bluuebunny/crossref_metadata_2025 huggingface dataset:
A Method for Detecting and Solving Auto Driller Instability: A Real-Time Control System Solution
Authors: Chatar Crispin , Pastusek Paul , Converset Julien , Wicks Nathan , Payette Gregory. S. , Quarles Tyler , Barajas Pablo
Published: November 2024

Multiple tool failures on projects across the globe led a multidomain team to collaborate with an operator to explore unconventional sources for causes and solutions. This is the narrative of the development, implementation, validation, and deployment of a novel solution to reduce auto driller instability. These systems are prone to "hidden" instability where large variations in parameters such as penetration rate, WOB, differential pressure, torque, and rotary speed are observed. The main roles of an auto driller are to control drilling parameters, reduce operational variations, and optimize drilling. System instability reduces drilling performance and the lifespan of surface and downhole tools. Service company and operator subject matter experts worked together to develop a method to detect instability. The resulting algorithm is used to monitor all the parameters affected by the auto driller system. Data from multiple sources, such as surface, downhole, and control system settings are aggregated and passed to a software plugin that enables system dysfunction to be identified. The user is presented with a wide range of alarms, flags, and key performance indicators (KPIs).

Multiple wells were monitored in real time using this algorithm. Potential dysfunction flags were passed to the operator's and service company's real-time operations centers (ROCs) to validate the output before suggestions were sent to the rig. This workflow identified multiple cases of instability and system shutdowns that went unnoticed for several minutes on the rig. In some cases, as much as 10% of drilling time per stand could be recovered from the system inefficiency. The deployment results were reviewed by a team of domain experts to validate the events that were caught and those that were missed, and then the algorithms were improved iteratively.

The system worked well with a fit-for-purpose real-time monitoring workflow producing near perfect results. Because it would be distracting to send the raw signals directly to the drillers at this point, more work needs to be done to make the interface available to the drill teams directly at the wellsite. It was found that reducing peak stress on components contributed to fewer downhole failures. The first trials were too short to quantify the effect on rig equipment life but reducing the peak torque on the top drive and motor current on the drawworks should lead to reduced failure rates for these tools. This information can also be sent to the rig contractor to quantify the value of upgraded control systems.
Advanced Electric Submersible Pump Technology Implementation in the Challenging Waterflood Field of Indonesia's Largest Oil Block
Authors: Alkahfi Sayid Habibi , Tejotriarso Satrio Hadi , Indhiarto P. Andri , Yulianto Bangun , Khairi Raihan Naufal , Allo Sakti Andi Lolo , Pasaribu Rinaldi , Anggaraini Hanny , Abadi Faiz Alfarisi
Published: November 2024

The primary objective of this paper is to evaluate the impact of advanced Electrical Submersible Pump (ESP) technologies on improving well performance in the BS Field, one of the most challenging operational environments in Indonesia's largest oil block. Specifically, the study aims to address the persistent issues of low permeability, poor sand connectivity, low reservoir pressure and high gas interference that have historically contributed to high failure rates and diminished oil recovery. Through the deployment of innovative ESP solutions tailored to these conditions, the research seeks to significantly enhance the operational efficiency and economic viability of the oil extraction processes.

Our study employed a comprehensive approach to assess the efficacy of advanced ESP technologies in the BS Field. Initially, a detailed field analysis was conducted to identify specific operational challenges. Subsequently, we implemented three distinct ESP technologies: modern low-rate ESPs, wide-range ESPs, and slim ESPs with motor shrouds, tailored to meet the unique needs of the field. The performance of these technologies was monitored through continuous data collection, including well test, sonolog, amp chart readings, and sensor outputs for pressure and temperature. This data was analyzed to evaluate improvements in operational efficiency and reliability, correlating technology deployment with changes in oil and fluid production rates

The implementation of advanced ESP technologies in the BS Field yielded significant improvements in well performance and operational efficiency. The deployment of modern low-rate ESPs extended the average run life of wells from 103 to 306 days, significantly reducing downtime and operational costs. Wide-range pumps demonstrated their efficacy in managing reservoir variability without the need for frequent resizing, thereby maintaining stable production rates and minimizing oil production losses. The slim ESP setups, equipped with motor shrouds and positioned below perforations, led to a notable increase in oil and fluid rates, achieving up to a 212% increase in oil production and increase more than 100% of fluid above pump (submergence fluid level). These setups also stabilized gas handling and maintained optimal motor temperatures, effectively mitigating risks such as gas locking and motor overheating. Our study concludes that these advanced ESP technologies are crucial for overcoming the unique challenges of high gas interference and poor sand connectivity in waterflood fields, offering significant operational and economic benefits to the oil extraction industry
Flare Recovery Successful Case Study
Authors: Gaber Mohamed Kamal
Published: November 2024

