bluuebunny/crossref_metadata_2025 huggingface dataset:
Sensitivity Analysis of Choke Size Selections on Reservoir Pressure Drawdown Using Prosper Modelling for Reservoir Management
Authors: Gidado A. O. , Adeniyi A. T. , Olusola B. , Giwa A.
Published: July 2023

It is important to know that analysis and selection of choke sizes for oil wells is imperative for production optimizations in reservoir management. Chokes are necessary in every wellhead completion for regulating flow from the reservoir. Random selection of choke sizes has been a bad practice. For the case study of this work, productions from 3 gas condensate wells have declined with pressure over three years. The initial reservoir pressures of 5870 psi, 4373 psi and 2248 psi, initial production rates ranging from 82.3 BOPD to 242.57 BOPD and 3.018 MMSCFD to 5.001 MMSCFD respectively, with choke sizes ranging from 22/64" to 24/64". However, these reservoir pressures have depleted over 3 years by about 100 psi to 3800 psi for each well with early water breakthrough ranging from 10% to 25% basic sediment and water (BS&W). No analysis of choke sizes selection to flow the wells at the initial stage. This research work has been carried out on pressure depletion control corresponding with its drawdown. This was achieved by modelling and simulating PVT data, completion data, IPR and VLP data and well-test data as well as sensitivity analysis with the aid of PROSPER. Results obtained indicated the need to reduce choke sizes, thereby reducing the drawdown. The reduction of choke size gave a decrease in production volume ranging from 15 to 59% for both oil and gas. However, the reduction in choke sizes also gave decrease in water production of about 92%, 100% and 22% for the respective wells. The choke size sensitivity analysis showed that continuation of the initial choke sizes on 24/64" gave a higher drawdown value above 100 psi, which increased the pull of water conning. Recommendation of the new choke sizes within 18/64" to 20/64" showed the drawdown of 79 psi, 71.5 psi and 80.5 psi. New choke size selection was recommended for the reservoir management of each well.
Determination of Minimum Miscibility Pressure Between Heavy Oil – Supercritical Carbon Dioxide System Using the Slim Tube Method
Authors: Uzoho C. U. , Okorafor I. F. , Olomu D. O. , Achilike N. E. , Adesina O. D. , Onyekonwu M. O.
Published: July 2023

The minimum miscibility pressure is the lowest pressure at which the reservoir fluid can be subjected in order to achieve miscibility with the desired gas. In this experimental study, a 40-ft slim tube, Haste alloy coil with an outer diameter of ¼″ was used to determine the minimum miscibility pressure (MMP) of a Heavy Oil-CO2 System at reservoir conditions. The slim tube was saturated with crude oil from a Niger Delta Field at a constant temperature of 139.2°F after which, 1.2 PV of supercritical carbon dioxide was injected above the heavy oil bubble point pressure at a constant flowrate of 0.2cc/min. The flooding process continued until a high-pressure drop was observed with minimal oil recovered. It was seen that the displacement efficiency increased with an increase in experimental pressures beyond a point where its increase was nominal. However, the MMP for this study occurred at a reservoir pressure of 2042 psi which is the break-over point where no significant change in oil recovery was observed with a recovery above 70%OOIP. The determined MMP was used as a guide in a CO2-EOR and CO2 secondary mode flooding project using a Niger Delta and tight Berea Buff reservoir core samples. The result shows that MMP plays a vital role in any successful miscible flooding EOR project. In the era of carbon capture and sequestration, we can therefore capture carbon and use it for EOR. However, the MMP of the crude oil has to be determined.
Introducing Python Coding to Petroleum Engineering Undergraduates: Excerpts from a Teaching Experience
Authors: Mosobalaje O. O. , Orodu O. D.
Published: July 2023

The post-Covid world is witnessing a rise in automation and remote work models. Oilfield operations are becoming increasingly innovation-driven with advances such as digitalization technologies, smart fields and intelligent wells. Proliferation of data is extending career frontiers in data analytics, machine learning and artificial intelligence. Human competence in computer programming is a key enabler of these trends. As a contribution to the Nigerian oil/gas human resources development, the petroleum engineering program at Covenant University recently developed and is implementing a course module on Python programing with oil/gas applications. This paper documents the philosophy, pedagogy, and prospects of this initiative and provides a guide for its implementation across the Nigerian educational space.

