The Prudhoe Bay oil field, 40 years old this year, has been an incubator for new technologies that have helped reshape the world’s oil industry.
None were so far-reaching - or hotly debated at the time - as horizontal drilling. But there were others, too.
Horizontal drilling was a radically new type of oil well, proved first commercially at Prudhoe Bay, and which helped pave the way for production of oil and gas from massive shale formations in the Lower 48.
At Prudhoe, however, the success of horizontal wells led to other breakthroughs, like drilling with lower-cost coiled tubing units for sidetrack wells, or wells drilled laterally, underground, from older well bores, as well as multilateral wells, where several wells are drilled underground from an older well.
These technologies have extended the economic life not only of Prudhoe but other North Slope fields.
“Horizontal and sidetrack drilling were a lifesaver for Prudhoe Bay,” said Dick Maskell, a retired BP drilling engineer, by allowing small pockets of oil previously bypassed to be commercially produced.
Prudhoe is now expected to ultimately produce 13 billion barrels or more compared with 9.6 billion barrels estimated when the field started production in 1977. New technology and new types of wells were crucial in adding reserves.
Other technologies
To be workable, however, horizontal drilling had to be matched with other new technologies developed outside Alaska but quickly imported to the state, such as measurement-while-drilling, or MWD, and its companion system, logging-while-drilling, or LWD.
These systems, along with new devices to control the direction of the drill bit underground, gave drillers at the surface virtual real-time data on where the drill bit was and what kind of rock it was drilling through. This is essential information if the well was to be guided with precision through thin layers of reservoir rock.
“Alaska was a leader in drilling horizontally in thin sands to develop wells that would otherwise be unproductive. But if the drillers cannot find out in real time which way the bottom hole assembly is drilling they cannot control the drill pipe,” said Greg Sarber, a BP well-site leader.
Most of the wells drilled now on the Slope, with both conventional rotary rigs and coiled-tubing, are horizontal, Sarber said. “No real-time measurement-while-drilling, no drilling program,” he said.
Horizontal drilling controversial
But horizontal drilling was highly controversial within BP in the mid-1980s when the company was preparing to try it at Prudhoe. It almost didn’t happen, at least for BP and on the North Slope, recalls Ted Stagg, a retired BP drilling engineer who supervised the project.
Old-school drillers and production managers at BP didn’t like the idea, he said. “They were very suspicious of any deviations over 62 degrees from vertical because they’d had too many bad experiences with stuck pipe,” Stagg remembers.
Horizontal wells are at 90 degrees. “They just didn’t think it was possible,” Stagg said.
Stagg remembers the fierce criticism in the beginning. He was given the assignment to drill the first horizontal well in Prudhoe and he faced skeptical colleagues. He recalled one memorable drilling department meeting. “You should be fired,” for pushing horizontal wells, an old-style production manager told him.
But the idea had champions high up who were in positions to make it happen. A key supporter, Stagg said, was Doug Webb, then a senior BP manager in Houston (formerly in Alaska) who overrode the traditionalists’ opposition in the company.
“BP’s commitment (to the idea) was strong in spite of the opposition from middle management. I was asked to prepare an AFE (authorization for expenditure). Doug Webb browbeat people in Alaska into signing it. He listened to all the predictions of massive cost overruns and he said ‘we’re going to do it anyway.’” Stagg remembers.
Practice well in Texas
However, BP’s Alaska management at the time insisted that a practice well be drilled in Texas to prove the concept - and on Houston’s budget, not Alaska’s. This was done, and in sandstone rock similar to Prudhoe. “We drilled 9,000 feet vertically and out 1,600 to 1,800 feet horizontally, and we showed we could do it,” Stagg said.
However, the drill rig needed a “top-drive” unit to allow the longer, 90-foot joints of drill pipeline needed for horizontal wells to be used. An Alaska United Drilling Co. rig was modified with a top-drive, the first in Alaska, to drill the first horizontal Alaska well, JX-2, in late 1985.
JX-2 was a huge success, silencing the naysayers. It produced 12,500 barrels per day, a very good well compared with a good result from a conventional well, then about 4,000 barrels per day.
There was indeed a cost overrun on JX-2, with $5.2 million spent compared with a $3.2 million budget, but Webb supported it because Stagg and other BP drillers were learning to do these wells. The overruns dropped significantly in the second (B-30) and third (Y-20) wells, and then cost targets were met.
Success in Europe
What motivated BP’s management to back horizontal drilling was the early success by another company, Elf Aquitaine (now Total), in drilling what were really prototypes of these wells in Europe. Two wells with 1,000-foot horizontal sections were drilled. “That really woke up BP,” Stagg said. However, Elf Aquitaine’s wells were in carbonate reservoirs, which were easier to drill and complete compared with sandstone like at Prudhoe Bay, he said.
There had been early efforts in the U.S. to drill horizontal wells but there was poor well control and only 50-foot to 100-foot sections could be drilled. These were not true horizontal wells, Stagg said. In any event, London gave marching orders to Houston to test the concept at Prudhoe and, from Houston Doug Webb gave the assignment to Alaska, and to Stagg.
