bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Impact of Different Shaly Sand Models on In Place Volumes and Reservoir Producibility in Niger Delta Reservoirs - The Dual Water and Normalized Waxman-Smits Saturation Models
Authors: Odizuru-Abangwu I. , Suleiman A. , Nwosu C. 
Published: February 2011

Abstract
This paper compares hydrocarbon saturation (and their impact on in place volumes and producibility) from two different saturation models in use in the industry for saturation calculations in shaly sands in the Niger-Delta.
For many of the leases where there are either JV partnerships or unitisation requirements, the different E&P companies approach hydrocarbon saturation estimation using different models, and it is important to understand where differences are expected to occur and what impact these differences make to both in place and recoverable hydrocarbon volumes.
This paper reviews two of the more popular shaly sands models used – The Schlumberger Dual Water Model (DWM –Clavier, Coates & Dumanoir, SPE 19772) and the recast Waxman-Smits model by Juhasz - the Normalized Waxman-Smits (NWS –I. Juhasz, SPWLA 19811) model.
The Dual Water model approaches the impact of clay minerals on the conductivity of reservoir rock by proposing the presence of two different ‘waters’; one within the free pore space and the other representative of the additional conductance path created by the cation-exchange process, due to the presence and morphology of clays.
The Waxman-Smits model, on the other hand, is premised on the understanding that only ‘one’ water (the saturating brine) is present, and provides a semi-empirical basis for capturing the effect of the additional conductance path created by the presence of clays. The Juhasz modification (the Normalized Qv approach) casts the Waxman-Smits in a form that is directly comparable with the Dual Water Model.
This paper summarizes the theoretical and experimental foundation of both shaly sands models and aims to quantitatively investigate the actual differences in the derived saturations, in selected Niger Delta reservoirs, in order to clearly show how much results from the methods differ. As mentioned, this will be extremely useful in comparing results for unitization purposes between oil companies who traditionally use different methods for hydrocarbon saturation calculations.
To reduce the uncertainty introduced by parameters used in the models, the comparison has been done on Niger Delta reservoirs with core-derived parameters.
In addition, core-derived saturation-height functions (from drainage capillary pressure curves) are compared to the log-derived saturation-height functions from both shaly sand models, to understand the impact on in place volumes and dynamic saturation functions (absolute and relative permeability derived from end point water and oil saturation).
PVT Characterization of a Gas Condensate Reservoir and Investigation of Factors Affecting Deliverability
Authors: Imo-Jack Otavie 
Published: February 2011

Abstract
This paper is a study aimed at the effect of Condensate blockage and tubing size on well deliverability. Gas sales contracts are usually based on the capacity of the system to deliver a specified rate over an agreed period of time. The results of this study are important to determine if a contract can be satisfied or in determining how it can be met. The EOS model is based on data collected from a gas condensate field, offshore Nigeria. This paper highlights the PVT properties most important in predicting gas condensate reservoir behaviour and the approach used in building the EOS model.
Proper EOS characterization is key in modeling the behavior of a gas condensate reservoir. As a starting point, the PVT report is obtained and a material balance analysis is carried out on the reported measured data. The reported data used in the equation of state (EOS) model are the Constant Volume Depletion (CVD), Constant Composition Expansion (CCE) and the hydrocarbon analysis during CVD. These are used in the study to do a material balance analysis based on existing correlations.
Apart from the subsurface samples, surface samples where obtained and physically recombined, a mathematical recombination was carried out as a quality check on the physical recombination. The material balance serves as a means of validating the PVT data before it is used for an EOS characterization. EOS characterization is carried out using the Soave-Redlich-Kwong (SRK) EOS which in this case is used to fit the measured PVT data through non-linear regression. The heavy fraction i.e. C7+ is split into SCN components from C7 to C30+ before the regression is carried out. In this study the fraction was split into thirty-four components. After a match is obtained, pseudoization is carried out to reduce the number of components in order to reduce simulation run time. EOS characterization is carried out in phazecomp, a state of the art EOS modeling tool. The EOS is tuned so as to match measured data as contained in the PVT report.
This characterized fluid is then used as the basis for input into the single well numerical simulation model by which deliverability is studied. The effect of condensate blockage is studied with relative permeability as a variable to see if a desired rate can be maintained as is expected by gas sales contracts. If there is substantial blockage effect from the result of the simulation then it is an indication that a condensate bank forms in the near well bore region leading to loss in productivity. This becomes a useful way to decide what kind of mechanism will be employed for depletion, for example gas injection to keep the pressure above dew point pressure could prevent condensate blockage. The effect of tubing size on well deliverability is also studied so as to get an optimal tubing size to see out a gas contract which is a tubing size that makes it possible to satisfy contractual obligations.
Application of Integrated Production System Modelling in Effective Well and Reservoir Management of the Bonga Field
Authors: Okoh Ehimhen , Sathyamoorthy Sekhar , Olaniyan Elozino , Ezeokeke Ozioma 
Published: February 2011