The module opens with a seminar on the emerging oil/gas opportunities in data science – to stimulate students’ interest. Thereafter, a gentle introduction to computer programming is taught. At its core, the module teaches basics of Python programming language – input/output, objects (values, variables, keywords), conditional and repetitive structures, functions, lists, tuples and dictionaries. The module is enriched with applications in reservoir volumetrics, material balance equation, PVT properties, reservoir discretization and simulation. Hands-on experience is enhanced with class demos and take-home programming assignments featuring simple algorithms. Also, the course features a training on the use of distributed version control (GitHub) for collaboration between students and instructors. All course materials are available on an open-access GitHub repository, with hyperlinks embedded in lecture notes. Ultimately, the course assesses students’ skills with exams set in the context of quasi-real-life projects. The future prospects targeted in this initiative includes a follow-up module on petroleum data analytics and machine learning, incorporation of Python coding into other modules, and a short-course for industry professionals.
Energy Efficiency as a Key Driver for Environmental Sustainability in the Oil and Gas Sector in Nigeria.
Authors: Oruwari Humphrey Otombosoba , Ubani Chris
Published: July 2023

Energy efficiency is concerned with the ratio of benefits gained from an energy related operation or activity in comparison to the actual energy utilized in deriving that benefits. In essence energy efficiency means doing more with less energy and it involves all aspects of energy production This study investigated energy efficiency as a key driver of environmental sustainability in oil and gas sector in Nigeria. Inefficiency in energy use has brought a significant negative impact by increasing cost of production and emission of green house gases. The implications of this is that the cost of oil and gas operations will be high thereby reducing the profitability and increasing emission by green house gases. The study methodology used literature review and case study of other countries with focus on the oil and gas sector. The findings revealed that energy consumption in oilfields found significant potential for reducing costs through energy efficiency improvements and contributing to climate change mitigation through reducing green house gases emissions. Moreover, reducing oilfield energy costs reduced the overall cost of oil production. Efficiency gains lead to reduced emission, simply changes to field equipment or operating procedures can yield major efficiency gains in oil and gas operation. It is concluded the adoption of energy efficiency in energy intensive sectors with huge carbon foot print such as oil and gas sector will serve to decarbonize the economy and accelerate the nation towards climate change mitigation and sustainable development. The key to increasing energy efficiency and reducing environmental costs is having the right drivers through education, policy and legislation, financial incentives and technological advances. These drivers need to be integrated with both management and technology of the business to drive down cost. It will be crucial for oil and gas companies to improve energy efficiency in all the production process.
Investigation of the Impact of Surfactant Concentration on Gas Well Deliquification
Authors: Kinate Bright Bariakpoa , Nmegbu Chukwuma Godwin Jacob , Amadichuku Nyelebuchi
Published: July 2023

This work investigates the effect of surfactant concentrations on gas well deliquification and quantify the incremental gas production rate. A base model was built to verify the possibility of liquid loading behavior using the Turner velocity criteria. Foam lift was enabled and the well flow path was defined including the micro-annular space between the coiled tubing and the tubing strings. Different Surfactant concentrations of 0.05, 0.1, 0.15, 0.2, 0.25, 0.3, 0.35, 0.4, 0.45 and 0.5mass percent were injected for an optimum concentration required to unload liquid from the gas well. Results reveals that the reservoir will deliver 13.315MMscf/day of gas across the completion into the wellbore when the pressure drawdown is maximum.The intersection of the inflow and outflow performance curves shows that the well was producing 2.09787 MMscf/day of gas which occurs where the Turner velocity criteria shows a potential issue (liquid loading). A gas production rate of 2.09787 MMscf/day was produced with no foam lift but with foam lift and 0.05mass% of surfactant injected, the well production rate increases from 2.09787 MMscf/day to 7.60823MMscf/day. The result shows that a surfactant mass percent of about 0.4% will maximize gas production from the well producing 7.71049MMscf/day. Results reveal that surfactant should not be injected at concentration above the critical micelles concentration (CMC) as it will lead to a significant increase in the frictional component of the fluid pressure loss due to the rheology of the foam.
Investigative Approaches to Troubleshooting and Remediating Sub-Optimal Gas Lift Performance in a Dual Completion Well
Authors: Akinola Obembe , Olufisayo Fagbowore , Ebikeme Adowei , Olumide Taiwo , Aluba Oragwu , Clement Chukwuka
Published: July 2023

Gas lift is said to be one of the most forgiving forms of artificial lift techniques because even a poorly designed gas lift system will lead to some production of fluids. As a result, the tendency exists for Production Engineers to pay little attention to designing and maintaining optimal gas lift systems. Some unique considerations are required for a dual gas lift system where both strings in a dual completion are on gas lift. Using a case study, this paper highlights key investigative questions and assessments to understand the individual well string performances, assess optimal contribution of both strings and optimal distribution of the injected gas. This paper focuses on the gas lift optimization on Well-AX SS which experienced production decline from about 1,000 BOPD to 40 BOPD.

The highlights of the methods employed involved investigating for communication between strings, identifying the string with highest production potential, determining optimal gas lift valve depth, and ensuring no surface network bottleneck exists. With industry emphasis on low-cost oil, it has become critical to minimize the Operating Expense (OPEX) by ensuring optimal gas lift injection into wells. After investigation and assessment of the production potential and the gas lift injection status, the gas lift injection was redesigned, and optimal gas lift design recommended. The work-over executed involved isolating the source of communication, shutting in the completion with lower potential and optimizing the gas lift system of the more productive string. This work-over led to an increase in production of 850 BOPD.

