bluuebunny/crossref_metadata_2025 huggingface dataset:
Non-Technical Risks Management: A Framework for Sustainable Energy Security and Stability
Authors: Ite Uwem E.
Published: July 2016

The concept of sustainability implies concern for the present and future generations. In its true form, sustainability requires striking a good balance in the decision-making process by considering the economic, environmental and social aspects of any development, including the development and maturation of oil and gas projects. Based on current projections of global population growth, there is no doubt that future demand for energy will increase significantly from current levels. On the other hand, the envisaged population growth and increased demand for energy will present opportunities and responsibilities for oil and gas companies. This will be compounded by the fact that the additional oil and gas volumes are more likely to be derived from locations with very complex economic, environmental and social characteristics. As such, the ability of oil and gas companies to sustainably mature the opportunities, and effectively manage the responsibilities, will have significant implications for energy security and stability at various levels. This paper discusses the role and significance of non-technical risks (NTR) management as a sustainable development framework, and the need for proactive NTR integration and management in oil and gas project maturation and development process. Efficient and effective management of NTRs has the potential to contribute to greater transparency in the oil and gas business, better returns on investments, and sustainable energy security and stability.
Compressibility Factor Correlation for the Niger Delta Gas
Authors: Muonagor C. M. , Ikiensikimama S. S. , Anyadiegwu C. I.
Published: July 2016

Gas compressibility factor (z) is very essential in gas engineering. Apart from PVT Lab measurements and its subsequent calculations, correlations exist for the estimation of Niger Delta gas z-factor but the correlations were developed with data of gas samples from regions different from the Niger Delta so they do not always predict Niger Delta gas z-factor with good accuracy hence the need for a new correlation that would predict Niger Delta gas z-factor with high accuracy. Correlation for estimating the z-factor of Niger Delta gas was developed in this work using Microsoft Excel Data Analysis Tool and SPSS Statistics Software. 300 data points from PVT analyses of 14 fluid samples from Niger Delta were obtained for this study. The existing correlations were evaluated for Niger Delta gas z-factor to determine the best performing correlation using statistical parameters like percent mean relative error, %MRE, percent mean absolute relative error, %MAE, standard deviation, SD, correlation coefficient, R and performance plots. The developed correlation was compared with the best performing correlation selected using the same parameters. The new correlation was found to perform better than the best performing existing correlation selected, the new correlation had lower %MRE, %MAE and SD; higher R and better performance plot than the best existing correlation. The developed correlation found to outperform the existing correlations is for the Niger Delta gas but can be used for all types of gas with properties falling within the range of data used for its development.
Seismic-Consistent Reservoir Facies Modelling; A Brown Field Example from Deep Water Niger Delta
Authors: Amoyedo Sunday , Atoyebi Haraya , Bally Joakim , Usman Musa , Nateganov Arthur , Bergamo Laurent , Berthet Philippe
Published: July 2016

Reservoir models often tend to be simple and do not always represent typical reservoir property variations and sometimes complex communication patterns typically encountered in deepwater turbiditic systems (amalgamated, laterally-offset stacked channel complexes and lobate systems). Consequently, such models prove unreliable for development planning and long term production forecast. To address this, seismic facies, which are derived from 3D inversion and subsequent classification studies, are often used either as a background trend or direct quantities in static model building process to guide both lateral and vertical reservoir grid population away from well control points.

In this paper, we discuss a methodology for the integration of well data (reference data) and seismic reservoir facies probabilities (auxiliary data) to build a seismic-consistent static reservoir model in a deep-water field, deep offshore Niger Delta. The methodology captures both vertical and lateral variations in reservoir quality seen on well logs (after up-scaling) and seismic-derived reservoir properties inferred from 3D and 4D seismic. Furthermore, we discuss the challenges (fault shallow effect, amplitude degradation across fluid contacts, etc.) and pitfalls (inversion uncertainties, clustering/classification uncertainties etc.) of seismic-driven reservoir facies modeling and their impacts on the reservoir history matching process. Additionally, we discuss potential corrective measures to address some of these challenges, thereby enhancing the consistency of seismically-derived reservoir facies.

The paper concludes with the validation of the geologic model with the use of 3D seismic loop-back process.
Portfolio Optimisation and Screening in Low Funding Era
Authors: Nwaokorie Chukwuemeka , Abia Godwin , Johnsen Esben
Published: July 2016

Portfolio optimisation is the process of choosing the proportions of various assets to be held in a portfolio, in such a way as to make the best use of the opportunities in that portfolio in any prevailing circumstance. This is a component of full-wide portfolio management which is an ill-defined and often over-used term. Whether or not a company's portfolio solution entails consolidating data into a spreadsheet or employing modern portfolio theory to develop an efficient frontier, the goal is to ensure long-term business success by optimising value returns at the minimum risk.

Since June 2014, international oil and gas prices have been declining and currently (Dec 2015) below 40 USD per barrel and 2.5 USD per million Btu respectively (Fig 1). This has brought much pressure on funding availability both on the sides of national and international oil companies.

