Cook Inlet Gas
Uncertainty in supply and demand
The new Cook Inlet Natural Gas Storage Alaska facility in Kenai is now operating to store surplus natural gas in summer for peak demand periods in winter, when gas supplies are low. CINGSA is critical new infrastructure adding security to Southcentral Alaska’s energy supply.
Photo courtesy of ENSTAR Natural Gas
There are concerns about natural gas supply in Southcentral Alaska. Gas fields in the region, discovered in the 1960s and 1970s, are being depleted. Southcentral utilities have estimated that annual gas supply may fall short of demand by 2014 or 2015 and are working on plans to import liquefied natural gas or compressed natural gas as a contingency.
Meanwhile, citing the gas shortage, ConocoPhillips has opted not to renew the liquefied natural gas export license for the company’s LNG plant at Nikiski, near Kenai. The North Cook Inlet gas field, which supplied the plant, still operates and now supplies the utilities. The plant is mothballed; however, it is being maintained in a state to restart if there are new gas discoveries or the plant can be used in some other way, such as an LNG import facility.
Despite the apparent shortages, the state of Alaska believes there are substantial undiscovered gas resources in Cook Inlet. Department of Natural Resources Commissioner Dan Sullivan (no relation to Anchorage Mayor Dan Sullivan) acknowledges the utilities’ concerns, but says that with additional drilling and investment in the existing fields, there could be new gas reserves and production.
“Cook Inlet is a maturing oil and gas basin. While there are legitimate concerns about contractual shortfalls of natural gas in 2014 and 2015, there are still large volumes of gas to be discovered and developed in small to intermediate-size fields,” Sullivan told Anchorage Mayor Dan Sullivan’s Energy Task Force March 14.
There are uncertainties, however. “Cook Inlet is currently witnessing a transition from larger producers like Chevron and Marathon to mid-size and smaller companies, like Hilcorp, Apache and NordAq,” the commissioner said.
“Generally, we see this as a positive trend, but transitions can slow actions and increase uncertainty,” particularly in a small market like Cook Inlet where there are a number of stakeholders, including utilities, producers, explorers, regulators and the state and federal governments, Sullivan said.
In their studies of gas remaining in the producing fields, the utilities have used a very conservative method, a “decline curve analysis.” This is appropriate for utilities, due to the legal requirement to assure their customers of service. “Utilities have a laser focus on the volume of gas available for contracts,” to supply gas, the commissioner said.
However, to get a bigger picture the DNR can use other methods, such as a “material balance analysis,” which the DNR used in addition to decline curve analysis; the agency estimates that there could be as much as 32 percent more gas in the existing fields than is assumed by the utilities in their study.
The state now estimates there is 1.1 trillion cubic feet of gas in remaining producible reserves in 28 fields in Cook Inlet. Using the material balance method of analysis, the Division of Oil and Gas estimates there is 355 billion cubic feet of undeveloped gas resources in three large fields. This includes 233 billion cubic feet of undeveloped gas in the Beluga gas field, on the west side of Cook Inlet; 72 billion cubic feet in the Trading Bay Unit and Grayling gas sands, an offshore field in the Inlet; and 50 billion cubic feet in the North Cook Inlet field, also an offshore field.
Nabors drilled the five storage wells.
Photos courtesy of ENSTAR Natural Gas
Unavailable Data Lowers Estimates
These estimates of undeveloped resources are undoubtedly low because two large Cook Inlet gas fields were left out of this analysis by the division: the Kenai gas field, one of the largest in Southcentral Alaska, and the Ninilchik gas field. Both are on the Kenai Peninsula. They were not included because the division did not have the same amount of data that was available for the three fields that were included.
There are, in addition, other resources in all the fields that are “behind the pipe,” in geologically isolated portions of the reservoirs that cannot be observed using either the decline curve or material balance analyses. That is because those methods of analysis are based on production data, but non-producing reservoir segments that can be inferred in various ways are not included.
Tapping those additional reserves seen in the material balance analysis or that exist behind the pipe will require additional drilling and investment in the fields, and Commissioner Sullivan acknowledges that there is not enough new drilling in the Inlet.
