bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technological Risk Assessment: A Panacea to Preventing Major Process Incidents- A Case Study of Amenam Kpono
Authors: Abia D. , Ajayi S. , Iwegbu M. 
Published: October 2018

Abstract
The explosion at BP's Texas city (March, 2005), macondo deepwater horizon blowout (April 2010), an Olefins Plant reboiler rupture and fire (June, 2013) and the explosion of a Refinery in Torrance (Feb, 2015) are all widely known major incidents that have resulted in major loss of lives, damage to the assets and the environment. These looses worth millions of dollars not counting the loss of lives shows that process safety barriers was compromised. How then can we be more certain that these incidents does not occur again in our plants? What indicators can we look out for? Are our risk assessment for process safety accidents properly assessed with adequate barriers defined to prevent the occureance of major incidents?
This paper focuses on the technological risk assessment (scenario based assessment; a Total E&P major risk assessment methodology) carried out on OML 99 for the management of major risk activities. To study, manage operational activities, hazards to people, environment and assets were identified and assessed in a systematic methodology and associated risks evaluated.
The objective of the process was to proffer risk reduction measures and ensure that sufficient barriers exist to prevent major risk scenarios.
The outcome of the technological risk process was the major risk register containing the top ten scenarios (Major Risks) showing scenarios, barriers/controls in preventing and protecting the occurrence of these major accidents with an action plan containing a list of approved risk reduction measures at the end of the ALARP demonstration.
As examples, the paper communicates the barrier management strategies between the major risk register, the site emergency response plan, safety critical barriers and management inorder for Field Operations management to ensure that the asset operational Chain of Command identifies and manages the major risks of their installations in order to prevent the occurrence of major incidents.
Empirical Model for Estimating Formation Volume Factor at Bubblepoint Pressure of Nigeria Crude Oil
Authors: Adeeyo Yisa Ademola 
Published: October 2018

Abstract
Formation Volume Factor (FVF) is a basic parameter in reserve estimates, reservoir management, and optimization. A small error in the value of FVF results in gross under or overestimation of original oil in place, reserve, wrong economic model and ultimately too optimistic or pessimistic return on investment. Formation Volume Factor is measured in the laboratory. In the absence of verifiable lab data, various published and recognized empirical models could be used. Since the most relevant factor influencing the properties of any reservoir fluid is the condition under which it was formed; this determines the value of different volatile and heavy hydrocarbon compounds that constitute the oil, some of these correlations are simply unreliable and could result in a serious error especially when used to predict FVF of crude from different region and or different range of crude characteristics. It is, therefore, important to use a very accurate model to estimate FVF for all petroleum engineering applications.
This study used more than 2050 unpublished PVT data sets from different locations in Nigeria in rigorous nonlinear regression modelling. Using modified Newton-Raphson nonlinear least-square data fitting approach; Levenberg-Marquardt algorithm, a new mathematical model was developed for the estimation of the Formation Volume Factor. Steps and algorithms used were illustrated.
A comparative study of published correlations and this study was carried out. Results show that the performance of the new model is more accurate, reliable and outperformed the existing models.
The results of this study will facilitate more accurate reservoir, production and surface facility engineering calculations of Nigeria crude oil.
Gas Hydrate Inhibition in a Simulated Offshore Environment Using Local Inhibitor
Authors: Urunwo Elechi Virtue , Ikiensikimama S. S. , Ajienka J. A. , Akaranta O. , Onyekonwu M. O. , Odutola T. O. , Okon E. O. 
Published: October 2018

