bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhancing Zonal Isolation in Total Loss Zones: Advanced Cementing Techniques for Deep Gas Wells
Authors: Quintero E. , Martanto R. , Edgar D. , Masoud R. , Urdaneta L. , Martinez C. 
Published: November 2024

Abstract
Achieving effective zonal isolation across multiple sections in the presence of weak formations is a significant challenge in the oil industry. The objective of this study is to address this challenge by discussing two successful primary cementing operations across total loss zones in deep gas wells.
In both cases, a meticulous approach was taken. The first involved a production casing, drilling from the previous casing string to the target depth, while the second operation was an intermediate casing. Despite encountering total losses while drilling, conventional lost circulation treatments failed, leading to blind drill the section. To address the zonal isolation challenge, a multi-stage cementing technique employing a novel plug and differential valve (DV) tool set was utilized, capable of withstanding pressure up to 3,000 psi. Extensive placement simulations were conducted to optimize mud removal and cement slurry design properties for the three-stage jobs.
The cement bond logs acquired post-operation exhibited excellent results, confirming successful zonal isolation in both cases. Despite encountering total loss zones, the meticulous planning and execution of the cementing process ensured achievement of the objectives. The utilization of the multi-stage cementing technique, coupled with the novel plug and DV tool set, proved instrumental in mitigating losses and enhancing cementing effectiveness. The comprehensive evaluation, including open hole (OH) caliper log assessment and extensive placement simulations, contributed to optimized mud removal and cement slurry design properties, further enhancing the success of the operations. Overall, this study highlights the efficacy of integrating advanced cementing techniques with detailed planning to overcome challenges associated with zonal isolation in weak formations. The successful outcomes of these operations highlight valuable insights that can inform and improve future cementing practices in similar challenging environments within the petroleum industry.
This paper presents a novel approach to cementing operations in challenging formations, particularly total loss zones encountered in deep gas wells. The utilization of a novel plug and DV set, capable of withstanding high pressures, offers a promising solution to enhance cementing operations in challenging conditions, contributing to the advancement of cementing practices in the petroleum industry.
Re-Development of a Forty-Year-Old Brown Field in South of Oman Producing from Five Different Stacked Reservoirs, Resulting in 50% Oil Gain by Doubling Water Injection
Authors: Hinai Mahmood A. Al 
Published: November 2024

Abstract
This paper showcases the impact of doubling water injection rate from 25k bbl/day to 50k bbl/day in a forty-year-old brown field which lead to 50% oil gain. This was achieved by executing activities to redevelop the five stacked reservoirs in this brown field for better reservoir management. The main activities in the field focused on: (1) de-commingling the water flooded reservoirs from the depletion reservoirs, (2) improving the vertical conformance of the waterflood units via dedicated injection through re-completing the injectors to tubing and casing injectors, Long & Short strings, (3) infill drilling to complete the patterns from 5-spot to 9-spot patterns to improve waterflood sweep, and (4) execute WRM optimization activities to increase injectivity in the water flooded reservoirs.
One of the main challenges in wells commingling production form different units is that individual unit's contribution is not well understood, particularly when the reservoirs have different rock and fluid properties and under different drive mechanisms. Furthermore, there is not much control on each unit production/injection contribution when they are commingled. Therefore, a re-development plan calls for de-commingling production/injection and further infill drill wells to have better understanding and control on the individual unit performance. This approach improved the conformance of the five reservoir units, hence injection and production. Despite the challenges related to urban planning, surface capacity and the ongoing drilling activities, the executed activities resulted in a step change in managing the five different reservoirs, 50% oil production gain, 100% increase in injection as well as new production data from dedicated individual units for the first time from this old brown field. In summary, improving reservoir management through de-commingling waterflooded reservoirs as well as further infill drilling and change in water injectors completions resulted in a step change in the ability to inject water and hence production growth.
The new development has opened further opportunities to continue developing reservoir units that used to be commingled resulting in reserves additions up to 10% of total field reserves. Furthermore, new approach is followed to produce the extremely high viscos oil of a reservoir by commingling, at surface, with nearby producers to ensure produced water pushes the extremely high viscos oil from the wellhead to the station.
Carbon Dioxide Site Storage Monitoring Using Cosmic Ray Muons
Authors: Steer C. A. , Ramsay T. S. , Thompson L. F. 
Published: November 2024

