bluuebunny/crossref_metadata_2025_split huggingface dataset:
Championing Nigerian Content Development Initiative through Hydrocarbon Maturation Studies: Project Management Lessons
Authors: Ndukwe Reginald , Cookey Mina , Nworie Ejiuwa 
Published: July 2014

Abstract
The Shell Petroleum Development Company of Nigeria Limited (SPDC) and its Joint Venture partners have consistently demonstrated leadership in developing Nigerian Content in the oil and gas industry through its Nigerian Content Development (NCD) initiative. This is further demonstrated by the landmark award of four oil and gas maturation services contracts for Petroleum Engineering studies to indigenous contractors. The contract award aimed at achieving: (1) Acceleration of hydrocarbon maturation and unlock huge resource portfolio/potential available in the fields of study; (2) Growth of hydrocarbon maturation capacity and capability of indigenous contractors in line with NCD aspirations of the Nigerian Government and (3) Enhancement of in-country capability in managing Petroleum Engineering studies delivery using local vendors.
The work scope included sub-surface evaluation of work elements in selected fields / reservoirs (up to well head), leading to feasibility reports. The work plan required the vendors to work from their locations and use their software and hardware, and local manpower resources to deliver the projects in a period of three years. The SPDC support team was available to (a) Coordinate delivery of the project (working in collaboration with the vendors' leadership teams to achieve this); (b) Provide technical "peer-assist" to the vendors (this is to enable the vendors to deliver quality results on time); (c) Deliver Wells and Facilities Engineering, Economics and Operations Readiness aspect of studies and (d) Integrate all works and produce feasibility reports.
The studies have progressed for about 18 months; with the project teams having made good progress; as well as encountering some challenges and risks which could impact project delivery, including: (1) High staff mobility among local vendors; (2) Staff technical competence; (3) Unrealistic contract bids; (4) Inadequate scoping of assurance requirements and (5) Project delivery within contract period. Mitigation plans for these challenges/risks are discussed herein, along with lessons learnt in the project management.
Improved Drilling Efficiency via Enhanced Water Based Mud in The Niger Delta
Authors: Falope F. D. , Orodu O. D. , Osayande I. , Uhunoma U. 
Published: July 2014

Abstract
This study focuses on latest advances in water based mud as a potential for the Niger Delta, its impact on drilling efficiencies and well productivity. Recently, New mud additives are been developed to enhance the rheology of water based mud to deliver the same characteristics and reliability of an oil based mud when considering the Niger Delta geology. Due to the challenges with Water Based Mud in respect to chemistry and suitability, Oil Based Mud (OBM) has become the main type of drilling fluid in deeper sections during drilling campaign in the Niger Delta. But the use of OBM as come with some challenges that has necessitated the further research and development of Water Based Mud rheology that can deliver the same results as OBM. Some of the challenges associated with the use of OBM include but not limited to high cost and management, contamination of OBM in the storage site during drilling activities, logistics complexity, environmental impact from spills and disposal, and impact on well productivity and reservoir management.
In countries such as Ghana, Columbia, Oman, Mexico, Enhanced WBM mud has been used and is still being used in drilling to deep depths (8000ft–10000ft) TVD in formations with similar geology with that of the Niger Delta. Sample wells will be reviewed from one of these regions for the project and they will be used to show the evolving new technologies and techniques in WBM rheology formulation.
This study is channeled to label the engineered properties of the mud, mud composition, its effects on drilling efficiency and well productivity, challenges encountered, the concept for an enhancement, added advantage in comparison to OBM, comparative cost advantage. It was discovered that Enhanced WBM has an added advantage hence leading to a reduction in pollution trends in the Niger Delta and cost effectiveness. Other advantages include addressing to an extent the challenges encountered with WBM such as (inhibition, hydration and solids control) leading to an enhanced well productivity and ultimately affects the overall cost of well delivery.
Proven and Possible Petroleum Plays of the Eastern Niger Delta Basin, Nigeria
Authors: Anomneze David O. 
Published: July 2014

