Posted on 12/03/2013 5:26:20 AM PST by thackney
Depending on whom you ask, it looks like California is getting closer to tapping the nearly 15 billion barrels of recoverable oil that lies deep in the Monterey Shale. On September 20, 2013, Governor Jerry Brown signed SB 4 into effect, a bill that provides California with its first set of requirements specifically associated with hydraulic fracturing and other well stimulation techniques, such as acidizing. Less than one month later, the California Department of Conservation (DOC) has released proposed regulations applicable to well stimulation treatments in the state, initiated the State’s environmental review process and set the stage for the release of Emergency Regulations, under which owners and operators will be able to proceed with well stimulation in the interim.
While both industry and environmental groups may have wanted more from out of SB 4, its passage and swift implementation will provide some certainty now for oil and gas operators looking to develop the Monterey Shale, and avoids a situation like that in New York State, where the future of hydraulic fracturing remains in limbo.
Further studies
SB 4 requires California’s Natural Resources Agency to, by January 1, 2015, complete a comprehensive independent scientific study on well stimulation treatments, including an evaluation of “the hazards and risks that well stimulation treatments pose to natural resources and public, occupational, and environmental health and safety.” SB 4 requires the study to be truly comprehensive, covering everything from the chemical make-up of the treatment to the way that flowback is treated after stimulation. Specifically, SB 4 provides that the study should consider well stimulation treatments, additive and water transportation to and from the well site, the mixing and handling of well stimulation treatment fluids and additives at the well site, options for the use of nontoxic additives in treatments, the use or reuse of treated or produced water in well stimulation treatment fluids, and the treatment and disposal of flowback fluids and other materials, if any, generated by the treatment. The study must also consider “acid matrix treatments” and air emissions, including potential greenhouse gas emissions.
SB 4 also provides that the DOC’s Division of Oil, Gas and Geothermal Resources (DOGGR) must conduct an Environmental Impact Report (EIR) to provide the public with detailed information regarding “any potential environmental impacts of well stimulation in the state. The requirement to perform an EIR goes beyond the analysis that is typically required for oil and gas activities in California. The state Senate Rules Committee noted in its analysis of SB 4 that “DOGGR regularly approves oil and gas development proposals under the CEQA categorical exemptions for minor alterations to land or existing facilities, or by way of negative or mitigated negative declarations. As a result, oil and gas permits are rarely reviewed in EIRs that would evaluate the potential risks associated with hydraulic fracturing.”
On November 15, 2013, DOC published a “Notice of Preparation” of an EIR “to evaluate the impacts of existing and potential future oil and gas wells stimulation treatments” occurring in the state. DOC has stated that the objectives of the EIR process are to:
identify, evaluate and disclose the potential environmental impacts of well stimulation treatments of both conventional and non-conventional oil and gas resources within the State;
further the State Legislature’s efforts to ensure that well stimulation practices are conducted in a manner that assures environmental protection, public safety, data collection and reporting, interagency coordination, regulatory oversight and monitoring, and public disclosure; and
allow for the safe recovery and production of the State’s oil and gas resources.
In December 2013 and January 2014, DOGGR will host several Scoping Meetings to solicit public comment on determining the scope and content of the EIR. Down the road, the study will result in publication of a Draft EIR and a Final EIR. Once the Draft EIR is released, there will be a 30-60 day public comment period.
Proposed regulations
Previously, in December 2012, DOGGR released a pre-rulemaking “discussion draft” of regulations applicable to hydraulic fracturing. The discussion draft did not trigger the formal rulemaking process and simply acted as a means of engaging stakeholders in the process early on. DOGGR withdrew the discussion draft following the passage of SB 4.
SB 4 directs DOGGR to develop regulations by January 1, 2015, that include the following components:
revisions to the rules and regulations governing construction of wells and well casings to ensure the integrity of wells, well casings, and the geologic and hydrologic isolation of the oil and gas formation during and following well stimulation treatments;
full disclosure of the composition and disposition of well stimulation fluids;
a provision for the well operator to provide for baseline and follow-up water testing upon request by a nearby property owner; and
threshold values for acid matrix stimulation treatments.
SB 4 also sets forth the need “to promote regulatory transparency and accountability.” To accomplish this, SB 4 directs DOGGR to enter into formal agreements with other agencies as necessary to clearly delineate “respective authority, responsibility, and notification and reporting requirements associated with well stimulation treatments and well stimulation treatment-related activities, including air and water quality monitoring.”
As directed by SB 4, DOC released its proposed regulations on November 15, 2013. Generally, the DOC proposed “SB 4 Well Stimulation Treatment Regulations” define the types of well stimulation treatments, e.g. “hydraulic fracturing,” and set out various requirements applicable to such treatments. Some of the requirements covered by the proposed regulations include the need to
obtain a permit prior to the treatment,
provide pre-treatment notice to property owners so that baseline water testing can be conducted,
perform an evaluation of the well integrity prior to treatment and monitoring during treatment,
adhere to standards for storage and handling of well stimulation fluids, (v) perform post-treatment monitoring, and
submit to the Chemical Disclosure Registry information relating to the contents of the treatment.
