bluuebunny/crossref_metadata_2025_split huggingface dataset:
Brassey Field Miscible Flood Management Program Features Innovative Tracer Injection
Authors: Anderson J. H. , Laurie R. A. , Loder W. R. , Kennedy Paul 
Published: December 2007

ABSTRACT
An extensive reservoir management program in a hydrocarbon miscible flood has allowed the reservoir team to stay abreast of reservoir performance and to influence ultimate recovery of oil.
A key component of this program, operated by Canadian Hunter Exploration Ltd. at the Brassey miscible flood in British Columbia, included the downhole manufacture of tritiated methane as part of an innovative tracer injection program. Other technical elements in the reservoir management program include frequent pressure surveys, volume monitoring, and compositional analysis.
Teamwork between geologists, reservoir engineers, production/facilities engineers, and field operations staff was absolutely essential to the success of the program.
Reservoir Potential of Thin-Bedded Turbidites: Prospect Tahoe
Authors: White C. D. , Bradburn F. R. , Brown R. L. , Thieme M. A. 
Published: December 2007

Abstract
Geological/Petrophysical modeling, production testing and pressure transient analysis have demonstrated that thin-bedded turbidites can be very productive and have large connected volumes at Prospect Tahoe. This offshore Alabama field (water depth = 1,500 ft) occurs as a northwest-southeast trending turbidite channel/levee complex and is predominantly a gas reservoir with a thin oil rim. There is a relatively large volume of geological and engineering data for this thin-bedded turbidite deposit. In addition to a 3-D seismic survey, there are seven exploratory penetrations (three with whole core), a production test, and PVT analyses from several samples. The hydrocarbon accumulation exhibits a proven hydrocarbon column height in excess of 700 feet over an area greater than 4,000 acres. The reservoir depth at Tahoe is about 10,000 feet subsea, and initial reservoir pressure is about 5,000 psia.
A 100 foot cored interval was completed and production tested, attaining a stabilized rate of 29 MMCFPD for three days. The subsequent five-day downhole shut-in exhibited persistent radial flow, indicating permeability-thickness of 1,700 md-ft and a connected area in excess of 520 acres. In the production test interval, over 1,400 individual beds were identified from whole core. The average sand bed thickness is less than 0.5 inches, and no sand bed exceeds three inches in thickness.
This interdisciplinary study demonstrated that thin-bedded turbidites can be successfully tested, be very productive, and have large connected volumes. This work may have analog application elsewhere.
Relative Permeability at Low Interfacial Tensions
Authors: Ronde Hidde 
Published: December 2007

Abstract
This paper shows that condensate trapping in a retrograde reservoir upon pressure depletion can be described by capillary condensation of a near-critical fluid in hydraulic channels with a permeability in the (tens of) milidarcy range(in contradistinction to capillary condensation for non-near-critical fluids, which occurs in the microdarcy range).
The Porous medium is modeled as a bundle of hydraulic channels, the smaller of which show Bing-hamian condensation, whereas the bigger ones show two-phase flow in a core-annular regime (often called filmflow).
Both phenomena can be explained by the supposition that a Cl-C3 near-critical fluid system goes through a Cahn transition(at an IFTc1-c3 = 0.3mN/m), the latter value being based on pendant drop-measurements on a 2,6-lutidine-water model system and the application of critical scaling principles.
A Cahn transition into a perfect wetting regime is not just a transition from very good wetting to perfect wetting in the capillary sense.This is a consequence of the fact that for near-critical fluids in thermodynamic equilibrium the solid(channel) wall is an essential part of the system that is in thermodynamic equilibrium, leading to a redistribution of phases in the capillaries (now hydraulic channels), whereas the spreading coefficient becomes essentially zero for such a system. When viscous forces are dominant this leads on its turn inside the Pressure-Composion Cl-C3-(Berea) phase envelope to a core-annular ("film-flow") regime for the bigger channels. The smaller ones go upon pressure depletion through a noticeable transition region outside this envelope, (where the effect for the larger ones can be neglected) causing Binghamian condensation. At the Cahn transition inside the envelope relative permeability curves of the Cl-C3(Berea) system straighten shockwise.In the filmflow-regime an Einstein emulsion contribution to relative permeability is clearly identifiable at the saturation extremes leading to asymétrie straightening of the relative permeability curves.
A Pore-Level Scenario for the Development of Mixed Wettability in Oil Reservoirs
Authors: Radke C. J. , Kovscek A. R. , Wong H. 
Published: December 2007

