bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Modified Non-Ionic Surface Active Agents in Enhanced Oil Recovery
Authors: Capelle Anthony , Littman Wolfgang 
Published: December 2007

ABSTRACT
As early as 1954 a study into the efficiency of nonionic detergents to displace crude oil from sandstone reservoirs was published by Dunning. In this study different exethylated alkylphenols were investigated and it was concluded that this calss of surfactants was among the most promising, provided the solubility in the injected waters at reservoir temperatures is sufficient. Since then hardly any investigation into these chemicals were carried out. Practically all work on chemical flooding, both in the laboratory and in the field has been focussed on petroleum sulfonates. Why this investigation into modified nonionics? The main reason is the excellent stability against electrolytes, a feature petroleum sulfonates do not have.
By combining the favourable properties of both the nonionics and anionics the so called modified nonionics were introduced for chemical flooding. The products show an excellent stability against electrolytes, especially divalent ions, and no temperature dependence of their solubility.
Illustrated by a practical example: sandstone reservoir, average salinity and medium temperature, the development of a flooding recipe based on modified nonionics will be discussed.
Attention will be focussed on the laboratory investigation and the optimization of the flooding recipe. It has been shown that a 50% pv slug containing about 0.5% surfactant will give about 35% incremental oil.
Mechanisms of Retention in Silicate Enhanced Dilute Surfactant Low Tension Floods
Authors: Krumrine Paul Henry 
Published: December 2007

ABSTRACT
Earlier work has shown that the addition of sodium silicates to dilute surfactant systems reduces surfactant retention in Berea cores better than Na2CO3, NaOH or STPP. This paper addresses the fact that in solution the sodium silicate molecule is a complex mixture of species which can exhibit a variety of properties, depending on the concentration and ratio of SiO2 to NaO2. By selecting the specific form in which the sodium silicate is added, it is possible to optimize the recovery of oil under a broad range of reservoir conditions. Specific variables which may be affected by silicate chemistry are IFT, rock wettability, surfactant retention and specific permeability reduction, leading to improved three-dimensional sweep.
A series of dilute surfactant core flooding tests were carried out, both with and without oil present, to determine the concentrations of the injected chemicals in the effluents. These tests covered a range of silicate ratios, brine salinity and hardness levels, and temperature conditions. The results show that each of these variables has specific effects on the retention of the injected chemicals by the sandstone substrate. Specifically, hardness increases retention of both silicate anion and surfactant, even with a large, soft water preflush. However, the silicate anion is preferentially retained, thereby leaving more surfactant in solution. Higher temperatures decrease retention of the surfactant and silicate anions. These results relate to observations of changes in recovery efficiency and permeability.
While few people consider carrying out low-tension floods at surfactant levels of 0.1 to 0.5% by weight, the results of these studies are generally applicable to both alkaline flooding and micellar flooding at much higher surfactant levels. In fact, this technology may have advantages as a low cost and technically less complex enhanced waterflood as compared to a micellar/polymer technique. Such a system would be best applied in the secondary waterflood stage. In either case, these same reactions and mechanisms control the surfactant concentrations in solution, and how well the injected fluid contacts the major part of the reservoir.
Standard Approach To Sampling And Chemical Analysis
Authors: Angwin Meredith Joan 
Published: December 2007

