Often forgotten next to drilling, well servicing now attracts increasing investments to advance automation, HSE
By Katie Mazerov, contributing editor
With an estimated 168 billion bbls of oil in place, the prolific oil sands of Alberta and British Columbia have been a pivotal factor in Canada’s ranking as one of the world’s top oil-rich nations. Abundant with bitumen, with a typical well producing as much as 2,500 bbl/day of oil, many believe the SAGD (steam-assisted gravity drainage) market holds the future of oil for western Canada.
Oil sands bitumen is described as relatively immobile, with a consistency similar to very hard rubber. To extract it with SAGD technology, most operators drill a pair of identical wells, one on top of the other. Large volumes of steam are pumped into the upper injector well, allowing the bitumen to flow to the bottom of the reservoir, facilitating production out of the bottom well, typically a 3,000-ft (1,000-meters) horizontal producer.
From a well servicing standpoint, the process poses unique and difficult challenges. SAGD wells feature a relatively short vertical section, 1,000 ft (300 meters), necessitating the need to push pipe into the well. The wells also require artificial lift, facilitated by electric submersible pumps that need to be changed out every 18 months.
Such issues have spawned discussion about the need to change the game in well-servicing technology, such as with conventional hydraulic snubbing units that push pipe in SAGD wells. Existing service rigs also may lack the technology to effectively handle the large tubing strings used inside the 13 3/8-in. production casing strings and 9 5/8-in liner strings required for the large-bore SAGD wells.
In August, Suncor Energy launched a fully automated well servicing rig during field tests on its Firebag field in northern Alberta. Calling the new Legacy rig a “well-servicing multi-tool,” Dwight Bulloch, manager, completions operations for Suncor, said the rig’s ability to drill, change out tools and run coiled tubing in a very small footprint and portable package “brings an advantage in well servicing, potentially allowing the company to move onto a well and get rigged up and working all in the same day.”
“For at least the last 10 years, the industry has been talking about the need to move beyond what is considered outdated technology,” he said, adding that he believes there have not been any significant step-changes in well servicing in the past 50 years. That is changing, however, as operators continue to prioritize safety in well production.
Nabors Industries’ Millennium rig, a relatively new design being used primarily in the US land market, features multiple safety innovations. Baker Hughes’ new rigless intervention system, developed for the offshore sector, has a self-pinning mast erection system that also enhances safety.
While companies may debate the merits of proven methods versus cutting-edge technologies, they agree that a strong safety culture bolstered by education and training is essential to the success of any well servicing operation. “At the end of the day, if we see a wash as far as the operational costs and the Legacy rig is just as efficient as our current rigs but delivers a safer operation, we would still embrace this technology,” Mr Bulloch said.
Pulling, pushing pipe
The Legacy rig’s main function is to pull and push pipe through doglegs. Its rack-and-pinion system can push down pipe up to 35 decanewtons (daN), a unit of tensile strength. Some conventional snubbing units can push down only 9 daN. The Legacy system also allows the driller to finesse the pipe through the horizontal section, said Terry Bendera, president of Alberta-based ProStar Well Service, owner of the Legacy rig.
“Conventional rigs can work in the oil sands market doing pad drilling work, but they are not the ideal tool because they don’t provide all the necessary risk mitigation features,” he said. “From an engineering standpoint, they require the need to rig up to accommodate snubbing units to access difficult areas. With the Legacy rig, we are addressing the specific needs of the oil sands market, while being safer and more environmentally friendly.”
Compared with some conventional service rigs that can be as long as 27 meters (88 ft), Legacy is 12.5 meters (41 ft) long. This means a smaller footprint, plus more horsepower but less emissions. The pump is mounted on the rig, eliminating the need to bring in a separate pump truck. It also reduces the number of required connections from the well to the pump by 75%, Mr Bendera said.
“We believe this step-change represents the evolution in the way wells are brought into production,” he said. The compact size and mobility of the rig also make it applicable in US shale plays, he added, such as the Bakken, where lack of infrastructure remains a challenge.
