bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Impact of Outsourcing on Marginal Field Project Delivery in Nigeria
Authors: Oruwari Humphrey Otombosoba , Okolo Samuel Chinedum 
Published: August 2021

Abstract
The oil and gas industry in Nigeria is undergoing rapid change and explosive growth especially for marginal oil fields. Marginal oil fields operators are indigenous companies with limited profitability and some operators embrace outsourcing in their operations. Furthermore, outsourcing is process in which a company contract with another company to manage service that it does not want to provide by itself. The study examined the effect of outsourcing on marginal field operations. Using literature review and case study in India, Egypt and Malaysia by marginal field operators it is observed that outsourcing has positively contributed to delivery of marginal field project. Outsourcing is beneficial because it allows companies to reduce their fixed asset costs. Outsourcing in form of alliance between indigenous and foreign companies would enhance the credibility of the indigenous companies and stimulate capacity building in terms of knowledge and technology transfer. It is recommended that for effective outsourcing there should be a clear legal frame work.
Impact of the Finance Act 2020 on Gas Utilization Projects
Authors: Gbakon Kaase 
Published: August 2021

Abstract
The newly passed Finance Act 2020 (FA2020) in Nigeria is reviewed especially as it relates to the oil and gas industry. The review is partly executed by modeling the specific provisions of the Act that impact gas utilization projects. The effect of the provisions on investor returns as well as the extent to which government objectives are met is ascertained – the government objectives being to prevent tax leakage via excessive financing costs, as well as encourage gas development and utilization.
A qualitative assessment of the FA2020 is first conducted to examine its provisions applicable to the oil and gas sector. Furthermore, a spreadsheet Discounted Cash Flow (DCF) economic model of a gas central processing facility is built. A hypothetical $800Million (CapEx), 300mmscfd gas processing facility, which is 70% debt financed is modeled by incorporating the provisions of the FA2020. The metrics of the project (both investor and government) are then compared under the scenarios of with and without the FA2020.
Key results indicate that the economic returns to investor in the gas processing facility are still largely preserved at a healthy level, even as government take improves by $102Million due to the FA2020. Specifically, without the FA2020, investor returns an IRR of 21.11% while due to the FA2020, investor IRR declines to 19.79%. Sensitivity analysis serves to illustrate one of the aims of the FA2020, which is to prevent tax loss from high cost of financing. Lengthening the tenor of loans reduces the fraction of the financing costs that is tax deductible. The modeling result shows that, ceteris paribus, for one (1) year increase in loan tenor, the amount of financing cost that is tax deductible reduces by 5%. Another important outcome is that for every $1 of government receipts preserved/enhanced by the FA, the investor NPV declines by 38cents
This impact assessment of the FA2020 on gas utilization projects is conducted against the backdrop of several government pronouncements and policy positions to encourage domestic gas development. Financing plays an important role in delivering gas projects, consequently the evaluation of the impact of the FA2020 becomes imperative. This is to allow an examination of the effect of the Act on the ability to meet the strategic objective of powering the economy via gas while fulfilling Nigeria’s climate change commitments by deeper adoption of gas as a transition fuel.
Cost Element Modelling, Prediction and Optimization in a Dual-Completion Well During a Coiled Tubing Unloading Operation
Authors: Ekeregbe Merit P. 
Published: August 2021

