bluuebunny/crossref_metadata_2025_split huggingface dataset:
Exploration and Production Economics of Low-Permeability Shallow Gas Formations In Appalachia
Authors: Vadgama Usman N. , Hinkle Bill B. 
Published: December 2007

Like an old spring that never will become a mighty Mississippi, but that you can count on endlessly for your own needs, many of the gas wells in Appalachia are lean but dependable. They may not be the Big Stuff, but they don't cost an arm and a leg, either.

Introduction
Recently, much has been said and published in the literature on the probable future energy supply and demand structure of the U. S. There is no need to emphasize further the scarcity of future energy supply or criticize regulatory bodies. Forecasts are that by 1990 the natural gas industry must supply more than 46 Tcf annually to meet America's consumer requirements. This is almost three times the current annual gas sales. All possible mean must be activated to meet those demands. One of the possible supplemental sources is an efficient exploitation of the known reservoirs. In an attempt to find new gas reserves in Appalachia, much attention has recently been given to deep drilling to test additional sediments. But there remain in this region huge expanses of shallow gas-bearing formations that are only partly developed. The further development of these sources has been restricted because of increasing drilling and operating costs and depressed gas prices, and the poor cash flows associated with low-deliverability wells. The petroleum industry's urgent need for additional reserves, coupled with recent intrastate price increases, has led many operators in other areas to develop reservoirs that were once considered too tight to provide a reasonable return on investment. Adding these factors, as well as relatively low leasing and rental costs, to the existence of sophisticated completion techniques has made the development of lower-permeability fields profitable. The Appalachian basin is worth an intensive second look. This report is based on 40 years of historical data on drilling costs, pressure buildups, open-flow potentials, and deliverabilities for more than 2,000 wells in eastern Kentucky, West Virginia, and Virginia. It analyzes from an economic point of view the exploration and production performance of shallow gas formations. performance of shallow gas formations. Shallow Gas Formations in the Appalachian Basin
Natural gas in the Appalachian basin is found in a large section from Cambrian to Permian age and covers geographically most of the basin. However, the most extensive fields are in Pennsylvania, West Virginia, and Kentucky and the greatest production has come from there. It is not our intention to go into detail on the geology of the area. Neither do we propose to cover the production performance of the propose to cover the production performance of the entire Appalachian basin. Our observations are limited to the shallow gas formations found mainly in eastern Kentucky, West Virginia, and Virginia. The analysis is based on data from the leases operated by Ashland Oil, Inc.
JPT
P. 985
In-Situ Acid Neutralization System Solves Facility Upset Problems
Authors: Greene E.B. , Lybarger J.H. , Richardson E.A. 
Published: December 2007

Introduction
Much of the world's crude oil is produced as emulsions that must be treated (demulsified) to be marketed. Normally, these emulsions can be readily broken by the addition of small amounts of demulsification chemicals, retention time, and, if necessary, heat. However, the oil produced from wells after an acid stimulation can be extremely difficult to treat, even with heat and large additions of treating chemicals. Poor demulsification can result in curtailed production, wet oil at the sales point, and large amounts of oil in the effluent water.There appear to be three basic reasons why emulsions from acid returns are more difficult to treat than normal production.1. Crude oils often contain organic acids and bases. Neutralization of these acids and bases can result in surface-active compounds that will lower the oil/water interfacial tension. With a lower oil/ water interfacial tension, the stable size of the dispersed droplet in the emulsion is much finer at any fixed agitation and thus more difficult than normal to demulsify. Fig. 1 shows the lowering of the oil/ water interfacial tension for an East Bay, La., crude in both the acid and the base.2. Acid media tend to result in adsorbed organic films at the oil/water interface. These films (generally asphaltenes and resins) act as physical barriers to the coalescence of the dispersed droplets. The strength of the films is increased at lower pH's.3. Acid can alter the wettability of loosened formation fines so that the new oil-wetted solids stabilize the emulsion. Like film strength, the apparent oil wetting is increased at lower pH's.We have developed a method to avoid these emulsion upset problems by controlling the pH of the return fluids.

Acid Spending System and Design
A technique has been developed to neutralize acid in situ. The system, designed to avoid both pH extremes of the returning acid treatments, consists of adding the diamide urea and an amide, such as acetamide or dimethyl formamide, to the acid.
JPT
P. 1153
Some Sidelights in Petroleum's Economic Progress
Authors: Willson C.O. 
Published: December 2007

This discussion concerns what might be considered the by-product developments and trends, or parts of the whole, within the oil industry which come to the attention of an editor in connection with his daily and weekly tasks.

