bluuebunny/crossref_metadata_2025_split huggingface dataset:
Techniques for Temporary Stabilization of Formations
Authors: Himes R. E. , Parker M. A. , Simon D. E. 
Published: December 2007

Abstract
Application of a class of organic molecules provides highly effective temporary formation stabilization while well completion and stimulation fluids are in contact with the formation. These molecules are more effective than commonly used inorganic stabilizers (salts) and can be used in much lower concentrations. As liquids, the method of application results in more efficient utilization and reduces the potential for negative environmental impact.
Literature is plentiful on the subject of temporary formation stabilization by applying inorganic cation to treating fluids to maintain a neutral net surface charge on clay surfaces. In the past, this has been done by the use of salts, such as potassium chloride. Unfortunately, inorganic cations with the necessary properties to stabilize formations as effectively as the aforementioned organic compounds are rare and impractical for large volume applications. A large-scale study of stabilization qualities of a number of these compounds was undertaken to obtain definitive performance data.
Subject paper reviews clay Stabilization theory and chemical theories on which research was based, describes research performed, and presents temporary formation stabilizers for use in well completions and stimulation operations. Results of field application of these organic formation stabilizers and benefits to improved fracturing efficiency and environmental impact will also be presented.
Viscous Fingering, Gravity Segregation, and Reservoir Heterogeneity in Miscible Displacements in Vertical Cross Sections
Authors: Araktingi U. G. , Orr F. M. 
Published: December 2007

Abstract
Combined effects of gravity segregation, viscous fingering and reservoir heterogeneity are examined in particle-tracking simulations of flow in vertical cross sections. Differences in model formulation from previous descriptions are reviewed briefly. The accuracy of the simulation representation of the physical flow mechanisms is tested. For homogeneous cross sections, simulator calculations are presented that illustrate the transition from flow in a single gravity-dominated tongue at low viscous to gravity ratio (Ngr) to flow dominated by viscous fingering at high values of Ngr. Quantitative accuracy of the simulator is tested against the experimental results of Pozzi and Blackwell. Simulation results agree with experimental results over wide ranges of mobility ratio, viscous to gravity ratio, and aspect ratio. Additional simulations also agree well with Stalkup's correlation of breakthrough recovery as a function of mobility ratio and Ngr.
The validated simulator is then used to augment Stalkup's correlation with results for additional mobility ratios. In addition, plots are presented of recovery after breakthrough as a function of Ngr for several mobility ratios. The results confirm that in homogeneous porous media, better displacement performance is observed at high viscous to gravity ratio for any mobility ratio. For heterogeneous porous media, however, that conclusion must be qualified. Example simulation results show that for injection of light solvent into a layered reservoir with high permeability low in the reservoir, better displacement efficiency is observed at intermediate values of Ngr than at high or low values. If the high permeability is at the top of the reservoir, high Ngr is still preferred.
Three-Phase Relative Permeability of Water-Wet Berea
Authors: Oak M. J. 
Published: December 2007

Abstract
Two-phase and three-phase relative permeabilities of water-wet Berea sandstone have been studied exper-imentally. Eight cases of saturation history have been investigated. About 1800 data have been collected using the steady-state method: about half of them for two-phase flow and the other half for three-phase flow. The experimental results are compared with predictions by Stone's methods.
Stone's predictions of three-phase oil relative permeability are unsatisfactory. The experimental data do not support the assumption that two-phase relative permeability data can be used to predict three-phase relative permeability with a similar saturation history. The data suggest that displacement of trapped oil by gas is an important factor affecting three-phase oil permeability. It is also suggested that there exists a critical oil phase saturation to initiate three-phase flow from water-oil two-phase flow, which can be different from that in the two-phase flow. The prediction methods fail to account for these factors.
Study of the Mechanisms of Carbon Dioxide Flooding and Applications to More Efficient EOR Projects
Authors: Haynes S. , Alston R. B. 
Published: December 2007

Abstract
The mechanisms of carbon dioxide flooding at pressures below the minimum miscibility pressure (MMP) were studied using a numerical model of a slim tube to determine a means of increasing the efficiency of such floods. Results of these studies indicate that, in multiple contact flooding (MCF), the gas phase at the liquid-gas front approaches a constant composition denoting a bank of solvent approaching conditions of miscibility, but not achieving it because of the quantity of methane, nitrogen, and other light gases that overwhelms it. The ethane plus components (C2+) composed approximately five percent of the reservoir gas phase. This constant compositional gas phase formed early in the flood and persisted throughout the flood until eventual gas breakthrough.
A simulated low-temperature flash of the reservoir gas phase produced a solvent that contained more than 75 percent ethane and propane. Slugs of this solvent were used to produce miscible displacements with CO2 gas at pressures 40 percent below the MMP. These findings were confirmed in further studies using fluids from several other reservoirs.
The Effect of Microscopic Heterogeneity on CO2-Foam Mobility: Part 2-Mechanistic Foam Simulation
Authors: Chang S. H. , Owusu L. A. , French S. B. , Kovarik F. S. 
Published: December 2007

