bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Technique for the Calculation of Mechanical Skin Damage of Horizontal Wells Caused by the Drilling Fluids
Authors: Malekzadeh Dariush , Tiab Djebbar 
Published: December 2007

Abstract
A horizontal well, due to its large contact with the formation, may be several times more productive than a vertical well draining the same volume. However, this large contact of a horizontal well with the formation will cause a more severe formation damage than the one obtained from a vertical well. Also, the time that the formation is exposed to the drilling fluid is much longer for a horizontal well compared to that of a vertical well. In addition, the design of a truly non-damaging drilling fluid may be very difficult for some formations. This becomes more complicated as the formation characteristics, such as the fraction of various types of clays, change with the horizontal distance being drilled. Therefore, during the production, some sections of the horizontal well which have severe damage will not contribute to the production. This paper presents the development of a new technique for determining the horizontal well length contributing to production, and the corresponding calculation of the correct mechanical skin damage caused by the horizontal drilling operations.
The method developed in this paper indicates that the response of a horizontal well with mechanical skin and of length Xf1 can be substituted by a horizontal well of length Xf2 with no mechanical skin. A relationship between the mechanical skin and (Xf1,Xf2) is obtained which is applicable for the case of long horizontal wells, thin formations, and formations with high vertical permeability. These are the cases which are most often present in horizontal well drilling and applications. The method developed here is also applicable to hydraulically fractured vertical wells with mechanical skin. For a horizontal well with mechanical skin damage, Xf2 is smaller than Xf1 while for a stimulated horizontal well Xf2 is greater than Xf1.
Scale Inhibition of Hydraulic Fractures in Prudhoe Bay
Authors: Martins J. P. , Kelly Roy , Lane R. H. , Olson J. B. , Brannon H. D. 
Published: December 2007

Abstract
Formation damage has caused production declines in many wells in the Prudhoe Bay Field. Acid stimulations have become progressively less effective in restoring productivities, and a major campaign of hydraulic fracturing has been undertaken, with excellent results.
To prevent scale deposition in the propped fractures, techniques have been developed to enable scale inhibitor to be deployed during fracturing operations, despite the high pHs, and also to be replenished in existing fractures.
Prediction of Filtration Under Dynamic Conditions
Authors: Peng Shuang Jiu , Peden J. M. 
Published: December 2007

Abstract
This paper presents a summary of the results of an experimental and theoretical study on filtration properties of water based drilling fluids under dynamic and static conditions. The experimental investigation of the filtration properties was conducted as a function of mud types, solids concentration, pressure and shear rate. A dynamic filtration equation was developed using a mass balance method based on the cake filtration theory prevailing in the chemical engineering industry. The results of experimental data showed substantial agreement with the filtration equation.
Extended Drillpipe Life With Tighter Specifications
Authors: Shepard J. S. 
Published: December 2007

Abstract
This paper is for the benefit of the drill pipe end user, and for those operators who wish to minimize their risks in the drilling of any well.
It wasn't too long ago that drilling industry focus was concentrated on drilling a straight hole. However, with increased reservoir productivity allowed with hole deviations up to and including 90 degrees, dramatic advances in technology were developed to make this possible. More sophisticated drilling fluids, measurement while drilling (MWD), new directional tools, and Top Drives have all contributed to the efficient drilling of highly deviated wells.
However, improvements to the same degree have not been made to drill pipe. This explains the growing use of higher grade drill pipe to withstand the higher stresses of deviated drilling, such as higher torque, accelerated O.D. wear, increased drag, drilling in compression, and severe amplitudes of cyclic bending stress.
Drillstring Problems Related to Internal Upset-Run-Out Area of Drillpipe
Authors: Shaffer E. A. 
Published: December 2007

