bluuebunny/crossref_metadata_2025_split huggingface dataset:
Waste Disposal and Earthquakes at the Rocky Mountain Arsenal, Derby, Colorado
Authors: van Poollen H.K. , Hoover D.B. 
Published: December 2007

The seismic activity triggered by injection into the RMA well at Derby, and the earthquakes that continued after injection was stopped should serve as a warning to the waste disposal engineer that no underground disposal project is routine. project is routine. Introduction
From 1962 until 1966, waste fluids were injected into the pre-Cambrian formations northwest of Denver, Colo. Since injection started into the 12,000-ft well, earthquakes have been observed in the area. This seismic activity, although different in character, continued when injection was stopped. Consideration has been given to removal of the waste fluids from the well to reduce earthquake magnitude and frequency. This article is a case history of the well, its operation, the observed earthquakes, and a discussion of possible mechanisms. Considerable information is available in various reports. See the references for more detailed information than can be given here.

Drilling and Completion
The Rocky Mountain Arsenal (RMA) disposed of waste waters by various means until 1961, when the deep waste disposal well was completed. Before the well was completed eight geologic formations were considered as possible injection reservoirs: the Hygiene sandstone, the Codell sandstone, the "J" sandstone, the Dakota sandstone, the Morrison formation, the Lyons formation and the Fountain formation. The hole was to be drilled to a total depth to penetrate the pre-Cambrian rocks. pre-Cambrian rocks. During drilling it was found that the potential reservoirs were tightly cemented with silica and that Cambrian was then considered as a disposal prospect. Waste disposal through wells is practiced in many states. The RMA disposal well is unique in that it is by far the deepest (12,000 ft) and in that the reservoir consists of fractures in crystalline rock as opposed to sedimentary rocks in other projects. Operating conditions of the well fall within the range of all wells. The maximum wellhead injection pressure for the RMA well was 1,100 psi during an injection rate of 300 gal/min. The greatest depth of other waste disposal wells is 7,650 ft; the maximum wellhead pressure is 400 psi, and the maximum injection rate is 700 gal/ min. During the drilling of the well, lost circulation was observed in the Lyons formation (9,582 to 9,772 ft). Eight instances of mud losses were noted. These ranged from a 10- to a 320-bbl loss. Cores indicated the formation to be fractured. The Fountain formation (9,772 to 11,880 ft) appeared to be highly fractured to a depth of 10,400 ft, with some fracturing at greater depths. Lost circulation was frequently experienced while drilling through the Fountain, mostly between 9,960 and 10,250 ft. The lowest mud loss took place at 11,080 and was the most serious one in the well, with some 1,350 bbl lost. The well was cased to 11,171 ft and subsequent drilling did not encounter lost circulation until after a core was cut in the pre-Cambrian (11,950 ft total depth).
P. 983
Simplified Gravity-Drainage Oil-Production Model for Mature Steamfloods
Authors: Closmann P. J. 
Published: December 2007

SummaryA model has been formulated for estimating the oil production during the mature phase of a steam-injection process. This model assumes that complete steam overlay has occurred and that subsequent gravity drainage of oil is accelerated because of the viscosity reduction in the heated-oil phase. The predicted oil-production rate declines approximately linearly at early times, depending on the initial oil level in the reservoir and at a gradually decreasing rate toward zero at long times. The model shows good agreement with various field cases.
Laboratory and Numerical Discontinuum Modeling of Wellbore Stability
Authors: Rawlings C.G. , Barton N.R. , Bandis S.C. , Addis M.A. , Gutierrez M.S. 
Published: December 2007

Summary
Wellbore-stability analyses based on intact wellbore walls can be too conservative because failed/fractured zones around wellbores relieve stress and give support. Wellbore-breakout analyses indicate that most drilled wells experience deformation beyond the rupture stage and that this deformation is acceptable for the drilling process. Validation of the methods available to predict wellbore stability requires a comparison of theoretical models with experimental simulations of wellbore behavior. This paper describes a series of scaled laboratory wellbore-stability experiments carried out under various borehole inclinations and stress conditions. The goal was to investigate the influence of the fractured zone, stress anisotropy, well deviation, and well orientation on wellbore stability. Classic log spiral fracture geometries were obtained around the wellbore, and the effect of the fractured zone on wellbore stability was studied with a distinct-element program called the universal distinct-element code (UDEC). Results show the importance of taking into account the stability of the fractured zone and subsequent wellbore breakout when wellbore stability is considered.

