Geology topics

Matthew K. Landon

Publications and source records attributed to Matthew K. Landon.

At least 19 recordsLinked to original sources

USGS2026

Evaluating groundwater quality influences from oil field operations and other anthropogenic activities in an urban setting, Santa Fe Springs, California

Groundwater quality is often affected by anthropogenic activities in urban settings. This study examines groundwater quality in and around the Santa Fe Springs Oil Field in Los Angeles County, California, where oil and gas production commonly intersects with high density industrial, commercial and residential land uses. Utilizing a combination of new and historical data, we evaluated potential pathways that would allow for oil field formation fluids to migrate into groundwater and whether mixing may have occurred based on the distribution of groundwater and oil field formation fluid tracers in samples. Samples were analyzed for a wide array of constituents including volatile organic compounds, light hydrocarbons, major ions, and various isotopic compositions. Despite evidence of oil field infrastructure providing potential pathways of migration via uncemented annular spaces, casing breaches and historical disposal of oil field formation water in surface ponds, the distribution and occurrence of stable isotopes of water, chloride, boron, and total dissolved solids do not indicate mixing of oil field formation water and groundwater. However, methane isotopic signatures and the presence of heavier alkanes suggest gas from oil-bearing formations have migrated from depth via oil field well infrastructure. Volatile organic compound detections were mainly from manufactured compounds unrelated to oil and gas production, with a relatively limited number of petroleum hydrocarbons also detected. Volatile organic compounds were generally found in wells tapping shallow, modern aged groundwater, indicating anthropogenic activities occurring at or near land surface as the source. Study results suggest that while oil field infrastructure provides migration pathways for oil field formation fluids to be introduced into groundwater, urban land uses not related to oil and gas production are the primary drivers of groundwater quality degradation.

California↗

USGS2026

Groundwater quality near an oil field in a stream-dominated recharge setting, California, USA

Alluvial valley aquifers are important sources of water supply in many areas but effects of co-located oil and gas development on these resources have not been widely reported, especially in settings where recharge is dominated by stream infiltration. Interpreting the presence of geochemical indicators in the context of hydrology, geology, and other factors provides a more complete understanding of the relations between groundwater and sources of oil-field fluids and aids in identifying risks associated with oil and gas development. Groundwater and Salinas River water samples were collected in an alluvial valley near the San Ardo Oil Field in Monterey County, California and analyzed for a wide range of dissolved chemical, gas, and isotopic constituents to determine if oil-field fluids (water and gas from oil-producing and non-producing zones) have mixed with fresh groundwater used for supply. Hydraulic gradients, age-dating tracers, and other geochemical indicators show that recharge from the Salinas River has the potential to dilute oil-field fluids that might migrate or seep into the aquifer. Groundwater and Salinas River water collected downgradient of the San Ardo Oil Field showed little or no evidence of mixing with oil-field fluids. Some samples within the oil field contained trace amounts of hydrocarbons or elevated temperatures, indicating that any potential effects from oil-field activities are minor or have been diluted by recharge from the Salinas River. The two samples with the most geochemical evidence of potential mixing with oil-field fluids (SP-18 and GW-17) were collected west of or along the Los Lobos fault, where naturally occurring hydrocarbons are near the land surface. Those samples are also near active or inactive oil-field wells, and so anthropogenic activities and pathways cannot be ruled out as a cause of trace detections of hydrocarbons and elevated temperatures in the aquifer.

California↗

USGS2025

Relations of groundwater quality to long-term surface disposal of produced water near the Midway-Sunset and Buena Vista Oil Fields, California, USA

