2.1 Geology

The San Ardo Oil Field is underlain by a western-sloping ridge composed of granitic basement rocks [22–25] that lie an average of about 700 meters (m) below land surface (bls) [17,26]. A series of warped sediments overlies the basement. The lowermost of these sediments are the marine-deposited Monterey, Santa Margarita, and Pancho Rico Formations. The Monterey Formation is the deepest of the marine formations and is composed of shales with interbedded organic-rich sands that produce oil from an anticlinal structure [22,23]. Oil is produced from two pools or zones: the Lombardi and Aurignac sands. The Lombardi sands produce gas and heavy oil (9-11^o American Petroleum Institute [API] gravity) from a depth of about 600 m bls [22,25]. The deeper Aurignac sands produce 13^o API gravity oil [25]. Above the Monterey Formation is the Santa Margarita Formation, which is composed of medium to coarse sands. The Pancho Rico Formation overlies the Santa Margarita Formation with 50–200 m of low-permeability mudstone, silt, and shale [17,22–24]. The overlying Paso Robles Formation and alluvial sediments consist of nonmarine gravel, sand, silt, and clay. It is often difficult to determine the geologic boundaries between the Paso Robles Formation and alluvial sediments [23,24].

The Los Lobos fault complex intersects the San Ardo Oil Field along the Salinas River (Fig 1) [24]. The areas west of the fault have undergone extensive folding and faulting, and the Monterey Formation has been thrust to the land surface [27]. Thin alluvium is also present in the tributary valleys west of the fault [28]. Additional information about the geologic system and geologic cross sections are provided in Stephens et al. [17].

2.2 Hydrogeologic setting

Fresh groundwater is primarily obtained from the unconfined alluvial valley aquifer that consists of shallow alluvial sediments and the underlying Paso Robles Formation in the alluvial valley [29]. The bottom of the Paso Robles Formation has been considered the base of freshwater, < 3,000 milligrams per liter (mg/L) total dissolved solids (TDS) [30,31]. The thickness of the alluvial sediments is about 60 m [30], and the thickness of the Paso Robles Formation is 90–335 m [24,32,33] in the San Ardo area. The alluvial valley is typically 1–3 km wide [17].

The Salinas River is a dominant hydrologic feature in the study area and flows northwest to Monterey Bay. It is the primary source of recharge to the alluvial valley aquifer and affects the movement and quality of groundwater [7,17,18,30]. Recharge from the river has been enhanced since the late 1950s by two upgradient reservoirs that capture winter flows and release water during dryer summer months [7]. Other sources of recharge are irrigation-return flow, intermittent infiltration along tributaries to the Salinas River, and percolation of precipitation that falls across the rest of the landscape. Treated produced water (PW; i.e., water produced along with hydrocarbons) discharged to recharge basins also has contributed water to the alluvial valley aquifer since 2007 (Fig 1) [34].

West of the alluvial valley, where the Monterey Formation is at land surface, groundwater flow is primarily through bedrock fractures. Only a few groundwater wells exist, but springs are common and streams flow intermittently in the valleys [27]. Groundwater west of the Los Lobos fault is generally of low quantity and quality [28]. Oil seeps at the land surface [24,35] and groundwater with up to 4,400 mg/L TDS at shallow intervals (<100 m bls) are naturally present in areas west of the Salinas River [28]. East of the alluvial valley, the Paso Robles and Pancho Rico Formations outcrop, with thin alluvium occurring in tributary stream valleys [21,29].

2.3 Oil-field history

The San Ardo Oil Field was discovered in 1947. However, substantial development did not occur until a pipeline was installed between the oil field and the Standard Oil Company’s Estero Bay marine terminal in 1951 [23]. Oil production peaked in 1967 at over 2.9 million cubic meters (m³) [36]. Since 2011, production has been relatively stable at about 1 million m³ of oil extracted from the oil field every year. Gas resources have also been produced from the San Ardo Oil Field, peaking in the 1950s. As of 2023, the San Ardo Oil Field had 3,063 wells (898 active, 482 idle, and 1,683 abandoned) [37].

The San Ardo Oil Field contains low-gravity oil, making it necessary to use injected steam to reduce its viscosity for extraction. These techniques increased the estimated ultimate recovery in the field from 32 million m³ in the late 1950s to 84 million m³ by the mid-1970s [38]. As of 2018, most active wells associated with oil production activities relied on cyclic steam to aid extraction, a method used in the field since 1963. These wells are injected with steam for a period of several weeks to several months. Oil is extracted until the temperature drops and the viscosity of the oil increases. The cycle is then repeated.

The process of injecting steam for enhanced recovery generates large amounts of hot water (~100 degrees Celsius [^oC]) along with the oil (produced water), which can range from 10 to 20 times the amount of oil recovered [39]. Most of the PW is injected back into producing and nonproducing zones via injection wells [31,40]. As of 2023, 15 PW disposal wells were active in the field and 24 were idle or abandoned (Fig 1) [37]. Oil-field PW has been reinjected into the Aurignac sands, Lombardi sands, and the Santa Margarita Formation [31,40].

To reduce the amount of water in the producing and injection zones, a water treatment facility was completed in 2007 to treat up to 7,900 m³ per day [34,39]. Multiple treatment processes are used at the facility, including de-oiling, degasification, chemical and ion exchange softening, multi-media filtration, cartridge filtration, double-pass reverse osmosis (RO), pH neutralization, and partial remineralization [39]. Output from the facility is discharged to post-treatment wetlands for additional treatment through sedimentation, microbial degradation, precipitation, and plant uptake. After wetland post-treatment, the water reaches the alluvial valley aquifer through recharge basins (Fig 1) [39,41].

