Baker Hughes’ Hughes Christensen Kymera hybrid bit combines the strengths of roller cones and PDC fixed cutters to target hard, interbedded formations. The bit ranges from 8 1/2 in. to 28 in. and has been deployed in 16 countries and completed more than 385 runs.

By Joanne Liou, editorial coordinator

In the wellbore, drill bits lead the way through formations to achieve longer wells more efficiently and quickly. The latest developments in drill bits share a common goal: optimize bit performance in the wellbore to save time and money. Coupling enhancements in bit design, material design and the manufacturing process, the results are consistently outperforming the previous generation. Baker Hughes, Halliburton, National Oilwell Varco (NOV), Smith Bits, Ulterra and Varel International capture some of their latest developments and improvements in drill bit technology.

Baker Hughes’ latest line of Hughes Christensen Talon PDC bits targets vertical, curve and lateral intervals with additional directional features, making it particularly suitable for the Rockies area. The bit has been launched in two basins in the Rockies, where the Talon 3D will be released by Q3 this year. The 3D version includes more directional features to make it more suitable for curve or directional drilling.

This line of bits offers application-specific cutters. “We drill in different basins in the US, with different drilling parameters, different rock in each area – we have application-specific cutters to pick from to optimize drilling performance,” Matt Zolnowsky, Baker Hughes drill bits performance engineer, said. “We are improving ROP and distance drilled… This is step-change technology that will save drilling time.”

The steel-body design features an increased junk-slot volume to improve hydraulic efficiency with a shorter bit-to-bend dimension to improve steerability and build-rate

Baker Hughes’ Hughes Christensen Kymera bit is often used to troubleshoot wells struggling with issues such as high vibration or stick-slip, hard-interbedded formations or toolface control.

aggressiveness when necessary. Application-specific, polished cutters with superior bit body hardfacing “take these steel body bits to record footages at record ROPs,” Mr Zolnowsky said.

Data analysis is another major element of the new bit design. “We now have a very efficient way to look at foot- and time-based drilling data to help the operators optimize the drilling system,” Mr Zolnowsky explained. Data analysis reaches beyond the bit design and looks at the overall wellbore – the BHA, drill string and other operating parameters. “We hear varying stories from the rig and from the office regarding drilling performance, but looking at the actual data is the preferred source of information to optimize the system.”

In the Haynesville Shale in Bossier Parish, La., where horizontal lateral hole sections typically range between 4,000 ft and 5,000 ft, the Talon 3D 6 ^3/4- in. bit drilled an entire lateral section in one run and decreased section drilling time by 36 hrs earlier this year. The bit increased single-run footage by 53% and saved the operator more than $80,000 for the section. The new bit offered directional control, as well as increased junk slot area for enhanced hydraulic efficiency.

The Hughes Christensen Talon PDC bit features a steel-body design with increased junk-slot volume to improve hydraulic efficiency with a shorter bit-to-bend dimension to improve steerability and build-rate aggressiveness. This line of bits offers application-specific cutters and targets vertical, curve and lateral intervals.

Combining the strengths of roller cones and PDC fixed cutters into a single bit, Baker Hughes recently expanded its range of offerings for the Hughes Christensen Kymera hybrid bits from 8 ½ in. to 28 in., following successes with the 12 ½-in. Spanning 16 countries with more than 385 completed runs, the bit targets hard, interbedded formations, Alan Holliday, product manager, explained. “On the design side, Kymera has become a combination of the fast-moving action of the PDC combined with the smooth roll action of the TCI,” he said.

The bit is used to troubleshoot wells where operators struggle with specific issues. “There’s a dysfunction in the hole for us to be running a hybrid – either the problem is high vibration or stick-slip, hard-interbedded formation or toolface control,” Mr Holliday said.

In Q1 this year in Colombia, the 8 ½-in. Kymera bit drilled through 460 ft of hard conglomerate rock and 1,232 ft of interbedded claystone and shale. The bit drilled 33.5 ft/hr, and the ROP exceeded 290% compared with a competitor’s offset well drilled using a 12 ^1/4-in. bit, replacing two PDC bits and a three-cone bit.

Five key technologies found in Halliburton’s MegaForce fixed-cutter bit, which debuted at the 2012 OTC, are aimed at providing an edge in ROP and ability to drill longer intervals by using SelectCutter PDC technology. “An increase in abrasion resistance and impact resistance  allows the cutter to drill through different payzones,” Brad Dunbar, fixed cutter product manager, said. The thermal mechanical properties of the cutter are represented in the two materials that expand at different rates when exposed to heat. “Being able to control that thermal mechanical piece of the cutter really helps to keep the cutter from damaging itself under heat conditions,” he added.

Another key technology is the multilevel force balancing, which veers from what the industry has used in the past 25 years. Before the multilevel layout concept, there was a general force balancing across an entire cutting structure so that a transition from one rock type to another was not as smooth. The multilevel force balancing ensures a balance between the transition periods as result of the way the cutters are laid out on the profile of the bit. “We’re balancing not only the whole cutting structure, but in addition, we’re balancing the transition as those different cutter groups go through the different formations,” Mr Dunbar explained.

Halliburton’s MegaForce fixed-cutter bit (left) and SteelForce bit (right) both have enhanced micro-nozzles to improve the flow of fluids across the cutting structure. MegaForce features SelectCutter PDC technology designed to increase abrasion resistance and impact resistance, and SteelForce targets high-ROP applications in shale plays.

Improved matrix materials – tungsten carbide, powdered metal – offer more erosion and wear resistance to prevent damage or breakage to the cutting structure, and enhanced micro-nozzles help improve the flow of fluids across the cutting structure, according to Halliburton.

In a field trial from March to April this year in Uintah County, Utah,  a 7 ^7/8-in. bit  was used to increase footage by 31% and, at the same time, increased ROP by 20% on the same section, compared with an offset well about 100 meters away.

SteelForce, which was released in November 2011 and is more focused on high-ROP applications in shales and where particles do not have as much erosion properties, also features the enhanced micro-nozzles used in MegaForce. In the clay-intensive Haynesville Shale in East Texas and North Louisiana, this steel-body bit is often used because it does not ball up from cuttings. “Being able to get the fluid flow across the face of the bit where we need it is one big advantage,” Mr Dunbar stated.

An anti-balling coating is also applied to the steel through a heat treatment. “The outer layer of the steel turns the electrical conductivity of the steel into a negative charge. When you have a water-based mud and the particles in that mud are also negative, they start repelling each other,” he explained. “A build-up of a water surface on the bit face itself helps prevent balling through that process.”

Halliburton notes that SteelForce has been deployed to most shale plays across the US, as well as offshore GOM and in the Middle East for drilling through carbonates.

Combining the abrasion resistance of impregnated bits with the high ROP of PDCs, NOV’s FuseTek bit targets applications that transition from medium to hard rock strength.

National Oilwell Varco

To bridge the gap between PDC and impregnated drill bit applications, NOV launched the FuseTek line of drill bits in April. The bits combine the abrasion resistance of impregnated bits with the high ROP of PDC bits. “We’re targeting applications that transition from medium to hard rock strength, where you normally drill with PDC bits for 80% of the run and need the durability of impregnated bits or insert bits to complete the harder interval,” Alexis Garcia, product line manager for hard rock drill bits, said. “You would have hard stringers that don’t allow the cutting structure to survive; therefore, with FuseTek, durability of the cutter structure is enhanced to drill further and faster, without the need to trip out of hole to change the bit type.”

The primary PDC cutting structure is backed by impregnated material and infused into the matrix. “The impregnated material has the capability to be a secondary structure that engages to continue drilling as an impregnated bit once the PDCs begin to wear,” Mr Garcia explained. In conglomerate and hard cherty sections, the bit becomes more impact-resistant to extend the bit life and optimizes the exposure of the material to be engaged in the formation when the primary cutting structure starts wearing out.

“The initial benefit of PDC shearing cutting mechanism is then converted to a grinding method after it loses its geometry by abrasion,” he added.

In an ongoing onshore Congo application that began in  Q4 2011 involving sandstone, limestone, claystones and conglomerates, an 8 ½-in. FuseTek bit drilled 1,532 ft at an ROP of approximately 25 ft/hr. The interval was 26% longer than the previous best offset.

In a recent run in Nacogdoches, Texas, a cutting structure experienced typical damage – cutter spalling, chipping and breakage – through the Travis Peak formation. The same bit fitted with the HeliosImpact cutters experienced very little damage drilling through the formation and was pulled after reaching a depth of 10,700 ft.

NOV also expanded its cutter technologies with HeliosEdge and HeliosImpact cutters in May. HeliosEdge increases ROP with high-efficiency cutters while HeliosImpact increases impact resistance with high-durability cutters.

The thermal-resistance technology that is applied to the bit removes the cobalt that is initially used to assist the high-pressure, high-temperature manufacture process promoting  diamond-to-diamond bonding. During drilling, high frictional heat build-up on the cutting edge can generate temperatures that lead to thermal degradation of the cutter. “Diamond with cobalt binder will start to break down as it reaches 700°C, leading to cutter failure. Once the cobalt is removed from the cutting edge, the diamond itself can go to 1,200°C, providing increased durability to drill further and faster,” Tom Roberts, product line director for cutter technology, said.

HeliosEdge features altered-edge-geometry (AEG) technology integrated with thermal resistance technology. The AEG provides more efficient weight transfers, allowing faster ROP and lower cost per foot without compromising durability. The cutters  target low depth of cut, torque-limited applications and can drill at least 30% faster, Mr Roberts said. Earlier this year offshore Norway, an 8 ½-in. bit drilled 1,610 ft at an ROP of 170 ft/hr, then was re-run to drill 12,300 ft at 128 ft/hr to TD. The run reflected the bit’s high ROP in an abrasive formation and set a record in the field.

The HeliosImpact cutters are better suited to withstand edge chipping experienced in harsh interbedded applications, where impact and cutter overload are the predominant cutter failure mechanism. In laboratory tests, these cutters showed a 45% improvement in impact resistance compared with conventional premium cutters, Mr Roberts said. Recently, a 9.875-in. bit was run in Nacogdoches, Texas, with the HeliosImpact cutters. When the bit was brought to surface and compared with an offset, Mr Roberts said, it could be seen that the bit with he new cutters had experienced little damage drilling through the Travis Peak and was pulled after reaching a depth of 10,700 ft.

