bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Characterization, Simulation & Estimation of Storage Capacity of depleted Reservoirs in Niger Delta for Underground Natural Gas Storage
Authors: Mgbaja U. M. , Enwere N. 
Published: July 2017

Abstract
Nigeria has the 9th Largest Gas Proven reserves in the world with an estimated reserve volume of 188 trillion standard cubic feet (SCF)1. Despite these enviable figures, Gas Utilization and Monetization in Nigeria is still below par operations. This is as a result of a number of issues including: ►Faulted Gas Distribution Networks►Low Gas Price►Insufficient favorable Gas Policies
Based on the current dynamics in Crude Oil Pricing & the need for more alternative and unconventional sources of energy, developing all facets of Natural Gas Technology, which has proven in recent times to be a formidable alternative source of energy is not only beneficial but imperative. In developed Nations, Storage of hydrocarbon resources is essential in order to meet seasonal demands. Continued commodity price volatility indicates that more storage is appropriate.
On Thursday, the 31st of March, 2016, Nigeria's power generation grounded to a complete halt, with a total output of 0MW for close to three hours.2 The reason for this detrimental incident has been linked to a number of factors including Pipeline Vandalism and the destruction of vital power infrastructure.3 Other most likely causes are the reduced Oil & Gas Production rates due to the declining Crude Oil Prices and therefore declining Global Demand for Nigeria's Crude.
In order to eliminate this problem, Underground Natural Gas Storage is a potential solution that will lead to a continuous availability of Natural Gas irrespective of market conditions and in turn an improvement in economic conditions.
Major Fields in the Niger delta are mature provinces, having been in production for well over 35 years, most of these fields are in the decline curve of the Oilfield Lifecycle. These depleted reservoirs can serve as underground natural storage for Nigeria's abundant associated gas.
The objective of this research is to estimate the projected volumes of depleted reservoirs in the Niger delta region, using reservoir data from particular fields and to analyze their gas deliverability & economic viability if utilized for underground storage.
The Effect of Regulation on the Development of Natural Gas Value Chain in Nigeria
Authors: Igbokoyi Alpheus O. , Daboer Justine N. , Iledare Omowumi 
Published: July 2017

Abstract
Natural and Energy resources are synonymous. They are very important to the nation's economy and industrial growth. Therefore, Government always has control through regulations over natural resources in any nation. Regulations can sometimes have negative impact on the development of natural resources and create artificial scarcity to the detriment of economic and industrial growth, and the welfare of the citizens. Over-regulated market has been known not to be conducive for competitive market and may even create price hike, which can be destructive to innovation and create unattractive business environment to both foreign and local investors.
Nigeria's Niger Delta has been described as gas rich zone. Up to date, the same gas has been poorly developed compared with oil. Apart from the liquefied natural gas project, the gas value chain in Nigeria has been poorly developed. This paper examines the historical gas development trend and evaluates the impact of regulation on the natural gas value chain in Nigeria. The historical impact of regulation on the United States of America's natural gas value chain development is also studied as a standard so as to underpin, by way of comparison, the reasons for the poor development of the natural gas value chain in Nigeria.
As a link to utility, natural gas is used for heating and cooking at homes, and providing electricity in the United States of America and other developed countries. It is also linked to some industrial sectors such as fertilizer, petrochemical, and refinery. Because of its utility structure, natural gas is regulated at some nodes along the value chain to accommodate, not by subsidizing, the financial capability of all citizens in purchasing such utility products. When natural gas is fully developed along its value chain for national development, the consequences are vibrant and stable economy coupled with industrial growth. Therefore, the purpose of this paper is to examine the natural gas market in Nigeria and compare it with United States' market which is a standard market that Nigeria can use as a blue print to follow.
Cost Effective Drilling in Heavy Oil and Financially Constrained Environment – A Sapele Shallow Field Development Case Study
Authors: Ijeoma Festus , Temisa Presline 
Published: July 2017

Abstract
Heavy oil is in abundance in the Niger Delta Region of Nigeria but few operators are developing it because the high cost of development. Most operators have also suspended drilling of new wells due to financial contraints and the high cost of drilling.
Apart from the heavy crude oil (18 to 20 deg API) characteristic of the Sapele Shallow field and the current financial constraints induced by low oil prices, the Sapele Shallow field has other technical challenges such as loss circulation, reservoir structural uncertainties and artificial lift issues for heavy oil. Other challenges include vague contractual rates, improper well scope definition and application of new technology.
Based on the reviews done, wells can still be drilled, even with shoe string budgets irrespective of the technical and financial challenges. A variety of technologies and concepts has been developed to mitigate the challenges and reduce the average Sapele Shallow field development budget, and they include; Re-negotiation and reduction of existing contractual rates.Improved well planning and landing strategies.Reduction in drain hole length.Batch drilling.Slim hole drilling.Proper well completion scope definition.
Effects of Ionic Interactions on the Stability and Destabilization of Water-In-Crude Oil Emulsions
Authors: Adeyemi Bamikole J. , Sulaimon Aliyu A. 
Published: July 2017

