bluuebunny/crossref_metadata_2025 huggingface dataset:
Effects of Rock and Fluid-Property Heterogeneities on SAGD Performance
Authors: Lawal Kazeem A.
Published: October 2018

To reduce computational costs and accelerate business decision-making, it is not unusual to downplay reservoir heterogeneities. In particular, the evaluation of steam-assisted gravity drainage (SAGD) and other thermal floods may be premised on a homogeneous reservoir, saturated with a heavy-oil of uniform properties. However, virtually all realistic formations are characterised by some spatial variation of rock and fluid properties, even over relatively short intervals. Therefore, to have a good understanding of the physics of oil recovery by SAGD, it is imperative to assess the sensitivity of this recovery process to common heterogeneities in rock and fluid properties. Employing three-dimensional, multiphase and multi-component numerical simulations, this paper tests the robustness of SAGD process to the vertical variation (layering effect) of some rock and fluid properties in a tar-bearing sandstone system. Here, the reservoir properties considered are absolute and relative permeabilities as well as thermal conductivity. On the fluid properties, vertical variation of oil viscosity is investigated. At initial conditions, the resulting vertical contrast of mobility along the heavy-oil column is about three orders of magnitude. In the cases examined, SAGD performance is found sensitive to rock and fluid-property heterogeneities. Permeability (relative), oil viscosity and rock-conductivity contrasts are observed to have significant impacts in the examples investigated. As a result, it is recommended that all heterogeneities should be properly captured at the appropriate scale to ensure realistic rationalisation and prediction of the performances of SAGD and similar thermal recovery processes.
An Analytic Study on Flowline Hydraulics as an Impairment Mechanism of Water Injectors
Authors: Lawal Kazeem A.
Published: October 2018

Considering its potential negative impacts on oil production rates and recovery, injectivity decline in water injectors can lead to significant erosion of project value. Although injector impairment is often related to subsurface-related factors, flowline hydraulics has been identified as a ‘soft’ mechanism of injector underperformance. However, compared to its subsurface counterparts, less attention has been given to flowline hydraulics as a cause of underperformance of water injectors, especially where multiple injectors share a common flowline. While complex network simulation models can be used to evaluate this impairment mechanism, computational costs and interpretation of the attendant simulation results can be worrisome.

To understand the dynamics of the subsurface-surface network of a water injection system without resorting to a complex model, this paper documents an aggregated-network approach, premised on the concept of a "super well". The super well reflects the aggregate reservoir, wellbore and surface hydraulic behaviours of the relevant wells, thus simplifying a complex network of injectors connected to a common reservoir and flowline system. Mathematical formulations of the hydraulics of the aggregate network are prescribed, and solved analytically.

As an illustration of this idea, a practical example is presented. The simulation results show how the injectivity of the super well vary with subsurface conditions plus the number and characteristics of injectors on the flowline at any time.

Among other contributions to the current body of knowledge, this work offers a simple and quick approach to assess the impacts of reservoir conditions, well count, well interactions, well conditions, injection pump pressure, and flowline characteristics on the aggregate and individual behaviours of water injectors sharing the same flowline. More important, the simulation results enable proper discrimination between surface and subsurface factors when evaluating possible underperformers in a network of water injectors.
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

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

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

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

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

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

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

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

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

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

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

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

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.
First Novel Intervention in High Pressure Gas Well to Improve Productivity in SPDC/Nigeria
Authors: Olugbenga Daodu , Michael Osuagwu , Adejoke Adebayo , John Emesi , Olayinka David , Chidi Okoro , Roseline Fasasi
Published: October 2018

The GBN NAG reservoir development project is part of the GBNRC Phase 1-6 project which involves the development of 6 wells with the potential to deliver additional 410MMscf/d to the GBNRC export gas market. The wells were drilled with heavily weighted POBM at 0.68 – 0.72 psi/ft. The lower completion was ran with the heavily weighted mud in hole and isolated with a Formation Isolated Valve (FIV) while the upper completion was completed with brine at 0.48 psi/ft. The wells were completed with 7" 13 Cr tubing, Reslink as sand control with potential of 120 MMscf/d each from each well.

