bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimization of the North Kuwait Jurassic Gas Integrated Production System - Modelling, Optimization, Impact
Authors: Alarouj M. , Akbar Y. , Al-Shuaib M. , Al-Saleh A. , Al-Salali Y. , Moes E. , Kosuke N. , Matvinko A. , Marketz F. , Saxena A.
Published: November 2024

Production System Optimization (PSO), an established Industry best practice for well, reservoir and facility management (WRFM) has been implemented for the North Kuwait Jurassic Gas (NKJG) asset with the objective to review, model and optimize the integrated production system (IPS). The focus of this paper is to describe the IPS, the modelling strategy, model results and the impact of PSO in NKJG.

The NKJG IPS consists of eleven fractured carbonate HPHT sour gas fields, with the majority of production coming from Middle Marat reservoir layers, approximately 270 producer wells, an extensive flowline network and six production facilities. The IPS was reviewed and modelled following a field-by-field approach starting with the relatively smaller Dhabi (DA) and Abdali (AD) fields, followed by upscaling and refining the reviews and models to the larger North-West Raudhatain (NWRA), Raudhatain (RA), Sabriyah (SA) and Umm Niqqa (UN) fields. Integrated production system modeling (IPSM) was conducted to quantify constraints in the IPS, construct limit diagrams and to estimate PSO gains from removing well, flowline network and facility constraints. Well modelling was conducted to assess well flow stability at larger choke sizes. Reservoir modelling was conducted to assess the long-term sustainability of optimization gains. Based on PSO gain estimates, opportunities were ranked, prioritized and executed. Incremental gains were measured and compared with estimates.

IPSM modelling demonstrated that the key opportunities to optimize the NKJG IPS are choke optimizations, flowline de-commingling and reducing facility inlet pressure, the largest PSO potential is in the largest field and that the flowline network is the dominating constraint only one medium-size field. Well modelling confirmed flow stability at larger choke sizes for the majority of identified bean-up opportunities. Only a limited number of choke optimization opportunities exist in fields with water production where gas well deliquification is required to restore and optimize well performance. Field-level reservoir modelling showed that PSO gains are sustainable in the long term. Realizing priority opportunities has contributed to achieving an asset gas production record. It was concluded that the integrated use of IPSM, well and reservoir models for PSO has generated an improved understanding of the NKJG IPS and, combined with effective opportunity management has a substantial impact on asset performance.
Maximizing Reservoir Potential: Coiled Tubing Multilateral Extended Reach Intervention for Acid Stimulation
Authors: Chishti S. S. , Correa P. , Alabdullah M. , Ahsan M.
Published: November 2024

Multilateral well designs have been gaining demand, aiming to expand the recovery of hydrocarbon or injection of recovered fluids, depending on application. The primary challenge in such well completion is accessing the unnatural laterals, followed by extending the coiled tubing (CT) depth reach at which the stimulation treatment can be delivered, which is normally restricted by the friction lock limit. This paper presents a solution for multilateral extended reach CT stimulation.

The producing multilateral well was completed as dual open hole laterals, from completion to open hole, increasing the friction coefficient and reducing the maximum reach. The application of a reliable hydraulic multilateral entry tool (MLT) and an extended reach tool (ERT) was proposed, which provided a reliable option to access the un-natural lateral and extend the reachability of coiled tubing for stimulation. The BHA included a real time integrated sensor tool and casing collar locator (CCL), powered by a reliable single conductor system for telemetry. The use of real time data provided confirmation on accessing the correct lateral.

The use of an MLT is mandatory to enable CT entry into the lateral leg. During intervention, the access depth to the lateral window was located with the use of CCL for depth accuracy, followed by pressurizing the MLT to a predetermined pressure for the tool to begin the search mode, indexing the wand section of the tool and enabling it to complete a mapping cycle by continuously rotating 360° in less than 2 minutes. A pressure drop signal will indicate that the window has been located and rotation will then stop with full kickoff achieved. If there is no pressure drop, the tool will complete full rotation and is reset to straight position by increasing pressure to a predetermined value. CT is then moved to next mapping depth and new cycle is started. Upon locating the window, the indexed wand section is run in hole (RIH) into the lateral past the access window and CT is stopped to reset the tool to extended position and allowing fluid to be continuously pumped through the ERT and the MLT. At this point, the ERT is activated, and it helps CT RIH past the default friction lock limit to perform stimulation at a deeper depth.

The combination of these technologies, prove to be an effective option to increase the working envelope of smaller OD CT in multilateral extended reach interventions, challenged by the offshore work environment. This application translates to an increased footage of direct stimulation in the open hole section and maximizing the reservoir potential.
Axial Resonance Troubleshooting and Resolution of an Induced Draft Fan
Authors: Ashour Mohammed , Shalabi Mustafa , Ganesh Sankar , Piton Nicolas
Published: November 2024

This case study is focused on accurately identifying the root cause of the observed resonance on the induced draft fan bearing in the axial direction, by analyzing the vibration data during steady state, and transient modes recorded during frequent balancing jobs. Also, the interpretation of Modal Analysis testing for the fan rotor in the fixed and free-free conditions to identify the influence of the structure support stiffness on the system natural frequency (bearing dependent modes).

