bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comparison of Reservoir Simulation Hysteresis Options
Authors: Kossack C. A. 
Published: December 2007

Abstract
An understanding of drainage and imbibition processes, three phase flow models, hysteresis in relative permeabilities and capillary pressure, and scanning curves is vital to the proper use of modern reservoir simulators. Several choices are available to the engineer for the three-phase model, for the hysteresis model, and for the treatment of the wetting phase during hysteresis. The combinations of parameters/models generated by these choices give the engineer a puzzling array of options. Unless one has studied hysteresis and simulated the various cases, it is difficult to know which combination is appropriate for their reservoir.
This paper discusses the models available for hysteresis in water-wet systems and the interaction of these models with the standard three phase relative permeability and capillary pressure models. Simulations are run with various combinations of models and the resulting scanning curves are plotted along with the drainage and imbibition bounding curves. One can see the differences between model combinations. A WAG injection into a linear reservoir is simulated for each combination of options. The oil, gas, and water production rates and oil recovery are compared.
Requirements to obtain proper scanning curves are provided. Experiments are recommended to help the engineer choose the appropriate combination of models for his/her reservoir.
A Coupled Model for Three-Phase Capillary Pressure and Relative Permeability
Authors: Hustad Odd Steve 
Published: December 2007

Abstract
A fully coupled formulation for three-phase capillary pressure and relative permeability is presented. The formulation incorporates hysteresis and miscibility on both capillary pressure and relative permeability, simultaneously. Consistency is ensured for all three two-phase boundary conditions, through the use of two-phase data and the application of normalized saturations.
Simulation examples of Water-Alternating-Gas (WAG) injection are demonstrated using water-, mixed- and oil-wet capillary pressure and relative permeability curves, both exhibiting hysteresis. The examples represent typical core-flooding scales in the cm to m range. Discussions and illustrations are given demonstrating the importance of the functional dependency and the extrapolation of two-phase capillary pressure values to three-phase flow properties.
The Use of Streamline Simulation in Reservoir Management: Methodology and Case Studies
Authors: Lolomari Tony , Bratvedt Kyrre , Crane Martha , Milliken William J. , Tyrie J. J. 
Published: December 2007

Abstract
Because of increased speed and accuracy, 3D streamline simulation now can be used in a wide range of reservoirs. Large reservoirs with hundreds or thousands of wells, several hundred thousand grid blocks and an extensive production history always have been a challenge for finite-difference simulation. The size and complexity of these reservoirs generally have limited simulation to sections or patterns.
The streamline technique enables simulation of these reservoirs by reducing the 3D domain to a series of 1D streamlines along which the fluid flow computations are performed, offering computational benefits orders of magnitude greater.. Additionally, increased accuracy is achieved by maintaining the sharp flood fronts from the displacement processes and reducing grid orientation effects.
The streamline simulation results substantially have more value as a reservoir management tool when used in conjunction with traditional reservoir engineering techniques such as standard finite-difference simulators.
Several case studies that highlight a variety of situations where streamline methods proved highly beneficial are presented in this paper. These studies will help the practicing reservoir engineer decide whether to apply streamline methods and the optimal timing for the application.
Inflow Performance Relationships for Gas Condensates
Authors: Guehria Fawzi M. 
Published: December 2007

Abstract
In this work, we describe a fast scheme to obtain time-dependent IPR curves for a depleting gas-condensate well without resorting to the use of simulation. The model reflects the flowing characteristics inside the reservoir. In addition, it is self-checking and consistent with the overall analysis of gas-condensate reservoir behavior. We also investigate the adequacy of reservoir material balance for gas-condensates to generate the IPR curves for a depleting gas-condensate well.
Transient effects are not considered in this work.
Inflow Performance Relationships (IPR’s) are a critical element in the design of new wells and in the monitoring and optimization of existing producing wells. In addition to Vogel-type relationships, various IPR models for different well geometry and different flow regimes have been presented. Generally, these models take advantage of analytical solutions for single-phase oil and for single-phase gas, to generate a flow rate profile with flowing pressure as a parameter.
For gas-condensate wells, standard dry-gas deliverability equations based on isochronal testing have always been used as IPR models. Unfortunately, due to severe deliverability reduction caused by condensate blockage, this approach is inadequate and usually leads to erroneous results.
In reality, the pressure drop that occurs in gas-condensate reservoirs operating below dew-point, is affected by up to three zones, i.e. 1) inner zone where both phases, gas and free condensate, are flowing, 2) middle zone where two phases coexist but only gas is mobile and 3) outer zone where only the single phase gas is flowing.
We verified the method with synthetic examples and good agreement was achieved in all cases.
Comprehensive System for Treatment and Injection of Produced Water: Field Case
Authors: Mantilla I. , Quintero P. 
Published: December 2007

