M. G. Temraz, Medhat M. M. Mandur, Brian P. Coffey
The reservoir sedimentology and depositional environment of the Lower Cretaceous Alam El Bueib Formation in the Betty-1 well, Shoushan Basin, were investigated by studying lithofacies, petrography, and calcareous nannofossils. The sedimentary lithofacies indicate a fluvial to shallow-marine depositional environment. We have lithologically identified and described five lithofacies assemblages (massive-sandstone facies; cherty massive-sandstone facies; argillaceous-sandstone facies; heterolithic, laminated sandstone/shale facies; and sandy/silty–shale facies); we have petrographically identified and described seven microfacies (laminated claystone and siltstone; ferruginous quartz–arenite; feldspathic ferruginous quartz–wacke; quartz–arenite; anhydritic quartz–arenite; biomicrite; and sandy-limestone microfacies). Calcareous nannofossils were used to determine the age of the investigated deposits. The calcareous-nannofossil species led to the recognition of two nannofossil zones of the Early Cretaceous (Nannoconus bermudezi zone of the Hauterivian and Nannoconus colomi zone of the Barremian). The studied sandstone reservoirs can be classified as compositionally immature feldspathic arenite and wacke. The main diagenetic minerals of the sandstones include authigenetic clay minerals, calcite cement, quartz overgrowth, and later ferroan carbonate. Wide porosity variations in sandstones correlate with an abundance of grain-coating clays and consequent inhibition of quartz cementation. Secondary porosity has been created mainly by feldspar, rock-fragment dissolution, and clay-matrix dissolution.
通过岩相、岩石学和钙质纳米化石研究，对寿山盆地Betty-1井下白垩统Alam El Bueib组储层沉积学及沉积环境进行了研究。沉积岩相为河流-浅海沉积环境。我们已经从岩性上识别和描述了5种岩相组合(块状砂岩相;砂质块状砂岩相;argillaceous-sandstone相;异石器时代层状砂岩/页岩相;砂质/粉砂质页岩相);岩石学鉴定和描述了7种微相(层状粘土岩和粉砂岩;铁质quartz-arenite;长石质含铁石英;quartz-arenite;anhydritic quartz-arenite;生物微晶灰岩;砂灰岩微相)。钙质纳米化石被用来确定所调查矿床的年龄。通过钙质-纳米化石物种的划分，确定了早白垩世的两个纳米化石带(Hauterivian的Nannoconus bermudezi带和Barremian的Nannoconus colomi带)。研究的砂岩储层可分为成分未成熟的长石砂质和泥质砂岩。砂岩的主要成岩矿物有自生粘土矿物、方解石胶结物、过度生长的石英和晚期的碳酸亚铁。砂岩孔隙度的广泛变化与丰富的颗粒包覆粘土和随之而来的石英胶结作用的抑制有关。次生孔隙主要由长石、岩屑溶蚀和粘土基质溶蚀作用形成。
{"title":"Reservoir sedimentology and depositional environment studies of Alam El Bueib Formation using microfacies and nannofossils in Betty-1 well, Shoushan Basin, northern Western Desert, Egypt","authors":"M. G. Temraz, Medhat M. M. Mandur, Brian P. Coffey","doi":"10.1306/EG.05211514009","DOIUrl":"https://doi.org/10.1306/EG.05211514009","url":null,"abstract":"The reservoir sedimentology and depositional environment of the Lower Cretaceous Alam El Bueib Formation in the Betty-1 well, Shoushan Basin, were investigated by studying lithofacies, petrography, and calcareous nannofossils. The sedimentary lithofacies indicate a fluvial to shallow-marine depositional environment. We have lithologically identified and described five lithofacies assemblages (massive-sandstone facies; cherty massive-sandstone facies; argillaceous-sandstone facies; heterolithic, laminated sandstone/shale facies; and sandy/silty–shale facies); we have petrographically identified and described seven microfacies (laminated claystone and siltstone; ferruginous quartz–arenite; feldspathic ferruginous quartz–wacke; quartz–arenite; anhydritic quartz–arenite; biomicrite; and sandy-limestone microfacies). Calcareous nannofossils were used to determine the age of the investigated deposits. The calcareous-nannofossil species led to the recognition of two nannofossil zones of the Early Cretaceous (Nannoconus bermudezi zone of the Hauterivian and Nannoconus colomi zone of the Barremian). The studied sandstone reservoirs can be classified as compositionally immature feldspathic arenite and wacke. The main diagenetic minerals of the sandstones include authigenetic clay minerals, calcite cement, quartz overgrowth, and later ferroan carbonate. Wide porosity variations in sandstones correlate with an abundance of grain-coating clays and consequent inhibition of quartz cementation. Secondary porosity has been created mainly by feldspar, rock-fragment dissolution, and clay-matrix dissolution.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2016-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.05211514009","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66164541","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Upward migration of brine because of pressurization resulting from injection is a risk of disposal of water produced with oil and geologic carbon storage. Analysis of the net production in each zone associated with oil production activities in the southern San Joaquin Valley, California, determined that net injection caused by disposal of water produced with oil occurred in zones above the shallowest zone with net production in several oil fields. The zones with net injection are also variously at depths just greater than the shallowest depths for geologic carbon storage or at depths intermediate between more typical geologic carbon storage depths and overlying groundwater with a total dissolved solids concentration appropriate for domestic use. As