What Techniques Work Best in the Monterey?
As pointed out in paper SPE 16277 (“What We Don’t Know About Self-Sourced Oil Reservoirs: Challenges and Potential Solutions,” 2012), the authors’ view is “that without significant collateral siltstone/sandstone or natural fracture systems present, little liquid petroleum production will be possible at commercial rates from typical mudstone-rich reservoirs.”
What this means is that oil produced directly from Monterey source rock must be found in areas bound by structural traps where the oil has been transported via sedimentological or fracture-hosted secondary or collateral carrier systems in mudstone-rich sections.
The authors underscore the basics: “The bulk of the oil storage in source rocks, however, is in kerogen, where dramatically diffusive [i.e., released to higher permeability regions of the reservoir at slow rates] rather than Darcy flow processes operate and where imposed fracturing may have little impact on productivity.”
In addition, as delineated in paper SPE 153310 (“Recent Advances in Dynamic Modeling of Naturally Fractured Reservoirs”), “Naturally fractured … reservoirs have complex pore systems because they are susceptible to diagenetic alteration including dissolution, dolomitization, and fracturing processes, which may enhance the reservoir quality or occlude reservoir quality through cementation.”
According to USGS geologist, Lynn Tennyson, “There is a whole complicated topic involving diagenetic changes in silica-dominated rocks, with increasing depth that affects oil storage and trapping (soft, very porous Opal-A diatomite, to more brittle less porous Opal-CT, to very easily fractured, brittle, not-very-porous quartz chert/siliceous shale). Any one of those can be an oil reservoir. The deepest one—brittle siliceous shale or chert—is the one that would be the unconventional reservoir, if the oil is still there and hasn’t mostly escaped to shallower reservoirs.”
Given the complexities of the diagenetically altered Monterey formation, what methods can be successfully used to exploit it either as a source or a reservoir rock?
According to Paper SPE 135520 (“Successful Thermal Recovery of Heavy Oil from an Ultra-Tight Reservoir Renews Development of the 100-Year-Old Orcutt Oil Field,” 2010) discusses a project that shows oil production by cyclic steam stimulation of oil-saturated diatomite is possible. The authors point out that this method of oil production has been successful in the San Joaquin basin since around 1996. Steam stimulation in the Orcutt field, some 100 miles southwest, also proved successful.
Following short-lived attempts to mine the diatomite in the 1920s and again in the 1980s, oil began to be produced at the Lost Hills and Belridge fields in the 1980s using fracture stimulation and water injection. By the mid-1990s, operators started to experience breakthroughs in heavy-oil diatomite projects using a modified cyclic steam stimulation approach. A combination of small steam dosages and close well spacing appears to have been first made in the Cymric field.
“Since that time,” say paper SPE 135520’s authors, “the process as it is applied today includes several variations for exploiting the richly oil-saturated diatomite. It has grown to become one of the leading oil extraction methods in California, accounting for about 12% of the state’s total daily output, or around 70,000 B/D. There are active projects in the South Belridge, Cymric, McKittrick, North Midway, and Midway-Sunset oil fields in the San Joaquin basin and in the Orcutt oil field in northwestern Santa Barbara County.” Major oil companies, as well as small and large independents, are conducting these operations.
According to Paper SPE 35745 (“Acid Stimulation Increases Production in 31S C/D Shale Reservoirs, Monterey Formation, Elk Hills Field, California,” 1996), a total of 29 carefully designed hydrofluoric acid treatments were delivered in the Monterey formation, Elk Hills field, from 1992 to 1995. The acid stimulation remedial program reversed an annual decline rate of 13% to an annual incline rate of 15%. The authors note, “the formation differs from other Monterey formations in that evidence of large widespread fracturing was not found.” This, again, speaks to the heterogeneity of the Monterey.
Occidental states on its website that it has “gained significant experience with shale production following [its] 1998 acquisition of Elk Hills field in Kern County, California.” Oxy points out that more than one-fourth of its California production is currently from what it calls “shales”—“porous rock that contains hydrocarbons but has little permeability.”
Oxy likens the Bakken and Eagle Ford shales to those in California, saying “They compare favorably … on such factors as total organic content, gross thickness, depth, porosity, and permeability.” It does not mention the key differences, however, including the Monterey formation’s depositional age, extreme natural fracturing, tendency towards great thickness, multiple lithofacies, tectonic activity, and folding that in places is quite contorted.
