bluuebunny/crossref_metadata_2025_split huggingface dataset:
Casing Plungers: Colorado Project Delivers Promising Results
Authors: Cramer John W. 
Published: December 2007

Abstract
This paper will discuss the history, theory of operation, candidate selection, installation procedure, and operation of casing plungers. Approximately 2000 casing plungers have been installed, primarily in the Appalachian Basin area of the US. The casing plunger is used to remove fluid from the well using only reservoir pressure to lift fluid from the wellbore. When fluid is removed from the wellbore, hydrostatic pressure is reduced and gas production can increase. As the name implies, the casing plunger operates in the production casing of the well. When installed in an appropriate well, casing plungers can help improve production and possibly reduce operating expenses. This paper will summarize current Appalachian Basin casing plunger practices. This paper will describe in depth a five well pilot project operating in Northeastern Colorado. The paper will review the planning, candidate selection, equipment installation, operation, maintenance, and evaluation of the project.
The concept of casing plungers can be traced back to 1956. Casing plungers have been operating successfully in some areas of the Appalachian Basin as early as the late 1980's. Swab wells, open-flow wells, tubing plunger, and pumping unit wells have all proven to be appropriate candidates for conversion to casing plunger production. Casing plungers are an accepted method of production and are currently being installed in new wells as well as in producing wells.
This paper will offer some of the experiences gained in casing plunger operations in the Appalachian Basin area to assist operators to determine if casing plunger technology may be applicable in the Rocky Mountain Region.
Reasonable Lightning Protection for Electric Submersible Pumps
Authors: Brinner T. R. 
Published: December 2007

Abstract
High cost, questionable efficacy and justifiable mistrust are the usual factors that must be overcome when applying lightning protection to ESP's. These factors are true of any product when its performance is difficult to measure and thereby almost impossible to compare with competing products. The intent here is to pull together those aspects of ESP lightning protection that are variable, and once they have been analyzed to recommend ways to organize effective protection.
The most bothersome variable is ground resistance. Basically it depends on soil moisture and mineral content. Soil moisture changes with the seasons. However, ground resistance can be measured, and even in arid regions of the world it is possible to construct low-resistance grounds. Resistance combines with the inductance of the lead wire to form a total ground impedance. When only a single Transient Voltage Surge Suppressor (TVSS) is used, the devices to be protected are always subjected to a minimum voltage equal to the ground impedance times the surge current.
A lightning filter remedies this problem by having separate inputs and outputs and running different ground connections to each. Consequently the lightning-stroke voltage does not appear instantaneously at the output terminals. Further the rate at which voltage increases is reduced, an important factor when trying to protect turn-to-turn insulation in the ESP motor. Being able to justify the added expense of a complete filter depends on how high the ground impedance gets and how critical it is to protect a given ESP.
Testing and verification of protection are major credibility concerns. Any device designed for lightning protection should be subjected to high-voltage impulse tests. Certainly some type of production tests should also be performed. Verification of protection in operation should involve some type of indicator lamp, which turns off when a line-to-ground fault occurs, a component fails or the bulb burns out.
In conclusion both the lightning filter and the TVSS provide much needed ESP lightning protection. The decision on which device to employ depends on ground impedance and the level of ESP protection the operator deems necessary.
Conventional Core vs. Mini-Permeameter Permeability Measurements: Tensleep Formation
Authors: Taylor L. H. , Vinopal R. J. 
Published: December 2007

Abstract
Conventional air horizontal permeability measurements collected at one foot sample intervals from the Tensleep Formation were compared to permeability values collected over the same depth range using a mini-permeameter with a sample frequency of 8 to 10 measurements per foot. The lithologies analyzed consisted of sandstone and dolostone from eolian dune, shoreface, sandflat, and shallow marine shelf facies. Comparison of mini-permeameter measurements averaged over one-foot intervals with the plug permeability value showed that the mini-permeameter average permeability value was higher in the shallow marine shelf and eolian lithologies. In the sandflat and shoreface lithologies, mini-permeameter values averaged over a one-foot interval were not significantly different from the single core plug permeability. Lithologies were analyzed by low power optical microscopy, thin section petrography, and scanning electron microscopy to characterize the pore system. The shallow marine shelf facies consists of dolomite with patchy sucrosic, vuggy, and fracture porosity. The average of the mini-permeameter measurements over a one-foot interval gave a better representation of all the pore system types observed. Eolian sandstones contain a matrix and fracture porosity system. The matrix porosity system shows variability in the size of pores and pore throats due to differential cementation by silica and dolomite and due to differences in grain size and sorting. Variability in the pore system is on a scale larger than a core plug in the eolian and shallow marine shelf facies which causes the deviation between the core plug and averaged mini-permeameter values. Shoreface units consist of homogeneously bioturbated fine-grained sandstone. The sandflat lithology is a ripple laminated fine-grained sandstone. In the shoreface and sandflat units, the pore system is largely uniform through the core on the scale of a core plug which causes no significant difference between core plug and averaged mini-permeameter values. The applicability of the mini-permeameter in providing a more detailed view of permeability distribution in a core is dependent on the uniformity of the pore system on a core scale.
The Effect of Surfactant-Bearing Fluids on Permeability Behavior in Oil-Producing Formations
Authors: Jennings Alfred R. 
Published: December 2007

