By Katherine Scott, editorial coordinator
Pulse Structural Monitoring, an Acteon company, unveiled three new software modules developed to complement its DrillASSURE drilling riser monitoring system software during a launch event at the 2012 IADC/SPE Drilling Conference and Exhibition in San Diego, Calif., on 7 March. Developed in conjunction with 2H Offshore, the new modules are DrillJOINT, DrillWINDOW and DrillADVISE and add to the current modules DrillFATIGUE, DrillTRANSIT and DrillVIV. The new interfaces are designed to help operators and contractors optimize use of their drill joint inventory, identify optimum operating windows and conduct safe campaigns by constantly analyzing conditions in real time.
“Improvement in safety, productivity and efficiency are increased and lower operating costs are the major benefits we see for integrating the software into (a company’s) operations,” said Jeff Diestler, business development manager for Pulse.
The DrillJOINT module is a complete inventory detailing the location, availability, technical specification, previous use and maintenance history of the owner’s drill joint. It enables operators and contractors to source riser joints and assemble a robust drilling stack on screen prior to drilling, saving time and enhancing safety and efficiency.
DrillWINDOW offers pre-drilling analysis of static and dynamic operating windows and hang-off envelopes. The user inputs known environmental data, such as wave height, current velocity and mud density, then the software evaluates these data points against approved safety margins to calculate the fatigue life of the drill stack.
Lastly, the DrillADVISE module calculates parameters such as vessel position, flex joint angles and environmental conditions, then presents easily interpretable data in real time to guide the user on proceeding safely and efficiently. Feedback is presented in colors: Green shows all parameters are within thresholds, amber indicated caution or corrective action are required, and red is an instruction to disconnect immediately.
The combination of hardware and software modules creates the DrillASSURE system, which provides information to support day-to-day drilling operation and longer-term integrity management. The system uses real-time software in conjunction with inputs from sensors on the topside vessel, lower marine riser package and along the length of the riser.
“With our DrillASSURE systems (we can) monitor fatigue accumulation on critical components,” Mr Diestler said.
Monday, March 26, 2012
Reservoir drives choice of RSS vs mud motors
Rotary steerables suit narrow formations; mud motors may be more cost-effective in broader boundaries
By Eric Malcore, Weatherford International Ltd
The ratio of directionally drilled wells to vertically placed wells is increasing. Access to progressively harder to reach reserves is driving more complex well geometries, which predicate the use of rotary steerable systems (RSS) to enhance rate of penetration (ROP), improve borehole quality and reduce torque and drag and stick slip. The various RSS technologies available today have revolutionized the drilling process in horizontal and deviated wells by facilitating greater intermediate reaches and longer laterals, allowing casing to be run more easily and allow proper weight transfer.
The service industry estimates that RSS technologies account for approximately $3.5 billion of the estimated $15 billion directional drilling market. The dynamics are shifting in favor of RSS.
Although not a new technology, high-performance mud motors also have become an accepted and reliable method in directional drilling operations, in many cases providing a cost-effective alternative to more costly rotary steerable tools.
Knowing when to choose a rotary steerable system and when to use a high-performance mud motor is critically important to optimize the drilling project from both an engineering performance and a cost perspective.
Many horizontal or deviated wells are extremely difficult or impossible to drill without an RSS. A key benefit of RSS technology is that it directs well trajectory without sliding, a condition that impacts the stability and orientation of the drill string to rotate in one direction. Without proper rotation, the entire drill string can stick to the borehole wall, making it difficult to achieve the desired weight transfer to the bit to achieve planned penetration rates. RSS tools provide continuous rotation of the drill pipe, minimizing the risk of the pipe becoming stuck or buckling.
Sliding also creates more waste because the lack of rotation keeps the fluid in a static state, making it more difficult to remove cuttings. The cuttings then pack off around the bottomhole assembly, causing the drill string to stick. With the continuous rotation enabled by rotary steerable tools, however, the friction holds the cuttings in suspension, allowing the fluid to create a vortex around the drill string to provide consistent hole-cleaning.