Abstract
As Nigerian operations expand into more challenging and costly operating environments, there is need for critical access to sound stratigraphic, depositional and reservoir facies models. The extraction of geomorphic insights and pattern recognition using predominantly 3D seismic data is a rapidly evolving discipline that facilitates the development of reservoir prediction models linked to significant plays. In this study a regional dataset which comprised of a merged 3D seismic volume, well logs, biostratigraphic, biofacies, paleobathymetry and core data from Eastern Niger Delta was interpreted and reviewed to show the overall structural, stratigraphic and architectural styles within the region to ensure that successes made in the past can be repeated and also make significant advances to ensure future exploration success. Hence, an added goal is to have a low-risk exploration workflow that is capable of correct prediction of reservoir rocks to be encountered in a new play and prospect. Three plays have been identified from this study: (1) Shelf Edge Deltas, (2) Pinch-Out Play and (3) Hanging Wall Play. Each play displays a unique morphology, seismic expression, structural configuration, migration pathway, seal integrity and reservoir dispersal pattern. These prediction models provide play based exploration targets for areas with similar depositional settings. The successful application of this technique serve to encourage exploration in the Niger Delta Basin by adopting strategies where seismic stratigraphy will be the most likely means to provide drilling targets to more independent operators.
West African Market Integration
Authors: Excel Ukpohor 
Published: July 2014

Abstract
With a landmass of about 5.1 million square kilometers and a community of 15 member states, Western Africa is one of the worlds most endowed regions with energy sources. The region holds about 13% of the total proven gas reserves in the world, with Nigeria accounting for almost all that figure with 185tcf.
While natural gas is fast becoming the worlds preferred choice of energy thus seeing an increase in its demand, the region is yet to fully harness the potential she possess in energy generation. West Africa still ranks amongst the regions with the lowest energy generation in the world. Major sources of energy are petroleum, natural gas and hydroelectricity and it is estimated that no more than 20 percent and in some countries as little as 5 percent of the populace have direct access to electricity. The figure falls to about 2 percent in the rural areas. This situation has become a major hindrance to the economic and technological growth of the region.
Thus, energy has become a major driver for regional integration in West Africa, which can assist many of her individual economies in overcoming the mismatch between energy demand and energy resource endowments. Furthermore, this can take advantage of economies of scale and help countries develop and gain access to low-cost energy to sustain future growth. Resource rich smaller economies would then export energy which can become engines of growth and development while larger economies energy imports may help postpone, reduce, or avoid capital investments in new production facilities and thereby overcome temporal cash flow problems.
To integrate the various economies of the region, the governments of the various countries have commenced a number of regional projects. The West African Gas Pipeline (WAGP) is a good example of regional energy market integration. It shows on the one hand achievements of government and regional institutions and the other, the willingness of international companies to invest in the regional market. The West African Power Pool is another regional project with the concept of integrating the national grids of the region member countries.
In this paper, the huge gas potential of the West Africa region will be highlighted and the impact of the gas production from the region on the global economy. The energy situation of the region will also be discussed with the various challenges detailed. The roles of natural gas in the various regional projects being executed will be listed with status update of these projects with particular emphasis on the West Africa Power Pool (WAPP) and the West Africa Gas Pipeline project. Various geopolitical influences will be discussed with major emphasis on polices that impact integration. Finally recommendations will be made on some key success factor that will promote rapid regional development in the face of the mounting challenges.
Resolution of Out of Zone Water Injection in Okan Field by Use of Material Balance Method
Authors: Olu Okpani , Adebayo Oguntona , Femi Afolayan , Segun Olonode 
Published: July 2014

Abstract
The Material Balance method is a good analytical tool for assessing and understanding energy balance and connectivity of reservoirs. This method was used to investigate the effect of water injection in a target reservoir and pressure response in the target reservoir and an adjacent reservoir in Okan field.
Water injection was initiated in two adjacent reservoirs (Reservoir "A" and Reservoir "B") in Okan Field in year 2002 with wells A1_Inj and B1_Inj respectively. Another water injector (Well A2_Inj) was completed in Reservoir "A" in year 2008 to provide further pressure support for the reservoir. Analysis showed that the water injection in Well A2_Inj was not providing pressure support to Reservoir "A" as expected. In addition an unexpected reservoir pressure increase was observed in Reservoir "B" from year 2008. It was suspected that Well A2_Inj was injecting out of zone and there was contemplation to cut-back water injection in the well and allocate the water injection to other injectors in the field.

Results
Material balance analysis was carried out by coupling Reservoir "A" and Reservoir "B". The following are the results of the study:
Mini-DST in a Gas Reservoir: Issues, Challenges and Benefits
Authors: Uwaga Anthony , Bardal Davoud , Ward Chris , Trim Melanie 
Published: July 2014