Contamination of groundwater by oil-field fluids in proximity to oil and gas development has been an issue of concern to water users and regulators given long histories of development and legacy disposal practices. A robust set of geochemical tracers including petroleum hydrocarbon compounds, thermogenic gases, inorganic ion concentrations, stable isotopes, radioactive isotopes, and noble gases were used to assess if oil-field fluids mixed with groundwater near the Midway-Sunset and Buena Vista Oil Fields in California, USA. Results show evidence of mixing of oil-field fluids with groundwater within the study area from either anthropogenic or natural processes. Produced water plumes associated with modern surface disposal facilities, used since the late 1950s, extend up to 1.5 km and currently remain within the boundaries of the oil fields. Plumes associated with earlier routing of produced water down natural drainages and in large retention structures (Midway Basin and Sunset Basin) near the Buena Vista Lake Bed are present in groundwater east of the oil fields. Based on geochemical tracer evidence, aerial imagery, and aerial electromagnetic surveys, these legacy plumes reach the western portion of the Central Valley aquifer system, an important groundwater resource for agricultural and domestic supply. The legacy plume associated with Sunset Basin may further be detected downgradient in deeper groundwater beneath the southern extent of the Buena Vista Lake Bed based on the presence of thermogenic gases and petroleum hydrocarbon compounds.

California↗

USGS2024

Groundwater quality near the Placerita Oil Field, California, 2018

Groundwater-quality data and potential fluid-migration pathways near the Placerita Oil Field in Los Angeles County, California, were examined by the U.S. Geological Survey to determine if oil-field fluids (water and gas from oil-producing and non-producing zones) have mixed with groundwater resources. Six of the 13 new groundwater samples collected for this study contained petroleum hydrocarbons, thermogenic gas, inorganic chemical signatures, and (or) isotopic values consistent with potential mixing with fluids from hydrocarbon-bearing formations. For historical groundwater samples, benzene was the most detected petroleum hydrocarbon. The historical groundwater samples with a benzene concentration greater than 0.5 micrograms per liter were from environmental monitoring wells at industrial or commercial facilities unrelated to oil and gas development that, in many cases, have identified soil or groundwater contamination and were not typically analyzed for other constituents that could provide additional lines of evidence for potential mixing with oil-field fluids. Methane was not detected in any of the 12 historical samples with a reported measurement. Reviewing historical data revealed factors that could potentially adversely affect groundwater quality in the study area. These factors include modified hydraulic gradients caused by large volumes of water extracted from the main production area and reinjected downgradient into nonproducing zones, well-barrier failures in wells constructed in the northern part of the oil field before the 1970s, well-barrier failures in produced-water disposal wells downgradient from the main production area, and naturally occurring hydrocarbons at shallow intervals. The groundwater samples most geochemically similar to samples from hydrocarbon-bearing formations were in areas where hydrocarbons are naturally occurring at shallow intervals and where oil development is at shallow depths. Additional data for hydraulic heads, water quality, and formation temperatures at multiple depths in areas with large injection volumes and well-integrity issues are needed to evaluate whether those factors have contributed to mixing between fluids from oil-producing or injection formations and groundwater resources.

California↗

USGS2024

Assessing potential effects of oil and gas development activities on groundwater quality near and overlying the Elk Hills and North Coles Levee Oil Fields, San Joaquin Valley, California

Groundwater resources are utilized near areas of intensive oil and gas development in California’s San Joaquin Valley. In this study, we examined chemical and isotopic data to assess if thermogenic gas or saline water from oil producing formations have mixed with groundwater near the Elk Hills and North Coles Levee Oil Fields in the southwestern San Joaquin Valley. Major ion concentrations and stable isotope compositions were largely consistent with natural processes, including mixing of different recharge sources and water-rock interactions. Trace methane concentrations likely resulted from microbial rather than thermogenic sources. Trace concentrations of benzene and other dissolved hydrocarbons in three wells had uncertain sources that could occur naturally or be derived from oil and gas development activities or other anthropogenic sources. In the mid-1990s, two industrial supply wells had increasing Cl and B concentrations likely explained by mixing with up to 15 percent saline oil-field water injected for disposal in nearby injection disposal wells. Shallow groundwater along the western margin of Buena Vista Lake Bed had elevated Cl, B, and SO 4 concentrations that could be explained by accumulation of salts during natural wetting and drying cycles or, alternatively, legacy surface disposal of saline oil-field water in upgradient ephemeral drainages. This study showed that groundwater had relatively little evidence of thermogenic gas or saline water from oil and gas sources in most parts of the study area. However, the evidence for groundwater mixing with injected disposal water, and possibly legacy surface disposal water, demonstrates produced water management practices as a potential risk factor for groundwater-quality degradation near oil and gas fields. Additional studies in the San Joaquin Valley and elsewhere could improve understanding of such risks by assessing the locations, volumes, and types of produced water disposal practices used during the life of oil fields.