2.4 Potential sources of hydrocarbons in groundwater

Anthropogenic activities and natural process have potential to affect groundwater quality near the San Ardo Oil Field. Spills and leaks in the oil field have been documented (Fig 2). In 1987, hydrocarbons were detected at concentrations above action levels established by the Monterey County Department of Health in shallow groundwater below an underground storage tank during its abandonment [42]. From July 2001 to April 2002, a steam injection well (API #0405321557) had a breached casing at about 183 m bls that potentially released liquid containing inorganic constituents, such as chloride, and vapor containing hydrocarbons into the Paso Robles Formation [43]. In 2022, hydrocarbons were detected in groundwater samples collected 4.3 to 5.2 m below three lined sumps that were historically used to store PW [44]. Records of the California Department of Conservation [45] include several documented oil-well casing failures that were within the zone of fresh groundwater, but a systematic review of oil-well records for escaped fluids was not within the scope of this study.

Download:

• PPT
  PowerPoint slide
• PNG
  larger image
• TIFF
  original image

Fig 2. Land cover and potential sources of hydrocarbons at or near the land surface in the San Ardo Oil Field study area, California.

Potential hydrocarbon sources from California State Water Resources Control Board [46], Bramlette and Daviess [35], and Durham [24]. Land cover from Multi-Resolution Land Characteristics Consortium [47]. Base map features from U.S. Geological Survey and California State digital data. [BTEX, benzene, toluene, ethylbenzene, and xylenes; LUST, leaking underground storage tank; RMP, California Oil and Gas Regional Monitoring Program; TPH, total petroleum hydrocarbons].

https://doi.org/10.1371/journal.pwat.0000499.g002

Landfills and surface disposal sites are within the study area and have been monitored in accordance with California waste discharge requirements. A disposal site that accepted oil-field wastes, including sulfur sludge, oily water, tank bottom sediments, and drilling muds, was active west of the Los Lobos fault from 1971 through 2002 [28] (Fig 2). Hydrogeologic assessments and monitoring of this site indicated that the oil-field wastes are contained on-site by low-permeability geologic barriers. Two former solid-waste landfills are located west of the town of San Ardo (Fig 2). One landfill was operated from 1961 to 1981 and the other operated from 1980 to 1984 [48]. Materials accepted include non-hazardous municipal, commercial, agricultural solid waste, and inert demolition debris from San Ardo and surrounding areas.

Naturally occurring oil seeps, tar sand, and bituminous rock outcrops are common west of and along the Los Lobos fault where the Monterey Formation is at the land surface [24,35]; however, commercially viable quantities of hydrocarbons were not discovered. These seeps may be from faults and fractures in the Monterey Formation that provide conduits for hydrocarbons to migrate from deeper in the formation to the land surface. Groundwater with up to 4,400 mg/L TDS at shallow intervals is also present west of the Los Lobos fault and concentrations were larger than California Drinking Water Maximum Contaminant Levels (MCLs) for cadmium, nickel, thallium, and selenium and secondary MCL's (esthetics) for sulfate, chloride, manganese, and total dissolved solids [28].

3.1 Sample collection

The USGS RMP collected six types of water samples using established water data-collection protocols and procedures [49–51]: groundwater (GW), Salinas River water (SW), springs (SP), water produced with oil from oil wells (PW), treated oil-field water for injection into oil-field formations, and wastewater from the RO treatment plant. Samples were collected from March 2019 through July 2021 from the area within the San Ardo Oil Field administrative boundary and the surrounding 5-km buffer zone in Monterey County, California (S1 Table). The sample sites were selected from searches of well databases and by contacting private landowners, local water agencies, and oil companies for permission to sample wells. Site access did not require permits.

Eighteen groundwater wells were sampled to obtain water chemistry data near oil development and in locations upgradient and downgradient from the San Ardo Oil Field (Fig 1 and S1 Table). Groundwater samples were collected from one public-supply well (GW-2), five monitoring wells (GW-1, GW-4, GW-14, GW-15, and GW-16), two irrigation wells (GW-5 and GW-13), one livestock well (GW-12), five wells that supply water for oil-field operations or other uses (GW-17, GW-19, GW-20, GW-21, and GW-22), and four domestic wells (GW-3, GW-6, GW-7, and GW-11). Two samples were collected from the Salinas River (SW-8 and SW-9). Sample SW-8 was collected upgradient of the San Ardo Oil Field, and sample SW-9 was collected downgradient of the San Ardo Oil Field. Two spring samples were collected west of the Los Lobos fault (SP-10 and SP-18). For purposes of this study, spring samples are categorized with groundwater samples. Ten oil wells were sampled for PW (PW03, PW04, PW05, PW06, PW07, PW08, PW10, PW11, PW12, PW13), two samples were collected to represent treated PW after removal of oil planned for injection (PW01 and PW09), and one sample of RO treatment plant wastewater was collected (PW02).

