bluuebunny/crossref_metadata_2025 huggingface dataset:
The Integrity Evaluation of Geological Body for CCUS Technology Based on Microseismic Monitoring Technology
Authors: Xu Jianguo , Zhou Yuchi , Pan Ruosheng , Huang Tianjie , Liu Bo , Gao Qiang , Liu Yutong
Published: November 2024

The integrity of geological bodies is a fundamental condition for the long-term and highly efficient storage of CO2. Geological body integrity of CO2 injection areas is indirectly judged by such conventional methods as primarily assessing contamination degree of water and gas in shallow layers, as well as changes in carbon flux in soil and the atmosphere. Direct identification methods for leakage pathways of inter-layers and faults are relatively limited. This paper puts forward a evaluation method for geological body integrity of Carbon Dioxide Capture, Utilization, and Storage (CCUS) based on microseismic monitoring technology.

This technique utilizes downhole geophones to collect data of target intervals, and employs perforation signals of adjacent wells for polarization analysis of P-waves. Then we correct the direction of the downhole geophones with three-components, optimize the velocity model. Subsequently, microseismic signals generated during the CO2 flooding process are located by adopting the method of multi-wave joint orientation technology. By analyzing the sequences and spread conditions of microseismic events, the spread distribution of CO2 flooding front is grasped, and the channeling condition of inter-layers is determined. This technology has been applied in the CO2 flooding test areas in Jilin Oilfield, which is the largest CCUS demonstration area in PetroChina. It is designed with 12-stage geophones, with a longitudinal monitoring range covering the top and bottom boundaries of the oil reservoir. The lateral monitoring range is approximately 1500m, and the monitoring period is 60 days, covering two complete water-gas alternating injection cycles, each cycle lasting 30 days.

By statistically analyzing the time sequence and magnitude attributes of microseismic events, a total of 539 effective microseismic events have been acquired, with magnitudes ranging from -3.13 to -0.906. In the vertical direction, the locations of microseismic events are concentrated in producing reservoir areas, with no continuous microseismic events occurring across the cover layer, indicating good integrity performance of the formation.

The successful application of this technology effectively evaluates the geological integrity of CCUS systems, which is of significant importance in guiding the subsequent location selection for CCUS/CCS technologies. Additionally, it provides effective data support for understanding the flow patterns of CO2 injected into the formation, and also the basis for the mapping of subsequent development plans.
A Breakthrough Sulfur Dust & Granulate Cleaning by UAE Made Robot
Authors: Alkhoujah K. , Al Ali A. , Al Ghassani M. , Al Marzooqi S. , Al Ameri M. , Al Muharrami F. , Karki H.
Published: November 2024

This paper will present a successful enhancement within ADNOC Sour Gas. Shah Gas development field (SGDF) consists of three main areas which are well pads and gas gathering, gas processing plant and Sulfur station. One of the major challenges at the Sulfur station is the management of Sulfur dust and granules around the granulators area. A dedicated working force is required to conduct cleaning activities to ensure smooth operations and avoid unanticipated operation interruption. Around 40 cleaners are required for cleaning activities for a period of 3-hours on daily basis in each shift. This paper will present the details and capabilities of the robot and its specification and the results of operating it at ADNOC Sour Gas Sulfur Station. Additionally, this paper will review some of the existing solutions and practices for Sulfur dust management in other Sulfur producing facilities around the world, such as Canada, Kazakhstan, and Saudi Arabia, and compare their effectiveness and efficiency with the proposed robot system.
Subsea Well Troubleshooting through flow Assurance Dynamic Simulation
Authors: Gioja G. , Montini M. , Tiozzo A.
Published: November 2024

During the commissioning of a gas well integrated into a cluster system, substantial quantities of liquids accumulated within the flowline, resulting from various operational anomalies. This accumulation presented a significant technical challenge during the well restart phase, primarily due to the volumetric surge of liquids in the Slug Catcher and the limitations of topside process liquid management systems. The complexity of this issue necessitated a thorough investigation and the development of a robust solution to displace the accumulated liquids and ensure an effective well restart.

To address this challenge, a series of comprehensive studies and analyses were undertaken. The core of this troubleshooting effort was the deployment of a model in a sophisticated flow assurance simulation tool. A multiphase dynamic simulator (MDS) was employed to simulate the liquid displacement process and evaluate the restart behavior of the well under different operational scenarios. This approach facilitated the identification of critical operational parameters and constraints, enabling the development of an effective and reliable operational procedure.

