understanding shallow and deep flow for assessing the risk of hydrocarbon development to groundwater quality in recent years concerns have been raised about the potential environmental impacts of oil and gas og 2 potential contaminant release mechanisms related to og and 3 the expected effects that contaminant releases could have on groundwater

geochemical evidence for possible natural migration of marcellus formation brine to shallow aquifers in pennsylvania the debate surrounding the safety of shale gas development in the appalachian basin has generated increased awareness of drinking water quality in rural communities concerns include the potential for migration of stray gas metal rich formation brines and hydraulic fracturing and or flowback fluids to drinking water aquifers a critical question common to these environmental risks is the hydraulic connectivity between the shale gas formations and the overlying shallow drinking water aquifers we present geochemical evidence from northeastern pennsylvania showing that pathways unrelated to recent drilling activities exist in some locations between deep underlying formations and shallow drinking water aquifers integration of chemical data br cl na ba sr and li and isotopic ratios 87sr 86sr 2h h 18o 16o and 228ra 226ra from this and previous studies in 426 shallow groundwater samples and 83 northern appalachian brine samples suggest that mixing relationships between shallow ground water and a deep formation brine causes groundwater salinization in some locations the strong geochemical fingerprint in the salinized cl 20 mg l groundwater sampled from the alluvium catskill and lock haven aquifers suggests possible migration of marcellus brine through naturally occurring pathways the occurrences of saline water do not correlate with the location of shale gas wells and are consistent with reported data before rapid shale gas development in the region however the presence of these fluids suggests conductive pathways and specific geostructural and or hydrodynamic regimes in northeastern pennsylvania that are at increased risk for contamination of shallow drinking water resources particularly by fugitive gases because of natural hydraulic connections to deeper formations

joint sets that enhance production from middle and upper devonian gas shales of the appalachian basin the marine middle and upper devonian section of the appalachian basin includes several black shale units that carry two regional joint sets j1 and j2 sets as observed in outcrop core and borehole images these joints formed close to or at peak burial depth as natural hydraulic fractures induced by abnormal fluid pressures generated during thermal maturation of organic matter when present together earlier j1 joints are crosscut by later j2 joints in outcrops of black shale on the foreland northwest side of the appalachian basin the east northeast trending j1 set is more closely spaced than the northwest striking j2 set however j2 joints are far more pervasive throughout the exposed devonian marine clastic section on both sides of the basin by geological coincidence the j1 set is nearly parallel the maximum compressive normal stress of the contemporary tectonic stress field shmax because the contemporary tectonic stress field favors the propagation of hydraulic fracture completions to the east northeast fracture stimulation from vertical wells intersects and drains j2 joints horizontal drilling and subsequent stimulation benefit from both joint sets by drilling in the north northwest south southeast directions horizontal wells cross and drain j1 joints whenever present then staged hydraulic fracture stimulations if necessary run east northeast i e parallel to the j1 set under the influence of the contemporary tectonic stress field thereby crosscutting and draining j2 joints

development and structural architecture of the eastern black sea the cenozoic sedimentary fill of the eastern black sea figure 1 is up to 10 km in thickness its bedding is almost horizontal with the the exception of basin flanks the eastern black sea basin is separated from the cenozoic sorokin and tuapse troughs by the buried shatsky and tetyaev ridges which have mesozoic and paleocene eocene sedimentary cover figure 2

long period long duration seismic events during hydraulic stimulation of shale and tight gas reservoirs part 2 location and mechanisms abstractlong period long duration lpld seismic events that have been observed during hydraulic stimulation of shale gas and tight gas reservoirs appear to represent slow shear slip on relatively large faults within the limitations of the recording geometry we determine the areas in the reservoirs where the events are located in two case studies in the barnett shale in one data set lpld events appear to occur in the region where the density of natural fractures as well as the fluid pressure during pumping were highest in the other data set the lpld events are observed to occur between two wells and seem to establish a hydraulic connection between them in both data sets the lpld events occur in areas with very few located microearthquakes a combination of factors such as high fluid pressure and or high clay content is potentially responsible for the slowly slipping faults the lpld events appear to be occurring only on faults large enough to produce a sequence of slow slip events we suggest that

