bluuebunny/crossref_metadata_2025_split huggingface dataset:
Makeup Torque and Rotary Shouldered Connection Reliability
Authors: Baryshnikov Anatoly , Ferrara Paolo , Schenato Adelmo , Curioni Emilio 
Published: December 2007

Abstract
This paper presents an analysis of the makeup torque influence on Rotary Shouldered Connection (RSC) reliability under static and dynamic loads. Both theoretical and experimental results of torque-turn diagrams and full scale fatigue tests are shown. The paper gives recommendations for the optimum makeup torque under cyclic loads for different material characteristics and suggests an operative patented method to estimate optimum makeup torques for connections directly at the rig site. Results are presented and discussed for different tool joint and drill collar connections. All conclusions are illustrated with a set of plots describing the results of the investigations.

Introduction
RSC friction capacity. A good make up quality is achieved by creating optimum preload conditions (axial loads) into connection by means of a makeup torque. This make up will guarantee maximum RSC reliability under applied static and/or dynamic loads and mud pressure. The main RSC geometrical parameters and friction coefficient on contact surfaces define the RSC friction capacity and preload condition into connection under the application of a given makeup torque. In the early days of deep drilling very little was known about RSC friction coefficient during making up and the friction coefficient was usually taken to be equal to 0.2. In 1950-60 a set of RSC makeup tests was developed with different compounds. Special connection design threads were used. Connections were made up at a given makeup torques and makeup axial loads were estimated by pin elongation measurements. These investigations showed that RCS friction coefficient without dope was equal to 0.133, while with the common dope used at the rig site (60% lead powders 40% grease base) it was equal to 0.08. This friction coefficient was accepted by API as a standard value for drilling calculations though it is not the same for different kinds of compounds, RSCs and drilling conditions.
The results of both theoretical and experimental investigations show that RSC optimum makeup torques are different under static and dynamic (fatigue) loading conditions and can be estimated. However, it is difficult to use existing recommendations at the rig site due to the influence of different technical and technological factors (well conditions, geometrical and mechanical connection parameters, frictional properties of thread compounds and so on) on the optimum makeup values. RSC friction capacity depends on different factors and may vary within a large range (more than 50%) during connection life and from one assembly to the other. While drilling, an improper break-in procedure, cleaning and lubrication of RSC may lead to local thread (or shoulder face) galling and dramatic changing of its friction capacity.
P. 197
A Model for Shock Sub Performance Qualification
Authors: Parfitt S. H. L. , Abbassian Fereidown 
Published: December 2007

ABSTRACT
This paper investigates the influence of the interaction between a tricone bit and the drilled formation on the axial dynamic behaviour of the drill string, with the aim of qualifying shock sub performance. It presents a simple tricone bit model including both material removal and the non linearity of lift off, which makes no assumptions as to the form of the bottom hole pattern. The model generates a trilobe pattern and the associated phenomena typically found in field data from tricone bit drilling in hard formations: power spectral density peaks on the low frequency side of 3xRPM and 6xRPM etc during 'smooth' drilling, and the beating phenomenon.
Slim Hole Drilling Package Proves Cost Effective in Remote Location
Authors: McNicoll R. M. , Schneider Georg , Marquardt P. , Martin David , Skekel D. 
Published: December 2007

ABSTRACT
The Manandaza South-1 slimhole exploration well was drilled in Madagascar during the period August to October, 1993. From receipt of tender documents to spud took 24 weeks. The well was drilled and satisfactorily evaluated, terminating in a 41/8" hole, at 60% of the cost of the nearby offset. It was drilled on a partnership basis using a small, modified workover hoist. The success of this venture has led the operator to plan future wells along similar lines.
Marginal Fields Development Using an Innovative Drilling Rig
Authors: Grandi Maurizio , Calderoni Angelo , Schenato Adelmo , Cicognani Claudio 
Published: December 2007

Abstract
The Oil Industry is actively involved in screening new technologies to solve a common problem: to reduce capital expenditures as well as to minimise environmental impact.
Budget reduction has forced several Oil Companies to identify new solutions: for example, in onshore applications, slim hole drilling has been recently seen as a suitable tool for cost reduction in a variety of applications such as frontier basins and prospect evaluation, re-entries, production from marginal fields and so on.
An overview is presented on low cost drilling for marginal fields production in mature areas.
In relation to this particular scenario, appropriate technologies have been investigated with the above aim.
An innovative drilling rig, particularly tailored for marginal fields development, is presented in the paper along with the preliminary results of field applications.
New Remote Control-Conventional Drawworks
Authors: Dupuis Dominique , Girault Alain , Codron Michel 
Published: December 2007

