bluuebunny/crossref_metadata_2025 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

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

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

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

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

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

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

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

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

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

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

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.
Cement Packer Re-Perforation – Well-AA Case Study
Authors: Jaja Adagogo J. , Adeyinka Boye , Atanda Bukola
Published: July 2017

Cement packer well work is a rig-less intervention method for accessing reserves above and between production packers. It is used to isolate a target completion interval from other hydrocarbon or non-hydrocarbon zones. Cement packer is used as an alternative to the conventional production packer. The key benefit of cement packer application is the cost savings (in the order of $MM) realized instead of using a major rig workover to achieve the same objective of isolation of a target interval. A key challenge however is the attendant increased skin caused by reduced perforation efficiency through the extra layer of cement plug. This paper addresses this issue by showing the work-around adopted by one of the Assets in Chevron Nigeria JV to improve well productivity.

Well-AA was evaluated and proposed for a zone switch non-rig workover intervention of the production interval from N-AA/Well-AA to K-AA/Well-5X reservoir in November 2012 using cement packer to isolate existing completion and recomplete in the new target reservoir. The zone switch and perforation were executed successfully via a cement packer operation but didn't flow after perforation. Several attempts to bring the well on production such as swabbing were made with no success. The outcome of the attempts indicated there was poor or lack of connectivity between the wellbore and the sand-face.

A well performance lookback was done to identify the well problem and it was recommended to re-perforate the proposed interval of the well and initiate gas lift. The recommendation for re-perforation was based on productivity index analysis of previous cement packer completions and the perforation gun performance with respect to the required penetration through the cement plug, tubing/casing and the formation. Estimated productivity index (PI) from two previous cement packer operations were the basis of the recommendation. Well-BD (was perforated twice) with calculated PI of 2 Bbls/Day/Psi and Well-CX (which was perforated once) with calculated PI of 0.3 Bbls/Day/Psi.

This paper will discuss the lessons learnt and best practice from re-perforation of Well-AA with a bigger and deeper penetrating perforation gun that restored initial production from 0 BOPD to 550 BOPD at natural flow condition via a SEWOP barge operation.
Assessment of Oil Spill Occurrences in Sections of the Niger Delta Region: Causes, Effects and Remedial Actions
Authors: Oriaku T. O. , Udo N. A. , Iwuala I. S.
Published: July 2017

The incessant pollution of land and water by crude oil and petroleum products in the Niger Delta region of Nigeria poses significant threats to its ecosystem. This region is known for its increasing oil spills because of its large oil deposits and growing oil and gas related industrial activities. Cases of unattended oil spills are also prevalent in these regions which have resulted in the persistence of large amounts of oil in the affected soils thus requiring effective ways of oil removal. It has been reported that these sites are poorly and most often never investigated to know the extent of contamination and as a result there is high possibility of accumulation of these pollutants in these affected areas. This paper, however, seeks to address this problem by giving an insight into some of the major causes of oil spill occurrences within NPDC Operational areas in Edo, Delta, Bayelsa and Port-Harcourt regions of the Niger Delta. Oil Spill data analysis done for the past 6 years (2011 to 2016) revealed that third party interferences which include sabotage, vandalism and crude oil theft accounted for 74.4% of the spillages within these regions. While 25.3% of spillages occurred due to corrosion, equipment failure and human error, less than 1% was ascribed to unknown and unidentifiable causes. Out of the estimated 44, 034.35 barrels of oil involved during these periods, about 37,279.84 barrels (approximately 85%) constituted the amount spilled through vandalism ranging from activities such as the use of hacksaw, dynamites and explosives on pipelines; and crude oil theft through hot tapping and illegal oil bunkering. The most prevalent vandalism occurrence was recorded along the Trans Forcados export pipeline axis within (OML 30) Delta State, a marine and seasonal swamp terrain.
An Integrated Multi-Disciplinary Analyses to Predict the Initial Fluid Contact and Its Impact on Field Development Strategy: A Case Study from Shallow Offshore Niger Delta Field
Authors: Kilic Cem , Das Anindya , Ehighebolo Thaddeus , Balogun Tayo , Adenaiye Olaniyi , Bhattacharya Tirthankar , Jiang Kun
Published: July 2017

Estimation of initial Hydrocarbon-Water-Contact in the light of conflicting information is critical to overall field development plan and project economics. Understanding the causes of conflicting information requires an integrated investigation of potential sources of the information and a structured approach for developing and ranking plausible explanations.