The Effect of Surfactant-Bearing Fluids on Permeability Behavior in Permeability Behavior in Oil-Producing Formations
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
The use of surfactants during various types of fracturing and acidizing treatments on oil wells is a commonly accepted practice. It is known and has been verified by several laboratory studies that surfactants have a marked effect on formation rock permeability in the treated wells. During hydraulic fracturing treatments, for example, large volumes of surfactant-bearing fluids are pumped deep into the formation matrix through the created fracture system.
This paper presents the results of an investigation of the behavior of fluid flow on formation core plugs that have been subjected to either aqueous base fluids or hydrocarbon fluids containing various types of oil-wetting or water-wetting surfactants. Guidelines as to the most efficient types of workover fluid and surfactant combinations for maintaining hydrocarbon permeability are indicated from the data obtained.
A method of "water-block" removal and restoring formation hydrocarbon permeability has also been observed permeability has also been observed and is discussed in this paper.

Introduction
When a fluid is pumped into a semistable environment such as a petroleum reservoir, vast changes in fluid saturations can occur in the area where the encroaching fluid is in contact with the formation and the formation fluids. The fluid pumped into the reservoir may be a fracturing fluid or some other type of workover fluid and may be an aqueous or hydrocarbon fluid.
The presence of the fluid can cause changes in the permeability and flow behavior of the formation. Due to the wide ranges and various types of fluids that are used in oil wells, the investigations discussed in this paper will be primarily related to fracturing fluids. primarily related to fracturing fluids. When a hydraulic fracture is produced in a formation, a breakdown or produced in a formation, a breakdown or actual parting of the rock occurs.
Development of Oil Soluble Resin Mixture for Control of Fluid Loss in Water Base Workover and Completion Fluids
Authors: Crowe C.W. , Cryar H.B. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
A new oil soluble additive has been developed to reduce fluid loss of workover and completion brines. This additive is composed of a mixture of finely divided friable and pliable oil soluble resins and is effective in all brine systems at temperatures up to 250 deg. F. Laboratory tests show good fluid loss control against permeabilities up to at least 900 md. An permeabilities up to at least 900 md. An additional oil soluble bridging agent is used with the additive in fractured or more permeable formations. permeable formations. Unlike the commonly used calcium carbonate type additives, which require acidizing following their use, this product forms a filter cake which is completely soluble in the produced oil. As a result, the danger of formation produced oil. As a result, the danger of formation damage is minimized. No supplemental water soluble gums or polymers are required for fluid loss control although they may be added to increase viscosity and solids carrying ability of the fluid.
The non-damaging nature of the additive is demonstrated by laboratory formation damage tests and the results of well treatments.

Introduction
In recent years, considerable effort has been directed toward the development of new techniques and materials to minimize formation damage during workover and completion operations. Many workover fluids previously in common use have been replaced by previously in common use have been replaced by newer non-damaging systems.
Solids free brines are finding increased use. These brines are designed to minimize formation damage and can be weighted by the addition of high concentrations of inorganic salts. Sodium chloride, potassium chloride, calcium chloride and calcium bromide are often used as weighting agents. Brine densities of up to 15.1 pounds per gallon are possible using mixtures of calcium chloride and calcium bromide.
A commonly encountered problem in the use of solids free workover brines is loss of the fluid to the formation.
Application of Kinetic Hydrate Inhibitor in Black-Oil Flowlines
Authors: Mitchell G. F. , Talley L. D. 
Published: December 2007

