bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Multiscale Method for Modeling Flow in Stratigraphically Complex Reservoirs
Authors: Alpak Faruk O. , Pal Mayur , Lie Knut-Andreas 
Published: February 2011

Abstract
A robust and efficient simulation technique is developed based on the extension of the mimetic finite volume method to multiscale hierarchical hexahedral (corner-point) grids via use of the multiscale mixed finite element method. The implementation of the mimetic subgrid discretization method is compact and generic for a large class of grids, and thereby, suitable for discretizations of reservoir models with complex geologic architecture. Flow equations are solved on a coarse grid where basis functions with subgrid resolution accurately account for subscale variations from an underlying fine-scale geomodel. The method relies on the construction of approximate velocity spaces that are adaptive to the local properties of the differential operator. A variant of the method for computing velocity basis functions is developed that utilizes an adaptive local-global algorithm to compute multiscale velocity basis functions by capturing the principal characteristics of global flow. Both local and local-global methods generate subgrid-scale velocity fields that reproduce the impact of fine-scale stratigraphic architecture. By using multiscale basis functions to discretize the flow equations on a coarse grid, one can retain the efficiency of an upscaling method, while at the same time produce detailed and conservative velocity fields on the underlying fine grid.
The accuracy and efficacy of the multiscale method is compared to that of fine-scale models and of coarse-scale models with no subgrid treatment for several two-phase flow scenarios. Numerical experiments involving two-phase incompressible flow and transport phenomena are carried out on high-resolution corner-point grids that explicitly represent example stratigraphic architectures found in real-life shallow marine and turbidite reservoirs. The multiscale method is several times faster than the direct solution of the fine-scale problem and yields more accurate solutions than coarse-scale modeling techniques that resort to explicit effective properties. The accuracy of the multiscale simulation method with adaptive local-global velocity basis functions are compared to that of the local velocity basis functions. The multiscale simulation results are consistently more accurate when the local-global method is employed for computing the velocity basis functions.
Effect of Sand Production on Pressure Drop for Vertical Wells in Gas Storage Reservoir
Authors: Olufemi Adekomaya , Darlington Etaje 
Published: February 2011

Abstract
Sand production is a natural consequence of fluid flow into a wellbore from the reservoir. Sand production was found to be not a problem in the early part of the fields with high reservoir pressures. But the effect of sand transport on pressure drop becomes more pronounced in the late life of reservoir. Accurate estimation of pressure drop due to sand production has been of great interest for a long time for production engineers.
Numerous solutions to halt sand effect on flowing pressure in gas wells have been attempted with low degree of success. In this paper, a model was developed that analyzed the significant effect of sand on pressure drop during early and late life of a well which was not accurately predicted in existing models.
Three Phase Modelling of Production Log Data Leads to More Accurate Decision Making and Saves Cost
Authors: Ojonah Oke , Gysen Alain 
Published: February 2011

Abstract
In well and reservoir management, optimum and accurate determination of multiple phase well-bore fluid entry is required to make decisions on water/gas shutoff opportunities. This can only be possible if good quality production log data is acquired and most importantly if accurate data analysis is done.
This paper examines the drawbacks experienced using the conventional production log analysis methods and its associated risks. It will introduce an alternative probabilistic approach leading to more accurate results. The results of a case study will also be presented where a cement water shutoff was planned and executed based on the result of conventional analysis. It will also show how the results of the probabilistic approach would have saved the cost of the cement water shutoff
Using Experimental Design Table with Reservoir Simulation to Manage Subsurface Uncertainties - A Niger Delta Case Study
Authors: Cyril Ogbalor , Peacock Anthony 
Published: February 2011

Abstract
Experimental Design (ED) methods are becoming a well-established alternative to traditional uncertainty analysis due to the fact that it offers a more efficient and consistent approach to identify and assess the impact of the key subsurface uncertainties on field development decision. This paper describes a case study of applying ED to assess development risks in a gas reservoir in the Niger Delta. The reservoir is areally very extensive but relatively thin and underlain by aquifer. Key development and recovery risks were recognised to be access to pressure support and water breakthrough at the production wells. The objective of the study was to define realistic P10-P50-P90 subsurface realisations and test various development concepts against this range of models to generate an optimal field development strategy.
A multi step ED approach was used to understand and manage the key subsurface uncertainties. Alternative linear screening designs and multi-level response surface designs were used in this study.
Key outcomes of the study were:
– Successful demonstration of the application of Experimental Design technology and alternative screening designs – Generation of Response Surface models for In-Place and recoverable volumes. – Definition of a realistic range of sub-surface realisations for the reservoir and identification of P10-P50-P90 sub-surface models using Probabilistic (Monte-Carlo) analysis – Definition of key sub-surface uncertainties to be targeted for appraisal program-Generation of a robust range of production profiles and reserves estimates.
Current Challenges in Unitisation - The Nigerian Experience
Authors: Ajayi Olufemi A. , Otoh George 
Published: February 2011

