bluuebunny/crossref_metadata_2025_split huggingface dataset:
Characteritization of Bio-Oil from Tectona Grandis as a Potential Scale Inhibitor
Authors: Adegoke Samuel Oluwafikayo , Falode Olugbenga Adebanjo , Nwankwo Princess Christiana 
Published: August 2021

Abstract
Calcium carbonate scales cause costly flow assurance problems in flowlines during petroleum production. Previous efforts to mitigate this problem using different chemical inhibitors though successful have resulted in environmental pollution during disposal. This study was designed to investigate the potential of bio-oil synthesized from Tectona grandis as an inhibitor to replace the conventional ones. Tectona grandis was obtained from Ibadan sawmill, Oyo state, Nigeria and characterized using Energy Dispersive X-Ray (EDX) analytical technique. Data generated by EDX analysis showed elemental composition of 78% carbon and 22% of other elements including nitrogen and oxygen. Tectona grandis was pyrolyzed at 5500C, a heating rate of 0.50C/sec, and a running time of 4 hours. 45.1% of the mixture of water and oil were collected and separated into phases in a centrifuge while the gasses were vented. The bio-oil was distilled at 120°C and analyzed using FTIR spectrometry. Spectra analyses showed the presence of -COOH and -CONH2 which are essential in the inhibition of calcium carbonate scale. With the help of a newly fabricated testing-rig system, calcium carbonate scales were formed by mixing equal mole of calcium chloride and sodium carbonate at the temperature range of 25-58°C and flow rates range of 8-15 ml/min, with/without inhibitor from 0, 5 g/l of maleic acid and 5 g/l of newly synthesized inhibitor. The mass of the calcium carbonate and the induction time was measured by the weighing balance and the conductivity meter respectively. For all of the experiments, the presence of maleic acid and newly synthesized inhibitor delayed the induction time by at least 10 mins and reduced the weight of calcium carbonates formed by at least 20%. Also, the mass of calcium carbonate scale formed at all the experiments showed less weight when newly synthesized inhibitor was used compared to when maleic acid inhibitor was used showing the effectiveness of the newly synthesized inhibitor over maleic acid. Therefore, this study shows high promise wood-based distilled oil as a potential calcium carbonate scale inhibitor and provides future direction for further studies.
Understanding the Impacts of Backpressure & Risk Analysis of Different Gas Hydrate Blockage Scenarios on the Integrity of Subsea Flowlines
Authors: Umeh Ebuka , Ephraim Maurice , Samson Nitonye 
Published: August 2021

Abstract
Offshore oil and gas pipelines are subjected to high pressure and high temperature (HP/HT) from the inner hydrocarbon content during operation. Both the rise in temperature and internal pressure may cause longitudinal expansion of the pipeline. This expansion is restrained or semi-restrained by the pipe end devices and the soil which results in build-up of compression stresses in the pipe wall. These pipelines are also exposed to so many familiar and unfamiliar forces related to static, dynamic and environmental forces.
This study presents a thorough review of various sources from literature on the integrity challenges of subsea flowlines and pipelines amid challenging operating conditions especially with regards to flow assurance. This paper evaluates the impact of hydrate deposition and agitation on the overall integrity of the subsea flowlines, riser-base and fitting e.g. elbows, valves e.t.c. A bow tie model was developed to determine the threats, causes, consequences, the top event and the impending hydrates that are to be designed and cause blockage and failure. Stress analysis were done with finite element tools which are ANSYS and Autodesk INVENTOR with only the hoop, Von Mises stress and the corresponding back pressure that occurred with the scenario of 0, 10,30,50,70,90 and 100% blockage of flowlines being analyzed and taking the 0% or null blockage as the pilot case with no hydrate formation. The result gotten from both results were validated with hand calculation with excel and the initial design values for the stress values before the initial operation of the wells after the first commissioning. In addition, HAZOP was done to understand the inherent risk involved in all the cases under study and results gotten would serve as a tool of precautions to operators and stakeholders in period of adversity when facing similar scenario.
Efficient Crude Oil Pricing Using a Machine Learning Approach
Authors: Falode Olugbenga , Udomboso Christopher 
Published: August 2021