Abstract
This paper presents the first commercial application in a crude oil system of a kinetic hydrate inhibitor (KHI) developed by Exxon. KHIs are water-soluble, non-toxic polymers that inhibit hydrate formation in pipelines at much lower dose rates than methanol or glycol by greatly slowing the rate of hydrate nucleation.
Following laboratory testing in Exxon's 4-in diameter hydrate flowloop at pressures up to 1800 psig, the KHI was field-tested in a 2-in diameter, 1.5-mi gas flowline in Alberta, Canada in 1996-97. The KHI was then commercialized in May 1998 and has since been used commercially in a variety of locations, including an 8-in diameter, 28-mi gas pipeline in the Gulf of Mexico. The economic and operating benefits of KHI have been clearly shown in these early applications.
In the application discussed here, KHI is being injected into a high-GOR flowline operated by Imperial Oil in the West Pembina field in Alberta, Canada. Prior to the winter of 1998-99, hydrate formation in this system was sporadic and was remediated by batch methanol treatment. KHI injection began February 1, 1999 and has since eliminated downtime due to hydrates. The KHI was proven effective at very low dose rates (0.5 gal/day in 16 bbl/day of produced water) and has not caused any observable impact in downstream facilities.
Results will be presented for subcooling performance, operability, shut-in performance, and economics relative to methanol. Imperial Oil has since elected to use KHI in three other flowlines in the West Pembina field.
The major conclusion of this work is that Exxon's KHI is effective in a crude oil system. The economic benefit of KHI is evident, as it was in earlier applications in gas-condensate fields. Operability of kinetic inhibitors is similar to methanol, and successful shut-ins and restarts are achievable.
Production of Biosurfactant and Biopolymer from Malaysian Oil Fields Isolated Microorganisms
Authors: Illias R. M. , Ooi S. W. , Idris A. K. , Rahman W. A. W. A. 
Published: December 2007

Abstract
Facultative thermophilic microorganisms were isolated from oil and water samples from Malaysian oil wells. The isolated microorganisms grow in an enrichment medium containing kerosene (hydrocarbon) as the source of carbon and energy. Batch-growth kinetic studies were carried out in a 500 ml shake flask and the production of biosurfactant and biopolymer were found to be cell growth associated. Two of the isolated microorganisms (S24A and S21A) are capable of producing biosurfactant in sucrose and glucose containing medium. These are indicated by the reduction of interfacial tension (IFT) of the supernatant. These two strains obtained the IFT reduction in both sucrose and glucose medium for more than 20 dynes/cm. Strain S19 and S12A can reduce the surface activity of growth medium only in sucrose and glucose medium respectively. Strain S19 can reduce the IFT of sucrose growth medium for 25.27 dynes/cm and no decreased in surface tension and interfacial tension were observed when S19 was grown in glucose medium. Adversely strain S12A can only reduce the IFT of glucose growth medium for more than 30 dynes/cm. Another two isolated bacteria was found to produce biopolymer and increase the viscosity of supernatant from 1 cp to 4 cp are strain S13 and S17A. These isolates produce exopolymer like material when grown on agar medium containing 5% sucrose.
Direct Finite Difference Simulation of A Gas Well with a Finite Capacity Vertical Fracture
Authors: Crafton J.W. , Harris C.D. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Numerical simulation of a well in a vertically fractured reservoir is described. Real gas potential is the dependent variable. A fractional step numerical method which simultaneously integrates the difference expressions of the reservoir and fracture in an economical manner is used. Simulations of well performance with constant well potential and at several fracture extents are shown and discussed.

Introduction
The increasing demand for an adequate supply of natural gas has caused the development of extremely low permeability gas reservoirs. This is now possible because hydraulic fracturing can produce fractures with radii of 500 feet or more and thus stimulate production to levels that are economic. Estimation of the benefits to result from the hydraulic generation of a fracture in a particular formation is desirable.
It is the authors' belief that the numerical model given here is sufficiently novel and advantageous to merit attention.
Real gas potential is the dependent variable. The fracture is taken to occupy a negligible volume when compared to the volume of the reservoir. Then there is not the difficult problem of giving numerical representation of the small fracture width and the large reservoir extent in the one model. Yet one-dimensional Darcy flow is modeled in the fracture and two-dimensional Darcy flow is modeled in the reservoir. The numerical replacements of those differential expressions are solved simultaneously with relative ease.
The numerical method used is from a class of methods called fractional step methods. Some recent results show how these methods lend themselves to the treatment of third type boundary conditions such as occur for this problem. Also, it is recognized that numerical methods of this type may yield solutions that exhibit peculiar behavior near boundaries. peculiar behavior near boundaries.
Field Application of an Alternative Foaming Agent for Coalbed Methane in the Nora Field in Southwestern Virginia
Authors: Myers R. R. , Mack D. J. , Awny J. A. , Creech G. 
Published: December 2007

