bluuebunny/crossref_metadata_2025_split huggingface dataset:
Real-Time Subsurface Risk Re-Assessment During Exploratory Drilling: Case of a Deep Play Exploration in Niger Delta
Authors: Okpako Kelvin O. , Amoo Tope , Tichelaar Bart 
Published: August 2024

Abstract
Many wells drilled in Niger Delta up to depths around 12000 ftss are hydrostatic or near hydrostatic, but some wells have encountered very high overpressure. Beyond this depth, formation pressure gradient just below 0.9 psi/ft have been measured, near well Total Depth (TD). Drilling through highly over-pressured sands require robust drilling practices, since taking a kick could present more challenging drilling risks and potential to create HSE incidents.
This paper presents a case history of an exploration well with the above-stated drilling situation with unusual pressure trend. It has a near-hydrostatic overburden that terminates at depth in a sharp pore pressure ramp with significant overpressures. Below the ramp, pore pressure sharply decreased back to near-hydrostatic in a thick reservoir interval. Below this reservoir interval, pore pressure ramped back to high overpressure down to well TD. Given this abnormal occurrence in the Niger-Delta, there was the need to evaluate the potential risk of over-pressured gas crossflow from the geo-pressured reservoirs to the normally pressured reservoirs through the Open-Hole (OH) section of the wellbore. This was critical to the drill-ahead decision that had to be made to extend the well into the exploration target sands or call well TD, prematurely.
The result of a quick subsurface risks assessment carried out during drilling showed that the shallower sands are competent formations that can serve as natural thief zones for crossflowing over-pressured gas. The risk of reservoir pressure inflation that could lead to formation top seal failure and Internal blow-out in the subsurface was also evaluated. This provided a technical business solution that aided the timely decision to drill-ahead and extend the well into the planned exploration targets.
The well discovered significant gas volumes, and was considered, ‘a near-Big Cat volumes discovery’, which has significantly increased the Nation’s gas resources. Landing well TD prematurely, instead of drilling to planned TD, would have cost us the volumes from the deeper exploration target sands. This real-time intervention ensured a quick decision was made and eliminated Non-Productive Time (NPT) that could have resulted from idle time. Finally, the risk re-assessment further demonstrated the value of effective collaboration in decision-based subsurface uncertainty management.
Optimization of Well Workover Efficiency: A Case Study of Cost-Effective Adoption of Hydraulic Workover Unit Technology
Authors: Anyaehie James , Edirhin Eta , Omatsone Oma , Anagbogu Emeke 
Published: August 2024

Abstract
This study explores the strategic adoption of Hydraulic Workover Unit (HWU) technology by two leading indigenous energy firms in Nigeria. The objective was to achieve significant cost efficiencies while adhering to the highest safety protocols during well workover operations. The initiative began with collaborative brainstorming sessions to explore innovative methodologies beyond traditional rig operations. A thorough examination of rig-based activities and infrastructure identified opportunities for operational optimization and cost efficiency. The HWU emerged as a promising alternative, despite inherent challenges. Comprehensive risk and uncertainty mitigation analyses were conducted, leading to the development of a robust and safe HWU work module.
The inaugural deployment of the HWU on a shallow offshore well's initial completion was successful and incident-free. Encouraged by this success, the HWU operation was replicated in land locations, converting two oil wells to water injection wells through workover operations. The initial completion of the shallow offshore well achieved an impressive production rate of over 4,000 barrels per day and a 40% cost saving compared to traditional rig operations. The onshore conversions were executed within six weeks per well, at a cost of $4.5 to $6.0 million each, significantly lower than the conventional rig costs of $8 to $12 million.
These successful cases demonstrate the effectiveness of adopting HWU for workover operations across diverse environments (land and shallow offshore). This paper details the processes and methodologies employed, offering valuable insights into a potential avenue for cost reduction exceeding 50% for typical workover operations in the Nigerian context.
Application of Pressure Transient Analysis to Gas Material Balance for Multi Rate Production
Authors: Okafor I. S. , Ajibade A. A. , Jakada K. , Chior T. J. , Gimba A. B. , Nzerem P. C. 
Published: August 2024