such, these net injections provide analogs for brine pressurization caused by geologic carbon storage, either in the injection zone around the CO2 plume or in overlying zones caused by vertical leakage of brine or CO2. Hundreds of newspaper articles regarding groundwater contamination in the main newspaper in the southern San Joaquin area collectively reported on effects on groundwater from tens of sources at tens of locations. These effects resulted in the closure of about 100 water supply wells. However, no effects caused by upward migration of brine were reported. Of the shallowest zones with oil production–related activity in each field, the Fruitvale field, Main area, Etchegoin pool had the largest cumulative net injection volume. This pool is also intersected by numerous faults and approximately 900 wells related to oil production, each providing a potential pathway for upward fluid migration. Total dissolved solids and nitrate concentration data are available from greater than 100 water supply wells overlying this pool. Analysis of these data determined there was no significant groundwater quality change likely attributable to upward migration of brine (p < 0.05). It is not known if this is because the application of current underground injection control regulations is effective or because upward migration of brine, which is a dense phase, to groundwater is unlikely. The different engineering and economic implications of these two hypotheses suggest the need for future work to ascertain which is correct under different conditions.
{"title":"Produced water disposal injection in the southern San Joaquin Valley: No evidence of groundwater quality effects due to upward leakage","authors":"P. Jordan, J. Gillespie","doi":"10.1306/EG.10131515012","DOIUrl":"https://doi.org/10.1306/EG.10131515012","url":null,"abstract":"Upward migration of brine because of pressurization resulting from injection is a risk of disposal of water produced with oil and geologic carbon storage. Analysis of the net production in each zone associated with oil production activities in the southern San Joaquin Valley, California, determined that net injection caused by disposal of water produced with oil occurred in zones above the shallowest zone with net production in several oil fields. The zones with net injection are also variously at depths just greater than the shallowest depths for geologic carbon storage or at depths intermediate between more typical geologic carbon storage depths and overlying groundwater with a total dissolved solids concentration appropriate for domestic use. As such, these net injections provide analogs for brine pressurization caused by geologic carbon storage, either in the injection zone around the CO2 plume or in overlying zones caused by vertical leakage of brine or CO2. Hundreds of newspaper articles regarding groundwater contamination in the main newspaper in the southern San Joaquin area collectively reported on effects on groundwater from tens of sources at tens of locations. These effects resulted in the closure of about 100 water supply wells. However, no effects caused by upward migration of brine were reported. Of the shallowest zones with oil production–related activity in each field, the Fruitvale field, Main area, Etchegoin pool had the largest cumulative net injection volume. This pool is also intersected by numerous faults and approximately 900 wells related to oil production, each providing a potential pathway for upward fluid migration. Total dissolved solids and nitrate concentration data are available from greater than 100 water supply wells overlying this pool. Analysis of these data determined there was no significant groundwater quality change likely attributable to upward migration of brine (p < 0.05). It is not known if this is because the application of current underground injection control regulations is effective or because upward migration of brine, which is a dense phase, to groundwater is unlikely. The different engineering and economic implications of these two hypotheses suggest the need for future work to ascertain which is correct under different conditions.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2016-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.10131515012","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66167944","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
P. Sammarco, Lance Horn, G. Taylor, D. Beltz, M. Nuttall, E. Hickerson, G. Schmahl