Abstract
Understanding the role of thin films in porous media is vital if wettability is to be elucidated at the pore level. The type and thickness of films coating pore walls determines reservoir wettability and whether or not reservoir rock can be altered from its initial state of wettability. Pore shape, especially pore wall curvature, is an important factor in determining wetting film thickness. Yet, pore shape and the physics of thin wetting films are generally neglected in models of flow in porous rocks. This paper incorporates thin wetting film forces into a collection of capillary tubes model to describe the geological development of so-called mixed-wettability in reservoir rock. Our model emphasizes the remarkable role of thin films.
New pore-level fluid configurations arise that are quite unexpected. For example, efficient water displacement of oil (i.e., low residual oil saturation) characteristic of mixed-wettability porous media comes about due to interconnected oil lenses or rivulets which bridge the walls adjacent to a pore corner.
Predicted residual oil saturations are found to be approximately 35 percent less in mixed-wet rock when compared to completely water-wet rock. Calculated capillary pressure curves mimic those of mixed-wet porous media in the primary drainage, imbibition, and secondary drainage modes. Amott-Harvey indices range from −0.18 to 0.36 also in good agreement with experimental values1,2.
Impact of Section 29 Tax Credits on Unconventional Gas Development and Gas Markets
Authors: Haas M. R. , Goulding A. J. 
Published: December 2007

Abstract
This paper provides some context and an empirical basis to evaluate the historical and potential impact of Section 29 production tax credits on the development and production of unconventional gas resources (UGR). The data, analyses and conclusions reported here are based on studies conducted for government and industry clients over the past two years.
The federal government implemented incentive pricing and Section 29 production tax credits over a decade ago as the principal policy tools to accelerate development of UGR. Given the large expected potential contributions of tight gas, coalbed methane and Devonian shale gas, these incentives were designed to reduce risk and improve project economics of these "high-cost" gas resources.
Despite the fundamental transformation of the gas industry over the past decade, however, the Section 29 credit has not changed in scope or mechanism since its inception in 1980. Critics of the credit allege that, during a time of significant changes in the characterization of the gas resource base, extraction technology effectiveness, gas markets, wellhead prices, and pipeline regulation, the credit has changed from a modest incentive to a major cause of market distortion.
The results of two recent studies are discussed that provide a basis for more rational debate about the merits of eliminating or extending the credit, in either its current or an alternative form. The first study1 addressed allegations that Section 29 credits were responsible for widespread wellhead gas price declines in 1991. After looking at supply, demand, transportation and market behavior for UGR-prone basins during 1991, we conclude that Section 29 credits had only a minor direct affect on wellhead prices.
The second study2 addressed the potential for an alternative configuration of the credit to restore the credit's originally intended impact. Alternative configurations of the credit are offered as a means to adhere to original Congressional intent for the credits, maximize efficiency and equity and minimize costs to the U.S. Treasury. Selection of an optimum credit configuration, however, first requires a clear specification of federal policy objectives.
Sorting Equiprobable Geostatistical Images by Simplified Flow Calculations
Authors: Guerillot D. R. , Morelon I. F. 
Published: December 2007