Abstract
Throughout the history of drill pipe use there has been an ongoing problem with fatigue failure. In recent years extensive studies have been performed to gather information in regard to early drill pipe fatigue failure. A very comprehensive report was published by API/IADC at the annual International Association of Drilling Contractors (IADC) meeting in September 1990. The report clearly identifies the major area of concern is at the transition area of the internal upset. Speaking conservatively, approximately 65% of the problems in this area originate from the inside surface. With this in mind a task was undertaken to develop an inspection system capable of reliably detecting inside or outside surface fatigue cracks in this part of the drill pipe tube.
The first step in development was to determine why existing inspection techniques were not successful in locating fatigue cracks in the upset transition area. Since the majority of equipment available relies on flux leakage principles some obvious problems became quickly evident. Pipe that starts developing internal fatigue cracks in the transition area has normally been in service for many years. Examination of the internal pipe surface usually reveals cracked and pitted coating or no coating at all. A typical electromagnetic inspection (EMI) type unit may or may not produce an indication of a crack in this area, dependent on the amount of flux leakage produced. Even if the pipe is suspected of having a crack, further prove-up is typically necessary by using a magnetic particle application. The problem begins here. Unless the inside surface is sandblasted to remove excess scale and coating, many false powder builds may be present. Therefore conventional magnetic particle inspection is limited. Magnetic particle inspection, at best, is only able to locate the larger cracks. Small cracks, in the early stage of development, can be easily overlooked. Another problem with conventional EMI systems is erroneous signals received due to abrupt changes in wall thickness at the transition area.
Therefore, improved inside surface crack detection and confirmation is needed. A development consideration was to design a system that would be able to locate and identify cracks independent of wall thickness changes, inside surface scale etc. Along with thickness changes the system needed the capability to reliably differentiate between inside and outside surface indications. A final consideration was to develop a system that was not too cumbersome or slow and could reliably repeat test results. The task was undertaken to develop an ultrasonic unit for the inspection of the drill pipe transition area. (Figure 1)
An Analysis of the Field Performance of Antiwhirl PDC Bits
Authors: Clegg J. M. 
Published: December 2007

Abstract
"Bit whirl", the backwards whirling motion of polycrystalline diamond compact (PDC) drill bits, has been identified as a significant contributory factor in the premature failure of PDC bits in the field.1 Two SPE papers have discussed bit whirl and the testing of various potential solutions, 1, 2 and one described the field testing of PDC bits modified to produce a "low friction gauge".3 This paper describes the design and subsequent testing in the laboratory and then in the field of a PDC bit designed from scratch to resist backwards whirling motion by incorporating various design features including the "low-friction gauge" concept described by Warren et al2 (described below as an "Antiwhirl bit"). It details the importance of the magnitude of the lateral component of the resultant cutting force on the bit and the angular extent of the bearing pads that react with this force, and describes and explains the directional behaviour of Antiwhirl bits in the field.
Bi-Center Bit Performance Reduces Drilling Cost in California
Authors: Quintana J. L. 
Published: December 2007

Abstract
The first polycrystalline diamond compact (PDC) bi-center bit application in California reduced cost per foot and helped eliminate tight hole problems associated with Pliocene age overpressured swelling shales. The bi-center bit design drills a larger hole than the casing inner diameter through which it passes.
Casing designs for two recent wells drilled below 15, 000 feet in the southern San Joaquin valley in Kem County, California required 7.625 inch flush joint liner to be run in an 8.500 inch hole. In the first well, the tight annular clearance of this casing and hole size combination resulted in a drilling liner sticking 3700 feet off bottom. This problem was avoided in the resulting sidetrack by underreaming the 8.500 inch hole to 9.875 inches. The second well also utilized the 9.875 inch underreamer method to successfully run a 7.625 inch flush joint drilling liner to bottom.
The bi-center bit design was used on a subsequent 16, 871 foot well to drill a 9.875 inch hole below 8.500 inch drift casing to reduce cost and eliminate the need for underreaming. The inherent mechanical risk of running an underreamer was eliminated and cost per foot was reduced by an average $31/ft. The cost savings associated with running the bi-center bit was $89, 000. Also, it was learned that hole geometry opposite the bi-center bit bottom hole assembly (BHA) greatly affects bit performance.
The bi-center bit concept was used again to drill a 6.750 inch sidetrack hole below 6.500 inch drift casing. Very tight hole conditions encountered in the original 6.500 inch hole were alleviated by the increased annular clearance provided by the 6.750 inch bi-center hole.
Drilling the Deepest Horizontal Well in the Gulf of Mexico, South Marsh Island 239 D-10
Authors: Jenkins R. W. , Patrickis A. N. 
Published: December 2007

ABSTRACT
Texaco drilled the deepest horizontal well to date in the Gulf of Mexico from the South Marsh Island 239 D platform in the summer of 1990. The well was drilled to a depth of 10092 ft true vertical depth (tvd) and a measured depth (md) of 12871 ft. The well bore was totally displaced from the platform by 4905 ft with over 900 ft of horizontal section being drilled in a hydrocarbon bearing zone.
The paper discusses the application of proven shallow horizontal well drilling techniques as they pertain to the deep horizontal well. The same technology, previously published by Texaco on shallow horizontal drilling projects, was utilized on the deep well bore and the successes and failures of this technology will be discussed. The paper will highlight directional planning for a deep horizontal well from a platform location as well as drilling fluid design, logging while drilling, specific hole problems, bottom hole assembly usage and completion techniques. The South Marsh Island 239 D-10 well was drilled to the proposed target without great delay considering the difficulty of the directional plan. But, this well did encounter severe problems when attempting to run the production casing upon completion of the drilling phase. The paper will discuss lessons learned from these failures as well as possible corrections to be employed on future deep (below 7000 ft) horizontal wells.
Case History of a Horizontal Well Using a High-Angle Pilot Hole
Authors: Stacey E. S. , Rogers C. T. , Bowman J. K. , Noblett B. R. , Cooney M. F. 
Published: December 2007