Calgary-based Rangeland Drilling Automation designed the Legacy rig. “Well servicing has traditionally been the poor cousin compared to the drilling industry, which in turn has led to a serious lack of innovation,” said Matt Dagert, technical sales representative for Rangeland. “Down time is very expensive for oil companies, and when wells go down, it is up to the service rigs to put them back in production as safely and efficiently as possible. With this new rig, we have taken a lot of the technology from the drilling industry and made it smaller, faster and more compact to suit the needs of the service industry.”
Safety and versatility were key drivers in the development of the rig. “Operators are increasingly concerned about safety and are starting to push for safer and more innovative technologies in the service industry,” he said. “With innovation such as this, we’re able to increase efficiency and safety by controlling operations from a climate-controlled driller’s cabin, allowing for personnel to be off the rig floor, in turn reducing the risk of injury by minimizing hands-on contact with equipment.”
Established in 2006, Rangeland started out manufacturing automated catwalks for well service rigs, later expanding into other products, such as an automated wrench with torque-monitoring and data-logging capabilities and compact top drives. “This new rig marks the integration of all these features,” Mr Dagert noted. Because it is completely remote-operated, the rig can run with a three-man crew instead of the traditional five-man crew. The remote control system includes two 12-in. HMI (human-machine interface) screens and joysticks that allow the driller and assistant driller to operate and monitor all the equipment from the driller’s cabin.
In field tests, the rig is doing downhole pump changes. With the pump mounted on the rig, the driller can reverse-circulate to kill the well from the cabin. In addition, instead of a conventional block with links and elevators, the rig is equipped with a tool carrier from which various attachments can be connected, he said.
“To get the pipe through the thick oil sands, we’ve installed a tool called a wobble, which rotates 30° from center, maneuvering the pipe through bends that are very challenging.”
A millennial breakthrough
Stephen Johnson, executive vice president, production services for Nabors Completion & Production Services Co, acknowledged that the well servicing industry typically doesn’t see the kind of technological innovation that has advanced the drilling side of the business over the years. He believes one of the biggest well servicing rig design breakthroughs in the past 30 years has been the Millennium rig, which was introduced to the market in the mid-2000s.
“After listening to our customers, we designed this rig from the ground up to be safe,” he said. “We felt that if we could make a much safer piece of equipment, it ultimately would perform better, and that truly has played out.”
Initially designed for the ultra-deep vertical (20,000-ft or 6,096-meters) gas well market before the existence of current hydraulic fracturing technology, the rig was able to shift to the horizontal shale market and reach measured depths up to 20,000 ft (6,096 meters). The Millennium now has the highest utilization among Nabors’ well servicing fleet, with all 90 units working.
“From a design perspective, we performed a statistical analysis of where incidents had occurred on the rig and addressed that through value-engineering,” Mr Johnson said.
Features include an electrical control system with a programmable logic controller (PLC) that provides a hands-free feed-off mechanism. It precisely controls weight-on-bit for milling out plugs and packers. Additionally, the PLC monitors hook load and traveling block speed, which optimizes the functionality of the disc brake system. “This is not an option on a conventional mechanical rig,” he said.
The PLC, operated with a joystick instead of a mechanical brake handle, includes several built-in safety features, such as a mechanism to prevent the blocks from hitting the crown or floor of the rig. A hydraulically adjustable work floor allows the rig supervisor and crew to work on the same level. The work floor hydraulically folds up to the mast when work is completed. An air-cooled disc brake system has replaced the mechanical brake. The rig also is designed to position closer to pumping units that often have to be dismantled and is easily winterized and de-winterized.
“We’ve had this rig in the field for several years, and it has proven to be a very safe, efficient piece of equipment with a lot of the innovation customers are requesting,” Mr Johnson added. “We also have developed a rig that people enjoy working on. With turnover the way it is today, that means a lot.”
By Katie Mazerov, contributing editor
North America’s shift to unconventional reservoirs over the past decade continues to bring change and innovation to the well intervention business. The complexity of these wells are still increasing, evidenced by longer and deeper wellbores. This means that remedial and tried-and-true methods that serviced the conventional vertical market as recently as seven years ago are sometimes not adequate anymore. “The unconventional plays are very demanding in terms of size, length and overall footprint, and the well intervention sector needs to adapt to these new industry challenges,” Teoman Altinkopru, vice president, well intervention marketing and technology for Schlumberger, said. “These wells require advanced-capability surface units and completely different technologies that improve the economics and reduce nonproductive time (NPT) and intervention costs for operators. The technologies that succeed in the marketplace are the ones that bring capability and efficiency to the entire operation.”