A Smith Bits engineer inspects the Spear shale-optimized steel-body PDC drill bit, available with ONYX II premium cutters. The bit has completed more than 4,000 runs in unconventional shale plays across North and South America, Europe and Asia. It features taller blades to create a more convex, bullet-shaped body, which increases the cuttings’ sweep around and from the bit face into the annulus. The cutters have been upgraded using a high-pressure, high-temperature manufacturing process of synthetic diamond.
Photo courtesy of Schlumberger

Smith Bits, a Schlumberger company

Since the March 2011 commercialization of the Spear steel-body PDC bit from Smith Bits, the bit has completed more than 4,000 runs  in unconventional shale plays across North and South America, Europe and Asia. The company continues to apply design enhancements, aiming to  outperform benchmarks set by the original design. “For the new generation Spear product, we concentrated our design on two main areas: the first was to really optimize the slot area between bit body and borehole to allow cuttings to flow to the annulus with the lowest resistance possible, and the second was to implement our new range of premium ONYX cutters. The results have been incredible,” Steve Segal, marketing & technology manager, explained.

The new design, which was field tested starting in Q4 2011, has been deployed in areas such as Argentina, Poland, Germany, Canada and China. It features taller blades to create a more convex, bullet-shaped body, which further increases the cuttings’ sweep around and from the bit face into the annulus. While the bit itself remains the same size, the taller blade is exposed to more volume for the cuttings. “A great deal of engineering, especially in the material and design of the blades have enabled us to make them much taller without compromising their integrity,” Mr Segal said.

Keeping cutters clean to ensure cleanliness and bite into new rock involves help from the placement of nozzles. Nozzles are embedded in the Spear body, which consequently creates a ledge where cuttings can accumulate and plug the nozzles – impacting the efficiency of hydraulics. The new bit design addresses the potential for accumulation by changing the body geometry around the nozzle, providing a channel for cuttings to escape – the shale evacuation channel, Mr Segal said. “We’ve noticed again further improvement in keeping all of the nozzles open to provide maximum hydraulic energy downhole.”

An anti-balling coating that has been used extensively in sticky-shale areas such as the Middle East is an available option to further prevent cuttings from sticking to the bit area and further assists in flushing away cuttings. “This proprietary material is electrochemically bonded to the outside of the bit to create a surface that repels shale particles,” Mr Segal said. “It allows for the shale cuttings to continue their journey from being drilled to the annulus without bonding and adhering to the drill bit. These measures really make a difference in improving the penetration rate and reducing problems associated with poor hydraulics.”

The ONYX II premium cutters in the Spear bit also have been upgraded using a high-pressure, high-temperature manufacturing process of synthetic diamond, Robert Ford, product commercialization manager, said. Using advances in manufacturing techniques that involve pressures exceeding 1 million psi and 1,000°F, the new material has improved wear resistance without sacrificing impact strength, he explained.

In the Louisiana Haynesville, the new-design 6 ¾-in. bit drilled more than 6,382 ft at 40 ft/hr earlier this year. The bit completed a tight curve and lateral section in one run, and based on median ROP, the bit was 40% faster than the original bit.

IDEAS, an integrated drill bit design platform that takes into account each element of the BHA in a 4D simulation, has allowed Smith Bits to create bits with application-specific enhancements without having to go through physical iterations and runs in customers’ wells. The company took the initial five- and six-blade design of the Spear bit and created a four-blade design using IDEAS, Mr Ford said. While fewer blades often equates to higher ROP, it also means durability and directional control might be compromised. To maintain both elements, “we used sophisticated computer modeling of the IDEAS platform – our virtual environment,” Mr Ford explained. “Rather than make hundreds of bits that are all different and trying to run them in customers’ wells to see how they react, we built a very detailed model of the downhole environment and perfected the design with customer input.”

The new four-blade, 8 ½-in. Spear bit designed for the Marcellus was deployed in late 2011. This was the first time the four-blade design was utilized in this application, and the bit drilled 5,764 ft in 42 hrs at a rate of 138 ft/hr, delivering an improvement of more than 40% based on the previous Spear designs. The bit maintained stability and steerablity for toolface control.

Ulterra’s LightSpeed process accelerates the deployment of new bits, such as the Midcon Granite Wash dull bit. The process was implemented in 2011 and helps to bring new technologies to commercialization within months.

Ulterra

To support the pace of development demonstrated in the drill bits market, Ulterra is working to accelerate the deployment of new bits, commercializing new technologies in a matter of months. Implemented in 2011, the LightSpeed process is founded on “the relationship you have with the PDC vendors themselves and particularly the ability to take a new cutter that looks exciting in the laboratory and have it tested in the field more rapidly than others,” Andy Murdock, director of PDC technologies, explained. Ulterra offers two families of PDC cutters: LightSpeed XTa and LightSpeed XTi. The first targets hard-rock and high-temperature drilling, particularly in shales, to improve abrasion resistance, and the latter targets extended-reach drilling applications to improve impact resistance. “We’ve been able to drill through formations that are a lot more difficult to drill, a lot deeper than we were able to drill. We are drilling 20% to 30% more footage in many applications than we were able to drill nine to 12 months ago,” Mr Murdock said.

Each cutter is developed for a specific application. Ulterra works with different vendors to source material that meets toughness criteria and customizes cutters to meet demands for abrasion resistance.

Using LightSpeed technology, the company’s 12 ¼ -in. U616M, six-bladed matrix PDC bit with 16-mm cutters set a footage record in the Granite Wash in western Oklahoma earlier this year. The bit drilled 7,065 ft from surface casing to 8,115 ft, saving the operator approximately $88,500 versus average offset wells, Matt Mumma, vice president of engineering, said.

The company’s 8 ¾-in. U616M, six-bladed matrix PDC bit with 16-mm cutters also set a record earlier this year in the Eagle Ford. From surface casing to TD, the bit drilled the vertical, curve and lateral intervals at 93 ft/hr in one run. The bit reached TD at 9,953 ft in 107 hrs and saved the operator approximately $133,000 versus average offset wells.

Left: Varel’s DuraTech steel-toothed bit series features updated hardmetal capable of withstanding stress when additional weight and greater RPMs are needed. To improve consistency, the company implemented quality control methods to the hardmetal during the manufacturing process. Right: Varel’s High Roller series, available as both TCI and steel-toothed designs, features redesigned head forgings and an enhanced bearing to improve the bits’ ability to handle high WOB and RPM. Bottom center: The High Roller series is treated with high energy tumbling, which is applied to cutters to alter surface attributes for better abrasion and impact resistance.

Varel

Despite the popularity of PDC bits today, roller-cones remain in high demand through the market. Varel International launched two roller-cone series within the last year to round out its product line between steel-toothed and TCI bits.

The DuraTech steel-toothed series, available from 3 ¾ to 13 ¾ in., features updated hardmetal capable of withstanding stress when additional weight and greater RPMs are needed. Updated manufacturing techniques reinforce a hardmetal to withstand impact, as well as abrasion, Karl Rose, field engineering manager – western hemisphere, explained. Varel introduced stringent quality control methods to the hardmetal because the application is completed by hand. The goal is to limit variations in the welding to improve consistency.

This series of bits has been deployed worldwide and has been most successful in GOM applications, the company said. The bits also have had successful runs in the Eagle Ford, the Rockies and the Barnett Shale.

The High Roller series, available from 14 ¾ to 17 ½ in. as both TCI and steel-toothed designs, features redesigned head forgings and an enhanced bearing. “The forging takes advantage of some of the better cleaning through hydraulics,” Mr Rose said, “streamlining some of the paths for fluid and cuttings to flow away from the face of the cutting structure.” The bearing is optimized to push the limits of handling high WOB and RPM applied to the bits. “As the rigs and equipment used on rigs continue to get bigger, stronger and provide more energy, all that still has to go through the drill bit. Bearings have to constantly be updated and improved in order to deal with and endure the energy levels that continue to increase.”

The grease reservoir system of this bit series also enhances flow of grease through the bearing. “As the bit is drilling, grease is able to circulate through the bearing to help keep it cool,” Mr Rose said. “The upgraded design greatly increases the grease  with the increase in size designed to match the demands of the bearing system.”

The series is also treated with high energy tumbling (HET). This treatment is not new but is being increasingly used because of the higher energy levels encountered by roller-cone bits. The HET process is applied to cutters to alter surface attributes for more abrasion and impact resistance. “While non-treated carbide inserts will show breakage, a bit with HET is able to prevent that breakage and just show wear,” Mr Rose said.

A customer’s need in the Middle East led to one of Varel’s biggest developments in the last year: a 44-in. steel-toothed, roller-cone bit. “A customer had the need for a large-diameter hole to be able to drill the top-hole section more efficiently without tripping,” Mr Rose explained. “In the past, either reamers or another kind of hole opener had to be used.” The three-cone bit that was developed for this application has six interchangeable carbide nozzles and is able to drill without having to go back and run a reamer behind it, which mitigates risk and reduces opportunities for error.

“For a hole that size, we’re obtaining ROP up to 30 ft/hr, which is fast for something that large, with footages over 800 ft drilled.”

Click here to view the embedded video.

By Joanne Liou, editorial coordinator

Mærsk Mc-Kinney Møller, photographed in 2003 next to a painting of his father, died on 16 April. He was 98.

Mærsk Mc-Kinney Møller, a businessman and philanthropist whose business spanned multiple continents and industries, from Europe to North America, from the airline industry to oil and gas, died 16 April in Copenhagen at the age of 98. Mr Mc-Kinney Møller began to cultivate the A.P. Moller – Maersk Group into the multinational conglomerate that it is today in the 1930s, when he began to work for his father, A.P. Møller.

Mr Mc-Kinney Møller became co-owner of Firmaet A.P. Møller, the managing owner/legal representative of the Mærsk Group in 1940. After his father died in 1965, Mr Mc-Kinney Møller inherited the leadership role as director and chairman of the major companies in the Maersk Group.