Abstract
Crude oil, a base for more than 6000 products that we use on a daily basis, accounts for 33% of global energy consumption. However, the outbreak and transmission of COVID-19 had significant implications for the entire value chain in the oil industry. The price crash and the fluctuations in price is known to have far reaching effect on global economies, with Nigeria hard. It has therefore become imperative to develop a tool for forecasting the price of crude oil in order to minimise the risks associated with volatility in oil prices and also be able to do proper planning. Hence, this article proposed a hybrid forecasting model involving a classical and machine learning techniques – autoregressive neural network, in determining the prices of crude oil. The monthly data used were obtained from the Central Bank of Nigeria website, spanning January 2006 to October 2020. Statistical efficiency was computed for the hybrid, and the models from which the proposed hybrid was built, using the percent relative efficiency. Analyses showed that the efficiency of the hybrid model, at 20 and 100 hidden neurons, was higher than that of the individual models, the latter being the best performing. The study recommends urgent diversification of the economy in order not for the nation to be plunged into a seemingly unending recession.
Analyzing the Influence of Salinity on Produced Water Re-Injection
Authors: Adeniyi Adekunle Tirimisiyu , Ejim Chimgozirim Prince 
Published: August 2021

Abstract
Produced water reinjection (PWRI) is one of the methods employed by oilfield operators to optimize production while conforming to increasingly stringent produced water disposal policies. Different produced water species from different facilities also have different salinities as a result of entrainment of treatment fluids, precipitation of salts at surface conditions, etc. During re-injection operations, the salinity of the injection fluid has to be accounted for as it affects the production. Previous studies have focused on laboratory analysis by core flooding. While this approach is indeed reasonable and offers a first-hand impression of the reservoir conditions, it presents a problem of cost and the age-old opinion that the core sample may not be representative of the entire reservoir. Therefore, I have employed a computer modeling approach using a commercial simulator to analyze the influence of salinity on production during produced water re-injection. It was found that the salinity truly affects production. Re-injection of produced water with salinity equal to the reservoir salinity of 1000 ppm was compared to three cases of re-injection of produced water from extraneous sources having salinities of 100 ppm, 500 ppm and 10000 ppm. It was found that salinity of 10000 ppm gave the best oil production performance for the reservoir model; a daily rate of 40 STB/DAY and an oil cumulative production of 40,000 STB. Incremental salinity of injected produced water led to incremental oil recovery. The mechanism resulting in incremental recovery was attributed to the increase in viscosity and decrease in mobility as the salinity increases.
Numerical Method of Estimating Distance Between Wells
Authors: Ezekiel Ayobami , Oduh Prince , Okoh Emmanuel , Onah Collins , Ojah Michael , Adewole Steve 
Published: August 2021

Abstract
In this study, a simpler numerical model for calculating inter-well distance was developed. This model was developed as an alternative to the Ei-function used for computing pressure drops. The mainobjective of developing this model is tomake resolution of pilfering issues easyto resolve. With the developed model, calculations relating to pressure drops and more specifically, inter-well distance, can be done with greater ease and accuracy. In developing this model, the integral equation of the Eifunction in the pressure drop equation was solved numerically. The numerical solution reduced thepressure drop equation to a polynomial equation which is much easier to solve. The developed model was used to solve real problems. Results generated from it were compared with those obtained using previous approaches. Important informationsuch as well configuration, region of the reservoir, and transient history wherethe work is valid are stated. The development of the correlations and tables forthe range of validity and values of the Ei-function is a major quantum leap in well testing and analysis. It will be quite cumbersome to resolve integrals with unknowns, hence, methods of trials and errors have been resorted to over the years. However, this new approach resolved the pressure drop equation into a systemof polynomials which is much easier to solve. Consequently, the distance betweenpossibly interfering wells (which is an important variable during interference test) can now be gotten with ease. The developed model is valid within the range of validity of the Ei-function. Without doubt, this work will help redefine the pressure drop equation into a polynomial equation which can easily be resolved using any of the known approaches to solving problems involving polynomials. More so, getting the correct distance betweenthe two wells in question is pivotal to the test. With the model developed in this work, getting inter-well distance is now easier and more accurate.
Development and Evaluation of Locally Made Polymer for Improved Oil Recovery
Authors: Adeniyi Adekunle Tirimisiyu , Emmanuel Peter Peibuluemi 
Published: August 2021