ABSTRACT
Most drilling rigs are equipped with a drawworks (DW) powered by one or several electrical DC motors. The DW has a braking device consisting of a mechanical brake and an eddy current brake (ECB). Standard controls are direct and multiple; as a result, the work station of the driller is located and engineered around these controls. This is anything but friendly to actuate with a lack of good ergonomic design.
This paper will describe how, without modifying any of the mechanical components and associated equipment of a conventional existing DW, a remote single joy stick allows the control of the upwards and downwards loads speed and automatically operaties the different components.
The engineering of the system relies on the electrotechnical controls of the power components concerned (DC motors and ECB) associated with adequately controlled and placed sensors. It shall be noted that the mechanical brake will be only used for emergency and "parking".
The paper will outline the field results and analyse the benefits of a such new control in term of ergonomy and location of drillers cabin. A consequence of this system is a refined control of the weight on hook. It is obvious that this system implements all the principle components for an automatic positionning of the travelling block.
Why Use a Top Drive on a Land Rig, or When?
Authors: Tyson R. W. , Schuck J. D. 
Published: December 2007

Abstract
The ultimate drilling customer is the Operator and his economics dictate when and how often he drills. Reducing overall well cost allows the operator to increase his drilling program. Can top drive drilling systems pay off for the operator and land contractor?
The purpose of this paper is to provide a comparison of drilling with and without a top drive on horizontal land wells. Actual drilling data and economics will be compared and analyzed. Advantages, limitations, and operational costs will be reviewed. The integration of the top drive system into a land rig, portability, installation, and operation will be examined.
The needs of the operator were conveyed to a specific drilling contractor who in turn developed a portable drilling package with a manufacturer, which would meet all the operational requirements and economics. The result stretches the operator's drilling dollar, and the contractor's rig utilization.
Use of a Novel Drill-In/Completion Fluid Based on Potassium Formate Brine on the First Open Hole Completion in the Gullfaks Field
Authors: Svendsen Øjvind , Toften J. K. , Marshall D. S. , Hermansson C. L. 
Published: December 2007

Abstract
This paper describes the first use of a novel drilling fluid based on potassium formate brine and weighted with manganese tetraoxide. Also included is the completion technique used to open hole complete an unconsolidated reservoir. The fluid was selected for maximum brine density, and to facilitate removal of the filtercake. Criteria for fluid and completion selection are presented together with laboratory work conducted to optimise the fluid and the completion for a specific application.
Potential problems related to operations and working environment were identified through a risk analysis approach. Predicted solutions are compared to actual field experience. Key factors included minimisation of ECD, monitoring of soluble barium in the drilling fluid, rig-crews' exposure to manganese tetraoxide and barium, and procedures to combat lost circulation. The filtercake removal and its transportation through the pre-packed screen completion were comprehensively investigated.
The perceived benefit of the formate brine system was the possibility to drill, complete and produce an unconsolidated, pressure sensitive reservoir with the same fluid.
This was achieved with minimal on-site fluid treatment. The fluid was significantly more expensive than conventional alternatives. However, based on drilling fluid performance, rig-time and well productivity, one can conclude that the field test was successful and the use of the fluid was justified.
Improved Fracturing Technologies Provide for Increased Well Productivity: A Case Study on Red Fork Formation Wells
Authors: Tjon-Joe-Pin Robert M. , Brannon Harold D. , Handren Patrick J. 
Published: December 2007

ABSTRACT
A case study has been conducted on Red Fork formation wells with bottomhole temperatures ranging from 225°-250°F. The fracturing applications and techniques in this area had historically provided lower than expected posttreatment productivity and a rapid decline rate, suggesting that the fracture conductivity were less than optimum. Joint efforts of the operator and service company, utilizing state-of-the-art fluids, breakers, and design methodologies, were employed to optimize well productivity. The case histories of hydraulic fracturing treatments and subsequent production performance of five offset wells are analyzed and presented. Average incremental production rates were significantly improved through application of the new technologies, clearly demonstrating the effectiveness of the modifications.
Production Automation System For Gas Lift Wells
Authors: Cooksey Andrew , Pool Mike 
Published: December 2007

