bluuebunny/crossref_metadata_2025_split huggingface dataset:
Coupled Hydro-Geomechanical Modelling of the Cold Production Process
Authors: Coombe Dennis , Tremblay Bernard , Tran David , Ma Huiping 
Published: December 2007

Abstract
Aspects of the cold production process have been studied mechanistically employing a unified framework and coupled geomechanical-fluid flow simulation models. The unified framework is a generalization of that proposed by Papamichos et al1 such that stress concentration causes mechanical weakening, and fluid flow causes erosional mobilization of sand particles. Porosity change is the primary coupling parameter whereby the soil mechanical and strength properties are altered as a continuum damage process, while erosional generation of mobilized sand particles causes fluid porosity increase and oil-sand slurry flow.
These ideas are implemented in coupled simulation models using different coupling strategies and different physical assumptions to study various aspects of the cold production process. The first coupled model is a stand-alone finite element model for two-dimensional radial plane strain and single phase fluid flow. Here the geomechanics and fluid flow aspects are fully coupled such that the time dependent (undrained to drained) mechanical stress transfer is strictly preserved. The second coupled model allows a more complete fluid model (including gas ex-solution and water influx), as well as a time dependent sand mobilization mechanism, but at the expense of a weaker (time explicit) geomechanical-fluid flow coupling, through Settari's concept of volume (effective porosity) coupling21.
These models are applied to simulations of cold production at the laboratory and field scale. The laboratory scale models are based on the CT experiments of Tremblay et al2, which emphasize the erosional aspects of the cold production process, and its coupling to gas exsolution. The field scale models are based on single well production observations in Alberta bitumen reservoirs, such as Yeung et al44 and include sensitivities to water influx. Additional geomechanical aspects which may be important in deeper reservoirs such as those in Venezuela are also illustrated.
Finally implications and recommendations for future simulation modelling at the field scale are provided.
Experimental Investigation of Foamy Oil Solution Gas Drive
Authors: Kamp A. M. , Heny C. , Andarcia L. , Lago M. , Rodriguez A. 
Published: December 2007

Abstract
A five-year laboratory and simulation investigation on heavy-oil solution-gas drive processes is reported. It is shown how the interpretation of these processes has changed over the years. Initially, it was attempted to take into account the "bubbly" character of the oil by changing the oil thermodynamical properties. Non-conventional PVT properties accounted for supersaturation and trapped gas bubbles. Later, in agreement with work in other research groups, the low produced gas-oil ratio and high recovery factors were modeled by introducing low gas-oil relative permeability. This allowed for history matching of laboratory and field data, but doubts remain about the predictive capacity of reservoir simulation models. This doubt is motivated by the observed flow geometry of the (dispersed flow), which is not physically taken into account in the reservoir simulation equations. It is concluded that more work is necessary on the determination of the mechanisms that govern the flow, and on the development ofm odels that more correctly represent the physics of dispersed gas-liquid flow in porous media. Further experiments in cores and micromodels, together with microscopic modeling of flow in pore spaces, should be part this work.
Device for Testing the Dynamic Stability of Highly Concentrated Emulsions against Coalescence
Authors: Ortega P. , McGrath G. , Núñez G. , Joseph D. 
Published: December 2007

Abstract
A portable and compact device with independently controlled shear, pressure variations and residence time for testing changes in the drop size distribution of concentrated oil in water emulsions is described by Joseph et al (1999, US Patent 5,987,969). Examples are presented where the device is used for quality control of emulsions in transport and manufacturing operations.
The Orinoco Oil Belt Targets Light/Medium Crude Oil and Product Market Opportunities
Authors: Alvarez C. E. , Marciano C. , Pereira C. , Larrauri K. , Morros F. , Bauduhin P. 
Published: December 2007

