The U.S. Department of Energy's Energy Information Agency (EIA) has reversed its initial assessment of California's Monterey Shale in the San Joaquin and Los Angeles Basins. Originally, in July 2011, the EIA estimated technically recoverable resources from the Monterey/Santos Formation at 15.4 billion barrels (Bbbl)—-more than twice the Eagle Ford and Bakken Shales combined. On May 22, 2014, however, the agency lowered its assessment by 96% to only 600 MMbbl of estimated technically recoverable resources.

Expectations are that operators will shy away from the Monterey as a potential tight oil resource in the aftermath of the EIA’s full version of the assessment, published in June. Prior to the EIA’s press release concerning the new assessment, Hart Energy Research & Consulting had examined more than 145 wells drilled in the Monterey Formation and come up with type curves much lower than the EIA’s original estimate of 550 MMbbl.

The Miocene shales of the Monterey Formation are the primary source rock in California and are found in multiple basins throughout the state. The source rocks include the Lower Monterey and the Santos Shale formations, which are often referred to as the Monterey/Santos Formation. The formations are thick, with multiple heterogeneous, biogenic-rich (siliceous, calcareous and carbonaceous) deposits, and only a minor fraction of the volume would be considered true shale.

The naturally fractured Antelope Shale zone of the Monterey Formation in Buena Vista Hills Field has been producing for more than 50 years. It has an oil gravity ranging from 25 to 40 degrees API. Although several companies have completed wells in the Antelope Shale, only Occidental Petroleum Corp. (NYSE: OXY) has reported plans for ongoing drilling in the Monterey.

Hart Energy selected and analyzed wells with first production starting in 2000 that were completed in the Antelope member of the Monterey. Our WorkbenchTM database indicates there are 145 of these wells in Kern County in the San Joaquin Basin. We categorized the wells into three groups based on their first three months' average production rate. Three decline type curves were used to match production history of these wells.

About 81% of the wells analyzed fall under the low type curve and only 8% fall under the high type curve.

Lower rate wells have a slower decline rate exhibiting a harmonic decline pattern, while the higher rate wells follow the power law decline curve. The type curve EURs derived for high, medium and low IP rate well groupings were 243 Mboe, 135 Mboe and 118 Mboe, respectively. These EURs are quite low compared to the average wells in oil plays such as the Bakken and Permian and are considerably lower than the EUR assumed in the EIA’s July 2011 report. What is not clear at this time is how many, if any, of these wells were drilled as horizontals with multiple-stage hydraulic fractures.

Although the Monterey Shale has vast available resources yet to be explored, the well results we derived and the limited available public operator disclosures raise questions about the play’s viability. Unless operators can successfully drill horizontal wells with multiple-stage hydraulic fractures to improve well performance, we don’t see this play as being developed on a large scale in the near term.

Moreover, stringent regulations for hydraulic fracturing in California could further slow play development. According to a February 2014 Ceres study on hydraulic fracturing and water stress, the Monterey play is in areas with high water stress. At this time, acidizing is generally used to stimulate wells rather than hydraulic fracturing. The increasing frequency and severity of droughts in California could make it difficult to apply hydraulic fracturing on a large scale. Also, more injection and disposal well construction could raise concerns among the public that hydraulic fracturing could increase the risk of earthquakes, significantly limiting the play’s potential.

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