Abstract
A producing field's oil and gas reserves are continually estimated throughout its lifetime. As more data about the reservoir is obtained over time, the uncertainty regarding the actual amount of reserves decreases. Various methods have been employed to determine these reserves, including the Material Balance Technique. The classical method applies the conservation of mass, which has evolved over time. This study aims to further enhance the gas Material Balance Technique by incorporating equations derived from analytical pressure transient analysis with multiple rate production. By combining transient analysis solutions with the linear Material Balance method, this approach offers the advantage of determining the initial gas-in-place, permeability, and skin of a reservoir simultaneously, without relying on independent sources for prior knowledge of any of these parameters. To streamline the process and facilitate analytical deductions, this work also utilizes Python programming for automation. Ultimately, this study develops a series of steps that were applied to a case study, enabling the simultaneous determination of the reservoir's permeability, skin-factor, and initial gas-in-place.
Exploring the Delicate Balance in the Optimal Execution of Concurrent Gas Cap Blowdown and Oil Rim Production in a Saturated Reservoir
Authors: Alaigba D. , Awani T. A. , Oyeleke Z. , Adebayo A. , Gbadamosi T. 
Published: August 2024

Abstract
As the global drive for providing cleaner energy for current and future generations intensifies, there is an increasing need to develop natural gas resources which are cleaner when compared with other liquid hydrocarbon sources. This is because hydrocarbon gases generally have lower carbon content compared to crude oils. Hydrocarbon gases can come from solution gas, associated gas (primary or secondary gas cap) or non-associated gas depending on the initial reservoir pressure, temperature, composition, and development phase of the hydrocarbon resource.
Imperatively, we have studied a field in which the reservoir sedimentation occurred in a wave-dominated fluvio-marine environment. These sands are usually capped by well-defined marine shales and the sands are predominantly rich in gas.
Natural gas production is traditionally limited to gas from non-associated gas reservoirs. However, a lot of oil accumulations around the globe have associated gas caps and these gas accumulations, often referred to as associated gas have historically been reserved to expand and provide pressure support for production from the oil rim while gas production from the gas cap is deferred to later in the reservoir life after the oil reserves have been produced. Forces related to economics and the global energy trilemma have seen an increasing interest in developing these associated gas resources together with the underlying oil volumes. Maximizing recoveries from oil rim reservoirs and their gas cap requires an understanding and optimization of the delicate balance that exists between the dynamics of production from both the oil and gas legs, associated aquifer support and secondary pressure maintenance scheme.
This study worked with a history-matched and calibrated three-dimensional reservoir model from a producing brown field in the Niger Delta to test different scenarios as follows; Assess the impact of oil rim production followed by gas cap blowdown on the ultimate recovery from both the gas cap and the oil rim, assess the impact of simultaneous gas cap blow down and oil rim production on the ultimate recovery from both the gas cap and the oil rim and finally assess the impact of gas cap blow down followed by oil rim production on the ultimate recovery from both the gas cap and the oil rim.
In each case above, sensitivities were run to determine the optimal gas cap blow down rates, production start-up time, well type configuration and impact of pressure maintenance. The results of this work have provided very valuable insights that result in the optimal development of both oil and gas resources from saturated oil reservoirs with gas cap resources.
Assessment of Polymer Resins as Alternative Abandonment Barrier Materials for High Pressure High Temperature (HPHT) Wells: A Multi Criteria Decision Making Approach
Authors: Chukwuemeka Augustine , Njuguna James , Oluyemi Gbenga , Attar Suhail 
Published: August 2024

Abstract
Portland cement is the predominant material for permanent abandonment of oil and gas wells. However, resins are increasingly finding applications in the mix of barrier materials for plug and abandonment of wells because of unique features that enable their flow into areas where solid bridging makes cement ineffective, their superior mechanical properties and the chemical stability to reservoir fluid. This study demonstrates how multi criteria decision making techniques can be applied for the selection and ranking of polymers as barrier materials in a high-pressure high temperature well abandonment scenario. Four materials shortlisted through material screening in Ansys Granta materials selector are ranked using Technique for Order of Preferences Similar to Ideal Solutions (TOPSIS) againstResAMBER and ThemaSet resins which have been applied in well abandonment operations. A combination of bubble diagrams, a defined boundary/limit operating conditions reflective of HPHT wells, and material performance indices, were used for materials screening in Ansys Granta. A sensitivity test indicates that the top-ranking materials remain unchanged within reasonable variations of the weights assigned to the ranking criteria. The resulting materials ranking shows that the mechanical properties and chemical stability of materials from the Polyamide-imide (PAI), Phenol formaldehyde (PF) and Polyetheretherketone (PEEK) groups support their potential application as barrier materials for the abandonment of high pressure, high temperature (HPHT) wells. The simplicity of this combination of multi criteria decision making techniques and its proven application for solving material selection problems in other industries suggestthat this strategy suitable for application in plug and abandonment.
Effective Apani Marginal Field Development Strategy: A Review of Facility Design and Combined Construction Methodologies to Drilling Location Preparation
Authors: Nwagbo Kenneth C. 
Published: August 2024

