bluuebunny/crossref_metadata_2025_split huggingface dataset:
Estimation of Bottom Hole Pressure in Electrical Submersible Pump Wells using Machine Learning Technique
Authors: Sanusi Sherif , Omisore Adenike , Blankson Eyituoyo , Anyanwu Chinedu , Eremiokhale Obehi 
Published: August 2021

Abstract
With the growing importance and application of Machine Learning in various complex operations in the Oil and Gas Industry, this study focuses on the implementation of data analytics for estimating and/or validating bottom-hole pressure (BHP) of Electrical Submersible Pump (ESP) wells. Depending on the placement of the ESP in the wellbore and fluid gravity of the well fluid, there can be little or no difference between BHP and Pump intake Pressure (PIP); hence these two parameters were used interchangeably. The study focuses majorly on validating PIP when there are concerns with downhole gauge readings. It also has application in estimating PIP when the gauge readings are not available, provided the relevant ESP parameters are obtainable. ESP wells generally have gauges that operate on "Comms-on-Power" principle i.e. downhole communication is via the power cable and loss of signal occurs when there is no good electrical integrity along the electrical path of the ESP system. For proper hydrocarbon accounting and statutory requirements, it is important to have downhole pressure readings on a continuous basis, however this cannot be guaranteed throughout the life cycle of the well. Therefore, an alternative method is essential and had to be sought.
In this study, the Response Surface Modelling (RSM) was first used to generate a model relating the ESP parameters acquired real-time to the PIP values. The model was fine-tuned with a Supervised Machine Learning algorithm: Artificial Neural Network (ANN). The performance of the algorithms was then validated using the R-Square and Mean Square Error values. The result proves that Machine Learning can be used to estimate PIP in a well without recourse to incurring additional cost of deploying new downhole gauges for acquisition of well and reservoir data.
Front-End Integrated Production System Modelling for Production Optimization – Experience from a Niger Delta Field
Authors: Okoro Felix , Arochukwu Elias , Adomokhai Segun , Dennar Linda 
Published: August 2021

Abstract
The M001 project involved the hook-up of 12 wells (17 conduits) which were drilled and completed between year 2000 and 2005 but were closed-in for operational reasons, until year 2019 when the first seven (7) conduits on cluster MX1 were cleaned up successfully. The seven conduits (Well-A, Well-B, Well-C, Well-D, Well-E, Well-F & Well-G) were expected to flow via three 8" bulk lines. Post well open-up and handover to production, significant bulking / backing out effects were observed.
An average Flow Line Pressure (FLP) of ∼22 bar was recorded on the flowlines, hence limiting the capacity to bulk the wells, [FLP increases towards Flowing Tubing Head Pressure (FTHP) hence, pushing the well out of the critical flow envelope as FTHP&lt;&lt;1.7FLP]. Due to this challenge, total production from Cluster MX1 was sub-optimal with only five (5) conduits out of seven (7) able to flow due to bulking and backing out effect. The sub-optimal performance from the conduits were investigated using the Integrated Production System Model (IPSM) / PIPESIM models. Four different scenarios were run in the model and the calibrated IPSM model indicated all 7 conduits should flow if there are no surface restrictions. The model identified pressure, mass and rate imbalances in the integrated system and suggested the presence of a restriction at the manifold, causing sub-optimal production from the wells.
The model outcome triggered an onsite investigation / troubleshooting from the wellhead to the manifold at the facilities end where an adjustable choke was identified in the ligaments of the manifold. In line with process safety requirements, a risk assessment was carried out and a Management of Change (MOC) raised to remove the adjustable choke at the manifold.
Post implementation of the intervention, all the seven (7) conduits produced without any bulking effect. Total production realized from the seven (7) conduits post execution of the recommended action is ca. 9.3 kbopd against 5.2 kbopd pre-intervention. A total of ca. 4.1 kbopd production gain was realized and 10 mln USD proposed for additional bulkline was saved.
A Review of Wet Gas Flow Metering Correlation
Authors: Adenubi Solomon , Appah Dulu , Okafor Emeka , Aimikhe Victor , Okologume Wilfred 
Published: August 2021