Climate change drives a global need to decarbonise and reduce emissions of CO2 into the atmosphere. Carbon Capture and Storage (CCS) is a critical technology that enables countries to undergo a fast transition to net zero emissions. The development of efficient and effective carbon dioxide storage involves the act of liquifying and storing carbon dioxide in natural geological reservoirs. As the dense phase CO2 is injected, deep underground, into a suitable storage site it will naturally pool underneath a capping layer, and develop a plume.
However, there are many regulatory and other factors which means that simply injecting CO2 into the sub-surface isn't sufficient. Of utmost importance is the need to assure public and operator confidence in the entire CCS process. Notably this also means that the CO2 is, indeed, effectively captured and is not passing through the subsurface and re-entering the atmosphere. Conventionally such monitoring takes place episodically via technologies based on seismic sensing, this paper introduces the first results from a novel monitoring approach which uses muons - naturally-occurring radiation - to provide continuous density information of a CCS plume post-injection. Results from the world's first use of this muon imaging technology in field trials in Norway in summer 2023 will be presented and compared with data from traditional seismic measurements that were executed concomitantly.
Compartmentalization, Complex Filling History and Operational Oil Alteration Due to EOR Processes Revealed Using State-of-the-Art Multivariate Geochemical Fingerprinting in a Mature Abu Dhabi Oilfield, UAE
Authors: Koksalan T. , Khan K. A. , Salahuddin A. A. , Aljneibi N. M. , Alblooshi M. N. A. , Adams J. J. 
Published: November 2024

Abstract
The studied Abu Dhabi onshore field, characterized by over 60 producing horizontal wells, has undergone extensive hydrocarbon recovery through miscible HC-WAG, CO2-WAG, and CO2-EOR techniques for more than 15 years. The field’s recent expansion includes delineation wells like X-194 and X-196, drilled to appraise potentially separate oil pools to the west and confirm structural integrity and reservoir continuity. This study leverages oil fingerprinting technology and geochemical data to evaluate the fluid connectivity between the main field and these step-out wells.
X-194, located 9 km west of the main pool, targets an up-dip trap potentially charged from the main field via a fill and spill mechanism. Conversely, X-196, situated 6.5 km southeast of X-195 and 4.5 km west of X-3, probes a different fault block with distinct pressure regimes and free water levels (FWL). The wells, perforated in subzones BII and BIII, target higher subzones due to the positioning of the FWL, with X-28 being the sole well perforated in the lowest BIV subzone.
The study focuses on high-resolution gas chromatography (HRGC) analysis of nine produced oil samples, collected from the two western step-out areas, the field’s crest, and adjacent wells across the fault. These moderate-maturity black oils, with API gravity values ranging from 37 to 39, exhibit geochemical similarity to oils from the main field, with slight variations in thermal maturity suggesting compositional grading.
Findings reveal that oils from the southwestern part of the field, closest to the FWL, display the lowest thermal maturity due to charge stacking, and have been affected by WAG operations. The reservoirs exploited by X-196 appear disconnected from the main field reservoirs, yet share genetic similarities with nearby oils, suggesting a common origin within the petroleum system. X-194’s oil, slightly less mature than its closest counterpart in the main field, supports the hypothesis of a fill and spill scenario but lacks evidence of fluid connectivity to the main field.
The study concludes that while there is a genetic link (i.e., common oil-source relationship) between the step-out wells and the main field, fluid connectivity among the areas is limited. We recommend further integration of geochemical data with reservoir and production dynamics to enhance the understanding of fluid distribution and recovery strategies in the field.
Critical Evaluation of API Free Water Test Addressing Gaps in Lightweight Cement Slurries Testing
Authors: Mahmoud Ahmed Abdulhamid 
Published: November 2024

Abstract
The American Petroleum Institute (API) free water test is a standard procedure designed to measure the free water content in cement slurries. However, this study identifies significant limitations in the API free water testing procedure, especially for cement slurries with very low densities achieved by adding excess water beyond the API's recommended limits. The investigation involved comparing the results of the standard 2-hour API free water test with an extended 24-hour test. The results revealed that for low-density slurries, the 24-hour samples showed a substantially higher amount of free water compared to the 2-hour API test results, the samples showed no free water after 2 hours of testing were experienced significant reduction in the cement column after 24 hours. This discrepancy indicates that the 2-hour API test fails to accurately capture the increased free water content in these slurries. The presence of this additional free water significantly reduces the effective height of the cement column. These findings highlight the inadequacy of the current API free water test for low-density cement slurries and suggest a need for a reassessment and possible modification of testing standards. This study offers a critical evaluation of the API free water test, emphasizing the importance of extended testing durations for lightweight slurries to accurately capture free water content. It suggests improvements and medications to the current testing procedure to make it more reliable and effective, thereby enhancing well cementing operations and ensuring better performance in well cementing.
Rapid Mass Level Organizational AI Sensitization and Skill Development Using No Code AI Tool
Authors: Chowdhury K. A. , Kawsar S. , Imam T. I. 
Published: November 2024

