bluuebunny/crossref_metadata_2025 huggingface dataset:
Heavy Oil Development and Reserve Addition Potentials: The Abura-6ST Case
Authors: Ijomanta Henry , Ifeduba Ebuka , Ayeni Olayinka , Akenobo Charles , Okoh Oluchukwu , Igbokwe Obianuju , Adebayo Odude
Published: July 2023

This paper evaluates the effect of the increment in recovery factor of the Abura Heavy Oil reservoirs on the heavy oil portfolio of NNPC E&P Limited and, ultimately, the reserve valuation of Nigeria as a country, considering that the Niger Delta basin has a significant amount of heavy oil reservoirs.

The Abura field has three (3) heavy oil reservoirs (1AB6, 2AB6 and 3AB6) with viscosity ranging between 10-17cp. These reservoirs were booked as contingent resources owing to sub-optimal production using conventional techniques and sub-commerciality. An FDP study in 2018 revealed that the heavy oil reservoirs could not sustain production and hence, are uneconomically viable to develop. The initial reservoir simulation results showed flow assurance issues mainly due to the high oil viscosity and consequently poor production rate, high water cut, and high-pressure drawdown due to unfavorable mobility ratios and flow assurance challenges caused by the high oil viscosity. Improved Oil Recovery (IOR) techniques were designed to combat the highlighted issues. The combination of IOR techniques employed includes deploying a Single Well Multiple completion which allowed the completion and commingling of 2 reservoirs (1AB6 and 2AB6) in the same tubing for increased oil production, deploying an Electrical Submersible Pump (ESP) to solve vertical lift challenges, installing Autonomous Inflow Control Devices (AICDs) to allow the preferential flow of oil, hydrocarbon fingerprinting for reservoir management and production allocation, and Micro Emulsion Based (MEB) stimulation post-completion, to reduce skin due to formation damage.

The results led to a significant increase in the forecasted production and, therefore, an increase in the reservoirs’ Expected Ultimate Recovery (EUR). This led to an eventual improvement of recovery factors for both reservoirs, positive migration of the contingent resources to reserves, increased revenue for the company, and a positive outlook for the numerous heavy oil resources in the company portfolio.
Well Management: Top Tier Well Approach
Authors: Bakenne Sulaiman , Oboh Stephen , Lucky Ishomo , Ugwa Iheanyi
Published: July 2023

Effective well management and reliability are fundamental to ensuring high well production uptime with the attendant benefit of minimizing unscheduled volume loss. Well equipment reliability is impacted by the scope and frequency of preventive maintenance (PM) in place. The optimum PM frequency is one that maximizes incremental value with reduced equipment failures. While defining the PM program, due consideration must be given to the well risk (business and safety) which impacts consequence level of failures. In matured assets with high well counts, PM programs should be structured to maximize uptime of wells with significant volume contribution, critical gas producers to support gas lift systems and injectors while also minimizing process safety risk on all wells. These wells are referred to as top tier wells.

This paper defines criteria for selecting top tier wells. It also focuses on using a Prevent-Detect- Respond-Recover (PDRR) approach in defining a well equipment PM program that meets industry and local regulatory requirements to drive improved reliability of the top tier wells.

Prevent-Detect initiatives leverage Root-Cause-Failure-Analysis (RCFA) data to minimize the likelihood of equipment failure, and by extension, provide a focused surveillance system to ensure failures are detected before equipment are taken out of service. Whereas Respond-Recover initiatives provide a defined response plan to well equipment reliability issues through low complexity intervention actions and subsequent detailed repairs to correct detected failures with minimal downtime impact.

The benefit of a top tier approach to PM is to drive incremental business benefit for the asset through optimization of existing resources.
Application of Blockchain Technology in the African Energy Industry: Use Cases, Limitations and Solutions
Authors: Chime C. E.
Published: July 2023

This paper explores the potential application of blockchain technology in the African energy industry, in the process, highlighting various use cases, identifying limitations, and proffering solutions to these limitations. The African energy industry is plagued by a plethora of problems such as a lack of access to reliable energy, the absence of transparency and trust, and limited access to financing amongst others. Blockchain technology can be employed to address these challenges by providing secure and transparent platforms for energy transactions, enabling peer-to-peer energy trading, and facilitating access to financing for both renewable and fossil energy projects. On the other hand, the implementation of blockchain technology in the energy industry faces several limitations which include a lack of regulatory clarity or a defined framework, inadequate infrastructure, and a lack of technical know-how. To address these limiting factors, this paper proffers several solutions such as the development of a clearly defined regulatory framework to enable the implementation of blockchain technology, the creation of industry standards to ensure interoperability and uniformity, and the promotion of education and training programs to build technical expertise. This paper also highlights existing case studies of blockchain-based energy projects in Africa to demonstrate the potential of blockchain technology in the energy industry. The paper concludes that while blockchain technology has the potential to revolutionize the African energy industry, early adoption is key and the importance of addressing existing limitations cannot be overemphasized.
Implementation of One-Trip Acid-Jetting Solution in AX field for an Operator in Nigeria
Authors: Ngerebara Justus , Alawode Olusiji , Hamzat Ismail , Gerber Jesse , Olaobaju Oluwaseyi , Onuoha Jombo , Espinoza Omar , Andrew Colin
Published: July 2023

The paper describes the integration of Service Provider's one-trip washpipe-conveyed Jetting-tool assembly with an 8.5″ open-hole horizontal stand-alone-screen sand-face completion for optimal delivery of acid treatment to the sand-face of injector well typically performed post completion following poor injectivity.