The subsequent sections of this paper detail the methodology employed, the insights gained from the simulation studies, and the formulation of the operational procedures designed to mitigate the issues associated with liquid accumulation during well restart. This study highlights the critical role of advanced simulation tools in addressing complex flow assurance challenges in hydrocarbon production systems.
An Efficient and Integrated Biomass to Sustainable Low-Carbon Bio-Ethylene Process
Authors: Raizada Abhishek , Sarin Yogendra
Published: November 2024

Various types of biomass such as agriculture waste/residues and sustainably sourced woody biomass can be utilized to produce circular, low carbon biofuels such as SAF/gasoline/methanol and Diesel for decarbonization of transport, as well as biobased chemicals like Ethylene Oxide (EO), Polyethylene and others. The entire process for conversion of biomass to biofuels and renewable chemicals presents a highly efficient, integrated and a low carbon sustainable alternative to fossil fuels as a solution urgently needed to combat climate change and for meeting the Net Zero Goals by 2050. The integrated process backed by trade secrets and extensive IP involves i) conversion of biomass into bioethanol intermediate via Petron's highly efficient and commercially demonstrated Cellulosic Ethanol G2.0 technology, and ii) dehydration (water removal) of bioethanol into high purity bio-ethylene. The ethylene produced is then purified upto the required grades depending on the downstream applications.

The biomass feedstock undergoes efficient pretreatment and is converted into constituent sugars via action of enzymes followed by fermentation into beer (alcohol) with high efficiency and yields. The beer is then purified to produce the required quality of ethanol which can be directly fed into Petron's proprietary Ethanol to Ethylene (EtE) process. The non-converted process residues are used as renewable fuel for green energy production. The bioethanol is dehydrated over a proprietary catalyst to produce high quality ethylene used for plastics, chemical and biofuel production. The water produced in the reaction is fully recycled back into the process requiring minimum freshwater and effluent generation.

This paper presents a low cost, efficient and integrated biorefinery concept for non-food biomass crops and waste biomass conversion into low carbon bio ethylene - the foundation of the global chemical industry for biofuels, plastics and bio-based chemicals production.

These biorefineries efficiently utilize either separately or a combination of low grade biomass crops (such as non-edible corn) and/or Cellulosic Biomass waste as feedstocks to produce multiple products such as High Protein Animal Nutrition Feed and Corn Oil (in case of non-edible biomass corn feedstock)ONLY the waste starch and fiber residues converted into low carbon EthanolBiogenic CO2 produced during ethanol fermentation is of high purity and can be used for multiple applicationsThe bioethanol once produced becomes a platform for production of BIOETHYLENE - the heart of the chemical industry – which can be converted further into biofuels such as Sustainable Aviation Fuel (SAF) as well as downstream renewable chemicals
Conquering Challenges: A Case Study of Successful Project Execution
Authors: Sarmah Suranjana , Rajak Nitesh Kumar
Published: November 2024

Oil India Limited's ambitious 30MW Gas Engine based power plant project flagged off at Duliajan, Assam, India, in January 2021. The project site was in one of the remotest corners of North-East India, where adverse climatic conditions, specifically heavy and extended monsoon, and logistical challenges inherently delays constructional activities. The challenges in this project increased manifold as it necessitated transportation of high tonnage equipment from Europe to the site, traversing international seas and thousands of km on road, at a time when the world was reeling under the Covid 19 pandemic and geo-political disturbances arising out of Russia Ukraine conflict. Apart from above, the project, being an extension within an existing power plant, was essentially brown field in nature and to carry out all the construction work with minimum hindrance to the running plants was one of the pre-requisites. Limited maneuverability, water logging issues, unchartered ground condition, need for dismantling of existing structures inside restricted industrial area were few of the many on ground hindrances encountered.

This paper presents a case study of remarkable execution of a high capex brownfield project of approximately $23 million amidst unprecedented challenges in the backdrop of COVID-19 pandemic and geopolitical tensions stemming out of the Russia-Ukraine conflict, in one of the remotest corners of Northeast India. Despite multifaceted adversities, the project stands as a testament to resilience and commitment, having been executed without time and cost overruns. This paper carefully examines and analyses the strategic decisions made to overcome various challenges encountered during different stages of project execution. Best practices that were followed from concept till commissioning of the project that had helped achieving the success are also the highlights of this paper.
Lithium Extraction from Produced Water using Lithium Aluminum Layered Double Hydroxide Chloride Sorbent
Authors: Alshammari Salem , Sangaru Shiv Shankar , Saleem Hussain , Ayirala Subhash
Published: November 2024

