bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Science and Economics Behind Coiled Tubing String Design and Optimization
Authors: Portman Lance 
Published: December 2007

Abstract
Coiled tubing has made great advances in recent years, increasing in size, strength and reliability. This has lead to a great increase in services that can be run on coiled tubing and in turn has lead to bigger, more complex and more expensive coil equipment being built and offered to the market.
With all this new equipment now on the market, it becomes more difficult to select the most appropriate equipment for a particular job, or indeed for a project of work that involves many different types of operations. There is a tendency to assume that "biggest is best". Both commercially and technically, the big coil unit may not always be the best choice.
This paper gives examples of the current capabilities of coiled tubing units, dispelling some of the myths associated with the smaller units such as "You cannot drill with a small coil unit" or "You always need a big coil unit in order to get higher circulation rates". The paper also lists applications where big coil units absolutely should not be used. Finally, guidelines are set out based on general technical and economic performance comparisons between varying size coil units.
Several techniques are listed which permit smaller coil sizes to be used in place of bigger units. The paper uses examples from actual field work and computer simulations.
Economics of Pennsylvania Shallow Production
Authors: Jack S.W. , Stewart Robert S. 
Published: December 2007

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

Abstract
The scope of this paper is to outline the economic possibilities which exist in the development drilling for natural gas in Western Pennsylvania. The area studied includes five Pennsylvania. The area studied includes five counties in Western Pennsylvania and concentrates on what is generally termed the Devonian Gas Sands. The definition of shallow has been taken at an average of 3,700 feet to and through the lowest producing horizon generally completed.
This is a study of a rather typical low permeability, low porosity natural gas horizon permeability, low porosity natural gas horizon (horizons) with the associated costs on a perwell basis, and gathering costs on an average perwell basis, and gathering costs on an average basis as experienced in the field.
Ultimate recoverable reserves and expected deliverabilities are discussed with reference to the overall profit ratio to be expected on an average well of this type. The basic information required for determining the economic feasibility have been based on historical production records throughout the area from production records throughout the area from numerous sources. This approach is used as being the most reliable in an area where ultimate recoverable and deliverability projections are very difficult.

Introduction
My introduction to the gas industry came at the age of four. My father and grandfather allowed me to travel with them during a rig move in Armstrong County, Pennsylvania. At that time they moved their rig using teams. The mud was so deep that they would place me on a stump or flat rock in order not to lose me in the mud. Their largest capital item was the drilling engine, which was a one-cylinder Franklin valveless engine with a reversible clutch at a total cost of $1,200.00. Natural gas was selling for 17 cts to 19 cts per mcf; cable tool drillers were being paid $8.00 per 12-hour day. Since then, except paid $8.00 per 12-hour day. Since then, except for the time spent in grade school, Greenbrier Military School, Lewisburg, W. Va., and the time spent in Europe during World War II as a rifleman, my entire life has been spent drilling gas wells and producing gas for various gas companies in Western Pennsylvania and Northern West Virgins.
Just prior to entering the service in World War II, drilling engines were still the main capital item; Waukesha power units and Reicee drilling engines were the popular ones selling for approximately $3,500.00. Drillers were being paid $1.00 per hour, and the price of natural gas was around 20cts per mcf. Upon returning from service, the trend in the drilling business was swinging to 36L Bucyrus Erie Spudders.
The Varying Modulus of Elasticity for Coiled Tubing Material
Authors: Tipton Steven M. 
Published: December 2007