During normal operation of the fan, it was observed that vibration response in the axial direction is increasing gradually and exceeding the trip limit, however the vibration levels reduced well below alarm limit after fan cleaning and balancing. Each fan required balancing almost 3 times yearly which affected the plant availability. Closer look on the vibration levels before balancing showed that axial vibration level is more than 5 times the horizontal vibration levels. 1X vibration polar plots in the axial direction during startup and shutdown showed phase lag around 70 degrees between full speed 1X vibration vector and low speed 1X vibration vector, to be understood that the fan is approaching a natural frequency close to running speed.

Modal Analysis study carried out on the fan rotor components (blade, impeller fixed mode, and impeller free-free mode), which revealed that the amplification of the 1X vibration observed in the axial direction is due to resonance, as the fan most likely found to be running at speed close to a lightly damped rotor natural frequency (first rigid mode).

It was concluded that, a change in the structure support stiffness is the root cause for this resonance condition, and it was recommended to inspect the fan rotor housing and supports to find out a resolution for the resonance condition in the axial direction and to shift the natural frequency with enough separation margin away from any forcing frequencies (i.e., 1X … etc.).

After site inspection and multiple investigations, the root cause of the change in the structure support stiffness was identified to be because of improper tightening torque during fan installation, which was changed as per OEM recommendations. Same solution was applied on all induced draft fans onsite (10 fans in total). Later, fans showed stable vibration levels for longer operation periods without the need for frequent balancing activities.
Revolutionize Alarm Management: Streamlining Processes with RoRPAic Process Automation (RPA) for Dynamic Attribute Tables
Authors: Al Kalbani F. , Al Abri A.
Published: November 2024

Alarm management is a critical component in various industries, essential for the timely detection and response to system anomalies and failures. The cornerstone of effective alarm management is the comprehensive preparation and maintenance of variable tables that accurately map alarms to their associated attributes. Traditionally, this task relies heavily on manual data entry, which is not only time-consuming but also prone to human error and resource-intensive. To address these challenges, we are introducing an innovative approach that leverages Robotics Process Automation (RPA) to automate the preparation of these variable tables. The integration of RPA into this process offers several significant advantages: enhanced efficiency by drastically reducing the time required for preparation and maintenance, improved accuracy by minimizing human involvement and thereby reducing errors, and optimized resource utilization by freeing up personnel to focus on more strategic and value-added activities. Additionally, RPA provides a scalable solution capable of handling large volumes of data without compromising performance or accuracy. This novel approach not only streamlines the process of alarm management but also sets a new benchmark for how industries can harness advanced technologies to enhance operational efficiency and reliability. By adopting RPA, organizations can achieve higher levels of accuracy, optimize resource utilization, and scale their operations more effectively, ultimately leading to improved overall system performance and resilience. Furthermore, we are planning to replicate the success of RPA in the Control and Automation (C&A) discipline and extend its application to the preparation of other critical deliverables, such as the instrument index, load list, and line list. Our efforts also include making this innovative solution available in the cloud, enabling other engineering design consultants to fully benefit from the efficiencies and improvements RPA offers, facilitating broader access, collaboration, and scalability for enhanced project execution and seamless workflow integration.
A Flexible Digital Approach to Monitor Offshore Chemical Applications on Floating Production Storage & Offloading Units Chemical Application Monitoring
Authors: King J. G. , Shetty S. S. , Smith D. W.
Published: November 2024

Offshore operators often deal with siloed or delayed data in their daily chemical program management. By integrating flexible data systems with an operator's preferred platforms, offshore teams can proactively manage chemical programs, significantly reducing the risks of non-productive time (NPT) or regulatory noncompliance. To begin this approach, stakeholders evaluated the reporting requirements to determine the necessary digital product modules.

Typically, a web-based SaaS chemical reporting application serves as the primary user interface. By collaborating with stakeholder teams, including FPSO integrators, operator subject matter experts, networking, and cybersecurity teams, to identify data sources, instrumentation, networks, and software in use or planned for the FPSO, including connectivity to onshore systems. After gathering and analyzing this information, a solution was proposed which included the required connectivity, telemetry, data movement, persistence, alerting, and reporting. This ensures the optimal management of chemical applications.

This approach was implemented on two FPSOs, establishing best practices for monitoring process temperatures, pressures, and flows using time-series historians. These systems proactively managed chemical inventories, application rates, and lab results, optimizing the utility of chemical programs and providing up-to-date operational data while leveraging the customer's existing infrastructure. The successful integration of offshore data from instrumentation and laboratory tests with onshore SaaS visualization and custom reporting was achieved despite the varied software, processes, and cybersecurity profiles of different operators. This required expertise in industry standards, open protocols, and close collaboration with multiple internal and external teams.