a post younger dryas black sea regression identified from sequence stratigraphy correlated to core analysis and dating the north western black sea shelf is the widest continental shelf of the black sea where the danube delta prodelta system includes important records on the black sea water level fluctuations this study integrates newly acquired high resolution single channel seismic reflection profiles and calypso piston cores recovered along a transect extending from the danube delta deep into its deep sea fan the correlated results provide information on the late quaternary architecture of the danube black sea shelf and on the role of global glacio eustatic fluctuations on the building of the danube delta prodelta the sedimentary sequences in the black sea are strongly affected by water level changes for the whole duration of late glacial holocene period the level of the black sea was controlled by the regional climate modifications rather than the global eustatic changes the seismic sequences recognized on a very high resolution seismic profile were dated by two calypso piston cores based on the obtained data during the last glacial maximum the black sea was a land locked lake with the level below 120 m in the course of the deglaciation the lake level rose up to 40 m which is confirmed by occurrence of the prodelta lobes formed after the rise in water level originated from the melt water following the younger dryas 11 000 8500 c 14 bp there occurred a new level lowering to the level of 100 m identified by the forced regression deposits recorded on the romanian shelf this last lowstand previously recognized by a pronounced shoreline with a characteristic beach profile and a belt of coastal dunes is also indicated by the prodelta at 100 m depth all these coastal features as well as the incised anastomosed channel system remained preserved on the shelf resulting from a rapid ultimate transgression starting immediately after 8500 c 14 bp c 2010 elsevier ltd and inqua all rights reserved

shallow gas transport and reservoirs in the vicinity of deeply rooted mud volcanoes in the central black sea abstract the principal objective of this paper is to understand the gas migration process and the structures of mud volcanoes in the central black sea multichannel seismic lines were acquired across 6 mud volcanoes in the central black sea msu yuzhmorgeologiya malyshev kornev goncharov and vassoevitch based on a high resolution seismic processing we analyzed acoustic anomalies and studied near surface sediment structures of these mud volcanoes four types of pathways for gas and fluid migration and three types of gas reservoirs were recognized a regional bottom simulating reflection bsr seems to be absent in most parts of the study area however a clear bsr was observed in one of the seismic profiles the free gas migrating upwards along these pathways were sealed by gas hydrates or fine grained sediments in the gas hydrate stability zone four seismic units were separated according to a suggested age model and identified seismic facies combining with the possible sedimentary processes of the central black sea we try to reveal the active mechanism of these mud volcanoes these mud volcanoes reveal two to three major active stages these active stages might be related to distinct sea level falls which seem to be one of the main trigger factors of the mud volcano eruptions in the central black sea a structural model for the msu mud volcano was presented with respect to mechanisms of gas migration and the origin of the gas

controls on carbonate skeletal mineralogy global co2 evolution and mass extinctions a quantitative compilation of carbonate skeletal mineralogy through the phanerozoic shows a progressive replacement of low mg calcite by aragonite this general trend overrides the subsidiary trend of greenhouse intervals favoring biogenic low mg calcite mineralogies calcite seas and icehouse intervals facilitating aragonite high mg calcite mineralogies aragonite seas the replacement of low mg calcite by aragonite was however achieved episodically at mass extinction intervals in particular the end permian extinction both preferentially removed species bearing unfavorable low mg calcite and allowed the selective radiation of biota with favorable aragonite this demonstrates the importance of incumbency in the evolution of skeletal mineralogy we suggest that the broad increase of aragonitic biota has been controlled by changes in atmospheric carbon dioxide partial pressure p co2 via carbonate mineral kinetics through the phanerozoic broadly decreasing p co2 levels led to decreasing total alkalinity and dissolved inorganic carbon and increasing oceanic ph superimposed upon this general trend there are cyclic episodes of relatively high p co2 and saturation state combined with a lower ratio of magnesium to calcium ions in seawater driven by the relatively slow changes in mid ocean ridge expansion rates mass extinction events many of which may have been caused by rapid global changes in temperature and or p co2 represent major intervals of turnover