Abstract
Strain-controlled low-cycle fatigue testing on axial coupon samples of coiled tubing alloys have revealed that the modulus of elasticity for cyclically stabilized material is considerably lower (e.g., on the order of 20%) than the modulus measured during the initial load application or during a conventional monotonic tensile test. However, a closer analysis indicates that the majority of the modulus drop occurs during the first strain application. Additional axial testing with small elastic unload-reload excursions validate that increasing plastic deformation during an otherwise monotonic load application causes an increasing drop in the elastic modulus. In this paper, fatigue data from two coiled tubing materials are presented which demonstrate the profound influence of plastic deformation on the modulus of elasticity. The modulus decrease is explained on the basis of fundamental reordering, or texturing, within the crystal structure of individual steel grains. The lower modulus has important implications with regards to depth estimation, buckling calculation and stuck point calculation.
New Downhole Gas Separator Enhances Coiled Tubing Jetting and Stimulation Procedures
Authors: Harris J. G. , Walters W. W. , Langhoff J. A. 
Published: December 2007

Abstract
Coiled tubing is a live well tool that has seen tremendous growth over the last decade. A new tool designed for the use with coiled tubing removes the gas from two-phase fluids. The phase separator has been successfully used to remove drilling damage and increase production in deep, low-pressure gas wells. The phase separator can also be used to separate the gas from two-phase systems when a Positive Displacement Motor is used in drilling and/or milling applications.
The introduction of the separator is a major breakthrough in downhole jetting technology. The mechanics that effect the removal of oilfield scales and permeability damage that restrict oil and gas production as well as injectivity will be discussed. The purpose for the tool development, laboratory testing techniques and methods are also presented.
This paper will focus on the technical benefits the tool brings to jetting applications. Procedures that have not been possible in low-pressure wells may now be accomplished and will be discussed.
Highly successful case studies will be outlined and analyzed to show the benefits derived when the gas is separated from the two-phase system. Most coiled tubing applications involve jetting technology and the new gas separator will broaden coiled tubing's role in the oil and gas industry.
Utilizing 4 ½-in. Monobores and Rigless Completions to Develop Marginal Reserves
Authors: Sanford John R. , Webb Tamara R. , Patout Seb , Morales Hugo 
Published: December 2007

Abstract
Marginal reserves in the Gulf of Mexico (GOM) shelf can be developed using old completion technology in new ways. Tubing-less completions or monobores are one of those technologies. Several monobores have been performed in the GOM, but usually, they were not the primary completion technique. Most were performed out of necessity, either because liners were stuck above the zone of interest or drill pipe was stuck across the interval.
Large cost savings can be realized by utilizing monobores as the primary completion without impairing the completion efficiencies. By eliminating the high day rates of a conventional platform rig, a single frac packed completion can be performed for less than $ 500,000.
This paper describes a technical review of two 4-½″ monobore completions that were performed in Eugene Island (EI) 273 to recover marginal reserves. The monobore completions were planned as the primary completion technique. However, several changes were made to the monobore completion as compared to conventional frac packing technology. For example, we utilized oriented, limited entry perforating (0°/180° phased and 0.25″ diameter entry holes, 4 shots per foot (spf) and no annular pack.
Many key learnings were identified during the completions and several changes were made prior to the second completion. These changes resulted in an overwhelming success both mechanically and financially. The second well, EI 273 Well C-1ST, was performed in less than 5 days at a cost of $ 465,000. The completion efficiency is 88 % and maximum sustained production was 20,000 mcfd.
Problems Of Independent Producers Subject To Federal Regulations
Authors: Gehr James G. 
Published: December 2007

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

Abstract
It is a daily occurrence to read and hear about our energy crisis. It is, and should be, everyones concern. The small voice of the independent oil and natural gas producer has been heard but not heeded. The independent oil and Gas Association of West Virginia, recognizing these problems, set out to correct the situation. It seemed that a reasonable solution should be attainable. However, we have experienced many setbacks which have been both expensive and frustrating. We have gained a great deal of respect for the problems of the interstate pipeline companies and the impossible task of federal regulation of natural gas prices.
The constant turmoil created by the Natural Gas Act and indecisions of the Federal Power Commission and Congress has put the entire petroleum industry, and put the entire petroleum industry, and especially the small independent, close to the point of extinction.
This cloud over our heads is certainly discouraging; however; we must not decrease our efforts toward a just and free enterprise system.