The flexible, modular approach on these projects to digital monitoring of offshore chemical applications on FPSOs has proven effective, regardless of variations in instrumentation, software, and cybersecurity across different organizations. This integrated digital solution marks a significant advancement in chemical program management on FPSO platforms, with the potential to enhance reliability, safety, and efficiency across the industry.
A Dynamic Workflow of Back Pressure Reduction Leading to Well Uptime Maximization
Authors: Al Silwadi B. , Kurokawa S. , Albishr M. , Al Marzooqi K. , Al-Hajeri A.
Published: November 2024

Objectives/Scope

Field XX is a brown field that has suffered from a high pressure sealine system for decades limiting the productivity of oil producers. A multi-disciplinary task force was established with the primary objective of innovating solutions to reduce the sealine pressure and benchmark these solutions versus potential production gain and economic feasibility.

Methods, Procedures, Process

The main challenge that was encountered to reduce the high sealine pressure includes the identification of the root causes As a result, a multi-disciplinary taskforce was developed in which five projects were identified to reduce the back pressure including acceleration of a 24″ between production complexes, offloading production from one complex to another, utilizing wellhead compression solutions, radial pressure reduction through inlet control valve design, and introduction of drag reducing agents. Each of these aspects was validated through nodal analysis, a coupling model, and the dynamic simulation model combined with the economic friendliness of each item.

Results, Observations, Conclusions

A multi-disciplinary task force used brainstorming and innovative workflows to verify five opportunities for reducing back pressure impact. The assessment to evaluate and verify the added value of each opportunity includes:

Novel/Additive Information

This paper is a clear demonstration of collaborative expertise demonstrating innovative mentalities and collectively identifying innovative solutions to a historic production bottleneck. The utilization of subsurface and surface combined solutions has proven to be extraordinarily successful in unlocking hidden barrels of oil with minimum investment requirements. The contents of this paper can be cascaded to multiple brown fields on a global scale to enhance production in an immediate time frame without jeopardizing reservoir health.
Petrophysical Challenges and Impact of Bitumen Quantification in Reservoir Rocks
Authors: Singhal Manu , Al-Abri Ahmed , Jarratt Thomas , Zhan Lang
Published: November 2024

Conventional reservoirs with bitumen pose a challenge to accurately quantify its presence and impact on reservoir producibility. Due to the presence of bitumen in the reservoir, which can be in the form of pore lining, pore fill and/or pore throat blocking, reservoir connected porosity and permeability is impaired. If volume of bitumen is not correctly quantified then hydrocarbon in place, completion decisions, reservoir producibility and ultimate recovery is impacted.

Basic logs often do not have sufficient contrast to differentiate bitumen from hydrocarbon in the reservoir, hence, advanced logs viz. NMR and spectroscopy logs are required to identify bitumen and its quantification. An in-house simultaneous multi-sensor inversion algorithm is developed to quantity lithology and fluid volumes which are then calibrated with available conventional core data.

This paper outlines a workflow to accurately quantity bitumen in the reservoir with the integration of logs and core. Detailed thin sections, core sedimentology, digital rock and petrography work has been integrated with logs to quantify bitumen and assessing its impact on reservoir properties. Moreover, impact of bitumen presence on reservoir producibility is assessed with production data and PLT acquired across the reservoirs of interest. Reservoir properties modelling workflow to build static model is also discussed to generate static model with bitumen variation and thereby assessing its impact on hydrocarbon in place and ultimate recovery.
Enhancing Reservoir Model Agility: Integrating New Drilling and Performance Data into Business Planning - A Case Study
Authors: Al Ali M. Y. , Ebeid M. , Alkhatib M. , Khattak I.
Published: November 2024

Objectives/Scope

This paper tackles the challenges of field development planning and optimization in a green onshore oil field where production data is limited. An agile workflow was employed to enhance the existing reservoir simulation model, preparing it for the selection of the optimal field development plan (FDP) while accounting for uncertainties. Subsequently, the paper reassesses the FDP considering the performance of wells drilled during the execution phase and the necessary updates derived from acquired data.

Methods, Procedures, Process

Through a comprehensive uncertainty analysis, multiple subsurface realizations were generated. A wide range of development scenarios and options were screened considering the uncertainties. Viable scenarios were then economically evaluated, leading to an optimal Field Development Plan (FDP) that not only addresses uncertainty robustly but also minimizes economic risk. The workflow employed was particularly suited to integrate new geological, drilling, and petrophysical data for updating the reservoir geological model. The challenges this workflow addresses include:

Results, Observations, Conclusions

The most robust development concept was chosen and analyzed, taking into account various viable development strategies such as plateau rate, drilling schedule, phasing, water injection timing, and artificial lift timings. A phased development approach was adopted, allowing for the acquisition of necessary data to reduce remaining uncertainties and prevent costly consequences of significant over- or under-capacity. Data obtained in one development phase were assessed and used to potentially update subsequent planned phases. The study revealed that field development could tolerate a delay in either water injection or artificial lift implementation. While it wasn't recommended to delay either at this stage, it's important to note that a potential long lead time in artificial lift implementation or the risk of lower injectivity wouldn't significantly impact field performance or ultimate recovery if contained within a few initial years of production. These findings further underscored the robustness of the proposed development plan.

