Groundwater methane in relation to oil and gasdevelopment and shallow coal seams in theDenver-Julesburg Basin of ColoradoOwen A. Sherwooda,1, Jessica D. Rogersb, Greg Lackeyb, Troy L. Burkeb, Stephen G. Osbornc, and Joseph N. Ryanb

aInstitute of Arctic and Alpine Research, University of Colorado, Boulder, CO 80309; bDepartment of Civil, Environmental and Architectural Engineering,University of Colorado, Boulder, CO 80309; and cDepartment of Geological Sciences, California State Polytechnical University, Pomona, CA 91768

Edited by Peter H. Gleick, Pacific Institute for Studies in Development, Environment, and Security, Oakland, CA, and approved June 7, 2016 (received forreview November 24, 2015)

Unconventional oil and gas development has generated intensepublic concerns about potential impacts to groundwater quality.Specific pathways of contamination have been identified; how-ever, overall rates of contamination remain ambiguous. We usedan archive of geochemical data collected from 1988 to 2014 todetermine the sources and occurrence of groundwater methanein the Denver-Julesburg Basin of northeastern Colorado. This60,000-km2 region has a 60-y-long history of hydraulic fracturing,with horizontal drilling and high-volume hydraulic fracturingbeginning in 2010. Of 924 sampled water wells in the basin, dis-solved methane was detected in 593 wells at depths of 20–190 m.Based on carbon and hydrogen stable isotopes and gas molecularratios, most of this methane was microbially generated, likely withinshallow coal seams. A total of 42 water wells contained thermogenicstray gas originating from underlying oil and gas producing forma-tions. Inadequate surface casing and leaks in production casing andwellhead seals in older, vertical oil and gas wells were identified asstray gas migration pathways. The rate of oil and gas wellbore failurewas estimated as 0.06% of the 54,000 oil and gas wells in the basin(lower estimate) to 0.15% of the 20,700 wells in the area where straygas contamination occurred (upper estimate) and has remainedsteady at about two cases per year since 2001. These results showthat wellbore barrier failure, not high-volume hydraulic fracturing inhorizontal wells, is themain cause of thermogenic stray gas migrationin this oil- and gas-producing basin.

unconventional oil and gas | hydraulic fracturing | groundwater |methane | stray gas

Horizontal drilling combined with hydraulic fracturing hasrevolutionized the petroleum industry. It has also generated

persistent concern about environmental impacts to groundwaterquality (1, 2). Rates and pathways of groundwater contaminationresulting from drilling and production operations remain con-troversial (3–6). Complicating factors include spatial overlap be-tween legacy and newer development and the presence of naturallyoccurring hydrocarbons in the shallow subsurface. Geochemicaldata can help resolve these factors and clarify potential impacts togroundwater (1, 7–11); however, there is a general lack of timeseries data of sufficient regional extent in most petroleum-producing basins. This problem underlies the rationale behindmoratoria on unconventional petroleum development withinvarious municipal and state/provincial jurisdictions (8).We focus here on the Denver-Julesburg (DJ) Basin of north-

eastern Colorado (Fig. 1), notable for having a 60-y-long historyof hydraulic fracturing. The technique was introduced in 1950 andexpanded during the 1970s–1990s to stimulate production fromlow-permeability reservoirs (SI Appendix) (12–14). Approximatelyhalf of the 49,800 vertical wells in the basin have been hydrauli-cally fractured, typically with two to three stages of fracturing(15). In 2010, horizontal drilling was introduced in the Watten-berg Field (Fig. 1) to exploit the Niobrara shale/chalk forma-tion (16). Virtually all of these 4,180 horizontal wells have

been hydraulically fractured, typically with 20+ stages of frac-turing (15). The DJ Basin produces both gas (446 billon cubic feetin 2014) and oil (88 million barrels in 2014) (15), comprising thefull range of thermogenic maturity from black oil to condensateand dry gas (12, 13). Previous studies on impacts to groundwaterfocused mainly on shale gas plays with a relatively short history ofhydraulic fracturing (3–10); this study focuses on unconventionaloil and gas with a long history of hydraulic fracturing.The presence of gas in DJ Basin groundwater was noted at

least as early as the 1880s, when artesian wells drilled to depthsof 365–425 m produced flammable gas (17). In 1982, residents nearthe towns of Hudson and LaSalle complained of well water thatwas oily, flammable, and undrinkable (18). In 1984, gas was foundleaking from five abandoned water wells (240–360 m) in LaSalle,one of which caused a destructive explosion and fire. Geochemicalanalysis determined that the gas originated in the Codell formation(SI Appendix), which was being developed at the time, but thespecific migration pathways were never identified (19).Following the events of the early 1980s, the Colorado Oil and

