bluuebunny/crossref_metadata_2025_split huggingface dataset:
Understanding Torque: The Key to Slide-Drilling Directional Wells
Authors: Maidla Eric , Haci Marc 
Published: December 2007

Abstract
An in-depth study of surface torque and its effect on drillstring and bit movement has led to the development of automated technology for optimizing directional drilling with a downhole motor/measurement while drilling (MWD) system. By assimilating surface torque with downhole bit and drillpipe behavior, the technology allows drillers to maximize drilling efficiency and improve wellbore quality (due to less trajectory tortuosity) during the sliding part of the drilling process. This paper describes this proprietary1,2,3 surface system and how developers used torque control to optimize slide drilling without introducing new equipment downhole.
The new technology integrates surface and MWD data to provide the following benefits in the sliding mode:
Improved ROP and horizontal reach capability Improved tool-face correction while drilling Improved well trajectory Improved motor life (less stalling) Quick and accurate tool-face orientation No lost-in-hole exposure Time savings from switching from rotating to sliding without coming off bottom; faster tool-face orientation; overall performance optimization (as listed above)
Drilling Fluid Affects MWD Magnetic Azimuth and Wellbore Position
Authors: Torkildsen Torgeir , Edvardsen Inge , Fjogstad Arild , Saasen Arild , Amundsen Per A. , Omland Tor H. 
Published: December 2007

Abstract
The drilling fluid may degrade the accuracy of magnetic azimuth and borehole position significantly so that it complicates the drilling operation and reduces the possibility to hit the planned targets. As an example: Azimuth is distorted up to 5° because of the magnetic properties (susceptibility) of the drilling fluid; and the wellbore is displaced 50 meter in one of the analyzed survey sections.
Survey data from 30 well sections in the North Sea and the Norwegian Ocean are analyzed in order to see whether the weight material in the drilling fluid may affect the magnetic characteristics for the drilling fluid. The cross-axial magnetic field intensity is attenuated more when applying ilmenite instead of barite as weight material. Another significant finding is that the attenuation is stronger in 12 ¼" sections than in 17 ½" and 8 ½" sections.
Laboratory experiments also indicate that drilling fluids with barite are less susceptible than those with ilmenite, and that fresh fluids are more favourable than used fluids. Attenuation factors for cross-axial magnetic components, which are derived from laboratory measurements and a simplified model of the downhole conditions, become much lower than those derived directly from the survey data. This contradiction is explained by some physical and operational conditions.
Guidelines have been established for how to control, reduce and eliminate the negative effect on the wellbore positions. The precautions and actions, which are presented, are dependent on the composition of the drilling fluid, the drilling operation, the wellbore directions, the magnetic interference sources, the accuracy of the geomagnetic reference field and the requirements for wellbore position accuracy and reliability.
The ultimate method for getting around this problem is to measure azimuth with a gyroscopic tool. However, multi-station analysis and corrections of magnetic survey data is also a satisfactory solution when certain operational and geometrical requirements are met.
A Step Change in Drilling Efficiency: Application of New Technology in the Alpine Development Field
Authors: Alvord Chip , Noel Brian , Johnson Vern , Handley Ron , Egedahl David , Cribbs Eric , Smith Lee 
Published: December 2007

