bluuebunny/crossref_metadata_2025 huggingface dataset:
Applied Sequence Stratigraphy Combined with Geological Modeling of the Greater Cheleken Area (Central Caspian Basin, Turkmenistan) Using New 3D OBN Acquisition to Reveal Channel Complex Systems from Delta to Deepwater Environments in Plio-Pleistocene Clastic Reservoirs
Authors: Ellen H. , AlAli Abdulla , Ajayi A. T. , Guney H.
Published: November 2024

The Greater Cheleken Area (GCA) reservoirs, developed offshore by Dragon Oil, are located along a complex NW-SE dextral transcurrent zone that separates the Northern and Southern Caspian Basins (SCB). This area hosts numerous hydrocarbon fields within thick, highly faulted Pliocene-Pleistocene clastic successions of the paleo-Amu-Darya Delta System, originating in the N-Balkan Fold Belt. We present a new model for the geological evolution of this region, based on the analysis and sequence stratigraphy interpretation of new 3D OBN seismic data, well logs, and integration with existing published data.

With the new 3D OBN acquisition, Dragon Oil has both PSTM and PSDM data for analysis, employing a sequence stratigraphy approach. Horizon markers have been defined using sequence boundaries and flooding surface markers for detailed interpretation. The seismic data reveals promising geological features from the Apsheron to the red bed series reservoir levels. Seismic sequence stratigraphy has identified various stratigraphic components, such as basin floor fans, channel levees, and prograding deltas. Fault interpretation has revealed faults extending from the Miocene level to younger levels of the Apsheron, exhibiting typical positive flower structure configurations.

Unconformity-bound sequences of alternating sandstones and shales, with limited limestones, conglomerates, and evaporites, are deposited in environments ranging from shallow marine, delta front, and delta plain to alluvial, lacustrine, and deepwater. These sequences include the Uppermost Miocene to Lower Pliocene Red Series (Lower, Middle, Upper Red Series), Upper Pliocene Akchagyl Formation, Lower Pleistocene Apsheron Formation, and Upper Pleistocene to Holocene, comprising twelve productive levels. Hundreds to thousands of mappable faults are connected to deep-seated shear zones and exhibit fault-sealing characteristics that create highly compartmentalized reservoirs with vertical and horizontal separations. These faults vary in shape and size and display continuous Pliocene-Pleistocene syn-sedimentary activity, including sediment thickness heterogeneities, pinch-outs, lateral facies changes, channel structures, and inversion structures.

The sedimentary complexity as well as structural geology configuration described through the new 3D OBN data provides fundamental insights into the major challenges in reservoir production strategies and opens new opportunities for exploration and appraisal.
Artificial Intelligence Powered Non-Destructive Testing for Inline Inspection
Authors: Al-Jarro Ahmed , Mostafa Tarek M. , Ooi Guang , Khater Moutazbellah , Mohamed Fahd , Ba’adani Mohammad , Abdulmohsin Mohammed , Bahky Thamer , Ghamdi Khalid , Zahrani Salah , Bagci Hakan , Ahmed Shehab
Published: November 2024

In this work, we present a novel AI-powered non-destructive testing (AI-NDT) technique for the examination and diagnostic of pipelines. This digital transformation development targets the detection and identification of degradation in metallic pipelines. It stems from various business needs to address an increasingly urgent challenge in the Oil and Gas sector and other related industries for the characterization of energy pipelines. This effort employs cutting-edge and bespoke AI models applied to hybrid data-physics modelling and acquisition techniques coupled with advanced sensing methods. The system interrogates the structural integrity of pipes via novel in-pipe advanced electromagnetic based sensing techniques. The AI inversion models learn on the hybrid data-physics modelling with high fidelity simulation techniques. The recorded data are fed into the AI model that directly maps them into images to represent the health status of inspected pipelines. Notably, not only this IR4.0 driven system allows for the examination of pipelines for their integrity, it also provides a direct mapping of the recorded spatiotemporal sensors’ responses to images that represent the cross-sectional profiles of the inspected pipelines along their entirety. The outcome is a system that equips end-users with effective and easy-to-use inspection methods to determine the health status of targeted assets; leading to a precise, accurate, and near real-time assessment, a first of its kind.
Revolutionizing Exploration Risk Mitigation: Strategic MPD Design for HEMMER-1 Startup Project
Authors: Justiniano Luis Carlos , Viera Leonardo Landivar , Ospina Jenny , Ojeda Luis Vidal , Ruiz Carlos Costales , Drpic Juan Mardones
Published: November 2024

In the 1970s, the Marcou-1 well was drilled in the continental area of the Manzano block in Punta Arenas, Chile. This well served as a key reference point for understanding the reservoir dynamics and geological characteristics of the region. The Manzano block is characterized by the presence of gas pockets in highly pressurized sandstone intercalations. The exploration of HEMMER-1 is crucial for assessing the potential of high-pressure zones, which could significantly influence future resource extraction strategies in the San Jorge basin. The HEMMER-1 well, using managed pressure drilling (MPD), represents the first such implementation in Chile.