Abstract
Gas hydrates pose a very serious flow assurance problem by impeding flow especially in the offshore environment where accessibility is restricted. This paper takes a look at gas hydrate inhibition in a simulated offshore environment using plant extract (PE) as local inhibitor. The essence of this work is to source for an effective and bio-degradable gas hydrate inhibitor from locally sourced materials and also ascertain their effectiveness as compared to a conventional hydrate inhibitor Mono ethylene glycol (MEG). Experiments were conducted using a mini flow loop. It will involve mitigating hydrate formation using varying weight percentages of the inhibitor (1wt%, 2wt% and 3wt %) and then evaluate their effect on hydrate inhibition in the mini flow loop. Sensitivity charts of pressure, temperature, time for both the local inhibitor and MEG were made. From the analysis, 1 and 2 weight percentages of the local plant extract (PE) showed better inhibitory capacity than MEG while 3 weight percentages of plant extract (PE) and MEG had a close match. Based on the result gotten, the PE could be recommended for field trial.
Siesmic Guided Property Modeling
Authors: Chukwusa Uche , Onyekonwu Mike 
Published: October 2018

Abstract
A realistic property model with reduced uncertainty will guarantee accurate reservoir description for field development purposes and hydrocarbon in place volume estimation. During the early development stages of a field, one of the major challenges associated with building a representative geologic model is the sparseness of data at well points. It is therefore necessary to rely heavily on remote data such as seismic, which generally supplies accurate information regarding horizontal continuity but lacks critical vertical information.
The objective of this study is to access the confidence level of using a seismic attribute like relative acoustic impedance to constrain the distribution of well log estimated property like porosity across the grid cells of a static reservoir model.
The common approach of accessing this confidence is by a simple cross plotting of the seismic generated attribute against well log estimated property. In some cases, the result shows a very low level of correlation and so the interpreter is discouraged in using that seismic attribute as constrain.
In this paper a method of calibrating the seismic attribute and well log property is developed. This involves cross plotting the seismic and well property on a zone by zone basis instead of the common method of using the entire reservoir thickness. This method helps to investigate the individual zone with good correlation coefficient and those with poor correlation coefficient
The "relative acoustic impedance" attribute which is a porosity indicator was used to calibrate log estimated porosity. This was done indirectly by first establishing a good negative correlation between log estimated porosity and log estimated acoustic impedance. The "relative acoustic impedance" was however resampled into the model and cross plotted against upscaled acoustic impedance log. Plots carried out within the entire reservoir thickness generally gave poor correlation coefficient. When these plots were carried out for each zone within each reservoir thickness, the result showed good correlation coefficient for most zones. Zones within the reservoirs with satisfactory correlation were however used for the seismic guided porosity distribution across the grid cells of the reservoir model.
Indigenous Participation in E&P Sector for Production Capacity Expansion and Investment Enhancement: Lessons from Nigeria
Authors: Akinlawon Adeyemi J. , Ildeare Omowumi O. 
Published: October 2018

Abstract
The indigenous operatorship programme in Nigeria was introduced by the Federal Government in 1993. A set of discretionary awards made on sole risk (SR) basis, in which government has neither participating nor economic interests was initiated to jump start the programme. Furthermore, a total of 28 fields were allocated to 35 indigenous companies to commence a complementary marginal fields program. Twelve (12) marginal fields are currently producing, the rest are at various stages of development. As at 2015, 16 indigenous companies had successfully acquired interests divested by the international oil companies (IOCs) from the joint venture (JV) assets. Hence, the number of JV companies has increased from the primary six IOC JV entities.
Performance evaluation of indigenous companies in terms of investment profile and production growth is the key objective of this paper. For the purpose of this paper quantitative descriptive approach is applied to appraise the indigenous operators, following allocation of sole risk blocks, marginal fields and the major divestments of the equity participation of some IOCs from the JV assets.
Accordingly, the emergence of indigenous operators has obviously changed the landscape of the oil and gas industry in Nigeria. Some IOCs are gradually divesting from the onshore and continental areas, while shifting attention to developing deep offshore assets. The Nigerian National Petroleum Corporation (NNPC), now has more JV Partners to manage and perhaps would have to revise its strategies for value maximization from its JV assets.
Breaking Down Complex Challenges with Simple Solutions Through Reservoir Navigation Service
Authors: Imomoh Victor , Ndokwu Chidi , Holbrough David , Idris Ma'aji , Fang Xiaodong , Otevwe Joseph 
Published: October 2018