the late holocene evolution of the black sea a critical view on the so called phanagorian regression abstract throughout its geologic history the black sea experienced major sea level changes accompanied by severe environmental modifications including geomorphologic reshaping the most spectacular changes were driven by the quaternary glaciations and deglaciations that reflect responses to milankovitch cycles of 100 and 20 ky periodicity major sea level changes were also considered for a shorter and more recent cyclicity the concept of the phanagorian re and transgression cycle supposedly with a minimum sea level stand of 5 6 m below its present position in the middle of the 1st millennium bc was established in 1963 by fedorov for the black sea region it was based on archaeological and palaeogeographical research conducted around the ancient greek colonies of the cimmerian bosporus in particular at the name giving site of phanagoria where underwater prospection had revealed the presence of a large number of submerged relics of the classical greek era analyses of sediment cores as well as 14c dated fossil coastal bars in the western and southern parts of taman peninsula show that contemporary coastal bars are related to different sea levels the dissymmetry can reach up to 6 m around 500 bc this and more evidence from drill cores confirms that on taman peninsula many of the apparent sea level changes are tectonically induced the subsidence may have been initiated by the release of gas from mud volcanoes inherited along anticline axes other observations around the black sea confirm that submerged archaeological sites correspond to areas where subsidence has taken places while the so called holocene highstand said to have been located above the present day sea level is associated with uplift areas triggered by the ongoing caucasus orogeny recent oceanographic research carried out in the black sea area shows that since the black sea was reconnected with the mediterranean sea i e 7500 14c bp at the latest both marine water bodies have been in equilibrium this fact and arguments from archaeology history hydrodynamics etc lead us to question the existence of the phanagorian regression it is important to note that none of the sea level curves established for the eastern mediterranean shows a comparable regression transgression cycle of several metres during the 1st millennium bc

petroleum geology and geochemistry of the council run gas field north central pennsylvania the council run field of north central pennsylvania is one of the most productive natural gas fields in the central appalachian basin the field is enigmatic because of its position near the eastern edge of the appalachian plateau where strata with reservoir potential elsewhere have low porosities and permeabilities or are poorly sealed council run has four principal reservoir sandstones the lower three occur in a distinct fourth order type 1 stratigraphic sequence the stacking pattern of sandstones in this sequence defines lowstand transgressive and highstand systems tracts core well log and map interpretations reveal that the lowest interval consists of multiple coarsening upward parasequences deposited in deltaic and nearshore environments of the lowstand systems tract during a forced regression most of these sandstones are lithic and some are highly feldspathic productive sandstones display hybrid void textures that consist of reduced primary intergranular pores preserved in part by relatively early petroleum emplacement and secondary oversized fabric selective pores the generative potential of the organic matter in the potential source rocks is exhausted but geochemical and petrographic evidences indicate that these black shales originally contained oil prone kerogens and generated liquid hydrocarbons stable isotope geochemistry suggests that gases were generated by primary cracking of kerogens and or by secondary cracking of oil between 320 and 290 ma dispersive migration paths were both lateral and vertical because of compression associated with alleghanian orogenesis most of the oil in the devonian section was cracked to gas during deeper burial between 270 and 240 ma

evaluating a groundwater supply contamination incident attributed to marcellus shale gas development high volume hydraulic fracturing hvhf has revolutionized the oil and gas industry worldwide but has been accompanied by highly controversial incidents of reported water contamination for example groundwater contamination by stray natural gas and spillage of brine and other gas drilling related fluids is known to occur however contamination of shallow potable aquifers by hvhf at depth has never been fully documented we investigated a case where marcellus shale gas wells in pennsylvania caused inundation of natural gas and foam in initially potable groundwater used by several households with comprehensive 2d gas chromatography coupled to time of flight mass spectrometry gcxgc tofms an unresolved complex mixture of organic compounds was identified in the aquifer similar signatures were also observed in flowback from marcellus shale gas wells a compound identified in flowback 2 n butoxyethanol was also positively identified in one of the foaming drinking water wells at nanogram per liter concentrations the most likely explanation of the incident is that stray natural gas and drilling or hf compounds were driven 1 3 km along shallow to intermediate depth fractures to the aquifer used as a potable water source part of the problem may have been wastewaters from a pit leak reported at the nearest gas well pad the only nearby pad where wells were hydraulically fractured before the contamination incident if samples of drilling pit and hvhf fluids had been available gcxgc tofms might have fingerprinted the contamination source such evaluations would contribute significantly to better management practices as the shale gas industry expands worldwide

capillary tension and imbibition sequester frack fluid in marcellus gas shale in a recent issue of pnas warner et al 1 interpreted local ground water chemistry in the appalachian basin as a signal for cross formational pathways where natural migration of brine from the deep formations may be ongoing today the implication of this paper is that the marcellus is leaking now naturally without any human assistance and that if water based fluid is injected into these cross formational pathways that leakage which is already contaminating the aquifers with salt could be made much worse