This technology proved essential for effectively managing the unpredictable pressure variances within the highly pressurized sandstone layers of the San Jorge formation. The success of the project was not solely due to the execution of advanced drilling techniques, but, as the first implantation into the region, it also hinged significantly on comprehensive training programs and meticulous planning. These preparatory steps ensured that the project team could adeptly handle the complex challenges presented, enhancing both drilling safety and operational efficiency. This study details the implementation of MPD and managed pressure cementing (MPC) as integral solutions to overcome the geological challenges and operational hazards.

The employment of these techniques facilitated the control of wellbore pressures and allowed for early kick detection and influx management, both essential for maintaining well integrity. Pressure buildup tests (PBUTs) and precise pressure management ensured the accurate characterization of the formation, confirming pore pressures and enabling safer drilling practices. Moreover, the successful execution of coring operations in MPD mode marked a significant advancement. Operating under statically underbalanced conditions, this approach ensured the integrity of core samples, which is critical for evaluating the reservoir's potential. The MPC technique further stabilized the wellbore, preventing fluid contamination and optimizing cementation processes, thereby enhancing overall operational efficiency.

This project not only demonstrates the feasibility and benefits of MPD in high-risk and unpredictable environments, but also sets a precedent for future exploratory and development projects in similar settings. The results underscore the effectiveness of MPD in reducing non-productive time (NPT), optimizing resource extraction, and mitigating operational risks, thus contributing substantially to the regional energy strategy and the broader goal of advancing drilling technologies in challenging environments.
First Dual Completion Digital Gas Lift System Installed in Middle East
Authors: Cannon G. D , Caproni C , Al Zaabi F. N , Al Sereidi A. O , Alshamsi AA , Salama E. S , Fonseca R. M , Abdulla M. F , BenAmara A , Faux S
Published: November 2024

Gas lift is one of the most crucial components for achieving and maintaining production targets for ADNOC Offshore assets. One major factor for this is the utilization of dual completions, whereby two production zones can be produced via a single casing conduit. Gas lift within dual completion wells is extremely challenging with conventional pressure operated gas lift valves due to the dynamic downhole conditions, fluctuating pressure and temperature and the inability to individually control the gas injection rate to each production string. In most cases, the string dedicated to the formation with lower productivity and reservoir pressure tends to "rob" the injection gas from other. Furthermore, well intervention is required to change out the gas lift valve orifice as downhole conditions evolve over the life of the well. To maximize the gas lift performance of the dual completion well, a Digital Gas Lift System (DIAL) was applied to a dual completion well on both production strings.

A suitable dual completion well candidate was selected in the Green Field SS. Once the candidate was selected a comprehensive design review was completed. The gas lift design determined that two DIAL Gas Lift Units were to be installed on each string. Orifice port sizes were selected to ensure that the optimum gas injection rate would be delivered. The DIAL Units are connected to a Surface Control System (SCS) which would enable surface control of the electric valves downhole. Each DIAL Unit features pressure and temperature gauges and valve position sensing to allow the operator to determine the Vertical Lift Performance (VLP) of each string, casing gradient and gas injection rate in real time. Furthermore, the DIAL System was integrated with the Field Distributed Control System (DCS), allowing for remote data driven decision making. A full System Integration Test (SIT) was completed ahead of the field installation, integration, and commissioning.

The DIAL System was successfully installed and commissioned. Through the ability to monitor and control the gas injection rate throughout the well life, the implementation of the DIAL System has resulted in substantial net present value generation through real time production optimization and the avoidance of well intervention, associated costs and deferred production required for gas lift valve change out and Flowing Gradient Surveys (FGS).
Realtime Well Engineering: Estimating Casing Runnability Risk While Drilling
Authors: Kumar S. Kiran , Samuel Robello
Published: November 2024