Abstract
In the Alpine Development Field of western North Slope, Alaska, application of new technology throughout the continuous drilling of more than 70 horizontal wells has produced an impressive step change in drilling efficiency. This step change is demonstrated clearly by real time cost savings and a significant reduction in drilling times even as the wells have become more challenging both in length and complexity.
Analysis of the extensive Alpine Development Field database of over 1,000,000 feet of hole drilled to date reveals how introduction of new technology and optimized operating parameters in the past two years has increased drilling efficiency by 17%.
Noting economic and environmental issues driving the need for increased efficiencies, the paper addresses the factors that most directly contributed to achieving that goal. These include: comprehensive well planning; optimization of rig capabilities, mud program and operating parameters; and "point-the-bit" rotary steerable technology matched with advanced technology PDC bits.
Highlighted are specific performance achievements in the 8 ½" hole section, a key driver for increasing efficiencies. This interval, which can exceed 10,000 feet, is drilled using the rotary steerable system, allowing utilization of 4" drill-pipe in both 8 ½" and 6-1/8" hole sections for significant time savings through management of both ECDs and standpipe pressure.
Planning/performance of rotary steerable runs, record ROPs achieved, and new bit design technology are detailed, and application and limitations of the new technology are clearly defined through a description of "lessons learned" in achieving this step change in performance.
Finally, economic analysis shows the significant savings realized to date, and estimates savings over the course of the remaining 20 planned wells to exceed four million dollars.
The Effect of Hole Curvature on the Wellbore Pressure Loss Prediction for Highly Tortuous Ultradeep Wells
Authors: Samuel G. Robello 
Published: December 2007

Abstract
Drilling operations in deep and ultra-deep water are increasing around the world. The development of these substantial prospects is very challenging and requires the integration of knowledge with prudent designs at different stages of the well development. However, the cost premium imposed by deep and ultra deepwater wells are higher and many of the discoveries are marginal in terms of the commercial viability. With the increase of developing and operating costs, there is a growing need to reduce the cost of drilling and other allied operations. The hydraulic program for the deep wells constitutes a significant portion of the well planning. Challenges associated with extreme depth, pressures and temperatures translate to additional problems to the well design. As the wells are drilled deeper and deeper, accurate prediction of the wellbore pressures are increasingly important. Also, more wells are drilled in rotary steerable mode. Alternating between the sliding and rotary modes results in hole spiraling and wellbore oscillation becomes more pronounced due to frequent slide drilling. The estimation of pressures during drilling are indispensable for making appropriate well completion decisions. The prediction of wellbore pressures and downhole equivalent circulating density are of critical importance in wells where the pressure must be maintained within narrow limits of pore and fracture pressures.
This paper presents a study on how to adapt to the new wellbore hole spiraling effects encountered in ultra deep wells. This paper examines some of these effects, while asserting that it is necessary to integrate this new approach, so that more accurate solutions can be predicted as a result. This new hydraulic design encapsulating hole spiraling effects provides a simple, practical way to view the severity of the wellbore oscillation.
A Novel Approach to Liner Floatation Extends the Standard Well Reach in a North Sea Field Development
Authors: Wang Zhihua , Musaeus Nils N. , Frøland Stig 
Published: December 2007

Abstract
This paper presents a case study for floating a 9-5/8" liner using a novel approach and its implication to the on-going Ringhorne platform development program. The paper describes the planning, testing and execution of the liner floatation job performed in a record-setting Ringhorne well. A standard and field proven 9-5/8" liner hanger system was modified, tested, and used as the mud-over-air isolation device. This system was used to run a 4560 m long 9-5/8" liner to a depth of 5961 m with 6-5/8" drill pipe as the landing string.
Evaluation of Cement Systems for Oil and Gas Well Zonal Isolation in a Full-Scale Annular Geometry
Authors: Boukhelifa L. , Moroni N. , James S. G. , Le Roy–Delage S. , Thiercelin M. J. , Lemaire G. 
Published: December 2007

Abstract
In a wellbore, loss of zonal isolation can be caused by the mechanical failure of the cement or by the generation of a microannulus. However, the behavior of the sealant is driven by the specific boundary conditions like the rock properties. Large-scale laboratory testing of the cement sheath in an annular geometry and in a confined situation was performed to simulate various well conditions and to evaluate the behavior of several sealants under simulated downhole stress conditions. The failure modes of the cement sheath were determined as a function of the cement mechanical properties, loading parameters, and boundary conditions. The results were used to validate an analytical model that predicts cement sheath failure.
Remediating Sustained Casing Pressure by Forming a Downhole Annular Seal with Low-Melt-Point Eutectic Metal
Authors: Carpenter Robert B. , Gonzalez Manuel E. , Granberry Verland , Becker Thomas E. 
Published: December 2007

