bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modelling the Scaling Tendency of Produced Water: A Case Study of Niger Delta Brown Field
Authors: Adeeyo Yisa , Onyeka Emeka , Etim Augusta , Brown Ernest , Ossai Onyebuchi , Udofia Ubong , Namtari Salihu 
Published: August 2020

Abstract
Most of the brown fields in Niger delta oil and gas province are experiencing decline in oil output coupled with increasing water production. This is more pronounced due to the mature fields having strong water drive. The management of this produced water has become very important as cost of handling such high volumes is unsustainable.
Most of the water management options include selective well completions, water shut-off, production rate control and produced water re-injection (PWRI). PWRI into the producing reservoir for the purpose of supporting the reservoir pressure and improving hydrocarbon sweep efficiency is a major benefit of the water injection activity. Other standard produced water management practices include disposal into depleted reservoir, deeper non oil-bearing reservoir or ocean.
Defining the process for the injection of produced water has posed a greater challenge to the optimization and management of oil reservoirs. This is not unconnected with adverse effects of the produced water on the reservoir properties when not properly treated. Such effects include but are not limited to scales and pore throat blockages leading to sand formation damage, reservoir souring, reduction in matrix permeability, fractures in the matrix caused by high water injection pressure.
In this work, representative samples were collected, and experimental measurements were made on three (3) flow stations produced water.
This study describes the water injection/disposal compatibility laboratory test results for scale formation modelling in the field with due consideration to the reservoir geology complexity and heterogeneity. Test and modelling results of mixes of produced water indicated the brine is supersaturated with magnesium carbonate (MgCO3) with scaling tendency much greater than one, fouling of the reservoir with H2S due to proliferation of Sulphate Reducing Bacteria (SRBs) and the attendant corrosion.
These results formed the basis for recommendations of the effective produced water treatment for water re-injection and disposal. This study will be of immense benefits to E & P companies operating in Niger Delta in particular, and Africa in general in their efforts to effectively manage produced water.
Supervised and Unsupervised Machine Learning Approach in Facies Prediction
Authors: Fadokun Daniel Oluwadara , Oshilike Ishioma Bridget , Onyekonwu Mike Obi 
Published: August 2020

Abstract
The identification and classification of lithofacies is key to understanding the heterogeneity of the reservoir. Traditional manual facies prediction using well log data are characterized by uncertainties and are often time consuming especially when working with large datasets. Machine learning provides a more efficient way of predicting facies when applied to large data. In this study we consider unsupervised learning approach: clustering and supervised learning approach: support vector machine for facies classification. Unsupervised learning was done using only raw and processed well logs parameters and the responses were grouped into various clusters based on similarities. Optimal number of clusters were selected from the elbow plot and dendogram. The supervised learning is done using well logs-raw and processed parameters. The targeted output was depofacies defined using core facies derived from core data. Both approaches showed good results with less uncertainty and bias when compared to already established facies defined from core data. The result from this process provides a more realistic input for generating facies models.
Well Abandonment and Wellsite Restoration: Case Studies of Well Sites Restored After Oil Production in Onshore Nigeria
Authors: Adebayo Adejoke , Ahmed Suleiman , Agbogu George , Ezenobi Eric , Akiba-eyo Effiowan 
Published: August 2020