One of the key challenges to optimal gas lift is accurate gas measurement and understanding the split of gas between each string in a dual completion. Lessons learned from this assessment include obtaining robust and recent surveillance data for well performance assessment and thorough evaluation of production strings to ascertain the injection depth of gas lift gas.
Decommissioning and Abandonment of Oil and Gas Assets – A Case for Coexisting with Mother Nature
Authors: Akanegbu Stanley , Agbogu George , Okonkwo Ngozi , Nnanna Erasmus , Imoyo Olusola
Published: July 2023

All oil and gas assets including wells, flowlines, production facilities, and all surface structures installed as part of the network of facilities required for the safe exploration, development and production of hydrocarbons are required by law to be properly decommissioned at the end of their useful life, and the environment restored to her original form in sync with mother nature. Of particular significance are the considerations that are given to Oil and Gas well Decommissioning and Abandonment (D&A) owing to their extensive sub-surface footprint where achieving acceptable D&A at their end of the useful life requires significant upfront planning during the early stages of project maturation and involves projections and decisions being made around funding, timing, and extent of the decommissioning that needs to be done including proper zonal abandonment of respective reservoirs, retrieval of well construction hardware and sub-surface plug back of the well to ensure hydrocarbon never finds their way to surface under any circumstance after abandonment of the well. The requirement and extent of Decommissioning and Abandonment of oil and gas assets is a statutory requirement governed by the legislature in place in respective countries of operation and governed by international best practices that ensures environmental sustainability, and the provisions for D&A is made in each operator's financial statements to recognize the liability for D&A at the end of the license expiry or at end of production. This mandated by international financial reporting standards (IFRS). The D&A process is fraught with a lot of technical and non-technical challenges, which require significant upfront identification, and robust risk identification and mitigation in order to be able to manage them and be in compliance.

This paper reviews the D&A practice in Nigeria, looks at candidate identification strategies, breaks down the methodology and best practices involved in D&A operations for wells, and x-rays the requirements for open-hole and cased-hole abandonment as well as the logging and testing requirements that guides the decisions made. The risks involved in D&A projects would be analyzed and insights into how they tie back to the mitigations put in place to ensure successful decommissioning and restorations of the assets reviewed, and how these all connects back to nature with a view to sustaining global best practices for returning our environment to her clean and green state before exploration activities disrupted nature's balance would be established.
Inhibition Effect of Order Brassicales Plant Extract (BPE) on Methane Gas Hydrate Formation in a Gas Dominated System
Authors: Wachikwu-Elechi V. U. , Ikiensikimama S. S. , Ajienka J. A.
Published: July 2023

Problems related to gas hydrate formation abound in oil field operations due to deep offshore activities, leading to severe adverse effects and safety problems all of which add to operating cost (OPEX). Prevention of these problems is key. The use THIs and KHIs have been explored but has their disadvantages. Due to the alarming rate of environmental degradation via toxic substances, there is an urgent need for friendly alternatives for both humans and the environment. This study compares the use of Brassicales Extract (BPE) and Poly n-vinyl caprolactam (N-VCap) as gas hydrate inhibitors. The BPE was evaluated using a locally fabricated stainless pipe mini flow loop. Hydrate formation and inhibition experiments were carried out for a period of 120 minutes with pressure and temperature readings recorded every 2 minutes. A rapid decrease in pressure and sudden increase in temperature are pointers to hydrate formation in the constant volume batch process loop. Microsoft excel was used to generate plots relevant to hydrate formation and inhibition. The various pressure plots showed that the BPE performed better than the conventional in most weight percentages considered. Pressure decline and temperature increase was more regulated in the systems with BPE unlike in the uninhibited experiment. The Volume of gas used up in the BPE inhibited system were 23.3, 14.7, 16.7, 15.3 and 12.7% for 0.01-0.05wt% respectively while for N-VCap, the volume of gas used up for the same weight percentage were 24, 17.3,22, 10.7 and 29.3% at the end of the experiments. BPE has inhibition efficiency values of 69.3, 80.7, 78.07, 79.82 and 83.3% for 0.01-0.05wt% respectively while that of the synthetic inhibitor was 68.42, 77.2, 71.1, 86 and 61.4%. It is recommended that the BPE be developed for gas hydrate inhibition because it did very well and is environmentally friendly unlike the N-VCap which is a toxicant.
Safeguarding Export Gas Supply with Subsurface Disposal of Produced Water: The MXC Approach to Liquid Handling
Authors: Udobata Uchenna , Ogbunude Basil , Muzan Eelah , Chiroma Barka , Musa Nabage , Maxwell-Amgbaduba Sunday , Monday Nanpan , Okereke Onyedikachi , Tamunotonye Biambo , Femi Obakhena , Chinedu Nwachukwu
Published: July 2023

Unprocessed gas from the gas wells in the nearby fields is routed through the production manifolds to the processing trains in gas plants. The associated liquids from the treatment process accumulate in a stabilization tank, where it undergoes separation by gravity into condensate and water and therefore needs to be evacuated to sustain gas production. The base design strategy for MXC's export gas supply from gas plants A and B relies on two major export pipelines as the primary evacuation routes for the accumulated condensate and water.