Abstract
Water-in-crude oil emulsions are formed as a result of high shear stresses at the flow restrictions such as choke valves and the wellhead during crude oil transport with produced water. Consequently, the produced water disperses in the crude oil forming droplets that are stabilized by the natural surfactants/emulsifiers in the crude oil. Emulsion droplets undergo spherical to ellipsoidal shape deformation and subsequent break up to smaller drops during flow. Droplet deformation is often resisted by the interfacial tension as determined by the Laplace pressure. The droplets will coalesce if they are attracted and adhered together but will become stable if repulsion between them dominates. However, the application of droplet-droplet interactions has not been adequately exploited for formulation of environmentally friendly chemical demulsifiers. This work investigates the effects of ionic interactions of droplets on the stability and destabilization of water-in-crude oil emulsions.
Properties of the crude oil used in this work were measured and correlated to the properties of the resulting emulsions at different water cuts and salinities. The stability of the emulsions was determined by examining the sedimentation and coalescence of emulsion droplets in bottle tests and backlight scattering methods. The breakage of the droplets was examined by conducting the rheology profiles of the emulsions. Subsequently, the emulsions were destabilized with sodium methyl ester sulfonate (SMES) at 70°C. SMES and is an anionic chemical material that is locally available, environmentally friendly and possess potential demulsifying properties. Results show that the emulsions were kinetically stable since the droplets remained highly dispersed and were characterized by diffusion–sedimentation subsequent equilibrium. Destabilization of water-in-crude oil emulsions is mostly a function of droplet momentum and the viscous force presented by the continuous phase. Thus, inducing ionic charges in emulsion systems can significantly enhance the force of attraction among emulsion droplets which leads to improved phase separation.
Integrating Petrophysical Data and Dynamic Modeling in Estimating Original Gas-Oil Contact in Post Production Reservoirs
Authors: Amaefuna Magnus , Ezenobi Eric , Okporiri Cyril , Ekwealor Jude 
Published: July 2017

Abstract
Clearly delineating contacts are usually aimed at before development, but what happens when later data indicates contacts different from what have been interpreted? How do we ‘work back in time’ to re-estimate the original contacts?
Our case study documents a reservoir which due to the poor well coverage, paucity of log data, side wall sample and pressure data, was initially interpreted as an oil bearing reservoir, however, a new well drilled post production of over 20 years indicated the presence of a huge gas cap, the size of which could not have been due to the formation of a secondary gas cap. This necessitated the determination of the original contacts in order to properly define the reservoir volumes which will impact on its future development.
This paper presents the use of an integrated thinking approach which makes use of all the available geological, petrophysical and dynamic data in determining the original fluid contacts in a post production scenario. Reservoir simulation using simple tools as material balance combined with petrophysical and geological concepts were applied in this paper. The results obtained shows that the use of static data alone such as petrophysical logs in determining the original contacts for post production reservoirs can be greatly misleading as the results obtained may conflict with dynamic data available for the reservoir and therefore not fully representative of the reservoir and its history.
A Comparative Study of Pseudo-Steady State Inflow Performance Between Horizontal and Vertical Gas Wells for Thin Reservoirs in the Niger Delta
Authors: Sukubo Ibianga 
Published: July 2017