Abstract
The Bonga field located offshore Nigeria in OML 118, has produced more than 275 MMstb in the last 4 years. Production rates from 16 subsea high rate oil producer wells from 5 different manifolds are being sustained by waterflooding that was implemented from the onset of production. Currently, mostly single zone oil producer wells drain 5 different deepwater turbidite reservoirs in the field. Fully treated seawater is injected from 13 subsea high rate water injector wells daisy chained onto 2 separate injection lines. Oil offtake on reservoir level is highly dependable on successful voidage replacement and pressure maintenance. In addition, constraints and operating envelopes in both the production and injection system make day-to-day optimizations extremely challenging. As with all waterflood and Enhanced Oil Recovery schemes, ‘world-class’ Well and Reservoir Management (WRM) is the foundation of a successful project. One key element of effective WRM is the application of Integrated Production System Modelling (IPSM).
Advanced and robust tools that model complex integrated systems from the reservoir to the topsides have been developed and applied extensively in the industry. An IPSM was built for Bonga allowing detailed dynamic reservoir simulation models to be linked with well, flowline / subsea and topside models. Both the injection and production network models were incorporated to simulate the actual field situation. In addition, an optimization script was built to manage offtake and distribution of injection water aligned to the field pressure policy. This enables the model to duplicate as closely as possible actions taken in the field. An integrated-discipline workflow was developed and applied on a monthly basis to maintain the Bonga IPSM ‘live’ through calibration with well test data and update with the latest field information.
The 2 key benefits of the IPSM are:
Integration of multi-disciplines (from subsurface to topside) in model update and calibration, and to ensure all aspects are considered for a robust forecast Testing new optimization opportunities or ideas for improving oil offtake and water injection prior to implementation in the field
Examples of successful application of IPSM in WRM are described in this paper, which also highlights future applications of IPSM for the Bonga asset.
Application of Natural Water Dumpflood in a Depleted Reservoir for Oil and Gas Recovery - Egbema West Example
Authors: Osharode Catherine Olukemi , Erivona Gloria , Nnadi Magnus , Folorunso Kareem 
Published: February 2011

Abstract
Water Dumpflood for reservoir pressure support is a non-conventional but simpler and cheaper alternative to Surface Water Injection. With dumpflood technology, a single well serves as the water producer and injector hence; the complexities of water treatment on surface can be avoided. A pilot Water Dumpflood scheme was executed 1997 in the Egbema West field and post performance analyses showed it has been successful in maintaining good pressure support since its inception 12 years ago. Opportunity exists to increase oil recovery significantly from this same reservoir by drilling additional water dumpflood wells for increased oil withdrawal given corresponding pressure support. With this, oil wells that were shut in many years ago, to minimise further pressure depletion, can be brought back to production and maintained with good well and reservoir management. There also exists an opportunity to supply the associated gas from these wells to a nearby power plant currently undergoing construction with a capacity to utilize as much as 100 MMscf per day.
This paper explores the benefits of increased water dumpflooding in the depleted reservoir and describes the selection of number and position of dumpflood wells for optimal recovery using dynamic modelling. It also reviews the historical performance of the pilot scheme and applies learning to improve the well completion design, injection rates and effective sand control for the additional wells. The application of Smart Technology for improved well and reservoir management have also been explored.
Water dumpflood can be very effective with good selection of well position, number, source aquifer, and target reservoir, completion design and sand control mechanism. Increasing the scope in this reservoir will not only increase oil recovery but also support energy demand through gas supply to the power plant.
Saturation Modelling in a Geological Complex Clastic Reservoir Using Log Derived Saturation Height Function: A Case Study of the E2 Reservoir, Era Eko Field in the Niger Delta
Authors: Chudi Obinna , Simon Roya , Omobude Osemoahu A. 
Published: February 2011