Each site was sampled once and therefore represents a snapshot in time. Shallow samples that have recharged the aquifer recently can be affected by changing conditions at the land surface, and water chemistry can vary temporally, complicating interpretations about the spatial relations of chemical constituents to potential sources. Available historical water chemistry data (see section 3.5) were insufficient to determine changes in groundwater chemistry through time [52]. However, groundwater-age tracers showed that most samples represented mixed age or premodern groundwater, which tend to have slower changes in groundwater quality than shallow modern-aged water affected by short term recharge events. Of the seven samples that contained modern and shallow groundwater, only one (GW-16) was central to the interpretations in this paper. In addition, analysis of water-level data through time (see section 3.3) do not show systematic changes in hydrologic conditions over time that can cause changes in groundwater quality.

3.2 Laboratory analysis

Groundwater and Salinas River samples were analyzed for (1) water-quality indicators, (2) major and minor ions, (3) nutrients, (4) trace elements, (5) volatile organic compounds (VOCs), (6) naturally-occurring radioactive material (radium isotopes), (7) groundwater age-dating tracers, (8) dissolved organic carbon (DOC), (9) dissolved standard and hydrocarbon gases (methane through hexane), (10) dissolved noble gases and atmospheric gases, (11) hydrogen and oxygen stable isotopes of water, and (12) hydrogen and carbon stable isotopes of methane [50]. This wide range of analytes provides information about the presence of chemical constituents that may be directly related to oil-field fluids (petroleum hydrocarbon VOCs and hydrocarbon gases) and other geochemical tracers that serve as supporting lines of evidence for potential mixing with oil-field fluids. The primary constituents discussed here are those with results most helpful for identifying potential effects of oil-field activities on groundwater in this study area. Oil-field water samples were analyzed for most of the same analytes except for age-dating tracers. All sample data are available from the U.S. Geological Survey Water Data for the Nation National Water Information System database at https://doi.org/10.5066/F7P55KJN [53] using the site identification numbers and sample dates listed in S1 Table.

Samples were classified as modern (recharged during or after 1953), premodern (pre-1953), or a mixture of ages based on the groundwater-age tracers tritium (³H) and carbon-14 in dissolved inorganic carbon (¹⁴C-DIC). Premodern groundwater was defined as having no detected ³H and ¹⁴C-DIC less than 75 percent modern carbon [51,54]. Modern groundwater was defined as having a ³H activity greater than 0.59 tritium unit and ¹⁴C-DIC greater than 90 percent modern carbon [19,51,55,56]. If any value fell outside of those ranges, the sample was classified as a mixture of modern and premodern groundwater. These thresholds are approximate values for classifying groundwater ages.

3.3 Groundwater-level elevations

To understand the directions of groundwater movement in the San Ardo area, a groundwater elevation model was constructed to map the water table over time. The modeled groundwater surface is intended to represent unconfined conditions spatially and temporally. The groundwater elevation (GWE) modeling here follows methods from Gillespie et al. [57] and Stephens et al. [58]; the model code, input data, and output data are available from Stephens et al. [58].

The GWE model input data consisted of groundwater elevations measured at water well sites (from various sources, refer to Stephens et al. [58]), river stage from a USGS stream gage on the Salinas River (SW-8, USGS streamgage 11150500), and water-table elevation estimates from geophysical logs collected after oil wells were drilled [58]. Measurements of GWEs were omitted if the uppermost well perforation was unknown or deeper than 40 m bls to ensure data represented unconfined conditions as much as possible. Forty meters was chosen because it delineated the set of shallower and deeper wells in the area. River stage elevations along the length of the Salinas River were included by extending measured river stage from the streamgage site and maintaining the river stage relative to change in land surface elevations along the river. In total, 1,684 GWE inputs were indexed with both space-time coordinates and the land surface elevation from a digital elevation model [58].

A Gaussian process (GP) was used to spatially and temporally model GWEs [59]. GPs are statistical models that use covariance functions to interpolate discrete observations into a continuous quantity. For the GP model, is a -element vector of water level measurements (in m relative to sea level) and are vectors of the space-time coordinates of these observations (space in km, time in years). denotes land surface elevation at location from a digital elevation model (in km). The GP estimates water level measurements as having the distribution . The covariance matrix has three components: a term for spatial trends, a term for spatial and temporal stationary correlations, and a term for observation noise. It is constructed using a location featurization function

(1)

a distance function

(2)

and a gamma-exponential stationary covariance function

(3)

where is the distance returned from Eq. 2. Combining these yields an expression for each entry of column in :

(4)

where distance

(5)

and noise term

(6)

with being an indicator function that returns 1 when its argument is true, else 0. Parameters of the model thus consist of the trend magnitude , a magnitude parameter (the “sill”) s, length scale , shape parameter , anisotropy scaling parameter , uncorrelated noise magnitude , and site-correlated noise magnitude that pertains to water level measurements from the same well. These parameters were fit to the measurements using maximum likelihood and are reported in S2 Table. The model was implemented using Geostat [60].

3.4 Hydraulic gradients between the aquifer and oil-field zones

Hydraulic gradients between oil-field zones and overlying groundwater were determined by comparing fluid-level elevations measured in idle oil wells (IWE) by oil-well operators [61] with the modeled GWE in the aquifer at those idle oil-well space-time locations. Available IWEs were primarily distributed across the main oil-production area and measurement dates ranged from 1988 to 2017. The most recent IWE was used for this comparison, and its value was subtracted from the modeled GWE value that corresponded to the IWE measurement space-time location [58]. Positive differences indicate that hydraulic gradients favor upward flow, and negative differences indicate potential for downward flow, if pathways permitting vertical flow exist. IWEs were not available for the area north of the main oil-production area where the largest amounts of fluids have been injected.