Abstract
Oil and gas production process starts from exploration, to appraisal, to development, and finally to abandonment. Exploration is done on the prospective field to determine presence of hydrocarbon (HC) and if present, an appraisal of the extent and volume of the HC is done. If the quantity of HC is found to be enough, it is developed and produced and after production of the HC reserve, abandonment is done.
For the exploratory, appraisal and development processes, wells are drilled, and this drilling involves making holes thousands of feet into the sub soil and the installation of tubulars and other completion accessories to ensure that the hydrocarbon comes to surface with ease and in a safe manner.
Wells are abandoned either because it has produced its potential and cannot be used for production anymore, or due to some integrity issues that could only be prevented by abandonment. To abandon a well, the produced/open HC reservoirs are properly isolated to prevent flow into other HC reservoirs or water bearing sands. The installed tubulars and accessories are then retrieved to surface.
After abandonment, to further reduce the environmental impact of the oil development, the sites are recommended to be fully restored to the pre-development state as much as possible.
This paper details the technical abandonment activities carried out for five wells that have produced for several years in onshore Nigeria. The paper also explains the site restoration activities and shows the various well site restoration stages including the re-vegetation of some of the well sites.
A Scheme for Estimating the Magnitude of the Maximum Horizontal Stress for Geomechanical Studies
Authors: Nwonodi Roland , Dosunmu Adewale , Ubani Chikwendu , Ojanomare Choja 
Published: August 2020

Abstract
It is very challenging to obtain values for the horizontal stresses in the subsurface, particularly the maximum horizontal stress. This discourages well planning, drilling operations, drill cuttings reinjection and geomechanical studies in general. While it is important to obtain accurate values of the in-situ stresses, there are currently no easy ways to get the maximum horizontal stress ahead of drilling operation. Results from the theory of elasticity may be possible, but there can be more unknowns than the required stresses and the lateral strains are hardly known. Hence, this research seeks to find ways to accurately determine the maximum horizontal stress. To this end, a generalized 3D expression was obtained from the elastic theory of subsurface stresses. Randomized set of 5000 data for the polyaxial stresses, in the range of 0.55-1.0 Psi/ft, were generated using sophisticated computer applications and plotted in the MATLAB software in order to get the parameters in the equation. The data were sorted in the order typical of a normal stress regime and the result obtained showed consistency with known practice. Thus, in order to determine an accurate value for the maximum horizontal stress: first obtain the vertical stress from density log; use data from leak-off test to obtain the minimum horizontal stress; obtain the pore pressure within the interval using conventional method; then use the development in this study to get the maximum horizontal stress.
Integrated Hydrocarbon Maturation of Three Reservoirs X1, X2-E, X2-W in the KOCA Field, Niger-Delta
Authors: Iwegbu Chiedu , Dudun Anireju , Olu-Oseh Okasime , Njoku Kelechi 
Published: August 2020

Abstract
Subsurface uncertainties in reservoir characterization remains a challenge in decision making in the development phase of hydrocarbon maturation process due to geological complexity and limitations in reservoir data to provide sufficient understanding of the subsurface. This study focuses on identifying, managing, narrowing these uncertainties and generating reservoir realizations and optimum development concept consistent with available data. Hence, the objective of this study is to generate a technically feasible & economically viable development plan for X1, X2W and X2E reservoirs in KOCA field.
The methodology deployed on this study is a multi-disciplinary integrated approach in a parallel setting with early focus on uncertainty identification, quantification, management and iterations amongst the team. Sensitivity analysis was used to evaluate the respective impact of the identified uncertainties on in-place and recoverable volumes and realizations were constrained by the most impacting uncertain parameters to generate a low case, base case and high case valid realizations of the subsurface. Development concepts were selected to optimize recovery using the base case realization with preliminary economic evaluations used to determine concepts economic viability.
The result of this study identifies Structure, Net-to-Gross, and Permeability as the top three uncertainties with most impact on volumes. Deterministic low, base and high case GIIP volumes computed are 354Bscf, 681Bscf and 1.1Tscf, while recoveries were 261Bscf, 546Bscf and 913Bscf respectively. Deterministic low, base and high case STOIIP volumes computed are 0.4MMSTB, 1.5MMSTB and 3.4MMSTB, while recoveries were 0.1MMSTB, 0.2MMSTB, and 0.02MMSTB respectively. Optimum subsurface development concept is two vertical gas well, no horizontal well is needed to develop the thin (12ft) oil rim and finally quick look project economics revealed that the project would be economically viable even for the Low-Case outcome: NPV (10%) is $150M and VIR (10%) is 3.92.
Integrated Production Forecasting for Improved Business Planning and Hydrocarbon Asset Management: A Niger Delta Brown Asset Experience
Authors: Ohabuike Onyemaechi , Afoama Ebuka , Bakor Leziga , Onyeka Emeka , Egbe Thankgod 
Published: August 2020