Substrate relief is a common characteristic of hard-bottom offshore banks and is associated with benthic biodiversity. Earlier studies revealed varying relief associated with offshore mesophotic communities. Correlations may exist between relief and benthic biodiversity, which in turn may be useful in determining drill sites. Such drill site determination requires obtaining an estimate of variability in relief on these banks and its associated geographic patterns. We performed fine-scale surveys of relief on 14 banks in the Gulf of Mexico to examine variation between them, geographic patterns, and possible processes influencing them: 28 Fathom, 29 Fathom, Alderdice, Bouma, Bright, Elvers, Geyer, Horseshoe, McGrail, Parker, Rankin, Rezak, Sidner, and Sonnier Banks. We used a multibeam sensor on a remotely operated vehicle, with resolution of approximately 0.5 m (2 ft). Average and standard deviation of relief were calculated at the transect, drop site, and bank levels of resolution. Sidner and McGrail Banks had the highest relief, and 29 Fathom and Sonnier had the lowest. Sidner Bank had relief averaging up to 11 m (36 ft) in height, whereas 29 Fathom Bank exhibited the lowest relief (range 1 to 2 m [3 to 7 ft]). Bright Bank and all others exhibited intermediate and variable relief at both the transect and drop site levels. Relief is not predictable on many banks because of high variability between drop sites. Some low-relief banks are predictable in their relief, lending themselves to predictions of benthic diversity and suitable drill sites. Relief decreased significantly as one moved northward in the study region. Relief exhibited a significant sinusoidal pattern from west to east. Banks with low relief occurred off Lake Calcasieu and Lafayette, Louisiana.
{"title":"A statistical approach to assessing relief on mesophotic banks: Bank comparisons and geographic patterns","authors":"P. Sammarco, Lance Horn, G. Taylor, D. Beltz, M. Nuttall, E. Hickerson, G. Schmahl","doi":"10.1306/EG.01121615013","DOIUrl":"https://doi.org/10.1306/EG.01121615013","url":null,"abstract":"Substrate relief is a common characteristic of hard-bottom offshore banks and is associated with benthic biodiversity. Earlier studies revealed varying relief associated with offshore mesophotic communities. Correlations may exist between relief and benthic biodiversity, which in turn may be useful in determining drill sites. Such drill site determination requires obtaining an estimate of variability in relief on these banks and its associated geographic patterns. We performed fine-scale surveys of relief on 14 banks in the Gulf of Mexico to examine variation between them, geographic patterns, and possible processes influencing them: 28 Fathom, 29 Fathom, Alderdice, Bouma, Bright, Elvers, Geyer, Horseshoe, McGrail, Parker, Rankin, Rezak, Sidner, and Sonnier Banks. We used a multibeam sensor on a remotely operated vehicle, with resolution of approximately 0.5 m (2 ft). Average and standard deviation of relief were calculated at the transect, drop site, and bank levels of resolution. Sidner and McGrail Banks had the highest relief, and 29 Fathom and Sonnier had the lowest. Sidner Bank had relief averaging up to 11 m (36 ft) in height, whereas 29 Fathom Bank exhibited the lowest relief (range 1 to 2 m [3 to 7 ft]). Bright Bank and all others exhibited intermediate and variable relief at both the transect and drop site levels. Relief is not predictable on many banks because of high variability between drop sites. Some low-relief banks are predictable in their relief, lending themselves to predictions of benthic diversity and suitable drill sites. Relief decreased significantly as one moved northward in the study region. Relief exhibited a significant sinusoidal pattern from west to east. Banks with low relief occurred off Lake Calcasieu and Lafayette, Louisiana.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2016-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.01121615013","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66163097","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
B. Ahmmed, M. Appold, Tianguang Fan, B. McPherson, R. Grigg, M. White
Numerical geochemical modeling was used to study the effects on pore-water composition and mineralogy from carbon dioxide (CO2) injection into the Pennsylvanian Morrow B Sandstone in the Farnsworth Unit in northern Texas to evaluate its potential for long-term CO2 sequestration. Speciation modeling showed the present Morrow B formation water to be supersaturated with respect to an assemblage of zeolite, clay, carbonate, mica, and aluminum hydroxide minerals and quartz. The principal accessory minerals in the Morrow B, feldspars and chlorite, were predicted to dissolve. A reaction-path model in which CO2 was progressively added up to its solubility limit into the Morrow B formation water showed a decrease in pH from its initial value of 7 to approximately 4.1 to 4.2, accompanied by the precipitation of small amounts of quartz, diaspore, and witherite. As the resultant CO2-charged fluid reacted with more of the Morrow B mineral matrix, the model predicted a rise in pH, reaching a maximum of 5.1 to 5.2 at a water–rock ratio of 10:1. At a higher water–rock ratio of 100:1, the pH rose to only 4.6 to 4.7. Diaspore, quartz, and nontronite precipitated consistently regardless of the water–rock ratio, but the carbonate minerals siderite, witherite, dolomite, and calcite precipitated at higher pH values only. As a result, CO2 sequestration by mineral trapping was predicted to be important only at low water–rock ratios, accounting for a maximum of 2% of the added CO2 at the lowest water–rock ratio investigated of 10:1, which corresponds to a small porosity increase of approximately 0.14% to 0.15%.
