Producers wary as Colorado oil, gas rules become law

Colorado Gov. Bill Ritter Jr. said that new oil and gas regulations would allow the industry to grow in a sustainable way compatible with the state’s economy as he signed them into law on Apr. 22. Producers remain concerned that the rules will simply create more delays and expenses.

“These rules were shaped with valuable input from people all across the state and unanimously adopted by the Colorado Oil & Gas Conservation Commission [COGCC]. They strike the right balance, a balance that recognizes the importance of a healthy industry and the importance of healthy communities, water supplies and wildlife,” the governor said.

“In 1999, Colorado issued 1,000 drilling permits. Last year, the state issued more than 8,000. These new, modern rules recognize this increase in drilling activity as well as the technological changes that have occurred within the industry over the past decade. The rules also incorporate the forward-looking practices already being used by companies such as EnCana, Williams, and Gunnison Energy,” he said.

The regulations took effect May 1 on federal lands and began to apply Apr. 1 on all other lands in the state.

Several producers with operations in the state did not want to comment for attribution. “We’ve handed this off to the Colorado Oil & Gas Association [COGA] because we’re going to have work under these new rules. I could speak for a good half hour if this was off-the-record,” one company’s official told OGJ.

“Our primary message involved the business environment for oil and gas companies in Colorado. Obviously, with the economic downturn, the state government has created an uncertain business environment where companies might be more comfortable to Louisiana or Texas,” said Nate Strauch, COGA communications coordinator.

‘Second bite of the apple’

Strauch said, “Colorado’s permitting already takes longer than the national average.

“Under the new rules, after the permit has been approved, different entities can come in and challenge the action. Surface owners can come in and second-guess the decision. So can the Department of Public Health and the Division of Wildlife. This gives them a second bite of the apple after being involved in the process already if they don’t like the results,” he told OGJ.

Strauch and Jack Ekstrom, a COGA board member, separately expressed concern about the new regulations’ impacts on smaller producers.

“The investment in compliance involves whether you can afford to do it. The delays and difficulties in getting a rig and having to restart the clock because of some minor hiccup remain to be seen,” said Ekstrom, who is executive director of investor relations and corporate communications at Whiting Petroleum Corp., Denver.

“You probably won’t see evidence during this downturn because there are plenty of rigs available. But once there’s an uptick, a company’s difficulty in timing and contracting for services may be complicated by having to wait or stand by if it hasn’t jumped through all the hoops perfectly,” he said.

COGCC Director Dave Neslin said the agency received a wide range of input as the regulations were developed.

“We incorporated a lot of input from both large and small operators, and we will continue to work with operators to help them comply successfully with these requirements,” he said.

“We intend to implement these changes in a reasonable and responsible manner. If there are issues we didn’t anticipate or if further changes are needed, the commission will consider adjustments. That’s the advantage of working through a regulatory process instead of the courts,” he told OGJ.

Downhole chemicals

The new regulations contain several significant provisions. Under Section 205, operators will be required to keep an inventory by wellsite of each chemical used downhole or stored for use downhole during drilling, completion, and workover operations, including fracture stimulation, in an amount exceeding 500 lb during any quarterly reporting period. They also will maintain an inventory of fuel stored at the well site in an amount exceeding 500 lb in a quarter.

When the composition of a chemical product is considered a trade secret by its vendor, operators will be required only to maintain the product’s identity. The vendor or service provider will be required to supply COGCC with a list of a trade secret chemical product’s ingredients when the commission’s director notifies them in writing that the information is necessary to respond to a spill or release, or a property owner registers a complaint about such a release.

COGCC’s director or designee may disclose such information to other staff members, but only to the extent that it is necessary for spill response assistance. The director also may disclose this information to relevant county public health directors or emergency managers, and the Colorado Department of Public Health and Environment’s environmental programs director. These individuals may then share this information with staff members under similar terms.

Vendors or service providers will also be required to provide a trade secret chemical product’s chemical constituents to any health professional if that professional, in submitting a written request, also executes a confidentiality agreement stating that the information will not be used for other purposes.

Oil field product manufacturers expressed concern about possibly having to disclose such ingredients, which they consider proprietary information, during a US House Oversight and Investigations Committee hearing 18 months ago. It was not immediately clear whether they think this provision in Colorado’s new regulations adequately addresses this issue.

Comprehensive drilling plans

Sec. 216 of the new regulations gives operators, for the first time, the opportunity to develop a comprehensive drilling plan.

This is designed to identify foreseeable oil and gas activities in a given geographic area, facilitate discussions about potential impacts, and facilitate measures to mitigate adverse consequences. An operator’s decision to initiate and enter into such a plan is voluntary.

“We’re trying to encourage companies to work with us at the planning stage and effectively bundle a number of locations together for the regulatory review process. That can be more efficient both for the companies and for us as a regulator, and to better understand cumulative effects. The aim is to look at a broader landscape instead of a single well. We’re trying to create incentives to use this rule, while trying to provide as much flexibility as possible so we’re not create impediments to this broad planning,” Neslin explained.

Several sections in the 300 series of the regulations revised the drilling permit process, he said.

“First, we have differentiated between the downhole technical issues and the surface environmental issues, which will be addressed in a separate location assessment. The idea is that Form 2-A, the second form, would be submitted for an entire drilling pad. Again, this is an effort to create efficiency. Each well would still require a drilling permit,” he said.

COGCC also will provide additional notice for public comment by posting the location assessment on its website and by supplying certain information from the drilling permit application to the local government, the surface owner and nearby landowners, according to Neslin.

