bluuebunny/crossref_metadata_2025_split huggingface dataset:
Challenges in Operating and Developing Strong Bottom Water Drive Reservoir. A Case Hosiery
Authors: Ibrahim Abdullatif , Al Massabi Abdurrahman , Bellah Samir , Al Hashemi Mohamed 
Published: October 2009

Abstract
An offshore Abu Dhabi carbonate oil field was discovered in 1969 and put on production in 1985. The field has two separate culminations producing from a reefal limestone formation deposited in the middle cretaceous. The northern culmination is characterized by good reservoir properties and supported with an active bottom water drive while the southern culmination is characterized by low reservoir properties and hence less support from the aquifer.
Initially the reservoir was developed by vertical and/or deviated oil producers and peripheral water injectors. Soon after production starts, wells water cut gradually increased to reach 50% within 4-5 years with drastic decline in oil production.
Horizontal drilling was implemented with an objective of increasing well exposure to reservoir, reducing drawdown and as such combating water coning/channeling phenomena. Although oil production from horizontal wells was substantially improved, water production trend and production decline, however, did not change in most of the cases.
Application of ESP in southern and northern culminations was initiated to overcome high water cut problem and hence elongates and improves wells production lifting capacity. ESP wells performance shows encouraging results, particularly in the southern culmination.
Managing this offshore reservoir at such high water production is one of the major challenges facing field development engineers. Reservoir heterogeneities, such as fractures and facies distribution, are believed to be main contributors to a water coning/channeling phenomena and to the escalation of water production trends. Therefore, understanding of geological, petrophysical, properties of the formation is the corner stone for , controlling water production problems and hence improving reservoir performance.
This paper provides an overview of the factors that are contributing to the rapid increase in water production and the associated decline in oil production, the vertical wells, horizontal & ESP performance. The paper also assesses new potential ideas for future development aiming towards increasing the sustainable production and recovery.
Shuaiba Transition Zone Reservoirs: From Modeling Studies To Field Development Challenges
Authors: Shiekah Issa Abu , Warrlich Georg , Goossens Peter , Alexander David M. , Zhu Fuping , Lamki Ali 
Published: October 2009

Abstract
Production data from several Shuaiba fields in the Sultanate of Oman demonstrate the oil recovery from capillary transition zones. This is underpinned by extensive detailed experimental and theoretical modeling studies describing favored oil mobility and residual oil saturation in transition zones in the Shuaiba formation reservoir. Nonetheless the economical development of capillary transition zone reservoirs, especially those with thin oil columns, remains an ongoing challenge and necessitates addressing uncertainties related to characterizing the lateral variations in initial oil saturation distribution, water flooding displacement, sweep efficiencies and accurate prediction of oil production.
This paper discusses good practices for ongoing developments of transition zone fields and predicting their performance. The key enablers are: (1) properly characterized initial saturation height functions for long horizontal well planning, (2) implementation of consistent set of hysteresis saturation functions in the reservoir simulation models and (3) geosteering tools for accurate well placement and spacing. Examples of predicted well performances for a field compared to the actual production data will be shown. The results highlight the generic trends in transition zone oil production and the recommended procedures for static and dynamic modeling during field development planning.
Prediction of Heavy Oil Viscosity in Current Reservoir Simulators
Authors: de la Porte J. J. , Riesco N. , Vesovic V. 
Published: October 2009

Abstract
An accurate estimate of oil mobility is essential for reliable exploitation of oil and gas reservoirs, and for development of new technologies, particularly with the industry's increasing reliance on unconventional resources such as heavy oil. The viscosity of heavy oil decreases rapidly with increasing temperature and with increasing concentrations of light components, and can vary over 2-3 orders of magnitude during typical exploration and productions operations. The accurate prediction of the viscosity is therefore difficult, and simple extrapolation of the current methods used in the petroleum industry for predicting the fluid viscosity in conventional reservoirs is fraught with difficulties.
This paper presents a comprehensive analysis of the use of a simple mole-average power law that is based on the Arrhenius equation and used as the default method in some widely used thermal reservoir simulators to predict mixture viscosity. Predictions based on the equation are compared to a set of accurate benchmark data that are based on the best available experimental data for hydrocarbon mixtures. These data cover a temperature range of -175°C to 200°C, and extend to high pressures. The accuracy of the data is better than 5%, sufficient for validation purposes. We summarize the conditions under which the simple power law provides reasonable estimates of viscosity, identify the ranges of pressure and temperature and composition for which large deviations can be expected, and discuss the implications of using the equation to predict heavy-oil viscosity. We demonstrate that the current practice of fitting scarce experimental data and using the viscosity of the heavy fraction as an adjustable parameter is problematic, and that extrapolation in temperature or to similar mixtures is highly unreliable.
Case Study: History Matching Using Enhanced Permeability Modifications (EPMs) for Court Bakken Heavy Oil Reservoir
Authors: Taabbodi L. , Osiowy G. , Hagstrom C. , Galdon L. 
Published: October 2009