ABSTRACT
Economic conditions in the gas and oil industry have necessitated not only reductions in manpower and capital expenditure but also optimization of existing facilities. The approach that appears to offer the most viability for satisfying these needs is system automation. For this reason, technology in gas lift operation has directed its attention toward the development of modular systems that can automate operations at each wellhead and platform. Intelligent controllers can be used 1) with centralized master station direction or 2) as stand-alone products for automating immediate response to preset conditional parameters. In addition to reducing manpower requirements, intelligent controllers will further enhance gas lift operation by helping to increase the efficiency of continuous- flow gas lift operations. In addition, they can be used to automate load shedding that results from lift gas fluctuations. With automated systems, operators can now set up field-wide programs that provide optimum use of available lift gas with minimal manpower; this supports the operational direction encouraged by the economic climate of today's oilfield.
Production rates increase when normal gas lift flow rate set-point control is maintained at each well. In the optimization system described in this paper, the set point changes can be manually entered at the wellhead controller or from a central master station.
The local controllers, in addition to receiving set points from the master station, can intelligently change flow-rate set points in cases in which the line pressure is reduced. Orderly startup and shutdown functions control each gas lift well. These special functions, particular to operating gas lift wells, are designed to preserve the integrity of the downhole equipment. Additional advantages are realized from the more efficient usage of the lift gas and the immediate indication of problems that occur in standard production process equipment.
The Effect of an Initial Gas Saturation on the Performance of a Waterflood
Authors: Dykstra H. 
Published: December 2007

Abstract
The behavior of a waterflood is affected, among other factors, by the initial gas saturation at the start of injection. To illustrate this effect on oil rate and on the water-oil ratio (WOR), calculations were made with the Dykstra-Parsons(1) layered system model. Two cases were chosen, one for a high gravity oil with a low mobility ratio, and one for a low gravity oil with a relatively high mobility ratio.
The factors that effect the recovery of oil are described. The ideal situation for calculating a waterflood performance, would be that the values of all of the parameters to be used in the model correctly define the reservoir and fluid properties and the displacement process. The more closely the parameters define the system, the greater will be the confidence in the predicted results. If production history is available, a history match can be made. Certain parameters can then be adjusted to obtain a better match with actual performance before predictions are made of future performance. Examples are given for two waterfloods.
The fluid properties and saturation data used in the analysis were based on pressures obtained from depletion calculations to establish initial conditions prior to the start of the waterflood. For Case 1, a 40 deg API oil having an initial bubble point pressure of 3500 psia at 220 deg F was depleted down to a gas saturation of 30 percent. For Case 2, a 20 deg API oil having an initial bubble point pressure of 1500 psia at 130 deg F was depleted down to a gas saturation of 12 percent.
The results of the study show a substantial decrease in maximum oil rate and a substantial rise in the level of the WOR-recovery curve with increase in initial gas saturation. These types of results, showing the effect of an initial gas saturation, have not heretofore been published.
Lithium Bromide Chiller Technology In Gas Processing
Authors: Huey Melton A. , Leppin Dennis 
Published: December 2007

Melton A. Huey, P.E., and Dennis Leppin*

Abstract
Lithium Bromide (LiBr) Absorption Chillers have been in use for more than half a century, mainly in the commercial air conditioning industry. The Gas Research Institute and EnMark Natural Gas Company cofounded a field test to determine the viability of this commercial air conditioning technology in the gas industry.
In 1991, a 10 MMCFD natural gas conditioning plant was constructed in Sherman, Texas. The plant was designed to use a standard, off-the-shelf chiller from Trane with a modified control scheme to maintain tight operating temperature parameters. The main objective was to obtain a 40 F dewpoint natural gas stream to meet pipeline sales specifications. Various testing performed over the past three years has proven that the chiller can be operated economically and on a continuous basis in an oilfield environment with minimal operation and maintenance costs.
P. 419
Computer Simulator of Coiled Tubing Wellbore Cleanouts In Deviated Wells Recommends Optimum Pump Rate and Fluid Viscosity
Authors: Walton I. C. 
Published: December 2007

ABSTRACT
Key factors in the efficient removal of sand fill from deviated wells are the proper selection of a fluid and the pump rates. The operation should be designed to (1) reduce or eliminate the formation of beds of particles in the annulus between the casing and tubing, (2) maintain the particles in suspension and (3) transport the fill to the surface.
Currently, the only guidelines available for the preferred pump rate and fluid properties apply specifically to vertical wells. In essence, the recommendation is that the linear fluid velocity in the annulus should exceed twice the particle fall velocity. However, in a deviated well, the linear fluid velocity will not prevent the particles from falling to the lower side of the annulus and forming a bed. Unless the particles are perfectly supported by the fluid, formation of a bed can only be prevented by maintaining a sufficiently high level of turbulent activity.
A new design tool for coiled tubing (CT) cleanouts in deviated wells has been developed. Based on a mechanistic model of particle transport in deviated wells, it predicts the conditions under which a particle bed is formed, calculates the depth of the bed and determines whether the bed slides upward, remains stationary or slides back down the well. Moreover, it calculates the minimum pump rate required to achieve complete suspension of the fill for different fluid viscosities, sand pick-up rates and deviation angles, thereby allowing a simple assessment of the optimum design parameters.
Decision Tree for Selection of Artificial Lift Method
Authors: Heinze Lloyd R. , Winkler Herald W. , Lea James F. 
Published: December 2007