As Mr Mc-Kinney Møller transformed his family’s shipping company, Maersk Line, into the world’s largest ocean carrier, his business endeavors expanded beyond shipping. In 1969, Maersk Air offered flights in Denmark and extended its operations to international, charter and cargo services until it was sold in 2005. In 1970, to support IT projects and operation within the Maersk Group, Mærsk Data was established and was sold to IBM in 2004. Knowledge and experience from exploration activities in Maersk Oil led to the establishment of Maersk Drilling in 1972.

Maersk Oil and Maersk Drilling sponsored the first IADC Well Control Conference in Esbjerg, Denmark, 1990, and the drilling division is actively involved in several IADC committees. Maersk was one of the first non-US offshore contractor members of IADC and was influential in the globalization of IADC in the 1990s and continues to play a positive role, Jens Hoffmark, IADC vice president – European operations, said. Mr Hoffmark retired from Maersk Drilling in 2009, after 42 years with the company. His most recent assignment was vice president – business development.

“(Mr McKinney-Møller) was a remarkable man, whose primary core value of his employees was uprightness – a very hard concept to measure in our digital era but an attribute readily recognized in Maersk employees and executives,” Mr Hoffmark said.

This year marks the 40th anniversary of Maersk Drilling. The company is increasingly focused on the ultra deepwater market. “We are working to double our fleet and hire 3,000 new employees by 2016. I’m proud to be part of this adventure – it started 40 years ago, yet one feels that we have only just begun,” Claus V. Hemmingsen, CEO of Maersk Drilling, said.

Mr Mc-Kinney Møller’s wife of 65 years, Emma, died in 2005. He is survived by three daughters, Ane Maersk Mc-Kinney Uggla, Leise Maersk Mc-Kinney Møller and Kirsten Mc-Kinney Møller Olufsen.

Buccaneer Energy acquires Glacier #1 Drilling Rig

Buccaneer Energy has acquired Glacier #1 Drilling Rig from Glacier Drilling Co, a subsidiary of Marathon Oil. Buccaneer purchased the rig for $7.5 million. The Glacier Rig is a Mesa 1000 carrier-mounted land drilling rig.  It was built in 2000 and can drill to depths of approximately 12,000 ft. The rig’s small size is ideal for pad drilling.

Mark Burns, Ensco

Burns to succeed Chadwick as Ensco executive VP, COO

Mark Burns, Ensco senior VP – Western Hemisphere, will replace William Chadwick as the company’s executive vice president and COO following Mr Chadwick’s retirement on 31 August. “Mark is a natural leader and an outstanding executive who is respected throughout our industry,” said Dan Rabun, chairman, president and CEO. Mr Burns was named IADC Contractor of the Year in 2007.

CARBO to construct proppant plant in Georgia

CARBO Ceramics will begin construction on a ceramic proppant manufacturing plant in Millen, Ga., by the end of 2012, and operations could begin near the end of 2013. Initial staffing for the plant should create 70 jobs in Jenkins County and bring as many as 300 construction jobs to the area during assembly of the plant.

Weatherford acquires completion tools company

Weatherford International recently acquired Petrowell, a company specializing in the design, engineering, manufacturing and testing of completion tools.

The acquisition bolsters Weatherford’s completions offering and enhances the company’s ability to provide interventionless technology and to tailor the completion geometry.

MaxX thread protectors

MSI opens manufacturing facility in Houston

MSI Oilfield Products opened a new 136,000-sq-ft thread protector manufacturing facility in Houston on 15 May. The facility features injection press capability machines, high cavitation mod bases, with additional tooling capabilities that are meant to increase production rates. The facility also incorporates MSI’s headquarters offices and room for warehousing.

PRODUCTS

NeoScope sourceless LWD service reduces risk

Schlumberger’s NeoScope sourceless logging-while-drilling formation evaluation service saved a customer seven days by eliminating the need for chemical sources.

Schlumberger’s NeoScope sourceless logging-while-drilling formation evaluation service, based on pulsed neutron generator technology, eliminates the need for chemical sources. The service provides real-time measurements close to the bit to guide interpretation and decision-making. The service was used to acquire a suite of petrophysical measurements in a directional exploration well in Africa, where poor borehole conditions prevented wireline tools from reaching the entire interval. The measurements helped save seven days by eliminating time and cost associated with chemical source deployment.

Halliburton expands line of downhole drilling motors

Halliburton has introduced the SperryDrill XL/XLS and GeoForce XL/XLS series motors to its fleet of positive displacement drilling motors.

SperryDrill and GeoForce XL/XLS offer downhole drilling motor technology for harsh drilling conditions and special applications, such as air, extended-reach and high-temperature drilling.

Baker Hughes’ casing packer remotely creates barrier

Baker Hughes’ ZX-e Electronically Actuated Casing Packer remotely creates a mechanical barrier to flow paths during wellbore construction, completion, production and abandonment operations, while a wireless top drive cement head handles heavy casing strings and remotely launches plugs, balls and darts.

The ZX-e remote actuated casing packer features an electronic trigger mechanism and sets the packer without pressure or pipe manipulation. The packer creates a gas-tight barrier between casing strings for critical applications and is the first to use a modular electronic trigger mechanism.

BOP with interchangeable LMRP increases rig flexibility

To enhance offshore rig flexibility and availability, GE has developed a BOP stack with an interchangeable lower marine riser package and lower stack frames. GE’s stacking system can land on any type of stack, which provides advantages when there are multiple stacked solutions that are custom fit. The BOP has been deployed in the GOM and West Africa regions.

Well completion system suitable for 12,500 differential environments

Superior Energy Services recently signed a contract with Anadarko to implement its Hydraulic Actuated Well Completion System. The system is fully integrated with Superior’s sand face tools. It gives customers the ability to complete, produce and remotely control multiple zones without well intervention.

The latest developed system is suited for 12,500 differential environments. The packer is hydraulically set and retrievable while the sliding sleeves are remote hydraulically operated.

Portable frac sand plant

CEMCO, McLanahan offer portable frac sand plant

McLanahan Corp and CEMCO have produced a portable frac sand plant. The portable plant offers an economical, efficient means for the production of two sizes of frac sand used in oil and natural gas drilling applications. The plant is easily transported from one deposit site to the next, enabling frac sand mining at multiple locations.

The plant allows for high volume production without the need to own and operate multiple stationary plants and obtain building permits.

James Watson, director, US Bureau of Safety and Environmental Enforcement

As anyone who works on the Outer Continental Shelf knows, offshore safety is everyone’s responsibility. Every company, every worker, every day. At this year’s Offshore Technology Conference, I unveiled the slogan my bureau adopted that embodies this vision: Safety at All Levels, at All Times. This phrase is much more than a slogan. It is our guiding principle.

Safety must be ever-present in all phases of offshore operations, not just when an inspector is present. It must affect every function, permeate every process and influence every decision. It must be culturally grounded in, and owned by, each individual involved in the operation. It is to this end that we are focusing our efforts and setting our priorities for the coming months.

We have made great strides during the past two years in enhancing safety standards, strengthening regulations and bolstering our inspector work force, but there is more work to do if we are to keep pace with a dynamic and cutting-edge industry.

We need to build and sustain the organizational, technical and intellectual capacity that keeps pace with technological improvements, innovates in regulation and enforcement, and reduces risk through systemic assessment. And we must continue to use the full range of authorities, policies and tools available to us to compel safety and environmental responsibility in all aspects of offshore energy exploration and development.

We are finalizing the Drilling Safety Rule and enhancements to the Safety and Environmental Management Systems (SEMS) Rule. We recently held a public forum to discuss next-generation technology for blowout preventers, and we are hard at work developing regulations to enhance the reliability of those critical systems. We are also working on a proposed rule to update the regulations for production safety systems. We are investing in training, hiring additional engineers and inspectors, and modernizing our Information Technology infrastructure to improve the efficiency of our operations. We are working with industry and interested stakeholders throughout the country to ensure we are focusing on all critical safety components and that we continue to track and adapt to the ever-changing technologies being employed by the industry.

Our engineers and inspectors are among the world’s leading experts in offshore energy development, and they are committed to public service. We are all passionate about offshore safety, but we can only do so much. We can promote a culture of safety that goes well beyond a checklist and measures performance, but we cannot instill that culture in offshore workers. Everyone in the industry, at all levels – from the CEOs to the companymen to the deckhands – must take ownership of their own safety.

This responsibility extends to contractors. We are holding everyone accountable for their actions, and contractors play a key role in the safety of offshore operations. Safety begins and ends with each and every person involved in offshore energy exploration and development.

This continues to be an important moment for our nation’s energy future. The President is committed to the responsible development of our nation’s offshore energy resources, and to do that, we must work together to create a strong safety culture. At the end of the day, we all agree that no amount of oil or natural gas is worth losing a single life. I am very pleased to see a renewed focus on safety from the industry, and I am committed to working with everyone on these efforts, but I am equally committed to pushing the oil and gas industry to live up to what has been promised: the development of an industry with a robust safety culture that truly embodies the concept that safety is the responsibility of everyone at all levels and at all times.

By Neil Ross, Tim Scaife and Robin Macmillan, National Oilwell Varco; Per Cato Berg, Statoil; James Jenner, Coupler Developments

Figure 1: In the Kristin S-2-H subsea well offshore Norway, a high-pressure zone below a depleted reservoir was drilled using the CCS to maintain uninterrupted circulation and a steady ECD to stay within the pore pressure/fracture pressure gradient window.

To construct new wells and continue production, Statoil decided to include the Continuous Circulation System (CCS) on the Kvitebjørn field of the North Sea. The CCS allows drill pipe connections to be made up or broken out without stopping drilling fluid circulation to the drill string. Uninterrupted circulation is particularly beneficial when drilling pressure-sensitive formations where adding or removing the dynamic component of the circulating pressure destabilizes pressure conditions in the wellbore, causing hole problems, lost time and additional costs.