Background
The basis of our problem stems from the Natural Gas Act of 1938 passed by Congress. The Act required the Federal Power Commission to regulate the price of natural gas sold in interstate pipeline systems. The trouble started in 1954 when the FPC was ordered by the Supreme Court to also set prices for producers. This task of determining "just producers. This task of determining "just and reasonable" prices individually for thousands of producers, turned into a real monster. So by 1960, the Commission publicly announced that even if its Staff were tripled, it couldn't catch up with pending cases for 83 years.
Several attempts have been made by the FP C to accomplish fair regulation. Geographical areas were set up where supposedly costs of operating were equal.
High-Pressure Coiled-Tubing-String Design
Authors: Zheng Andrew S. , Larsen Henrik A. 
Published: December 2007

Abstract
High-pressure coiled tubing applications pose many technical challenges to coiled tubing string design: collapse, diametral growth, elongation and wall thinning, to name a few. This paper discusses an optimal string design methodology for coiled tubing in high pressure applications. The string design methodology uses a sophisticated collapse-prediction model for oval coiled tubing, taking into account the effect of axial load on collapse resistance. It also considers the effect of diametral growth, elongation and wall thinning on the performance of a high-pressure coiled tubing (HPCT) string. By integrating these design parameters into the framework of an optimal string design methodology, this paper presents an effective approach for high pressure coiled tubing string design. The paper also presents examples of HPCT string design. It is demonstrated that it is possible to design HPCT strings capable of withstanding more than 9000-psi collapse pressure while maintaining the field usability of the HPCT string.
Results of Recent Inspections Performed on Coiled Tubing
Authors: Stanley Roderic K. 
Published: December 2007

Abstract
The full-length NDE inspection of coiled tubing is now well established, and it is expected that NDE will play an increasing role in setting quality standards for used coiled tubing. Nondestructive Evaluation (NDE) methods are currently being documented into the API Recommended Practice for Care, Maintenance and Inspection of Coiled Tubing in order to set baseline requirements for inspection, and should form an integral part of a string management programme. Non-contact electromagnetic techniques for wall thickness measurement, ovality measurement, and flaw detection are in use in such tools, and have resulted in the following: detection of internal corrosion, section removal from the bed-wrap, downhole, and mid sections of tubes, scrapping entire tubes, and the detection of heavily fatigued areas in high strength tubing.
This paper indicates the type and value of the information that has been collected by performing NDE inspection, and presents the results of some recent inspections in detail. The paper also indicates the need for universal rules for derating sections of tubing in terms of both wall condition and consumed fatigue life.
The development of a universal vocabulary for the problems associated with coiled tubing in use that is consistent with current API terminology is also discussed.
Deepwater Mooring System Using CT Technology
Authors: Head Phil , Turner Dan , French David , Hanson Tim , Cameron Gerry 
Published: December 2007

Abstract
This paper provides an introduction to a joint industry project (JIP) which plans to employ coiled tubing (CT) from the deck of a vessel to deploy and install anchor points for mobile offshore drilling units requiring deepwater moorings.
CT offers significant advantages for installation of anchor points. It is a rapid conveyance means to the seabed; in addition it can supply significant power for drilling and is a circulation means once there. It provides the means for deploying anchors to considerable depths in the seabed, as appropriate to provide the necessary retainment force.
The vessel can then immediately perform a proof load test on the mooring line to ensure the quality of the anchor point. Only if it meets the required capacity is the CT then disconnected and recovered back to the vessel to collect the next anchor assembly and mooring line. To unset the anchor point, the mooring line is pulled taut and a release tool is dropped down the mooring line, close to the seabed, to activate a release mechanism which allows the mooring line to come free.
The concept offers many advantages over conventional anchors, including:
Pin point accuracy with reference to the mooring pattern centre.
Rapid and accurate anchorage deployment to significant depths into the seafloor
Very high ratio of pull-out force to weight of anchor equipment
Reduced difficulties in transportation and handling and therefore increased safety for anchor handling personnel.
Significantly reduced CAPEX and OPEX.
Simple recovery of anchor and mooring line when released from rig.
Dynamically Overbalanced Coiled Tubing Drilling on the North Slope of Alaska
Authors: Kara D. T. , Gantt L. L. , Blount C. G. , Hearn D. D. 
Published: December 2007