Lithium-ion batteries (LIB) are crucial components for renewable energy generation and storage technologies, making lithium an essential mineral due to its irreplaceable role in LIB because of its unique physiochemical properties. While lithium is traditionally extracted from solid mineral deposits or Salar brines in the lithium triangle of South America, alternative sources such as produced water from oil and gas reservoirs offer a promising yet underutilized opportunity. Nevertheless, produced water from oil and gas reservoirs contains low lithium levels but can be enriched through desalination. This approach concentrates lithium and generates fresh water that can be utilized for various upstream oil and gas applications, including improved oil recovery, formulating fracking fluids and oil desalting, along with other potential uses like irrigation. In this study, we analyzed the lithium concentration in produced water desalination reject, finding it to be 60 ppm amid a concentrated brine matrix with a total dissolved solids (TDS) of approximately 290,000 ppm. We synthesized a selective lithium aluminum layered double hydroxide chloride (LADH-Cl) sorbent to effectively capture lithium at low levels. The sorbent was characterized using powder X-ray diffraction (PXRD), thermogravimetric analysis (TGA), and inductively coupled plasma-atomic emission spectroscopy (ICP-AES), confirming its successful synthesis. When applied to real-produced water desalination reject samples, the LADH-Cl sorbent reduced lithium concentration from 60 ppm to 21 ppm using just 51.2 mg of sorbent with 20 g of brine. This work highlights the potential of LADH-Cl as an effective sorbent for lithium extraction from produced water, offering a dual benefit of waste brine utilization and valuable lithium recovery.
Review of CO2 Specifications in Novel Industrial CCS Transportation and Storage Hubs
Authors: Yazdanpanah M. , Galliot L. , Perrin S. , Moulie G , Raurich Sara
Published: November 2024

Carbon Capture and Storage (CCS) is considered as one of the major industrial solutions to enable the energy transition. This technology permits to reduce footprint of current carbon intensive industries on the short and medium-term and can be a long-term solution for hard to abate carbon emission sectors. Even if CO2 transportation and storage has been deployed for a few decades, as in Enhanced Oil Recovery applications or for food/medical CO2 applications, CCS sets novel challenges as it implies the development of widespread transportation and storage hubs with multiple CO2 sources coming from different industries.

CO2 specification becomes one of the major elements when establishing a CCS chain and necessitate cross discipline efforts covering among other: design requirements (process, flow assurance, thermodynamics), system integrity (corrosion), Health Safety and Environment (HSE), and reservoir, delineating the capture and conditioning facilities to be considered by the source plants. CO2 specification is highly impacted by the transportation mode: ship transportation requires a purity of about 99.5% CO2, while pipeline transportation can allow purity as low as 96% CO2. Moreover, some impurities, such as H2S, NOx, SOx, even at ppm levels, may trigger a set of corrosion mechanism with the risk of impairing the overall integrity of the system.

Establishing a CO2 specification for a CCS chain is complex, requiring anticipating (i) the CO2 sources characteristics (ii) the chain characteristics and its operating conditions (iii) the potential impact of impurities in order to establish the best compromise between impurities maximum allowable concentration versus safe CCS chain with optimized design, operations and costs.
Experimental Analysis of Geochemical Changes Caused by CO2 Injection: A Study of Lithuanian Saline Aquifers
Authors: Malik Shruti , Khan Muhammad Saad , Pal Mayur , Gomari Sina Rezaei , Rahman Mohammad Azizur , Al-Shalabi Emad W.
Published: November 2024

The successful implementation of long-term carbon dioxide (CO2) storage in the subsurface requires an understanding of the CO2-brine- rock interaction, which tends to affect the petrophysical properties of the subsurface. This work evaluates the suitability of Lithuania's Baltic basin deep saline aquifers for long-term storage of CO2 by examining the geochemical behavior of CO2 when interacting with formation water and rock minerals. The Lithuanian reservoirs are composed of sandstones with quartz as the dominant mineral and minor traces of clays. These aquifers have shown potential for CO2 storage in terms of their depth and capacity. In the present work, the coreflooding apparatus was utilized to inject CO2 into rock samples and perform a series of experiments. Thes experiments investigated the impact of CO2 injection on rock samples with varying permeability and porosity. Initially, core samples were saturated with brine solutions representing Lithuania's saline aquifers’ salinity. Subsequently, saturated samples were placed in core holder, and brine injection was carried out to restore reservoir conditions. Following this, liquid CO2 was injected into rock samples. Impact of salinity, injection rates, and pressure effects were investigated. CO2 injection modeling was also performed to compare consistency of experimental results. The study measured the permeability of rock samples before and after CO2 injection at different brine injection rates (0.1, 0.3, 0.5, 0.9, and 1.5 mL/min). The results showed a drop in permeability following CO2 injection, which might be attributed to factors such as mineral alteration and salt precipitation, particularly at injection locations. This effect is consistent with findings from CO2 injection models over a 10-year period and observation over a 100-year period. The CO2 injection simulation modeling showed that significant changes in the formation's pH and porosity occurred near the injection site, while these parameters remained relatively constant farther from the injection site. Additionally, the low reactivity of quartz with CO2 suggested that negligible mineralogical changes were observed. This work highlights the importance of understanding the complex CO2-brine-rock interaction for safe gas storage in Lithuanian saline aquifers and also addresses the research gap in literature by providing experimental data in an area lacking such analysis. The present work emphasizes the need to enhance the research for long-term practical storage of CO2 in subsurface reservoirs.
Prognosis on Potential Drilling and Well Integrity Risks Associated with Developing KSA's Geothermal Resources
Authors: Bukahmseen R. , Birinci B. , Merey G.
Published: November 2024