Abstract
Unitisation enables the exploitation, as a single unit, of Oil and Gas deposits in fields/reservoirs straddling two or more parties’ mutual concession boundaries, under a single authority notwithstanding the respective permits or contract areas different contractual terms. This process, when completed, prevents disputes between the parties, which could potentially hinder efficient exploitation. Additionally, the practice of Unitisation enables sharing economies of scale and making best use of technical information, means and equipment. It also reduces / rationalizes costs and investments in order to optimally develop fields as a single unit.
Given the current legislation and legal framework for Unitisation in Nigeria, significant improvements have been observed from the regulatory institutions and other industry players, in the last 10 years. These include 2008 issued "Guidelines for Unitisation in Nigeria" by the Department of Petroleum Resources (DPR).
Although the concept of Unitisation is now commonplace in Nigeria, there are still challenges that need to be addressed. These include requirement for Unitisation for Brown – Brown fields (where both parties are already producing), assets/infrastructure valuation whereby both parties possess assets/infrastructure prior to Unitisation, and process of Reference Date (for commencement of Unitisation) issuance by DPR among others. The goal is overcoming challenges that cause delays in project delivery and shorten the process of Unitisation. Also, inefficient utilisation of resources, and the challenges of developing straddling fields are eliminated, as global energy demand and cost of supply increases.
This paper, will explore some options and potential solutions to these challenges faced in the practice of Unitisation in Nigeria. Some of the solutions proffered are in the area of inclusion of non-straddling reservoirs in a unit and consistency in interpretation when production exist prior to Unitisation by one or both of the licence(s).
Implications of Injection Water Capacity Limitations in Field Development in Deepwater Nigeria
Authors: Obidike Peter , Ekebafe Abraham , Uchenna Orekyeh , Areje Adegoke , Elozino Olaniyan , Onyema Ohabuike 
Published: February 2011

Abstract
The economics of deepwater oil field developments rely heavily on the availability of high oil production rate wells that can generate early income to pay for the high CAPEX invested in such field developments. In addition to the cash flow is the uncertainty that surround such high CAPEX developments. For example the influence of governments and policy changes leaves the investor no choice than to ensure early recovery of investment. To support the required high oil production rates, the reservoir pressures must be maintained to minimize the chances of breakout of gas in the reservoir in an under saturated system or production of gas cap gas in a saturated system.
Often times, the question is not whether to apply a reservoir maintenance scheme or doubts about the strength of the aquifer but when is the appropriate time to implement the water injection scheme and thus optimize the development for stakeholders both in terms of economics and ultimate recovery.
The choice of scheme to employ follows the decision to provide reservoir pressure support as part of reservoir management strategy. Water injection in the deepwater setting appear to be a preferable choice over gas given the ready availability of sea water and less complications in the operation of the injection system when compared to gas injection.
Further to the decision on the use of water injection for reservoir maintenance is the question of sizing of the injection facility to deliver the required amount of water for the field development. Subsurface and Project engineering teams most often depend on global industry knowledge especially the golf of Mexico to design the injection facilities. However occasions arise where the development plans and aspirations defer. For example, the sizing of the injection system may not have considered the complexity of the reservoirs nor the future development plans for nearby fields. Such occasions may result in ad hoc operational philosophy to optimize oil production.
This paper aims to put the shortcomings of water injection limitations in deepwater Nigeria in perspective, identify best practices in such instances and make recommendations for future development planning.
Modelling High Rate Fractured Injection in the Bonga Field
Authors: Okoh Ehimhen , Sathyamoorthy Sekhar , Ebitu Sophia 
Published: February 2011

Abstract
The Bonga field has produced more than 275 MMstb in the last 4 years, a major contributor to deepwater oil produced offshore Nigeria to date. High production rates are being sustained as a result of the pressure maintenance scheme based on waterflooding that was implemented from the onset of production. Fully treated seawater is injected from 13 subsea high rate water injector wells daisy-chained on two separate water injection lines. To date more than 370 MMbbls of treated seawater has been injected in the field.
High rates in water injector wells can only be achieved through fractured injection. Industry experience so far shows that matrix injection mode leads to declining well injectivity. However, for effective reservoir management, it is required that fractures created are not excessively large to cause integrity concerns on nearby seals, reservoirs and wells. Hence, it is necessary to predict the fracture dimensions for corresponding injection rates and pressures for effective waterflood management. The size (length and height) of an induced fracture depends on several parameters.
This paper describes the use of an in-house fractured injection tool for estimating lateral and vertical extension of waterflood-induced fractures in Bonga wells. History matching of field data is performed to calibrate the model. Information from Pressure Transient Analysis and well interventions is used to improve model prediction. The analysis shows that with continuous high rate injection, long contained fractures are created in these high Darcy sands. Prediction results are used to define operating envelopes for these high rate water injector wells, with rates constrained in some wells to prevent induced fractures breaching the top shale layer.
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.