ABSTRACT
Measurements of the chemical constituents of geothermal fluids are frequently not reproducible from sample to sample. Some of this instability derives from changes in the well with time, but a considerable portion of the lack of reproducibility is due to the sampling and analytical methods. Geothermal fluids, at wellhead, are at elevated temperatures and pressures, but chemical analysis methods require samples at ambient temperature and pressure. In much geothermal sampling, the transition between the two conditions is uncontrolled; gases are lost, solids precipitate, and the constituents of the liquid portion of the sample change. This can result in data that are inconsistent and difficult to interpret.
The Electric Power Research Institute has made considerable progress in solving this problem by standardizing the sampling and analysis procedure. This was done by: Building a mobile chemistry laboratory, containing chemical equipment suited for on-site geothermal analysisBuilding a fluid sampling system (FSS) to carefully control the change in temperature and pressure between well-head and ambient.Designing a "chemical signature test" procedure for analyzing geothermal fluids at a variety of sites.
The mobile laboratory travels to the geothermal site to perform the chemical analysis. This makes it possible for samples to be analyzed very rapidly after they are taken, with no delays, since delays can cause chemical changes in the sample.
The FSS is a small, portable flash-condenser system which reduces the fluid's temperature and pressure in a controlled manner.
The signature test procedure defines how the FSS will be used, how the constituents will be analyzed, and what quality control methods will be used. It also outlines expected detection limits for the various constituents.
This paper describes the mobile laboratory, fluid sampling system and signature test. It also describes the laboratory's recent visit to a geopressured site, with results from that site.
Polymer Performance in Low Permeability Reservoirs
Authors: Danri Michael W. , Burnett David B. , Hall Larry M. 
Published: December 2007

ABSTRACT
Polymer performance was evaluated in core material from four low permeability (9.1 to 45 md) reservoirs. Injectivity impairment was noted in the higher permeability cores. Rock properties were examined by a variety of techniques in order to explain the apparently anomalous injectivity behavior. Results show that reservoir core characteristics other than permeability can dominate polymer performance, and that special core analysis techniques can be used to screen and characterize reservoir porous media.
A Study of the Application of Polymeric Gels in Porous Media
Authors: Batycky J. P. , Maini B. B. , Milosz G. 
Published: December 2007

ABSTRACT
Crosslinking experiments with polyacrylamide and cellulosic polymers using chromium and aluminum as crosslinking cations have been performed in glass tubes as well as in Berea sandstone plugs. The dependence of gel strength on salinity, polymer concentration and concentration of the crosslinking agents was investigated to determine optimum conditions. For a given polymer concentration the gel strength was found to peak at optimum concentrations of the crosslinking agents and declined at higher concentrations. Comparisons of gel strengths between the tube and porous media measurements show that the concentrations of crosslinking agents required for maximum gel strength are considerably higher in Berea sandstone plugs than those in glass tube experiments. Further experiments in which the Berea plugs were preequilibrated with the crosslinking agents show that the requirement of higher concentration could not be attributed to adsorption or ion exchange. It is suggested that the differences may be due to the necessity of creating a much finer gel structure in the porous medium and the corresponding requirement of a more prolific nucleation.
It was found that, at low polyacrylamide concentrations, gels did not form, yet mobility reduction still occurred. The basis for the reduction was determined to be due to the precipitation of the polymer from solution, which then plugged the porous medium.
Diverting Agents for Sweep Improvements in Flooding Operations—Laboratory Studies
Authors: Navratil Martin , Sovak Mojmir , Mitchell Mark Stephen 
Published: December 2007

ABSTRACT
Sweep efficiency in oil bearing reservoirs having high permeability zones, streaks or fractures can be improved by injecting gel-forming solutions which have the following attractive features: Prior to gelation, these solutions are low viscosity fluids which can be pumped as easily as water.Gel times from 10 seconds to 100 hours can be obtained at temperatures below 65°C.These gels can withstand temperatures typically employed in steam recovery of heavy oils.Partial removal of gels from high permeability zones and partial restoration of the initial permeability are also possible.
Acid Corrosion Inhibitor Adsorption and its Effect on Matrix Stimulation Results
Authors: Crowe Curtis W. , Minor Stephen S. 
Published: December 2007