R11 reservoir in Yama field has conflicting information from two wells drilled 19 years apart, which indicates the possibility of compartmentalization within the reservoir or pressure depletion from a nearby field. The discovery well, which is closer to the crest, encountered a GDT and GWC is estimated to be at 9790 ftss with an assumed regional water gradient. A later appraisal well, located at the flank of the structure, clearly logged a GWC, but it is 126 ft. deeper than the estimated GWC from the discovery well. In addition, the appraisal well recorded 120 psi lower pressure than the discovery well. This conflicting information could be explained by 4 possible scenarios: 1) Errors in measurements, 2) Uncertainty in regional water gradient line 3) Reservoir compartmentalization 4) Pressure depletion from a nearby producing field.

While the vintage of tool for pressure and depth measurement in the discovery well is relatively old, the difference of 126 ft. due to measurement error is unlikely. All the pressure points align quite well and estimated depth measurements errors are much smaller. On the other hand, pressure analyses with a range uncertainty in regional water gradient could narrow the difference, but not all of it alone. Possibility of reservoir compartmentalization due to faulting has quite a large impact in overall field recovery and the reservoir development. The last possible explanation for the conflicting information is the potential depletion of the pressure from a nearby field via a connecting aquifer. Analyses indicate that while it is possible to lower the reservoir pressure due to production from a nearby field, the magnitude of the pressure-drop would have been significantly smaller.

Based on a series of static and dynamic modelling as well as sensitivity runs, the conflicting information can be explained by pressure depletion and the reservoir is in communication. This scenario is selected as the "Base Case" for development planning. On the other hand, the compartmentalized scenario is also considered a possibility but as a "Low Case" scenario, hence it is included in field development scenarios and the impact of it is built in the project economics.
Pragmatic Joint Venture Financing Options in Nigeria: Implications on Economic Metrics and Government Take Statistics
Authors: Iledare Omowunmi , Fubara Susan Amiesa
Published: July 2017

The design of fiscal regime by oil producing government is usually tailored to capture high economic rent for the maximization of their citizen’s welfare. This has been the case of the royalty/tax system practiced in Nigeria, also known as the joint venture arrangement. The fiscal incentives under this system have been espoused to yield higher government take compared to the other fiscal systems practiced. Nevertheless, government participation in the joint venture arrangement through its NOC requires the government to provide funds for project development with cash call obligation. However, the NOC has defaulted, severally, in fulfilling its cash call obligations which has delayed several project developments. Thus, the recent government exit from JV cash call agreement is a favourable development that have created a vacuum as to how the joint venture operations would be funded and the impact on the economic metrics and the government take. It is against this background that we employed the use of a deterministic and stochastic cash flow model under 3 funding scenarios for the R/T system. Our empirical result shows that the impact of capital cost recovery yields a decrease in government take. The price of crude oil, royalty and profit petroleum tax were shown to have the highest impact on the government take. We concluded that despite the impact of the joint venture financing option on the government take statistics, the economic metrics yield higher profitability index thus making the project viable. Hence, we recommend that government considers a pseudo PSC or an overriding royalty funding arrangement in order to retain its participatory interest in the JV agreement without the obligation of cash call. Given that this funding option will impact the government take as shown in our analysis, the fiscal incentives used under this system should be reviewed and revised.
Non-Technical Risk Quantification: A Value Improvement Process for Maximising Returns and Increasing Value
Authors: E Ite Uwem
Published: July 2017