The release of the proposed regulations kicks off the beginning of the formal rulemaking process and the 60-day comment period. DOC has indicated that, in alignment with SB 4, the regulations are scheduled to go in to effect on January 1, 2015. In the meantime, DOC plans to implement emergency regulations effective January 1, 2014 “to ensure the major requirements of SB 4 are addressed in the interim.”
In the meantime…
Unlike New York, California does not expect industry to sit on the sidelines until January 1, 2015 when the final rules are to be promulgated. SB 4 provides that, until the rules are finalized and implemented, DOGGR “shall allow” all well stimulation treatment activities, provided various conditions are met. DOC plans on releasing a “streamlined interim procedure” by December 13, 2013.
The interim procedure will take the form of Emergency Regulations, effective January 2014, for a one-year period. Under the Emergency Regulations, owners and operators will be able to proceed with well stimulation treatments without obtaining a permit, as long as certain conditions are met. Based on DOC’s SB 4 Implementation Plan, the Emergency Regulations will:
define well stimulation treatments covered by the interim procedure, including threshold values for acid volume;
with assistance from the State Water Board, provide initial guidance for owners and operators on the development of groundwater monitoring plans;
specify how operators are to certify compliance with SB 4, including disclosures relating to:
-the date and location of the well stimulation treatment;
-the makeup and volume of fluids other than water, by CAS number and trade name;
-disposition of fluids;
-tracer use;
-radioactivity of produced fluids;
-water use and water management planning compliance;
-groundwater monitoring compliance;
-compliance with requirements for neighbor notification and neighbor testing rights; and
-the posting of chemical information to the Internet.
Looking forward
Governor Brown included a signing statement with SB 4 that specifically references permitting under the new law and the need for efficiency in issuing permits. In that statement, Governor Brown directs the DOC to “develop an efficient permitting program for well stimulation activities that groups permits together based on factors such as known geologic conditions and environmental impacts, while providing for more particularized review in other situations when necessary.”
Governor Brown has pledged to work with the state legislature to address certain areas of SB 4 and to develop amendments as needed. While there is still work to be done, the passage of SB 4 signals that California has recognized the tremendous potential of the Monterey Shale and is working toward establishing a regulatory program to facilitate the development of that resource now. Despite some challenges on the horizon, SB 4 demonstrates California’s commitment to developing the Monterey Shale, which provides the oil and gas industry with some certainty. The end result could be a boon to a state economy that has had its fair share of rough spots over the last few years.
“Oil executive Harold Hamm, who made billions tapping the vast Bakken oil field in North Dakota before other companies saw the potential, sounded a pessimistic tone about whether the industry will develop California’s Monterey Shale formation, which is estimated to have possibly five times more oil.
“It’s just been tough to break the code on how to get that,” said Hamm, founder and CEO of Continental Resources, an independent oil company with the largest footprint in the Bakken oil fields in Western North Dakota. “Everybody thought they could and it hasn’t worked out.”
He added that the field, which is located in the San Joaquin Valley in central California, has not yet matured to a form that companies could develop with today’s technologies.”
And if you think that the Sierra Club and other greenies are going to allow any real development, I have a bridge to sell you.
Again, the work has already started. There are multiple companies that already have wells in the Monterey. It has been technically challenging in ways different from the Eagle Ford and Bakken.
Yep. If you look at the hwy infrastructure, the only roads heavy equipment can use is scenic Hwy 1, Hwy 68 to Salinas, and Hwy 101 which runs North and south connecting to 1 and 68.
Progress is slow, but there are about 3 dozen rigs working the Monterey Shale plays.
Shale requires tracking or some other form of making the shale liquid enough to flow…. tell me where exactly are these so called working wells? You can’t mean the rigs off of Santa Barbara that have been shut down since the last century.
And by the way drilling means next to nothing if you aren’t getting anything out
The Monterey, like Eagle Ford and Bakken, are not retorting the shale to release liquid. The are producing the liquid already released from the shale via geological process. The vast majority of hydrocarbons is still locked in the shale and requires heat to release, but the 2~5% that is already released is in the billions of barrels.
The Monterey shale field is 100% onshore. It overlaps a lot of the Bakersfield area.
This bit of fluff from the oil industry is about an area that has produced oil for more than 100 years. It borders the Kern oil fields. You also notice from the article that there is NO mention of actual tracking or otherwise dealing with the shale to give up its oil.
Colorado Shale fields were in this same state in the 70s. Much was claimed, much was ‘started’….nothing was produced and all major players have pulled out.
Do not kid yourselves. California is NOT North Dakota. This will never come to fruition EVEN IF the technology were there
“Shale requires tracking or some other form of making the shale liquid enough to flow…. tell me where exactly are these so called working wells? You can’t mean the rigs off of Santa Barbara that have been shut down since the last century.
And by the way drilling means next to nothing if you aren’t getting anything out”
There are bridges in Arizona that can also be sold for all those anxious to throw money into the Monterey Shale.