A stream of 2 up to 4 Million Standard Cubic Feet Per Day (MMSCFD) sweet gas used to be burnt and flared on site as a waste of energy causing more than 27,000 pounds per hour (lb/hr.) of CO2 emissions and wasting a power of 5.5 Mega Watt (MW), on the other hand site compressors and generators required a source of power, accordingly a new flared gas recovery skid with a capacity of 4 MMSCFD is installed on site for providing power to Compressors and Gas Generators, cutting the CO2 emissions, put an end to the bleeding running cost of flaring. Skid is designed to recover a flared sweet gas stream of approximately 73 % Molar fraction of Methane (C1) and 12 % Molar fraction of Ethane (C2), approximately 0.5 % of Pentane (C5) and 0.13 of Hexane plus (C6+). The maximum allowable acceptable water content for conditioned gas is 70 pound per Million Standard Cubic Feet Per Day (lb/MMSCFD). A maximum consumed power of 130 Kilo Watt (KW) as a total duty. The maximum allowable acceptable of CO2 downstream from the unit is 3.8 % Molar fraction. Gas Lower heating value should not be lower than 1,000 British Thermal Unit per Cubic Feet (BTU/FT3) The main process components of the skid are summarized as: gas filtration, gas metering (totalizer), gas heaters, gas reduction., outlet scrubbers, controlling and instrumentations and piping and accessories. Recovering a flared gas up to 4 MMSCFD, cutting total running cost of approximately 1.1 Million United States American Dollars (MMUSD)/year, saving the required power of approximately 10.6 MW for the site facilities and also reduce the environmental harm impacts of flared gas cutting the CO2 emissions of 27,141.34 lb/hr. As 60% of electric power is produced of natural gas, capturing flared gas could cover 5% of Egypt's energy needs and add 300 MMUSD to national economy the introduced solution of flared gas recovery skid is able to recover a flared gas up to 4 MMSCFD against an estimated cost of 1.1 MMUSD as a fixed cost and existing asset on site to put an end to the bleeding running cost of 1.1 MMUSD / year for power generation in addition to the cost of gas flaring. Moreover producing and saving total electrical power of approximately 10.6 MW for the existing sire facilities in addition to reduce the environmental harm impacts of flared gas through cutting the CO2 emissions of more than 27,000 lb/hr. matching with the Climate Change Conference that took place in Sharm El-Sheikh, Egypt (COP 27) and also Climate Change Conference (COP 28) that took place in United Arab Emirates.
Deploying Efficient and Lean Maintenance Model by Optimization and Standardization of Companywide Maintenance Job Plans and Resources Adopting a Centralized and Unified Approach
Authors: Rajpurohit Surendra S. , Adwan Mohamed Zaky , El Sayed Gamal Wael , Al Rashedi Mohamed Ali , Iyer Rajesh Sivaraman , Pramanik Mrinmoy Kumar , Al Mazrouei Khamis Humaid , Mohammed Abdalla Osama Omar , Ramachandran Ajay , Anilkumar Ravishankar , Al Zahmi Abdulazeiz Mohamed Rashed , Al Shehhi Talal Mohammed , Vadakkengara Abdul Gafoor , Patel Priteshkumar Amrutbhai , Ali Safdar , Beg Furqan Husain , Al Katheeri Mohamed Abdulla , Al Ali Ali Humaid
Published: November 2024

As part of our continuous efforts to foster uniformity, efficiency, compliance to best practices and standardization, a new systematic initiative was taken to standardize and optimize the maintenance job plans and resources (logistics and manpower) for three maintenance disciplines (Mechanical, Electrical & Instrument) across company sites to ensure optimal number of personnel required for a defined set of maintenance activities. We conducted an initial review and analysis of the maintenance plans across company sites and found discrepancies and different practices implemented. Potential opportunities were also identified which could be utilized to obtain lean and standardized maintenance programs across company sites. Thus, SMEs from different disciplines conducted deep dive reviews and brainstorming sessions to reach an optimal maintenance program that can be implemented without compromising HSE and asset integrity. It was also observed that there was no systematic and standardized practice being followed to quantify the required maintenance resources (manpower and logistics) and to validate the forecasted manpower for business plan. The outcome of maintenance job plan standardization exercise was later applied to validate the manpower requirement (existing as well as 5 / 10-Year business plan) and thus achieving significant optimization.
Evaluating and Enhancing Rig Controls Automation Through Digital Transformation Efforts
Authors: Auld S. , Wood A. , Whitlow Z. , Hopwood F. , Kern S.
Published: November 2024

Rig controls are essential for digital transformation, serving as an automation tool to execute complicated repetitive processes with precision and accuracy. Process execution and consistency are typically measured by time, while drilling processes use constant set points often incorporating system feedback. Evaluating the effectiveness of these processes, which depend on system feedback, goes beyond time metrics, and requires further digital transformation efforts for proper support and assessment of success.

