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Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume II - Drilling Engineering

Robert F. Mitchell, Editor

Chapter 13 - Emerging Drilling Technologies

By Roy C. Long, SPE, DOE/FE National Energy Technology Laboratory

Pgs. 571-588

ISBN 978-1-55563-114-7
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In a special report in the Oil and Gas Journal,[1] a representative of the Drilling Engineering Association ’ s (DEA) Advisory Board ( noted that "among the most important new technologies for the drilling industry are expandable tubulars, more cost-effective rotary steerable systems, and intelligent drillpipe for high-rate bottomhole data telemetry." The following discussion of emerging drilling technologies will be limited to those technologies now coming into the market, not those, such as rotary steerable and multilateral technologies, that have ready reference on service company Internet websites. Hence, this discussion is not comprehensive, but it is intended to include most of the high-impact technologies that are likely to be commercialized in the next 3 to 5 years with a brief look beyond.

The focus on drilling technology in the United States at the beginning of the 21st century is primarily in response to the fact that its remaining oil and gas resources exist in mature provinces of significantly depleted basins or in difficult drilling environments, such as the Arctic or the deepwater Gulf of Mexico (GOM). Because the United States has led the world in petroleum demand, the environment of depletion and push for further development of these mature basins will provide lessons and technology immediately applicable to the rest of the world as the world resource base continues to mature. All nations have a stake and will benefit from this development of the next redefinition of drilling state of the art.

The most basic requirement of drilling technology is that it provide safe, economic access to subsurface geologic formations to evaluate/optimize their production potential or to produce the resource existing there. The operative word is "economic." In high-cost environments, such as the deepwater offshore, technology is needed to maximize efficiency and to minimize time on location. With the advent of deepwater operations, concepts such as "parallel operations" and "flat time reduction" have become familiar technology focus areas ( In the onshore arena where reservoir potential is lower, the cost of accessing that potential also has to be reduced with such technologies as casing drilling. Also, with the advent of "unconventional resources" and fracture "sweet spots" as primary exploration targets, technology must provide a "smart drilling" capability to enhance finding these more difficult targets and to optimize access to the target in a manner that maximizes the production.

Advances in technology in the past decade are not all simply random evolutionary advances but represent a step change in drilling technology. They often represent a major change in drilling paradigms brought on by pressure to develop new resources in the face of existing domestic depletion and more challenging drilling environments.

Many of the technologies discussed in this chapter were presented in the keynote presentation at the DEA’

s Future of Well Construction workshop ( This chapter provides an overview that includes references for more detailed information. The previously referenced website for the DEA provides an excellent summary of current industry technology focus areas (see Project Summaries). Links to other websites providing information on other key drilling technologies can be found under Information Exchange.


Some of the most interesting near-term technologies (within 5 years of commercialization) are being developed to address the challenges of the deepwater GOM exploration. The deepwater GOM provides the high-cost environment (operating cost of U.S. $250,000/D or more) that encourages the risk-taking required to give new technologies the opportunity to demonstrate potential.

Dual Gradient Drilling Systems

Perhaps one of the most important ventures in the area of high-cost technologies for deepwater challenges is the development of dual gradient drilling systems (DGDSs). DGDS is often referred to as riserless drilling. It is generally accepted that DGDS is required in water depths of >

5,000 ft. There have been a number of unpublished examples, however, in which application of the technology was needed in water depths as shallow as 3,000 ft. The need for DGDS is relatively simple; it is caused by the reduced fracture gradient of formations below the mudline resulting from the reduced weight, or gradient (0.5 vs. 1.0 psi/ft), resulting from water above the mudline as viewed from a drillship operating at sea level. The various systems shown in Fig. 13.1, in one manner or another, isolate the borehole pressure gradient below the mudline from the drilling mud gradient above. In all but the Maurer Technology, Inc. DGDS, isolation is achieved mechanically by valves and pumping. The Maurer approach seeks to achieve the same benefit by pumping lightweight solid additives (LWSAs) from the drillship into the riser at mudline. This concept allows minimum equipment and intervention risk on the seafloor. The LWSAs investigated to date consist of hollow glass spheres and polymeric beads.

