It has been suggested by some that methane contamination of water wells is the main negative consequence of the development of natural gas resources. Concurrently, speculation in academic white papers and in the press that methane may be toxic has resulted in public concern. In northern Pennsylvania, methane being released from groundwater and entering homes (so-called stray gas) has become a focus of this concern. This phenomenon was widespread decades before shale gas development was initiated. This paper reviews the available literature on the safety and health hazards associated with natural gas. It concludes that the risks to homeowners are highest from flash fires occurring in methane oxygen gas clouds at relatively low methane concentrations collecting in poorly ventilated, confined areas of houses such as basements. Such risks can be mitigated effectively and in most cases at minimal cost. Methane can result in death from hypoxia (lack of oxygen) but only at methane levels in the air of more than 60%, which are unlikely to develop except under exceptional circumstances. There is no evidence that low to moderate levels of exposure to methane in air have any toxic effect on humans, and evidence for such effects at very high levels (already fatal because of hypoxia) is equivocal. It seems likely that methane at concentrations at least as high as 2.5% may well have positive health benefits for some diseases.
{"title":"Does methane pose significant health and public safety hazards?—A review","authors":"I. Duncan","doi":"10.1306/EG.06191515005","DOIUrl":"https://doi.org/10.1306/EG.06191515005","url":null,"abstract":"It has been suggested by some that methane contamination of water wells is the main negative consequence of the development of natural gas resources. Concurrently, speculation in academic white papers and in the press that methane may be toxic has resulted in public concern. In northern Pennsylvania, methane being released from groundwater and entering homes (so-called stray gas) has become a focus of this concern. This phenomenon was widespread decades before shale gas development was initiated. This paper reviews the available literature on the safety and health hazards associated with natural gas. It concludes that the risks to homeowners are highest from flash fires occurring in methane oxygen gas clouds at relatively low methane concentrations collecting in poorly ventilated, confined areas of houses such as basements. Such risks can be mitigated effectively and in most cases at minimal cost. Methane can result in death from hypoxia (lack of oxygen) but only at methane levels in the air of more than 60%, which are unlikely to develop except under exceptional circumstances. There is no evidence that low to moderate levels of exposure to methane in air have any toxic effect on humans, and evidence for such effects at very high levels (already fatal because of hypoxia) is equivocal. It seems likely that methane at concentrations at least as high as 2.5% may well have positive health benefits for some diseases.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.06191515005","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66165747","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}
Electromagnetic (EM) methods were used to characterize (1) the general near-surface geology and stratigraphy and (2) the initial electrical conductivity distribution at a enhanced oil recovery (EOR) site to assess and monitor possible near-surface environmental impacts of a carbon sequestration experiment. The field study was conducted at Cranfield Field, an EOR site where is being injected into a depleted oil and gas reservoir in the Cretaceous lower Tuscaloosa Formation in western Mississippi. The study focused on Tertiary and younger strata between the ground surface and maximum depths of approximately 200 m (656 ft) that host groundwater more than 3000 m (9843 ft) above the oil and gas reservoir and injection zone. It included an airborne geophysical survey collecting frequency-domain EM data, time-domain surface EM measurements, borehole logging with EM induction, natural gamma spectra, and water-level measurements. Different approaches of temperature drift corrections for the borehole EM data were compared; good results of consistent and accurate conductivity values were produced by combining both directions of a two-way (uphole and downhole) measurement. The airborne EM provided data over a large area with sufficient detail to give an overview for the subsequent surface and borehole surveys, the surface time-domain data gave insight into greater depths, and the borehole induction data provided the necessary details. These three EM methods complement each other in areal coverage, lateral and vertical resolution, and exploration depth. Together, they can provide a comprehensive near-surface characterization of the study area that is necessary to establish initial-state conditions that support future monitoring of potential migration to the near-surface environment.