RSS technology also reduces drag, allowing extension in well reach, especially important in horizontal applications. Rotary steerables typically deliver a smooth in-gauge wellbore and control the toolface at the bit, which provides more accurate directional control and less tortuosity. They also enable the use of logging-while-drilling (LWD) azimuthal sensors to obtain full borehole images.
Applying Precise Directional Control
An important factor in rotary steerable systems is that they provide precise directional control and are therefore suited to narrow zones as tight as 1 ½ ft. In that regard, the tools also can provide geosteering in these narrow reservoirs, where corrections can be made in real time without sliding.
An RSS was used to successfully drill and complete a section of a horizontal water-injection well with an 8 ½-in. hole in Abu Dhabi.
Using Weatherford’s Revolution rotary steerable system, the operator was able to drill 2,200 ft (671 meters) at a depth of 8,725 to 12,918 ft (2,659 to 3,937 meters) in less than 90 hrs in one run, saving 41 hrs of drilling time and achieving a significant cost savings without nonproductive time.
The same system was used in another Abu Dhabi water-injection well to facilitate drilling and completion of an ultra-narrow, 6-ft zone with a 6-in. hole size and a run length of 4,193 ft (1,278 meters).
The operator was able to drill almost 20 ft (6 meters) deeper than anticipated, reaching a target that otherwise would have been missed.
In an onshore Saudi Arabian field prone to lost circulation, differential sticking and hydrogen-sulfide challenges, the same technology drilled a 3°/100-ft (30-meter) dogleg section with a 6 1/8-in. hole in an extended-reach horizontal water-injection well to a target depth of 16,856 ft (5,138 meters). Average ROP was 35 ft/hr (11 meters/hr). Prior to deployment of the system, optimal ROP had been difficult to achieve with a steerable motor assembly.
The system drilled a total of 7,316 ft (2,230 meters) in one run, achieving a field run-length record and meeting the operator’s goal to minimize excess tripping time. The operation saved 24 hours in drilling time and associated costs and allowed the operator to avoid stuck-pipe and lost-in-hole risks that occur in similar extended-reach wells.
In the Bay of Bengal in Eastern India, the same RSS technology performed a record-breaking shoe-to-shoe run in a claystone formation, with interbedded sandstone, marl and calcareous clay. The deep exploratory well had an inclination of 34°. The system drilled a 12 ¼-in. in-gauge hole and then drilled to a measured depth of 4,918 ft (1,499 meters) to improve the average ROP and reduce the number of wiper trips and backreaming. Drilling time was 192 hrs, with an average ROP of 25.6 ft/hr (7.8 meters/hr).
RSS technology has been enhanced in recent years by the development of motorized rotary steerable systems, where a power section placed on the RSS tool provides additional rpm and torque while still achieving the benefits of control and eliminated sliding. This hybrid-type application is increasingly being used in regions such as the Middle East, where the rock and carbonates are especially hard.
High-performance mud motors can save 50% or more a day over rotary steerable systems. Mud motors also can be used with smaller rigs that can’t rotate fast enough to enable the rotary steerable mechanism to perform. However, rotary steerables provide greater precision in directional control, an advantage in tight formations.High-performance Alternative
Despite its many benefits, rotary steerable technologies can present some disadvantages, including cost, if used in situations where precise directional control is not the primary objective. For example, to justify the expense of using a rotary steerable system, the savings in rig time and other costs must be greater than the rotary steerable cost.
Rotary steerable drilling performance is delivered from the use of surface rotation, making them rig-dependent. They offer limited selection of bit sizes and speeds, and they involve greater complexities, both mechanically and electronically compared with motors. The high rotation speeds can cause premature wear to the casing and drill string, which can be slightly decoupled by using an integrated power section with the RSS, albeit adding significantly to the cost.
The replacement cost of a rotary steerable system, if it is lost in the hole, can exceed $1 million, depending on the system and size. That does not include the replacement cost of the accessory tools.
In cases where deploying an RSS is either cost-prohibitive or impractical, a high-performance mud motor can also achieve desired results, provided it is used in the proper application. However, high-performance mud motors are best suited to broad target areas and zones that require less precision, or in doglegs that are too aggressive for an RSS.
