is listed as a critical safeguard that protects the system from hazardous conditions. Failure of critical safeguards will increase the likelihood of hazardous scenarios occurring and thus impact the overall risk ranking of operating the facility. As a risk management effort, it is important to validate the safety integrity level (SIL) of the critical safeguards currently installed at the facilities and design an appropriate maintenance strategy to maintain the SIL value as originally designed. However, given the vast amount of equipment that is scattered over a large area, this is a very challenging effort.

This paper discusses a novel attempt to validate the actual critical safeguards SIL in brownfield facilities by conducting a hybrid of an extensive reliability-centered maintenance study and a regression-based machine learning model to obtain the actual equipment failure rates based on incomplete historical failure data stored at the Computerized Maintenance Management System (CMMS). A recalculation of the current SIL level and comparing the results with the original SIL design will provide information on the level of degradation that occurred and the appropriate solution.

To illustrate the application of the technique, a case study is presented based on the experience in implementing the life cycle of a safety instrumented system (SIS) according to the IEC 61508/61511 guidance as a maintenance strategy to maintain the SIL of a critical safeguard. Through these efforts, critical safeguard SILs are maintained on designed SILs and are capable of achieving credit risk reduction aimed at hazardous scenarios while setting the database for further improvement in the adoption of digital technology.
Dynamic Fracture Characterization Using Multiphase Rate Transient Analysis of Flowback and Production Data
Authors: Zhang Zhengxin , Sun Guoqing , Zhou Xingze , Dang Kaiyan , Su Xing
Published: October 2023

This study presented a comprehensive method for characterizing reservoir properties and hydraulic fracture (HF) closure dynamics using the Rate Transient Analysis (RTA) of flowback and production data.

The proposed method includes straight-line analysis (SLA), type-curve analysis (TCA), and model history matching (MHM), which are developed for scenarios of two-phase flow in fracture, stimulated reservoir volume (SRV), and NSRV domains. HF closure dynamics are characterized by two key parameters: pressure-dependent permeability and porosity controlled by fracture permeability-modulus and compressibility. The above techniques are combined into a generalized workflow to iteratively estimate the five parameters (four optional parameters and one fixed parameter) by reconciling data in different domains of time (single-phase water flow, two-phase flow, and hydrocarbon-dominated flow), analysis methods (SLA, TCA, MHM), and phases (water and hydrocarbon phase).

We used flowback and production data from a shale gas well in the US to verify the practicability of the method. The analysis results of the field cases confirm the good performance of the newly developed comprehensive method and verify the accuracy in estimating the static fracture properties (initial fracture pore volume and permeability) and the HF dynamic parameters using the proposed generalized workflow. The accurate prediction of the decreasing fracture permeability and porosity, fracture permeability-modulus, and compressibility demonstrates the applicability of the workflow in quantifying HF dynamics. The field application results suggest a reduction of the fracture pore volume by 30%, and a reduction of the fracture permeability by 98% for shale gas well.

Instead of a single analysis method for RTA, this paper proposed a comprehensive analysis method that includes SLA, TCA, and MHM. The interpretation results of the three analysis methods are mutually constrained, which can reduce the non-uniqueness problem of inversion. Compared with the others fracture characterization workflow that need fixed input and output parameters. This proposes general workflow not only completely characterizes the fracture closure dynamics but also can select the unknown parameters (to be determined) according to the actual scenarios of a well and the demands of reservoir engineers.
Generation of Chloralkali and Hydrogen from Produced Water
Authors: Omporkas Terath Kumar , M Basri Ana Hasrinatullina , B Md Noor Mohd Hisham
Published: October 2023

To flawlessly orchestrate various contaminants in any hydrocarbon production wells is an important art and at times determine business profitability margin. As introduction, contaminants can be classified into two main categories namely: soluble contaminants and insoluble contaminants. The constituents of soluble contaminants include acid gases, mercury, and organo-metallic compounds. On the other hand, insoluble contaminants are substances that do not dissolve in hydrocarbon. Examples of such contaminants include salt, emulsion, and moisture. These contaminants can cause operational difficulties such as corrosion, scaling, and reduced efficiency in production facilities hence the management of these contaminants normally requires the implementation of separation and treatment processes which later would increase the operation expenses.