Proposal
Described are proof-of-concept developments to form a seal for mitigating sustained casing pressure caused by annular pressure buildup. Annular pressure can result from numerous sources, including tubing leaks, loss of isolation potential within the cement column because of poor mud displacement, free water-induced channels, stress fractures, and failure of the cement to cover all potential sources of annular pressure. In most cases, annular pressure is not observed at the wellhead until the well is placed on production, making it difficult to identify, access, or remediate the pressure source. A new and novel approach to remediation has been tested in which a low-melt-point alloy metal is dropped down the backside of the casing where annular pressure has been observed. The metal is allowed to accumulate at the top of cement or other physical barrier, melted with an induction-heating tool, and allowed to cool and solidify. This process forms an annular seal to stop fluid communication between the formation and wellhead.
This method was demonstrated within a full-scale, simulated well section. An electromagnetic induction tool provided sufficient localized heating to completely melt solder-type alloy metal placed between concentric casings. Subsequent pressure-testing verified that a complete melt, sufficient to provide an effective seal against fluid pressure, was achieved in both water- and synthetic-based drilling fluids. Shear-bond test results of various alloys were equal or superior to cement, and the solid-liquid phase transitions (set points) occurred at precise temperature levels. All metals tested contained bismuth because of its unique characteristic of expanding upon solidification to provide enhanced pressure-containment performance. Full-scale testing was conducted using 17-ft long concentric annular models constructed of 8-in. and 5-in. diameter steel pipes. Subsequent field-testing is currently being planned.
World's First Completion Set Inside Expandable Screen
Authors: Gilmer Mike , Emerson Brent 
Published: December 2007

Abstract
This paper will discuss the utilization and flexibility of expandable screens in open hole environments. It will provide a case history of a significant "World's First" where a completion was set inside expandable screen. The completion provided a single selective well, where one could selectively produce different zones in the reservoir. Expandable packers provided isolation in the open hole, while a conventional completion packer provided isolation inside the expandable pipe.
Breakthroughs using Solid Expandable Tubulars to Construct Extended Reach Wells
Authors: Demong Karl , Rivenbark Mark , Mason David 
Published: December 2007

Abstract
Many modern well construction techniques have been developed with an eye toward drilling deeper, longer, and more cost effective Extended Reach Drilling (ERD) wells. One notable technology that has contributed to this effort is solid expandable tubulars. This technology was developed specifically to allow additional casing strings to be run to cover up problem zones and facilitate drilling the well to the ERD target. Solid expanable tubulars also help to reduce the overall resources required to construct the well. Projections show that using them would significantly reduce the size or volume, as well as the cost of the rig, the drill string, the bits, the cement, and, of course, the casing, resulting in lower overall costs. This result has been born out in practice and will culminate in the single-diameter well described elsewhere.1
The effects on ERD wells will be substantial, but there are important ‘side effects’ that can have a profound cumulative effect. The torque and drag on an ERD well is usually the limiting factor in the actual reach possible. These limits are mitigated by drilling fluid properties and the use of rotary steerable drilling tools among other technologies. Torque and drag are primarily influenced by geometric conditions like dogleg severity (DLS) and casing open hole size vs. drill string size, surface effects (commonly grouped together and named the friction factor), and drill string dynamic conditions (such as axial and rotary motion that overcomes the friction). The use of solid expandables has two distinct effects that can be favorable for the drilling of ERD wells. An important effect is that more favorable drill string casing geometry is possible and can reduce the tendency for helical buckling or drill string lockup. Another important impact is the ability to use larger drilling tubulars.
This paper will examine data supporting the positive effect of solid expandable tubulars on drill string torque and drag. Data modeled for an ERD well shows the theoretical drilling limit improvement from these effects in real example wells. Extended reach drilling limitations have been pushed out significantly in recent times. Advances in mud systems, geomechanics, and the advent of rotary steerable systems have significantly improved the ability to reach further to access hydrocarbons. However, limitations, though receding, still exist. To counter them, new approaches are being developed that attack in various ways the traditional boundaries of extended reach drilling applications.
Pore Pressure/Fracture Gradient Prediction Challenges: The Successful Design and Implementation of a Remote Exploratory Well Plan
Authors: Hradecky David C. , Postler Daniel P. 
Published: December 2007