In the absence of these major export pipelines, the condensate can be evacuated by spiking via the gas export pipeline to the LNG plant. However, the only available option to evacuate the produced water was by barging to the export terminal for subsequent disposal into the sea. This option was unsustainable due to logistics, insecurity, and operating costs. Inability to dispose of the produced water would result in water level build-up in the condensate stabilization tank, which impacts the ability to spike condensate, forced reduction in gas production as much as 500MMscf/d or complete gas plant shut down with deferments as high as 1.2 Bscf/d from both gas plants. With the prevailing external context of frequent and prolonged outages of the export pipelines, resulting in gas deferment, and external regulatory requirements to limit evacuation of produced water to the sea, it became imperative to create additional options for liquid evacuation to guarantee the security of export gas supply as well as meet regulatory requirements.

Produced water disposal into the subsurface was considered a critical and essential strategy for building this robustness. This paper discusses the strategy adopted by MXC to build water disposal capacity in Plant A, comply with regulator stipulations, and sustain gas supply from MXC's gas plants. It highlights the initial trade-offs and challenges in developing and managing the system and the best practices adopted to improve system reliability.
Using Machine Learning to Predict Permeability from Well Logs: A Comparative Study of Different Models
Authors: Asimiea Nicholas Walson , Ebere Emmanuella Nkiruka
Published: July 2023

Permeability is a crucial parameter in reservoir engineering, as it determines how easily fluids can flow through subsurface rocks. Traditional methods of measuring permeability are expensive, error-prone and time-consuming, which has led to the development of machine learning models that can predict permeability based on well-log data. This study aims to determine the most effective machine learning models for predicting permeability based on available well-log data. The study covers a detailed explanation of the data-gathering and pre-processing techniques used. Four input features were used in the models, namely gamma ray (GR), bulk density (RHOB), neutron porosity (NPHI), and resistivity (RT). Six different models were trained and evaluated based on their performance, namely linear regression, support vector machine, decision trees, gradient boosting, multi-layer perceptron, and random forest models. The models were evaluated based on their Mean Squared Error and RSquare values. Our results showed that the random forest model outperformed the other models, achieving a Mean Squared Error (MSE) value of 0.88. The multi-layer perceptron and gradient boosting models also showed promising results, achieving MSE values of 0.81 each. These findings suggest that machine learning models can be a powerful tool for predicting permeability from well-log data, and the random forest model, in particular, holds great promise for future modelling efforts in this area.
Evaluation of the Potential of Watermelon Rind as a Ph Enhancer for Water-Based Drilling Fluid
Authors: Salihu A. , Sani I. , Ibrahim K. , Nzerem P. , Gimba A. S. B
Published: July 2023

How effectively drilling mud's qualities, such as pH, mud weight, viscosity, etc. are maintained determines how successful it is. Therefore, it is essential to choose drilling fluids, additives, and its composition carefully. The urgent need for product substitution, cost cutting, waste management, and environmental protection was connected with this study project. This research attempted to determine whether potassium hydroxide might be replaced by watermelon rinds (KOH). Watermelon rinds are a common household waste that is commonly available, easily accessible, and biodegradable. They also contain a high amount of potassium. The method used to synthesize KOH from the watermelon rind is caustification of potassium carbonate (K2CO3) from calcining of processed watermelon rind (dried and pulverized). A laboratory barrel of water-based mud was prepared using Wyoming bentonite clay. The produced additives from the watermelon rinds were added to the mud at different concentrations. The results obtained from the experiments conducted showed that the values pH values for synthesized KOH gave comparable results to the commercial KOH. The pH increase was 8.62%, 12.06%, 24.25% and 39.31% for watermelon rind (processed rind), ash, synthesized potassium carbonate and synthesized KOH respectively at maximum concentration. The four additives used increased filtrate loss and mud cake thickness, the rheological properties and mud weight of the mud. In conclusion as a pH enhancer, the synthesized KOH from watermelon rind is suitable and also has secondary effects on mud weight, filtration properties and rheological properties.
Operationalising Process Safety in Gas Lift Operations - Okom Field Experience
Authors: Obong Benjamin , Ofia Ifeanyichukwu , Balogun Bayo , Ukenye Sunday , Oginni Abiodun , Mozeh James , Azibapu Franklin , Ewuzie Theresa
Published: July 2023

The oil and gas industry faces inherent hazards that can result in process safety incidents, such as leaks, fires, and explosions, causing harm to people, assets and the environment. Process safety requires a comprehensive commitment from everyone involved, going beyond policy compliance. Each specialization within the industry has a role in maintaining a safe work area and ensuring sustainable oil and gas production.

Process safety entails the proper design, safe operation, and maintenance of physical assets like drilling rigs, platforms, and processing facilities to prevent the release of hazardous materials. It relies on proactive leadership and competent personnel to achieve the goal of zero harm to employees, contractors, communities, and the environment. A crucial aspect of process safety management is the continuous evaluation of potential risks, the identification of preventive measures, and the assessment of the effectiveness of existing controls. Many process safety incidents in the industry have resulted from a failure to recognize and mitigate risks associated with changes. The Piper Alpha disaster in 1988 serves as a tragic example of such a failure.

