bluuebunny/crossref_metadata_2025_split huggingface dataset:
Paper Hedging Against Cyclical Crude Oil Price Fluctuations: Cost Optimization Initiatives for the Nigerian Oil & Gas Industry
Authors: Ugolo Jerry , Fagbami Debo , Iwegbu Mike 
Published: July 2019

Abstract
This paper discusses the effect of crude oil price fluctuation on the personnel, projects and finances of oil & gas exploration and producing companies, as well as, the cost optimization efforts carried out during the era of lowcrude oil price. Following investigation and historical data, it is evident that crude oil price fluctuation is cyclical in nature. To make their product available for sale, oil & gas organizations, at the peak of the crude oil cycle engage in high operating-cost systems. With drastic fall in the price of the product, as experienced between July 2014 and February 2015, such organizations were faced with the challenge of continuing production at a non-profitable cost.
Crude oil price fall, have always had a big negative impact on the personnel, projects and operations of organizations in the Nigerian oil and gas industry. For personnel, the most prevalent impact was the loss of jobs, for company operations it was the reduction in revenue (income) for the companies and for projects it was the delay or cancellation of projects earlier considered profitable. These losses or delay of projects led to reduction in product portfolio and/or divestments for the organizations involved.
For the Nigerian oil and gas companies to adapt to the economic changes occasioned by the change in price, several measures have been proposed which include individual companies initiating and utilizing procedures that ensure good costing of projects, benchmarking of relevant prices and promoting good costing practices and proper management of balance sheet and adhering strongly to sustainable OPEX and CAPEX levels, to ensure opportunities are identified and utilized.
The researchers asserts that crude oil price fall with its attendant negative impact could be scientifically explained. A quantitative research methodology has been applied in the study of this topic. Using online survey, information has been gathered from respondents from six different oil and gas companies indicating their demography, individual experience, companies experience and project experience during the last crude oil price fall (2014 -2017). Secondary data obtained from historical records helped to show the influence of crude price slump on the financial health status of oil and gas exploration and producing companies. The data also helped to confirm the primary data received in the online survey.
Waterflood Management in Spring Field
Authors: Kuku Abimbola , Omotayo-Johnson Mobolaji , Achinivu Ochi , Awotiku Oluwabiyi , Oyegwa Akomeno 
Published: July 2019

Abstract
Spring Field was discovered in 1963 and started production in 1965. Waterflooding began in 1999 in one reservoir and has subsequently expanded to nine reservoirs to date. Waterflooding in the Spring Field is basically a peripheral water injection system with the use of brackish water as injection water. Waterflooding in Spring Field has been instrumental in "arresting" base decline, sustaining and re-pressurization of depleted reservoirs. There are currently 29 active producing reservoirs in the Spring Field with waterflooded reservoirs accounting for ~ 63% of current oil Production and ~ 52% of the estimated ultimate recovery (EUR).
The management of waterflood systems can most often be quite challenging with Spring Field not being an exception. Waterflood challenges observed in Spring Field include both surface and subsurface issues such as non- uniform volumetric sweep due to complex reservoir architecture (Compartmentalized/ Multi-lobed Reservoirs), long fill-up time due to late startup of water injection, unbalanced Injectivity, out of zone injection, injection pumps reliability to mention a few. Managing and resolving these issues would therefore require a systematic and logical structured approach to ascertain the "health" of the Waterflood system in place with the overall objective of improving its efficiency, hence the purpose for this paper.
This paper focuses on the use of the Surveillance, Analysis and Optimization (SA&O) workflow processes in the management of the water flood system currently in place in the Spring Field. The paper also highlights examples where this workflow process has helped in identifying gaps and optimization opportunities in the Spring Field. The Surveillance, Analysis and Optimization process include the following: ➢Surveillance- Acquisition of necessary data from multiple sources.➢Analysis- Review/ Interpretation of acquired data using various diagnostic tools. For ease of Analysis and Reviews, this element is subdivided into three distinct categories:● Health Check Category● Predictive Category● Problem Identification Category➢Optimization- Recommended corrective actions and efforts carried out to improve Waterflood efficiency based on observations from various analysis.
Artificial Neural Network for Prediction of Hydrate Formation Temperature
Authors: Olabisi Odutola Toyin , Atubokiki Ajienka Joseph , Babawale Ojedapo 
Published: July 2019