Abstract
In an era where cost is a significant component of decision making, every possibility of reducing operational cost in the Oil and Gas industry is a welcome development. The volatile nature of the Oil market creates uncertainty in the industry. One way to manage this uncertainty is by the ability to predict and optimize our operations to reduce all of our cost elements. When cost is planned and predicted as accurately as possible, the operation optimizations can be managed efficiently.
Practically, all new drills require CT unloading of the completion or kill fluids to allow the natural flow of the wells. Hitherto, there is no mathematical model that combines information from one of the wells in an unloading dual completion project that can be used to aid decision-making in the other well for the same unloading project and thereby result in an effective cost-saving. Deploying the mathematical model of cost element prediction and optimization can minimize operational unloading costs. The two strings of the dual completion flow from different reservoirs. Still, the link between the two drainages post completion is the kill fluid density, and can aid in cost estimation for optimum benefit. The lesson learned or data acquired from the lifting of the slave reservoir string can be optimized to effectively and efficiently lift the master reservoir string. The decision of first unloading the slave reservoir string is critical for correct prediction and optimization of the ultimate cost.
The mathematical model was able to predict the consumable cost elements such as the gallon of nitrogen and time that may be spent on the long string from the correlative analysis of the short string. The more energy is required for unloading the short string and it is the more critical well than the long string because it is the slave string since no consideration as such is given to it when beneficiating the kill fluid to target the long string reservoir pressure with a certain safety overbalance. The rule for the mud weight or the weight of the kill fluid is the highest depth with highest reservoir pressure which is the sand on the long string.
With the data from the short string and upper sand reservoir, the lift depth and unloading operation can be optimized to save cost. The short string will incur the higher cost and as such should be lifted last and the optimization can be done with the factor of the LS.
Assessment and Optimization of Waterflooding Performance in a Hydrocarbon Reservoir
Authors: Osatemple Miracle Imwonsa , Adeniyi Adekunle Tirimisiyu , Giwa Abdulwaha 
Published: August 2021

Abstract
In order to properly meet up with the ever-increasing demand for petroleum products worldwide, it has become increasingly necessary to produce oil and gas fields more economically and efficiently. Waterflooding is currently the most widely used secondary recovery method to improve oil recovery after primary depletion. A crucial component required to conduct an efficient waterflooding operation is an optimal production setting, most especially with respect to the amount of water involved. This research work has been carried out to develop a model that can be used to maximize oil recovery and minimize water production with the least amount and number of waterflood variables in order to minimize the secondary recovery investment cost. The gradient-based approach to optimize the production and net present value (NPV) from a waterflood reservoir using the flow rates or bottom hole pressures of the production wells as the controlling factors with the use of smart well technology was applied. In this approach, a variant of the optimal switching time technique was used in the optimization process to equalize the arrival times of the waterfront at multiple producers, thereby increasing the cumulative oil production. The optimization procedure involved maximizing the objective function (NPV) by adjusting a set of manipulated variables (flow rates). The optimal pressure profile of the waterflood scenario that gave the maximum NPV was obtained as the solution to the waterflood problem. The proposed optimization methodology was applied to a waterflood process carried out on a reservoir field developed by a five-spot recovery design in the Niger Delta area of Nigeria, which was used as a case study. The forward run was carried out with a commercial reservoir oil simulator. The results of the waterflood optimization revealed that an increase in the net present value of up to 9.7% and an increase in cumulative production of up to 30% from the base case could be achieved.
Artificial Intelligence Model for Predicting Formation Damage in Oil and Gas Wells
Authors: Effiong Augustine James , Etim Joseph Okon , Okon Anietie Ndarake 
Published: August 2021

Abstract
An artificial neural network (ANN) was developed to predict skin, a formation damage parameter in oil and gas drilling, well completion and production operations. Four performance metrics: goodness of fit (R2), mean square error (MSE), root mean square error (RMSE), average absolute percentage relative error (AAPRE), was used to check the performance of the developed model. The results obtained indicate that the model had an overall MSE of 355.343, RMSE of 18.850, AAPRE of 4.090 and an R2 of 0.9978. All the predictions agreed with the measured result. The generalization capacity of the developed ANN model was assessed using 500 randomly generated datasets that were not part of the model training process. The results obtained indicate that the developed model predicted 97% of these new datasets with an MSE of 375.021, RMSE of 19.370, AAPRE of 6.090 and R2 of 0.9731, while Standing (1970) equation resulted in R2of −0.807, MSE of 9.34×1016, AAPRE of 3.10×106 and RMSE of 4.10×105. The relative importance analysis of the model input parameters showed that the flow rates (q), permeability (k), porosity (φ) and pressure drop (Δp) had a significant impact on the skin (S) values estimated from the downhole. Thus, the developed model if embedded in a downhole (sensing) tool that capture these basic or required reservoir parameters: pressure, flowrate, permeability, viscosity, and thickness, would eliminate the diagnostic approach of estimating skin factor in the petroleum industry.
EOR Consideration in Marginal Field Operations
Authors: Uche Chukwunonso , Esieboma Samuel , Uche Jennifer , Bukar Ibrahim 
Published: August 2021