Abstract
The recent successful drilling of Devon Energy Ghana's Tarpon 1-1X Miocene test well is evidence that the application of current 3-D seismic technology, accurate modeling, and the proper expertise, can lead to accurate pore pressures and fracture gradient predictions without direct offset well information.
The well was drilled in 6,330 ft of water, making it the deepest water depth oil and gas exploratory well drilled offshore Ghana. The nearest wells from which data could be obtained for analyzing the lithology and stratigraphy of the Tarpon 1-1X were shallow-water, shallow-depth wells that penetrated older Cretaceous formations not targeted by the Tarpon well. For this reason, the data were less than reliable for comparative purposes.
Instead, seismic interval velocities extracted from the 2-D and 3-D seismic surveys were used to predict pore pressures and fracture gradients.
The Use of Vertical Interference Testing to Improve Reservoir Characterization
Authors: Kuchuk Fikri J. , Halford Frank , Hafez Hafez , Zeybek Murat 
Published: December 2007

Abstract
Stratified or layered carbonate reservoirs are common in the UAE and throughout the Middle East. For field development and reservoir management it is important to describe the layering in terms of the vertical and horizontal layer permeabilities and the vertical communication between layers. Vertical communication between layers affects the overall development plan, the economics and management of enhanced recovery projects. The number and placement of both injector and producer wells will require an accurate description of the layering.
In this paper, we discuss the use Interval Pressure Transient Testing (IPTT), which is also commonly called Vertical Interference Testing, and Vertical Pressure Profiling in a major oil field in UAE. The objective was to characterize the vertical and horizontal layer permeabilities and vertical communication through the main producing reservoir section.
In a newly drilled and uncompleted well, eight IPTT tests were conducted with a Formation Tester Dual Straddle Packer and two Probe Modules. The vertical pressure profile along the wellbore was also obtained for information about the geology and flow units as well as depletion.
The interval pressure test at each location was interpreted using an appropriate geological model with the packer and probe pressure and flow rate measurements. The interpretation procedure consisted of identification of the different flow regimes followed by history (type curve) matching for the estimation of vertical and horizontal permeabilities for each layer. The interpretation of two of the interval pressure transient tests is presented.
Low Cost Well Intervention Using Wireline to Evaluate and Repair Tubing Leak
Authors: Burkhead David , Ahmad Mubashir , McCabe Marc , Willems Jan 
Published: December 2007

Abstract
Introduction
Well X-1 had developed significant communication between the 4 ½ inch tubing and production casing. This was confirmed by well head pressure measurements and diagnostic testing. Slick line testing with a "pony tail" confirmed the presence of a hole in the tubing at approximately 10,854ft. Consideration was given to set a straddle packer across the leaking tubing section, but that would only be effective if the overall state of the tubing was acceptable. If not, a work over rig would be required to pull and replace the completion.
The extent of corrosion in the tubing was evaluated using a Microvertilog (VRTM) tubing inspection tool (Figure 1). Unlike a multi-finger caliper, the VRTM evaluates the inside and the outside of the tubing for defects. If the evaluation of the VRTM data would show that the corroded sections were sufficiently localized, a straddle packer run on wireline could be used to repair the well.
Tool Theory
The Microvertilog service utilizes magnetic flux leakage measurements to determine the location, extent and severity of corrosion and other metal loss defects in the tubing. A permanent magnet produces high levels of magnetic flux within the tubing or casing wall. Defects in the tubing cause flux disturbances or "leakage", that are detected by a circumferential array of inductive coil (FL) sensors. The flux leakage measured by each sensor is recorded at surface (or in memory) and displayed as FL1, FL2.......FL8 (Figure 2). The tools also have a circumferential set of discriminator sensors (DIS1, DIS2....DIS8). These sensors are aligned with the FL sensors and respond only to flux anomalies on the inside wall of the tubing. By combining this FL and DIS data it is possible not only to determine location and severity of a defect, but also to differentiate whether the defect is internal (Figure 3) or external (Figure 4). It is also possible to distinguish between a metal gain (centralizers, down hole hardware -Figure 5) and a metal loss (corrosion, milling defects - Figure 6).
The Prediction of Cloud Point Temperature: In Pure Paraffin Deposition
Authors: Sadeghazad Ayoub , Sobhi G. Ali 
Published: December 2007