Post clean up and Multi Rate Test activities some of the wells were observed to produce with drawdown higher than the acceptable limit therefore necessitating the reduction of well potential to adhere to the draw down limit and prevent possible well integrity incident.

The team was therefore charged with the responsibility to proffer feasible well intervention options in a High-Pressure environment to restore full wells potential of 410MMscf/d at the most economical way possible without compromising on safety and well integrity.

This paper documents the integrated approach taken by the team to identify the cause of high drawdown in these wells, feasible intervention options and selection criteria leading to restoration of planned potential therefore meeting up company obligations to GBNRC supply and preventing possible well integrity incident in these wells.
Review of Fiscal Incentives on the Development of the Domestic Gas Market in Nigeria
Authors: Adeyinka Temitope , Aron David
Published: October 2018

Over the past two decades Nigeria has made significant progress in the production and utilisation of its gas resources. The development of Nigeria LNG (NLNG) brought about a sharp rise in annual gas production from about 1.5 TCF in 1999 to 2.8 TCF in 2010. The domestic utilisation of gas also got a boost with the approval of the Nigerian Gas Master Plan by government and subsequent issuance of the National Gas Supply and Pricing Regulations in 2008. Over the same period gas flaring has reduced significantly from about 52% of produced gas in the early 2000s to about 10% in 2016. Prior to the development of NLNG, as much 70% to 90% of the gas in Nigeria was flared.

As part of efforts by government to develop gas resources and increase gas utilisation, a series of amendments were made to the Petroleum Act 1969, including different flare-down initiatives as well as new regulations and commercial framework. Fiscal incentives were also provided specifically to increase gas utilisation in the domestic market.

This paper will review the impact of the fiscal incentives on the domestic gas market in Nigeria with a focus on the involvement of the indigenous upstream oil and gas companies. The level of investments in domestic gas utilisation projects by indigenous companies will be analysed. The paper will further explore the level of gas flaring among the different upstream oil and gas companies operating in Nigeria. Comparisons will be made between the different companies under different fiscal arrangements, namely IOCs with JV and PSC arrangements, indigenous companies with sole risk and JV contracts and indigenous marginal field operators. We will review the effectiveness of fiscal incentives in increasing domestic gas utilisation and lessons on areas of improvement for stakeholders.
Success Factors for Marginal Oil Field Development in Niger-Delta Region
Authors: Otombosoba Oruwari Humphrey , Dosunmu Adewale
Published: October 2018

As the hydrocarbon reserves in the fields of Niger Delta region declines, there is the need for improved recovery from existing oil and gas fields reserves especially those classified as marginal oil fields. Despite policy initiatives and considerable potential for the development of marginal fields in Nigeria, marginal oil field development has not been fully successful. It is against this background that this study was undertaken to assess the critical success factors for marginal oil field development in Niger Delta region of Nigeria. An extensive literature review and case study marginal field operators were carried out. The result revealed that the sustainability indicators of marginal oil field development in Nigeria are: Collaboration, partnership/joint ventures, corporate social responsibility, the use of innovative technology, integrated development of oil and gas fields, mergers and acquisition, equipment/facility leasing, clustering and availability of related and support industries are the key factors that enabled the successful operations of marginal field development in Nigeria. The significance of the study is as follows: It serves as a useful guide for investors wishing to participate in the sustainable development of marginal oil fields; it provides new information towards policies that promotes sustainable development of oil and gas resources. The overall significance of the study is to contribute to knowledge on the management of hydrocarbon resource for economic sustainability in Nigeria. It is recommended that the best route for marginal field development is to forge joint action programme by combining global best practice by marginal field operators, government agencies responsible for regulating the oil and gas industry and other stake holders.
Geostatistics – Kriging and Co-Kriging Methods in Reservoir Characterization of Hydrocarbon Rock Deposits
Authors: Ochie Karen Ifeoma , Rotimi Oluwatosin John
Published: October 2018