ABSTRACT
CO2-foam flow mechanistic studies (Part 1 in JPT1) continue to be concerned with (1) the visualization of high-pressure gas/oil/surfactant solution flow through glass micromodels which helps determine the principal oil recovery mechanisms at the pore level during CO2-foam displacement at reservoir conditions. (2) high-pressure, foam coreflood displacements to generate new physical correlations which can be used in field studies, and (3) the development of a generalized, mechanistic foam flood simulator.
Flow visualization experiments have been run to compare the performance of in-situ-generated foam displacements with water-alternate-gas displacements. Also, displacements comparing pregenerated and in-situ-generated foam have been performed. For heterogeneous models in the presence of crude oil, increasing flow rates resulted in improved sweep efficiencies for both pregenerated foam and in-situ generated (simultaneous injection) foam strategies. For WAG displacements, increasing flow rates decreased recovery. WAG displacements demonstrated, on average, the poorest sweep efficiencies. For the layered (communicating zone) model, it was observed that static or leave behind lamellae were not as effective in zone blockage and fluid diversion as a dense foam in the presence of oil.
A new foam coreflood apparatus was constructed and is being used to investigate CO2/foam systems. Coreflood experiments were run with (1) simultaneous injection of CO2 and brine, and (2) simultaneous injection of CO2 and surfactant solution into Berea sandstone. The cores were initially saturated with brine. Pressure drop and effluent volumes were matched with the new foam-flow model, thus fixing physical correlation free parameters. A new correlation has been proposed for the relationship between gas mobility and gas fraction, interstitial gas velocity, surfactant concentration, and oil saturation.
The two-dimensional, mechanistic, foam-flow-in-porous-media model is presented. Here, foam is generated by the following mechanisms: snap-off or lamella division, and leave-behind, all of which are included in the simulation. In addition, foam coalescence and trapping processes are incorporated in the simulator. The model can represent many of the mechanisms associated with high-permeability zone blockage, fluid diversion, and increased trapped oil recovery.
Foams for Effective Gas Blockage in the Presence of Crude Oil
Authors: Hanssen J. E. , Dalland M. 
Published: December 2007

Abstract
A study of foams for possible application in a new process with a potential for improving production from thin oil rims by formation of effective barriers against gas coning is reported. A total of 48 foaming agents for aqueous and non-aqueous systems have been evaluated using a gas-blockage test, as well as bulk foam stability tests and measurements of relevant surfactant properties. All experiments were performed in contact with sea water and crude oil at elevated temperature. In the gas-blockage test, foam is generated in 2-m long, 8.5-µm2 bead packs by constant-pressure displacement of a surfactant solution by gas at residual oil saturation. Stabilized gas rates through the foam-filled glass-bead pack are subsequently measured as a function of stepwise increasing pressure gradients. Only 4 foams were found capable of reducing gas permeability to the order of 0.1 µm2 or lower, at pressure gradients of 1 to 5 bar/m. These four products were found to be effective also in long-term tests at a constant pressure gradient of 1.5 bar/m. A number of foams known to be efficient gas-blocking agents in oil-free media were non-blocking in presence of residual oil. Bulk stability could not predict the gas-blocking ability for the foams studied. Further, no correlation was found between foam gas-blocking ability and the interfacial tensions, spreading conditions, oil saturation, foam quality, surfactant oil solubilization, or relative wetting abilities of surfactants measured. The four successful products found are fluorinated surfactants, from three different manufacturers, and were effective at 0.5 to 1 wt% concentration. Several fluorinated surfactants failed the gas-blockage test. Possible relations between observed gas-blockage performance and other properties are discussed. The phenomena involved appear to be complex and no clear relation between surfactant properties and foam performance has been found. Speculation is offered on what may be the controlling factors for foam gas-blockage efficiency.
Mathematical Modeling of Foam Flooding
Authors: Fisher A. W. , Foulser R. W. S. , Goodyear S. G. 
Published: December 2007

ABSTRACT
In studying the flow of foam in unconsolidated porous media Khatib et al have shown that the destruction of foam lamellae depends on the gas/surfactant solution flowrates, fluid mobilities, and rock capillary pressure. This paper examines this flow regime, which we call the coalescence regime, in more detail. We have found that all published data referring to foam flow in consolidated media are consistent with a generalisation of Khatib's model. This new model is described in this paper.
Two and three phase steady-state foam mobility models have been developed which exploit the dominant role of the foam coalescence mechanism. These models are based on published data for foam flow. The mobility models are then used in a finite difference, three phase, multi-component simulator. The simulator is applied to show that it can reproduce the generic transient foam behaviour observed in core floods. Calculations are then used to examine some of the important issues that have to be considered when designing field applications of foam flooding.
Steam Circulation in Horizontal Wellbores
Authors: Best D. A. , Lesage R. P. , Arthur J. E. 
Published: December 2007

