bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.