Abstract
There is a continuous need to improve hydrocarbon recovery efficiency especially from a brown asset, with a view to extending the life of the asset with reasonable operating cost in order to deliver sustained profit to the business. This is made even more imperative due to the dwindling crude oil prices and an operating environment with ever increasing challenges especially in the area of security, asset integrity, frequent deferment due to export line vandalism and crude theft, and community disturbances. All these factors result in most companies operating within the Niger Delta environment and by extension the country at large not being able to create robust production forecasts to support their annual business plans. In the end, actual annual average crude production ends up much lower in most cases than the projected plan. The big question however is: How do we build robust forecasting models that can better predict our business outcomes in the Niger Delta?
This paper seeks to demonstrate the possibilities available within the Nigerian space, all driven and developed with indigenous capabilities, of how this problem was successfully solved for a major asset, operated by a leading indigenous Exploration and Production company through active collaboration with another leading indigenous Petroleum Engineering software solutions provider.
Tracking and Reduction of Geological Non-Productive Time – A Case Study of an Oil Field in Niger Delta Basin, Nigeria
Authors: Onyeji J. A , Ekun O. A , Asaolu A. O. , Mba A. P , Owoyemi A. O. , Nwachukwu A. P. 
Published: August 2020

Abstract
It is a well-established practice in the oil and gas industry to capture daily non-productive time (NPT) resulting from unscheduled events during drilling campaigns. Annually, the cost estimate of non-productive time (NPT) is about 31 percent of the total cost of drilling per well in the study area. Geologic Non-Productive Time (GNPT) caused by geological related subsurface events constitute major part of NPT. In most cases, GNPT is not usually tracked and or decoupled from NPT and this has made it difficult to focus efforts on with a view to proffering solutions to their occurrences. The objective of this study is to identify, measure, track and analyze underlying causes of GNPT in order to minimize or prevent financial losses and potential damages (tangible & intangible) associated with these events. The methodology used in this study includes integration of subsurface cuttings and geological features, formation evaluation challenges and observed drilling events to define twelve major subsurface events that were grouped into four GNPT categories. The categories are: (1) well flow, (2) lost circulation, (3) wellbore instability and (4) Subsurface evaluation. These events were tracked with the corresponding cost and rig time implications for wells drilled within the selected time frame. Fifty wells were drilled between 2015 to 2017 in our study area, and GNPT occurred in seventeen wells costing millions of dollars. From our analysis of the tracked GNPT over this period, the GNPT big hitters were found to be wellbore instability and lost circulation issues. The result of this study led to concerted efforts at reducing the GNPT in the drilling operations by focusing diligently on tackling the identified GNPT big hitters in 2017 through deployment of more accurate pore pressure, fracture gradient, wellbore stability modeling and most importantly, adopting effective communication strategies among the subsurface and drilling teams. This study aided in identifying, preventing and controlling the big hitters' events, thus reducing drilling incidents and overall well costs.
The Effects of Different Salt Types and Concentration on CO2 Injectivity During CO2 Sequestration in Deep Saline Aquifers
Authors: Edem Donatus , Abba Muhammad , Nourian Amir , Babaie Meisam , Mohammed Nuhu 
Published: August 2020