Good E&P business decisions require robust assessment of technical (e.g. reservoir porosity and permeability) and non-technical risks (e.g. safety, health and environmental issues). It is evident that the prevailing low oil price regime has resulted in significant reductions in the capital expenditure of E&P companies. Several high-cost, long-lived projects have been slowed down, postponed or even cancelled. Unfortunately, Non-technical risks (NTRs) constitute the most common cause of project delays and cost increase. They are most likely to be underestimated and overlooked, with implications for value erosion at the project level and, in extreme cases, significant portfolio value erosion at the corporate or industry level. The success of E&P business especially during the prevailing low oil price regime requires recognition of uncertainty and practical strategies to minimize or mitigate risk to ensure delivery of projects within realistic cost estimates and timeframe, with a view to maximizing returns and increasing value. This paper presents Non-Technical Risk Quantification (NTR-Q) as a value improvement practice for maximizing returns and increasing value. It makes a case for proactive and periodic NTR-Q as part of the overall NTR management process. It examines a suite of NTR-Q methodologies, and goes further to discuss three major reasons for NTR-Q, namely: to prioritize the NTR management and response plan; to arrive at a balanced, risked view of the project value; and to promote clarity on the precise nature of the risk and its potential impact. The paper concludes that NTR-Q might serve different purposes, which will also vary depending on the phase and maturity of the project. As such the scope and effort of the quantification needs to be tailored to the decision to be made.
Deepwater Infill Drilling Evaluation Using Experimental Design: The Agbami Case Study
Authors: Adeyinka Adeboye , Olatunde Folarin , Bodunrin Abiodun
Published: July 2017

The Agbami field is one of the largest producing deep-water assets in Nigeria. It was discovered in 1998 and put on stream in 2008 with the field development staggered into three phases. Adopting a phased approach has eased the burden of project management and allowed the Asset team incorporate the key learnings of each phase into the subsequent phases while reducing uncertainty and improving decision making to derive maximum value from the asset.

With the third phase of the field development approaching its later stages, it became necessary for the Asset team to take a second look at the wealth of data that had been gathered in the 7 years of production and re-evaluate the subsurface understanding with a view to identifying by-passed or un-swept oil that could potentially increase recovery from the reservoirs.

Uncertainties are inherent in every project and the Agbami project is no exception being a major capital project with its fair share of uncertainties. This paper focuses on how the Asset team tackled the challenge of generating a meaningful and reliable production forecast for the infill drilling opportunities to drive decision making while accommodating operational uncertainties, equipment delivery scheduling and subsurface uncertainties in the reference case as the Agbami Phase 3 project was still on-going as at the time of this work. This was done through the application of design of experiments to generate low, mid and high realizations of the reference case which was then carried forward into the incremental case.

This paper discusses the process utilized in establishing a range for these uncertainties from historical data and how this was integrated (using experimental design) to generate probabilistic forecasts for the infill drilling opportunities to drive decisions that would maximize the value of the Agbami field for all stakeholders.
Time Lapse Seismic Survey: Adding Value in the Agbami Field
Authors: Olatunde Folarin , Adeyinka Adeboye , Lawal Olumide , Iyiola Sunkanmi , Faparusi Dan , Bodunrin Abiodun , Sustakoski Richard , Ebo Henrietta
Published: July 2017

Time-lapse seismic survey also known as 4D seismic has established itself as a useful tool for reservoir monitoring and has gained wide acceptance within the industry. Technological advancements in the area of acquisition and processing have further strengthened the case for its application.

The recent 4D seismic acquisition and interpretation in Agbami has proven to be an economically viable means of adding tremendous value to an oil field irrespective of the development stage it is in, and has been an excellent enabler for reservoir surveillance and resolution of subsurface uncertainties.

Effective management of a field such as Agbami requires a surveillance method which can provide insight into spatial fluid movements with time, which the traditional surveillance methods are unable to provide. This type of insight is required to support sound reservoir management and field development decisions which Agbami 4D seismic provides. The information from the Agbami 4D monitor has shed more light around the fault network architecture within the field and has validated and in some cases changed some of the initial assumption around the sealing nature of these faults.