Abstract
Gas hydrate deposition is one of the major Flow Assurance problems in petroleum production in the offshore environment. Therefore, is important to accurately predict hydrate formation conditions and avoid these conditions or propose a hydrate management plan. This study compares the effectiveness of Artificial Neural Network (ANN) for predicting hydrate formation temperature to the effectiveness of other hydrate temperature prediction correlations such as: Towler and Mokhtab correlation, Hammerschmidt correlation and Bahadori and Vuthalaru correlation. The ANN was trained using 459 hydrate formation experimental data points from Katz chart and Wilcox et al chart. Pressure (P) and specific gravity (ϒ) were chosen as the inputs in the 4-layer network while temperature was the output. The data points were for gases of specific gravity of 0.5539, 0.6, 0.7, 0.8, 0.9 and 1.0. The experimental pressures considered were from 49 psia to 4000 psia. The Neural Network was built using an excel add-in tool, NEUROXL. ANN accurately predicted the experimental hydrate formation temperature with the regression coefficient greater than 0.98 for the different specific gravities considered. Moreso, the error analysis shows ANN performed better than Towler and Mokhtab correlation, Hammerschmidt correlation and Bahadori and Vuthalaru correlation because it had the least Mean Absolute percentage error, MAPE (3.5) compared to the other correlations. ANN is a viable tool for hydrate prediction and the current model can be improved upon by including more experimental data in the ANN.
Geobody Interpretation and Its Application for Field Development
Authors: Olaniyi Adenaiye , Miguel Mora-Glukstad I. , Anindya Das , Kefe Amrasa 
Published: July 2019

Abstract
Geobody identification via Spectral Decomposition has been used to optimize the development of a reservoir for a green field (Nime – not a real name) in the shallow offshore Niger Delta.
The target reservoir (NM1 – not real name) is covered by a 3D seismic data that was acquired and processed using Post Stack Time Migration technique in the late nineties. Six exploration and appraisal wells have been drilled through the reservoir to date. Stratigraphically, the reservoir is approximately a 250- feet thick high net-to-gross (0.98 – 1), high porosity (0.26 – 0.28) sandstone interpreted to be stacked channel and shoreface sediments that were deposited in marginal marine environment.
Given the high net-to-gross and porosity of the reservoir and absence of any intra-reservoir fault that may compartmentalize the reservoir, the reservoir is deemed laterally continuous and connected. However, fluid contact values derived from reliable combination of gamma ray, resistivity, neutron and density logs from the wells indicate a difference of 25 feet for the oil water contact (OWC) in the reservoir. To fully understand the contrasting information viz 25ft OWC difference in a highly sandy and ‘connected’ reservoir, spectral decomposition volume attribute was generated from the 3D seismic data and analyzed to determine the reservoir architecture.
The spectral decomposition workflow applied involved two basic steps: i) Spectral analyser – to determine dominant frequencies in the 3D seismic volume; and ii) Spectral decomposition – creating 3D volumes for the dominant frequencies and analyzing them with the aim of identifying geobodies (channels) and defining the reservoir architecture.
Prior to carrying out the Spectral Analyser, the 3D seismic cube should be ‘cropped’ to the required area of interest (AOI) to reduce computer memory required to run the algorithm. It is also advised to run any post-processing seismic workflow (e.g. VanGogh) that will increase signal to noise ratio before spectral decomposition.
This paper presents the details of the Spectral Decomposition workflow which can be applied for identification of geobodies and how its result was used to optimally plan development wells in the target reservoir to mitigate an unlikely compartmentalization of the reservoir.
Safety and Economic Assessment of the Voltaian Basin Project
Authors: Fuah E. B. , Otoo F. N. , Anthony W. 
Published: July 2019