AX field injectivity performance has been on the declined mostly attributed to poor sand development, shorter horizontal interval (Low NtG), fines migration, hammer effect, and ineffective removal of filter cakes. To manage this, Operator employed two main approaches to tackle the problems which include the use of check valve screens and Jetting tool for acid treatment at the sand face to effectively dissolve and remove filter cake following a learning from Gulf of Mexico in 2021 (OTC 31713). The integrated team, comprising of Operator and Service provider carried out extensive design upgrade and modifications of the Jetting tool technology. Additional scope included integration with a separate third-party service tool and adapting a barrier valve's shifter tool in the Jetting tool.

The Jetting-tool technology has been successfully implemented in the acid treatment of two injector wells in the AX field with reported early positive signs of improved injectivity thereby removing the high cost of post-completion stimulation to enhance injectivity.

This new approach allows the operator to save significant post-completion intervention costs by adding the stimulation capability to the completion phase of the well, obtaining a better well-injectivity performance at a reduced cost which would have been otherwise done with coil tubing.
The Future Perspective: Geothermal Energy in Nigeria – An Option to be Explored
Authors: Kelechi F. M. , Owoka O. I.
Published: July 2023

As the transition towards a green energy future intensifies, cleaner energy sources are expected to drive the decline in the demand for fossil fuels. This creates room for renewable energy sources such as geothermal. Geothermal energy is generated from the earth's crust which is transported through cracks and fractures in the host rocks and its natural fluids at temperatures above the ambient level. The rate of heat flow in the crust is estimated to be 59Mw/m2 [1.9*10-2 Btu/h/ft2]. In mature continental cratons, the geothermal gradient can be as low as 10 °C per kilometer. However, in active volcanic areas, it can exceed 100 °C per kilometer. A typical geothermal gradient of 25 °C km− 1 gives a conductive heat flux of 60 mWm− 2 for electricity generation. Considering the Nigerian basement complex, the estimated geothermal gradient of Borno and Sokoto States, both located in the Northern region are 1.1 to 5.9°C/100m with a heat flow of 8.9 to 117.8mW/m-2 and 0.9 to 7.6°C/100m with a geothermal heat flow of 52.11 to 130.28mWm-2 respectively. In addition, in eastern Nigeria, Anambra State, the estimated geothermal gradient is 2.5 to 4.9°C/100m with a heat flow of 64.4 to 97.3 mWm-2. Geothermal energy has the potential to improve Nigeria's current poor energy dynamic. Enhanced Geothermal System would exploit heat energy that is trapped in the subsurface host rock by creating an open system of connected fractures along which water can flow down the injection wells and get heated through contact with the rocks. This is then recovered to the surface in production wells to form a closed loop. The idea is an extrapolation that emulates a hydrothermal circulation system – which produces electricity that can be applied commercially.
Geomechanical Risks Screening of Producing Fields – Key Contribution to Safety Standards
Authors: Arogun Olubunmi , Schutjens Peter , Anijekwu Chinedu
Published: July 2023

Production of oil and gas, as well as injection of water, gas, or steam, will generally cause a change in pore pressure, total stresses and temperature in the reservoir and its surrounding formations. The resulting stress changes may cause compaction or lead to shear failure or tensile fracturing, that in turn can lead to fluid containment issues and compromise the integrity of the wellbore and surface facilities. In line with the company's Goal Zero vision, 48 active fields in the Niger Delta, some of which have been producing since the 70s, were subjected to fit-for-purpose screening to ensure geomechanical risks associated with our operations were identified and adequately handled. Some of the fields are highly faulted and compartmentalized. Oil accumulations are fault controlled and several of the fields have gas caps.

The screening identified risks such as sand control, compaction and subsidence, top seal integrity loss and wellbore instability in the fields. The risks were assessed using the Risk Assessment Matrix to check potential impact on safety and production and the probability of occurrence which ranged from low to medium. In compliance with process safety requirements, the risk of reservoir compaction was evaluated using 1D analytical models. The screening resulted in proposals of integrated solutions to address and mitigate the risks. The recommendations included, 1) acquisition of core measurements to reduce uncertainty of uniaxial strain compressibility required to estimate reservoir compaction, and 2) mechanism-based evaluation of seal integrity to analyze the potential of out-of-zone-injection and cross flow between reservoirs. Some recommendations have been implemented to reduce the risks to as low as reasonably possible (ALARP).