Efforts focusing on developing geothermal energy in the Kingdom of Saudi Arabia are increasing and drilling operations of geothermal wells are being prepared for. This paper will provide an overview of geothermal energy resources in the Kingdom and an analysis of the potential drilling and well integrity risks that could be faced while developing geothermal resources in the Kingdom with a focus on medium and low-enthalpy geothermal systems. The paper uses drilling data obtained from a massive drilling campaign of geothermal wells and applies the experience gained and lessons learned from this drilling campaign in the prognosis for potential drilling and well integrity risks of drilling geothermal wells in the Kingdom of Saudi Arabia. It will also provide a literature review on the available geothermal resources in the Kingdom of Saudi Arabia, with a focus on medium and low enthalpy geothermal systems, and classify such resources geographically and in terms of economic feasibility and possible geothermal energy utilization and venues of applications. The study demonstrated the availability of vast geothermal energy resources in the Kingdom of Saudi Arabia. Such resources are classified into three main categories. First and most economically feasible to be developed are the high enthalpy geothermal energy resources which are present in radiogenic granites in the Arabian Shield rocks with a total area of 161,467 sq. km. The high heat flow in this system is associated with the radioactive decay of some radioactive minerals (Uranium, Thorium, and Potassium) existing within the granites. Another high enthalpy geothermal system in the Kingdom is the volcanic rocks (Harrats) within the Arabian Shield with a total area of 90,000 sq. Km. Some Harrats were found to be associated with dike intrusion and magma chamber appearing at about 8 km below the Harrat (Lunayyir). Hot springs in the western coast are identified as medium enthalpy geothermal systems and Clastic deposits are classified as low enthalpy geothermal systems available across the country. Main identified drilling risks are lost circulations cement placement. Other important factors affecting the well integrity are mainly casing selection, well design, and pump selection. The study concludes that considering the vast and geographically diversified geothermal resources in the Kingdom and with careful consideration of the drilling and well integrity risks associated with geothermal wells, the Kingdom is set to start an interesting and successful journey in developing its geothermal resources. This paper will be an important reference for developing geothermal resources in the Kingdom of Saudi Arabia in terms of drilling-associated risks and recommended mitigation practices. It will also provide an overview of the horizons for developing geothermal resources in the Kingdom of Saudi Arabia.
Magnetic Ranging Technology for Drilling Operations
Authors: Bahri Salim Al , Musallami Ahmed Al , Nicholas Greenwell
Published: November 2024

Steam-Assisted Gravity Drainage (SAGD) represents a highly effective and innovative approach for enhancing oil production efficiency in Oman, particularly in the context of well-to-well injection techniques. As an advanced method of enhanced oil recovery, SAGD is specifically tailored for the extraction of heavy crude oil and bitumen, which are prevalent in certain regions of Oman.

Occidental of Oman, already a leader in reservoir steam flood technology, was interested in conducting a horizontal SAGD pilot project in Oman. This technology builds upon traditional steam stimulation methods but introduces a more sophisticated mechanism that involves the strategic drilling of two horizontal wells into the oil reservoir.

In this configuration, one horizontal well is drilled a few meters true vertical depth (TVD) above the other horizontal, creating a unique system that facilitates the efficient transfer of heat and oil. The upper well is utilized for the injection of steam, which serves to heat the surrounding oil reservoir and requires a perforated liner to be installed in the horizontal section. When steam is injected, the heating process significantly reduces the viscosity of the heavy crude oil, allowing it to flow more freely. As the oil becomes less viscous, it can then gravitate downwards into the lower well, where it is subsequently extracted for processing.

The implementation of SAGD in Oman not only promises to increase production rates, but also enhances the overall efficiency of resource extraction. By optimizing the use of steam and leveraging the natural gravitational forces within the reservoir, SAGD minimizes the energy required for oil recovery, thereby promoting more sustainable practices in the oil industry. Furthermore, this technology aligns with Oman's broader goals of maximizing its hydrocarbon resources while ensuring environmental stewardship. As such, SAGD stands out as a pivotal technology that could significantly transform Oman's oil production landscape, driving both economic growth and technological advancement in the region.

