bluuebunny/crossref_metadata_2025 huggingface dataset:
An Integrated Approach to Well Test Analysis - Use of Numerical Simulation for Complex Reservoir Systems
Authors: Mijinyawa A. , Alamina P. , Orekoya A.
Published: February 2011

Simple interpretation models, which are fast and reliable, are usually used in traditional well test analysis for estimating well and reservoir properties. However, more sophisticated interpretation models are required for the identification, description and quantification of geologically complex reservoir systems. These complex models are often not readily available in the literature.

This paper presents a multi-disciplinary approach involving ‘history matching’ of well test data to seismic and geological information using a simple 2D numerical simulator.

The test case is a practical scenario where a long multi-rate test in a gas reservoir is history-matched (using the 2D numerical simulator) with geological and petrophysical data to obtain a test drainage radius. Then the deterministic (volumetric) estimates of hydrocarbon-initially-in-place based on the resulting geometry (from the numerical simulation) are compared with estimates of minimum tested volumes derived using the method of Whittle et al, 2008.

In the end it is shown that for single-phase systems with small pressure drops, the simple 2D numerical simulator can aid in the reduction of geological uncertainty thereby solving a complex problem through relatively simpler means.
Hydrocarbon Effect Correction on Porosity Calculation from Density Neutron Logs Using Volume of Shale in Niger Delta
Authors: Anyaehie James C. , Olanrewaju Oladiran
Published: February 2011

A good estimate of porosity can be derived from the density log based on the simple tool physics, if key variables such as fluid density (of the invaded zone) and matrix density are known. Sandstone dominates mineralogy in the Niger Delta area and its density is known within an acceptable uncertainty, based on abundant availability of core measurements. However, the uncertainties associated with in-situ fluid density values are more drastic (0.2 − 1.1g/cc), depending on the formation fluid density, the drilling mud density and degree of invasion. In evaluating the porosity of the formation, estimation of actual fluid density to be used, especially across light hydrocarbon zones, has always been a major source of uncertainty and different methods have evolved over the years for tackling this challenge. This paper examines some of the methods that have been used over the years and provides a simple, robust and auditable method for providing a good estimate of formation porosity that does not depend on an independent estimation of fluid density, and as such, it is not affected by the presence or otherwise of light hydrocarbons. It uses a combination of the density and neutron logs, with volume of shale calculated from the same log sets as a compensator.
Production Technology Challenges in Deepwater Subsea Tie-Back Developments
Authors: Ageh E. A. , Uzoh O. J. , Ituah I.
Published: February 2011

The era of easy oil is coming to an end, a lot of the major reserve finds these days are located in very challenging operating environments such as deep and ultra-deep water. Subsea tie-back systems over the years have evolved as a solution to the challenge of harnessing these reserves in a cost effective manner. The challenges for subsea type developments are not only limited to the cost of drilling and infrastructure or the complexity of the subsea layouts but also the technology of assessing and producing the volumes to surface poses a great challenge. Production technology challenges include multi-phase fluid flow, completion design, flow assurance (hydrate mitigation & management), well intervention and long term well monitoring. Of particular concern are the issues of water-flood management, intelligent completion & production systems which are core to achieving increased ultimate reservoir recovery and production volumes required for cost effectiveness. This article highlights the major production technology challenges articulated for a typical long subsea tie-back development and discusses how these could be managed.
Estimating Irreducible Water Saturation and Relative Permeability From Logs
Authors: Uguru Chukwuma , Udofia Abasiubong , Oladiran Olanrewaju
Published: February 2011

Through the years there has been the problem of characterising reservoirs properly with insufficient data. This is because such data were either not acquired due to operational difficulties, cut budgets or needs not anticipated or where acquired were not of the right quality and thus not useful in building reservoir models that could be used to predict reservoir performance. One such key shortage is relative permeability data from SCAL. The impact of this shortage is being felt as the Niger Delta reservoirs increasingly move to the "brown" category over time and the need for reliable reservoir models increases.