Novel/Additive Information

Addressing large subsurface uncertainty alongside an extensive array of potential development scenarios necessitated cutting-edge uncertainty analysis and screening workflows to identify the optimal Field Development Plan (FDP). These innovative workflows, tailored for such unique challenges, hold significant promise for application in similar green fields. Detailed descriptions of these workflows will be provided in the paper.

Category (Complete)

056: FIELD DEVELOPMENT: Innovative Oil Development Plans and Case Studies
Post-Frac CT Intervention: An Overview of the Evolution of Practices in Extended Laterals in Unconventional Resources
Authors: Al Mulhim F. A. , Aldubikhi A. S. , Baki S. A.
Published: November 2024

This paper investigates post-frac Coiled Tubing (CT) intervention in extended lateral wells to evaluate the job design and the procedures implemented and how they dictate the evolution of practices, with more experience gained through the execution of many intervention operations.

This paper will be conducting a systemic assessment on the latest improvements in CT intervention practices. In addition, a hindsight review of the evolution of practices will be presented. Following that, the steps undertook to tackle extended laterals for postfrac are revisited and assessed, further exploring the key enablers that allowed that milestone to be achieved repeatedly.

In addition, the paper covers an overview on the evolution of practices in extended laterals as experience in intervening these wells increase. This will include best practices, an overview of the current level of efficiency, enabling technologies, and the new challenges to overcome paving the way forward.

Upon looking at post-frac CT intervention, namely frac plug mill out, an improvement in practices is clearly noted with time. This improvement was enabled using tapered coil tubing string design which improved overall lateral reach, in addition to the use of specialized bottom hole assembly components such as hydraulic extended reach tools to aid in maximizing reach limits overcoming commonly faced issues like lockups and buckling. However, the changes identified new challenges and bottlenecks that require further studying and trialing to finetune the progress of CT operations moving forward.

Preliminary results from the analysis done indicated that in CT milling operations, BHA components like motors and hydraulic extended reach tools are likely to be the new bottlenecks that dictate the progress and the smoothness of operations. A key enabler to overcome the bottlenecks presented and to fully unlock the potential & reach of CT intervention in extended laterals is to effectively work and collaborate with vendors and service providers to ensure tools are designed with a fit-for-purpose objective in mind.

Such overview of the evolution of CT intervention in extended lateral wells will allow operators and service providers to maximize the lateral length of horizontal wells confidently, therefore, increasing the overall reservoir contact. This can all be done with mobile CT units, which will save valuable rig time in addition to being safer and more efficient.
Innovative Multitrip Method for All-Electric Intelligent Multilateral Completions in Extended-Reach Wells
Authors: Fedorchenko E. , Musayev R. , Abramov Y. , Revheim K. , Agu D. , Warden A.
Published: November 2024

The multitrip all-electric multilateral well completion system with applicability also for in-lateral monitoring and control is a groundbreaking approach to well completion that provides both reliable deployment and reservoir management. It incorporates a first-of-its-kind wireless deployment system, for which the experiences and lessons learned by a major service provider and operator throughout the project are reviewed. The application of this tool is not limited to this specific deployment but can be incorporated in multilateral completion designs and deepwater applications. Applicable for even the most challenging environments and well completion designs, this technology is another step forward to achieving electrification of oil and gas well completions.
How Midstream Companies are Enabling CCUS: A Case Study
Authors: Mohammadi A. , Al Balushi B. , Al-Mujaini N.
Published: November 2024

Carbon capture, utilization, and storage (CCUS) is a crucial pillar in the global decarbonization journey. The deployment of CO2 transportation infrastructure is pivotal to enabling successful CCUS value chains. This paper explores how OQ Gas networks (OQGN), Oman's exclusive natural gas transmission network owner and operator, is overcoming various challenges, from technical to commercial to regulatory, to develop Oman's open access, multi-user CO2 pipeline transmission network, linking CO2 emission sources to sinks.

To conceptualize a national CO2 pipeline network, OQGN has followed a robust methodology in determining the CO2 market forecasts across the country, consisting of stakeholder engagements, the release of a CO2 market survey, while also examining significant emitters and respective sinks. A techno-economic analysis of the network was also conducted, as well as assessing viable commercial model options and the strategies and economic regulations needed to futureproof the network. Policies and regulations are crucial to accelerating CCUS uptake as they provide clarity and assurances to investors, lenders, and societies. In addition, OQGN is providing input to Oman's Policy Maker on CO2 transport regulations to define robust legal frameworks that ensure the health and safety of people and the environment while concurrently aiming to ease regulatory burdens.

