bluuebunny/crossref_metadata_2025_split huggingface dataset:
On the Design of Fracture Acidizing Treatments
Authors: Gdanski R. D. , Lee W. S. 
Published: December 2007

ABSTRACT
A fracture acidizing simulator has been written which incorporates many of the recent advances in fracture geometry and temperature calculations and the acid spending process with the many complex variables which affect acid spending. All the various effects have been coupled to reduce errors and improve simulation. A procedure which should effectively correlate laboratory acid-etched conductivity tests with anticipated field results has also been introduced.
Drillable Service Packer Systems Increase Well Service Versatility
Authors: Hushbeck D. F. , Streich S. G. 
Published: December 2007

Abstract
Cement retainers have changed very little in the past 10 years, but represent well developed technology. Their biggest shortcoming is a lack of versatility in that they are designed strictly for remedial cementing operations.
A new generation of drillable packers is becoming available to combine the convenience of drillability with the versatility of large bores and multiple valve options. These drillable service packers (DSP) will help fill the gap between drillable cement retainers and retrievable service packers. DSP are designed to give versatility so that time and money can be saved.
DSP will use valving similar to that in drillable cement retainers, which have been used for many years to control pressure and placement of cement during remedial cementing operations. This valving offers downhole pressure control that is not readily available with retrievable packers. This pressure control could be useful in operations outside remedial cementing to provide control before, during, and after testing and stimulation operations. Drillable service packers will allow for testing, treating, and squeeze operations to be performed through a single packer. This feature is extremely cost effective for both drilling and workover operations.
This paper will explore the use of drillable service packers and possible applications of this new downhole technology.
New Fluid-Loss Additives for Oilfield Cementing
Authors: Crema S. C. , Kucera C. H. , Konrad G. 
Published: December 2007

ABSTRACT
The proper cementation of a liner is an operation essential to the completion of an oilwell. A low fluid loss rate is required to prevent setting of the cement slurries before proper placement is achieved. Modified natural polymers are, at the present time, the most common fluid loss additives. However, temperature instability, retardation and high viscosity of the cement slurries are undesirable side effects of these additives. We have synthesized and tested a series of polymers and copolymers to identify potential fluid loss additives and to study the effect of various substituents on the effectiveness of the final material. Measurements of fluid loss, free water, rheology, thickening time and compressive strengths show that the developoment of good fluid loss control additives for cement depend upon careful control of copolymer composition and molecular weight.
Field Compressors for High Pressure Gas Injection Service
Authors: McCutchan Jerry M. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the 42nd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Oct. 1–4, 1967. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
This paper was formulated to assist production engineers with the design of unattended field gas compressor installations.
With the increasing use of field gas compressors in oil recovery, it is anticipated that the data in this report can be used to decrease the expense caused by usual experimentation in equipment and design for the initial compressor installation.
Experience gained in the design and installation of the Cities Service Oil Co. Dora Roberts Ranch Devonian unit and Virey Ellenburger gas injection projects, as shown on Fig. 2, was utilized. A general layout of a typical compressor installation is included as Fig. 3 and should be referred to as this paper is read.
Gas injection was begun in the Devonian unit in May, 1961, and in the Virey field in Jan., 1966. Because of the high revenue potential and the long productive life of these fields, slow speed, integral, gas engine driven compressors were selected. Since the injection locations are numerous and the predicted injectivity pattern indicated possible future changes, the advantages of having this equipment completely packaged was utilized.
Compressors with hp ratings of 180 and 330 were selected to best fit the required injectivity rates. These compressors were designed to boost 1,800 psig residue gas to discharge pressures up to 7,500 psig.
A survey of 21 gas compressors totaling 4,380 hp in the two fields was made for 1966. Average operating conditions were 1,800-psig suction and 5,800-psig discharge pressures. During 1966, these compressors handled 16,874,639 Mcf of gas. The average downtime for these packaged units for routine maintenance was 1.2 percent. Compressor maintenance expense averaged $19.12/hp. Compression cost, excluding depreciation, averaged 0.933 cents per Mcf.
The 180-hp compressors operated at 550 rpm and the 330-hp compressors operate at 400 rpm. The survey showed less downtime for routine maintenance for the 330-hp compressors, thus indicating the advantage of the slower-speed equipment.
Discounted Profit per Barrel: A Comprehensive Valuation Criterion for Everyone
Authors: Randall B. L. 
Published: December 2007

