fax 01-972-952-9435. AbstractIn recent years, drilling programs have become significantly more aggressive and challenging.Rotary shouldered connections (RSC) in extended reach and ultra-deep wells face unprecedented loads. Torque is one of the constraints imposed by modern drilling applications on standard RSC. In order to prevent uncontrolled downhole make-up in severe drilling environments, standard RSC are, in some cases, madeup above recommended torque values.This paper discusses the effect of increased make-up torque on the fatigue performance of RSC. It presents the results of full-scale fatigue testing on API NC connections and discusses the correlation with various analytical modeling methods currently in use to determine the suitability of increased make-up torque in specific drilling applications. Make-up torque values ranging from 30% to 90% of the connection torsional strength are compared to determine the full impact of make-up torque on fatigue life.The paper provides drilling engineers additional information to assess the potential risks associated with varying make-up torque in relation to drilling parameters.

This paper presents the results of a two-year comprehensive effort to design, test, and qualify third-generation rotary-shouldered connections (RSC) for 20,000 psi internal and 10,000 psi external pressure service. ISO13679 testing methodologies for casing and tubing were modified to evaluate the RSC pressure capability. Results from comprehensive finite element modeling and extensive laboratory testing designed to reproduce the harsh, aggressive loading modes and high pressures encountered in field use are presented. The result of this program is a RSC that incorporates a double-start thread form to reduce the number of revolutions to assemble the connection by 50 percent reducing trip time. The thread form also provides a unique dual-radius thread root that offers a step change improvement in fatigue resistance. A metal-to-metal seal provides pressure integrity. In addition to providing a 20,000 psi internal and 10,000 psi external pressure rating, the new connections provide increased mechanical and hydraulic performance compared to second generation high torque connections while also providing fatigue performance greater than standard API connections. Introduction New developments in drilling tubulars are rapidly evolving and represent enabling technologies for the industry's continued advancement of drilling deeper, further and more cost-effective wells. Much focus has been made toward the advancement of RSC technology to permit high torque drilling of extended reach, directional and horizontal wells. In response to this need, the development of third generation, ultra-high torque connections was recently announced providing reduced tripping times and the mechanical and hydraulic load requirements for drilling today's deepwater, extended reach and ultra-deep wells. The next step in the evolution of RSCs has now occurred with the development of a third-generation, gas-tight, pressure rated connection providing enabling technology for high-pressure completion and workover, drill-stem testing, UBD and intervention riser applications. Although drill pipe, drill pipe connections and drill stem materials represent mature technologies, innovations are being developed in these areas. This third generation gas-tight, double-shoulder connection presented here represents several advancements that address some of the challenges ahead. Double-Shoulder Connection Design Development First generation double-shoulder connections (1st Gen. DSC), see Figure 1, were introduced in the early 1980's.4 1st Gen. DSC's were basically API rotary-shoulder connections (primarily NC or FH) with a second torque shoulder added inside the box member at the pin nose interface.1,3 These 1st Gen. DSC's incorporated the same basic design features in terms of thread form, taper, lead, pitch diameters, etc. as the API connection on which they were based. These connections yielded a simple, straight forward solution that increased the connection torsional strength by approximately 40 percent over the corresponding API connection.

Shale drilling for both natural gas and hydrocarbon liquids has increased dramatically in North America over the last several years. Shale oil and gas deposits are known to exist all over the globe including Australia and the rest of the Asia Pacific. This paper discusses the requirements for drillpipe in shale drilling applications along with a review of some of the challenges and problems associated with the drillstring in these critical applications. Most wells are horizontal with long departures. Typical wells in the Bakken Shale are 17,000 ft MD, 11,000 ft TVD with a 6,000 ft horizontal reach. Drilling these wells puts huge demands on the drillpipe and rotary shoulder connections and pushes the drilling equipment and rig crews beyond the requirements of typical onshore well construction projects. Many, if not most, of the shale wells require advanced design, double shoulder connections (DSC) on the drillstring to provide the enhanced torsional strength and streamlined connection dimensions required to effectively drill these prospects. The paper presents connection design solutions along with considerations for safe and efficient running procedures. Although, the advanced DSCs are designed to be transparent to normal drilling operations, compared to standard API connections, some problems have been encountered. The paper addresses these running and handling issues and provides guidelines to mitigate these problems. Excessive tool joint and drillpipe body wear have also been encountered in several shale plays. This is discussed, along with recommendations to limit wear. Stick-slip has created drillstring problems on several wells. Stick-slip can cause damage to the drillpipe and, in the extreme, downhole connection back-offs have occurred. The paper looks at aspects of case histories to illustrate these issues and provides lessons learned to improve shale drilling operations in North America, the Asia Pacific and other regions of the world.