{"title":"Chemical effects of carbon dioxide sequestration in the Upper Morrow Sandstone in the Farnsworth, Texas, hydrocarbon unit","authors":"B. Ahmmed, M. Appold, Tianguang Fan, B. McPherson, R. Grigg, M. White","doi":"10.1306/EG.09031515006","DOIUrl":"https://doi.org/10.1306/EG.09031515006","url":null,"abstract":"Numerical geochemical modeling was used to study the effects on pore-water composition and mineralogy from carbon dioxide (CO2) injection into the Pennsylvanian Morrow B Sandstone in the Farnsworth Unit in northern Texas to evaluate its potential for long-term CO2 sequestration. Speciation modeling showed the present Morrow B formation water to be supersaturated with respect to an assemblage of zeolite, clay, carbonate, mica, and aluminum hydroxide minerals and quartz. The principal accessory minerals in the Morrow B, feldspars and chlorite, were predicted to dissolve. A reaction-path model in which CO2 was progressively added up to its solubility limit into the Morrow B formation water showed a decrease in pH from its initial value of 7 to approximately 4.1 to 4.2, accompanied by the precipitation of small amounts of quartz, diaspore, and witherite. As the resultant CO2-charged fluid reacted with more of the Morrow B mineral matrix, the model predicted a rise in pH, reaching a maximum of 5.1 to 5.2 at a water–rock ratio of 10:1. At a higher water–rock ratio of 100:1, the pH rose to only 4.6 to 4.7. Diaspore, quartz, and nontronite precipitated consistently regardless of the water–rock ratio, but the carbonate minerals siderite, witherite, dolomite, and calcite precipitated at higher pH values only. As a result, CO2 sequestration by mineral trapping was predicted to be important only at low water–rock ratios, accounting for a maximum of 2% of the added CO2 at the lowest water–rock ratio investigated of 10:1, which corresponds to a small porosity increase of approximately 0.14% to 0.15%.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2016-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.09031515006","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66167085","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Chesapeake Energy Corporation funded consultants and the authors of this paper through their organizations of employment and, in the case of Donald Siegel, privately to do basic research on this temporal data set and prepare the paper. The authors of this report did all analysis and writing. The opinions and conclusions expressed in this paper are those of the authors and do not necessarily reflect those of Chesapeake Energy Corporation. During the preparation of this paper, all authors worked for the organizations noted in authorship. Bert Smith is a former employee of Chesapeake Energy Corporation, having worked there from May 2012 to September 2013, and has been employed by Enviro Clean Cardinal since November 2013. While employed at Chesapeake Energy Corporation, he managed this temporal study, which was completed shortly after he left Chesapeake Energy Corporation. Enviro Clean Cardinal also does consulting work for Chesapeake Energy Corporation. Prior to May 2012, Bert Smith worked for Science Applications International Corporation, which consulted for Chesapeake Energy Corporation. Mark Becker has worked for Chesapeake Energy Corporation since March 2012; prior to that, he worked for the US Geological Survey for 24 yr. Donald Siegel works for Syracuse University, but he was funded privately for this work. Neither Bert Smith nor Donald Siegel have competing corporate financial interests exceeding guidelines presented by AAPG Environmental Geosciences. Mark Becker is a current employee of Chesapeake Energy Corporation and owns stock in the company in an amount in excess of $5000. Bert Smith is the lead author and contributed to the paper preparation, technical interpretations, and review of these data and paper. Mark Becker contributed to the paper preparation, technical interpretations, and review of these data and paper. Donald Siegel contributed to the paper preparation, technical interpretations, and review of these data and paper.