Abstract
The main object of this paper is to evaluate and discuss the cloud point temperature dependence on the solution nature in the crude oil. A correlation was also developed to predict the cloud point temperature in paraffin precipitation.
The cloud point temperature is an important parameter to see weather there will be paraffin precipitation or not. So, we interested on the parameters that affect the cloud point temperature of pure paraffinic hydrocarbons. Therefore, besides literature survey, some experiments on paraffin precipitation and deposition have been performed and evaluated. We mean heavy paraffinic hydrocarbon components by the pure paraffins.
Based on our experimental observations, the most important parameters that affect the hydrocarbon cloud point temperature are the apparent molecular weights of solution and solute, and solute weight fraction. These are the basic parameters of our developed correlation. In other words, the correlation is based on the intensive properties of the solution components such as their molecular weights and melting point temperatures, and the extensive properties such as weight fractions.
Through the regression process different equations have been used and a complex nonlinear polynomial equation was selected to obtain a correlation which predicts the cloud point temperature with less than 1.8-percent error. This modeled correlation is very simple to use and less time consuming with respect to the other models.
Unconventional approach to resolving primary and secondary porosity in Gulf carbonates from conventional logs and borehole images
Authors: Akbar Mahmoud , Chakravorty Sandeep , Russell S. Duffy , Al Deeb Maged A. , Efnik Mohamed R. Saleh , Thower Roxy , Karakhanian Hagop , Mohamed Sayed Salman , Bushara Mohamed N. 
Published: December 2007

Abstract
Traditionally, downhole porosity measurements are made through nuclear/acoustic logs (both wireline and logging-while-drilling) and cores. In homogeneous carbonates, log porosity is generally a good substitute for core data. However, in heterogeneous carbonates with complex pore systems resulting from leaching/dissolution, cementation, and dolomitization, discrepancies exist between log- and core-derived porosity. Moreover, thin-bedded layers of high and low porosity, which are found to have a pronounced effect on reservoir production, are routinely unidentifiable on conventional logs because of their limited vertical resolution capabilities (2-3 feet).
An innovative methodology has been developed to generate a porosity log with a minimum vertical resolution of 0.2 inch that also takes into account the azimuthal heterogeneities of the carbonate reservoir exposed in a wellbore. To achieve the high-resolution porosity log and entire porosity spectrum around the well, borehole images are used as external constraints after calibration with log porosity and resistivity. This methodology has significant applications in carbonate reservoir characterization. First, the identification of thin intervals of very high (related to high permeability) and low (dense, stylolitic) porosity is possible. Second, vuggy and moldic porosity can be quantified, and third, carbonate facies and reservoir rock types can be characterized. Several case studies from the U.Cretaceous / L. Cretaceous reservoirs and Upper Thamama Reservoirs highlight the effectiveness of the methodology to characterize porosity heterogeneity. Known porosity variations from core and mercury injection data confirm the heterogeneity demonstrated on the high-resolution porosity log. Since most carbonate reservoirs exhibit considerable porosity heterogeneity, this methodology has significant potential application to improve reservoir characterization in many areas.