Rachael Seeley, Editor
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WATFORD CITY, ND-Hess Corp., taking seriously a state mandate to reduce flaring in the Bakken shale, has adopted the use of a remote NGL capture technology at a handful of North Dakota wellsites to help meet its goals.
The deadline for meeting North Dakota's first statewide flaring reduction target passed on Oct. 1. On that date, operators were required to capture 76% of gas production or face production restrictions in January.
"We are meeting the state's gas capture targets and expect to continue to do so in the future," said John Roper, senior manager of onshore communications for Hess.
The company's 2013 Corporate Sustainability Report shows that Bakken flaring is expected to fall to 10% of gas production by 2017. The company declined to disclose the proportion of gas now flared by its Bakken operations, citing a quiet period imposed by the US Securities and Exchange Commission (SEC) for the pending monetization of Bakken midstream assets.
Hess is one of the largest producers in the Bakken. Data compiled by analyst Scott Hanold at RBC Capital Markets show that the company accounts for 6% of total production in the Williston basin.
System design
Lynn Helms, director of North Dakota Mineral Resources, said this summer that most Bakken operators were complying with flaring reduction targets ahead of schedule. But "there's some, a handful, that are really going to need a lot of wellsite technology," Helms said (UOGR, July-August 2014, p. 18).
Hess' flaring reduction strategy includes the utilization of the mobile gas capture and NLG recovery technology developed by Gtuit and now contracted by the company and its partner Corval Group (see box).
The Gtuit system is mounted on a trailer that attaches to an 18-wheeler. It can be disconnected and recommissioned at a new wellsite in less than 24 hrs.
When rich Bakken gas arrives at the Gtuit system, it is compressed and sent to a refrigeration unit where the NGLs drop out. The collected NGLs are then sent to a small de-ethanization tower that removes the most volatile NGL and pumped into a storage tank. The residual methane and rejected ethane are sent on to an engineered flare maintained by the operator or other value-added processes that yield CNG, LNG, or electric power.
The Gtuit system was weatherized to withstand winter temperatures that can fall as low as -40° F., with wind chills of -60° F. "We've had two winters of experience … the version of the unit today has been through the severest weather that the region can deal out," said Dave Reif, vice-president of business development for Corval. "It's a very hostile environment to work in."
After some early trials and modifications, the winterization efforts proved effective. In the winter months of early 2014, Gtuit's units were operational more than 95% of the time.
The Gtuit treatment system reduces the volume of flared gas and the emissions of volatile organic compounds from the flare stack. It can accommodate pad sites with multiple wells that each have variable gas composition and flow rates. Gtuit Chief Operating Officer Mark Peterson said production from a single Bakken well can fluctuate from 200-400 Mcfd in a matter of minutes.
Units are available with processing capacities of 300 Mcfd, 500 Mcfd, or 1 MMcfd. They can be linked together to operate in parallel to match capacity to the production curve of a multiwell pad.
In early October, a 1 MMcfd and 500 Mcfd unit were operating in parallel at a four-well Hess pad site near Watford City, ND (see photos). The units, shown to UOGR, had been on site for 2 weeks. The pad site did not appear to be connected to pipelines. Onsite storage tanks collected crude and NGL while natural gas was flared.
Hess now has 5-10 gas capture units working at its Bakken wellsites.
Leading Bakken producer
The Bakken is expected to be the single biggest contributor to Hess' company-wide production growth through 2018. Production averaged 80,000 boe/d in the second quarter, up 25% from the year-earlier period. A September investor presentation shows output rising to 125,000 boe/d in 2016 and 150,000 boe/d in 2018.
Hess holds more than 640,000 net acres of Bakken leasehold and has allocated $2.2 billion to the play this year. It is running a 17-rig program and brought 53 gross operated wells online in the second quarter. Drilling and completion costs averaged $7.4 million/well.
In addition to introducing the remote NGL capture technology, Hess earlier this year increased processing capacity at its Tioga gas plant in northwestern North Dakota to 300 MMcfd from 100 MMcfd. Bakken flaring was expected to fall to 15-20% of total gas production after the plant reopened, down from 25% prior to the expansion (UOGR July-August 2014, p. 15).
Pipeline constraints
Pipeline capacity constraints are evident in state data. In April, about two thirds of North Dakota's flared gas came from pipeline-connected wells.
During the first few months that a multi-well pad is online, the initial production surge can overwhelm pipeline capacity-knocking upstream wells off the system and increasing flaring volumes.
Additional natural gas pipeline, processing, and compression capacity is being constructed across the state. This, combined with wellsite gas conditioning technology like Gtuit's, is helping to reduce the proportion of gas being flared, even as new production continues to come online each day.
"The [Gtuit] technology is helping us to reduce flaring and capture value in the Bakken as we our work to get key infrastructure in place," Roper said.
Data from the North Dakota Department of Mineral Resources show 28% of the state's 1.3 bcfd of gas production was flared in August, down from a high of 36% in Sep. 2011, when production was just 490 MMcfd.
The Gtuit system has applications for wells that come online in areas with limited gas pipeline or processing capacity. Gtuit monitors the flow rates and, when high initial production rates taper off, a company technician removes a unit and reinstalls it at another one of the operator's wellsites.
Production rates are highest in the initial months after a well is brought online.
Jesse Jones, lead analyst for Wood Mackenzie, said production at a typical Bakken well declines by 50-60% in the first 6 months that it is online, relative to the 30-day initial production rate. Output typically falls 70-75% in the first year.
At wellsites that utilize the Gtuit technology, extracted NGL is stored on site in 18,000 gal storage tanks, known as portapacs, which are typically emptied every 1-3 days, depending on the number of units onsite and the flare gas composition.
A field technician from Gtuit supervises offloading to ensure proper safety protocols are followed and neither the onsite storage tank nor the delivery truck contains water that would cause the load to be rejected upon arrival at a processing facility. The partnership also manages the transportation logistics of the extracted NGL.
Price tag
In a presentation to the NDIC in April, Gtuit Pres. and Chief Executive Officer Brian Cebull said the typical cost for a 500 Mcfd system that includes all equipment and service is $45,000-60,000/month, depending on the number of systems. The company has a variety of cost models that include sharing a proportion of proceeds generated by NGL sales.
In early October, Gtuit operated 12 remote NGL capture units in the field. The units were divided amongst Hess and two other producers.
By mid-October, Gtuit's units had collectively processed more than 3 million gal of Bakken NGL.
Gtuit is one of several companies selling portable, wellsite technology designed to reduce flaring. GE Oil & Gas Inc. offers CNG In A Box, a mobile system the size of a shipping container that compresses gas at the wellsite for use in bifuel rigs, vehicles, and other equipment. Statoil tested the GE system earlier this year.
Interest in the Gtuit system increased after North Dakota Gov. Jack Dalrymple approved the flaring reduction plan. "We've seen significantly more energy around this since the July ruling," Reif told UOGR.
By Jan. 1, 2015, operators will be required to capture 77% of their Bakken gas production, rising to 85% in January 2016. As the statewide flaring reduction deadline approaches, mobile well site technology is apt to attract more attention.