bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Measurement of Hydraulic Fracture Fluids: Case Study
Authors: Davidson B. M. , Saunders B. F. , Holditch S. A. 
Published: December 2007

Abstract
We performed intense quality control (JQC) on 54 hydraulic fracture treatments during 1992-93. Our detailed fluid testing in the field has indicated the complex nature of fracture fluid systems currently used by the industry. This paper documents our experience with fracture fluids blended in the field and tested under in-situ conditions. Several problems were encountered while performing intense quality control operations on these wells, including overcrosslinked gel systems and contaminated additives. Many of these problems became apparent only after evaluating the fracture fluids at bottomhole temperatures and shear rales. Many fluids that failed viscosity tests at bottomhole conditions looked to be adequate when tested at surface conditions.
The importance of quality control in stimulation operations has been investigated and its importance recognized by the industry.1-4 Intense quality control is performed on location using equipment carried in a rheology van. The rheology van contains two Fann Model 50 viscometers that we use to evaluate the fracture fluids at bottom hole temperatures and shear rates, and a complete wet chemistry lab. Analyses of fracture fluids with the rheology van has been described in a previous paper5 and GR1 publication.6
Intense quality control is not a new concept. IQC is routinely used in the evaluation of cement slurries. To test recommended mixtures of cement and additives, pilot tests are always performed on cement slurries prior to pumping to test recommended mixtures of cement and additives. Results of the pilot and blend tests indicate if a particular cement mixture will perform as designed. Similarly, we test fracture fluid systems at conditions designed to simulate reservoir temperatures in our IQC work. We use the chemicals and additives that will actually be pumped during the treatment. Using the actual chemicals is a critical part of IQC, and it is the reason that testing must be performed at the wellsite, prior to the treatment. Blended samples are collected during the fracture treatment and tested as the treatment is in progress. The tests performed during the treatment are compared to the pilot tests to ensure the fluid pumped down hole is performing as expected. We inventory all additives before, during, and after the treatment to verify the fracture fluid system is blended accurately.
The Use of Inert Gas to Test Potential Gas Storage Aguifers
Authors: Wingerter Jack R. 
Published: December 2007

Abstract
Factors for using inert gas generators to test a questionable cap rock in potential gas storage aquifers are presented and discussed. presented and discussed. The theory of inert gas generation is compared to field use. Mechanical and corrosion problems involved with practical application are presented. practical application are presented. Cost per MCF of inert gas is compared to natural gas. Recommendations for reducing mechanical and corrosion problems are presented as well as conclusions presented as well as conclusions concerning the practical use of the inert generator.
Introduction
Testing the adequacy of the cap rock to contain natural gas in potential gas storage aquifers may be accomplished in several ways. A water pumping test in many cases is sufficient and should be tried first. (Pulse testing is another alternative.) The most positive proof of the cap rock's adequacy positive proof of the cap rock's adequacy is to inject a gas. If, however, the cap rock should be inadequate, natural gas would not be desirable because of the hazardous conditions created by leaks into upper formations. Air should not be used because of the explosive conditions that would exist if natural gas were injected. Bulk storage facilities would make the purchase of an inert gas rather expensive. The use of an inert gas generator would seem to be the most realistic means of testing the field without risking the potential hazards of natural-gas, should it leak. Inert gas generation is not new. The first patent for an inert gas machine was applied for in 1911. Since that time, many types of inert gas generators have been built and used for various application throughout the industry. (Examples: gas re-pressurization, gas lift, well drilling, etc.) As early as 1924, a plant was built to produce inert gas from a mixture of boiler stack gas and engine exhaust. This project failed because of corrosion problems. In 1949, Pan American built a re-pressurization Pan American built a re-pressurization plant in Wyoming's Elk Basin. This plant in Wyoming's Elk Basin. This project developed severe corrosion problems project developed severe corrosion problems in the early stages. Over the years, costly maintenance and repairs have reduced corrosion to a workable level.
Incorporation of Production Data Into the Reservoir Description Process
Authors: Hird K. B. , Kelkar M. G. 
Published: December 2007

Abstract
Current computer technology has given us the ability to generate realizations of spatial reservoir properties as never before. However, achieving the goal of generating reservoir descriptions which are consistent with all of the available information continues to be a difficult and time-consuming process. Especially, the inability to constrain probabilistic-based reservoir descriptions using (dynamic) production data is becoming recognized as one of the primary short-comings of existing techniques.
This paper describes a procedure to identify, quantify and incorporate within a conditional simulation procedure the spatial reservoir characteristics which dominate well performance. Primary production data are used to determine controlling spatial characteristics. The primary production parameters are combined with waterflood constraints and the method of simulated annealing to produce realistic reservoir descriptions-both in terms of their spatial characteristics and simulated well performance. Although excellent matches of well performance are also obtained using these "indirect performance constraints" while excluding the variogram constraint, it is shown that the resulting alternative reservoir descriptions poorly reproduce actual spatial reservoir properties. Thus, it is concluded that spatial correlation structures cannot be extracted from performance data. The robustness and flexibility of the approach is demonstrated using a two-dimensional areal, field scale reservoir study. The proposed technique can be used to greatly reduce the uncertainty of predicting future reservoir performance.
Quantification of the Relative Importance of Fracture and Matrix Flow Units to Reservoir Storage Capacity and Transmissibility
Authors: Cline S. B. , Tiab Djebbar 
Published: December 2007