3.5 Historical water chemistry data

Results from the COGG RMP sampling efforts were supplemented with historical water chemistry data from five sources (S1 Fig): U.S. Geological Survey [53], the California State Water Resources Control Board [46,62–64], the California Department of Water Resources [65], the California State Water Resources Control Board Division of Drinking Water [66], and Metzger [52]. Historical water chemistry sample results were reviewed for inorganic constituents; benzene, toluene, ethylbenzene, and xylene (BTEX); age-dating tracers; and light hydrocarbon gases. Presence of BTEX was used to indicate the occurrence of hydrocarbons in groundwater because those compounds adversely affect human health [67] and are, therefore, analyzed more frequently than other hydrocarbons. BTEX also have relatively higher solubilities than other hydrocarbons [67].

3.6 Oil-field infrastructure and activities

Well construction, fluid-injection volumes, and fluid-production volumes were obtained from the California Department of Conservation [37,40]. Spatial patterns of the fluid-volume balance (difference between injection and production) for the time period with data available for individual wells (January 1977 through December 2017) were determined for all oil-field pools (Aurignac, Lombardi, and Santa Margarita) using methods described in Shimabukuro et al. [68], Stanton et al. [69], and Stanton et al. [70].

Current California oil and gas regulations require annular cement in the borehole annulus between the steel casing and the surrounding formation from the top of the oil and gas reservoir to about 30 m above the base of the freshwater zone, and in some cases to land surface [71]. However, many oil wells installed historically have gaps in borehole annular cement overlying oil-producing zones. Gaps in the annular cement can potentially serve as pathways for upward movement of fluids from oil production and injection zones when they are within the geologic formations that confine oil-field fluids. The cemented intervals in oil wells at the time of construction were estimated for this study using methods described by Stanton et al. [69, appendix 4] on the basis of reported depth of the cement injection point, casing diameter, borehole diameter, casing bottom, and the volume of cement and cement additives used [37]. Cemented intervals were estimated for a random selection of 20 percent of San Ardo Oil Field wells completed in each decade to obtain a temporally unbiased dataset for assessing changes in cementing practices over time. They were then evaluated to determine the presence of gaps in the annular cement within the Pancho Rico Formation, the interval most likely to affect groundwater quality if a pathway connecting these zones is present, at 406 oil-field wells distributed across the San Ardo Oil Field (S3 Table). Gaps less than 10 m long were considered within the margin of error because of potential errors associated with the method.

3.7 Evaluating evidence of oil-field fluids mixing with groundwater resources

Evidence of potential mixing with oil-field fluids relied primarily on the presence of petroleum hydrocarbons (thermogenic hydrocarbon gases or hydrocarbon VOCs) or elevated temperatures in groundwater samples. The hydrocarbon VOCs analyzed for this study are in S4 Table. Thermogenic hydrocarbon gases in groundwater are used as a marker of potential mixing with fluids from hydrocarbon-bearing formations because they are formed in deep geologic formations with high pressure and temperature along with coal, oil, and natural gas deposits [72,73]. Propane and heavier hydrocarbon gases (C3-C6+) are indicative of thermogenic gas [74]. Thermogenic conditions produce the lighter hydrocarbon gases methane (C1) and ethane (C2) in addition to the heavier gases, but those gases are not definitive indicators of thermogenic sources because they can also result from microbial decomposition of organic matter in geochemically reducing settings through microbial methanogenesis [75]. However, thermogenic methane can be distinguished from microbial methane using the stable isotopes of hydrogen and carbon in methane (δ²H–CH₄ and δ¹³C–CH₄, respectively). Values of δ¹³C–CH₄ greater than -50 per mil generally indicate a thermogenic source of methane, and when both δ²H–CH₄ and δ¹³C–CH₄ were known, they were compared to zone boundaries for microbial and thermogenic methane sources [72].

Samples with evidence of potential mixing were examined more closely with respect to additional geochemical indicators, historical groundwater chemistry, oil-field water chemistry, nearby oil-well characteristics, other anthropogenic activities, and natural processes. Additional geochemical indicators used to assess evidence for potential mixing of groundwater with oil-field fluids included the presence of VOCs that are not hydrocarbons but have been detected in California oil-field fluids [76], TDS concentration greater than 1,000 mg/L, concentrations and ratios of the inorganic constituents chloride, bromide, boron, and iodide [51], dissolved organic carbon greater than 3 mg/L [77,78], and depletion of light noble gases relative to heavier noble gases. Methods and calculations for interpreting noble gas concentrations and isotopic ratios are provided in S1 Text, S7 and S8 Tables.

4.1 Hydraulic gradients and sources of water in the aquifer

An understanding of groundwater movement within the aquifer system is necessary for identifying areas that are hydraulically downgradient of the oil field and other sources of water that might contain chemicals of concern. Based on the limited data and topographic gradients, regional groundwater-flow in the uplands is expected to be towards the alluvial valley (Fig 3). Within the alluvial valley, water elevations in the Salinas River are generally higher than in the surrounding alluvial valley aquifer, and therefore, river water is expected to flow into and mix with groundwater as it flows northwest through the valley. These results are broadly similar to hydrologic flow patterns identified in previous regional groundwater-flow modeling of the Salinas River Valley [30].

Download:

• PPT
  PowerPoint slide
• PNG
  larger image
• TIFF
  original image

Fig 3. Modeled groundwater-level elevations (GWE) in spring 2020 and measured GWE at California Oil and Gas Regional Monitoring Program (RMP) sites relative to average elevation of the Salinas River at site SW-8 for the year of each groundwater-level measurement.