The Monterey takes a very thick oil column and/or extensive natural fractures to make it commercially attractive.
Reason is simple physics: liquids do not move well in this type of rock unless assisted by fractures. That is the secret to Bakken’s success.
One cannot make money attempting to duplicate fractures provided by Mother Nature. Just too expensive to accomplish.
The commercial success stories are few and far between, mostly offshore with thick oil columns assisted by natural fractures, and some onshore with local fracturing complexity.
Most of the oil produced in California over the years is believed to have its origin in the Monterey Formation and has migrated to more permeable layers, which has given rise to some of the nation’s largest oil fields. These large fields, including Midway-Sunset, Belridge South, Kern River, Cymric, and Wilmington, are situated in the southern half of California (although oil production is found in other parts of the state, as well). About 77 percent of California’s crude production is from the state’s top 10 fields. The single highest producing county in the state is Kern County, which alone accounts for approximately three-fourths of the state’s crude oil output.
http://oilindependents.org/the-story-of-california-crude/
After dropping to less than 20 active rigs in late 2009, activity in California has surged to more than 50 rigs, according to Baker Hughes. Many of those rigs are pursuing traditional production, but shale development has been active as well, particularly in the Monterey formation itself. While much of this activity is done through vertical and directional drilling, the state has also recently experienced steady horizontal drilling since 2011. Horizontal wells tend to run deeper than other wells in the state. The Monterey formation’s geology is varied and compartmentalized, but is based on diatomaceous material (the skeletons of microscopic diatoms) that varies from low-permeability diatomite closer to the surface to a more fractured material at greater depths to a quartz phase at the deepest ranges. It presents its own unique challenges, and specific techniques used elsewhere may not be directly applicable in the Monterey. This may be one reason California’s shale potential is more latent when compared to many states around the country.
And again I suggest to you that California oil production is well known and has been hampered consistently over the last half century. People have blocked expansion off shore. They have block expansion in the Bakersfield area.
How many barrels have these 3 dozen rigs produced to date???
You used the word tracking again. Do you mean hydraulic fracturing or something else.
It is on the edges of the Kern Oil Fields discovered in the 19th century. Oil has been produced in California for over a hundred years. We do not disagree on that. Your little sniper says nothing that I didn’t already acknowledge. What has not been shown is anything productive from actual shale rock. Californians routinely do things against their own best interest. They shut down power plants. They institute new air resources board regulations. They block off shore drilling. They shut down existing sites.
You can hope all you want. The truth is the left in California will kill this off way before the bullet train gasps its last breath
Do you understand that the falling oil production rate in California finally bottomed out and began a tiny climb?
No doubt they are behind most everyone others. And plenty of folks will drag down the progress and get in the way. But the increase in production has started, following the increase in drilling rigs that already started.
California Field Production of Crude Oil
http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=MCRFPCA2&f=M
darned autofill…. FRACKING FRACKING that’s what I meant to type.
Thank you for bringing to my attention
They opened up old wells in the Kern Field.
Please quit hyperventilating over this. You do not seem to understand the politics of California at all. You can throw out oil reports all you want. The logging industry in California was killed by the greenies. I already cited the manufacturing losses in Silicon Valley (and through out the state). California is a home for wayward Mexicans and very rich folks from either Hollyweird or Silicon Valley.
Those who happen to be there because they have been there before things went so friggin nuts know that things are getting worse not better.
Wrong. Venoco for example has been producing oil from the Monterey since the late 1990s. The flow rates don't match the believe potential, but it has been going on for a while.
Example:
http://investor.venocoinc.com/phoenix.zhtml?c=193733&p=irol-newsArticle&ID=1875709&highlight=
During the third quarter, Venoco successfully completed a well to a probable location in a separate geologic structure, known as Coal Oil Point, located to the northeast of Platform Holly in the South Ellwood field. The Coal Oil Point structure has two separate fault blocks. The well path of the probable well resulted in the intersection of the northern fault block in only the lowermost Monterey zone (M7), whereas the southern fault block was intersected in only the uppermost Monterey zone (M1). The well was completed in two sections, the first of which was in the northern fault block and was wet and the second of which was in the southern fault block and was successful. The well was on production for approximately 15 days prior to the annual maintenance shutdown at Platform Holly and produced at an average rate of approximately 220 barrels of oil per day over that period. Subsequent to the shutdown, production from the well declined to an average rate of approximately 100 barrels of oil per day.
By the way, I've done design and construction work for oil/gas in California. It has been a decade since the last time, but I have some understanding. I've been involved in getting construction and operation permits (limited role, more engineering/design/construction/startup)
No you really don’t. Those who live there or who have just recently left know. You do not.
and by the by the ND Bracken field uses fracking
The application of hydraulic fracturing technology caused a boom in Bakken production since 2000. By the end of 2010 oil production rates had reached 458,000 barrels (72,800 m3) per day outstripping the pipeline capacity to ship oil out of the Bakken.[9][10] The production technology gain has led a veteran industry insider to declare that the USGS estimates are too low.[11]
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