Abstract
Recent changes, upgrades and development in artificial lift equipment have expanded the considerations for selection of pumping method. This paper covers sucker rod pumping, continuous gas-lift, intermittent gas-lift, electric submersible pumping, hydraulic reciprocating pumping, hydraulic jet systems, plunger lift, progressing cavity pumping, and additional miscellaneous pumping methods. Changes in well conditions and equipment capabilities demand timely reviews of the original lift method decision to determine if it is still the best choice. Often the selection of the lift method is based on operating personnel / decision maker equipment familiarity. Included in the decision tree should be a long term economic analysis. This paper will consider how new advances in individual methods have changed their cost effectiveness and provided solutions to unique problems.
There is not a single lift system that is the most economic system for all wells. In order to access the practically and the economics of various methods of artificial lift, the first step is to generate an IPR (Inflow Performance Relationship) curve or a PI (Productivity Index). Then a profile of expected and desired production versus time should be determined. Figures 1 & 2.
With the above information, potential artificial lift methods can be introduced, including expected run lives and cost considerations for the most obvious methods. Detailed cost estimates of the well operating cost are then reported and compared to the numbers used in the economic evaluation of the field. The economics of low rate wells and high rate wells need to be adjusted to account for the economics of the project.
The economy of scale and simpler logistics of just using one lift system in most fields will probably not weigh up against the savings of using the most economic system on each well. Early in the life of the field the well may produce 100% oil with a moderate GOR. As the field declines and pressure maintenance begins GOR will increase and then rapidly decline while water production will increase. What range of BFPD is project, and what is the desired producing sand face pressure, Pwf.
Areas of evaluation of lift methods include (1) lifetime cost, (2) operating cost, (3) energy efficiency, (4) initial capital cost.
A Methodology to Optimize Fracturing Treatments in a Tight Gas Field of Northwest Louisiana
Authors: Kiburz D. E. , Sullivan S. C. 
Published: December 2007

ABSTRACTA systematic approach to optimize stimulation treatments on a field-wide basis has been developed for the Gray Sand reservoir, a member of the Smackover formation, in the Cotton Valley field of northwest Louisiana. Since the inception of the program, productivity increased 72%, costs reduced 14% and service quality significantly improved bya team approach between operator and service company the application of technology to design and optimization tracking and evaluation of results.This paper presents the results and advantages of using this three-step approach to optimize stimulation treatments in the Gray Sand reservoir. However, this methodology can be effectively applied to any field to optimize productivity and costs.
Depositional, Diagenetic, and Tectonic Controls on Frontier Formation Reservoir Characteristics: Moxa Arch, Southwestern Wyoming
Authors: Home John C. , Forster John R. 
Published: December 2007

ABSTRACT
The Frontier Formation of the Moxa Arch in southwestern Wyoming provides an excellent example of the interplay among sedimentation, diagenesis, and tectonics on reservoir quality and performance. During the Cretaceous, thrust uplift and crustal loading occurred in the Sevier Orogenic Belt to the west of the foreland basin. The thrust sheets provided ample sediment to the Moxa Arch area during Frontier time. These sediments accumulated in wave-dominated deltaic, strandplain, coastalplain, and incised valley-fill depositional environments. The tectonic activity in the Sevier Orogenic Belt caused recurrent differential movement of orthogonally-shaped basement blocks along the Moxa Arch. These Movements created fractured lineaments at block boundaries. In addition, the recurrent movements of basement blocks influenced paleostructuring, diagenetic fluid migration paths, and sediment dispersal patterns of the Frontier.
The depositional facies of Frontier sediments control the primary porosity and permeability trends of Frontier reservoirs along the Moxa Arch. Post-depositional fractures caused by recurrent differential movements along zones of weakness at basement block boundaries secondarily enhance permeability and performance characteristics of Frontier reservoirs. Both the depositional facies and post-depositional fracturing of the Frontier influence the diagenetic trends affecting secondary porosity and permeability characteristics of Frontier reservoirs along the Moxa Arch. It is this complicated interplay of depositional, tectonic, and diagenetic influences that control the characteristics of Frontier reservoirs along the Moxa Arch.
Increasing Gas Reserves Through Technology in SW Wyoming
Authors: Duda John R. 
Published: December 2007

ABSTRACT
Results from modeling the deployment of advanced E&P technologies indicate that natural gas "reserves" (possible, probable, and potential) in the over-pressured, tight portion of the Greater Green River Basin can be significantly increased. The reserve increases, attributable to advanced technologies, total about 20 Tcf for wellhead gas prices of $1.25/Mcf to $2.00/Mcf. A majority of these reserves are contained in the Almond and Lewis plays, at depths of 9,000 ft to 12,000 ft. In part, the reserve gains stem from economical exploitation of the gas resource at deeper depths.