Abstract
Computer modeling of heavy oil reservoirs has become progressively more challenging in order to represent geological reality and its impact on fluid flow. A method has been developed in which completion, production, and injection information, coupled with the static well data, are used to model enhanced permeability channels that have been created around the wells as a result of production and/or injection.
Court heavy oil field located in West Central Saskatchewan, Canada is a Bakken heavy oil reservoir (17°API, in-situ viscosity of ~155 c.p). The field, which has been under an active waterflood depletion strategy for the last 20 years, has achieved a recovery factor to date of ~ 24%. The geological complexities found in the Bakken Formation at Court introduce many challenges for history matching. It was discovered that successful history matching required the introduction of enhanced permeability modifications (EPMs). The EPM regions were superimposed over the geological model. Flow simulations using the EPMs region concept resulted in a significant improvement in the overall quality of the history match at both the group and field levels. Sensitivity studies were also undertaken to determine the minimum EPM requirement to gain the history match.
This paper describes how to use completion, production and injection data in the flow model to predict the high permeability zones in the vicinity of a wellbore. As it will be discussed in more detail, this technique allows for the achievement of a reasonable history match using a Black Oil reservoir simulator. The model was history matched to liquid rate, water cut, and pressure. The simulation model has been used to evaluate the current waterflood and predict the possible future enhanced oil recovery (EOR) opportunities for this field.
A Simple Method for Accurate Prediction of Temperature Drops in Natural Gas Production Systems for Black-Oil Models
Authors: Bahadori A. , Vuthaluru H. B. 
Published: October 2009

Abstract
Accurate prediction of the temperature drop accompanying a given pressure drop for the natural gas production well is necessary in the effective design of natural gas production facilities. Current rigorous compositional models depend on many variables and require information about fluid composition. In this paper, a simple-to-use method which is easier than current available models, is presented to predict accurately the appropriate temperature drop accompanying a given pressure drop in natural gas production wells based on the black-oil model to get a quick approximate solution for the temperature drop of a natural gas streams in gas production wells. The obtained results illustrate that excellent agreement is observed between the reported data and the values calculated using the new developed method. Considering the results, the new developed correlation is recommended for rapid estimation of wellbore temperature drops in gas production wells for pressures up to 45 MPa and pressure drops up to 25 MPa. This Simple-to-use approach can be of immense practical value for the gas reservoir and production engineers to readily estimate temperature drops in gas production wells at various conditions. In particular, personnel dealing with natural gas production activities would find the proposed approach to be of immense help and user friendly involving no complex expressions with transparent calculations.
Modeling Well Performance in Shale-Gas Reservoirs
Authors: Cipolla C. L. , Lolon E. P. , Erdle J. C. , Tathed V. 
Published: October 2009

Abstract
The paper focuses on modeling well performance in shale-gas reservoirs using numerical simulation. Stimulation treatments in many shale-gas reservoirs create very complex fracture networks. These fracture networks are required to achieve economic production rates from rock with a matrix permeability of 1e-4 to 1e-5 md. The primary issues with modeling production from shale-gas reservoirs are accurately describing gas flow from the tight shale matrix into the fracture network, properly characterizing the matrix block size (or fracture density) and the conductivity of the network fractures, and evaluating the impacts of stress sensitive network fracture conductivity and gas desorption. This paper contrasts numerical reservoir simulation approaches using discrete modeling of the tight matrix and fracture network to that of dual porosity models. The paper illustrates that discretely gridding the network fractures is required to accurately model fluid flow in shale-gas reservoirs (with complex fracture networks) and show that dual porosity solutions do not adequately capture the transient flow in the very low permeability matrix blocks. The paper also illustrates the impact of gas desorption on the production profile and ultimate gas recovery in various shale reservoirs, showing that in some shale-gas reservoirs desorption may be a minor component of gas recovery. In addition, the paper details the impact of stress sensitive network fracture conductivity on well productivity. The reservoir simulations show that as closure stress increases in the fracture network, significant reductions in network fracture conductivity are likely, decreasing ultimate gas recovery. However, the effects of stress sensitive network fracture conductivity may not be evident in the initial well performance (1-2 years) and could lead to optimistic gas recovery forecasts. The paper presents selected examples from Barnett shale horizontal wells that incorporate microseismic fracture mapping and production data to illustrate the application of the production modeling to evaluate well performance in unconventional gas reservoirs.
Horizontal Well Design Incorporated with Interwell Interference, Drilling Location, and Trajectory for the Recovery Optimization
Authors: Lee J. W. , Park C. , Kang J. M. , Jeong C. K. 
Published: October 2009