Abstract
The conventional and globally accepted method of saturation modelling is using capillary pressure curve (cap-curve) data from special core analysis (SCAL). The functions describe the drainage process during hydrocarbon migration and are expressed as a relationship between saturation, the height above the Free-Water-Level (established from a wireline pressure analysis) and a model property (commonly porosity and permeability). The functions are established by first fitting some mathematical function to the cap-curve data (smoothing) and then establishing trends between the function parameters (capillary entry, saturation end point and some shape factor) and the model property, resulting in an averaging of the capillary pressure curves (which have been converted from pressure to height) or log derived saturations. Common curve-fitting or smoothing techniques are the Brooks-Corey, Thomeer, Lambda and Heseldin techniques. This method allows better understanding of the saturation distribution in a reservoir, given that water saturation is distributed in geologic models using a saturation height function (SHF) that relates rock properties (porosity and permeability) and height above free water level (HAFWL). SHF based on cap-curves are used by reservoir engineers to initialise water saturation in dynamic models and depending on the heterogeneity of the reservoir, different SHF are generated to accommodate different rock property classes. However, where there is no core data or no SCAL measurements, SHF can also be derived from available log data.
This study presents a case where the SHF was generated from a suite of log and fluid data for a structurally complex reservoir in the Niger delta. Different functions were generated for different porosity classes. In order to better define the classes, electrofacies were modelled from the gamma ray log. The results from modelled saturation showed good agreement with log-derived saturation and this formed an integral input to hydrocarbon volume estimation. A 5% increase in STOIIP is seen with saturation from SHF as compared to that estimated from log-based saturation.
Permeability Characterization of Upper Miocene Reservoirs, Lower Congo Basin, Offshore Angola; An Integrated Approach
Authors: Abangwu Prince , Carvalho Nilton , Dhir Rakesh , Gacem T. , Santos C. , Jacob C. , Baig M. , Dutta D. , Saikia P. 
Published: February 2011

Abstract
Permeability log is the main input required to deliver 3D reservoir property which alongside other properties are used for reservoir simulation to estimate recovery factor, reservoir connectivity, flow units, barriers, baffles and production profiles. This underscores the importance of this parameter which can be obtained mainly from core analysis, nuclear magnetic resonance (NMR), stoneley (sonic), well testing (DST), wireline formation tester, petrophysical evaluation of rock properties and mineralogy.
Amongst these approaches, log based permeability estimation has over the years received consistent embrace due to robust measurements that provide permeability information at relatively small sample rates, which account for minor heterogeneities unlike conventional approach of large scale core based approximations. However, the need to ensure accuracy of log based measurements have drawn wide attention and many analysts have taken steps to validate log based permeability results with core data, formation tester and well test analysis results.
Permeability characterization for two reservoirs in the Lower Congo Basin offshore Angola was done using log based measurements from basic triple combo and LWD spectroscopy measurements, mobility estimation from sonic alongside formation tester samples, SCAL analysis and well testing results. This paper presents the workflow for evaluation, integration and comparison of permeability from various sources, highlighting challenges and sources of error in the approach.
Analyzing the Impact of Temperature Effects and Other Fracturing Parameters on Fracture Growth Propagation and Injectivity in Unconsolidated Sands
Authors: Ageh E. A. , Ebitu S. , Uzoh O. J. 
Published: February 2011

Abstract
Reservoir sands in the deepwater formations in West Africa are largely soft and unconsolidated based on data from producing fields and preliminary studies on upcoming developments.
Studies have shown that fractured injection in unconsolidated sands is different from hard rock fracturing in which case a single dominant fracture is created during injection. For unconsolidated sands, smaller fractures are created to bypass impairment and much of the injection may be under matrix rather than fractured conditions. Given the importance of waterflood to most projects, it is imperative to understand the dynamics of fractured injection in this type of sands and all the factors that can impact on the effectiveness and efficiency of designed waterflood systems. This is even more important for upcoming projects whose viability may depend on the delivery of high rate – high ultimate recovery wells which can only be supported by an effective pressure maintenance /voidage replacement system.
In this paper we present a study carried out on one of such developments (turbidite reservoirs in Deepwater West Africa) for which a water injection program is to be designed. The modeling work is highlighted and the effect of different parameters on fracture growth propagation and injectivity were analysed.
Delivering Relevant Time Value Through i-Field* Application: Agbami Well Start-Up Case Study
Authors: Nwogu Ikemefula C. , Oyewole Anthony , Meinert David P. 
Published: February 2011

Abstract
This paper highlights the concepts of digital oilfield development as applied to Agbami field, located in the deepwater offshore Nigeria. In order to enhance value and make reliable and timely decisions, the i-Field network system was developed and implemented in Agbami field. The Agbami field i-FieldTM system is a web based, Online, Real Time Asset Management tool used to manage subsurface uncertainties and optimize the performance of the Intelligent Well Completion Systems installed in the field using a set of work flows. Intelligent Completion System have multiple sensors monitoring the performance of the producing reservoir and wellbore in real time. These sensors produce a huge volume of data which are processed into information by the i-fieldTM system. These information were used by the start-up team to make relevant time decisions. This paper focuses on how the i-FieldTM system enhanced the well start-up operation in Agbami field using real time monitoring as a platform to monitor the well progress and identify challenges during the initial start-up operation.
A number of case studies are presented to demonstrate the benefit of real time monitoring using relevant time data acquisition from downhole and subsea instruments, interpretation and quick response to well start-up challenges.
Meeting the Human Capital Requirement of the Oil and Gas Sector in Nigeria
Authors: Ekebafe A. O. , Nigeria Shell , Joledo O. A. 
Published: February 2011