Interdisciplinary teams required
One of the unexpected results of horizontal drilling, however, was that it required the forming of close-knit, interdisciplinary teams that included drillers, petroleum, reservoir engineers and geologists working side-by-side during the planning and drilling of the well. Reservoir segments were so thin, as little as 10 feet thick, that decisions had to be made immediately, which meant people have to be right there, at the table.
Surprisingly, this was a new concept in drilling. Previously each department had their turf and there was time for inter-departmental consultations, and a kind of “command and control” management from the top. The geologists and petroleum engineers developed the well plans and turned it over to the drilling department, and that was it.
That doesn’t work with horizontal wells, however. A team approach was needed because things changed quickly. “It seemed at times that the geologists barely had time to go to the bathroom,” Stagg recalls.
It didn’t take long for the production departments in both ARCO Alaska and BP, the two North Slope operators, to figure out that horizontal wells could also be drilled as “sidetracks” or new underground wells off the wellbores of older, vertical wells. This was a kind of recycling of the older wells, most of which had dropped off in production, and it sharply lowered the cost of tapped new oil.
Coiled-tubing drilling
Another innovation then came along. It was coiled-tubing drilling, or the drilling of a sidetrack with a low-cost coiled-tubing unit instead of using a big rotary drill rig, which cost a lot more. Coiled tubing uses lengths of flexible metal tubing unrolled from big coils at the surface and inserted down well-bores to do work that doesn’t require a big drill rig.
Stagg doesn’t remember who first came up with the idea of putting a drill bit and motor at the end of the coiled tube, and drilling with it, but he recalls a great deal of experimentation in the early 1990s within both ARCO and BP on new things that could be done with coiled tubing.
“Coiled tubing was an interesting technology but when it was first introduced to Alaska we used it for interventions on existing wells. We were mostly doing well treatments with different fluids, pumping acid or nitrogen to help stimulate the well,” BP’s Greg Sarber explained.
There was a push on to do more things with coiled tubing because it was much cheaper than a big rotary rig.
However, innovations within companies need champions, and Stagg gives credit to Chris Phillips, then BP’s production manager, for being a key internal advocate for coiled-tubing drilling.
Phillips tasked Eric Walker, then in BP’s wells group, with expanding uses for coiled tubing eventually to drilling. Walker brought Brock Williams and Ted Stagg into his group.
Parallel track at ARCO
ARCO was on a parallel track and actually ahead of BP, Stagg said. Within that company Don Scheve, then ARCO’s production manager, was the champion for coiled-tubing drilling, Stagg said. BP’s Sarber said other advocates on the ARCO side included Curtis Blout and David Hearn. They were “two of the biggest innovators,” he said.
However, a big obstacle to drilling with coiled tubing became apparent. The drillers could install a “whipstock” device in the bore of the older well to defect the drill bit but there was no “mill” that could be installed on the coiled tubing that was capable of auguring a hole through the steel pipe for a new sidetrack well.
Mike Yore at Weatherford invented one, Stagg said. “He went out to the shop and just fabricated it. We tried it and it worked,” he said. Yore’s mill has evolved from the original hand-built tungsten carbide version to the diamond mill used today. He still works at Weatherford.
Sharing between companies
The ARCO and BP drilling and wells groups worked closely together and there was a frequent sharing of lessons learned. One example, Stagg said, was that a structure at the surface was needed to support the heavy coiled tubing. BP tried to work with a tower-type structure and drilled a couple of wells, but it was a flop, Stagg remembers.
ARCO took a different track, a correct one, as it turned out, and used a small workover rig placed alongside a mobile coiled-tubing unit. That was the right approach but improvements in efficiency were needed. Out of that collaboration, Stagg said, came Nordic-Calista Rig 1, the first combined drill rig and C-T unit to be built. The design has been improved substantially in the years since.
A small workover rig is needed in coiled-tubing drilling to run long strings of production piping into a completed horizontal sidetrack and to manage the quantities of drill mud needed to clean the hole and control the down-hole pressure, and to keep the well safe.
Turf encroachment
The oilfield innovators still had to wear their flak-jackets, however. Conventional rotary-drilling managers weren’t happy about seeing their turf encroached on.
“I remember once showing up at a drill pad with my coiled-tubing unit, where there was also a drill rig, and having the drilling supervisor come rushing out, yelling at me to get my equipment off ‘his’ pad,” Stagg recalls.
Coiled-tubing drilling was a breakthrough technology but Eric Walker, now retired, said there are limits to it being used off the North Slope, at least for now.
One is the heavy weight of the coils used for drilling, particularly when combined with a mobile workover rig, which creates issues when roads have weight limits.
The North Slope oilfield road system is designed for wide, heavy loads, which means equipment like Nordic 1 and 2 can be moved easily and efficiently, Walker said in an interview. This isn’t usually the case elsewhere, however.
Coiled-tubing drilling has been tried on the Kenai Peninsula, for example, but the local roads can’t take the weight of the units. They have to be broken down to be moved, which adds time and cost, he said.
Another limitation is that the large-diameter production tubing used on the North Slope’s older wells, with diameters of 7 and 5 1/2 inches, can easily accommodate the coiled tubing. In the Lower 48 states production tubing of 2 3/8 inches and 2 7/8 inches diameters are common. “With narrower tubing, drilling with coiled tubing would be much more difficult,” Stagg said. But given the pace of innovation in the industry, coiled-tubing drilling might someday become common industry-wide.