Introduction
Wellbore stability requires a proper balance between the uncontrollable factors of earth stresses, rock strength, and pore pressure and the controllable factors of wellbore fluid pressure and mud chemical composition. The causes of instability can be classified as either chemical or mechanical effects (this paper considers only mechanical effects). Recent research into wellbore stability concentrated on assessing the problem from a continuous-media concept. This paper, however, also assesses the stability of the fractured "breakout" zone around wellbores with UDEC.
The increasing use of deviated, extended-reach, and horizontal wells has escalated the demand for wellbore-stability studies during the planning stages of oil and gas fields. Continuum analytical and numerical models used to predict wellbore stability generally consider the stresses developed in a plane perpendicular to the wellbore axis and how these stresses compare with the strength of the surrounding material (obtained from triaxial tests).
Successful Control of Fracture Height Growth by Placement of Artificial Barrier
Authors: Mukherjee Hemanta , Paoli B. F. , McDonald Todd , Cartaya Hugo , Anderson J. A. 
Published: December 2007

Abstract
This paper presents a method to control fracture height growth through the selective placement of artificial barriers above and below the pay zone. These barriers are created prior to the actual treatment by pumping a mix of different size and density proppants with low viscosity carrying fluid, that allows fast settling of these proppants or, if desired, floatation to the top of the fracture channel or both. Typically a viscous pad is pumped to create a fracture channel. This pad is followed with 5–10 cp fluid slurry carrying a mix of heavier proppant that settles to the bottom of the fracture channel and a light proppant that rises to the top of the fracture channel. The proppant slurry is allowed to bridge at the top or the bottom tip of the fracture, inhibiting further growth of these tips. The actual treatment following this barrier placement is thus focused through these barriers confining itself within the barriers and resulting in a longer extension within the pay zone. Such controlled fracture height allows further optimization of fracture length by reducing or increasing the amount of proppant as called for in the design. Two case studies are presented in this paper from two formations known to suffer from fracture height growth.
Low-Permeability Gas Well Performance At Constant Pressure
Authors: Stewart Paul R. 
Published: December 2007

Presented here is an analysis of the long-term production performance of some low-permeability wells in the Big Piney-LaBarge Frontier gas field of Wyoming. A rigorous technique is proposed for predicting the abandonment pressure, and thus the recovery efficiency, of such gas wells.

Introduction
The petroleum industry's search for new natural gas reserves has progressively led to the development of reservoirs that have been assumed to be too tight to provide a reasonable return on invested capital. The Frontier reservoir in the Big Piney-LaBarge field of Wyoming is an excellent example of a lower-permeability field that, through the use of sophisticated sand-fracturing techniques, is now a profitable operation, with initial recoverable reserves in excess of 3 Tcf.
The Big Piney-LaBarge Frontier gas field is located along the western margin of the Green River Basin in western Wyoming. It is approximately 25 miles long, has a maximum width of 16 miles, and is located on the LaBarge platform, which is basically a large anticlinal structure overridden by thrust faulting from the west. It is the largest gas field in Wyoming, in both size and production rate, currently producing approximately 160 MMcf/D from about 220 wells. Cumulative production to date is more than 550 Bcf. Overall spacing is essentially 320 acres/well, with recent infill drilling programs on 160 acres in selected areas.
The Frontier formation, of Cretaceous age, has been separated into the First, Second, and Third Frontier zones. The average gross interval covered by these zones is 650 ft, with approximately 130 ft of gross sand and 35 t of net sand. All productive zones are commonly combined and produced as one "reservoir".
The zones are very widespread but they are very heterogeneous both laterally and vertically, and vary from fine- to medium-grained, well sorted to conglomeritic, with variable amounts of silt and clay matrix. Eastward, the sands become progressively more silty and tighter. Porosities are rather uniform, but permeabilities are extremely variable, and generally quite low. Over-all average rock and gas properties are as follows:Effective porosity 16 percentWater saturation 40 percentPermeability (absolute) 1 mdPermeability (to gas) 0.5 mdAverage perforated depth 7,050 ft (+ 150 ft)Bottom-hole temperature 165°FCondensate content 5 bbl/MMcf
Prediction of Deposition of Calcium Sulfate Scale Under Down-Hole Conditions
Authors: Vetter O.J.G. , Phillips R.C. 
Published: December 2007

The thermodynamic method of calculating calcium sulfate scale has been improved by including the effects of complicated down-hole phase equilibria. Although the modified method has its limitations, it appears to provide more reliable results.