It is worth emphasizing that although these contaminants are considered undesirable in hydrocarbon production process, they hold promising potential as valuable resources for other industries. A prime example is type of salt present which can be utilized as a viable input for chloralkali generation. chloralkali production encompasses the electrolysis of salt (sodium chloride) to yield sodium hypochlorite and hydrogen.

Commercialization plays a significant and intriguing role in the utilization of these contaminants. By identifying and developing business framework for the contaminants, it is really worth to consider industry partners which can turn what would otherwise be waste or disposal burdens into valuable resources. This commercialization process involves establishing common interest partnerships with other industries that can benefit from these contaminants, ensuring proper treatment and processing to meet quality standards, and creating a supply chain for the contaminants to reach their respective markets and perhaps beyond compliance to local authorities’ laws and regulation.

Before advancing to the circular economy phase, it is essential to prioritize the establishment of a sustainable foundation within the existing linear economy ecosystem. This is crucial to ensure a consistent and sustainable supply of resources for circular economy endeavors.
Machine Learning Sweet Spot Identification and Performance Validation Utilising Reservoir and Completion Data from Unconventional Reservoir in British Columbia, Canada
Authors: Leem Junghun , Musa Ikhwanul Hafizi , Mazeli Abd Hakim , Che Yusoff M Fakharuddin , Jowett David , Redpath Darcy , Saltman Peter
Published: October 2023

Production in an unconventional reservoir varies widely depending on reservoir characteristics (e.g., thickness, permeability, brittleness, natural fracturing), and completion design (e.g., well spacing, frac spacing, proppant volume). A comprehensive method of data analytics and predictive Machine Learning (ML) modeling was developed and deployed in the Montney unconventional siltstone gas reservoir, British Columbia, Canada to identify production zone "sweet spots" from reservoir quality data (i.e., geological, geophysical, and geomechanical) data and completion quality data (e.g., frac spacing, fluid volume, and proppant intensity), which were utilized to enhance and optimize production performance of this unconventional reservoir.

Typical data analytics and predictive ML modeling utilizes all the reservoir quality data and completion quality data together. The completion quality data tends to dominate over the reservoir quality data, because of a higher statistical correlation (i.e., weight) of the completion data to observed production. Hence, resulting predictive ML models commonly underestimate the effects of the reservoir quality on production, and exaggerate the influence of the completion quality data. To overcome these shortcomings, the reservoir quality data and the completion quality data are separated and normalized independently. The normalized reservoir and completion quality data are utilized to identify sweet spots and optimize completion design respectively, through predictive ML modelling.

This novel methodology of predictive ML modeling has identified sweet spots from key controlling reservoir quality data and as well as prescribed optimal completion designs from key controlling completion quality data. The trained predictive ML model was tested by a blind test (R2=79.0%) from 1-year of cumulative production from 6 Montney wells in the Town Pool, which was also validated by recent completions from 6 other Town Montney Pool wells (R2=78.7%).
The Evolution of Estimated Ultimate Recovery (EUR) Estimates Over the Project Life Cycle: Lessons Learnt from three Examples
Authors: Nah Wenbin , Adam Peter Alastair
Published: October 2023

Estimated Ultimate Recovery (EUR) of oil and gas projects is an important quantity to track over the project life to help understand and mitigate any deviations in project performance. In general, the range of uncertainty narrows over time as more data is available to constrain the estimates. However, this is not always the case. This paper presents three examples covering both gas and oil fields at different stages of their lives, which show how EUR and the corresponding range of EUR uncertainty varies over the life of each field.

