Apache plans to have spent US$1 billion on its Alpine High asset by the end of 2018, the company’s CEO and president, John Christmann, said in an update on October 9. Apache is also considering a sale of its midstream facilities on this project.
The Alpine High development is an “extremely large wet gas play”, he continued, with more than 3,500 economic locations. Based on 4,400-foot (1,340-metre) laterals, wells should cost US$4-6 million, with net present values of US$5-8 million. Beyond the wet gas play, there are another 1,500 locations.
For a high-end well, the NPV rises to as high as US$19 million, the executive said. Longer laterals may improve these calculations further. One of the “upper range” wells will generate positive returns, from oil and NGLs, even if gas prices are zero, the company claims.
As the company learns more about the play, it expects well results to improve – even while keeping its rig count flat from 2017 to 2018.
While Apache has a muted view of gas prices, cutting its expectations for 2018 from 2017, Alpine High’s economics are driven by low costs and the “tremendous volumes” of oil and NGLs.
The company has drilled around 70 wells in the play over the year, providing it with greater insight into the fairway, while also starting work on infrastructure to support the development. Apache has 336,000 acres (1,359 square km) of licences on the play, up 9% since September 2016.
The Alpine High is made up of three zones: the northern flank, the crest and the southern flank. The northern part is the largest, covering around 56% of the acreage and with Apache having drilled 54% of its wells there. Christmann pointed out, though, that this drilling emphasis did not necessarily mean that this was the most attractive. Rather, these were where initial leases were acquired, with nearer-term expirations.
Apache has been tight-lipped about some aspects of the Alpine High, it acknowledged. The company said, when it announced the discovery of the play in September 2016, it had chosen not to disclose information about the “seal integrity of the source rock, the impact of deep-seated faults and shallow geologic complexities”.
The company said its knowledge of these problems had allowed it to make progress on the Alpine High, an area that had frustrated all previous operators. Of the 3 billion barrels of oil originally in place (OOIP) on the project, Apache expects to recover around 13%.
Work on gas infrastructure began in November 2016 and first gas sales were achieved on May 3 of this year, ahead of the target of the end of June. Apache said it had drawn on experience from its work in the Permian Basin and in Egypt to carry out this plan.
Apache installed 14 miles (22.5 km) of takeaway trunkline, 4 miles (6.4 km) of gathering lines and five production facilities, with a connection to the Comanche Trails pipeline. Work is continuing, with 70 miles (113 km) of trunkline, running from the north and south, under way. Two of the five sections of this larger plan have been completed, covering 42 miles (68 km).
Gas processing capacity is currently at 200 mmcf (5.66 mcm) per day and by the end of this year should have reached 330 mmcf (9.3 mcm) per day from five facilities. Gas is being sold into Mexico, at a slight premium to the Waha daily benchmark.
Oil and NGLs are being trucked from the play, at a cost of US$3 per barrel, but by 2019-20 a pipeline should have been built.
Given the appeal of these midstream assets, Apache said it was considering some sort of sale, although there is not yet a clear plan.