The advantage gained by these systems can be noted by comparing Figs. 13.2 and 13.3. For the conventional drilling case (Fig. 13.2), the gradient in the wellbore is relative to the drillship in all cases because the mud column is hydraulically continuous from the bottom of the hole up the riser to the drillship. This results in additional pressure being applied at the mudline (mud density minus seawater density times water depth times a units constant). The increased "backpressure" at the mudline has the effect of minimizing the drilling distance between casing points. The pressure at the bottom of the hole over a particular interval is usually referred to as equivalent circulating density. The equivalent circulating density from the mudline to total depth for conventional riser systems is always greater than for subsea systems in which the pressure (both circulating and static) required to get the mud from the mudline to the drillship is hydraulically isolated from the borehole or greatly reduced in density at the mudline.

Fig. 13.3 demonstrates that isolation of the pressure caused by the drilling mud above the mudline results in a borehole gradient that allows significantly longer openhole sections before reaching the depth at which casing must be set to avoid exceeding the fracture pressure.

Types of DGDS. Fig. 13.1 is an attempt to show some of the DGDS concepts being considered. The Subsea Mudlift development program produced the only prototype DGDS successfully field tested to date; however, deployment cost has proved problematic to market penetration.[2],[3]

Consideration is being given to the DGDS approach (Fig. 13.4) proposed by Maurer to reduce the cost of achieving a dual gradient drilling capability. Maurer is leading a consortium to look into the feasibility of injecting LWSA at the mudline to control gradient in the riser ( The strength of the approach is that it has the potential to simplify significantly the equipment installed at the mudline and hence to reduce the cost of the DGDS. In addition, the LWSAs are well behaved in the riser; they maintain constant shape and do not migrate significantly when pumping is stopped for a reasonably long period of time. To date, both hollow glass spheres and polypropylene beads have undergone testing for use as LWSAs; however, an investigation of alternatives is ongoing.

Fig. 13.5 shows a side-by-side comparison of the results of using DGDS compared with conventional single gradient drilling. As noted in the figure, the setting depth of all casing strings is significantly increased. This is achieved, in effect, by isolating the borehole pressure from the weight of the seawater above the mudline. Most systems achieve this isolation through rather complex combinations of pumps and cuttings processing equipment at the mudline. The Maurer DGDS achieves a similar effect by lowering the fluid density in the riser well below 8 lbm/gal. Regardless of the system considered, the most notable benefits of DGDS technology are that it has the potential to enhance the capability of drilling to even deeper targets in ultradeep waters of the GOM and it allows active control of borehole mud gradient. It should be noted that the latter benefit could also be a significant safety consideration.

High-Speed Communications. Communication with downhole tools while drilling is currently achieved with either mud-pulse telemetry or electromagnetic-based systems. The maximum data transmission rate (correlated with bandwidth) of these systems is about 10 bits per second. [4] As a result, much of the information from measurement while drilling and logging while drilling must be processed and stored in computer memory associated with the downhole instrumentation near the drill bit. The term "real-time monitoring" can be applied in only a very limited sense with current technology.

The potential for true real-time monitoring has increased significantly with the initiation of the commercialization phase of a Dept. of Energy (DOE) technology development contract with Novatek, Inc. Novatek and its partner, Grant Prideco, have begun commercial construction of Intellipipe® ( Intellipipe represents a novel and robust means of transmitting data up drillpipe at a transmission rate of 1 million bits per second. Key to the success of this technology was development of a high-efficiency coupling that enabled successful transmission of data across many tool joints without the need for amplification over lengths exceeding 1,000 ft. Another key feature of the system is that it will allow the drillpipe to act as a local area network within which many different tools or systems located anywhere within the drillstring can be individually addressed and/or turned on and off. Fig. 13.6 is a concept drawing that shows the basic components of the proposed real-time monitoring and control system. Fig. 13.7 details the components of the electromagnetic coupling across the tool joint. The recessed coil in the pin connection comes in very close, controlled proximity with the coil in the base of the box connection during makeup. The design results in a strong connection and forms the basis of a robust, reliable, efficient electromagnetic coupling for transfer of data across the connection.

Subsea Completion Systems. Drilling is not the only challenge to deepwater drilling economics. Current deepwater technology trends almost exclusively require huge discoveries and unprecedented production rates to ensure acceptable rates of return. One method to reduce the high development capital expenditures associated with deepwater environments that is being explored (Fig. 13.8) is a modular system designed for easy retrieval to the surface using diverless techniques for repair and maintenance, process reconfiguration, and equipment upgrade. The system reconfiguration will be accomplished by a workboat instead of a drillship. As a result, the cost of the reconfiguration, or "intervention," could be reduced as much as $200,000 per day compared with systems accomplishing similar functions. This reduction in capital expenditures associated with intervention is expected to make many smaller reservoirs economically viable.