Occidental Oman: Top Independent Oil Producer in Oman

Oxy Oman is a wholly owned subsidiary of Occidental (Oxy), an international oil and gas exploration and production company. Oxy has been producing in Oman for 40 years, where it has steadily increased production and reserves and is honored to partner with the Government of Oman. Today, Oxy is the largest independent oil producer operating in the country, covering more than 6 million gross acres. Oxo's major operations are located in northern Oman, primarily in Safah and Wadi Latham Fields in Block 9, Khamilah Field in Block 27, and in Block 62, where we operate the Muradi Huraymah gas plant, and in south-central Oman in Block 53 at Mukhaizna Field. One of Oxy targets is leaving Zero barrel behind. Therefore, this is a strategic project for Oxy and Oman.
Enabling Digital Transformation by Automating the Well Trajectory Design
Authors: Tamimi H. Al , Moreno C. , Dolle N.
Published: November 2024

PDO is transforming its well and urban planning by adopting digital technologies and Artificial Intelligence (AI) to improve organisational efficiency and maximise business value through faster quality decisions. Since 2020, PDO has collaborated with a third-party contractor to provide a novel solution to an Industry-wide problem – how to reduce the well planning cycle by effectively plan +100 wells in a congested brownfield setting. This work has resulted in 2023 in the organization-wide deployment of a full-stack customized AI-assisted solution, which is now starting to become embedded in the well delivery and field development planning workflows.

Traditional well delivery and field development planning workflows in the industry are still very manual, time-consuming (multiple man-months of work), and sequential. Well-delivery and field development planning in congested brownfield assets require close collaboration between multi-disciplinary teams - geologists, well engineers, geomatics, concept engineers, and reservoir engineers. In particular, in planning 100+ infill wells in fields with limited remaining options for well pads and hundreds of already existing wells. These conventional and sequential ways of working, are therefore likely to leave value on the table because it is difficult to find new feasible well locations and trajectories to optimize the development efficiently.

The tested and implemented workflow includes a self-learning AI algorithm to auto-generate feasible well trajectories combined with an optimization solver for finding preferred surface locations in a constrained urban plan. These are integrated into a full-stack digital solution with direct interfaces to PDO's corporate data repositories. The computations and resulting analysis are facilitated through an intuitive user interface that enables transparency and keeps users in control while improving efficiency with AI assistance.

The novel approach leads to a step change reduction of +40% in cycle time of the Data Analysis phase (from 6 to 3 months), for well and urban planning in a complex brownfield (800+ existing wells), to design 100-200 infill targets. The Value calculation in one of the piloted assets reflected an additional amount of 5 million USD in the NPV of the project. It provides potential game-changing digital solutions to PDO and the industry, enabling improved performance, much shorter cycle times and robust, unbiased well trajectories.

In summary, this is a tangible example of real digital transformation of a complex problem through a full-stack integrated AI-assisted solution. The new approach transformed the process from a sequential well planning workflow into an iterative and fast AI solution – parallelized urban planning method, including all technical considerations while adding significant value represented in hydrocarbon acceleration / early production.
Analyzing Offset Wells for Benchmarking UC Gas Well's Technical Limit in Field Development De-Risking Strategy: A Digital Solution
Authors: Kamble Rahul , Kirby Clifford , Al Wahedi Saeed , Kataria Prateek , Shakoor Imran , Abu Askar Ibrahim , Saddiq N.
Published: November 2024

This technical abstract delves into optimizing well delivery time in unconventional drilling projects by leveraging digital solutions, focusing on offset well data analysis, invisible lost time (ILT), and well time benchmarking. Emphasizing the complexities of limited well counts within de-risking strategies, the integration of digital technology has revolutionized conventional drilling practices, improving operational efficiency and productivity in well drilling and completion processes.

The study focuses on the crucial role of digital tools in analyzing offset well data and employing ILT analysis to optimize present and future drilling operations within an unconventional development drilling campaign. It explores the significance of these tools in analyzing historical well data to benchmark operations, identify ILT areas, and ultimately drive operational excellence and consistency. Case studies and empirical analyses underscore the significance of utilizing digital solutions for offset well data analysis and ILT identification, refining drilling strategies, and reducing non-productive time (NPT), thereby enhancing overall drilling efficiency.

Utilizing the digital solution, this study analyzed two distinct drilling campaigns conducted by different teams, examining seven offset wells drilled by various rigs. The analysis includes investigating operational events through detailed key performance indicators (KPI) categories, ILT drivers, drilling practices, NPTs, and unplanned events. After identifying contributors to ILT and NPT, the study provided composite well time estimations for a UC gas HTHP well, enabling the establishment of detailed rig operations benchmarks allowing more accurate well delivery time estimations for future development drilling projects.