Based on the CCUS market projections, OQGN anticipates three CCUS ecosystems to be established in Oman: a Northern Ecosystem, a Central Ecosystem and a Southern Ecosystem; the ecosystems connect major emitters mainly located in coastal industrial areas to utilization sites further inland. The price cap model is concluded to be the most optimum due to its flexibility and adaptability. Moreover, futureproofing the network can be ensured through oversizing as well as through specific economic regulations or government support.

This paper provides a case study of how a midstream company is growing its portfolio to transport a new commodity in a nascent sector, leveraging its expertise to address key challenges, and ultimately enabling a low carbon economy.
Advanced Reservoir Permeability Distribution Prediction: A Discrete Cosine Transform-Based History Matching Workflow
Authors: Hamady Abdelrafae El , Gharieb Amr , Diaz Alberto , Bogachev Kirill , Eydinov Dmitry
Published: November 2024

Reliable reservoir simulation is essential for effective reservoir management in the petroleum industry, as it enables engineers to make well-informed decisions on production strategies and resource allocation. However, accurately calibrating reservoir models to match observed field data remains a significant challenge. This difficulty primarily arises from the inherent uncertainties in key parameters such as permeability and porosity, which are crucial for predicting reservoir behavior and performance.

Traditional history matching methods, which involve adjusting reservoir parameters to align simulated models with observed production data, often require substantial computational resources and can produce multiple solutions that do not necessarily reflect the true reservoir conditions. These methods typically rely on extensive trial and error, leading to models lacking geological accuracy and realism. To overcome these limitations, there is increasing interest in applying advanced mathematical techniques and intelligent algorithms that offer more efficient, precise, and geologically consistent solutions.

This paper introduces a novel workflow for enhancing the accuracy and efficiency of history matching in reservoir simulations using real-field data. The approach addresses uncertainties in permeability and porosity relationships, particularly when modifying relative permeability (RP) might conflict with lab-measured data. A multi-objective Differential Evolution algorithm is employed to tackle these uncertainties, reduce randomness, and identify optimal solutions along the Pareto front. This process is followed by Principal Component Analysis (PCA), used for clustering all optimal solutions along the Pareto front, leading to several clusters of well-matched oil/water (O/W) models.

Finally, the Discrete Cosine Transform (DCT) is applied to capture key reservoir features and expedite optimization. By converting the permeability array into the frequency domain, the DCT achieves significant data compression while preserving essential geological characteristics, thereby reducing data complexity and enhancing the efficiency and accuracy of history matching. The methodology culminates in integrating the matched O/W models with bottom-hole pressure (BHP) data, resulting in comprehensive O/W/BHP matched models. This framework minimizes uncertainties and provides an efficient, systematic approach for improving history matching in complex reservoir simulations.
Enhancing Concentrated Solar Power (CSP) with Geothermal Energy: A Geothermal Battery Approach
Authors: Agson-Gani P. H. , Roshan H. , Regenauer-Lieb K. , Rahman S.
Published: November 2024

This study presents an innovative approach to integrating concentrated solar power (CSP) with ultra-high-temperature underground thermal energy storage (UTES) as a geothermal battery for power generation. UHT-UTES is a combination of a CSP plant and a Geothermal Battery. The system consists of two main wells, a Brayton cycle and an Organic Rankine Cycle (ORC), which are used to convert the heat from the CSP into electricity. The ORC is used to extract heat from the CSP and the ORC is used to extract heat. The analytical solution is based on a one-dimensional (1D) approach to calculate the heat injection cycle in the battery, employing a one-dimensional approach. The numerical results show that the system can maintain more than 94% of its initial output capacity after 30 years, demonstrating the potential of this hybrid approach to enhance the longevity and reliability of renewable energy systems. The study further shows that the effectiveness of the UHT-UTES system depends on site-specific parameters, such as Direct Normal Irradiance (DNI) and subsurface temperatures.
Corrosion Inhibitor Characterization with Rewarding Laboratory Tests for Oil Pipelines
Authors: Hirano S. , Mizukami H. , Sei T. , Yasui A. , Sunaba T.
Published: November 2024

Oil-soluble and water-dispersible corrosion inhibitors are normally used to mitigate corrosion in pipelines operating. The performance of corrosion inhibitors has been described mainly in terms of the adsorption of surfactants on metal surfaces. The persistence of the adsorbed film is primarily evaluated by corrosion tests. That is why the corrosion tests are the main technique for the inhibitor evaluation. However, the partition of the surfactant from oil to water and its dispersion in water should also significantly affect the corrosion inhibition mechanism. We propose the evaluation methods and show examples of quality evaluation. The corrosion inhibitor was characterized with relatively familiar instruments at the oil company's laboratory. Those measurement such as average molecular weight, TOC, Zeta potential and particle size were conducted among the qualification of corrosion inhibitors. As a result, the amount of dispersion, the stability of dispersion and the some component could be evaluated even for commercial products in more detail. Those data must be useful to assess the quality stability and will contribute the inhibitor selection.
Mathematical Modelling of Co-Current and Counter-Current Spontaneous Imbibition into a 2D Matrix Block Accounting for Boundary Conditions, Gravity and Viscous Coupling
Authors: Qiao Y. , Andersen P. Ø.
Published: November 2024