“In certain instances, we will consult regarding the application with the state health and wildlife departments. We have tried to limit those to where they would provide added value. Consultation with the health department, for instance, would occur when an operator is seeking a variance, while the wildlife division would be consulted when an operator proposes drilling a well in sensitive wildlife habitat,” he told OGJ.

Public water systems

Section 317-B provides special protection for public water systems, Neslin continued.

“It creates a setback requirement next to drinking water tributaries and imposes operating standards for an additional half mile from the tributary. These public drinking water tributaries have been mapped with these buffer and operating standard areas. This is a new requirement that deliberately incorporated a lot of language proposed by the industry. It’s a lengthy requirement, but there are opportunities for operators to obtain exceptions and variances,” he said.

Sec. 608 deals with coalbed methane wells. Its provisions include a requirement for operators to assess the risk of gas or produced water leaking to the ground surface or into subsurface water resources, taking into account plugging and cementing procedures in any recompletion or plugging-and-abandonment report filed with COGCC. Other subsections address water well sampling, coal outcrop and coal mine monitoring, a static bottomhole pressure survey prior to production, bradenhead testing, and locally specific field orders.

Neslin said that another rule, Sec. 805, deals with odors. It was developed after the state and county governments in the Piceance basin received several complaints. Operators will be required to install an emissions control device on certain kinds of production equipment that emit 5 tons/year or more of volatile organic compounds within ½ mile of schools, homes, and hospitals. Constructions of pits with that amount of VOCs yearly also will be restricted, he said.

There are three new wildlife rules in the 1,200 sections of the new regulations. One allows the state’s wildlife division to consult with the COGCC, operator, and surface owner regarding wildlife impact mitigation. The agency will not be allowed to veto the drilling permit, but it can make suggestions, Neslin said. “These sensitive wildlife areas include elk winter range, big horn sheep winter range, elk calving areas, and grouse production areas,” he said.

A second involves restricted occupancy areas, which the COGCC director described very small areas around the state’s most critical wildlife areas such as within a half mile of a bald eagle nest or 300 ft of a cutthroat trout habitat. In these areas, operators will be required to avoid additional surface disturbance where technically and economically feasible to do so.

Not an ‘NSO’ requirement

Neslin continued, “If an operator can develop the resource from outside the area, we expect them to do so. If they can’t, they won’t be required to.

“It’s not a ‘no surface occupancy’ requirement. Operators can also consult with the Division of Wildlife and our staff on alternative mitigation within these areas,” Neslin said. The third new wildlife rule involves operating practices, many of which were proposed by producers which are using them already, he added.

“We also updated our pit requirements to reflect the best current practices, including liners, soil standards, and groundwater standards. The bonding requirements, which had not been changed in 12-14 years, were updated to reflect current costs. We have updated some of our safety requirements to reflect new information and current practices,” he noted.

Neslin said COGCC thinks the new requirements strike a balance which allows the oil and gas industry to continue to operate in the state while protecting the environment and the public’s safety and welfare.

“The commission is sensitive to the need to facilitate a smooth transition. It grandfathered existing permits and permit applications. We’ve done training across the state to educate companies about the amendments and how they apply. We’ve tried to explain the amended permitting process. And we’re working through issues as they arise with operators, the Department of Health, and the Division of Wildlife to investigate environmental and wildlife issues,” he told OGJ.

But COGA’s Strauch said the new regulations fall short of what the legislature intended. “When it gave the commission authority to promulgate the rules, the directive include a requirement for them to be timely and efficient. The process proved to be neither,” he maintained.

Ekstrom said, “The COGCC claimed the rules hadn’t been altered for years. But if you go back through the records, there have been changes which we thought were reasoned and rational, and had the industry’s input. With the latest rules, we were asked to comment and participate in a meaningful way. But it’s my perception as a director of COGA that our serious and reasonable suggestions were, if not summarily dismissed, given short shrift. I found the process very disappointing.

“We talked about jobs. The western part of the state has experienced significant downturns in employment. Certainly the national financial malaise and crash in prices had something to do with it. But our company decided that with these new rules, we’d move our rig over to Utah,” he told OGJ.

Afar Exploration Co. LLC, Tulsa, cited possible terrorist activity in terminating a planned 150 line-km seismic survey on the 3.75-million-acre Afar block in northern Ethiopia in early April 2009.

Antitank mines along a road near the border with Eritrea exploded, killing several people and destroying passenger vehicles, William C. Athens, president of Afar, reported to the Ethiopian Ministry of Mines & Energy.

Afar Exploration, which holds 100% interest, previously ran airborne gravity and magnetic surveys on the block in the Danakil depression and located structures promising for oil and gas potential, Athens said (see map, OGJ, Apr. 14, 2008, p. 39).

New Zealand Crown Minerals will make available 1,500 km of 5,000 km of recently shot 2D seismic in the unexplored Reinga basin in the Tasman Sea off the northern tip of the North Island.

CGG Veritas gathered the data on a nonexclusive basis. Current information suggests geology similar to the Taranaki basin, but the previously available seismic did not attract industry interest.

“The new seismic shows many possible leads including sedimentary drapes over basement highs with adjacent deep grabens and stratigraphic pinchouts. A thorough interpretation of the data by New Zealand’s GNS Science will precede a blocks offer opening in late 2009,” Crown Minerals said.

Cimarex Energy Co., Denver, has participated in 49 wells in the Anadarko basin Woodford shale play since late 2007.

Of the 49 wells, 36 are on line and the rest are either awaiting completion or drilling. The 30-day initial average production rate, normalized for a 4,300-ft lateral, is 4.5 MMcfd.

The company’s 2009 program is to drill or participate in 50 gross (23 net) wells. Cimarex holds 98,000 net acres in the play.