'Sour gas' forces ExxonMobil to modify well array in Point Thomson field

Wesley LoyPetroleum News

ExxonMobil is significantly changing its Point Thomson plans because of an unexpected "sour gas" problem involving the two wells already drilled at the remote North Slope field.

In 2010, the company finished drilling two wells on Point Thomson's central pad. One well was to be a producer and the other an injector for the natural gas condensate project. But during well testing, ExxonMobil encountered higher levels of hydrogen sulfide than expected. Hydrogen sulfide, or H2S, is a "sour" or acidic gas.

Materials for the two wells were not designed for "sour service" and could suffer damage. Ultimately, both wells will be used as injectors, and a third well will be drilled as the initial Point Thomson producer, the company said.

Kim Jordan, an ExxonMobil spokeswoman in Houston, said the sour gas issue will not affect the overall schedule for the Point Thomson development.

Likewise, state Natural Resources Commissioner Dan Sullivan said work appears to be proceeding according to plan.

In a legal settlement with the state, ExxonMobil has pledged to commence initial production at Point Thomson by the winter of 2015-16, or no later than May 1, 2016.

ExxonMobil detailed the sour gas problem during a recent briefing of officials with the Alaska Oil and Gas Conservation Commission and the Department of Natural Resources. DNR provided a copy of ExxonMobil's PowerPoint presentation from the Oct. 30 briefing to Petroleum News. The sour gas issue previously was not known publicly.

The Point Thomson unit is on state acreage along the Beaufort Sea coastline, about 60 miles east of Prudhoe Bay and just west of the Arctic National Wildlife Refuge.

The field is believed to contain hugely valuable reserves of natural gas, estimated at 8 trillion cubic feet. ExxonMobil says it also contains an estimated 200 million barrels of condensate, a light liquid hydrocarbon associated with natural gas.

Despite its riches, the field has yet to produce any gas or oil since its discovery in the 1970s. ExxonMobil and its partners in the field have cited the lack of a North Slope natural gas pipeline, as well as the field's remote location and technical challenges, as reasons for the lack of development.

Beginning in 2005, state officials began to take increasingly aggressive steps to try to force ExxonMobil to produce at Point Thomson. A court conflict soon developed as the oil companies sought to block the state's attempts to dissolve the unit and invalidate the underlying leases.

Under pressure, ExxonMobil drilled a pair of wells at Point Thomson. Finally, on March 29, 2012, the state and the oil companies reached a settlement agreement that resolved all the legal issues and laid out a schedule for the gradual development of the field.

While the settlement does not guarantee production, ExxonMobil and its partners will lose acreage if they don't move forward with development, state officials say.

The other major stakeholders in Point Thomson are BP and ConocoPhillips.

The first development phase, known as the "initial production system," will be designed to produce 10,000 barrels a day of condensate to start.

Major field construction has not yet occurred at Point Thomson, but is expected to begin ramping up this winter. The project will involve establishing central, west and east pads; infield roads and gathering lines; worker housing and a barge dock; and a 22-mile pipeline to tie Point Thomson into the existing North Slope oil transportation network.

The condensate production involves producer and injector wells "cycling" gas in tandem. The producer well brings wet gas to the surface. The gas goes into processing facilities for collection of the condensate. The injector well then shoots the residual dry gas back underground.

Petroleum News