Geology topics

Jenna L. Shelton

Publications and source records attributed to Jenna L. Shelton.

25 records · Page 2Linked to original sources

USGS2018

Microbial community composition of a hydrocarbon reservoir 40 years after a CO2 enhanced oil recovery flood

Injecting CO 2 into depleted oil reservoirs to extract additional crude oil is a common enhanced oil recovery (CO 2 -EOR) technique. However, little is known about how in situ microbial communities may be impacted by CO 2 flooding, or if any permanent microbiological changes occur after flooding has ceased. Formation water was collected from an oil field that was flooded for CO 2 -EOR in the 1980s, including samples from areas affected by or outside of the flood region, to determine the impacts of CO 2 -EOR on reservoir microbial communities. Archaea, specifically methanogens, were more abundant than bacteria in all samples, while identified bacteria exhibited much greater diversity than the archaea. Microbial communities in CO 2 -impacted and non-impacted samples did not significantly differ (ANOSIM: Statistic R = -0.2597, significance = 0.769). However, several low abundance bacteria were found to be significantly associated with the CO 2 -affected group; very few of these species are known to metabolize CO 2 or are associated with CO 2 -rich habitats. Although this study had limitations, on a broad scale, either the CO 2 flood did not impact the microbial community composition of the target formation, or microbial communities in affected wells may have reverted back to pre-injection conditions over the ca. 40 years since the CO 2 -EOR.

Louisiana↗

USGS2018

The isometric log-ratio (ilr)-ion plot: A proposed alternative to the Piper diagram

The Piper diagram has been a staple for the analysis of water chemistry data since its introduction in 1944. It was conceived to be a method for water classification, determination of potential water mixing between end-members, and to aid in the identification of chemical reactions controlling a sample set. This study uses the information gleaned over the years since the release of the Piper diagram and proposes an alternative to it, capturing the strengths of the original diagram while adding new ideas to increase its robustness. The new method uses compositional data analysis to create 4 isometric log-ratio coordinates for the 6 major chemical species analyzed in the Piper diagram and transforms the data to a 4-field bi-plot, the ilr-ion plot. This ilr-ion plot conveys all of the information in the Piper diagram (water mixing, water types, and chemical reactions) while also visualizing additional data, the ability to examine Ca 2+ /Mg 2+ versus Cl-/SO 4 2− . The Piper and the ilr-ion plot were also compared using multiple synthetic and real datasets in order to illustrate the caveats and the advantages of using either diagram to analyze water chemistry data. Although there are challenges with using the ilr-ion plot (e.g., missing or zero values zeros in the dataset must be imputed by positive real numbers), it appears that the use of compositional data analysis coupled with the ilr-ion plot provides a more in-depth and complete analysis of water quality data compared to the original Piper diagram.

Journal of Geochemical Exploration↗

USGS2016

Environmental drivers of differences in microbial community structure in crude oil reservoirs across a methanogenic gradient

Stimulating in situ microbial communities in oil reservoirs to produce natural gas is a potentially viable strategy for recovering additional fossil fuel resources following traditional recovery operations. Little is known about what geochemical parameters drive microbial population dynamics in biodegraded, methanogenic oil reservoirs. We investigated if microbial community structure was significantly impacted by the extent of crude oil biodegradation, extent of biogenic methane production, and formation water chemistry. Twenty-two oil production wells from north central Louisiana, USA, were sampled for analysis of microbial community structure and fluid geochemistry. Archaea were the dominant microbial community in the majority of the wells sampled. Methanogens, including hydrogenotrophic and methylotrophic organisms, were numerically dominant in every well, accounting for, on average, over 98% of the total Archaea present. The dominant Bacteria groups were Pseudomonas, Acinetobacter , Enterobacteriaceae, and Clostridiales, which have also been identified in other microbially-altered oil reservoirs. Comparing microbial community structure to fluid (gas, water, and oil) geochemistry revealed that the relative extent of biodegradation, salinity, and spatial location were the major drivers of microbial diversity. Archaeal relative abundance was independent of the extent of methanogenesis, but closely correlated to the extent of crude oil biodegradation; therefore, microbial community structure is likely not a good sole predictor of methanogenic activity, but may predict the extent of crude oil biodegradation. However, when the shallow, highly biodegraded, low salinity wells were excluded from the statistical analysis, no environmental parameters could explain the differences in microbial community structure. This suggests that the microbial community structure of the 5 shallow, up-dip wells was different than the 17 deeper, down-dip wells. Also, the 17 down-dip wells had statistically similar microbial communities despite significant changes in environmental parameters between oil fields. Together, this implies that no single microbial population is a reliable indicator of a reservoir's ability to degrade crude oil to methane, and that geochemistry may be a more important indicator for selecting a reservoir suitable for microbial enhancement of natural gas generation.