Understanding the spatial distribution of the physical and chemical properties of rocks and the fluids they contain is very essential in determining hydrocarbon deposits, source, seals and aquifers. Population of petrophysical data for reservoir analysis has always been challenging in hydrocarbon exploration with little or no knowledge about the reservoir or with few pilot wells. Several basic interpolation methods, and geostatistical interpolation methods such as kriging and co-kriging have been used to populate the petrophysical parameters for better analysis but without much consideration for removal of inherent data error. The need then arises for the data to be populated to be error free because an abnormal or anomalous data set would not be representative, irrespective of the accuracy of the model. In this study, the Gamma test (GT) which is a non-parametric technique is used to assess the quality of the data since it is independent on the geostatistical model. Five workflow that took cognizance of GT filtered and unfiltered data assemblage were used. The data is then populated in the models by using geostatistical methods of kriging and co-kriging to interpolate the petrophysical data for further analysis thereby reducing the uncertainties faced during reservoir characterization and reserves estimation of in-place hydrocarbon and understanding of intrinsic reservoir heterogeneities. Results were compared to the results obtained when using both a basic interpolation method: inverse distance method, and geostatistical methods without proper data assessment. Compared to the other interpolation methods, this technique achieved a lower estimation variance error hence can be said to create a better representation of the reservoir petrophysical parameters.
Nano Augumented Biosurfactant Formulation for Oil Recovery in Medium Oil Reservoirs
Authors: Temiouwa Ojo , Oluwaanmi Olabode , Ifeanyi Seteyeobot , Tomiwa Oguntade
Published: October 2018

Production from most oil field using waterflooding has proven not to produce residual oil due to numerous factors. Several recovery mechanisms have been applied which to an extent has its own influence both on the environment, percentage recovery and also the cost of purchase.

In this blending process the bio-surfactant derived from jatropha oil at different concentrations were augmented with nanoparticles for core flooding experiment. A blend of Bio-surfactant and nanoparticles (B-NPs) is a dual purpose recovery mechanism which alters surface wettability, improves fluid mobility, solubility improvement and stabilizes the foam and emulsions formed. At the surface of the nanoparticle, a single layer is formed by the bio-surfactant which is an electrostatic based interaction given rise to particles that are oil loving. Encouraged greatly by electrostatic interactions, the surfactant will then become a monolayer on the nanoparticle surface, resulting in more hydrophobic particles. The impact of the various particle sizes will be considered to analyze to stability of each BNPs concentration for residual oil recovery.

During the laboratory core flooding experiment on Berea cores, the results shows that the nanoparticle-stabilized emulsions increased the oil recovery rate by 8% after water flooding and reduction in the interfacial tension was at the minimum approximately 25 to 1 mN/m.
Effects of Direct Injection DI on Knocking Combustion in Spark Ignition SI Engine Operated on 75-RON and Ethanol Fuels
Authors: Nwovu Sampson Ojon , Cairns Alasdair , Vafamehr Hassan
Published: October 2018