A dependable reservoir model requires a robust definition of the relative permeability. To address this, a new opportunity that recycles an old technique is being proposed as an effective means of obtaining dependable and representative relative permeability data. The method leans on the abundance of log data for saturation evaluation, permeability estimation using techniques already proven and published.

These techniques provide a platform for deriving water saturation and permeability as continuous curves with the result that irreducible water saturation and consequently relative permeability for water and hydrocarbons respectively can be derived as curves across reservoir intervals using expressions earlier published by Park Jones (1944/45). The resulting Rel-Perm versus Water saturation plots agree well with good data from SCAL showing that the technique can be deployed reliably where SCAL data is non existent or judged to be of poor quality. The technique also ensures that Rel-Perms are derived from data from subject reservoirs.

This method has been applied successfully in reservoirs studies with the impact that it facilitated improvements in turn-around times and quality of history matching in reservoir simulation. Two such results are presented in this paper.
Maximising Value from Integrated Well and Reservoir Management and Facilities Reviews: A 2-Field Case Study from the Niger Delta
Authors: Thomas Ayoola Olakunle , Oke-oghene Uruh , Ijeoma Odizuru-Abangwu , Nnamdi Dike , Boniface Mgbaja , Gbenga Folorunso , Patricia Kalu
Published: February 2011

Integrated well and reservoir management (WRM) and facilities reviews have developed to be the method of choice in getting the best value out of a producing field over the asset lifecycle. The process has evolved from the early method of isolated reservoirs and wells reviews carried out by the petroleum engineers (mostly involving only the reservoir engineers and production technologists) to an integrated approach involving the participation of production geologists, petrophysicists, well completion and intervention engineers, process and facilities engineers, production programmers and production operations engineers. The former method involved the making of decisions regarding field performance optimisation by a select group of petroleum engineers who in turn then struggle to get the review recommendations put into practice by the rest of the petroleum and surface facilities skill pool. The integrated approach involved the collective analysis of all the field data ranging from geological, reservoir and petrophysical data to well completion, production and surface facilities performance by all the skill pool involved in the day-to-day development of the producing asset. This allows for the collective ownership of decisions reached and easy translation of review recommendations to practical applications to optimise production from the producing asset in the shortest time and with the least internal resistance.

The additional benefits of the integrated approach to field performance optimisation include accelerated production, cost savings and a better understanding of the producing asset as a whole by the review team. These benefits are highlighted using a 2-field case study taken from SPDC's portfolio in the Niger-Delta. The conclusions show how production enhancement decisions and field production optimisation can be achieved effectively and efficiently using the integrated review method.
Using Integrated Production Modeling (IPM) as an Optimization Tool for Field Development Planning and Management
Authors: Ageh E. A. , Adegoke A. , Uzoh O. J.
Published: February 2011

IPM offers a cost effective technique for assessing and optimizing field development concepts, it allows for evaluation of various scenario plays whether they be well pairing, well count, well phasing, subsea layout, pipeline sizing, flow stream scheduling or process configuration to achieve maximum recovery of any particular fluid stream. IPM can also be used as a change management tool during the execution phase of a development project to understand the impact of change on the system.

The petroleum experts (PETEX) modeling tool has been employed for the evaluation of the Bonga North deepwater subsea tie-back development, the software enables the integration of flow assurance with subsurface deliverability and the topside constraints (both envisaged and existing) for all considered options. The tieback development was designed as a haulage filler to an existing Bonga FPSO and hence the IPM model was built to provide answers to pertinent development and production concerns such as the best timing for bringing the tie-back development on stream and the impact of the tie-back on the host field production and recovery.