The lesson from these examples is that the range of uncertainty tends to be too narrow, both in the appraisal phase, as well as in the production phase. EUR estimates may be too narrow in the appraisal phase due to the lack of available datapoints to constrain the volumetric based assumptions. In the production phase where forecasts are often based on simulation models, a limited number of geological realizations will naturally constrain the range of results from simulation, even when many realizations of lesser parameters are conducted.

In one of the examples, there was a sudden increase in the range of EUR, and the paper discusses the reasons for this, which are mostly attributed to additional data. The paper further notes the possibility of an anchoring bias underlying the results and provides multiple reasons on why EUR and Reserve estimates may be affected by this bias, such as continuity of the project team, as well as internal/external pressures.

It is thus important for technical personal, management, investors and lenders to keep an open mind, and not be pigeonholed into overly narrow ranges of uncertainty. Be brave to challenge the estimator to justify apparently narrow ranges of EUR uncertainty, as well as any suspected anchor bias in the ever-evolving EUR estimates.
Alkali-Polymer EOR Flooding in Europe: Part I - Surface: Water Softening Field Tests in Presence of Back-Produced Polymer
Authors: Marx Markus , Grillneder Roland , Lüftenegger Markus , Krenn Christof , Kornberger Martin , Hincapie Rafael Eduardo
Published: October 2023

Maximized depletion of mature oil reservoirs is gaining substantial importance. One of the last measures to be considered in the late life of a suitable brownfield is likely to be alkaline-polymer-EOR. OMV is currently carrying out alkaline polymer flood projects in Austria and Romania. Since AP flooding introduces significantly increased complexity, it is vital to take maximum advantage of available expertise and to not pass up any opportunity to generate additional field-based data whenever possible.

Field tests performed in the Matzen Field (Austria) were used to qualify an ion-exchange-based water softening process in saline produced water and in the presence of back-produced partially hydrolyzed polymer (HPAM). A stringent goal was set to reduce the divalent cation concentration in produced water to less than 5mg/l at the test location. Evaluations were thoroughly performed under a broad variety of operating conditions and water characteristics. A thorough analysis and evaluation was performed on the impacts of various concentrations of oil and polymer or altered viscosities, as well as modified operating conditions such as flux rates.

Observations describe different mechanisms related to water salinity and polymer-induced viscosity, as well as the way in which they affect the efficiency of the process. The WAC ion exchanger unit was optimized and adjusted to ensure compliance with the targeted divalent cation concentration in the presence of more than 400ppm of back-produced HPAM and more than 23 g/l of TDS content. Under these conditions, optimum operating conditions and risk mitigation measures were identified in order to achieve the best unit availability and service time between regeneration cycles. Last of all, an economic outlook was created in terms of expected chemical consumption for ion exchanger operation in the presence of back-produced polymer.

The outcomes of this field trial provided crucial insights into operational aspects, allowed significant risk reduction, and represented the basis for designing upscaled water softening systems which were implemented in alkaline polymer flood projects in OMV assets.
Top 8 Digital Safety Trends in Oil and Gas in 2023
Authors: Daher Elie
Published: October 2023

Top 8 digital safety trends in Oil and Gas in 2023

Oil and Gas is one of the most hazardous industries to work in. From exposure to toxic gases to working at dangerous temperatures, lone worker management to fall detection, there are a host of safety issues that are common to the industry. It is also an industry undergoing a revolutionary digital transformation. With changes, come challenges and new opportunities. This paper looks at the top digital safety trends that are taking place within the industry.