California↗

USGS2024

Land-use interactions, Oil-Field infrastructure, and natural processes control hydrocarbon and arsenic concentrations in groundwater, Poso Creek Oil Field, California, USA

Like many hydrocarbon production areas in the U.S., the Poso Creek Oil Field in California includes and is adjacent to other land uses (agricultural and other developed lands) that affect the hydrology and geochemistry of the aquifer overlying and adjacent to oil development. We hypothesize that the distributions of hydrocarbons and arsenic in groundwater in such areas will be controlled by complex interactions between mixed land uses, oil-field infrastructure, and natural processes. In 2020–2021, samples of groundwater and surface water were collected and analyzed for a large suite of inorganic and organic chemicals and isotope and gas tracers to test this hypothesis. Those data are supplemented with ancillary data on historical geochemistry, hydrology, geology, and oil-field infrastructure. Hydrocarbons in groundwater (e.g., methane through pentane gases and benzene) are associated with natural processes (e.g., fault offsets or transition in sediment depositional environment) and oil-field infrastructure (e.g., fluid-migration pathways associated with uncemented annulus in oil wells or unlined pits). Arsenic concentrations >10 μg per liter (μg/L; maximum concentration 12.9 μg/L) are associated with natural processes in old, high-pH groundwater, and more recent recharge of water from natural and/or engineered recharge processes. Along the southwest margin of the oil field, pumping for drinking-water and irrigation supplies in combination with engineered groundwater recharge produce a depression in groundwater elevations where groundwater with elevated sulfate concentrations from agricultural areas and groundwater with hydrocarbons from the oil field mix to produce a zone of sulfate reduction that removes hydrocarbons and arsenic from groundwater but produces elevated sulfide (S 2- ) concentrations (maximum concentration 29 mg per liter, mg/L). In this study, multiple approaches were required to resolve the overlapping effects of land uses, oil-field infrastructure, and natural processes on the distributions of hydrocarbons and arsenic in groundwater. The combined use of geographic, historical, physical, chemical, isotopic, and other information to constrain processes could be a useful approach for studies in other hydrocarbon-production areas. This is particularly important where land uses affect aquifer hydrology to an extent that causes mixing of groundwaters with different chemical compositions.

California↗

USGS2023

Groundwater quality near the Montebello Oil Field, Los Angeles County, California

Groundwater quality and potential sources and migration pathways of chemical constituents associated with hydrocarbon-bearing formations were assessed by the U.S. Geological Survey for the California State Water Resources Control Board Oil and Gas Regional Monitoring Program (RMP). Groundwater samples were collected as part of the RMP from 21 preexisting wells used for public supply, monitoring, or irrigation in and near the Montebello Oil Field and analyzed for constituents associated with hydrocarbon-bearing formations and constituents used to identify recently recharged groundwater and older groundwater. The newly collected RMP data were supplemented with historical sample data from 849 groundwater wells and analyzed with respect to explanatory factors that have the potential to influence water quality. Potential sources and migration pathways of fluids (water, gas, or oil) from hydrocarbon-bearing formations that could affect groundwater quality in the Montebello Oil Field include large volumes of recycled produced water (water withdrawn from an oil well and brought to the surface that may include oil, water, and gas from the geologic formation and water or gas injected for enhanced recovery) that have been reinjected since the 1960s to enhance oil production, oil and gas wells with well-integrity issues, and oil and gas wells with an uncemented annulus that intersects groundwater resource zones. Trace amounts of dissolved petroleum hydrocarbons, thermogenic gas (propane through pentane range), or both, were detected in seven groundwater samples collected in 2014 and 2018 as part of the RMP. Five of those samples also contained manufactured volatile organic compounds and at least some modern-age groundwater (recharged during or after 1953), indicating that the hydrocarbons could have originated from surficial, or shallow, sources unrelated to oil and gas development. Two samples contained low concentrations of petroleum hydrocarbons (less than 0.1 microgram per liter) and did not contain detections of manufactured volatile organic compounds in pre-modern groundwater. These samples were collected from relatively deep wells (greater than 140 meters below land surface) with perforations completed in marine sediments that may contain water with similar compositions to produced water. The RMP sample results and available historical data in and near the Montebello Oil Field did not provide conclusive evidence that oil and gas development has adversely affected groundwater resources. All samples with detectable petroleum hydrocarbons, thermogenic gases, or both, were collected from sites that also are within 500 meters of anthropogenic hydrocarbon sources not associated with oil and gas development or sources. In addition, naturally occurring sources of hydrocarbons that exist at intervals shallower than, or are in areas outside of, economically productive oil- and gas-producing zones could affect groundwater quality. A definitive analysis of relations of groundwater quality to potential anthropogenic and natural explanatory factors was not possible because of the low density of new and historical sampling data, particularly in parts of the Montebello Oil Field where the largest relative risks to groundwater from hydrocarbon-bearing formations exist. Areas to consider for more detailed monitoring and analysis in the future that may present the largest relative potential risks to groundwater quality include (1) areas downgradient from historical surface ponds and sumps and (2) areas with co-located high net injection (oil reservoir injection exceeds production), old oil and gas wells that may be more likely to develop well-integrity issues than newer wells, and oil and gas wells with uncemented boreholes intersecting groundwater zones. To help fill gaps resulting from sparse groundwater wells, temperature and resistivity borehole log data could be analyzed to locate anomalies that identify potential areas where relatively warm or saline water from deeper hydrocarbon-bearing formations is present in groundwater.