To fully manage the SPDC's gas portfolio, innovative and sound processes were initiated to optimise and screen a very significant part of our portfolio to ensure that the company still meets and sustains her gas supply obligations with optimal value returns. Prioritisation and ranking of different projects using known parameters and also generating portfolio sensitives using PetroVR tool provided us the foundation for robust decisions on the way forward.

Problem Statement: Evaluate different portfolio options to meet supply agreements and obligations.Prioritise all projects in the portfolio and rank them considering technical, commercial and other non-technical indicators.

The methodologies applied in resolving the above problems were along two work streams namely: Build an integrated gas portfolio model using the PetroVR tool. This was built consistent with latestcompany's operating plan and creating multiple scenarios. The model has production forecasting and economics evaluation/screening capabilities. Therefore, it was possible to check each portfolio scenario in terms of ability to meet gas supply and their economics value.Project prioritisation tool. This is an in-house tool with analytical abilities. Key input data are ultimate recovery, gas Production rate, CAPEX, UDC, NPV, strategic considerations, etc.

The results of these evaluations have helped the company make appropriate decisions on its gas supply strategy and ensuring projects with capacity to meet obligations are matured in priority order.
Experimental Approach to CEOR Optimization in Niger Delta
Authors: Taiwo Oluwaseun Ayodele , Mamudu Abbas , Adijat Ogienagbon , Olafuyi Olalekan , Joshua Dala
Published: July 2016

As important as Chemical Enhanced Oil Recovery (CEOR) methods are to generating additional oil, the effectiveness of the CEOR method used is dependent on its design, rock-fluid and fluid-fluid interaction. Therefore this paper presents the outcome of experimental works to formulate an optimum surfactant Polymer slug for tertiary oil recovery (TOR) of the Niger Delta oil.

Firstly, the displacement efficiency of Hengfloc 63020, a polymer was tested four flood experiments for Niger delta oil. Also the rheological properties for a wide range of concentrations were measured. Secondly, Teepol was screened in the pack flood test at different concentrations. Thirdly, the optimum surfactant concentration and optimum surfactant injection rate were investigated. The fourth set of experiments investigated the effect of flood process design in a three beads pack flood tests to select an appropriate scheme. Using the best flood scheme, the formulated SP slug was then used to recover oils of viscosity range from 3.5cp to 140cp. Advanced mathematical methods were used to analyze and model the experimental results.

The experimental results show that better displacement efficiency can be achieved within a range of polymer concentration for oil. Also the performance of SP flood program is dependent on the right slug formulation, the injection rate and the overall project design. From the analysis of the cores used in the experiment, a fair idea of the efficiency of surfactant –polymer flooding in reservoirs with similar properties of the cores used in the experiment can be inferred.
Grain Size Effects on Residual Oil Saturation
Authors: Taiwo Oluwaseun Ayodele , Mamudu Abbas , Dagogo-Jack Cyrusba , Joshua Dala , Olafuyi Olalekan
Published: July 2016

In order to improve the efficiency of the enhanced oil recovery process, researchers have come up with different methods such as mobility control, chemical, miscible, thermal and other processes such as microbial. In chemical flooding for example, alkaline, polymer, surfactant, surfactant polymer (SP) and alkaline surfactant polymer (ASP) have all been employed in the quest for better efficiency. However, grain size effect on the recovery system during these tertiary recovery techniques has received less attention over the years.

This paper presents evaluation of the effects of grain size on residual oil saturation (ROS) from experimental studies of oil recovery potentials of a formulated ASP slug in synthetic porous media. 1% weight of sodium hydroxide (NaOH), 0.15% weight of shell enordet 0242 supplied by shell research centre and 0.02% weight of hengfloc 63020 were used as alkali, surfactant and polymer respectively. Ranges of core grain sizes of 0.063 to 0.090, 0.106 to 0.150, 0.150 to 0.212, 0.212 0.300 and 0.425 to 0.600 micron were considered in five different experiments performed. Each of the experiment was accomplished by a procedural sequence of brine saturation, oil saturation, water flooding and ASP flooding.

The results show that the porosity of the synthesized core increases with decreasing grain size from 37.2% to 43.74% for a range of 0.600 micron to 0.063 micron of sizes. The permeability of the synthetic core decreases from 2309 millidarcy to 669 millidarcy as the grain size decreases from 0.600 micron to 0.063 micron. Pressure drop across the beads pack increases from 0.294 psi to 1.015 psi as the grain size reduces. The oil recovery by an immiscible fluid through the beads pack increases as the pore throat get smaller or the grain size reduces. The volume of ROS after flooding reduces as grain size reduces.
Fractional Wettability Effects on Surfactant Flooding for Recovering Light Oil Using Teepol
Authors: Taiwo Oluwaseun Ayodele , Uzezi Orivri , Mamudu Abbas , Onuoha Sean , Adijat Ogienagbon , Olafuyi Olalekan
Published: July 2016