The top trends that will be investigated in this paper include: Real time safety solutions (RTLS): Real-time location services have re-defined personnel monitoring. From real time access control to personnel monitoring, geo-fencing to vehicle collision avoidance, real-time location tracking has a wide range of applications that can be used to make the industry safer.Remote monitoring: Remote monitoring technologies are one of the most adopted digital technologies used by Oil and Gas companies around the world. From a safety perspective, remote monitoring has changed the game for confined space monitoring. Gas monitors, breathing air apparatus can all now be monitored remotely reducing the number of onsite personnel required contributing to a safer and more efficient worksite.Connected worker solutions: Networked devices are transforming lone workers to connected workers. Through a comprehensive solution of apps, industrial IIoT infrastructure and connected devices, workers can now directly communicate and connect with the command center ensuring enhanced safety for lone workers.Smarter equipment: Equipment, devices and tools are also getting smarter. All traditional equipment can be ‘smarter’ by using data, AI and IIoT technology to work with each other to revolutionize their role in safety.AI solutions: AI is being increasingly used in Oil and Gas for a range of safety solutions. Computer Vision for example has a versatile range of applications that ensure safer workers. From PPE compliance to fall detection, Computer Vision and other AI technologies can be used to ensure safer Oil and Gas workers.Automation of hazardous and high-risk jobs: Robots and drones have been taking over high-risk jobs to keep workers safe.Training in the digital era: Better trained workers are safer workers. With the rapid rise in digital technologies, there are a growing number of digital and hybrid training and coaching sessions that are becoming more popular. AI is also being increasingly used in training to ensure a highly trained workforce.Digital twins: More organizations are investing in digital twins to detect, predict and even help prevent incidents from happening in the real world by better understanding their impacts in the digital world by gaining a clearer comprehension of their consequences in the digital sphere.
AI Innovations in Waterflood Management, The Path to Autonomous Operations
Authors: Khataniar Sanjoy Kumar , Biniwale Shripad Suhas , Elfeel Mohamed Ahmed , Tellez Camilo Ernesto
Published: October 2023

In the S-Field operations office, a daily battle ensues in the quest to increase production and maximize profits from waterflooding. One of the main control mechanisms applied to optimize the waterflooded reservoirs is by controlling the water injection and pumping rates of producers to balance patterns, maximize sweep, and maintain reservoir pressure. The reservoir surveillance team has been using a simple spreadsheet analytical approach that was quite limiting as the number of injection patterns increased, and the flood matured, leading to a water breakthrough. There was a need for a more sophisticated approach that could leverage artificial intelligence (AI) technology, especially since the entire asset was undergoing significant digitalization of its operations.

This paper presents various innovations in bringing real applications of AI for waterflood management. This includes innovations in business processes, application of design thinking methodology, agile development, and AI. The AI waterflood management solution combines cloud technologies, big data processing, data analytics, machine learning algorithms, robotics, sensors and monitoring system, automation, edge gateways, and augmented and virtual reality (AR/VR).

Design thinking principles and a human-centric approach within an agile innovation framework were utilized for rapid prototyping and deployment. A waterflood management framework that addressed the business's operational, tactical, and strategic aspects created the backdrop for designing the solution architecture. New injector-producer modeling techniques that leveraged AI and were fit-for-purpose for reservoir surveillance and production engineers were prototyped. An interactive pattern flood management tool, adapted from streamline simulation-based waterflood analysis methods, was developed for injection pattern analysis and intelligent optimization workflow.

Field pilot testing for over a year proved that the prototype could reliably detect injector-production interactions and recommend operating set points in relevant time. Reduced time to decision, improved analysis efficiency and reliability of short-term forecasts, reduced field visits and health-safety-environment (HSE) exposure, and finally ease-of-use has been experienced. The learnings from this project are being leveraged to develop a deployable solution and move the needle toward autonomous waterflood operations.
Improving Water Injection Pump (WIP) Reliability through Integrated Water System Evaluation in XYZ Field
Authors: Priambudi Aris , Machfud Adam Aliyya
Published: October 2023

XYZ Field in Central Sumatra is the largest waterflood operation in Southeast Asia. Water Injection Pump (WIP) is the critical equipment to enable this waterflood operation to maximize the oil production process. Based on WIP performance evaluation in Jan 2017 – Jun 2018, it was found that the average WIP reliability was 92.5% and average Loss Production Opportunity (LPO) was 268 BOPD. The contributing factors for this poor WIP performance were not only from the internal WIP unit but also from its external system.