Abstract
Entrained liquids in produced natural gas introduce flow-prediction errors in gas metering; hence there is a need to correct flowmeters’ response to these errors. The development of improved wet gas flow correlations is an effective means of optimizing the predictive capabilities of these meters. This study reviews selected wet gas flow correlations, assesses their merits and demerits, and offers novel options and possibilities for developing highly optimized wet gas correlations for industrial applications. Prospects and possibilities for developing highly optimized wet gas flow correlations are also suggested in this paper, resulting in a significant expansion of the use of wet gas flow meters. These possibilities will include model development and experimental investigation of wet gas flows under relatively high-pressure operating conditions.
Surface Complexation Modelling of Potential Determining Ions Sorption on Oil/Brine and Brine/Rock Interfaces
Authors: Adeyemi Bamikole , Jadhawar Prashant , Akanji Lateef 
Published: August 2021

Abstract
Previous studies on smart water effects have suggested wettability alteration as the most significant mechanism for additional oil recovery during smart water injection. Though many other mechanisms have been observed and proposed in several other studies, much more attention is paid to the detachment of oil films from rock surfaces. It is, however, clear from prevailing understanding that the activities at oil/brine interfaces might require as much attention as given to the brine/rock interfaces. This paper presents diffuse double layer surface complexation modelling of the adsorption of potential determining (Ca2+, Mg2+ and SO42-) ions on oil carboxylic and carbonate surfaces.
Surface complexation models are developed by defining the adsorption sites, surface area and mass of the oil and carbonate surfaces. The chemical reactions involving the surface sites and five different brine solutions are also defined. The brine solutions include formation water, sea water, sea water diluted 20 and 50 times, and sea water with four times SO42- concentration. The amount of the divalent ions adsorbed at pH range of 5 to 8 are determined after the reactions had reached equilibrium. Adsorption of the ions on oil carboxylic and carbonate surfaces at elevated temperature for the sea water is also investigated.
Results show that significant number of divalent ions are collected at the oil/brine interfaces just as adsorbed at the brine/rock interfaces. The results suggest that the equilibrium reactions and the dynamics at the two mathematical interfaces in any oil/brine/rock systems are equally important to reach a full understanding of the main mechanisms behind smart water effects. Therefore, the dynamics of ionic reactions at the oil/brine interface can play critical roles in defining smart water effects on residual oil mobilization.
Pressures and Pressure Derivatives of a Vertical Well Located Within Two Inclined Faults: Case Study of Basic Angles and Unequal Well Distances from Faults
Authors: Ojah Michael , Adewole Steve 
Published: August 2021

Abstract
Pressure transient analysis has been used to evaluate performance of a vertical well located within two intersecting sealing faults. The nature and types of boundary affect productivity in bounded reservoirs. Well performance is strongly affected by well location with respect to the boundary, be it single, paired and parallel or paired and inclined. The goal of this research was to study pressure behavior as well as performance of a vertical well located within two intersecting sealing faults inclined at various angles θ and at unequal distances to faults. Unlike similar works previously carried out, this work can be used to study or predict pressure distribution of a well in a wedge system located at unequal distances to faults. Using the concept of images, the study proposed new models for estimating distances between image well(s) and active well. These models were applied in the solution to the dimensionless diffusivity equation to characterize pressure transient behavior of a well located at unequal distances to the inclined faults. These pressures and pressure derivatives were computed from the total pressure drop expression summing all the image wells by the principle of superposition. The MATLAB, Python and Excel software were deployed to compute all the dimensionless pressures for the different well designs. The results obtained show that 1) the proposed models give accurate estimation of active well distances to image wells; 2) the models show that the distance between the active and image wells d0,i increases for the range of values of angles 0°&lt; θ0,i ≤ 180° and decreases for the range 180° &lt; θ0,i &lt; 360°; 3) the relationship between unequal well distances and productivity has a maximum point; 4) beyond this point, the well ceases to be productive and; 5) this maximum point is at equal distances of the well from both faults, in this case, 15 ft. Larger magnitudes of dimensionless pressure derivatives would indicate higher oil production for any well design and inclination of the boundaries. Worthy of future works are similar studies on 1) horizontal wells and 2) mixed boundaries, that is, one sealing fault and one constant pressure boundary.
Regulatory Requirements for Accuracy in Flare Gas Measurement – Synergizing Software Method Advancement to assist the Hardware Technology to meet Accuracy Demands
Authors: Umeh Ebuka , Ibeh Stanley , Obah Boniface , Abonyi Chukwunonso , Nnakaihe Stephen 
Published: August 2021