{"title":"Characterizing initial-state conductivity distribution at a CO2 injection site with airborne, surface, and borehole electromagnetic induction methods","authors":"L. Costard, J. G. Paine","doi":"10.1306/EG.06191515004","DOIUrl":"https://doi.org/10.1306/EG.06191515004","url":null,"abstract":"Electromagnetic (EM) methods were used to characterize (1) the general near-surface geology and stratigraphy and (2) the initial electrical conductivity distribution at a enhanced oil recovery (EOR) site to assess and monitor possible near-surface environmental impacts of a carbon sequestration experiment. The field study was conducted at Cranfield Field, an EOR site where is being injected into a depleted oil and gas reservoir in the Cretaceous lower Tuscaloosa Formation in western Mississippi. The study focused on Tertiary and younger strata between the ground surface and maximum depths of approximately 200 m (656 ft) that host groundwater more than 3000 m (9843 ft) above the oil and gas reservoir and injection zone. It included an airborne geophysical survey collecting frequency-domain EM data, time-domain surface EM measurements, borehole logging with EM induction, natural gamma spectra, and water-level measurements. Different approaches of temperature drift corrections for the borehole EM data were compared; good results of consistent and accurate conductivity values were produced by combining both directions of a two-way (uphole and downhole) measurement. The airborne EM provided data over a large area with sufficient detail to give an overview for the subsequent surface and borehole surveys, the surface time-domain data gave insight into greater depths, and the borehole induction data provided the necessary details. These three EM methods complement each other in areal coverage, lateral and vertical resolution, and exploration depth. Together, they can provide a comprehensive near-surface characterization of the study area that is necessary to establish initial-state conditions that support future monitoring of potential migration to the near-surface environment.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.06191515004","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66165699","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}
One of the challenges confronting carbon dioxide capture and sequestration (CCS) in geologic media over extended periods of time is determining the caprock sealing capacity. If the pressure of supercritical carbon dioxide injected in the repository overcomes the caprock sealing capacity, leaking of may enter other porous formations, compromising the storage formation, or even may go back to the atmosphere, and thus the process of sequestration becomes futile. Carbon dioxide sealing capacity is controlled by two groups of parameters: (1) texture (e.g., the pore-throat size, distribution, geometry, and sorting; median grain size, porosity, degree of bioturbation, specific surface area, preferred orientation of matrix clay minerals, orientation, and aspect of ratio of organic particles) and (2) composition (mineralogical content, proportion of soft, deformable mineral grains to rigid grains, organic matter content, carbonate content, silt content, cementation, ductility, compaction, and ash content). The primary goal of this study was to investigate several parameters listed above and to estimate their respective contributions to sealing capacity to better understand its role in shale and carbonates. To assess the effect of textural and compositional properties on maximum retention column height, we collected 30 representative core samples from caprock formations in three counties (Cimarron, Texas, and Beaver) in the Oklahoma Panhandle. The study area was chosen because it hosts three depleted gas fields with a storage capacity of more than 35 million bbl and is situated at a crossroad leading to some significant stationary sources from North Texas, South Kansas, and northern Oklahoma. We used mercury injection porosimetry, scanning electron microscopy (SEM), Sedigraph energy dispersive spectra (EDS), x-ray diffraction (XRD), Brunauer–Emmett–Teller-specific surface area, and total organic carbon (TOC) measurements to assess textural and compositional properties of collected samples. The range of column height for the samples used in this study is between 0.2 and 1358 m (0.66 and 4455 ft). The average column height is 351 m (1152 ft). The depth interval approximately 1400 m (4593 ft) could reach relatively high values of column height, up to 1200 m (3937 ft). The above-mentioned interval is composed of mainly Cherokee and Morrowan Formations (shale seals). Principal component analysis (PCA) was carried out to infer the possible relationships between textural and compositional parameters. Generally, composition of our samples (shales vs. carbonates and sandstones) indicates a relatively stronger control on caprock sealing capacity, although individual mineral makeup of shale samples seems not correlated with retention column heights. In the same time, many textural parameters play a significant role in determining the sealing capacity of carbonate caprocks.