Abstract
This work describes a comprehensive system that was designed, built and commissioned in Yarigui-Cantagallo field (Colombia) for treating and re-injecting produced water.
The facility mainly consists of one plate-pack separator, one induced-gas flotation cell, one nutshell filter and high-pressure pumps. Field data including water quality analysis in all stages of treatment are shown as well as calculated efficiencies for the equipment.
This system is adequate to obtain high quality water for reinjection in very tight formations.
Volumetric Growth and Hydraulic Conductivity of Naturally Fractured Reservoirs During Hydraulic Fracturing: A Case Study Using Australian Conditions
Authors: Hossain M. M. , Rahman M. K. , Rahman S. S. 
Published: December 2007

AbstractThe limitation of conventional hydraulic fracturing with two long wings of coplanar fractures is well recognized in the context of naturally fractured tight gas or Hot Dry Rock (HDR) geothermal reservoirs. This paper presents a 3D model for an alternative stimulation technology for such reservoirs. The model stochastically simulates actual reservoir representative natural fractures processing field data available from cores and logs. These simulated fractures are then analyzed for deformations with the combination of simple elastic structural mechanics and linear elastic fracture mechanics principles coupling with the injected fluid pressure and in-situ stresses. Finally, the hydraulic conductivity and the reservoir growth pattern are formulated as functions of fracture deformations.The applicability of the model has been verified using the data of actual fracture stimulation programs conducted in the Hijiori HDR site. It has been found that the model is capable of simulating actual natural fracture distribution in the reservoir. The model is finally applied to a series of numerical analysis with central Australian reservoir conditions to investigate the sensitivity of natural fracture parameters (e.g. size, density and orientation) and in-situ stresses to reservoir growth and conductivity. It is observed that the reservoir growth pattern is mainly influenced by fracture parameters and the relative magnitude and direction of in-situ stresses. Reservoirs with predominantly strike-slip and reverse faulting stress regimes and high deviatoric stresses are favorable for horizontally dominant reservoir growth - a pattern which is highly desirable for efficient HDR geothermal energy extraction. The information provided in the paper is directly applicable to HDR geothermal reservoir development with a high potential for new applications in tight gas reservoirs in which the abundance of natural fractures is so far posing significant complexity to conventional hydraulic fracturing, resulting in multiple fractures, high treatment pressure and premature screen-out.
Interpreting Spinner Response in Multiphase Bubble Flow
Authors: Wang Jianrong , Chace David , Georgi Dan , Maxit Jorge 
Published: December 2007

Abstract
The conventional production logging spinner is widely used to log both single and multiphase flows in producing wells, and it is well known that the spinner response in multiphase flow is complicated and difficult to interpret. A brief literature survey finds few models for interpreting the spinner response in multiphase flow. The general conclusions from previously published works are that the response is still more or less linear with the total volume flow rates, but still very difficult to interpret with any confidence.
In this paper, a mechanistic model based on angular momentum balance of the spinner rotor in bubble flow is introduced. The model is composed of two parts. In the first part, it is assumed that a) the fluids passing through the spinner blades are well mixed, b) there is slip between phases, c) the flow does not swirl. Therefore, an idealized spinner response under idealized bubble flow is developed. The results show that the spinner response in multiphase bubble flow is not a linear univariable function of the total fluid volume passing through the spinner, but rather a multivariable function of slip velocity, volume fraction, continuous phase velocity, and fluid properties. The second part of the analysis introduces the concept of bubble travel length to consider the effect of the spinner cage or centralizer on bubble flow trajectory.
Seismic While Drilling for Enhanced Look-Ahead-of-Bit Capabilities - Case Study of Successful Mud Pulse Coupling Demonstration
Authors: Judzis A. , Green T. S. , Hoversten G. M. , Black A. D. 
Published: December 2007

Abstract
Accurate prediction of formation pressures (pore pressures) is critical to conduct safe and economic drilling operations. This information is essential for both optimizing casing and drilling fluid programs, and is vital in avoiding well control problems. Seismic while drilling techniques offer improved safety and drilling performance for areas where uncertainties exist in formation tops and prediction of over-pressured zones. Examples of potential economic benefit include elimination of casing strings, maintenance of optimum hole size to total depth, and reduction of non-productive time. There are currently no systems that reliably provide this capability.
This paper presents the results of an ongoing development program designed to improve the efficiency and safety of drilling operations through the development of a down hole seismic source for enhanced ‘look-ahead-of-the-bit’ capabilities while drilling. The program is funded in part through the US Department of Energy. Results obtained from innovative large-scale tests show the effects of a down hole seismic source utilizing the hydraulic force of a mud pulse generated through a flow interruption device. Three axis accelerometers embedded in rock samples in a simulated wellbore environment showed signal responses which are under review in anticipation of analyzing ‘look-ahead-of-bit’ requirements.
The results provide a unique opportunity to examine seismic wave propagation in samples shorter than a wavelength and the potential to benchmark seismic sources for coupling efficiency before deploying tools in an expensive offshore environment. For offshore operations, the ability to improve pore pressure predictions ahead of the bit is one key to success.
Enhanced Productivity in a Heavy Oil Reefal Reservoir as a Result of Improved Reservoir Characterization
Authors: Elshahawi Hani , Klimentos Theodore , Elzefzaf Taher , Emara Maher 
Published: December 2007