California↗

USGS2023

Fluid migration pathways to groundwater in mature oil fields: Exploring the roles of water injection/production and oil-well integrity in California, USA

Mature oil fields potentially contain multiple fluid migration pathways toward protected groundwater (total dissolved solids, TDS, in nonexempted aquifer <10,000 mg/L) because of their extensive development histories. Time-series data for water use, fluid pressures, oil-well construction, and geochemistry from the South Belridge and Lost Hills mature oil fields in California are used to explore the roles of injection/production of oil-field water and well-integrity issues in fluid migration. Injection/production of oil-field water modified hydraulic gradients in both oil fields, resulting in chemical transport from deeper groundwater and hydrocarbon-reservoir systems to aquifers in the oil fields. Those aquifers are used for water supply outside the oil-field boundaries. Oil wells drilled before 1976 can be fluid migration pathways because a relatively large percentage of them have >10 m of uncemented annulus that straddles oil-well casing damage and/or the base of groundwater with TDS <10,000 mg/L. The risk of groundwater-quality degradation is higher when wells with those risk factors occur in areas with upward hydraulic gradients created by positive net injection, groundwater withdrawals, or combinations of these variables. The complex changes in hydrologic conditions and groundwater chemistry likely would not have been discovered in the absence of years to decades of monitoring data for groundwater elevations and chemistry, and installation of monitoring wells in areas with overlapping risk factors. Important monitoring concepts based on results from this and other studies include monitoring hydrocarbon-reservoir and groundwater systems at multiple spatiotemporal scales and maintaining transparency and accessibility of data and analyses. This analysis focuses on two California oil fields, but the methods used and processes affecting fluid migration could be relevant in other oil fields where substantial injection/production of oil-field water occurs and oil-well integrity is of concern.

California↗

USGS2023

Spectral characterization of dissolved organic matter in groundwater to assess mixing with oil-field water near selected oil fields, southern California

Samples of oil-field water (oil wells, injectate, disposal ponds) and groundwater near selected oil and gas fields in southern California were analyzed for dissolved organic carbon (DOC) concentration and by optical spectroscopic techniques (i.e., absorbance and fluorescence) to assess whether these measurements can be used to distinguish between oil-field water (Oil Field), native groundwater (WGnat), and native groundwater mixed with oil-field water from surface (WGsurf) or subsurface sources (WGsub), and if so whether commonly reported optical measurements can be used as a screening tool to identify such water. Concentrations of DOC were significantly (p < 0.0001) higher (67 to 2934 mg C L−1) in oil-field water compared to native groundwater samples (<5.0 mg C L−1). Individual optical properties varied by water category and frequently overlapped. However, multivariate statistical analysis showed that when evaluated in combination, 10 optical properties were determined by discriminant analysis to be significant (p < 0.05) in distinguishing among water categories. Principal component analysis of those 10 optical properties showed that these properties can be used to successfully distinguish Oil Field samples from WGnat, WGsurf, and WGsub even when mixing fractions are low (approximately 10 %).