There is an urgent requirement in the drilling industry to discern the plausible causes associated with a casing stuck event and short landing of a casing. Traditional methods involve analyzing widely used legacy models such as the Torque and Drag/Swab Surge models and requires the interpretation of several plots at once, making it not comprehensive enough to account for many factors that may cause the casing stuck; in particular, the geometrical aspect of the wellbore is often overlooked while determining the risk. Furthermore, the available methods rely heavily on the experience of the drilling engineer, which is exacerbated by the fact that the casing stuck event is usually detected close to the casing stuck event, leaving very little time to perform any corrective measures that might alleviate the situation. Any last-minute intervention is generally not enough or is expensive and not ideal. Thus, there is a need in the drilling industry to have solutions that work in real-time that asses the risk of the casing stuck event which is comprehensive enough to take most factors into account that might affect the probability of casing stuck. The solution provided should also be simple and must not involve reading several plots at once; this removes the operational fatigue of the drilling engineer while monitoring the drilling operation. Moreover, the casing stuck event ideally must be predicted way ahead of time so that appropriate intervention is possible without having to resort to extreme measures. This paper proposes one such solution which is validated across several wells. The solution encapsulates the risk of the casing stuck considering several factors that might affect the probability of getting stuck into a single number(index) between 0 to 100, higher the value indicates higher risk. The solution offers to predict the casing stuck during the drilling operation itself leaving sufficient time for any intervention that may be needed. The geometrical aspect of the wellbore is also included in the construction of this index along with several other factors making the solution comprehensive. Finally, a single plot of the index value versus the depth is presented to drilling engineer for easy interpretation. This paper presents the methodology adopted in the construction of the real-time solution and discusses a few validation points using real cases.
Learning from the Past, Setting the Future Up for Success –Insights from PDO's Assurance Journey to overcome Project Management Challenges
Authors: Reddy D. , Mehdi R.
Published: November 2024

The Exploration & Production (E&P) industry is going through a transformational journey to broadly shift processes, technologies, behaviors to adapt the business to the energy transition. Petroleum Development Oman (PDO) has embarked into a transformational journey to forge its future path with a refreshed strategy and new purpose of "Building a sustainable and low carbon future" to maximize value for Oman. The PDO Upstream Petroleum Assurance (UPA) team has a pivotal role in that journey. The Upstream Petroleum Assurance (UPA) team is the custodian of PDO's Value Assurance Review process, ensuring end-to-end oversight from Exploration to Operate, focusing on compliance to Process Safety Standards, Subsurface Excellence, enhancing Capital Efficiency & Competitiveness, GHG (Green House Gas) competitiveness, facilitating robust decision-making, assurance & integration across functions.

In assisting teams to maximize value, the UPA team curate a repository of valuable insights, trends, best practices, and areas for improvement. The objective of this paper is to cascade these valuable learnings, improvements in tools, processes, and assurance activities to ensure every project achieves top quartile project delivery performance.

Retrospective lookback analysis & Post Investment Reviews was performed on significant number of projects matured and delivered over last few years. Review scope included both Technical and Process (Maturation & Assurance process).

This paper highlights best practices and winning strategies, identifies improvement areas to achieve best in class project delivery. Key themes addressed in this paper are delivering high quality Field Development Plans (FDP), Knowledge Management (learnings from other projects), Management of Change - (Risk Assessment & Integration).

To further hard-wire lessons learned & replicate successes, collaborative efforts with Data Management initiated to consolidate learnings from assurance events into a centralized tool (Learning Knowledge Base (LKB). LKB review & incorporating Lessons Learnt is mandated as part of assurance templates. Lessons Learnt sessions planned to ensure cross learnings between various assets & functions.

Reviews also emphasized the opportunity to improve the Management of Change (MoC) process. This paper highlights MoC process improvements to foster compliance, cross-functional alignment to ensure changes are managed safely and more visibly.

Key learnings and best practices were identified that could be a gamechanger for future projects, by improving integration, bringing process efficiency, and eliminating waste. This paper highlights best practices from PDO's front runner projects and brings awareness on potential pitfalls in front end loading with an objective to share learnings for achieving excellence in project delivery.
Real Case Study Showcasing New Solution for Unplanned Stuck Pipe Events Using Remote Wireline Operations in Challenging North Sea Environment
Authors: Bruneau J. , Kumar V. , Elafifi A. , Gonzalez R. , Dixit A. , Bang M.
Published: November 2024

Stuck pipe events are a major challenge for oil and gas operators; they can occur during drilling, completion, or abandonment operations, and can put the whole well at risk. They are also one of the main sources of non-productive time, as recovering from such event is usually a lengthy process and tend to disturb the entire operation. In the North Sea, weather is unpredictable and logistics has been known to be challenging, leading to rigs shutting down while waiting on personnel and equipment, further delaying the return to normal.

Utilizing wireline remote operations has had a massive impact on how fast the operations can be completed. It has saved days of waiting on weather, equipment, and personnel. Expert wireline engineers in the Remote Operations Center are available 24/7 and the required equipment, such as Mechanical Pipe Cutter and Downhole Electric Cutting Tool, are usually available at the rig site. A unique work model combining multiskilled personnel on offshore rigs along with remote professionals onshore is used, paired with digital technologies available in the market. Statement of requirement for connectivity and rig infrastructure for communication was defined. Detailed risk assessment was conducted in planning stage. RACI matrix involving all tasks at rig site or remote center were clearly defined. Escalation process was developed to have clear communication guidelines.