The study compares the effect of simultaneous Port Fuel Injection (PFI) and Direct Injection (DI) on heavy knock in Optical Spark Ignition (SI) engine operated on gasoline (75-RON) and ethanol. It involved evaluation of the Knocking Intensities (KI), In-cylinder Pressure, and Mass Fraction Burned (MFB) of the fuels. The engine has full bore and operated at typical stoichiometric part-load condition with fixed spark timing. We used high-speed natural light (or chemiluminescence) imaging and the engine operating thermodynamics properties to analyze the influence of a particular combustion cycle on the preceding cycle. We observed the combustion process until multiple centred auto-ignition occurred with varied knocking intensities of up to ~50bar. During heavy knock, we adopted fast over-fueling approach and injected varied amounts of fuel into the end-gas region. We found the fast over-fueling to consistently suppressed auto-ignition and eliminated knock for both fuels, especially ethanol. We attributed the effect to reduced auto-ignition delay time and charge cooling effect associated with DI. We compared the cyclic variations of both fuels using the in-cylinder pressures. The result showed that ethanol had higher pressure than RON-75 at both PFI and DI approaches. We attributed the higher pressure of ethanol to its higher affinity to pre-ignition. In terms of MFB, 75-RON demonstrated fastest burning rate than the ethanol at both PFI and DI. We attributed the lower burning rate of ethanol to the increased air mixture dilution effect associated with alcohol fuels. We also attributed it to the higher latent heat of vaporization of the ethanol. Between 50 to 90% mass of the mixture burned, Ethanol proved a higher MFB than RON-75. We likened the improved combustion of ethanol to the presence of oxygen or hydroxyl ion (OH-) in its molecular structure.
Examining the Legal and Regulatory Framework on Marginal Oil Field Development in Nigeria
Authors: Otombosoba Oruwari Humphrey , Dosunmu Adewale
Published: October 2018

The legal and regulatory frame work is critical for marginal field development in Nigeria. The petroleum amendment decree No 23 of 1996 is the basis of marginal field development. The Petroleum Act of 1969 with its amendments prior to Decree 23 of August 1996, prevented access by non-discoverers/owners to undeveloped or marginal fields. Indigenous companies are mostly non-discoverers/owners and this concern about the low level of participation of Nigerian nationals in the petroleum industry was addressed in the Petroleum (Amendment) Decree No 23 of 1996, which had the effect of giving the government absolute discretion in making guidelines for the farm-out of marginal fields. Before August 1996, the potentials of significant contributions by small and/or third-party operators (the so-called independents) to national production capacity had remained negated, unlike many oil basins of the world where the emplaced laws for acreage lease, farm-in/farm-out, the permissible limits of production, and interest acquisition/assignment, all serve to facilitate the transfer of rights to reserves. The overriding reason for the initiation of marginal field development program is to bring about economic development through revenue generation, promotion of indigenous participation in oil and gas sector and discouraging the abandonment of depleting oil fields considered marginal in Nigeria, in additional to technology acquisition and diffusion in the oil and gas industry. However no meaningful oil and gas development can take place without adequate legal and regulatory frame work. This paper assesses the effectiveness of legal and regulatory frame work for marginal field development program in Nigeria. The outcome of the study showed that the decree only guaranteed a 40% foreign equity holding. The provision preventing foreign equity holders of 40% from acting as operators will also act as a disincentive to investment as the lack of competencies on the part of local Oil Companies LOCs (as operators) will discourage many investors It also identifies lack of compensation clause for the original owners of the marginal oilfields in the legal frame work setting up marginal oil field program. The study offers useful suggestion for improvement. It is recommended that the passage of the Petroleum Industry Bill should make the laws governing the marginal field operations in Nigeria to be robust and comprehensive.
Design and Evaluation of Cement Slurries to Prevent Gas Migration – Well XRT Abandonment a Case Study
Authors: Okoli Ugochukwu
Published: October 2018

Well Cementing design is a critical component of Well engineering, as efficient cement design ensures the protection of the casing assemblies from fluid corrosion, and ensures the mechanical support of the well. It also ensures that hydraulic communication between different zones is prevented.

Well abandonment is also critical as the design of the slurry required needs to be designed to efficiently keep hydrocarbons in the wellbore and prevent any immediate, short term or long term migration of hydrocarbons to surface.

There are numerous studies and publications discussing the causes of gas migration after primary cement jobs and well abandonment, some of the causes of gas migration have been linked to poor fluid loss control, poor drilling fluid displacement (reduces seal efficiency at the interfaces), and long cement setting times which allows time for gas to percolate through the partially set cement slurry.