The fractional or mixed wettability of porous media has been recognized as ubiquitous condition in the petroleum literatures. Fractional wettability refers to the fraction of the total pore surface area which is preferentially water or oil-wet. And this wetting condition of a reservoir rock plays a significant role in determining the oil recovery

This paper presents laboratory analysis of the effect of wettability alteration on recovery mechanism and the effects of Teepol at different wettability conditions using a glass beads-pack. Oil wet condition was established by the use of kerosene and other fractional wettability conditions were also established. Six experiments were performed. In all the experiments, imbibition, drainage, water flooding, surfactant flooding and polymer flooding were carried out on the porous medium. 0.7PV surfactant solution (teepol) at a concentration of 0.9%wt and 1.1PV polymer solution (gum Arabic) at 5%wt concentration were used. In experiment A, B, C, D, E and Z (control), the porous medium was 100% water wet, 25% water wet and 75% oil wet, 50% water wet and 50% oil wet, 75% water wet and 25% oil wet, 100% oil wet, 100% water wet respectively.

The results show that equal percent wettability of both water and oil and complete wettability of either oil or water yield more incremental oil when compared with those of 25% water wet and 75% oil wet condition and 75% water wet and 25% oil wet fractional wettability. Teepol is effective in lowering the oil-water IFT in all porous media with recovery ranging from about 75.5 to 90% of the residual oil saturation (ROS). Experiment C (50-50 fractional wettability) has the highest incremental oil recovery due to grain-to-grain interactive forces while experiment Z has the lowest recovery (about 41% of ROS). This strongly suggests mixed or fractional wettability reservoirs are good candidate of chemical EOR technique. However, even fractions contributions to the mixed wettability by both phases are required for optimum process performance.
Enhanced Integrated Characterization of a Complex Naturally Fractured Reservoir using Mud Logs, 3D Seismic and Performance Data
Authors: Ershaghi Iraj , Ojukwu Chima , Mayerson Drew , Rozek Stephanie
Published: July 2016

This paper presents the results of a study for estimation of reserves in a highly complex naturally fractured reservoir off the Coast of California. The fractured reservoir at the Point Arguello Field, consisting of the siliceous rocks of the Monterey Formation, has produced more than 187 million barrels of oil during the last three decades primarily from fractures intersecting the extended reach and directionally drilled wells. This study was conducted to assess the economic viability of continuing production of the field and economic incentives for maintaining operations at the three existing offshore production platforms. In our study we examined the remaining reserves from the fracture controlled production and scrutinized the potential contribution of the tight matrix to primary recovery and for EOR processes. In this integrated and comprehensive study, we used a new interpretation of 3D seismic data, re-visited extensive mud log data, prepared diagnostic plots of performance data and incorporated conventional logs, DST and core data to characterize the production system.

From the analysis of GOR, WOR, and 3D seismic we identified 10 separate compartments and related the vast differences observed in well productivities to the compartment size, degree of fracturing and behavior of water influx. We also developed common sense reservoir forecasting solutions to examine the potential application of CO2 injection for extracting oil from the tight matrix. The economic forecasting indicates substantial opportunities by managing water influx, exploiting bypassed intervals by new perforations, and drilling infill wells in blocks using volumetric curvature analysis data.

Lessons learned show the definitive significance of integrated reservoir characterization, importance of mud logs and 3D seismic, and fault characterization for defining compartments, and potential applications to other similarly fractured reservoirs.
Modifying the Performance Index in evaluating Risky Oil and Gas Investments
Authors: Akinpelu L. O. , Isehunwa S. O.
Published: July 2016

Oil and Gas investments are inherently risky, especially in upstream exploration where technical risk is predominant. Because of the large upfront expenditure required for these projects, it is imperative that investors in the business are well informed of the risk to which their capital is exposed. However, most commonly used performance measures focus on one aspect of what is a multidimensional problem. While expected value gives an indication of the amount of value created by the investment, the standard deviation gives an insight into the distribution of expected returns. The Performance Index combines these two insights into a single measure, value created per unit of variability (the standard deviation), which is a significant improvement over the one dimensional measures.

However, the Performance Index, PI is based on total variance and does not reflect the uncertainty structure of the risky investment. PI does not distinguish between upside and downside variances and can sometimes give a lower ranking to a prospect with large upside variance (High gain situation) leading to the Paradox of aversion to incremental reward (PAIR). We show this flaw in PI in an expected value maximization context as well as in an expected utility maximization context.