shallow aquifer vulnerability from subsurface fluid injection at a proposed shale gas hydraulic fracturing site groundwater flow resulting from a proposed hydraulic fracturing fracking operation was numerically modeled using 91 scenarios scenarios were chosen to be a combination of hydrogeological factors that a priori would control the long term migration of fracking fluids to the shallow subsurface these factors were induced fracture extent cross basin groundwater flow deep low hydraulic conductivity strata deep high hydraulic conductivity strata fault hydraulic conductivity and overpressure the study considered the bowland basin northwest england with fracking of the bowland shale at 2000 m depth and the shallow aquifer being the sherwood sandstone at 300 500 m depth of the 91 scenarios 73 scenarios resulted in tracked particles not reaching the shallow aquifer within 10000 years and 18 resulted in travel times less than 10000 years four factors proved to have a statistically significant impact on reducing travel time to the aquifer increased induced fracture extent absence of deep high hydraulic conductivity strata relatively low fault hydraulic conductivity and magnitude of overpressure modeling suggests that high hydraulic conductivity formations can be more effective barriers to vertical flow than low hydraulic conductivity formations furthermore low hydraulic conductivity faults can result in subsurface pressure compartmentalization reducing horizontal groundwater flow and encouraging vertical fluid migration the modeled worst case scenario using unlikely geology and induced fracture lengths maximum values for strata hydraulic conductivity and with conservative tracer behaviour had a particle travel time of 130 years to the base of the shallow aquifer this study has identified hydrogeological factors which lead to aquifer vulnerability from shale exploitation

numerical simulation of the environmental impact of hydraulic fracturing of tight shale gas reservoirs on near surface groundwater background base cases shallow reservoirs short term gas and water transport hydrocarbon production from unconventional resources and the use of reservoir stimulation techniques such as hydraulic fracturing has grown explosively over the last decade however concerns have arisen that reservoir stimulation creates significant environmental threats through the creation of permeable pathways connecting the stimulated reservoir with shallower freshwater aquifers thus resulting in the contamination of potable groundwater by escaping hydrocarbons or other reservoir fluids this study investigates by numerical simulation gas and water transport between a shallow tight gas reservoir and a shallower overlying freshwater aquifer following hydraulic fracturing operations if such a connecting pathway has been created we focus on two general failure scenarios 1 communication between the reservoir and aquifer via a connecting fracture or fault and 2 communication via a deteriorated preexisting nearby well we conclude that the key factors driving short term transport of gas include high permeability for the connecting pathway and the overall volume of the connecting feature production from the reservoir is likely to mitigate release through reduction of available free gas and lowering of reservoir pressure and not producing may increase the potential for release we also find that hydrostatic tight gas reservoirs are unlikely to act as a continuing source of migrating gas as gas contained within the newly formed hydraulic fracture is the primary source for potential contamination such incidents of gas escape are likely to be limited in duration and scope for hydrostatic reservoirs reliable field and laboratory data must be acquired to constrain the factors and determine the likelihood of these outcomes

hydraulic fracturing fluid migration in the subsurface a review and expanded modeling results understanding the transport of hydraulic fracturing hf fluid that is injected into the deep subsurface for shale gas extraction is important to ensure that shallow drinking water aquifers are not contaminated topographically driven flow overpressured shale reservoirs permeable pathways such as faults or leaky wellbores the increased formation pressure due to hf fluid injection and the density contrast of the hf fluid to the surrounding brine can encourage upward hf fluid migration in contrast the very low shale permeability and capillary imbibition of water into partially saturated shale may sequester much of the hf fluid and well production will remove hf fluid from the subsurface we review the literature on important aspects of hf fluid migration single phase flow and transport simulations are performed to quantify how much hf fluid is removed via the wellbore with flowback and produced water how much reaches overlying aquifers and how much is permanently sequestered by capillary imbibition which is treated as a sink term based on a semianalytical one dimensional solution for two phase flow these simulations include all of the important aspects of hf fluid migration identified in the literature review and are performed in five stages to faithfully represent the typical operation of a hydraulically fractured well no fracturing fluid reaches the aquifer without a permeable pathway in the presence of a permeable pathway 10 times more fracturing fluid reaches the aquifer if well production and capillary imbibition are not included in the model