Abstract
Salting-out effect during CO2 storage in deep saline aquifers can have severe consequences during carbon capture and storage operations in terms of CO2 injectivity. The impact and physical mechanisms of salt precipitation in the vicinity of injection area is not fully clear. Core flooding experiments were conducted to investigate the effects of different brine-saturated sandstones during CO2 injection. The reported findings are directly relevant for CO2 sequestration operations as well as enhanced gas and oil recovery technologies (EGR, EOR). The characterisation and core analysis of the core samples to validate the petrophysical properties (Porosity, Permeability) of the core sample was carried out before core flooding using Helium Porosimetry. The brine solutions were prepared from different salts (NaCl, CaCl2, KCl, MgCl2), which represent the salt composition of a typical deep saline aquifers. The core samples were saturated with different brine salinities (5, 10, 15, 20, 25, wt.% Salt) and core flooding process was conducted at a simulated reservoir pressure of 1500 psig, temperature of 45°C, with a constant injection rate of 3 ml/min. The salting out effect was greater in MgCl2 and CaCl2 as compared to monovalent salt (NaCl and KCl). Porosity decreased by 0.5% to 7% while permeability was decreased by up to 50% in all the tested scenarios. CO2 solubility was evaluated in a pressure decay test, which in turn affects injectivity. The results from this study showed that the magnitude of CO2 injectivity impairment is dependent on both the concentration and type of salt. The findings provide basic understanding of the different salt concentration inducing salt precipitation during CO2 injection into core samples completely saturated with the formation brine. The insight gained in this study could be useful in designing an operating condition for CO2 sequestration in deep saline aquifers and minimising injectivity problems.
Crude Oil Price Risk Management: Should Nigeria Hedge Its Crude Oil Production?
Authors: Adegun Adedamola , Abiola Olalekan 
Published: August 2020

Abstract
The volatility of the crude oil market and the uncertainties imposed on oil companies and oil producing nations is well documented. For National Oil Companies (NOCs) vested with the responsibility of managing their country's oil and gas resources and providing revenue needed for much investments, the unpredictability of the crude oil market poses more challenges. In Nigeria, oil price fluctuations constraint national and sub-national budgets as oil benchmarks are typically optimistic. From 2015 – 2019, actual revenue accretion from crude oil sales compared to benchmark price and production have been as low as fifty percent (50%) of target.
To address the uncertainties and guarantee stable revenue, it's imperative for Nigeria to implement best practice in crude oil price risk management by considering the merits and demerits of available tools such as hedging. A pertinent question is if hedging (similar to Mexico) a credible, beneficial option for Nigeria? Would hedging have improved Nigeria's revenue if adopted in the last five (5) years? This paper attempts to provide answers by analysing various hedging options and studying the success and downsides of major sovereign hedging programs.
We further explored the empirical and normative dynamics that will accelerate or impede the adoption of hedging and suggested mitigating options. We find that considering the empirical factors alone, crude oil price risk management is a potentially viable option for Nigeria as benefits extend beyond direct revenue increase. Hedging will instil discipline, confidence and ultimately attract investments into the Nigerian oil sector. Our conclusions nonetheless recognise that the soft, qualitative factors around hedging if not well managed could be a drawback, impacting revenues.
Optimising Offshore Structures Decommissioning - A Multicriteria Decision Approach
Authors: Eke Emmanuel , Iyalla Ibiye , Andrawus Jesse , Prabhu Radhakrishna 
Published: August 2020

Abstract
Decommissioning activity is being delayed due to cash flow constraints in most companies, others are taking advantage of the low oil prices to expedite decommissioning activity as some associated cost becomes cheaper. Nevertheless, decommissioning is an emerging and growing market. There is a forecasted increase in global decommissioning projects from about $2.4 billion in 2015 to $13 billion per year by 2040, with an estimated 2000 offshore structures to be decommissioned between 2021 and 2040. These costs are very high considering decommissioning is an activity that does not necessarily bring in an income to producing companies. Thus, companies are seeking ways to optimize the process of decommissioning so as to reduce overall cost.
This work identifies and evaluates the various decommissioning options and criteria for decision making and proposes a multicriteria decision making approach that will optimise decommissioning process and efficiency savings.
Development of a Modified Weymouth Equation for Large Diameter Pipelines
Authors: Oladipo Akintunde , Nwankwo Princess 
Published: August 2020