切萨皮克能源公司通过他们的雇佣组织资助了顾问和这篇论文的作者，在唐纳德·西格尔的例子中，他们私下对这个时间数据集做基础研究并准备论文。这份报告的作者做了所有的分析和写作。本文仅代表作者的观点和结论，并不代表切萨皮克能源公司的观点和结论。在本文的准备过程中，所有作者都在作者署名中注明的组织工作。Bert Smith，他是Chesapeake Energy Corporation的前雇员，从2012年5月到2013年9月在那里工作，并自2013年11月以来受雇于Enviro Clean Cardinal。在切萨皮克能源公司工作期间，他管理了这项时间研究，该研究在他离开切萨皮克能源公司后不久完成。Enviro Clean Cardinal还为切萨皮克能源公司(Chesapeake Energy Corporation)提供咨询服务。2012年5月之前，他就职于Science Applications International Corporation，该公司为Chesapeake Energy Corporation提供咨询服务。Mark Becker, 2012年3月以来，他在Chesapeake Energy Corporation工作;在此之前，他为美国地质调查局工作了24年。唐纳德·西格尔在锡拉丘兹大学工作，但他的研究是由私人资助的。伯特·史密斯和唐纳德·西格尔都没有超越AAPG环境地球科学提出的指导方针来竞争企业的财务利益。马克·贝克尔是切萨皮克能源公司的现任员工，拥有该公司超过5000美元的股票。Bert Smith是主要作者，他对论文的准备、技术解释以及对这些数据和论文的审查做出了贡献。Mark Becker对论文的准备、技术解释以及对这些数据和论文的审查做出了贡献。Donald Siegel对论文的准备、技术解释以及对这些数据和论文的审查做出了贡献。
{"title":"Temporal variability of methane in domestic groundwater wells, northeastern Pennsylvania","authors":"Bert J Smith, M. Becker, D. Siegel","doi":"10.1306/EG.01121615016","DOIUrl":"https://doi.org/10.1306/EG.01121615016","url":null,"abstract":"Chesapeake Energy Corporation funded consultants and the authors of this paper through their organizations of employment and, in the case of Donald Siegel, privately to do basic research on this temporal data set and prepare the paper. The authors of this report did all analysis and writing. The opinions and conclusions expressed in this paper are those of the authors and do not necessarily reflect those of Chesapeake Energy Corporation. During the preparation of this paper, all authors worked for the organizations noted in authorship. Bert Smith is a former employee of Chesapeake Energy Corporation, having worked there from May 2012 to September 2013, and has been employed by Enviro Clean Cardinal since November 2013. While employed at Chesapeake Energy Corporation, he managed this temporal study, which was completed shortly after he left Chesapeake Energy Corporation. Enviro Clean Cardinal also does consulting work for Chesapeake Energy Corporation. Prior to May 2012, Bert Smith worked for Science Applications International Corporation, which consulted for Chesapeake Energy Corporation. Mark Becker has worked for Chesapeake Energy Corporation since March 2012; prior to that, he worked for the US Geological Survey for 24 yr. Donald Siegel works for Syracuse University, but he was funded privately for this work. Neither Bert Smith nor Donald Siegel have competing corporate financial interests exceeding guidelines presented by AAPG Environmental Geosciences. Mark Becker is a current employee of Chesapeake Energy Corporation and owns stock in the company in an amount in excess of $5000. Bert Smith is the lead author and contributed to the paper preparation, technical interpretations, and review of these data and paper. Mark Becker contributed to the paper preparation, technical interpretations, and review of these data and paper. Donald Siegel contributed to the paper preparation, technical interpretations, and review of these data and paper.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2016-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.01121615016","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66163165","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
D. Siegel, Bert J Smith, E. Perry, Rikka L. Bothun, M. Hollingsworth
Conflict of interest information is provided below for the authors of this paper. • Chesapeake Energy Corporation (Chesapeake) funded the authors of this paper through their organizations of employment and, in the case of the senior author, privately, to do basic research to evaluate this very large data set and prepare the paper. Data were collected on behalf of Chesapeake by paid third-party consultants to comply with regulatory programs. The analyses and interpretations, and report writing, were done by the authors of the paper. The decision to submit the paper was that of the authors. The opinions and conclusions expressed in this paper are those of the authors and do not necessarily reflect those of Chesapeake. • During the preparation of this paper, all authors worked for the organizations noted in authorship. Mark Hollingsworth is a current employee of Chesapeake, having worked there from February 2011 to the present. Prior to Mr. Hollingsworth’s employment by Chesapeake, he worked for TestAmerica Laboratories, Inc., which provided laboratory analytical consulting services