Automation of rig controls has advanced to a point where an entire drilling stand can be drilled without driller intervention, utilizing predetermined system set points. The next stage of evolution involves optimizing these processes automatically and iteratively. To assess complex automated processes effectively, new digital tools are necessary to enhance scalability of the technology across a large fleet of rigs, enabling real-time interpretation of results. Consequently, a new digital system has been developed to better support rig control automation, enhancing scalability in the digital transformation process.

Drilling departments often focus on lagging indicators such as rate of penetration or well cycle times, overlooking critical leading indicators embedded within the design criteria for control performance. Rig control automations are designed with distinct objectives and performance criteria to measure and interpret.

For instance, an autodriller and stick-slip mitigation controller are typically associated with metrics such as rate of penetration (ROP) and potential bit damage during operations. To effectively assess autodriller performance, it is crucial to understand the system's priorities and analyze time data comparing control commands and responses. The stick-slip mitigation controller benefits from frequency domain data on torque disturbances at surface to properly evaluate performance.

Similarly, a process controller managing weight-on-bit requires time domain analysis similar to the autodriller, but these events are intermittent. This necessitates an event-based data model for mining performance data, including detailed substate analysis within each event. As automation evolves within digital transformation, sophisticated analysis tools are essential for evaluating performance of automated processes.

The drilling rig generates extensive data, much of which exceeds typical requirements for control analysis. However, due to the sheer volume, not all data can be transmitted back to a central data center. Therefore, the control design aims to provide the driller with as many indicators on location as feasible.
Delivering Record-Breaking Gross Footage with Single Slim Bottomhole Assembly
Authors: Fish R. , Saaidi A. A. , Greenwell N. , Kasimin A. , Muqarshi M. A. , Samir E. , Ali A. , Popov T.
Published: November 2024

A new field record for drilling the longest footage with a single bottomhole assembly (BHA) in a slim hole was recently achieved in the Safah field in northern Oman. A multidisciplinary team focused on digital advancements and process enhancements to improve the drilling efficiency and sustainability of the different aspects in the Safah development well construction process. The process considered the introduction of a remote operation structure comprised of directional drillers, geosteerers, and measurement engineers working together through an enhanced communication channel to improve and expedite decision making. Employing a remote operation model also helped to reduce the rigsite crew size, lower the HSE exposure in the rigsite, and enable faster deployment of new technologies. Lean geosteering processes were recommended to reduce off-bottom time and improve the penetration rate. Detailed shock and vibration analyses were conducted, exploring innovative designs and components for mitigation. An updated downhole software with a new downlink command was employed for the first time in the field, minimizing the number of downlinks and performing the downlinks on bottom for improved overall drilling efficiency and reduced the downhole vibration.

This case study highlights the technology innovation, engineering solutions, sustainable remote operation structure, and the valuable learnings that led to this record-breaking achievement.
The Smooth Transition: Cutting-Edge Drag Reduction for Decarbonization
Authors: Aslam Muhammad , Haider Farooq , Balooshi Eisa Al , Ketbi Abdulla Al , Alshehhi Khulood , Amir Muhammad Kashif , Ahmed S. , Ahmed MS.
Published: November 2024

Significant energy is consumed for the transportation and pumping of crude oil from processing facilities to terminals through long distance piping networks. This paper emphasizes on the technologies advancements and strategic initiative of drag reducing agents deployment at ADNOC Onshore asset that reduced the frictional losses of the network and thus saved more than 1.4 MM USD in terms of power tariff, enhanced facility availability and abatement of more than 16000 M ton CO2 / Year.

Major energy consumer in Oil and Gas facilities is export pumping system, where stabilized crude oil is pumped to shipping terminals. High energy consumption in the export pipeline system is caused by significant pressure losses due to turbulent flows caused by the trajectory and long length of network.

Suitable selection is very essential, to ensure the energy efficiency and compatibility of the chemical. Therefore, very stringent evaluation criteria DRAs adopted includes. Compatibility with the piping material to avoid any potential chemical reaction, thus integrity of network.Effectiveness in reducing the drag and improvement in pressure drop.Stability of the DRA under the extreme operating conditions.Operability concerns.Cost-effectiveness and rate of return.

Environmental and safety considerations, such as the toxicity and biodegradability of the DRA.

For the better understanding of drag reduction mechanism in crude oil pipelines and optimum dosage selection of chemical, various published literature and several technology providers were consulted. Based on the evaluation criteria, pilot was conceived at the major asset in Adnoc Onshore for one year. Pilot deployment of Drag reducing agent has shown significant energy saving. DRA dosage of 2 mg/L in the export crude oil network has reduced back pressure up to 5 bar from the network and thus enabled Asset to stop one export pump while maintaining the sustainable oil production rate. This strategic initiative for energy efficiency enhancement and decarbonization has resulted in OPEX reduction of more than 1.4 MM USD / year in terms of power tariff and GHG abatement of 16000 m Tons CO2 / Year, along with 30% enhancing the availability of facilities.