Abstract
"Marginal field" was introduced to the oil and gas industry to identify those fields that have negative economic effects in its development. More specifically it is possible to define a marginal field as a field that is cost ineffective to develop with conventional oil and gas means of technology. Economic development of marginal fields in most cases requires the use of existing processes to minimize cost of finding evolving technologies in development of reserves. This paper generally evaluates the feasibility of using the enhanced oil recovery technique to improve reserves in a marginal field operating environment. A marginal heavy oil field in the offshore environment of the Niger Delta region which started production in 2011 is used as a case study to evaluate the feasibility of the use of enhanced oil recovery method to improve recovery.
Due to poor mobility ratio in this heavy oil field and its associated big aquifer sizes, pockets of unrecovered oil have been left behind the water fronts and water cut has risen above 80% in most of the producing wells. Recent integrated field evaluation shows that the recovery factor is poor compared to the size of oil originally in place and this triggered the need to process subsurface assessments of developing such reserves that exist in any marginal field using enhanced oil recovery technique. This paper therefore goes through the fundamental scope of an enhanced oil recovery study process to determine the applicability of this technology in a marginal oil field.
Harnessing Local Input for Job Creation-the Need for Collaboration Between the Academia and Industry; A Case Study of Carnegie African Diaspora Fellowship Program
Authors: Mbanefo Henry. C. 
Published: August 2021

Abstract
This paper is an attempt to design a practical model of mutually-beneficial collaboration between the academia and industry for training and graduate mentoring. This ideal collaboration is modeled for efficacy and sustainability. This paper seeks to bring to the fore, an ideal collaborative framework whereby sustainability is the key. The paper will identify several key factors and prescribe pragmatic processes for achieving an ideal mutually-beneficial collaboration for graduate mentoring, training and skill acquisition. More so, the paper will identify and prescribe the kind and level of expertise, qualification for personnel and the necessary facility needed for such trainings. Funding has been identified as one the key factors militating against the success of any collaboration. The paper will address the process of attracting funding as well as managing such funds. Areas of funding and potential collaborators will be identified. Organizational expertise is critical to the success of any ideal collaboration. The paper will match desired expertise with potential corporations as well as institutions capable of incubating such expertise and technology.
Performance Evaluation of Local Material Rice Husk Ash under Downhole Conditions with the Addition of Basic Oil Well Additives Antifoam, Fluid Loss, Dispersant and Retarder on Oil Well Cementing
Authors: Akintola Akinwale , Akintola Sarah 
Published: August 2021

Abstract
The effect of RHA on Compressive Strength as well as other parameters like Consistency and Rheological properties etc. on Class G cement slurry is studied. The following additives were used; Rice Husk Ash (for Compressive Strength), Guinea Corn Husk Ash (Retarder) and other liquid additives which are fluid Loss Additive, Antifoam, Dispersant, Retarder and Water in the formulation of the cement slurry. This research is a comparative analysis based on experimental study on the effectiveness of the various additives on the cement slurry using pure Class G cement slurry combined with all liquid additives as a control.
At a Bottomhole Circulating Temperature of 140°C, the Compressive Strength tests carried out on the slurry samples showed that the strength of the concrete increases as the concentration of the RHA increases with time of curing, also the compressive strength started to increase. The best Compressive Strength result was obtained with the percentages of cement replaced by 13.01% RHA. The strength showed impressive increase with time, with highest compressive strength encountered in 24 hours. The Thickening Time of the set Cement Slurry was considered using Class G cement and different percentage of RHA. The final Thickening Time decreases with increase in Rice Husk Ash. Decrease in the setting time was noticeable from 1.87 hrs (at 13.01% RHA) from 40bc to 100 bc.
At BHST of 700°C increasing the ash concentration resulted in decrease in the Plastic Viscosities (PV) and increase in the Yield Points of the slurries. The results indicate that the slurries formulated using this ash has viscosities which are within the recommended values showing it is desirable to pump such slurry. For both 124°C and Bottom Hole Pressure of 7700psi the amount of fluid loss increases as the percentage of RHA added increases but it is below 50cp which is acceptable.
Enhanced Oil Recovery Application of Nanoparticles in Niger Delta Water-Wet Reservoir Rock
Authors: Udoh Tinuola 
Published: August 2021