Spontaneous imbibition is a mechanism where capillary forces drive multiphase fluid flow such that non-wetting fluid is displaced by wetting fluid. This is relevant in naturally fractured reservoirs where matrix blocks are disconnected by a highly conductive fracture network. Traditional modeling approaches tend to rely on Darcy's law with relative permeabilities. However, many experimental works have shown features such as reduced mobility or delayed onset of imbibition that are not captured by these standard approaches but can be explained by viscous coupling (which causes more flow resistance during counter-current than co-current flow). These terms arise naturally in the fundamental momentum equations describing fluid flow. In a dynamic setting where flow regimes may change locally and with time there may not be a simple way of upscaling observed laboratory data. In this work we therefore explore imbibition in a setting where water and oil cover a 2D matrix block with some or all surfaces open, including mechanisms of viscous coupling and different flow regimes due to various boundary conditions of the system. The input parameters are based on experimentally matched data where the non-standard terms are accurately and uniquely quantified. The code is validated against commercial software for cases where the non-standard terms are negligible. Imbibition rate increases when opening more area to water or oil. For a given open area, there is an optimal area fraction open to oil that minimizes the recovery time long term. At early time recovery primarily increases with the area open to water. Viscous coupling increases the imbibition time when more of the production is counter-current, i.e. a higher fraction is exposed to water. The generalized model with a specific term accounting for viscous coupling produces similar behavior as conventional modeling for cases dominated by co-current flow because of applying relative permeabilities measured under such conditions. Increasing water viscosity appeared to reduce imbibition rate more for co-current dominated cases than counter-current dominated cases. For cases with same open area and same areas exposed to water and oil, a more concentrated distribution of oil at the boundaries is unfavorable for oil recovery, compared to a more even distribution.
Seismic Reservoir Characterization Workflow with a Fast Post-Processing Update to Handle the Unfavorable Seismic Conditions of the Onshore Middle East Carbonates
Authors: Baturin Mikhail , Lombardi Morgane , Hamdi Mahmood Hamdi Hassan , Ahmed Jahan Zeb , Ben Maroof Muneera Saleh Salem , Pramudyo Yuni Budi
Published: November 2024

This paper describes the joint acoustic-porosity seismic inversion study performed on the seismic data from a field in UAE anticipated by a seismic reservoir characterization feasibility study with an aim to control the quality of the input dataset and its fit for the declared aim as well as to define the most efficient seismic inversion method and updated with a quick amplitude correction to compensate for the unwanted seismic artefacts.

The main challenges were related to the seismic quality issues proceeding from the onshore sand dunes constrained acquisition environment and the bandwidth limitations due to the carbonate reservoir domain.

Quality control of the input seismic data revealed a necessity for the correction of the seismic amplitude suffering of surface-related effects in an efficient yet a timely manner due to the operational time constraints. The corresponding procedures were defined and applied. Yet such approach is potentially associated with the risks to the preservation of the true seismic amplitudes and thus required detailed quality controls to ensure a geologically meaningful output.
Cost Effective Remote Magnetic Inspection of Pipelines. Case Study
Authors: Ablaev Anton , Zozulya Andrey
Published: November 2024

This article presents a technology for Remote Magnetic Inspections (RMI) of pipelines based on the Villari effect. The technology consists of a measuring device, a magnetic field and a software package. The paper presents general description of technology, some procedure and recommendation for technology method, and it is advantages comparison to other methods. The results of the pilot jobs showed a correlation with conventional inspection of the pipeline after excavation at the few pits. Remote magnetic inspection is faster and cheaper than other conventional methods.

The company has developed a new remote magnetic inspection tool with GNSS sensor that allow to detect anomalies with better accuracy, also company develop new software that use artificial intelligence to process the data faster and with better results. Several pilot works were carried out, which showed the correlation of the data with direct measurements of pipeline after excavation of the pit.

Diagnostics proceed as follows. The operator walks along the pipe and measures the change of the magnetic field in places where there are defects in the pipeline, the magnetic field is distorted, and the defects and anomalies can be determined.

All data is registered at the software and processed using artificial intelligence. The customer receives a final report with a map of anomalies, each anomaly categorized by 3 categories (normal, critical and supercritical). After that client prioritize pipeline fixing activity.