Abstract
Over the years, the industry has been so used to the hard logic of utilizing flare gas meters (notably the ultrasonic flare gas meters) in the measurement of stranded flare gas. This is because it has been a workable solution for years with minimal challenges due to the broader range of accuracy required by regulatory bodies. Usually, companies are either constrained to either utilize the associated gas from the oil and gas facilities as fuel gas to power up the unit or reinject in the reservoir to serve as pressure maintenance agent that pushes the oil towards the reservoir, or stored in the reservoir and/or flare the gas (which in most cases, have been deployed by operators despite the penalties by the regulatory organization). With the recent steer in carbon capture, natural gas utilization, climate change and energy transition, accuracy level demands has been made more stringent with some countries including Nigeria requesting for 2.5 – 3% accuracy level of measurement from operators in a bid to monitor and curb the essence flue gases that are unaccounted for. This can only be for gases flared during routine conditions which does include when process upsets give rise to shut down and blowdown of gases through the flare header to the flare tip.
The high demand of measurement accuracy has opened windows for OEM to produce calibrated meters that are bespoke with a longer timeline for recalibration as most of the hardware in critical operations could require a process shutdown to either maintain, repair, calibrate or even replace. With this growing concerns in the industry and the surging growth of digitalization involving AI, data analytics etc in other areas, the software method would be a potential source of synergy to assist the failing hardware which are being impacted by time as calibration issues continue to resurface throughout the life of the meters, giving rise to wider accuracy measurement in the region 5 – 10%, hence attracting the hammer from the regulators.
This paper is intended to produce a deep dive of the current regulatory requirements for gas measurement in Nigeria by the regulators (DPR), the impact of the recent 3% accuracy requirements as it impacts both large and medium size operators, the role of gas measurement software for bridging the gaps and shortfalls of the hardware components. A case study of newly developed flare gas measurement software and its impact in assisting operators in gas performance reporting, production allocation and flare penalties where applicable
Overcoming Challenges of Pigging the Unpiggable Pipelines
Authors: Oragwu Chinedu , Molyneux Daniel , Lawal Lukeman , Ameh Stanley 
Published: August 2021

Abstract
Carbon steel pipelines are used to transport hydrocarbons globally because carbon steel is relatively easier to fabricate, safe for use, raw materials are available and less expensive. Amidst these benefits, carbon steel is susceptible to severe corrosion and other anomalies. Pipeline corrosion is a significant concern in the oil and gas industry. It has caused several minor and catastrophic losses of containment with resultant fatalities, environmental pollutions, asset damage, and production downtimes.
The increasing failures of in-service pipelines have led the Department of Petroleum Resources (DPR) to intensify regulatory scrutiny of pipeline integrity assessment and management in Nigeria to ensure strict compliance to the regulatory requirements by the Oil Producing Companies. According to DPR Act (Section 2.5.2.1), all pipelines greater than 6" size diameter must be inspected every five (5) years with intelligent pigs (inline inspection tools) that would provide the accurate condition of the pipeline. However, many pipelines in Nigeria are unpiggable or difficult to inspect with intelligent pigs due to the unavailability of pigging facilities (especially in brownfields), pipelines with short bend radiuses, dual diameters, flow parameters, etcetera.
This paper explores case studies involving the use of advanced inline inspection technology to conduct inline inspection of difficult-to-inspect dual-diameter pipelines.
Undersaturated Hydrocarbon Reservoir Waterflooding: A simulation Approach to Performance Assessment
Authors: Adeniyi Adekunle Tirimisiyu , Osatemple Miracle Imwonsa , Giwa Abdulwahab 
Published: August 2021