The main factor to consider with any shale is that, as Apache’s George E. King states in paper SPE 133456 (“Thirty Years of Gas Shale Fracturing: What Have We Learned?” 2010) “No two shales are alike”—whether considering different formations that are widely geographically separated, different wells within the same formation, or different locations along one wellbore.
Oxy does state it “is applying the expertise gained from exploring and producing Elk Hills’ shale zones to some of its other California assets, including properties in the Los Angeles, Ventura, and San Joaquin basins.” The company states that the development program to appraise a resource it estimates as being “over 20 billion bbl of potential oil in place” will occur over many years, while the company also studies “stimulation methods, interval production, reservoir characterization, and reservoir management techniques.”
Generally speaking, as stated in paper SPE 144526 (“Is There a ‘Silver Bullet Technique’ for Stimulating California’s Monterey Shale?” 2011), “the economics of a Monterey development are affected by the thickness of the pay interval. The thickness of the target pay is one of the most important parameters in deciding between a vertical or horizontal wellbore.”
In one example, paper SPE 144526 authors cite the southeast Lost Hills field, where the pay thickness can be as much as 800 ft with variable Monterey shale lithologies spanning the productive target intervals. Depending on the well location on the anticlinal structure, the top of the first productive horizon (Reef Ridge) is ~6,000 ft and the base of the lowest productive horizon (McDonald shale) is as deep as ~9,500 ft. Oil accumulation is a result of a stratigraphic and structural trap. Field development has been with 5½-in. cemented casing in vertical wellbores, completed with multiple hydraulic fracture stages. The fracture staging strategy and fracture treatment design has evolved over the years, beginning mostly around 1980.
In another example within paper SPE 144526, the authors describe the economical development of the Rose and North Shafter fields, where the pay interval is a thin 40-ft layer of McLure shale, a Miocene Age quartz-phase biogenic source siliceous shale (i.e., “porcelanite”). The oil accumulation occurs on a homocline (i.e., a diagenetic trap with Opal CT siliceous shale acting as the caprock). Conventional vertical wells were not economic; acidizing only provided a short-lived productivity improvement. Horizontal wells with an uncemented liner, completed with a single hydraulic fracture treatment stage, produced economic results. “Despite the multiple-component far-field fracture complexity,” write the authors, “sufficient fracture width was created to avoid pervasive proppant bridging problems.” The authors caution, however, that “this may not be true in other California Miocene Monterey development areas, due to the generally high level of tectonic activity across the state.”
It is likely that a combination of techniques—including matrix acidizing (with and without horizontal drilling), thermal recovery by steam-flooding and cyclic steam-injection, and waterflooding, in addition to some usage of hydraulic fracturing in single or multiple stages along with vertical or horizontal drilling—will, with increased precision due to improving simulation and reservoir characterization methods, be used in production from wells targeting the Monterey. The key will be continued improvements in understanding the formation—both as a source rock and reservoir.
“The Best Analog for the Monterey Is the Monterey”
This statement was made by Venoco vice president of exploration Michael D. Wracher on slide #19 of a Venoco presentation, dated 26 May 2010, titled “Monterey Shale Focused Analyst Day.” The Monterey’s characteristics, while extensively studied, need to be explored much further. The following are three examples of developments that point to increased understanding of the Monterey:
Scanning Acoustic Microscopy
“Successful exploration and production programs for organic-rich shales (ORSs),” states paper SPE 123531 (“Maturity and Impedance Analysis of Organic-Rich Shales”), need reliable identification of their kerogen content as well as maturity through indirect seismic methods. However, the properties of kerogen are poorly understood, so predictions about maturity and rock-kerogen systems remain a challenge.”
The authors of paper SPE 123531 used scanning acoustic microscopy to analyze and map the impedance microstructure in ORSs. From this they quantified textural properties in images (from formations including the Bakken, the Woodford, the Niobrara, and the Monterey, among others) and related these textural properties to maturity and to impedance from acoustic-wave propagation measured at centimeter scales.
The combined study of acoustic properties and ORSs’ microstructures gave important insight into changes resulting from kerogen maturation. It appears that textural heterogeneity, elastic impedance, velocity, and density increase with increasing shale maturity. In such ways, understanding is growing about how to determine, before drilling, the presence of kerogen in formations like the Monterey. Kerogen content might best indicate the presence of commercial quantities of oil.