Also, originally planned drilling locations and completion strategies have been modified based on the insight from the 4D seismic. The 4D seismic has also created value in the calibration of the reservoir simulation models and the location of bypassed oil within the field for future infill drilling. Forward modeling of expected seismic response based on proxy simulations helps to set realistic expectations of what can be seen in 4D seismic data. This paper discusses the acquisition, processing and interpretation of 4D seismic surveys in Agbami and how this information is being used to maximize the value in the field for the stakeholders.
Improvement in Suspension Cap Design that would Aid Future Well Intervention Activities
Authors: Iyowu Chizoba , Chimere Nwoji , Igben Pius , Nwachukwu Israel , Theophilus Ugonwanne
Published: July 2017

Suspension Caps are used on wells that are temporarily suspended with plans that these wells could be reopened up for production in the future; or wells scheduled for permanent abandonment at a later date. Prevalently suspension caps have flanges that would fit into the tubing hanger equipped with a kerotest valve for taking pressures. These also have only a single bore covering two strings which makes it impossible to intervene on individual strings for dual string wells. To overcome these typical challenges, fit for purpose suspension flanges were designed with Gate valves that provide additional barriers in case the barriers on the wells are compromised. These suspension flanges are also designed with two bores for dual string wells making the ease of intervention on individual string possible.

Wells are designed and drilled with the intention of producing till the reservoir is appreciably depleted after which the well is finally abandoned and environment restored to its natural habitat. The expected total production from a typical well has however been impacted by the current trend of vandalism experienced in Nigeria especially in Niger delta. Most of SPDC wells are vandalized prior to the end of their life cycle and have exposed the company to various challenges such as exposures to environmental pollution, reputation issues, loss of Assets, etc. These challenges prompted the wellhead/well integrity team of SPDC to ingeniously design suspension caps that would improve ease of intervention on the wells without compromising any safety standards at lower cost and response time. The paper demonstrates the value in the use of these modified suspension caps especially in terms of safety and cost appreciation.
Evaluation of Sand Production Potential using Well Logs
Authors: Balarabe Tafida , Isehunwa Sunday
Published: July 2017

Sand Production is one of the major challenges in oil and gas wells. It damages well head equipment and flowlines leading to lost production time and unnecessary workover expenses. Meanwhile, utilizing sand control measures when not needed can reduce production rates while reducing profits. Several methods have been developed to accurately predict sanding potentials. However, most are rather complex and time consuming. This study was justified to develop a real-time sanding model with minimal input parameters using well log data.

A geomechanical model was developed to estimate critical pressure below which sand production is expected. Effective stresses at a stable perforation cavity and far field were established using stress-strain relationship. Hoek Brown's failure criterion was applied to investigate the failure mechanics once stability was lost. The parameters in the model included poisson ratio v, uniaxial compressive strength C_o, biot's poroelastic coefficient α, overburden pressure P_ob, and Hoek Brown's material constant s and a. Five different hypothetical case studies were used to validate the model and the trends are very encouraging. A FORTRAN program was written for the model in order to facilitate sanding predictions.

The results observed by the model gives curves that increase at various points of depth, indicating potentially weak sandstone where sanding should be expected. A bottomhole flowing pressure, Pwf, 2500 psi was specified. It was observed that case A will not experience sand production. Cases B and C will experience sanding in the intervals 3000 - 3675ft and 3000 - 3625ft respectively. Cases D and E will experience sand production. Upon comparison with other published analytical models such as Almisned 1995 and Oseghe 2015, it gives very optimistic results.