ABSTRACT
A model to evaluate heat losses, steam quality and pressure profiles during steam circulation in a wellbore has been developed. The model's unique ability to simulate countercurrent flow streams accounts for the interactions of heat transfer, fluid flow, phase changes, slippage between steam and water, and flow regime changes. It is based on the conservation equations of mass, momentum and energy. The energy conservation equations can account for heat transfer in a stagnant annular gas blanket as well as the transient heat loss to the overburden and the reservoir.
The mixture densities and frictional pressure drops were evaluated from two phase flow correlations. The heat transfer from the flowing streams was calculated from overall heat transfer coefficients involving thermal resistances and film condensation/vaporization coefficients. The conservation equations were solved iteratively by the Newton-Raphson method.
The development of this model arose from a need to determine the wellbore heatloss distribution during the warm-up phase in Mobil Oil Canada's horizontal well at Cold Lake. Results from the model are verified with actual field data.
Implications of Water-Alternate-Gas Injection for Profile Control and Injectivity
Authors: Gorell S. B. 
Published: December 2007

ABSTRACT
Simulation results are presented which demonstrate that Water Alternate Gas (WAG) injection should not be expected to improve vertical distribution of solvent, relative to continuous slug injection, for tertiary processes in non-communicating layered systems. These results are explained by considering the way in which fluid mobilities within, and between, different layers vary with time. WAG injection reduces the effective mobility of fluids in the highest permeability layer compared with continuous injection. However, it also reduces the mobility of the fluids in all the other layers, which can actually increase the fraction of CO2 entering the highest permeability layer with WAG. Profile control with WAG should not be expected whenever the effective fluid mobility during solvent injection is higher than during water injection.
The effect of compressibility on follow-up water injectivity reductions are also considered. Reduced water injectivity can result from the high compressibility of CO2 and the redistribution of pressure profiles when the injectant is changed from CO2 to water. While this redistribution is occurring, the local injection pressure gradient, and therefore the injectivity, is lower than one would calculate if compressibility were ignored. Differences between pressure and rate constrained injection schemes and the effects of slug size are also discussed.
Effect of High Shear Rate on In-Situ Gelation of a Xanthan/Cr(III) System
Authors: Jousset F. , Green D. W. , Willhite G. P. , McCool C. S. 
Published: December 2007

ABSTRACT
An experimental investigation of the effect of high shear rates on the mechanisms of in situ gelation and development of flow resistance of a xanthan/Cr(III) gel system in sandpacks was made to simulate the conditions around a wellbore during a gel treatment. Gel solutions were mixed in-line to give an injected solution concentration of 1,500 ppm xanthan and 50 ppm Cr(III). Such a gel system has a gel time in bulk in the neighborhood of 15 hours. A 15 foot length of unconsolidated sand was used as the porous medium. The effect of high shear rates was examined by varying the frontal velocity from 12 to 120 ft/d. During each gel displacement, pressure drops across sub-sections of the sandpack were recorded as well as data on the effluent. Gelation behavior and Cr(III) concentrations of effluent samples were measured.
In gel displacements conducted at linear velocities between 11 to 35 ft/d. a high flow resistance developed at a specific location in the sandpacks confirming earlier work of Hejri et al.1,5. The build-up in flow resistance (in situ gelation) was accompanied by a reduced polymer concentration downstream of this location, which was inferred from reduced pressure drops and reduced effluent viscosity. The location of this region of high flow resistance was correlated linearly as a function of frontal velocity. Studies performed on effluent samples indicated that a large amount of Cr(III) and polymer were retained in the sandpacks. Moreover, the high flow resistances developed at a location where the age of the flowing solution was around 10 hours, corresponding approximately to the point where the viscosity starts to increase for this gel system.1.
At frontal velocities of 83 and 118 ft/d no significant flow resistance developed in these sandpacks. The residence time was apparently too small and the shear rate too large for in situ gelation to occur. The results of the experiments indicate that in situ gelation is mainly controlled by the kinetics of the gelation reaction and gel/polymer retention.
The Low-Tension Polymer Flood Approach to Cost-Effective Chemical EOR
Authors: Kalpakci B. , Arf T. G. , Barker J. W. , Krupa A. S. , Morgan J. C. , Neira R. D. 
Published: December 2007