Gas lift systems can present integrity challenges. Operators have prioritized addressing well integrity compromises in gas lift systems, especially regarding the check valve in gas lift valves.

The Okom field with over fifty-nine (59) years of production, began using artificial lift gas in 1993 to maximize oil production but has encountered challenges in its gas lift system operations, such as reverse flow issues and liquid fouling of gas lift manifolds during shutdowns, which further emphasizes the importance of process safety management in its operations. Aging infrastructure further underscores the criticality of process safety for mature assets like Okom.

This paper focuses on the integrated approach employed by the Okom Asset team to address process safety challenges, maintain gas lift integrity, manage major accident hazards, and consistently deliver process safety fundamentals across its assets.
Reservoir Souring Assessment and Application of Design and Engineering Practice to Successfully Predict and Mitigate H2S Release in a Produced Water Well Intervention
Authors: Aniekan Obot A. , Basil Ogbunude C. , Imaobong Bassey P. , Eelah Muzan , Ihuoma Green , Conrad Ibekwe , Jonathan Mude , Onajite Taro , Gogo Oforiokuma
Published: July 2023

In-depth understanding of subsurface risk is critical to the safe execution of well intervention operations. One of such high potential subsurface risk is the uncontrolled release of hydrogen sulphide (H2S) which is considered a critical hazard in the oil and gas industry that can put lives and asset at risk. H2S is often generated in anaerobic environments by the activities of Sulphur reducing bacteria which may be introduced by injection of sea or produced water into a reservoir. In addition, H2S can be released during well stimulation interventions in produced water disposal wells. These two possibilities for the release of H2S were considered in the recent assessment, planning and execution of BZ071 acid stimulation intervention. BZ071 is a produced water disposal (PWD) well injecting into the S1000 sand in the BZ NAG facility, with initial injection capacity of about 6kbwpd and cumulative of >2MMbbl disposed into the target reservoir. The initial reservoir souring prediction assessment carried out at the commissioning of the PWD facility showed a high potential of H2S proliferation in the reservoir, although with no chance of H2S release to surface since there was no producer on the S1000 sand. The planning and integrated risk assessment of the BZ071 acid stimulation intervention involved extensive integrated review of the initial souring assessment to keep any potential H2S gas release to As Low as Reasonably Practicable (ALARP). This paper presents the success story of the 1st experience of H2S Release in BZ well intervention operation, which was carefully managed without any HSSE exposure, achieving goal zero. It outlines the reservoir souring prediction assessment, collaborative roll-up of controls and the learnings which led to a successful execution and mitigation of H2S gas release.
Alpha-28 FastTrack Maturation to Execution – Securing Export Gas Supply
Authors: Obakhena O. F. , Biambo T. G , Alli-Oluwafuyi J. , Ikiliagwu C.
Published: July 2023

In the global aspiration to meet an ever-increasing energy demand, fossil fuel and indeed natural gas plays a vital role both in energy security and energy transition. Natural gas is also a key driver of industrialization, a requirement for national growth and development. In the Niger Delta, problems with security & sabotage of hydrocarbon liquid evacuation pipelines as well as slippages in gas drilling projects has also led to shortages in gas supply, creating challenges in meeting contractual obligations to customers with attendant loss of revenue in a high oil & gas price regime.

To harness Nigeria huge gas reserve in the current business climate, it is pertinent to arrest declining gas production caused by aging reservoirs & maximize utility of available ullage by accelerating maturation of gas resources. Quickly maturing a gas resource to market has become very important to meet contract shortfalls in the short term and to comply with the recent call for sustainable greener and cleaner energy for environmental reasons on a long term.

Typically, the maturation and development of a gas project/well takes a minimum of two (2) years from identification to execution.

Maturation of Alpha-28 well in the Alpha field, a brown field Niger Delta, Nigeria, took about 12 months from identification to execution. This was achieved by adopting a non-conventional project maturation. This leaner approach, which did not lose any aspect of the project assurance intents of the conventional approach, involved proper framing, risk assessment, scaling, flexibility, and proactive engagement of all relevant stakeholders to ensure alignment. This paper discusses what was done differently, the how and the learnings that are planned to be incorporated into future similar projects.
Sedimentary Facies, Depositional Environment and Reservoir Quality of Group-B Shallow Clastic Reservoir in the Malay Basin, Malaysia
Authors: Bashiron N. , Johari S. , Sidek A. , Agi A. , Ariffin M. H. , Supee A. , Ridzuan N. , Mahat S. Q. Aini
Published: July 2023