ABSTRACT
Acid corrosion inhibitors provide protection by adsorbing on metal surfaces, thus forming a barrier against acid attack. Upon entering the formation, the inhibitor is strongly adsorbed on clays and other minerals present within the matrix of the rock. In some cases, inhibitors contain acid-insoluble residues which can cause surface plugging of the formation face. Inhibitor adsorption and formation plugging by inhibitor residues can have a major influence on cleanup rate and the ultimate effective permeability of the treated zone. Consequently, acid corrosion inhibitors should be evaluated both for their ability to protect metal and for their potentially damaging effect on stimulation results.
Laboratory tests, using a computerized core test permeameter, demonstrate the strong influence of acid inhibitors upon acid injectivity, cleanup rate and stabilized long-term effective permeability. The adsorption characteristics of the inhibitor were shown to strongly influence test results. The beneficial effect of mutual solvent upon injection rate and, in some cases, well cleanup was also demonstrated.
Data are presented showing the influence of temperature, differential pressure and mutual solvent upon injectivity, cleanup rate and apparent stabilized oil permeability. Various types of inhibitors were evaluated under a variety of test conditions.
In general, it was found that damage resulting from the corrosion inhibitors was more pronounced at the lower temperatures and that mutual solvents reduced the magnitude of the problem.
New Acid Systems for Sandstone Stimulation
Authors: Clark Greig J. , Wong Tony C. T. , Mungan N. 
Published: December 2007

Abstract
A new series of prepackaged acid systems have been developed for stimulation of sandstone formations. The original system, containing phosphoric acid and other additives (labelled P.P.A.S.* throughout this article) was specifically formulated to overcome several limitations of existing acid systems. The scope of applications for P.P.A.S. has since been expanded by combining HCl (Hydrochloric acid) or HF (Hydrofluoric acid) with the P.P.A.S. to form hybrid systems that have unique properties. These new systems have been successfully used for stimulating sandstone formations that have been difficult to treat with existing acid systems. The problems associated with currently used acids and their limitations are compared to the P.P.A.S to illustrate the advantages of these new systems.
Clay Protection Chemicals: A Practical Evaluation and Application Technique for their Use in Stimulation Fluids
Authors: Callaway Ralph Edward , Ortiz Joseph , Holcomb David Lee 
Published: December 2007

Abstract
The emphasis on providing protection to sensitive clays in a variety of reservoir types has led to the development and application of specific chemistries. These range from monovalent to polyvalent salts and more recently, to polymer based systems. In numerous published cases exotic interaction studies have been performed to evaluate the potential effectiveness of these clay protection additives.
The need for a simple standard screening technique to allow comparative testing and ultimately specific designs for clay additive usage is obvious. This technique will illustrate the significance of clay species interaction with clay stabilizing fluids and point to any harmful side effects on reservoir permeability that may be caused by the clay stabilizer.
The study presents a simple procedure for indexing clay stabilizing additives in order to insure that the most effective one is chosen and implemented as a "specific" agent to control a "specific" clay situation. Use of a packed column in addition to berea core allows the designer to vary the type and amount of clay in the column in order to simulate the clay content of the formation in question.
Factors affecting the performance of clay stabilizers will be prioritized. They include compatibility with other additives, permeability damage, and ability to prevent clay migration in a packed column.
An attempt will be made to document results with respect to clay chemical/clay species interaction. This will be done before and after permeability flow tests using scanning electron microscopy.
The evaluation of stabilizers examined in this study will be documented by indexing each chemical. This index will be shown to be a useful tool in differentiating among the numerous clay stabilizers available in the market today.
Reservoir Performance Changes Due to Inelastic Deformation
Authors: Schatz John F. , Ahmed Usman , Carroll Michael 
Published: December 2007

ABSTRACT
Long-term prediction of reservoir performance can be strongly influenced by stress sensitivity. As the effective stress in a reservoir increases due to production, the porosity and permeability decreases. Inelastic rock deformation mechanisms play a significant role in bringing about these changes in porosity and permeability. This paper shows that inelastic pore collapse can be the dominant mechanism in reducing pore space and permeability even when reservoir conditions are hydrostatic. The presence of a shear component in the in-situ stress can increase these effects. A numerical simulated reservoir study has shown that well work-over and stimulation projects could be warranted earlier than currently practiced.
Viscous Heavy Brine Completion Fluids
Authors: Darlington R. Keith , House Roy F. , Hunter Daniel V. 
Published: December 2007