ABSTRACT
Petro-Hunt Corporation drilled a horizontal well in the Austin Chaikin Gonzales County, Texas. A high-angle pilot hole was used to determine a target interval and horizontal borehole orientation, while satisfying a variety of operational and geological considerations.
The well was directionally drilled to an angle of 44° and intermediate casing was set. The pilot hole was then drilled at the same angle through the target formation and evaluated using openhole logs, including a circumferential acoustic imaging device. After evaluation, the pilothole was plugged back, and the horizontal borehole was kicked off and drilled to a horizontal displacement of 3, 578 ft.
This method allowed the entire target formation to be evaluated prior to committing the wellbore to a particular interval, while avoiding potential operational problems associated with a vertical pilot hole. The acoustic imaging log allowed the operator to select the optimum Stratigraphic interval in which to locate the horizontal borehole, and confirmed the proper borehole orientation. The well was successfully completed on schedule and within budget.
The planning and drilling of the well is reviewed, with emphasis placed on operational and geological considerations and the evaluation of the pilot hole.
Rock Drillability Related to A Roller Cone Bit
Authors: Morris Richard I. 
Published: December 2007

Abstract
Security Engineering Division of Dresser Industries has utilized the basic bit penetration mechanism of a roller-cone rotary bit in the development of a drillability index for "hard" rock mining bits. A 1/8 inch radius, hemispherical drill bit element is pressed into a flat surface of a hand sample with a hydraulic pump and ram until a distinct crater is formed. The crater depth divided by the ram load constitutes a penetration or drillability index, p'/E. From this index, bit type, drilling weight, average penetration rate and approximate bit life may be determined. Field results have been well within the degree of accuracy consistent with sampling error.
Introduction
For several years there has been a need in mining and construction for a reliable method of determining drillability of hard rock by a simple test of hand samples. Early in 1966, Security Engineering Division of Dresser Industries began development of a method to measure rock drillability relative to a roller-cone bit used in drilling large (5 to 15 inches) blast holes. A rock strength value or drillability index was considered the essential value to be determined. From that value would be determined bit type, bit weight required, average penetration rate at a given rotary penetration rate at a given rotary speed, and bit life. Standard rock properties had not yet been reliably related to drillability, therefore, the basic bit penetration mechanism was adapted to a test device.
A Field Method for Controlling Drillstring Torsional Vibrations
Authors: Sananikone Prasert , Kamoshima Osamu , White D. B. 
Published: December 2007

Abstract
Torsional vibrations are detrimental to the life of drillstring components (1,2,3,4). Although methods of controlling them have been proposed (1,3,4), their general dependence on strain gauges to measure drillstring torque make them unsuitable for the drilling environment. In this paper we describe a new, practical, system which does not use such a sensor, and present extensive field test results taken from a semisubmersible rig drilling in the North Sea. The system was shown to be very effective in suppressing torsional vibrations. It uses measurements of motor current, acceleration and a microprocessor to modulate the drive to the motor.
An analysis is given to show that not only does the system performs just as well as one using a strain gauges sensor, but it also performs better than a system which uses motor current only. Considerations for the system design are also discussed.
A significant reduction of drillstring torsional vibrations, DTV's, will reduce the cost of drilling wells by reducing damage to drillstring components and lost rig time. Drilling efficiency is enhanced through the suppression of "stick-slip" motion at the bit.
Field Trials of the First RA-D (Rig Automation—Drilling) Automated Drilling Rig
Authors: Simpson B. K. 
Published: December 2007

Abstract
The only fully convincing way to overcome doubts and concerns over a new technology is to build a first-off and demonstrate the functional and performance capabilities to those who have the need and the authority to introduce new and operationally safe equipment.
Strachan & Henshaw have designed, built and works tested a full scale "Proof-of-Concept" RA-D rig and are now carrying out field trails by performing drilling operations. The drilling industry has been awaiting early release of these results.
The 454 tonne (1,000,0001bs) hook load, modular singles rig using hydraulic power and programmable logic control, has been constructed as a response to a call from the industry for improved safety, low manning, minimum weight, consistent performance and reliability.
RA-D is the result of technology transfer from several industries and represents a significant change in the way drilling facilities and operations can be planned, and managed in the future.
The project is producing results that confirm the concept and the paper discusses these in detail.
It will be seen that the project has crossed boundaries and overcome technical difficulties to produce marketable technology.
The paper also shows how this RA-D technology can be applied to a variety of applications and give short and long term cost benefits.
This first-build programme demonstrates co-operation between Operators, Drilling Contractors, Equipment Suppliers and Government agencies. Each regard the result as a major contribution to the developing technology of drilling from platforms, jack-ups, semi's and on land.
Innovative Steerable Underreaming BHA Design Overcome BOP Restrictions
Authors: Raitt Ferrier W. S. , Boyle John 
Published: December 2007

