BP Exploration (Alaska) is pushing the technology envelope at its Prudhoe Bay viscous oil satellites, drilling multiple horizontal lateral legs from single well bores to access as much reservoir sand as possible in the shallow Schrader Bluff reservoir. In 2003 BP drilled the first trilateral well on the slope; in 2004 it drilled the first quadrilateral; and this winter the company completed the first pentalateral. All targeted the Schrader, either at Orion or Polaris, two satellite fields under development on the western side of the Prudhoe Bay field.
In the 1990s the Schrader was accessed with vertical wells, crossing vertically through multiple narrow reservoir sands, but production rates were not economic. Current well technology enables BP to drill horizontally, opening reservoirs to production for a mile or more; and the company is opening multiple reservoir sands from one well bore.
The five horizontal laterals in the S-213A well at Polaris access 27,000 feet of reservoir, Gil Beuhler, Prudhoe Bay satellite development manager, told Petroleum News in a May 10 interview. Compare that, he said, to 200-250 feet of reservoir opened up when a well is drilled vertically through four or five Schrader Bluff sands each up to 50 feet thick.
The impacts on production are dramatic. The S-213A, sidetracked off an older vertical well bore, came on production in March at several thousand barrels per day and Beuhler said the last test he saw was in the 3,500 bpd range. While long-term flow rates are expected to be in the 1,000 to 1,500 bpd rate, the original vertical well, the S-213, had a long-term rate of 200-300 bpd, he said.
That production comes at a price, Buehler said, with a lot more money invested in this pentalateral, $10 million, than in a vertical well to the Schrader, which might cost a quarter of that to drill.
But those vertical wells “weren’t fully accessing the potential” of the Schrader Bluff formation, he said. Although the multilateral wells are more expensive and more challenging, “now you’re progressing the opportunity.”
North Slope viscous oil is in shallow reservoirs, close to the permafrost: it is cold and doesn’t flow as readily as oil in deeper, warmer reservoirs: hence the productivity problem which BP is addressing with multilateral wells. The shallow reservoirs also aren’t as well consolidated as deeper sandstones and fine sand from the reservoirs is produced to the surface along with the oil. That issue —handling the solids — is a separate issue, Beuhler said, a facilities issue. Those solids have to be removed from oil processing facilities and trucked to a grind and inject facility, adding costs to Schrader production.
Wells more complicatedThe wells BP is drilling in the Schrader Bluff formation — and wells that ConocoPhillips Alaska is drilling in the analogous West Sak formation at the Kuparuk River field — address the viscous oil productivity issue with technology. The companies have a regional viscous team which shares technology and best practices, Buehler said: “We can’t afford to make the same mistakes across multiple assets. We can’t afford to have a success and not apply it across all the assets.” The team shares current challenges and technology developments, including where a new technology might best be tried first. It’s “a very collaborative effort,” he said, because the developments are similar and have “similar challenges that require similar solutions.”
That’s also true within BP-operated North Slope fields. Prudhoe Bay operations drilling engineer Mik Triolo started working the viscous issue at Milne Point and then moved over to Prudhoe, working on early multilateral and horizontal well designs.
The Polaris pentalateral builds on the technology used at the Orion quadrilateral, he said. Both have multi-lateral junctions. But the S-213A also has an open-hole junction kick-off for one sand small enough it didn’t justify the cost of a junction box. Because of uncertainties about what the reservoir will do under production conditions — and how stable that open-hole junction would be once the well was producing — they ran an aluminum billet, an aluminum tube, out to the end of the liner and milled off that to reduce the open-hole area at the junction.
Triolo said it too early to know how it will work, but the drilling portion of the work was successful, the liner was successfully inserted past the open-hole junction and “it significantly reduces the cost” of the two laterals because a junction isn’t required.
S-213A took longer to drillThe L-201 quadrilateral took about 40 days to drill, Triolo said. The S-213A pentalateral took about 80 days to drill, partly due to completion difficulties, “none that we were not able to overcome.”
Buehler said that goes with technology development:
“We’re pushing the technology envelope. We’ve got to; we can’t live with status quo,” so while it’s painful to spend 80 days drilling a well, “if we don’t do that we won’t unlock the well component of the viscous strategy and technology development.”
The angle of the wells — each lateral about a mile long — also makes them challenging, Triolo said. These are shallow extended reach drilling wells, with true vertical depths of between 4,000 and 5,000 feet, stepping out 12,000 to 13,000 feet in measured depth. That is at “the very edge of the envelope” industry-wide for shallow ERD wells, he said.
In addition to the aluminum billet, BP also ran swell packers in the S-213A well, Triolo said. The 10-foot long elements area a little bigger than the liner and expand over time and seal off the annular area between the liner and the well bore. As the wells are drilled, logs are run, and determinations are made then whether to run in packers and where, providing future potential shut-off capabilities along the length of the lateral.
Packers help manage the well over time, Buehler said. In a vertical well if one reservoir zone starts producing water you can go in and shut off that zone. In a lateral well, the swell packer provides a way “to go in and isolate specific parts of a specific well bore.”
“We’re not just trying to maximize productivity right now, we’re trying to maximize the total life-cycle benefit of the well,” Buehler said. How will you manage the well 20 or 30 years from now? The swell packers are used for “formation integrity — trying to keep things in place” and for well-bore mitigation.
What’s next?More multilaterals per well isn’t the direction Buehler sees this technology going in the Schrader Bluff formation.
The number of multilaterals depends on the number of sands in a reservoir, he said.
Typically ConocoPhillips is drilling two laterals from West Sak wells while BP is drilling four to five in the Schrader. It’s a function of the reservoir, Buehler said. “Their pay can be accessed with fewer laterals because it’s a little bit thicker. … In Polaris we have five distinct pay intervals.” Orion has four.
“The reservoir’s talking to you in terms of how many laterals you need” and the technology component determines “how many laterals you can actually do,” Buehler said.
As for what’s next: “I would like to be able to drill farther,” put in more open-hole junctions vs. junction boxes, because of the cost factor, and “be able to hold more of the reservoir in place and reduce our solids production.”