This paper highlights the engineering methods, and how they can be used to properly evaluate the cement slurry design to ensure that gas flow through the cement lattice is completely prevented. It assumes that all other issues which involving poor execution (mud displacement, poor slurry mixing, use of low quality materials and chemicals, human errors), are annulled.

The correlations/equations discussed and used for the evaluation of the abandoned case study well (Well XRT) are the Gas Flow Potential, Slurry Performance Number, Hydrostatic Number and Pressure Decay Limit Parameter. Results from critical evaluation with these equations confirmed that the Well XRT was efficiently abandoned.

The paper further recommends that these equations should be used by Well Engineers be used to evaluate slurry designs for casing cementing and abandonment operations, as they will help ensure that the mechanical and hydraulic isolation is efficiently designed for and achieved.
Using a Land Rig in an Offshore Location: Some Lessons from a Niger-Delta Experience
Authors: Eyitayo Mumuney , Eyitayo Stella , Lawanson Sulaimon
Published: October 2018

In line with national aspiration to increase hydrocarbon reserves and production rate, the last 18 years have witnessed the award of licenses for the development of about 30 marginal fields in the Niger Delta. However, only nine of these green fields have come on-stream to date, while others are at different stages of development, including inactivity. Among multiple reasons, this disappointing performance has been attributed to the combination of high development costs and paucity of funds. With rig rate as the main culprit, drilling/completion typically accounts for 60-70% of development costs. One strategy to lower the commerciality barrier of marginal fields is to address rig costs, without compromising safety and other performance indicators.

This paper presents a case study on the unusual, but successful, deployment of a land rig in a swamp-located marginal field (5-ft water depth) in the Niger Delta. To save about 70% on rig rate, a land rig was evaluated and used in preference to a swamp rig to develop this oil field, which was hitherto stranded.

Employing rigorous multidisciplinary technical evaluations, this feat was accomplished by constructing a fit-for-purpose platform using a reinforced 18-5/8″ casing, thick metallic sheets and 20mm H-beams. The design and execution entailed several considerations, including rig positioning, corrosion risks, and drilling dynamics to total depth (9400ft MD). To enable this first successful use of a land rig in a Niger-Delta swamp, subsequent hydrocarbon production, evacuation and storage were considered.

The planning and execution of the drilling and completions aspect of this project are described, focusing on the success, challenges, and lessons learnt. Among other lessons, the engineering and operational tactics behind the rig placement are highlighted. These insights should be of significant value to other operators of marginal fields in the Niger Delta, and elsewhere.
Making JV Gas Available to the Domestic Market with Minimum Additional Oil Recovery AOR Impact
Authors: Mkpasi Ernest
Published: October 2018

In continuation of her drive to energize the Nigerian economy, the Federal Government of Nigeria (FGN) recently introduced policy reforms in the oil and gas sector to ensure adequate gas supply to the power, gas-based industries and commercial sub-sectors of the domestic gas market.

Mobil Producing Nigeria (MPN) and her Joint Venture (JV) partner, the Nigeria National Petroleum Corporation (NNPC), through the National Petroleum Investment Management Services (NAPIMS) are progressing the 20", 400 million scf/d, 53km Oso – QIT Gas Pipeline Project (OQPP), a key enabler for making the JV's gas available to the domestic market.

The NNPC/MPN JV currently holds about 14 Tcf of gas resources, with the Associated Gas (AG) accounting for 74% while the Non Associated Gas (NAG) account for the balance. The AG are located in the JV's producing fields while the NAG are located in mostly undeveloped fields.

The NNPC / MPN JV currently produces over 1 Bscf/d of gas from mostly the AG fields/reservoirs. Some 67% of this produced gas is utilized for gas injection for Additional Oil Recovery (AOR) in 7 fields. Making the JV's gas available to the domestic market will entail diverting some of the gas currently being re-injected for AOR to the domestic market.

This paper describes the workflow undertaken to optimize oil recovery (in the gas injection reservoirs) within the boundaries of making some 100 – 400 million scf/d of the JV's gas available to the domestic market.