bluuebunny/crossref_metadata_2025_split huggingface dataset:
Water-Coning in a Fractured Reservoir
Authors: Van Golf-Racht T. D. , Sonier Fernand 
Published: December 2007

Abstract
The Coning problem in a "conventional reservoir" (porous media) has always been examined in the light of "preventing the water-cut" in oil production wells which partially penetrate an oil layer underlain by water. For almost six decades all of the papers concerning the water-coning problem have limited their investigation to the evaluation of the "maximum" water-free or gas-free production rate (called the "critical oil rate") versus the oil pay magnitude and well penetration depth into the oil interval. The objective of this paper is the extend the investigation to the coning criteria in a "fractured reservoir" by including the production of oil and water and not only preventing the production of water.
Such a changement in the Muskat criteria required an examination of the fluid flow toward the well in the fracture network and thus the coning development and behaviour associated with the coning water-cut and total fluid production rates. The relationship of "coning water cut" vs. "production rate" in time in a fractured reservoir was examined for the first time out of the classic design approach of the coning production.
Among the problems examined are: 1) the role of "well completion" and its design in relation to the production of oil and water from a fractured reservoir, 2) the role of the "reverse coning" in estimating the maximum coning water-cut, 3) reservoir "internal architecture" role associated with the matrix "blocks size" influence on coning water-cut behaviour, 4) the role of horizontal and vertical fracture density, which is equivalent to a certain degree of anisotropy. The results of the study have demonstrated the gain of some important ideas in the water coning area and the combined effect of various reservoir characteristics for an optimized design of a well producing from a fractured reservoir.
Understanding Cavity Well Performance
Authors: Young G. B. C. , Kelso B. S. , Paul G. W. 
Published: December 2007

ABSTRACT
Open-hole cavity completions provide significant improvement in gas production from the Fruitland coal play in the northern San Juan basin. Where reservoir properties are favorable for cavitation, such as in the basin’s "fairway" area, gas production rates from cavitated wells generally exceed production from wells completed using hydraulic stimulation techniques, often by a factor of 3 to 10 times. Analysis of regional geologic trends and a simulation-based analysis of cavity well performance were used to better understand the downhole conditions responsible for this success, and to determine how these conditions differ from those of fracture stimulated wells.
Comparison of Water Saturations from Capillary Pressure Measurements with Oil-Base-Mud Core Data Ivishak (Sadlerochit) Reservoir, Prudhoe Bay Field
Authors: Richardson J. G. , Holstein E. D. 
Published: December 2007

Abstract
Oil-base-mud cores (OBC) were used as the method for determining water saturations (Sw) in the Ivishak (sometimes referred to at the Sadlerochit) Reservoir of the Prudhoe Bay Field. As-received Swobc ranged from less than 1% to 56% PV. A large alternate centrifuge capillary pressure database was developed to provide an independent check of the OBC results. Development of this database required selection of samples statistically representative of rock types in the reservoir and laboratory techniques that produced reliable results. Comparing Swpc to Swobc values required the consideration of the burial and hydrocarbon accumulation histories and the variations in hydrocarbon properties within the reservoir. This paper discusses the excellent agreement between the two data sets when all pertinent variables are considered.
IFT and Flushing Studies to Validate as-Received Oil-Base-Core Water Saturations from the Ivishak (Sadlerochit) Reservoir, Prudhoe Bay Field
Authors: Reed R. L. , Humphrey R. A. , Holstein E. D. , Rathmell J. J. 
Published: December 2007

Abstract
As-received oil-base-core water saturations were used as the primary source of data for determining Sw for the Ivishak Reservoir (also referred to as the Sadlerochit Reservoir), Prudhoe Bay Field. These saturations varied from &lt; 1% PV to 56% PV. Considerable work was done to validate the reliability of these data. This paper describes laboratory experiments, namely IFT measurements and core flushing studies, done to determine the affect a certain variables on the effect of mud filtrate invasion on resident water saturations. The IFT work suggested no movement of connate water would result from filtrate invasion although at extreme boundary conditions, the possibility could not be eliminated. The flushing studies indicated that at a range of conditions that may exist during coring, there is &lt; 1 water saturation unit change in Sw caused by filtrate invasion.
Simulation Model for Predicting Placement of Gels
Authors: Stavland Arne , Kvanvik B. A. , Lohne Arild 
Published: December 2007