Abstract
The current data-driven digitalization in the oil and gas industry offers opportunities for enhanced safety, efficiency, and significant financial benefits. It supports the transition from a labor-intensive business model to a technology-centric one. However, this shift can introduce high-skill digital labor demands, substantial technology adoption, in some cases lead to disenfranchisement of existing employee especially where artificial intelligence (AI) is utilized. This endeavor implements several AI experience programs using no-code AI technology to quickly sensitize and develop AI skills across various organizational levels.
Four distinct curriculums of 2-hour, 4-hour, 8-hour, and 16-hour durations were developed to provide AI experiences for accomplishing four different skill levels, employee ranges from c-suite executives, regular administrative staff to university faculty and students. The curriculums are designed for non-programmers and non-technical employees, helping them transform real-world problems into AI problems and solve them. Participants gain practical experience in building AI solutions aimed at revenue maximization and cost savings. The learning process is accelerated using a no-code AI tool, which was developed by customizing an automated machine learning Python code to provide an easy-to-use democratized AI interface accessible via a website.
A 16-hour AI sensitization and skill development program was implemented for the oil and gas, power and utilities, financial, government and healthcare industries through university short AI experience program. A survey conducted among non-IT, non-programmer participants showed that 61% reported significant transformation in AI understanding, 81% found the program relevant to their industry’s challenges, and 86% gained confidence in solving AI problems independently. The skill development program was also applied in the oil and gas industry through 2-hour, 4-hour, and 8-hour programs to quickly develop AI skills.
The novelty of this training program lies in the use of no-code AI technology, which eliminates the need for high-tech AI adoption, tedious programming learning processes, and computer science degrees. This approach allows for rapid mass-level AI sensitization and cultural transformation within the oil and gas industry, enabling more effective operation of AI related endeavors and AI implementation throughout organizations. Recent, introduction of generative AI into this technology provides personalized learning experience based on employee’s domain expertise.
An Innovative Approach for Optimizing Remedial Cement Squeeze Operation with a Mechanical Port Collar
Authors: Munoz Julio C Guzman , Aldejani Abdullah M , Alkhaldi Abdulmohsen F , Hasan Muhammad , Allam Belal , Mumtaz Saad 
Published: November 2024

Abstract
This paper aims to spotlight the distinctive approach of utilizing port collar technology in remedial cementing operations, focusing on its unparalleled ability to significantly reduce rig time, optimize operations and increase efficiency. It will be discussed in detail the operational sequence, showcasing the merits, and highlighting the substantial time-saving benefits of this ground-breaking approach.
Total loss circulation is a common occurrence in various fields where depleted or fractured zones are encountered while drilling. In such cases, conventional cement job cannot ensure a good cement across the entire liner/casing. Therefore, remedial cement squeeze job is performed to ensure well integrity in case of total losses. Conventional remedial cement squeeze operation includes the following: running the liner without setting liner top packer, doing the conventional cement job to the loss zone, then run a drillable cement retainer above the liner top to perform cement squeeze operation, afterwards drill-out the cement retainer, run a polish mill and finally deploy liner tie-back packer. Thus, a conventional remedial cement squeeze operation has a lot of complexities and extended operations days. The proposed methodology with the port collar has proven to have significantly minimize rig days and reduce the number of trips to only one. In this operation, a port collar is placed below the liner hanger. The process includes setting the liner hanger, executing a conventional cement job to the loss zone, setting the liner top packer, and subsequently pulling out of the hole. Running in hole with an inner string tool to open the port collar and efficiently squeeze cement into the loss zone, ensuring a controlled and swift operation to ensure well integrity.
A comparative analysis has been performed for both approaches where few wells have been studied in detail. The implementation of Port Collar approach for squeeze cementing has demonstrated a drastic reduction in rig time. Moreover, the compelling comparative results and observations derived from the jobs conducted will be discussed in detail. Furthermore, the unique benefits of the port collar being full bore with no drill out requirement, possibility of multi open and close cycles with metal-to-metal seal and contribution to well integrity have been highlighted and discussed.
Emphasizing a unique approach to squeeze cementing, this paper provides novel information to the petroleum industry. By offering a fresh perspective on time-saving strategies, this paper contributes valuable insights that can reshape existing industry practices and advance the state of knowledge in drilling, ultimately fostering more cost-effective and efficient well integrity solutions.
Most Rigorously Tested Liner Hanger Ever? - Expandable Liner Hanger with All Metal-To-Metal Seals Qualified as Primary Well Barrier, Optimizes Well Design and Enables Production Rate Increase
Authors: Rice J. K. , Chuvas R. de. C. , Lazaro A. 
Published: November 2024