to Chesapeake. Bert Smith is a former employee of Chesapeake, having worked there from May 2012 to September 2013, and has been employed by Enviro Clean Cardinal from November 2013 to the present. Enviro Clean Cardinal also does consulting work for Chesapeake. Prior to May 2013, Mr. Smith worked for Science Applications International Corporation, which did consulting work for Chesapeake. Elizabeth Perry works for AECOM, who provides energy consulting services to government and private industry, including Chesapeake. Rikka Bothun also worked for AECOM during most of the time this paper was under preparation but left AECOM in December 2014 and now works for a private consulting company that does not do consulting work for Chesapeake. • None of the following authors (Don Siegel, Bert Smith, Elizabeth Perry, or Rikka Bothun) have competing corporate financial interests exceeding guidelines presented by AAPG Environmental Geosciences Journal. Mark Hollingsworth is a current employee of Chesapeake and owns stock in the company in an amount in excess of $5000. • Donald Siegel is the lead author and contributor to the manuscript’s preparation, technical interpretations, and review of these data and the manuscript. Bert Smith contributed to the manuscript preparation, technical interpretations, and review of these data and the manuscript. Elizabeth Perry and Rikka Bothun contributed to the manuscript preparation, technical interpretations, and review. Mark Hollingsworth maintains the Chesapeake baseline data set and contributed to the manuscript preparation and review of these data and the manuscript. • Due to confidentiality agreements with landowners whose wells were sampled, latitude and longitude cannot be shown on maps.
{"title":"Dissolved methane in shallow groundwater of the Appalachian Basin: Results from the Chesapeake Energy predrilling geochemical database","authors":"D. Siegel, Bert J Smith, E. Perry, Rikka L. Bothun, M. Hollingsworth","doi":"10.1306/EG.01051615015","DOIUrl":"https://doi.org/10.1306/EG.01051615015","url":null,"abstract":"Conflict of interest information is provided below for the authors of this paper. • Chesapeake Energy Corporation (Chesapeake) funded the authors of this paper through their organizations of employment and, in the case of the senior author, privately, to do basic research to evaluate this very large data set and prepare the paper. Data were collected on behalf of Chesapeake by paid third-party consultants to comply with regulatory programs. The analyses and interpretations, and report writing, were done by the authors of the paper. The decision to submit the paper was that of the authors. The opinions and conclusions expressed in this paper are those of the authors and do not necessarily reflect those of Chesapeake. • During the preparation of this paper, all authors worked for the organizations noted in authorship. Mark Hollingsworth is a current employee of Chesapeake, having worked there from February 2011 to the present. Prior to Mr. Hollingsworth’s employment by Chesapeake, he worked for TestAmerica Laboratories, Inc., which provided laboratory analytical consulting services to Chesapeake. Bert Smith is a former employee of Chesapeake, having worked there from May 2012 to September 2013, and has been employed by Enviro Clean Cardinal from November 2013 to the present. Enviro Clean Cardinal also does consulting work for Chesapeake. Prior to May 2013, Mr. Smith worked for Science Applications International Corporation, which did consulting work for Chesapeake. Elizabeth Perry works for AECOM, who provides energy consulting services to government and private industry, including Chesapeake. Rikka Bothun also worked for AECOM during most of the time this paper was under preparation but left AECOM in December 2014 and now works for a private consulting company that does not do consulting work for Chesapeake. • None of the following authors (Don Siegel, Bert Smith, Elizabeth Perry, or Rikka Bothun) have competing corporate financial interests exceeding guidelines presented by AAPG Environmental Geosciences Journal. Mark Hollingsworth is a current employee of Chesapeake and owns stock in the company in an amount in excess of $5000. • Donald Siegel is the lead author and contributor to the manuscript’s preparation, technical interpretations, and review of these data and the manuscript. Bert Smith contributed to the manuscript preparation, technical interpretations, and review of these data and the manuscript. Elizabeth Perry and Rikka Bothun contributed to the manuscript preparation, technical interpretations, and review. Mark Hollingsworth maintains the Chesapeake baseline data set and contributed to the manuscript preparation and review of these data and the manuscript. • Due to confidentiality agreements with landowners whose wells were sampled, latitude and longitude cannot be shown on maps.