Producers 2020: BlueCrest eyes gas as oil declines

Cosmopolitan has increasingly complex oil wells and an advancing gas project

Eric Lidgi

for Petroleum News

The recent uncertainties in economic markets - and in world oil markets in particular - have favored gas over oil at the Cosmopolitan unit for BlueCrest Alaska Operating LLC.

The company had been planning a series of remarkably complex oil wells at its offshore Cook Inlet unit, located off the coast of Anchor Point, in the southern Kenai Peninsula.

“With the development of the COVID Pandemic in early 2020 and the collapse in the oil markets, BlueCrest put its drilling plans on hold,” the company wrote in its 2021 plan of development, submitted to the state in late September 2020. “This pause in drilling has allowed BlueCrest to advance the evaluation of developing the offshore gas reserves.”

For several years, BlueCrest has been developing Cosmopolitan using increasingly complex well designs intended to improve production while saving both time and money.

Before the coronavirus, the local subsidiary of the Dallas-based independent had been working through the permitting process on a proposed well with 24 distinct laterals.

The proposed well would have combined three of its previously tested eight-lateral “fishbone” wells into a single well. In the “trident” well, BlueCrest would drill one main wellbore from the surface that would then split into three subsurface “fishbone” wells.

The project is as much a regulatory challenge as a technical one. BlueCrest needs to obtain 24 separate drilling permits from the Alaska Oil and Gas Conservation Commission, not to mention a field-wide development plan intended to obviate the need for requesting a series of spacing exemptions for each of the individual lateral wells.

The AOGCC approved spacing exemptions for the H-13XX well and its seven laterals in late February 2019 and issued drilling permits in early March 2019. But in late July 2019, Principal Drilling Engineer Tom McKay wrote to the agency, cancelling the drilling permit for the H-13 well “since we have no current plans to drill this well at this time.”

In June 2020, the AOGCC approved updated pool rules for the Cosmopolitan unit allowing BlueCrest to proceed with the 800-foot spacing of the fishbone design, provided that the company does not drill any wells within 500 feet of existing lease boundaries.

In its 2020 plan of development, BlueCrest proposed drilling at least one and possible two of these trident wells in 2020. But by late September 2020, the company had yet to receive all its necessary permits for the first well, let alone a second. In its 2021 plan, the company said that it had delayed the trident project in response to economic conditions.

Instead, BlueCrest said it would “conduct some well work” on the Hansen 1AL1 well over the coming year “to extend its life.” The company also said it would “perform Hot Oil treatments” on the H4, H12, H14 and H16A wells, “to maintain production rates.”

All additional drilling plans are “dependent upon the current market conditions.”

The case for fishbones

“The fishbone wells achieve significantly more reservoir contact and penetration than conventional wells, but we haven’t calculated the incremental ultimate recovery; it is substantial,” CEO and President J. Benjamin Johnson told Petroleum News in 2019.

“Each fishbone well contacts the same amount of reservoir rock as seven-nine individual horizontal wells, and each trident well should recover the same ultimate reserves as three fishbone wells since the reservoir contact is the same,” Johnson said, adding, “so, each trident well provides the same amount of reservoir contact as 21-27 individual wells.”

And because each lateral builds off existing surface work, the design saves time - as much as five months for each well, shaving two years for an entire trident, Johnson said.

Trending toward complexity

BlueCrest brought Cosmopolitan into production in early 2016 from a well drilled by former operator (and former partner) Buccaneer Energy Ltd. Using its custom-built BlueCrest Rig No. 1, BlueCrest launched a solo development effort in November 2016.

The program began with the H-16 well and H-14 well. Even those initial wells were complex by normal Cook Inlet standards. BlueCrest Rig No. 1 accommodated wells extending three miles out and then a mile-and-a-half down to the reservoir and an additional mile-and-a-half horizontally through the sands, according to the company. The H-16 well, for example, was a 22,810-foot well targeting the Hemlock at 7,089 feet.

The company suspended the rest of its five-well program proposed in early 2017, in response to the state withholding between $75 million and $100 million exploration tax credits.

In the interim, the company re-evaluated its approach.

The following summer, in late July 2018, BlueCrest completed the H-12 well in a “fishbone” design: a “spine” well running through the Hemlock with seven lateral “ribs” drilled every 800 feet up through the Hemlock and Starichkof horizons. These ribs drained to the spine well, which then flows back to shore, where oil is trucked to market.

The company repeated the design later in the year by re-drilling the H-16 well. The H-16A well also used the eight-well fishbone design mimicking an 800-foot spacing array.

According to the company, the fishbone wells are particularly well suited for the rock formation at the unit. The consolidated nature of the geology allows wellbores to remain open after drilling, making hydraulic fracturing less effective than the multilateral approach. The wells “have been very effective in maximizing the production from a given area.” The H-16A well came online in December 2018 and accounted for 29% of oil production and 10% of gas production at the field as of October 2019.

Pleased with those results, BlueCrest drilled the H-4 well into the southern end of the reservoir in early 2019. The well also had the one-well/seven-lateral fishbone pattern.

The company brought the H-4 well online in March 2019. The well accounted for 26% of oil production and 7% of gas production at the field as of October 2019.

Crunching the numbers reveals the cumulative benefits of this approach. BlueCrest has drilled only three wells at the unit, but it’s producing from 20 supplemental laterals. And, seen another way, the company has only used five of the 20 slots at its drilling pad.

The program has yielded large increases in oil production. Cosmopolitan produced 1,356.7 barrels of oil per day on average in the year ending July 2019, up from 526.8 barrels per day the year prior. The unit produced 9.64 million cubic feet per day of gas during that year, down considerably from 2.7 billion cubic feet per day the year prior.

In its previous plan of development, submitted late September 2019, BlueCrest proposed a “trident” well design as a way to further improve efficiency at the unit.

What about gas?

The company discovered the gas field in 2013, with its initial offshore exploration drilling in the area. The field would require an offshore platform or a jack-up rig.

“We have a large gas resource, proven; it’s been tested, but it’s expensive to develop,” Johnson said. “We’re just waiting to see what the market looks like.”

The natural gas deposit consists of coalbed methane that has migrated into the Tyonek formation, which lies above all the oil zones in the unit, according to Johnson.

As a result of the delays brought about by the coronavirus and the resulting economic upheavals, BlueCrest also addressed a different natural gas issue by commissioning a mechanical refrigeration unit, MRU, at the unit.

The MRU allows BlueCrest to meet Alaska pipeline quality standards by reducing the dew point of produced natural gas produced in its existing oil stream. The unit removes propane, butane and other liquids not desired for Alaska distribution. The unit can process as much as 35 million cubic feet per day.

“We’re not sure exactly what its origin is, but (the natural gas is) intermixed within the oil zones, and so, one way or another it has absorbed natural gas liquids,” Johnson told Petroleum News in late September 2020. “Some of our oil wells initially will produce a lot of gas,” he added. “We have one well that - we were never able to open it up because we didn’t have a MRU that could handle its gas rate - it probably would have made 17 million a day.”

The MRU was designed to handle all gas-related needs from existing oil production and could perhaps also handle any additional needs from the proposed offshore development, which is a much drier gas.