{"title":"Carbon dioxide sealing capacity: Textural or compositional controls? A case study from the Oklahoma Panhandle*","authors":"C. Crânganu, H. Soleymani","doi":"10.1306/EG.04021515002","DOIUrl":"https://doi.org/10.1306/EG.04021515002","url":null,"abstract":"One of the challenges confronting carbon dioxide capture and sequestration (CCS) in geologic media over extended periods of time is determining the caprock sealing capacity. If the pressure of supercritical carbon dioxide injected in the repository overcomes the caprock sealing capacity, leaking of may enter other porous formations, compromising the storage formation, or even may go back to the atmosphere, and thus the process of sequestration becomes futile. Carbon dioxide sealing capacity is controlled by two groups of parameters: (1) texture (e.g., the pore-throat size, distribution, geometry, and sorting; median grain size, porosity, degree of bioturbation, specific surface area, preferred orientation of matrix clay minerals, orientation, and aspect of ratio of organic particles) and (2) composition (mineralogical content, proportion of soft, deformable mineral grains to rigid grains, organic matter content, carbonate content, silt content, cementation, ductility, compaction, and ash content). The primary goal of this study was to investigate several parameters listed above and to estimate their respective contributions to sealing capacity to better understand its role in shale and carbonates. To assess the effect of textural and compositional properties on maximum retention column height, we collected 30 representative core samples from caprock formations in three counties (Cimarron, Texas, and Beaver) in the Oklahoma Panhandle. The study area was chosen because it hosts three depleted gas fields with a storage capacity of more than 35 million bbl and is situated at a crossroad leading to some significant stationary sources from North Texas, South Kansas, and northern Oklahoma. We used mercury injection porosimetry, scanning electron microscopy (SEM), Sedigraph energy dispersive spectra (EDS), x-ray diffraction (XRD), Brunauer–Emmett–Teller-specific surface area, and total organic carbon (TOC) measurements to assess textural and compositional properties of collected samples. The range of column height for the samples used in this study is between 0.2 and 1358 m (0.66 and 4455 ft). The average column height is 351 m (1152 ft). The depth interval approximately 1400 m (4593 ft) could reach relatively high values of column height, up to 1200 m (3937 ft). The above-mentioned interval is composed of mainly Cherokee and Morrowan Formations (shale seals). Principal component analysis (PCA) was carried out to infer the possible relationships between textural and compositional parameters. Generally, composition of our samples (shales vs. carbonates and sandstones) indicates a relatively stronger control on caprock sealing capacity, although individual mineral makeup of shale samples seems not correlated with retention column heights. In the same time, many textural parameters play a significant role in determining the sealing capacity of carbonate caprocks.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.04021515002","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66164017","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}
Net fluid production and pressure data were gathered to estimate the amount of storage space available and the potential for additional oil recovery using -enhanced oil recovery (EOR) in the Phacoides sandstone, McKittrick oilfield, San Joaquin Valley, California. The Phacoides reservoir has produced 61.5 million reservoir barrels of fluid, a volume equivalent to the subsurface capacity of 9.8 million metric tons of . Reservoir pressure changes with fluid production suggest that injecting 1 million metric tons of may raise reservoir pressures by 2 MPa (255 psi). We assume that the sealing capacity of the reservoir for injection is equivalent to the conditions controlling the original hydrocarbon accumulation. If injection pressures exceed this limit, the could leak through the caprock, from aging wellbores or along faults in the reservoir. Faulting has compartmentalized the reservoir into six major blocks with varying degrees of hydraulic communication. Injection wells will be required within each sealed fault block, resulting in additional costs for implementing a carbon capture and sequestration (CCS) project. Through -EOR, an additional 17 million bbl of oil may be recoverable, thereby offsetting the cost of carbon storage. This is equivalent to 1.4 million metric tons of additional storage space. However, assuming that none of the carbon is captured, combustion of this additional oil will add approximately 7 million metric tons of to the atmosphere, negating the available storage space in the reservoir and resulting in a net carbon gain to the atmosphere of 700,000 metric tons.