This paper presents our method of geomechanical risk screening and gives examples of its positive impact on the company's safety standards via implementation of integrated solutions to prevent or mitigate the geomechanical risks.
Evaluation of Groundnut Shell and Yam Peel as a Loss Circulation Control Material in Drilling
Authors: Ishaku Y. , Okafor I. , Jakada K. , Nzerem P. , Salihu A.
Published: July 2023

As a result of enormous uncertainties and high cost of materials employed in the design and formulation of drilling fluids used drilling operations in the oil and gas industry, it is important to select the most appropriate drilling materials to increase drilling efficiency, while reducing the total cost of drilling through import substitution, especially with locally available materials. In this paper, an experiment was conducted to test and investigate the suitability of Yam Peel and Groundnut Shell as loss circulation materials. The selected lost circulation material was washed, purified, dried, and crushed, thereafter the materials were characterized using the FTIR and SEM. Different mud samples were prepared using the locally sourced materials and Carboxymethyl Cellulose (CMC), tested for its rheological properties, and thereafter compared to ascertain the suitability of the mud prepared with the locally sourced lost circulation material drilling, in line with established API standard. Results obtained shows viable comparison between the locally sourced loss circulation material and its imported lost circulation material.
Hydrodynamic Cavitation as Oil Pretreatment Prior to Distillation
Authors: Ajinomoh C. S. , Momoh O. R. , Maku J. J.
Published: July 2023

Hydrodynamic cavitation has been employed in literature to distort the structure of crude oil as a way of its intensification prior to refining, with majority paying attention to adding additives in order to improve the yield. No attention has been paid to varying the storage time of the crude after cavitation. Hence, it was thought necessary to vary the storage time after cavitation in order to increase the yield of crude oil. 350 g of the feedstock was characterized and then continuously circulated through an orifice/cavitation device for 30s, then it was stored in an airtight plastic container. The storage time was varied from 2 hours to 240 hours for different runs. True boiling Point distillation for 295g of the cavitated crude was carried out after. The results showed that there was a strong correlation between the changes in the density of the stored cavitated crude and the yield of the crude. The yield of lighter distillate/fractions increases with reduction in density of stored cavitated crude and the yield of heavier distillate increases with increase in density of cavitated crude. The increase in the yield of light fractions was attributed to cold cracking of heavier molecules in the crude and the increase in yield of heavier fractions was attributed to the recombination reactions of the radical molecules in the crude. The increase in the overall yield when compared with untreated crude can be achieved by striking a balance between cold cracking and recombination reactions which occurred at 122 hours of storage after cavitation
Evaluating the Potential of Renewable Energy to Address Energy Accessibility, Affordability, and Sustainability Challenges in Africa
Authors: Ezeh M. C. , Fidel-Anekwe T. H. , Ikpabi P. B.
Published: July 2023

Energy accessibility, affordability, and sustainability are crucial factors for developing any country, particularly in Africa. The numerous challenges most African population face in providing reliable and affordable energy to their communities hinder economic and social development.

This study evaluates the potential of renewable energy to address energy accessibility, affordability, and sustainability challenges in African countries. To do this, the study involves a review of successful renewable energy projects in Africa and an analysis of energy consumption and production data. Several key factors are considered in this analysis. Firstly, this study examines the feasibility of different renewable energy technologies in African contexts. This includes an assessment of the potential for solar and wind power to provide reliable energy, as well as an examination of other renewable energy options. Secondly, the study considers the economic and financial implications of renewable energy adoption. This includes analyzing the costs and benefits of different renewable energy technologies, including examining the financing and investment requirements for renewable energy projects.

Finally, this study assesses renewable energy's social and environmental impacts in Africa. This includes an evaluation of the potential for renewable energy to improve energy access in disadvantaged communities and examining the environmental benefits of renewable energy. By examining successful renewable energy projects and analyzing energy consumption and production data, this study provides strategic recommendations on how African countries can adopt renewable energy technologies to enhance their energy systems and transition to cleaner energy sources.
Prediction of Thermal Conductivity of Rocks in Geothermal Field Using Machine Learning Methods: a Comparative Approach
Authors: Ekeopara P. U. , Nwosu C. J. , Kelechi F. M. , Nwadiaro C. P. , ThankGod K. K.
Published: July 2023

Thermal conductivity of rocks defined as the ability of rocks to transmit heat, can indicate the potential for geothermal resource in a given location. While direct laboratory core sample analysis and indirect analysis leveraging empirical correlations from electric logs are used to determine thermal conductivity of rocks, they are usually expensive, time consuming and difficult to implement. Hence, in this study, several machine learning methods specifically Gradient Boosting Regressor, Random Forest, K-nearest neighbour, ensemble method (voting regressor), and Artificial Neural Networks were developed for the real-time prediction of thermal conductivity of rocks in geothermal wells. Data being obtained from Utah Forge field project included drilling data, thermal conductivity data and other necessary information from the field. With real-time sensor drilling data such as Rate of penetration (ROP), surface RPM, Flow in, Weight on bit (WOB), and Pump pressure, as input parameters and matrix thermal conductivity (MTC) as output, the models were developed. The results obtained from this study, showed excellent performances for majority of the models. However, it was observed that the ensemble voting regressor, which combined the top three models was able to predict thermal conductivity with above 89% and 80% R2 scores on the train and validation datasets respectively. Thus, this research work describes the feasibility of leveraging several machine learning methods in estimating thermal conductivity of rocks which is cost effective, and practically achievable.
Modified Straight-Line Depreciation Model for Upstream Petroleum Investment
Authors: Ogolo Oghenerume , Iyalla Ere , Tahir Salahudden M. , Ileogbunam Emeka , Egede Frank , Obe Ayodele
Published: July 2023