Abstract
Oil and Gas resources continue to occupy the attention of the petroleum industry, policymakers, and the general public. It is one of the most important sectors, the most demanding, challenging, and exciting engineering, and technological advances, it is important to investigate the effective ways of developing new marginal field; a review of timely delivery of Apani Field location preparation projects (Drill site, Site camp, Access Road & Utilities) within a record time. Hence, via literature review, this paper is packed with the aim of reviewing the project lean construction management processes adopted in Apani Field development, by determining the oil and gas execution phase, as well as examining the project construction management approach based on the Apani Field Asset Development Plan. It is found that in the accelerated Apani Field drilling location preparation projects execution, a model and/or structure for systematic project management was developed with the aim to improve the decision-making process and overall timely project execution, where typically, the systematic Asset development consist of five main phases, mainly (1) Asset appraisal; (2) Concept selection and definition; (3) Planning phase; (4) Timely project execution and handover phase, (5) Drilling operation and production. Apani Field Asset development strategy is also found to be executed in the typical Oil and Gas projects development stages, namely: (1) Conceptual design; (2) Front-End Engineering Design; (3) Procurement; (4) Facility design; (5) Construction; (6) Installation; (7) Mechanical completion; and (8) Commissioning. The findings of this paper are expected to provide a clear picture and understanding, on how new oil and gas assets (including pre-drilled and plugged wellheads), should be effectively recovered and developed (timely project execution).
Well Placement Optimization for Improved Recovery of a Heavy Oil Reservoir – A Case Study of Heavy Oil Reservoir in Niger-Delta Area
Authors: Ehibor Idahosa Osahon , Maku Gbenga , Amafuna Magnus , Oyekade Suraju , Agbo Johnson , Goodhead Eresinkumo , David Onaiwu , Okoro Emeka , Olafuyi Olalekan 
Published: August 2024

Abstract
Efficient development tactics for oil fields, including well placement, pattern, and quantity, are critical to optimizing oil and gas production yields in mature reservoirs worldwide. However, because of the different API density of the crude oils in the reservoir, enormous number of grid blocks and multiple proxy tests that must be generated, optimizing well placement becomes difficult for reservoirs with significantly larger areal extent.
The objective of this study is to optimize the placements of injector and producer wells in the Field XY field, a heavy oil reservoir under chemical flooding and production in the Niger- Delta region, adopting NPV as the objective function. The optimal configurations of the injection and producer wells are chosen using the differential evolution approach and particle swarm optimization techniques. The technique was programmed for the numerical simulator CMG STARS. The outcomes of the numerical simulation is produced by the CMOST AI-based CMG artificial intelligence optimization technique.
The EOR project's net present value has increased by 57%, according to the optimization method's results. Additionally, following production and injection during a 20-year simulation period, the differential evolution optimization method outperformed the particle swarm optimization.
Developing Engineering Entrepreneurship for Maximizing Opportunities in the Midstream & Downstream Industries of Petroleum Sector
Authors: Oyekan Olugbenro 
Published: August 2024

Abstract
The connection between engineering and entrepreneurship may seem minimal or inexistent, but that would be only to a linear observer, or someone interested only in the spellings of both professions. Any practical observer and market eyewitness, academic or professional, would admit that the differences, in terms of stages and outcomes, between engineering and entrepreneurship are inconsequential. What engineers deal with in infrastructures, physical and technological projects, they are very similar to activities that entrepreneurs undertake in businesses, market, and economies. Ultimately, they like many other professional works, both contribute to the socio-economic development of societies through their abilities to provide solution to problems or inventions for markets.
This initial desk research bothers on the development of engineering professionals into business developers and managers, who can identify economic opportunities within the activities and problems that exist in the midstream and downstream industries of the petroleum sector.
Fortunately, learning is a universal concept by which all mammals can advance their skills and abilities through the intake of information, repetition of actions and formation of habits through interactions with one another despite their diversity. Learning provides a very reliable opportunity for physical, mental, economic, and social growth for development to occur in individuals, their organisations, and the larger human societies.
Epoxy Helicoid Sleeve for Conductor Casings: An Approach to Enhance Structural Integrity and Corrosion Resistance in Offshore wells
Authors: Oboh Stephen , Bakenne Sulaiman , Afamefuna Okenna , Ishomo Lucky , Ugwa Iheanyi , Aziz Ahmad Muzammil Abdul , Samsudin Muhammad Yunus Ahmad 
Published: August 2024