This model serves as a useful tool for making well informed cost effective decisions regarding sanding and sand control requirements.
Flowing Material Balance and Rate Transient Analysis Modelling with Augmented Non-Continuous Permanent Downhole Gauge Data
Authors: Ukauku Ikwan , Johnson Anthony , Olatunji Bakare , Korubo Waazor , Olugbenga Daodu , Nwachinemere Uche , Ebeh Chioma , lledare Wumi
Published: July 2017

Flowing Material Balance (FMB) and Rate Transient Analysis (RTA) have evolved as well and reservoir performance evaluation techniques which make use of the large amount of pressure data from permanent downhole gauge (PDHG). Meaningful analysis requires the pressure and production data to be continuous but often there are operational breaks in the data making analysis quite difficult. Case histories of FMB and RTA that use augmented non-continuous pressure data from PDHG as basis for modelling well and reservoir performance to deal with this gap are presented in this paper.

The proposed method involves derivation of continuous pressure trend by splicing and merging depth-converted tubing head pressure data with non-continuous PDHG pressure data in the intervals where the later are discontinuous with appropriate quality checking to ensure no hump or sink at the transitions as well as consistency in trend. Any remaining gaps are then handled by interpolation of offset points. The augmented non-continuous PDHG data is then applied in FMB and RTA to estimate connected GIIP and remaining recoverable resources following an acceptable analytical or numerical history matching. A workflow to enable application of the process is documented in this paper.

Results from the case histories are comparable with previously published 3D static and dynamic models. The results could be influenced by the noise level in the data but this could be managed with appropriate de-noising method like wavelength filtration which was used in this case study.

This approach offers the maximum use of PDHG pressure data in reservoir surveillance not just as a real time monitoring technique but additionally as enabler in predicting life cycle performance of a reservoir in the absence of, or complimentary to 3D dynamic simulation model or other methods in the industry. It is simpler and less resource consuming performance-based approach than 3D dynamic simulation.
Pitfalls in Channel Reservoirs Development: Implications for HCIIP Assessment and Development
Authors: Amuboh Okiemute , Manuel Tekena , Yunana Yahaya , Nworie Ejiuwa , Ugboaja Remmy
Published: July 2017

The Niger Delta basin is dominated by shoreface deposits although tidal and estuarine channel deposits are typical. While reservoir modelling, HCIIP assessment, development strategy and placement of wells are commonly understood to be underpinned by sand distribution, there might have been a common tendency to apply a shoreface mindset in the channel reservoir settings. A methodologicalgeological understanding of channelized sand-bodies, their distribution and development underpinned by the integration of seismic and well data is therefore critical to optimal hydrocarbon maturation and development.

The Eureka X7000 reservoir interpreted as channel sands from well logs of REKA-001 and mapped consistently on reflectivity data, suggested good sand development across the structure. Subsequent REKA-002 and REKA-003 flank wells results, resulted in a suprise in sand development, and a resultant reduction in HCIIP and reserves, highlighting blindspots that could have beenmitigated by the integration of acoustic impedance seismic volume, log data and realistic conceptual model scenarios of the reservoir.

REKA-001 penetrated a channel complex 94 ft thick within the Eureka X7000 reservoir comprising three individual channel units~ 30 ft thick. Therefore, the reservoir was thought to be a channel complex with a maximum width of 2km comprising of series of individual channels with a width/thickness ratio of 66:1 based on REKA-001 results and existing analogues. This model would imply very good sand development with high NTG in the reservoir. REKA-002 was planned (1.6km away from REKA-001)as an appraisal/development well as part of the initial field development plan on the eastern flank of the structure. Post-drill assessment of the well results showed that the REKA-002 well penetrated the channel sand deposit sub-optimally and poorly developed which translated to a reduction in hydrocarbon volumes and in general well promise for the reservoir. The current estimated GIIP for X7000 reservoir is 169 Bscf some55% less than the pre-drill volumes of 376 Bscf.

The REKA-002 well result on the X7000 is discussed to highlight the pre-drill geological evaluation pit-falls based on available well data and post-drill integration of quantitative seismic data, facies/property and sequence stratigrahic modelling approach to provide lessons for future field development plans.