Depreciation is a method used to recover the cost of an asset or facility used to develop and produce petroleum from any oil and gas field. The challenge with the straight-line depreciation method used to depreciate an asset was, it does not take into consideration the time value of money. Over time, the value of money changes. The amount recovered after the depreciation period is usually less than the future value of the asset. This is because the value of money today is not the same as the value of money tomorrow. Hence, there was the need to incorporate the time value of money into the straight-line depreciation model. This research considered the incorporation of the time value of money into the depreciation equation. The conventional straight-line depreciation equation was modified by incorporating the time value concept of money into the equation. A petroleum economic model was developed using a spreadsheet approach. The model was used to evaluate the impact of the modified straight-line depreciation model on the profitability of petroleum investments. Two petroleum investment scenarios were considered. Scenario 1 had the conventional depreciation model. Scenario 2 had the modified depreciation model for comparative analysis. The effect of the conventional and modified depreciation model on the profitability of the investment was evaluated. The NCF of the contractor for Scenarios 1 and 2 when the oil price was $50/bbl was $214 MM and $317 MM respectively. While the NCF of the host government for Scenarios 1 and 2 when the oil price was $50/bbl were $627 MM and $524 MM respectively. It was observed that the incorporation of the time value of money into the depreciation equation increased the NCF of the contractor. This allowed the contractor to mitigate the effect of risk associated with the value of the asset over time due to inflation. The modified depreciation model made the petroleum fiscal arrangement more attractive.
Oil & Gas Production Capacity Digitalization – A Strategic Approach to Production Deferment Management
Authors: Adebajo A. K. , Duruzor E. D. , Oyakhire B. O. , Onasanya B. A. , Nwangwu C. V. , Michael E. O. , Akpedeye D. O. , Afere O. O. , Ayalogu D. I.
Published: July 2023

Deferred production is a common occurrence in the E&P industry particularly for mature assets, usually accounting for significant volumes to an assets total production. As a result, E&P companies are continually pursuing innovative ideas and leveraging the latest technologies to support earlyidentification of underperforming wells to minimize production loss and maximize asset recovery.

This paper focuses on Oando Energy Resources (OER) in-house development and operationalization of a Production Capacity Digitalization solution. A continuous business process improvement initiative geared towards enhancing the management of the company's portfolio of shut-in wells and reporteddeferred volumes. The digital solution is designed to guide senior management towards strategic planning and achieving cost-effective production restoration by integrating time, budgetary and economic factors in a single platform for shut-in volumes classification.

The digital platform integrates multi-disciplinary asset data, deferment management processes withorganizational structure and leverages petroleum engineering workflows (validation, diagnosis & analysis) for systemic understanding and collaboration of stakeholders, to make informed decisions on volumes restoration efforts, ensure the technical team is chasing the "right" volumes forrestoration and focus on high priority assets with critical production capacity.

This paper describes the production capacity workflow, implementation, development strategy, valueproposition and benefits of the solution to OER on her quest for improved business performance management and operations excellence in order to maximize value for all stakeholders.
Practical Hydrocarbon Allocation – A Machine Learning Approach
Authors: Diaso K. I , Kalio J. , Owoseni S. M. , Duruzor E. , Onasanya B.
Published: July 2023

The current conventional method of hydrocarbon production allocation of reservoir fluids’ contribution to the separate producing strings from commingled production in the oil and gas industry considers some rigid assumptions that make the allocated volume mostly unreasonable. This uncertainty is usually due to the fixed decline rate assumption normally adopted for a specified period until a new well test of the contributing strings is available to generate a new allocation factor anytime production allocation is required.

This paper presents an artificial intelligence approach in the determination of real-time allocation factors for determining contributing production flow performance from commingled production using a machine learning algorithm with the fixed rate assumption using well flow parameters such as the flowing tubing head pressure, flowline pressure and other well parameters to generate transient rates for the producing strings, to create new allocation factor when required.

