bluuebunny/crossref_metadata_2025_split huggingface dataset:
Injection Well-Producer Well Combinations in THAI 'Toe-To-Heel Air Injection'
Authors: Xia T. X. , Greaves M. , Turta A. T. 
Published: December 2007

Abstract
THAI – ‘Toe-to-Heel Air Injection’ is a new, short-distance displacement process, that achieves high recovery efficiency by virtue of its stable operation and ability to produce mobilised oil directly into an active section of the horizontal producer well, just ahead of the combustion front. THAI, therefore, avoids the pitfalls inherent in most conventionally operated in situ combustion (ISC) processes, which employ vertical injection-vertical producer wells to achieve longdistance displacement. However, the problem of achieving efficient ignition and start-up still requires critical attention, in order to ensure optimal process operation.
A series of 3-D tests on heavy Wolf Lake crude (10.5 °API) and Athabasca Tar Sand Bitumen (8 °API) were made using well configurations: vertical (VI) or horizontal injection (HI) and horizontal producer (HP) wells in direct line drive (VIHP, HIHP); staggered line drive (VI2HP) and line drive (2VIHP). Experimentally, the horizontal injector configuration (HIHP) was found to be the most efficient for achieving rapid start-up, i.e. the shortest time to achieve stable combustion front propagation. However, injection of air via a horizontal well is not a very practical design for field operation. The single vertical injector configuration (VI2HP) was slow to achieve stable operation, due to the development of a much smaller ignition zone, initially, compared with the HIHP configuration. When hot air was used for ignition, the time delay for oil production is related to the reservoir temperature. When the initial temperature in the sandpack was 15°C, then a vertical injector, placed high in the sandpack, combined with a horizontal producer well (VIHP) achieved slower start-up than VI2HP for post-steam flood THAI, with the initial sandpack at 100°C. All of the tests achieved very high oil recoveries, averaging greater than 80% OOIP, except in the VIHP test. The recovery in the latter case was only 70% OOIP due to the loss of air injectivity during later stages of the combustion. Significantly, THAI also preserves the very substantial thermal upgrading which occurs in the mobile oil zone, averaging an increase of 6 to 8 API points.
Estimating Geomechanical Properties Using an Integrated Flow Model
Authors: Fanchi J. R. 
Published: December 2007

Abstract
The purpose of this paper is to show how to estimate geomechanical parameters for improved recovery and coalbed methane production processes using an integrated flow model. An integrated flow model combines a petrophysical model with a traditional flow simulator. The usefulness of reservoir geophysical information from an integrated flow model is discussed for the following scenarios: forecasting the reservoir geophysical response of CO2 injection in a mature oil field; estimating subsidence during depletion of an oil reservoir with a gas cap; and predicting the change in geomechanical properties during the life of a coalbed methane reservoir.
Full Field Simulation of Aquifer Interdiction in the Kern River Field, California
Authors: Baumann C. E. , Osterloh W. T. , Temple R. C. , Lolley C. S. 
Published: December 2007

Abstract
This paper describes an efficient numerical technique and reservoir model that were developed to simulate full field aquifer interdiction strategies for reducing water influx into the production area of the "Giant" Kern River Field. The main objective of the simulation is to optimize dewatering wells’ locations and rates to increase the thermal recovery efficiency by reducing the heat loss to the influx of bottom and edge water. Other benefits are accelerated reserve recovery and increased ultimate recovery.
A novel two-phase liquid-gas model with a two-component water-oil liquid phase was implemented. Of significant importance to this modeling effort is an accurate and efficient simulation of the free liquid-gas interface. This is due to the high pumping rates of the dewatering wells, which can produce up to 60,000 BWPD, with the consequent changes in the liquid-gas interface elevation. Such changes in turn affect the fluid pressure at a considerable distance from the interdiction wells, with the consequent change in the reservoir fluid flow. The liquid-gas interface is simulated with a numerical technique capable of tracking the liquid-gas interface across gridblocks. This numerical model delivers accurate simulations of the liquid-gas interface movement using relatively coarse grids, making possible to perform full field simulations on desktop computers.
Very good observation wells’ pressure matches have been obtained, and performance predictions indicate that at least 25% aquifer water interdiction efficiency is possible, with the consequent increase in thermal recovery efficiency.
An Alternative View of Filter Cake Formation in Fractures
Authors: Seright R. S. 
Published: December 2007