Semi-variance analysis gives an insight into the uncertainty structure of a risky investment. We use semi-variance analysis to propose a modification to PI to eliminate the problem of PAIR. Total variance is decomposed into upside and downside variances and the modified PI estimated based on downside variance alone. In decomposing the variance, we recommend using a threshold value to avoid the problem of a "shifting mean". We demonstrate through two examples (1) that though conventional PI may correctly rank risky prospects, non-recognition of the uncertainty structure does not accurately reflect the risk characteristics of an investment, and through a second example, a well drilling situation in which conventional and the modified PI lead to different ranking and investment decision recommendations.
Effects of Mud Filtrate Invasion on Well Log Measurements
Authors: Akinsete Oluwatoyin O. , Adekoya Doyinsola A.
Published: July 2016

Invasion of mud filtrate into surrounding formation affects most data acquired by logging tools, which impedes accurate formation evaluation. The invasion process may result in formation damage and reduction in well producibility. The objectives of this work are to determine the effects of invasion on induction well logs, identify the invasion profile present, and to determine the factors influencing invasion. Therefore, a realistic model depicting the actual wellbore conditions is required in order to accurately analyze the invasion process, and its effects on well logs.

In this work, a numerical model is developed. The physics of mud filtrate invasion in overbalanced drilling is numerically simulated using a 3D multiphase fluid flow simulator. Sensitivity analysis is done to quantify the influence of several petrophysical parameters on the spatial distribution of mud filtrate away from the wellbore, and the corresponding effects on induction logging tools.

Result showed that the distribution of salt concentration due to the invasion of fresh water-base mud into a formation containing highly saline formation water affects resistivity measurements. Based on the plot of resistivity against radial distance of invasion from the wellbore, annulus invasion profile is found to be present. Also, sensitivity analysis showed that formation parameters such as porosity and permeability, in-situ fluid saturation and mudcake permeability are important factors to consider when determining the extent of filtrate invasion. A plot of formation resistivity versus formation porosity shows that a reduction of formation porosity from 0.25 to 0.1 increased the radial distance of invasion by about 70ft, and also shifted the annulus deeper into the formation.

Result also showed that both medium and deep induction logs can be affected by invasion, and this depends on the total time of invasion, the formation rock and fluid properties and mudcake properties.
Effects of Temperature and Pressure on Shale Cuttings Dispersion in Water Based Mud WBM Using NACL, CACL2, KCL Salts as Primary Inhibiting Agents and Polymer XCD Xanthan Gum as Secondary Inhibiting Agent
Authors: Babajide Ale , Adebowale Oladepo , Adesina Fadairo , Churchill Ako , Ifechukwu Micheals
Published: July 2016

The primary cause of wellbore instability is the interaction of water based mud with shales which usually involves the movement of water and ions into or out of shale thereby causing alterations in mechanical property of the shale resulting in dispersion of shale particles into the mud.

This work involves experiments to analyze the effects of chemical osmosis, diffusive flow prior to shale hydration and inhibition, determination of the effects of salt addition on pH and density of mud and also determination of the effect of Temperature and pressure other than just temperature on dispersion of shale cuttings into water based mud. It also shows the behaviour of shale in various inhibitive agents e.g NaCl, KCl, CaCl2 and Polymer XCD when being hot rolled.

Results from experiment performed in this work confirmed that osmosis and ionic diffusion play a great role in shale hydration and dispersion. It also showed that subjecting the system to temperature and pressure conditions other than just temperature caused more dispersion of shale into mud.

KCl was the best inhibitive agent as more shale cuttings were recovered from the mud while the least shale recovery was from CaCl2/salt formulation. A further experiment was performed by adding polymer XCD to the Salt/mud formulations so as to investigate its inhibitive capability; result showed that more shale cuttings were recovered as compared to when only Salt/mud was used.
Production Optimization in the Duke Field Using the IPM Suite
Authors: Alaigba David , Orodu Oyinkepreye D. , Aguilera Maria
Published: July 2016

This project focuses on building a reservoir sub-sea network model for a condensate field in the gulf of Guinea, the Duke Field. It integrates the five developed Duke reservoirs, development wells and subsea network using the Petroleum Experts' Integrated Production Model suite of software, (IPM) which is widely used in the E&P industry especially for integrated forecasting, surveillance and production system optimization that require integration of surface and subsurface models.

Following the acquisition and quality control of data from other teams working on the Duke Field, a network model which integrates the five Duke reservoirs, their associated wells and subsea network up to the production separator was built. The model was initialized and used to predict full field performance under different scenarios.

Finally, a water injection allocation sensitivity study was performed and the results were analyzed both technically and economically. From the technical point of view, the option to reallocate 10 kbwpd from reservoir U to reservoir P-upper North and another 10 kbwpd from Reservoir ST to reservoir Q-Lower brought about the optimum recovery. This was also supported by a simple economic analysis. It was then recommended that additional water injectors be drilled in P-Upper North and Q-Lower to unlock an additional 8.4 MMSTB of reserves resulting from higher sweep efficiencies and better pressure maintenance.
Evaluating the Effect of Temperature and Polymer Concentration on Properties of Xanthan Gravel Pack Fluid
Authors: John A. O. , Joel O. F. , Chukwuma F. O.
Published: July 2016