Three-phase pumps have been used with limited success to pump deepwater production to separation facilities. However, one characteristic of the deepwater GOM is the significant topographic relief, occasionally reaching 1,000 ft in one 9-sq-mile lease. Such relief results in subsea pipelines acting as separators. As a result, severe slugging phenomena have been reported[5] in cases of extended pipeline distance and elevation change. Separating the liquid and gas very near the subsea wellheads is expected to significantly reduce pumping problems, required pumping horsepower, and many problems associated with hydrate production.


Technologies discussed within this section are included because their development initiated with onshore field tests and because the technologies are considered essential to economics for enabling further exploration of ultradeep ( > 20,000 ft) onshore petroleum resources. However, it is recognized that the need to further reduce operating cost and efficiency offshore will likely lead to expanded commercialization of these technologies more rapidly in this arena.

Expandable Tubulars

One of the most exciting developments in the last decade has been expandable tubulars because they offer the potential for a "monoborehole" and drilling to depths no longer limited by initial hole diameter. As a result, the focus on tubulars has concentrated on expandable casing. Shell and Halliburton formed a company, Enventure, that is specializing in the commercialization of expandable casing based on earlier Shell work. A key development from that work is the concept of the monodiameter borehole (Fig. 13.9). Production casing can be run inside the expanded form of casing with the same diameter with this concept. It will allow, for the first time, casing to be set at will or as needed without a penalty in completed depth. Lost-circulation zones, swelling shales, and other drilling problems can be put behind pipe as necessary without jeopardizing planned total depth. Total depth limitations will now be limited primarily to mechanical capabilities of the drill rig, casing, and/or drillpipe run into and out of the borehole.

Elastomers on the exterior of the expanded casing have proved to be effective pressure seals in liner lap applications in lieu of running a conventional liner hanger seal assembly. Additional testing for sealing potential is being conducted. As of this writing, Enventure is planning a field test to investigate the potential of expandable casing to seal off against the formation without cement. If the test is successful, it will demonstrate the potential to eliminate most cementing operations, one of the costliest phases of well construction. If this becomes an accepted, safe practice, it could enable other opportunities for unprecedented reductions in exploration cost.

Casing Drilling

Drilling with casing is not a new concept; it has been used in the mining and water-well industries [6] for many years. However, modifying the tools and materials for oilfield use and extending drilling depth beyond a few thousand feet is new. This new approach, called Casing Drilling TM , was developed [7] and field tested [8] and culminated in a successful demonstration to ≈ 9,500 ft early in 2002 in South Texas by Tesco Corp. and its partner, Conoco. The demonstration was the result of > 5 years of development that included development of tools for directional drilling.[9] The demonstration resulted in an actual overall drilling time reduction of 17.5% and a potential for as much as a 33% reduction.[10] In October 2002, Tesco won World Oil’ s prestigious Next Generation Idea Award, which recognized the technology as a step change in drilling. Fig. 13.10 is the comparison diagram from Tesco’

s website ( used to denote areas in which Casing Drilling has proved superior to conventional drilling. Those areas are (1) swelling formations, (2) sloughing formations, (3) washouts, (4) swabbing, (5) hole in casing or key seats, and (6) running logs and casing. One area not mentioned in the diagram is lost circulation. In the South Texas field demonstration, conventional drilling in the area was characterized by lost circulation and stuck pipe. In fact, the offset conventional well used for comparison experienced a total of 53 hours of lost circulation and stuck pipe, whereas the Casing Drilling test had only 1 hour. Typically, stuck pipe and lost circulation accounted for 75% of the trouble time for conventionally drilled wells in the test area. The reason for fewer lost-circulation difficulties associated with Casing Drilling is not clear at this time; however, studies are currently underway to better our understanding of the phenomenon.

Deep Hard-Rock Drilling

As the quest for new petroleum supplies has increased in the past few years, operators have been forced to drill deeper to find new reserves. Much of the higher cost of drilling deeper, especially onshore, is typically associated with decreased rate of penetration (ROP) caused by both harder rock and higher mud weights required to counter the overpressured reservoirs often associated with deeper drilling. The following discussion centers on technologies intended to enhance the deep drilling capability.