The modeled 1-sigma uncertainty of the modeled GWE ranged from 11 to 19 meters (m; median = 12 m) within the San Ardo Oil Field. Contour lines of modeled GWE in the uplands were smoothed for visualization purposes. The GWE model input data consisted of groundwater elevations measured at water well sites (from various sources, refer to Stephens et al. [58]), river stage from a USGS stream gage on the Salinas River (SW-8, USGS streamgage 11150500), and water-table elevation estimates from geophysical logs collected after oil wells were drilled [58]. Base map features from California State digital data. [RMP, California Oil and Gas Regional Monitoring Program].

https://doi.org/10.1371/journal.pwat.0000499.g003

Wells with measured GWEs that are lower than the Salinas River are more likely to contain a component of Salinas River water in samples. The sampled wells and springs in the uplands (GW-6, GW-7, SP-10, and SP-18) had measured GWEs that were higher than the Salinas River, and most of the sampled wells in the alluvial valley aquifer had measured GWEs that were lower than the Salinas River. Three wells sampled in the alluvial valley aquifer within the San Ardo Oil Field (GW-19, GW-21, and GW-22) had a measured GWE similar to the river elevation (within 1.5 m). These were three of the deepest samples (top of well perforations > 35 m bls) within the valley, indicating a potential hydraulic equilibrium between water contributions from the river and water contributions from the underlying sediments that receive waters from the uplands that have traveled over long flow paths.

Geochemical and isotopic indicators provided additional support for understanding groundwater-flow patterns within the alluvial valley aquifer. Isotopes used to determine groundwater age (³H and ¹⁴C-DIC) indicated that groundwater in the uplands (GW-6, GW-7, and GW-12) and in the deeper samples within the valley (GW-19, GW-20, and GW-22) were premodern (recharged before 1953) (Fig 1 and S5 Table). Shallower samples in the valley contained either modern (recharged in 1953 or later) or a mixture of modern and premodern groundwater, indicating that river water, rainwater, excess irrigation water, or wastewater disposal is entering the shallower parts of the aquifer and mixing with older groundwater at depth.

Relative proportions of major inorganic constituents as charge equivalents [79] also indicated contributions of modern river water to the alluvial valley aquifer. Most of the samples that were collected closest to the river and contained modern groundwater (GW-2, GW-3, GW-4, and GW-16) were geochemically similar to the Salinas River samples (SW-8 and SW-9) (Fig 4). Samples collected farther from the river differed geochemically from the Salinas River samples. Samples GW-5 and GW-13 were collected from irrigation wells and had unique geochemical qualities (elevated nitrate, TDS, chloride, and boron) compared to other groundwater samples (Fig 5 and S5 Table) that make it likely that the geochemistry of those samples was affected to a greater degree by irrigation-return flows in a localized vertical flow dominated system. Groundwater from a spring west of the Los Lobos fault and upgradient of most oil-field activities (SP-18), and a monitoring well immediately downgradient of the treated PW recharge basins (GW-14) also had unique geochemical signatures unlike other groundwater samples. SP-18 was collected in an area where the Monterey Formation is at the land surface and where faulting and oil seeps are common [24,35]. The relative proportions of cations in SP-18 are similar to PW samples but its anions are like samples collected near the river. The stable isotopes of water in GW-14 are similar to PW and indicate that its source is likely treated PW from the upgradient recharge basins (Fig 6). However, GW-14 contained smaller amounts of chloride and boron (Fig 5) and many other dissolved chemical constituents than other groundwater samples [50] and no other indicators of mixing with oil-field fluids, reflecting a reset of the chemical but not the isotopic character of the PW during the treatment process.

Download:

• PPT
  PowerPoint slide
• PNG
  larger image
• TIFF
  original image

Fig 4. Trilinear diagram showing relative proportions of major ions, San Ardo Oil Field study area, California, 2019-2021.

Data from samples collected by the California Oil and Gas Regional Monitoring Program.

https://doi.org/10.1371/journal.pwat.0000499.g004

Download:

• PPT
  PowerPoint slide
• PNG
  larger image
• TIFF
  original image

Fig 5. Concentrations of chloride in relation to boron, San Ardo Oil Field study area, California, 2019-2021.

Decile markers indicate possible percentage of mixing with produced water (PW). Data from samples collected by the California Oil and Gas Regional Monitoring Program.

https://doi.org/10.1371/journal.pwat.0000499.g005

Download:

• PPT
  PowerPoint slide
• PNG
  larger image
• TIFF
  original image

Fig 6. Stable isotopes of hydrogen and oxygen in water collected from California Oil and Gas Regional Monitoring Program (RMP) sites, San Ardo Oil Field study area, California, 2019-2021.

Global meteoric water line from Craig [80].

https://doi.org/10.1371/journal.pwat.0000499.g006

4.2 Hydraulic gradients and potential pathways between the aquifer and oil-field zones

Potential for upward movement of fluids from oil-field zones is greater in areas where water is injected in quantities large enough to cause positive hydraulic pressures relative to the overlying aquifer. Measured idle oil-well elevations (IWEs) were lower than modeled GWEs at 94% of the 719 oil wells with a measurement, indicating that vertical gradients in the oil-production area are mostly downward and towards the oil-producing zones (Fig 7A). However, IWEs were not available in the area north of the main oil-production area where most of the injection wells are located (Fig 1).