This paper presents the recent innovations of DRAs deployment for crude oil export system and also summaries the viability of chemicals utilization for friction reduction and provides stringent selection criteria that ensures optimum dosage to ensure net positive return on investment. This paper also sheds light on the operational constraints encountered during the deployment and design consideration during the design of new facilities.
Technology Basis for Shifting from IM to PMM For ESPs - Pathway for Decarbonizing ESP Operations, Field Case from Oman
Authors: Al Hashar D. M. , Al Aulaqi T. , Vahgjipurwala M.
Published: November 2024

Bisat field located in north of Oman has completed ten years of oil field operation with a rising trend in energy intensity index. The OQ company has set a comprehensive energy efficiency program targeting the upstream business unit. The Electrical Submersible Pump (ESP) is one of the popular technologies for artificial lift systems in the oil industry, however their high energy intensity index necessitates exploration of alternative methods to reduce expenses and power consumption that can enhance overall Energy Efficiency. The Permanent Magnet Motor (PMM) stands out as an ESP technology that delivers superior energy efficiency and performance compared to conventional induction motors (IM).

Fig. 1 shows a comprehensive roadmap for ESP operations decarbonization starting with optimizing the operating condition of the ESP followed by technology upgrade towards PMM. The next step would be to consider alternative power options for ESPs, especially for cases where these are operated by diesel generators. This ESP energy efficiency roadmap would provide a pathway for optimizing ESP operations for OQ to achieve its decarbonization targets.

The paper will review the business case for technology pilot and implementation of PMM technology for ESPs in the industry to understand the potential savings in replacing conventional IM technology for ESPs. The paper reviews the studies and results reported in one of the upstream Omani field regarding comparison between PMM vs IM technology for ESPs to provide framework for retrofitting IM ESPs with PMM ESPs paving the way for reducing the field energy intensity index and decarbonizing upstream operations. Savings from implementing PMM ESPs have been evaluated under different scenarios. Four wells have been identified as ring fence pilot. The selection criteria for candidate wells for pilot implementation are discussed to qualify the energy savings and establish the acceptance success criteria for deployment.

There is considerable debate in the literature to substantiate the benefits and savings from PMM technology for ESPs with field testing done to confirm the savings under different scenarios. PMMs can generate two to four times the power of equivalent sized IMs. In addition, power losses with this type of motor are lower due to the zero-rotor loss and reduced iron friction/windage losses as the motors are smaller in size. This results in enhanced power efficiency exceeding 90% and can double the expected life cycle due to the high reliability and reduced mean time between failures (MTBF). PMM technology can enable reduction in energy intensity for ESP wells and enable decarbonization for ESP operations.
SGPD T&I Digitalization and Robotic Execution
Authors: Al-Kulaib Ibrahim , Al-Marzooq Alaa
Published: November 2024

In order to ensure the company's facilities working at the optimum operating mood with the best in class reliability, Saudi Aramco Engineering Standard mandates executing a turnaround for a gas and oil separation plant (GOSP) every seven years. The purpose of the turnaround is to inspect and enhance the integrity of the major equipment, such as pressure vessels, drums, tanks, pumps, compressors, motors and so on. The methodology of planning and executing a turnaround is very crucial. The traditional methodology is to do manual planning, inspection and execution through paper-based checklists and traditional labor-based activities. However, at South Ghawar Producing Department (SGPD), the turnaround tracking is smartly digitalized to instantly get the required information for the plan, cost and execution. Moreover, the inspection is done through UAV drones and crawler robots to give accurate readings of the equipment conditions. Furthermore, 4IR technologies are utilized to execute maintenance activities accurately, timely and without any direct exposure of toxic materials which is a great HSE enhancement. The planning and execution of turnaround projects is done through four gates:

The implementation was done though:
Empowering Leaders, Enhanced Continuous Improvement Coaching Program
Authors: Al Bulushi J. Y. , Ba Wazer I. G. , Al Khaburi A. Z. , Al Kindi N. K. , Al Salmi A. A. , Al Zaabi Y. S.
Published: November 2024

Executive Summary

The Coaching Competency Framework developed for Continuous Improvement (CI) Coaches at Petroleum Development Oman aims to enhance leadership capabilities, foster problem-solving teams, and embed a mindset of ongoing performance improvement and organizational change.

Implemented over a two-year full-time program with clear KPIs and timelines, the framework achieved a minimum 70% competency rate among participants. In 2024, the program underwent significant enhancements aligned with PDO's strategic goals, integrating goal deployment, agile methodologies, change management techniques, and international coaching standards alongside the original framework. These updates enriched participant experiences, facilitating practical application in real-world scenarios.