Mud Hammers. Industrial hammers for hard rock drilling have been around for some time, but most have been air operated and used mostly in the mining industry. Historically, hammers have been thought to have limited capability in oil and gas drilling operations, with their use limited to air drilling. Because of "chip holddown" and erosion through the hammer when drilling mud is used, hammers were not considered for drilling operations involving drilling mud. As a result, hammers have never been seriously considered for most deep drilling where hammer energy might enhance ROP by helping to overcome increased rock strength.

In an effort to develop novel drilling technologies, the DOE awarded a contract to Novatek to develop an "integrated" drilling system using a mud hammer as the primary engine (see Fig. 13.11 and [1]. The previously referenced high-speed communication system for drillpipe was part of that development. Another part of that development was a mud hammer that incorporated a number of revolutionary concepts, as shown in Fig. 13.12. Most notably, the bit was a radical departure from typical hammer bits. It was essentially a five-bladed drag bit with polycrystalline diamond cutters (PDCs) specially manufactured by Novatek to allow the aggressive drag bit profile to be used in soft formations but still allow enhanced drilling in hard formations using the high-energy impacts of the optimized industrial hammer. In addition, the hammer piston is used to energize a series of high-pressure jets (≈ 5,000 psi) that exhaust directly in front of each PDC to achieve an unprecedented level of cleaning ahead of each cutter. The jets also energize fractures ahead of the bit to enhance ROP.

Directional steering is made possible by means of a directional control sub (see Fig. 13.11). The control sub causes preferential firing of the jet pulse on the side of the hole in the direction the operator wants to steer, as shown in Fig. 13.12.

The Novatek IDS hammer and other hammers were part of a test program funded by the DOE to provide a focused study program for investigation of mud hammer potential in deep hard-rock drilling environments. That program is being run by TerraTek with several industry participants. The first results of that program were published in the SPE Journal of Petroleum Technology Online.[11]

In summary, the current status of mud hammer investigation is still unfolding, with improvements in a number of mud hammers being driven by the testing program at TerraTek. The promise provided by mud hammers is potentially far more extensive than simply enhancing ROP in deep hard rock, although that alone would be sufficient. Mud hammers provide extremely strong seismic energy coupling into the rock. It might be possible to incorporate a mud-hammer-based seismic imaging system into the previously discussed high-speed communications system to provide a "seismic look-ahead" capability that could allow navigation directly into the desired hydrocarbon target or sweet spot. Such a system would be a significant step forward in the exploration and development of fractured, unconventional reservoirs.

Mud-Pulse Drilling. Another novel approach to enhancing ROP in deep mud drilled wells was developed by Tempress Technologies. Fig. 13.13 shows the basic principles used in this system. Chip holddown is a well-documented phenomenon associated with mud drilling, especially in deep environments. In essence, the fluid pressure of the mud inhibits rock chips made by the drill bit from being removed from the cutting face in front of the bit. The result is regrinding of cuttings and a slowing of ROP.

The mud-pulse drilling system comprises an oscillator valve in the drillstring, which momentarily interrupts flow of the drill mud around a velocity section on the outer wall of the pipe. This interruption in flow results in extreme depressurization pulses (

> 1,500 psi) developing below the bit. Theoretically, this causes rapid decompression of the fluids in the rock ahead of the drill bit and results in an apparent decrease in rock strength ahead of the bit, which results in increased ROP. The system can be run with almost any drill bit.

To date, development and testing are continuing. A more detailed description and the latest information can be found at Tempress’

website (


So far in this discussion, new methods have been the source of innovation. However, advancements in materials are also at the heart of the current drilling revolution. Receiving focus are both resin-based and metal composites. Resin composites have been studied extensively, with the advent of carbon-fiber-based materials showing promise for significant increases in yield strength and reductions in required weight. Metal composites have made another dramatic jump in capabilities with the commercialization of microwave-processed (MWP) diamond and tungsten carbide composites. Potential uses and combinations of MWP materials have not been fully explored.

Resin Composites

The term "resin" is used here to describe the family of composite materials that use a resin to bind a matrix of fibers, usually woven. Many such materials have been commercialized for coiled tubing applications because composite resiliency to cyclic stress results in significantly longer life of the coiled tubing string than steel coiled tubing. In addition, composite coiled tubing is lighter than its steel counterpart, and communication cables can be embedded in the wall of the pipe.[12] Currently available composite coiled tubing is typically <

5 in. in diameter. Some interest has been expressed in developing larger-diameter composite pipe for increased rigidity in horizontal and extended-reach drilling.