ABSTRACT
The Low Tension Polymer Flood approach addresses the two EOR problems of cost and control. Coinjection of low concentration surfactant and a biopolymer, followed by a further mobility control buffer, leads to much reduced overall chemical consumption, even in relatively high clay content rock. Though the optimum chemical injection period is more prolonged, the oil recovery timescale is not unduly prolonged. The LTPF process moves chemical flooding surfactant a long way toward being a simple, low-level waterflood additive process, attractive for field operations. It uses surfactant-polymer interactions as an advantage rather than coping with them as a problem.
The chemical system described is based on a scleroglucan biopolymer (500 – 750 ppm) plus surfactant mixture (3000 ppm total surfactant). No cosolvent is used. This system was developed specifically for use with high salinity injection water (seawater) in a high temperature reservoir. The essential phase behavior description is given, together with other physical parameters and detailed coreflood performance.
Finally, we discuss the computer simulation approach used to predict reservoir performance and the results obtained.
Numerical Simulation of Single-Well Polymer Gel Treatments in Heterogeneous Formations
Authors: Hughes D. S. , Woods C. L. , Crofts H. J. , Dixon R. T. 
Published: December 2007

Abstract
High watercuts are a pressing problem in North Sea fields. The application of polymer gels to block-off the water producing layers has been judged successful in many American fields, and this established technology may be fairly readily extendable to the more demanding conditions offshore. A difficulty is that there is generally some vertical communication between the geological layers.
A radial, near-well bore model has been constructed for the Ness layers of the Upper Brent reservoir of a representative field. The pre- and post-production phases of gel treatments have been simulated, with the effects on fluid mobilities of polymer adsorption and gelation modelled directly. The effects of various degrees of vertical communication, and gel strategies and properties have been investigated.
Principal conclusions are:
Near-well bore gel treatments would be effective providing there is at least some restriction to vertical flow. Low concentration "thin" gels act mainly through the permeability-reducing property of the adsorbed gel, whereas higher concentration "thick" gels act mainly through the increased viscosity of the aqueous phase. It is more effective to inject gel into only the watered-out layers; and this strategy is favoured more for thicker gels. "Thick" gel treatments without selective completion block all except the highest-permeability layer. They should therefore only be considered if this layer still contains mobile oil, the watercut is high, and production is currently limited by handling capacity.
Field Studies of Microbial EOR
Authors: Sheehy A. J. 
Published: December 2007

Abstract
Microbiologically enhanced oil recovery (MEOR) is the use of microorganisms to facilitate, increase or extend oil production from a natural reservoir. The concept is more than 40 years old, however, early proposals were poorly conceived and in most instances of no practical value. Recent studies have developed microbial biotechnology to resolve specific production problems such as pressure depletion and sweep inefficiency in a target reservoir.
Field trials to determine and document the effectiveness of microbial process, and to assess the validity of laboratory studies and models have been conducted. The application of ME0R in these trials has resulted in a substantial and sustained increase in production compared to control operations on the same reservoir. Increased production has been sustained from a single treatment.
A field assessment of the new technology in the Alton field is described. Twelve months after treatment an approximate 40% increase in net oil production continues. The test is unique because of the stringent controls applied during the assessment.
Use of Eight Flux Streams Per Cell in a Two-Dimensional, Three-Phase, Unsteady-State Reservoir Simulation Model
Authors: Garrett J.E. , Osborne H.C. 
Published: December 2007

American Institute of Mining, Metallurgical and Petroleum Engineers Inc.

Abstract
Conventional reservoir simulation models use four-directional flux calculating procedures and accordingly compute fluid injection procedures and accordingly compute fluid injection performance with an inherent inaccuracy that performance with an inherent inaccuracy that often is of substantial magnitude. Tests show that the velocity of frontal movements computed are too slow diagonal to the grid axes and too fast parallel to the grid axes. The magnitude of the inaccuracy was found to range from +42% to -32% when referenced to a more accurate eight-flux procedure herein described. The four-flux inaccuracy can lead to especially serious error when matching limited fluid injection performance.
The eight-flux concept presented requires that the model's grids be viewed as symmetrical octagons for the purpose of computing the resistance to fluid flow from one grid to another.
The conclusion is reached that a model using the eight-flux computational procedure calculates saturation fronts more accurately; results in better reservoir performance matching and flood performance predictions; and is computationally more stable. The alternating direction explicit-type computational procedures are well suited to handle the procedures are well suited to handle the eight flux calculations.

Introduction
Normally, in grid-type reservoir simulation models, flux calculations are made in only four directions with respect to each cell. These flux streams run between each cell and the four abutting cells along lines perpendicular to the four faces. For fluids to move perpendicular to the four faces. For fluids to move diagonally with respect to the axes of the cells, it proceeds in a stair-step fashion, making a 90 degree turn at the center of each cell. As a result of this procedure the flood fronts resulting from model simulation are distorted.
One technique for improving flood front tracking in a numeric model is to compute flux into and out of each cell in eight directions rather than four. Thus, as far as flux calculations are concerned, the cells are treated as symmetrical-octagons.