The utilities’ conservative decline curve analysis assumes little new drilling and estimates that to meet the projected gas supply gap the number of new producing wells will have to double from what is currently being drilled.
A critical question is whether that investment will be made. There is some reason for optimism that more investments are coming because of the entry of Hilcorp LLC into Cook Inlet and the completion, effective Jan. 31, of former gas-producing wells owned by Marathon Oil Co. Hilcorp had purchased Chevon Corp. producing properties in 2012 but most of those, such as the offshore producing platforms in Cook Inlet, are dedicated to oil.
Taking over ownership of the Marathon gas fields now gives Hilcorp control of about 70 percent of the Cook Inlet gas production, and the company has a reputation for aggressively rejuvenating old wells and fields, based on a long record in the U.S. Gulf States.
Since taking over in February, Hilcorp has in fact reworked and also simply “turned on” many gas wells that Marathon had not worked with—or had shut off—in the final year of its ownership. This move by Hilcorp in February quickly made more gas available to utilities like Enstar Natural Gas Co., which was very concerned about its gas supply during cold weather in December.
Hilcorp won’t comment on how much new gas it is now producing or how much gas is remaining in the Marathon fields it acquired. The company says it must do its own assessment of the remaining reserves. However, the company’s actions, for example its decision to bring two new land rigs to Cook Inlet, one of which will be working on gas wells, signals that it intends to invest. Hilcorp is also bringing two smaller “workover” rigs to rework old wells on the offshore Inlet platforms, but much of this is aimed at increasing oil production.
Apache Corp., another new company to the region, has an aggressive long-term plan and has drilled its first exploration well. While Apache is focused mainly on oil it will likely find some gas when it finds oil—and if there are gas prospects near its areas of interest, Apache may drill those, the company has said.
Explorers like NordAq and Furie Operating Alaska, two small independents, have reported gas discoveries, although it’s too early to know the amount or when or if it might be produced. Buccaneer Energy, another independent, is developing new gas production from discoveries on the Kenai Peninsula, although the quantities are small.
An aerial overview of the entire facility straight across Cook Inlet from Redoubt volcano earlier this year. (Inset: The 5.5 acre well pad and five storage wells are on state land adjacent to the main CINGSA facility.)
Photos courtesy of ENSTAR Natural Gas
Utilities Plan to Import Gas
Despite this encouragement, the utilities say there is not yet enough information on committed drilling and signed new gas contracts to allay their concerns. For example, there are concerns that much of Hilcorp’s investment is aimed at new oil production rather than gas. Cook Inlet region gas prices are among the highest in the nation, at $6 to $8 per thousand cubic feet, but crude oil prices are higher on an equivalent energy-value basis, so investing in oil is more profitable. Until there is more assurance, planning for the LNG or compressed natural gas imports is continuing, the utilities say.
Despite the current apparent shortage of gas, the major challenge Cook Inlet producers and explorers have is the nature of the small regional gas market, which consists of Enstar and the electric utilities now that the ConocoPhillips plant is no longer exporting gas.
This means that if an explorer is lucky and finds a lot of gas, there may not be a market for it, ironically. Openings for the utilities come only at certain intervals.
A new industrial gas customer, however, may be the Donlin Creek gold mine that is planned to be built in the mid-Kuskokwim River region west of Anchorage. Donlin Gold, the joint-venture that is developing the mine, is planning a 14-inch gas pipeline from Cook Inlet to Donlin Gold that would be built to supply energy to the mine if it is built. Donlin Gold could be a significant industrial customer that would require a steady, year-round supply.
While it does not require new gas supply, the Cook Inlet Natural Gas Storage Alaska project now in operation near Kenai is a significant addition to the local energy infrastructure.
Previously the utilities had to purchase more gas in the winter when demand peaked, but summer demand was low, leaving producers with huge seasonal swings in demand. The new gas storage facility allows the utilities to purchase gas year-round, storing the gas in summer and withdrawing it to meet peak demands in winter.
Because the utilities that are contracted to store gas in CINGSA can now buy in the summer, producers are able to even out their production and not have to throttle wells back in summer, which can damage the wells.
Mike Bradner is publisher of the Alaska Legislative Digest.
Posted: April 30, 2013