Abstract
The paper presents a horizontal well-design economically optimized by GA(Genetic Algorithm), which considers drilling location, various trajectories, and drilling cost. Previous designs for the production well have been limited at selecting the drilling spot and placing the fixed-shape trajectories to maximize the cumulative production. They are difficult to produce the systematic design that covers whole reservoir characteristics since they concentrated on only the location or the fixed trajectory for additional one well or two wells. Furthermore, they are incapable of fully investigating the interference effect among the producing wells in a heterogeneous reservoir as well as the profit maximization at the view point of economist.
The optimization model integrates GA with a node-based configuration that allows several kick-off points for the horizontal well-designs. The chromosome of GA involves the data regarding the location coordinates, the number of kick-off points, the trajectories, and the number of wells. The object function evaluates the profit consisted of production rate and cost information related to drilling and operation. Waterflooding with one injection well is carried out and the effect of inter-well interference is examined in a heterogeneous reservoir.
The developed model improves both profit and cumulative production comparing with the conventional vertical well-designs. The wells are distributed sparsely due to the interwell interference meanwhile they are assembled in higher permeable zones of a heterogeneous reservoir. The approach makes it possible the more reliable well-design considering several kick-off points, well placement, and various trajectories.
On State Constraints of Adjoint Optimization in Oil Reservoir Water-flooding
Authors: Suwartadi E. , Krogstad S. , Foss B. 
Published: October 2009

Abstract
Optimization on large scale reservoir models may be prohibitive in terms of run-time. The adjoint based method is an efficient way to compute gradients in such systems. The presence of state constraints however may be detrimental to computational efficiency. In this paper we explore the use of adjoints and the interior point method for reservoir problems, in particular the optimal production setting problem with state constraints. State constraints typically include limits on water saturation in grid blocks close to producer wells or limits on water production rate. Results are encouraging since computational efficiency is maintained in the two examples which are studied in this paper.
Upscaling in Partially Fractured Oil Reservoirs Using Homogenization
Authors: Salimi Hamidreza , Bruining Johannes 
Published: October 2009

Abstract
Flow modeling in fractured reservoirs is largely confined to the so-called sugar cube model. Here, we consider a situation where matrix blocks are connected to neighboring blocks so that part of the global flow occurs only in the matrix domain. We call this a partially fractured reservoir (PFR). As opposed to the sugar cube model, global flow in the matrix blocks plays an important role in the PFR when the interconnections between the matrix blocks are sufficiently large. We apply homogenization to derive an upscaled model for partially fractured reservoirs that combines dual-porosity and dualpermeability concepts simultaneously. We formulate a well-posed fully implicit 3D upscaled numerical model and investigate oil recovery mechanisms for different dimensionless characteristic numbers. As we found previously for the sugar cube model, the Peclet number, defined here as the ratio between the capillary diffusion time in the matrix and the residence time of the fluids in the fracture, plays a crucial role. The gravity number and specific fracture-matrix interface area play a secondary role. For low Peclet numbers and high gravity numbers, the results are sensitive to gravity and water injection rates, but relatively insensitive to the specific fracture-matrix interface area, matrix block size, and reservoir geometry, i.e., sugar cube versus PFR. At low Peclet numbers and high gravity numbers, ECLIPSE simulations (Barenblatt or Warren and Root (BWR) approach) give poor predictions and overestimate the oil recovery, but initially show good agreement with the solution of the PFR model at intermediate Peclet numbers. At high Peclet numbers, the results are relatively insensitive to gravity, but sensitive to the other conditions mentioned above. In particular, when the specific fracture-matrix interface area is large, it enhances the imbibition and consequently leads to a higher oil production. If this fraction is low, it leads to a considerable retardation of the imbibition process, which leads to an earlier water breakthrough and lower oil recovery. The ECLIPSE simulations and the sugar cube model result in inaccurate predictions of the oil production rate at high Peclet numbers. This can be inferred from the discrepancy with respect to the PFR model for which we assert that it accurately predicts the oil recovery. We conclude that at low Peclet numbers and large gravity numbers it is advantageous to increase the water injection rate to improve the Net Present Value. However, at high Peclet numbers increasing the flow rate may lead to uneconomical water cuts.
Single Porosity Simulation of Fractures With Low to Medium Fracture-to-Matrix Permeability Contrast
Authors: Abdel-Ghani Rida 
Published: October 2009