This model was tested on multiple jobs with great success. The first ever fully remote operation using the Mechanical Pipe Cutter service in the North Sea was successful. In total, 5 cuts were completed remotely; the first 2 cuts were successful but didn’t result in being able to pull the pipe, due to damaged control lines downhole. After consulting with the operator, 3 more cuts were performed and the pipe was successfully pulled and laid down at surface. A tractor was used for conveyance, leading to integrating teams and prevented sending additional personal offshore. Post job data delivery to customer was done quicker, as remote engineers focused on data processing and delivery while the offshore personnel worked on rigging down tools and returning the well to customer. With over 60 jobs done successfully to date, our customers have saved huge costs. 25% reduction in personal on board was achieved leading to almost 2.5 ton of CO2 emissions saved.

This was a first worldwide, as this service had never been run fully remote anywhere else. More logging units are getting upgraded with fiber connectivity to support future operations, and wellsite supervisors have been trained on this innovative approach. Strong horizontal knowledge transfer between rigs crews is possible by having 24/7 central support onshore. This paper will explain in detail the holistic approach in terms of technology development, multiskilled personnel and remote logging applications.
Innovative Surveillance Characterization for Fluids Behavior in Multilateral Producer Utilizing Inflow Tracer Approach in Carbonate Reservoir
Authors: Jamal Mariam Abdulraheem , El-Daoushy Ahmad AbdelGhany , Al-Shuaib Mariam , AlHashash Faisal , Rogers Blair , Jayakumar Swathika , Nair Sajan Rajasekharan , Al-Mutairi Fayez Misfer , Al-Omair Shahad , Slama Hedi
Published: November 2024

Multilateral drilling and completion is aiming to increase well productivity while reducing the drilling, completion and production cost. Understanding the inflow from multilateral well is important to optimize the production of the well and decide on the optimum WRFM in sort of the production parameters, pressure support and further development of the area. Inflow characterization requirement has been raised during the planning stage of new level-1 multilateral producer to understand the production from each lateral and provide the required optimization and production management for the well, which was a challenge in previous drilled level-1 multilateral wells.

Inflow tracers approach has been deployed to understand the inflow from each lateral during the flow back and early stage of well`s production. Different inflow oil and water tracers have been injected in each lateral after drilling and during acid stimulation of each lateral. The tracers have been mixed carefully at the surface with the treatment fluids and separately for each lateral. Samples have been collected from the well at the surface during the flowback of the well and during the early-stabilized production stage.

The Inflow Tracers from the three laterals have been detected in the surface samples. The tracer concentration in the produced oil and the water phases showed the performance of each lateral during the flowback stage, which indicated the efficiency of the cleaning, transient inflow and productivity of each lateral. The results during the stabilized early production stage was matching with the results achieved at the end of the flowback, where two laterals were dominating the production and the third lateral was with low productivity then ceased flow in the early production stage of the well.

Inflow tracer approach has provided invaluable information and understanding on the inflow from multilateral level-1 producer during the transient and early stabilized flow for the first time in the field, which was a challenge to obtain through conventional PLT. Moreover, the acquired data is presenting the well inflow per lateral at same time and during the longer production time or a full stage of well production compared to the conventional PLT. The inflow Tracer approach has proved the possibility to monitor the transient and early production stage of the lelvl-1 multilateral without well intervention with no related risk, in addition no deferred production and reduced cost.
Impact of Methanol on the Scale Deposition – a Case Study from West Africa
Authors: Baraka-Lokmane S. , de Sousa A. M.
Published: November 2024

The introduction of methanol to control hydrate risk presents new challenges in terms of increased scale tendency (dehydration of brine) and interactions of the hydrate control chemicals with scale inhibitor performance. The use of methanol for preservation during the full field shutdown in a West African field has shown the increase of the scaling risk of both calcium carbonate (CaCO3) and barium sulphate (BaSO4). This study highlights the challenges faced on field during full field shutdown (FFSD) where after start-up, mineral deposits have been observed at subsea and topside.

A full understanding of the evolution of the production water chemistry through the field life cycle has been carried out, including the analysis of scale deposits and supersaturation changes, has been developed. A detailed scaling risk assessment has been performed with and without the presence of methanol, to assess the impact of this hydrate inhibitor on the formation and deposition of calcium carbonate and barium sulphate scales. The scaling risk evaluation has shown the same risks as the previous study carried out in 2019: High scaling risk for calcium carbonate at topside. The use of methanol for preservation during the full field shutdown, carried out in June 2021, has shown the increase of the scaling risk of both calcium carbonate and barium sulphate scales at the risers, the control valve downstream, 1st stage separator, the strainer upstream crude oil transfer pumps and wash tanks. A full monitoring and treatment recommendation is presented in this paper. The impact of methanol on the increase of the scaling risk, using a thermodynamic model has also been discussed. This study outlines the process by which the risk assessment of scale formation and deposition in the presence of methanol was made and how the scale control measures for effective scale management of subsea installation has been carried out. This feedback is intended to be used further on, during the production chemistry studies.
Win-Win Synergy Between Two Assets, A Novel Approach to Unlock Production Constraint and Enhance Sustainable Oil Rate
Authors: Elabrashy Manar , Mathur Avnish , Ojha Aditya , Al Kindi Mohamed , Al Badi Mohamed , Al Dhanhani Jawaher
Published: November 2024