Abstract
The Orinoco Oil Belt keeps a firm path towards the manufacturing of upgraded crude oils. Currently, all efforts are concentrated on the production of its first barrel of synthetic crude oil from the first of the four environmental friendly world class projects in progress (named Petrozuata, Cerro Negro, Sincor and Hamaca) in the Jose area, located on the northeastern side of the country. Its huge reserves support at least ten additional new projects, each processing some 200 MBCD for a 35-year period to manufacture L/M crude oils and high quality products in Venezuela. These potential new projects would represent an outstanding impulse to the economic development of the eastern part of the country. Several options to integrate production activities, upgrading plant schemes and locations, as well as market opportunities have been studied. Options contributing with the highest added value to the nation and project partners are highlighted in this paper. The "tailor made" upgrading schemes to process extra heavy crude oils contribute to strengthen the quality of the Venezuelan hydrocarbon exports package, and furthermore, maximize its value. A new project to transform extra heavy crude oil from the Orinoco Oil Belt could also support commercial efforts to penetrate new markets as well as contribute to the development of the national chemical industry through the industrialization of off gases and solids produced in its upgrading plant. The study results confirm the Orinoco Oil Belt as PDVSA secure source of light, medium and heavy crude oil and high quality products, offering likewise excellent opportunities for the participation of strategic foreign partners and national investors in the Venezuelan hydrocarbon business.
Evaluation of Fracture Stimulation Treatments by Integrated Reservoir Description and Fracture Treatment Analysis in the Pecos Slope Abo Tight-Gas Reservoir, Southeastern New Mexico
Authors: Sanchez Steve , Engler Thomas W. , Kelly Mike 
Published: December 2007

Abstract
The primary goal of this study was to couple reservoir characterization of the Abo Formation with hydraulic fracture analysis and subsequently, to infer infill drilling potential. Two detailed case studies were investigated to reevaluate original hydraulic fracture treatment designs, to compare and evaluate fracture parameters, and to determine if the fracture treatments were providing sufficient reservoir stimulation.
Approximately 80 wells were studied in the southern part of the Pecos Slope Abo Field. Decline curve analysis was performed on all wells by a modified set of Fetkovich type curves. Analysis of this work show linear to near-linear flow in most cases with permeability values less than 0.1 md and variations in reservoir properties as is typically observed in low permeability reservoirs. These variations resulted in difficulty in evaluating infill drilling potential.
Evaluation of fracture stimulation treatments was accomplished by matching recorded surface treating pressure with a fracture propagation model. Unusually high initiation pressures were observed in the case study wells; initial stress state, vertical fracture growth, fracture toughness, perforation restrictions, and the development of multiple fractures in a single, bounded layer were evaluated as possible causes for the high initiation pressures. Results from this work showed the multiple fractures model providing the best match for the two wells. Fracture length varied from approximately 1150 ft to 750 ft with a single fracture model and was reduced by approximately 10 to 30% for each additional fracture added. The fracture data was input into a fractured well performance model, which was used to match the production rate and therefore verify the process.
The integration of decline curve analysis and fracture analysis provided better descriptions of reservoir properties and more accurate designs of fracture propagation models. This combined approach also improved evaluation of infill drilling potential by evaluating reservoir properties and stimulation.
Log Evaluation of Low - Resistivity Sandstone Reservoirs
Authors: Hamada G. M. , Al-Awad M. N. J. , Almalik M. S. 
Published: December 2007

Abstract
A careful examination of the mud log and sidewall cores in certain interval of hydrocarbon anomaly, dry oil from low resistivity sands was surprisingly discoverded and confirmed afterward by well testing results. The problem with these sands is that the resistivity logs indicate high water saturation, but water free hydrocarbon will be produced.
This paper discusses the different reasons sandstone reservoirs can have low resistivity. The mechanisms resposibles for low resistivity phenomenon are described as being caused by the inclusion of clay or pyrite minerals and as being due to microporosity. Clean bearing sandstone has high resistivity, but when this rock contains clay, or heavy minerals such as pyrite, the resistivity can become low. Pyrite shows a good electrical conductivity, that is usually comparable to or even higher than the conductivity of formation water, and can therefore have a larger effect than shale. In this work, different shaly sand models will be discussed and applied in two field examples to correct the calculated water saturation from shale effect to get the true water saturation level. The contribution of NMR log in solving problems of low resistivity microporisity sandstone reservoirs was iluustrated by a third field example.
A Novel Technique for Treating Asphaltene Deposition Using Laser Technology
Authors: Zekri Abdulrazag Y. , Shedid Shedid A. , Alkashef Hassan 
Published: December 2007