Abstract
No horizontal gas well has been drilled in the Niger Delta since the inception of the technology and its first application in the region. The argument has been that the present vertical well technology, unlike oil, is adequate for gas production considering the relatively favourable petrophysical properties (e.g. permeability) and the usually significant pay thickness in the region. As a result, no evaluation of possible application of the horizontal well technology in gas production has been considered in the region. However, there are several pockets of gas resources trapped in highly heterogeneous reservoirs of less than 20ft within the region which pose deliverability challenge to the use of vertical wells in terms of drawdown and flow assurance.
For a quick evaluation of the possible impact of horizontal technology on gas well deliverability in the Niger Delta, the effective wellbore radius concept was applied. This concept can be used for practical comparison in reservoirs and/or fields where no horizontal well has been drilled; particularly for small pay thicknesses. As a result, a comparative horizontal inflow model for pseudo-steady state radial flow was developed and validated using field data.
It was observed that for thin anisotropic reservoirs, horizontal well performance is at least better than vertical well as much as the following conditions are satisfied: (1) h/L=0.1 for all the sensitized range of kh/kv, (2) h/L=0.2 for kh/kv ≤ 35, (3) h/L=0.3 for kh/kv ≤10, (4) h/L=0.4 for kh/kv ≤5 and (5) h/L=0.5 for kh/kv =2. Above the scaled aspect ratio boundaries, the deliverability ratio drops below one. Though the horizontal well deliverability is higher the impact of turbulence is seen to be in the range of 0.98 – 1.06 depending on the scaled aspect ratio; and the effect of reservoir anisotropy is between 2 – 80% for these thin reservoirs across typical ranges (200 ≥ kh/kv ≥ 2) seen in the Niger Delta.
This paper presents the comparative model and its quick evaluation results with examples after due testing; considering the impact of non-Darcy turbulence, scaled aspect ratio and reservoir anisotropy.
Evaluating Gas Recycling Scheme in a Retrograde Gas Condensate Field Under Contractual Supply Obligations: Niger-Delta Case Study
Authors: Balogun Olalekan , Alli Adem , Ogbuli Andrew , Apampa Yewande , Bahry Alia , Fasasi Roseline 
Published: July 2017

Abstract
While the development of retrograde gas-condensate fields is usually targeted at supplying medium to long-term contractual obligations, their profitability is significantly influenced by the ability to maximize condensate (C5+) recovery. This, however, is impacted by the retrograde condensation phenomenon where condensate drop-out in the reservoir during depletion results in loss of huge amounts of valuable liquids, which reduces the effective gas permeability and overall reservoir productivity. One of the ways to manage the impacts of this phenomenon is via Gas Recycling.
Horner Field is located onshore Niger-Delta and has two prolific overpressured reservoirs, G1X and G2X. G1X reservoir is a lean gas reservoir with initial CGR of 51stb/MMscf. G2X reservoir is a near critical fluid with a CGR range of 188 to 280stb/MMscf with depth, suggesting a compositional grading system. The potential production challenge in G2X reservoir is retrograde condensation in the reservoir coupled with water encroachment. The Constant Volume Depletion (CVD) Experiment from the PVT Laboratory Study indicates maximum liquid dropout of 6% at reservoir pressure of about 2000 psia in G1X reservoir and 40% at reservoir pressure of about 4000 psia in G2X reservoir, thereby making G2X reservoir a potential candidate for enhanced condensate recovery.
This paper presents overview of an assessment of the potential benefits of gas recycling in Horner Field using full compositional dynamic and integrated production models. Six development wells were found to be optimal for Horner field development. Sensitivities on injector optimum location and well counts were carried out. While the natural gas (mainly methane) from G2X reservoir was being recycled into thesame reservoir, the wells in G1X reservoir were beaned up to ensure security of gas supply obligation. 1-injector Scenario was found to be optimal with incremental condensate recovery factor of about 8%and positive economic indices of 15.2% IRR.
Use of Green Burner Technology for Well Cleaning-Experiences and Lessons Learnt
Authors: Ugo’ Okoli , Horace Awi 
Published: July 2017

Abstract
Conventionally, during clean-up and well-testing operations, it is required to receive fluid from the wellbore to the drilling rig. Due to the unavailability of adequate storage facilities on these rigs, it is typical to flare the hydrocarbons received from the clean-up and testing operations. The problems involved with burning the hydrocarbons during offshore well clean up and testing has been the discharge of hydrocarbon emissions into the air. These gases are a by-product of the incomplete combustion of hydrocarbons, and recent studies have shown deleterious climatic effects of these gases.
Due to the poor efficiency of some conventional burners, there are also "fall-outs" during the flaring operations which leave thin oil sheen on the water surface. The oil sheen on the water surface prevents oxygen to get to the phytoplankton, and in extreme cases asphyxiates the sea animals and causing further pollution issues to the marine environment.
To mitigate climatic and the environmental issues and ensure conformance to the Nigerian regulatory laws, an optimized burner technology (Green Burner), which addresses incomplete combustion of hydrocarbons and fallout conditions was identified. It was used by Addax Petroleum for flaring hydrocarbons during clean up and testing operations.
This paper discusses the effects of flaring with poor systems with low efficiency burning disposal systems, and highlights the advantages of using the Green Burner technology for flaring operations.
Predicting Time-to-Failure of Water Injectors due to Internal and External Particulates
Authors: Lawal Kazeem A. 
Published: July 2017