Shallow reservoirs in Group-B of MS-field in Malay Basin, Terengganu's offshore, Malaysia were explored for development. Poor understanding of depositional settings, stratigraphic context, lithofacies, reservoir geometry, reservoir quality, and heterogeneity are some of the difficulties encountered in developing these shallow reservoirs. In this study, these challenges were circumvented by performing reservoir architecture and quality analysis. This was achieved by integrating the interpretation from the cores, well logs, petrographic and petrophysical analyses for depositional model generation, lithofacies description, as well as reservoir geometry, continuity, and quality determination. Five lithofacies were identified in Group-B, namely: laminated mudstone (ML), bioturbated mudstone (MB), heterolithic mud dominated (MH), heterolithic sand dominated (SH), and bioturbated sandstone (SB). The sediments encountered in ML and SB lithofacies consist of moderate to good reservoir quality, while for SH and MH, they ranged from high to low quality. This study provides a better insight to the shallow reservoir heterogeneity in MS-field and the results obtained could also be applied to the other similar shallow reservoirs for characterization and modelling improvement processes.
An Improved Model for Accurate Description of Drilling Fluid Rheological Behaviour in Enhanced-Water and Low-Toxicity Oil-Based Muds
Authors: Johnson Folayan Adewale , Dosunmu Adewale , Boniface Oriji Aleruchi
Published: July 2023

In this study, a new rheological model was developed by the introduction of dimensionless plastic viscosity and shear rate correction factors (k and n) respectively to the plastic viscosity stress-term of the Bingham plastic rheological model with a view to correcting the under-estimation errors that are associated with the model at high shear rate condition in the pipe. Similarly, an effective yield stress τeff was also incorporated into the model to correctly describe the resistance to flow at low shear rate condition in the annulus by taking into account the effect of lowest shear rate stress on the yield-stress term of the model. The drilling fluid matrix consists of a low toxicity oil-based mud (LTOBM) and a high-performance, nanoparticle-enhanced water-based mud (EWBM). The rheological characteristics of these muds were evaluated at temperatures of 30°C, 60°C and 120°C and pressures of 14.7psi, 2500psi and 5000psi respectively. The experiments were conducted under API recommended standard equipment and procedures. Also, statistical tools were employed to quantify the degree of deviation of the model from experimental values.

Empirical results of the new model comparative rheological performance analysis with different existing models that are commonly used in the oil industries showed that the developed model accurately predicts fluid rheology better than the Bingham plastic model at both high and low shear rates conditions in the LTOBM and EWBM at all tested temperatures and pressures. The new model performed better than the Bingham plastic and the power law models at 30°C and 14.7psi for the EWBM with lowest standard error deviation of 1.5096 as against 4.4392 and 2.2573 for BPRM and PLRM respectively. Similarly, the average absolute error of the new model for EWBM at 30°C and 14.7psia is 1.6874 unlike BPRM and PLRM with (EAA) values of 5.3249 and 2.8704 respectively. The new model is not significantly temperature and pressure dependent at high shear rate.
Optimization of Two-Phase and Three-Phase Separator Designs
Authors: Olugbenga A. G. , Ochayi A. E.
Published: July 2023

Mechanical constraints and non-linear fluid dynamics are factors that determine the design of the primary separator units in an oilfield. This study comprehensively outlined the design procedures of a two-phase and three-phase separators focusing on the challenges encountered during separator designs. The designs were calculatively altered after which the results were simulated using the Aspen Hysys software. Theories and relationships of existing separator designs were also employed in the optimization of the model. They comprised of declarative set of equations which are not dependent on the method of solution thereby making modifications easier and assumptions clearer in the context of horizontal separator, the models were outlined and illustrated.
An Assessment of the Level of Awareness and Knowledge Towards the Dangers of Climate Change and Energy Transition: Northern Nigeria as a Case Study
Authors: Inuwa Haruna Muhd , Usman Abdullahi
Published: July 2023

Access to energy is a pressing issue in both developed and developing countries. To achieve socio-economic development, countries worldwide, including those in Africa, must carefully plan their energy transitions, considering the advantages and disadvantages of different approaches and learning from past experiences. In Nigeria, over 80% of the population in underdeveloped areas lacks access to energy, with cooking being the primary energy-consuming activity. As the oil-producing powerhouse of Africa, Nigeria is increasingly becoming a significant emitter of greenhouse gases, and without intervention, emissions are projected to rise dramatically by 2040. This study focuses on the status of energy transition and climate change awareness in the northern part of Nigeria. A research questionnaire was designed to gather responses related to our research questions, following a comprehensive literature review. The collected responses were analyzed to generate structured results. The findings indicate that the majority of participants (51%) fall within the 20-30 age bracket. Notably, 52% of respondents rely on firewood as their primary energy source, while gas usage (24%) is also relatively high but considerably lower than firewood. Encouragingly, our study reveals that 51.4% of respondents expressed a preference for switching from firewood to electric cookers as their home energy source, despite the significant investment required for power infrastructure and policy support. Overall, the results of this study contribute to addressing awareness gaps, framing communication strategies, and promoting public engagement in the campaign against climate change risks and the adoption of safer energy transitions.
Field Surface Planner Algorithm for Integrated Gas Asset Management
Authors: Adeeyo Y. A. , Abu A. M. , Adun G. O. , Lucciano-Gabriel M.
Published: July 2023

As the world transitions towards a more sustainable energy landscape, the need for a less environmentally harmful transition fuel becomes increasingly crucial. This has led to renewed interest in developing previously abandoned natural gas fields. In this paper, we present Field Surface Planner Algorithm (FSPA), a DCA-based model implemented in Python, which aims to generate an effective investment timing strategy for bringing new wells online in large gas fields. The model considers various surface facilities and commercial constraints, while prioritizing the fulfillment of contractual gas demand.