Used since the early 1990s for a multitude of oilfield applications, high-performance mud motors achieve greater torque and ROP than conventional mud motors. The mud motor leverages the reduced rubber profile in the power section to gain additional torque, which creates less deformation as the rotor spins. The reduced rubber deformation translates into more torque for the bit, which in turn allows for higher ROP and more aggressive bit designs.
For operators, the key advantage is that a high-performance mud motor can result in daily cost savings of 50% or more over an RSS. Lost-in-hole costs also are significantly lower; a 6 ¾-in. high-performance mud motor has a typical lost-in-hole cost of $168,000.
High-performance mud motors can often out-perform standard, non-motorized RSS, which depend on the rig rotary table to spin the bit. The motor power component of the high-performance mud motor, on the other hand, provides bit rotation and power directly to the bit. High-performance mud motors also can be used in situations that involve smaller rigs that can’t rotate fast enough to enable the rotary steerable mechanism to perform.
Another benefit is that all bit types and sizes can be used with a high-performance mud motor, making it useful for a variety of applications, including situations where a particular bit that is not compatible with an RSS must be run.
High-performance mud motors do, however, require sliding for directional control, which typically reduces ROP. They offer poor and inconsistent hole-cleaning and poor hole gauge. Also, LWD sensors often get pushed back farther from the bit. Motor bend with high-performance mud motors can limit the drill string rotary speed or not allow any rotation at all. These factors must be considered in selecting this method of drilling.
It’s believed that rotary steerable technologies account for approximately $3.5 billion of the estimated $15 billion directional drilling market.UAE Test Cases
High-performance mud motors have been used successfully in many deviated drilling operations and have achieved better-than-average ROP rates in three offshore test cases – the Thamama, Hith and Arab formations in the United Arab Emirates.
Seven wells in the Thamama Formation featured multiple target zones and were characterized by hard, Cretaceous limestone, but they presented no sliding issues. The operator used high-performance mud motors to drill the wells, which were not horizontal but had deviations ranging from 0° to 30° and had 8 ½-in. hole sizes.
The high-performance mud motors performed with an average ROP of 28 ft/hr (8.5 meters/hr). The best performance for the motors was 44 ft/hr (143.4 meters/hr), and the worst performance was 17 ft /hr (5.2 meters/hr). The Hith Formation also featured hard drilling conditions, with Jurassic anhydrite and dolomite rock but no sliding issues. The operator again drilled seven hole sections, all deviated but not horizontal, with 8 ½-in. hole sizes and a build section of 25° to 90°. In this case, the high-performance mud motors delivered an average ROP of 18 ft/hr (5.5 meters/hr). The highest ROP was 41 ft/hr (12.5 meters/hr), and the lowest was 9.88 ft/hr (3 meters/hr).
In the Arab Formation, featuring Jurassic carbonate/anhydrite rock, both sliding and directional control challenges were present. The lateral section was +/- 90°. Again, the operator drilled seven 8 ½-in. hole sections with high-performance mud motors.
The operation achieved an average ROP of 18 ft/hr (5.5 meters/hr). The best performance was 31 ft/hr (9.4 meters/hr), while the worst performance was 10 ft/hr (3 meters/hr).
The emergence of multiple technologies to optimize the drilling process can make selection of the proper technology confusing. Understanding reservoir properties along with diligent analysis of the well program, including formation, bit selection, directional program and other factors, must be considered when determining whether an RSS or a high-performance mud motor will achieve the best results in terms of cost and efficiency.
In tight or narrow formations where precise, directional control is needed, RSS are often the optimal choice for achieving drilling optimization and increased ROP. In zones with broader boundaries, a high-performance mud motor can provide results at a lower cost, provided issues such as sliding are carefully examined.
Revolution rotary steerable system is a trademark of Weatherford.
Case study: Algerian underground blowout
Incident demonstrates need for well-trained crews, adequate mud equipment
By Pedro Martinez Aguilar, Repsol Exploration; Michael Arnold, John Lee, Boots & Coots, a Halliburton Service
Partial mud-loss in the Tournasian formation occurred because the formation permeability and porosity were sufficiently high to allow loss of whole mud. An open-hole formation integrity test (FIT) should be performed after repairing the loss zone and regaining circulation to ensure the wellbore pressure integrity is still equivalent to the FIT recorded at the last shoe depth.The outcome of a well control and blowout incident reflects how well a crew is trained and prepared. This article will discuss the sequence of a well control operation that occurred in Algeria in December 2008, which includes the influx, steps to identify the situation, operations to control the underground blowout and the response of the well.
