ExxonMobil is making a significant change to its planned Point Thomson project due to an unexpected “sour gas” problem involving the two wells already drilled at the remote Alaska North Slope field.
In 2010, the company finished drilling two wells on Point Thomson’s central pad, the PTU-15 and the PTU-16. 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 that can be very damaging.
The PTU-15 and PTU-16 well materials were not designed for “sour service” and will need casing mitigation, ExxonMobil has told state oil and gas industry regulators.
Ultimately, both wells will be used as injectors, and a third well will be drilled as the initial Point Thomson producer, the company said.
Schedule remains intact
Kim Jordan, an ExxonMobil spokeswoman in Houston, told Petroleum News on Jan. 9 that the sour gas issue “does not impact the overall schedule” for the Point Thomson development.
Likewise, state Natural Resources Commissioner Dan Sullivan said work appears to be proceeding according to plan.
Under 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.
“In none of our briefings with Exxon has there been even the hint of that important date not being abided by,” Sullivan said in a Jan. 9 interview.
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.
Long struggle
The Point Thomson unit is on state-owned 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.
How project will work
The first development phase, known as the “initial production system,” will be designed to produce 10,000 barrels per 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 export pipeline to tie Point Thomson production into the existing North Slope oil transportation network.
ExxonMobil has acquired the major authorizations, including a federal wetlands permit and a state certificate of public convenience and necessity for the pipeline.
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.
At the Oct. 30 briefing, ExxonMobil told state officials the potential consequences of the high H2S levels in the PTU-15 and PTU-16 wells. The company said testing determined that “under a shut-in condition with a well tubing failure, the well casing could experience rapid corrosion.”
The wells are “suspended in a safe condition,” and were inspected in July 2012, ExxonMobil said.
Going forward, the company plans to use both wells as injectors after installation of liners.
Jordan, the ExxonMobil spokeswoman, further explained in an email: “The liners, with reduced internal diameters, required the use of smaller production tubing which reduced the flow capability of both wells. For this reason, both the PTU-15 and PTU-16 will be used as injectors.”
ExxonMobil has told state officials it intends to accelerate the planned drilling of another well at the west pad. This well will be the producer, able to provide “the required flow rate to achieve the design rate level agreed in the Settlement Agreement,” Jordan’s email said.
The agreement calls for cycling 200 million cubic feet per day of gas.
The west pad well will be tied into the central pad, where the gas processing and compression facilities will be located. The west and central pads are about four miles apart.