Gas Conservation Commission (COGCC) took over responsi-bility for investigating water quality complaints. Beginning in2005, regulations requiring geochemical testing of water wellswere introduced (SI Appendix). As a result, the COGCC hasaccumulated groundwater and natural gas geochemical mea-surements going back to 1988, constituting one of the mostcomprehensive groundwater geochemical datasets related topetroleum development anywhere. The data span a time range

Significance

The impact of unconventional oil and gas development ongroundwater quality remains controversial. We use an archiveof public domain data to examine factors influencing the dis-tribution and sources of groundwater methane in the oil- andgas-producing Denver-Julesburg Basin of Colorado. Thermo-genic stray gas sourced from deep oil and gas reservoirs im-pacted 42 water wells in 32 separate cases at a rate of abouttwo cases per year from 2001 to 2014. The rate did not changeafter the introduction of horizontal drilling combined withhigh-volume hydraulic fracturing in 2010. The risk of stray gascontamination ranged from 0.12% of 35,000 water wells in thebasin (lower estimate) to 4.5% of the 924 water wells thatwere tested (upper estimate).

Author contributions: O.A.S. and J.N.R. designed research; O.A.S., J.D.R., G.L., T.L.B., andS.G.O. performed research; O.A.S., J.D.R., G.L., T.L.B., and S.G.O. analyzed data; and O.A.S.and J.N.R. wrote the paper.

The authors declare no conflict of interest.

This article is a PNAS Direct Submission.

Freely available online through the PNAS open access option.1To whom correspondence should be addressed. Email: owen.sherwood@colorado.edu.

This article contains supporting information online at www.pnas.org/lookup/suppl/doi:10.1073/pnas.1523267113/-/DCSupplemental.

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over which oil and gas wellbore construction evolved fromvertical wells with uncemented sections to horizontal wells withfully cased and cemented vertical sections (20). We obtaineddata from the COGCC in October 2014, and after rigorousdata screening and quality control protocols (SI Appendix), we

examined the distribution and origins of groundwater methane inrelation to oil and gas development in the DJ Basin.

Results and DiscussionDissolved methane was detected in 593 water wells, representinga majority (64%) of the 924 water wells for which analysis formethane was conducted. The COGCC reporting threshold of1 mg/L methane was exceeded in 261 wells. The hazard thresholdof 10 mg/L was exceeded in 122 wells, and the hazard mitigationlevel of 28 mg/L was exceeded in 5 wells (SI Appendix). Long-term repeatability in dissolved methane measurements wasassessed from a subset of 92 water wells that underwent follow-up sampling over a period of up to 20 y. Sample pairwise dif-ferences varied by 67% (1 SD, n = 136; SI Appendix), whichhighlights well-known problems in repeatability of dissolvedmethane measurements due to hydrological variability andsampling and analytical methods (11, 21). Nevertheless, overallspatial and temporal patterns of dissolved methane providevaluable insights to origins and associated hazards of ground-water methane in the DJ Basin (Fig. 1).Genetic origins of groundwater methane were assessed from

stable carbon isotopes of methane (δ13CC1) and gas molecularratios [C1/(C2 + C3)] in 211 of the water wells (22) (Fig. 2 and SIAppendix). Dissolved methane concentrations were >1 mg/L inall but four of the water wells. Of these 211 wells, 169 hadmethane with δ13CC1 < −60‰ and C1/(C2 + C3) > 100, char-acteristic of microbial methane. Stable hydrogen isotope ratios(δ2HC1) further showed that the microbial methane is in-termediate between the CO2 reduction and acetate fermentationmethanogenic pathways (SI Appendix). Another 29 water wellscontained methane with δ13CC1 > −55‰ and C1/(C2 + C3) < 50,characteristic of thermogenic methane. A final 13 wells hadisotopic and molecular values representing mixed microbial-thermogenic methane [δ13CC1 < −55‰ and C1/(C2 + C3) < 100]

