diagenetic history of tight sandstones and gas entrapment in the yulin gas field in the central area of the ordos basin china abstract the ordos basin is a large cratonic basin with an area of 250 000 km2 in central china upper paleozoic coals and shales serve as gas source rocks with peak generation and migration at the end of the early cretaceous recent exploration has verified the huge gas potential in the basin centered gas accumulation system bcgas however the mechanism for the gas accumulation is controversial with an integrated approach of thin section petrography ultra violet fluorescence microscopy fluid inclusion microthermometry raman microspectrometry scanning electron microscopy and x ray diffractometry we identified diagenetic trapping and evaluated the diagenetic history of sandstone reservoirs in the yulin gas field in the central area where structural stratigraphic and or sedimentary lithologic traps have not been found it was revealed that three phases of diagenesis and hydrocarbon charging occurred respectively in the late triassic late jurassic and at the end of the early cretaceous in the first two phases acidic water entered the reservoir and caused dissolution and cementation resulting in porosity increase however further subsidence and diagenesis including compaction and cementation markedly reduced the pore space at the end of the early cretaceous the bulk of the gas migrated into the tight reservoirs and the bcgas trap was formed in the updip portion of this system cementation continued to occur due to low gas saturation and has provided effective seals to retain gas for a longer period of time than water block in the bcgas the mechanism for the gas entrapment was changed from water block by capillary pressure in the bcgas to diagenetic sealing the diagenetic seals in the updip portion of the sand body were formed after gas charging which indicates that there is a large hydrocarbon exploration potential at the basin centered area

evidence for reduced quartz cementation rates in oil filled sandstones when quartz rich sands are buried and heated pore space is gradually filled by precipitation of quartz cement from aqueous formation fluids here we examine whether the presence of oil in the pore space can retard or halt this loss of porosity by slowing or stopping quartz cementation the effect of oil fill on quartz cementation is examined by using the distribution of quartz cement in the brae formation deep water sandstone reservoir of the miller oil field north sea petrographic data demonstrate that sandstones from the oil zone have much less quartz cement and more porosity than sandstones from the water zone sandstones in both oil and water zones are compositionally and texturally identical and have been affected by a similar burial history kinetic modeling of the cementation process suggests that progressive oil charging has slowed quartz cement growth rates by at least two orders of magnitude halting it completely in the most extreme cases our data demonstrate that early oil charging in the crestal part of an anticline can preserve porosity in deeply buried sandstones this knowledge is especially relevant to porosity prediction for petroleum exploration in deeply buried sandstones

sandstone diagenesis and reservoir quality prediction models myths and reality models and concepts of sandstone diagenesis developed over the past two decades are currently employed with variable success to predict reservoir quality in hydrocarbon exploration not all of these are equally supported by quantitative data observations and rigorous hypothesis testing simple plots of sandstone porosity versus extrinsic parameters such as current subsurface depth or temperature are commonly extrapolated but rarely yield accurate predictions for lithified sandstones calibrated numerical models that simulate compaction and quartz cementation when linked to basin models have proven successful in predicting sandstone porosity and permeability where sufficient analog information regarding sandstone texture composition and quartz surface area is available analysis of global regional and local data sets indicates the following regarding contemporary diagenetic models used to predict reservoir quality 1 the effectiveness of grain coatings on quartz grains e g chlorite microquartz as an inhibitor of quartz cementation is supported by abundant empirical data and recent experimental results 2 vertical effective stress although a fundamental factor in compaction cannot be used alone as an accurate predictor of porosity for lithified sandstones 3 secondary porosity related to dissolution of framework grains and or cements is most commonly volumetrically minor 2 exceptions are rare and not easily predicted with current models 4 the hypothesis and widely held belief that hydrocarbon pore fluids suppress porosity loss due to quartz cementation is not supported by detailed data and does not represent a viable predictive model 5 heat flow perturbations associated with allochthonous salt bodies can result in suppressed thermal exposure thereby slowing the rate of quartz cementation in some subsalt sands

