bluuebunny/crossref_metadata_2025_split huggingface dataset:
Bifurcation Analyses of Water Out Mechanisms in Heterogeneous Reservoirs
Authors: Luan Zhi-an 
Published: December 2007

Abstract
Based on a geostatistical model and an abstract model new ideas on water out mechanisms of heterogeneous reservoirs are presented. It shows that the strong heterogeneous reservoirs are initial imperfect, so that long period prediction of dynamical behavior is impractical. Unsuitable water drive perturbations will bring the reservoir with high permeability variation rapidly into attractor set that have a low recovery. The further movement and shrinkage of attractors are done only by using physics-hydrodynamic methods.

Models of Water Out
In heterogeneous reservoirs practical every formation is stratified to some extent; that is to say, it contains layers of differing permeability ki(x),i=1,2,…,n. To illustrate the effect of such stratification on water/oil ratio, we construct a simple geostatistical model in which permeability of any layer is random variable and permeability of specific layers will take on constants equal to or higher k. The probability distribution function F(k) is the thickness ratio of these specific layers to all layers, and it can be defined by = F'(k)dk = f(k)dk where h = formation thickness, h = sum thickness of the specific layers (permeability&gt;k), f(k)= distribution density of permeability k. It will be assumed that there is no vertical communication between the layers, except through the well bore. Considering l-D piston-like displacement we obtain the global water/oil ratio R. In formulae 1-length of formation, k* is permeability of a layer in which the water breaks into the bottom of the wellbore From the Eq. 1, firstly, note that fact:
the larger o / w, the more viscous the oil, the more rapidly will the water/oil ratio increase. Secondly, note that this increase will also depend on the standard deviation of the formation permeability. The larger the coefficient of variation, the more rapidly will the breakthrough occur. Once the water has flooded a high permeable stringer, it has established a "short - circuit" of least flow resistance and led a low sweep efficiency. It should be indicated that the water accumulation near the oil well bore will be preferable imbibed into less permeable layers. Therefore, if the medium is water (or oil)-wet, the relative permeability of oil phase near a well bore may decrease dramatically with cumulative production, which will bring this reservoir rapidly into the higher water out. A typical change of water saturation is shown on the right-hand portion of Fig. 1. The characterization of area sweep models is similar to that of the above vertical sweep model.
As an extreme case, reservoirs having fracture-matrix are both area heterogeneity and vertical heterogeneity. For real reservoirs, there is no a realistic geostatistical model.

Water Out Mechanisms and Attractors
Buckley-Leverett (B-L) equation is a nonlinear evolution equation which contains nonlinear convective and capillary dissipative terms. P. 811
An Application Utilizing Horizontal Re-entries Versus Water-flooding for Depleting a Mid-Life Niagaran Reef
Authors: Pieters D. A. , Pearce L. A. 
Published: December 2007

Abstract
Waterflooding has been the preferred secondary recovery technique for mid-life Michigan Niagaran reefs that were large enough to economically warrant it. Since these pinnacle reefs average 50-550 acres, the success in waterflooding such a limited space has been a hit or miss proposition depending on the pinpoint accuracy in locating injector and producer. This paper presents a case history for the Colfax 25 reef where five horizontal drainholes were positioned across the field in a pattern to access and drain all areas of the reservoir. This particular reef was chosen based on identified incremental reserves, areal extent and on past production history which displayed reservoir characteristics that were favorable for horizontal wells. The application was tremendously successful. Production in all wells doubled as gas oil ratios were significantly reduced. Start-up costs were slightly below those of a conventional water flood and operating costs were substantially lower than would be incurred for a waterflood.
Mobility of Polymer Solutions in Porous Media
Authors: Ershaghi Iraj , Handy Lyman L. 
Published: December 2007