Louisiana↗

USGS2016

Determining CO 2 storage potential during miscible CO 2 enhanced oil recovery: Noble gas and stable isotope tracers

Rising atmospheric carbon dioxide (CO 2 ) concentrations are fueling anthropogenic climate change. Geologic sequestration of anthropogenic CO 2 in depleted oil reservoirs is one option for reducing CO 2 emissions to the atmosphere while enhancing oil recovery. In order to evaluate the feasibility of using enhanced oil recovery (EOR) sites in the United States for permanent CO 2 storage, an active multi-stage miscible CO 2 flooding project in the Permian Basin (North Ward Estes Field, near Wickett, Texas) was investigated. In addition, two major natural CO 2 reservoirs in the southeastern Paradox Basin (McElmo Dome and Doe Canyon) were also investigated as they provide CO 2 for EOR operations in the Permian Basin. Produced gas and water were collected from three different CO 2 flooding phases (with different start dates) within the North Ward Estes Field to evaluate possible CO 2 storage mechanisms and amounts of total CO 2 retention. McElmo Dome and Doe Canyon were sampled for produced gas to determine the noble gas and stable isotope signature of the original injected EOR gas and to confirm the source of this naturally-occurring CO 2 . As expected, the natural CO 2 produced from McElmo Dome and Doe Canyon is a mix of mantle and crustal sources. When comparing CO 2 injection and production rates for the CO 2 floods in the North Ward Estes Field, it appears that CO 2 retention in the reservoir decreased over the course of the three injections, retaining 39%, 49% and 61% of the injected CO 2 for the 2008, 2010, and 2013 projects, respectively, characteristic of maturing CO 2 miscible flood projects. Noble gas isotopic composition of the injected and produced gas for the flood projects suggest no active fractionation, while δ 13 C CO 2 values suggest no active CO 2 dissolution into formation water, or mineralization. CO 2 volumes capable of dissolving in residual formation fluids were also estimated along with the potential to store pure-phase supercritical CO 2 . Using a combination of dissolution trapping and residual trapping, both volumes of CO 2 currently retained in the 2008 and 2013 projects could be justified, suggesting no major leakage is occurring. These subsurface reservoirs, jointly considered, have the capacity to store up to 9 years of CO 2 emissions from an average US powerplant.

International Journal of Greenhouse Gas Control↗

USGS2016

Impact of formation water geochemistry and crude oil biodegradation on microbial methanogenesis

Converting non-producible crude oil to CH 4 via methanogenic crude oil biodegradation in oil reservoirs could serve as one way to increase our energy profile. Yet, field data supporting the direct relationship between methanogenesis and crude oil biodegradation are sparse. Indicators of methanogenesis, based on the formation water and gas geochemistry (e.g. alkalinity, δ 13 C–CO 2 ) were compared with indicators of crude oil biodegradation (e.g. pristane/phytane and n -alkane ratios) from wells in the Wilcox Group of Louisiana to determine if increases in extent of methanogenesis were related to increases in extent of crude oil biodegradation. Shallow wells (393–442 m depth) contained highly biodegraded oils associated with low extent of methanogenesis, while the deepest (> 1208 m) wells contained minimally degraded oils and produced fluids suggesting a low extent of methanogenesis. Mid-depth wells (666–857 m) in the central field had the highest indicators of methanogenesis and contained moderately biodegraded oils. Little correlation existed between extents of crude oil biodegradation and methanogenesis across the whole transect (avg. R 2 = 0.13). However, when wells with the greatest extent of crude oil biodegradation were eliminated (3 of 6 oilfields), better correlation between extent of methanogenesis and biodegradation (avg. R 2 = 0.53) was observed. The results suggest that oil quality and salinity impact methanogenic crude oil biodegradation. Reservoirs indicating moderate extent of crude oil biodegradation and high extent of methanogenesis, such as the central field, would be good candidates for attempting to enhance methanogenic crude oil biodegradation as a result of the observations from the study.