An Onshore oil field X production mandated target rate is 180 MBD from carbonate reservoirs. The field has been developed to produce oil & gas maintaining pressure with cyclic Water alternating gas (WAG) injecting methodology. Over the years field Gas oil ratio (GOR) has increased and consequently total associated gas production has increased, causing production constraints due to Surface facilities gas handling capacity limitation. This has resulted in oil production curtailment, which impacts the oil asset's ability to achieve its production target. The two assets, namely oil asset and gas asset collaborated and cooperated for a synergy to deal with challenges of well testing of gas producers and reducing gas injection, production enhancement to meet sustainable oil production target in oil field X and worked out mutually beneficial solution. A win-win scenario was identified, in which two inactive gas producers have been agreed for temporary injection of excess associated gas in Zone-1 gas cap. As Win-win synergy between two assets, two gas wells, well-A and Well -B, have been temporary converted to gas injectors, re-directing surplus associated gas into these wells instead injecting in Oil reservoirs for pressure maintenance, to enable reduction of gas injection volume in oil asset reservoirs, enable sustainable oil production enhancement and enable increase in water injection to support the reservoir pressure and maintain VRR. Moreover, this reduction in gas injection volume will support lowering the GOR over time in the oil asset, in addition to yielding an improvement in condensate production at the gas asset side during resumption of gas production post conclusion of injection phase.
Leveraging Physics-Informed Neural Networks for Faster and More Accurate Simulation of Gas-to-Liquid Operations and Design
Authors: Nikolaienko T. , Patel H. , Panda A. , Joshi S. , Jaso S. , Kalyanaraman K.
Published: November 2024

We present a novel approach to multiscale modeling of Gas-to-Liquid (GTL) processes based on Fischer-Tropsch (FT) synthesis, leveraging Physics-Informed Neural Networks (PINNs). We address the computational challenges inherent to theory-based, ground-up modeling of FT reactors by developing and integrating PINN models for two critical scales: microkinetics and catalyst pellet. The PINN-based approach demonstrates significant computational efficiency gains compared to traditional numerical methods, achieving speedups of 5 and 7 orders of magnitude in case of microkinetics and the pellet-scale model respectively, when employing the ability of GPU to process multiple sets of reaction conditions within the same run. Notably, this increased computational efficiency is achieved without compromising accuracy, with relative errors generally below 1% for most hydrocarbon product reaction rates across a wide range of industrially relevant operating conditions. The developed framework enables near real-time simulation of complete FT reactor tubes, with a full solution obtained in approximately 4 seconds on a single consumer-grade workstation (equipped with 1x V100 GPU). Results from these simulations show qualitative agreement with characteristics observed in real-world reactors. The scalability and parallelization capabilities of neural networks further enhance the potential for rapid, large-scale simulations, creating new possibilities, in line with the industry trend towards digital twins for reactor optimization, process control, and plant-wide simulations, which were previously considered to be computationally intractable.
The Sabah's Ophiolite Mineralogical Studies for Evaluation of Natural Hydrogen Potential
Authors: Ismail H. H. , Zhao H. , Rajput S. , Jones E. A. , Tan S. W. , Sobri N. S.
Published: November 2024