Integrated Water System Evaluation was introduced to improve WIP performance to its desired level and to minimize LPO impact. From the internal system, the evaluation was started by analyzing the failure mode for each 78 WIP's, finding root causes, and developing mitigation plans to prevent failure from re-occurring in the future. It was found that there were 8 WIPs in low-efficiency condition and 7 WIPs operating outside the Best Efficiency Point (BEP). The evaluation was continued to the external system which consists of water injection line network and water injection well (WIW). It was found that the WIP discharge pressure was increasing from 700 PSIG up to 780 PSIG in all XYZ field areas. The main root causes were unbalanced water distribution and several WIW's being off due to various reasons.

Based on comprehensive analysis of the XYZ Field water system, it was recommended to perform the following actions to improve the WIP Performance: 1) Perform a proactive overhaul program for 8 WIPs with low-efficiency issues, 2) Adjust the Control Valve opening to ensure WIP operates within BEP, 3) Develop recommended discharge pressure setting range for each WIPs, 4) Re-POI (Put on Injection) inactive WIWs, 5) Perform fluid dispatching to balance water distribution in XYZ Field areas, such as transfer 100,000 Barrels Fluid Per Day (BFPD) from Area 4 to Area 6, transfer 55,000 BFPD from Area 5 to Area 4, and isolate interconnection between Area 1 and Area 3.

After implementation, there are some improvements as follows: 1) The range of WIP within BEP was increased from 37% to 62%, 2) WIP Reliability was increased from 89% (Jan 2017) to 96% (Jul 2018), 3) LPO due to WIP failure was decreased from 268 BOPD to 42 BOPD, 4) Average WIP discharge pressure was decreased from 780 PSIG to 700 PSIG. To sustain these improvements, the WIP performance monitoring flow process and tools have been developed. In recent years, when Company established aggressive programs to increase oil production, we experienced a similar condition that impacted WIP performance. But by having the sustained flow process and tools, we can manage the situation well and prevent major LPO and reliability incidents.
Well Design for Sustainable Field Development Plan Towards Achieving Net Zero Carbon Emission by 2050
Authors: Musa Muhammad Idham Adli , M Dan Iliyas , M Garib Nurul Iffah , M Safari Lai Harni Farihah
Published: October 2023

New field development operation and hydrocarbon production have been one of the main contributors to global carbon emission. With the introduction of carbon tax, the cost of developing new fields and hydrocarbon production is expected to increase significantly if no serious action is taken to address the carbon footprint from such activity, especially in the high Carbon Dioxide (CO2) field. This paper will share on the sustainable development concept undertaken by PETRONAS to address the future of Net Zero Carbon Emission (NZCE) by 2050 during field development planning of a high CO2 hydrocarbon reservoir and the approach in realizing the plan.

Surface facility is designed to filter all the CO2 in the hydrocarbon production at offshore CPP (Central Processing Platform) and re-inject it back into the formation via a dedicated gas injector well. The well placement is carefully analyzed to be located at area where the injected CO2 gas can enhance the hydrocarbon recovery by maintaining the reservoir gas cap pressure. CO2 gas also can be used as a source of gas for oil producer wells that require gas lift. PETRONAS had established a process flow during well detail engineering design to guide the project team that consists of Subsurface and Facilities to find the right balance in addressing the risk of CO2 related well integrity issues and project economics outcome. Part of the process flow involves the sensitivity analysis of reinjection gas specification downstream surface compressor at CPP impact towards well casing and tubing material selection, CO2 plume migration and estimating reservoir condition at the end of field life.

This established process flow managed to effectively guide the FDP (Field Development Plan) team to come out with the best cost-effective development concept that able to realize both company ambition of sustainable field development plan toward net zero carbon emission and projecting positive economic result.