California↗

USGS2022

Occurrence of water and thermogenic gas from oil-bearing formations in groundwater near the Orcutt Oil Field, California, USA

Study region Santa Barbara County, California, USA. Study focus To analyze a wide array of newly collected chemical, isotopic, dissolved gas, and age dating tracers in conjunction with historical data from groundwater and oil wells to determine if water and/or thermogenic gas from oil-bearing formations have mixed with groundwater in the Orcutt Oil Field and surrounding area. New hydrological insights for the region Three of 15 groundwater samples had compositions indicating potential mixing with water and/or thermogenic gas from oil-bearing formations. Relevant indicators included salinity tracers (TDS, Cl, Br), NH 3, DOC, enriched δ 13 C-DIC, δ 2 H-CH 4 , δ 13 C-CH 4 , and δ 13 C-C 2 H 6 values, and trace amounts of C3-C5 gas. The potential sources/pathways for oil-bearing formation water and/or thermogenic gas in groundwater overlying and adjacent to the Orcutt Oil Field include: (1) upward movement from formations developed for oil production due to: (a) natural migration; or (b) anthropogenic activity such as injection and/or movement along wellbores; and (2) oil and gas shows in overlying non-producing oil-bearing formations. Groundwater age tracers, elevated 4 He concentrations, and isotopic compositions of noble gases indicated legacy produced water ponds were not a source. This phase of the study relied on samples and data from existing infrastructure. Additional data on potential end-member compositions from new and existing wells and assessments of potential vertical head gradients and pathways between oil and groundwater zones may yield additional insight.

California↗

USGS2021

Geostatistical mapping of salinity conditioned on borehole logs, Montebello Oil Field, California

We present a geostatistics-based stochastic salinity estimation framework for the Montebello Oil Field that capitalizes on available total dissolved solids (TDS) data from groundwater samples as well as electrical resistivity (ER) data from borehole logging. Data from TDS samples ( n = 4924) was coded into an indicator framework based on falling below four selected thresholds (500, 1000, 3000, and 10,000 mg/L). Collocated TDS-ER data from the surrounding groundwater basin were then employed to produce a kernel density estimator to establish conditional probabilities for ER data ( n = 8 boreholes) falling below the selected TDS thresholds within the Montebello Oil Field area. Directional variograms were estimated from these indicator coded data, and 500 TDS realizations from conditional indicator simulation were generated for the subsurface region above the Montebello Oil Field reservoir. Simulations were summarized as 3D maps of median TDS, most likely salinity class, and probability for exceeding each of the specified TDS thresholds. Results suggested TDS was below 500 mg/L in most of the study area, with a trend toward higher values (500 to 1000 mg/L) to the southwest; consistent with the average regional groundwater flow direction. Discrete localized zones of TDS greater than 1000 mg/L were observed, with one of these zones in the greater than 10,000 mg/L range; however, these areas were not prevalent. The probabilistic approach used here is adaptable and is readily modified to include additional data and types and can be employed in time-lapse salinity modeling through Bayesian updating.

California↗

USGS2021

Relative risk of groundwater-quality degradation near California (USA) oil fields estimated from 3H, 14C, and 4He