This paper describes the structure of the IPM model and its various components, it also highlights some of the benefits and challenges of deploying IPM for field development optimization using the PETEX GAP production modeling tool coupled with an in-house reservoir simulator.
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

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

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

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

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

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

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

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

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

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

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

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.
Prospects and Economics of Miscible -CO2 Enhanced Oil Recovery in Some Nigerian Reservoirs.
Authors: Ibukunoluwa A. O. , Onyekonwu M. O.
Published: February 2011

On exhausting conventional oil extraction techniques, about 2/3 of discovered reserves are usually unproduced. CO2 injection into oil reservoirs is widely accepted as an effective Enhanced Oil Recovery (EOR) technique, and has been used in the oil industry for over 40 years. In this study, incremental oil, producible by CO2-EOR from the large domestic oil reservoirs at Obagi field was calculated. The study utilized the CO2-PROPHET model to evaluate the oil database and found Obagi fit for CO2 flooding. Afterwards a Kinder Morgan Scoping economic model was used to evaluate the economic viability of the flood. With 1.2 Billion barrels initial oil in place and a residual oil saturation of 50%, the field would only have up to 17% recovery at a 100% hydrocarbon pore volume of CO2 injected. Sensitivity on the Dykstra Parsons correlation coefficient showed that increasing the parameter i.e. (increasing heterogeneity) results in no change in oil produced with time. Also, a sensitivity on viscosity showed that for the range of oil viscosities analyzed, oil production clearly decreases with increasing oil viscosity. Economic sensitivity was positive with a Present Value Profit after Tax of $149.8MM. This is equivalent to $1,623,038,950.00 after a project lifetime of 25 years.
Non-Linear Programming for Well Spacing Optimization of Oil Reservoirs.
Authors: John U. M. , Onyekonwu M. O.
Published: February 2011

Background: The subject of well spacing is one of vital importance in the petroleum industry. The well itself plays a very significant role in the development of the oil and gas reservoirs and in the control of the recovery process. However, determination of appropriate well spacing for maximum economic oil recovery has been a complicated and controversial issue in oil field development. Various studies on the subject have indicated a slim relation between well spacing and recovery. This study will however focus on the optimization of field development in order to maximize returns on investment. A simplified economic optimization model to optimize well spacing in oil reservoirs has thus been proposed.

Methodology: The optimization model developed has been solved to find the optimal well spacing that will maximize Net Present Value of investment, using NonLinear Programming (NLP) Excel-Based Solver.Data for case study was from an offshore field. Sensitivity analysis to determine the extent of changes in optimum Well spacing with respect to model parameters was carried out.

Results: Cost of field development could be greatly optimized using NLP. Well spacing has been seen to decrease with recoverable reserves for maximum Net Present Value (NPV) until a point where increase in the number of wells decreases NPV. An optimal solution exits within this region. Optimal well spacing has been observed to be far more sensitive to oil price than to other model parameters such as investment cost per well, production rate and interest rate.

Conclusion: Intuitive approach to solving well spacing problem requires current oil industry knowledge and experience. Economics sets the limit for drilling of development and infill wells.
Controlling Fugitive Emissions in Nigeria's Oil and Gas Industry: Proper Sealing Device Selection a Panacea
Authors: Nwaoha Chikezie
Published: February 2011

As the world grows and economies develop, future demand for energy will continue to grow dramatically. The International Energy Agency and many others predict that the world's total energy demand will grow by 35% in 2030 higher than it is today, and oil/natural gas are expected to account for nearly 60% of total energy through 2030 (Glass J.S. jr., 2009). This implies that fugitive emissions must be minimized in order to preserve scarce resources and address the global climate challenge. Because of the predicted growth in emissions in the coming decades, 70 – 80% will come in developing countries (T Arrowsmith,2009). Nigeria a developing country, and the world'seleventh largest crudeoil producer with reserves estimated at over 36 billion barrels, will play a big role in preserving health, safety and global environment. Worldwide, fugitive emissions from equipment leaks such as valves, and pumps contribute to over 1 million metric tonnes of volatile organic compounds/hazardous air pollutants (VOC/HAP) per year (Onat A, 2006).