Abstract
Over the past few years, considerable interest has developed in the use of certain synthetic polymers as mobility improvement additives in waterflooding. It has been argued that these compounds, when added in very low concentrations to the injection water, exhibit extraordinary flow resistance and reduce the injection water mobility. The mechanism by which these polymers cause excessive flow resistance is not yet clearly defined, however.
In this study flow of polymers through porous media was investigated computing polymer porous media was investigated computing polymer solution mobilities within porous media from measurements of pressures as a function of distance along linear core samples. Determination of pressure gradients within the cores has eliminated effects resulting from plugging of the inlet face. Filtered and unfiltered polymer solutions were used.
In general, filtered polymer solutions gave better penetration of the pore space. With unfiltered polymer solutions substantial filtration occurred at the inlet end of consolidated cores. Little or no polymer penetrated to the effluent end. Water mobilities calculated between pressure taps were essentially equal to that of brine. Filtered polymers, however, did show brine mobility reduction between pressure taps. With continued injection the water mobility continued to decrease and did not appear to approach a steady state short of plugging. This plugging effect was substantiated by polymer plugging effect was substantiated by polymer concentration measured for the effluent fluid. These concentrations went through a maximum and then decreased to zero as the polymer plugging became complete. The results indicated accumulated in-depth polymer plugging of the porous medium.
Although the results do confirm in-depth reduction of water mobilities, they also suggest that the deep penetration of reservoir rocks required in waterflooding would not be likely to occur. The residual effect appears to be an unsteady state effect which leads to complete plugging of moderate to low permeability plugging of moderate to low permeability sandstones with continued injection. The polymers do appear to have potentials in sealing thief zones and thereby improving vertical sweep efficiency.

Introduction
Oil recovery by waterflooding can be effectively improved by reducing the mobility ratio between the injected water and the displaced oil. This has been well substantiated by both theoretical and experimental studies.
A Study of Oil Recovery by In-Situ Combustion with the Addition of Water
Authors: Alderman John H. , Osoba J.S. 
Published: December 2007

Abstract
The object of this work was to improve the forward combustion process by injecting water simultaneously with air. One of the methods used to recover oil from underground reservoirs that has gained interest in recent years is in-situ combustion. This process involves ignition of the oil in reservoir rock and the propagation of the resultant combustion zone propagation of the resultant combustion zone toward producing wells by the injection of air. However, at the present time this method has enjoyed only marginal economic success in a limited number of applications.
To study this process, a combustion tube was packed with oil, water, sand and clay. Combustion was initiated and propagated down the tube by the injection of air. In three runs water was injected with the air to study its effect. The produced gas and liquids were measured and analyzed. The temperature and rate of advance of the combustion front were also measured. Pressures at the inlet, outlet and points along the tube were measured throughout points along the tube were measured throughout the run.
It was found that adding water to the injected air effected the oil recovery. In all cases where water was injected, oil recovery increased. The rate of oil recovery also increased. More efficient utilization of heat also took place because of the movement of heat from behind the combustion zone to the oil zone ahead of the combustion zone.

Introduction
Among the methods to recover oil from underground reservoirs that have gained interest in recent years are those involving the application of heat to the reservoir. The use of heat to increase production rate and recovery is not new, however. Shortly after the completion of the Drake well in 1859, steam was used to melt paraffin from the wellbore and increase the rate of paraffin from the wellbore and increase the rate of oil production. In 1935, the Russians were conducting experiments to recover more oil by a process they called crude oil gasification. This process they called crude oil gasification. This work involved moving heat outward from a wellbore into a formation and was the forerunner of an oil-recovery mechanism known today as in-situ combustion.
In-situ combustion has, however, met with only marginal economic success in displacing oil from reservoir rock and has found limited application. One reason for this has been poor utilization of the generated heat. Most of the heat is left in the burned portion of the reservoir.
One advantage gained from the application of heat to a reservoir is based on reduction of crude oil viscosity at the higher temperature. For the lower gravity oils this is a substantial decrease.
Cost Control & Development And Production Of Egyptian Western Desert Marginal Fields
Authors: Pretto Lorenzo , Ghareeb Mohamed 
Published: December 2007

Abstract
The various crises which affected our oil industry have emphasized the need for detailed control of expenditure for development and production of oil small discoveries. Fields with recoverable reserves of about five MMSTB are classified by EGPC as marginal fields. In the past such discoveries in Egypt were not considered economic. A few years ago EGPC, through its operating companies, introduced and adopted new management systems that many of international major companies were utilizing. The following approaches are used to cut the operating costs:-EGPC supporting the operating companies by all available technical information for drilling production and processing operations.Facilities sharing.Existing pipeline network utilization in developing western desert marginal oil fields.Using early production system to evaluate the field in order to minimize the capital cost.
This paper will provide and discuss Agiba experience in developing and producing marginal fields. As case histories this paper will present Ras El-hekma and Zarif fields development and production achieved by Agiba staff challenging effort.