FSPA's algorithm revolves around a sales error concept, which quantifies the disparity between the current sales gas rate and the nominated gas demand. By comparing this sales error against a predetermined error tolerance, the model determines the optimal timing for introducing new wells into production. This approach ensures that the gas field's total sales gas rate remains in line with the nominated gas demand, while minimizing any potential environmental impact.

To ensure efficient operation, FSPA operates within the bounds of nominated gas demand constraints and facility constraints. Nominated gas demand constraints serve as a limit against which the on-stream dates and DCA forecasts for future wells are optimized, minimizing the need for flaring gas. Facility constraints restrict the volume of gas supply that the algorithm optimizes, aligning it with the capabilities of the surface facilities.

During a well's initial contribution, FSPA generates accurate DCA forecasts based on several key factors, including the exact amount of sales gas required to close existing gaps, the well's reserves, and economic limitations. This information aids in making informed decisions regarding short-term production shortfalls and facilitates effective negotiation with customers, ultimately delivering substantial value for the organization involved in gas field development.

By providing an efficient solution for well sequencing, the proposed model significantly reduces gas flaring costs, minimizes opportunity costs associated with production shortfalls, and assists in short-term decision-making processes. Overall, it offers a valuable contribution to sustainable energy transition efforts and promotes responsible development in the gas industry.
How Affordable is Minigrid Power for Sustainable Electricity Supply in Nigeria
Authors: Iwegbu Michael , IBE Anthony , Osokogwu Uche
Published: July 2023

The current conventional electricity model based on a central national power generation and long-distance transmission grids with its attendant losses is no longer sustainable particularly in isolated rural communities where the cost of building transmission lines and transporting fuels is high. The utilization of minigrids to provide an efficient source of power in Nigeria with a population of over 200 million people have begun. However, it appears this is not sufficient to stimulate the growth of minigrid adoption in Nigeria especially as there is a large disparity between the present minigrid and the national grid price of electricity (N250 - N300/kWh versus N53-N76/kWh), this currently serves as a deterrent to minigrids adoption, viability, and sustainability in Nigeria.

This paper examined the factors that contribute to the high cost of electricity generation from minigrids as well as provided recommendations to reduce the cost of electricity generation from minigrids by carrying out a technical and economic simulation of an existing 85KW solar based renewable energy minigrid project in Nigeria. This paper used HOMER software for the simulation using Solar PV (PV), Storage Battery(B), Diesel Generator (DG) and Converter as the basecase scenario and other alternative scenarios were also modelled using CNG (Compressed Natural Gas) and LPG (Liquified Petroleum Gas) as alternate sources of fuel

A structured analysis of the results obtained from the model show that fuel costs accounts as one of the key drivers of the minigrid systems tariff cost, the use of LPG as a source of fuel reduced the tariff cost by about 14% and CNG by about 38%. Based on these findings, this paper proposes the use of LPG and CNG as substitute fuels instead of diesel to reduce the current minigrid systems tariff costs.
Harnessing Value from Mature Offshore Asset: Successes from Recent Acid Stimulation Campaigns in Field X
Authors: Ganiyu Adeyemi , Burgess Matthew , Eyeregba Aghogho , Vesters Jules , Festus Chukwu , Adebayo Olufemi , Anthony Oyewole
Published: July 2023

Field X is a mature offshore field in the Niger Delta. In 2013, several wells in field X experienced significant production decline and a study conducted by cross-functional team identified fines migration as the primary cause of sandface impairment and acid stimulation was recommended as remediation for the damage. This technical work highlights the strategies and methodology adopted in implementing acid stimulation in field X.

The approach to candidate selection involved screening of historical well test data and pressure transient analyses (PTA) database for impaired/at-risk completions. Typical selection criteria are productivity index (PI) degradation (> 50%), pressure drop due to near wellbore skin (DP skin >500psi), violation of flux constraint, Interval Control Valve (ICV) integrity (dual completion) and water-cut evolution (<5.0%). The team also piloted diversion agents in the field to improve stimulation in wells with high water-cut. A novel method of using dynamic positioning marine vessel with Remotely Operated Vehicle (ROV) and customized dual conduit Coil Tubing (CT) have been deployed to bullhead acid into the formation.