Introduction
Calcium sulfate (CaSO4) scale, especially gypsum, still causes unpredictable problems in many oil fields. This type of scale can cause severe plugging of equipment and producing formations; it creates the necessity of costly workovers and stimulation jobs. The best method for combating this scale seems to be the application of inhibitors - for example, by squeeze techniques - before the scale is formed. The reason is obvious: it is much more economical to prevent the formation of scale than to repair the damage caused by it. To apply the most suitable inhibition method, we have to know if and to what extent scaling occurs. At least some knowledge about the likely location of scale within the wall is equally important. The present methods of predicting scale in an oil field do not give all the answers, even though the literature contains enough data to develop and prove a more precise and reliable method.
It is still common practice to wait for a production decline in the field, then pull the tubing and find - more or less accidentally - scale on the now-exposed metal surface. This scale sample is considered a proof for the occurrence of scale. This procedure can be very costly, and irreparable damage can be done before the scale is detected. Besides, this method fails frequently because scaling can occur even without the deposition of scale in the tubing.
A better method for scale prediction is the use of water analyses and solubility data of CaSO4 compounds in the oilfield brines. There are many publications1–9,12,13,15,16 on the solubility of calcium sulfate compounds in water and brines at 1 atm. Most of the data in these publications are in good agreement. Together with the information from the water analyses, they are used to predict potential scale deposition. Diagrams, empirical equations, or thermodynamic relations are used to find the "maximum" solubility of calcium sulfate, mostly gypsum, in a water of similar composition.6–9,12–14 If the Ca++ and SO4-- concentrations in the actual water approximate the calculated "maximum" concentration of CaSO4, the field brine is said to have a "scaling tendency". We believe that this method can give only vague and unreliable information because it gives the solubility of CaSO4 or its hydrates at 1 atm only.
Digital-Log Management System
Authors: Tan A. A. , Potts J. K. 
Published: December 2007

Summary
Digital-log data is essential to any petrophysical and log-correlation software package. Gathering of such data, however, is often painstaking and laborious. A significant portion of the interpreter's valuable time is spent in data compilation and verification. In response to this data management need in Conoco, the digital-log management system (called LMS) was developed.
The LMS uses existing data-storage standards and stable technology to implement a common digital-log management solution throughout the company. To achieve system portability, LMS is delivered with a stable well-data model and a comprehensive log catalogue maintained in a relational database.
1993 U.S. Petroleum Engineering Manpower Supply and Demand
Authors: Wattenbarger R.A. , Morriss Steven 
Published: December 2007

Summary
The SPE Manpower Committee's U.S. surveys show that large companies will decrease their hiring while small companies and service companies will increase their hiring of engineers. During 1992–93, only about 65% of graduating petroleum engineering students were known to have jobs. Another finding is that, overall, new U.S. SPE membership is decreasing, while non-U.S. membership is increasing.

Introduction
Each year, the SPE Manpower Committee reports on the results of petroleum engineering manpower supply and demand surveys to inform SPE members about hiring patterns of engineers in the petroleum industry and the supply of graduates from U.S. petroleum engineering schools.
The 1993 demand survey was sent to selected employers of petroleum engineering graduates, including large and small producing companies and service companies. Only 19 companies responded with usable surveys, compared with 26 usable surveys returned last year (see Table 1). Companies were asked to report on four items: total engineering graduates employed at year-end, petroleum engineering graduates employed at year-end, total engineering graduates hired on campus, and petroleum engineering graduates hired on campus.
For each item, companies reported an actual figure for 1992 and forecasted values for 1993–95. Forecasted figures included estimates for high, low, and most likely scenarios for 1994–95. Table 1 compares this year's demand survey response with last year's response.
The 1992–93 supply survey was sent to all petroleum engineering schools in the U.S., including those offering petroleum engineering options within other degree programs. Like last year, 20 schools responded to the survey. This response represents about 90% of the petroleum engineering enrollment in the U.S.
For the 1992–93 (actual) and 1993–94 and 1994–95 (forecast) academic years, each school reported (1) BS-, MS-, and PhD-degree graduates, total and those seeking employment, and (2) employment of 1992–93 graduates by type of employer. It was assumed that the 1992–93 academic year graduates would be hired in the 1993 calendar year, and so on. Students not seeking employment included international students returning home and students entering graduate school or the military.