Abstract
Coiled Tubing Drilling (CTD) continues to play a dominant role in through-tubing sidetracking of wells on the North Slope of Alaska. Recently several CTD candidates were targeted in an over-pressured reservoir. Three wells were successfully CT sidetracked as a pilot project in this over-pressured reservoir. The ultra-slimhole directional drilling system −2.75″ nominal openhole diameter-developed at Prudhoe Bay1 was used in combination with an unconventional approach to maintain overbalanced conditions when sidetracking these wells.
Hydraulic modeling showed that with a kill weight drilling fluid, the calculated Equivalent Circulating Density (ECD) at the sand face could approach the regional fracture gradient. In addition, kill weight mud in the formulation required for CTD operations would be a significant expense. To address these concerns, the wells were CT sidetracked using a less expensive under-balanced drilling fluid system. Although the drilling fluid hydrostatic pressure was less than reservoir pressure, over-balanced drilling conditions were dynamically maintained by the high ECD while circulating, and controlled by increasing the surface pressure using a choke when circulating at less than drilling rates.
High Pressure Coiled Tubing Instrumental in Deep Water Well Work
Authors: Larsen Henrik Aslak , Porter David A. , Peterson Chad 
Published: December 2007

Abstract
High Pressure Coiled Tubing (HPCT) has been utilized to perform stimulation, memory production logging, plug retrieval, washing across a gravel pack screen and gravel pack logging. The two jobs reported here comprised of seven runs.
The work was performed in the Gulf of Mexico on the Troika field in Green Canyon 200 (Figure 1). The rig was Global Marine's semi-submersible the Glomar Arctic 1 working in approximately 2700 feet of water.
The wells are high rate, high-pressure oil wells. They are capable of flowing in excess of 30,000 BOPD and 60 MMSCFD. This field has reset the Gulf of Mexico record for the highest rate oil producers.
Operations were performed with up to 9 feet of heavy seas with 6,600 psi on the well head and at 18,300 feet total depth.
The objectives of both jobs were met, and the extreme well conditions pushed the operating envelope of the equipment and the personnel. The authors believe that the quality of onsite personnel, a steep learning curve along with generally accepted best practices, and advances in procedures and equipment allowed the successful execution of these jobs.
The cost of the CT was approximately 10% of the total daily operational cost.
Simulation of the Bradshaw Berea Field
Authors: Royo Carlos M. 
Published: December 2007

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

Abstract
A numerical model was used to simulate a portion of the Bradshaw Gas Reservoir and to portion of the Bradshaw Gas Reservoir and to evaluate the effect of well spacing and gathering-system pressure on production. A model study of the entire reservoir was not warranted because of limited data. After selecting a portion of the reservoir for which production data were available, an acceptable production data were available, an acceptable history match was obtained and performance prediction runs made to simulate the reservoir prediction runs made to simulate the reservoir under different future operating conditions.
Following the reservoir study the effect of well spacing on economics was determined. Production forecasts were obtained for well Production forecasts were obtained for well spacings ranging from 150 to 400-acres and for formation thicknesses of 20 and 25 feet. For each case, the economics of a typical well were determined for four gas price levels, including the current price. The results show that while the profitability index increases as well spacing increases, the present worth value calculate at a ten percent discount rate exhibits a maximum within the range of well spacings investigated. The maximum value depends on the gas price and the formation thickness.