This technology can be used where in-line inspection cannot be carried out; in addition, this technology is several times cheaper than in-pipe inspection, and it does not require preparation and shutdown of the pipeline. New equipment allows pipeline inspections to be carried out faster (up to 50 km per day when using drones), cheaper and without stopping pipelines.
Static and Dynamic Reservoir Rock Typing of Highly Heterogeneous Fluvial Delta Marine Sands Deposited in Mesopotamian Basin
Authors: Akbi H. , Aidarbayev S. , Qiu M. , Al-Wadi A.
Published: November 2024

Geological reservoir study is a crucial step to understand the reservoir properties that drive hydrocarbon flow behavior as part of reservoir life cycle. Among them, sandstone reservoirs have a lot of challenges when the data is scarce to integrate and link between the different disciplines. Nevertheless, a collaboration between geologists and petrophysicists paved a way to systematically fill data gaps which resulted in understanding of petrophysical distributions and the degree of heterogeneity.

The methodology starts with a principal component analysis of logs to identify useful data for prediction. It uses the core description, XRD and the thin section to reveal the major diagenetic events and critical mineralogy. Simultaneously, this workflow calculates the hydraulic flow units (HFU) based on core data (K, Phi) flow zone indicators, discrete rock types and global hydraulic elements. The stratigraphically modified Lorenz plot is used to identify storage capacity and flow capacity to detect high permeability flags. The static characteristics are linked with the dynamic HFUs to decipher cloud boundaries that have unique geological and fluid-flow parameters.

The core description shows the following depo-zones within a fluvial delta marine sand: delta front mouth bar, distributary channels, distributary mouth bar and prodelta rock types. The thin section indicates the influence of kaolinite and cementation in some reservoir intervals. This knowledge was incorporated to calculate permeability with a higher precision (R2= 0.9 – 0.98) in comparison with core permeability. The FZI method showed seven rock types. Stratigraphically modified Lorenz plot used pore-throat radius, storage capacity, flow capacity, and reservoir speed characteristics. This technique resulted in 5 to 8 hydraulic flow units that divided the Poro-Perm cloud into barrier, baffle, normal flow, and super flow based on slope changes. The distributary channel has the best rock type, while the delta front mouth bar and distributary mouth bar have the medium to the worst rock types while the prodelta has the poorest rock types.

Through the integration of sedimentological and petrophysical data, this workflow enables the characterization of highly heterogeneous sandstone reservoirs. Its result improves the prediction of rock type, permeability, and water saturation properties in geological models. Furthermore, it optimizes the number of RRTs to reduce uncertainty resulting in the creation of a robust static model and a better prediction during the implementation of the dynamic model.
Automated Production Allocation & Deferment Calculation Using Integrated Digital Oil Field Realtime Surveillance Data and Physics Based Well-Models
Authors: Al Jabri Kawthe , Al Hinai Ahme , More Anand Raosahe , Kumar Nitis , Kumar Suresh
Published: November 2024

Objectives/Scope

Automate Production Allocation and Deferment calculation workflow using Integrated Digital Oil Field (DOF) realtime surveillance data and physics based well models benefitting ARA Petroleum's Production Optimization team by improving Field Allocation factor, improving DOF system performance, reduce production losses caused due to delayed & errored manual calculations processes and integration of this data with Business Intelligence (BI) and cross domain applications. Achieve complete digital transformation of the process.

Methods, Procedures, Process

DOF team developed physics-based models for all wells (ESP, PCP and Naturally flowing types) using PVT, Completion, Artificial lift system data and integrated these models with DOF Real time data (RTD) for automatic estimation of Well rates. Using Well Management System (WMS) and Real time data of custody transfer meter, calculation of Field factors was automated to generate Allocated rates automatically. The process was coupled with daily well flowing hours to estimate deferment production due to well downtime, trips. This daily automatic workflow task is scheduled on Production server for faster and accurate data generation of daily and average allocated rates. This paper describes in detail the workflow used for implementation of the process.

Results, Observations, Conclusions

Since implementation of the Automatic Allocation and Deferment workflow, it has maintained daily and average allocated rates for 80+ ESP, PCP and Naturally flowing wells in the field. Application of the workflow has resulted in improved ability to track production with targets. Corrected Allocated rates w.r.t optimized well parameters is an added advantage of this workflow rather than using constant rates between two valid well-tests which was an outdated traditional approach. This allocated rates data has helped ARA petroleum engineers to accurately; compare production with target plan, optimize well/reservoir performance, perform material balance and/or reservoir history matching, run production forecasting, perform hydrocarbon accounting, estimate produced reserves, take reservoir management decisions, implement EOR, plan well intervention etc. Below are the key results by successful implementation of the workflow:

The input and output database of this workflow is successfully integrated with BI and other cross domain applications for quick and efficient analysis.