The DOE-funded project with Advanced Composite Products and Technology (ACPT) and its joint industry project partners is focused on development of a 5.5-in.-diameter composite drillpipe[13] with conventional steel connections that will be cost-competitive with steel drillpipe. Key benefits of the pipe are that it will be half the weight of steel drillpipe and will be essentially interchangeable with existing drillpipe.

Interestingly, during the development of the 5.5-in.-diameter pipe, a number of smaller-diameter test specimens were manufactured. On the basis of the results of testing the smaller-diameter drillpipe, interest was expressed in using it for developing the build section for short-radius boreholes. This interest culminated in a field test of the short-radius composite drillpipe (SR CDP). The following summary of that operation was provided from ACPT and is accompanied by photos in Fig. 13.14:

The field test was completed on November 6, 2002 by Grand Resources, Inc. at their Bird Creek site. Starting with an existing well that stopped producing in 1923, Grand Resources packed the bottom of the well and sealed it with concrete. Then they lowered the drill string 1208 feet and began directionally drilling a 70-ft-radius curvature through the well casing and into the strata. The SR CDP was furnished by ACPT, Inc. and DOE/NETL for the purpose of drilling the curve and lateral section that extends 1000 feet into the strata. The pipe worked flawlessly and Grand Resources was pleased with performance of the new product. Grand Resources estimates that this renewed well will produce 30 to 50 barrels of oil per day for quite some time. Grand Resources plans to renew 14 additional wells in the same area in the near future and will use the new composite drill pipe in these endeavors. The CDP was not used to drill the lateral portion of this well because air hammer tools were used for this section. Grand Resources will test sections of CDP with air hammer tools in the next well. The air hammer beats at 2400 strokes per minute with a 4 to 6 inch stroke. This will be a good test of the strength and durability of the CDP. As they gain experience and confidence in the product, Grand Resources expects to extend the reach from 1000 to 2000 feet by using the CDP.

Metal Composites

Although there have been a number of advances in metal composite materials, much excitement has been focused on the application of microwave sintering of "green bodies" associated with powder metal technology. Powder metal technology is not new, but the sintering, or densifying, of the green body through microwave heating is a novel concept made possible only recently. The microwave energy heats relatively quickly and evenly from within the green body. This allows a process time that is a fraction of that for conventional sintering (hours vs. days). In addition, as noted in Fig. 13.15, the finished product is typically 30% stronger with improved impact resistance and corrosion resistance. Fig. 13.15 also shows that MWP is applicable to a number of materials (most notably tungsten carbide, diamond composite, and steels). A research program is under way at Pennsylvania State U. (with its commercialization partner, Dennis Tool Co.) to investigate the potential use of MWP for the manufacture of ceramics and hard transparent polycrystalline materials. The latter involves a Defense Advanced Research Agency-funded project to investigate the potential for using MWP to manufacture "transparent armor." If successful, such materials could find their way into hardened subsystems for MWD.

It should be noted that the ability to form diamond composite with tungsten carbide was a significant leap forward in materials development. In conventional processing/sintering, the diamond composite is turned to graphite because of the high temperatures required for sintering the tungsten carbide and the long heating and cooling times required. With microwave processing, the entire sintering process can be accomplished before the diamond composite is affected. In addition, the boundary between the diamond composite and tungsten carbide is not well defined because of a diffusion bonding process. This process is being investigated for its potential to make "functionally graded" materials. Such materials would allow entire bits and/or cutter assemblies to be manufactured in a single process in which diamond composite is bonded to tungsten carbide that is, in turn, bonded to drill steel. It might even be possible to form thread into the green body before sintering to eliminate machining.

An extension of this technology has been in the investigation of the potential for MWP to be applied to the manufacture of coiled tubing. If use of MWP technology results in a tubular that is 30% stronger and retains the same ductile character of competing steels used for coiled tubing, another leap in coiled-tubing drilling capability will be a reality. This should be known within the next 3 years.

In a related development, the above-mentioned "supermaterials" will allow even more aggressive cutting structures and drilling machines. One such drilling tool is already being evaluated by Dennis Tool Co. It is a drilling motor that uses high-speed milling concepts to abrade rock. A pilot bit is rotated counter to the direction of three high-speed cones that follow the bit and open the hole to the required diameter. The result of this action is zero torque transferred to the drillstring, a significant benefit to coiled-tubing operations. The drill appears to be capable of drilling on the order of 80 ft/hr in almost any type of rock. A final commercial version of this high-potential drilling machine could depend on proper application of the new supermaterials.