ABSTRACT
Unexpected early waterflood breakthrough in a high matrix porosity, Pennsylvanian age sandstone reservoir, indicated the possible presence of a high directional permeability fracture flow system superimposed on the matrix flow system. A simulation study was initiated to study this problem.
Simulation history matching results showed that the fractures exhibited high directional permeability but low storage capacity relative to the matrix portion of the reservoir. A low fracture intensity index was calculated. This low storage capacity fracture system supports the hypothesis that the fracture system resulted from previous stimulation treatments rather than from an extensive naturally occurring fracture system. The recognition and quantification of this new model led to significant improvements in field production practices, well alignments, ultimate oil recovery and production forecasting.
Proppant Effects on Zirconium Crosslinked Frac Fluids
Authors: Smith V. T. , Colt J. R. , Johnson R. L. , Sinclair A. R. 
Published: December 2007

ABSTRACT
Interactions between proppants and a zirconium crosslinked hydroxypropyl guar (HPG) frac fluid were examined using rheological test methods. The advantages of curable RCP over tempered RCP and sand have been well chronicled.1,2 However, one disadvantage of curable RCP has been its effect on frac fluid viscosity and breaker activity. By definition, curable RCP is chemically reactive, and the chemistry required to form bonds between grains can interfere with a fluid's crosslinking mechanism. Using a Nordman 5002 viscometer with real-time digital data acquisition, viscosity data were gathered to quantify the rheology of crosslinked fluid exposed to uncoated sand, tempered RCP, and curable RCP. Proppant effects on oxidative breakers were studied by direct proppant / breaker consumption titrations. In addition, leachate samples of curable and tempered RCP were analyzed using Fourier Transform – Infrared Spectroscopy (FT-IR); differences in leachate provided information on which chemical species were reactive in interactive fluid chemistry.
Increased Production in Low-Temperature Gas Wells Through Improved Breaker Technology
Authors: Samuelson M. L. , Chmilowski Walt , Sinclair J. J. 
Published: December 2007

ABSTRACT
A discussion is presented on the improvement of shallow gas well production through the use of advanced low-temperature breaker technology. A systematic field evaluation has shown that the use of this new breaker system has increased well production in spite of inherent problems in the area due to severe proppant embedment. Previous use of an encapsulated breaker (EB) designed for well temperatures above 125°F had shown some improvement in production over conventional dissolved breakers. However, the current study has shown that the new breaker system, designed for temperatures &lt;125°F and closure stress &lt;1000 psi, has been able to improve production by an additional 15 to 22% in direct offset comparisons. Study criteria included selection of a suitable area, maintenance of a consistent drilling and completion program, and variance only in the breaker system used. Laboratory development of the new breaker system also is discussed, including effects of temperature and closure stress on barrier properties, and fracture conductivity comparisons.
Integrated Approach Doubles System Capacity
Authors: Pelgrom J. J. , Angiblaud L. G. , Bouvet E. J. , Davidson C. J. , Holtslag paul , De Ruwe Bart , Shaw Julian 
Published: December 2007

Abstract
The use of integrated system modelling of wells and facilities and the application of performance improving chemicals and novel techniques allowed Shell Gabon to increase Rabi field output by nearly a factor of two over the initial projections. Optimisations are carried out in a consistent and systematic manner without jeopardising system integrity and safety standards. These efforts increased project profitability while obviating the need for major system extensions. Some (identified) upgrading measures are still required to reduce long-term operating costs and to reduce deferments.
Integrated Reservoir Description and Flow Performance Evaluation of Self Unit, Glenn Pool Field
Authors: Ahuja B. K. , Bahar Asnul , Kerr D. R. , Kelkar M. G. 
Published: December 2007

Abstract
This paper presents reservoir characterization results of a mature oil field followed by a successful flow simulation. The study area is the Self Unit (160 Ac) in part of the Glenn Pool field, which was discovered in 1905. Since discovery, the Glenn Sand reservoir has only produced 20% of the original in place. Under the sponsorship of the Department of Energy, a methodology is being established to produce additional oil from the reservoir in a cost effective manner. The first step of this process is to generate an integrated reservoir description followed by a successful comparison between historical performance and the simulated performance. The details of this step are presented in this paper.
Monument Butte Unit Case Study: Demonstration of a Successful Waterflood in a Fluvial Deltaic Reservoir
Authors: Deo M. D. , Sarkar Avik , Nielson D. L. , Lomax J. D. , Pennington B. I. 
Published: December 2007