Abstract
Crude oils produced in many parts of the world contain asphaltenes. Asphaltenes plugging is a well-known cause of near-wellbore formation damage. The deposition phenomenon of asphaltene is mainly due to thermodynamic changes. Asphaltene deposition leads to production loss and requires expensive and in many times environmentally unfriendly corrective measures. This project proposes a novel technique for cleaning asphaltenes with laser energy. A laboratory laser diode modules was used to perform experiments. A two-inch column of bitumen/powdered limestone mixture was placed on top of a powdered limestone column in a flow cell, and the flow rates were measured before and after the laser treatment. The rate was correlated with permeability of this powdered limestone column in absence of bitumen. In a second series of experiments, actual consolidated limestone cores were subjected to flow of asphaltenic crude to simulate the damage process (i.e. permeability reduction). The damaged cores were subjected to laser treatments at various laser intensity and treatment time intervals.
Experiment results indicated that asphaltene get disrupted after exposure to laser energy. However, the maximum amount of cleaning was noticed after an exposure of one hour and at a higher laser intensity. The increased flow rate measured employing the powdered limestone column after treatment can be used in an oil field to disrupt, or desegregate asphaltene from the vicinity of oil production wells. However, the simultaneous pumping is required during the laser treatment to avoid the reprecipitation of the disrupted asphaltene. The laser energy alters the thermodynamics of the system, which resulted in re-dissolve some of the asphaltene back into the liquid phase (reversible process). The proposed technique provides environmental friendly process and advanced technological breakthrough for treating asphaltene deposition in the petroleum industry.
Simultaneous Determination of Reservoir Pressure and Initial Fluid-in-Place from Production Data and Flowing Bottom Hole Pressure -- Theory
Authors: Wang Shie-Way 
Published: December 2007

Abstract
One frequently encountered difficulty in material balance calculation is lack of shut-in reservoir pressure. This work presents a new method that can be applied under pseudo steady-state conditions to simultaneously determine the average reservoir pressure and initial fluid in place using only surface production data and flowing bottom hole pressure. This new method is derived from a combination of a generalized material balance formulation and pseudo steady state theory and is applicable to both oil and gas reservoirs for single-phase flow with no water influx. This method does not rely on pressure build-up tests, knowledge of drainage area or permeability, but it requires flowing bottom hole pressure. For constant flowing bottom-hole pressure or variable production rate, this work presents an algorithm to convert fluctuating or constant flowing bottom hole pressure into corrected flowing bottom-hole pressure with a decline rate essentially identical to that of average reservoir pressure. Methods for analyzing transient flow are also discussed in this work. This new method is useful in analyzing surface production data and flowing bottom hole pressures for reservoirs significantly lacking data.
Conformance Water-Management Team Developments and Solutions on Projects in the Permian Basin
Authors: Creel P. , Vavrek G. , Honnert M. , Kelley R. , Tate R. , Dalrymple E. D. 
Published: December 2007

Abstract
A team was formed to solve field-wide conformance problems in a San Andres (dolomite) unit of the Slaughter Field, Hockley Co., Texas. The team&apos;s goal was to increase oil production and decrease production costs by understanding fluid movement through the reservoir. The team was comprised of operating and service company personnel who performed data analysis, and developed engineering and solution designs.
The reservoir conformance team identified, quantified, and fully described field conformance problems. Team members focused on understanding fluid movement through the total reservoir rather than on single wells. They developed a framework of data for designing successful conformance solutions. This framework includes data about the reservoir, completion design, drilling and workover history, production and well-test history, logs, diagnostic analysis, and placement options. The framework serves as a data-collection tool and as a tool for identifying missing data.1
This project involves the following tasks: (1) analyzing approximately 300 wells, (2) identifying conformance candidate (pilot) wells, (3) implementing the pilot wells, (4) analyzing the results from the pilot wells, and (5) applying those results to the rest of the unit.
In this project, team members developed the typical data analysis, reservoir and production engineering proposals, and solutions proposals, and also thoroughly reviewed the customer&apos;s economic drivers. In these mature units, enhancing recovery and production rates and reducing costs were important factors.
Treatments have been placed and analyzed for sweep improvement, CO2 reduction, and water cycling-breakthroughs.
Reserve Estimates for Naturally Fractured Reservoirs
Authors: Briggs Arthur R. 
Published: December 2007

Abstract
Reserves estimates in naturally fractured reservoirs present a unique challenge to the reservoir engineer. Reservoir storage capacities and thus reserves in a fractured reservoir come from two major sources: fracture capacity and matrix capacity. Most fractured reservoirs consist of a combination of these two capacities.
Defining area of drainage in a naturally fractured reservoir presents another challenge. Fractures often contribute most of the delivery capacity in a fractured reservoir. Drainage area in a naturally fractured reservoir is oriented along open fracture systems with significant areas included from nearby reservoir rock containing appreciable matrix porosity and permeability and intersected by the fracture system. Horizontal drilling, which is usually oriented in an attempt to intersect several open fracture systems, adds another dimension to the problem of defining area of drainage and delivery capacity.
This paper investigates the application of the major types of reserve estimates including analogy, volumetric, and performance analysis to naturally fractured reservoirs. Sample illustrations and calculations for typical reservoirs will be reviewed and discussed.
Modelling the Productivity of a Multifractured-Horizontal Well
Authors: Cvetkovic' Branimir , Halvorsen Gotskalk , Sagen Jan , Rigatos E. N. 
Published: December 2007