Organic Geochemistry↗

USGS2014

Fate of injected CO2 in the Wilcox Group, Louisiana, Gulf Coast Basin: Chemical and isotopic tracers of microbial–brine–rock–CO2 interactions

The “2800’ sandstone” of the Olla oil field is an oil and gas-producing reservoir in a coal-bearing interval of the Paleocene–Eocene Wilcox Group in north-central Louisiana, USA. In the 1980s, this producing unit was flooded with CO 2 in an enhanced oil recovery (EOR) project, leaving &sim;30% of the injected CO 2 in the 2800’ sandstone post-injection. This study utilizes isotopic and geochemical tracers from co-produced natural gas, oil and brine to determine the fate of the injected CO 2 , including the possibility of enhanced microbial conversion of CO 2 to CH 4 via methanogenesis. Stable carbon isotopes of CO 2 , CH 4 and DIC, together with mol% CO 2 show that 4 out of 17 wells sampled in the 2800’ sandstone are still producing injected CO 2 . The dominant fate of the injected CO 2 appears to be dissolution in formation fluids and gas-phase trapping. There is some isotopic and geochemical evidence for enhanced microbial methanogenesis in 2 samples; however, the CO 2 spread unevenly throughout the reservoir, and thus cannot explain the elevated indicators for methanogenesis observed across the entire field. Vertical migration out of the target 2800’ sandstone reservoir is also apparent in 3 samples located stratigraphically above the target sand. Reservoirs comparable to the 2800’ sandstone, located along a 90-km transect, were also sampled to investigate regional trends in gas composition, brine chemistry and microbial activity. Microbial methane, likely sourced from biodegradation of organic substrates within the formation, was found in all oil fields sampled, while indicators of methanogenesis (e.g. high alkalinity, δ 13 C-CO 2 and δ 13 C-DIC values) and oxidation of propane were greatest in the Olla Field, likely due to its more ideal environmental conditions (i.e. suitable range of pH, temperature, salinity, sulfate and iron concentrations).

Louisiana↗

USGS2013

Fate(s) of injected CO2 in a coal-bearing formation, Louisiana, Gulf Coast Basin: Chemical and isotopic tracers of microbial-brine-rock-CO2 interactions

Coal beds are one of the most promising reservoirs for geologic carbon dioxide (CO₂) sequestration, as CO₂ can strongly adsorb onto organic matter and displace methane; however, little is known about the long-term fate of CO₂ sequestered in coal beds. The "2800' sand" of the Olla oil field is a coal-bearing, oil and gas-producing reservoir of the Paleocene–Eocene Wilcox Group in north-central Louisiana. In the 1980s, this field, specifically the 2800' sand, was flooded with CO₂ in an enhanced oil recovery (EOR) project, with 9.0×10⁷m³ of CO₂ remaining in the 2800' sand after injection ceased. This study utilized isotopic and geochemical tracers from co-produced natural gas, oil and brine from reservoirs located stratigraphically above, below and within the 2800' sand to determine the fate of the remaining EOR-CO₂, examining the possibilities of CO₂ migration, dissolution, mineral trapping, gas-phase trapping, and sorption to coal beds, while also testing a previous hypothesis that EOR-CO₂ may have been converted by microbes (CO₂-reducing methanogens) into methane, creating a microbial "hotspot". Reservoirs stratigraphically-comparable to the 2800' sand, but located in adjacent oil fields across a 90-km transect were sampled to investigate regional trends in gas composition, brine chemistry and microbial activity. The source field for the EOR-CO₂, the Black Lake Field, was also sampled to establish the δ¹³C-CO₂ value of the injected gas (0.9‰ +/- 0.9‰). Four samples collected from the Olla 2800' sand produced CO₂-rich gas with δ¹³C-CO₂ values (average 9.9‰) much lower than average (pre-injection) conditions (+15.9‰, average of sands located stratigraphically below the 2800' sand in the Olla Field) and at much higher CO₂ concentrations (24.9 mole %) than average (7.6 mole %, average of sands located stratigraphically below the 2800' sand in the Olla Field), suggesting the presence of EOR-CO₂ and gas-phase trapping as a major storage mechanism. Using δ¹³C values of CO₂ and dissolved organic carbon (DIC), CO₂ dissolution was also shown to be a major storage mechanism for 3 of the 4 samples from the Olla 2800' sand. Minor storage mechanisms were shown to be migration, which only affected 2 samples (from 1 well), and some EOR-CO₂ conversion to microbial methane for 3 of the 4 Olla 2800' sand samples. Since methanogenesis was not shown to be a major storage mechanism for the EOR-CO₂ in the Olla Field (CO₂ injection did not stimulate methanogenesis), samples were examined from adjacent oil fields to determine the cause of the Olla microbial "hot-spot". Microbial methane was found in all oil fields sampled, but indicators of methanogenesis (e.g. alkalinity, high δ¹³C-DIC values) were the greatest in the Olla Field, and the environmental conditions (salinity, pH, temperature) were most ideal for microbial CO₂ reduction in the Olla field, compared to adjacent fields.

Thesis↗