Abstract
Various geostatistical models have been proposed to generate possible descriptions of the internal structure of heterogeneous reservoirs. For actual reservoir engineering studies, there are practical problems in dealing with large numbers of possible images. This paper proposes an efficient way of sorting the images, accounting for dynamic criteria, allowing a few images to be selected for detailed study.
The method consists in performing simplified reservoir simulations in which the pressure field is held constant in time, rather than being updated at each time step. The pressure field used is calculated by assuming a steady state flow within the reservoir but using the actual boundary conditions (well rates or pressures). The saturation evolution takes into account the multiphase parameters. In this paper, it is shown that these simplified simulations are sufficient to sort the images for a model problem. Here, the criteria used are the breakthrough times and the oil productions.
The advantage of this approach is that significantly less computer time is needed to perform the simplified simulations than the full simulations. This makes it possible to run simplified simulations for many equiprobable images in order to find the extreme behaviors. Some images are then selected for complete simulations. In addition, a working methodology is proposed to determine the number of geostatistical descriptions to be considered.
Developing Gas Reservoir Descriptions Through Multiwell Performance History Matching: Case Histories From Oklahoma’s Anadarko Basin
Authors: Gunter G. W. , Jones J. R. 
Published: December 2007

Abstract
Though history matching of multiwell performance using numerical simulators is a common method of developing reservoir descriptions for oil fields, it is rarely used for gas producing areas. This is appropriate when gas well performance follows conventional theory. When BHP/Z versus cumulative production curves are nonlinear the use of simulation can provide great advantages. This paper illustrates how history matching well by well 72-hour shut-in BHP/Z versus cumulative production plots in a full field numerical simulator is used to develop a complete reservoir description for two gas-producing horizons in Oklahoma’s Anadarko Basin. Such performance data from a 31 well field in the Penn-sylvanian-aged Red Fork sandstone and a 49 well field Mississippian-aged Britt sandstone field were matched using an in-house multiwell gas reservoir simulator. This paper describes the match of the data from the 31 well Red Fork reservoir. This work has significantly improved our understanding of the importance of nonlinear BHP/Z versus versus cumulative production. Using detailed numerical simulation allowed us to account for layering, boundaries, areal property variations, curtailment and offset well effects.
The resulting reservoir description was used with the simulator to identify and/or evaluate infill drilling locations, optimize reserves by exploring various reservoir management options, and to monitor the effects of competitive lease line position to protect reserves. As a direct result of this study, more than 50 BCF of reserves were protected or exploited. The model predictions of future performance are shown to accurately match subsequently measured actual well BHP/Z points for both infill and existing locations. Thus, the reservoir description has proven itself to be a powerful reservoir management tool.
Automatic Waterflood History Matching Using Dimensionless Performance Curves
Authors: Carlson F. M. , Stein M. H. 
Published: December 2007

Abstract
An automatic history matching technique has been developed and tested. A reservoir simulator is used to generate single-layer predictions of performance for volumetric depletion and waterflooding of patterns typically used in a field. To accommodate the effect of a varying initial gas saturation, waterflood predictions are made at several different initial gas saturations at the start of waterflooding. These results are converted in dimensionless form and used to generate multilayer predictions. Nonlinear regression is then used to change the reservoir description until a satisfactory match of historical performance is obtained. While this technique strictly applies only to reservoirs in which crossflow between reservoir layers is negligible and in which vertical heterogeneities dominate areal heterogeneities, it’s more general application is discussed. In addition to being automatic, the technique takes only a few CPU seconds on an IBM 3090 for a typical application.
Comprehensive testing under the assumed developmental conditions is presented. Nonuniqueness aspects of kh and rw are also discussed.
The effects of infill drilling in the history of a reservoir can be accommodated by the technique. Infill drilling is handled by making single-layer waterflood numerical simulations of infill drilling at various levels of pore volumes of injected water prior to infilling.
Testing of the new technique with field data showed good agreement with field data and a multilayer reservoir simulator prediction for the initial stages of waterflooding. It is demonstrated that the infill performance of a reservoir layer with a free gas saturation at the time of infill drilling is somewhat dependent on the gas saturation.
Analysis of Reinfiltration in Fractured Porous Media
Authors: Barkve Tor , Firoozabadi Abbas 
Published: December 2007