Abstract
Well testing during the drilling of a well using a Drill Stem Test (DST) tool is a well-established practice in the oil and gas industry. As the name suggests the well test is conducted using the drill stem with the DST tool replacing the drill bit. It is done in open or cased hole and the objective is to measure the pressure, permeability and productivity of the zone of interest. It also gives a measure of the damage done to the formation during the drilling process.
In the case of an oil reservoir oil is produced to surface during the DST operation and either collected in tanks or flared together with the associated gas. In the case of a gas-only reservoir the gas produced to surface is flared.
Some of the issues of carrying out a DST test are the high costs involved, limitations in acquiring detailed zone specific information instead of averaging over the well test length and the potentially negative impact on the environment from hydrocarbon flaring. It is to overcome these challenges that the industry looked for alternative well test approaches that can be more efficiently undertaken during drilling operations such as the Wireline Formation Test (WFT), also known as a mini-DST.
A mini-DST well test is carried out using a wireline tool and is conducted in open-hole. The well test involves isolating a zone of interest using packers with pressure and hydrocarbon flow rate readings captured using a single probe, a dual probe or a combination of single and dual probes. Unlike the DST it can be done over multiple zones, isolating one zone at a time and has an added advantage that all fluid flow takes place down-hole.
In reservoir intervals with good permeabilities and high production rates, the relatively high mobility of gas compared to oil will result in turbulent flow being observed in the wellbore thereby introducing ‘noise’ that will mask the sensing of pressure transients by the probe. This is not the case in mini-DST test as the production rates are quite low already. However, for a gas reservoir it is sensitive to the permeability-thickness (kh) product in the zone of interest, since higher kh and lower gas rates can result in a very small drawdown. Therefore pressure gauge sensitivity becomes a significant factor in the well test design for a mini-DST. With a typical gauge resolution of ca. 0.01 units there is, therefore, an inherent constraint to targeting primarily low kh flow zones. This can result in a trade-off when selecting reservoir units to test based on their permeability (k) and thickness (h).
This paper looks at some of the issues to be considered in the design and operation of a mini-DST well test for a gas reservoir and highlights key benefits that can be derived. It further discusses some of the operational challenges encountered during a case study.
Effective Field Development Management of a Gas Field in the Niger Delta
Authors: Egu Daniel Ikechukwu 
Published: July 2014

Abstract
Investment and operational planning of gas field development under severe uncertainties in gas reserves poses a major challenge in post parts of Eocene Niger Delta. Such uncertainties include the size of gas in the reservoir, the recovery factor, the required number of wells to be drilled, permeability variations and other criteria. Fekete "FAST" Evolution software was used to run a detailed sensitivity analysis of reservoir properties particularly permeability, in order to determine the number of wells to drill, recovery factor, net present value (NPV) and also the sales of gas produced per well, to effectively ensure maximum hydrocarbon recovery and a good return on investment without posing danger to the reservoir. Results however showed that in terms of recovery factor, scope three had a maximum recovery factor of about 73.61%, in terms of sales gas produced per well. It also had the highest sales gas production of about 10811.5M$, which will yield about 32434.4M$ for the three number of wells investigated as a result of a higher permeability. Also in terms of the net present value, scope one had the highest value of 110633.06M$, for the 12 numbers of wells investigated. It is recommended that since scope three had a better performance than the base case due to higher permeability value, a stimulation job may be carried out at the completion of the project to enhance the permeability of the reservoir, but the cost of carrying out the stimulation job should be considered and analyzed to ensure a good return on investment, before embarking on the decision.
Improved Deliverability Model for Horizontal and Multilateral Wells
Authors: Ulaeto U. W. , Onyekonwu M. , Ikiensikimama S. 
Published: July 2014

Abstract
A simple semi-analytical model was developed in this study to predict the productivity of horizontal oil wells. This model used the technique of coupling flow from a box-shaped drainage volume to that of the flow in the wellbore. Considerations were made for friction, acceleration, and fluid-inflow effects. Change in flow regime from laminar to turbulent was also taken into account to describe the flow in the wellbore. The reservoir-inflow model used in the productivity model for flow in the reservoir used a combination of 1D and 2D models and also considered varying skin along the wellbore to account for the heterogeneity of the near-wellbore region due to drilling-fluid invasion into the formation. In addition, reservoir-permeability anisotropy and convergence of flow to the wellbore were considered in the inflow model. Comparison of this model with three well known models using field data reveals that the proposed deliverability model is more accurate with a 4% error. The existing models gave greater errors. The accuracy of this new model can be attributed to more realistic modeling of the reservoir and wellbore.
Determination of Cutoffs and Implications in Integrated Reservoir Studies
Authors: Ebong Michael , Onyekonwu Mike 
Published: July 2014