Results from 2021 to mid-year 2024 demonstrate that PDO's Change and Continuous Improvement Department successfully developed over 40 coaches capable in driving business with a Continuous Improvement mindset, yielding substantial benefits including increased oil production, reduced deferment, cost savings, enhanced FTE efficiency, GHG reductions, and improved safety protocols. The collective value generated from these initiatives are very high.

Transitioning the program to an accelerated two-year format aims to further amplify organizational benefits in the future. The Continuous Improvement Coaching Program Framework indicates replicable potential for adoption across oil and gas sectors in the region, underscoring the strategic value of investing in people to develop leadership for sustainable growth and operational excellence.
Enhancing Waterflood Efficiency Through Integrated Workflows and Advanced Analytics
Authors: Gerges Nader , Ahmed Basma , Belayouni Nidhal , Franco Alba , Shaikh Iliyas , Ayoubi Reda , Gore Sonal , Ramatullayev Samat
Published: November 2024

Optimizing waterfloods requires a comprehensive approach that combines production-centric solutions with a focus on the subsurface reservoir. Holistic waterflood management requires a broad framework to cover all decision-making situations: operational, tactical, and strategic. In this paper, we seek to demonstrate a solution that combines physics-based streamlines flow dynamics together with advanced analytics to optimize short-term operational and tactical decision making.

Our approach integrates physics-based streamline data with well production and injection rates to estimate fluid flow dynamics. This enables comprehensive analysis of well performance, facilitating identification of potential workover candidates for optimization. We create and manage workover strategies, estimating their effects for effective interventions. Utilizing opportunity screening logic, the solution identifies opportunities for production/injection adjustments or injector conversions. Automated history match analysis refines these opportunities, focusing on high-quality matches. Integration with reservoir management guidelines and an automated economics engine prioritizes actionable opportunities. Flexible data ingestion ensures updated insights for enhanced decision-making.

The solution underwent successful piloting in two large ADNOC reservoirs with extensive waterflooding and thousands of wells. It generated numerous opportunities, enhancing understanding of injection-production dynamics. Notably, it provided actionable insights for short-term optimization, including injection / production increase / decrease and well conversions / shutdown. Serving as a decision support model, it offered alternatives and recommendations, optimized for operational and tactical decisions via comprehensive dashboards incorporating business KPIs.

This hybrid model, combining physics-based results with data-driven analytics, maximizes dynamic reservoir model utilization for short-term optimization and robust decision-making. Integrated with traditional petroleum engineering insights, it streamlines workflows and bridges subsurface and surface integration gaps, facilitating more efficient operations and resource utilization.

This paper introduces a novel approach to waterflood optimization, merging physics-based streamlines with advanced analytics for short-term operational and tactical decision-making. By integrating production-centric solutions with subsurface reservoir focus, it offers a holistic framework to address operational and tactical decision-making scenarios. This innovative methodology enhances traditional waterflood management practices, providing practicing engineers with a comprehensive toolset to optimize reservoir performance efficiently.
Design One, Build Many (D1BM) Concepts in Engineering, Procurement, and Construction (EPC)
Authors: Mehta J.
Published: November 2024

The "Design One, Build Many" concept in Engineering, Procurement, and Construction (EPC) refers to a strategy that involves designing a standard set of components that can be replicated in multiple projects. This approach allows for cost savings and improved efficiency by minimising design and engineering efforts and maximising the use of standard components.

Methods, Procedures, Process

Standardisation: The first step is to standardise the design of critical components or systems frequently used in EPC projects. This involves creating a set of standard specifications, drawings, and design guidelines that can be used across multiple projects.

Modularisation: The next step is to modularise the design of the standard components, breaking them down into smaller, interchangeable parts, increasing flexibility in the design and reducing the amount of customisation required.

Replication: Once the standard components are designed and modularised, they can be replicated across multiple projects. This allows for standardised equipment, materials, and labour, resulting in cost savings and improved efficiency.

Results, Observations, Conclusions

Cost Savings: Using standardised components and designs results in cost savings through economies of scale. Reduced design and engineering efforts and increased standard components and labour use also contribute to cost savings.

Improved Efficiency: The Design One, Build Many approach reduces the time required for design and engineering efforts and improves project efficiency by standardising components and reducing the need for customisation.

Quality Control: Standardisation and replication help improve quality control by reducing the potential for errors and enhancing the predictability of project outcomes.

Improved Safety: Standardisation of components and processes enhances safety by reducing potential errors and inconsistencies in construction and operation.

Reduced Environmental Impact: Standardised components and designs also reduce the environmental impact of EPC projects by reducing waste and improving energy efficiency.