Data from marginal fields in the Niger Delta were used as case studies and the results generated from this exercise after proper data pre-processing depict reasonable output with precision of high confidence level. Results from this approach can also be used in the absence of a reliable well test.
Achieving Sustainable Energy Transition; - What Works in Sub-Saharan Africa
Authors: Kelechi F. M. , Ogbodo I. S. , Adah J. A. , Aribisala A. A. , Akagbosu P. I.
Published: July 2023

According to a United Nations report from November, 2022, the world population reached 8 billion for the first time in human history with 6.74 billion people living in low and middle - income countries (LMICs) and 1.3 billion living in developed countries. 53 of Africa's 54 countries fall under the former category. The population of Africa is estimated to be 1.4 billion with 1.17 billion in sub-Saharan Africa. Presently, 770 million people globally have no access to electricity mostly in Africa and Asia with 3.8 billion depending on solid fuels for cooking and other domestic uses. Data obtained from WHO reported that 568 million people in sub-Saharan Africa are living without access to electricity and clean energy. In developing nations, wood, charcoal, and dung are commonly used as traditional cooking fuels, with wood being the primary source of energy. The emission from these fuels in addition to those from fossil fuels further reduces the quality of air which causes ambient air pollution, a condition with adverse effects on human health. However, there are initiatives that have been adopted to alleviate the problems including the future expectation for global access to clean energy as conveyed in the 2030 United Nations Sustainable Development Goals (goal number 7); the 2063 African Union Commission Agenda; the Paris Agreement at COP21; and the United Nations Sustainable Energy for All (SE4A). This paper reviews historical trends in energy usage in sub-Saharan Africa, the present conditions and status of development, across policy and technological prongs, in terms of the current energy transition. Furthermore, the paper seeks to highlight opportunities for future sustainable energy development across all sectors and businesses in order to provide energy to the 568 million without access in sub-Saharan Africa, while bearing in mind the environmental implications for the global population at large.
Rigless Conductor Piling Using Threaded Tubulars - A Strategy to Sustain Oil Production in Onshore Niger Delta
Authors: Mrakpor O. , Adigolo C. , Anorue F. , Udi E. , Oga-Eluwa K. , Ahaneku G. , Campbell W.
Published: July 2023

Onshore Producing wells in proximity to new cellar slots are required to be shut-in during rigless conductor piling operations using welded conductors. The project objective is to design a novel technology system that can safely makeup and drive threaded conductors without using a drilling rig, thus preventing welding operations (hot works) and production deferment.

A multi-disciplinary approach of drilling, safety and structural engineering was implemented during the planning phase. System integration test (SIT) was carried out between the drive sub, piling hammer and conductor. Anticollision analysis was carried out to prevent collision issues with producing wells. Conductor pipe specification was defined to withstand piling loads. A two-staged support frame was designed and fabricated for conductor centralization. Conventional tubular running equipment was combined with piling equipment to make-up and drive threaded conductor pipes. Conductor verticality was achieved using two cranes positioned perpendicularly, working in-tandem and personnel coordinated with intrinsically safe radio devices.

The use of this hybrid technology ensured that three slots were successfully piled without welding operations or shutting-in producing oil wells, saving a total of 21,000 bbls ($1.89m @ $90/bbl). Case studies of previous rigless conventional piling operations using welded conductors were compared with the slots piled using the novel rigless hybrid technology. The new approach is safer and more efficient with utmost benefits in sustaining hydrocarbon production in existing locations with live wells close to the new slots. The most significant new finding is that it was possible to make up and drive threaded conductors safely onshore without using a drilling rig, thereby eliminating welding (hot) works.
Zeolitic Imidazole Frameworks for Super Selective Separation of Propylene from Propane
Authors: Agbajei T. A. , Karanikolos Georgios N. , Khaleel Maryam
Published: July 2023

Olefin and paraffin gases are important products of the petrochemical refining industry wherein their effective separation could provide high economic gains and competitiveness in the emerging energy markets amidst state-of-the-art technology. Important chemicals such as polyethylene and polypropylene are derived from raw materials in the form of light olefins, including ethylene and propylene, processible via naphtha cracking. However, since this leads to its production among other valuable by-products separation/refinement is required and this is commonly achieved through technical and energy-intensive cryogenic distillation due to the similarity in thermophysical properties of the process effluents. Thus, cost-effective and energy-efficient processes are required among which membrane-based separation techniques stand out. In that line, zeolitic imidazolium frameworks (ZIFs) have shown a superior potential to provide high selectivity and high permeability to particular species in a mixture they are used to refine. This superior effectiveness is attributed to ZIF's uniform pore sizes that enable sharp molecular sieving, as well as its highly porous structure that enables fast species transport through it, with minimal mass transfer hindrance for the targeted/preferably selected specie. Among ZIFs, there exists one called ZIF-8 which is especially suited to propylene/propane separation and has been widely reported for its sharp molecular sieving performance for this mixture. ZIF-8 is also distinctly stable, and relatively easy to synthesize from cheap and readily available starting materials. Recent advances in the fabrication methods reported for ZIF-8 synthesis are presented in this work, along with a comparison of the separation performance for propylene and propane resulting from different types of ZIF-8 produced by these methods. The potential effect of utilizing this ZIF material in the refining units applied for olefin/paraffin separation is also critically evaluated towards its industrial utilization.
Accessing Energy Resources in a Complex Geologic Setting Unraveled by Ocean Bottom Node (OBN) Seismic During Project Execution
Authors: Ochai-Audu E. N. , Otung A. D. , Mora-Glukstad M. , Nworie E.
Published: July 2023