Abstract
Fluvial deltaic reservoirs contain a significant portion of the known world oil resources. Due to the sinuous na-ture of the sands, it is difficult to implement improved oil recovery projects in these reservoirs. The case study described in this paper is the demonstration of a well-planned water flood in a classic fluvial deltaic system, and consists of geologic characterization and reservoir simulation. The Monument Butte Unit, located in the Uinta Basin, Utah, has 22 operating wells; eight injectors and the rest producers. The oil from the unit is highly paraffinic and is produced primarily from two sands. In primary recovery, the reservoir performance was typical of an undersaturated reservoir whose initial pressure was close to the bubble point pressure. The Unit had produced about 5% of the oil in place at the end of primary production and was producing at a rate of 40 STB/day, when the water flood was initiated. The water flood design was novel and was engineered contrary to convention. The response to the water flood was extraordinary and the unit has been producing at more than 300 STB/day for the past two years. About 10% of OOIP has been recovered to date. Every aspect of the field history was matched well by the reservoir simulator.
Microbial Enhanced Waterflooding Field Tests
Authors: Bryant R. S. , Stepp A. K. , Bertus K. M. , Burchfield T. E. , Dennis Mike 
Published: December 2007

Abstract
To determine the feasibility of improving oil recovery and the economics of microbial enhanced waterflooding in mature oil wells in the United States, two field pilots have been conducted. Candidate fields were screened to determine whether they have any potential for a microbial system developed at the National Institute for Petroleum and Energy Research (NIPER), and microbial compatibility tests were conducted in the laboratory to select the target field. A specific microbial formulation was selected that was compatible with the chosen reservoir environment and had been shown to recover oil after waterflooding in Berea sandstone and field core. The microbial formulation was designed to improve microscopic oil displacement efficiency by surfactant, gas and acid production from fermentation of molasses. A 20-acre pilot test was initiated in October 1986, and completed in December 1989.
Results from this pilot demonstrated that microorganisms could be injected into an ongoing waterflood and that such injection could increase the oil production rate by at least 13%.
A larger test (380 producing acres) was completed in the same formation to evaluate the feasibility of commercial application of the technology. This field pilot was injected with microorganisms and molasses from a centralized injection station in June 1990. Although microorganisms were injected only once, nutrient injection continued throughout the project life. All 19 injection wells were treated, and oil production was monitored from the 47 production wells. Treatments were similar to procedures for the field pilot demonstration. No operational problems were encountered. At the end of May 1993, the oil production rate was improved by 19.6%.
A Single Well Test Method That Yields a Dispersion-Free Measure of Reservoir Fluid Drift Rate
Authors: Wellington S. L. , Simmons J. F. , Hara S. K. , Richardson E. A. 
Published: December 2007

Abstract
A unique single-well tracer test sequence for quantifying reservoir fluid drift rate free of dispersion is presented. Similarly with previous methods, the new method relies on the time dependence of drift. An analytical model allows the results to be interpreted using a Personal Computer at the wellsite.
EOR by Miscible CO2 Injection in the North Sea
Authors: Lindeberg Erik , Holt Torleif 
Published: December 2007

Abstract
A study of CO2 injection into an oil reservoir on the Norwegian Continental Shelf has been conducted. Oil production during miscible CO2 injection was simulated with a compositional reservoir simulator and a three dimensional reservoir model. This production profile was compared to water injection. The simulations showed that considerably more oil could be recovered with CO2 injection, approximately 63% OOIP, compared to approximately 43% OOIP for water injection.
Results from miscibility studies, measurement of phase diagrams and extraction experiments were used to tune the phase behaviour description of the simulator. Numerical simulation of laboratory core flood experiments were used to quality test the compositional simulator. A good agreement between measured and simulated production profiles were obtained.
A Model To Estimate the Performance of Foamed Gel for Conformance Control
Authors: Miller M. J. , Fogler H. S. 
Published: December 2007

Summary
Foamed gel barriers efficiently render porous media impermeable to gas or liquid flow and recently have been considered for fluid diversion. However, exceeding a critical pressure drop across the barrier will rupture conductive channels through the barrier. A foamed gel breakdown model has been developed to estimate the maximum pressure a given barrier can withstand and estimate the permeability after rupture. The simulation results are consistent with laboratory experiments. Only the elastic modulus and the critical failure stress are required to qualitatively compare two different foamed gels.
Tax Incentive for Enhanced Oil Recovery Projects
Authors: Buckner L. A. 
Published: December 2007

