bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Evolution of Rotary Steerable Practices to Drill Faster, Safer and Cheaper Deepwater Salt Sections in the Gulf of Mexico
Authors: Aburto Marco , Clyde Robert 
Published: March 2009

Abstract
The North American Gulf Coast offshore continental basin was formed following the breakup of the super continent Pangaea at the end of the Permian period and contains one of the largest known deposits of salt in the world. The salt encountered in this region is relatively soft, with negligible porosity, and may deform under temperature and pressure. Drilling salt in different regions requires different drilling practices and challenges. Because of the variable range of salt properties and because of salt's effect on nonproductive time, to date there has been no substitute for experience for successful salt drilling.
The petroleum industry is continually pushing to drill longer, faster, and safer sections; salt drilling is no exception to this philosophy. The dramatic advancements in salt drilling performance over the last decade—from the use of traditional drilling practices with rotary systems, mud motors, and possibly turbines—have been used to slightly improve penetration rates. The first Schlumberger push-the-bit rotary steerable salt drilling run in the USA Gulf of Mexico was executed in 2000. Since then more than 150 runs and almost half a million feet have been drilled in salt with this type of rotary steerable system.
This paper summarizes the analysis of the Schlumberger push-the-bit rotary steerable runs in the North American Gulf of Mexico. The analysis confirms the successful drilling assembly design and drilling techniques to yield optimum salt drilling performance toward a benchmark for today's salt drilling environment.
Signal Attenuation for Electromagnetic Telemetry Systems
Authors: Schnitger Jochen , Macpherson John 
Published: March 2009

AbstractElectromagnetic (EM) systems are used for MWD telemetry during drilling. The deployment of EM telemetry systems is only successful when the signal does not vanish in noise. Knowing the attenuation profile with depth of an EM signal is a helpful guide for predicting successful deployment. This paper details several case studies on the different attenuation profiles in North America.In the case studies the actual signal strength was measured by an EM surface system at the wellsite, with a field operator logging the measurement against depth. EM signal amplitude generally attenuates exponentially against depth, although this is highly dependent on mud and formation resistivities. While modeling provides information about the expected signal tendencies (for example, the effect of casing on signal amplitudes), EM transmission is heavily influenced by many factors, among them the presence of extremely resistive thin beds in the formation and the distribution of surface resistivity. These factors are hard to include in the simulations. The case studies included here illustrate the different relationships between actual measurements and depth.By understanding the EM signal attenuation within a region it is possible to validate and calibrate EM transmission models, so that the successful deployment of EM telemetry systems can be predicted.
Implementation of Novel Tar Casing Drilling Tool in Deepwater Gulf of Mexico
Authors: Connor John , Djamil Arifun , Lambert Kevin , Graham Tom 
Published: March 2009

Abstract
In late 2007, while drilling Chevron's Big Foot #3 Appraisal well in the deepwater Gulf of Mexico, an extremely mobile tar zone was encountered subsalt at ~20,800 ft. Numerous unsuccessful attempts were made to conventionally drill thru the tar to deepen the well. The tar would have to be cased off in order to continue drilling.
Conventional casing methods were considered and it was determined that - due to the extreme tar mobility - the liner would have to be drilled thru the tar. Since extreme torque was encountered while drilling with a conventional drilling BHA, a novel approach to liner drilling was pursued.
A Service Provider had recently developed a tar liner drilling tool for another Operator which allowed the concurrent running of a 11-7/8" liner while drilling oversized hole below the liner shoe utilizing a bit, motor and concentric reamer with returns taken up the inside of the casing. This tar casing drilling tool had never previously been utilized in a wellbore.
This paper will present how Chevron worked in conjunction with the other Operator, and the Service Provider, to implement the tool on three successive attempts before finally successfully casing off the tar zone 55 days after first encountering it. Details of the application of the tool, lessons learned and future tar casing drilling tool enhancements will also be presented in the paper.
Improve Drilling Performance by Controlling Risk and Reducing Non-Productive Time in a Challenging High-Temperature, High-Pressure Well
Authors: Prebensen Ole Iacob , Vidvei Svennung , Nesheim Gunvald , James Reagan , Anda Trygve 
Published: March 2009