ABSTRACT
A scaling of the two-phase, two-dimensional flow in an anisotropic matrix block is proposed. The scaling allows analysis of the reinfiltration process in a matrix block and the study of the influence of gravity, capillarity and matrix block dimensions on reinfiltration and drainage rates. An approximation for the maximum drainage rate of a matrix block without segregation assumption is also derived.
The main conclusion of this paper is that the combination of gravity and capillarity forces generally provides conditions for a pronounced reinfiltration process in fractured porous media.
Effect of Crossflow on Sweep Efficiency in Water/Oil Displacements in Heterogeneous Reservoirs
Authors: Fitzmorris R. E. , Kelsey F. J. , Pande K. K. 
Published: December 2007

ABSTRACT
Fluid crossflow can significantly affect sweep efficiency in heterogeneous reservoirs. The importance of fluid crossflow relative to purely longitudinal convective transport in a two-dimensional setting depends on several factors. Rock properties such as porosity, permeability, the ratio of vertical to horizontal permeability, and length scale of correlation are important factors. Fluid properties such as phase densities, phase viscosities, and interfacial tension are also factors. Coupled rock-fluid properties, for example, wettability, relative permeabilities, and capillary pressure are also factors. In addition to these factors, flow velocity, system dimensions, and boundary conditions also affect sweep efficiency. In this paper we examine the role of capillary forces, in addition to viscous and gravity forces, on sweep efficiency of immiscible displacements in a heterogeneous porous medium. A fully implicit, black oil, reservoir simulation model was used to compute displacement performance in two-dimensional, fine-grid (x-z) cross-sections. The results presented in this paper clearly show the importance of capillary crossflow as a recovery mechanism, in addition to viscous and gravity crossflow, in displacements in heterogeneous reservoirs.
The Impact of Errors in Measurements of Coalbed Methane Reservoir Properties on Well Production Forecasts
Authors: Zuber M. D. , Olszewski A. J. 
Published: December 2007

ABSTRACT
This paper presents the results from two simulation parametric studies of coalbed methane well forecasting techniques. Phase I qualitatively identifies the relative impact of key reservoir properties, and rank orders them. Phase ∏ uses a Monte Carlo simulation approach to quantify the degree of confidence associated with coalbed methane well forecasts for two sets of distributions of key reservoir properties. Results indicate that the range of error associated with the best currently-available reser- voir property measurement techniques significantly impedes the engineer’s ability to accurately forecast production with confidence, and points to the need for improved measurement accuracy for key reservoir properties.
Failure of Chalk During Waterflooding of the Ekofisk Field
Authors: Teufel L. W. , Rhett D. W. 
Published: December 2007

Abstract
A full-field water-injection program for enhanced oil recovery is being conducted in the Ekofisk field, a naturally fractured chalk reservoir in the North Sea. The effect of waterflooding on reservoir behavior has been directly observed in a well that was drilled into an area of the field that has been swept by the waterflood. Measurements of pore pressure, temperature, and in situ stress in this well show that injection of cold seawater at high rates and pressures has locally repressurized the reservoir and reduced reservoir temperature, which in turn has decreased the principal effective stresses. Failure envelopes derived from laboratory compression tests of reservoir chalk indicate that the resultant deviatoric stress is sufficient to cause shear failure of chalk and slippage of fractures. Intense fracturing in repressurized zones of this well observed in logs and core support this conclusion. Large increases in reservoir permeability measured in well tests conducted before and after waterflooding indicate the extensive nature of waterflood-induced fracturing. It is likely that waterflood-induced fracturing has contributed to the very good performance of the Ekofisk waterflood. Waterflood-induced fracturing has increased fracture density and fracture surface area and reduced matrix block dimensions in reservoir chalk, and thereby increased imbibition rates and waterflood sweep efficiency.
The Effect of Capillary Connectivity Across Horizontal Fractures on Gravity Drainage from Fractured Porous Media
Authors: Stones E. J. , Zimmerman S. A. , Chien C. V. , Marsden S. S. 
Published: December 2007