ABSTRACT
As the number of slots on multi-well templates increase and extended reach wells become commonplace, there is an increased need for directionally controlled surface hole.
When implementing the above, BOP restrictions such as riser ID have necessitated drilling of a pilot hole which is subsequently underreamed to the required hole diameter for surface casing.
This paper describes the design/operation, performance and potential applications/limitations of a proprietary steerable system comprising a bit and underreamer below a downhole mud motor. This system provides directional control while drilling and hole opening simultaneously in a top hole section.
Field experience results from the British and Dutch sectors of the North Sea are discussed.
Efficiency Drilling Techniques for Increased Penetration Rates in the Gulf of Mexico
Authors: Weakley R. R. 
Published: December 2007

ABSTRACT
Numerous techniques have been applied over the years in an effort to increase the drilling efficiency of Gulf Coast wells. While there are many innovative approaches to nippling up BOP's, wellhead configurations, bottom hole assemblies, etc., this paper focuses on those applied to the drilling fluids which significantly impacted increased penetration rates.
Many sophisticated mud systems and drilling practices have been developed over the years in response to borehole conditions and in many instances have resulted in a more complex, less efficient and less cost effective solution.
Through utilization of techniques herein described, penetration rates have generally at least doubled and in some instances a four and five fold increase in penetration rate has been realized without sacrificing borehole conditions.
This paper will describe the techniques for increased penetration rates in detail. Illustrations will include pit arrangement, hydraulics information, mud properties and flowline properties. Also, some case histories of wells will be discussed and some depth vs. hours curves will be illustrated.
These techniques have been utilized on both straight holes and directional wells in the Gulf of Mexico with great success. In all instances significant reductions in the cost per foot and days to drill have been realized.
An Advanced System for the Early Detection of Sticking Pipe
Authors: Jardine S. I. , McCann D. P. , Barber S. S. 
Published: December 2007

ABSTRACT
Today when drill pipe, drill collars and MWD units become stuck in the hole it can result in significant loss of time and money. To reduce stuck pipe requires early indication of the problem and the relevant information to be made available to the drilling team. Sticking events may be the result of several contributory factors which can produce symptoms detectable before the event. This paper describes a system for realtime monitoring of wellbore friction using surface measurements logged by a computer system in order to give advanced warning of changing borehole conditions before they result in stuck pipe.
The basis of the friction monitoring system is a method of recording representative values of hookload and torque to produce depth indexed "profiles" of expected values for a particular well. The profiles form a template which serves to indicate when measurements exceed expected values and conditions are worsening. A "Smart Alarm" has been developed to detect these differences and to trigger a warning directly to the driller. Automatic processing of hookload and torque measurements while drilling identifies anomalies which may be indicative of sticking problems. The system provides realtime displays to all key rig personnel and an offline workstation which can be used to investigate the problem in detail.
Why Compressive Loads on Drill Bits Produce Tensile Splitting in Rock
Authors: Paul B. , Gangal M.D. 
Published: December 2007

Abstract
Conventional methods of drilling with rotary and percussive bits utilize a wedge-shaped tooth form which places a compressive line load on the rock. According to the classical theory of elasticity, the stresses caused by a compressive line loading at the surface are everywhere compressive within the interior of the rock. Paradoxically, it has been observed in the laboratory that the rock directly under the point of the bit undergoes a splitting type of failure which strongly suggests the presence of reasonably large tension stress in the rock, notwithstanding the prediction of the classical theory.
It is shown that the classical solution, for stresses under a line load does not reproduce the true condition underneath a rock bit, and a more realistic boundary condition is proposed. Having formulated a more realistic boundary condition one is still faced with the very difficult mathematical problem of solving the field equations of problem of solving the field equations of the theory of elasticity to find the state of stress in the rock. In this paper, we apply a recently developed paper, we apply a recently developed digital computer program which clearly shows the presence of tensile stresses, directly under the bit, which are of such a nature and such a magnitude as to explain the "splitting action" observed in practice.
Introduction
Rock drill bits are essentially wedges, or indentors of various shapes, which load the rock over a small surface area in order to produce high contact stresses. It is therefore perhaps natural to analyze the situation by treating the applied load as a line loading (for a wedge bit) or concentrated load (e.g. for a button-bit) in an effort to estimate the stress field in the rock. This approach is all the more attractive because the stress and strain fields in a semi-infinite elastic body, subjected to a line load, as shown in Fig. 1-a, have been found by Flamant to be given by the simple expressions:
..............(1)