研究人员收集了加利福尼亚San Joaquin Valley McKittrick油田Phacoides砂岩的净流体产量和压力数据，以估计可用的存储空间和使用提高采收率(EOR)提高采收率的潜力。Phacoides油藏已经生产了6150万桶流体，相当于980万公吨的地下容量。油藏压力随流体产量的变化表明，注入100万公吨可能会使油藏压力提高2 MPa (255 psi)。我们假设储层的封闭能力相当于控制原始油气聚集的条件。如果注入压力超过这个极限，则可能从老化的井眼或沿油藏断层渗漏穿过盖层。断裂作用将储层划分为6个具有不同程度水力连通的主要区块。在每个封闭断块内都需要打注水井，这就导致了实施碳捕获与封存(CCS)项目的额外成本。通过eor，可以开采额外的1700万桶石油，从而抵消了碳储存的成本。这相当于140万吨额外的存储空间。然而，假设没有任何碳被捕获，这些额外石油的燃烧将向大气中增加约700万吨的碳，抵消了储层中的可用存储空间，导致大气中的净碳收益为70万吨。
{"title":"Carbon storage and CO2-enhanced oil recovery potential in the Temblor Formation, northeast McKittrick oilfield, San Joaquin Valley, California","authors":"K. Harrington, J. Gillespie","doi":"10.1306/EG.03121515001","DOIUrl":"https://doi.org/10.1306/EG.03121515001","url":null,"abstract":"Net fluid production and pressure data were gathered to estimate the amount of storage space available and the potential for additional oil recovery using -enhanced oil recovery (EOR) in the Phacoides sandstone, McKittrick oilfield, San Joaquin Valley, California. The Phacoides reservoir has produced 61.5 million reservoir barrels of fluid, a volume equivalent to the subsurface capacity of 9.8 million metric tons of . Reservoir pressure changes with fluid production suggest that injecting 1 million metric tons of may raise reservoir pressures by 2 MPa (255 psi). We assume that the sealing capacity of the reservoir for injection is equivalent to the conditions controlling the original hydrocarbon accumulation. If injection pressures exceed this limit, the could leak through the caprock, from aging wellbores or along faults in the reservoir. Faulting has compartmentalized the reservoir into six major blocks with varying degrees of hydraulic communication. Injection wells will be required within each sealed fault block, resulting in additional costs for implementing a carbon capture and sequestration (CCS) project. Through -EOR, an additional 17 million bbl of oil may be recoverable, thereby offsetting the cost of carbon storage. This is equivalent to 1.4 million metric tons of additional storage space. However, assuming that none of the carbon is captured, combustion of this additional oil will add approximately 7 million metric tons of to the atmosphere, negating the available storage space in the reservoir and resulting in a net carbon gain to the atmosphere of 700,000 metric tons.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.03121515001","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66163825","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}
Examination of historical water-quality data (major cations and anions and total dissolved solids [TDS]) for Rock Creek, located in eastern Nebraska’s saline wetlands north of the Platte River, revealed that concentrations of sodium (Na), chloride (Cl), and TDS increased significantly in the downstream reach below the town of Ceresco, exceeding the U.S. Environmental Protection Agency (USEPA) secondary drinking water standards of 250 mg/L for Cl and 500 mg/L for TDS. Research into the probable source(s) of these inorganic constituents revealed that the Dakota Formation of Late Cretaceous age subcrops in the study area and typically yields water with elevated concentrations of Na, Cl, and TDS in southeastern Nebraska. This brackish to saline water upwells to the surficial aquifer and Rock Creek streambed. Additionally, the significant levels of Na and Cl correlate well with the occurrence of unique saline wetlands along Rock Creek downstream from Ceresco. Public-domain geochemical speciation software codes (Visual MINTEQ and NETPATH) were used to characterize and investigate aqueous geochemistry of Rock Creek discharge and to calculate mixing proportions of Dakota Formation water and stream discharge. The NETPATH output suggests that 3.3%–18% of discharge in Rock Creek approximately 10 km (6.2 mi) southeast of Ceresco, Nebraska, originates from the Dakota Formation and probably the underlying Pennsylvanian bedrock. Hopefully, this paper will be the impetus for an up-to-date, comprehensive, and geochemical-rich data investigation of the Dakota Aquifer’s impact on the inorganic water quality of Rock Creek.