For purposes of this discussion, microsystems are those systems or subsystems that represent a quantum leap in the size and/or capability of currently available systems. Interest in these systems is tied to the interest in "smart" drilling and the demand for increased information and reliability. Reliability can often be defined as simplicity. Hence, smaller systems that require less power or are passive measurement devices can be of great benefit in building more complicated sensory and communication networks.

Fiber-Optic Devices

With the incorporation of "interferometry" technology into fiber-optic systems, it has become possible to talk about extremely small packages suitable for harsh environments, [14] such as a drilling environment. Fig. 13.16 shows an example of a pressure sensor developed for a stationary measurement environment, such as a well completion. With the advent of composite drillpipe and the capability to embed such systems into the wall of the pipe, using much more sophisticated information systems for drilling is very possible.


If it were possible to reduce drilling cost to the point that it could be considered a part of "predrill" prospect development, a significant capability would exist for improving the economics of developing today ’ s fractured, unconventional resource. That feasibility is being investigated (Fig. 13.17) at Los Alamos Natl. Laboratory under a grant through DOE’ s National Gas and Oil Technology Partnership Program ( The project is called microdrilling. The first enabling technologies were the microelectromechanical systems (MEMS) that made feasible a complete "rethink" of new economies possible for exploration drilling. It is possible to talk about smart drilling systems drilling 2⅜-in.-diameter and smaller boreholes with drill rigs that do not look at all like today’

s conventional rigs. The MEMS technologies also make possible downhole systems that are essential for steering and formation evaluation.

To be successful, microdrilling cannot simply be an expensive, smaller form of "slimhole" technology. The MEMS technology will allow a significant reduction in the size of drill rigs and drilling systems. However, the key will be to reduce total well cost. Such concepts as the monoborehole resulting from expandable tubular technology must be part of the complete microdrilling capability. In addition, high-ROP drilling tools will need to be investigated.

Of significant potential to all coiled-tubing drilling is the development program for a high-pressure coiled-tubing drilling system. Maurer Technology developed and tested this system with financial assistance from the DOE. Instantaneous ROPs as high as 1,400 ft/hr were recorded during surface testing in limestone. The project description can be found at The system incorporates a special moineau-type, positive-displacement motor with high-pressure (10,000 psi) housing. The motor drives a special PDC bit with high-pressure jets to etch the rock ahead of the bit. Thus, the bit only needs to break up the remaining rock not cut by the jet.

Such systems are excellent for coiled-tubing operations because they offer the potential for high ROPs without significant drilling torque.

Federally Funded Drilling Projects

Quite often, companies participate in federally cost-shared drilling technology development. The details that follow are provided to bring the reader up to date on the latest published trends in drilling technology development that could affect the drilling industry soon. It might be thought of as a long look into today ’ s "crystal ball" for tomorrow’ s technologies.

On 23 September 2002, the DOE’ s Office of Fossil Energy announced the awards to its National Energy Technology Laboratory’ s Deep Trek Solicitation for initiation of development of the following technologies (if successful, commercialization anticipated within 5 to 10 years):

  1. APS Technology Inc., Cromwell, Connecticut, plans to develop a two-component system that monitors and controls drilling vibrations in smart drilling technologies. Drillstring vibration causes premature failure of equipment, which reduces the depth and speed at which a well is drilled. A multiaxis active damper will be used to minimize harmful vibrations, which will extend the life of the drill bit and other components and improve the ROP. A real-time system that monitors three-axis vibrations and related measurements will be used to assess the vibration environment and adjust the damper accordingly.
  2. E-Spectrum Technologies, San Antonio, Texas, proposes to develop a communications system that allows well operators to receive vital measurements while a well is being drilled, which improves drilling and consequently production. The system would directly control adjustable downhole tools and make changes in drilling in real time, greatly improving a well’

s future production level. E-Spectrum will build and field test a prototype of a wireless electromagnetic telemetry system for use in high-temperature (392°F) drilling beyond 20,000 ft. The system will be composed of a surface unit receiver/transmitter, downhole data-acquisition module, downhole repeater module, and a downhole receiver/transmitter module.

