Industry leaders are calling for changes to the North Dakota Industrial Commission’s, NDIC, proposed field rules for conditioning Bakken crude.
The commission decided at its Nov. 13 meeting to open the document to public comment for one week to allow interested parties to offer any further insight or recommendations. The North Dakota Petroleum Council, along with individual operators and other industry groups were quick to criticize the commission’s plans to set specific operating temperatures, pressures and techniques in order to establish a standard barrel of Bakken oil.
“We support the NDIC’s overall concept of a Reid Vapor Pressure Target but oppose the micromanagement of how we reach that target,” NDPC President Ron Ness stated in a submitted letter.
The proposed order would require the state’s oil to be treated at temperatures of at least 115 degrees Fahrenheit and pressures of at least 50 pounds per square inch, psi, in order to stay at or below a Reid vapor pressure of 13.7 psi. The order requires operators who are not already complying with temperature and pressure parameters to undergo a quarterly third party test of the crude to ensure that the Reid vapor pressure has not exceeded 13.7 psi. Any operator seeking alternative methods to condition the oil must request approval by going before the commission through the formal hearing process. In addition, transload rail facilities must submit a notice to the Department of Mineral Resources if they discover that any Bakken crude oil received exceeds the 13.7 psi threshold and also provide the source of the oil and action taken to deal with the noncompliance.
The American Petroleum Institute, API, noted that Bakken operators may develop operating procedures on an individual basis considering a variety of factors unique to their businesses and the NDIC should not interfere by requiring specific parameters.
“We believe that if NDIC’s goal is to limit the vapor pressure of crude oil, then the most effective and clear way to do so would be to prescribe a vapor pressure specification and not operating requirements,” API Group Director of Downstream and Industry Operations Robert Greco, III said in a statement.
Greco also points out that while the commission expects operators to follow conditioning standards at well sites, it fails to recognize that crude oil may not be directly transported from the well. Some may be gathered and transported from a storage area and further processed by additional facilities.
“In that case, the rules to meet 13.7 psi should be imposed on the stream that leaves the processing facility (e.g. stabilizer) for transport, with those results then applicable to every well or lease processed by the additional equipment and facilities,” Greco explained in an effort to show that the order is unclear in its intent and implementation.
Temperature issues
While operators generally support the NDIC’s efforts to improve the marketability and safe transportation of crude oil, they request greater flexibility in the methods to achieve it. Hess Corp. proposed using a gas-liquid separator and/or an emulsion heater-treater to heat fluids to a range of 90 to 120 degrees Fahrenheit that can be retained for at least 30 minutes.
“Hess’ Bakken operating experience has shown that as retention time in a gas-liquid separator and/or emulsion heater-treater is increased, the temperature requirements to lower vapor pressure values is decreased,” the company said in a submitted statement.
Operators feel that the higher temperatures could limit operators’ ability to use gas gathering pipelines which cannot operate with fluids heated to more than 120 degrees Fahrenheit without negatively impacting the equipment. XTO Energy Engineering Manager for Western Operations Matthew Gusdorf said the pipelines are designed to operate at moderate temperatures to allow higher pressures to maximize gas volume throughput, so higher temperature gas can be accepted but only at lower pressures.
“Imposing the temperature requirements would have a dramatic effect on the ability to gather gas and could subsequently lead to a step-change increase in flaring,” Gusdorf said.
The NDPC also contends that the NDIC’s proposed order does not take into account all operating conditions such as daily flow rates and ambient temperatures and ultimately creates unintended consequences such as flaring, emissions, and fire hazards.
Measuring pressures
Hess stated its concerns about sampling practices, noting that the commission did not fully clarify how Reid vapor pressures would to be measured. The company recommended that sampling be done in a simple procedure that is repeatable and does not require equipment with limited availability. Hess proposed an amendment to the proposed rules that would only require quarterly testing until a historical trend of compliance is established. Then testing would only be conducted annually. Since Hess currently operates 53 central facilities and 283 well sites, it feels the proposed quarterly sampling would be “unduly burdensome” to its operations. It estimates that the price to comply with sampling at that frequency would add $1 million to $2 million to operating costs each year. Hess also requested that the third party testing requirement be amended to allow for testing to be done by sufficiently trained Hess personnel and then periodically audited by a qualified third party.
Overstepping railroad boundaries
Operators challenged the NDIC’s authority to regulate rail transloading facilities since it is preempted by the Hazardous Materials Transportation Act which prohibits states from imposing requirements on railroad safety in addition to federal government regulations. Federal rules already provide limitations on flashpoint, initial boiling point, packing requirements, labeling and placarding requirements.
“Since the federal hazardous materials regulations governing the transportation of petroleum crude oil do not regulate RVP (Reid vapor pressure) and would allow Bakken crude with an RVP greater than 13.7 to be transported, North Dakota’s RVP restrictions are preempted, as they would preclude the transportation of a hazardous material that is authorized for transportation under the HMTA,” David Friedman, regulatory vice president for the American Fuel and Petroleum Manufacturers, AFPM, said in submitted comments.
“By their very nature, rail transloading facilities operate in interstate commerce because the vast majority of crude oil produced in North Dakota is shipped out of state for refining,” Hess Field and Plant Operations Director Brent Lohnes explained. Lohnes added that an additional layer of state regulation on these shipments could cause discrimination of out-of-state crude that may not meet the 13.7 psi and restrict the state’s terminals’ ability to handle that production.
“The field rule would … slow the transportation of out-of-state Bakken crude oil, and thus conflict with a key purpose of federal transportation safety law,” Lohnes continued.
Taking responsibility
API accused NDIC of making rail terminals do its job of ensuring producers comply with regulations. If the commission expects every incoming load of crude oil to comply, API feels the testing should be conducted by the regulators or an independent third party on behalf of the regulators, or monitored and reported by the producers themselves. Furthermore, API is unclear on how NDIC expects rail operators to dispose of any non-compliant crude oil since stabilization equipment would be a multi-million dollar expense for rail terminals and the intent of NDIC was to keep all conditioning and stabilization requirements at the wellhead.
Senior Vice President Nathan Savage of the Savage rail facility near Trenton, North Dakota, expressed concerns that testing crude on every inbound truck or pipeline would be “extremely onerous, very expensive and operationally infeasible.”
He gave an example that if Savage received 75,000 barrels of crude per day by truck, Reid vapor pressure testing would equate to an additional expense of $96,000 a day. Installing the necessary equipment to conduct the testing would cost $1.2 million. His other concern was the continuous flow of crude oil from pipelines into his facility and no practical means to isolate the source wells for the crude or to stop the incoming flow pending pressure test results.