Abstract
There are a good numbers of brown hydrocarbon reservoirs, with a substantial amount of bypassed oil. These reservoirs are said to be brown, because a huge chunk of its recoverable oil have been produced. Since a significant number of prominent oil fields are matured and the number of new discoveries is declining, it is imperative to assess performances of waterflooding in such reservoirs; taking an undersaturated reservoir as a case study. It should be recalled that Waterflooding is widely accepted and used as a means of secondary oil recovery method, sometimes after depletion of primary energy sources. The effects of permeability distribution on flood performances is of concerns in this study. The presence of high permeability streaks could lead to an early water breakthrough at the producers, thus reducing the sweep efficiency in the field. A solution approach adopted in this study was reserve water injection. A reverse approach because, a producing well is converted to water injector while water injector well is converted to oil producing well. This optimization method was applied to a waterflood process carried out on a reservoir field developed by a two - spot recovery design in the Niger Delta area of Nigeria that is being used as a case study. Simulation runs were carried out with a commercial reservoir oil simulator. The result showed an increase in oil production with a significant reduction in water-cut. The Net Present Value, NPV, of the project was re-evaluated with present oil production. The results of the waterflood optimization revealed that an increase in the net present value of up to 20% and an increase in cumulative production of up to 27% from the base case was achieved. The cost of produced water treatment for re-injection and rated higher water pump had little impact on the overall project economy. Therefore, it can conclude that changes in well status in wells status in an heterogenous hydrocarbon reservoir will increase oil production.
The Commercial Potentials of Underground Natural Gas Storage in Nigeria
Authors: Adegun Adedamola , Rufai Femi 
Published: August 2021

Abstract
Nigeria is the 2nd biggest natural gas producer in Africa, with much of it exported as LNG, some re-injected while a small fraction serves the domestic market. The volume supplied to the domestic market plays an outsized role in the energy mix and economy of Nigeria with over 90% supplied to thermal power plants and industrial clusters. As huge upstream gas projects continue to take Final Investment Decision, pipeline takeaway capacity grows and demand increases, the dependence on natural gas and preponderance in the energy mix will likely persist. Natural gas is the present and future of Nigeria's energy needs.
The domestic gas industry is evolving but has been fraught with challenges. Oil and gas infrastructure are often disrupted and production shut-in, mostly triggered by infrastructure unavailablity, environmental concerns and prioritisation of hydro power generation during River Niger's white and black floods, all of which come at a cost to upstream producers. Gas producers are often compelled to curtail production of gas plants (associated and non-associated) to avoid environmental disasters and prohibitive gas flare penalties. Can underground gas storage (UGS) be an opportunity for gas producers to guarantee continued operations during disruptions and provide buffer for national strategic benefits?
This paper seeks to explore the potential technical and economic dynamics of underground natural gas storage in Nigeria in the context of extant technical regulations, seasonal demand variations, gas flare penalties and local operating environment. The paper presents types of underground storages and recommends the most suitable, considers options for optimal location of UGS in Nigeria and undertakes an economic evaluation of a UGS project. The findings are further presented alongside the critical technical, regulatory and fiscal factors that may facilitate future investments and growth of underground gas storage in Nigeria.
Computer Implementation of the Dykstra-Parsons Method of Waterflood Calculation
Authors: Lekia Prosper Kiisi 
Published: August 2021