The serpentinization of the mafic and ultramafic rocks is one of the most significant mechanisms for producing natural hydrogen in the subsurface. The northern part of Borneo is notable for its complex regional geology, particularly regarding Fe-rich rocks in the ophiolite zone of Sabah. This article discusses the mineralogy of ophiolites in Sabah, which could lead to the natural hydrogen feasibility via serpentinization processes. Fieldworks were conducted in selected outcrops in order to investigate the presence of ophiolites, standard petrography and x-ray diffraction (XRD) analyses were performed on the mineral composition and composition of the rocks. The investigation area includes the ophiolites found in Ranau, Telupid and Lahad Datu, these ophiolites are composed of crystalline basement and ultramafic- serpentinite rocks that are of Triassic to Early Tertiary age. The rock samples consist mainly of serpentinite with some basalt, dolerite and amphibolite. These rocks are unconformably overlain by younger sedimentary rocks, including the Eocene-Oligocene Crocker Formation and the Paleocene-Eocene Trusmadi Formation in northern Sabah. In central Sabah, the ophiolite is overlain by the Eocene-Oligocene Crocker Formation and the Kulapis Formation, while the ophiolite in southern Sabah is overlain by the Oligocene-Middle Miocene mélange sequence such as the Kuamut, Ayer and Kalumpang Formations. The results of the geochemical and mineralogical investigations show that the serpentinite samples contain a considerable amount of serpentine minerals such as antigorite, cronstedtite and lizardite as well as some unaltered ultramafic/mafic minerals (e.g. forsterite, fayalite, pyroxene and hornblende) and traces of secondary minerals (such as magnetite, chromite, hematite, siderite and pyrite). The degree of serpentinization in the serpentinite samples ranges from 25% to 79% by volume, with most samples exceeding 45%. Other rock types such as basalt, dolerite and amphibolite show a lower degree of serpentinization, ranging from 2% to 20%. The results of the laboratory analyses indicate that significant serpentinization processes have taken place along the ophiolite zone of Sabah. The overlying sedimentary rock formations could provide reservoir and seal traps for the hydrogen gas accumulation. These results give new insight into potential natural hydrogen resources in Sabah's ophiolite zone; however, more detailed investigations are needed for further evaluation. Limited subsurface data is a major challenge in studying the entire natural subsurface hydrogen system along the ophiolite zone in Sabah.
Enhancing Hydrogen Evolution Efficiency in Alkaline Water Electrolysis Using Optimized Raney Nickel Coatings on Stainless Steel Electrodes
Authors: Gond S. , Mishra A.
Published: November 2024

Hydrogen, as a clean and high-energy-density fuel, holds immense promise for future energy systems. The aim of this study is to enhance the efficacy and durability of hydrogen evolution reactions (HER) in alkaline water electrolysis by optimizing Raney Nickel coatings on stainless steel electrodes. This work aims to reduce costs and improve the performance of electrolysis systems, making hydrogen production more feasible for large-scale applications.

The study involved the electrodeposition of Raney Nickel on stainless steel substrates using a modified Watt’s bath. The pretreatment process included degreasing, acid pickling, and Nickel Strike coating to prepare the electrode surface. Functional coatings were applied in a solution containing NiSO4, NiCl2, H3BO3, and ZnCl2 at 50°C. The obtained coating substrates were characterized both chemically and morphogically by XRF analysis and confocal laser scanning microscopy. The performance of the electrodes was evaluated through electrochemical measurements, determining the electrochemical surface area (ECSA) and overpotentials for HER and oxygen evolution reactions (OER)

The optimized Raney Nickel coatings, referred to as Raney 2, demonstrated a significant improvement in both HER and OER performance compared to traditional coatings. The Raney 2 coating exhibited a threefold increase in ECSA. The accelerated aging tests showed that the Raney 2 coating outperformed Raney 1, with lower peak voltages and improved stability over time. The roughness factor of the Raney 2 electrode is higher, indicating has an extensive reactive surface area. Furthermore, the study confirmed that the incorporation of elements from the 316-grade stainless steel counter-electrode, such as iron, contributed to enhanced catalytic activity, particularly for OER. These findings suggest that the modified coating process can significantly extend the operational life and efficiency of electrolysis electrodes.

This work presents a novel approach to enhancing the performance of Raney Nickel coatings by incorporating a 316-grade stainless steel counter-electrode during deposition, which has not been extensively explored in existing literature. The resulting hybrid coating demonstrates superior electrochemical performance and durability, offering a cost-effective solution for improving alkaline water electrolysis systems. This advancement can significantly contribute to the development of more sustainable and efficient hydrogen production technologies.
Increasing Oil While Reducing Water Production in a Mature Field with High-Permeability Sandstone and an Active Aquifer in the Colombia Llanos Basin: Case Study
Authors: Palacios Jinna Marcela , Jaramillo Jose Luis , Ebratth Oscar Aressu , Ramos Diana Rocío , Gomez Jaime , Hernandez Fabian
Published: November 2024

Low reservoir pressure, oil production, reduced wellhead pressure, and increased water production are among the characteristics that describe mature fields. A major challenge in these fields involve the maintenance of production despite high water rates. The identification of the water production mechanism and the application of the correct treatment for each well is crucial to achieve profitable field development. The analysis and execution of water control operations in a field located in a remote region in Colombia are presented. This project was designed and executed with a combination of multiple tools, including a reservoir simulator for reservoir characterization, petrophysical software that enables continuous and iterative data collaboration and real-time well log analysis within geoscience and engineering workflows, and productivity analysis developed to optimize the design and placement of conformance treatments along with production forecast estimations of the treatment results.This water technology application represents an achievement for the field and serves as a reference for future water control operations under similar conditions, such as high permeability, heavy oil production, and a strong aquifer. The project covers the entire comprehensive diagnostics process, to include data analysis, candidate selection, water mechanism diagnosis, treatment design, and operation execution. The first pilot in a vertical well demonstrated successful results, which initiated further analysis, design, and execution for horizontal wells that present additional challenges and are part of the evaluation process to expand the project. This expansion aims to reduce water production and increase oil output throughout the field.
Evolution of Zawtika Sand Control from Cased Hole Gravel Pack to Alternative Method
Authors: Prachitmutita I. , Choodesh A. , Nopsiri N. , Piyakunkiat N. , Hnuruang K.
Published: November 2024

The Zawtika field, located offshore in Myanmar, is a vital source of natural gas. However, the field has consistently faced significant challenges related to sand production. Sand production occurs when the formation sand enters the wellbore along with the produced hydrocarbons, which can lead to numerous operational problems such as erosion of downhole and surface equipment, clogging of production tubing, and even complete loss of well integrity. Addressing these issues is paramount to maintaining continuous and efficient production.