insights from petrography mineralogy and u pb zircon geochronology into the provenance and reservoir potential of cenozoic siliciclastic depositional systems supplying the northern margin of the eastern black sea the eastern black sea is one of the few remaining underexplored hydrocarbon basins in europe reservoir quality is a key risk factor in the basin the analysis of up dip portions of oligocene to pliocene depositional systems exposed around its northern and eastern margins enable the composition and provenance of sandstones within the basin to be predicted two major sources of quartz rich sandstone are present the russian western greater caucasus which became a subaerial sediment source in the oligocene and the east european craton scythian platform these are predicted to form better quality reservoirs at shallow and moderate burial depths than their rock fragment rich counterparts due to lesser amounts of compactional porosity loss oligo miocene sandstones from the russian western greater caucasus were deposited as turbidites in the tuapse trough sandstones from the east european craton scythian platform were largely trapped within the indolo kuban basin north of the greater caucasus they only entered the eastern black sea in large volumes from latest miocene or pliocene time in the region of the kerch taman shelf at the western tip of the greater caucasus however it is possible that a precursor to this system supplied the oligocene to early miocene reservoir sandstones within the subbotina field the dziruli massif in western georgia also generated quartz rich sandstones but these are not thought to have entered the black sea

long period long duration seismic events during hydraulic stimulation of shale and tight gas reservoirs part 1 waveform characteristics abstractlong period long duration lpld seismic events are relatively low amplitude signals that have been observed during hydraulic fracturing in several shale gas and tight gas reservoirs these events are similar in appearance to tectonic tremor sequences observed in subduction zones and transform fault boundaries lpld events are predominantly composed of s waves but weaker p waves have also been identified in some cases microearthquakes are observed during the events based on the similarity with tectonic tremors and our observations of several impulsive s wave arrivals within the lpld events we interpret the lpld events as resulting from the superposition of slow shear slip events on relatively large faults most large lpld waveforms appear to start as a relatively slower low amplitude precursor lacking clear impulsive arrivals we estimate the energy carried by the larger lpld events to be 1000 times greater than a mw 2 microseismic event that is typical of the events that occur during hyd

integrating induced seismicity with rock mechanics a conceptual model for the 2011 preese hall fracture development and induced seismicity by integrating multiple datasets with relevant theory covering fluid injection and fracturing a conceptual model has been developed for the fracture development and induced seismicity associated with the fracking in 2011 of the carboniferous bowland shale in the preese hall 1 well in lancashire nw england key features of this model include the steep fault that has been recognized adjoining this well which slipped in the largest induced earthquakes and the presence of a weak subhorizontal flat within the depth range of the fluid injection which was opened by this injection taking account of the geometry of the fault and the orientation of the local stress field the model predicts that the induced seismicity was concentrated approximately 700 m sse of the preese hall 1 wellhead in roughly the place where microseismic investigations have established that this activity was located a further key observation critical to explaining the subsequent sequence of events is the recognition that the fluid injection during stage 2 of this fracking took place at a high net pressure approximately 17 mpa larger than necessary as a result the fluid injection opened a patch of the flat making a hydraulic connection with the fracture network already created during stage 1 continued fluid injection thus enlarged the latter fracture network which ultimately extended southwards far enough to intersect the steep part of the fault and induce the largest earthquake of the sequence there subsequent fluid injection during fracking stages 3 and 4 added to the complexity of this interconnected fracture network in part due to the injection during stage 4 being again under high net pressure this model can account for many aspects of the preese hall record notably how it was possible for the induced fracture network to intersect the seismogenic fault so far from the injection point the interconnection between fractures meant that the stage 1 fracture continued to grow during stage 2 rather than two separate smaller fractures isolated from each other being created calculations indicate that despite the high net pressure the project only went wrong by a narrow margin had the net pressure been approximately 15 mpa rather than approximately 17 mpa the induced seismicity would not have occurred the model also predicts that some of the smaller induced earthquakes had tensile or hybrid focal mechanisms this would have been testable had any seismographs been deployed locally to monitor the activity the analysis emphasizes the undesirability of injecting fracking fluid under high net pressure in this region where flat patches of fault and or subhorizontal structural discontinuities are present recommendations follow for future best practice or regulatory guidelines

early stage hypogene karstification in a mountain hydrologic system a coupled thermohydrochemical model incorporating buoyant convection 1 the early stage of hypogene karstification is investigated using a coupled thermohydrochemical model of a mountain hydrologic system in which water enters along a water table and descends to significant depth 1 km before ascending through a central high permeability fracture the model incorporates reactive alteration driven by dissolution precipitation of limestone in a carbonic acid system due to both temperature and pressure dependent solubility and kinetics simulations were carried out for homogeneous and heterogeneous initial fracture aperture fields using the fehm finite element heat and mass transfer code initially retrograde solubility is the dominant mechanism of fracture aperture growth as the fracture transmissivity increases a critical rayleigh number value is exceeded at some stage buoyant convection is then initiated and controls the evolution of the system thereafter for an initially homogeneous fracture aperture field deep well organized buoyant convection rolls form for initially heterogeneous aperture fields preferential flow suppresses large buoyant convection rolls although a large number of smaller rolls form even after the onset of buoyant convection dissolution in the fracture is sustained along upward flow paths by retrograde solubility and by additional mixing corrosion effects closer to the surface aperture growth patterns in the fracture are very different from those observed in simulations of epigenic karst systems and retain imprints of both buoyant convection and preferential flow both retrograde solubility and buoyant convection contribute to these differences the paper demonstrates the potential value of coupled models as tools for understanding the evolution and behavior of hypogene karst systems