Abstract
Today's complex and challenging reservoirs are now accessible using state-of-the-art technology in drilling and logging-while-drilling (LWD). The drive for advanced, capable technologies to explore the full production potential of these reserves cannot be overemphasized. In addition to the drive for increased production from existing fields, there is an increased focus on precisely placed horizontal wells in the best part of the reservoirs. The drilling is carried out by using the existing well stock and employing re-entry techniques. The dramatic adjustment in the crude oil price has made cost-effective drilling and geosteering solutions increasingly critical for delivering efficient, economic wells.
Reservoir navigation services involve predicting the geology ahead of the bit to optimize the placement and drilling of a horizontal wellbore in a complex reservoir. These predictions are based on formation evaluation data gathered while drilling using deep-reading azimuthal resistivity LWD tools and innovative interpretation techniques to update the geologic model in real time. Adjustments to the well trajectory based on the updated geologic model are enabled by downhole systems that have good directional control and use continuous proportional steering technology to steer the bit.
Well QH is a 3D complex well located in the Adanga Field of the Niger Delta Basin, offshore Nigeria. The well is drilled to a total hole depth of 9,512 ft MD. The Q reservoir is shallow, at approximately 3,600 ft true vertical depth (TVD), and it required complex 3D well planning to precisely land and drill a horizontal well in the thin, intercalated sand and shale sequence. There are other directional challenges inherent in a brown field development when drilling from a complex multiple slot platforms with existing producing and suspended wells.
This paper discusses the well QH as a case study, showcasing how reservoir navigation services with fit-for-purpose LWD data can result in increased net lateral production in a complex, thin multilayered reservoir. The case study highlights how the uncertainties encountered during planning stage and challenges in the execution stage were turned into a success story. This paper also discuss the application of well placement through advanced, user-friendly software, grounded on the state-of–the-art LWD and rotary steerable technology and their significant impact on the project, challenges and lessons learned.
Impact of Fines Migration on Well XX and Lessons Learnt from Stimulation Exercise
Authors: Ayopo Kudayisi , Eze Celestine , Dokubo Richard , Oluwatobiloba Oladunni 
Published: October 2018

Abstract
Formation damage by Fines Migration is one of the leading causes of loss of productivity in oil and gas wells. Oil field operators report significant losses which can sometimes reach 100% as a result. This is one main reason why operators around the world carry out well interventions in the range of hundreds of thousands of dollars in order to improve wells’ productivity or bring them back to production.
Well XX, one of the most prolific producers in a field in the Niger Delta area of Nigeria began to experience noticeable decline in wellhead pressure and oil production as soon as spikes in water production were observed. Shortly after this observation the well quitted and was later shut in. Wireline re-entry, BHP survey, Wax and Asphaltene studies and others were conducted to ascertain the root cause of the problem while elimination method led to the suspicion of fines migration. The well was then lined up for acid stimulation.
The well was stimulated with a Coiled Tubing unit using Regular Clay Acid (RCA) as the main treatment fluid as advised by the contractor. The well was restored to production after the entire activity and well cleanup. This improvement in productivity was followed by high water cut and increase in well head pressure to its initial value.
After the successful stimulation exercise, the well pressure and production were observed to drop continually while BS&W was on the increasing trend. Soon afterwards the well status returned to initial and a second stimulation was planned for the well. The second stimulation was planned with understanding of the type of migrating clay which necessitated a change of recipe for the stimulation.
This paper details the issues with the well before stimulation, results of studies that were conducted, the first stimulation exercises - results, analysis of post stimulation data and planning and success of second stimulation.
Replacing Petroleum Profit Tax with a Dual Petroleum Tax System: Implication on Petroleum Project Economics in Nigeria
Authors: Echendu Joseph C. , Iledare Omowunmi O. , Akinlawon Adeyemi J. , Idowu Adekunle J. 
Published: October 2018