Sand production from oil wells is undesirable and could have several consequences. There are several techniques of controlling or minimizing sand production from wells. Gravel Packing is one the most reliable methods of sand control. The success of gravel pack job operations in the field depends, to a large extent, on the fluid designs. Several types of polymers have been used in the past and some are still currently being utilized as gelling agents for gravel pack fluids. Different polymers impart different properties on the fluid system, making the fluid to exhibits different behaviours at different downhole conditions and this can have positive or even negative effect on the job execution. The polymer used for preparing gravel carrier fluids must have acceptable properties to match the well and engineering design requirements to prevent job failure and/or formation damage. Xanthan polymer has shown excellent gravel carrying capacity and good gel strength. In this study, the effect of temperature and polymer concentration on the degradation of xanthan was evaluated with different concentration of Sodium Persulfate oxidizer breaker. The proppant carrying capacity at different temperatures was also investigated. Test results indicated that gel break time, rheology and sand suspension properties are function of temperature, breaker and polymer concentrations.
Challenges and Prospects of the Use of Horizontal Directional Drilling Techniques for Laying Oil and Gas Pipelines in Nigeria
Authors: Ibeh S.U. U , Nnakaihe S.E. E
Published: July 2016

Nigeria pipelines especially the petroleum and petroleum product pipelines are always vandalized by the sabotage. Huge amount of money is expended to put the damaged pipeline in good shape, and petroleum and petroleum product transfer is sometimes hampered due to leakages and damages caused by the oil thieves. Also huge money is being budgeted yearly to secure the pipelines. To combat this problem, Horizontal Directional Drilling (HDD) is being proposed.

HDD is a method of installing underground pipes and conduits along a prescribed bore path from the surface, with minimal impact to the surrounding area. Installation lengths up to 6500ft and depth of 200ft have been completed and diameters up to 48 in. have been installed in shorter runs. The process begins when a directional bore machine pushes a bore head connected to hollow pipe into the ground at an angle. As each joint of drill pipe is pushed into the ground a new one is added behind. In rock, a mud motor, which converts the hydraulic pressure of the drilling fluid into mechanical rotation, is used to rotate the bit and the drill pipe is not continuously rotated. Steerage is accomplished by aligning the angle of the mud motor to the desired direction.

This paper investigates the challenges and prospects of using the HDD technique to lay pipeline to a greater depth/distance that will be inaccessible by the oil thieves. The construction process (pilot hole, reaming and pullback) along with the major components (drill rig, drill pipe, slurry, slurry recycling, survey equipment, drill bits, and reamers) is discussed. The advantages of cost reduction, and environmental, social and time benefits were examined in this study. The challenges of proper soils information, subsurface conditions, training and knowledge, drilling fluids and binding of the drill pipe and reamer/bit are highlighted.
Improved Reservoir Fluid Modeling Using Optimized Flash Calculations
Authors: Ogali Oscar I. , Egbe Samuel O.
Published: July 2016

A realistic reservoir fluid model is important when studying the mechanics and dynamics of a reservoir. One of the methods used in building reliable fluid models is the equation of state. Fluid description using this method is iterative and largely depends on the speed and accuracy of the flash calculations used to generate the equilibrium ratios. In this study, a machine learning technique known as the gradient descent algorithm, was used to optimize the fluid modeling process in terms of time, computer resources and accuracy. This involved applying the gradient descent algorithm to the flash calculations. Fluid models built using equations of state are often uncertain for practical use. This is due to errors in the predictions of the model. Thus, experimental data was used to tune the thermodynamic parameters of the developed fluid model, using automatic non-linear regression, so as to further improve the accuracy of the model. The results show a physically and mathematically acceptable fluid model with accuracies up to 5 decimal places. Therefore, optimizing fluid modeling processes using machine learning techniques can improve the overall speed and accuracy of the process.
Application of Artificial Intelligence Techniques in Drilling System Design and Operations: A State of the Art Review and Future Research Pathways
Authors: Bello Opeyemi , Teodoriu Catalin , Yaqoob Tanveer , Oppelt Joachim , Holzmann Javier , Obiwanne Alisigwe
Published: July 2016

Artificial Intelligence (AI) has found extensive usage in simplifying complex decision-making procedures in practically every competitive market field, and oil and gas upstream industry is no exception to it. AI involves the use of sophisticated networking tools and algorithms in solving multifaceted problems in a way that imitates human intellect, with the aim of enabling computers and machines to execute tasks that could earlier be carried out only through demanding human brainstorming. Unlike other simpler computational automations, AI enables the designed tools to "learn" through repeated operation, thereby continuously refining the computing capabilities as more data is fed into the system.

Over the years, AI has led to significant designing and computation optimizations in the global Petroleum Exploration and Production (E&P) industry, and its applications have only continued to grow with the advent of modern drilling and production technologies. Tools such as Artificial Neural Networks (ANN), Generic Algorithms, Support Vector Machines and Fuzzy Logic have a historic connection with the E & P industry for more than 16 years now, with the first application dated in 1989 for development of an intelligent reservoir simulator interface, and for well-log interpretation and drill bit diagnosis through neural networks. Devices and softwares with basis from the above mentioned AI tools have been proposed to abridge the technology gaps hindering automated execution and monitoring of key reservoir simulation, drilling and completion procedures including seismic pattern recognition, reservoir characterisation and history matching, permeability and porosity prediction, PVT analysis, drill bits diagnosis, overtime well pressure-drop estimation, well production optimization, well performance projection, well / field portfolio management and quick, logical decision making in critical and expensive drilling operations.