Demand Survey
Producing companies responding to the demand survey were divided into large-company and small-company groups on the basis of their engineering employment. Companies employing 150 or more engineers were considered large companies. This group corresponds to the top 13 oil and gas producers on the basis of equivalent U.S. daily oil production. The "top 13" group accounts for about 84% of U.S. production. Seven usable responses were obtained from this group, representing a total engineering employment of 4,007 at year-end 1993.
A Critical Evaluation of Short and Long Range Correlation Methods for Heterogeneous Rocks
Authors: Du Changan , Ershaghi Iraj 
Published: December 2007

Abstract
Indications of short and long range correlation are important basis for stochastic modeling of geological reservoirs. This paper examines the merits of various statistical methods for recognizing rock properties correlations in vertical columns. Specifically the persistence of patterns analyzed by the R/S method were analyzed with the application of semi-variogram and power spectral density methods. From synthetically generated patterns (fGn, fBm), short and long range correlations for large data sets corresponding to pure, layered and composite homogeneous and heterogeneous sets was analyzed. Additionally, the impact of the overlap averaging on the estimation of correlation were evaluated. Concurrent analysis using the three techniques is shown to enhance the interpretation of the correlation type.
Discrimination Between Reservoir Models in Well-Test Analysis
Authors: Anraku Toshiyuki , Home R. N. 
Published: December 2007

Summary
In well-test analysis with nonlinear regression, discrimination between candidate reservoir models is a key procedure. Graphical analysis now performs this step, with the pressure derivative plot and confidence intervals used to select an adequate model. Human bias may influence the selection by graphical analysis, however, and the result may vary according to the interpreters. Confidence intervals can give a quantitative evaluation of model discrimination, but it sometimes provides inappropriate results.
We propose a new quantitative method, the sequential predictive probability method, to discriminate between candidate reservoir models. This method is based on Bayesian inference, in which all information about the reservoir model and, subsequently, the reservoir parameters deduced from well-test data, is expressed in terms of probability and is regarded as a direct extension of the idea of confidence intervals. This method gives a unified measure of model discrimination. We demonstrate the applications of this method to synthetic and actual field well-test data.
Pull-Through Forces in Buckled Tubing
Authors: Mitchell R. F. 
Published: December 2007

Abstract
Conventional analysis of tool passage through buckled tubing is based on planar curvature assumptions. However, helical buckling involves three-dimensional geometry which can be further complicated by wellbore curvature. This paper is an analysis of tool clearances within tubing, including the effects of tool orientation, helical buckling and wellbore curvature. The maximum free passage tool length for combined buckling and wellbore curvature is determined. Alternately, the minimum pull-through force for a given tool length is determined.
A New Method of Overbalanced Perforating and Surging of Resin for Sand Control
Authors: Dees John M. , Handren Patrick J. 
Published: December 2007

Summary
Gravel packing of perforations is the conventional method for sand control in the petroleum industry. Case histories of 12 well treatments provide details of a new procedure for high-energy resin placement that controls sand in a formation. The new consolidation method uses an extremely overbalanced pressure surge with liquid resin on perforations. This paper presents the problem, theory, process description, job procedure, and results of resin treatments with perforating or surging with a high-energy overbalanced pressure pulse. Highlights include potential applications. Benefits of the technique include accelerating on-line production and reducing completion rig time spent on controlling sand. The method appears to yield equal or better results than previous conventional gravel-packing techniques.

Introduction
The underbalanced method is the petroleum industry standard for perforating wells requiring sand control. Efforts to prevent the perforating guns from sanding up with for mation sand restrict the amount of underbalanced differential pressure. Sufficient underbalanced pressures for full perforation cleanup is not standard. Perforations that are not cleaned adequately will not readily accept resin during matrix injection.
Operating companies took underbalanced perforating to offshore operations with the introduction of tubing-conveyed perforating guns in 1970. Today, few offshore operators consider overbalanced pressure in wellbores when perforating a well for sand control. Environmental concerns or equipment limitations provide a few cases of overbalanced perforating. In these rare instances, the fluid hydrostatic pressure will slightly exceed reservoir pressure. This reduces fluid invasion from mud or expensive brine water before the gravel-pack procedure.
Until now, the industry has accepted underbalanced perforating and gravel packing as the best way to complete a well for sand control. Oryx Energy Co. began a research project on sand control in wells with gas generators and resin in Oct. 1988. Success with the propellant-gas fracture resin placement method led to extension of the research to include extreme overbalanced perforating with resin in Aug. 1990. The downhole high-energy placement of resin for sand control now challenges the industry's conventional standard of underbalanced perforating and gravel packing for sand control.