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Fig. 1. Study area in the DJ Basin of Northeastern Colorado. (A) Overviewmap showing distribution of dissolved methane and thermogenic gas oc-currences in 924 groundwater wells in relation to aquifers and oil and gaswells. (B) Closeup of Wattenberg field, also showing the distribution of coal-bearing deposits and coal mining fields (23), and northeast-trending wrenchfaults (12). Location of coal samples discussed in text is shown in both panels.Aquifers of the Denver Basin aquifer system (Dawson through Laramie-FoxHills) are listed from youngest (Top) to oldest; Dakota-Cheyenne and HighPlains represent separate aquifer systems (44). Fig. 2. Genetic characterization plot (22) of C1/(C2 + C3) vs. δ13CC1 for

groundwater aquifers compared with natural gases from producing for-mations in Wattenberg field. Repeat samples from water wells are included.Groundwaters fall within microbial and thermogenic domains and along amixing line (bold curve) calculated for thermogenic [δ13CC1 = −46‰; C1/(C2 +C3) = 5] and apparent Laramie-Fox Hill (LFH) microbial end-member values[δ13CC1 = −72‰; C1/(C2 + C3) = 1,000]. Arrows show oxidation trends usingindicated fractionation factors (αCH4-CO2), following calculations in ref. 22.There were no data for Dawson or High Plains aquifers.

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and fell along a mixing line between the microbial and thermogenicend-members. Six samples had δ13CC1 and C1/(C2 + C3) values thatmight be considered impacted by oxidation (Fig. 2). Repeatability ofδ13CC1 measurements (1.2‰, n = 63; SI Appendix) was excellent.Repeatability of C1/(C2+C3) was poorer (42%, n= 76; SI Appendix),but this would affect determination of genetic origin in less than 5%of samples (Fig. 2). Median (±bootstrapped 95% confidence limits)concentrations of dissolved methane categorized by genetic originincreased in the following order: unknown (0.03 +0.00=−0.01 mg/L),thermogenic (7.1 +2.8=−1.6 mg/L), microbial (9.2 +0.8=−0.6 mg/L),mixed (12.5 +2.0=−2.5 mg/L) (SI Appendix).Spatial and stratigraphic relationships suggest that the micro-

bial methane is sourced from shallow coal seams (Figs. 1 and 3and SI Appendix). Microbial methane occurred primarily in wellsscreened in the Denver aquifer (181 ± 10 m depth), which containslignite, and the confined part of the Laramie-Fox Hills aquifer(189 +10=−8 m), which is interbedded with subbituminous coal(23, 24). Within the confined Laramie-Fox Hills aquifer, ele-vated methane concentrations occur in a region overlying andextending down-dip of the Boulder-Weld coal field; within theDenver aquifer, elevated methane occurs near the Scrantoncoal mining district (Fig. 1). Reports of gas venting, suffoca-tions, fires, and explosions from coal mines, and gas-in-placemeasurements of up to 24 ft3/ton indicate coalbed methanepotential in this area, with a total resource estimated at 2 trillion cubicfeet (23, 24). Samples of Laramie formation coals from 185 to 234 mdepth contained methane with δ13CC1 = −69 ± 0.2‰ (n = 5; SIAppendix). This value is consistent with dissolved methane in theconfined Laramie-Fox Hills aquifer at similar depths and supports amicrobial, not thermogenic, origin of the coalbed methane. Note alsothe subbituminous B/C rank of Laramie formation coal throughoutthe basin is inconsistent with thermogenic methane production (23–25). Methane in Denver formation lignites has not been analyzed;however, the more depleted values of δ13CC1and δ2HC1 in Denveraquifer dissolved methane (Fig. 2 and SI Appendix) are consistentwith the isotopic composition of lignites in general (26).Although coal is a likely source of microbial methane in the