Moreover, this paper emphasizes the importance of rig operation benchmarking, utilizing digital solutions to track, compare and enhance drilling performance against unconventional drilling wells record. The findings highlight that integrating digital solutions with ILT analysis and benchmarking enables more informed decision-making, leading to streamlined and optimized well operations within unconventional oil and gas drilling projects.
Achieving Optimal Injection Conformance with Autonomous Outflow Control Devices in Fractured Reservoirs: Case Studies in the South Oman Fields
Authors: Riyami Samiya , Moradi Mojtaba , Marimuthu Raam
Published: November 2024

Properties including propagating/dilating fractures. Development and growth of thief zones are confirmed by regular run of Multi-Injection Logging Tool (MILT) into the wells plus observing the performance of nearby producers. Although several techniques have been applied to improve the conformance of injection wells, they often lack the ability to effectively address this heterogeneity and achieve optimal injection. This paper presents field case studies in the South of Oman demonstrating the successful application of Autonomous Outflow Control Devices (AOCDs) in injection wells. AOCDs are innovative downhole tools strategically placed within the wellbore. These devices act as autonomous valves, automatically choking back fluid flow in thief zones when a predefined upper flow rate limit is reached. This dynamic flow control mechanism redirects injected fluids to less-productive zones, promoting a more even distribution and maximizing reservoir contact. The first installations of AOCDs in Oman have yielded promising results, significantly improving injection conformance and well performance. Here's a detailed look at the key findings: 1) Enhanced Injectivity Profile: Compared to conventional completions, the wells equipped with AOCDs exhibit a significantly different injection pressure-rate (Q vs P) profile. This profile indicates a more favourable injectivity response, characterized by a reduced pressure increase for a given injection rate. This signifies a more even distribution of injected fluids across the entire reservoir as opposed to the rapid pressure rise observed in conventional completions due to concentrated flowing thief zones. 2) Reduced Thief Zone Dominance: MILT data from the AOCD wells after installation reveals a dramatic reduction, exceeding 75% in some instances, in the contribution of thief zones from the total injected volume. This substantial decrease effectively mitigates the further growth of these preferential flow paths and their detrimental impact on reservoir sweep efficiency. 3) Increased Production Efficiency: The optimized injection profile achieved by AOCDs is believed to have significantly contributed to a 30% increase in oil production from nearby producing wells. Additionally, a lower water cut was observed, indicating improved recovery of valuable hydrocarbons. The field data presented in this paper provides compelling evidence for the effectiveness of AOCDs in achieving optimal injection conformance and well performance in fractured reservoirs. This innovative technology not only enhances well efficiency and reduces operational costs but also offers valuable insights for future well-completion strategies. By enabling more effective reservoir management, AOCDs pave the way for improved field development practices and ultimately contribute to maximizing oil recovery from fractured reservoirs.
Maximizing Production Recovery in Challenging Reservoirs: Insights from Autonomous Inflow Control Device (AICD) Implementation in Offshore Malaysia
Authors: Mohd Jeffry Suzanna Juyanty , Ye Lin Catherine Tang , Mappanyompa Ertiawati , May Chen Dharshini Yeap , Ain Sapian Nik Fazril , Hughes Mark Anthony
Published: November 2024

Field B is an offshore brown field in Malaysia which has faced significant challenges due to the presence of a thin oil rim amidst complex reservoir conditions characterized by massive gas cap, uneven contacts, strong water drive and high sand production. Historically, early gas and water breakthroughs have been observed, leading to elevated gas-oil ratio (GOR) and high water cut. Autonomous Inflow Control Devices (AICDs) were incorporated in new horizontal infill wells since 2018 to allow production control and mitigate high GOR issues. AICDs have enabled autonomous regulation of unwanted production fluids, leveraging Bernoulli's Principle. The deployment was meticulously assessed based on reservoir characteristics, production objectives, and economic viability.

This study thoroughly examines the performance of the horizontal wells equipped with AICDs integrated with openhole standalone screens (OHSAS) completion in Field B. The performance of the wells with AICDs were also compared with similar wells without AICDs to evaluate the value of this technology. Through comprehensive analysis, the investigation addressed the challenges encountered, outlined the best practices, and formulated the effective well production and monitoring strategies to ensure sustained functionality and reliability of AICDs over the production lifecycle.

Various factors influencing well performance were explored, providing insights into the role of AICDs in optimizing production amidst challenging reservoir conditions. Since AICDs were adopted in recent infill wells, it was observed that the technology managed to control the gas-oil ratio (GOR) in wells that were located closer to the current gas-oil contact (GOC) and maximized the productivity.

This paper features a comprehensive summary of the reservoir management, production strategy and resulting production improvement in Field B with the application of AICDs. Moreover, this paper also highlights on the effectiveness of AICDs in Field B, offering valuable insights for oil and gas operators navigating similar challenging reservoir conditions, ultimately aiming to optimize overall production efficiency.
Potential Energy Transformation into Hydropower Driven by Existing Returned Sea Water at Offshore Island
Authors: Almehrzi N. Humaid , Alriyami M.
Published: November 2024

