Invest money, do work
Hilcorp executives describe the company’s strategy for Cook Inlet oil and gas
In a hydrocarbon basin such as that of Alaska’s Cook Inlet, where oil and gas production has declined significantly over the years, there are only two ways to up the production figures: explore for undiscovered resources or redevelop existing oil and gas fields, John Barnes, Hilcorp Alaska vice president for exploration and production, commented at a “lunch and learn” session of the Alaska House Resources Committee on Feb. 25.
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And Hilcorp specializes in that second approach, breathing new life into old fields through new development programs involving significant investment, Barnes said.
“We’ve increased our capital investment,” Barnes said. “We’re spending over $300 million a year in capital.”
Hilcorp spokeswoman Lori Nelson told Petroleum News in a Feb. 26 email that Hilcorp expects to spend more than $350 million in Alaska in 2014.
Attracted to the basinHilcorp first entered the Cook Inlet oil and gas industry in 2011 when it purchased Chevron’s Cook Inlet assets. In 2012 the company acquired Marathon’s Cook Inlet oil and gas fields. Barnes said that Hilcorp had been attracted to the Cook Inlet by the existence of some aging but large oil and gas fields; access to land through the State of Alaska leasing system and through private ownership; the effective rule of law; and a stable state fiscal policy.
The Cook Inlet has seen a surge of new activity in recent years with several companies, in addition to Hilcorp, operating in the basin, exploring and developing new resources.
Increased productionAnd Hilcorp’s development approach has been paying off. The company’s oilfield development activities, in combination with other field development by Cook Inlet Energy Inc., another Cook Inlet oil producer, have resulted in a sharp rise in oil production from the basin, from a plateau of a little over 10,000 barrels per day in 2012 to a figure of around 20,000 barrels per day recently.
“Activity gets oil and gas production up, and that’s what we’re all about,” Barnes said.
A star performer in this trend has been the Swanson River field, the first field to go into production when oil started flowing from the Cook Inlet basin in 1958 — production from Swanson River has increased from several hundred barrels per day when Hilcorp took over the field to 2,500 barrels per day recently, Barnes said. The Trading Bay field on the west side of the inlet has seen production increasing from 600 or 700 barrels per day to more than 3,000 barrels per day, while production from other fields is also rising.
Tearing things apartSuccessful field development involves “listening” to the day-to-day performance of the field reservoir, which is hidden deep underground, analyzing that performance to apply reservoir engineering, and then tearing that performance apart before putting it back together with a brand new understanding, Barnes said.
“That’s where it starts,” he said, adding that the next step is to “tear apart” the old wells, to bring those wells back into effective production. Some of the wells are nearly 50 years old, with many mechanical issues and with a need to run tools and install new downhole equipment. In fact, unlike some major oil companies, Hilcorp sees an old well as an asset ripe for redevelopment, rather than a liability, Barnes said. But it is also essential to also drill new wells, he said.
It is also necessary to repair or upgrade the surface facilities to support the new production, he said.
And all of that costs money, the money that must be invested to achieve the production turnaround.
“You have to know the game you’re getting into,” Barnes said. “You can’t come into a field and try to redevelop it by pinching pennies.”
Decimated support industryA major challenge that Hilcorp has had to face is the weak state of the decimated oilfield support industry in the Cook Inlet region. When Hilcorp set up shop in Alaska there was insufficient local skilled labor for the work required, and little or no availability of the type of drilling rigs, specialized tools and modern equipment required to support new work, Barnes said.
However, a number of service companies have been working with Hilcorp to revive the Cook Inlet industry. And Hilcorp has increased its capital expenditure, drilling more wells and obtaining new equipment. The company has brought in two “pulling units” for refurbishing wells on offshore platforms, and two modern drilling rigs for onshore drilling. In 2013 Hilcorp drilled about 10 new wells and performed workovers on upwards of 70 existing wells, Barnes said.
The importance of costBut everything reverts to cost — drilling a well in an old Cook Inlet field might now cost 20 times what that well would have cost when the field was young. But the oil production rate from the modern well in the aging field reservoir would typically be a fraction of the flow rate from an early well, thus driving a need to tightly manage drilling costs.