methane contamination of drinking water caused by hydraulic fracturing remains unproven shale gas extraction involves the drilling of organic rich low permeability shale and then stimulation of hydraulic fractures that allows gas to be produced methane in aquifers located above the shale strata for instance in pennsylvania united states has been attributed by some to be the result of contamination caused by the hydraulic fracturing process the work by osborn et al 1 described geochemical data from 68 drinking water wells in northeastern pennsylvania and upstate new york and evaluated whether the aquifers that the water wells penetrated were contaminated with thermogenic methane sourced from the underlying marcellus and utica shale formations the work by osborn et al 1 concluded that contamination had occurred and that the contamination accompanied gas well drilling and hydraulic fracturing the inference from the text and title of the paper is clear hydraulic fracturing had a role however the evidential basis for implicating this specific process is not sound and needs to be closely scrutinized

numerical analysis of fracture propagation during hydraulic fracturing operations in shale gas systems abstract we perform numerical studies on vertical fracture propagation induced by tensile hydraulic fracturing for shale gas reservoirs from the numerical simulation we find that tensile fracturing occurs discontinuously in time which generates saw toothed responses of pressure the fracture aperture and displacement and that fracture propagation is sensitive to factors such as initial condition of saturation a type of the injection fluid heterogeneity tensile strength elastic moduli and permeability models gas injection induces faster fracturing in shale gas reservoirs than water injection for the same mass injection because of high mobility of gas however water injection to highly water saturated formations can contribute to fast pressurization and high mobility of water resulting in large fracturing for moderate initial water saturation complex physical responses within the fracture result from strong nonlinear permeability and multiphase flow with gravity pressure diffusion and pressurization within the fracture are also affected by permeability high intrinsic and high relative permeabilities result in fast fluid movement of injected fluid followed by fast fracturing high young s modulus and high poisson s ratio do not seem favorable to fracture propagation although they are not significantly sensitive for heterogeneity a geological layer of high strength between near surface and above the shale gas reservoirs can prevent vertical fracture propagation changing the direction of fracturing horizontally

along strike variations in the composition of sandstones derived from the uplifting western greater caucasus causes and implications for reservoir quality prediction in the eastern black sea oligo miocene outcrops along the southern margin of the western greater caucasus preserve a record of sediments shed from the range into the northern and central parts of the eastern black sea sandstones in the russian western caucasus are significantly more quartz rich than those located farther se in western georgia the latter contain appreciably more mudstone and volcanic rock fragments oligo miocene turbidite systems derived from the russian western caucasus in the tuapse trough and central eastern black sea may therefore form better quality reservoirs at shallow to moderate depths than sediments derived from west georgian volcaniclastic sources in the easternmost part of the basin palynomorph analysis indicates sediment derivation predominantly from jurassic and cretaceous strata in the russian western caucasus and from eocene strata and an increasing proportion of cretaceous strata upsection in western georgia an eocene volcaniclastic source is proposed for the increased rock fragment component in west georgian sandstones eocene volcaniclastic rocks are no longer exposed in the greater caucasus but similar rocks form the inverted fill of the adjara trialet basin farther south in the lesser caucasus the former presence of a northern strand of this basin in the west georgian caucasus is supported by earlier thermochronological work

hydraulic fracturing in unconventional gas reservoirs risks in the geological system part 2 hydraulic fracturing is a method used for the production of unconventional gas resources huge amounts of so called fracturing fluid 10 000 20 000 m3 are injected into a gas reservoir to create fractures in solid rock formations upon which mobilised methane fills the pore space and the fracturing fluid is withdrawn hydraulic fracturing may pose a threat to groundwater resources if fracturing fluid or brine can migrate through fault zones into shallow aquifers diffuse methane emissions from the gas reservoir may not only contaminate shallow groundwater aquifers but also escape into the atmosphere where methane acts as a greenhouse gas the working group risks in the geological system as part of exxonmobil s hydrofracking dialogue and information dissemination processes was tasked with the assessment of possible hazards posed by migrating fluids as a result of hydraulic fracturing activities in this work several flow paths for fracturing fluid brine and methane are identified and scenarios are set up to qualitatively estimate under what circumstances these fluids would leak into shallower layers the parametrisation for potential hydraulic fracturing sites in north rhine westphalia and lower saxony both in germany is derived from literature using upper and lower bounds of hydraulic parameters the results show that a significant fluid migration is only possible if a combination of several conservative assumptions is met by a scenario