ABSTRACT
An activated hydroxyethyl cellulose has been developed which will viscosify brines of any density up to 19.2 lb/gal containing calcuim chloride, calcium bromide and/or zinc bromide. The use of activated hydroxyethyl cellulose allows preparation of viscosified brines at ambient temperature and without undissolved polymer solids. The time required to prepare a viscosified brine is greatly reduced. In addition, the rheology of brines viscosified with activated HEC can be accurately predicted allowing brines with equivalent solution rheology properties to be prepared batch after batch.
A Simplified Predictive Model for Micellar-Polymer Flooding
Authors: Paul George W. , Lake Larry W. , Pope Gary A. , Young Genevieve B. 
Published: December 2007

ABSTRACT
The purpose of this paper is to present a simple, reliable and inexpensive predictive model which allows the economic assessment of micellar-polymer flooding. An oil recovery algorithm is developed from theory and the results of numerical simulation. The model contains correlations which relate factors impacting oil recovery to reservoir and process data: capillary number (permeability, depth, spacing), heterogeneity (Dykstra-Parsons coefficient), crossflow (kv/kh), surfactant sorption (clay fraction) and wettability (relative permeability). Oil breakthrough, peak oil rate and project life are estimated from oil-water fractional flow theory, augmented with an effective mobility ratio to represent heterogeneity. The model is validated against the results of numerical simulation and is compared with the results of several field projects.
Location of Drilling Sites in the Devonian Shales by Aerial Photography
Authors: McIver R. D. , Kyle J. R. , Zielinski R. E. 
Published: December 2007

ABSTRACT
Current estimates of gas in place in the Devonian Shales of the Appalachian Basin range up to 2,500 TCF. For the most part, the majority of this resource is tied up in the shale matrix and the source and reservoir of this gas is the same as the low permeability and porosity of the shale prevents migration of the gas to a more classical reservoir rock. Where there is fracturing of the shales, the fracture network serves as a reservoir and wells drilled in the area of fracturing tend to be good producers.
For exploration purposes, the most probable areas for drilling of the shales are those that have a high density of natural fracturing. Aerial photography has been used to locate potential drilling sites in the Basin. The use of this technique is based upon the premise that fractures evident in surface sediments are often useful indicators of subsurface fracturing favorable for the accumulation of hydrocarbons.
Buried fault traps, anticlines, and salt domes are frequently revealed by surface fault configurations or locally anomalous joint orientations. Moreover, since fractures are frequently conduits and collection sites for hydrocarbons, a concentration of surface fractures may indicate a potential productive reservoir at depth.
Aerial photography allows fractures to be recognized and mapped in almost every type of terrain and soil cover. A photogeological study designed to aid in the location of specific prospects typically begins with a study of LANDSAT photos to spot large scale features. This is followed by a study of stereoscopic photo pairs and photomosaics of larger scale. For pinpointing drilling sites in such cases, the greatest weight is placed on the interpretations from stereoscopic photo pairs.
The current paper reviews the premise of photogeology, the techniques used in applying aerial photography as an exploration tool and finally the application of photogeology in identifying specific well sites in the Devonian Shales of the Appalachian Basin.
Relationship of Methane Content of Coal Rank and Depth: Theoretical vs. Observed
Authors: Eddy Greg E. , Rightmire Craig T. , Byrer Charles W. 
Published: December 2007

ABSTRACT
Prediction of gas content of coalbeds, and therefore potential producibility, has relied primarily on its observed relationship to coal rank, pressure, and the methane adsorption capacity of a given coal. This relationship has been illustrated by the construction of adsorption isotherms for various coals from experimental data. These adsorption isotherms were developed for sized, clean coal particles. The value and limitations of these adsorption isotherms are addressed by relating them to observed coalbed methane gas content data.
Coalbed gas content determined by the "Direct Method" includes three separate figures: lost gas, desorbed gas, and residual gas. The residual gas and its relationship to the total gas content is discussed. The ratio of lost and desorbed gas to residual gas has been determined for some ranks of coal.
The ratio is very dependent on rank. Residual gas increases as rank increases, reaches a maximum at the rank of high-volatile A bituminous and decreases rapidly as rank increases to medium-volatile.
The general conclusion is made that the cause of the pattern of correlation of residual gas to rank is a change in the internal structure of the coal and the moisture content of the coal.
Coalbed Methane Potential of the Appalachians
Authors: Adams Margaret A. , Hewitt Jeanne L. , Malone Rodney D. 
Published: December 2007

