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The first of the Cook Inlet giants Alaska’s Kenai gas field has delivered more than 2.4 trillion cubic feet of dry natural gas since going into production in 1961 Alan Bailey Petroleum News
Although not the largest of the world-class gas fields in Alaska’s Cook Inlet basin, the Kenai gas field was the first of the major gas fields to be discovered. The discovery came in 1959, just a couple of years after that of the Swanson River oil field, during a search for oil in the basin. And, since going into production in 1961 the field has delivered more than 2.4 trillion cubic feet of gas, according to a paper about the field by Jennifer Enos and Brook Maier, published recently by the American Association of Petroleum Geologists in an a memoir on the oil and gas fields of the Cook Inlet basin.
The discovery well for the field, originally called the Kenai Unit No. 1 but now called the Kenai Unit 14-6, was spud at the crest of a geologic structure identified from seismic data and situated to the south of the town of Kenai, on the Kenai Peninsula. Drilled to a depth of 15,047 feet, seeking oil in the deep Hemlock formation, the well encountered major quantities of gas in the relatively shallow Sterling formation, Enos and Maier wrote.
Gas market needed With the discovery of a large field holding almost pure methane, companies started seeking markets for gas. Union Oil Company of California and Ohio Oil Co., the discoverers of the field, partnered with Anchorage Gas to build a pipeline for delivering gas into Anchorage. Anchorage Gas later became Enstar Natural Gas Co., the main Southcentral Alaska gas utility, Enos and Maier wrote.
But, with gas production exceeding local utility needs, the construction of the Kenai-Nikiski pipeline allowed the start of delivery of gas to the Swanson River field in 1967 - the gas was used for pressure maintenance in the Swanson River oil reservoir. In 1969 the export of gas as liquefied natural gas began to Japan, from a newly constructed export facility at Nikiski. And the construction by Union Oil of a fertilizer plant at Nikiski provided an additional market for Kenai gas. Agrium Inc. later purchased the fertilizer plant.
Eventual declines in Cook Inlet gas production, including that of the Kenai field, led to the mothballing of both the fertilizer plant and the LNG plant, although, with a resurgence of the Cook Inlet gas industry, the LNG plant has recently re-opened.
Self-contained system The Kenai gas field forms its own self-contained petroleum system, with the rocks that source the gas and the rock reservoirs that hold the gas all located within a sequence of strata of Tertiary age, Enos and Maier wrote. The field occupies a large, elongated dome-like geologic structure which has acted as a trap for the field’s gas. However, some gas has also become trapped in isolated sand bodies, in some of the more discontinuous sands, the authors wrote.
The gas is biogenic in origin, generated from the microbial decomposition of organic material in the abundant coal seams and organic-rich mudstones found in the Tertiary sequence. The coal seams and mudstone layers act as barriers to gas migration, thus acting as seal rocks for the field’s hydrocarbon traps.
The Sterling formation The Sterling formation in which gas was originally discovered is the youngest and shallowest of the productive rock intervals in the field. The Sterling in the Kenai gas field consists of 11 distinct sands in five separate gas pools, with each pool representing a group of sands that are in pressure communication with each other. The formation accounts for 1.8 trillion cubic feet of the field’s overall gas production, Enos and Maier wrote. However, one of the pools, pool six, is now used as a reservoir for gas storage, the authors wrote.
As appears to be the case with all of the Tertiary rocks in the Cook Inlet basin, the sediments that ultimately formed the Sterling in the Kenai field were laid down on land from a system of sediment-bearing rivers. In the Kenai field the Sterling sands were deposited from meandering streams, with mudstones and coal forming in areas outside active river channels. Consequently, while the sands tend to vary in thickness and extent, in general the Sterling sands are quite continuous and form the highest quality and most laterally extensive reservoirs in the field, Enos and Maier wrote. The sands, which can be more than 200 feet thick in their thickest parts, are friable, with little cementation.
Sterling production peaked in 1983 and declined steeply after that, Enos and Maier wrote.
The Beluga formation The Beluga formation, underneath the Sterling, consists of more than 2,000 feet of sediments deposited from a complex system of streams and out-washes over ancient plains. Unlike the Sterling, whose sediment appears to have originated from a volcanic area to the west, the sediments that formed the Beluga originated from metamorphosed sedimentary rocks to the east. The sand bodies that form gas reservoirs range from continuous lenses in the upper Beluga to thin, discontinuous units in the middle and lower sections of the formation.
The upper part of the Beluga contains 13 distinct sand units in a 700-foot section, with this part of the field having a similar production history to that of the Sterling. But reservoir quality is poorer in the middle and lower parts of the Beluga and the sands tend to be relatively thin and discontinuous in this part of the section. One particular challenge in this part of the field is the difficulty of imaging the relatively small sand bodies from seismic data. And the upper part of the Tyonek formation, below the Beluga, is similar to the lower Beluga - more than 30 individual gas-bearing sands have been identified in the section, from the middle Beluga down through the upper Tyonek, Enos and Maier wrote.
To improve gas production from the multiple sand bodies in the Beluga and upper Tyonek, Marathon Oil Co., operator of the field for many years, devised what it called the Excape technology, a well completion technology that enables well perforation and fracturing stimulation for individual sands. And, with those individual sands rarely traceable through the subsurface, reservoir modeling and reserve estimation tend to use statistical techniques and to rely on performance data, Enos and Maier wrote.
Despite the challenges of the middle Beluga, the lower Beluga and the upper Tyonek sands as productive gas reservoirs, the sands have cumulatively produced an estimated 217 billion cubic feet of gas since first being developed in 1977, Enos and Maier wrote.
Deep Tyonek In the Cook inlet basin, the lower part of the Tyonek formation, referred to as the “Deep Tyonek” tends to hold oil but in the Kenai field it only contains gas. Reservoir quality is much better than in the upper part of the formation. And with sands having been laid down from meandering rivers, individual sand bodies can reach thicknesses of up to 50 feet and they tend to be laterally extensive. The Deep Tyonek has yielded 206 billion cubic feet of gas since production from this section of the field started in 1968, Enos and Maier wrote.
Given the differing characteristics of different reservoir sands within the field, production from different reservoirs tend to meet different market needs - steady production from the Beluga and Tyonek tends to meet base-load gas demand, while the higher gas deliverability of the Sterling tends to be more suited to support the high swings in utility gas demand during the Alaska winters, Enos and Maier wrote.
And, through more than 50 years of continuous operation, supported by the ingenuity of new development technologies, the Kenai gas field has provided energy for Southcentral Alaska, supporting many jobs and generating government revenues, Enos and Maier wrote.
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