bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experience Gained from 318 Injection Well KOH Clay Stabilization Treatments
Authors: Norman C. A. , Smith J. E. 
Published: December 2007

Abstract
Water injection in clay sensitive sandstone formations often results in decreased permeability and low injectivity. Some types of clays, including montmorillonites, swell upon contact with fresh water, plugging pore throats and reducing permeability. Migrating clays, including kaolinites and illites, reduce permeability as they become trapped in pore throat openings. KOH (potassium hydroxide) clay stabilization results from the interaction of caustic with the clay in the presence of potassium ions. The KOH-clay chemical reaction permanently alters the clay chemistry so that the clay minerals are unaffected by changes in water composition. Several field case histories, discussed in the following paragraphs, demonstrate that KOH can mitigate the effects of both swelling and migrating clays. Field results indicate that a single KOH treatment is effective over the economic life of the well.
Laboratory studies and empirical results indicate that the most important considerations for optimizing KOH treatment results are: 1) KOH concentration; 2) KOH contact time with reservoir rock; 3) maintaining a constant flow rate of the KOH solution during the treatment, and; 4) reservoir temperature.
The majority of KOH treatments have been applied in Cretaceous sandstone formations in the Powder River Basin of Wyoming. However, KOH offers the potential for injectivity improvement in other clay sensitive formations, and should be considered as an alternative to hydraulic fracturing in some areas. Finally, a simple waterflood simulation is presented in order to evaluate the economics of KOH.
Water and Gas Coning toward Finite-Conductivity Horizontal Wells: Cone Buildup and Breakthrough
Authors: Umnuayponwiwat Suwan , Ozkan Erdal 
Published: December 2007

Abstract
This study concludes that the shape as well as the time of breakthrough of a water or a gas cone are significantly affected by the pressure drop within the wellbore. An analytical model is used to demonstrate features of the movement of a cone when pressure drops in the wellbore are important. It is shown that wellbore hydraulics produces a self-sharpening feature and this leads to breakthrough at the heel of the well. This behavior may not be demonstrated by assuming an infinite-conductivity wellbore. The model described here may be used to assist simulation studies by providing specifics on the movement of the cone.
Reducing Uncertainty in Reservoir Management Using Semi-Analytical Modeling and Long Term Daily Data Acquisition
Authors: Foster Gary A. , Wong Dale W. 
Published: December 2007

Abstract
The availability of accurate daily pressure, flow rate and temperature data allows the reservoir engineer an opportunity to model the reservoir behavior and predict reservoir performance with increased accuracy. Tools currently available including decline analysis, simple analytical methods, complex analytical methods and the use of material balance techniques provide independent approaches to the problem of production forecasting and reserves determination. Each method is limited to an inherent level of accuracy based on assumptions of reservoir size and the effect of interference. A field case is used to demonstrate the range of predictions using the alternate methods at different stages in the life of the reservoir. Each member of the exploration and development team including production operations, accounting and the IS group needed to be satisfied their requirements were being met using a daily data reporting system. A low earth orbit satellite system was chosen to transmit data based on reliability, cost and the ease of use and implementation.
Improved Completion Method for Mesaverde-Meeteetse Wells in the Wind River Basin
Authors: Long Ed , Kundert Pat 
Published: December 2007

Abstract
In 1996, Tom Brown, Inc. began drilling new deep Mesaverde-Meeteetse formation wells in the Muddy Ridge field in central Wyoming. The formations consist of many layers of potential pay zones over a long gross interval. Total depth of the wells is about 13,000 ft, with the uppermost pay zones at about 9,500 ft. Over this 3,500-ft gross interval, as many as 50 potential pay zones may be present.
Initial completions consisted of grouping three or four of the best-developed zones together. The zones were then hydraulically fractured and flow-tested for an extended period so production could be determined. Conventional retrievable bridge plugs and packers isolated additional zones as the completion progressed up the hole to new zones. Because of the individual stimulations and extensive flow-testing, the typical well completion lasted several weeks (or months).
The challenge was to find a new streamlined completion method that would reduce the time required to place the wells on production. To meet this challenge, a composite fracturing plug (CFP) was used. A CFP holds pressure from above the tool while successive zones are treated, but it allows flow from zones below it during cleanup.
The current general procedure is to perforate 8 to 10 zones in the lower Mesaverde formation and to perform a hydraulic fracture treatment down the casing. A CFP is then run on wireline and set above the zones just stimulated. Additional Mesaverde zones are perforated, and a second fracturing treatment can be pumped the same day. Pinally, tubing with a pumpoff bit is snubbed into the well, and all the CFP's are drilled out. The entire Mesaverde-Meeteetse group of zones was perforated and fractured in 3 to 5 days when this technique was used.
Using composite fracturing plugs has reduced the well completion to a matter of days, and has made rigless completion possible for the stimulation phase.
Use of Hydraulic Fracture Diagnostics to Optimize Fracturing Jobs in the Arcabuz-Culebra Field
Authors: Wolhart Stephen L. , Berumen Sergio , Cipolla Craig L. , Barton Colleen A. , Branagan Paul T. 
Published: December 2007