Future Demands
Predicting yearly petroleum demands has become a somewhat hazardous undertaking in this country since World War II. In some years the projections have varied so widely from actual demands as they have materialized that they have lost much of their value as a guide to operators. For example. most of the projections of a year ago called for an increase in 1954 U. S. demands of 4 to 4 1/2 per cent over 1953. The increase was less than 1 per cent. This means that the actual demand was around 250,000 B/D less than the anticipated level of operation, and that fact accounts for some of the unwanted oil developments of the past year.
It is true, however, that the good years tend to offset the poor ones so that the five and 10-year periods work out, as regards demands, more in line with predictions. With this situation in mind some economists are predicting more than average gains for 1955. Keeping in mind that in these days of surpluses it is easier and less painful to expand operations than it is to contract them, a gain of 5% per cent domestic appears reasonable at this time. With a further decrease in exports in prospect we end Lip with a 4.8 per cent gain in over-all demands.
This will total an estimated 8,483,560 B/D in this country for this year or a gain of 388,560 B/D over the year that has just closed. Of this total gain of 141,824,400 bbl for the entire year it is estimated that 78 per cent will come from domestic crude oil producers, 12 1/2 per cent from imports. and 8 1/2 per cent from natural gas liquids.
Analysis Procedure for Variable-Rate Pressure Drawdown Data
Authors: Lee W.J. , Harrell R.R. , McCain W.D. 
Published: December 2007

Use of pressure drawdown tests to characterize gas wells has long been accepted, in principle, to be an excellent formation evaluation technique. In practice, however, the theoretical requirement that flow rates must be maintained strictly constant during the test has led to two major problems:the constant flow rate requirement is frequently ignored, and use of conventional analysis on such tests has led to serious error in many cases, leading to a loss of confidence in drawdown testing; orthe constant flow rate is maintained, but only with a great deal of difficulty.
Winestock and Colpitts showed that both problems could be avoided if gas-well drawdown tests were run with a fixed choke - usually resulting in a slowly decreasing flow rate during the test - if a simple modification of conventional analysis theory is employed. In fact, Winestock and Colpitts claimed that the method they proposed would be adequate in general for smoothly varying flow rates, even though the total change in flow rate from beginning to end of a test was large. This claim requires justification because the method proposed by Winestock and Colpitts is an approximation, and it clearly must fail when the rate of change in flow rate is sufficiently large. The purpose of our investigations, therefore, was to find the limits of applicability of the Winestock and Colpitts method.
First, we reviewed their proposed method and the reason for the method. A frequently used equation describing a pressure drawdown test in a gas well is pressure drawdown test in a gas well is+F (1)
In this equation all terms except flowing bottom-hole pressure, Pwf, and test time, t, are assumed to be constant. Winestock Pwf, and test time, t, are assumed to be constant. Winestock and Colpitts point out that use of the equation in this form can lead to serious errors if it is applied to analyze drawdown tests in which flow rates vary even slightly during the test. They propose, however, that for a test with flow rate varying slightly, the test is modeled adequately by a simple rearrangement of Eq. 1:
= 712 (2)
They propose that the entire group on the left side of Eq. 2, consisting of two variables, bottom-hole flowing pressure, Pwf, and gas production rate qr, both measured pressure, Pwf, and gas production rate qr, both measured during the test, be plotted against the logarithm of test time, t. The permeability thickness product would then be a function of the slope of the resulting line. The turbulence constant, F B, must be obtained before this graph can be prepared.
P. 115
The Effect of Asphaltene Precipitation on Carbonate-Rock Permeability: An Experimental and Numerical Approach
Authors: Ali M. A. , Islam M. R. 
Published: December 2007

SummaryA series of experiments was carried out to determine the effect of asphaltene precipitation on the intrinsic permeability of carbonate rocks. Experiments indicated the existence of three different flow regimes, namely monotonous steady state, quasisteady state, and continuous plugging. The numerical model helped identify mech- anisms involved in these flow regimes. The existence of a contin- uous plugging regime at a high flow rate is of particular concern in the petroleum industry because of increased probability of plugging near the wellbore. The numerical model couples the surface excess theory for adsorption with the mechanical entrapment theory. The mathematical model accurately predicts permeability damage from mechanical trapping and adsorption. The model predictions agree favorably with experimental results for different flow rates.
Developments in Synchrotron X-Ray Microtomography With Applications to Flow in Porous Media
Authors: Coles M. E. , Hazlett R. D. , Muegge E. L. , Jones K. W. , Andrews B. , Dowd B. , Siddons P. , Peskin A. , Spanne P. , Soll W. E. 
Published: December 2007