Abstract
In this paper, the enhanced oil recovery potential of the application of nanoparticles in Niger Delta water-wet reservoir rock was investigated. Core flooding experiments were conducted on the sandstone core samples at 25 °C with the applications of nanoparticles in secondary and tertiary injection modes. The oil production during flooding was used to evaluate the enhanced oil recovery potential of the nanoparticles in the reservoir rock. The results of the study showed that the application of nanoparticles in tertiary mode after the secondary formation brine flooding increased oil production by 16.19% OIIP. Also, a comparison between the oil recoveries from secondary formation brine and nanoparticles flooding showed that higher oil recovery of 81% OIIP was made with secondary nanoparticles flooding against 57% OIIP made with formation brine flooding. Finally, better oil recovery of 7.67% OIIP was achieved with secondary application of nanoparticles relative to the tertiary application of formation brine and nanoparticles flooding. The results of this study are significant for the design of the application of nanoparticles in Niger Delta reservoirs.
Zingiberales Extract ZE: A Locally Sourced Natural Compound as Gas Hydrate Inhibitor
Authors: Elechi Virtue Urunwo , Ikiensikimama Sunday Sunday , Ajienka Joseph Atubokiki , Akaranta Onyewuchi Emmanuel , Okon Okon Efiong 
Published: August 2021

Abstract
Gas hydrates are impediments to flow of gas and oil and its avoidance and mitigation is key to oil and gas operators. Mitigation via chemical controls is more suitable for marine environments. The effectiveness of 2wt% of an extract from the plant order, Zingiberales has been compared to that of Mono-Ethylene Glycol in a simulated offshore laboratory mini flow loop of 0.5-inch ID. The results from final pressure shows the value of ZE to be 107 psi while that of the MEG was 99 psi. The ∆P for ZE was 43 psi while that of MEG was 51 psi. The difference in ∆P was 8psi more than that of MEG. The Inhibition Capacity (%) values showed ZE to have performed better with a value of 62.28% while that of MEG was 55.26%. ZE had an Inhibition Capacity that was 7.02% more than that of MEG which is mostly imported and is termed a toxic alcohol, meaning that it is both human and environmentally hazardous. ZE therefore should be considered for development as a gas hydrate inhibitor.
Digital Transformation of Storage Tank Chart For PMS and AGO
Authors: Ayodele Emmanuel , Chukuigwe Ndubuisi , Akpogomeh Oshogwe , Bilal Ibrahim 
Published: August 2021

Abstract
Petroleum product needs to be stored and transported from various sources before they get to the final consumers, there by requiring storage tanks. Calibration of storage tank by dry and wet strapping process have evolved over the years with state-of-the-art facilities. The calibration charts are used to determine and know the volume of fluid in a tank given the height of the petroleum products stored in the tank. Calculating volume of a tank with the integration method has a lot of sources of error thereby affecting the result of the volume calculated and causing losses in revenue due to inaccurate calibrated tanks. With the losses in revenue due to wrong computations or computational errors, a fast, dynamic and cost-effective solutions become imperative to solve these computation problems. The tank charts having been delivered for daily usage and fiscalization process after the tank strapping process, calculation errors need to be minimized in order to report accurately petroleum products in stocks, which is a function of temperature, density and volume correction factor. This paper aims to solve the problem by semi automating the process of calculating total volume of product in stock with error free results. Approach in this paper was used and test run for a storage facility X. This paper shows how calculations from calibrated tanks can be done with a virtual method using excel spreadsheet and converted into a software for effective use and making percentage error almost zero. The results obtained from this method of computation were error free and devoid of human errors.
Successful Implementation of Blast Joint Perforation Technology in a Dual String Completion
Authors: Ofia Ifeanyichukwu , Briggs Esther , Longe Victor , Iyengumwena Ricky , Wong Dominic 
Published: August 2021