Laramie-Fox Hills aquifer, we cannot rule out the possibility thatthe microbial methane may also originate from slightly deepergas-bearing reservoirs. Gas from two water wells drilled to the

so-called “1100 foot sandstone” at depths of ∼381 m hadδ13CC1 = −67.09 and −67.26‰ and C1/(C2 + C3) = 310 and 711(SI Appendix). These values are slightly isotopically heavier andchemically wetter than gas in the Laramie-Fox Hills aquifer.Methane occurrence is also controlled by groundwater redox

conditions. Both the Denver aquifer and the confined Laramie-Fox Hills aquifer contain Na-HCO3 waters with low sulfate (SO4)concentrations (≤30 mg/L; SI Appendix), which is compatible withmicrobial methanogenesis (22, 26). In contrast, the unconfinedLaramie-Fox Hills (the part of the Fox Hills formation not over-laid by the Laramie formation) contains Ca-Na-HCO3-Cl waterwith high sulfate (>300 mg/L), similar to groundwater in the over-lying Quaternary alluvium and in the Dakota-Cheyenne aquifer inthe northern half of Wattenberg field (SI Appendix). Higher sulfatein these aquifers is considered to be incompatible with microbialmethanogenesis (22, 26).Based on δ13CC1 and C1/(C2 + C3) criteria described above, a

total of 42 water wells, all located in or near the Wattenbergfield, had thermogenic or mixed microbial-thermogenic methanedetected at least once in their sampling history (SI Appendix).The thermogenic gas comes from underlying (>1,000 m deep)production reservoirs, as indicated by δ13CC1 and C1/(C2 + C3)compositions that overlap with or fall along a mixing line extendingto gases of the Sussex, Codell, Niobrara, or J-Sand formations (Fig.2). Measurements of the δ13C of ethane (δ13CC2) and propane(δ13CC3) from water wells, where available, also overlap with thatof production formations (Fig. 4). Because microbes produce verylittle ethane and propane, thermogenic ethane and propane arenot significantly diluted by the presence of microbial gas (22) (SIAppendix). Because of this, δ13CC2 and δ13CC3 can be used to tracethe source of stray gas to a specific oil and gas reservoir, providedthat the isotopic signature of the source reservoir is known and noisotopic fractionation or mixing has occurred during migration andaccumulation (21, 27, 28) (Fig. 5). Measurements of δ13CC2 andδ13CC3 also rule out the possibility that heavier δ13CC1 in the watersamples are caused by oxidation (22). Finally, C2–C6 molecular

Fig. 3. Plot of dissolved methane concentrations vs. groundwater aquifer,colored by methane genetic origin. Underlying vertical lines and boxes repre-sent median ± 95% confidence limits (SI Appendix). Numbers to right of eachdata series represent number of samples. Repeat water well samples included.

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ing

Fig. 4. Natural gas isotope plot (45) of δ13C vs. reciprocal carbon number forgroundwater aquifers compared with production gas formation averages.δ13CC2 and δ13CC3 more clearly distinguish between microbial and thermogenicgases compared with δ13CC1. Water samples with thermogenic isotope signa-tures overlap with production gases. Repeat water well samples included.

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compositions of thermogenic gases in water wells also overlap withthose of production gases (SI Appendix).Due to clustering, the 42 water wells with thermogenic gas

represent 32 separate cases of stray gas migration (SI Appendix).The 32 cases are based on complaint reports filed with the COGCCdue to water quality concerns, bubbles in water, explosions, orthermogenic gas detected during baseline sampling. In six of thecases, two to four water wells in close proximity and screened in thesame aquifer contained thermogenic gas, thus comprising a clusterimpact. Complaint files include information about sequence ofevents, investigations of nearby oil and gas wellbore constructionand integrity [e.g., surface casing vent, or “bradenhead,” pressures,mechanical integrity tests (MITs), cement bond logs, productionvolumes], and resolution, if any (SI Appendix). This contextual in-formation is critical as geochemical evidence alone cannot pinpointspecific pathways of gas migration (3, 21). In 10 of the 29 com-plaints for which documentation exists, thermogenic stray gas wasattributed to barrier failures in nearby oil and gas wells and resultedin Notices of Alleged Violation (NOAV) and/or remediation ordersissued by the COGCC (SI Appendix). In one case, wellbore failurewas suspected, but never confirmed by the COGCC. In three of thecomplaints, the landowner settled with an oil and gas operatorprivately, and no information about the cause of gas migration wasavailable. The remaining 15 complaints were unresolved or are stillunder investigation by the COGCC.Although low in number, the 11 cases of confirmed or suspected