Abstract
This paper describes a simulation model for gel placement. The model is a modified UTCHEM simulation model. Experimental data including retention, gelation strength and gelation rate are matched with the model. It has been stressed that the same set of input data are used in the simulations of the different experiments. The retention of the crosslinker can be crucial and is described by the dissolution of carbonate minerals in the reservoir. In shut-in treatments, gelation strength is found to increase as the permeability increases. Gelation or aggregation is also described during a continuos injection.
Evaluation of Correlations and Parachors To Predict Low Interfacial Tensions in Condensate Systems
Authors: Fawcett M. J. 
Published: December 2007

ABSTRACT
Gas-condensate relative permeability curves are enhanced when the interfacial tension (IFT) is low. Parachor methods generally give poor predictions in the low IFT region. The paper presents new IFT, density, and composition data from a model six component gas-condensate, and IFT and density data from a rich reservoir gas-condensate. Low IFTs were collected using a laser light scattering technique. Single component, multicomponent, and reservoir fluid data were used to evaluate density based IFT correlations. Improved Stegemeier-Hough single component parachors, and parachors for crude oil cuts were derived.
Gas/Oil Capillary Pressure: Measurements at Reservoir Conditions and Effect on Gas-Gravity Drainage
Authors: Longeron D. G. , Kalaydjian François , Bardon Charles , Desremaux L. M. 
Published: December 2007

ABSTRACT
Predictions of oil recovery by immiscible gas injection require accurate laboratory determination of gas-oil capillary pressures. Two series of drainage capillary pressure measurements were performed on sandstone core samples with and without connate water saturation. Binary mixtures of methane/n-heptane at different equilibrium pressures were used to obtain wide variations in the gas- liquid interfacial tensions (IFT) values.
Measurements have shown that the gas-oil capillary pressures determined at different levels of IFT and without connate water can be transformed into one capillary pressure function (Pc/IFT) down to IFT = 3.7 mN/m. Below this value, the capillary pressures measured were significantly lower than those estimated by the Young- Laplace equation. In the presence of connate water, the gas-oil capillary pressures were always higher than the ones measured without water saturation.
The impact using measured instead of scaled capillary pressures from mercury-air data was evaluated through numerical simulations of free gas-gravity drainage on a one meter-long block of a fractured reservoir. Simulations have shown that the kinetics and the level of oil recovery are very sensitive to the capillary pressure curves used as input data. For low IFT values and without connate water saturation the oil recovery is underestimated by about 6% PV using scaled capillary pressures from mercury-air data.
An opposite variation is observed in presence of connate water saturation.
A Laboratory Investigation of Gravity Drainage/Waterflood Interaction in Prudhoe Bay
Authors: Espie A. A. , Brown C. E. , Narayanan K. R. , Wilcox T. C. 
Published: December 2007

ABSTRACT
The Prudhoe Bay reservoir has a number of different oil recovery mechanisms operating in different parts of the field - gravity drainage, waterflooding, miscible flood and vaporisation. The boundaries between the different processes are not fixed, but have moved as the individual processes have matured in the reservoir. One of the key challenges in the management of the field is understanding the interactions that occur between different mechanisms.
One such interaction is that between the upstructure gravity drainage process and the peripheral waterflood. Interpretation and management of reservoir response in this region requires characterisation of the three phase displacement process as water displaces oil in the presence of a high gas saturation.
The aim of this study was to establish and interpret laboratory data quantifying the dynamics of oil bank growth during waterflood/gravity drainage interactions on the core scale. Advanced saturation monitoring was used to monitor the development of the oil bank. Novel tracer techniques were developed to measure transient oil saturations under three phase conditions. Detailed comparison of the core displacements with the predicted behaviour was performed using simulation.
Low-Temperature Analogs of High-Temperature Water/Oil Relative Permeabilities
Authors: Kumar Mridul , Inouye T. A. 
Published: December 2007