The paper reviews and analyzes this successful integration of AI techniques as the missing piece of the puzzle in many reservoir, drilling and production aspects. It provides an update on the level of AI involvement in service operations and the application trends in the industry. A summary of various research papers and reports associated with AI usage in the upstream industry as well as its limitations has been presented.
Sensitivity Analysis of a Single Mixed Refrigerant Liquefaction Process of Natural Gas
Authors: Una D. C. , Oduola M. K. , Odagme B. S.
Published: July 2016

The demand for greater efficiency and large capacity for liquefaction process is inevitable for optimization. This study presents the sensitivity analysis of the factors that affects liquefaction processes of natural gas. Some of these factors are the natural gas pressure, temperature and composition on the single mixed refrigerant liquefaction process was simulated using ASPEN HYSYS 8.6 software. The effects of these parameters on specific power, power consumption and refrigerant flow rate of the process were simulations and examined. At constant pressure, temperature decreased from 15 to 5°C resulted in a 15% decrease in specific power and an increase from 15 to 25 °C resulted to 40% increase. At constant temperature, a decrease in natural gas pressure from 60 to 30bar and increase in specific power from 0.387 to 0.452 kWh/kg-LNG was observed which amounts to a 16.80% increase and when increased from 60 to 90bar specific power decreases from 0.387 to 0.348kWh/kg-LNG about 10.08 % decrease. Thus, when natural gas is supplied at a given pressure and temperature, a decrease in supply pressure will increase power consumption and an increase in supply pressure will decrease power consumption. The useful exergy for the system was about 26% of the total energy (46.42MW) available, indicating that about 74% of energy supplied by the compressor ended up as losses in different components in the process liquefaction cycle. However, the largest loss occurred in LNG heat exchanger and cooler which were to 25 and 24% respectively. The simulation results showed that, natural gas supplied at 150MMScf, 60bar and 15°C gave rise to LNG production of about 0.95MTPA.
Economics and System Metrics Applications for Upstream Capital Investment Performance Evaluation: An Empirical Review and Guide
Authors: Paraclete Nnadili , Adenike Adejola , Iledare Wumi
Published: July 2016

The petroleum industry is one of the most influential players in the world economy. The need to understand and assess the value in the oil and gas sector has never been greater than it is today. Over the next two decades the sector will need to invest substantial amounts of capital to meet the growing demand for energy which will involve rising cost pressure and competitive forces. Large scale of capital investment is required for most petroleum projects hence, it is important that investment decisions are based on a thorough analysis of variables and uncertainties. An ability to assess the viability of investments and the real value of oil and gas assets is critical to success where a range of complex technologies and facilities are required.

This paper examines the economics and system metrics application for upstream capital investment performance evaluation. Three capital investment choices (R, S, and T) were considered, using; the expected value analysis, decision tree analysis, stochastic dominance and @Risk tools.

Results show that stochastic dominance tests exposes the risk sensitivity of prospect R and S, opposing metrics results exposed the mutual exclusivity of the prospects and sensitivity analysis shows effect of uncertain dry hole probability on Expected Monetary Values (EMV). Therefore, for a strategic project selection, risk attitude of investor was introduced as a criterion for prospect selection between "R' and "S" and a range of dry hole probabilities (29% – 40%) was obtained for prospect "S".
Evaluating the Oil Mobilization Properties of Nanoparticles Treated with Arabic Gum and Xanthan Gum for Trapped Oil in Porous Media
Authors: Joseph-Igbor Bridget , Orodu Oyinkepreye D. , Afolabi Richard O.
Published: July 2016

The flow of multiple fluid phases in porous media often results in trapped droplets of the non-wetting phase. Recent experimental and theoretical studies have suggested that nanoparticle aqueous dispersions may be effective at mobilizing trapped droplets of oil in porous media. Hypotheses to explain the observation include the nanoparticles' modification of solid wettability, changes in interfacial tension and interface rheology. The difficulty in observing droplet behavior on the pore scale has made the understanding of such mechanism still unclear. In this work, the relationship between nanoparticle concentration and microscopic diversion of flow was investigated and how this impacts on the oil mobilization efficiency. Also investigated in this work was how the rheology of the dispersion medium for nanoparticles impacts on the overall recovery of trapped oil in porous media. A core flooding experiment was carried out on which aqueous solutions of different concentrations of the nanoparticle dispersion was used as the displacing fluid likewise rheological modified solutions of the nanofluids. The output of this work showed that the nanoparticle concentration impacts on the recovery of trapped oil through the microscopic diversion of fluid flow in porous media and this phenomenon in conjunction with earlier mention hypothesis effectively showed how nanoparticles enhances the recovery of trapped oil in porous media.
Synergistic Effects of Dispersed Bonny Light Crude Oil on Selected Aquatic Organism
Authors: Nwaizuzu C. , Joel O. F. , Sikoki F. D.
Published: July 2016