Download:

• PPT
  PowerPoint slide
• PNG
  larger image
• TIFF
  original image

Fig 7. A. Difference in elevation between idle oil-well fluid elevations (IWEs) and modeled groundwater elevations (GWEs) and implied hydraulic gradients between them, and estimated change in fluid height computed from the difference in volume of fluids produced and injected; and B.

spatial distribution of oil-field wells with incomplete annular cement within the Pancho Rico Formation. Measured IWEs from Shimabukuro et al. [61], modeled GWEs from Stephens et al. [58], and base map features from California State digital data.

https://doi.org/10.1371/journal.pwat.0000499.g007

Another method for evaluating the potential for upward movement of fluids is to compare the volume of water and steam injected to the volume of water and oil extracted. Historical fluid injection and production data for the San Ardo Oil Field indicate that more fluid (oil and water) has been extracted than was injected, creating a pressure gradient toward the oil-producing zones [33,36,71]. However, those data did not account for spatial differences across the oil field.

Spatial patterns of the fluid volume balance across the oil field for the period of 1977–2017 for all pools [40] showed a net negative balance within the main oil production area, providing additional evidence that gradients were mostly downward (Fig 7A). However, a net positive balance was present north, west, and south of the main oil production area where disposal injection occurs, favoring upward movement of water at the margins of the oil field.

Although hydraulic gradients, when known, can indicate potential for migration of oil-field fluids, a pathway must be present for fluids to move upward. The Pancho Rico Formation separates the oil-producing and injection zones from overlying fresh groundwater resources with about 50–200 m of low-permeability sediments [17,26]. Potential pathways through the low permeability sediments include incomplete cementing in the annulus around the outer casing of oil wells, incomplete cementing during well or dry hole abandonment, oil-well cement and casing failures, and faults [81–83]. Risks associated with oil-well pathways are greater for older oil wells because well casings and cement seals degrade over time [4,82,84–86], and because well construction and abandonment practices, such as cement quality, have improved through time to better protect groundwater [82,87,88]. Large temperature fluctuations associated with steam injection wells cause additional well-operation stresses that can affect oil-well integrity [81,82].

Of the 406 oil-field wells evaluated for gaps in annular cement within the vertical extent of the Pancho Rico Formation, only 50 (12 percent) had incomplete cementing (> 10 m cement gap, Fig 7B). Oil-field wells assessed in the area north of the main production area where the largest net positive fluid balances occur were constructed such that cementing was complete within the Pancho Rico Formation. Analysis of construction records for oil wells in other oil fields in California has indicated that older oil wells generally have longer gaps in annular cement than modern wells [4,69,70], and that is also true within the San Ardo Oil Field (Fig 8). Of the 50 oil-field wells with incomplete cement, 40 of them were constructed before the 1970s [40]. Thirty-eight of the 50 wells have been abandoned, reducing the risk of upward movement of oil-field fluids if abandonment practices resulted in more complete sealing within the Pancho Rico Formation. However, well abandonment practices were not evaluated for this study. For the 12 wells that were not abandoned, two were not in use (idle), six were active steam injection wells, two were observation wells, and two were active production wells with no steam injection since 1977. Well-casing failures and faults can also introduce pathways for upward movement of oil-field fluids, but a comprehensive analysis to evaluate that risk was beyond the scope of the work.

Download:

• PPT
  PowerPoint slide
• PNG
  larger image
• TIFF
  original image

Fig 8. Temporal distribution of oil-field wells with complete and incomplete annular cement within the Pancho Rico Formation at the time of construction, San Ardo Oil Field, California.

Cemented intervals estimated using data from California Department of Conservation [37].

https://doi.org/10.1371/journal.pwat.0000499.g008

4.3 Hydrocarbons in groundwater

Hydrocarbons were identified in groundwater using the presence of thermogenic hydrocarbon gases and/or hydrocarbon VOCs. Samples GW-17, SP-18, and GW-19 contained trace levels of heavier hydrocarbon gases (C3+) (Fig 9A, Table 1, and S5 Table), suggesting that the gases at these sites were at least partially from thermogenic sources. However, samples SP-18 and GW-19 only contained C6 + hydrocarbon gases, and it can be difficult to interpret these detections because individual gases were not reported. Samples GW-17, SP-18, GW-20, and GW-22 had a methane concentration large enough for analysis of stable isotopes of δ²H–CH₄ and/or δ¹³C–CH₄ (S5 Table). Those values indicated that methane in sample SP-18 was more likely from a thermogenic source than a microbial source, methane in samples GW-20 and GW-22 could have been from either a microbial or thermogenic source, and methane in GW-17 was from a microbial source. The source of methane in samples GW-20 and GW-22 was inconclusive because only δ¹³C–CH₄ could be measured, and those values were isotopically heavy. Isotopically heavy methane can result from oxidation of microbial methane as well as thermogenic methane. Two RMP groundwater samples contained at least one hydrocarbon VOC (Fig 9A). GW-16 contained toluene, and SP-18 contained 4-isopropyltoluene and naphthalene. The detected hydrocarbon VOCs were at concentrations less than 1.5 micrograms per liter (ug/L) and were much lower than their drinking-water maximum contaminant levels [89,90].