Pumps/compressors account for 10%, flanges-5%, tanks-10%, valves-60%, and relief valves-15% (Fluid Sealing Association, 2008). Valves which account for 60% of fugitive emissions presents the greatest opportunity for reducing fugitive emissions. Therefore, sealing devices will play a major role in lowering emissions. In this role they keep valves from releasing emissions, flanges from spraying fluids etc. The process of selecting the right sealing device begins with identifying service conditions. A simple acronym, TAMPSS-temperature, application, media, pressure, size and speed provides a general guide to assuring selection of the correct sealing device for your application (Drago J and Tones M, 2007). Therefore, this paper is aimed at presenting the most effective and efficient way of prolonging our scarce resources, reducing fugitive emissions, minimizing environmental harm, improving worker and public safety, and meeting the global energy demand.
Prediction of Vapor Pressure of Aqueous Hydrate Inhibitor Solutions Using Arrhenius-Type Asymptotic Exponential Function
Authors: Bahadori A. , Vuthaluru H. B.
Published: February 2011

Hydrate inhibition with different inhibitors such as, methanol, ethylene glycol (EG), continues to play a critical role in many natural gas transmission and processing operations. In this work, simple-to-use predictive tools are presented here for the prediction of vapor pressures of aqueous hydrate inhibitors (namely methanol, ethylene glycol, diethylene glycol and triethylene glycol) as a function of temperature and hydrate inhibitor mass fraction in water phase using a novel and simple-to-use Arrhenius-type asymptotic exponential function. The proposed tool predicts the vapor pressure of aqueous methanol solutions and glycol solutions for temperatures up to 100°C. Estimations are found to be in excellent agreement with the reliable data in the literature with average absolute deviations being around 3.8 and 1.5% for vapor pressures of aqueous methanol solutions and glycol solutions respectively. The proposed method is easier than currently available models and involves a fewer number of parameters, requiring less complicated and shorter computations. The tool developed in this study can be of immense practical value for the engineers and scientists to have a quick check on the vapor pressures of aqueous methanol, ethylene glycol, diethylene glycol, and triethylene glycol solutions at various conditions without opting for any experimental measurements. In particular, chemical and process engineers would find the approach to be user-friendly with transparent calculations involving no complex expressions.
Experiment and Mechanism Analysis on Threshold Pressure Gradient with Different Fluids
Authors: Baoquan Zeng , Linsong Cheng , fei Hao
Published: February 2011

Fluids with different components were used in threshold pressure gradient (TPG) experiment by steady "pressure~velocity" method. Influence of Permeability and fluids components on TPG was analyzed. The study indicates different fluids give different TPG versus permeability power function, TPG of different fluids was as follows: Distilled water >Injected water >Formation water >Surfactant solution. Mechanism analysis of TPG reduction shows that higher salinity and Surfactant are favorable to TPG reduction, and it offers a theoretical explanation for injection of formation water and surfactant solution in the low permeability reservoir. The injection of the two fluids can decrease injection pressure and increase injection capacity for water wells.
Surfactant Treatment has Amazingly Improved Squeeze Cementing Result
Authors: Winarga Kanuga , Dewanto Christianto Widi
Published: February 2011

Usually squeeze cementing job was done in more than once; failure usually happens and need to be re-squeezed once or more. One time squeeze cementing is very rarely occurs. Hypothetical theory is caused by leaking, space appears between matrix rock and cement during drying process. This phenomenon happens due to the fluid base differentiation between both fluids in cementation process which causing dis-joint cement fluid (water base) with oil film that coats the rock matrix wall (oil wet).

Surfactant treatment method is used to reduce squeeze cementing frequency where main function of surfactant is to change fluid surface tension between oil and water so both fluids will blend homogeneously. Cement slurry as water base fluid are expected to perfectly coat in rock matrix that have changed to be water wet from originally oil wet. By injecting amount of surfactant into rock formation and soaking couple hours before squeeze cementing job execute, expected could change formation rock wettability from oil wet into water wet so coated and trapped oil between matrix rock will release and pushed by water or cement slurry when it pumped or squeezed. Perfectly adhere between rock matrix and cement will happen to disappear the space and finally increase the quality of Squeeze Cementing Job.