ABSTRACT
Dynamic-displacement experiments were conducted to develop and evaluate a simpler low-temperature analog of the high-temperature relative permeability data. Results show that a low-temperature analog of the high-temperature relative permeabilities can be obtained if the water/oil viscosity ratio at the two temperatures and wettabilities are similar. Furthermore, measured endpoint saturations were found to be independent of temperature and predominately a function of viscosity ratio. Using our data and numerical/analytical calculations we show that the observed temperature dependency of endpoint saturations are primarily measurement artifacts caused by viscosity ratio effects.
Gas/Oil Relative Permeabilities and Residual Oil Saturations in a Field Case of a Very Light Oil, in the Near-Miscibility Conditions
Authors: Bardon Charles , Longeron D. G. , Baudoin Francis , Delhomme Abdelkader , Naili Nabil 
Published: December 2007

ABSTRACT
The Hassi-Messaoud Field is one of the biggest oil fields in the world, made to produce by miscible gas flooding since 1964, a few years after the beginning of production. In some blocks, the pressure decline has been very great and such that pressure is currently close to the minimum miscibility pressure (MMP).
Laboratory studies were undertaken on representative core samples with the reservoir fluids to determine the gas/oil relative permeabilities and residual oil saturations (Sorg) at different levels of pressure, below the MMP. The recombined oil samples were prepared with the same stock tank oil and two separator gases, one of them containing significantly more intermediates than the other. The two recombined oils had the same bubble-point pressure. The MMP was measured for these two different oils with an injection gas called "medium gas", produced on the field itself.
The high sensitivity of the MMP to the associate gas composition has been outlined. The Sorg values were very low (between 25 and 5% PV) depending on the initial oil composition and on the level of pressure. A correlation has been established between the observed Sorg and the difference between the pressure of each test and the MMP versus the MMP. Finally, this study has demonstrated that the gas flooding process is very efficient even if the miscibility is no longer reached, while staying however in near miscibility conditions.
Dynamic Validation of Phase Behaviour Models for Reservoir Studies of Gas Injection Schemes
Authors: Khazam M. M. , Danesh Ali , Tehrani D. H. , Todd A. C. , Burgass R. 
Published: December 2007

ABSTRACT
Compositional models based on cubic equations of state (EOS) are generally employed for simulation of the reservoir performance in gas injection processes. Tuning of the EOS to experimental equilibrium data generated at static conditions, PVT data, prior to its use for compositional studies is the current practice in the oil industry. The displacement of oil in a slim tube by the injection gas simulates the phase behaviour resulting from the continuous contact between the two phases in the reservoir more realistically than any other laboratory tests. It has therefore been suggested that the comparison of the displacement data with simulated results of a compositional model using the tuned EOS can be employed to evaluate and, if necessary, further tune the phase behaviour model. As the flow parameters and numerical methods incorporated in the simulation model can strongly affect the prediction results, the value of such an exercise has been seriously questioned.
A systematic study of the applicability of the gas-oil displacement data for tuning of the phase behaviour model to simulate gas injection processes was conducted in this study. The flow characteristics of a number of slim tubes packed with glass beads were evaluated by displacing binary oil mixtures with equilibrated gases to measure the relative permeabilities of the phases at no mass transfer conditions. A large amount of data at different interfacial tension values were used to develop relative permeability-saturation correlations as a function of the interfacial tension. Liquid-Liquid displacement tests were conducted to measure the physical dispersion in the slim tube. The information was used to select the grid block/time step size of the simulator to match the numerical dispersion, due to the truncation error, to that of the physical dispersion.
The reliability of the developed parameters was confirmed by comparing predicted and measured displacement data using multicomponent and real reservoir fluids at no mass transfer conditions.
Having identified all the parameters of the slim tube and simulation model, a series of gas-oil displacements were conducted using multicomponent and real reservoir fluids at miscible and immiscible conditions. The fluids were initially tested at static conditions and the generated experimental data were used to tune the phase behaviour model prior to simulation of the dynamic gas injection tests.
The simulated displacement results, for miscible and immiscible conditions, matched the experimental data favourably where the tuned model was capable of adequately predicting the static data covering the whole range of compositional variations. The study highlighted the value of displacement data for evaluating phase behaviour models particularly at conditions where significant mass exchange occurs between the phases.
Laser Light Scattering Studies of Natural Gas Hydrates
Authors: Nerheim A. R. , Svartaas T. M. , Samuelsen E. J. 
Published: December 2007