Relative risks of groundwater-quality degradation near selected California oil fields are estimated by examining spatial and temporal patterns in chemical and isotopic data in the context of groundwater-age categories defined by tritium and carbon-14. In the Coastal basins, western San Joaquin Valley (SJV), and eastern SJV; 82, 76, and 0% of samples are premodern (pre-1953 recharge), respectively; and 3, 0, and 31% are modern (recharged during or after 1953), respectively. Carbon-14 and helium-4 data indicate most premodern samples are 1000 to 10,000 (33%) or >10,000 (50%) years old. Organic chemicals that could be associated with deeper hydrocarbon reservoirs (e.g. thermogenic gases and benzene) occur most frequently in premodern groundwater, suggesting premodern groundwater has a higher risk of degradation from upward migration of hydrocarbons than modern and mixed-age groundwater. Low sulfate concentrations in some premodern groundwater containing high thermogenic-methane concentrations (>28 mg/L) indicate methane attenuation associated with sulfate reduction can be limited in premodern groundwater. The more common occurrence of manufactured compounds, like tetrachloroethene, in modern and mixed-age groundwater than in premodern groundwater indicates modern and mixed-age groundwater has a higher risk of degradation from land-surface sources than premodern groundwater. Time-series data for chloride in groundwater affected by disposal of oil-field water in unlined ponds indicate some modern and mixed-age groundwater are susceptible to chemical migration within 2–3 km of surface sources. Timescales for diluting chloride concentrations in groundwater with fresh recharge once disposal ponds are decommissioned are shorter in mixed-age groundwater with large fractions of modern water (9–14 years in one example) than in mixed-age groundwater with large fractions of premodern water (no evidence of dilution after 12 years of monitoring in one example). The presence of predominantly premodern groundwater in the Coastal basins and western SJV indicates these areas have relatively high risk from upward migration of hydrocarbons, reduced methane attenuation capacity, and long dilution times, whereas predominantly modern- and mixed-age groundwater in the eastern SJV indicates this area has relatively high risk from chemical migration from land-surface sources and subsequent extensive spreading. Age-based characterizations of relative risk could inform the design of groundwater-monitoring programs near oil fields in terms of the spatial distribution of monitoring points relative to source areas and monitoring frequency and duration.

California↗

USGS2021

Groundwater quality of aquifers overlying the Oxnard Oil Field, Ventura County, California

Groundwater samples collected from irrigation, monitoring, and municipal supply wells near the Oxnard Oil Field were analyzed for chemical and isotopic tracers to evaluate if thermogenic gas or water from hydrocarbon-bearing formations have mixed with surrounding groundwater. New and historical data show no evidence of water from hydrocarbon-bearing formations in groundwater overlying the field. However, thermogenic gas mixed with microbial methane was detected in 5 wells at concentrations ranging from 0.011–9.1 mg/L. The presence of these gases at concentrations <10 mg/L do not indicate degraded water quality posing a known health risk. Analysis of carbon isotopes (δ 13 C-CH 4 ) and hydrogen isotopes (δ 2 H-CH 4 ) of methane and ratios of methane to heavier hydrocarbon gases were used to differentiate sources of methane between a) microbial, b) thermogenic or c) mixed sources. Results indicate that microbial-sourced methane is widespread in the study area, and concentrations overlap with those from thermogenic sources. The highest concentrations of thermogenic gas were observed in proximity to relatively high density of oil wells, large injection volumes of water disposal and cyclic steam, shallow oil development, and hydrocarbon shows in sediments overlying the producing oil reservoirs. Depths of water wells containing thermogenic gas were within approximately 200 m of the top of the Vaca Tar Sand production zone (approximately 600 m below land surface). Due to the limited sampling density, the source and pathways of thermogenic gas detected in groundwater could not be conclusively determined. Thermogenic gas detected in the absence of co-occurring water from hydrocarbon-bearing formations may result from natural gas migration over geologic time from the Vaca Tar Sand or deeper formations, hydrocarbon shows in sediments overlying producing zones, and/or gas leaking from oil-field infrastructure. Denser sampling of groundwater, potential end-members, and pressure monitoring could help better distinguish pathways of thermogenic gases.