More and Better Seismic
Oxy and Venoco jointly funded a 500-square-mile 3D seismic survey in California, the largest ever conducted there. It was completed in 2011, and the results have not yet been revealed.
The MARS Project
The Monterey and Related Sedimentary Rocks Project, founded in 2011, is led by director Richard Behl, professor in the Department of Geological Sciences at California State University, Long Beach.
“At the same time that there has been a loss of expertise [due to retirement and turnover],” states the MARS Project prospectus, “there is a compelling need to address new and more sophisticated questions about the origin, variability, and character of Monterey and related sediments and how the primary composition and distribution controls reservoir characteristics, such as matrix porosity, permeability, and fracture networks.”
The MARS Project is a focused center of excellence dedicated to researching the Monterey formation and has a dozen students currently working on Monterey-related theses. Corporate affiliates include Oxy, Aera Energy, Venoco, ExxonMobil, BreitBurn Energy Partners, Plains E&P, Signal Hill Petroleum, and Bayswater E&P.
Looking to the Future
According to EIA statistics (which start at 1981), onshore California oil production has steadily declined from a peak of 34.3 million bbl/month in January 1986 to less than half that—16.4 million bbl/month in January 2013. And from a peak of 6.3 million bbl/month mid-1995, oil production offshore the US West Coast has been in decline, to the most recent figure of 1.4 million bbl/month in December 2012.
An auction for 15 California oil and gas lease parcels conducted by the US Department of the Interior Bureau of Land Management on 12 December 2012 was expected to garner some excitement. All 15—in California’s Fresno, Monterey, and San Benito counties—were sold. But the prices were startlingly low. A total of 17,832.80 acres sold for USD 104,099.50. Average bid per acre was USD 4.21, with USD 10.00 the high per-acre bid.
“We have no crystal ball when it comes to the Monterey formation,” said Pete Stark, vice president of industry relations at IHS/CERA. “But then no one does. As Winston Churchill said [about Russia], ‘It is a riddle, wrapped in a mystery, inside an enigma.’”
Ken Peters, science advisor for Schlumberger Information Solutions and consulting professor in the Department of Geological and Environmental Sciences at Stanford University, commented, “The Monterey source rock contains far greater volumes of hydrocarbons trapped within kerogen and matrix porosity than all of the conventional oil that migrated away from it. However, many technical challenges remain.”
“Depending on location,” he explained, “the source rock may be immature, it may have the wrong geomechanical properties for effective hydraulic fracturing, or it may be too deep for hydrocarbons to be recovered economically. Advanced technology, including three-dimensional basin and petroleum system modeling, will be the key to competitive advantage in the renewed search for both conventional and unconventional Monterey resources.”
Peters and several other co-principals at Stanford lead the Basin and Petroleum System Modeling (BPSM) Industrial Affiliates Program, where PhD candidates conduct research using geochemistry and petroleum system modeling software. Much of this research involves studies related to the Monterey formation. Corporate affiliates include Aera, BP, Chevron, Conoco-Phillips, Great Bear, Hess, Nexen, Oxy, Petrobras, Saudi Aramco, and Schlumberger.
“It is possible that most of the generated oil has migrated upwards into conventional structural and stratigraphic traps,” said the USGS’s Lynn Tennyson. “We just don’t know.” The USGS is in the process of assessing the Monterey using a “probabilistic geology-based methodology.”
Tennyson has been reading through well histories that describe what happens when one drills a deep well that accesses the Monterey formation. “My impression,” she said, “and it’s not a result, but an impression, is that with a lot of wells drilling in the deep Monterey, there’s a little oil and a lot of water. The oil seems to peter out in months and the water increases.”
“It’s a sad fact that most of the big fields in California were discovered in the late 1800s and early 1900s, when oil industry technology was still in its infancy,” said Peters. “Today, Monterey plays are divided by company into many postage-size areas and it’s difficult to connect the dots using advanced technology. It is time for more companies to share or trade information and support research programs designed to address these complex problems.”
“The future potential of the Monterey is not just finding true ‘unconventional’ oil,” commented the MARS Project’s Rick Behl. “There’s also the potential for finding deeper, hidden, or more subtle conventional oil.”