Rachael Seeley,
Editor
Operators that fail to comply with North Dakota's flaring reduction targets in the Bakken shale may soon be compelled to curtail production from wells found in violation, according to an order issued by state regulators in July.
The order, signed by North Dakota Gov. Jack Dalrymple, is considered the final regulatory piece of a flaring reduction policy approved in March by the North Dakota Industrial Commission (NDIC)(UOGR, May-June 2014, p.5).
Lynn Helms, director of NDIC's Department of Mineral Resources, said most Bakken operators already comply with the flaring reduction targets. "Most of the operators and big companies are in compliance on a statewide basis. There are some that are very close, and they've got some work to do," Helms said.
North Dakota oil production has risen sharply in recent years thanks largely to the Bakken and Three Forks formations. Earlier this year, state-wide production exceeded a record 1 million b/d. North Dakota is now the second-largest oil producing state in the US, after Texas.
Just over 1 bcfd of gas is produced in North Dakota, most of which is associated gas from Bakken and Three Forks oil wells. However, a lack of gas gathering infrastructure has led to high amounts of flaring. Thirty percent of state-wide gas production was flared in April. That is down from 36% in March, due to the start-up of Hess Corp.'s expanded Tioga Gas Plant.
Gas plant capacity in North Dakota now exceeds total gas production. However, "many bottlenecks exist in the current gas gathering infrastructure due to the high liquid content of the gas, the prolific volumes of oil and gas yielded during initial production, increasing pipeline pressure that requires the installation of additional compressors, and, in some cases, undersized pipe," the order said.
First deadline nears
The first deadline for the flaring reduction plan is fast approaching. The state intends to capture 74% of gas production by Oct. 1, 2014. That figure rises to 77% in January 2015; 85% in January 2016; and 90% in October 2020.
Operators must report October production figures to the state by Dec. 1. "We will then audit October production in December and potentially impose production restrictions in January," Helms said. Wells that collect 60% of associated gas may be capped at 200 b/d of oil production, and wells capturing less may be capped at 100 b/d.
There are no exceptions for wells connected to gas gathering systems with insufficient capacity. In April, about two thirds of North Dakota's flared gas came from connected wells.
According to the order, "In instances where significant amounts of surplus gas is flared due to the insufficient collection system, production should be restricted unless significant amounts of surplus gas is captured for beneficial consumption, or utilized in a value-added process."
Mobile solutions
In areas with insufficient infrastructure, producers may gather, process, and utilize surplus gas at the wellsite. Some producers, like Statoil North America Inc. and Hess Corp., have already deployed such technology. Statoil, for instance, is utilizing rigs and equipment capable of running on a combination of natural gas and diesel (UOGR, May-June 2014, p.1).
Other technologies available to help producers meet flaring reduction targets include GE Oil & Gas Inc.'s 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. A partnership between Gtuit LLC and Corval Group offers similarly sized mobile units capable of extracting NGL from the gas stream at the wellsite. Producers also may lease mechanical refrigeration units (MRU) from Kinder Morgan Treating for use at the wellsite.
Statoil is pilot-testing the CNG In A Box system, and Hess Corp. is expanding its use of Gtuit's mobile NGL extraction system. Kinder Morgan said it had 10 MRU leased in the Bakken region in July, with more on the way.
David Reif, vice-president of business development for Corval, said Gtuit's technology enables producers to avoid flaring until permanent gas gathering infrastructure is installed and manage high gas flows during the initial production phase.
A mobile flaring solution is ideal because flaring moves around the Williston basin, occurring wherever midstream capacity is overwhelmed. It often occurs in an area when a group of wells on a multiwell pad is brought online at high initial rates, knocking other wells off local midstream systems.
Helms said production restrictions serve a dual purpose. "The obvious one is to reduce the volume of gas flared or the duration of the flare. But they also provide an extremely strong financial incentive to contract with some type of wellsite process or gas gatherer, if they are available, to actually gather or put the gas into a value-added process," Helms said.
Production curtailments will prompt producers to view wellsite gas utilization technologies from a new perspective. The stand-alone economics of many of these technologies are not enticing, due to relatively low natural gas prices in the US, but the equation changes when curtailed oil production is factored in.
Helms said: "Companies have looked at those technologies on a stand-alone economic basis and this will force them to look at it on a holistic, how-does-it-impact-production basis-to be able to utilize something that's marginally economic, or maybe slightly economic, in order to impact an overall well."
The state does grant leniency in certain circumstances. In areas where leasehold is not held by production, the first well drilled in a spacing unit is permitted a 14-day initial flowback period during which it can flow at unrestricted production rates, followed by another 76 days of maximum efficient production regardless of whether it is connected to a gas gathering system.
The exception is designed to allow producers to make planning decisions about future wells and infrastructure needs in the spacing unit.
Gas capture plan required
A key aspect of the state-wide flaring reduction plan, which became effective June 1, requires producers to submit a gas capture plan with every application for a permit to drill a well. The plans are designed to improve communication between producers and midstream companies and promote better planning for gas-handling needs.
Gas capture plans include information on area gathering system connections and processing plants; the rate and duration of planned flowback; current system capacity; a timeline for connecting the well; and a signed affidavit verifying that the plan has been shared with area midstream companies (UOGR, May-June 2014, p.5).
As of July 1, the Oil and Gas Division had received 136 permit applications with the newly required gas capture plans. Of these, 27 had been approved.
According to Helms, production curtailments will provide the state with an enforcement mechanism for ensuring that operators submit quality gas capture plans and flaring reduction goals are ultimately met. "Obviously, the goal here is not to restrict production," Helms said.