Abstract
A new model was developed to describe water leakoff from Cr(III)-acetate-HPAM gels during extrusion through fractures. This model is fundamentally different than the conventional filter cake model that was used during hydraulic fracturing. Even so, the model accurately predicted leakoff during extrusion of a guar-borate gel. Thus, the new model may be of interest in hydraulic fracturing.
For a Cr(III)-acetate-HPAM gel, pressure gradients and gel dehydration during extrusion were similar at 20°C, 40°C, 60°C, and 80°C. Similar gel dehydration behavior was observed over a three-fold range of concentration for Cr(III)-acetate-HPAM gels. During extrusion, measurements of pressure gradient versus HPAM concentration paralleled those of elastic modulus versus HPAM concentration.
In 0.04-in.-wide fractures, gel mobilization during brine injection (i.e, gel washout) occurred at pressure gradients similar to those during gel injection. In wider fractures (0.08-and 0.16-in.), Cr(III)-acetate-HPAM gels experienced mobilization at lower than expected pressure gradients. We explored how incorporation of particulate matter into gel affects washout from fractures. Shredded polypropylene and fiberglass insulation dispersed well in Cr(III)-acetate-HPAM gelants and gels. In contrast, mica, nut plug, diatomaceous earth, and celloflakes experienced severe gravity segregation. Incorporation of 0.1%-0.2% fiberglass insulation into Cr(III)-acetate-HPAM gels reduced gel washout during subsequent brine injection. However, improved formulations are needed to prevent washout for fractures that are wider than 0.08 in.
Analytical Matrix-Fracture Transfer Models For Oil Recovery by Hindered-Capillary Imbibition
Authors: Civan Faruk , Rasmussen Maurice L. 
Published: December 2007

Abstract
The previous matrix-fracture transfer models overlooked the effect of the fracture surface conditions on oil recovery by water imbibition. This paper presents an improved matrix-fracture-transfer model and approximate analytical solutions for waterflooding of oil reservoirs by hindered-capillary imbibition into matrix blocks surrounded by natural fractures. The rectangular and spherical type simpler shapes are considered to represent the matrix blocks formed by intersecting fractures. The immiscible displacement equations are simplified by means of the unit-end-point-mobility-ratio approximation and solved analytically. The restricted and hindered capillary imbibition phenomenon is considered in order to account for the finite-skin effect of the matrix block surfaces by various processes, including the formation of a stationary fluid film or an actual skin because of formation damage by various processes, such as deposition of minerals and other debris, and adverse rock-fluid interactions. Then, full scale, and short and long-term analytical solutions are presented and validated by experimental data.
By means of these analytical models, various laboratory experimental data are analyzed, and it is demonstrated that the condition of the matrix block surface is an important factor in hindering the rate of water imbibition into matrix blocks and the matrix-to-fracture oil expulsion, and therefore reducing the oil recovery factor. Comparison with previous simplified models shows that the present model is superior and can accurately predict the matrix-to-fracture oil transfer over the full range of the oil recovery period, while the previous models can only represent either the early- or the late-time behavior with limited accuracy. In addition, the effect of the reservoir rock wettability on the rate of oil recovery by hindered-capillary imbibition is investigated by means of the capillary dispersion coefficient, determined by correlating the experimental data using the new models. This study reveals that there is a strong relationship between the oil recovery factor and the capillary dispersion coefficient.
The analytical models developed here can be utilized for rapid prediction of oil recovery from naturally fractured reservoirs undergoing a water flooding process.
Impact of Fracture Permeability on Oil Recovery in Moderately Water-Wet Fractured Chalk Reservoirs
Authors: Graue A. , Nesse K. , Baldwin B. A. , Spinler E. A. , Tobola D. P. 
Published: December 2007

Abstract
The impact of fracture permeability on oil recovery from moderately-water-wet chalk has been determined. Nuclear Tracer Imaging was used to measure local fluid movement and to identify locations of trapped oil resulting from waterflooding a sleeved, fractured chalk block. Increasing the confinement pressure between experiments decreased the permeability of an interconnected fracture network for each sequential waterflood. The experiments showed that the dominant oil recovery mechanism was spontaneous imbibition, however, viscous oil recovery added significantly to the total oil production when the permeability ratio between the fractured system and the matrix was less than 20. The amount of oil viscously recovered increased as the fracture permeability decreased.
Improved Hydrocarbon Recovery in the United Kingdom Continental Shelf: Past, Present and Future
Authors: Jayasekera A. J. , Goodyear S. G. 
Published: December 2007