Introduction
Several discoveries in Egypt, which were not considered economic at the time of discovery, started to produce in the past few years. This change happened because a non traditional approach was followed in developing and operating such fields, turning them into profitable projects. The unconventional methods to develop marginal fields, mainly utilized to cut developing and operating costs are:–utilization of rented and/or shared existing facilities–utilization of existing pipelines–use of existing exporting facilities–company work by challenging objectives : high commitment and motivation to find innovative ways of applying new or existing technology to achieve challenging results.
This paper gives better insights into Agiba's potentiality and capability in developing fields / reserves that were not economically attractive in the past.
Example of these development schemes that were recently achieved by either technology application or new innovation are:–Zarif field–Ras El-hekma field
In the near future, end of November, another marginal field, El Faras, will start up. Figure (1) shows western desert location.
P. 309
Waste Water Reclamation for Steam Generator Feed Kern River Field, California
Authors: Smith M.L. 
Published: December 2007

Abstract
This report is a summary of a program of comprehensive study, testing, pilot work, and the operational development of a system which reclaims fresh produced water for use as steam generator feedwater. This system is unique because of:
(1) The extremely high quality of the effluent - essentially 0 PPM suspended solids of which oil is the primary contaminant.
(2) The capacity of the system - initial design 200,000 BPD - now increased to 250,000 BPD.
(3) A design which guarantees continuous throughput on a 24-hour basis.
(4) The reclamation which is accomplished at a cost per barrel competitive with other fresh water sources.
The report will discuss the other methods of reclamation tested, the engineering considerations used in the design of the system, and operating problems encountered in the initial operation. The system which has been in operation for three years started at a capacity of 100,000 BPD. It is presently treating in excess of 200,000 BPD and will reach 250,000 BPD by the end of this year.

Introduction
The Getty Oil Company thermal program in the Kern River Field is completely dependent on an adequate and reliable supply of steam generator feedwater. in the summer of 1966, generator feedwater requirements of 100,000 BPD were supplied by eight water wells. This well water was softened and distributed to the field at a company facility called the G and W softening plant. Increasing feedwater requirements, a rapidly dropping water table, and more stringent requirements by the State Water Pollution Control Board on the disposal of field waste water made it apparent that a waste water reclamation system should be investigated. If successful, this system would serve the dual purpose of providing an independent supply for the necessary feedwater requirements and, at the same time, solve the problem of waste water disposal. problem of waste water disposal.
Full Field Dual Porosity Modelling of a Complex Fractured Chalk Oil Reservoir Subject to both Gas and Water Injection
Authors: Conway P.I. , Damm M. , Andersen P.M. 
Published: December 2007

Abstract
The Gorm Field A-block reservoir is a tight chalk oil reservoir which has been on production since 1981. The reservoir contains an interconnected tectonic fracture network at the crest of a domal structure, the flanks of the structure being non-fractured. Reservoir pressure has initially been supported by gas injection which was installed for gas disposal. Water injection was initiated in 1989.
An integrated production development study has been performed in which dual porosity reservoir simulation modelling has been a central activity. A key task has been to identify the dominant recovery mechanism(s) to assist in selection of an optimal further development scheme. A conceptual simulation model comprising a simple 1-dimensional dual porosity stack model, and a finely gridded 3-dimensional full block dual porosity simulation model have been constructed. The models incorporate capillary continuity, gas-oil re-imbibition effects, and calculate the contribution to oil recovery from pressure differentials across matrix blocks due to dynamic pressure gradients in the fracture system. In addition, capillary pressure and relative permeability hysteresis have been incorporated based on SCAL data.
Field historical production and injection performance have been successfully matched using the full block model, including the observed response in production wells to gas and water injection, and pressure gradients within the reservoir observed from RFT data.
The calibrated models subsequently have been used to demonstrate that;–gas-oil gravity drainage has been slowed by reimbibition effects and has had a limited effect on oil recovery–significant oil recovery was attributable to viscous gradients in the fracture system as a result of gas injection. However, due to recycling of large volumes of gas through the fracture system, this was a less efficient recovery mechanism than could have been achieved by water injection.–oil recovery due to natural water influx or water injection had been predominantly via spontaneous imbibition to date, and remaining movable oil could be best activated by increasing viscous gradients by stepping up flank and basal water flooding.–gas relative permeability hysteresis has caused significant volumes of free gas to be trapped in the crest of the reservoir
Gas injection has subsequently been discontinued and water injection extended. The drilling of three production wells and one injection well and the provision of greater water injection capacity was predicted to lead to a doubling of field oil rate due to the decline in producing GOR, and an increase in ultimate oil recovery from 33% to 44%. The early field response has supported these predictions.