Abstract
Nucleation and growth of gas hydrate crystals have been investigated using Photon Correlation Spectroscopy (PCS). Hydrate experiments were performed using distilled and filtered water together with a gas mixture which forms hydrates of structure II (94 mol% methane and 6 mol% propane). Several different pressures and temperatures were investigated and the particle sizes measured during gas hydrate nucleation ranged from 2 nm to 80 nm, approximately, depending on the magnitude of the driving force.
Experiments were performed on both static and moderately stirred systems. The static experiments were difficult to reproduce both with respect to induction time and required driving forces. However, in the stirred experiments the reproducibility was much improved, especially at low temperatures.
Steam Heating of Fractured Formations Containing Heavy Oil: Basic Premises and a Single-Block Analytical Model
Authors: Pooladi-Darvish Mehran , Tortike W. S. , Farouq Ali S. M. 
Published: December 2007

ABSTRACTInterest in modeling thermal processes in naturally fractured reservoirs containing heavy oil has grown considerably because of encouraging results from experimental and theoretical studies as well as pilot tests. However, satisfactory predictive models are still lacking. This paper examines one component of such a model by studying a single block of a naturally fractured reservoir under steam injection, and presenting analytical solutions for heat flow and non-isothermal gravity drainage from the block.The fracture-matrix heat transfer is investigated first by analyzing the governing differential equations. It is found analytically that for a typical matrix block in the steam zone, the transient temperature distribution within a single block is not affected by convection. For physical properties other than those considered in this paper, it is shown that evaluation of the Peclet Number indicates the order of error that will be introduced if convection is neglected. This is found to be in the order of 1% for a typical fractured carbonate reservoir. Next, an integral method is used to obtain the transient temperature distribution within the block, which can be used directly for the heat consumption calculations. The temperature distribution is incorporated into an analytical equation to obtain the thermal drainage rate under gravity flow. The final equation is a relation between the physical properties of a single block and the flow rate in an easy-to-calculate form. The solution of the problem shows that using oil viscosity at average block temperature is adequate for recovery calculations during the heating period. These findings can be used in single block and fieldwide modeling of heat and fluid flow in fractured reservoirs, such as those in the Middle East.
Improving the Potential to Produce Oil from Naturally Fractured Reservoirs
Authors: Perez Jorge M. , Poston S. W. , Berg R. R. , Friedman M. , Gangi A. F. , Nighswander J. 
Published: December 2007

ABSTRACT
A multi-phase effort that involved geological, geophysical, and petroleum engineering studies yielded an improved understanding of naturally fractured reservoirs and potential manners to improve the incidence of oil production from such reservoirs.
Maps of fracture traces on bedding planes in the Austin Chalk outcrops showed organized trends of the fracture development and a hierarchical nature within the complete fracture system.
Vertical Seismic Profile, VSP data has been used to estimate fracture orientation from shear-wave splitting.
Well log responses in Austin Chalk wells have shown to be a reliable indicator of organic maturity. Well logs have also been used to calculate average resistivity of producing zones and to correlate resistivity with oil saturation and therefore with producing potential.
Additionally, the use of carbonated water imbibition displacement processes has shown encouraging results of accelerating and increasing oil recovery of oil which do not have appreciable asphaltene contents.
Theoretical/Experimental Considerations About Oil Displacement by Water in a Fractured Porous Medium
Authors: Perez-Rosales Candelario , Cruz-Hernandez Juana , Samaniego-V Fernando 
Published: December 2007