This paper would provide more insight into the study and analysis to be considered during designing new wells in a field that integrate development wells producing hydrocarbon and Carbon Capture & Storage (CCS) CO2 wells with lesson learnt and best practices that are valuable for future project with similar scope.
Chemically Enhanced Carbon Dioxide Geosequestration Using Nanofluids
Authors: Jha Nilesh Kumar , Kitagawa Hirotake , Abe Masashi , Sonoda Takashi , Murakami Satoru , Farrokhrouz Mohsen , Keshavarz Alireza , Iglauer Stefan
Published: October 2023

Carbon dioxide (CO2) sequestration in the subsurface porous geological media is the most favored large-scale climate change mitigation technique to achieve a net-zero target. The efficiency of CO2 subsurface storage depends on its rock's wetting ability, which affects its flow efficiency and residual or structural trapping. Reported laboratory investigations have shown that nanoparticle formulations have great potential for altering the wettability to more water-wet conditions favoring CO2 trapping potential. However, the compatible nanoparticles tailored for CO2 sequestration under temperature, pressure, and salinity conditions have not been reported, as per our knowledge. Therefore, this article demonstrates how modified silica nanoparticles affect the rock's surface and help enhance CO2 trapping potential under storage conditions using wettability, IFT, and CT coreflooding experiments.

Several silica nanoparticles were fabricated for this purpose. The fabricated silica nanoparticles were modified, given the unfavorable formation brine salinity and ionic compositions affecting their stability. The resulting modified silica nanoparticles were diluted to 0.5 wt% with synthetic brine and observed for brine resistance at 50 °C for one month. They were further tested for wettability alteration of the organic acid-aged sandstone rock representative substrate in the presence of supercritical CO2 at 50 °C and 10 MPa by contact angle method. Furthermore, we evaluated their performance by computed tomography (CT) coreflooding experiments using Fontainebleau sandstone core plugs.

These nanoparticles altered the wettability of the organic acid-aged sandstone rock representative substrate sample from intermediate wet (advancing brine contact angle - 90-108°) to strongly water wet (advancing brine contact angle - 33-49°). Modified silica nanoparticles also show high brine resistance. Therefore, up to 24.2% reductions in IFTs were observed using nanoparticles. Moreover, CT coreflooding test results shows good performance of novel nanofluids treatment on CO2 trapping potential through evaluation of initial and residual trapping. Therefore, up to 80.6 % and 55.8 % increments were observed using nanoparticles in initial and residual scCO2 saturations, respectively.

We are reporting the use of novel modified silica nanoparticles for CO2 sequestration in sandstone formation for the first time, as per our knowledge. We expect these specialty nano-materials to enhance CO2 storage capacity through nanofluid injections as one of the emerging techniques for achieving net zero.
Casing Conductor Installation with Auger Drilling to Secure Uncompacted Surface Formation
Authors: Gibran Kemal , Ritamawan Radianto , Saragih Anggi Muhammad Sabri , Wicaksono Nuring Tyas , Malik Mahamy Abdul , Prestywa Ryan Hera , Khasbianto Fuji
Published: October 2023

There are two main hazards in surface hole section in Mutiara and Pamaguan fields, loss circulation and shallow gas. Blowout incident due to both hazards occurred in Pamaguan in 2012. While influx was moving, the conductor shoe was unable to withstand the differential pressure and cracked due to influx coming up through weak area around conductor shoe (broaching). Hence conductor must be set deeper to make sure the shoe is strong enough to withstand the pressure in case any occurrence of unscheduled events.

Independent Well Integrity Assessment Team (IWIAT) recommends minimum conductor depth is 250 ft. In Mutiara and Pamaguan Fields, conductor piling limited to 250 blow/ft can reach an average depth of 50 ft below ground level. It is either additional surface casing must be run or new method must be used. One of the methods that might potentially be used is auger drilling which has been used in construction industry to install conductor as a base foundation until 450 ft depth with max 59″ diameter. To implement this in field with loss circulation and shallow gas hazard (later known as dual hazards), modification of procedure is needed by adding sequences before auger drilling. Pilot slim hole drilling complete with diverter, kill mud and LCM were prepared to mitigate these dual hazards prior to enlarge the hole with auger.