Novel/Additive Information

The Design One, Build Many approach is valuable for achieving cost savings and improved efficiency in EPC projects. This approach can be utilised for offshore oil and gas/renewable energy (HVAC or HVDC platform), green hydrogen/ammonia, and oil and gas onshore projects. E.g. One platform will be designed for the base case with all standard requirements, and an alternate platform will be provided with a base case plus additional platform-specific requirements such as changes in water depth level for jacket design/ sand removal unit/ wax mitigation arrangement/corrosion inhibitor/gas lift/derating using HIPPS.
Understanding Different Mineralization Near Faults and Exploring Far Field Fractures Network Using Full Logging Suite in Khuff formation- The Case Study from Offshore, UAE
Authors: Uluyuz S. , Bradley T. , Ibe E. , Prabantara A. , Menon P. , Swedan T. , Belova N. , Hu J.
Published: November 2024

The Khuff formation of the United Arab Emirates, is a deep-seated reservoir with temperature exceeding 300 degF and it is characterized as a very dense and fractured unconventional reservoir. Khuff formations exhibit a very complex mineralogy and stratigraphy along with various stages of diagenetic burial, making it challenging to confidently characterize. A detailed fracture characterization and evaluation of the mineralogy is required to determine the possible source and extent of its occurrence. This paper presents an integrated approach using multiple sources of data to effectively characterize this complex unconventional reservoir.

Standard reservoir properties were determined by integration of conventional and advanced logs. Detailed mineralogy was characterized using advanced pulsed neutron elemental spectroscopy logs, in combination with X-ray diffraction (XRD) analysis of cuttings, to understand the occurrence of identified minerals seen in this well.

In the highly fractured reservoir, it was observed that both natural and induced fractures are present over many intervals, so making fracture analysis challenging. Utilizing high-resolution resistivity borehole image data provided high confidence detailed feature and facies identification that helped in classifying these fractures. Furthermore, integrating high-resolution resistivity borehole image data with acoustic near wellbore reflection images, confidence of fracture strike was increased. This integration enabled confident interpretation of the fracture and fault hierarchy within the Khuff formation, extending our insights up to 80 ft away from the borehole. Additionally, when integrating this information with minerology analysis and core data, it was observed that different fault and fracture zones are associated with different mineralization. This improved the understanding of the relationship between fracturing and faulting and mineralization, by comparison of detailed facies analysis to tectonic events: in particular, it was observed that thick anhydrite deposits correspond with deformation on internal argillaceous carbonates during compaction.

This case study demonstrates the synergistic integration of various log measurements and data sources to confidently characterize formation properties, including fault-fracture network, mineralogy, and facies of the Khuff formation. By doing so, we gain a clear understanding of the formation in this specific area of the field We propose that this methodology can be applied to other similar complex carbonate formations to aid in characterizing their properties.
Combining Ultra-Deep Resistivity for Landing and Horizontal Sections to Maximize Reservoir Exposure in Complex Clastic Reservoirs Utilizing High Definition 1D and 3D Inversions
Authors: Abdulmohsen Mustafa , Bikchandaev Eduard , Al-Zawad Ahmed , Fouda Mohamed
Published: November 2024

Prior to drilling the horizontal reservoir section of any well, a landing section is usually drilled to place trajectory of the well in the target zone. Selective logging-while drilling (LWD) sensors such as gamma ray, resistivity, density and neutron porosity may be considered to be used while drilling the landing section. Conventional LWD sensors have a limited depth of investigation (DOI) when compared to LWD reservoir mapping sensors. This paper presents the advantages of utilizing ultra-deep resistivity (UDR) tools to improve the landing practices and improve the well placement efficiency in the following horizontal sections.

Prior to drilling landing section intensive and comprehensive pre-well analysis is performed in order to identify optimal ultra-deep resistivity tool setting and frequencies for the purposes of getting most informative 1D and 3D inversions. Azimuthal ultra-deep resistivity tools along with triple combo logs have been utilized while drilling landing sections for multiple wells in complex clastics environment. Intensive analysis of ultra-deep resistivity data has been done and showed the optimum settings of the tool frequencies and transmitter-receiver spacings to successfully map the target zone at the maximum possible distance. High definition 1D and 3D inversions were used and provided valuable information for optimizing the landing strategy as well the well placement of the lateral section.

Ultra-Deep resistivity tools were able to map target higher resistive zone at distances higher than 50ft TVD away from the wellbore starting 75deg wellbore inclination. In addition, advanced ultra-deep resistivity inversion algorithms allowed the mapping of 6 distinct laminated low and high resistivity zones of variable properties and thicknesses. Target zone structural dip angle and thickness was identified while drilling allowing the well trajectory to be optimally placed in the target zone with the optimum hole inclination and to prevent accidental reservoir exit or unnecessary excessive drilling footage. LWD log responses of the drilled intervals have also confirmed the ultra-deep resistivity inversion response. Intensive analysis for the 3D inversion data improved reservoir insight revealing structural displacements in the target zone. All of this information were then used to optimize the strategy for the lateral well placement and as a result both laterals has been successfully geosteered in target zones of complex clastics reservoir with high net-to-gross ratio (NTG).