The core of the CCS is a pressure vessel constructed from three blowout preventer (BOP) bodies surmounted by a snubbing device, which can apply sufficient torque to make or break drill pipe connections and control the vertical movement of the disconnected drill pipe against the circulating pressure. The pressure vessel (Main Unit) contains three sets of rams, blind in the center and pipe rams top and bottom, the lower set being upside-down to contain pressure from above. When in use, the Main Unit is located on the rotary table with the drill string passing through it. To make or break a connection while continuing to circulate, the drill string is landed in slips connected to the Main Unit, and the pipe rams are closed, isolating the tooljoint before filling the cavity between the rams with drilling fluid at circulating pressure.

The snubber then breaks the connection and allows the pin to rise under control before closing the blind rams. Circulation continues through the open drill pipe box below the blind rams and is closed to the top drive before bleeding off the pressure above the blind rams and opening the upper pipe rams to allow the next stand/joint of pipe to be picked up. The procedure is reversed to make the new connection.

The principle attributes of the CCS are:

• Only one modification to the rig is required to install the system;

• No changes or additions to the drill string are needed;

• All connection operations are safely confined within a pressure container constructed from conventional blowout preventer components; and

• The connection process is “hands off.”

The CCS can be used on any rig equipped with a top drive and with sufficient height clearance within the derrick to allow a drill pipe stand to be raised 3 meters above the rotary table for access into or withdrawal from the Main Unit.

It can be used to drill with open annulus returns or in conjunction with managed pressure drilling (MPD) rotating BOP, closed annulus systems.

The earliest commercial application of the CCS was the successful re-entry and deepening of a high-pressure gas discovery well offshore Egypt in 2005, (SPE 102859). Since then it has found application in re-entering and deepening high-pressure, high-temperature (HPHT) gas wells offshore Norway for two major operators and is being introduced to drilling operations offshore Brazil.

Figure 2: The main components of the CCS – the Main Unit, the mud diverter skid, the control container and the control panel – are essentially standard for all installations. The top drive interface is another essential component and is picked up and installed when the CCS is located on the rig floor over the well.

The Kvitebjørn Field

The gas/condensate field is located in the Norwegian sector of the northern North Sea, southeast of the Gullfaks field. It has been developed from a platform in a water depth of 190 meters. The HPHT reservoir comprises Mid-Jurassic Brent and lower Jurassic Cook sandstones with the top at approximately 4,070 meters TVD. The initial reservoir pore pressure was 775 bar (11,237 psi) and formation fracture pressure 875 bar (12,685 psi), but pressure depletion induced by early production resulted in the convergence of pore and fracture pressure gradients.

After drilling nine development wells, a pressure reduction of more than 140 bar (2,030 psi) had occurred, and circulation could not be maintained when drilling through the reservoir. Massive losses were experienced while drilling the 34/11-A-2 well, and further drilling was suspended as it was no longer possible to safely drill the reservoir.

Production was reduced by 50% in December 2006 and completely shut down in May 2007 when depletion reached nearly 200 bar (2,900 psi).

To construct new wells and continue production from the field, a Statoil drilling team reviewed the situation and established an MPD program to safely drill the reservoir. As a member of the joint industry project that supported the development of the CCS, Statoil decided to include the system in the MPD “toolbox” that resulted, together with pressure control while drilling (PCWD) equipment (rotating BOP, automatic annulus choke control), hydraulic flow modeling, designer mud system, etc (SPE/IADC 114484).

Including the CCS would enable two important parameters to be controlled by maintaining uninterrupted circulation during connections. Having established the dynamic circulating pressure or equivalent circulating density (ECD) required to achieve the bottomhole pressure (BHP) required to safely drill in the reduced pore pressure/fracture pressure gradient window, maintaining it during connections would be critical to avoid loss of circulation and/or high-pressure gas influx.

The downhole hydraulic stability would also maintain a stable circulating fluid temperature profile, which was expected to improve the monitoring and detection of trends in other drilling fluid circulation parameters. Continuous circulation would also eliminate the negative and positive pressure surges generated when stopping/starting circulation to make connections conventionally. These pressure surges can create BHP fluctuations and hole problems in HPHT wells.

After drilling the reservoir section in MPD mode, tripping out of the hole could be safely managed only if an overbalance on the BHP could be maintained. A caesium/potassium (Cs/K) formate mud pill (BMP) was developed to support a weighted mud column placed above the lighter drilling fluid. The drill string could be circulated approximately two-thirds of the way out of the hole using the CCS, before displacing this isolation pill and then circulating heavier mud into position above it to maintain the necessary safe BHP.

After displacing the heavier mud to the well, the CCS could be down rigged, and normal tripping operations can be resumed. The reverse routine would apply when running in with a new BHA.

Following the successful re-entry of the Port Fouad Marine Deep well offshore Egypt, the CCS was used by Statoil to re-enter and deepen the Kristin S-2-H subsea well offshore Norway in March/April 2006 using the Scarabeo 5 semisubmersible. A high-pressure zone below a depleted reservoir was drilled using only the CCS to maintain uninterrupted circulation and a steady ECD to stay within the pore pressure/fracture pressure gradient window (Figure 1). With a mud weight of 1.98 sg, an ECD of 2.06 to 2.13 sg was maintained while circulating at 250-380 gals/min (950-1,440 L/min) and 3,000-3,800 psi (207-262 bar) with no annulus control.

Some 216 meters of 8 ½-in. hole were drilled to a TD of 5,362-meters MD. During the drilling operation, 151 connections were made while drilling and reaming without interrupting the circulation of fluid to the wellbore. The success of this operation and the experience gained helped to establish the CCS with Statoil as a viable and reliable drilling tool.

Figure 3: Mud weight and circulating profile for well Kvitebjørn 34/11-A-13 were based on known pressure data from previously drilled wells where the pressure gradient declined from 1.92 sg at the top of the reservoir to 1.82 sg at the base.

The next stage was the inclusion of the CCS in the MPD planning for the Kvitebjørn wells. This occupied approximately two years, during which engineering studies and extensive testing of the MPD package were carried out to ensure the compatibility of all the technologies involved. Hazard identification and hazard operability studies were also conducted together with regular meetings with Norway’s Petroleum Safety Authority to keep it advised and gain its support.

Trials of the BMP and the CCS were carried out at the Ullrig facility in Stavanger prior to offshore operations.

Installation of the MPD package on the small, automated Kvitebjørn platform required careful planning, and considerable effort was expended on commissioning and testing the systems. For the CCS, the main components were as shown in Figure 2 and are essentially standard for all installations. The main items are:

• The Main Unit, which is located over the rotary table when in use. When offline, a set-back, servicing and testing area is required, which must be accessible by a rig crane;

• The mud diverter manifold (MDM), which can be located anywhere convenient for connection to the high-pressure mud delivery line between the mud pumps and the standpipe manifold. An isolation manifold in the high-pressure mud line for connection to the MDM is the main modification to the rig required for the CCS. High-pressure flexible hoses connect the MDM to the CCS;

• Control container and high-pressure power unit. This houses the computer control system and the hydraulic fluid power supply for the system and can be located anywhere from which the hydraulic hoses and fibre-optic cables can be safely run to the rig floor; and

• Control panel located at the driller’s position, from where the CCS is operated.

The other essential components – the extension saver sub and top drive interface – are picked up and installed when the CCS is located on the rig floor over the well.

Prior to commencing an operation with the CCS, it is essential that a survey of the rig/platform is carried out before planning the layout of the components and where hydraulic control hoses, cables and high-pressure mud hoses can be safely positioned to minimize tripping hazards, pinch points, etc. This was particularly important because of the small size of the Kvitebjørn platform and the space required for the PCWD equipment. After installation and testing, time was allocated to familiarize and train the drilling crew on operations with the PCWD and CCS equipment.

In addition to the equipment, four/five personnel were required to service and operate the CCS on a two per 12-hr shift rotation, plus supervisor. This had an impact on the available rig accommodation.

After completing the tests at the Ullrig facility, Kvitebjørn 34/11-A-13 was the first well on which MPD was used (SPE/IADC 114484). After being synchronized with the rig operating systems, the CCS performed reliably as part of the MPD package. Considerable time was devoted to training the drilling crews on operations with the combined MPD installation and CCS before starting drilling. This included rigging up the CCS over the well and making and breaking connections with no circulation; dry connections, before starting circulation and repeating the process with live drilling fluid in the system. The CCS was finally employed once the BHA had been run and washed to bottom in open hole and the MPD drilling parameters had been established while circulating the Cs/K drilling fluid. The mud weight and circulating profile were based on the known pressure data from the previously drilled wells where the pressure gradient declined from 1.92 sg at the top of the reservoir to 1.82 sg at the base (Figure 3). The objective was to start drilling with an ECD of 1.94 sg and maintain this 0.02-sg margin over the measured pore pressure as the reservoir was penetrated.

To enable this, formation pressure while drilling and ECD measurement were included in the MWD suite in the BHA.

The reservoir was successfully drilled from 6,101-meters MD to 6,351-meters MD. With the combination of MPD and MWD tools, the ECD was accurately measured, allowing the mud weight to be reduced from 1.84 sg to 1.81 sg and still maintain the margin of 0.02 sg over the reservoir pressure.

Figure 4: Throughout the operation on well Kvitebjørn 34/11-A-13, 222 connections were made with the CCS in an average of 32 min, including connections made for training. Without training times, operational connections were approximately 20 to 25 min.

While drilling the reservoir, a wash-out was detected, and the drill string parted while being pulled under MPD conditions. With the CCS in place, it was possible to continue circulating and control the well while displacing a 2.12-sg BMP at approximately 1,800 meters to establish hydrostatic balance while conducting fishing operations.

After recovering the fish, drilling resumed and TD was reached without further incident while maintaining an ECD of 1.92 sg with a combination of PCWD and the CCS. The average drilling parameters were 1,000 L/min (265 gal/min) circulating rate and 100 RPM with a rotary torque of 45-58 KNm (33,000-43,000 ft-lbs). The annulus choke pressure was 14-16 bar (200-230 psi) with a circulating rate of 580 L/min (150 gal/min) from the auxiliary pump.

Formation pressures varied throughout the reservoir, with a maximum depletion of 124 bar (1,800 psi) in the lower Ness Formation. At TD, an overbalanced mud system was circulated into place to control the well prior to completion activities, including running a liner.