Abstract
The results of computer simulations and laboratory tests have been applied at Porth field in Nigeria to achieve a successful perforation through a blast joint to access hydrocarbon behind pipe.
Accessing hydrocarbons behind pipe in multizone completions can be difficult. The options are; an expensive rig-based workover or a cost-effective, rigless, through-tubing perforation. For a rigless through-tubing option, the detonated perforation charges must pass through a blast joint, the casing and the cement and then into the target reservoir. The major concern is usually whether there will be enough penetration {Burky 2018} into the target reservoir interval, given the layers of material resistance that the charges will have to overcome, starting at the blast joint. The Blast joint has a higher wall thickness and a larger outer diameter than that of the conventional tubing string to mitigate against erosion from producing the target interval behind pipe. The goal in perforation operations is achieving the maximum production while reducing perforation damage. {Jackson 2016}.
Computer simulations and laboratory tests for a well at Porth field in Nigeria were carried out to determine the potential for successful perforation through a blast joint to access hydrocarbon behind pipe. Coupon tests using different gun sizes and charges where simulated and tested to ascertain the most effective option to achieve the desired reservoir penetration. Both computer simulations and laboratory test results showed that a reasonable depth of penetration into the target reservoir interval was possible to achieve. The perforation job using a 1.56-in., six-shots-per-foot (6 spf), 60° phasing gun was successfully carried out and the well has been tested to a potential of 780bbl/d at a tubing head pressure of 943psi and choke size 20/64th.
This success lays the foundation for going after other similar opportunities locked in behind-pipe previously thought inaccessible owing to the presence of a blast joint across the target interval. Associated rig costs for a workover of up to $10 million can be saved on each opportunity using this approach.
Hydrocarbon of the Future: Sustainability, Energy Transition and Developing Nations
Authors: Ifalade Oluwajuwon , Obode Elizabeth , Chineke Joseph 
Published: August 2021

Abstract
The population of Africa is estimated to be about 1.5 billion, 25% of world population but the continent accounts for only 3.2% of global electricity generation (2.2% coming from South Africa, Egypt, Algeria and Morocco). This translates to the lowest per capita energy of any continent. The rapidly growing population in Africa will inevitably result in the emergence of more African cities and this underscores a need to urgently address the energy poverty concerns presented.
The global energy landscape is changing, and Africa finds herself at a vantage point in the complex interplay between energy, development, climate change and sustainability. The need to provide an answer to these concerns is further highlighted by the effects of globalization and climate change.
The onus rests on African countries to find a cross-functional solution; one which answers simultaneously to socio-economic and environmental challenges. This involves driving growth in energy supply and hence industrialization via the adoption of a balanced mix that harnesses all energy potential and integrated utilization possibilities.
Projected increase in energy demands coupled with emission allowances present a unique opportunity for these countries to put in place plans and infrastructure congruent with the future energy landscape. In contrast to the narrative where African energy is driven majorly by renewables, the continent must first maximize the enormous fossil fuel potentials domiciled in large gas reserves in some of her countries to create an economy that can support a sustainable energy future.
Natural gas is expected to play a vital role in the transition to a more environment friendly future of energy, especially in developing countries. This paper aims to present the prospects and challenges of the use of natural gas as a driver of sustainability and energy transition in the developing nations. Nigeria and the Nigerian Gas Master Plan will be taken as a Case Study.