Abstract
Gas production from the UKCS commenced in 1967 and oil production in 1975. The North Sea area is now very much a mature province with the large fields in the Southern, Central and Northern North Sea producing at significantly below their early plateau production rates. Here the drive is to maximise the overall economic hydrocarbon recovery from the province, by making the best use of the infrastructure that has been built up to bring in new discoveries and improve recovery from the mature fields. New areas (deeper, harsher climate) are being opened up for exploration on the Atlantic Margin.
This paper reviews the evolution of the mature areas of the UKCS, with case studies to illustrate the technical challenges that have been overcome. Over the years government and industry have expended considerable resources in developing innovative techniques for improved hydrocarbon recovery. These range from developments in the application of EOR processes to advances in drilling and reservoir management technology, including novel seismic techniques to identify new or bypassed oil. Technological advances have also unlocked reserves in heavy oils and in high-pressure high-temperature (HPHT) condensate fields, which were left undeveloped until the 1990s.
Finally the potential for further exploitation and life extension of the UKCS as a significant hydrocarbon province will be reviewed. This will cover perceived technology gaps in opening up the new areas in deeper water, opportunities for redeveloping mature fields using new technology, combining IOR with carbon dioxide sequestration, and the need to drive down costs to be competitive in the international arena, while honouring environmental commitments.
Conditions for Foam Generation in Homogeneous Porous Media
Authors: Dicksen Tanzil , Hirasaki George J. , Miller Clarence A. 
Published: December 2007

Abstract
The generation of strong foam in homogeneous porous media has been reported to be a function of flow rate, pressure drop, permeability, and system length. This study seeks to explain foam generation in terms of dimensionless groups and establish the criteria for foam generation based on the mobilization of stationary foam lamellae.
Steady-state theories and experiments in the literature suggested the existence of a critical pressure gradient for foam mobilization that is inversely proportional to permeability. Experiments involving transient displacement of surfactant solution with gas injection, however, revealed a critical pressure drop that is inversely proportional to the square-root of permeability. The observation led to a new criterion for mobilization and foam generation in transient experiments, that the pressure drop across the displacement front must exceed the pressure drop to mobilize a single lamella.
Micromodel Studies of Polymer-Enhanced Foam Flow Through Porous Media
Authors: Romero C. , Alvarez J. M. , Müller A. J. , Bolívar U. Simón 
Published: December 2007

Abstract
In recent years the use of polymer-enhanced foams (PEFs) and gelled foams has become a focus of interest for gas shut-off control. Many studies have focused in evaluating the blocking ability and rheology of these PEFs before applying them in the field, but a bigger effort still has to be done in understanding the flow behavior of these fluids, which are much more complex in nature than conventional foams.
In this paper we present new micromodel studies that have been conducted with PEFs in constricted capillaries. Experiments were carried out using an alpha-olefin-sulfonate (AOS) foaming agent and five different polyacrylamides varying molecular weight, hydrolysis content and functionality. New data indicates that PEFs show a different flow behavior than that reported for conventional foams and that existing foam models may have to be reviewed to simulate PEF flow through porous media.
In 1992 Osterloh and Jante1 had identified for conventional foams the presence of two distinct flow regimes when flowing through porous media: a high quality regime where pressure gradient was independent of gas flow rate, and a low quality regime in which pressure gradient was independent of liquid flow rate. Alvarez, Rivas and Rossen2 later confirmed this to be a part of a general foam behavior.
In our studies, we found indications of the presence of these two foam flow regimes for conventional foams in constricted capillaries, while all PEFs showed under this geometry a completely different behavior, where the high quality regime seemed to be absent.
These results could indicate that capillary pressure and coalescence do not govern PEF flow in porous media, as it does for conventional foams. Micromodel studies however, might not be directly applicable to flow in real reservoir conditions, but implications of the results here published could be useful in understanding the behavior of these fluids. Due to the simplicity of the pore geometry, these results can also assist in the evaluation of existing foam flow models for PEF flow, or in the future development of new models to understand the physics involved in the flow of these complex fluids through porous media.
Improved Oil Recovery by Flank Waterflooding in the Lagunillas 07 Reservoir, Venezuela: A Case Study
Authors: Agbon I. S. , Ramones M. , Patniyot S. , Chang R. , Chek-Yan N. 
Published: December 2007

Abstract
The Lagunillas 07 reservoir is located Lake Maracaibo in Venezuela. The reservoir contains the Laguna, Lagunillas and La Rosa formations. The sands are of the Miocene age, poorly consolidated, well sorted and fine-grained. The oil had an 18° API and a viscosity of 21 cp at initial conditions. Oil production began in 1926 and more than 1,000 wells have been drilled. Flank waterflooding, at an average water injection rate of 100,000 stb per day, was introduced for pressure maintenance purposes in 1984. By December 1999, cumulative water injected was 558 million barrels and 36.7 % of the initial oil in place had been produced.
This paper evaluates the impact of the flank waterflooding project in the Lagunillas 07 reservoir. The net oil recovery due to the flank waterflooding is estimated. The real time water front movement is determined with a front-tracking technique that uses fluid production data. The movement shows water fingering due to reservoir heterogeneity. A good match is obtained when the water front movement is cross-correlated with the petrophysical properties of the reservoir. Finally, the impact of the flank waterflooding on recovery factor is highlighted.
The paper concludes that a net oil recovery of 17 million barrels can be attributed to the flank waterflooding from 1984 to 1999. A net oil recovery of 160 million barrels is expected if the flank waterflooding is continued until 2019. The flank waterflooding is therefore considered a success. A future development plan is proposed for the reservoir.
A Guide to High Pressure Air Injection (HPAI) Based Oil Recovery
Authors: Moore R. G. , Mehta S. A. , Ursenbach M. G. 
Published: December 2007