Auger drilling with above mitigation is well proven and thus most reliable method to reach minimum 250 ft in depth. It is the safest method since pilot slim hole is drilled using mini diverter prior to enlarge hole with auger. Auger drilling method also eliminates surface loss circulation during rig operation in shallow and uncompacted formation, casing collapse due to driven to refusal in order to reach required depth, and other subsequent well NPT that might happen in surface section. Using auger drilling to install conductor can eliminate the needs to drill additional surface section and set additional surface casing by rig to strengthen the conductor section. Saving 1 section means 3 days faster on drilling operation which means cost reduction, eliminate operational risk in surface section, and opportunity to reach deeper TD. With this saving days, one additional well can be delivered in one-year operation in Mutiara and Pamaguan Field.
Economic Evaluation for Potential CCUS Integration Project Between Ammonia Plant and Oil Field Tertiary Recovery Using CO2 Injection in Indonesia
Authors: Raksawiguna Matahari Dewa , Wirananda Mohammad Farrel , Yasmin Kharisma Asri , Chandra Steven
Published: October 2023

Indonesia is committed to reducing global greenhouse gas emissions, especially in the industrial and energy sectors. One of the big opportunities is implementing carbon capture, utilization, and storage (CCUS) in Ammonia production as it has the lowest overall CCUS cost and geographically the existing ammonia plant is strategic to the potential oil field. This paper discusses the economic evaluation for the CCUS integration project between an ammonia plant and oil field tertiary recovery using CO2 injection, along with the sensitivity analysis of the economic variables. The selection process of a potential oil field that will be injected is based on the characteristic of its reservoir and its production performance. Furthermore, the distance between the oil field and the existing ammonia plant is also considered to minimize the transportation cost of CO2. The study of economic model contract for ammonia plant constructed by cashflow analysis. While for the Oilfield CO2 Injection project refers to Indonesia's existing oil and gas contract model, which is the Production Sharing Contract (PSC) cost recovery and gross split. In addition, several economic variables sensitivity was performed, such as oil price, oil production rate, capital expenditures, operation expenditures, and CO2 price.

Economic evaluation from ammonia plants and oil fields shows fairly good economic indicators. The economic parameter for the ammonia plant gives 13.54% of IRR, 661.95 MMUSD of NPV, and 6.19 years of pay-out time. On the oil field side, the PSC Cost Recovery scheme offers the contractor 18.82 % of IRR, 0.33 MMUSD of NPV, and 4.85 years of pay-out time. In comparison, the PSC Gross Split scheme offers 19.55% of IRR, 0.40 MMUSD of NPV, and 5.48 years of pay-out time. For this study, the result indicates PSC Gross Split scheme gives a better economic parameter than PSC Cost Recovery. The sensitivity analysis shows that oil prices and capital expenditure are very significant on economic parameters. Therefore, government policies are required to give contractors more attractive economic parameters. Based on the economic evaluation, implementing CCUS in the small field gives a fairly good result for economic parameters. Furthermore, this paper provides a comprehensive assessment based on an economic evaluation of the ammonia plant and oil field that could give additional information to the government as the policy maker to accelerate the implementation of CCUS integration, particularly in small fields in Indonesia.
Mini-ROV Utilization for Banyu Urip FSO Underwater Inspection and Maintenance
Authors: Jayatra Kharisma
Published: October 2023

The objective of this paper is to evaluate the use of a mini-ROV (Remotely Operated Vehicle) for conducting intermediate Underwater Inspection in Lieu of Dry-Docking (UWILD) surveys as well as various underwater inspection & maintenance works in the Floating Storage & Offloading (FSO) Gagak Rimang (turret-moored FSO) operated by ExxonMobil Cepu Limited (EMCL).

UWILD is divided into Intermediate Survey & Special Survey which differs in scope. Intermediate UWILD Survey consists of General Visual Inspection, Cathodic Protection (CP) readings on offshore vessel's hull, weld inspections, and marine growth assessments. Meanwhile, Special Survey includes all the Intermediate Survey scope with additional sea-valves internal & external examination and operational test. Typically, the UWILD inspection utilizes conventional method by using divers and/or work-class ROV which require dive support vessel. With two underwater campaigns every five year – it is considered an operational challenge for offshore vessel to optimize cost since in many countries the drydock / UWILD requirements are tied with government regulation.