Oil spill dispersants (OSD) are known to be effective tools needed to clean and disperse oil spills. One major concern in the use of dispersants is their toxicity. The toxicity of individual chemicals may be known and be of no concern, but when combined with other chemicals they can have unknown additive or synergistic effects. This study was therefore designed to investigate the toxicological effects of OSD Seacare and Bonny light crude oil on the African Catfish (Clarias gariepinus). The 96hr acute toxicity of the water accommodated fraction (WAF) of the mixture of OSD Seacare and Bonny light crude oil was investigated as well as the critical body residue on the fingerlings of the African Catfish. The mean (±SD) weight and height of the fish was 1.27±0.37g and 5.35±0.57cm respectively. The following concentrations, 30, 90, 180 and 270ml/L, were used for the definitive test of the CEWAF. The LC50 for the CEWAF was determined to be 199.289ml/L while no death was recorded in the WAF-co. The oil spill dispersant Seacare synergized the toxicity of the crude oil on the test organism by more than 4.516 times further proving that oil spill dispersants can and do synergize the toxicity of crude oil on aquatic organisms. There was no PAH recorded in the fish from the control. From the fish exposed to 30ml/L of the dispersed oil concentration, the total PAH concentration was 0.730227ppm with 1 Benzo (g,h,i) perylene accounting for the total amount. Whereas the total PAH in the fish exposed to the 270ml/L concentration was 2.52903ppm with Naphthalene accounting for the total amount. After the acute toxicity testing and the test organisms were put in clean water, it was noticed that the test organisms exposed to the dispersed oil had a change in colour and there was reduced feeding in both those exposed to the WAF of the crude oil and dispersed oil.
Comparative Analysis of Drilling Cost Used for Petroleum Economics in the North Sea, Gulf of Mexico and Niger Delta Regions
Authors: Ikwan Ukauku , Egba Amba Ndoma , Dosunmu Adewale , Iledare Wumi
Published: July 2016

The primary objective of an E & P company is to drill and produce hydrocarbon at minimum cost with high level of safety without compromising environmental standards. With the current global downward slide in oil prices most E & P firms are slashing costs to shore up profitability. Drilling operations are high capital-intensive projects that drive unit production cost northwards. This paper presents a comparative analysis of drilling costs in three geographical locations of the world petroleum provinces viz; North Sea, Gulf of Mexico and Niger Delta with sensitivities of the various elements that affect drilling cost with a view to assisting operators and rig owners on optimizing activities in a lean environment.

Relying on panel data sourced from databases of a global energy consultant and industry operators, historical absolute average cost and footage trends were compared during the period of 10 years (2005-2014). A randomly selected well cost data was used to carry out the sensitivity analysis to deduce key determinants.

It was found that although there are regional differences that reflect the local geology and some economic factors, drilling times and all costs rise sharply with increasing depth. Also drilling cost for the Niger delta province is highest compared to the other two regions. The sensitivity study showed that the highest contributor to high drilling cost is the intangible element in which the rig rate, hole problems and security issues should be the focus in drilling cost reduction and economics. Contract renegotiation strategy to drive down rig rates and establish new market equilibrium is recommended in this lean environment. Also tangible costs from tubulars can be reduced with favourable policy on reviving Nigerian steel industries to enable local sourcing of these tubulars, improve employment rate hence reduce insecurity in the Niger Delta area.
Gas to Power in Nigeria: This Burden on Natural Gas
Authors: Onwuka Emmanuel I. , Iledare Omowumi O. , Echendu Joseph C.
Published: July 2016

One million heads of population require at least 1000 megawatts of electricity capacity as a rule of thumb in industrialized economies. Sub-Saharan Africa (SSA) as at 2013 averaged about 0.91 MW per one thousand head of population on this scale. Nigeria is the largest economy in this region, but only attained peak generated power of 5074.7 MW in 2016 giving it a generated power per population (GPP) value of 0.003%. Nigerian economic development is stunted by the perennial abysmal performance on the scale of GPP.

Many studies have reported a seemingly direct proportionality relationship between economic development and available electricity capacity in a clime. Nigeria has plans to increase electricity capacity through natural gas utilization. This energy resource sustainability however, may not be guaranteed from a non-renewable scale.

This paper evaluates the sustainability of electricity capacity targets in Nigeria and the need placed on natural gas keeping in perspective 0.1%, 0.0075% and 0.003% levels of GPP.

The approach adopts a gas turbine (GT) performance modelling leveraging on the basic thermodynamic processes. Specific fuel consumption (SFC) is determined from the operating conditions of a GT. Given the set GPP scenarios, power profiles are evaluated by imposing the electricity demand outlook estimated with base population growth rate of 2.52%. Interaction of the SFC and the power profiles result in the required quantity of natural gas supplied to the GT power stations.