Abstract
Hydrocarbons recoveries from matured fileds require enhancement. This is because matured oil fields have undergone pressure depletions. Polymer injection is a proven means of hydrocarbon recovery enhancement. Therefore, search for polymer materials and preparations of polymer, in the vicinity of matured field is the focus of this study. A lead was found in a starch and investigated to cassava tubers. Cassava starch are brine - water soluble, and are used for favorable mobility control. Laboratory tests were conducted for starch solubility and stability at predetermined saline environment and selected ‘reservoir’ temperature and pressure. Physico - chemical properties and other characteristics of the locally sourced polymer were guided by branded commercial polymers. In all, ten batches of laboratory core flooding excercises were conducted on oil-soaked cores, with five different brine concentrations, followed by another five-cassava starch polymer of concentration 0.00 g/l, 4.35 g/L, 5.13 g/L, 7.02 g/L, and 8.81 g/L. The respective polymer viscosities were 0 cp, 1.28 cp, 2.25 cp, 3.30 cp, and 4.15 cp. While the oil sample of 24.27°API at a temparture of 33°C, was used throughout. Respectively, a displacement efficiency of 51.86 %, 51.86 %, 51.85 %, 51.85 %, and 51.86 % were obtained as results.
Application of Machine Learniing For Reservoir Facies Classification in Port Field, Offshore Niger Delta
Authors: Asedegbega Jerome , Ayinde Oladayo , Nwakanma Alexander 
Published: August 2021

Abstract
Several computer-aided techniques have been developed in recent past to improve interpretational accuracy of subsurface geology. This paradigm shift has provided tremendous success in variety of Machine Learning Application domains and help for better feasibility study in reservoir evaluation using multiple classification techniques. Facies classification is an essential subsurface exploration task as sedimentary facies reflect associated physical, chemical, and biological conditions that formation unit experienced during sedimentation activity.
This study however, employed formation samples for facies classification using Machine Learning (ML) techniques and classified different facies from well logs in seven (7) wells of the PORT Field, Offshore Niger Delta. Six wells were concatenated during data preparation and trained using supervised ML algorithms before validating the models by blind testing on one well log to predict discrete facies groups. The analysis started with data preparation and examination where various features of the available well data were conditioned.
For the model building and performance, support vector machine, random forest, decision tree, extra tree, neural network (multilayer preceptor), k-nearest neighbor and logistic regression model were built after dividing the data sets into training, test, and blind test well data. Results of metric score for the blind test well estimated for the various models using Jaccard index and F1-score indicated 0.73 and 0.82 for support vector machine, 0.38 and 0.54 for random forest, 0.78 and 0.83 for extra tree, 0.91 and 0.95 for k-nearest neighbor, 0.41 and 0.56 for decision tree, 0.63 and 0.74 for logistic regression, 0.55 and 0.68 for neural network, respectively.
The efficiency of ML techniques for enhancing the prediction accuracy and decreasing the procedure time and their approach toward the data, makes it importantly desirable to recommend them in subsurface facies classification analysis.
Realizing Value from Adherence to Crude Oil Custody Transfer Automatic Sampling Standards
Authors: Potten Gary 
Published: August 2021

