Insights to the future of California oil regulation gushed at a Thursday meeting of government and local industry representatives near Bakersfield.
Among the more notable tidbits to flow from the well-attended gathering was word that the agency crafting the state's first fracking-specific regulations is considering reaching out to regional water boards about the possibility of "allocating" water for the highly effective but equally controversial technique.
Also discussed at Thursday's meeting of the California Oil & Gas Workgroup were state regulators' latest ideas about how upcoming rules could protect groundwater during fracking, also known as hydraulic fracturing, and what disclosure requirements these regulations may contain.
Fracking was not the only subject to hold the industry's attention Thursday. State Department of Conservation officials also took questions about how they may respond to recent legal challenges to state environmental reviews of oil projects, and they hinted at how they may tackle the thorny issues of underground waste injections and leakage of oil field fluids in the oil-rich diatomaceous geological formations in West Kern.
As things stand, oil producers are left to their own devices to secure water for fracking, which injects water, sand and chemicals underground at high pressure to release oil that is otherwise unrecoverable. Recent industry data suggest that a single frack job in Kern County uses an average of about 155,000 gallons of water.
While that's several millions of gallons less than fracking typically requires in natural gas-rich states like Pennsylvania and Texas, State Oil and Gas Supervisor Tim Kustic said fracking operations in California still use "significant (water) resources."
He clarified during a break in the meeting, explaining that the department has no authority over water allocation. But he said that his agency within the department, the state Division of Oil, Gas and Geothermal Resources, may decide to engage somehow with water boards, some of which have already expressed interest in fracking's impact on water resources.
"I don't know if we would play a role other than notifying them," he said.
Kustic added that, as part of a formal rulemaking process expected to begin later this year, DOGGR is also looking at how to safeguard the integrity of cap rocks that effectively prevent fracking fluids from migrating upward and contaminating groundwater. He said the division may prohibit fracking within a certain buffer zone below the cap rock, and that it will likely impose a minimum distance from which fracking may be performed near other wells to prevent fluid migration.
Also, the division is thinking about reviewing existing well records to make sure cap rock is protected, Kustic said. That would save oil companies time and money because they would not have to gather geological core samples or perform other tests.
Kustic also touched on a sensitive issue for oil producers: pre-notification of frack jobs. He said the new rules may contain some level of prenotification to DOGGR, as well as post-fracking reporting. The industry has opposed any requirement to inform nearby residents before fracking out of fear that it could stir up local opposition to the practice.
Another touchy topic he addressed were potential regulatory distinctions between fracking in areas with freshwater reservoirs and places with undrinkable groundwater, such as oil-rich West Kern. Without going into much detail, he said there could be "subtle differences" in how the division approaches regulation in each scenario.
Kustic's boss, Mark Nechodom, director of the Department of Conservation, offered some thoughts on how his staff is considering responding to at least two lawsuits accusing the state of performing inadequate environmental reviews of oil projects on Kern County farmland.
"It's time to update and rethink how we do this" environmental work, Nechodom told Thursday's audience of about 45 people gathered at the local office of the federal Bureau of Land Management. He quickly added, however, that any new process will involve "no surprises" and that changes would only be made after a series of discussions set for this fall.
In fact, he said, the department has long intended to change its approach to California Environmental Quality Act reviews, which he said is sufficient but needs to be more carefully defined for legal purposes.
Kustic took time to update the work group on DOGGR's progress toward new rules on cyclic steaming, or "steam fracking," in West Kern's diatomite oil fields. That oil-rich region is where a Chevron supervisor was killed in 2011 after falling into a sinkhole state investigators believe was caused by cyclic steaming.
With no similar sinkholes reported since the tragedy, the division has focused its efforts on preventing leakage and eruptions of fluids, known as "surface expressions."
Kustic said such events appear to have been significantly reduced by new industry practices that involve closer monitoring of cyclic steaming and quicker response to surface expressions. He added that new rules will eventually address cyclic steaming in Kern's diatomaceous formations but that DOGGR has its hands full for now.
Another focus of DOGGR's in recent years has been how to regulate injections of hydrogen sulfide -- a toxic, naturally occurring gas better known as "sour gas" -- and other oil field waste materials.
Kustic's predecessor, Elena Miller, had argued that the division has no authority to regulate sour gas injections, which the industry sees as crucial to local oil production. Miller also insisted on careful review of such injections to protect groundwater. The industry complained that she was holding up oil production. In November Gov. Jerry Brown sided with the industry and fired Miller as well as Nechodom's predecessor, Derek Chernow.
Kustic said Thursday that the division has gathered legal opinions confirming that DOGGR does, in fact, have authority to regulate sour gas injections.
But in a change that could pose new costs to oil producers, he also said that DOGGR could begin requiring that oil field operators continuously monitor injection wells.
Currently, the main tests of injection wells, a form of pressure testing, is required only once every five years.