AbstractThe Nullipore reservoir in the fields of Egypt's General Petroleum Company (GPC) is a heavy oil reefal reservoir located in the Gulf of Suez area. The Nullipore formation is characterized by a high degree of heterogeneity, which, in addition to the high oil viscosity, has made it difficult to locate and drain oil effectively. This was further complicated by the lack of accurate seismic and geological data. For these reasons, the reservoir had been traditionally considered only as a secondary or backup prospect. Recently, an approach was initiated, based on the use of innovative logging techniques for better reservoir characterization as well as production data analysis for better understanding of reservoir dynamics. This has led to the realization that the reservoir's productivity is primarily controlled by the flow contribution from natural fractures. New horizontal wells were hence planned and completed on the basis of the newly acquired information with excellent results. Moreover, older wells were recompleted using the data acquired from these horizontal wells, leading to large increases in production.This paper describes the methods used to locate the natural fractures that lead to the majority of production in the Nullipore reservoir. Central to these are the fracture detection logs and log-analysis methods employed. It also details how new wells can be put in place to intercept these fractures and effectively drain the oil.
Remaining Oil Saturation from NMR in a Mixed-Wet, Three-Phase Carbonate Reservoir
Authors: Akkurt R. , Merkel R. H. , Coates G. R. , Stever R. C. 
Published: December 2007

Abstract
Accurate determination of remaining oil saturation is critical for the successful implementation of enhanced recovery programs planned for the Yates field. Determination of oil saturation in this strongly heterogeneous, mixed-wet, and vuggy carbonate reservoir, however, is difficult. Conventional methods generally fail to produce robust results because of the variations in the Archie exponents m, and n, both in space and time. The saturation variations originate from the double displacement processes employed for improved recovery, which have generated a sizable gas cap and a moving oil/water contact.
Because of its direct reservoir fluid characterization capabilities, NMR logging was earlier identified as a potential alternative for the direct determination of remaining oil saturation at the Yates Field. A series of MRIL logs was run in 1998, where the main objective of the logging program was to exploit the diffusion contrast between oil and water. Results from this logging program were unsatisfactory because the apparent T2 contrast between the oil and water phases was not sufficiently large to allow an accurate determination of the various fluid fractions.
An extensive modeling study was then initiated to study the feasibility of NMR logging for oil saturation measurements. Existing MRIL logs and limited laboratory data were used as input into the models. Modeling showed that interecho times in excess of 6 ms. could increase the apparent T2 contrast between the oil and water phases. However, modeling also showed that such an increase in T2 contrast would be accompanied by severely lowered T2 resolution, which would in turn increase the uncertainty in computed saturations. Further modeling showed that the combination of higher magnetic field gradients and long interecho times could yield sufficient T2 contrast without compromising T2 resolution. It was then decided to modify an existing MRIL-C tool to achieve these objectives.
An observation well that was included in the 1998 program was relogged in late 1999 with the specially configured MRIL-C tool. Interpretation of the data acquired with this special tool and the remaining oil saturation determined from an NMR only technique agreed very well with the existing field model and petrophysical data. Expansion of the pilot study to a multiple-well evaluation program is currently being planned.
The Dynamics of Combustion Fronts in Porous Media
Authors: Akkutlu I. Yücel , Yortsos Yannis C. 
Published: December 2007

Abstract
The sustained propagation of combustion fronts in porous media is a necessary condition for the success of an in-situ combustion project for oil recovery. Compared to other recovery methods, in-situ combustion involves the added complexity of exothermic chemical reactions and temperature-dependent chemical kinetics. This gives rise to reaction zones of a spatially narrow width, within which heat release rates, temperatures and species concentrations vary significantly. This sharp variation makes difficult the simulation of combustion processes using coarse grids and the implementation of upscaling methods.
In this paper, we propose a method for solving this problem by treating the reaction region as a place of discontinuities in the appropriate variables, which include, for example, fluxes of heat and mass. Using a rigorous perturbation approach, similar to that used in the propagation of flames [3], and smoldering combustion [7], we derive appropriate jump conditions that relate the change in these variables across the front. These conditions account for the kinetics of the reaction between the oxidant and the fuel, the changes in the morphology of the pore space and the heat and mass transfer in the reaction zone. Then, the modeling of the problem reduces to the modeling of the dynamics of a combustion front, on the regions of either side of which transport of momentum (fluids), heat and mass, but not chemical reactions, must be considered. Properties of the two regions are coupled using the derived jump conditions. This methodology allows to explicitly incorporate permeability heterogeneity effects in the process description, without the undue complexity of the coupled chemical reactions.
Oxidation of Heavy Oil and Their SARA Fractions: Its Role in Modeling In-Situ Combustion
Authors: Akin Serhat , Kok Mustafa V. , Bagci Suat , Karacan Ozgen 
Published: December 2007