An operator drilled a 12 1/4-in. exploratory well at 11,516 ft in the Emsian formation and set a string of 13 3/8-in. casing at 5,250 ft. A pit gain was observed, and the well was shut in. The maximum annulus pressure recorded after shut-in was 570 psi. A sudden drop in annulus pressure to 325 psi suggested lost circulation and was assumed to be in the Tournasian formation (5,305 ft to 6,180 ft), where severe lost returns had been recorded while drilling (5,580 ft to 5,740 ft).
The pressure drop made it difficult to assess the kick, thus hindering conventional well-control techniques.
Initial Well-Control Actions
Pore-pressure equivalent mud weight (EMW) at the Emsian formation was estimated to be 11.7 to 12.7 lbm/gal. The formation-strength EMW at the Tournasian formation was estimated to be 10.0 to 11.7 lbm/gal. Believing the well was experiencing losses to the Tournasian, 189 bbl of 11.6-lbm/gal mud was pumped into the casing annulus. The annulus pressure remained constant, indicating the possibility of an underground blowout.
As the annulus pressure continued to increase to 1,000 psi, 340 bbl of 11.6-lbm/gal mud was pumped down the casing annulus to reduce the pressure. A volume of 340 bbl of 9.9-lbm/gal mud was pumped down the drill string while maintaining a maximum choke-back pressure of 1,600 psi. After pumping the mud, the stabilized pressure was used to determine the bottomhole pressure. While adjusting the choke, an influx entered the wellbore.
To prevent the annulus pressure from increasing beyond 1,000 psi, batches of 13.3-lbm/gal mud were pumped periodically into the annulus. The initial volumes of mud contained lost-circulation material (LCM) to help cure the losses.
The drill pipe was filled periodically to avoid gas migration up the drill string. Shut-in drill pressure remained at 0 psi. Losses in the annulus were reduced when the LCM reached the loss zone, and the shut-in drill pipe pressure gauge began indicating pressure.
Sandwich-Kill Attempt
The hole was displaced through both the drill pipe and the annulus, “sandwiching” the influx into the lost zone.
The Emsian formation pressure was predicted to be between 12.1 and 12.7 lbm/gal EMW, meaning a 15.9-lbm/gal kill mud would overbalance the Emsian formation by +/- 3.2 lbm/gal. A cement unit was used to pump 818 bbl of 11.6-lbm/gal mud down the casing annulus, and rig pumps were used to pump 1,006 bbl of 15.9-lbm/gal mud down the drill pipe.
The operation was partially successful because the annulus pressure was still 600 psi at the end of the procedure. However, it confirmed that the bottomhole pressure and the pressure at the loss zone were higher than predicted.
Casing pressure began to increase, and drill pipe pressure remained at 0 psi. Once the casing pressure reached 2,050 psi, the drill pipe pressure increased proportionally to the casing pressure.
Communication between the annulus and the drill string was demonstrated by bleeding off 300 psi on the casing, causing a 25-psi drill pipe-pressure decrease. To keep the casing pressure as low as possible, gas was bled from the casing annulus until fluid was observed at the surface. Thereafter, the casing pressure could not be further reduced.
Circulation-Kill Attempt
Heavy mud was pumped down the drill string to control bottomhole pressure and to circulate gas out of the well. Without an accurate value for the bottomhole pressure, the proposed kill-mud weight was 13.3 lbm/gal, based on the mud hydrostatic pressure and the shut-in casing pressure but neglecting the height of the gas in the annulus.
After pumping began, drill pipe pressure dropped to 0 psi. Consequently, the choke had to be adjusted without a reference value for drill pipe pressure. The choke position was kept constant, adjusted only when annulus pressure increased. Mud losses were difficult to quantify, and the well was shut in when the rig ran out of mud.
During the mud buildup, temperature and pressure logs were run to the depth of the downhole motor in the bottomhole assembly. These logs indicated the fluid level was around 4,216 ft and the pressure at 11,411 ft total depth was 4,630 psi.