Neglecting reserves replacement and assigning 70% of base electricity demand to natural gas, a GPP of 0.1%, 0.0075% and 0.003% would deplete allotted base reserves at estimated yearly average rates of 30.8, 6.25 and 4.41 bcf/d respectively. This may only be sustainable for just 16, 79 and 112 years in that order.

It is therefore instructive that renewable electricity generation sources be reconsidered in the future energy resource mix projections for genuine economic development in Nigeria.
Efficient Installation of a Modular Straddle System for Deep Water Gas or Water Shut Offs
Authors: Rajamani Karthik , Ipsen Michael
Published: July 2016

A well with a high gas-oil-ratio (GOR) was experiencing gas coning due to the recycling of injected gas. A gas shut off was recommended to improve gas handling efficiency due to the constraints on surface processing capacity. The strategy was to install a 138 m, retrievable straddle assembly across a zone spanning from 2572 m measured depth (MD) to 2719 m MD in the 5 ½" open hole gravel pack (OHGP) screens.

The client's considerations included coiled tubing (CT) and slickline. It was also necessary to be as efficient as possible to keep time and costs down. Based on these considerations, the operator decided to use an electric line (e-line) tractor combined with a hydraulic stroking tool for its high reliability. The stroking tool also provided the benefit of delivering the required force at the exact point where it was needed downhole as compared to coiled tubing, which would exert the force from the surface.

The complete straddle packer assembly was successfully installed in 17 runs without any non-productive or lost time incidents. As a result of the intervention, gas production was greatly reduced and oil production was returned to normal levels. The operation was so successful that the client saved nearly 30 days on an operation that was planned for 45 days.

Due to the success of the initial operation, the client decided to execute several other, similar water and gas shut off operations in the field replicating the same methodology. This paper highlights the methodology used and the cost and HSE benefits provided by selecting the e-line solution with the tractor and stroking tools to perform the gas shut off. The paper will also discuss the details of the job planning as well as the execution of the operation, marking a first in this West African country.
Impact of Oil Base Mud Contamination OBM on Waxy Crude Properties
Authors: Mmata Bella , Ajienka Joseph , Onyekonwu Mike , Chukwu Godwin
Published: July 2016

Oil base drilling mud is commonly used during drilling operations because of the associated advantages especially in terms of cost and time savings benefits. However, once there is excessive overbalance pressure in the mud column during drilling, the oil base mud will invade the hydrocarbon formation. And since base oil used in preparing the drilling fluid is miscible with the formation hydrocarbon fluid, it will contaminate the reservoir fluids and alter the fluid's properties. Hence for waxy fluids (paraffinic), when early time contaminated samples are collected down hole via open hole wire line sampling, erroneous fluid property data will be generated in the course of characterization. Such erroneous data can be quite misleading, especially when used for the early phase upstream facility design. And the cost implication can be enormous for the flow assurance engineer. In this work, a waxy crude sample was collected from an onshore field in the Niger Delta region. Subsequently, the sample was contaminated with various levels of oil base mud in order to investigate the errors induced by OBM on waxy crude properties such as the wax appearance temperature (WAT), pour point, density and viscosity. The result shows that the presence of OBM contamination, significantly impacts on the waxy crude properties with pour point temperature being the most affected by contamination. Hence caution should be exercised when using or interpreting experimental data obtained from waxy samples contaminated with oil base mud.
Process Design Evaluation of an Optimum Modular Topping Refinery for Nigeria Crude Oil Using HYSYS Software
Authors: Mamudu O. A. , Igwe G. J. , Okonkwo E.
Published: July 2016

Industrially, unprocessed crude oil has little or no value; hence there is the need for any country to have operational petroleum refineries to convert the crude oil from its original state into more useful product. According to the Nigerian National Petroleum Corporation (NNPC) 2001-2013 annual bulletin, even with a total refining capacity of 445,000 bopd (barrel of oil per day) expected from the Nigeria four conventional refineries, the country still records scarcity of refined products as none of the refineries can boast of working above 60 percent of its design capacity. In an attempt to provide solution to the above worsening scenario, modular refineries set up at strategic positions within the country can help to boast refining capacity. Although different modular topping refinery configurations exist, this paper examines the simple, pre-flash and the pre-flash pump around reflux scheme in terms of maximum product yield using the Niger Delta Petroleum Resources (NDPR), Bonny Light, Bonny Medium, Brass and Qua Iboe crude assay. Crude oil characterization using Aspen Hysys was done based on their true boiling point to determine the maximum liquid volume fraction of the different distillates. Simulations of the different crude assay were carried out on the different topping refinery configurations highlighting the variation between characterized and simulated volumetric cuts. The result shows that NDPR crude will favour the production of LPG, light naphtha and diesel. Bonny medium crude will favour the production of gas oil and residue oil while qua iboe and brass will favour the production of kerosene and heavy naphtha respectively. The best scheme for different distillates was also determined