Abstract
One of the challenges of the petroleum industry is achieving maximum recovery from oil reservoirs. The natural energy of the reservoir, primary recoveries in most cases do not exceed 20%. To improve recovery, secondary recovery techniques are employed. With secondary recovery techniques such as waterflooding, an incremental recovery ranging from 15 to 25% can be achieved. Several theories and methods have been developed for predicting waterflood performance.
The Dykstra-Parson technique stands as the most widely used of these methods. The authors developed a discrete, analytical solution from which the vertical coverage, water-oil ratio, cumulative oil produced, cumulative water produced and injected, and the time required for injection was determined. Reznik et al extended the work of Dykstra and Parson to include exact, analytical, continuous solutions, with explicit solutions for time, constant injection pressure, and constant overall injection rate conditions, property time, real or process time, with the assumption of piston-like displacement.
This work presents a computer implementation to compare the results of the Dykstra and Parson method, and the Reznik et al extension. A user-friendly graphical user interface executable application has been developed for both methods using Python 3. The application provides an interactive GUI output for graphs and tables with the python matplotlib module, and Pandastable. The GUI was built with Tkinter and converted to an executable desktop application using Pyinstaller and the Nullsoft Scriptable Install System, to serve as a hands-on tool for petroleum engineers and the industry.
The results of the program for both methods gave a close match with that obtained from the simulation performed with Flow (Open Porous Media). The results provided more insight into the underlying principles and applications of the methods.
Applications of AI and Data-Driven Modeling in Energy Production and Marketing Processes
Authors: Ugoyah Joy , Igbine Anita Mary 
Published: August 2021

Abstract
Faster and more accurate decisions are what the Oil and Gas industry needs with the world's fast-evolving energy needs and economy. The area of Artificial intelligence and Data-driven modelling is relatively new and has not found popular application in the industry. AI is an emerging technology that can be used to predict event outcomes and automate anomaly-detection processes.
The various applications of AI in different industries were researched into. This paper highlighted important processes that can be improved with the application of Artificial Intelligence through data-driven modelling. It also highlights areas in the various industries where AI intelligence is already being applied and ways it can be improved.
AI and data-driven modelling has the potential to improve exploration accuracy, reduce production down-time, reduce cost of maintenance, and reduce health and safety risks.
This body of information can serve as a guideline for adopting AI in the oil and gas industry. A trend of industry-tailored intelligence solutions would be more effective in the evolving energy industry.
Non-Edible Oil Based Surfactant For Enhanced Oil Recovery
Authors: Adeniyi Adekunle Tirimisiyu , Onyemaechi Ijoma 
Published: August 2021

Abstract
After the primary and secondary oil recoveries, a substantial amount of oil is left in the reservoir which can be recovered by tertiary methods like the Alkaline-Surfactant Flood. Reasons for having some unproduced hydrocarbon in the reservoir include and not limited to the following; forces of attraction fluid contacts, low permeability, high viscous fluid, poor swept efficiency, etc. Although, it is possible to commence waterflooding together chemical injection at the start of production. Reservoir simulation with commercial simulator, could guide in selecting the most appropriate period to commence chemical flooding. In this study, the performance of a new synthetic surfactant produced from Jatropha Curcas seed was compared with that of a selected commercial surfactant in the presence of an alkaline and this shows that the non-edible Jatropha oil is a natural, inexpensive and a renewable source of energy for the production of anionic surfactants and a good substitute for commercial surfactants like Sodium Dodecyl Sulphate (SDS). The Methyl Ester Sulfonate (MES) surfactant showed no precipitation or cloudiness during stability test and was able to reduce the Interfacial Tension (IFT) to 0.018 mN/m and 0.020 mN/m in the presence of sodium carbonate and sodium hydroxide respectively as alkaline at low surfactant concentration. The optimum alkaline surfactant formulation in terms of oil recovery performance obtained from the core flooding experiment corresponds to a concentration of sodium carbonate (0.5wt%), sodium hydroxide (0.5wt%) mixed in distilled water and Methyl Ester Sulfonate (MES) surfactant (1wt%). The injection of 0.5 percentage volume of alkaline surfactant slug produced an incremental oil recovery of 26.7% and 29% respectively. With these incremental oil recoveries, increasing demand for hydrocarbons product could be met, and returns on investment portfolio will be improved.