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2016-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.01051615015","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66162929","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Disposal of the liquid wastes generated during extraction of unconventional oil and gas resources in North America is increasingly becoming a constraint to development. Currently, the bulk of these wastes is disposed of by injection into deep bedrock formations. In certain development areas, the presence of suitable disposal formations is scarce, or disposal operations are difficult to site given area constraints. To address this challenge, a process of identifying high-value disposal targets (i.e., formations and locations) was developed using a combination of hydrogeological principles, multicriteria analysis, and geospatial mapping. This paper outlines the process developed to identify potential disposal targets to support oil sand development in Alberta and the results obtained.
{"title":"Disposal in the unconventional oil and gas sector: Challenges and solutions","authors":"J. Fennell","doi":"10.1306/EG.09221515010","DOIUrl":"https://doi.org/10.1306/EG.09221515010","url":null,"abstract":"Disposal of the liquid wastes generated during extraction of unconventional oil and gas resources in North America is increasingly becoming a constraint to development. Currently, the bulk of these wastes is disposed of by injection into deep bedrock formations. In certain development areas, the presence of suitable disposal formations is scarce, or disposal operations are difficult to site given area constraints. To address this challenge, a process of identifying high-value disposal targets (i.e., formations and locations) was developed using a combination of hydrogeological principles, multicriteria analysis, and geospatial mapping. This paper outlines the process developed to identify potential disposal targets to support oil sand development in Alberta and the results obtained.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.09221515010","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66167689","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Many different rock intervals are used for brine disposal injection in the Appalachian Basin. The study area was defined as eastern Kentucky, Ohio, Pennsylvania, and West Virginia. Brine injection in the study area has increased from approximately 6–7 million barrels (bbl) per year in the early 2000s to 17.6 million bbl in 2012, mostly due to shale gas activity. A review of geologic properties and subsurface distribution of rock formations used for injection is useful to understand brine disposal operations in the region. Operational data on injection rates and pressures were compiled for 2008–2012 for more than 300 class II brine disposal wells. Several class II brine disposal wells were monitored with continuous wellhead pressure loggers to estimate reservoir properties and understand injection operations. Project results provide a catalog of injection rates for the various formations, which range from hundreds to more than 100,000 bbl per month per well. Hydrologic analysis of depleted hydrocarbon reservoirs and deep saline formations in the study area indicates that there is a large capacity for brine disposal, but the characteristics of the rock formations may limit injection rates. Based on hydrocarbon production and brine injection volumes from 2008 to 2012, approximately 9984 bbl of brine were routed to class II brine disposal wells per billion cubic feet gas production, which suggests ultimate demand of up to 706–2290 million bbl brine disposal related to unconventional Marcellus and Utica plays. Understanding the geology and operational history of the injection zones is critical to support safe, reliable, and environmentally responsible brine disposal in the region.