ABSTRACT
Economic evaluators of petroleum industry projects have long sought after a single, comprehensive valuation criterion by which investment opportunities could be properly screened and ranked. Recently, Seba has advocated, as captioned in his paper's title, that the present value ratio (or discounted profit to investment ratio, DPR) is " The Only Investment Selection Criteria You Will Ever Need". Many would agree that because DPR is a measure of both the magnitude and the time-distribution of the return, and because DPR can be computed using a discount rate reflecting the appropriate cost of funds or average opportunity rate, it is singularly the most comprehensive valuation criterion available.
However, the screening and ranking of competing investment projects on the basis of DPR is, in fact, a comparison that utilizes a per-dollar-of-investment-capital basis. Though this is certainly not incorrect, it is not always preferred. Often, it is desired instead to compare investment opportunities on a per-unit-of-product basis. Industry managers, particularly, seem to invariably pose questions regarding acquisition cost per barrel or finding cost per barrel.
This paper defines a new valuation criteria, Discounted Profit Per Barrel (DPB), that is shown to be as comprehensive as DPR, while maintaining a per-unit-of-product basis. It is demonstrated that DPB will always be directly proportional to DPR, yet will always have a ranking behavior that is unique. In addition, it will be shown that utilizing DPB instead of DPR at lower discounting rates can prevent duplicity in the economic analysis.
A Geologic and Coalbed Methane Resource Analysis of the Menefee Formation in the San Juan Basin, Southwestern Colorado and Northwestern New Mexico
Authors: Crist T. E. , Boyer C. M. , Kelso B. S. 
Published: December 2007

ABSTRACT
The Menefee Formation of the Upper Cretaceous Mesaverde Group in the San Juan Basin of Colorado and New Mexico contains abundant coal beds with a substantial coalbed methane resource. Stratigraphically lower than the actively targeted coal beds of the Fruitland Formation, the Menefee Formation coal beds have until recently been overlooked as a potential gas production zone. The total coal resource of the Menefee Formation, including determination of coal rank and coal bed thickness variability, was estimated using extensive subsurface geologic data. Estimates of coal gas content were extrapolated for the Menefee Formation coal beds from a previous study of the overlying Fruitland Formation coal beds. The combination of coal resource and gas content information resulted in a preliminary in-place coalbed methane resource estimate of 38 trillion cubic feet of gas contained in 145 billion tons of coal. As part of the development of the gas in-place estimates, regional cross-sections and isopach, structure and coal quality (rank) maps were produced which illustrate the regional nature and variability of the Menefee Formation coal beds in the San Juan Basin. Because of the variable thickness of the Menefee Formation and the lenticular nature of the contained coal beds, this study delineated regional areas where the potential for the development of the coalbed methane resource is more favorable. Having identified a potential area, an in-depth geologic and reservoir evaluation on a much smaller scale would be required prior to production drilling.
Coalbed Methane Resource Evaluation From Wireline Logs in the Northeastern San Juan Basin: A Case Study
Authors: Mullen M. J. 
Published: December 2007

Abstract
Methane produced from coalbeds is a developing reservoir in the San Juan basin of Colorado and New Mexico. Most of the evaluation of this resource is being done by coring and testing. A cost-effective method to evaluate untested coalbeds would include using wireline logs already run through the coalbeds to assist in the evaluation process. Core analysis and production tests are essential information to use with log analysis to make meaningful evaluations from wireline logs.
This study examines 17 wells drilled in the northeastern part of the San Juan basin. These wells were drilled to produce gas from the Pictured Cliff sandstone, with the Fruitland Coal as a secondary pay zone. The objective of this study was to determine the resource potential of the Fruitland coalbeds using the available log, core and production data. The proximate analysis data from a well in which a coal core was cut was used to calibrate the log analysis in the study area. Measured gas content data was used to calibrate the algorithm which calculated gas content from wireline data. Net coal thickness, igneous intrusive thickness, productivity potential, coal tonage per acre, average gas content and gas content per acre are the results of this study. They are contoured to highlight the most probable area in the township to pursue coalbed methane development.
Understanding the Effect of Natural Fractures on the Hydrofracture Stimulation of Gas Reservoirs
Authors: Heuze F. E. , Shaffer R. J. , Blair S. C. , Thorpe R. K. 
Published: December 2007

ABSTRACT
A finite element model for propagation of discrete fractures has been coupled to an implicit time-dependent fluid flow capability to be used as a predictive tool for hydraulic fracturing through sandstone lenses, as found in the Western Tight Gas Sands. Validation of the model is obtained by simulating controlled physical experiments. Our numerical model, FEFFLAP, was used to replicate the extension of a single-wing crack, driven through gypsum cement into a sandstone lens. Pressure-time records from the model and the experiments compare favorably.
Modeling of Fracture Propagation in Layered Reservoirs
Authors: Settari A. , Wong S. K. 
Published: December 2007

Abstract
The paper describes a new practical method of calculating dynamic fracture growth in multilayered reservoirs. The method predicts growth rate with time for a situation with two shale layers on each side of the centre (reservoir) layer. The static (equilibrium height) results are obtained as a limiting case at large times. Based on the numerical solutions, a correlation was developed which is computationally very efficient and can be implemented in any pseudo-3-D fracture simulator.
The examples of simulated fracture growth show the importance of even small barriers for temporary containment of fractures and the importance of the dynamic pressure effects as opposed to an equilibrium height model.
Technology Advances Unlock the Potential of the Tight Frontier Formation in the Moxa Arch
Authors: Haas M. R. , McFall K. S. , Coates J-M. P. 
Published: December 2007