In the last two campaigns executed in 2020 & 2021, this ingenious way of harnessing value from field X has resulted to combined incremental Initial Production (IP) gain of approximately 10,000 bopd and safeguarded completion of a critical oil producer (~11,000 bopd). The total project cost for the two campaigns was ~$25.4 million resulting in significant cost savings (>$51.6 million) compared to rig operations. The use of cross-functional team, robust candidate selection, continuous lookback and adoption of best practices were critical to successful execution. Some challenges being experienced in the field are lack of adequate injectivity, formation lock-up, increasing gas oil ratio (GOR) and increasing water-cut. The team plans to deploy diverters across additional high water-cut wells in future campaigns.
Integration of Technologies for Heavy Oil Production – An NNPC E&P Ltd Approach
Authors: Ifeduba E. A , Ijomanta H. U. , Hamza S. M. , Ayeni O. M. , Udo N. A. , Niyang A. S. , Okoh O. M. , Akinnurun Y. S. , Ogweda M. , Emetoh T. , Esene J. O. , Ojeaga B.
Published: July 2023

NNPC E&P Ltd (NEPL) recently successfully drilled, completed and tested the Abura 6ST well which integrated multiple Improved Oil Recovery techniques to develop some heavy oil reservoirs in the Abura field. The 1AB6 and 2AB6 reservoir fluids have viscosities of 10 and 17 Centipoise and API gravity ranging from 16 – 20API° which is a marked variation from NEPL's conventional resources. NEPL is estimated to have over 1.2B barrels of heavy crude oil in her portfolio therefore an attempt to unlock the potential from these reservoirs had a lot of implication for the company. Conventional methods of producing this reservoir were not economically viable mainly due to the high oil viscosity and consequent preferential flow of water rather than oil.

The NEPL team resorted to integration of multiple improved oil recovery IOR techniques to ensure an economically viable well.The first of such improved oil recovery techniques was the use the ESP as the Abura field did not have any gas source for gas lift. Artificial lift was to eliminate flow assurance issues that such a hydrocarbon system would have. Another IOR technique was the combination of horizontal and deviated well bores to drain the reservoirs through a single wellbore in a commingled fashion. The well cuts across the shallowest reservoir as a high angle section and lands in the deeper reservoir as a horizontal well. To ensure preferential flow of oil from the reservoir into the wellbore, Autonomous Inflow Control Device AICD was deployed for both the horizontal and vertical sections of the completion which uses viscosity differences to prevent early water breakthrough and reduce water production.

To meet NUPRC's back allocation requirements, hydrocarbon fluid samples were collected during the drilling operation and unique fingerprint markers were identified which will aid in the determination of each reservoir's production contribution for proper hydrocarbon accounting. In the completions aspect of the design, Swell packers for zonal segmentation, Micro-emulsion breaker system for near well-bore remediation and improved permeability, downhole gauges & sensors and a Y-Tool assembly for alternate access in rigless intervention mode. The Abura 6ST well produced circa 2900 BOPD on choke 28/64 and ESP frequency of 40Hz.This paper seeks to elucidate on some of the IOR technologies and how they were integrated to facilitate the delivery of the first heavy oil ESP well in NEPL's direct operations.
Improving Well Construction/Intervention Time and Cost Estimation Accuracy Via Historical Performance Data Analysis
Authors: Orji Mirian Kosi , Arowosafe Toyin , Agiaye John
Published: July 2023

Time and cost estimation and the accuracy of it, are central to engineering design and forms the basis for economic analysis of projects. There are several factors that could result in cost or schedule overruns ranging from unplanned non-productive time, inefficiencies, changes in macro indices etcetera; however, one often overlooked factor is deficient time and cost estimation. Hence in addition to factoring prevailing market and contract rates for materials and services, it is important to critically analyze and benchmark plans against known performance for higher accuracy around estimations.

Well project time and cost models generally consist of estimating in modules or sub-phases and aggregating these modules to makeup the total. This can either result in a single discrete estimate or in ranges based on probability and statistical performance - inherently implying that some form of historic performance is crucial to the estimation accuracy. This paper describes a structured approach to developing a probabilistic estimation tool by analyzing past performance data at a phase or subphase level. This tool can be domiciled on a range of computation platforms using similar methodology, which comprises data collection from execution reports, data cleanup and organization to harmonize terminologies and group operation types, and finally statistical and mathematical data analysis. Statistical analysis develops probabilistic relationships in the dataset and correlation between performance variables such as depth and time; while mathematical analysis incorporates numerical correlations and multiple variables to generate estimates in modules and finally aggregates the discrete phase estimates.

The estimation has two major components – Time and Cost.

The analysis of time component considers the productive and non-productive time by phase; determines depth dependent operations and their correlation to time and assigns a mathematical function to each phase The cost component is broken down into two sub-components – recurrent cost which is highly time-dependent and non-recurrent (material and services) cost which are usually based on pre-defined contractual rates An additional end function is benchmarking, for comparison between estimates and historic performance

The aggregate of the probabilistic estimate of each module gives the total estimate of time and cost for a given well construction or intervention scope, with the overall objective of improving and maintaining estimation accuracy to avoid overruns and over-estimation of drilling, completions, workover and intervention projects.