As an integral part of the MPD package, the CCS performed well throughout the section and made connections without interrupting circulation. A tapered drill string of 4 ½-in. and 5-in. OD drill pipe was used in anticipation of encountering high rotary torque. The CCS only operated on the 5-in. OD pipe and routinely made up and broke out connections with up to 63 KNm (46,000 ft-lbs) of torque. During the connection process, the standpipe pressure fluctuated by around 6 bar (85 psi), mainly due to repressurizing the fluid in the upper chamber of the Main Unit from the standpipe after making a connection. This was reflected in a variation downhole of less than 2 bar (30 psi).

Throughout the operation, detailed records of CCS performance were kept by the operations team, including examples of typical connection time graphs (Figure 4) and circulating pressure profiles in the standpipe and lower CCS chamber (Figure 5). In addition, each connection made or broken was logged by the CCS operator and records kept of any issues arising, actions taken and of spares and other consumables used during the operation. All this information was made available to Statoil.

During drilling operations on the A-13 well, 222 connections were made with the CCS in an average time of 32 min, which included connections made for training purposes. Discounting training times, operational connections were in the 20-25 min range. Connection time is measured from the time drilling ceases until it can be resumed. While it may seem long by conventional standards, it is partially affected by the operating speed of the rig’s pipe-handling system.

When used to drill complex HPHT wells, such as on the Kvitebjørn field, the ability to maintain the established downhole circulating pressure environment while making connections is of prime importance, not the time taken. Conventionally, with the pressure surges experienced when stopping and starting circulation and the loss of the ECD, it could take even longer to make a connection in pressure-sensitive formations or even prove impossible to safely drill such a hole section.

Following the success of MPD operations on A-13, the system was used to drill the A-12 well in October/November 2007. Statoil has continued to develop the Kvitebjørn field using MPD to drill the depleted reservoir in wells A-3 in 2008, A-9 in 2009, A-7 in 2010 and A-1 in 2011.

During February/March 2008, the CCS alone was again deployed by Statoil on the Scarabeo 5 semi to drill the reservoir section of the Kristin N-2H well. Drilling with continuous circulation without annulus control and using the data from MWD logging tools, the ECD was used to keep the well under control, avoiding loss of circulation to the depleted zones in the reservoir.

Typically when drilling the 8 ½-in. hole and circulating at 1,000 L/min (265 gal/min), an ECD of 2.05 sg could be maintained with a static mud weight of 1.96 sg. At TD, the drill string was pulled with continuous circulation into the last casing shoe before displacing heavier 1.98-sg mud to the casing to maintain the BHP before down-rigging the CCS and tripping normally.

Continuous circulation technology was used by ConocoPhillips on the Eldfisk B-01 well (November 2010) and Eldfisk A-27 well (June 2011). With the CCS, a stable pressure environment and constant ECD was maintained to drill and underream the reservoir section. No annulus control was used, and the wells were displaced to heavier mud at TD before running casing.

In operations over a period of more than six years, the benefits of drilling pressure-sensitive formations with uninterrupted circulation have been demonstrated. The CCS has been regularly used, both with MPD equipment and on its own, to maintain a steady ECD when drilling formations with narrow pore pressure/fracture pressure gradients. The only significant modification since its introduction was the increase in the torque capacity of the snubber to handle 5 ^7/8-in. XT drill pipe and the increased height of the Main Unit necessitated by the additional spaceout between the rams to accommodate the extra length of the tooljoints.

For future operations, a way must be found to reduce the time taken to install and rig-up/rig-down the system. This is essentially a planning and logistics problem, depending on the layout of the rig or platform and the other coincident activities. The control system must also be developed with the objective of automating and speeding up the sequence of operations involved in the connection process. For long-term use, integration with the rig’s control system should be investigated, which in turn should reduce the number of personnel needed to operate the system, particularly when deployed on offshore installations.

This article is based on SPE/IADC 156899, “Use of the Continuous Circulation System on the Kvitebjørn Field,” presented at the 2012 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference, 20-21 March, Milan, Italy.

 By Peter Cooke, Columbus McKinnon

If there is any doubt about the safety of the equipment or lift, stop the hoist, lower the load and report the condition to the supervisor. All lifting operations should be conducted so that no one will be injured if there is an equipment failure, and pre-planning a lift with everyone involved will ensure proper equipment and personnel are in place.

All too often, hoisting-related accidents in North America could have been prevented simply by properly training operators on the operation, safe rigging, inspection and maintenance procedures of the hoist. Training of equipment operators isn’t just the smart thing to do; it’s a requirement. Training should not be looked upon as an additional cost but as a means to reduce overall costs by reducing the number of injuries and product malfunctions, as well as increasing productivity. Whenever there’s a lifting task, the job should be done right, from the initial inspection to the end of the lifting operation.

Before starting a lift, all PPE normally required for a work area should be used, including eye, hand and/or hearing protection. In addition, any time a load is lifted higher than 5 ft, there is a greater risk of a head injury. This can be minimized by wearing a hard hat. Others involved in the lifting operation, such as riggers and spotters, should also wear head protection if the load is to be lifted 5 ft or higher.

Operators should perform a pre-operation inspection and preparation procedures to identify potential problems, prevent accidents and enhance the safety of the work environment. For hand hoist and lever tools, consult ASME B30.16 (underhung hoist) and ASME B30.21 (lever tools). Make sure the hoist is not tagged with an out-of-order sign.

Next, a visual inspection of the hooks, chain, wire rope or synthetic straps should be performed. Check for broken wires, damage to chain such as cracks, nicks, gouges, wear and stretch, kinks, twists and latches on hooks for proper function. Per ASME B30.16, all hoists must be equipped with a safety latch that is working properly unless the application makes the use of a latch impractical as determined by a qualified person.

It should also be checked if the hoist is properly reeved. All warning and safety labels must be present and legible. Make sure there are no signs of oil leakage on the hoist and on the floor beneath the hoist. The work area should also be clear of any accumulation of materials to prevent tripping or slipping. Additionally, check for poor lighting.

After a visual inspection, test-run the hoist with no load. Run the hoist all the way up and all the way down. If any unusual sounds can be heard coming from the hoist, report it immediately and tag the hoist out of service.

Be sure that the hoist stopping distance is normal and there is not excessive drift. This can be accomplished by lifting a light load, use 50 lbs/load bearing parts of chain (reeving) for hand hoists and 100 lbs/load bearing parts of chain for lever tools. This will ensure the brake is operating properly.

Two prime causes of accidents are overloading and poor rigging, so attention should always be paid to the hoist’s lifting capacity. Under no circumstance can the total weight to be lifted exceed the hoist’s capacity. Further, never lift a load where the weight is uncertain. Load weights can be found in manufacturers’ catalogs, drawings, bills of lading, steel manuals or labeled on the load itself. Weight can also be obtained using a dynamometer, crane scale or weight scales.

If there is no other means to determine the weight, it can be calculated. Consult a rigging handbook or engineer to help determine and calculate the weight of an object.

The hoist’s constraints should also be well understood. Pay attention to the pull to lift full-load values. Each hoist is designed to lift under the power of one person. It should not take two people to pull on a hand chain or lever arm, nor to put an extender on a lever tool (cheater bar). This is a sure sign the hoist is overloaded.

If it takes 58 lbs of pull force to raise 1 ton, any pull force over this value will overload the hoist. Consult the manufacturer’s specifications and train the equipment operators on what each pull force should be. Many US hoist manufacturers (and some manufacturers outside the US) offer overload protection devices for hand-powered hoists, either as standard equipment or as an added-cost option. This device protects the user, the overhead structure and the hoist from an excessive overload condition.

Equipment operators should perform a pre-operation inspection to identify potential problems, prevent accidents and enhance the safety of the work environment. This sample checklist can be used before a hoisting operation. After completing the checklist, a visual inspection followed by a test-run will provide added safety for everyone who will be involved in the lift.

Several hoist manufactures use a friction-type, clutched hub as a part of the hoist’s chain wheel or lever arm. When the pull on the lever or hand chain is great enough to slip the clutch and prevent the load from being lifted, the operator becomes aware that the hoist is overloaded.

Use proper rigging techniques when lifting loads. Rigging training for the operator is important. Rigging handbooks and proper equipment should be readily available to ensure a safe lift. If there is any doubt about the safety of the equipment or lift, stop the hoist, lower the load and report the condition to the supervisor.

Conduct all lifting operations so that no one will be injured if there is an equipment failure. Use proper hand signals and communication with all workers involved with the lift. Pre-planning a lift with everyone involved will ensure proper equipment and personnel are in place.

The following is a review of very basic safe rigging practices:

• When rigging, make sure the load hook and the upper suspension form a straight line.

• The chain or body of the hoist should never come in contact with the load.

• Never tip load hooks.

• Always use a sling or lifting device to rig around loads, and use engineered lift points for attachment.

• Never work under suspended loads or lift loads over people.

• Never lift people with a hoist.

• When leaving the hoist unattended, land any attached loads.

• When the job is complete, place hoist or hook location in a place that will not interfere with the movement of people or materials.

When you’re at the controls of a hoist, you’ve got a lot of responsibility in your hands. Your co-workers are counting on you to use skill, good judgment and common sense.

By Katie Mazerov, contributing editor

Baker Hughes believes that service companies are seeing a migration from traditional hydraulic IWS to systems with electric valves and components for a higher level of functionality. However, not every well can justify the cost of an electric system.

Fifteen years after the first intelligent well system (IWS) was installed in Norway, the application is finally stepping out of its high-end niche and gaining broad recognition as the game-changer it was designed to be. While multizone completions in deepwater and unconventional reservoirs are driving innovation, intelligent well systems are also emerging as valuable tools for mainstream and even low-end markets, including mature and brown fields, for flow control, zone isolation and permanent monitoring.

As oil prices remain high, operators who once viewed intelligent well technology as simply an intervention-avoidance tool are seeing its benefit as a reservoir management and optimization system and including the technology in their well completion plans.