oil and gas wellbore barrier failure inform discussions about path-ways of thermogenic stray gas migration (10, 29–32) (SI Appendix).Wellbore designs in the DJ Basin have evolved with the history ofCOGCC regulations and operator practices. Wells with the highestprobability of failure have “short” surface casings, a legacy of anearlier (pre-1993) regulatory era when surface casings were not set

deep enough to protect aquifers not in use at the time (20, 33) (Fig.5). These wells also have uncemented sections of production casingin which hydrostatic pressure of fluid in the wellbore annulus isthe only barrier to vertical migration of gas originating fromintermediate-depth formations (20) (Fig. 5). All 11 cases ofwellbore failure involved vertical wells drilled before 1993, 7 ofwhich were hydraulically fractured. All 11 wells had short surfacecasings and uncemented intermediate sections. Six wells also hadcasing leaks revealed by MIT failure and one well had a wellheadseal leak; however, there likely would have been no impact togroundwater had these wells been constructed with sufficientlydeep surface casings. These results highlight the importance of“regulatory failure” to protect groundwater quality. All of thefailed wells underwent remedial cementing and were returned toproduction (six wells) or plugged and abandoned (five wells) (SIAppendix). Insufficient data were collected for assessment ofgroundwater contamination levels after remediation.Based on COGCC investigations, none of the oil and gas

wellbore failures involved horizontal, hydraulically fracturedwells, all of which have been drilled since 2010 (SI Appendix).This result is likely due to the fact that, since 1993, surfacecasings are required by COGCC regulations to extend at least 50ft (15 m) below the deepest potable aquifer. The majority (89%)of horizontal wells also have production casings that are eitherfully cemented or cemented above the shallowest hydrocarbon-bearing formation (20). This evidence supports the growing con-sensus that wellbore barrier failure, not the process of high-volumehydraulic fracturing itself, is the main thermogenic stray gas mi-gration pathway (1, 3, 9, 10, 20, 27, 29, 30).The 11 documented cases of wellbore failure also inform the

debate about setback distances. Impacted groundwater wellswere all located within 1 km of the known wellbore failure (SIAppendix), a result generally consistent with thermogenic gasoccurrence in the Marcellus shale area of Pennsylvania (4, 6) andthe Barnett shale area in Texas (34). It is possible that the 15unresolved cases were caused by wellbore failures beyond thisdistance because COGCC investigations typically focus on oiland gas development within a half mile (0.8 km) of an impactedwater well; however, the number of affected water wells drops offrapidly within this distance (SI Appendix).Reasons for not determining the source of stray gas include

missing or incomplete data or documentation in COGCC ar-chives, inconclusive geochemical data (problematic when sam-ples were not measured for δ13CC2–3), lack of wellbore failuresidentified within the COGCC-investigated search radius, andfailure to measure bradenhead pressure or conduct mechanicalintegrity testing on all wells within the search radius. Based onremedial cementing records and bradenhead pressure data,Fleckenstein et al. (20) identified 388 of 11,617 wells with shortsurface casings and uncemented intermediate sections inWattenberg field with “possible barrier failures.” Although therewere far fewer (n = 42) water wells with thermogenic stray gas, itseems probable that wellbore barrier failures could have con-tributed to unresolved cases of thermogenic stray gas migrationeven though specific wellbores were never identified. For ex-ample, case 1 (SI Appendix) from 1988 involved a suspected gaswell that underwent remedial cementing and was then aban-doned without orders from the COGCC to conduct bradenheador MIT testing. The case was therefore never officially resolved,despite a case narrative that strongly points to this well as thesource of stray thermogenic gas in a nearby water well.Finally, there is the possibility of fault-assisted gas migration

beyond the apparent 1 km radius of impact, the probability ofwhich is difficult to assess. To our knowledge, there are no naturalseeps of thermogenic gas in the Wattenberg Field. Listric faultscutting through the Laramie-Fox Hills formation are believed toterminate in the upper 500 m of the Pierre Shale (14, 24), wherethey could intersect with the uncemented production casings of