This paper describes an improved horizontal well landing practices allowing to successfully map and place the wells in the target zones and optimizing the well placement of the horizontal sections.
A Novel Approach to Enhancing the CO2 Sequestration Volumetric Capacity for CCS Project by Re-Injection of Produced Brine
Authors: Akhtar M. , Patil P. , Sridhar G. , Ibrahim M.
Published: November 2024

Objectives/Scope

Reducing anthropogenic carbon dioxide (CO2) in the atmosphere is crucial for mitigating climate change. CO2 Capture and Sequestration (CCS) is considered one of the most promising options for carbon reduction. It involves the injection of CO2 into the structural reservoirs in deep, permeable geologic formations. The effectiveness of CCS relies heavily on the geological and petrophysical properties of the storage reservoir. It has been studied that some percentage of injected supercritical CO2 is securely trapped underground via two major trapping mechanisms: physical trapping, and geochemical trapping. Physical trapping mechanisms include structural (hydrostratigraphic) trapping, residual (capillary) trapping, and sorption trapping. The physical trapping is relatively fixed for a given storage reservoir due to its geological parameters. The geochemical trapping mechanism occurs through solubility trapping and mineral trapping. It is very well known that solubility trapping includes slow diffusion in the aqueous phase and convective processes. In the case of mineral trapping, the process is over a much longer period, and it is one of the slowest mechanisms.

Methods, Procedures, and Process

This study employed a novel approach to enhance CO2 sequestration rates by injecting CO2 and brine produced from the same reservoir simultaneously. The solubility trapping occurs because of the dissolution of CO2 in the brine, leading to dense CO2-saturated brine. The main rate-limiting step in solubility trapping is the CO2 migration in brine which happens through diffusion and is very well known to be a slow process. To address this, the study proposed enhancing the mixing between injected CO2 and brine during the injection phase while maintaining reservoir pressure.

Results, Observations, Conclusions

Utilizing a systematic numerical model, the study identified an optimal approach involving a combination of CO2 and brine injection with brine production based on reservoir pressure transients. This strategy significantly enhanced CO2 injection rates, leading to a potential increase in CO2 sequestration capacity throughout the injection and storage campaign. Thus, with this innovative approach and with the use of existing CCS reservoir and existing facilities we achieved 10% to 30% more CO2 sequestration capacity through enhanced solubility trapping as well as some increment in mineral trapping.

Novel/Additive Information

A novel approach was employed to enhance CO2 sequestration rates by injecting CO2 and brine produced from the same reservoir simultaneously. This simulation exercise provides guidelines on enhanced reservoir management to increase CO2 sequestration rates and therefore volumes in a reservoir by managing the production and disposal of water. These novel guidelines enable operators to increase the economic value and ROI (Return on Investment) on such CSS projects.
Development and Demonstration of In-House Design Green Hydrogen Production Technologies with Reduced CAPEX and OPEX
Authors: Panigrahy Bharati , Rao B. Ramachandra , Maheshwari Vipul Kumar
Published: November 2024

Design of highly efficient cost effective and self-supported bi-functional electrocatalyst for the production of green Hydrogen is significant for renewable and sustainable energy conversion to achieve future carbon neutral. Meanwhile, as we know that the overall water splitting is an uphill reaction requires 285.8 kJ of energy, corresponds to the HHV of hydrogen, state-of-the-art developments are necessary to greatly improve the efficiency by rationally designing non-precious metal-based robust bi-functional catalysts for promoting both the cathodic hydrogen evolution and anodic oxygen evolution reactions. The performance of metal phosphide towards hydrogen and oxygen evolution was examined under application relevant conditions in an alkaline and anion exchange membrane (AEM) electrolyzer cell stack. The in-house designed stacked electrolyzer exhibited stable performances with a hydrogen production rate of few Nm3 per hour without any decay, pave the path towards large scale application with substantial reduction in CAPEX and OPEX cost.

Key Words: Water splitting, Green Hydrogen, Electrolyzer, Electrolysis, HER, OER
Reducing GHG (Greenhouse Gas) Emissions by Using Zero Flare Technology to Enhance the Sustainability
Authors: Ahmad Zeeshan , Albadi Mohamad Mubarik , Chitre Sunil , Al Mheiri Eissa Ateeq Ahmed , Shaker Ashraf , Al Hosani Abdulla Ahmed Al Haj , Alzeyoudi Mohamed Ali , Nastase Georgiana
Published: November 2024