Summary
High resolution computed microtomography (CMT) with synchrotron X-ray sources provides the ability to obtain three-dimensional (3D) images of specimens with a spatial resolution on the order of micrometers. Microimaging capabilities at Brookhaven Natl. Laboratory's Natl. Synchrotron Light Source have been enhanced to provide larger and higher resolution 3D renderings of pore networks in reservoir rocks at a fraction of the time required in previous first generation scanning methods. Such data are used to model single and multiphase flow properties in digital images of real porous media. Pore networks are analyzed for tortuosity and connectivity measures, which have been elusive parameters in transport property models. We present examples of porosimetry simulation through network modeling to produce initial water saturation and residual oil distributions in a water-wet pore system. Furthermore, pore networks can provide the boundary condition framework for more rigorous simulations of displacement, such as in the lattice Boltzmann simulated waterflood example provided. Direct comparison between simulation and experiment is also possible. CMT images of a 6-mm subsection of a 1-in. diameter reservoir core sample were obtained before and after flooding to residual oil. The fluid distributions from CMT, lattice Boltzmann waterflood simulation, and percolation-based network modeling were found to be highly correlated. Advances in 3D visualization will allow even greater digestion and interpretation of phenomena dependent upon pore interconnectivity and multipore interactions.
New Well Architectures Increase Gas Recovery and Reduce Drilling Costs
Authors: Horn M. J. , Plathey D. P. 
Published: December 2007

Summary
Gas recovery on the Bongkot field has increased by 5% and well costs have decreased by 50% over a 4 year period. This was achieved by modifying the production strategy, and evolving well designs from classic multizone completions to tubingless monobore designs. Tubingless well designs have allowed a more aggressive perforating strategy, which taps gas reserves that were previously lost. Reduced consumable requirements and elimination of completion operations have contributed to lower overall well costs. This paper describes the process that led to the development of the tubingless design.
Fracturing, Frac Packing, and Formation Failure Control: Can Screenless Completions Prevent Sand Production?
Authors: Morita Nobuo , Burton R. C. , Davis Eric 
Published: December 2007

Summary
Some successful results have been reported for screenless frac-packing methods1–3; however, no scientific guidelines were given regarding the conditions under which a screen can be eliminated from a well. In this paper, we report field data from sand-producing wells and review the onset and the rate of sand production for those wells with and without hydraulic fractures. From these field observations and numerical modeling analysis, we give guidelines for when a screen must be run and when a screen can be eliminated.
Practical Application of NMR Logging in Carbonate Reservoirs
Authors: Logan W. D. , Horkowitz J. P. , Laronga Robert , Cromwell D. W. 
Published: December 2007

Summary
Nuclear magnetic resonance (NMR) data acquisition and interpretation in carbonate reservoirs is much more challenging than in sandstones, where it is a well-established technology. Heterogeneous porosity distribution, a broad range of pore sizes, a wide variety of complex textures, and low surface relaxivity combine to complicate the picture considerably. The successful practical application of NMR in these reservoirs requires the development of acquisition and interpretation techniques specifically suited to the task.
In carbonate reservoirs dominated by intercrystalline or inter-granular porosity, NMR can deliver accurate estimates of porosity, permeability, bound fluid volume, and residual oil saturation (ROS). In heterogeneous carbonate reservoirs more complex interpretation models are required, normally based on the integration of whole core and log data. NMR answer products, based on these new techniques, are presented and validated with core data and by comparison with other logging measurements.
Numerical Study of Natural Convection and Diffusion in Fractured Porous Media
Authors: Ghorayeb Kassem , Firoozabadi Abbas 
Published: December 2007

Summary
Compositional variation in a rectangular two-dimensional (x,z) fractured porous medium containing a two-component singlephase fluid in the presence of a prescribed linear temperature field is considered. The work examines the effect of the fracture parameters: fracture aperture (or fracture permeability), fracture intensity, and fracture connectivity on the fluid compositional variation. Numerical results reveal that, for a high fracture aperture, a pronounced convective motion within the fractures takes place, whereas the composition is only affected beyond a certain fracture aperture. The effect of connected and discrete fractures on compositional variation is also studied; connected fractures influence the compositional variation much more than discrete fractures, as expected. The convection cells are mainly loops which develop within the connected fractures.
Pressure-History Inversion for Interpretation of Fracture Treatments
Authors: Gulrajani S. N. , Mack M. G. , Elbel J. L. 
Published: December 2007

Summary
Conventional analysis of hydraulic fracturing treatments with analytical solutions is based on idealized assumptions, which limits its usefulness in many applications. Manual (trial and error) pressure matching techniques by means of a fracture simulator are laborious and consider only one parameter at a time. This paper presents an alternative technique for consistent analysis of pressure records during both injection and decline, including changes caused by rate and fluid viscosity variations. This allows it to be used to analyze calibration as well as propped treatment pressures, which gives it broad field application. The technique includes a formal inversion procedure coupled with a hydraulic fracture simulator that includes both two-dimensional fracture models and a pseudo-three-dimensional height growth model. The algorithm is extended to identify the occurrence of nonuniqueness, an inherent limitation in any fracturing pressure interpretation.
Comprehensive case studies from fracture treatments in different formations in North America, the North Sea, and Africa are presented. Calibration treatments are first analyzed with this technique, then propped treatment pressures are predicted and then confirmed with field measurements. The analysis is applied to both normal and tip-screenout treatments, some with pressure records showing near-wellbore pressure losses. Good agreement between the predicted and measured pressures in these cases shows the validity of the algorithm and confirms its use for field application.
Rheological Properties of Low-Gel-Loading Borate Fracture Gels
Authors: Harris P. C. , Heath S. J. 
Published: December 2007