age constraints on intra formational unconformities in upper jurassic lower cretaceous carbonates in northeast turkey geodynamic and hydrocarbon implications abstract upper jurassic lowermost cretaceous carbonate build ups are imaged on seismic data in the black sea they form important untested hydrocarbon reservoirs that are the focus of active exploration outcrop analogues to these build ups around the black sea contain a series of subaerial exposure surfaces the hiatuses associated with a number of these subaerial exposure surfaces have been dated in a well exposed callovian or upper oxfordian to barremian shallow water inner platform carbonate succession the berdiga formation in the eastern pontides using strontium isotope stratigraphy and foraminiferal biostratigraphy they span the latest kimmeridgian to tithonian or berriasian and the hauterivian to barremian less well constrained but broadly contemporaneous stratigraphic gaps in multiple successions around the black sea provide additional insights and point to a regional driving mechanism the timing of hiatus formation does not correspond to periods of eustatic lowstand it does coincide however with late tithonian to berriasian and hauterivian to early aptian episodes of rifting in the greater caucasus basin located farther to the north thus it is possible that subaerial exposure was caused by rift flank uplift during periods of regional extension uplift due to slab break off is discounted as a control because it post dates rather than pre dates locally developed kimmeridgian magmatism rift flank uplift is likely to have also affected carbonate build ups on the intervening rift shoulders of the eastern black sea the shatskiy ridge and the mid black sea high at outcrop subaerial exposure is often associated with karstification and secondary porosity development similar processes may have occurred in the offshore helping to enhance the reservoir quality of these exploration targets

numerical assessment of potential impacts of hydraulically fractured bowland shale on overlying aquifers natural gas extracted from hydraulically fractured shale formations potentially has a big impact on the global energy landscape however there are concerns of potential environmental impacts of hydraulic fracturing of the shale formations particularly those related to water quality to evaluate the potential impact of hydraulically fractured shale on overlying aquifers we conduct realizations of numerical modeling simulations to assess fluid flow and chloride transport from a synthetic bowland shale over a period of 11 000 years the synthetic fractured shale was represented by a three dimensional discrete fracture model that was developed by using the data from a bowland shale gas exploration in lancashire uk chloride mass exchange between fractures and the rock matrix was fully accounted for in the model the assessment was carried out to investigate fluid and chloride mass fluxes before during and after hydraulic fracturing of the bowland shale impacts of the upward fracture height and aperture as well as hydraulic conductivity of the multilayered bedrock system are also included this assessment this modeling revealed that the hydraulically fractured bowland shale is unlikely to pose a risk to its overlying groundwater quality when the induced fracture aperture is 200 m with the fracture aperture 1000 m the upward chloride flux becomes very sensitive to the upward fracture height growth and hydraulic conductivity of the multilayered bedrock system in the extremely unlikely event of the upward fracture growth directly connecting the shale formation to the overlying sherwood sandstone aquifer with the fracture aperture 1000 m the upward chloride mass flux could potentially pose risks to the overlying aquifer in 100 years the model study also revealed that the upward mass flux is significantly intercepted by the horizontal mass flux within a high permeable layer between the bowland shale and its overlying aquifers reducing further upward flux toward the overlying aquifers

