Reaping the rewards of replication
When the name of the game in deep-water developments is keeping costs down and bringing in production quickly, one operator focuses on keeping subsea fields as simple as possible.
Most of the projects operated by the three Deep Gulf Energy companies for the deep-water US Gulf of Mexico follow a basic subsea tie-back pattern. The projects typically require one to three wells, a flowline, an umbilical and some processing equipment on the host platform.
“We don’t have to do a lot of pre-sanction engineering because all of our projects look alike,” says Richard Clark, president of Deep Gulf operating companies. “As soon as we have made a discovery, we can start ordering the equipment. That means we can usually get on stream in less than 18 months.”
That is partly a function of the company’s focus on keeping costs and risks as low as possible.
“We don’t do a lot of new stuff and experimenting,” he says. “We try to use the same type of equipment over and over again so we’re not relearning things.
“We’re using a lot of technology, but we’re not going to be a groundbreaker. We leave the prototyping and the very, very new technology to the bigger companies with better resources. We follow close behind after technology has been proven.”
A technology of interest to Clark is one-trip multi-zone gravel packs. “We haven’t had the opportunity to use (them), but we’ve seen what Chevron has done with this technology in the Wilcox trend, and it is impressive,” he says.
Setting the pattern
Clark, a founder of Mariner Energy in 1996, left that company in 2002. A couple of years later he and some of his Mariner Energy associates founded the initial Deep Gulf company, which receives a large portion of its private equity backing from the First Reserve Corporation. Deep Gulf employs a similar strategy to Mariner – in short, it focuses on subsea tie-backs and doing “projects that a lot of the majors would feel are not material to them but that are economic to us”.
Since Clark’s Mariner Energy days, most of what he has seen change has been on the prospecting side of the business.
“At Mariner, back in 1996, we were doing amplitude-driven exploration. We still are, but a lot of the obvious amplitudes are gone now. Now we are looking for more subtle amplitudes often near or under salt. We use more sophisticated seismic,” he says, noting wide azimuth seismic is a technology of choice. “We bought a large survey of wide azimuth data over the areas we’re interested in.”
Deep Gulf does some in-house processing, such as inversions and cleaning up data, but outsources the bigger projects.
“Our in-house efforts have really paid off for us,” he says. For example, Clark says, the initial well in one of Deep Gulf’s recent developments found a relatively small accumulation that disappointed the original operator.
“We did an inversion on the seismic using the data from that original well. The inversion showed a nice amplitude slightly deeper that did not stand out on the original data. We took over the project and drilled the second well, which resulted in a very nice discovery. Without the inversion, we probably would have dropped the lease,” he says.
The field, in almost 6000 feet (1800 metres) of water, began production in late 2016 and in December was flowing at 12,000 barrels per day.
Although Deep Gulf typically avoids using new technologies, the Kodiak field, in 4800 feet (1463 metres) water depth, brought some challenges only new technologies could solve.
For starters, the 38 degree API oil at Kodiak had a high carbon dioxide content, which required a special corrosion-resistant alloy (CRA) lining in the flowlines.
“This was the first time they’ve used this technology in the Gulf of Mexico,” he says. “It was a very challenging project from that perspective.”
The pipe consists of a high-strength carbon steel outer pipe lined on the inside with four millimetres of a CRA. Clark says the company initially could not find a manufacturer that could reliably make the pipe. Attempts to coextrude the CRA with the outer pipe were unsuccessful. The company elected to use a mechanically lined pipe made by Tenaris.
The CRA liners were installed in Germany by Butting, a family-owned German pipe manufacturing company. The CRA was formed into a liner, then inserted into the outer pipe. The assembly was then pressured up to 34,000 psi internally to expand the liner and mechanically bond the pipes together.
Deep Gulf intended to lay the pipe with a reeled vessel, so it carried out a lot of bend testing to evaluate the impact of reeling the pipe on the mechanical bond. Once satisfied that it could be safely done, welding began at the spool base.
According to Clark, welding was also a challenge. The pipe is more than an inch thick, so it required multiple passes to complete a weld. Once in the field, the actual installation of the pipe went smoothly, he says.
BP drilled the Kodiak discovery well in 2008 that found more than 400 feet of pay, while the 2009 appraisal well came in lower than expected and wet.
“It was a nice discovery, but it wasn’t as big as they’d originally anticipated,” Clark says of the Miocene oil play.
A Deep Gulf company bought the interests in the field in 2012. In 2015, Deep Gulf drilled a high-pressure, high-temperature development well to almost 30,000 feet. The field’s production equipment producing the field is rated to 15,000 psi and 275 degrees Fahrenheit.
Kodiak, in Mississippi Canyon blocks 727 and 771, is tied back six miles (9.6 kilometres) to the Eni/Williams Devils Tower spar. Two modular decks were added at Devils Tower to handle the anticipated Kodiak production stream of 20,000 bpd. Deep Gulf installed a series of buoys – one per mooring line – and filled them with nitrogen.
This lifted the spar by 10 feet, allowing Deep Gulf to install the extra payload on the spar, which then weighed enough to sink back to its original depth. In effect, the buoys took the load of the mooring system off the spar so the spar could hold more weight.
“That’s the first time I’d heard about that being done,” Clark says.
Deep Gulf completed three zones using smart completions. “It was the highest high-pressure, high-temperature gravel pack that had been done in the Gulf of Mexico,” he says.
The two lower zones, which had higher pressure, have been flowing since March 2016. With those reservoirs somewhat depressurised, Deep Gulf applied for and received regulatory approval to begin production from the upper zone and to commingle all three of the zones. Clark anticipates bringing the third zone online around January 2017.
Kodiak also presented a new flow assurance issue for Deep Gulf. “There were asphaltenes. We hadn’t dealt with that before,” Clark says.
The asphaltenes began depositing in the production tubing as the pressure decreased. While the operator was continuously using ashphaltene inhibitors, a substantial amount was still building up in the tubing.
“We came up with a way to treat for asphaltenes,” Clark says. “On a monthly schedule, we pump 90 barrels of xylene through the umbilical and into the tubing with the well shut in. We let it soak about 12 hours and flow it out, and that pretty well flushes it. We basically start over. I thought our guys did a good job in identifying that problem very early and finding an effective treatment for it very quickly.”
Deep Gulf plans to drill a second development well in the field after obtaining sufficient production history.
Looking forward, Clark sees more drilling and the possibility of venturing into a new-to-the-company basin.
“We’re not involved in the Wilcox. That’s the frontier area in the deep water,” Clark says. “It’s too early in the trend, but we’re starting to look at it.”