Abstract
The Voltaian basin, Ghana's largest inland basin is the least explored of the sedimentary basins in Ghana. Based on past reconnaissance surveys, albeit limited survey data, the basin is believed to have prospects of hydrocarbon reserves. The government has therefore renewed interest in the Voltaian Basin Project (VBP) to prepare and promote the basin to allow hydrocarbon exploitation activities. Ghana National Petroleum Corporation (GNPC), has been tasked to undertake this project. This paper undertook a safety assessment of the VBP and post VBP, and also examined its economic impact on the Ghanaian economy using standard risk management techniques and economic modelling respectively.
It was deduced that a combination of high to low levels of risk exist in all phases of the project. Out of 64 hazards identified with the VBP and post VBP, three (3) were found to be of high risk, fifty-one (51) of medium risk and ten (10) of low risk. These risks range from gas leakage, through cement plug failure to slips, trips and falls. However, with appropriate mitigation measures such as routine inspection, routine maintenance and repairs, organizing periodic training programs and ensuring a robust Safety Management System, these risks could be reduced to the barest minimum, if not eliminated. The project is therefore a safe endeavour.
In the event of commercial discovery, based on reliable data and informed estimations, the project was observed to accrue net earnings based on net present value for all stakeholders in the sums of at least $18.8 billion, $2.5 billion and $23.8 billion for government, GNPC and International Oil Companies respectively after ten (10) years of production.
The project, if successful, would contribute immensely to the development of the Ghanaian economy. It is expected to replenish the country's declining reserves, provide a comparatively cheaper means of hydrocarbon exploitation, help build the capacity of the national oil company for operatorship in Exploration and Production operations and enhance Ghana's energy supply, bridging the demand gap.
Creating Value Through Integrated Reservoir Study in Mature Asset via Reservoir Uncertainty Characterization: A Case Study from the Niger Delta Field A05 Reservoir
Authors: Jaja Adagogo J. , Okani Nnamdi , Eme Vincent , Ricardos Ricardo Combella , GOM Chevron , Silpngarmlers Lynn 
Published: July 2019

Abstract
In the Early phases of field development, the drilled hydrocarbon appraisal wells may not have been sufficient to define rock properties, fluid typing and contacts. It's very important to define the range of uncertainty in such fields. This is because as the field matures other dynamic data will become available to validate these probable volumes.
The ideal development scenario provides the practitioner with a full suite of data defining the reservoir geometries, reservoir properties, fluid properties etc. to make subsurface decisions. However, in most cases, operational realities will deny the reservoir practitioner this full suite of data.
One practical convention that is used to resolve this data paucity challenge is to evaluate and report the lowest possible volume, if this low case is economic the project will be economic with potential for more upside outcomes. However, a challenge that can arise with this is that after several iterations the low case can become the only case. A better practice is to characterize uncertainty of reservoir parameters during the early stages of field development and carry out the full range outcomes through the field's life. These ranges will then be validated as the field matures.
This paper demonstrates a case in the Niger Delta field A05 reservoir were dynamic simulation model was used to narrow the uncertainty range on the GOC. Proper identification and characterization of the GOC uncertainties helped for the estimate of a range of STOOIP used for dynamic simulation model. Though no static dataset was available to reduce this uncertainty on the GOC, during dynamic simulation, the high-case oil in-place volume was found to be the best match to historical production data with the integration of another reservoir, Delta A12, in one dynamic simulation model. Both reservoirs communicate through the aquifer, separated by a saddle. This then proved up additional volumes in the reservoir, identified previously overlooked reserves and allowed the asset team to propose an extra infill well opportunity than what was previously planned. This new understanding of the A05 reservoir increased the oil estimated ultimate recovery (EUR) by 4.6 MMSTBO.
Performance Assessment and Economic Analysis of Blended Class G Cement With Local Cement for Oil Well Cementing Operations: A Case Study of Ghana
Authors: Amorin Richard , Broni-Bediako Eric , Westkinn Collins , Appau Prince Opoku 
Published: July 2019