{"title":"Geologic and hydrologic aspects of brine disposal intervals in the Appalachian Basin","authors":"J. Sminchak","doi":"10.1306/EG.09031515008","DOIUrl":"https://doi.org/10.1306/EG.09031515008","url":null,"abstract":"Many different rock intervals are used for brine disposal injection in the Appalachian Basin. The study area was defined as eastern Kentucky, Ohio, Pennsylvania, and West Virginia. Brine injection in the study area has increased from approximately 6–7 million barrels (bbl) per year in the early 2000s to 17.6 million bbl in 2012, mostly due to shale gas activity. A review of geologic properties and subsurface distribution of rock formations used for injection is useful to understand brine disposal operations in the region. Operational data on injection rates and pressures were compiled for 2008–2012 for more than 300 class II brine disposal wells. Several class II brine disposal wells were monitored with continuous wellhead pressure loggers to estimate reservoir properties and understand injection operations. Project results provide a catalog of injection rates for the various formations, which range from hundreds to more than 100,000 bbl per month per well. Hydrologic analysis of depleted hydrocarbon reservoirs and deep saline formations in the study area indicates that there is a large capacity for brine disposal, but the characteristics of the rock formations may limit injection rates. Based on hydrocarbon production and brine injection volumes from 2008 to 2012, approximately 9984 bbl of brine were routed to class II brine disposal wells per billion cubic feet gas production, which suggests ultimate demand of up to 706–2290 million bbl brine disposal related to unconventional Marcellus and Utica plays. Understanding the geology and operational history of the injection zones is critical to support safe, reliable, and environmentally responsible brine disposal in the region.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66167138","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Thousands of shale gas wells have been drilled and hydraulically fractured across the state of Pennsylvania over the past decade, and more wells are being drilled each year. The drilled lengths of these wells and the amount of water being used to hydraulically fracture (frac) them continue to increase. These increases have led to an increase in the volume of wastewater being produced each year. However, the ratio of energy produced per barrel of wastewater has increased significantly over the past six years. Recent data show the volume of wastewater produced in one year is approximately 20% of the volume of frac water used in that same year. With changes in state policies, drilling companies in Pennsylvania have been recycling most of their wastewaters over the past few years. The development of various treatment technologies and brine-resistant frac mixtures has allowed companies to recycle this wastewater for use in future frac jobs. Use of this recycled water does not appear to be having a significant effect on production of oil or gas from wells. Recycling wastewater can be very cost-competitive when compared to options such as disposal via waste-treatment plants or injection wells.
{"title":"Wastewater recycling and reuse trends in Pennsylvania shale gas wells","authors":"Katherine W. Schmid, D. Yoxtheimer","doi":"10.1306/EG.09181515009","DOIUrl":"https://doi.org/10.1306/EG.09181515009","url":null,"abstract":"Thousands of shale gas wells have been drilled and hydraulically fractured across the state of Pennsylvania over the past decade, and more wells are being drilled each year. The drilled lengths of these wells and the amount of water being used to hydraulically fracture (frac) them continue to increase. These increases have led to an increase in the volume of wastewater being produced each year. However, the ratio of energy produced per barrel of wastewater has increased significantly over the past six years. Recent data show the volume of wastewater produced in one year is approximately 20% of the volume of frac water used in that same year. With changes in state policies, drilling companies in Pennsylvania have been recycling most of their wastewaters over the past few years. The development of various treatment technologies and brine-resistant frac mixtures has allowed companies to recycle this wastewater for use in future frac jobs. Use of this recycled water does not appear to be having a significant effect on production of oil or gas from wells. Recycling wastewater can be very cost-competitive when compared to options such as disposal via waste-treatment plants or injection wells.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.09181515009","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66167160","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Shale gas development in the United States has revolutionized energy production and supply, making the nation energy independent for the first time in decades. However, many people remain concerned that the large-scale hydraulic fracturing necessary to recover hydrocarbons from shale may degrade the environment, including groundwater. Improving the understanding of how groundwater may be impacted by shale gas development requires field monitoring at multiple sites on different shale plays under a variety of climates and hydrologic conditions. Such monitoring has been difficult to achieve because of a lack of access to commercial sites and an absence of funding to drill dedicated research wells.
{"title":"Adventures in groundwater monitoring: Why has it been so difficult to obtain groundwater data near shale gas wells?","authors":"D. Soeder","doi":"10.1306/EG.09221515011","DOIUrl":"https://doi.org/10.1306/EG.09221515011","url":null,"abstract":"Shale gas development in the United States has revolutionized energy production and supply, making the nation energy independent for the first time in decades. However, many people remain concerned that the large-scale hydraulic fracturing necessary to recover hydrocarbons from shale may degrade the environment, including groundwater. Improving the understanding of how groundwater may be impacted by shale gas development requires field monitoring at multiple sites on different shale plays under a variety of climates and hydrologic conditions. Such monitoring has been difficult to achieve because of a lack of access to commercial sites and an absence of funding to drill dedicated research wells.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.09221515011","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66167735","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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