Abstract
The paper evaluates the impact of the single tax system at its current rate in comparison to the proposed dual tax system in the National Petroleum Fiscal Policy in Nigeria on project economic performances. The paper also expounds on the arguments between two schools of thought (single tax and dual tax proponents) towards understanding the rationale underlying the divergent viewpoints. The methodological approach applies the discounted cash flow modelling framework to evaluate the performances of terrain based projects using selected metrics such as internal rate of return (IRR), discounted payout (DPO), net present value (NPV) and government take (GT) under the two tax systems. It calibrates the unit technical cost (UTC) for typical deep water projects in Nigeria and imposes the current and proposed fiscal terms. Varying cost treatment options and alternative allowable/incentives are investigated in the modelling framework using global best practices. The paper concludes that whichever tax system is adopted, it is possible to achieve equivalent economic metrics. However, the dual tax system presents a better flexible option over the single tax system as one of the split rates – especially the hydrocarbon resource tax – could serve as an instrument to incentivize investment, promote conservation, expand resource base through technology innovation more easily without denying the mineral owner an outright revenue via taxation. In a classical case like Nigeria, where national fiscal budget is largely financed using hydrocarbon revenue, the dual tax system seemingly offers a better option for revenue sharing among the stakeholders – the resource owners and the Federal Government than the current single upstream tax system. This paper bridges the gap between the divergent viewpoints on taxation system in Nigeria by proffering a pathway. It suggests that the overall objectives of stakeholders could be achieved using the same metrics if the mechanics in designing a fiscal system is better understood. This will lead to progressive application in achieving the divergent expectations.
Impact of Appropriate Gas Transmission Tariff on Private Investment in Gas Backbone Pipelines in Nigeria
Authors: Adejumo Adedapo , lledare Omowumi , Dosunmu Adewale 
Published: October 2018

Abstract
The objective of this paper is to develop a model based on the Rate of Return framework to determine appropriate natural gas pipeline tariff for a given pipeline specification. The Levelized tariff will be based on the pipeline's cost of providing service to enable the pipeline investors to recover their Costs and earn a return on their investment. Ceteris paribus, with the transparent determination of acceptable gas pipeline tariff that guarantees profitability, investors will be incentivized to invest in building and operating gas backbone pipelines to serve the huge local gas market in Nigeria. Arbitrary rate of return, inefficient pipeline tariff and absence of regulation regime are reasons why investment in the gas pipelines has been unattractive to local and foreign investors.
Application of Machine Learning Ideas to Reservoir Fluid Properties Estimation
Authors: Onwuchekwa Chukwuma 
Published: October 2018

Abstract
Machine learning refers to a range of data-driven techniques that give computers the ability to learn from exposure to data and to make predictions based on the learning. Popular applications of machine learning include hand-written digit recognition technology used by some banks to automatically process cheques, spam filtering technologies used by email applications to detect spam mails and object recognition technologies in self-driving cars, to name a few. Examples from the Oil and Gas sector, though less exotic, have also been growing steadily. For example, artificial neural networks have been used for years for the estimation of reservoir properties such as permeability and porosity; there have also been applications of the technique in the analysis of the huge amount of pressure and flow rate data from permanent downhole gauges; also, data-driven predictive analytics have been applied in mature fields with huge amounts of data.
This paper discusses the results of an investigation of the performance of some machine learning techniques in the prediction of reservoir fluid properties. The techniques investigated include K Nearest Neighbors (KNN), Support Vector Regression, Kernel Ridge Regression, Random Forest, Adaptive Boosting (Adaboost) and Collaborative Filtering. PVT data from a database of 296 oil and 72 gas reservoirs from the Niger Delta were used in the study. The input data used in the training include initial reservoir pressure, saturation pressure, solution gas oil ratio (for oil samples), formation volume factor, condensate gas ratio (for gas samples), API gravity, gas gravity, saturated oil viscosity and dead oil viscosity. Trained models were developed using the techniques and used to predict saturation pressure and formation volume factor, oil viscosity and condensate gas ratio respectively for samples that were not part of the training.
It was found that all six techniques gave very good results for the oil formation volume factor, comparable to and in some cases exceeding the performance of standard industry correlations such as Standing and Vasquez-Beggs. The techniques also gave good results for bubble pressure better than the standard correlations. For oil viscosity, the Random Forest and Adaptive Boosting gave very good results, of the same quality as that obtained with the popular Beggs-Robinson correlation, and did not require dead oil viscosity data. Performance of the techniques in estimating gas PVT parameters was not as good; due perhaps to the limited gas data. However, Adaptive Boosting and Support Vector Regression gave good results for dew point pressures. Overall the results indicate that these machine learning techniques offer promise for fluid properties estimation and should be given consideration where a company has acquired large amount of PVT data in a geological basin it operates.
Integrated Approach to Well Integrity Data Quality Management Initiative in Shell Nigeria
Authors: Benjamin Ajaraogu , Cosmas Nwankwo 
Published: October 2018