Abstract
This paper presents the results of a study conducted to improve hydraulic fracturing and field development in the Arcabuz-Culebra Gas Field in Mexico. Hydraulic fracture mapping was performed on four stimulation treatments using a combination of tiltmeters (surface and downhole) and microseismic imaging. Fracture mapping was complimented by 3-D fracture modeling and geomechanical modeling. Data analyses resulted in recommendations regarding well positioning and hydraulic fracture design.
A New Approach for Predicting Frictional Pressure Losses of Non-Newtonian Fluids in Coiled Tubing
Authors: Medjani B. , Shah S. N. 
Published: December 2007

Abstract
The importance of the pressure loss in the design of treatments for various field applications while using non-Newtonian fluids necessitates the estimation of the pressure loss in the reeled part of the coiled tubing unit.
The present work discusses the analysis of frictional pressure loss of non-Newtonian fluids flowing through coiled tubing and includes the effects of fluid concentration and the influence of coiled tubing curvature and length. An experimental investigation of three polymeric solutions is conducted to predict the frictional pressure losses related to their flow behavior in coiled tubing.
A total of 1500 ft of 1-in., 5000 ft of 1 1/2-in. and 3000 ft of 2 3/8-in. coiled tubing was used for this purpose. Also, straight sections of coiled tubing were employed for obtaining frictional losses in straight sections, which then are compared with those of reeled coiled tubing.
Experimental results are also compared with the correlations presented earlier by Srinivasan for Newtonian fluids and McCann for non-Newtonian fluids. From the data analysis, it was found necessary to develop a new model which includes Dean number. The Dean number takes into account the curvature effect. This new model is proposed for the prediction of the friction factor in coiled tubing for fluids exhibiting power law pseudoplastic type behavior with flow behavior index less than unity.
Case Studies Demonstrate That Effective Soluble Scale Removal Treatment Outperforms Bull Heading
Authors: Larsen Henrik Aslak , Peterson Chad D. 
Published: December 2007

Abstract
Scale is often encountered in producing well bores. This paper presents five cases where soluble scale has been removed through an optimized approach of coiled tubing conveyed tools and hydrochloric acid. A comparison between different methods available to the industry is made. The paper covers removing carbonates, sulfides and cement from sub-surface safety valves and gravel pack screens. Field comparisons have been made between simple bull heading of solvents, impact hammers, motor and mills, simple jetting nozzles, and optimized jetting tools with solvents. The combination of solvents and tools with optimized hydraulics is shown to be highly effective.
The results are presented with increase in production rates where applicable. Three examples are shown where increase in production ranges from 50% to an 8-fold increase.
Managing Differential Pressures During Coiled Tubing Operations
Authors: Rosato M. J. , Courville P. W. 
Published: December 2007

Abstract
Coiled tubing (CT) is routinely deployed in wells producing from multiple pay intervals. Multizone completions induce pressure gradients that present significant operating risks to CT operations. Kicks and lost circulation can cause reservoir damage, blowouts, and lost pipe. Countless CT strings have been lost in wells because of uncontrolled well responses during treatments.
Wellsite observations have improved the diagnosis and prevention of circulation problems caused by differential pressures. Some of the specific factors influencing these problems are formation fluid levels, well geometry, interval height, and temperature. Reservoir management techniques can reduce the hazards imposed by differential pressures. However, because kicks and lost circulation cannot always be avoided, contingency plans are necessary. Prejob calculations and planning procedures can help operators establish practices that minimize the adverse effects of kicks and lost circulation.
A comprehensive strategy for CT operations includes contingency planning. While some risk must be assumed in all well-intervention processes, proactive planning can minimize problems and increase the potential for success.
The Removal of Hard Scales From Geothermal Wells: California Case Histories
Authors: McClatchie D. W. , Verity R. 
Published: December 2007

Abstract
The Geothermal Industry’s largest remedial budgetary cost involves the removal of scale from its existing completions. From it’s inception forty years ago, the geothermal industry has tried many different systems and applications for the removal of very hard scale from their injection and production wells. Today the most widely used and accepted method for hard scale removal has been the use of a workover rig utilizing a bit and scraper. This method, although partially effective, does not fully address the impediment of scale in the well conduit – a bit and scraper simply cannot remove what it cannot reach. In addition, with the advent of high alloy materials to combat the corrosion effects of these scales, along with pressure depleted formations, this method is proving to be inadequate as it can cause severe damage to the expensive wellbore tubulars. This paper reviews and discusses several case histories of a newly developed technique for removing these very hard geothermal scales.
A New Approach to Monitor Tubing Limits
Authors: Zheng Andrew S. , van Adrichem Willem P. 
Published: December 2007