Abstract
To complete a very challenging high-temperature, high-pressure (HTHP) well in the North Sea, several engineering issues needed to be resolved before commencing drilling. One of the requirements of the well was to drill without replacing the existing drill pipe on location. Changing the drillpipe specification would result in extra tripping time and a high increase in cost. As the hydraulic window was narrow, maintaining the configuration of the drill pipe limited the equivalent circulating density (ECD). At the same time, the temperature regime was high; a specific oil-based drilling fluid (OBM) with treated micronized barite (TMB) was chosen as the only solution to resolve these challenges. In combination with this specific drilling fluid, the operator decided to utilize simulation software that enabled real-time hydraulic values to be displayed during the entire HTHP operation.
The drilling fluid with micronized barite provided several benefits compared to conventional OBMs. A more conventional drilling fluid meant a significantly higher viscosity to maintain the weight material in suspension, thereby increasing the circulating pressures and ECD. As the micronized barite viscosity profile is low, even at high densities, tripping speeds were dramatically increased as compared to offset wells. This includes tripping in and out with drilling assembly and during running of casing. Furthermore, the viscosity of such a fluid enables any flow checks to be completed much faster, thereby reducing time spent. Additional benefits such as zero barite sag, low maintenance of the system and the elimination of expected circulating time to condition the fluid after a 10-day long static period were all part of this successful well completion.
Drilling Fluid Design Prevents Lost Returns by Building Integrity Continuously While Drilling in East Texas
Authors: Vaczi Kenneth B. , Estes Brent L. , Ryan James T. , Linehan Shawna M. , Mota Miguel O. 
Published: March 2009

Abstract
The paper describes the application of a high solids, high filtration fluid with engineered particle sizes to prevent lost returns in the operator's Trawick field. The system (referred to here as a drill-and-stress fluid (DSF)) functions by immediately arresting the growth of lost returns fractures at the bit and building the fracture closure stress (FCS) to exceed the borehole pressure. This approach is allowing an 800-ft depleted zone with a history of severe losses to be drilled without resorting to multiple discrete lost returns treatments. Protective casing has also been eliminated.
As producing fields mature, depleted intervals are drilled to access remaining reserves. This increases well complexity and cost, and the impact on economics may limit ultimate recovery, particularly in fields with high stimulation costs or low production rates. The operator faces these challenges in its Trawick drilling operations in East Texas where destabilization of shallow, weak shale following losses, and repeated treatments in the pay zone have led to stuck pipe, significantly increasing well costs as the field has matured.
In recent years, a variety of particulate treatment systems have been developed to build stress continuously. DSF differs from some systems in that it arrests fracture growth though the development of an immobile mass within the fracture rather than through the formation of a blockage at the fracture aperture. It is also relatively inexpensive. This case history is also significant because the fluid worked successfully in long intervals of very low permeability (0.1 md), which has historically been challenging for a continuous stress-building fluid.
The paper will discuss the development of the technology to allow successful application of DSF, the pilot program that validated the observed increases in integrity, and the operational learnings that were developed during the pilot program.
Well Design for Environmentally Friendly Drilling Systems: Using a Graduate Student Drilling Class Team Challenge to Identify Options for Reducing Impacts
Authors: Burnett David B. , Yu OK-Youn , Schubert Jerome Jacob 
Published: March 2009

Abstract
The Oil and Gas industry is becoming more adept in reducing its impact on the environment and in showing optimal use of resources. This approach to environmentally friendly drilling offers the two-fold advantage of the reduction of the footprint of drilling operations while realizing savings by reducing waste treatment, hauling and remediation costs.
The Harold Vance Department of Petroleum Engineering at Texas A&M University has incorporated an Environmentally Friendly Drilling System (EFD) design into its PE 661 graduate drilling class. The "661 Team Challenge" semester project was assigned to the students to "design a well on paper" using low impact drilling technology. A systems engineering optimization protocol approach was utilized to incorporate a number of current and emerging EFD technologies into a single clean drilling system with no or very limited environmental impact. A web-based decision optimization tool was developed to follow the systems approach technology evaluation procedure and select an optimal system. The resulting well designs were judged as to their suitability for implementation in a protected wetland on the Texas Gulf Coast.

Introduction
The Harold Vance Department of Petroleum Engineering at Texas A&M University offers a series of five graduate courses designed to introduce Petroleum Engineering to new graduate students with a limited Petroleum Engineering Background. One of these courses is PETE 661 Drilling Engineering where we teach "drilling for non-drillers". Although this course is designed for non-drillers, there are a number of students with considerable experience in drilling who take the course as a refresher or for exposure to an alternate view of Drilling Engineering.
Water Based Fluid Designed for Depleted Tight Gas Sands Eliminates NPT
Authors: Hoover Erik , Trenery John , Mullen Greg , Richards Lawrence 
Published: March 2009