Bigger coiled tubing (CT) sizes and digital tools that deliver real-time downhole data to improve the speed and accuracy of complex operations are key advances being deployed in North America. Schlumberger sees the North American unconventional market as, the biggest growth area for well intervention products and services, Mr Altinkopru said. “The Bakken, Eagle Ford and Permian Basin are exploding in terms of activity and growth.”
Whereas 1 ¼-in. or 1 ¾-in. CT with 16,000- to 17,000-ft strings were standard surface spreads six or seven years ago, these unconventional plays are now calling for 2 3/8-in. CT in excess of 20,000 ft, he pointed out. Schlumberger is also using a client feedback protocol to engineer further advances.
The Schlumberger ACTive family of live downhole CT services enables operators to acquire real-time downhole measurements in a variety of well configurations. “In the past, industry relied on surface indicators to understand what was going on downhole during an intervention operation,” Mr Altinkopru said. “But that approach doesn’t work in horizontal wells because, regardless of how much weight on the pipe, wire or conduit is being deployed in the horizontal section of the well, the surface weight does not increase.”
The service uses real-time casing collar locator and gamma ray measurements to correlate depth, temperature, tension and compression and pressure downhole for mechanical operations, such as deploying perforating guns. “For example, by providing wireline depth accuracy in CT operations, we can eliminate the need for a ‘dummy’ run to place the guns accurately, bringing a new level of efficiency to the operation,” Mr Altinkopru said.
In 2010, the ACTive system was deployed for a stimulation operation in an underperforming shale well in the Elk Hills Oilfield near Bakersfield, Calif. The technology was able to precisely calculate downhole conditions, including bottomhole pressure, based on true vertical depth to validate the quality of foamed fluids being pumped into the annulus. Engineers had previously estimated bottomhole pressure of 1,200 psi, but the system confirmed the pressure was actually 300 psi and revealed a much lower temperature at the perforated interval compared with the geothermal gradient. This difference meant reducing nitrogen gas rates to supply the required 70% foam quality during the diversion stage. The adjusted calculation saved the operator more than US $10,000 and five hours of NPT.
For slickline operations, the Schlumberger LIVE digital slickline service can log, perforate, set, seal and perform mechanical operations, such as fishing, with digital surface control and depth correlation. “For fishing jobs, for example, the service enables real-time data to be streamed to the surface using a digital downhole adjustable jar, D-Jar, on the same coated wire, ensuring efficiency, accuracy and consistency by reducing reliance on the skill and experience of the operator,” Mr Altinkopru said. “This allows us, in a controlled manner, to run slickline into the well, latch onto the fish using a pre-tensioned slickline cable to whatever weight is required, then send a command from the surface for D-Jar to release the fish.”
Solutions like these are also being deployed outside North America where conventional wells are becoming more complex, he said. “Unconventional production has not achieved the same momentum internationally as in North America, but wells are increasingly deep and extended. They look like North American wells, but they are conventional reservoirs.
“Wells worldwide are no longer the shallow, vertical designs industry has conventionally produced,” he continued. “Going forward, the complexity of today’s wells will require advanced technologies and services at a frequency that is higher than what industry has seen thus far.”
ACTive, LIVE and D-Jar are marks of Schlumberger.
Back to basics
For the conventional land market, older-design rigs with tried-and-true technology, such as standard braking systems, are still delivering results for many companies. Cloverleaf Well Service, launched in 2008 in Rock Springs, Wyo., went back to the basics in building its fleet. “These rigs perform well and don’t fail, which is what our customers want for workovers and maintenance,” said Jerry Chitwood, operations superintendent for Cloverleaf. The self-propelled rigs are 104 ft (32 meters) high, with 250,000-lb derricks and 500 hp and can be moved easily from well to well.
With a focus on gas wells, Cloverleaf has two service rigs working in southwestern Wyoming, including one in the Jonah gas field, and a rig on the Kenai Peninsula in Alaska. The rigs are being used primarily for workovers and well maintenance, such as fishing and tubing change-outs. “As the gas zones start depleting, they produce water, so we have to plug those zones to allow the gas to flow,” Mr Chitwood explained. A swabbing rig in the Jonah field is used to remove water from the production pipe, he said.