Download:

• PPT
  PowerPoint slide
• PNG
  larger image
• TIFF
  original image

Table 1. Summary of detections of classes of compounds used to indicate potential mixing with oil-field fluids, San Ardo Oil Field, California, 2019-2021. Data from samples collected by the California Oil and Gas Regional Monitoring Program.

https://doi.org/10.1371/journal.pwat.0000499.t001

Download:

• PPT
  PowerPoint slide
• PNG
  larger image
• TIFF
  original image

Fig 9. A. Detections of hydrocarbons in California Regional Monitoring Program (RMP) samples; and B. detections of benzene, toluene, ethylbenzene, and xylene (BTEX) compounds in historical groundwater samples, San Ardo Oil Field study area, California. Historical groundwater sample data from multiple sources (see section 3.5).

Base map features from U.S. Geological Survey and California State digital data.

https://doi.org/10.1371/journal.pwat.0000499.g009

Five of the six samples identified as containing or potentially containing hydrocarbons (GW-16, GW-17, GW-19, GW-20, and GW-22) were near active oil-field infrastructure, two of which were downgradient of documented subsurface hydrocarbon leaks (Fig 2). In addition, four of the six samples (GW-17, GW-19, GW-20, and GW-22) also had elevated groundwater temperature (Table 1). See section 4.4 for more discussion of elevated temperatures. One of those samples (GW-17) also had noble gas evidence of mixing with oil-field fluids (depletion of light noble gases relative to heavy noble gases; see S1 Text for additional information). That sample was collected from a shallow well (S5 Table) situated along the Los Lobos fault (Fig 1), which may serve as a conduit for upward movement of water and gases. It was also downgradient of areas with oil seeps and an oil-field waste disposal site to the west (Fig 2) [24,28,35].

Sample GW-16 was collected from a shallow well near the Salinas River (Fig 1 and S5 Table) and the source of a hydrocarbon VOC was uncertain. The sample was classified as modern-aged water, and the only hydrocarbon VOC detected was toluene. It also contained acetone, another VOC that has been identified in some California oil-field water [76]. However, toluene and acetone are also common solvents associated with some well construction materials and could be derived from these sources [91–93]. Major inorganic constituent (Fig 4) and water isotopic values (Fig 6) from GW-16 indicated that this sample was predominantly composed of Salinas River water, which would likely dilute concentrations in groundwater.

Samples GW-19, GW-20, and GW-22 were collected from deeper wells (top of well perforations > 40 m bls), contained only premodern water, and were farther from the Salinas River than other samples that contained hydrocarbons (Fig 1). Those samples had similar boron to chloride ratios that plotted along an apparent mixing line between Salinas River water and PW samples (Fig 5) and were isotopically similar to upland groundwater samples GW-6 and GW-7 to the east and the upland spring discharge sample SP-18 to the west (Fig 6). This isotopic similarity and estimated lateral groundwater flow gradients from eastern uplands toward the Salinas River Valley (Fig 3) were consistent with water from GW-19, GW-20, and GW-22 primarily originating from the uplands to the east and traveling over long groundwater-flow paths before entering the alluvial valley aquifer. If the hydrocarbons in these samples were from oil-field fluids, age-dating results indicated that the source was from subsurface leaks or naturally occurring sources that had not been in contact with the atmosphere since the 1950s, ruling out recent surface spills as a potential source. Samples GW-19 and GW-20 also contained higher TDS concentrations than the other samples in the alluvial valley aquifer that were not collected from irrigation wells (S5 Table), but these samples did not contain hydrocarbon VOCs. Any potential mixing with oil-field fluids in these wells was either minor or the hydrocarbons had been attenuated through biological processes because the concentrations of hydrocarbon gases were very low (<0.1 mg/L; S5 Table). Potential sources of thermogenic gas in GW-19, GW-20, and GW-22 could include leaky wells associated with hydrocarbon resource development in the San Ardo Oil Field surrounding these wells or naturally occurring geologic sources.

Sample SP-18 (Los Lobos Spring) contained more indicators of potential mixing than other groundwater samples (Table 1). It was not near active oil-field infrastructure but was collected west of the Los Lobos fault where faults, oil seeps, and naturally occurring hydrocarbons are near the land surface. It was also located near an abandoned oil well that never commercially produced but has core descriptions of oil-stained sand intervals (API #0405301406 [37]), and it is possible that the well’s borehole could have served as a conduit for upward movement of fluids from oil-bearing formations. At that site, a test hole was drilled to 2,052 m bls. Faults may have been encountered in the borehole during drilling because well drilling fluids were lost as the borehole was deepened. During abandonment, cement was used to plug the hole between land surface and 156 m bls, and the rest of the hole was filled with heavy drilling fluid. The drilling record indicated that springs were present nearby prior to drilling the well, providing evidence that this spring was not caused by a pathway introduced during or after drilling.

Historical water chemistry data did not provide additional information for determining the presence of thermogenic gases. Historical methane concentrations were available for nine groundwater samples collected in 2015 and 2016 in and near the oil field [46]. However, δ²H–CH₄ and/or δ¹³C–CH₄ values were not available for determining the source of methane for the historical samples. Results for heavier hydrocarbon gases were also not available from historical data sources.

Results for historical BTEX analyses were available for 107 groundwater samples collected between 1986 and 2020 at 26 wells and three springs distributed across the study area (Fig 9B). Four historical groundwater samples contained detectable BTEX compounds at relatively low concentrations (≤ 3 µg/L). Three of the historical BTEX detections were near oil-field development and one was near a landfill located northwest of the San Ardo Oil Field and west of the Salinas River (Fig 2) [48]. One of the three samples near oil-field development was collected in 2020 from shallow monitoring well GW-14 located downgradient of treated PW recharge basins. However, that well was also sampled by the RMP in 2021, and no hydrocarbons or other chemical constituents from PW were detected in that sample. BTEX was also detected in historical samples collected in 2013 from well GW-22 and a nearby oil-field water supply well, but not in the RMP sample collected from well GW-22 in 2021.