This study has applied in melibur wells; the result successfully reduces the cementing job frequency into half from the four times previously in each well. It leads the cost efficiency. The three wells that have been squeezed without surfactant hold the pressure test after four times cementing. Meanwhile from another two wells with surfactant treatment the frequency could be reduced and significantly saving cost about 41% from the previous. It was concluded that surfactant treatment has become a great solution to increase squeeze cementing quality.
Permeability Prediction of Un-Cored Intervals Using New IMLR Method and Artificial Neural Networks: A Case Study of Bangestan Field, Iran
Authors: Naeeni Mohammad Nazari , Zargari Hadi , Ashena Rahim , Ashena Rahman , Kharrat Riyaz
Published: February 2011

Knowledge of permeability is critical for developing an effective reservoir description. Permeability data may calculated from well tests, cores and logs. Normally, using well log data to derive estimates of permeability is the lowest cost method. In the last years, the concept of hydraulic flow units (HFU) has been used in the petroleum industry to improve prediction of permeability in un-cored intervals/wells. This concept is strongly related to the flow zone indicator (FZI) which is a function of the reservoir quality index (RQI). Both measures are based on porosity and permeability of cores. It is assumed that samples with similar FZI values belong to the same HFU.

This paper will focus on the evaluation of formation permeability in un-cored intervals for a carbonate reservoir in Iran from core and well log data. We used Flow Zone Index method for rock type identification and Artificial Neural Networks for permeability estimation. Identifying the hydraulic flow units that is the first step of predicting permeability always takes lots of time and lack appropriate accuracy. We have developed a new clustering technique that is more precise, easy to apply and taking much less time.
An Artificial Neural Network Approach to Formation Damage Prediction Due to Asphaltene Deposition
Authors: Rezaian A. , Kordestany A. , Haghighat Sefat M.
Published: February 2011

Formation damage due to asphaltene deposition could have bad consequences on oil production through heavy oil recovery, miscible flooding, and even primary recovery. Many tests were carried out by researchers to find the amount of permeability decline, but the limits in which the asphaltene deposited in oil or at the pore surface was not determined.

In this paper, neural network is used to predict rock-fluid interactions describing permeability decline due to asphaltene deposition. The second stage of asphaltene deposition (if we separate it into precipitation from liquid phase, and deposition on pore surface) is considered in which n-hexane is used to flocculate asphaltene particles in order to determine the effect of deposition on sandstone rock due to changing of pressure, temperature, and composition of reservoir oil.

An artificial neural network is trained using data gathered by performing various dynamic experiments with pre-separated oil asphaltene content, moreover, some of the experimental data used to test the network and resulted a good agreement so it could predict the trend of permeability reduction due to deposition of asphaltene.

This network can be used to predict the trend of formation damage due to asphaltene deposition under various pressures and asphaltene concentrations. Thus, this study guides us to a novel explanation of flow behavior in porous media.
Determination of Cone Receding Time in Horizontal Wells
Authors: Ibelegbu C. , Onyekonwu M. , Okorie C.
Published: February 2011

Often critical rates are never economical to operators as they seek to produce above the established critical rates without any prior analysis of an economical stand-off rate at which continuous high GOR/ BS&W becomes uneconomical. Wells are shut for long time without any knowledge of shut-in duration to allow for fluid stability before being brought back on production.

This study generates two new solutions, analytical and numerical solutions used in determining cone receding time in horizontal wells after coning occurs. Field data are used to validate the analytical and numerical solution results for the coned wells. Semi-analytical solutions are applied with the numerical solution results, to generate unique solution/ coefficient (Cth- cone coefficient) for each well/ reservoir with respect to its flow mechanisms associated with water coning/ production. An eclipse dynamic model is also used to validate the numerical results/ solutions.