Abstract
The successful implementation of a crude oil custody transfer sampling system is a key component to achieving a desired measurement uncertainty for a crude oil metering station or loading/unloading point. Our analysis of thousands of installations worldwide provides practical examples of how operators can be confident that when they install a sampling system, it will deliver the uncertainty that they need to meet the overall custody transfer requirements. Crude oil sampling for custody transfer becomes more challenging as production flow rates decline, oil fields mature, and water cut content increases. It is therefore important that the performance of a sampling system is evaluated on a regular basis and that any limitations are identified. Any risk of change in performance or measurement uncertainty can then be prioritized or minimized. International standards and contracts determine the allowable uncertainty for net oil (oil minus water) for custody transfer/allocation. For accurate allocation of the sources of crude oil or the application of tax tariffs, fluids must be measured prior to being comingled. Automatic crude oil sampling can be challenging because it can require high-energy mixing with low power consumption and negligible pressure loss to overcome stratification and allow representative sampling. The certification, or "proving", of the sampling system provides a basis for establishing and verifying the system's true uncertainty at worst case conditions. There is an abundance of computational fluid dynamics (CFD) simulations and studies on crude oil (and water) mixing. However, these are abstract because of the uncertainty in where the water is located and how it may be dispersed at the boundary conditions of any simulation. To provide more robust simulations, we expanded on the established methods by combining simulation data with known theoretical calculations and engineering laboratory test data as well as hundreds of certifications (proving) results from around the world. Automatic sampling systems using dynamic mixing technology delivers a unique solution that enables operators to minimize the quality measurement uncertainty, improve overall balance, and reduce financial loss (and unaccounted for) in custody transfer quality measurements.
Geochemical Characteristics of the Campano-Maastrictian Sediments of the Anambra Basin, Southeastern Nigeria - Implication For Provenance, Paleodepositional Environment, Maturity and Tectonic Setting
Authors: Okiotor Michael Edirin , Ogueh EDeh Desiree 
Published: August 2021

Abstract
The present study investigates the Anambra Basin shales to determine the provenance and maturity of the sediments using standard geochemical techniques. Twelve (12) representative samples recovered from shale sequences of The Mamu Formation and Nkporo Group of The Anambra Basin were studied to determine the sediment provenance, paleoenvironment, diagenetic conditions, maturity as well as the tectonic setting.
To consider in detail and establish the inherent constituents of the Major minerals, Trace and Rare Earth elements, Inductively Coupled Plasma Mass Spectrometry (ICP-MS) analyses techniques was employed. The detrital minerals determined are Al2O3 (18.27% and 21.16%), TiO2 (1.73% and 1.63%) and Fe2O3 (2.78% \ and 2.85%), for Nkporo Group and Mamu Formation respectively. The enrichment of SiO2, Al2O3 and TiO2 (1.14, 1.94, 3.67 respectively) supported by Chemical Index of Alteration (CIA) of 93.54 & 39.55 and Rb/Sr ratio of 0.57 & 0.40, indicate that the Anambra Basin sediments are matured. TiO2/AL2O3 binary plots, Th/Co Vs La/Sc crossplots, Th-Sc-Zr triplots and Cr, Ni concentration suggest mixed provenance of felsic to mafic source rocks for these sediments. From the log (K2O/Na2O) Vs SiO2 crossplots, a passive margin tectonic setting was determined for these sediments.
Assessing Investment in Ghana's Upstream Oil and Gas Industry: the Risk and Returns
Authors: Oppong Riverson , Kwame Amoni Edward 
Published: August 2021