The temperature log detected disturbance around 5,600 ft, which corresponded to the depth of the Tournasian formation. The log response was interpreted as fluid movement. The repeat section of the log corroborated the crossflow at the Tournasian formation at the same depth where losses were experienced in drilling.
Annulus-Pressure-Control Attempt
Because drill pipe pressure was 0 psi, there was no reference for operating the choke. It was decided to maintain constant annulus pressure or allow it to decrease. Four LCM pills were pumped. As the first pill reached the thief zone, the losses decreased to zero. Subsequently, the pit levels increased, indicating slight gains. The volume pumped and the time when the LCM reached the surface indicated the hole was in gauge.
Once the losses were reduced to a minimum, the pump rate was increased and the choke was opened slightly to counteract the vacuum effect on the drill pipe. However, the mud level in the drill pipe dropped continuously.
When the choke opened to 1/16 in., casing pressure dropped more than expected. This jeopardized the control of the influx from the Emsian formation. The pumps were stopped, and after a few minutes, the drill pipe pressure began to increase. An influx of gas appeared to migrate inside the string, prompting the pipe to be displaced with 13.3-lbm/gal mud.
The well response indicated gas remained in the annulus, and the integrity of the Tournasian formation was still low. The kill operation resumed, and 239 bbl of 12.1-lbm/gal mud were pumped ahead of the 13.3-lbm/gal mud. The 12.1-lbm/gal mud did not reach the Tournasian formation. Consequently, the pressure in front of the weak zone at the Tournasian formation was minimized. At that point, more LCM pills were pumped.
While making repairs to the mud-gas separator, additional influxes entered the wellbore. When pumping restarted, pressure peaks suggested partial plugging of the ports in the circulation sub. As a precaution, no further LCM was pumped.
The drilling log reflects the sequence of events of an underground blowout and the well control operations that occurred in Algeria in December 2008.Low-Choke Attempt
Changes in the annulus pressure after shutting in the well indicated that there was still a small amount of gas in the annulus or at least above the Tournasian formation. The “low-choke” method was used, attempting to control the influx from the kick zone at the bottom of the well while allowing the loss zone to deplete to a lower pressure. The basis was to hold the choke pressure equal to or slightly greater than the last recorded shut-in value while circulating as fast as safely possible. The mud density was designed to sufficiently overbalance the kick zone.
An 11.6-lbm/gal mud provided 50-psi hydrostatic pressure, in addition to annulus friction-pressure overbalance to the kick zone. The choke pressure was calculated using the casing pressure observed at the beginning of the operation, with an additional 200-psi safety factor added. The circulating rate used was as fast as the surface equipment would allow. Sixty-three bbl of 12.2-lbm/gal mud were pumped into the annulus.
An increase in drill pipe pressure suggested the presence of gas inside the pipe. The operation was stopped when bottoms-up volumes from the Tournasian and the Emsian formations were observed at the surface, and the crew prepared to reduce the annulus pressure. Operations resumed after the drill pipe was filled.
The well was monitored, and the casing pressure was bled off 100 psi to test communication between the annulus and the drill pipe. An unexpected 200-psi increase in drill pipe pressure occurred, indicating there were now two different pressure systems partially isolated by one or more packoffs in the annulus.
Once the bottoms-up volume from the Emsian formation reached surface, the choke was opened at separate intervals to bleed off 200 psi. Four intervals were needed to reduce the casing pressure to 500 psi. Because it was difficult to keep the casing pressure stable, it was decided to fully open the choke, allowing the casing pressure to rapidly bleed off to 0 psi. No returns were recorded at surface.
The pump rate was increased without result, except for a brief increase in pipe pressure, which suggested a restriction or packoff was present in the annulus. A total of 110 bbl of mud, along with 60 bbl of water, was pumped down the annulus to compensate for the fluid-level drop. The calculated fluid level was 1,371 ft.
Once pumping into the annulus stopped and the casing pressure dropped to 0 psi, the blowout preventer was opened to monitor the well. Because of the possibility of pipe plugging and annulus packoff, the pipe was worked. Five feet of pipe movement was gained, but rotation was impossible. The well was shut in with the annular preventer when mud overflowed at the bell nipple.