“With continued demand for petroleum energy and political uncertainty in areas that produce the majority of the world’s oil, most operators are looking for oil in more challenging and demanding places, such as deepwater,” said Savio Saldanha, senior product manager of Intelligent Flow Control, Halliburton’s Completion Tools business line. “With significant investment stakes in such high-risk environments, operators are looking to intelligent well completions (IWC) to not only help constrain capital spending but to maximize reservoir productivity.”

With the increase in reliability, market acceptance of intelligent completions technology is growing. “More and more operators are wanting to implement this technology to various segments of the completion market,” Mr Saldanha said. He estimates the industry has installed roughly 1,000 IWCs since 1997, with Halliburton responsible for 550 of those using its SmartWell system intelligent completion technology. By 2008, the company had installed 41 deepwater IWCs; that number has increased to 111 and is growing.

Intelligent completion is now an integral part of any deepwater development, and so much so that, in deepwater plays such as the Gulf of Mexico’s (GOM) Lower Tertiary Formation, characterized by continuous zones as long as 3,000 ft, operators are looking to IWC technology to help produce these expansive reservoirs as multizone completions.

“A certain amount of technological innovation will be required in these areas as operators consider integrating intelligent completions with sand-control technology, with the intent of completing the reservoirs in a single trip or a few trips, as opposed to multiple trips,” he added. The GOM’s high-pressure, high-temperature (HPHT) conditions are also fostering innovation.

Besides deepwater, IWC systems also can help improve the economics in unconventional reserves. “For example, we’re looking at how intelligent completion systems, such as the sSteam valve, can assist in steam-assisted gravity draining operations by allowing for uniform placement of steam across the wellbore to help produce the reserves more economically,” Mr Saldanha said.

Halliburton is looking at how intelligent completions, such as its sSteam valve, can enhance steam-assisted gravity draining applications by allowing for uniform placement of steam across the wellbore to help produce the reserves more economically.

For the unconventional market where frac stimulation is required, Halliburton has designed a frac valve that will allow multiple zones to be stimulated selectively with no intervention from the surface. Where the artificial lift market is concerned, the company is looking at running intelligent completion technology in electric submersible pump (ESP) wells. “ESP pumps need to be replaced periodically,” he explained. “To avoid pulling the entire completion, we have designed a disconnect tool that allows us to keep the lower intelligent completion in the hole and just retrieve the ESP pump and replace it.”

But the greatest potential for intelligent completion technology is in the overall reservoir optimization process, an area the industry has not yet fully embraced, Mr Saldanha believes. “The correct implementation of an intelligent completion system can deliver substantial benefits,” he said. “An IW system does not deliver maximum benefit unless it is included as part of the optimization process. This involves feeding critical data, such as temperature, pressure and flow rates provided by the IW system back into a reservoir management software to achieve an even workflow process that will allow operators to maximize every drop of oil.”

Another growing arena for IW technology lies in extreme reservoir contact and maximum reservoir contact wells in high-volume fields, explained Joseph Eck, product line manager for Intelligent Completions at Schlumberger. “The driver behind this and other applications beyond the deepwater sector is recovery,” he said. “Many in the industry focus on production – get it now, get it faster – but for operators really pushing IW technologies, the goal is to extract a higher percentage of oil and gas from the reservoir than they were able to do previously.”

Over the past two years, Schlumberger has focused on advancing cost-effective technologies for multistage completions for a range of offshore and land applications. These include the development of downhole wet mates for hydraulic and electric power and communications, enabling deployment of IW systems in the lower zone that connect back to surface when running the upper completion. Bandwidth limitations have led Schlumberger to develop technologies in subsea controls specific to IW systems, enabling subsea integration that goes beyond the standard subsea and controls architecture.

“We have a roadmap that looks well into the future to determine what we need to develop both short- and long-term to bring value to customers and bring recovery up to a high level,” Mr Eck noted. “We’ve expanded the sensing ability of these intelligent completion systems because often, the sensing was done above the IW systems. Now, with some of the new systems in the field, we are looking to expand the sensing into the laterals and the mother bore in combination with flow control devices.”

Schlumberger believes that its IntelliZone Compact modular zonal management system is a key development; it is a fully integrated flow control system for multizone wells that provides an alternative to sliding sleeves and conventional flow control completion systems. The system integrates a flow control valve, a packer, an optional pressure and temperature monitoring system with valve-position sensing, and an optional multidrop module.

Halliburton believes that its SmartWell system intelligent completion technology accounts for more than half of the roughly 1,000 intelligent well completions installed in the industry since 1997.

“The excessive need for customization and lack of a common well architecture have made the cost of IW systems artificially high,” Mr Eck said. “With integrated platforms such as IntelliZone Compact, the cost reliability/value quotient is more advantageous to operators. An integrated design allows these systems to be more industrialized – faster to design, faster to deliver and deploy. We’ve seen an increase in recovery between 1 ½ to 2 times the rate over conventional well designs with this system.”

The technology has been deployed in several countries across all continents and for diverse applications, including zonal control in conventionally commingled producers, selective zonal control for water shut-off, in-carbonate wells, replacement of mechanical intervention technologies, multizone extended well testing, selective water injection and lateral control in a tri-lateral well.

Where the industry has lagged is in developing integrated work flows for modeling pre-job and post-job analysis, Mr Eck maintains. “Pre-job issues revolve around understanding and predicting the value of IW systems. But the biggest gap involves the use and understanding of data to drive the value of these systems,” he continued. “This has consistently masked the true value of intelligent wells in what they can deliver.”

Stem-to-stern Solutions

Above and below: Schlumberger’s IntelliZone Compact modular zonal management system provides a streamlined alternative to sliding sleeves and conventional flow control completion systems. It integrates a flow control valve, a packer, an operational pressure and temperature monitoring system with valve-position sensing, and an optional multidrop module. In a tri-lateral well application (below), the system was installed with TRMAXX safety valve and QUANTUM packers.

By providing flow control, permanent monitoring and retrieval of downhole data for decision-making, intelligent well systems are taking the completion market from one of providing solutions for stabilizing the wellbore to one of managing the payzone, said Ricardo Tirado, production line manager, Intelligent Well Systems for Baker Hughes. “The benefits are significant in terms of capital expenditure savings, lower operating expenses and fewer wells drilled,” he said. “These systems can be controlled and monitored remotely, delivering stem-to-stern solutions that help operators better manage reservoirs and increase recovery.”

Baker Hughes has deployed its InForce hydraulic intelligent well system globally, including a marginal field that was discovered alongside a target reservoir in the North Sea. “The operator couldn’t justify the cost of dedicating another well to the smaller reservoir, but rather than leave it unproduced, drilled a multilateral well to intersect both reservoirs with one well,” Mr Tirado said. “We knew this smaller reservoir would produce water before the main one would, so we used the system to remotely isolate the problem zone so the operator could produce oil and avoid an intervention.”

But service companies are seeing a migration from traditional hydraulic IWS to systems with electric valves and components, which Baker Hughes is developing. “The level of functionality with electric systems is better than what we can achieve with hydraulic systems, but the economics are also different,” Mr Tirado explained. “Not every well can justify the cost of an electric system, which uses components borrowed from the aerospace industry.”

“Typically, hydraulic systems have multiple control lines coming through the wellhead, so we need the infrastructure to control those lines,” said Darrin Willauer, Baker Hughes product line director for Intelligent Production Systems. “In wells with three to five zones, that is often not an issue, but with the number of zones increasing to six zones — and some design plans calling for eight to 10 zones — the number of hydraulic lines becomes an issue. With electric completions, we can run multiple valves off a single line. In this way, some of the cost of installing an electric completion is offset by reducing the subsea infrastructure costs.”

Schlumberger’s IntelliZone Compact modular zonal management system

Electric IWS completions can be cost-effective for prolific, multizone wells in deepwater GOM reservoirs; however, operators are starting to show interest in using them to extend the life of mature onshore wells to delay water production or shut off water-producing zones, Mr Willauer noted.

Advances in fiber optics are bringing new monitoring capabilities to the industry, such as distributed temperature sensing along the entire length of a well. “We can measure temperature at 1- and 0.5-meter increments along the length of the well and use that information to determine where the flows are coming in,” he said. “During a hydraulic frac, we can use fiber optics to determine where the fluid is going into the well so we know where the fracture is occurring.”

New gauges, such as the SureSENS 175, provide accurate pressure and temperature data for temperatures up to 350°F. “For hotter environments, we’ve developed a portfolio of fiber-optic pressure/temperature gauges that can withstand temperatures higher than 450°F,” Mr Willauer said.

“Over the last several years, we’ve seen customers more willing to run sophisticated instrumentation like this on their wells to make decisions that result in better reservoir management and recovery,” he continued. “We need to understand how the reservoir is going to produce, then provide the right completion equipment to maximize recovery of a formation and provide downhole data in a way that allows our customers to take appropriate action.”

For 2011, contractors reported 2,947 recordable incidents and 838 lost-time incidents, including 18 fatalities. The largest percentage of fatalities occurred to workers who had between one and five years of service. Most of the reported victims were floormen.

The drilling industry’s worldwide lost-time incidence (LTI) rate dropped to a record low of 0.34 in 2011, an 11% improvement over the rate of 0.38 in 2010. Further, for the first time since the IADC Incident Statistics Program (ISP) was established 50 years ago, participating offshore contractors did not report any fatalities for the year.

Fatalities fell to 18, compared with 32 fatalities in 2010, and the 2011 fatality incidence rate declined from 2010’s 0.014 to 0.007. The recordables rates went from 1.31 to 1.17, which is 11% better than the 2010 report.

Long term, the industry’s efforts toward safety have resulted in the occupational LTI rate falling from more than 14.00 in 1963 to 0.34 in 2011, a 41-fold improvement.

A total of 101 contractors, representing approximately 78% of the worldwide oil and gas drilling rig fleet, participated in the 2011 ISP. The program has tracked safety and accident information for the drilling industry since 1962. The data presented accounts for 504.34 million manhours worked, during which a total of 838 LTIs and 2,947 recordable incidents were reported.

Incidence rates are calculated on incidents per 200,000 manhours. Data is compiled separately for land and offshore operations and for eight geographic regions — US, Europe, Canada, Africa, Middle East, Asia Pacific, Central America/Caribbean and South America.