EMCL demonstrate initiative of mini-ROV utilization for Intermediate UWILD Survey on FSO vessel, namely Gagak Rimang. The mini-ROV was trialed as it has the capability to perform comprehensive inspection as well as cleaning with minimum cost.

The use of the mini-ROV was successful in completing the intermediate UWILD survey pioneered in 2022. The ROV was able to access and inspect areas that would have been challenging or implausible for divers to reach, such as the underside of the platforms and tight spaces between structures. In addition, the use of the ROV eliminated the need for divers to enter the water, improving safety and reducing the cost and logistical challenges of diver-based surveys.

Compared with conventional methods, the utilization of mini-ROV has provided significant cost saving until the end of facility life. The first mini-ROV implementation in EMCL has demonstrated that its use is a feasible and effective alternative to conventional method for intermediate inspections of offshore vessels. Mini-ROV also provides one-stop solution by allowing mount-ability of certain attachment tools to enable cleaning & measurement works. The use of mini-ROVs can improve safety and reduce cost and logistical challenges, making them a valuable tool for the maintenance and integrity management of offshore assets.
Success Story of Pressure Network Optimization Application on Multi-Problem Surface and Subsurface Facilities Ardjuna Field
Authors: Setiawan Muchamad Agus , Saputra Diarista Toma , Abdul Goni Mochamad Jalal , Yusup Irvan Sopandi , Arifin Muhamad , Arifin Wirdan
Published: October 2023

Gas lift consumption and pressure need to be controlled so that oil and gas production in a well can be optimum. The 2020 FGS result shows tubing leaks in the MB-2 wells. Therefore, the gas lift injection cannot be optimum. Also, the MB-2 Production Separator is experiencing corrosion, and the operating pressure is only 74 psig. Oil wells in MB-2 Onshore will be optimum between 2,880 – 3,000 BFPD with gas lift pressure of 430 – 470 psig. However, when the pressure rises to 490 psig, production will drop to 2,640 BFPD, and when gas pressure drops to 400 psig, the oil production will only 2,568 BFPD. The operating pressure limit in the Production separator makes the Main Gas Line (MGL) operate below at 72 psig

The FGS results show that tubing leak/tubing communication conditions in the MB-2 well, the optimum injection gas lift is 4 MMSCFD with a pressure of 430 – 470 psig for all MB-2 wells. Currently, the MB-2 wells only installed Merla valves, making it difficult to maintain the stability of gas injection. Pressure networking optimization in the upstream part of the well is carried out by installing PCV on the MB-2 incoming gas lift. By applying Nodal Analysis simulation result, we get the data MB-2 production in November 2021 increase after PCV installation. The second pressure networking optimization uses Network Modelling Software simulation to determine the optimum pressure along the Main Gas Line (MGL) from the well to the compressor. MMF Turbine Gas Compressor speed increased from 93% to 96%, so the Main Gas Line (MGL) from the well to the compressor operates below 50 psig. This operating mode results in the low FTP (Flow tubing pressure) of each well and no back pressure on the MM wells. Moreover, the Production Separator's operating pressure can be kept below 72 Psig.

The pressure networking optimization by installing PCV at upstream MB-2 wells is proven to keep gas lift injection into each well stable in terms of flow rate and pressure. Furthermore, keeping the Main Gas Line (MGL) pressure below 72 psig can prevent the backpressure to the well and the operating pressure limit of the Production Separator is not exceeded. Pressure networking optimization can save gas lift consumption by 2 MMSCFD and increase production of MM oil and gas wells by 10% (27 billion rupiah per year). Stable injection gas lift & low Main Gas Line (MGL) pressure can increase the production of the MM well and achieve the annual production target.