Abstract
Good cementing job practices are required for an efficient advancement in drilling and production operations. Most drilled oil and gas wells in Ghana employ the use of class G cement in its cementing operations. This class G cement is imported, scarcely available and relatively more expensive compared to other forms of cements. It also does not promote the local content and local participation policy of the country in the oil and gas sector. This has therefore necessitated the need to research into available local cements (easily available and relatively inexpensive) as an alternative to serve the same purpose as the imported class G cement. This research therefore assesses the performance of class G cement blended with local cement at different ratios in an attempt to reducing the overdependence of the class G cement while considering the technical requirements and economic implications. All the blended samples met the minimum API compressive strength requirement of 1500 psi when cured for 8 hours at 140 °F. Though, free fluid values increased with increasing amount of local cement ratio, all values recorded were below the maximum field requirement value of 5.9%. The blended samples exhibited the ability to be pumpable, recording plastic viscosity less than the maximum recommended value of 100 centipoise (cP). It was therefore established that the use of blended samples (local and Class G) for oil well cementing operations in Ghana would save the industry from 19.57% to 78.28% of money over the use of class G cement only. Considering the performance and economic benefits of the blended cement over the class G cement only at the test conditions, it is highly recommended that, the industry adopts the blending of class G cement with the local cement in their cementing operations to boost the local economy as well as to reducing their cementing operation cost.
Evaluation of Cuttings Transport in Well Annulus Using Power Law Model
Authors: Menegbo Edward K. , Charles Eme , Dosunmu Adewale 
Published: July 2019

Abstract
The efficiency of cuttings transport is very important factor for a good drilling operation program. The transportation of these cuttings through the annulus is a complex problem that is affected by many parameters. For effective cuttings transport prediction, it will require that all these parameters be considered simultaneously. Predictions of pressure losses and cuttings transportation through the annulus are very complex during drilling operation due to the combination of interacting drilling parameters. Success during drilling program is due to efficiently cleaned hole. For better understanding of the effects of some of these parameters that affect cutting transportation, the power law of non-Newtonian viscosity model was adopted to establish the mathematical model of the cutting transport process in the well annulus. Some of the hole-cleaning challenges focused are: the absence of the basic data needed to fully evaluate present field practices and current concepts on drill cutting transport, the combined effect of operational parameters and drilling fluid properties, the effect of operational parameters and cutting properties and what is the effect of rheology model on cutting transport simulation. Poor hole-cleaning during drilling can lead to a lot of bore hole issues which has a negative effects. The overall effect is increase in drilling time and drilling cost. The proposed tool allows more precise prediction of cuttings transport property in the whole range of the well. In this paper, the effects of annular fluid velocity, transport ratio, size and density of cuttings are investigated. The results obtained showed that the most important factors controlling cutting transport are annular velocity and the fluid rheological properties. From the simulation result, it can be observed that an optimum transport ratio was obtained at 1.42m/s. The transport ratio increases rapidly with velocity but then begins to level out or increase more slowly in the velocity range of 1.42 to 1.62 m/s. We can also deduce from the result that cuttings velocity increases with the flow rate; but this increment does not follow a linear behaviour.
Rheological Properties of Terminalia Mantaly Exudate as Drilling Mud Additive
Authors: Inemugha Olanari , Chukwuma Franklin , Akaranta Onyewuchi , Ajienka Joseph A. 
Published: July 2019