Novel/Additive Information

The utilization of real time surveillance data and Well models have proven to be an efficient way to maintain accurate well and/or field wise allocated production rates and deferment volumes automatically. Well and Region wise reports are easy to prepare with this digital data source, to track Production performance for ARA petroleum Assets.
Enhancing Offshore Operations: Secure Data Sharing for Automatic Oil Spill Detection
Authors: Røstad J. , Prytz G.
Published: November 2024

Early and reliable automatic Oil Spill Detection is vital. The earlier a spill is detected, the less chance it has of causing an environmental disaster. As the popularity of Oil Spill Detection has grown, information integrity and cybersecurity are becoming increasingly important for safe and unbiased reporting. Secure data sharing fosters trust and collaboration, facilitating transparent decision-making.

Automatic Oil Spill Detection is done by physics-based image processing from X-band radars streams. Verification and volume estimation can be achieved from added infrared cameras.

To make sure the detection is un-tampered, modern information security systems following ISO 27001 procedures are needed. By creating a secure end-to-end pathway, information can flow from the physical detection through the monitoring software and to the onshore stakeholders - in Oil Spill Detection context: the operator and environmental authority as the regulator. Only then all parties can be sure of having the same information at the same time.

Major oil operators and offshore vessels have for years used remote sensing instrumentation critical for their operation. Locked in data has been a major issue for operational excellence improving revenue and HSEQ. Adding the most modern technology within IoT, cloud and information security has made data easily available with improved offshore operations in multiple areas. A faster oil spill response is achieved since alarms earlier reach everyone involved in surveillance and recovery teams. Waiting on weather is greatly reduced by having access to the right data. Some operations have weather limits where accurate data removes doubt. Other operations experience problems that can be mitigated by enhancing the understanding of the sea state. Having multiple users of the same data also results in a reduced need for various measurement systems, reducing carbon footprint and conducting a more sustainable operation. It is also a critical tool in building trust to authorities through unbiased reporting and transparency.

Remote sensing techniques have proven their popularity. This paper demonstrates how modern information technology helps by adding more value to tested and proven sensors and systems within Offshore Marine Operations.
First Middle East Single-Trip Intelligent Completion Installation with Both an Electrical Submersible Pump (ESP) and a Downhole Wet-Mate.
Authors: AlRaml Haida , Ufondu Kene O , Al Haj Ahme , Almasri Abdulrakeeb
Published: November 2024

Intelligent completions in multizone wells require hydraulic control lines tied back to surface. To reduce capital expenditure (CAPEX) and complexity related to workovers to replace ESPs, a downhole wet mate was implemented in those intelligent completions.

This paper discusses further optimizations made to facilitate and simplify the deployment with only one trip. This improvement to achieve a single trip has significant positive impacts on health, safety, and environment (HSE), formation exposure, deployment complexity, and CAPEX.

The innovative single-trip intelligent completion system with ESP and downhole wet-mate eliminates the need for the ICVs and zonal feedthrough isolation packers to be run on drill pipe. All the completion components are installed in one single trip. The lower completion zonal feed-through isolation packers are set through the packer setting control line via a surface hydraulic pump, followed by setting the ESP packer by applying tubing pressure against a slickline plug.

The single-trip intelligent completion with ESP and downhole wet-mate was successfully deployed in the Middle East. This installation saved 27 hours of rig time.The complexity of the installation and HSE risks were eliminated by:Eliminating the requirement to pull the drill pipe with control lines and the large clamps.Isolating the formation during tubing hanger landingAll well objectives were met.Deployed all equipment successfully on a single trip.Confirmed the integrity of the packers.Successfully functioning of the ICVs.

This paper will discuss the novel aspects of implementing a single-trip intelligent completion with ESP and downhole wet-mate through the utilization of control-line set zonal feed-through isolation packers.
New Guideline for Corrosion Under Insulation
Authors: Wiggen F. , Jessen J. V. , Rivero A. R. , Aanesen R.
Published: November 2024

Corrosion Under Insulation (CUI) is considered one of the major threats to integrity of process facilities. The Net Zero Technology Centre (UK) estimates that CUI now contribute to over 20% of the major oil and gas accidents reported within the EU since 1984 /1/ and regulators in the North Sea report that 50% of the reported hydrocarbon leaks is caused by CUI /2/. Earlier industry publications /3/ suggest that CUI accounts for more than 40% of a plant's piping maintenance expenditure and 10% of the total maintenance budget.

A Joint Industry Project (JIP) consisting of oil & gas operators in the North Sea and DNV resulted in 2019 in a new recommended practice, DNV-RP-G109 "Risk Based Management of Corrosion Under Insulation" ©/4/ where a new qualitative risk methodology was introduced to the industry. This methodology is based on assessment of 4 barriers, the material barrier, the coating barrier, the water wetting barrier and the design barrier/5/. The methodology is now referred to as a preferred methodology to manage CUI by legislators in Norway /6/ and are taken into use in several other countries as well.

This paper will address the forthcoming update of DNV-RP-G109 related to CUI in corrosion resistant alloys and the use of humidity sensors to assess probability of water wetting in the insulation.