“You have to be fixated on cost. You really have to look at that,” Barnes said. Hilcorp can spend $50,000 to $80,000 per day running a pulling unit, and several hundred thousand dollars per day operating an old drilling rig on a platform, he said.
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Keeping ahead of the Cook Inlet gas curve
Faced with worries from Southcentral Alaska power and gas utilities about the specter of having to import liquefied natural gas, as gas production from the Cook Inlet declines, Hilcorp has pushed the gas production commitment from its acquired Cook Inlet fields from a volume of just 32 billion or 33 billion cubic feet to almost 50 billion cubic feet in 2014, while also making every effort to maintain annual production at or above that 50-billion-cubic feet level, Kurt Gibson, the company’s vice president for its Alaska midstream division, told a “lunch and learn” session of the Alaska House Resources Committee on Feb. 25.
Previous existing gas supply contracts had shown a steady production decline through to 2018, with no committed gas supplies beyond that year.
Asked the customersIn January 2013 Hilcorp sent a solicitation to all potential gas buyers in the Cook Inlet region, asking them for their supply needs through 2017, Gibson said.
“But what customers needed to know, for them to plan their businesses, was ‘is there gas (actually) available in the Cook Inlet?’” he said.
So, in April Hilcorp held a conference with its gas supply customers, to provide information about the Cook Inlet gas reserves situation and to evaluate how Hilcorp might address future gas purchase requirements.
“That conversation was productive. … We talked about our common interests — their need to plan their business. … Our need to know what our gas sales portfolio was going to look like,” Gibson said. The discussion emphasized the importance of commitments in the form of firm purchase agreements to justify gas development expenditure, he said.
This conference led to the placement of additional gas under contract, to complete the utilities’ needs through to the first quarter of 2018, Gibson said.
Timeframe for importsHilcorp also asked the utilities how long it would take to establish a gas supply from elsewhere, should Cook Inlet gas supplies fall short of gas demand — the response was that setting up import arrangements might take three or four years, Gibson said. The conclusion was that five-year contracts would “let everyone sleep at night,” with an annual gas supply conversation between Hilcorp and the utilities enabling further supplies to be added to the ends of the contracts in due course.
The timeframe of the new contracts through to 2018 says nothing about how long Cook Inlet gas reserves might continue to support local gas supply needs, Gibson said. Instead, the timeframe actually reflects the terms of a consent decree between Hilcorp and the State of Alaska. That consent decree, negotiated following concerns about Hilcorp’s new dominance of the Cook Inlet gas market, set ceiling prices for Cook Inlet utility gas purchased from Hilcorp through to 2017. And, with it making little sense to terminate contracts in the middle of the winter, the Hilcorp negotiated contracts through to the end of first quarter of 2018, Gibson said.
Gibson said that on Feb. 24 Hilcorp had followed up on its commitment to an annual gas supply conversation by asking its customers for information about the anticipated demand beyond the end of the contracts agreed in 2013, and by announcing a 2014 customer conference.
Market challengesBut the difficult gas market in Southcentral Alaska presents some significant challenges for gas producers. John Barnes, Hilcorp Alaska vice president for exploration and development, showed a graph of production from the company’s Happy Valley gas field on the Kenai Peninsula. After a sharp rise in production from the field between July 2012 and the spring of 2013, following efforts by Hilcorp to re-invigorate the field, production tumbled around mid-July 2013 before picking back up again. That abrupt production fall resulted from a lack of summer gas demand, following the closure of industrial gas plants on the Kenai Peninsula such as the Nikiski liquefied natural gas facility, Barnes explained, adding that having to temporarily shut in gas wells can compromise future well performance.
Asked about the potential re-opening of the shuttered liquefied natural gas plant, Barnes said that having the export facility running again would be a great step forward.
“Demand creates supply and I think having that plant opportunity, whether it’s that or other industrials, is a great stimulus to the economy,” Barnes said.