An attempt was made to establish circulation. Initially, the casing pressure rose very quickly to more than 3,000 psi. On the second attempt, the drill pipe pressure increased from 1,800 psi to 3,500 psi after pumping only 31 bbl of mud. With an entire drill pipe capacity of 187 bbl, this indicated the pipe was plugged. Further, the casing pressure did not reflect the pressure changes. It was concluded that one or more packoffs were present in the annulus.
An unsuccessful attempt was made to break the packoffs by pumping down the annulus. Subsequent efforts focused on bleeding off the annulus pressure and attempting to work the pipe to free the drill string, and a “lubricate and bleed” method was attempted. Large amounts of gas were recorded at surface, resulting in the annulus pressure dropping to 0 psi, and losses were also recorded. After filling up the hole with 13.3-lbm/gal mud and water, the well again began to flow. A 50-bbl mud cap using a 13.3-lbm/gal high-viscosity pill was pumped down the annulus but was unsuccessful in preventing gas from percolating to the surface.
When the annulus was bled off and the mud level was confirmed to be at surface, the pipe was worked. The drill string was torqued-up and continued to be worked. The string did not become free, moving 8 ft upward without releasing any torque.
The pipe was completely stuck, and circulation was impossible. The operator abandoned the drilled section of the well. The inside of the drill string was killed by isolating the inside diameter with cement or mechanical plugs. The drill string was perforated as deeply as possible to isolate the annulus using cement. A coiled-tubing unit was then used to cut the drill string, and the Tournasian formation was allowed to unload.
Lessons Learned
• The Tournasian partial mud-loss event occurred because the formation permeability and porosity were high to allow loss of whole mud (natural losses). This was evident by treating the losses with LCM. It is recommended that an open-hole formation integrity test (FIT) be performed after repairing the loss zone and regaining circulation. This helps ensure the wellbore pressure integrity is equivalent to the FIT recorded at the last shoe depth.
• If leak-off occurs before the equivalent shoe FIT is reached, wellbore maximum allowable surface pressure and kick tolerance should be recalculated at the loss-zone depth to accommodate the downgraded FIT.
• If creditable formation-pressure data is not available, the heaviest kill-mud weight possible should be used.
• Training in kick detection and BOP shut-in on all rigs is recommended.
The main lesson learned from this incident was the necessity for well-trained and experienced drilling crews and the importance of adequately sized mud-mixing and handling equipment.
The authors thank the management of Repsol Exploration and Boots & Coots for permission to present this paper.
This article is based on a presentation at the 2011 IADC Critical Issues Asia Pacific Conference & Exhibition, 23-24 November, Kuala Lumpur, Malaysia.
News Cuttings
Justin Hodges awarded for committee leadership
Joe Hurt (right), IADC regional vice president North America and lead staff land/HSE, presents Justin Hodges (left), director of safety, claims & risk at Hodges Trucking, with the IADC Committee Chairman’s plaque for leading the Rig Moving Committee from 2010 through 2011. Mr Hodges’ successor is Anthony Zacniewski, director of HSE at Bandera Drilling.
Geer named IADC regional director – ME & Africa
Dave Geer has joined IADC as regional director for the Middle East & Africa, responsible for coordinating and promoting the IADC’s activities in those regions.
Mr Geer has more than 34 years of experience in the drilling industry, including 15-plus years working offshore in several positions and 19 years in management positions in sales, project management and marine operations.
He has expertise in MODU operations, risk management, safety and loss control, regulations and contracts.
OOC awards recognize IADC SEMS work
Two IADC staff members were among 10 people who received recognition awards from the Offshore Operators Committee (OOC) on 7 December 2011 in recognition of their efforts and contributions in the development and rollout of the SEMS Toolkit last year. Thr
The Offshore Operators Committee recognized major contributors to the SEMS Toolkit on 7 December. Front row from left are Brenda Kelly and Julia Swindle, IADC; Milton Bell, ExxonMobil; and Bill Walker, Cobalt International Energy. Back row from left are Troy Nugent, Baker Hughes; Greg Duncan, ConocoPhillips; and Jeff Ostmeyer, Anadarko.ough an OOC task force and in cooperation with the Center for Offshore Safety (COS), the toolkit was developed to address consistency and compliance with new requirements by the US Bureau of Ocean Energy Management (BOEM), as well as their effective networking with other industry representatives.