The global transition to renewable energy is essential for addressing growing electricity demand, reducing greenhouse gas emissions, and combating climate change. ADNOC is committed to this shift through its 2030 Sustainability Strategy, which aims to cut GHG emissions intensity by 25% by 2030, requiring innovative technologies and solutions to meet this goal. This project proposes constructing a hydroelectric plant on Zirku Island, utilizing the cooling water return channel to the sea. The approach is to install an in-line turbine within the cooling water return pipeline, driven by the flow of seawater, to generate electricity. The electricity produced will be fed into the grid to meet the island's energy demand, simultaneously allowing more fuel gas to be redirected to downstream markets. The cooling water network services all consumers within the process plant and eventually returns water to the sea through a degassing tank, adhering to strict environmental standards. The existing system operates with a flow rate of 9,000 cubic meters per hour of treated seawater through a 48-inch pipe, maintaining a minimum pressure of 25 PSIG. Initial studies suggest that this setup could generate approximately 3,206 MWh of electric energy annually. The estimated project capital expenditure (CAPEX) is around 573,500 USD. Further detailed studies are underway to assess the most suitable turbine type and explore potential system modifications for enhancing efficiency. This paper presents a technical proposal that illustrates how waste energy can be converted into clean, renewable electricity, providing a reliable energy supply while supporting ADNOC's sustainability goals and contributing to the UAE's broader renewable energy objectives. Importantly, this innovative use of hydropower technology could serve as a model for other offshore oil and gas sites globally, demonstrating how wasted potential energy can be repurposed into green energy and inspiring similar initiatives.
Comprehensive Approach for Confirming and Modelling Residual Oil Distribution Below Current Free Water Level in Brown Giant Oil Field, Offshore Abu Dhabi
Authors: Montani Hiroki , Voleti Deepak Kumar , Yamamoto Kazuyuki , Inokuma Yuto , Farooq Umer , Alshamsi Suad Mubarak
Published: November 2024

Optimizing the development of oil and gas, which are finite underground resources, is indispensable for human activities. Historically, humanity has prioritized the extraction of conventional oil and gas, which are easier to produce. However, recent technological advancements have enabled the efficient extraction of unconventional oil and gas, such as shale oil. The target reservoir of this study has similarly focused on conventional oil that is located above current free water level (FWL). Nevertheless, historical core data, log data, and production data of the reservoir indicated the presence of oil below current FWL. The oil below current FWL is considered to be residual oil, which is the result of an imbibition process that occurred after the oil charge. The exact distribution and development potential of residual oil, however, were not well understood. Additionally, since the late 1970s, peripheral water injection (PWI) from outside the current FWL has been implemented in this reservoir to maintain pressure, but it has been ineffective. A hypothesis was formed that the cause of this pressure discontinuity might be the residual oil.

For the above reasons, it became necessary to accurately capture the distribution of residual oil below current FWL to optimize future development plans in this reservoir. Previous reservoir models had not successfully modeled the distribution of residual oil below current FWL. Therefore, this study adopted a new static modelling technique that is most suitable for the heterogeneous and mud-dominant reservoir. To accurately model the distribution of residual oil below current FWL, we created a paleo FWL surface in addition to current FWL and constructed a water saturation (Sw) model based on the paleo FWL surface with saturation height function (SHF) for each static rock type (SRT). This approach allowed us to model the distribution of residual oil below current FWL. As a result, the matching accuracy between the Sw model and Sw log significantly improved compared to previous model. Moreover, the distribution of residual oil obtained from this modelling study was consistent with regional tectonic events. Furthermore, accurately modelling the thick Sw transition zone of residual oil allowed us to reproduce the pressure difference between peripheral water injectors and oil producers in the dynamic model without arbitrary modelling methods. The results of this study led to the optimization of future development plans such as water injector location for pressure maintenance.
Making Non-Metallic Downhole Tubulars a Reality – An Analytical Load Estimation Workflow
Authors: Boubenider Rafik , AlAdawy Ahmed , Cooke David , Mintzas Angelos , Elshamy Omar
Published: November 2024

Non-metallic composite downhole tubulars provide significant value including less carbon footprint and reduced total cost of ownership. However, matching pipe performance envelopes to combined loading in different scenarios cannot be performed using commercially available software, due to various challenges including anisotropic pipe behavior, variation of material properties across the depth and change of well conditions. This publication highlights multidisciplinary collaborative efforts to estimate such loading in composite tubulars and compare to existing use cases.

Load cases and conditions were determined, and analytical calculation workflows were deduced for loads at various depths and conditions across the lifetime. Load cases and alternate loading sequences are listed, interactions between tubular & system components are reflected and proper boundary conditions are applied to estimate such combined loads. Validation was performed against finite element analysis methods and methodology was applied in specific well applications.

Results using suggested analytical methodology show good matching with numerical results using finite element analysis. Loads were matched against pipe performance envelopes with suggested safety margins for different pipe designs. Whilst pipe design changes, variation of pipe effective properties, including stiffness, density, and dimensions, affect the total combined loads acting on the tubular system. Well construction parameters including deviation profile, depth, and geothermal gradient affect conditions inside the well, differential pressure and axial loads. Change of system components including pipe connections, completion, installation tools and ancillaries significantly affects such loading profiles. These system components can be optimized and custom components and installation procedures for non-metallic composite tubulars can be developed and qualified to reduce such loads on the pipe.