New developments in drilling tubulars are rapidly evolving and represent enabling technologies for the industry's continued advancement of drilling deeper, further and more cost-effective wells. Much focus has been made toward the advancement of drill pipe connection technology to permit high torque drilling of extended reach, directional and horizontal wells. First and second generation high torque connections have been available to the industry for several years. In today's rig market; deepwater, extended reach and ultradeep wells dictate large spread rates that can benefit significantly from reduced tripping times. These same wells often have mechanical and hydraulic load requirements for which today's high torque connections may not be specifically optimized. In response to this need, the development of third generation, ultra-high torque connections is now complete. This paper will present the results of a 2–1/2 year comprehensive effort to design, test, manufacture and field trial a family of connections that were engineered to meet the specific needs of each drill pipe size. Results from extensive laboratory tests and two field trial programs designed to produce harsh, aggressive dynamic loads to the connections are presented. The thread form is a double-start thread that reduces the number of revolutions to assemble the connection by 50%. The thread form also provides a unique dual-radius thread root that offers a step change improvement in fatigue resistance. Conservative estimates suggest that the new connections will save approximately 7–1/2 hours in planned trip time per 20,000 ft well. The new connections provide increased mechanical and hydraulic performance compared to second generation high torque connections while also providing fatigue performance greater than standard API connections. These connections can facilitate more challenging wells, provide increased cost savings and reduce risk during the well construction process. Introduction The current trend to drill offshore in deeper waters, longer extended reach wells and record setting ultra-deep wells is destined to continue. Many rig contractors are presently upgrading or building new jack-up, semi-submersible and dynamically positioned drill ship rigs capable of drilling to 35,000+ ft total depth (TD). One rig contractor, in particular, recently contracted the manufacture of three $650 million USD dynamically positioned drill ships capable of drilling in 12,000 ft of water to well depths of 40,000 ft.(1) Wells that are in the planning stages today demand drill string technology with capabilities that exceed current connection designs and material performance properties. As mentioned above, rig rates have risen dramatically, as have the costs for virtually all services, equipment, tools and materials used by the energy drilling industry. At the same time, existing wells and reservoirs are experiencing accelerated decline rates. Our industry must respond to these realities with advanced technologies that improve efficiency, enabling wells to be drilled more effectively and at acceptable costs. Drill pipe and drill stem materials and connections represent mature technologies. Nevertheless, innovations can and are being developed in this important area critical in the quest to exploit more remote hydrocarbon target zones. The third generation double-shoulder connection presented in this paper represents one advancement that addresses some of the drilling challenges ahead.

The Pattani gas field in the Gulf of Thailand is known for having marginally economic reservoirs and so the operating company, Chevron Thailand Exploration and Production LTD (CTEP formerly known as Unocal Thailand LTD), has always needed to drill wells as fast as possible and at the lowest economic cost. This quest for efficiency led to selecting a slim hole drilling program that is completed within days, and as such, puts a lot of stress on the drilling equipment and in particular the small size drill string. Over the years, the size of the drill pipe used to drill the production interval has evolved from 3½ to 4 in. with the use of a streamlined second-generation double-shouldered connection. Selecting a drill pipe configuration with higher torsional strength, improved hydraulics and buckling resistance contributed to improved performance and drillers delivering wells faster. The move to a 4 in. drill pipe body increased the stiffness and fatigue resistance compared to the 3–1/2 in. pipe. As a result, the fatigue resistance of the premium drill pipe connection was considered to be an area of improvement for the special fast drilling operation. This paper will present the various options considered to enhance the connection fatigue resistance, the results obtained in simulation, laboratory testing and ultimately in operation. This last section includes information on the inspection reject rates and impact on the frequency of inspection that directly relates to the level of confidence one has in the equipment. Need for fast drilling in the gulf of Thailand The well design currently drilled in the CTEP operated Pattani gas field has evolved over the past 40 years to one that can now be regularly drilled and completed in less than 4.5 days. These wells are a three string, slimhole, well that is completed as a monobore. The reserves per well are marginal and are further complicated by a steep production decline so, CTEP has to drill hundreds of new wells each year to maintain production output. This requirement to drill and complete hundreds of additional wells means that the well design must be executed in the shortest time and at the cheapest cost so as to maintain the viability of the field. With a now well refined well design and drilling program, the rate of penetration (ROP) and subsequent drilling time are the main variable that influence the overall days per well. For this reason the emphasis by the CTEP drilling department has always been on improving ROP through innovation of drill bit design, bottom hole assembly tools and design and drill pipe design and specifications. A typical well profile drilled in the CTEP operated Pattani field is shown in Figure 1 of the Appendices. Build rates in the shallow section of the well are typically 8 degrees per 100 ft so as to maintain the 8½ in. tangent inclination below a nominal 60 degrees; this to ensure firstly that open hole logs can be run in the slimhole section and also that the well can be perforated on electric line. The high doglegs in the shallow section of the well greatly contribute to the stress placed on the drill string and factor in the fatigue life of the drill pipe. The extreme nature of this fast drilling environment sees the drill pipe constantly rotated at between 180 to 250 revolutions per minute during the drilling of the entire slimhole section. It is common for the on bottom rate of penetration in the production hole section to exceed 500 ft/hr and overall section ROP including the time it takes for making connections can reach 300 ft/hr. In one year a string of slimhole drill pipe can drill as much as 300,000 ft of open hole formation. Drill string selection and improvement Several drill strings are used for drilling the various sections of these wells. Top hole and intermediate hole sections. The first two intervals, the 12 ¼ and 8 ½ in. hole respectively, are drilled with a string of 5 in. API drill pipe. The total on bottom drilling time for these two sections is typically less than 8 hrs. Drilling performance in this part of the well program is driven predominantly by bit selection and directional tool performance and thus can be drilled efficiently using standard drill pipe with conventional API rotary-shouldered connections. This paper does not cover these hole sections and will only focus on the slim hole section that enters the pay interval.