IADC’s Dr Brenda Kelly, senior director of accreditation and certification, and Julia Swindle, industry compliance specialist, attended the ceremony to receive the awards from OOC chairperson Susan Hathcock, Anadarko Petroleum.
Dr Kelly’s contributions were her leadership of the Competence Subcommittee, development of the Knowledge and Skills Documentation Tool, contributions to the SEMS Compliance Readiness Worksheet and other tools, and speaking at a series of rollout conferences held in August and September last year. Ms Swindle contributed to review of all tools and provided administrative support of the entire SEMS Toolkit development effort. IADC has seconded Ms Swindle to work with the COS for one year to help with the initial establishment of the COS.
Besides Dr Kelly and Ms Swindle, other recipients of the award included Milton Bell, ExxonMobil; Greg Duncan, ConocoPhillips; Roger Molaison, BHP Billiton; Troy Nugent, Baker Hughes; Jeff Ostmeyer, Anadarko; Kim Parker, Hercules Offshore; Ruth Rodriguez, Delmar; and Bill Walker, Cobalt International Energy. Each recipient contributed significantly to the development of the tools in the toolkit, working with subcommittees and/or providing administrative support. A significant number of IADC member companies also contributed to the effort.
“The participants on the task force have my sincerest gratitude and respect for their leadership and contributions to the SEMS toolkit, which is of immeasurable value to our industry,” said Mr Ostmeyer, who led the toolkit development effort.
Currently, the OOC SEMS Subcommittee and its task groups have concluded their work with the public release of 8 SEMS Toolkit products. Tools developed were:
• Audit checklist;
• Contractor readiness tool;
• Matrix of regulatory required training for drilling, production and marine positions;
• SEMS orientation curriculum;
• Knowledge and skills documentation tool;
• Operator-contractor agree letter templates; and
• Definitions.
These tools are available on the IADC website.
The COS will adopt all tools and maintain them going forward, although a small team from the OOC SEMS Subcommittee continues to work with the COS in the development of the Auditor Certification Program.
Hendricks to lead Patterson-UTI upon Wall’s retirement
William Andrew Hendricks Jr will join Patterson-UTI Energy as chief operating officer on 2 April, the company announced today. Mr Hendricks comes from Schlumberger, where he has served since 2010 as president of the Drilling and Measurements division. In addition, Patterson-UTI announced that Doug Wall, president and chief executive officer, will retire later this year. It is expected that Mr Hendricks will assume the position of president and chief executive officer upon Mr Wall’s retirement.
“Andy’s vast experience successfully managing diverse businesses – businesses with technology and geographic challenges – demonstrate his ability to lead and manage. We believe this experience and leadership ability make him the right person to help us execute our current strategic plan of continuing to grow our two core businesses – land drilling and pressure pumping in North America,” Mark Siegel, Patterson-UTI chairman, said.
He said of Mr Wall’s retirement: “We greatly appreciate the excellent leadership that he has provided; during his tenure, our company has made enormous strides. Our APEX rig programs, which numbered six rigs when he arrived, now stand at 94 new APEX rigs. Within our overall fleet of approximately 330 marketable rigs, we now have approximately 150 that are highly capable of drilling shale and other unconventional plays. Moreover, during his tenure, we have more than quadrupled our pressure pumping fleet and significantly expanded the geographic footprint of our pressure pumping business.
Mr Wall will continue as CEO until his retirement later in the year and will remain as a consultant for two years to ensure a smooth transition
Mr Hendricks received a bachelor of science degree in petroleum engineering from Texas A&M University in 1987. He also completed executive finance training at IMD in Switzerland in 2008. Mr Hendricks started his career working for Ocean Drilling and Exploration Company as a roustabout and roughneck on the Ocean Spur jackup in the Gulf of Mexico.
Click here to watch IADC group VP/publisher Mike Killalea talk with Andy Hendricks at the 2012 IADC/SPE Drilling Conference in San Diego to discuss recently launched technologies.
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