{"title":"Impact of the Dakota Aquifer on major-ion chemistry of Rock Creek discharge, eastern Nebraska, Midwest region","authors":"J. C. Atkinson","doi":"10.1306/EG.10231414006","DOIUrl":"https://doi.org/10.1306/EG.10231414006","url":null,"abstract":"Examination of historical water-quality data (major cations and anions and total dissolved solids [TDS]) for Rock Creek, located in eastern Nebraska’s saline wetlands north of the Platte River, revealed that concentrations of sodium (Na), chloride (Cl), and TDS increased significantly in the downstream reach below the town of Ceresco, exceeding the U.S. Environmental Protection Agency (USEPA) secondary drinking water standards of 250 mg/L for Cl and 500 mg/L for TDS. Research into the probable source(s) of these inorganic constituents revealed that the Dakota Formation of Late Cretaceous age subcrops in the study area and typically yields water with elevated concentrations of Na, Cl, and TDS in southeastern Nebraska. This brackish to saline water upwells to the surficial aquifer and Rock Creek streambed. Additionally, the significant levels of Na and Cl correlate well with the occurrence of unique saline wetlands along Rock Creek downstream from Ceresco. Public-domain geochemical speciation software codes (Visual MINTEQ and NETPATH) were used to characterize and investigate aqueous geochemistry of Rock Creek discharge and to calculate mixing proportions of Dakota Formation water and stream discharge. The NETPATH output suggests that 3.3%–18% of discharge in Rock Creek approximately 10 km (6.2 mi) southeast of Ceresco, Nebraska, originates from the Dakota Formation and probably the underlying Pennsylvanian bedrock. Hopefully, this paper will be the impetus for an up-to-date, comprehensive, and geochemical-rich data investigation of the Dakota Aquifer’s impact on the inorganic water quality of Rock Creek.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.10231414006","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66168118","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}
This study simulated the injection of supercritical phase into the South Georgia Rift (SGR) basin to evaluate the feasibility of long-term storage. Because of the lack of basin data, an equilibrium model was used to estimate the initial hydrostatic pressure, temperature, and salinity gradients that represent our study area. For the equilibrium model, the USGS SEAWAT program was used and for the injection simulation, TOUGH2-ECO2N was used. A stochastic approach was used to populate the permeability in the injection layer within the model domain. The statistical method to address permeability uncertainty and heterogeneity was sequential Gaussian simulation. The target injection depths are well below the 1 km (∼0.62 mi) depth required to maintain as a supercritical fluid. There were very little data pertaining to the properties in the deep Jurassic/Triassic SGR basin formations. So, conservative porosity and permeability starting points were postulated using data from analogous basins. This study simulated 30 million tons of injected at a rate of 1 million tons per year for 30 yr, which is the minimum capacity requirement by the U.S. Department of Energy (DOE) for a viable storage reservoir. In addition to this requirement, a 970-yr shut-in time (no injection) was also simulated to better determine the long-term fate and migration of the injected and to ensure that the SGR basin could effectively contain 30 million tons of . The preliminary modeling of injection indicated that the SGR basin is suitable for geologic storage of this U.S. DOE stated minimum capacity.
{"title":"CO2 injection simulation into the South Georgia Rift Basin for geologic storage: A preliminary assessment","authors":"D. Brantley, J. Shafer, V. Lakshmi","doi":"10.1306/EG.09191414008","DOIUrl":"https://doi.org/10.1306/EG.09191414008","url":null,"abstract":"This study simulated the injection of supercritical phase into the South Georgia Rift (SGR) basin to evaluate the feasibility of long-term storage. Because of the lack of basin data, an equilibrium model was used to estimate the initial hydrostatic pressure, temperature, and salinity gradients that represent our study area. For the equilibrium model, the USGS SEAWAT program was used and for the injection simulation, TOUGH2-ECO2N was used. A stochastic approach was used to populate the permeability in the injection layer within the model domain. The statistical method to address permeability uncertainty and heterogeneity was sequential Gaussian simulation. The target injection depths are well below the 1 km (∼0.62 mi) depth required to maintain as a supercritical fluid. There were very little data pertaining to the properties in the deep Jurassic/Triassic SGR basin formations. So, conservative porosity and permeability starting points were postulated using data from analogous basins. This study simulated 30 million tons of injected at a rate of 1 million tons per year for 30 yr, which is the minimum capacity requirement by the U.S. Department of Energy (DOE) for a viable storage reservoir. In addition to this requirement, a 970-yr shut-in time (no injection) was also simulated to better determine the long-term fate and migration of the injected and to ensure that the SGR basin could effectively contain 30 million tons of . The preliminary modeling of injection indicated that the SGR basin is suitable for geologic storage of this U.S. DOE stated minimum capacity.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2015-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.09191414008","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66167228","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}