Abstract
This paper presents a new approach to monitor coiled tubing tension and pressure limits during operation. The conventional way to monitor the tubing limits in real time is through monitoring the section right below the stripper. It works well for a single-wall tubing string operating in a shallow well with low wellhead pressure. For high-pressure wells, deep wells or high deviation wells, this becomes inadequate because the critical section may not be at the section below the stripper. Instead of monitoring the tubing limits at a specific section (such as the section below the stripper), the model presented herein dynamically tracks and monitors the critical section of the tubing during operation.
Our approach starts with a new way to express the tension and pressure limit curve of the coiled tubing. The use of effective force to generate the limit curve facilitates the task to identify the critical section of the coiled tubing during operation. To identify the critical section, the distributions of tubing force and pressure difference along the coiled tubing downhole are calculated during the operation. This information is used to calculate the safety factor along the coiled tubing string, from which the critical section is identified. A software based on this approach has been developed, which allows operators to dynamically track and monitor the critical sections during operation. By coupling with surface measurements (such as ovality) in real time, it significantly improves operators’ ability to monitor tubing limits.
Stimulation of the Ekofisk
Authors: Mancillas Gene , Matson R.P. , Ziara B.A. 
Published: December 2007

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

Introduction
Discovery of the Ekofisk oil field in 1969 ended a long and frustrating search for commercial oil in the North Sea. It became the first North Sea oil field to be produced commercially and proved to be the largest oil field in proved to be the largest oil field in western Europe to date. Its success opened a bright new era for a number of European countries which formerly had to import most of their oil.
The development of the Ekofisk field in the turbulent and hostile environment of the North Sea presented many engineering challenges. Many new techniques and designs had to be developed before the Ekofisk could become a successful commercial reservoir, one of which was the stimulation design for the oil reservoir. Careful consideration had to be given to all the well information available (only one well had been drilled). Specific information about the reservoir's structure, performance, etc., was not available, due performance, etc., was not available, due to the limited number of wells drilled. Well data that was available and would influence the stimulation design included the high reservoir pressure, high bottom hole temperature, and the massive thick carbonate reservoir. The stimulation design included the development of new materials and a specific blender for performing the treatments.

HISTORY - DISCOVERY
The Ekofisk field was discovered in late 1969 by the Phillips Group in the Norwegian sector of the North Sea. The Ekofisk is located approximately 200 miles from the Norwegian coast and very near the United Kingdom-Norwegian seaward boundary line.
Oil was discovered in the Danian Formation on the Ekofisk structure at approximately 10,000 feet with the drilling of Well 2/4-1AX in November 1969.
Subsequent to Well 1AX, three additional wells, 2X, 3X, and 4X, were drilled.
The Commission On Engineering Education: Its Objectives And Program in Relation To Engineering Faculty Development
Authors: Hall Newman A. 
Published: December 2007

Publication Rights Reserved
This paper was prepared for the 38th Annual Fall Meeting of the Society of Petroleum Engineers of AIME in New Orleans, La., on October 6–9, 1963, and is considered the property of the Society of Petroleum Engineers. Permission to published is hereby restricted to an abstract of not more than 300 words, with no Illustrations, unless the paper is specifically released to the press by the Editor of the Journal of Petroleum Technology or the Executive Secretary. Such abstract should contain conspicuous acknowledgement 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 providing proper credit is given that publication and the original presentation of the paper.
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.
Engineering education in recent years, has fortunately been the subject of intense concern on the part of the profession and faculty. Quite naturally, these groups have the most valid reason for interest and should assume the greatest responsibility. However, this interest has not resulted consistently in a uniform expression of opinion or course of action. In fact, the diversity of approach to educational problems has presented conflicts which have intensified the difficulties facing those most intimately involved.
The Commission on Engineering Education was established to clarify educational concerns and identify goals for a direct program of action. It was organized in August, 1961 by a conference of engineers brought together under NSF auspices because it was believed engineering education could be advanced most objectively by a group which did not represent vested interests of organizations or institutions. Consequently, the Commission has dedicated itself to developing and maintaining engineering education at a maximum level of excellence by strengthening the environment and improving the effectiveness of engineering education. It is promoting those activities which will:
Increase the capabilities of individual faculty members. Provide educational resources to facilitate the introduction of advances in science and technology, to improve teaching efficiently, to encourage initiative. Develop a more adequate understanding of factors affecting the motivation and accomplishment of present and potential engineering students.
Application of Geostatistical and Fluid Flow Simulations to Evaluate Options for Well Placement
Authors: Pathak R. , Ogbe D. O. , Jensen J. L. 
Published: December 2007