Abstract
The study sought to assess Investment in Ghana Upstream Sector, looking at the risk involved in the loss of Investment and the returns from the investment. The specific objectives were: to establish the level of investment in the oil and gas projects that are producing in commercial volumes in the Upstream sector of Ghana, to assess the revenues realized by Ghana and the IOCs from the sale of oil and gas since the start of commercial production in the year 2010.
The researchers noticed that investors in the upstream sector face risk such as: price volatility risk, political risk, investment risk, and many other risks that affect the upstream operations. For the purposes of this study, risk is limited to investment risk. Thus, the researchers are looking at the level of investment in the upstream sector and whether the investment has any relation with the returns or revenues.
A purposeful sampling technique was used to select the three commercial producing fields in Ghana for the Study. These are the Jubilee field, the TEN field, and the SGN field. Secondary data including oil and gas production volumes was taken from the annual reports of PIAC. Other secondary data was taken from Petroleum Commission, and Ministry of Finance.
The results of the study showed that a total of about 8.8 billion US dollars was invested in the Jubilee field. About 4.998 billion US dollars and 5.2 billion US dollars was invested in TEN and SGN fields respectively. This means a total of about 19 billion US dollars was invested in the exploration and development of the three producing fields in Ghana.
The results also indicated that despite all the risk in the upstream sector, about 22.69 billion US dollars revenues has been realized by the IOCs from the sale of oil and gas since the commencement of production in the year 2010. The results also showed that Ghana group realized about 4.98 billion US dollars from the revenues of oil and gas over the same period.
Innovative Use of Injectivity Tests as Interference Tests during Field Development: The EGINA Experience
Authors: Mogbo Obuekwe , Atewologun Adetayo 
Published: August 2021

Abstract
This paper presents the innovative use of interference tests in the assessment of reservoir connectivity and the field oil production rate during the development phase and prior to the first oil of the EGINA field, which is located in a water depth of 1600 m, deep offshore Niger Delta. The interference test campaign involved 26 pre-first oil wells (13 oil producers and 13 water injectors) to assess and subsequently mitigate reservoir connectivity uncertainties arising from the numerous faults and between the different channels within the complexes. The results proved valuable in confirming or otherwise reservoir connectivity, field oil production rate and the number of wells required at first oil to achieve the production plateau.
The tests were designed using the analytical method (PIE software) and the reservoir simulation models enabling to establish the cumulative water injection required, the injection duration and the time a response is expected at the observers. These all had impacts on the planning, OIMR vessel requirements and selection of permanent downhole gauges for the wells.
In addition, the tests were performed with the water injectors as pulsers and the oil producers as observers allowing to avoid and the associated environmental impact. Ten interference tests were realized compared to four planned in the FDP partly due to the use of the more cost effective OIMR vessel in addition to the rig.
Modelling and Simulation of Acid Gas Absorption from Natural Gas by Amine Solution Using Aspen HYSYS
Authors: IKPEZE Victoria Kamnetochi , OWOLABI John Olusoji , OLATEJU Idowu Iyabo , GIWA Abdulwahab 
Published: August 2021

Abstract
This work has been carried out to model and simulate a typical acid gas absorption process using Aspen HYSYS process simulator. The chemical components involved in the process development were water, methane, ethane, propane, higher alkanes, carbon dioxide, hydrogen sulphide, nitrogen and amines: monoethanolamine (MEA), diethanolamine (DEA), triethanolamine (TEA) and methyldiethanolamine (MDEA). The fluid package selected for the simulation before entering the simulation environment was Acid Gas – Chemical Solvents. In the simulation environment, the model was developed by picking an absorber from the Model Palette, placing it and assigning the input and the output streams involved before inputting the parameters required for model convergence. The carbon dioxide-rich feed gas was made to enter the absorber at the bottom inlet stream while the lean amine stream entered at the top inlet and showered down on the uprising gas thereby trapping the carbon dioxide molecules within the gas. The top product from the absorber was the treated gas while the amine solution and the trapped carbon dioxide left the absorber as the bottom product. Different simulations were run to investigate the performance of the amines under the same operating conditions. It was discovered that, of all the four amine solvents considered in this work for the removal of carbon dioxide by chemical absorption, MEA had the highest efficiency but would require more dehydration because it had the highest water content. DEA was also found to scrub the carbon dioxide down to acceptable levels. However, TEA and MDEA barely scrubbed any carbon dioxide under these conditions, as their carbon dioxide compositions were found to be unacceptable. The analyses of the results obtained from the simulations indicated that Aspen HYSYS can be used to study the process of acid gas absorption successfully.