As we go through the energy transition, accessing energy resources in a complex geologic setting such as the shallow offshore Niger Delta remains a challenge. Utilizing advanced technology/method to understand the subsurface and locate the remaining "advantaged hydrocarbon" is key for optimal well placement and sustainable production. The unsuccessful drilling results of a recent late life Shallow Water Asset development campaign drove the use of recently acquired advanced technology seismic, Ocean Bottom Node (OBN) integrated with other data set to analyse the reason for the well failures and propose alternative scenarios. As the resulting evaluation clearly explained why the wells failed, technical reviewers considered that the results were sound and supported the drilling of a new well based on the latest evaluation. A new well was successfully drilled, reservoir parameters matched new predictions and initial production was estimated at ~2000 bblo/day. Results showed that the structure is much smaller than what was initially interpreted on the legacy seismic. Hence, plans to drill more wells into the structure was dropped. The learnings from this evaluation were deployed to all planned shallow water wells to prevent future suboptimal well results.
Integrated Approach to Addressing Well Integrity Challenges: A case study of Well AA
Authors: Ezenobi Eric , Alli-Oluwafuyi Jumah , Imorame Imonitie , Okolomma Emmanuel , Biambo Tamunotonye , Laoye Abiodun , Ayodele Bunmi , Nworie Ejiuwa
Published: July 2023

Operating wells safely is a critical aspect of E&P business because of the significant exposure and huge negative impact of associated incidents on People, Asset, Community and Environment. Well integrity failure has grave reputational and financial consequences which can ultimately lead to losing license to operate and/or loss of lives. In our company, well integrity management receives topmost leadership focus, with requisite standard guidelines, which are regularly reviewed and updated to ensure the objective of operating wells safely are achieved.

The risk of loss of well integrity is higher as wells age, however, in some very few cases newly completed wells may also fail. Loss of well integrity could result in sustained annular pressure, hydrocarbon spill, underground blow-out, or contamination of ground water aquifer in some cases. The potential causes include (but not limited to) poor cement annular cementation or bonding, casing/tubing corrosion and/or compromised completion jewelries.

Our case study, Well AA is situated in the shallow offshore terrain of the Niger Delta. The well was completed as a Single String Single (SSS) horizontal oil producer. Shortly after the well came on-stream, sustained high A-annulus pressure was observed during ramp-up. This eventually exceeded the Maximum Allowable Annular Surface Pressure (MAASP), resulting in a well integrity concern.

A comprehensive risk assessment was carried out to identify potential leak path, generate risk assessment matrix and recommend preliminary leak investigation activities. In line with the guideline, initial bleed-down procedures were deployed but this did not abate the A-annulus pressure. Detailed downhole investigation integrating spectral noise and high precision temperature logs confirmed the production packer was compromised. Subsequently, well AA was worked over and integrity restored, safeguarding production promise of over 1500 bopd.

This paper therefore details the integrated approach taken by the asset team to identify the well integrity issue, assess risk level, investigate cause of A-annular pressure build up and how it was addressed. This paper is intended to provide a guide to technical staff facing similar well integrity challenge.
Reservoir Modelling of Multizone Completions in Brown Field Excellence Workover Wells
Authors: Ikwan Ukauku , Azugwu Isidore , Iwegbu Chibuzo , Avu Albert , Agwu Ndukwe , Eta Edirhin
Published: July 2023

Many fields in the Niger Delta are made up of stacked reservoirs. Conventional completion and production are by bottoms-up approach. Multizone completion using one string as a key element of Brown Field Excellence is novel or at best evolving in Nigeria. It ensures many reservoir intervals are completed and comingled during production and has many benefits. Major challenges are delivery schedule of equipment, additional regulatory approvals and cross flow that could impact both rate and ultimate recovery. Proactive engagements for co-creating the solution at design phase is a panacea for successful multizone completion workover. In this paper, a muti-tank material balance reservoir model was built and used to predict performance and cross flow phenomenon in eight comingled stacked reservoirs. Most importantly, the model shows that in this novel approach of WO recompletion it is possible to achieve an instantaneous potential of 11.5 Kbopd with 8 zones comingled even in the presence of cross flow from an old well that made a maximum of 3.0 Kbopd from conventional completion. By closing the cross flow big heater reservoir from the onset behind sleeve till cross flow ceases following pressure equilibration, it is even possible to achieve initial instantaneous potential of 12.0 Kbopd. It is recommended to use the model to close behind sleeve, interval with negative flow rate (cross flow) during production of the multi zone completed well. The modelling approach in this paper is recommended for application in other Brown Field Excellence multi zone completions in any multizone workover portfolio. The model could also argument hydrocarbon accounting techniques of routine finger printing and production logging since it predicts contributions of all fluids from each zone viz oil, gas, and water rates as a function of time.
Exploring the Feasibility of Implementing Polyalphaolefin (PAO) Lubricants as an Alternative Lubrication Solution in the Petroleum Industry
Authors: Akpoghomeh O.
Published: July 2023

The petroleum industry is a significant consumer of lubricants, with an estimated consumption of more than 2 billion gallons per year. However, the use of traditional lubricants in this industry can have significant environmental and economic impacts. One potential alternative lubrication solution is the use of Polyalphaolefin (PAO) lubricants. PAOs are synthetic hydrocarbons that are biodegradable and non-toxic and can provide good lubrication and corrosion protection.