Abstract
The use of single porosity models to simulate fracture flow is a challenge for simulation engineers. The main challenge remains in the speed at which water advances in the fracture system with little production from the producers that intersect the fractures. In single porosity modeling, water has to displace the oil ahead of the flood front to reach a producer. Due to the high matrix to fracture storage ratio, this usually results in over-prediction of the produced oil volume prior to water breakthrough. One typical solution to this problem is the use of local grid refinement, where an engineer will represent the fracture or fracture corridor with a "thinner" line of cells.
Another alternative solution is to modify the relative permeability curves of oil and water, to slow the oil movement and speed up the water movement in these cells. Paul van Lingen et al (2001) presented a technique that relies on modifying the relative permeability curves to produce "pseudo relative permeability" curves for the grid blocks containing fractures, without the need for grid modification. This method reflects a considerable advancement in the modeling of fracture system behavior in single porosity systems. It allowed to model faster breakthrough times and higher water production rates after breakthrough.
This paper describes a modified pseudo relative permeability correlation, which is based on the van Lingen et al method, that improves the water breakthrough time and water cut predictions, especially in the low to medium fracture-to-matrix permeability contrast cases. The new method restricts the pseudo curves to the widely known straight line curves that are typically used to represent fracture flow in dual porosity modeling. The modified correlation was numerically tested with various permeability contrast cases and was compared to a dual porosity model. The method is currently being used for modeling a large Middle East oil reservoir.
A Novel Method to Develop a New Scaling Equation for Modeling of Asphaltene Precipitation
Authors: Bagheri M. B. , Kharrat R. , Mirzabozorg A. , Ghotbi C. , Dastkhan Z. 
Published: October 2009

Abstract
Most investigations showed that the prevalent thermodynamic models are incapable of predicting asphaltene precipitation without extensive data fitting. This is primarily due to lack of knowledge of the asphaltene properties, its complex nature and the large number of parameters affecting precipitation. Hece, several authors tried to generate a simple and universe mathematical model in order to predict the amount of asphaltene precipitation. In spite of these efforts, the authors only considered temperature and type of solvents as the effective parameters in generating their scaling equations. The major disadvantage of these models is their inability in predicting the amount of asphaltene precipitation for different crude oils. Therefore, this deficiency contradicts to the universality of these models. In this work by performing experimental tests on different crude oils and analyzing their properties such as GOR, Resin to Asphaltene ratio, mole percent of plus fractions and residual oil density, a new scaling equation was developed for the predicting of asphaltene precipitation of different crude oil samples. The developed correlation can be used to estimate the amount of precipitated asphaltene at different dilution ratios and the onset dilution ratio of precipitation. The new scaling correlation has been validated with another experimental precipitation data generated after developing the scaling correlation.
Ensuring Water Saturation Consistency Between Static (Fine-Grid) and Dynamic (Upscaled) Models—A Case Study of the North Kuwait Jurassic Complex
Authors: Ghorayeb Kassem , Tan Leong Hooi , Limsukhon Manoch , Aziz Rafi Mohammad 
Published: October 2009

Abstract
The North Kuwait Jurassic Complex (NKJC) consists of six fields with four identified reservoirs in the naturally fractured Jurassic carbonate section. An integrated model incorporating seismic, geological, petrophysical, and engineering data is built to estimate the hydrocarbon volumes and provide multiscenario production forecasts for the NKJC.
Water saturation is populated in the static (fine-grid) model using a saturation height function (SHF), which is a continuous function of porosity and height above free-water level (HAFWL). The SHF is equivalent to a capillary pressure (at reservoir conditions), which is a function of porosity and water saturation. Capillary pressure curves based on the SHF are used to initialize water saturation in the dynamic (upscaled) model.
Given the fact that reservoir simulators cannot handle capillary pressure curves as continuous functions of porosity, discretization of the porosity-dependent capillary pressure function was performed. For this purpose, 15 capillary pressure curves (corresponding to 15 porosity categories) were used. Populating initial water saturation in the dynamic model using the SHF (or the equivalent capillary pressure curves) results in a substantial discrepancy in terms of water saturation between the static model and the dynamic model. The discrepancy is mainly because of the nonlinear dependency of the SHF versus porosity and the averaging of HAFWL. Upscaling tends to eliminate the high and low porosity values in favor of the average porosity, which leads to substantial changes in the resulting water saturation.
Because the calculated water saturation is highly dependent on the porosity and HAFWL, upscaling results in a mismatch between static and dynamic models in terms of hydrocarbon estimates. To overcome this problem, the initial water saturation in the simulation model is populated using the pore volume–weighted, upscaled water saturation from the static model. The endpoint-scaling functionality in the simulator is then used to modify the discrete set of capillary pressure curves to support the provided initial water saturation.
Results show that the correction of the capillary pressure curves needed by the simulator to support the provided initial water saturation values is relatively minor while full consistency between the static and dynamic models in terms of water saturation is obtained.