Abstract
In this study, we apply geostatistical and flow simulations to a section of the Endicott field, Alaska to assess options for well placement. Both sequential Gaussian and sequential indicator simulations were used to model Zones 2A and 2B. Wells were then placed in the models to assess sensitivities to location and petrophysical properties. Some cases were found to have much higher productivities and lower sensitivities.
Three porosity and permeability realizations, selected from 100 realizations and representing high, medium, and low cases, were used for fluid flow simulations. Flow simulations were used to evaluate 15 potential well locations. We analyzed the performance of fully penetrating vertical and 600-ft, 1800ft, and 3000-ft horizontal wells at each location considering various well orientations, kV/kh ratios, and position in the reservoir geosystem.
The flow simulation results show that the 3000-ft horizontal well gives the best performance in most of the cases. However, the performance of the horizontal wells deteriorated rapidly with a decrease in the permeability anisotropy (kV/kh). In that case, a vertical well is a better option, especially for the thick reservoir here. The proposed method should find application in targeting infill wells in a new development.
Oil and Gas Reserve Growth-A Model for the Volga-Ural Province, Russia
Authors: Verma Mahendra K. , Ulmishek Greogory F. , Gilbershtein Andrei P. 
Published: December 2007

Abstract
An understanding of reserve growth in known oil and gas fields has become a critical component of energy resource analysis. Significant statistical studies of reserve growth have been published in the U.S., whereas little information is available on other regions of the world. It may be expected that in many countries the magnitude of reserve growth is different from that in the U.S. because of differences in reporting systems and in exploration and production practices. This paper describes the results of a reserve growth study in a group of largest oil and gas fields of the Volga-Ural petroleum province, Russia. The dynamics of reserve growth in these fields shows rapid reserve additions during the first 5 years of field exploration and development, which results from intensive step-out and delineation drilling. Later reserve growth is slow and is related to improvements in recovery technologies and discoveries of new pools and extensions. These two stages of reserve growth are described by two different groups of empirical models. A comparison of these models with the models developed for the lower 48 states and Gulf Coast offshore of the U.S. demonstrates that the reserve growth in the Volga-Ural province is significantly lower than in the U.S. The proposed models may be used for assessment of future reserve additions in known fields of countries that presently have or recently had a centrally-planned economic system.
Barrier-Free Learning for Well Construction
Authors: Trantham J. A. , Deagen J. M. 
Published: December 2007

Abstract
Well Construction and Information Technology (IT) groups are working together at ARCO Alaska, Inc. (AAI) to create a real-time, barrier free, learning environment. In this environment, engineers discover that small "jewels" of knowledge are easily shared and discovered. This is accomplished by identifying compartmentalized knowledge, breaking down organizational barriers and disseminating knowledge broadly. New technologies enable automatic data collection, publishing, and collaboration with outside contractors via the web. These new tools alone can not turn a group into a real-time learning organization. In order for this to happen, the members of the well construction groups continue to design new work processes and communication standards.
Scaling of Co-Current and Counter-Current Capillary Imbibition for Surfactant and Polymer Injection in Naturally Fractured Reservoirs
Authors: Babadagli T. 
Published: December 2007

Abstract
To increase capillary imbibition recovery rate and deplete matrix oil efficiently, surfactant and polymer solutions can be injected into naturally fractured reservoirs. Laboratory experiments are needed to understand the response of the reservoir rock and fluids to these applications and a scale-up process is required to quantify the recovery for reservoir conditions before injecting these expensive fluids.
This study tests the existing capillary imbibition scaling-up formulations in literature and proposes modifications to them for surfactant and polymer injection applications. Laboratory tests were performed using Berea Sandstone cores with different shapes, sizes and boundary conditions. The rock samples were surface-coated to create many different boundary conditions causing co- or counter-current imbibition or both. Kerosene, engine oil, mineral oil and crude oil were selected as the oleic phase. Brine and two different concentrations of surfactant and polymer solutions were the aqueous phase types. The capillary imbibition recovery curves were then used to test the existing scaling formulations.
It was observed that the scaling groups were applicable with certain modifications to the co-current flow of surfactant and polymer solution-oil pairs as well as the brine-oil cases. Modifications to the Mattax and Kyte's scaling group for the capillary imbibition of high IFT fluids (brine-oil and polymer solution-oil experiments) were introduced for the matrix boundary conditions, oil viscosity and wettability. In case of co-current flow, the gravity forces dominate recovery for low IFT experiments and modification to the gravity scaling group for the boundary conditions is required. For counter-current flow, however, the scaling groups were observed inapplicable even after the modifications.