Abstract
Corrosion poses a significant challenge to the integrity and longevity of offshore structures, more severely will be at the splash zone environment. This is the zone where both marine and atmospheric conditions converge exposing structures to corrosive blend of seawater, waves, tidal actions and different atmospheric conditions.
A combined effect of metocean current due to high water depth, well design architecture and mechanical upward forces plays a significant role in the corrosion rate in conductor casings across the splash zone.
The corrosion rate according to Byron F. (Materials Performance Journal 2020); is highest across the splash zone ranging from 0.8 to 1.0mm/yr. with the least corrosion rate being at the subsoil zone ranging from 0.05 to 0.35mm/yr.
The Epoxy Helicoid solution is designed to address structural integrity and corrosion challenges in conductor pipes, the solution combines the benefits of epoxy coatings and helicoidal reinforcement to create a robust and corrosion-resistant system. The epoxy coating acts as a barrier against corrosive elements, while the helicoidal reinforcement enhances the structural strength of the conductor pipes, reducing vulnerability to external forces such as waves and currents.
The potential for increased service life and reduced maintenance costs presents a compelling case for the widespread adoption of this technology in offshore drilling operations.
In conclusion, the Epoxy Helicoid Solution emerges as a promising strategy to effectively mitigate conductor corrosion at the splash zone, contributing to the ongoing efforts within the offshore industry to enhance infrastructure durability and reduce maintenance costs in corrosive environments.
Application of Smart Well Technology in Polymer Flooding for Heavy Oil Recovery
Authors: Uyoyoh O. E. , Ojukwu I. N. , Taiwo O. A. , Olafuyi O. O. 
Published: August 2024

Abstract
This technical paper delves into the Application of Smart Well Technology in Polymer Flooding for Heavy Oil Recovery, with a focus on optimizing injection operations for Enhanced Oil Recovery (EOR) in challenging reservoir conditions. The study involves a comprehensive analysis of reservoir properties, feasibility considerations, and cost-benefit assessments related to the integration of smart well technology. By incorporating real-time monitoring and control systems, smart wells autonomously optimize injection operations to maximize oil recovery while minimizing polymer consumption. The research encompasses a thorough analysis of polymer flooding, heavy oil recovery methods, and smart well technology, culminating in the development of a simulation model to evaluate the performance of smart well-assisted polymer flooding. Results and discussions from the simulation of polymer injection and production plans highlight the potential benefits and challenges of incorporating smart well. technology in polymer flooding operations. This study contributes to the advancement of enhanced oil recovery endeavors and provides valuable insights for future research and development in the field of heavy oil recovery.
Evaluating the Impact of Wellbore Type on Effective Recovery of Condensates in a Gas Condensate Reservoir
Authors: Ibe Alonge , Ehibor Idahosa , Anim John , Ekpah Innocent , Amaefuna Magnus , Olajide Olanike , Amaefuna Magnus , Olafuyi Olalekan. 
Published: August 2024

Abstract
The objective of the study was to evaluate the impact of different wellbore types on the effective retrieval of condensates in a gas condensate reservoir. Two reservoir models were built using CMG (Computer Modelling Group) and IMEX reservoir simulation models. These models had similar rock and fluid parameters, but the only difference was the type of well used. Model A is equipped with a vertical well, while Model B has a horizontal well. The results revealed notable discrepancies in the recovery performance between the two types of wells. Model A, with a vertical well, displayed an initial decrease in output, commencing at a rate of 123 million standard cubic feet per day of gas and 350 barrels per day of condensates at the separator. By the third year, the rate of recovery sharply decreased to less than 20 barrels per day of condensate and 1 million standard cubic feet per day, indicating a dramatic fall in the productivity of the reservoir. On the other hand, Model B, which included a horizontal well, showed a more advantageous recovery path. Gas extraction has commenced at a rate of around 1000 million standard cubic feet per day, together with a strong recovery of 704 barrels per day of condensate in the separator. In contrast to the vertical well, the horizontal well demonstrated consistent and prolonged performance until encountering a decrease. The results emphasize the significant influence of wellbore type on the efficiency of recovering condensate in gas condensate reservoirs. Horizontal wells have shown improved performance in terms of enhanced recovery rates and sustained productivity when compared to vertical wells. This study provides useful information for enhancing the development and exploitation strategies of gas condensate reservoirs.