Abstract
Flow equations are necessary for the estimation of flow rate in pipelines. Several flow equations exist and so do conventions for their application. Their range of applicability are delineated in literature such as D. W. Schroeder, Jr. and GL Noble Denton (2010). These works record the limited range of applicability of the Weymouth Equation compared to other existing flow equations. This failing of the Weymouth Equation is most prominent in large diameter pipelines. Fully turbulent flow predominates in large diameter pipelines like trunk lines and the use of Weymouth Equation for calculation of flow rate in such scenarios results in significant discrepancies. This work extends the range of applicability of the Weymouth to fully turbulent flow regimes in large diameter pipelines. In particular, the Weymouth friction factor is corrected by introducing a term accounting for internal pipe roughness.
Friction factors for different flow scenarios were calculated and plotted against the Reynolds Number and the Flow Rate to reveal the transition to fully turbulent flow regime. Python programming language was used to compute a table of friction data using both the Colebrook-White Equation and the Weymouth Friction Factor equation. A correction factor was introduced into the Weymouth friction factor that takes into consideration the variation of pipe roughness. Further, the new friction factor relationship was used to modify the existing Weymouth equation.
The Modified Weymouth Equation obtained predicted well for fully turbulent flow scenarios. Compared against the Weymouth Equation, it maintained an appreciable efficiency as pipe roughness was varied from standard values obtainable with new pipelines.
This study achieved its set objectives of improving the efficiency of the Weymouth Equation for large diameter pipelines. It will find application in the accurate estimation of flow rate as technologies evolve for non-intrusive determination of internal pipe roughness.
An Overview of Microbial Enhanced Oil Recovery in Nigeria
Authors: Anuka Agnes , Falode Olugbenga , Ogunshe Adenike , Udie Celestine 
Published: August 2020

Abstract
The use of microbial metabolites by interfacial tension reduction and wettability alteration mechanisms, for improved oil recovery from oil reservoirs, especially in mature oil fields have always been advocated for as a cheaper and environmentally-safe method of increasing oil production. Although microbial enhanced oil recovery (MEOR) in some advanced nations have come close to commercial applications, Nigeria is yet to venture into the microbial enhancement of oil recovery.
Nigeria as a nation has had its fair share of the global dilemma of decreased oil production caused by unrecovered oil in oil reserves, resulting in adverse effects on its economy energy status. Uncertainties on the efficiency of MEOR in practical reservoirs, failure of petroleum engineers and scientists to form multidisciplinary teams, and lack of adequate understanding of MEOR processes are some factors that have slowed down the process of adopting MEOR as an alternative to other enhanced oil recovery methods in Nigeria. Other significant factors include, lack of appropriate microbial mechanisms for the success of MEOR applications; various in situ and ex situ laboratory and field trials experiments on effectiveness of high-strength biosurfactants, in microbial enhanced oil recovery, best interfacial tension reduction and wettability alteration mechanisms, novel sets of core flooding tests, with potential indigenous and control microbial consortium, for optimal oil recovery efficiency; adsorption of microbial cells and biofilm formation for inductive MEOR, towards wettability alteration of reservoir rock for production of neutrally wet condition, for the improvement of oil recovery efficiency; modified advantageous quorum-sensing and behavioural diversity of potential MEOR-applicable microbes, as well as, genetic modification of selected safe and environmental-friendly candidates.
In addition to economic, health and environmental issues that still linger, and call for urgent attention, a general overview of microbial enhanced oil recovery in Nigeria comprising of the mechanisms of oil recovery by MEOR, factors hindering its implementation in Nigeria and the need for MEOR laboratory and field trials to be performed in order to determine the viability of the process in Nigeria is pertinent in order to provide a lasting solution to decreasing oil production.