Abstract
The building of 3D models from seismic, geological, petrophysical, well, drilling, reservoir and production engineering data which are used in the study of optimal recovery of hydrocarbons from petroleum reservoirs has become commonplace. During the static modeling phase of the workflow, there is the need for the application of limits on the petrophysical properties to differentiate reservoir from non-reservoir rock. These limits are called cutoffs: limiting values of petrophysical properties in the static models.
In this case study, multiple regression analysis was used to derive the best relationship of the form k = f(Ø, Vsh, Sw) which was then used to estimate optimum petrophysical cutoffs for the reservoir. Four static models of the reservoir were then built: the first model with only a Vsh cutoff of 0.42 to delineate reservoir rock from the non-reservoir rock. The other 3 utilized various Ø, Vsh and Sw cutoffs in their building. Four dynamic models of the reservoir were then built from the static models and were history matched to observed production and pressure data. Performance prediction was then carried out using the different history matched models. Finally, using the results of the forecast and other data, an economic analysis was carried out to determine the economic implications of the different cutoffs on the results of the studies.
The results showed that the values of the Ø cutoff affected the values of the corresponding Vsh and Sw cutoffs as well as those of the HCIIPs, with the general trend being that a reduction in the Ø cutoff increased the values of the Vsh and Sw cutoffs. The economic analysis showed that petrophysical cutoffs used in the development of the static (and the dynamic) models sure had some impact on the results of the analysis.
Ringfencing of Investment Spending and its Implications on the Profitability of Exploration and Production Projects
Authors: Babatola Awoniyi 
Published: July 2014

Abstract
Ringfencing is a common clause in the Production Sharing Contract (PSC) which implies that all costs and expenses related to the development and operation of a single reservoir, field or block, should be assigned and deducted from the revenues generated solely by that resource unit.
When certain costs are ringfenced, the probability of profitability of investments in frontier areas becomes slimmer.
Allowing exploration costs to cross a ringfence will impact more on the economic profitability of investment and promote further spending in the upstream business. This will act more as a stimulant for investors to explore such opportunities with the assurance that some successful play can compensate for losses during exploration.
The purpose of this paper is to evaluate the impact of ringfencing on profitability of an E&P asset and to show that allowing costs to cross a ringfence will be a strong incentive for the oil industry operators and would give some level of confidence that development of marginal fields would be economically viable. Such incentive proved to work in the UK in the early 1980s and 1990s. Allowing this incentive will show that the Host Government is willing to share E&P risk, reduce the degree of economic outcome uncertainty and creates an investment friendly environment for the operators.
Engineering Design and Calibration of Gas Metering Systems in Era of Increasing Product Cost
Authors: Ogwo O. U. 
Published: July 2014

Abstract
A new engineering design and calibration procedures for the natural gas metering system is presented that will enable the elimination of the over-sighted intrinsic errors in gas measurement, reduction to the barest minimum of the operational errors frequently incurred in the use of the flow meters, and resolution of the discrepancies between the various standards used in designing gas metering systems. As natural gas continues to gain prominence in the global energy mix and its price continues to appreciate, it becomes necessary (to take advantage of evolving technologies) to eliminate the systematic errors and minimize the random errors in gas measurement, the errors of which were hitherto considered insignificant in the face of calibration constraints. This paper explains why orifice flowmeters should now be calibrated online, emphasizes (using field and factory acceptance test (FAT) data) the need for online calibration of the new generation flowmeters even when equipped with self diagnostic mechanism, and presents the master prover selection procedure. The paper which is based on field experiences acquired over extended period of time during work visits to a number of gas fields in Nigeria, Europe and the United States of America, also reconciles the discrepancies existing between the two major standards (the AGA-3 and ISO 5167) used in the measurement of hydrocarbon gas.
Fracture Pressure Prediction Model for Deepwater Fields, Gulf of Guinea
Authors: Jenakumo Timipere D. , Itua Osazua J. , Ebimobowei Wodu K. 
Published: July 2014

Abstract
Following the 2010 Gulf of Mexico Macondo well control incidence, increased emphasis has been placed on the safe delivery of wells. Fracture pressure prediction is a critical input to effective well planning and safe drilling especially in deepwater environments due to rising well costs and narrower drilling margins with increasing water depths. Therefore, accurate formation fracture and pore pressure prediction is crucial to minimize potential borehole stability concerns, lost circulation problems and optimize casing setting depths during drilling. Also, for fields where water flooding is used to enhance recovery or maintain reservoir pressure, proper estimate of fracture pressure is necessary to curtail implications such as loss of production, injectivity and reputational damage in the event that there is loss of containment and hydrocarbons migrate through to surface.
This work establishes empirical correlations for fracture pressure prediction from field leak–off tests data; builds on existing foundations relating fracture pressure with overburden, in-situ effective stress ratio and pore pressure. The results indicate that the developed correlations can be suitably applied in offshore fields in the Gulf of Guinea deepwater environment.