Abstract
Despite difficult reservoir settings, low wellhead prices, and limited markets for currently undedicated gas in the Rocky Mountains, the Frontier formation in the Greater Green River Basin has the potential to contribute significant new low cost gas reserves.
The Upper Cretaceous Frontier is predominantly tight and contains substantial volumes of gas. The Federal Energy Regulatory Commission (FERC) has designated over 2,700 square miles of the Frontier formation in the Greater Green River basin as tight and eligible for economic incentives.1 The United States Geological Survey (USGS) estimates that the Green River Frontier/Dakota Formations contain between 220 and 490 Tcf of tight gas in place.2 Recent improvements in formation evaluation and stimulation designs, and its location in the Moxa Arch at the gateway of a pending pipeline, make the low permeability Frontier formation a desirable near term source of gas for the growing cogeneration and thermal EOR markets in California.
Despite similar technical challenges faced in many other tight settings (e.g. inadequate formation evaluation techniques, inaccurate fracture diagnostics, and the difficulty in reliably designing and delivering effective fractures), over 175 tight Frontier wells were drilled between 1981 and 1987. While Frontier development activity has declined with the market generally in the past few years, the continued availability of economic incentives, improved stimulation techniques and the opening of new markets have further renewed operator interest in development. Finally, the Gas Research Institute (GRI) has selected the Frontier as a possible site for field-based, cooperative R&D to improve tight gas formation and stimulation technologies.
This paper characterizes the formation and describes the technical challenges and development strategies needed to add reserves. First, the paper describes the geologic setting and reservoir characteristics that control potential. Second, it outlines the evolution of stimulation and production practices in tight Frontier wells. Finally, it compares the potential of the Frontier under current technical and market conditions with estimates of future potential based on recent advances in formation evaluation and fracturing techniques.
The Role of Geology in Characterizing Low-Permeability Sandstones, North Appleby Field, East Texas Basin
Authors: Tye R. S. , Laubach S. E. , Dutton S. P. , Herrington K. L. 
Published: December 2007

Abstract
Geological knowledge of low-permeability (permeability &lt;0.1 md) hydrocarbon-bearing sandstone reservoirs enhances exploration and exploitation strategies. Structural, stratigraphic, and petrographic analyses are required to interpret trap style, reservoir quality, and porosity and permeability distribution. Information compiled in such studies facilitates (1) the estimation of reservoir volume and drainage area, (2) the design of drilling and completion programs, (3) the location of development wells, and (4) the calibration of logs.
At North Appleby field, data from cored wells in the lower Travis Peak Formation have established a foundation for predictions about reservoir geometry, occurrence of natural fractures, and the degree and type of diagenesis that the reservoir has undergone. Only after integrating structural, stratigraphic, and petrographic data on the evolution of these low-permeability sandstones can relationships among sand-body geometry and orientation, diagenesis, and natural fractures be discerned. Broad, tabular reservoirs were deposited by braided- to meandering-fluvial systems. Reservoir seals and internal fluid-flow barriers consist of mudstones and porosity-occluding quartz cement. Pore types range from micropores to primary and secondary macropores. Vertical natural fractures are macropores that are oriented at approximately right angles to sandstone trends. Natural fractures are abundant in sandstone with very extensive quartz cement (&gt;17%); in these rocks natural fractures should be considered in reservoir evaluations and hydraulic-fracture treatment design.
Geometry and quality of Travis Peak reservoirs vary with depositional environment and degree of diagenesis. Reservoirs at the top of the formation are thin and separated by mudstones; few natural fractures occur in these sandstones. Productive sandstones at the base of the formation, however, are thicker and more sand rich; these contain a greater percentage of quartz cement and are naturally fractured.
Viscosity Measurement Throughout Frac Job Gives Increased Gel Control During Continuous Mining
Authors: Harms W. M. , Curtice R. 
Published: December 2007