Abstract
Polymers are known for controlling fluid loss and modifying rheology in drilling muds through polymer chain entanglement and polymer-solvent interactions. Natural polymers have been used in the formulation of drilling muds, mainly due to their high molecular weight and eco-friendliness but they have limitations in controlling fluid loss, modifying viscosity or forming good gel strength in saline and thermal environments. This study reports laboratory evaluation of Terminalia mantaly exudates as viscosifier in drilling mud formulations. The effects of polymer concentrations, temperature, pH and salinity on the rheological properties of this novel biopolymer were investigated. Results obtained show that as polymer concentration increases (0.5% – 2.5%w/v), the rheological properties (apparent viscosity, plastic viscosity and yield point) of the biopolymer increased. At the polymer concentrations investigated, an increase in temperature (80°F-150°F) results in a slight decrease in the rheological properties of the polymer. At 2%w/v polymer concentration, an increase in salinity results in a slight decrease in its rheological properties, while at 1.5%w/v polymer concentration, an increase in pH (4-10) shows no significant change in the rheological properties. The shear stress increases with increase in shear rate and obeys the Bingham plastic model. The results obtained show that the polymer has a good alkaline resistance at pH above 7 and stable rheological properties at increased salinity and temperature. This has been attributed to the stable repulsive forces of the negatively charged polyelectrolyte of the polymer as salinity increases. From the results obtained in this study, Terminalia mantaly exudate can be a substitute for conventional natural polymers in water-based drilling muds.
Key Success Factors and Challenges of Gas Injection in a Deep Offshore Turbidite Environment – Deepwater Akpo Field Example
Authors: Oukmal Jed , Biu Victor , Usman Musa 
Published: July 2019

Abstract
Gas injection is used as an improved recovery mechanism to provide reservoir pressure maintenance, oil swelling and sweeping. This mechanism offers a high microscopic recovery comparing to water injection thanks to a lower residual oil saturation to gas. However, its macroscopic recovery tends in general to be smaller due to a lower sweep efficiency - a direct consequence of high gas to oil mobility ratio. The case of Akpo Z represents a success story where gas injection led to a significant increase in the condensate ultimate recovery higher than 70%, as a result of the combination of both high microscopic and macroscopic recoveries. Akpo Z is a light condensate-bearing turbidite reservoir deep offshore Nigeria and has been developed using two gas injectors located at the crest of the structure with four oil producers at the flanks. The key success factors of gas injection in Akpo Z are linked both to a favorable subsurface environment, in particular, a large structure, good horizontal connectivity and a near critical light fluid, but also to appropriate reservoir development choices. These elements are detailed in this paper. This paper also shows the challenges linked to daily reservoir management and monitoring from an operator point of view, in particular, the impact of gas injection availability on condensate production shortfalls and the uncertainties linked to gas production and injection metering. Throughout the field life, several monitoring tools such as Intelligent Well Completion (IWC) and 4D seismic have been leveraged to take appropriate reservoir management decisions that led to a delay in gas and water breakthrough and sustain field condensate potential.
Divergent View on the Use of Interpolation Techniques in Reservoir Analysis
Authors: Ezenworo Ebuka , Achumba Gabriel , Adenuga Kazeem 
Published: July 2019

Abstract
The most common methods of interpolation are direct, lagrange, newton divided difference, and spline. Each of these techniques has first, second, and third order approximating polynomials that can be used anytime the need for interpolation arises in mathematical analysis. Of all the methods outlined above, the first order approximating polynomials of these interpolation techniques have found great use because of the ease of application. The fact that these polynomials estimate approximate values calls for the need to check the most accurate interpolation method. Accuracy in reservoir modelling and analysis is of great importance to the petroleum industry because business decisions are taken from the outcome of such analysis. Most of these analyses depend on the accuracy of interpolation been employed.
In this paper, some basic PVT parameters were analyzed with both large and few data points. Few data points were used in order to replicate real life scenario since most of the PVT parameters come with few data point after laboratory experiments. For the large data points, all the interpolating techniques irrespective of the order of their approximating polynomials gave a good result but with few data points, different results were obtained. From the results, it was observed that for PVT interpolations, spline third order approximating polynomial performed better than the rest with few data points.