Abstract
In recent years, high pressure air injection (HPAI) has proven to be a valuable IOR process, especially in deep, high pressure, low permeability fields where other recovery processes are uneconomic.
This paper will provide engineers and engineering managers with a wide-ranging look at the key factors that should be addressed when considering a high pressure air injection (HPAI) based IOR process in a light oil reservoir. The paper is based on many years of involvement of the authors both in the laboratory and the field, as well as drawing on published literature.
The main focus is on key design and operating criteria that must be considered, including reservoir screening, air injection design, ignition, and monitoring. The benefits and potential risks of HPAI are also discussed.
Along with the discussion of design and operating criteria, the paper contributes significantly in the comparison of oxidation/combustion kinetics for light oils versus heavy oils (HPAI versus in situ combustion), as well as in a discussion of the oil mobilizing effects of a gas flood compared to an advancing thermal (combustion) front.
Time-Dependent Shape Factors for Secondary Recovery in Naturally Fractured Reservoirs
Authors: Penuela G. , Hughes R. G. , Civan F. , Wiggins M. L. 
Published: December 2007

Abstract
An accurate interporosity flow equation incorporating a time-dependent shape factor is derived and verified for improved dual-porosity modeling of waterflooding in naturally fractured reservoirs. This equation expresses the interporosity exchange rate in terms of the oil phase pressure gradient in the matrix, fracture surface area, fluid effective permeability at the matrix/fracture interface, fluid viscosity and a variable matrix-block shape factor. This approach can accommodate the flow directed from matrix to fractures while representing the permeability of interconnected fractures as a tensor. The model equations are expressed in dimensionless form for convenient integration into present numerical simulators for accurate simulation of waterflooding in naturally fractured reservoirs. These features distinguish this model from the conventional sugar-cube modeling of naturally fractured reservoirs.
Fine-grid numerical simulation of a matrix block is performed to verify the flow equation using the time-dependent shape factor. Numerical experiments with various size matrix blocks indicate the shape factor varies with time and converges to the steady-state shape factor value reported in previous studies for single-phase flow. The shape factor for single-phase flow converges to a steady-state value at a speed proportional to the reciprocal of total compressibility, while the shape factor for two-phase flow converges at a speed proportional to the slope obtained from the capillary pressure curve evaluated at the average water saturation present at the matrix/fracture interface. Therefore, the single-phase shape factor converges much more rapidly to its steady-state value than the two-phase shape factor.
This study demonstrates that neglecting the time-dependency of the shape factor introduces significant errors in fractured reservoir simulation, and time-dependent shape factors are needed because of the variation of the water saturation front location in the matrix block, which moves from the fracture face to the block-center as the water flows from the fracture into the matrix.
Effects of Stimulating Indigenous Bacteria in Oil Reservoirs on Relative Permeability Curves
Authors: El Ela M. Abu , El-Tayeb S. , Sayyouh M. H. , Dayem M. Abdel , Desouky S. 
Published: December 2007

Abstract
Laboratory studies show the existence of some strains of bacteria in field crude oils and formation waters. This work is concerned with studying the effect of indigenous bacterial activities on the relative permeability of samples from Egyptian fields. Such study is an original contribution to the knowledge of microbial enhanced oil recovery.
Phase volume studies were carried out using two types of crude oils having different spores forming bacteria. The relative permeability experiments were conducted in sandstone cores. Some available nutrient solutions being used in the field tests were also used.
Based on the phase volume measurements, it was found that the indigenous microbial growth was better after two days incubation time with 1% molasses concentration as a nutrient. Residual oil saturation was found to decrease with stimulating the indigenous bacteria in the crude oils by using 1% molasses concentration. Presence of 1% molasses concentration increases the relative permeability to oil. It was found also that crude oil A, which contains Clostridium sp. and Bacillus sp., gave better relative permeability curve behavior than that of crude oil B, which contains Bacillus sp. only. Salinity increase decreases the relative permeability to oil. In the presence or absence of molasses, no clear trend of absolute permeability on oil-water relative permeability curves was observed.
The results obtained are discussed and analyzed in terms of the system phase variation, interfacial forces, wettability characteristics, hydrogen ion concentrations, viscosity effects, and mechanical and mineralogical analysis of the cores.