Automating more of the oil & gas industry's processes will ultimately improve safety. So said several industry leaders during the recent Drilling & Completing Trouble Zones conference in Galveston, Texas. Jennifer Pallanich was there.
Baker Hughes' Allen Sinor, VP for global accounts, says the dynamics of population growth will place ever increasing demands on energy supply driving exploration into harsher and deeper environments. These environments have increased risk, which can be mitigated by using smart automations systems. In fact, the industry has begun to apply automation, but at a slower pace than other business segments. 'The digital age is truly becoming the age of automation,' he says. It makes sense, he adds, because people may not notice subtle changes critical to operations, but that a computer would. 'The question is where do you start taking control?'
Sinor notes the industry has had the ability to: collect, transmit and display data; simulate drilling ahead; automate drilling processes; and automate well control. These abilities, he notes, were documented in various SPE papers given nearly three decades ago. If the technology fundamentals were in place years ago, he questions why the industry is not fully using these technologies today, especially around well control, which is the most critical operation in offshore drilling and exploration.
He suggests the oil & gas sector borrows a page from the playbooks of other industries. The automotive industry is a playbook to study around R&D, where automation from manufacturing to driver assist and dynamic radar is gaining strides, he says. 'Take something as simple as cameras. It's amazing all the things that have cameras on them. Cruise ships may have 600, whereas a casino may have over 5000. Yet, our drilling rigs will have less than a half dozen, or none at all.' Sinor says. 'What if we could own the decisive moment before an incident, with the ability to play back the last moments before an incident would be helpful,' he says. 'Why don't we have an airplane black box?'
Hege Kverneland, corporate VP and CTO for NOV, urges proper training to ensure automation is used safely. 'If they put new technology out there and we don't know how to use it, we will use it wrong.'
Automation, she says, removes human error. 'We're not so smart all the time,' Kverneland notes, and there are varying levels of experience in the industry. Experience and competency are two reasons to automate, but economics and well consistency are others, she says.
'In my mind, our new, sophisticated modern drilling rigs are not automated,' Kverneland says. 'They are semi-automated, but mainly remotely operated from the driller's cabin.'
Another way to bolster safety levels is to simulate more activity. 'When we're going to drill a really difficult well, we need to have drilled it first in a simulator,' she says. But the simulation needs to be taken just as seriously as if the drill bit were actually cutting into the earth. As an airline representative once told her, 'We treat this [simulator] as the real world. If we mess up here, we mess up in the real world. Because if we mess up here, people die,' she says, adding that was good advice.
Staffing and experience remain key points in the industry. According to Chesapeake Energy Corp operations manager John Adcock: 'The job hopping that's going on creates the issues at our companies, and we're just shuffling the deck.' It's important to find out why people keep moving from one company to another, he adds. 'The things we manage, we understand. It's the people we manage that are the hardest part of a manager's job.'
Kevin Lacy, VP for global drilling & production at Talisman Energy, believes the oil & gas industry turns on people. 'The next breakthrough is not technical. I think it's the one that's going to address the people problem and the one that's going to address the leadership of the upstream companies,' he says.
Several companies delivered case histories revolving around trouble zone drilling & completions during the conference.
Baker Hughes offered two case histories on its low-flow low-pressure drop slimhole under reamer. Dean Enterline, the company's product manager for hole enlargement, says the tool was run four times in two different wells and proved successful compared to the industry's standard reamers in deepwater Gulf of Mexico. In the first case history, the operator had been pumping 14.2ppg syntheticbased mud with a rotary steerable system. The pumps were maxed out at 4250psi. The operator lost circulation and changed to water-based mud, so Baker Hughes suggested using the low-flow low-pressure drop 6in by 7in reamer tool to provide better flow characteristics at the same pump pressure for better bit cleaning. At the maximum recommended flow of 400g/min, the calculated pressure drop remained under 10 psi through the reamer, he says.
In the second case history, the operator experienced similar lost circulation. In this instance, the operator chose to reduce the flow rate to minimize loses of the synthetic mud. The blades were calculated to begin opening at 70g/min and were fully open at 113g/min. Enterline says it makes sense to use the tool in cases where the pressure limit is reached before the reamer is added; in deep wells or with small drillstrings; in hydraulically challenged wells with pump limitations; when extra flow is needed to improve hole cleaning, such as in a high-angle well; and when flow needs to be reduced because of lost returns.
In total, he says, the reamer has been used on 14 deepwater runs with 100% success. The runs have all been 72° inclination or less with a total of 18,747ft drilled and reamed, 614 hours of drilling and reaming, and 929 hours of circulating. The tool is available in 6in by 7in and 6.5in by 7.5in, but 'theoretically the technology to achieve the low flow low pressure characteristics are scalable to any size that's required', Enterline says.
Ron Hinkie, senior account leader at Halliburton, notes that hybrid swellable technology was recently deployed on a deepwater well in the Gulf of Mexico. There was no liner-top packer available for the casing and liner sizes. This left the operator with the option of either performing a liner-top squeeze after cementing, which can be costly, or using a swellable packer below the mechanical hanger, where uncertainty about the presence of oil or water could create some variability in the swelling time. Swellable rubber will swell in the presence of oil, while a swellable packer with salt embedded in the rubber will swell in the presence of water or oil.
Halliburton's solution was a hybrid swellable packer, says Hinkie. 'It will swell, seal and hold pressure using either oil or water. Earlier we were talking about automation. This is about as automated as you can get. You run it into the hole and nothing more needs to be done. Once it sees the fuel, it swells.'
For this well Halliburton, was asked to deliver a differential pressure of 3500psi, but opted instead to design the swellable packer for a higher differential pressure to accelerate the swell speed of the packer, Hinkie says. 'The time to the first seal was two days, and the packer supplied 8137psi within five days.' OE
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