California↗

USGS2020

Probabilistic categorical groundwater salinity mapping from airborne electromagnetic data adjacent to California’s Lost Hills and Belridge oil fields

Growing water stress has led to emerging interest in protecting fresh and brackish groundwater as a potential supplement to water supplies and raised questions about factors that could affect the future quality of fresh and brackish aquifers. Limited well infrastructure, particularly in regions where elevated salinity has led to limited historical groundwater development, hinders traditional mapping of salinity distributions through groundwater sampling. This paper presents a quantitative salinity mapping approach of the upper 300 m using high‐resolution, regionally comprehensive resistivity models derived from Bayesian inversion of an airborne electromagnetic survey adjacent to the Lost Hills and Belridge oil fields in the southwestern San Joaquin Valley of California. Using local water quality observations as an interpretational foundation, a probabilistic approach yields maps of fresh, saline, and brackish groundwater while quantifying joint uncertainty inherited from the geophysical data and interpretational relations. Saline and fresh regions are mapped with relatively high confidence in many locations, while areas of lower confidence, particularly at depth, can be mapped as their most probable salinity category while reflecting the relative uncertainty in the interpretation. These maps identify a stratified salinity structure, where saline water commonly occurs in the surficial aquifer overlying fresher groundwater in the Tulare aquifer, separated by regional confining clay layers. Downgradient of unlined surface water diversions, recharge of imported surface water results in relatively fresh groundwater throughout the depth of investigation.

California↗

USGS2019

Occurrence and sources of radium in groundwater associated with oil fields in the southern San Joaquin Valley, California

Geochemical data from 40 water wells were used to examine the occurrence and sources of radium (Ra) in groundwater associated with three oil fields in California (Fruitvale, Lost Hills, South Belridge). 226Ra+228Ra activities (range=0.010-0.51 Bq/L) exceeded the 0.185 Bq/L drinking-water standard in 18% of the wells (not drinking-water wells). Radium activities were correlated with TDS concentrations (p<0.001, ρ=0.90, range=145-15,900 mg/L), Mn+Fe concentrations (p<0.001, ρ=0.82, range=<0.005-18.5 mg/L), and pH (p<0.001, ρ=-0.67, range=6.2-9.2), indicating Ra in groundwater was influenced by salinity, redox, and pH. Ra-rich groundwater was mixed with up to 45% oil-field water at some locations, primarily infiltrating through unlined disposal ponds, based on Cl, Li, noble-gas, and other data. Yet 228Ra/226Ra ratios in pond-impacted groundwater (median=3.1) differed from those in oil-field water (median=0.51). PHREEQC mixing calculations and spatial geochemical variations suggest the Ra in oil-field water was removed by co-precipitation with secondary barite and adsorption on Mn-Fe precipitates in the near-pond environment. The saline, organic-rich oil-field water subsequently mobilized Ra from downgradient aquifer sediments via Ra-desorption and Mn/Fe-reduction processes. This study demonstrates that infiltration of oil-field water may leach Ra into groundwater by changing salinity and redox conditions in the subsurface rather than by mixing with a high-Ra source.

California↗

USGS2019

Groundwater quality of a public supply aquifer in proximity to oil development, Fruitvale Oil Field, Bakersfield, California

Due to concerns over the effects of oil production activities on groundwater quality in California, chemical, isotopic, dissolved gas and age-dating tracers were analyzed in samples collected from public-supply wells and produced-water sites in the Fruitvale oil field (FVOF). A combination of newly collected and historical data was used to determine whether oil formation fluids have mixed with groundwater used for public supply and what the potential pathways for the migration of oil formation fluids into groundwater may be. Stable isotopes of water (δ 2 H and δ 18 O) and age dating ( 3 H, 3 He trit , SF 6 and 14 C) tracers in groundwater samples were consistent with the Kern River being the main source of recharge to aquifers. The distribution of major ion concentrations and pH with distance from the Kern River indicate that natural processes were the primary controls on groundwater salinity. Two of 14 groundwater samples had δ 13 C-DIC values (−2.4 to +1.9 per mil) consistent with mixtures of <1 to about 9 percent oil-field water. Concentrations of TDS in groundwater samples were generally much lower (129–1,200 milligrams per liter (mg/l), median 216 mg/l) than produced water samples (586–24,930 mg/l, median 2,717 mg/l), suggesting that any mixing of oil-field water with groundwater has not significantly affected groundwater salinity. Trace concentrations of thermogenic methane were detected in three groundwater samples that did not have dissolved inorganic or isotopic indicators consistent with mixing of oil-field water, suggesting that stray gases may have migrated from the subsurface via preferential pathways such as leaky well bores into groundwater aquifers. Low concentrations of petroleum hydrocarbons were detected in samples that also contained anthropogenic VOCs and components of post- and pre-1950s recharge, indicating that petroleum hydrocarbons could have come from subsurface and/or surface sources. Overall, the results of this study indicated that groundwater currently used for public supply in the FVOF was of good quality with little, if any, effects from oil production activities. This may be due in part to the relatively rapid flushing of the aquifer system by recharge from the Kern River.