Cloverleaf also has ventured into the unconventional shale oil market, with a rig of the same design doing completions work in the Bakken, primarily drilling out frac plugs used in plug-and-perf operations. “This rig works 365 days a year, 24 hours a day,” Mr Chitwood said. “These wells also require a lot of clean-outs created from surrounding wells being fractured and communicating.” The situation occurs when sand and fluid being pumped at high pressures into a new well encroach into zones of a nearby producing well, he explained.
Mr Chitwood agrees that advanced well servicing technology is not happening at the rate it is occurring on the drilling side of the business. “On the well servicing side, automation and technology can actually have the reverse effect of slowing down the process because of the many tasks the rigs perform, such as setting and moving packers, fishing and clean-outs,” he said. “In terms of fishing, the operator needs to be able to feel or sense an object in the wellbore, using a brake handle.”
What has changed is the safety culture. “Today, it’s a rarity when someone gets hurt on a rig,” Mr Chitwood said. Cloverleaf’s training matrix and OSHA statistics are made available to operators. Insurers and regulators are starting to require that parameters be set, limiting the up and down movement of the blocks on the derrick, he noted. If a block exceeds the limit, either on the crown or floor of the derrick, the brake is automatically engaged. “If these measures save one person from being injured, it’s the right thing to do,” he said.
A rigless alternative
For the offshore arena, Aberdeen-based EFC Group has designed and manufactured the new Mastiff rigless intervention system (RIS) for Baker Hughes. The unit provides operators with an alternative method for carrying out pipe installation and retrieval operations, eliminating the need for a costly offshore rig and reducing the cost of abandonment, workover and drive pipe pre-installation operations.
“The self-erecting, self-pinning tower enhances safety by removing the requirement for workers manipulating loads and working at height,” said Bob Will, EFC chief executive. “The pre-spooled crown completely eliminates any manual handling of hoist cables.” The lightweight, modular unit has a working height of up to 100 ft (30 meters) and a 352-ton pulling capacity, he added. The system is capable of pulling 50-ft (15-meter) sections of 36-in. conductor pipe and cemented inner casing strings.
After the pipe is removed, the well slot can be prepared for a new, full-sized wellbore using equipment such as drive-pipe whipstocks and hammer services. A Baker Hughes Tubular Services sub-mudline drive pipe whipstock (SDW) allows an old wellbore to be plugged and abandoned and new drive pipe to be driven, making the platform slot available for the drilling of a new well.
Once the containerized RIS load is delivered to site, the unit can be rigged up or rigged down in hours. Baker Hughes is currently conducting a feasibility study, working with intervention vessels to allow more mobility and easier platform access of the unit for conductor (slot) installation and conductor slot recovery operations.
The industry is placing increasingly importance on providing formal ongoing education to ensure personnel competency in well control and well servicing operations, including completions and hydraulic workovers, said Barry Cooper, manager of business development for Well Control School.
“In our experience, companies with a strong, top-down safety culture that put a priority on training are more productive, safer and maintain lower insurance rates,” he said. “It is critical to understand what it takes to keep a well under control when servicing it with coiled tubing, wireline, snubbing or well completion operations,” Mr Cooper said. “That includes understanding and detecting kicks and learning how to avoid a blowout through effective management of fluids and pressures in order to maintain balance and control pressure. Our training increasingly concentrates more on well control safety barriers, specifically how safety barriers can prevent incidents.”
System 21, a web-based version of the school’s well control curriculum, was developed in 2008 to provide students with a more accessible, self-paced training program. Students are given a pre-test and a post-test for each training module; they must pass the post-test before moving on to the next module. Currently, 7,000 to 7,500 students register for training through the school each year, with roughly half opting to use System 21, which has greater appeal with younger workers entering the industry, Mr. Cooper said.
While North America continues to be Well Control School’s largest market, the company has seen growth worldwide in recent years due to increased awareness, a higher global well count and a heightened regulatory environment. Well Control School’s training curriculum is now used by students in 40 countries and is expanding into markets like Australia.
Millennium is a trademarked term of Nabors Industries.