4.4 Elevated temperature in groundwater

Elevated groundwater temperatures can indicate that: (1) hot oil-field fluids from underlying oil-producing zones have leaked into the aquifer along preferential pathways such as leaky wellbores or faults; (2) there were surface spills of hot water that recharged the aquifer; (3) there has been advective transport of steam that leaked from nearby injection well casing failure (Fig 2); (4) groundwater has contacted steam-injection well casings and was heated through conduction; or (5) heat has been transported via thermal diffusivity from the steam injection zones to the groundwater zones. Only the first two mechanisms result in the release of oil-field fluids into the aquifer. The other mechanisms produce elevated groundwater temperatures without corresponding groundwater quality degradation. In addition to providing evidence of potential mixing with oil-field fluids, elevated groundwater temperatures also have potential to reduce evidence of mixing through increased attenuation of hydrocarbons, if present [4,94,95].

Elevated temperatures compared to ambient values occur in some groundwater overlying the San Ardo Oil Field in response to heating of underlying oil-producing zones by steam injection to enhance recovery of low gravity oil [17]. The ambient formation temperature has been measured in temperature profiles from observation wells collected by oil-field operators [17,37] and are apparent in temperatures of groundwater pumped from some water wells (Fig 10A). From 1966 through 2017, 243 million m³ of steam have been injected into the San Ardo Oil Field, with the greatest volumes into injection wells along the river (Fig 10B). Oil-field samples in the San Ardo Oil Field had temperatures up to 100^o C (S6 Table). Elevated temperatures (greater than 30^o C) were measured in five groundwater wells sampled by the RMP (GW-17, GW-19, GW-20, GW-21, and GW-22), all of which were collected near steamed oil wells (Table 1 and Fig 10B). Discussion of samples GW-17, GW-19, GW-20, and GW-22 is presented in the previous section. Sample GW-21 is slightly shallower than the other RMP groundwater samples collected nearby and contained a mixture of modern and premodern water, indicating a vertical gradient in groundwater ages in that part of the study area. GW-21 was also different from the deeper samples (GW-19, GW-20, GW-22) with regard to the relative proportions of major inorganic constituents (Fig 4), concentrations of boron relative to chloride (Fig 5), and water isotopes (Fig 6). Its geochemical properties and isotopic values were more similar to GW-17, a shallower sample near oil-field wells that also contained modern and premodern groundwater and was likely mixed with Salinas River water (Table 1). The only other potential evidence for mixing with oil-field fluids in GW-21 was the presence of acetone, a VOC that is not a petroleum hydrocarbon but is sometimes present in California oil-field fluids [76] (S5 Table). Samples GW-20, GW-21, and GW-22 were downgradient of a steam injection well that had a breached casing in 2001 and 2002 at a depth of 183 m bls (Fig 2), but any potential increase in groundwater temperatures caused by that breach would not likely affect groundwater temperatures measured in 2021 for the RMP.

Download:

• PPT
  PowerPoint slide
• PNG
  larger image
• TIFF
  original image

Fig 10. A. Elevated temperatures in California Oil and Gas Regional Monitoring Program (RMP) and historical samples; and B. volumes of steam injection from 1977-2017, San Ardo Oil Field study area, California. Historical temperature data from multiple sources (see section 3.5).

Base map features from U.S. Geological Survey and California State digital data.

https://doi.org/10.1371/journal.pwat.0000499.g010

The co-occurrence of traces of thermogenic gas in GW-17 with elevated temperatures could indicate that site was affected by transport of oil-field fluids with heated groundwater along anthropogenic and/or natural pathways such as faults near the well. Evidence of the presence of oil-field fluids in GW-19, GW-20, GW-21, and GW-22 are more uncertain and so the relation to elevated groundwater temperatures, if any, was not clear. However, the groundwater with elevated temperatures showed only trace detections of hydrocarbons, when present, so it may be that much of the heating of groundwater overlying the oil field was due to heating mechanisms that did not result in large upward fluxes of oil-field fluids.

Other geochemical tracers provided additional lines of evidence about potential sources of the elevated groundwater temperatures. Light noble gases are removed from water when it is converted to steam [96]. Only GW-17 exhibited depletion of light noble gases, indicating the potential for mixing with water affected by steaming (S1 Text). Groundwater recharge temperatures were calculated using noble gas concentrations, and all samples were consistent with ambient recharge temperatures in the region (S1 Text). Those results indicated that the samples with elevated temperature had cooler recharge temperatures and then became warmer within the aquifer, ruling out recharge of hot water from a surface spill. In addition, samples GW-19, GW-20, and GW-22 only contained premodern water indicating that those samples were unlikely affected by a recent surface spill of hot water but may be consistent with subsurface mixing with heated water.

Historical data indicated that elevated temperatures were not common in groundwater. None of the 113 historical groundwater samples collected from 1953 through 2022 across the study area had a temperature greater than 30^o C (Fig 10A). However, historical data generally were not available near steam injection wells. Only one sample, collected in 2005, was in the steamed part of the oil field. Therefore, data were not available for comparing groundwater temperatures prior to when steam injection began in 1963 to temperatures after steam injection.