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Fig. 5. Example of confirmed wellbore barrier failure (COGCC Complaint200097544; SI Appendix). (A) Wellbore diagrams of gas well and water well(lateral offset = 103 m). Mechanical integrity testing of gas well revealedleaks in uncemented production casing at 71–99 m depth, below the surfacecasing, which was set above the top of the Upper Arapahoe aquifer. Pro-duction gases from the J-Sand formation thereby migrated to domesticwater well screened in the Upper Arapahoe aquifer. Horizontal scale is ex-aggerated by 50×. (B) Natural gas isotope plot (45) showing identical δ13CC1–3signatures in the gas well and water well.

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older wellbores, thus establishing potential gas migration pathways.Major wrench faults originating from basement rocks and believedto be a heat source for the Wattenberg geothermal anomaly (12)are another possible pathway, although less likely because of ter-mination of these faults within the Pierre Shale and observation thatstray gas occurrence does not line up along the northeast-trendingwrench faults (Fig. 1). Moreover, stray gases have the same C1–C5composition as production gases (SI Appendix), which suggestsrelatively rapid transport via wellbores because geological seepagetends to strip gases of heavier alkanes during migration (35).The COGCC water quality dataset has the unique importance

of providing a 26-y sampling history that spans the time beforeand after development of horizontal wellbores with high-volumehydraulic fracturing beginning in 2010 (Fig. 6). In contrast to aprevious report (36), we find no increase in dissolved methaneconcentrations over time (linear regression of dissolved methanevs. date, excluding nondetects: slope = −0.22, P = 0.002; excludingsamples <1 mg/L: slope = 0.02, P > 0.05). The rate of thermogenicstray gas occurrence, including both resolved and unresolved cases,has remained steady at about two cases per year since 2001 (Fig. 6).The apparent step change around the year 2000 probably reflectschanges in COGCC complaint investigation and reporting proce-dures. Note that there is no change in the rate around the year2010, when horizontal drilling with high-volume hydraulic fractur-ing was introduced. These results further support the conclusionthat horizontal drilling with high-volume hydraulic fracturing has

not had a discernible impact on the origin and occurrence ofthermogenic stray gas in the DJ Basin.With evidence that 42 separate water wells have been impacted

as of the year 2014, the risk of thermogenic stray gas is estimatedas 0.12% of 35,000 water wells in the DJ Basin (37) (lower esti-mate) to 4.5% of 924 water wells sampled and analyzed formethane (upper estimate). Assuming all 32 cases of thermogenicstray gas originate from oil and gas wellbore failures, the rate ofwellbore failure is estimated at 0.06% of the 54,000 active andabandoned oil and gas wells across the Colorado part of the DJ basin(lower estimate) and 0.15% of the 20,700 active and abandoned oiland gas wells in theWattenberg field (upper estimate), where most ofthe cases of stray gas occurred (Fig. 1). These rates are 1.6–4 timeslower than the fraction of shale gas wells in Pennsylvania that haveled to methane migration into groundwater (0.24%) (9). The contrastin rates highlights differences in geology, regulations, operators, andconstruction practices among different petroleum-producing basins(29–31). It should also be noted that the occurrence of thermogenicstray gas is likely underrepresented because of the spatial density ofsampled water, willingness of landowners to have their water tested,and the possibility that stray hydrocarbons are rapidly oxidized undercertain redox conditions (38). Although the total number of cases ofthermogenic stray gas is relatively low, it is clear from COGCCcomplaint reports that individual cases pose significant safety, fi-nancial, emotional, and health risks to landowners (SI Appendix).Evaluation, mitigation, and prevention of these impacts shouldremain an ongoing high priority (32, 39, 40).This study demonstrates the value of a large, continuously