ABSTRACT
Coal mines in the Appalachian Basin emit approximately 180 million cubic feet (MMcf) of high-quality methane into the atmosphere daily. The existence of mines in West Virginia, southwest Virginia, eastern Kentucky, Ohio, Pennsylvania, Tennessee, and Alabama with high gas emissions of over 100 thousand cubic feet per day (Mcf/d) suggests that further investigation into the economic development of this unconventional energy source is warranted. Appalachian coals occur as multiple beds, individually up to 14 feet thick (Pittsburgh coalbed in Pennsylvania and West Virginia). The gas content of these bituminous coal seams has been measured at 93 cubic feet per ton (cu ft/t) from a depth of 149 feet (Waynesburg coalbed, Pennsylvania) to over 560 cu ft/t at 1,764 feet (Pocahontas No. 3 coalbed in West Virginia); in the anthracite region, 690 cu ft/t have been measured where the overburden is 685 feet thick (Peach Mountain coalbed).
Detailed studies in the southern Warrior Basin indicate the presence of up to 20 trillion cubic feet (Tcf) of gas, and preliminary work in the Central and Northern Appalachian Basins suggests a resource of 50 and 80 Tcf, respectively. Many coal operators are realizing the production potential of coalbed methane. In Buchanan County, Virginia, the Island Creek Coal Company produced up to 434 Mcf/d from 12 horizontal boreholes drilled into the mine face. Waynesburg College in Pennsylvania will realize a savings of $25,000 toward their annual energy bill from a 1,450-foot vertical well drilled on campus. In Alabama, U.S. Steel's mines just began commercial production, and sold 25 Mmcf to a gas pipeline company in December 1981; and Jim Walters Resources has begun an ambitious program to drill up to 700 wells with a predicted total production of 60 billion cubic feet (Bcf).
These examples of the successful exploitation of a resource formerly considered only a hazard to coal mining indicate a promising future for coalbed methane.
A Successful Stimulation Research Program for a Tight Sand Reservoir
Authors: Greenfield Harvey S. , Ahmed Usman , Schatz John F. , Jones Arfon H. 
Published: December 2007

ABSTRACT
Two research wells were drilled and completed in a known, yet heretofore unproductive tight sand gas reservoir in the Green River Basin. Although previous wells were drilled in the area and hydraulically fractured, there has been no commercial production. The consideration of advanced methods of stimulation design and changing gas prices caused recent renewed interest. A systematic approach led to successful fractures of one zone in each of the two wells. Initial production rose from 107 to 4150 MCFD in one well and from 35 to 1450 MCFD in the second well after stimulation treatments.
Field Study — Steinle Ranch, an Intermediate Depth Oil Field, Shows Significant Benefit from Bauxite Proppants
Authors: Kohlhaas Charles A. 
Published: December 2007

ABSTRACT
The Steinle Ranch Field was initially developed in the mid-1970's. Wells were drilled, cased, perforated, and treated by chemical injection with lease-crude or condensate carriers to restore oil saturation to the formation, which is suspected to be hydrophobic. Stimulation by hydraulic fracturing of four wells was attempted from 1975 through 1977 with mixed results and no particular success. These treatments used sand and glass beads for proppant.
A fifth hydraulic fracture treatment, in which sintered bauxite was used as the proppant was very successful. As a result, all wells in the field have been fractured. This program, in a mature field in late stages of depletion, at intermediate depth (10,600 ft.), has been very successful; approximately 940,000 barrels of additional reserves have resulted for a total cost of approximately $2,000,000, a return on investment of 9.4:1. Comparing these reserves to estimated reserves if the wells had been propped with sand shows a 23:1 return by the incremental reserves on the incremental cost of the bauxite.