Introduction
The Gorm field, located in the Danish Sector of the North Sea, was discovered in 1971 by the N-1X exploration well.
P. 497
Miscible Waterflooding Using a Phosphate Ester Solubilizer
Authors: Halbert W.G. , Inks Clyde G. 
Published: December 2007

Abstract
A simple micellar solution or microemulsion has been tested for its oil displacement capabilities in a sandstone core. The micellar solution was prepared using crude oil, water and a phosphate prepared using crude oil, water and a phosphate ester surfactant.
Phase studies at 74 degrees F showed that a micellar solution existed when the phosphate ester surfactant concentration was 4 to 8 percent by volume or greater in a sour crude oil and water system. Similar concentration requirements were exhibited by a sweet crude oil-water system. Tests at elevated temperatures showed that the microemulsions tended to degrade as temperature was increased. Partial and total neutralization of the acid surfactant improved the microemulsions tolerance of higher temperatures.
Oil displacement tests showed that the micellar solution employed was capable of displacing 90 percent of the core's oil saturation. Slug floods of 30 percent PV and larger yielded an oil displacement percent PV and larger yielded an oil displacement efficiency of 90 percent also. Water-driven slugs were employed. Displacement efficiencies exhibited by oil-rich and water-rich micellar solutions were slightly different. These differences are explored via dilution arguments.

Introduction
Numerous patents and publications have appeared regarding the use of micellar solutions or microemulsions for secondary recovery of oil and the stimulation of water injection wells. These papers report the use of certain petroleum sulfonates as the solubilizing agent. The excellent capabilities of the petroleum sulfonates has been demonstrated.
The purpose of this study was to explore the oil displacement merits and certain phase characteristics presented by a different solubilizer - a mono substituted presented by a different solubilizer - a mono substituted ortho phosphate ester. The surfactant employed is manufactured by BASF Wyandotte Corp. and marketed as KLEARFAC AA-420. This surfactant is an anionic, biodegradable liquid that exhibits solubilizing properties within a broad pH spectrum 17 Used primarily in metal cleaning and textile processing, its capability of recovering oil has not been previously studied.
Preliminary phase behavior studies showed that KLEARFAC AA-420 was an excellent solubilizer of crude oil and water. This characteristic prompted a series of oil displacement tests plus further phase behavior tests at elevated temperatures.
The Three-State Model Of Pore Fluid Distribution
Authors: Chen Yongsheng , Liu Zhenyu , Dewu Fu 
Published: December 2007

Abstract
This paper, which uses large amount of data, discusses the wettability of formations and reservoirs and its characteristics by analyzing the surface tension and surface electrostatic force of different rock minerals and pore fluids, the effect of preferential wetting and preferential adsorption on reservoir wettability, and the change of reservoir wettability after water flooding. On the basis of the above discussion, three-state model of pore fluid distribution are divided into three types.

Surface Dynamic Nature of Rock - Forming Minerals, Clay and Fluids

i. Rock-forming minerals
Liquids and solids have surface tension. All the experimental materials indicate that solids have larger surface tension than liquids. The mineral grains which form reservoirs are made up of non-uniform ions with different electric properties. All the ions on the surfaces of the grains have an asymmetrically electric field as well as an asymmetrically gravitational field. These asymmetrical fields make the grain surfaces form a weak electromagnetic field. Now we shall analyze the commonest surface layer.

i) Quartz
Take the commonest - quartz for example. The crystal structure of - quartz is shown in Fig. 1. It is usually known as silicon-oxygen tetrahedron. From this we can know:The tetrahedron surface is oxygenThe proportion between silicon and oxygen in SiO2 is 1:2.Because of the above characteristics of the surface structure, the quartz surface is made to be a negative electric field. It is proved by calculation that the force of unit negative charge at the distance b (0) from the surface of - quartz is(1)where - diameter of O2 - f - Coulomb factore - Charge of an electron

ii) Feldspar
In the gap of the frame structure formed by silicon-oxygen tetrahedrons and aluminium-oxygen tetrahedrons, these are full of potassium or sodium ions sometimes Calcium or barium ions (See Fig. 2). Such crystal characteristics, in addition to the actions of potassium ions, decrease the negative field intensity of the crystal surface and make the negative field intensity of Feldspar surface less than that of quartz's.
Calcite also exists in rock-forming materials of sandstone reservoirs. Analyzing of crystal structure, the polarity of calcite is smaller than feldspar's. Since water is a molecule with strong polarity, general speaking minerals which have strong field intensity have strong hydrophilic nature. Daqing Oilfield made an experiment by use of a crystal of feldspar and quartz and the same quantity of oil and water. The result is that the contact angle of oil on the quartz chip is smaller than that on the feldspar's. This indicates that quartz has a stronger hydrophilic nature than feldspar.

ii. Fluids
The fluids in the pore space are usually oil, air and water.
P. 1