The economic significance of sand control cannot be overstated. The costs associated with managing sand production include frequent well interventions, equipment replacements, and production downtime. These costs can quickly escalate, making it economically unfeasible to operate without effective sand control measures. Thus, the pursuit of cost-effective and reliable sand control techniques is driven by the need to enhance the economic viability of gas production from the Zawtika field.

This paper aims to present the evolution of sand control techniques implemented in the Zawtika field. It will detail the transition from traditional methods such as the Cased Hole Gravel Pack (CHGP) to more advanced and alternative approaches. The objective is to highlight how these changes have contributed to improved sand control efficiency, reduced operational costs, and enhanced overall production performance.
Subsurface Data Acquisition and Operational Excellence in ADNOC’s First CCS Well in the UAE
Authors: Karim M. , Farmer R. G. , Parra H. , Al Neyadi A. , Xu S. , Vantala A. , Arbadov G.
Published: November 2024

As a key milestone in ADNOC’s sustainability initiatives and to support the UAE’s net-zero goals, a major CCS project was initiated, focused on permanent CO2 storage in deep carbonate saline aquifers in onshore Abu Dhabi (Abu Dhabi Environment Report, 2017). Following a comprehensive feasibility study (Xu et al, 2022), a combined appraisal and injection site was selected and the first commercial CO2 injection well was completed in 2023.

This paper reports the outcomes of a comprehensive operational data driven acquisition program across two major saline aquifer reservoirs; Formation A and Formation B as well as across caprocks overlying these reservoirs. Data analysis involved the combination of wireline logs, core data and formation pressures and fluid sampling.

Iterative cross discipline involvement in the well design for the first CCS well was critical to achieve the data acquisition goals of the well (Figure 1). Key challenges involved integrating well data outcomes and conducting mini frac tests to evaluate the seal integrity of the overlying formations and confirm the reservoir rock quality and variability in A and B formations, which are under-explored in this part of the UAE.

The cap rock integrity was assessed by conducting multiple mini-frac tests in the Caprock and A formations. Drilling and logging programs were designed to ensure that reliable micro-frac tests and image log pre-post frac could be conducted. The results showed that the breakdown pressure in the caprock formation indicates a strong sealing capacity.

Quantification of reservoir quality and characterizing the heterogeneity was important, so core analysis was fast tracked and then matched with NMR results from the data acquisition. This dataset, combined with dynamic information, will be a crucial source for validating future CCS wells performance in UAE.

Once primary data acquisition was achieved across the reservoir and caprock intervals, all subsurface data analysis was carried out simultaneously and fast-tracked to ensure effective and reliable information was available to optimize decisions for the well to deliver on UAE’s net-zero aspirations strategy.
Advanced Phase Behavior Analysis of CO2-Rich Streams with Innovative ThermoQuartz ResoSense Technology
Authors: Hoopanah M. , Joonaki E. , Tohidi B. , Mozaffar H. , Vatandoost A.
Published: November 2024

Advancing monitoring instruments specifically designed for detecting water condensate or hydrate formations is crucial for ensuring the safe and efficient production of gas and transportation of impure CO2 within specific pressure and temperature ranges. The prevention of water condensation and subsequent corrosion remains a major challenge in the energy industry, especially within the burgeoning Carbon Capture, Utilisation, and Storage (CCUS) sector. As the industry increasingly moves towards multiphase transportation, the need for advanced flow assurance monitoring technologies becomes necessary. These technologies are essential for accurately evaluating risks associated with water condensation, corrosion, and hydrate plugging, thereby facilitating the secure and efficient transportation of CO2. Significant issues arise due to changes in phase behaviour in CO2-rich streams. Even small amounts of polar impurities can alter the dew point and phase envelope, leading to the formation of corrosive aqueous solutions at temperatures well above the dew point of pure water. Impurities such as methanol and Triethylene Glycol are particularly concerning in CCUS networks. Currently, no off-the-shelf solutions effectively address these CO2-induced flow assurance challenges, underscoring the issue's complexity and importance.