updated, and publicly accessible groundwater geochemical da-tabase from a petroleum industry regulator. Although focusedsampling campaigns can shed light on specific groundwatercontamination incidents and pathways, the true extent and na-ture of industry-related impacts to groundwater is only revealedthrough long-term, regional-scale monitoring. Thus, the COGCCgroundwater monitoring regulations and geochemical data ar-chive may provide a useful template for other regulatory agen-cies. The availability of isotopic measurements of ethane andhigher alkanes in particular provides a more robust forensic toolthan methane isotopes alone, which are less diagnostic of geneticorigins. Availability of wellbore integrity data (surface casingvent pressure and mechanical integrity testing) is critical forevaluating pathways of stray gas migration. COGCC data showpervasive and naturally occurring microbial methane in coal-bearing aquifers of the DJ Basin. A total of 42 water wellscontained thermogenic stray gas, representing 32 separate casesof contamination, occurring at the rate of two cases per yearsince 2001. None of the cases could be specifically attributed torecent horizontal well drilling or hydraulic fracturing. Assess-ment of the risk of thermogenic methane release should there-fore address the full history and life cycle of both conventionaland unconventional oil and gas operations.

MethodsGroundwater geochemical data were downloaded from the COGCC onlineColoradoOil andGas Information System (COGIS) system (dnrwebmapgdev.state.co.us/mg2012app/) using custom computer scripts during October of 2014. Asubset of these data containing additional groundwater well metadata wasaccessed via bulk download (cogcc.state.co.us/documents/data/downloads/environmental/WaterWellDownload.html), and the two datasets were mergedbased on “FacID” number. Data were limited to locations within the DJ Basinthat could be cross-correlated against Colorado Department of Water Re-sources (DWR) water well permits (37) based on matching of at least two ofthe following parameters: DWR receipt number, DWR permit number, loca-tion, and depth. Data quality assurance/quality control protocols were modi-fied from refs. 41 and 42 for large water quality datasets. Data screeningcriteria, treatment of nondetects, and analysis of measurement repeatabilityare described in SI Appendix. Production gas geochemical data are from 77production wells in the Wattenberg Field (43). Additional production gas datain Fig. 5 and in complaint narratives (SI Appendix) were downloaded from

A

B

Fig. 6. Time series plots. (A) Methane concentration vs. sample collectiondate, colored by genetic origin. Line shows number of samples measured fordissolved methane per year. Implementation dates of COGCC regulatory andColorado Oil and Gas Association (COGA) voluntary baseline water qualitymonitoring shown in top margin (SI Appendix). (B) Cumulative number ofcases of thermogenic stray gas. Numbers indicate the number of impactedwater wells where n > 1.

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the COGCC COGIS system. Sampled well American Petroleum Institutenumbers were cross-correlated to COGCC well production summaries (15)to identify the source reservoir at the time of sampling. Complaint filesassociated with thermogenic stray gas were accessed from the COGCCComplaints database (cogcc.state.co.us/complaints2.html#/searchcomplaints).Complaints were searched on public land survey system location (section,township, range) or by well owner. Specifics to each case were interpreted fromthe associated complaint documentation (SI Appendix). Because the COGCC pro-vides limited functionality for filtering and querying online data, we built a dataportal with improved functionality for querying COGCC environmental samples,facilities, inspections, complaints, and other information where all of the data andinformation presented in this paper can be searched and viewed (https://data.airwatergas.org/content/query-tools/cogcc-database).

Stable carbon isotope data are reported in delta notation, whereδ13C= ½ð13C=12CÞsample=ð13C=12CÞVPDB − 1�× 1,000 and δ2H= ½ð2H=1HÞsample=

ð2H=1HÞVSMOW − 1�×1,000, Vienna Pee Dee Belemnite (VPDB) and ViennaStandard Mean Ocean Water (VSMOW) are standards. Because of nonnormaldata distributions, summary statistics were computed using statistical boot-strapping (n = 1,000) and are reported as the median +95% CI=−95% CI.

ACKNOWLEDGMENTS. We thank the Colorado Oil and Gas ConservationCommission for providing access to data and Erica Wiener for assistancewith data management. The manuscript was improved by the commentsof three anonymous reviewers. This work was supported by the NationalScience Foundation Sustainability Research Network program (Grant CBET-1240584).

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