ABSTRACT
Based upon observations made with a two-dimensional porous cell, which allows direct visualization of fluid displacement processes, theoretical formulations were established for explaining oil displacement by water in a fractured porous medium. The theory rests on the idea that fluids are transported essentially through the fractures by a convective process, whereas water inflow to the matrix blocks is carried out by a dispersive process which depends on the difference between fracture and matrix water saturation. With these considerations, a derivation is presented of an expression for water saturation as a function of distance and time. Agreement between theory and experiment is reasonably good.
Application of a New Scale Up Methodology to the Simulation of Displacement Processes in Heterogeneous Reservoirs
Authors: Durlofsky L. J. , Milliken W. J. , Dehghani K. , Jones R. C. 
Published: December 2007

ABSTRACT
A general method for the scale up of highly detailed, heterogeneous reservoir cross sections is presented and applied to the simulation of several recovery processes in a variety of geologic settings. The scale up technique proceeds by first identifying portions of the fine scale reservoir description which could potentially lead to high fluid velocities, typically regions of connected, high permeability. These regions are then modeled in detail while the remainder of the domain is coarsened using a general numerical technique for the calculation of effective permeability. The overall scale up method is applied to the cross sectional simulation of three actual fields. Waterflood, steamflood and miscible flood recovery processes are considered. In all these cases, the scale up technique is shown to give coarsened reservoir descriptions which provide simulation results in very good agreement with those of the detailed reservoir descriptions. For these simulations, speedups in computation times, for the coarsened models relative to their fine grid counterparts, range from a factor of 10 to a factor of 200.
A Systems Approach to Completing Hostile Environment Reservoirs
Authors: Huntoon G. G. 
Published: December 2007

Abstract
The economics of developing a hostile environment reservoir should be able to support a high front end investment to make a completion commensurate with the risk. A completion scenario which uses current material technology and quality practices can influence the long-term cost of a completion design. A complete economic cost analysis would need to be performed to evaluate various completion scenarios. The well stream composition and reservoir performance data will help define the requirements for material selection and tubular sizing. Realistic quality plans and modem completion practices are necessary to successfully and economically complete current hostile environment wells. Amoco uses a variety of completion scenarios depending on the operating conditions. Amoco's experience using inhibitors and carbon steel in hostile environments has been excellent. With the emphasis on reducing long-term cost, the expanded use of higher alloy tubulars for production liners and tubing has been increasing. Concurrently, wellhead metallurgy and valve configuration has moved toward the higher alloy materials and larger diameters. Extensive planning is necessary to coordinate a successful completion. Good project planning will look at detailed tubular design, wellhead design, specifications and quality plans. One particular aspect of Amoco's tubular design is the use of a tubular quality level (TQL).
The current methodology of completing a hostile environment wells will be discussed from a knowledge base of evolving technology and project and quality planning.
Elimination of Near-Wellbore Tortuosities by Means of Hydrojetting
Authors: Surjaatmadja J. B. , Abass H. H. , Brumley J. L. 
Published: December 2007

Abstract
Near-wellbore tortuosity is one of many conditions that can cause additional friction pressure loss during the injection or production phase of a well. Production pressure loss reduces the potential production capacity of the well. In addition, difficulties with proppant placement are often attributed to the presence of tortuous fracture paths, which can lead to premature screenouts in the fracturing operation.
This paper discusses the importance of proper design and placement of perforations to obtain good fracture initiation. By doing so, optimal well production can be attained. Practical implementations of hydrojetting techniques as a substitute for the shaped-charge perforating process are discussed. The formation of tortuosities and the use of hydrojetting are demonstrated through laboratory tests. Hydrojetting tools that are used to achieve a fracture initiation from deviated or horizontal wells are also discussed.