Application of reel-deployed thermoplastic composite pipes is unique and novel in downhole applications and must be accompanied by customized design workflows and validation programs. A new analytical design approach was developed for estimating the thermoplastic composite pipe structural response. This publication is bringing an integrated workflow for estimating these loads on non-metallic downhole tubulars, which – to the best of the authors’ knowledge – has not been presented elsewhere.
Mitigating Gas Hydrate Formation in Deepwater Operations Using Red Onion Skin Extract ROSE
Authors: Wachikwu-Elechi Virtue Urunwo , Onyekachi Ndidi Precious , Ikiensikimama Sunday Sunday
Published: November 2024

One of the serious flow assurance issues plaguing the oil and gas industry is Gas Hydrate formation. They are nonstoichiometric glasslike or crystalline compounds that form when water referred to as host molecules encapsulate hydrocarbon or non-hydrocarbon gases (guest molecules) at low temperatures and high-pressure conditions. They cause restrictions/plugging of flowlines when allowed to form which mitigates flow assurance. The use of agro-waste in various process activities is becoming popular due to environmental concerns and public health. This study seeks to address the use of such waste; Red Onion Skin extract (ROSE) as an inhibitor for gas hydrate. A locally formulated High-pressure magnetic stirrer was used to screen varying weight percentages of ROSE (0.01-0.03wt%) and compared to a conventional hydrate inhibitor Polyvinylpyrrolidone (PVP). The performance of the agro waste skin extract (ROSE) was assessed using pressure, temperature plots as well as relevant plots. Gas hydrate formation was indicated by a rise in the temperature of the reactor cell and a drastic reduction in the cell's pressure. The final pressures for 0.01-0.03wt% of ROSE were 11.2, 12.3 and 12 bar while values for the same weight percentage of PVP were 12.3,11.6, and 10.1 bar respectively. The ROSE performed better than PVP at 0.02 and 0.03wt% respectively showing its optimum inhibition performance at 0.02wt%. Although the performance of PVP was better than that of ROSE at the lowest concentration of 0.01wt%, the difference in the final pressure value was about 1.1 bar which shows ROSE's competitiveness at the weight percent. Again the ROSE helps to check environmental degradation, toxicity, and high cost of the convention PVPThe difference in values for ROSE at 0.03 and 0.03wt% was about 0.3 bar which is an indication that inhibition above 0.02wt% was needless and uneconomical. 0.01wt% while for 0.02 and 0.03wt% ROSE out-performed the PVP. The ROSE has been shown to perform better than PVP in most weight percentages used and can be harnessed as an alternative to costly and toxic inhibitors by the Oil and Gas industry taking into cognizance its eco-friendliness and human health compliance.
An Integrated Reservoir Evaluation Technique for Dual Structure Reservoir Based on Geomorphic Features and Seismic Anisotropy and its Application to Granite Buried Hill Reservoir in Central Africa
Authors: Yaliang Xia , Jiawen Song , Xiaodong Wei , Lirong Dou , Jingchun Wang , Jie Hu , Juntao Zhang , Yunpeng Hou , Xin Chen , Zhongfan Wang , Dengyi Xiao , Donghai Liu
Published: November 2024

The basement of Bongor Basin in Chad, Central Africa, is composed of Precambrian granite, gneiss and mixed granite. The basin is a tensile basin formed by the Central African shear strike-slip and tensioning effect. Strong overturning exists in the basin and it suffered long-term weathering and denudation during the Paleozoic and Jurassic periods. Core and drilling data show that both pore and fracture reservoirs are developed in the buried hill, and there are great differences in reservoir patterns and development situation among the buried hills, the reservoir is highly heterogeneous, which have great influence on productivity.

This method is based on wide-band, wide-azimuth and high-density seismic data. Combined with logging, core analysis, imaging and production data, this paper firstly summarized the development model of buried-hill reservoir, divided favorable reservoir sections of buried-hill vertically and identified types of reservoir voids, secondly integrated with the results of three-dimensional seismic structural characterization of buried-hill, completed the classification of buried hill morphology, and summarized the reservoir development characteristics of different types of buried hill. On the basis of fully considering the formation, influencing factors and preservation conditions of buried-hill reservoirs, the pre-stack and post-stack prediction are combined to carry out classification prediction of pore and fracture reservoir, among which the prediction method of porous reservoir based on buried hill geomorphological characteristics and seismic sensitive parameters is proposed for the first time. Pre-stack OVT fracture prediction based on seismic wave anisotropy of different azimuth has become a hot spot in fracture prediction in recent years. The study result clarified the distribution characteristics of buried-hill pore and fracture reservoirs, improved the prediction accuracy of buried-hill reservoirs, and provided a set of reliable technology for buried-hill exploration in this area. It is also suitable for exploration and evaluation of other reservoirs with similar seismic and geological conditions.