Abstract
The Brazilian Pre-salt fields have driven technology developments and casing architecture advancements1 over the past 19 years. In 2023, Petrobras challenged the industry to design, test and build a liner hanger to meet the extreme requirements of their Buzios field 5 section well configuration2 which requires a high-capacity liner hanger to provide the interface between 10 ¾ and 14" casing as a well barrier with no tieback to the subsea wellhead. The original intention of this Expandable Liner Hanger (ELH) interface is to be a barrier replacing the cement at the top of the liner (TOL). This well configuration requires a long casing string to be suspended on a liner hanger with the potential for intersecting a fractured zone at the top of the reservoir. Both the length of liner and the fractured zones are challenges to establishing cement integrity at to the top of the liner without the need for remedial cement operations which can be costly and time consuming. The ELH system is designed and tested as a seal at the top of the liner for the full well life without the need for cement. As there were no industry standard testing protocols which effectively simulate the full well life conditions, Petrobras established their own protocol to specify the testing requirement that covers this application. As compared to industry protocols such as API19LH, the Petrobras requirements included rigorous testing related to a much higher number of individual points of applied load and pressure (427 total), a challenging non-metallic chemical resistance protocol, and metallurgy to provide corrosion resistance.
In this improved well configuration, the use of a liner hanger enables a 6 5/8" intelligent completion to be deployed through the reservoir while above the liner hanger a larger 7 5/8" production string is installed inside the 14" increasing the ability for higher flow volumes during production (Figure 1). This casing design considered the full life cycle of the well from an expected initial state of oil production (without water or gas), followed by water/gas breakthrough and production with a mixture of oil, water, and gas. The well design also considered a drop in the reservoir pressure resulting in the bubble point being reached causing a mixture of oil and gas to be produced. The design and subsequent testing protocol establishes a system which is applicable to the Buzios field project and many other fields where the required loads and pressures are within the envelope.
Figure 1 Well configurations showing conventional and optimized well design with 10 ¾ expandable liner hanger
Development of the Mozambique Gas Industry - Will Onshore LNG or Floating LNG Production Facilities Most Likely Deliver Profitable Projects for the IOCs?
Authors: Meulengracht C. S. , Djupvik J. A. , Barhate A. 
Published: November 2024

Abstract

Objective/Scope
Since 2010 more than 100 Tcf of recoverable gas reserves have been discovered offshore Mozambique. Large gas discoveries that are distant from markets now have 2 different LNG development solutions. The first is the classical onshore LNG production facility and the second is the offshore floating LNG (FLNG) production facility, a comparatively new development solution. This paper examines both solutions for all fields being developed or planned with both deterministic and stochastic LNG price assumptions.

Method/Procedure/Process
The Rovuma basin now features the Coral South FLNG in production, and the Coral North FLNG and several onshore LNG production facilities are being planned. Gas production profiles and costs including DRILLEX, CAPEX and OPEX are determined for these projects with their foreseen development solutions. Then the same profiles are estimated for the alternative development solutions.
Base case deterministic economic analysis is carried out with detailed after-tax cash flows for all projects using both development solutions. Sensitivity analyses allow for calculating tornado diagrams and break-even values. Where appropriate a portfolio analysis is performed to include the effect of being in tax positions with multiple fields.
In addition, stochastic random-walk LNG price scenarios are applied for all projects, including alternative development solutions. NPVs are then plotted as cumulative density distributions to determine the probabilities of the projects being economical for the IOCs given the LNG price variation assumptions. Cumulative density distributions are also created for the Government Takes.

Results/Observations/Conclusions
The calculated cumulative density distributions are skewed S-shaped curves leading to the conclusion that NPVs are log-normally distributed.
The most important result is that the probabilities for the projects delivering positive NPV given stochastic LNG price scenarios, and therefore providing a minimum return equal to the discount rate, can be determined and compared with other projects and project solutions. Cumulative density distributions for the Government Takes are also be determined.
The strengths and weaknesses of stochastic analysis versus deterministic analysis are discussed.

Novelty/Additive Information
Pure deterministic analysis with sensitivities is excellent for analyzing the robustness of a project, however when supplemented by stochastic analysis deeper insights are achieved.
The novelty of this paper is the application of real project data with two alternative development solutions and then applying stochastic random-walk prices to evaluate the probabilities of being economical. The LNG prices are the most uncertain aspect of an LNG development and have the greatest impact on the economics.