  1. Pennsylvania State U., University Park, and Quality Tubing Inc., Houston, will develop a continuous microwave process to make seamless coiled tubing and drillpipes efficiently and economically. Improving the performance, life cycle, and ROP of these materials will allow deeper wells to be drilled. Drill mud, which contains drilling fluids, causes erosion and leaks that weaken conventionally welded drillpipes, causing them to fail.
  2. Pinnacle Technologies, San Francisco, will review current and past stimulation techniques for deep-well completions to develop data that help minimize uncertainty and increase success in drilling deep formations. Information will be obtained through literature reviews; interviews with operators, service companies, and consultants; evaluations of rock mechanics and fracture growth in deep formations; and assessments of stimulation techniques in three to five gas wells. A comprehensive report will be assembled and given to the gas industry through publications and workshops.
  3. Terra Tek, Salt Lake City, Utah, will develop and test prototypes of novel drill bits and advances in high-temperature, high-pressure fluids suited for slow, deep-drilling operations. With its private industry partners, Terra Tek will characterize technologies, develop and supply new bit prototypes and drilling fluids, and field test prototypes. Researchers will benchmark the performance of emerging products by conducting drilling tests in its laboratory. Joining Terra Tek will be the U. of Tulsa, Hughes Christensen, BP America, Conoco, INTEQ Drilling Fluids, Marathon Oil Co., ExxonMobil, and National Oilwell.

Find more information on the above programs at


Sincere appreciation is expressed for approval to publish graphic materials provided for this publication from the following companies: Conoco and all its Subsea Mudlift Project partners; Maurer Technology, Inc.; Novatek and its Intellipipe partner, Grant Prideco; Conoco and its subsea completion project partner, Kvaerner; Enventure; Tesco Corp.; Tempress Technologies; ACPT and its composite drillpipe joint industry partners; Pennsylvania State U. and its partner, Dennis Tool Co.; Virginia Polytechnics Inst.; and Los Alamos Natl. Laboratory. Appreciation is also extended to NETL ’

s Strategic Center for Natural Gas and Oil, for the information on the DOE-funded projects.


A number of the technologies discussed in this chapter were sponsored by an agency of the United States government. Neither the United States government, any agency thereof, nor any of their employees make any warranty, express or implied, or assume any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed or represent that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States government or any agency thereof. The views and opinions expressed here do not necessarily state or reflect those of the United States government or any agency thereof.


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  3. Eggemeyer, J.C., Akins, M.E., Brainard, R.R. et al. 2001. SubSea MudLift Drilling: Design and Implementation of a Dual Gradient Drilling System. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisianna, 30 September–3 October. SPE-71359-MS.
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  10. Fontenot, K., Highnote, J., Warren, T. et al. 2003. Casing Drilling Activity Expands in South Texas. Presented at the SPE/IADC Drilling Conference, Amsterdam, Netherlands, 19-21 February. SPE-79862-MS.
  11. Tibbitts, G.A., Long, R.C., Miller, B.E. et al. 2002. World's First Benchmarking of Drilling Mud Hammer Performance at Depth Conditions. Presented at the IADC/SPE Drilling Conference, Dallas, Texas, 26-28 February. SPE-74540-MS.
  12. Coats, E.A. and Farabee, M. 2002. The Hybrid Drilling System: Incorporating Composite Coiled Tubing and Hydraulic Workover Technologies into One Integrated Drilling System. Presented at the IADC/SPE Drilling Conference, Dallas, Texas, 26-28 February. SPE-74538-MS.
  13. Leslie, J.C., Jean, J., Truong, L. et al. 2001. Cost Effective Composite Drill Pipe: Increased ERD, Lower Cost Deepwater Drilling and Real-Time LWD/MWD Communication. Presented at the SPE/IADC Drilling Conference, Amsterdam, Netherlands, 27 February-1 March. SPE-67764-MS.
  14. Ruan, H., Chen, Y., Liu, Y. et al. 2001. Optical Fiber Logging System for Multiphase Profile Analysis in Steam Injection Wells. Presented at the SPE Western Regional Meeting, Bakersfield, California, 26-30 March. SPE-68807-MS.

SI Metric Conversions Factors

ft × 3.048* E–01 = m
°F   (°F–32)/1.8   = °C
gal × 3.785 412 E–03 = kg
in. × 2.54* E+00 = cm
lbm × 4.535 924 E–01 = kg
psi × 6.894 575 E+00 = kPa
sq mile × 2.589 988 E+06 = m2


Conversion factor is exact.