Abstract
All surfactants used in hydraulic fracturing adsorb a thin film on the surface of coal within its cleat structure. Foaming agents have been known to persist in produced fluids for long periods of time post-treatment. When methane gas trapped in the coal's matrix begins to desorb and flow through the cleat network in the presence of water and a surfactant film, foam bubbles can form blocking flow of gas to the cleat system and the propped fracture. The net effect is a decrease in the relative gas permeability. The direct result is less gas production.
A novel surfactant or foaming agent has been identified as being much less damaging to relative gas permeability. This paper documents the move from the laboratory to the field of this foaming agent in the first known field trial to validate its potential to improve gas production.
Analysis of Worldwide Natural Gas Production
Authors: Al-Fattah S. M. , Startzman R. A. 
Published: December 2007

Abstract
Natural gas is an increasingly important source of the world's energy. Estimating future supplies of this valuable commodity is an important economic and strategic endeavor. This paper analyses historical natural gas production trends for the 53 countries that produce virtually all of the world's natural gas. Using a multicyclic Hubbert method, we forecast the world's future supply of natural gas to the year 2050.
Our analysis showed that the world ultimate reserves of conventional natural gas will be around 10,000 Tcf, of which about 7,900 Tcf of gas reserves remains to be recovered at the end of 1997. The world production of natural gas is expected to peak by 2014 at a production rate extending from 2012 until 2017 of approximately 99 Tcf/yr. Based on the 1997 world gas production and the results of this study, the world supply of conventional natural gas will continue for 96 years with reserves depletion rate of 1%/yr.
In his 1956, and later 1980, predictions of U.S. natural gas production, M. King Hubbert1 - 4 used one complete production cycle to forecast production and estimate ultimate recovery of natural gas for the United States. Several authors have shown that Hubbert's model with one production cycle is generally adequate for predicting crude oil production. However, this study shows that, in the case of natural gas production, most countries exhibit two or more Hubbert-type production cycles. These additional cycles apparently result from changing exploration technology, regulations, and economic and/or political events. Using a Hubbert model with a single production cycle did not allow for these factors. We found that most of the 53 countries apparently exhibit multicyclic gas production. To account for additional production cycles we used a modified version of the Hubbert model which is referred to as the "multicyclic Hubbert" model. A nonlinear least-squares regression was used to determine the parameters of the multicyclic model for each country. Exploration data, when available, were used to calibrate country models with production data. We also present a mathematical analysis of the Hubbert model by deriving equations for determining the production rates at inflection points and their time of occurrence on the Hubbert curve. We will demonstrate a graphical technique to verify the results.
An Effective Technique to Integrate Core and Wireline NMR Log Data through Relaxivity Grouping or NMR Facies Identification
Authors: Ohen Henry A. , Enwere Paulinus M. , Egwim Rising C. 
Published: December 2007

Abstract
Interpretation of nuclear magnetic resonance (NMR) logs is challenged by the following three factors (1) incpnrect-critical T2 cutoff foF free fluid index (2) incorrect permeability model and (3) effect of unusual.relaxivity properties of the rock on relaxation times. Some of these challenges can be addressed through the use of NMR core spectrometry data for log calibration. The major difficulty lies in the ability or inability to apply the core data correctly in log calibration.
In this work, we demonstrate that the identification and delineation of NMR relaxivity group or NMR facies are critical in the application of laboratory NMR calibration data to log analysis. The method presented also allows direct application of laboratory-based model for log interpretation irrespective of tool-dependent factors like logging speed, borehole conditions, fluid types and saturation.
In developing this technique, the following were taken into consideration (1), the fundamental physics of the behaviour of the magnetic dipole of hydrogen nuclei in the presence of an applied (external) magnetic field, (2), the mathematical relationship between the relaxation rates of magnetisation, the pore size that contain the liquid and other surface properties of the porous media, and (3), the mineralogital attributes of the formation.
We define NMR facies as units in the reservoir that have similar NMR relaxation characteristics. These units are delineated into groups referred to as relaxivity groups. Each relaxivity group has similar T2 cut off and relaxivity product. The combined influence of mineralogicai and textural attributes on relaxation rate is captured in this method.
Delineation of these groups is based on NMR porosity and normalised median value of the relaxation time, T2m. These data can be obtained directly from NMR log data.
The validity and applicability of the methodology is demonstrated by a regional study of NMR transverse relaxation time constant T2. Measurement were carried out on over 400 core plugs, and mineralogical, textural and pore size attributes on selected samples.
The benefits of NMR relaxivity grouping include:
Basis for tool calibration and enhanced interpretation of NMR log output. Algorithm for permeaoility and residual oil saturation determination.