Abstract
The former Minister of State for Energy (Petroleum), Mr. Odein Ajumogobia while delivering a lecture at the SPE 2008 Annual Oloibiri Lecture was of the opinion that the oil and gas industry presents a natural platform to champion local capacity building given the technological edge inherent in its activities, high potential for job creation, and transferability of industry capabilities through strategic linkages to other sectors of the economy. The Challenge therefore will be for the Oil industry and all other stakeholders to brace up to the challenge of local capacity building.
In various fora the dearth of capable fresh graduates from Nigeria Universities and the trend amongst many Nigerian companies going abroad to recruit fresh graduates have been noted as an issue of concern and need for deliberate strategic resolution. Also mentioned was that our universities are not structured to produce competent graduates for the oil industry at a time when we should be exporting technically competent professionals.
This paper examines the issues, challenges, root causes and proffer solutions to the lingering problem of providing competent and highly skilled human capital in the industry, and also managing the transition for young professionals in the petroleum industry. The major stake holders which include the Government, Oil & Gas firm, Academia, Young practicing engineers and the Students are discussed as critical success factor in combating the human capital crisis facing the Oil industry in Nigeria.
This paper was inspired by the excellent experience and exposure gathered while working with various internship students serving with Shell Nigeria Exploration and Production Company (SNEPCO). This Paper encourages other operators in the oil industry to emulate the firm in their contribution to capacity building to meet target for the local content development.
Recommendations from this paper includes a major strategic focus on Training and human capacity development (Academia/Industry), Policies and Laws to ensure oil industry commitment to capacity building (Government), Bridge building initiatives from the industry (via young professionals/Industry) and commitment to capacity development (students).
A Genetic Algorithm Approach to Determination of Optimum Diameter of Gas Transmission Pipes
Authors: Rezaian A. , Alipanah M. , Nezamabadi-pour Hossein , kazemi Hamid 
Published: February 2011

Abstract
Design and implementation of gas distribution networks is one of the most complex and expensive stages in gas transport projects. Usually there is no optimization on pipes diameter.
Genetic algorithm is based on "Natural Selection" idea of Darwin. Natural selection is the process by which heritable traits that makes it more likely for an organism to survive and successfully reproduce become more common in a population over successive generations. So, any genetic algorithm is composed of an initial population in which bests are chosen to produce next population. This population is subject to mutation and finally next generation is produced which has its parents traits. Theoretically and experimentally evolutionary algorithms are proven to be an efficient and powerful tool in finding optimum solution in a reasonable time. Using genetic algorithms to optimize pipes diameter, the costs of distribution projects can be reduced significantly.
In this study, gas consumption was estimated in a certain area using statistical methods based on maximum gas consumption of commercial units and households. As a result, 5 pipes should have 1.5″ and 1.25 diameters and the rest should have a diameter of 1″. Because of program parameters, the final results will always be in allowable range of velocity and pressure. Present research showed 64% optimization compared to traditional approach. Economically this would be a great saving on expenses.
According to results, final solution is the best solution for this problem in which all standards are observed and genetic algorithm is an efficient tool to find optimum solution of everyday problems. The advantages of this approach are: Easy Transfer of topology data to program;Usage of this program to optimize any distribution network;All formulas, allowable diameters and corresponding cost can be changed readily; andFast to find optimum solution, even in large and complex networks.
A New Approach for Recovery Factor Estimation; Using the Mechanics of Fluid Flow through Reservoir and Production Tubing and Expansion of Formation and Reservoir Fluids
Authors: Kareem Lateef A , Omeke James E. , Achumba G. I 
Published: February 2011

Abstract
Recovery factor in recent years has been modelled empirically due to complexities that exist subsurface, and as a result most of the models lacked dimensional homogeneity and neglected the physics of reservoir driving forces that complementarily produce fluids from the reservoir. While these models (mostly Proxies) might satisfy statistical conditions and predict the recovery factors with some degree of accuracy, they fail to reflect well established relationship between physical parameters of the models.
In this study, reservoir fluid behaviour, hydraulics of tubing and porous media flow, gas expansion and water influx, original oil and gas in place and well head pressure during the course of production are taken into account.
The model was used to predict the recovery factors of some selected reservoirs that are no longer producing and the result were in agreement
The benefits of this new model include, adaptability to any reservoir under study, prediction of production limit (reduction to decline curve) and analysis of hydraulics of tubing flow.