California↗

USGS2019

Factors affecting 1,2,3-trichloropropane contamination in groundwater in California

1,2,3-Trichloropropane (1,2,3-TCP) is a volatile organic chemical of eminent concern due to its carcinogenic, mutagenic, and reproductive effects, and its frequent occurrence at concentrations of concern worldwide. In California, 1,2,3-TCP was detected in 6.5% of 1237 wells sampled by the U. S. Geological Survey (USGS). About 8% of domestic wells had a detection of 1,2,3-TCP, compared to 5% of public-supply wells. 1,2,3-TCP was detected in 5.5% of most recent samples from 7787 public-supply well sources of the California State Water Resources Control Board Division of Drinking Water (DDW). Concentrations ranged from <0.005 to 2.7 μg/L. The California maximum contaminant level (MCL) is 0.005 μg/L. Most of the detections occurred in the San Joaquin Valley, where 1,2,3-TCP was detected above the MCL in 16% of USGS sampled wells and 18% of DDW wells. 1,2,3-TCP occurrence and concentrations are related to legacy fumigant use and hydrogeologic factors. Understanding factors affecting 1,2,3-TCP will aid in determining vulnerability and long term persistence in the San Joaquin Valley, which can help focus efforts to manage drinking water resources on the most vulnerable areas and also inform efforts in other areas of the state and worldwide. Widespread occurrence of 1,2,3-TCP is related to nonpoint source agricultural contaminant inputs. High concentrations of 1,2,3-TCP are in young, shallow, oxic groundwater beneath primarily orchard/vineyard crops. These areas are in coarse-grained sediments that promote rapid recharge, related to proximal alluvial fan sediments deposited by large streams that drain glaciated watersheds of the Sierra Nevada. 1,2,3-TCP co-occurs with 1,2-dibromo-3-chloropropane (DBCP) and 1,2-dichloropropane (1,2-DCP) throughout modern age groundwater, indicating its long term persistence with little degradation. The highest concentrations of 1,2,3-TCP were observed at point source cleanup sites in urban areas; depending on the age and source of groundwater to nearby public-supply wells, these areas may see increasing concentrations of 1,2,3-TCP.

California↗

USGS2019

Groundwater salinity and the effects of produced water disposal in the Lost Hills-Belridge oilfields, Kern County, California

Increased oil and gas production in many areas has led to concerns over the effects these activities may be having on nearby groundwater quality. In this study we determine the lateral and vertical extent of groundwater with less than 10,000 milligrams per liter (mg/l) total dissolved solids (TDS) near the Lost Hills-Belridge oilfields in northwestern Kern County, California and document evidence of impacts by produced water disposal within the Tulare aquifer and overlying alluvium—the primary protected aquifers in the area. The depth at which groundwater salinity surpasses 10,000 mg/l ranges from 150 m (500 ft [ft]) in the northwestern part of the study area to 490 to 550 m (1,600-1,800 ft) in the south and east respectively as determined by geophysical log analysis and lab analysis of produced water samples. Comparison of logs from replacement wells with logs from their older counterparts shows relatively higher resistivity intervals representing the vadose zone or fresher groundwater being replaced by intervals with much lower resistivity due to infiltration of brines from surface disposal ponds and injection of brines into disposal wells. The effect of the surface ponds is confined to the alluvial aquifer—the underlying Tulare aquifer is largely protected by a regional clay layer at the base of the alluvium. Sand layers affected by injection of produced waters in nearby disposal wells often exhibit log resistivity profiles that change from high resistivity in their upper parts to low resistivity near the base due to stratification by gravity segregation of the denser brines within each affected sand. The effects of produced water injection are mainly evident within the Tulare Formation and can be noted as far as 550 m (1,800 ft) from the main group of disposal wells located along the east flank of South Belridge.

California↗