Abstract
The value of horizontal multiple fractured wells can be maximized when the parameters with the greatest effect on productivity of such wells is understood. As a step towards achieving maximum value from horizontal multifractured wells, a computer model (MFHOW) has been developed that allows the user to quickly assess the impact of various well or reservoir properties on well performance. The model is generally three-dimensional and considers full time variability. It assumes single-phase oil flow and is based on semianalytical techniques. The model may be used for modelling transverse or longitudinal fractures of varying type (uniform flux, infinite conductivity, finite conductivity). Flexibility to use various constraints and the option of multi-run sensitivity generation can be used for prognosis of multifractured horizontal well productivity and its diagnosis. The model solution that is developed can be used for general screening and optimization of a multifractured horizontal well because of the fast numerical algorithms implemented. For any given set of reservoir, fracture and well parameters the oil rate, cumulative production, well pressure, or productivity index can be determined. Various model features are presented through sensitivity results and comparison with actual data from a North Sea well.
Studies in Vertical and Horizontal Well-Flow Behavior in Cases of Permeability Anisotropy
Authors: Cline S. B. , Tiab D. 
Published: December 2007

Abstract
Modified 2-phase analytical equation solutions to vertical well behavior match simulated results quite well for fluid flow in both isotropic and highly anisotropic permeability cases above and below the bubble point. Also no matter what the contrast in kx and ky, if the geometric mean permeability was held constant, the simulated rate vs. pressure results were essentially identical to each other. This confirmed the often-used geometric mean permeability approximation. In contrast, analytical solutions to horizontal well flow generally follow simulated solutions in isotropic media but do not match simulated horizontal results very well in horizontally anisotropic permeability conditions. Also horizontal simulations diverge markedly from one another as the permeability contrast increases despite keeping the geometric mean identical. The mismatch is especially pronounced as the x and y directional permeability contrast increases, in cases of pressure above the bubble point and in cases where the well length is large compared to the reservoir dimensions. This behavior is not predicted from standard analytical equations utilizing geometric mean permeabilities.
Extensive simulation experiments allowed construction of graphical relationships that present the effect of increasing degrees of reservoir permeability anisotropy on horizontal well fluid flow as a function of dimensionless well length, reservoir dimension ratios, grid block size and density, reservoir pressure and severities of anisotropy. Despite a constant geometric mean permeability, the flow rate deviation from the isotropic case increases as the degree permeability contrast becomes more severe in the principal x and y directions. The deviation from the isotropic case also increases
as the well length increases for any given reservoir dimension. The deviation is also more apparent as reservoir pressure increases above the bubble point. The number of grid blocks used did not seem to have any appreciable effect on the results.
Geological Parameterization of a Reservoir Model for History Matching Incorporating Time-Lapse Seismic Based on a Case Study of the Statfjord Field
Authors: van Ditzhuijzen R. , Oldenziel T. , van Kruijsdijk C. P. J .W. 
Published: December 2007

Abstract
The geological structure can have a tremendous impact on hydrocarbon flow and, especially in structurally complex reservoirs, is often one of the biggest uncertainties in reservoir modeling. One can think for example, of the sealing capacity of faults or of preferential fluid flow paths dictated by geological bodies. Using geological and structural parameters, these features can be incorporated when history matching a reservoir model. History matching with geologic parameters can enhance reservoir management by identifying non-swept regions and optimizing the placement of infill wells. In this paper we demonstrate an automated history matching method, using geological parameterization. Both time-lapse seismic and production data are used in an integrated manner. The method is tested on a synthetic reservoir, which resembles a structurally complex gravity slide system, common in North Sea reservoirs and other reservoirs situated in similar rift systems. The East Flank of the Statfjord Field is used as an example. The slump and associated faults are characterized by the following parameters: position, size and throw. Results show that the slumps / faults in a structurally complex reservoir can successfully be history matched. Evaluation of the conditioning data shows that the time-lapse seismic data gives more accurate information about the structure than production data.