Abstract
Recent regulations and standards demand that there is a need for a systematic Well Integrity Management and control during the entire life cycle of a well.
Availability of reliable Well Integrity data is fundamental to a proactive, efficient and transparent life cycle Well Integrity management.
The use of low cost smart systems, processes, and incorporation of a number of API performance standards have been adopted and implemented by operators to ensure that their Assets are operated within their defined operating envelopes and meet the required performance standards and process safety requirements.
The operate phase is the longest phase in the Well Integrity life cycle management and thus a critical phase that requires intelligent systems, experience and resources to maximize and optimize the life cycle value of the Asset. This phase can span decades and usually involves data acquisition, assurance and analysis For well integrity prediction.
The key challenge for operators is the ability to maintain a comprehensive and reliable dataset for proactive Well Integrity management due to reasons ranging from resources to gaps in critical data as a result human error and legacy well issues.
This paper will discuss the Well Integrity data quality gaps, key challenges, data management architecture framework, improvement initiatives, lessons learnt and the impact in the overall Well Integrity Compliance.
Advances in Cement Packer Slurry Design Using Liquid Cement Latex: Offshore Nigeria Delta Case Study
Authors: Osaronwaji Emmanuel , Okubor Eleanor , Deele Happiness , Chemmarikattil Rohan , Onuh Haruna , Omodu Orji , Awonaike Oluwatoni , Onobrakpor Ochuko 
Published: October 2018

Abstract
The deployment of a coiled tubing (CT) conveyed cement packers for accessing bypassed hydrocarbon/ marginal reserves through rigless through-tubing well intervention presents economic potential for mature field access and optimization. They provide a good means of zonal isolation of the last reserves in an existing wellbore. However, zonal isolation is challenging in highly deviated wells. These shortcomings are predominantly related to slurry density control, displacement efficiency, well architecture (completion jewelry), poor cement bonding in the annulus between the tubing and production casing, and issues with pulling the CT out of hole while maintaining the differential pressure between the well head and casing head pressures (estimated top of cement in the casing annulus).
Recently, the application of liquid cement latex (LCL) additive for cement packer completions using CT has shown remarkable success. LCL cement additive is a liquid additive designed to lower equivalent circulating density (ECD) and impart excellent fluid-loss control, high-temperature suspension properties, and acid resistance to cement slurries. This paper summarizes the operational and logistical process of executing a cement packer with conventional cement and LCL additive in a highly deviated well, offshore Niger Delta. In addition, the applications, features, and benefits of LCL with associated spacer fluid is detailed. The operational and logistical benefits of using LCL is discussed, concentrating on its ease of transportation and pumping, minimal equipment requirements, consistent slurry properties, and reduced environmental exposures. Best practices recommendations are also be made for cement packer placement, supported by the executed successful deployment in the offshore Niger Delta using LCL.