This research aims to investigate the feasibility of implementing PAO lubricants as an alternative lubrication solution in the petroleum industry. The study will include a review of the current state of the art in PAO lubricants and their potential application in the petroleum industry. The study will also include laboratory testing to evaluate the performance characteristics of PAO lubricants in comparison to traditional lubricants under various conditions representative of the petroleum industry.

This research will provide a comprehensive analysis of the technical, economic, and environmental aspects of using PAO lubricants in the petroleum industry. This includes the evaluation of the costs and benefits of using PAO lubricants, as well as the environmental impacts associated with their production and use. The results of this research will provide valuable information for the petroleum industry and could potentially lead to a significant reduction in the environmental impact of lubricants used in the petroleum industry.

It is expected that this research will show that the use of PAO lubricants could lead to a reduction of up to 15% in lubricant consumption and up to 20% in greenhouse gas emissions in the petroleum industry. Additionally, it's estimated that the use of PAO lubricants could lead to a significant reduction in the environmental impact of lubricants used in the petroleum industry, with a reduction in the environmental impact of up to 50% compared to traditional lubricants.
In-House Software Development for Viscosity Computation
Authors: Lukpata J. L. , Mmata B. , Onyekonwu M. O.
Published: July 2023

Viscosity is one of the most important fluid properties required in characterizing or evaluating hydrocarbon oils. Experimental measurement of viscosity can be strenuous and time consuming especially for dead oils; even when measuring with top notch equipment models like Vinci 1000 viscometer, Amatek CAP1000+ viscometer, etc. Amongst the various viscometers available in the petroleum industry, the cannon-fenske viscometer is a widely used and accepted model for dead oil viscosity measurements as it conforms to ASTM 445. Although very self-efficient, the use of this equipment involves time-consuming computations. A more challenging task with this equipment is choosing a suitable tube size for a particular fluid. This involves a long series of trials and validity checks which invariably leads to man-hour loss. This work introduces a user-friendly software solution for use with the cannon-fenske viscometer. The software was built on the python Graphical User Interface (GUI) framework, Tkinter, employing modules as Pandas, NumPy, Sklearn (scikit), etc. It was developed within the JetBrains PyCharm 2022 Integrated Development Environment (IDE). Object-Oriented Programming (OOP) technique was adopted for implementing the workflow for all calculations. This software solution performs all calculations and checks associated with the cannon-fenske viscometer. In addition, it comes with a built-in stopwatch that can be used in the absence of an external stopwatch. Validation of results was done using fifty-five (55) data sets from the laboratory. It is concluded that the use of the software reduces human errors associated with manual computation of results while using the cannon-fenske viscometer. The use of this software also makes viscometer tube selection easy. The overall time spent on viscosity measurements is reduced (by more than 50%) with the use of this software.
Well Diagnostic of New Underperforming Wells Using Downhole Log Tool [SNT & MDT]
Authors: Gidado A. O. , Ekesiobi C. , Kpone-Tonwe H. , Adesun J.
Published: July 2023

Production of hydrocarbon from wells drilled into oil bearing zones for sustained period of time could result in wellbore integrity damage, which is capable of shutting down oil and gas production. To detect such problems, a diagnostic operation is performed to acquire and identify the source(s) of the wellbore integrity damage. The result of this, is raw subsurface well data, requiring further qualitative interpretation to establish causes and solutions to wellbore problems. To improve the accuracy of subsurface well data qualitative interpretation, the data acquiring process must be efficient and painstakingly performed. This work outlines and describes process of acquiring data through well diagnostics. This technique is applied to a well in the Niger Delta area operational for 10 years. The production volume from the well was about 68% lesser than expected rate from the DST result. Magnetic Thickness detection (MTD) and SNT-Temperature log were deployed as a wellbore diagnostic tool. The MTD tool run in the long string of the well from 13,742ft to 10,302ft, helps in detecting End of Tubing of the short string at 10,562.6ft, corrosion detection (Tubing Wall loss) at 12% maximum, perforation depth and casing conditions. The SNT-Temperature tool was run through the entire length of the tubing. It helped in detecting tubing leak at 13,391ft, formation activity between two reservoirs at 13,530ft – 13,560ft and fluid flow from perforation depth. These diagnostic analysis helps in identifying uncertainties in the well bore, thereby postulating direct solutions for the well.
Implementation of Engineered Rigless Through Tubing Sand Exclusion Solution to Enhance Hydrocarbon Production: The Field X Case Study, Niger Delta, Nigeria
Authors: Momodu Ehigie , Soro Augustine , Olaoye Abiodun , Omedo Augustine , Osode Peter , Olugbade Oluwatobi Raymond , Akinlade Deji
Published: July 2023