Abstract
Experimental results for gravity induced drainage from fractured porous media are presented which explore the effect of varying the number of fractures in a given height of medium, the overburden pressure experienced by fracture blocks, and the cross-sectional area of contact between fracture blocks on drainage rate and eventual recovery. Drainage rate and eventual recovery may be increased by a greater overburden pressure, and fewer fractures for a given height of medium. In some cases these factors may also be increased by reducing the cross-sectional area for flow across me fractures. Data are also presented which compare these factors for two different types of rocks. Computer Aided Tomography (CAT scan) results are used to determine saturation profiles for systems of six and twelve fracture blocks. From this work, the effective cross-sectional area of capillary contact across horizontal fractures is identified as a critical factor in both vertical drainage rate and cumulative production from fractured porous media. This experimental basis is then used to explore effective cross-sectional area as a parameter for simulation, which could ease computational requirements for drainage simulation.
Engineering Evaluation and Performance Analysis of the Loop Gas Storage Field
Authors: Wells J. A. , Evans L. J. 
Published: December 2007

Abstract
This paper describes a reservoir performance evaluation of the Yates Sand system underlying the Loop Gas Storage Field, Gaines County, Texas. A PC based numerical simulator was utilized to build a three-dimensional, two-phase operating model for the Yates Sand system. In the course of the study, the reservoir model evolved from a preliminary representation to a validated working model of the field. The model was initially constructed from digitized reservoir data and then adjusted to yield an accurate reproduction ("history match") of the past reservoir performance from both primary depletion and storage operations. After simulating a primary recovery of 12.45 BCF from a reservoir originally containing 13.25 BCF of gas at a discovery pressure of 2841 psig, additional wells were placed in the model and converted for storage calculations. A successful match of the 1981-1989 storage history yielded a Yates Sand system characterization consisting of a main storage zone (C2) and a lower collector zone (C3) which was not currently in communication with the storage wellbores. Several model cases were designed and run to evaluate current field deliverability and future enhancement potential. Based on this model, the storage field has been expanded from a deliverability of 50 MMCF/D and a working gas of 5.0 BCF to a deliverability of 200 MMCF/D and a working gas of 9.4 BCF, with 2.625 BCF of cushion gas being converted to working gas.
Gas Storage Caverns in East Yorkshire Zechstein Salt: Some Geological and Engineering Aspects of Site Selection
Authors: Knott Iain , Cross K. G. 
Published: December 2007

Abstract
Natural gas has been stored in underground salt cavities in the UK since 1979: for ‘peak shaving’ purposes to supplement demand from the high pressure National Transmission System. Solution mining of the salt cavities began in 1974. This existing facility is known as the Hornsea Installation and is located on the East Yorkshire coast.
The identification of the need for an additional greenfield storage site, together with the geological problems encountered at the Hornsea Installation led to a geological appraisal of the Permian Zechstein salt along the coastal strip of East Yorkshire.
The paper briefly describes the process facilities and engineering requirements at the existing facility for development of salt cavities and then summarises the criteria that were established in a feasibility study, to select a new site location.
A geological evaluation of existing well control and available seismic data in the coastal area was carried out on the basis of required thickness of salt and purity. The paper highlights the results of this study concentrating on the use and limitations of existing seismic and borehole data in quantifying and modelling loss of salt in the At wick 4 well at Hornsea and the inability to detect highly soluble carnalitic salts using seismic methods.
Seismic analysis has indicated that several potential sites previously thought to have been acceptable are now considered as unsuitable for cavern development but the identification of a suitable site in a previously unconsidered area to the South has reduced associated geological risks for cavity development.