Abstract
Economic feasibility studies have shown the need for a low cost, efficient treatment design to make stimulation of the Mancos B formation near Rangely, Colorado practical and attractive. Design simulation indicated that tight control of base gel viscosity combined with a high, but achievable, rate of displacement was necessary. This would place a 40 lb linear gel system containing 73,000 lb proppant in the formation at a rate of 50 bbl/min.
Operational efficiency from the personnel and equipment involved could best be attained through use of a continuous-mix approach since job time was short and rig-up time and expense would be greater in a batch mix scheme.
When treating wells with low viscosity linear frac gels, real-time information about frac fluid viscosity is critical, especially when using continuous mix fluid systems to stimulate shallow formations. Pipe transit time is on the order of 30-45 seconds; therefore it was essential that the fluid had developed significant viscosity to effectively create a fracture of sufficient height and width to place proppant throughout the net pay zone.
A monitoring system consisting of a rheology skid, two viscometers, and data acquisition hardware has been combined with a stabilized polymer system (SPS) to deliver a controlled, continuously-mixed linear fluid system. Viscosity was measured at three critical points in the flow stream.
From this work it has been observed that laboratory measurements are comparable to those obtained using field equipment to mix job-sized volumes of fluid. This paper presents a comparison of the laboratory findings and field results. Also presented are design details of the setup, job designs, and a discussion of the continuous mix system.
The Effect of Guar and HPG Crosslinked Fracturing Fluids on Well Performance: A Case Study
Authors: Wine J. D. , DeBonis M. P. , Thomas R. L. 
Published: December 2007

Abstract
A case study comparing the performance of wells fractured with crosslinked guar and hydroxypropyl guar (HPG) is presented. Data indicates that for a given crosslinked system, guar and HPG polymers yield comparable proppant pack impairment and fracture conductivity. Detailed laboratory conductivity and well performance data are presented for both low and high temperature conditions.
Laboratory conductivity data is reported for proppant placed with guar and HPG crosslinked fracturing fluids under in-situ conditions. The effects of proppant embedment, the gel filter cake, and long-term exposure to reservoir temperature and closure stress were determined in this study. Additionally, the effect of crosslinker, breaker system, and polymer load on fracture conductivity is discussed in detail.
Subsequent to laboratory testing, numerous fracture design and production simulations were performed to determine the effect of guar and HPG crosslinked fluids on well performance. The data indicates the forecasted cumulative production of wells fractured with guar and HPG are similar. However, due to the relatively lower cost of guar, the Net Present Value (NPV) of wells fractured using guar is greater due to lower treatment costs.
A case study of sixteen high-temperature wells located in Weld County, Colorado was performed to determine the "actual" effect of the fracturing fluid on well performance. A comparison of post-frac well production data indicates guar and HPG crosslinked fluid yield comparable proppant pack impairment, and thus similar well performance. A detailed discussion is presented.
Rheologic Measurements of a Crosslinked Fracture Fluid Under Conditions Expected During a Fracture Treatment
Authors: Worlow D. W. , Holditch S. A. 
Published: December 2007

Abstract
This paper details the development of a laboratory testing procedure that simulates the shear and temperature environment that a fracturing fluid is subjected to throughout a fracturing treatment, including the low shear rates (30-100 sec−1) experienced in the fracture. Building on previous parametric studies of fluid responses to differing test procedures, this new procedure appears to give results that are representative of the viscous properties of the fluid rather than the procedure used to run the test.
The validity of our proposed procedure has been verified by testing gels from four suppliers with gel loadings of 40 and 60 lb/1000 gal at temperatures of 200 and 250° F. Acceptance of a procedure such as the one presented in this paper would allow for more accurate control in the design and execution of fracture treatments, and serve as a basis for meaningful, quantitative comparisons between available gel systems.
J-Sand Polymer Flood Performance Review
Authors: Weiss W. W. , Chain J. M. 
Published: December 2007

Abstract
In this paper.the design methodology for the Warner Ranch Unit polymerflood is reviewed. The design included field tests which are believed to have underestimated polymer retention. This result in turn adversely affected project performance. The propagation of the polyacrylamide through the rock was much less than anticipated.
Performance of a polymer injection well is compared to several J-Sand water injection wells. It is evident that injectivity is greatly reduced with polymer injection; the loss in injectivity approximates that which is expected when the mobility ratio is reduced to less than one.
Most field projects have demonstrated that the absolute benefits of polymerflooding are difficult to quantify, and the Warner Ranch Unit is not an exception. Two producing wells produced 18,000 bbl of incremental oil attributed to polymer injection.
Limited Communication Between Hydraulic Fracture and (Deviated) Wellbore
Authors: Veeken C. A. M. , Davies D. R. , Walters J. V. 
Published: December 2007

ABSTRACT
When wellbores are deviated or are located in tectonically active areas it is unlikely that the plane of the wellbore and an artificial hydraulic fracture will be co-incident. This could result in limited entry effects due to poor communication between the wellbore and the hydraulic fracture or the presence of multiple fractures, and hence in a reduced well productivity.
A combined experimental and theoretical study has been carried out to investigate the influence of key parameters on the fracture-wellbore communication, aiming to identify the potential problem wells and to aid in optimising completion procedures for a North-Sea gas field.
The hydraulic fracture treatments were successfully placed, though the fluid friction experienced over the perforations during the treatments did show a dependence on well orientation (indicative that a minor form of limited entry was occurring).