This paper explores some basic economics of the climate change issue and how government response may impact the petroleum industry. Possible economic aspects are addressed by examining past and projected fossil fuel production numbers, calculating their resulting emissions, and then projecting how regulations or taxes might affect energy prices and production. Nine medium to major petroleum companies, which do business in the USA, are currently factoring in some kind of carbon emission restrictions into their long-range business plans. A driver for these plans is that the vast majority of countries, including the world’s largest emitters, have formally agreed to limit their emissions to avoid a 2°C (3.6°F) rise in global temperatures. Because there is no agreement yet on a set number of allowable emissions, this paper utilizes estimated carbon budgets from one paper, Meinshausen et al. (2009). Some pertinent results derived herein are the following: 1) oil and natural gas only comprise 33.3% of potential emissions from fossil fuels; 2) under a probability scenario of exceeding 2°C (3.6°F), all proven reserves of oil and natural gas (as of 2012) could be consumed, whereas only 56% could be utilized with continued coal consumption. To demonstrate how a market approach might limit carbon emissions, a simple model shows how an annually increasing carbon tax affects the relative price of fossil fuels and alternative energy. The objective of this paper is to present arguments that there are economic reasons for American Association of Petroleum Geologists (AAPG) to address the issue of climate change.
本文探讨了气候变化问题的一些基本经济学，以及政府的应对措施如何影响石油工业。通过检查过去和预计的化石燃料产量，计算其产生的排放量，然后预测法规或税收如何影响能源价格和生产，可以解决可能的经济方面的问题。在美国开展业务的九家大中型石油公司目前正在将某种碳排放限制纳入其长期业务计划。这些计划的一个推动因素是，绝大多数国家，包括世界上最大的排放国，已经正式同意限制排放，以避免全球气温上升2°C(3.6°F)。由于对允许排放的数量尚未达成一致，本文使用了Meinshausen et al.(2009)的一篇论文中的估计碳预算。本文得出的一些相关结果如下:1)石油和天然气仅占化石燃料潜在排放量的33.3%;2)在超过2°C(3.6°F)的概率情景下，所有已探明的石油和天然气储量(截至2012年)都可以被消耗，而在持续消耗煤炭的情况下，只有56%可以被利用。为了证明市场方法如何限制碳排放，一个简单的模型显示了每年增加的碳税如何影响化石燃料和替代能源的相对价格。本文的目的是提出美国石油地质学家协会(AAPG)解决气候变化问题有经济原因的论点。
{"title":"An examination of carbon budgets, carbon taxes, industry attitudes to global warming, and AAPG","authors":"J. Rine","doi":"10.1306/EG.04231414001","DOIUrl":"https://doi.org/10.1306/EG.04231414001","url":null,"abstract":"This paper explores some basic economics of the climate change issue and how government response may impact the petroleum industry. Possible economic aspects are addressed by examining past and projected fossil fuel production numbers, calculating their resulting emissions, and then projecting how regulations or taxes might affect energy prices and production. Nine medium to major petroleum companies, which do business in the USA, are currently factoring in some kind of carbon emission restrictions into their long-range business plans. A driver for these plans is that the vast majority of countries, including the world’s largest emitters, have formally agreed to limit their emissions to avoid a 2°C (3.6°F) rise in global temperatures. Because there is no agreement yet on a set number of allowable emissions, this paper utilizes estimated carbon budgets from one paper, Meinshausen et al. (2009). Some pertinent results derived herein are the following: 1) oil and natural gas only comprise 33.3% of potential emissions from fossil fuels; 2) under a probability scenario of exceeding 2°C (3.6°F), all proven reserves of oil and natural gas (as of 2012) could be consumed, whereas only 56% could be utilized with continued coal consumption. To demonstrate how a market approach might limit carbon emissions, a simple model shows how an annually increasing carbon tax affects the relative price of fossil fuels and alternative energy. The objective of this paper is to present arguments that there are economic reasons for American Association of Petroleum Geologists (AAPG) to address the issue of climate change.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2014-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.04231414001","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66164668","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}
Geological sequestration of for enhanced oil recovery (EOR) has been in use for decades, but it now represents a potentially economical method of mitigating anthropogenic output. However, current understanding of the interaction between injected and the reservoir rock is limited and prevents accurate estimation of reservoir capacity. Delineating the diagenesis of the reservoir is useful in predicting post- injection changes in reservoir porosity and permeability. The Albian Donovan Sand member of the Rodessa Formation, Citronelle Field, Alabama, is the subject of an ongoing Department of Energy -EOR suitability study. The arkosic Donovan Sand is highly heterogeneous, containing conglomeratic intervals, low to extensive poikilotopic calcite cement, loose to tight grain packing, and low , water injection and oil and gas production rates dropped below modeled values. We propose that the injection dissolved calcite cement proximal to the injection well and reprecipitated it nearby with the effect of reducing porosity and/or permeability.