Summary
This paper presents a study of hydration, crosslinking, and rheological properties of 15- to 25-lbm/1,000-gal optimized borate-crosslinked guar fluids. Hydration and crosslinking properties of fluids were measured in a new turbulent flow-loop viscometer to simulate the high shear mixing of fracture fluids in surface equipment and the pumping of the fluids down tubulars. Fluids were then heated and measured in laminar flow to simulate fluid flow in a fracture. The effects of conditioning crosslinked fluids in high shear rate flow on laminar flow properties were observed.
Hydration rates were measured for guar at different levels of shear history. Optimum shear levels and times for hydration were observed for the time-dependent base gel fluids. The properties of the crosslinked fluid were critically dependent upon the base gel fluid state of hydration before crosslinking. Properly crosslinked fluids did not shear-thin back to base gel levels but maintained significant viscosity even at high shear levels.
Power-law index values were measured for low-polymer borate fluids with a three-viscometer method that uses constant shear rates. Lower values of n′ were found for the new fluids compared with conventional borate fluids with similar polymer loadings. Proppant transport properties were qualitatively observed in a transparent slot model showing good transport for both an optimized 25-lbm/1,000-gal borate fluid and a conventional 35-lbm/1,000-gal borate fluid.
Development of a Bubble-Population Correlation for Foam-Flow Modeling in Porous Media
Authors: Bertin H. J. , Quintard M. Y. , Castanier L. M. 
Published: December 2007

SummaryThis study shows a bubble-population correlation based on experimental observations and theoretical results obtained at the pore scale (micromodels, network modeling) and at the core scale (transient foam flow in homogeneous media). In this correlation, we express explicitly the evolution of the mobile bubble density (the foam texture that governs foam viscosity) as a function of the physical properties of the porous medium (porosity, permeability, and capillary pressure) and the evolution of the mobile gas saturation. This correlation has been rather easily implemented in a numerical simulator and the resulting set of data has been matched against results of transient experiments performed with unconsolidated porous medium under a computerized tomography (CT) scanner as well as experiments performed in another research institution with natural sandstone. The match of the experimental data and the correlation are good. The results have also been compared with a complete simulation that uses the population-balance model. The agreement is excellent between the two types of models.This simplified formulation allows decoupling the effect of the porous media parameters, such as porosity, permeability, and capillary pressure, from the effects caused by the surfactant. It conserves most of the benefits of the physics of foam flow as seen in the literature.
Cold Production of Heavy Oil From Horizontal Wells in the Frog Lake Field
Authors: Huang W. S. , Marcum B. E. , Chase M. R. , Yu C. L. 
Published: December 2007

Summary
Texaco Canada Petroleum Inc. (TCPI) has successfully conducted a 10-horizontal well primary production pilot project at Frog Lake, Alberta, Canada. The gravity of the heavy oil ranges from 10 to 14°API, and the oil viscosity ranges from 20,000 to 50,000 cp. These 10 wells were completed in the Lower Waseca formation (one of five prospective formations in the field) and were produced by use of a coproduction of sand and oil from the reservoir at ambient temperatures, known as cold production. These wells were very successful, with most wells displaying productive capabilities in excess of 100 B/D. Based on the technical success of the 10-well pilot, a long-term staged development plan was established to resolve some technical challenges identified by the 10-well project. These challenges include reduction of operating costs and improvement of artificial lift and well reliability. As part of the development plan, over 70 horizontal wells have been drilled and production has peaked at 3,000 BOPD.
This paper summarizes the history of the Frog Lake field, completion and production techniques for the pilot project, and some of the operational and technical challenges encountered. A field-wide development strategy and potential for enhanced oil recovery (EOR) are also discussed.
Paraffin Deposition From Crude Oils: Comparison of Laboratory Results With Field Data
Authors: Hammami Ahmed , Raines M. A. 
Published: December 2007

Summary
In this study, we evaluate the characteristics of four reservoir fluids sampled from two offshore fields in the Gulf of Mexico as well as their propensities towards paraffins deposition due to temperature and/or pressure variations. State-of-the-art techniques, namely a cross polarized microscopy and a laser based solids detection system, have been used to measure the onsets of paraffin crystallization temperatures, also known as wax appearance temperatures (WAT) and/or cloud points. The results are presented, discussed and compared to reported field data. Explanations for the observed differences and/or similarities between laboratory and field WAT are proposed.