Abstract
Unconventional gas resources offer the only significant gas production growth potential in the coming years, currently accounting for 43% of the US gas production. Tight gas represents approximately 70% of the unconventional production and significant reserves are yet to be developed. In the United States, Utah, Colorado and Texas host the vast majority of those resources. Other major potential fields are located in China, Algeria, Argentina, Indonesia and the Middle East.
Drilling in mature depleted fields can be costly in non-productive time (NPT) associated with stuck pipe, whole mud losses and side tracks. A new water-based mud system addressing depleted tight gas reservoirs has been successfully introduced to provide increased drilling performance as compared to conventional water-based mud systems. The new High Performance Water Based Mud (HPWBM) is a viable solution for onshore drilling in mature, depleted tight gas sands. This technology is applicable to any tight depleted gas reservoir where losses or stuck pipe occur.
This paper provides a technical overview of the new HPWBM performance in a technically challenging field where massive losses, stuck pipe, twist-offs and other fluid associated NPT are common. The case histories presented are from an independent operator drilling in South Texas and highlight the successes and optimized learning curve of the system as compared to offsets drilled with conventional water-based mud (WBM) and oil-based mud (OBM) systems by the operator.
Rotating Magnetic Ranging Service and Single Wire Guidance Tool Facilitates in Efficient Downhole Well Connections
Authors: Oskarsen Ray T. , Wright John W. , Fitterer Donal , Winter Dave , Nekut Anthony , Sheckler Jed 
Published: March 2009

Abstract
Downhole connections between multiple wellbores have applications in many operations such as extended-reach drilling, multilateral completions, subsurface pipelines, and downhole fluid separation.
An R&D project was undertaken to develop and validate an electromagnetic ranging concept for enabling cost-efficient downhole connections—namely, Rotating Magnetic Ranging Services and Single Wire Guidance. After extensive testing that found the ranging technology suitable, an existing offshore well jacket located in Southeast Asia, in 5.1 m of water and 1.3 km from shore, was identified as a good candidate for field validation of the concept. The electromagnetic-ranging technology facilitated the successful intersection of the target well according to plan, including by-pass within specified proximity (&lt; 40 cm) and in the correct sand (+−1.5 m TVD window).
This paper discusses some of the many applications of downhole well connections. Furthermore, it explains the Rotating Magnetic Ranging Service and Single Wire Guidance ranging concept, which enables efficient downhole well connections.
Tracking Drilling Efficiency Using Hydro-Mechanical Specific Energy
Authors: Mohan Kshitij , Adil Faraaz , Samuel Robello 
Published: March 2009

Abstract
Over the last few years, different types of bits have been introduced to meet the challenges of steerable as well as rotary steerable systems; and it is imperative that bits be utilized optimally in these systems. As challenges increase with increasing depths, it becomes even more important for one to efficiently utilize the available energy. A new correlation identifying inefficient drilling conditions is presented in this paper. Mechanical Specific Energy (MSE) has been used to improve drilling rates, with mixed results. Hydro Mechanical Drilling Specific Energy (HMSE), which is introduced here, encompasses hydraulic as well as mechanical energy. HMSE quantifies the amount of energy required to drill a unit volume of rock and remove it from underneath the bit. HMSE includes axial, torsional, and hydraulic energy and is different from MSE because it includes a hydraulic term. The initial MSE correlation (Teale, 1964) was modified to accommodate the new hydraulic term. This paper attempts to better model downhole drilling by introducing the hydraulic energy term in the MSE correlation by defining it as hydro mechanical specific energy. While the majority of the drilling occurs because of the bit, it is a well known fact that some drilling occurs due to the "jet impact impingement" caused by the drilling fluid as well.
A comprehensive set of equations have also been developed and introduced here for hole opening scenarios.
Experimental and field data presented in this paper show that HMSE can identify inefficient drilling conditions. The new hydraulic term included in the specific energy correlation is the key to correctly match the amount of energy required to drill and overcome the strength and stresses of formation being drilled. Also, this new term illustrates how much hydraulic energy is needed to drill faster when the mechanical energy (axial and torsional) is increased. The results also show the importance of including the bit hydraulic energy term into any specific energy analysis for drilling optimization. The pump-off force for weight on the bit due to the fluid force is also included in the calculation. Field results reveal specific patterns for inefficient drilling conditions and also reveal a good correlation between calculated HMSE and the expected requirements for rock removal under existent conditions of stress at the bit face.
Development of the 18-3/4" – 20,000 psi Subsea Wellhead System for High Pressure and High Temperature Applications
Authors: McCoy Bernard , Singeetham Shiva 
Published: March 2009