{"title":"Petrologic evidence for the diagenesis of the Donovan Sand, Citronelle Field, Alabama, and implications for CO2 storage and enhanced oil recovery","authors":"G. Case, A. Weislogel, Keith Coffindaffer","doi":"10.1306/EG.03111413013","DOIUrl":"https://doi.org/10.1306/EG.03111413013","url":null,"abstract":"Geological sequestration of for enhanced oil recovery (EOR) has been in use for decades, but it now represents a potentially economical method of mitigating anthropogenic output. However, current understanding of the interaction between injected and the reservoir rock is limited and prevents accurate estimation of reservoir capacity. Delineating the diagenesis of the reservoir is useful in predicting post- injection changes in reservoir porosity and permeability. The Albian Donovan Sand member of the Rodessa Formation, Citronelle Field, Alabama, is the subject of an ongoing Department of Energy -EOR suitability study. The arkosic Donovan Sand is highly heterogeneous, containing conglomeratic intervals, low to extensive poikilotopic calcite cement, loose to tight grain packing, and low , water injection and oil and gas production rates dropped below modeled values. We propose that the injection dissolved calcite cement proximal to the injection well and reprecipitated it nearby with the effect of reducing porosity and/or permeability.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2014-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.03111413013","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66163761","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}
The Eau Claire Formation of the midwestern United States was evaluated for its potential use as a confining unit (seal) overlying a sandstone reservoir to securely store injected . This evaluation included: (1) lithofacies composition and distribution, (2) capillary entry pressure analysis, and (3) fluid- and fracture-pressure analysis. The regional distribution of lithofacies in the Eau Claire was evaluated by examination of core and log data from selected wells across the study area. Log data were used to define electro-lithofacies, which are spatially variable and represent a mixture of shale, siltstone, sandstone, limestone, and dolomite. Because of the significant variation in lithofacies and the complex spatial distribution, the entire interval should be considered in evaluating the seal capacity of the unit at a given locality. Mercury-injection capillary pressure (MICP) data were obtained on 17 samples of Eau Claire lithofacies ranging from muddy shale to sand/silt to evaluate the potential for capillary entry of fluids into the pore system of the lithofacies of the unit. Interpretation of these data indicated capillary failure of the muddy shale lithofacies is unlikely. However, many of the MICP samples contain millimeter-scale silt/sand interbeds, which would probably allow entry but, because these beds commonly have very limited lateral continuity, they are very unlikely to provide pathways for large-scale leakage through the interval. Evaluation of structural settings, lithostatic and existing formation aquifer pressures in the Eau Claire, in conjunction with the height of columns stored in the underlying Mount Simon Sandstone (Cambrian), suggest that fluid pressures induced by a static buoyant plume are unlikely to induce fractures in the formation. However, elevation of the aquifer pressure during injection may be capable of creating fractures within the unit.