The industry’s fatalities fell to 18 incidents in 2011, with the incidence rate at 0.007, compared with 2010’s 0.014. Employees with one to five years of service with the company accounted for six fatalities, making up the largest percentage. Fatalities of employees who had less than six months of service totaled five, and one victim had six months to a year of service. Three of the victims had worked for the company between five years to 10 years, and two victims had worked for the company for 10 years or more.

Employees with between one and five years of service had the highest number of LTIs and recordables, followed by those with zero to three months of service.

Four fatalities occurred during tripping operations and three during routine drilling operations. Six of the fatalities involved struck-by incidents while three were due to fall-type incidents. Seven of the fatalities occurred to floormen; five were supervisors of drillers or above.

09:00-16:00 hours was the leading category in lost-time injuries and recordable incidents by time of day.

In the European onshore and offshore categories, drilling contractors together worked more than 71.2 million manhours in 2011, with one fatality on land. Offshore workers accounted for 33.46 million manhours while land had 37.76 million manhours.

Caught-between incidents accounted for the most LTI and recordable incidents and was closely followed by struck-by incidents.

More than 136.71 million manhours were worked together by US land and offshore contractors, who reported a total of 11 fatalities. Onshore operations accounted for 99.24 million manhours worked with 11 fatalities. Offshore contractors worked 37.47 million manhours and had no fatalities.

The floorman position suffered the largest percentage of LTIs and recordables.

Canadian contractors had zero fatalities in 2011. Land workers reported 2.99 million manhours, and offshore workers reported 0.83 million manhours for a combined total of accounted for over 3.8 million manhours.

By month, July accounted for the most LTIs, while both July and August accounted for the highest numbers of recordable incidents.

The Central America and Caribbean region also had no fatalities. Combined, contractors accounted for 13.46 million manhours, with land operations working a reported 5.28 million manhours and offshore operations working 8.18 million manhours.

As in past years, by far the most injuries in drilling operations occurred on the rig floor.

Africa land and offshore together reported 52.94 million manhours with three fatalities. Onshore operations accounted for 24.68 million manhours with three fatalities while offshore had 28.26 million manhours and no fatalities.

Pipes/tubulars is the equipment category responsible for the most LTI and recordable incidents.

Contractors in the Middle East worked over 103.2 million manhours with one fatal incident. The land division had 71.27 million manhours and one fatality while the offshore division reported 31.94 million manhours and no fatalities.

Fingers are still the most vulnerable part of the body, statistics show.

Asia Pacific accounted for 61.4 million manhours and two fatalities. Offshore had 45.12 million manhours with no fatalities while onshore had 16.28 million manhours and two fatalities.

By activity, tripping in/out is the operation that involves the most LTI and recordable incidents and is followed closely by rig up/down and rig repairs.

South America made up 61.58 million manhours with no fatalities. Land operations had 42.18 million manhours while offshore operations had 19.40 million manhours.

Middle East offshore operations significantly improved its LTI rate in 2011 by 48%, going from 0.23 in 2010 to 0.12 last year. The region’s offshore recordables rate also went down by 32%, from 0.77 in 2010 to 0.52 in 2011. In onshore operations in the Middle East, however, the LTI rate worsened by 33% from 0.18 in 2010 to 0.24 last year, but their recordable incidence rate improved slightly from 0.86 in 2010 to 0.83 in 2011.

Africa’s onshore LTI rate also improved. For 2010, the rate was 0.39, which improved by 28% to 0.28 for 2011, and their recordable incidence rate improved by 23% from 1.16 in 2010 to 0.89 in 2011. Offshore workers in this region also saw an improvement in their LTI rate, by 8% from 0.25 in 2010 to 0.23 for 2011, and the offshore recordable incidence rate improved by 13% from 0.91 in 2010 to 0.79 in 2011.

In 2010, US land had an LTI rate of 1.02, which improved by 21% to 0.81 in 2011. Their 2010 recordable incidence rate of 3.44 improved by 17% to 2.87 in 2011. Offshore, the LTI rate improved 29% from 0.24 in 2010 to 0.17 in 2011, and their recordable incidence rate improved by 12% from 0.86 in 2010 to 0.76 in 2011.

South America’s onshore LTI rate for 2010 was 0.23, which improved by 26% to 0.17 for 2011, and their recordable incidence rate improved by 21% from 0.94 in 2010 to 0.74 in 2011. The offshore LTI rate went down by 21% from 0.39 in 2010 to 0.31 for 2011. The offshore recordable incidence rate also improved by 15% from 1.03 in 2010 to 0.88 last year.

The LTI rate among Asia Pacific offshore workers improved by 13% from 0.16 in 2010 to 0.14 in 2011, and the total recordable incidence rate improved by 9% from .67 in 2010 to 0.61 last year. Asia Pacific land workers’ LTI rate, however, worsened by 78% from 0.18 in 2010 to 0.32 in 2011, and their recordable incidence rate worsened 9% from 0.91 in 2010 to 0.99 last year.

Central America and Caribbean’s land 2010 LTI rate of 0.48 improved by 38% to 0.30 for 2011, but their recordable incidence rate of 0.89 for 2010 worsened by  19% to 1.06 for 2011. Offshore, Central America and Caribbean’s LTI rate worsened by 40%, going from 0.05 in 2010 to 0.07 in 2011. Their recordable incidence rate also worsened by 40% from 0.42 in 2010 to 0.59 for 2011.

In the European region, the offshore 2011 LTI rate worsened by 29% to 0.27, from 0.21 in 2010, and the 2011 recordable incidence rate also worsened 8% from 0.74 to 0.80. Europe onshore’s LTI rate also worsened by 32%, from 0.22 in 2010 to 0.29 in 2011, and their 2011 recordable incidence rate worsened by 29% from 0.31 to 0.40.

Canada land’s LTI rate for 2010 was 0.35, which more than tripled to 1.07 in 2011, and its recordable incidence rate of 2.29 worsened by 69% to 3.88 in 2011. Canada offshore saw a 2011 LTI rate of 0.24 worsen by 26% from 0.19 in 2010 and a recordable incidence rate of 0.48 in 2011 improve by 58% from 1.14 in 2010.

• By occupation, the floorman position suffered the largest percentage of injuries, similar to previous years.

• By body part, fingers remained the most vulnerable part of the body.

• By incident type, caught-between incidents accounted for the most incidents and was closely followed by struck-by injuries.

• By equipment, pipes/tubulars was the equipment category responsible for the most LTIs and recordable incidents.

• By activity, tripping in/out involved the most lost-time and recordable injuries.

• By location, by far the most injuries in drilling operations occurred on the rig floor.

• By time in service, employees with between one to five years of service had the most LTIs and recordables, followed by employees with six months to one year of service.

• By time of day, the most LTI and recordable incidents occurred between 09:00 to 16:00 hours.

• By month, June accounted for the most LTIs while August accounted for the most recordables.

Overall, most industry incidence rates improved in 2011, even with the increase in industry activity. Fingers remain the most vulnerable part of the body, and most injuries in drilling operations are still occurring on the rig floor, according to the available reports.

For more information about the IADC Incident Statistics Program or to participate, please visit the IADC website.

New Zealand HSE regulations revision

IADC has submitted comments to the New Zealand Department of Labour commenting on its review of the Health and Safety in Employment (Petroleum Exploration and Extraction) Regulations of 1999. The letter, sent by IADC VP – offshore technical and regulatory affairs Alan Spackman, noted that IADC intends to assess its HSE Case Guidelines for MODUs against the revised New Zealand regulatory requirements when they are promulgated. The IADC guidelines will be revised as appropriate, with a new section to assist members in assuring compliance.

IADC is among several industry organizations that the Irish Offshore Operators’ Association (IOOA) has recommended to meet with Ireland’s National Parks and Wildlife Service (NPWS), with the purpose of discussing proposals to protect marine mammals from man-made sound sources. The IOOA believes that the proposed changes are likely to result in drilling operations and seismic surveys taking substantially longer while offering little, if any, additional protection to marine life.

IOOA suggested that, before the Draft Guidance is finalized, a meeting with IADC, IOOA, OGP and the International Association of Geophysical Contractors be held. Interpretation and application of the Draft Guidance should be discussed, and alternative approaches to protect marine mammals should be explored.

Mr Spackman recently attended the 90th session the IMO Marine Safety Committee (MSC), where several actions were approved:

• The MSC has directed its Sub-Committee on Dangerous Goods, Solid Cargoes and Containers to develop amendments to the IMO MODU Codes to ensure that the provisions of the recently approved Safety of Life at Sea (SOLAS) regulations requiring periodic confined space rescue drills are extended to MODUs.

• The Marshall Islands, Vanuatu, IADC and the International Marine Contractors Association, the MSC has directed that the Sub-Committee on Standards of Training and Watchkeeping to revise Resolution A.891(21) on Recommendations on training of personnel on mobile offshore units.

• The MSC also directed the Sub-Committee on Ship Design and Equipment to develop amendments to MSC/Circ.645 on guidelines for vessels with dynamic positioning systems.

• In approving new SOLAS regulations aimed at prohibiting chemical processing onboard ships at sea, the committee also accepted amendments to the proposed regulation that exempted offshore oil industry vessels from the SOLAS amendments. Had the exemption not been included, the SOLAS regulations could have been interpreted to prohibit onboard mixing of downhole fluids and cements.

By Gregg Germer, ExxonMobil Canada East; Allen Verret, Offshore Operators Committee; Robert Watson, Seatrax Cranes; Larry Smith, Oil States Nautilus Cranes

Figure 1: A review of OCS lifting data from 2011 by the API Offshore Lifting Safety Data Workgroup shows that the overall number of incidents and injuries associated with lifting remained fairly flat compared with 2010 data.

The overall number of incidents and injuries on the Outer Continental Shelf (OCS) in 2011 associated with lifting has remained fairly flat compared with 2010 data, according to a review by the API Offshore Lifting Safety Data Workgroup (OLSDW). Further, it was found that training of personnel and following procedures – rather than equipment failures – are the elements that industry must focus on in order to further reduce incidents.