This study aims to validate and improve our innovative sensor-based technology, ThermoQuartz ResoSense, which monitors phase behaviour and determines the dew point/vapor-liquid equilibrium in CO2 -rich streams. Several High-Pressure-High-Temperature-QCM experiments were conducted under stable pressure conditions, maintained either by pump operation or pressure suspension once the target was reached. The system was pre-conditioned at peak temperature, followed by controlled cooling through distinct cycles, with a corresponding heating cycle raising the temperature at the same rate.
Transformation of Concept Evaluation Studies with Cloud Native Digital Twins
Authors: Tran A. , Knight D. , Gaader A.
Published: November 2024

The adoption of cloud native digital twin platforms has, in the past 3–4 years, begun to alter completely the execution and delivery model for offshore concept and pre-FEED studies. When stakeholders visualize the field development concepts in 1D/2D/3D, ensure appropriate project data is shared seamlessly, and understand the remaining tasks needed to close the study considerable efficiencies will be attained. The early evaluation of these novel execution methods show project delivery time reductions of 45–55%.

Time spent by valuable staff finding and assembling the necessary data to conduct concept selection and Pre-FEED studies is better spent creating and evaluating a larger concept catalog. The digital twin platform streamlines gathering and the sharing of the 3D surveys, WMS data, legacy data stored in GIS, and even data in Excel files. Critical project data no longer is shared by staff via "electronic" files, email. The digital twin platform has unleashed secure project data via novel workflows inside the secure data platform in real time via the cloud. The team generates many more concept variants than ever before and by using the platform's APIs delivers concept data into external tools needed (cost, risk, engineering) for their screen processes.

Early phase project teams typically spend over 50 or 60% of their time working on a project just locating and assembling the various datasets that are needed to begin their workflows. The digital twin platform can easily ingest data from a wide variety of sources and build the background 3D model. The reported time savings for concept study workflows are: Build 3D background models – 40%; layout production equipment – 30%; route pipelines and umbilicals – 50%; create Concept Selection Report (Cost Estimates, MELs, 2D maps, 2D schematic of system) - 60%; Equipment Datasheets – 60%

Teams have reported that when major inputs to or requirements for the concept study have changed, such as well count or well location, the required effort to build the new concept catalog can be up to 70% less than without the use of the digital twin platform.

Traditional early phase project delivery methods are inefficient, creating unnecessary risk and uncertainty for front end teams from both operators and suppliers. Teams adopting a cloud-based, digital twin platform have created transformative workflows for the delivery of concept and Pre-Feed phases. These efforts have shown to boost productivity by nearly 50% and, more importantly, are allowing a deeper concept catalog to be studied which ultimately reduces the risk when executing the project in the EPCI phase.
Model-Informed Reservoir Appraisal Strategy to Reduce Reservoir Performance Uncertainty for Unconventional Development in Delaware Basin, New Mexico, United States
Authors: Alqallabi S. A. , Hehmeyer O. J. , Krishnamurthy J. K. , Bello R. O. , Forcina A. V. , Lopez C. , Miller N. M.
Published: November 2024

This study discusses an integrated reservoir assessment, including reservoir surveillance and analysis, fracture modeling, and reservoir simulation, carried out for an unconventional development prospect located in the Delaware Basin of New Mexico, United States. The objective was to assess reservoir performance, estimate the potential for vertical and lateral communication between reservoir intervals, and determine optimal well density. The assessment enabled the development of a fit-for-purpose appraisal strategy, grounded in modern reservoir data collection, which will effectively reduce uncertainty in the development plan.

This study used data from offset wells as a reference to conduct the analysis. The logs and reservoir data were used to develop reservoir and geomechanical property inputs for hydraulic fracturing and simulation modeling. Reservoir stress maps were created, and multiple stress scenarios, including isotropic and anisotropic, were generated and used as input to fracture simulation. Mechanistic fracture models were constructed for different reservoir intervals based on analog stimulation recipes and stress curve sensitivities. The resulting fracture geometries were input to reservoir simulation to determine the economically optimum well density.

The geomechanics analysis shows lateral variation in stress properties through the prospect area with limited stress barriers observed in some reservoirs. The hydraulic fracture models suggest limited vertical interaction between intervals. Simulation results suggest an optimum well spacing that is tighter for the shallower 2nd Bone Spring interval vs. the deeper Wolfcamp. Simulation results are supported by offset analogues which show well performance degradation at tighter spacing. Simulation shows reservoir performance is most affected by matrix permeability and fracture half-length. The models suggest significant remaining uncertainty. To reduce uncertainties, a robust, tailored data collection plan is proposed, including vertical and slanted horizontal monitoring wells instrumented with fiber and gauges, quad combo logs, core sampling, time lapse geochemistry sampling on ten wells, and six PVT samples.

The study highlights the significance of effective data integration from different subsurface domains to enhance field uncertainty understanding and avoid unnecessary costs during appraisal data collection.