{"title":"An evaluation of the seal capacity and CO2 retention properties of the Eau Claire Formation (Cambrian)","authors":"R. Lahann, J. Rupp, C. Medina","doi":"10.1306/EG.05011414003","DOIUrl":"https://doi.org/10.1306/EG.05011414003","url":null,"abstract":"The Eau Claire Formation of the midwestern United States was evaluated for its potential use as a confining unit (seal) overlying a sandstone reservoir to securely store injected . This evaluation included: (1) lithofacies composition and distribution, (2) capillary entry pressure analysis, and (3) fluid- and fracture-pressure analysis. The regional distribution of lithofacies in the Eau Claire was evaluated by examination of core and log data from selected wells across the study area. Log data were used to define electro-lithofacies, which are spatially variable and represent a mixture of shale, siltstone, sandstone, limestone, and dolomite. Because of the significant variation in lithofacies and the complex spatial distribution, the entire interval should be considered in evaluating the seal capacity of the unit at a given locality. Mercury-injection capillary pressure (MICP) data were obtained on 17 samples of Eau Claire lithofacies ranging from muddy shale to sand/silt to evaluate the potential for capillary entry of fluids into the pore system of the lithofacies of the unit. Interpretation of these data indicated capillary failure of the muddy shale lithofacies is unlikely. However, many of the MICP samples contain millimeter-scale silt/sand interbeds, which would probably allow entry but, because these beds commonly have very limited lateral continuity, they are very unlikely to provide pathways for large-scale leakage through the interval. Evaluation of structural settings, lithostatic and existing formation aquifer pressures in the Eau Claire, in conjunction with the height of columns stored in the underlying Mount Simon Sandstone (Cambrian), suggest that fluid pressures induced by a static buoyant plume are unlikely to induce fractures in the formation. However, elevation of the aquifer pressure during injection may be capable of creating fractures within the unit.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2014-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.05011414003","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66164841","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}
Hydraulic fracture stimulation (HFS) of unconventional oil and gas reservoirs is of public concern with respect to fugitive gas emissions, fracture height growth, induced seismicity, and groundwater quality changes. We evaluate the potential pathways of fugitive gas seepage during stimulation, in production, and after abandonment; we conclude that the quality of the casing installations is the major concern with respect to future gas migration. The pathway outside the casing is of particular concern as it likely leads to many wells leaking natural gas from thin intermediate-depth gas zones rather than from the deeper target reservoirs. These paths must be understood, likely cases identified, and the probability of leakage mitigated by methods such as casing perforation and squeeze, expanding packers of long life, and induced leakoff into saline aquifers. HFS itself appears not to be a significant risk, with two exceptions. These occur during the high-pressure stage of HFS when (1) legacy well casings are intersected by fracturing fluids and when (2) these fluids pressurize nearby offset wells that have not been shut in, particularly offset wells in the same formation that are surrounded by a region of pressure depletion in which the horizontal stresses are also diminished. This paper focuses on the issue of gas migration from deeper than the surface casing that occurs outside the casing caused by geomechanical processes associated with cement shrinkage, and we review the origin of the gas pulses recorded in noise logs, landowner wells, and surface-casing vents.
{"title":"Seepage pathway assessment for natural gas to shallow groundwater during well stimulation, in production, and after abandonment","authors":"M. Dusseault, R. Jackson","doi":"10.1306/EG.04231414004","DOIUrl":"https://doi.org/10.1306/EG.04231414004","url":null,"abstract":"Hydraulic fracture stimulation (HFS) of unconventional oil and gas reservoirs is of public concern with respect to fugitive gas emissions, fracture height growth, induced seismicity, and groundwater quality changes. We evaluate the potential pathways of fugitive gas seepage during stimulation, in production, and after abandonment; we conclude that the quality of the casing installations is the major concern with respect to future gas migration. The pathway outside the casing is of particular concern as it likely leads to many wells leaking natural gas from thin intermediate-depth gas zones rather than from the deeper target reservoirs. These paths must be understood, likely cases identified, and the probability of leakage mitigated by methods such as casing perforation and squeeze, expanding packers of long life, and induced leakoff into saline aquifers. HFS itself appears not to be a significant risk, with two exceptions. These occur during the high-pressure stage of HFS when (1) legacy well casings are intersected by fracturing fluids and when (2) these fluids pressurize nearby offset wells that have not been shut in, particularly offset wells in the same formation that are surrounded by a region of pressure depletion in which the horizontal stresses are also diminished. This paper focuses on the issue of gas migration from deeper than the surface casing that occurs outside the casing caused by geomechanical processes associated with cement shrinkage, and we review the origin of the gas pulses recorded in noise logs, landowner wells, and surface-casing vents.","PeriodicalId":11706,"journal":{"name":"Environmental Geosciences","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2014-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1306/EG.04231414004","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"66164697","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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