Sand production is widely recognized to have a detrimental influence on well deliverability and creates safety concerns because of equipment damage and surface flowline breaches. Sand production, while unavoidable in highly permeable reservoirs like in the Niger Delta basins, is deleterious to both downhole completion and surface hydrocarbon production and treatment systems, as with the candidate wells in the Field X. Sanding in these candidate wells required sand management being a daily routine alongside daily hydrocarbon production throughout the life of the wells until it became unmanageable and costlier, resulting in most of the wells being shut in, thus causing significant production deferment and loss of revenue

An immediate need for a safe, cost-effective, and timely Sand Exclusion Solution was required to improve and restore production with minimum allowable/manageable sand production from the wells. To find the optimum approach to address the sand production issues, a variety of alternatives were considered, including well recompletion workover, in-situ sand consolidation, internal gravel packing, and rigless Thru-Tubing Sand Screen Hang Off, to restore completion integrity. Following several review meetings, Thru-Tubing Sand Screen Hang-off was chosen as the safest, time and cost-effective choice because of its minimal equipment spread, properly sized sand screens and in-house knowledge to for successful installation. However, intervening the candidate wells with minimal equipment spread required thorough subsurface studies, well engineering, and reservoir simulations (Nodal Analysis), to tailor the solutions to what the wells required.
Phase Behaviour of a Near-Critical Gas Condensate Reservoir Fluid from a Conventional Field in the Niger Delta
Authors: Mmata B. , Kiinee L. , Okeke H. , Onyekonwu M. O.
Published: July 2023

Near-critical gas condensate reservoir fluid like near-critical oil has a very complex hydrocarbon phase behavior and is likely to be encountered as deeper formations are been drilled in an extensive search for hydrocarbon deposits. It is a highly unconventional fluid and lacks adequate characterization approach in the open literature due to its complexity as it is found in the near critical region of a hydrocarbon phase envelope of a multi-component system. All known Equations of State models such as Peng Robinson (PR), Soave-Redlich-Kwong (SRK) etc, have been found to be inadequate in characterizing this fluid. This paper presents an experimental methodology and results of a Pressure-Volume-Temperature (PVT) analysis done on two near-critical gas condensate reservoir fluids from a gas field in the Niger Delta region. Constant Composition Expansion (CCE), single stage flash and reservoir fluid composition analysis were carried out using state-of-the-art visual PVT cell and gas chromatograph. The CCE test performed clearly showed the unusual but unique formation of two liquid phases rather than one liquid phase during the isothermal depressurization below the dew point pressure and the subsequent disappearance of the lower liquid phase. This critical opalescence phase behavior is unique to a near-critical gas condensate fluid. The CCE experiments also showed the maximum liquid drop out (LDO) behavior (about 45% condensate dropout) at a small pressure drop of 100-150 psig below the dew point pressure. The C7+ mole percent (<12.5%) and the produced gas-oil ratio (>5,000 SCF/STB) were other parameters used to further provide a reasonable insight that the fluid under study is a near-critical gas condensate. In conclusion, proper characterization of a near-critical gas condensate reservoir fluid will greatly aid the reservoir and production engineers to have a better and more robust field development strategy to produce and manage near-critical gas condensate reservoir.
Balancing Energy Access in Sub-Saharan Africa: A Comparative Analysis of Energy Accessibility in Sub-Saharan Africa and Northern Africa
Authors: Ezeh M. C. , Okoroafor E. R.
Published: July 2023

Modern civilization depends on energy to survive; therefore, it must be readily available, affordable, reliable, and safe. With over 1.2 billion people residing in Sub-Saharan Africa, over 570 million people live without electricity, and 900 million have no access to clean cooking (IEA, 2020). Despite efforts to expand access to electricity, many households and businesses in the region still need more affordable and reliable energy. Due to limited access to energy in Sub-Saharan Africa, the region has witnessed thousands of deaths yearly. The limited energy access also impairs hospital operations, impedes educational achievement, and raises economic expenditures. Therefore, increasing energy supply and distribution in Sub-Saharan Africa is urgently needed.

This paper conducts a comparative analysis of energy accessibility in Northern and Sub-Saharan Africa using SWOT and PESTEL analysis. It analyses the barriers and prospects for balancing energy access in Sub-Saharan Africa by identifying the strengths, weaknesses, threats, and opportunities of energy accessibility in both regions and the political, social, technological, social, economic, environmental, and legal factors that affect it.

The research findings reveal that there has been recent growth in energy access in Northern Africa attributable to smart green funding and innovative regulatory framework. Concurrently, Sub-Saharan Africa faces significant challenges to increasing energy accessibility, irrespective of its potential for renewable energy development. This paper concludes with recommendations for addressing the challenges and leveraging the opportunities to enhance energy accessibility in Sub-Saharan Africa. Also, this research would give the proper framework to increase energy efficiency and accomplish the climate targets outlined in the Paris Agreement.