Abstract
Where the natural drive mechanisms are inadequate, water-injection is commonly employed to supplement reservoir energy and improve sweep efficiency in conventional oil fields. In such applications, there is usually a strong positive correlation between field performance and injectivity/longevity of the water injectors. However, injectors are vulnerable to impairments, which can result in gradual injectivity decline and catastrophic failure. Therefore, robust field management and business planning require a good understanding of the impairment mechanisms of water injectors in general and, more important, reliable predictions of their injectivity behaviour and active lifetimes.
Following a review of common impairment mechanisms, this paper highlights the complexity and uncertainties of injector failure. It then exploits the two major impairment mechanisms of water-hammer and deep-bed filtration (DBF) to develop simple semi-empirical mathematical models for predicting the time-to-failure of vertical and slightly deviated water injectors. While water-hammer mobilises solid particulates native to the formation and deposits same in the wellbore, DBF entails external particulates suspended in the injection water and deposited in the reservoir. The mechanisms and impacts of these independent sources and deposition of formation-damaging particulates are covered.
Among other findings, sensitivity tests performed on the proposed models using realistic input data provide important insights into the mitigation and management of injector impairments caused by water hammer and DBF. To enhance the performance and longevity of water injectors, this study shows that these impairments can be mitigated through practical strategies such as (i) provision of long sumps (rat holes) as part of well completions; (ii) minimising the frequency and duration of emergency shutdown; and (iii) minimising the concentration of solid particulates entrained in injection water.
Finally, given the almost inevitability of injector degradation, it is recommended that realistic forecasting of oil and gas production associated with waterfloods should always account for potential injectivity decline and possible failure of applicable water injectors.
The Impact of Crude Oil Emulsion on Horizontal Separator Efficiency
Authors: Joseph A. , Obong B. , Ajienka J. A. 
Published: July 2017

Abstract
The problems associated with oil production are assuming unprecedented proportion and complexity. As a field matures, with high water cut from wells, water breakthrough from water flood operations or other artificial pressure maintenance programs, water production and consequently, the produced fluid water cut and gas-oil ratio would be changing. As these fluids flow from the reservoir to surface facilities, the fluid is subjected to agitation and changes in temperature and pressure, which result in the precipitation of originally soluble substances in the crude to form emulsions, scales, hydrates, etc along the flowline. Although, the water content in the crude oil is reduced in the separators, a considerable amount enough to cause havoc is left behind in the crude and this could cause high transportation cost, as valuable transportation capacities will be occupied by valueless water. In many other instances, the separator fluid loading may exceed the original design capacity of the vessel resulting in poor oil and water effluent standards. This paper develops a procedure that describes the impact of crude oil emulsion on the efficiency of horizontal separators. The procedure can be used to monitor and optimize the operating conditions of horizontal separators to achieve good effluent qualities, thus providing a diagnostic tool to identify areas in the separation train that may be experiencing problems.
Challenges of and Learnings from Abandonment Operations in the Niger Delta
Authors: Enyekwe Alfred , Agbogu George , Ojo Osayande 
Published: July 2017

Abstract
Abandonment of wells is a significant part of oilfield abandonment, accompanied by abandonment of facilities and installations. Well abandonment operations in the Niger Delta of Nigeria have covered different categories of wells; –Previously suspended wells–Completed wells of varied completions design– single string, two string dual, two string multiple–Wells with varying degree of vandalisation including cases where entire wellhead system were cut off and stolen.
Long term safety and prevention of reservoir wellbore fluids, or gas from being released to the environment, is a top priority. While well abandonment is subject to detailed planning from the early design stages for a well, external circumstances throughout the well life may pose new needs or challenges that need to be factored in and addressed when approaching the actual abandonment.
For vandalised wells, their condition makes sub-surface abandonment objectives difficult to achieve. Compliance to desirable permanent barrier isolation strategy and legislation becomes technically more challenging. Dual string wells with tubing hangers severed off are difficult to handle. In wells with high deviation, loss of tension on the tubing due to the severed hanger can cause a permanent buckling in deeper sections, making it impossible to run in tools. Wells completed in multiple zones are faced with the risk of inter-zonal communication in the case where pressure regimes are significantly different, which could lead to more complicated sub-surface challenges. This also creates the risk of having combined loss and kick situation from two different reservoirs respectively. The increasing severity of vandalisation has re-inforced these risks and has increased the cost of abandonment significantly.
This paper highlights the challenges and learnings from an abandonment campaign in the Niger Delta. The unique experience of abandonment operations on vandalised wells is detailed. A focus on further potential cost savings game changers hinged on efficient execution, competitive scoping and leveraging on technology is discussed.