Abstract
Beginning with the Omnibus Budget Reconciliation Act of 1990*, the federal government has recently attempted to encourage domestic oil production through federal income tax incentives. Section 43 of the Internal Revenue Code provides a tax credit for projects employing enhanced oil recovery (EOR) methods. The EOR credit was enacted to stimulate the production of potentially recoverable domestic oil reserves. The federal tax system previously attempted to provide an incentive for EOR projects when the Windfall Profit Tax rules, before repeal, contained an incentive tax rate on oil recovered using tertiary (EOR) methods.
The credit is an amount equal to 15 percent of the qualified enhanced oil recovery costs paid or incurred by a taxpayer in connection with a qualified enhanced oil recovery project. A credit to reduce an income tax liability can provide a significant economic benefit as an indirect discount on the cost of a project. However, the true economic impact to an EOR project must be evaluated considering the rules for qualification and the limitations applicable to the credit as determined under the framework of the federal income tax system.
Development of a Model Technology Transfer Program To Assist Independent Operators
Authors: Schoeling L. G. , Green D. W. , Willhite G. P. , Watney W. L. 
Published: December 2007

Abstract
This paper describes the development of the Kansas Technology Transfer Model (KTTM) which is proposed as a regional model for the development of other technology-transfer programs for independent operators throughout other oil producing regions in the United States. The KTTM is an expansion and adaptation of the University of Kansas Tertiary Oil Recovery Project (TORP) concept of oilfield technology transfer to independent oil producers. The KTTM is the product of a grant from the United States Department of Energy (DOE) in August 1992 to the Kansas University Energy Research Center to develop a technology transfer model which could be utilized nationwide. The focus of the KTTM is to assist in reducing the rate of well abandonment in the near term and to increase oil recovery using conventional technology.
Included is the linkage of the regional model with the national technology transfer plan, and the methodology to adapt the model on a regional basis. The technology transfer plan also includes an evaluation technique to measure the process.
Mechanistic Prediction of Foam Displacement in Multidimensions: A Population Balance Approach
Authors: Kovscek A. R. , Patzek T. W. , Radke C. J. 
Published: December 2007

ABSTRACT
The high mobility of typical gases used in enhanced oil recovery (EOR) techniques impairs ultimate oil recovery. Foamed gas, though, is a promising agent for achieving mobility control in porous media. Because reservoir-scale simulation is a vital component of the engineering and economic evaluation of any EOR project, efficient application of foam as a displacement fluid requires a predictive numerical model. Unfortunately, no such model is currently available for foam injection in the field.
We have incorporate a conservation equation for the number density of foam bubbles into an implicit, three-dimensional, compositional, and thermal reservoir simulator and created a fully functional, mechanistic foam simulator. Because foam mobility is a strong function of bubble texture, the bubble population balance is necessary to make accurate predictions of foam flow behavior. Foam generation and destruction are included through rate expressions that depend on saturations and surfactant concentration. Gas relative permeability and effective viscosity are modified according to the texture of foam bubbles. In this paper, we explore foam flow in radial, layered, and heterogeneous porous media. Simulations in radial geometries indicate that foam can be formed deep within rock formations, but that the rate of propagation is slow. Foam proves effective in controlling gas mobility in layered porous media. Significant flow diversion and sweep improvement by foam are predicted, regardless of whether the layers are communicating or isolated.
Floating Drilling Experience in Santa Barbara Channel, California
Authors: Harris L.M. 
Published: December 2007

This paper was prepared for the 40th Annual California Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in San Francisco, Calif., Nov. 6–7, 1969. 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 publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor 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
The equipment and practices for two floating drilling vessels working in water depths greater than 1000 feet in the Santa Barbara Channel have been designed to provide maximum reliability and safety. Experience to date has shown the systems to be efficient and to have met design criteria.

Introduction
Since the Federal Lease Sale in the Santa Barbara Channel of February 6, 1968, Humble has drilled fourteen wells with floating rigs in water depths ranging from 280 feet to 1300 feet. Although the water depth for some of these wells exceeds previous industry experience, the environment in the Channel is relatively mild. Historical data have indicated that the probable yearly maximum conditions in the central Santa Barbara Channel would not exceed:
Five-minute average winds of 65 knots from the west and northwest or from the east and southeast. Significant wave heights of 16 feet with a period of 13 seconds. Maximum waves associated with this sea state would be about 30 feet. Surface or near surface currents of 2.4 knots parallel to the California coastline.
The data have shown generally that these conditions occur for only a very small percentage of the time in winter months in the main part of the Channel east of Point Conception. Near the west end of the Channel, a yearly maximum significant wave height of 18 feet might occur with greater frequency.