Introduction
The Bradshaw Gas Field is located in McDowell County, West Virginia. The reservoir is a tight, relatively low-pressure Berea sand at an average depth of approximately 4000 feet, with first production established in the middle 1960's. Development of the reservoir was based on 150-acre to 300-acre spacing depending on the operator. Cities Service Oil has been producing its wells since 1966 on 300-acre spacing. producing its wells since 1966 on 300-acre spacing. This investigation was initiated to answer several questions concerning the development of the reservoir. Of particular interest was the optimum well spacing because portions of the reservoir still remained to be developed. Also, infill drilling could be initiated at several locations provided 150-acre or 200-acre spacing proved to be more economically attractive than proved to be more economically attractive than 300-acre spacing. Another objective of the investigation was to determine the effect of lowering the gathering-system pressure on production. At the time the study was production. At the time the study was undertaken, Cities Service Oil was delivering gas at a line pressure of 250–300 psig, while outside operators were producing into a line pressure of about 150 psig. In addition, other pressure of about 150 psig. In addition, other operators had drilled several wells and planned to drill several more on small leases along a railroad right-of-way which goes through some of Cities Service Oil leases.
Use of Resin-Coated Proppant to Control Shallow, Low-Temperature Unconsolidated Sands
Authors: Geehan T. , Deckert S. L. , Johnson K. , Arnold W. T. 
Published: December 2007

Abstract
The paper describes two applications of different resin-coated proppants to obtain a consolidated proppant pack to reduce proppant flowback and formation sand production.
The zones of interest are part of the Schrader Bluff development project. Three zones were treated; one was in the deeper, more consolidated O sand formation, and two were in the less consolidated N sand. The problem of sand production was further complicated by the viscous nature of the oil in place, which was in the range of 17 to 21 API.
The reservoir temperatures ranged from 80° to 110° F. In the higher temperature zones, the catalyst required to initiate the resin set was more benign and thus allowed the use of a cross-linked borate as the base fracturing fluid. In the cooler formation, the complexity of the operation was increased by the need for a catalyst based on a mixture of acid and alcohol. This was required to ensure the resin-coated proppant pack obtained sufficient compressive strength to withstand the viscous drag of the heavy oil. The need for the more aggressive catalyst in the lower temperature zones necessitated the use of HEC as the base fluid for fracturing because the catalyst was incompatible with borate-based fluids. The composition of the catalyst was modified to meet the safety standards for pumping as demanded by the operating procedures from the service company.
The paper also describes the fracture geometry determined from analysis of the treating data and the production results from the treated zones.
High GOR Wells Optimization, Prudhoe Bay Practice
Authors: Peruzzi Tave , Krumanocker Erich 
Published: December 2007

Abstract
Many oil fields are gas handling limited. A requirement or desire not to flare and the relatively higher costs of gas compression compared to liquid handling are the main reasons. Optimization of high GOR wells in gas handling limited fields should result in a higher field oil rate. This paper describes high GOR well optimization in Prudhoe Bay. This description may provide ideas applicable to other gas handling limited fields.
In this paper the problem of high gas/oil ratio well optimization is explained. Empirical observations, strategy, tools and examples for optimizing high GOR wells in a gas constrained field are presented. Overall results, as well as specific well production responses, are discussed.
An Improved Sandstone Acidizing Model: The Importance of Secondary and Tertiary Reactions
Authors: Murtaza Ziauddin , Berndt Oliver , Robert Joel 
Published: December 2007

Abstract
An improved model for sandstone acidizing is presented, following a review of sandstone acidizing models. The improved model resolves complex sandstone mineralogy into eight distinct minerals instead of two or three minerals as was done previously and uses empirical correlations to compute equilibration between various aluminum and silicon fluoride species. The improved model provides a reasonable estimate of porosity evolution and acid consumption for most sandstones with known mineralogy, and unlike previous models it does not require experimental predetermination of acid capacity and Damköhler numbers. Validation of the model with several sandstones for a wide variety of injection rates and temperatures is presented. Sensitivity analyses performed with the model are also discussed.