fractured shale gas systems the first commercial united states natural gas production 1821 came from an organic rich devonian shale in the appalachian basin understanding the geological and geochemical nature of organic shale formations and improving their gas producibility have subsequently been the challenge of millions of dollars worth of research since the 1970s shale gas systems essentially are continuous type biogenic predominant thermogenic or combined biogenic thermogenic gas accumulations characterized by widespread gas saturation subtle trapping mechanisms seals of variable lithology and relatively short hydrocarbon migration distances shale gas may be stored as free gas in natural fractures and intergranular porosity as gas sorbed onto kerogen and clay particle surfaces or as gas dissolved in kerogen and bitumen five united states shale formations that presently produce gas commercially exhibit an unexpectedly wide variation in the values of five key parameters thermal maturity expressed as vitrinite reflectance sorbed gas fraction reservoir thickness total organic carbon content and volume of gas in place the degree of natural fracture development in an otherwise low matrix permeability shale reservoir is a controlling factor in gas producibility to date unstimulated commercial production has been achievable in only a small proportion of shale wells those that intercept natural fracture networks in most other cases a successful shale gas well requires hydraulic stimulation together the devonian antrim shale of the michigan basin and devonian ohio shale of the appalachian basin accounted for about 84 of the total 380 bcf of shale gas produced in 1999 however annual gas production is steadily increasing from three other major organic shale formations that subsequently have been explored and developed the devonian new albany shale in the illinois basin the mississippian barnett shale in the fort worth basin and the cretaceous lewis shale in the san juan basin in the basins for which estimates have been made shale gas resources are substantial with in place volumes of 497 783 tcf the estimated technically recoverable resource exclusive of the lewis shale ranges from 31 to 76 tcf in both cases the ohio shale accounts for the largest share

geochemistry of wellbore integrity in co2 sequestration portland cement steel brine co2 interactions geochemistry and wellbore integrity in co2 sequestration effective geologic sequestration of co2 requires long term storage with very low leak rates injection wells are an obvious leakage pathway for co2 because they perforate the confining caprock in addition sequestration sites are likely to use monitoring wells to assess performance and in the case of depleted oil and gas fields may contain 10s to 1000s of older operating and abandoned wells all wells may have leakage pathways due to faulty construction or other defects however it is the subject of this chapter to consider whether geochemical reactions induced by co2 could result in damage to wells and the development of leaks this concern is based on the thermodynamic incompatibility of co2 saturated fluids with the portland cement and steel used to prevent fluid migration to the surface portland cement is an alkaline substance with ph 12 5 and is not in equilibrium with co2 bearing fluids ph 6 low carbon steel used as well casing is subject to aggressive corrosion by carbonic acid as a result well integrity has been a central issue in risk analysis of sequestration sites gasda et al 2004 ipcc 2005 viswanathan et al 2008 nordbotten et al 2009 at the outset it is important to bear in mind that geochemical reactions alone do not yield insight into wellbore integrity which is governed primarily by the effective permeability of the portland cement seal and the mechanical integrity of the system thus the significance of chemical reactions must be considered with respect to their impact to changes in permeability or in strength there is an unfortunate tendency in the literature to not distinguish between reaction and impact often co2 reactions are described as degradation of cement or corrosion of cement without adequately defining what these terms

comment on hydraulic fracturing in faulted sedimentary basins numerical simulation of potential contamination of shallow aquifers over long time scales by claire gassiat et al

imbibition of hydraulic fracturing fluids into partially saturated shale recent studies suggest that imbibition of hydraulic fracturing fluids into partially saturated shale is an important mechanism that restricts their migration thus reducing the risk of groundwater contamination we present computations of imbibition based on an exact semianalytical solution for spontaneous imbibition these computations lead to quantitative estimates of an imbibition rate parameter a with units of lt 1 2 for shale which is related to porous medium and fluid properties and the initial water saturation our calculations suggest that significant fractions of injected fluid volumes 15 95 can be imbibed in shale gas systems whereas imbibition volumes in shale oil systems is much lower 3 27 we present a nondimensionalization of a which provides insights into the critical factors controlling imbibition and facilitates the estimation of a based on readily measured porous medium and fluid properties for a given set of medium and fluid properties a varies by less than factors of 1 8 gas nonwetting phase and 3 4 oil nonwetting phase over the range of initial water saturations reported for the marcellus shale 0 05 0 6 however for higher initial water saturations a decreases significantly the intrinsic permeability of the shale and the viscosity of the fluids are the most important properties controlling the imbibition rate

hydraulic fractures how far can they go the maximum reported height of an upward propagating hydraulic fracture from several thousand fracturing operations in the marcellus barnett woodford eagle ford and niobrara shale usa is 588 m of the 1170 natural hydraulic fracture pipes imaged with three dimensional seismic data offshore of west africa and mid norway it is 1106 m based on these empirical data the probability of a stimulated and natural hydraulic fracture extending vertically 350 m is 1 and 33 respectively constraining the probability of stimulating unusually tall hydraulic fractures in sedimentary rocks is extremely important as an evidence base for decisions on the safe vertical separation between the depth of stimulation and rock strata not intended for penetration