This innovative solution combines a compression unit with a flexible line to offer flaring alternative for transferring hydrocarbons to the network. The Zero Flaring Technology (ZFT) Package consists of a gas compressor and triplex pump in one mobile skid, along with temporary Reinforced Thermo-Plastic (RTP) pipes to connect the well to the nearest production facilities by avoiding 3360 etCO2. However, with the Zero Flaring Technology, it is not only supporting the testing operation but also assisting the low potential liquid loaded well to start and continue production with zero Greenhouse gas (GHG) emission. Low-pressure oil rim well selected for test. Zero flaring technology assessed for technical and commercial suitability, which used portable ultra low-pressure compressor, triplex pumps and reinforced pipes to handle sour oil and gas fluids. HAZOP (Hazard and operability) study conducted by using preconditioning system to improve the performance of the technology. Well-X was connected to flow to clean test package and mobile wellhead compressor technology to flow the non-connected well to the nearby pipe network without any flaring. Gas pressure increased from 350 psi to 600 psi against line pressure and oil separated in surge tank was pumped at higher pressure to keep the flow in close loop. RTP was used for the first time in a sour gas environment by linking to nearby oil facilities. Increased hydrocarbon recovery and revenue was the key factor. Sustainable production of 3 MMSCF/D gas with 600 BPD of liquid observed during trial of 14 days and managed to complete reservoir monitoring activities. Reduced operational costs and risks by using ZFT, 3360 etCO2 avoided with zero flaring concept. Such technology concluded a success story for low potential liquid loaded wells. Operational challenges encountered during the trial included compressor pressure maintenance, gas impact on efficiency of triplex pump and Reinforced thermos plastic flow line integrity by flowing at various flowing conditions. Troubleshooting lesson learns concluded for future implementations.

In summary, this technology improves technical knowledge and results from the effective deployment and evaluation of the zero-flare technology application and the RTP system. This will be an innovation to raise health and safety standards, the environmental rules, and the community expectations while well testing operation with sustainable solutions.
Validated Multiphysics Modeling For Advanced Pipeline Integrity Management
Authors: Nonn A. , Marx P.
Published: November 2024

The aim of this paper is to present practical steps for utilizing a validated multiphysics approach for fracture control in CO2 pipelines within the framework of Carbon Capture Transport and Storage (CCTS). Ensuring the arrest of running ductile fracture (RDF) is a crucial safety requirement for the transportation of dense-phase CO2. However, current standards rely on outdated and restrictive methods, imposing severe limitations on pipeline material and structural design. As a result, projects that fall outside these standards face the need for extremely costly tests, often leading to delays or cancellations of CCTS initiatives.

This study introduces an advanced, validated, fully-coupled fluid-structure interaction (FSI) model designed to accurately predict fracture propagation in CO2 pipelines. A key advantage of this approach is its use of robust and reproducible calibration and validation procedures combined with high-quality material characterization data. The full coupling of structural, fluid, and backfill models is essential for obtaining precise results, not only in determining arrest occurrence but also in analyzing properties such as fracture velocity history, 3D pressure distributions behind the propagating crack, wall thinning, and crack tip opening angle. The FSI model has demonstrated its value as a cost-effective tool for safety assessments, enabling the development of fracture control plans that specify minimum required material properties and fluid compositions for optimized pipeline design, both onshore and offshore. Additionally, performing virtual studies with the parameterized FSI model enables the generation of synthetic data for training and validating a machine learning surrogate model. This surrogate model can be integrated into industrial practices, facilitating the application of multiphysics modeling without the need for extensive expertise.
A Tale of Three DST: Evolution of operational and interpretation strategies to characterize a complex, HPHT, offshore carbonate gas reservoir
Authors: Hemaprasertsuk J. , Bandyopadhyay P. , Hamdan M. K. , Akarapipatkul P. , Chayraksa K. , Vattanapornpirom K. , Chia B. S. , Worawutthichanyakul T.
Published: November 2024

Well testing through the Drill Stem Test (DST) plays an important role in reservoir characterization, particularly for complex field developments. Lang Lebah field is a HPHT carbonate reservoir located in Central Luconia Basin, offshore Sarawak, Malaysia, has a very challenging development condition and therefore relies heavily on the data from DST to plan an optimal development strategy (Escobar, 2017).

The first DST in the field was carried out in 2019 in the discovery well of the field. This was followed by two more wells in 2021 and 2024 where DST were conducted to adequately characterize the reservoir before proceeding to development. This paper presents the unique challenges faced with both operation and Pressure Transient Analysis (PTA) interpretation, and how the techniques and strategies were refined during this period to achieve an adequate level of reservoir assessment which is sufficient to move to FID in a multi-billion USD development.

In the first well (2019), operational problems resulted in suboptimal DST acquisition and PTA data were uninterpretable. Extensive root cause analysis followed, and possible areas of improvement (both operational and acquisition strategy) identified. In the second DST in 2021, the data quality improved, but the interpretation was still a challenge as the well never came out of spherical flow regime. Interpretation could still be carried out to make development decisions. In the third DST in 2024, a different zone was tested where the refined strategy could provide very good quality data. New interpretation challenges were observed requiring an unconventional approach.

Although this paper talks about this specific field only, most of the lessons can be applied for any other fields too. Also, there are key takeaways in terms of planning for reservoir heterogeneity in a carbonate reservoir which can impact overall job planning and contingency strategies.