The OLSDW was organized in 2009 to analyze lifting data/incidents on the Outer Continental Shelf (OCS). It was tasked to comment on trends and lessons learned and to communicate its recommendations on safety improvements to the industry through the IADC, API, OOC, Bureau of Safety and Environmental Enforcement (BSEE) and the United States Coast Guard (USCG). The effort was driven by the industry and by the two regulatory agencies, BSEE and USCG.

The workgroup, which is composed of operators, drilling contractors, crane manufacturers, industry organizations (API, OOC, IADC), governmental bodies (BSEE, USCG), offshore vessel operators, and lifting device manufacturers, has now reviewed data from 2006 through 2011.

The general process for the review begins with all OLSDW members signing a confidentiality agreement due to the sensitive nature of the data provided by BSEE.  A “dump” of the raw data associated with lifting is sent to the OLSDW from BSEE’s database. A dedicated group of four people from the OLSDW then begin their review. The first pass on the data is reviewed at a high level to ensure the incidents provided by BSEE are lifting-related.

Once the list of incidents has been agreed upon, a more thorough review is done on each incident. The team searches for trends. It asks who is getting injured, what the causes are and what the contributing factors are. The data from each review are compared with the data from previous reviews to identify trends.

The OLSDW recently completed its review of 2011 lifting incidents. The good news is the overall number of incidents and injuries associated with lifting has remained fairly flat compared with 2010 data (Figure 1).  However, there were two fatalities associated with lifting in 2011, which clearly must be addressed.

As seen in Figure 2, employee failure and the load contacted/shifted remain the top causes for injuries for 2011. It is significant that equipment failure is not the main cause of the injuries. Injuries from equipment failures do occur, but given the causal pattern that has emerged, it is clear that training of personnel and ensuring procedures are followed must be emphasized to reduce incidents.

For 2011, there were no surprises as data showed that the rigger continues to be the person most likely to be injured and the hand the most likely body part injured.

Figure 2: Injuries from employee failure and load contacted/shifted remain top causes of lifting incidents/injuries on the OCS. It is significant that equipment failure is not the main cause – indicating that training of personnel and ensuring procedures are followed must be emphasized.

From a review of the 2011 data, the OLSDW is recommending that training continue to focus on riggers, with particular attention to the position of their body to the load and the placement of hands on the load being lifted. The OLSDW also recommends that riggers should minimize contact with the load.  The less contact with the load, the less potential there is for an injury.

In addition, the OLSDW recommends a crane operator refresher training on planning the load swing path to help prevent and minimize the number of loads coming in contact with objects and snagging. The continued and ongoing training of personnel is the best way to affect behavior to reduce/eliminate lifting injuries.

The final recommendation from the OLSDW is to implement a new reporting format. This will aid in the analysis of lifting incidents. In reviewing the data from BSEE, the OLSDW has noted that the information received from the operators consists of a very brief narrative of the incident. The kind and extent of details of the narrative can significantly vary from operator to operator.  The new reporting format, which the OLSDW has developed and is recommending to be used by all operators, will increase the consistency, quality and amount of information provided. This will yield better learnings and in turn reduce or eliminate lifting injuries. The new form can easily be attached to “eWell” when reporting back to BSEE.

The OLSDW’s goals are simple and direct: reduce or eliminate injuries associated with lifting incidents. This can only be achieved by operators, trade associations and regulators working together.  Through the API standards program – and based on recommendations from OLSDW – these stakeholders are now updating API Recommended Practice 2D on training, lift planning and JSAs.  BSEE supports the OLSDW by providing yearly lifting incident data.

API RP 2D 7th edition to address training for lifting operations personnel

By David Landry and Joe Sologub, API RP2D Technical Committee Co-chairs

In October 2010, a group of industry professionals met in New Orleans, La., to begin updating the sixth edition of API Recommended Practice 2D “Operations and Maintenance of Offshore Cranes.” The undertaking was intended to help address recommendations from the 2009 API Safe Lifting Task Group (SLTG). This article provides a brief summary of the changes that will be forthcoming in the seventh edition of API RP 2D when finalized.

The SLTG was a diverse group of personnel from both industry and regulatory arenas that was organized to address observations and concerns expressed by two regulatory agencies – the US Bureau of Safety and Environmental Enforcement (BSEE), formerly the Minerals Management Service (MMS), and the United States Coast Guard (USCG) – regarding industry lifting operations. The SLTG conducted a review of Outer Continental Shelf (OCS) incident data covering lifting operations from 1990 to 2009. However, the group primarily focused on data from 2006 to 2009 because of changes in MMS incident-reporting requirements that took place in 2006.

From their data review, the SLTG concluded that most incidents occurred when personnel were not following their training or established procedures and that the personnel getting hurt most frequently was the rigger.

As part of their efforts, the SLTG made numerous recommendations to three main groups: 1) operators, 2) trade associations and 3) regulators. Among recommendations to the trade association group was to update API RP 2D and that this update be directed toward rigger training, lift planning and job safety analysis (JSAs).

Since the April 2010 Macondo incident, the offshore industry landscape has changed significantly. The MMS is no longer a regulatory agency, and the issue of lifting operations now falls under the jurisdiction of BSEE and the USCG. BSEE has also implemented its Safety and Environmental Management Systems (SEMS) program, which also addresses some of the issues identified by the SLTG (e.g., JSAs).

At the conclusion of the October 2010 meeting, subcommittees were formed to work on updating/revising the various sections of the sixth edition of the RP. Several additions/new sections were originally proposed at the meeting. These included but were not limited to the following:  lift planning, JSAs, temporary cranes and offshore supply vessel (OSV) lifting operations

Since that meeting, there have been numerous meetings of the main committee to review and discuss the work of the subcommittees on their respective sections of the RP.  Some of the originally suggested additions to the recommended practice (e.g., JSAs) have been scaled back from what was originally proposed due to other regulatory coverage of these issues (e.g., SEMS).

Since October 2010, a considerable amount of work has been conducted by the subcommittees to formulate the technical information and language for the RP. There will be numerous changes in many sections of the forthcoming in the proposed seventh edition of the RP.

The most significant/controversial changes will revolve around the training required for personnel that are involved with lifting operations (e.g., crane operators, crane inspectors, riggers, etc.).  There will be more hands-on training and demonstration of competencies versus classroom training. This is an attempt to address the SLTG’s recommendations

The seventh edition is currently in its editorial phase; an editorial committee from the members of the committee has been formed and will begin formatting the document into its final draft so that the RP can be sent out for balloting.

Due to the addition of new sections, a considerable amount of administrative and formatting work has to be done to get the document into a finalized version.  It is hoped that the RP will be ready for balloting in late 2012 or early 2013.

This article is based on a presentation at the 2012 IADC Lifting & Mechanical Handling Conference & Exhibition, 18-19 July in Lafayette, La.

Against the changing backdrop of E&P regulation in the post-Macondo world and with shales capturing a skeptical public eye, we must as an industry unite on basic principles of governance and self-regulation. If industry is to sustain its license to drill and produce, it’s critical to collaborate and confront tough realities.

History has clearly demonstrated that a goal-setting regulatory philosophy leads to the safest operations. The 1988 explosion of the production platform Piper Alpha in the UK North Sea resulted in the landmark Cullen Report, whose recommendations culminated in the original safety case. IADC led in development of the safety case and, over time, has enhanced these tools and propagated them globally.

Regulators, industry and the public have mutual goals and interests in ensuring safe and environmentally responsible operations. Regulators should not be lapdogs, but neither need they be pit bulls: Tense relations between government and industry are contrary to the public’s best interests.

Industry must move forward with self-regulation and improved best practices, and so it is. The expansion of IADC’s Knowledge, Skills & Abilities competency guidelines (Page 20) is one key example.

We cannot craft sensible regulations nor best practices without a sound understanding of the nuances of the roles of each industry sector. For example, drilling contractors are basically well manufacturers, producing a product wholly designed by its customer, the operator. Drilling contractors are innocent of involvement in well planning and are absent any stake in subsurface reserves. Logically, contractors should not be liable for reservoir discharges, save for severe negligence. To hold contractors thus liable is a recipe for insurance cancellations and the potential demise of the industry.

Legal hassles also hinder safety.  Literally, fear of criminal prosecution has blocked some operators from sharing information about recent events that, if disseminated, would clearly help the industry. Criminal prosecution and arrests are a new, alarming step change beyond all-too-familiar civil litigation.

Another factoid is that politicians will be politicians – reactive and preening for the public. When politicians flex their muscles, it’s invariably a knee jerk. Witness the latest antics of the European Union, which is attempting what amounts to a power grab of pan-European E&P regulation. I suppose the EU is encouraged by its powerhouse performance in the financial sector!

This proposed North Sea EU-thanization is largely a post-Macondo Pavlovian response. But, if imposed, seasoned North Sea regulators – in the UK, Norway, Netherlands, Germany – will be subordinated to green EU bureaucrats.

In fairness, there is a case for uniformity. IADC some years ago worked closely with the regulators’ group North Sea Offshore Authorities Forum to harmonize training requirements across national borders. And in emerging Eastern Europe, regulators may benefit from the EU’s assistance. But one size doesn’t fit all. And sidelining skilled regulators is a poor way forward.

Magne Ognedal, chief of the Petroleum Safety Authority Norway, is such a seasoned regulator. Mr Ognedal, speaking on our Licence to Drill panel at IADC World Drilling 2012 (June, Barcelona), shed some light on the political hand wringing in Europe post-Macondo. The EU called for a moratorium, and the Norwegian regulator was duly queried on the topic by his ministers.

Mr Ognedal is far too polite and courtly to complain. But reading between the lines, it was obvious to me that significant political pressure descended upon him to endorse a drilling moratorium. But Magne Ognedal stood firm.

“I said I had no reason to close down,” Mr Ognedal related. “As a professional, I need a reason to close down. So my advice [was] to do nothing until we have discovered what went wrong and why. And this conversation went on for three months before the politicians calmed down. …

“I think they are very happy today that they didn’t do anything.”

Sometimes, what you really want is to not get what you want.