AbstractIn situ combustion is a thermal recovery technique where energy is generated by a combustion front that is propagated along the reservoir by air injection. Most of the previously conducted studies report thermal and fluid dynamics aspects of the process. Modeling in situ combustion process requires extensive knowledge of reservoir data as well as reaction kinetics data. Unfortunately, limited kinetic data are available on the rates and the nature of partial oxidation reactions and the high-temperature combustion reactions of crude oils and their saturate, aromatic, resin, and asphaltene (SARA) fractions. Moreover, the impact of such data on the modeling of the in situ combustion process has not been investigated thoroughly. Thus, we modeled in situ combustion experiments conducted on a 3D semi-scaled physical model that represents one fourth of a repeated five spot pattern. In all experiments a vertical injector is employed whereas, both vertical and horizontal producers have been installed to recover two different crude oils (heavy and medium). Several locations for the producers have been tried while keeping the length of the wells constant: vertical injector-vertical producer, vertical injector-horizontal side producer, and vertical injector-horizontal diagonal producer. In these experiments diagonal producers performed better than the others. We first simulated the experiments by incorporating a kinetic model that is based on grouping the products of cracking into six pseudo components as heavy oil, medium oil, light oil, two non-condensable gases and coke using a commercial thermal simulator (CMG’s STARS). Four chemical reactions were considered: cracking of heavy oil to light oil and coke, heavy oil burning, light oil burning, and coke burning. Most of the experiments were history matched successfully with the exception of ones where a diagonal horizontal producer was used. We then repeated the simulations using SARA kinetic parameters. We observed that all matches were somewhat improved. We finally present a discussion of application of the models to field scale.
Filtercake Cleanup in Open-Hole Gravel-Packed Completions: A Necessity or a Myth?
Authors: Brady M. E. , Bradbury A. J. , Sehgal G. , Brand F. , Ali S. A. , Bennett C. L. , Gilchrist J. M. , Troncoso J. , Price-Smith C. , Foxenberg W. E. , Parlar M. 
Published: December 2007

Abstract
Offshore reservoirs requiring sand control pose a major completion challenge because of extremely high cost and risk involved in remedial treatments, particularly in sub-sea completion and/or deep-water environments. It is therefore of utmost importance to ensure sand control without sacrificing flow conformance, recoverable reserves and well deliverability throughout the expected life of the completion. A major trend in these environments is towards open-hole, horizontal, gravel-packed completions. Although gravel packing stabilizes the wellbore, it can also entrap the filter-cake formed by the reservoir drilling fluid, potentially resulting in high drawdown requirements (flow initiation pressures) and/or low production rates (retained permeabilities). The cleanup procedures in the industry have varied significantly from no cleanup at all to complicated two-stage breaker treatments involving post-completion coiled tubing intervention, with no guidelines existing in the literature.
In this paper, we present experimental results and field cases involving filter-cake flow-back through gravel packs with and without cleanup. Effects of various parameters, including gravel size (40/60, 20/40, and 12/20), formation permeability, drill-solids type (clays, quartz) and concentration, and the type of cleanup fluid have been investigated. Flow initiation pressure and retained permeabilities during flow back are reported as a function of these parameters. The experimental results show that the flow initiation pressure is a strong function of gravel size and the type of drill solids. It is concluded that, in clean (low-to-no clay content) formations of large grains and high permeabilities (~ several darcies) requiring large gravel sizes (e.g., 12/20), an enzyme or an oxidizer treatment is sufficient based on laboratory results and productivity predictions. This conclusion is also supported by several field applications as shown. In lower permeability (~ 100–250 md) formations of small sand sizes requiring smaller gravel (e.g., 40/60) elimination of both the fluid loss control agent (starch) and bridging agent (CaCO3) is necessary based on high flow initiation pressures and low retained permeabilities. In intermediate permeability (~ 500–800 md) formations of medium size sand-grains typically requiring 20/40 gravel, the results depend strongly on the type of drill solids: in clean formations (no clays in drilling fluid), an enzyme or an oxidizer treatment is sufficient, while in dirty formations removal of both CaCO3 and starch is necessary. These results are also supported by field case histories presented in the paper.