Abstract
There is an increasing need for higher pressure and higher temperature rated equipment as wells are being drilled in such reservoirs in deep water subsea fields. This paper presents the development of the first 18-3/4" – 20,000 psi subsea wellhead system rated for 0°F to 350°F temperature applications utilizing high capacity running and specialty running tools. Included are details of the three year development project including component design, reliability analysis, and prototype testing of the equipment in the laboratory with simulated field conditions. With this technology, operators can explore fields while further completion technology is developed. This 20ksi subsea wellhead technology will enable operators to drill wells using 15ksi BOP stacks while the 20ksi BOP stack is under development. The wellhead system includes special provisions to enable annulus seal assemblies to be tested to 20ksi while isolating the BOP stack. Drilling into high pressure zones for logging or testing can be performed through a 13-5/8"-20ksi BOP stack which latches directly to the subsea wellhead. In synopsis, this paper highlights the wellhead system details utilized for extreme environments up to 350°F and up to 20,000psi working pressure. The goal of this paper is to open the industry's horizons to production fields and reservoirs that operators previously could not develop due to technological constraints such as the higher bottom hole pressures or greater well temperatures with existing subsea mudline wellhead equipment.
A Fit for Purpose Combination of Positive Displacement Motor and Rotary Steerable Systems Delivers a Step Change in Drilling Optimization in Tomoporo Field: A West Venezuela Case Study
Authors: Ochoa Danny , Palacio Julio , Akinniranye Goke , Chirinos Edween 
Published: March 2009

Abstract
Drilling directional wells in the Tomoporo field in western Venezuela is a challenging and risky operation. Wellbore instability, differential sticking and weak sand zones are common problems in the area. Considerable Non-Productive Time (NPT) is the result of difficult trips, poor hole quality, circulation losses and stuck pipe incidents. Under these conditions, the use of conventional positive displacement motors (PDM) escalates the risk of stuck pipe when difficult sliding and low rates of penetration increase the exposure to open hole conditions. The use of rotary steerable systems (RSS) allowed mitigating some of the hazards, but high shocks and vibrations (S&V) in laminated formations added to the harsh drilling conditions raised the number of unplanned bit trips and downhole tools damage.
A drilling assembly containing a rotary steerable tool below a specially designed, high-torque PDM provided the benefits of both conventional and RSS drilling by delivering faster rotation per minute (RPM) at the bit. The increase in RPM reduced vibration perpetuation and transmission in the rest of the drill string. The PDM dampened S&V, mitigated the effects of stick/slip and helped prevent damage to the RSS tools. The combination of PDM and RSS had a positive impact on the life of the bit and downhole tools, and resulted in an increase in both on-bottom and average rate of penetration. This approach marks a step change in performance, achieving a reduction in drilling time of approximately 50% compared to the average established for the area over the previous 5 years.
This paper will present a detailed study of this fit for purpose solution to increase footage per day mitigating shocks and vibrations and its success in dramatically reducing risk in directionally drilled wells.
Significant Step Taken to Eliminate Sustained ‘B’ Annulus Pressure in Major North Sea HPHT Development
Authors: Hunter Liz , Kinnaird Bill , Grégoire Michel 
Published: March 2009

Abstract
Detailed engineering analysis and good placement practices have been key in the prevention of chronic ‘B’ annulus pressure in the Central Graben HPHT area. A solution was developed based on independent life-of-well studies conducted in tandem by the cementing and oil companies which predicted the risk of sheath failure and subsequent gas migration.
Long-term isolation of the gas-bearing Hod formation has been an issue in Central Graben HPHT since earliest development, leading to costly management and maintenance of sustained ‘B’ annuli pressure. Elimination of the problem is a major challenge highlighted by plans for future sub-sea completions.
The Elgin-Franklin field is the world's largest HPHT development, so effective well design is crucial. Five clear steps were taken to achieve life-of-well isolation.
Analysis to predict failure mechanisms across all well-events were carried out with engineering programs from both the oil and cementing companies. Results were similar, identifying risk areas, the main being cement-formation debonding at the change to lightweight completion fluid. Effects on risks were investigated by altering well parameters, such as fluid weights and pressures. Most effective reductions were made by altering mechanical properties of the cement such as Young's modulus, Poisson's ratio and tensile strength. Extensive lab analysis was used to develop the best solution. A cement slurry was designed providing optimum mechanical properties. North Sea environmental restrictions were an important consideration. Triaxial measurements were made by both parties independently. A full-scale yard trial qualified the design for the field. Cement and other property enhancing additives were blended, transported and delivered to a cement unit where it was mixed on-the-fly. The large volume job was carried out with the rig cement unit, no special equipment was required. Good displacement practice meant adjustment of slurry rheologies to meet actual well conditions. The logistics of using a special blend were a consideration.
Since placement, the annulus pressure has been recorded. No abnormal pressure has occurred in 14 months since completion, during fluid change-out, or throughout high production output.