influence of multistage oil emplacement on carbonate cementation in the eocene shahejie formation dongying sag bohai bay basin china abstract the influence of multi stage oil emplacement on carbonate cementation was investigated on the basis of determining the sequence of oil emplacement and carbonate cementation in the clastic reservoirs of the upper part of the fourth member of the eocene shahejie formation es4s in the yanxie 229 area dongying sag the sequence of multistage oil emplacement and carbonate cementation was determined by projecting the homogenization temperatures ths of two phase aqueous inclusions on a burial and thermal history plot the ratio of the number of quartz grains with yellow fluorescent oil inclusions therein to the total number of quartz grains ygoi and the ratio of the number of quartz grains with blue fluorescent oil inclusions therein to the total number of quartz grains bgoi were calculated to analyze the paleo oil saturation of each stage of oil emplacement the ygoi and bgoi values reflect the relative level of the paleo oil saturation of the first stage yellow fluorescent fsyf oil and the second stage blue fluorescent ssbf oil respectively a large number of primary pores were preserved in the oil layers whereas only a small number of dissolution pores and micropores were developed in the oil bearing water layers and dry layers calcite dolomite ferrocalcite and ankerite cementation and two stage oil emplacement occurred in the es4s reservoirs the fsyf oil emplacement occurred earlier than the ankerite cementation and ferrocalcite cementation but later than the calcite cementation and dolomite cementation the ssbf oil emplacement occurred later than all phases of carbonate cementation the dolomite cementation was not influenced by the fsyf oil emplacement because it occurred earlier than the fsyf oil emplacement the ankerite cementation was dominantly inhibited by the fsyf oil emplacement in the oil layers and the degree of inhibition increased with the increase in paleo oil saturation of the fsyf oil the ssbf oil emplacement further increased the paleo oil saturation in the oil layers which enhanced the inhibition of the ankerite cementation and even stopped it the ankerite cementation in the dry layers and oil bearing water layers was slowed down or stopped due to the lack of pores and the low transportation rate of external material which was caused by the intense ankerite cementation prior to the ssbf oil emplacement

patterns of water 87sr 86sr variations in oil gas and water saturated rocks implications for fluid communication processes distances and timescales abstract this study reviews 87sr 86sr depth profiles of formation waters sampled by sr residual salt analysis sr rsa from 100 oil gas wells and research sites including reservoirs with clastic and carbonate host rocks and with gas oil and water as the continuous fluid phase globally the water data form a smooth trend between low seawater like 87sr 86sr ratios 0 706 at shallow depths and high 0 724 ratios in deeply buried rocks where water rock interaction dominates we test the hypothesis that 87sr 86sr depth profiles in individual wells could be influenced by diffusional mixing processes by developing 1d diffusion mixing equations to simulate compositional patterns through time and comparing them with observed profiles different combinations of boundary and initial conditions generate various patterns characteristic of diffusion including non steady state curves relating to incomplete mixing and steady state patterns such as vertical or inclined straight lines where initial heterogeneities have fully mixed the dataset yielded 193 occurrences of these patterns steady state patterns are more common and longer in water zones while non steady state patterns are more common and longer in oil and gas zones the detection of diffusional mixing patterns in hydrocarbon saturated rocks suggests that diffusion is active although on average a factor of 13 18 slower than in comparable water saturated rocks pattern generation and equilibration times were modelled for each non steady state pattern and compared with the time since reservoir filling with oil gas revealing that 90 of them could have been generated since filling but 60 of them would already have mixed to steady state had the initial compositional heterogeneities arisen during or before reservoir filling this is critical evidence that at least some of the initial heterogeneities must have arisen and subsequently partially mixed after filling these patterns tend to be short the evidence for post fill water rock interaction and diffusive transport has important implications for porosity permeability prediction indicating that key diagenetic processes like quartz cementation may be inhibited by hydrocarbon filling but not stopped altogether compositional differences of water within oil gas zones reveal the folly of using one aquifer water sample as the basis for interpreting water saturations from well resistivity logs for in place resource estimation sr rsa studies may thus be useful in designing water sampling strategies

hydrocarbon filling and leakage history of a deep geopressured sandstone fulmar formation united kingdom north sea diagenetic minerals in a water filled borehole from the jurassic fulmar formation united kingdom central north sea record two phases of hydrocarbon filling and emptying initial oil charge was during the late cretaceous at shallow burial depths of about 1 5 km 0 9 mi as we consider that hydrocarbon has preserved porosity during burial this has implications for the understanding of the porosity evolution of the fulmar formation which in other locations is an important hydrocarbon reservoir the early oil charge as recorded by illite k ar ages progressively filled the structure from 84 to 59 ma and possibly precipitated bitumen because of biodegradation the first oil predated many of the burial diagenetic reactions within the sandstone after leak off at ca 60 ma diagenetic reactions continued in an open geochemical system with possible import of co2 products of these reactions include ankerite and quartz overgrowth cements hydrocarbon staining postdates these phases and provides evidence of a hydrocarbon charge probably gas condensate the second hydrocarbon charge also leaked off and the sandstone is now water bearing previous work on the fulmar formation has incorrectly placed all the diagenetic reactions as predating the first arrival of hydrocarbon the present day pore fluids are high salinity high 18o fluids derived from the underlying permian zechstein evaporates these fluids entered the reservoir during a phase of overpressure release that caused fracturing of the framework quartz grains possibly coincident with the second phase of hydrocarbon leak off at 2 5 ma mark wilkinson studied sandstone hosted calcite concretions for his ph d and has subsequently tried to take a more holistic view of the diagenesis of sedimentary basins his career has been funded by a variety of oil companies although he is currently involved in geological disposal of some of the co2 that he was partly responsible for producing stuart haszeldine is a professor at edinburgh university he received his ph d on clastic and coal sedimentology in 1981 from the university of strathclyde after an attempted reeducation in the oil industry he has collaborated with many companies to research on hydrocarbon reservoir quality radioactive waste disposal and coal resources he currently heads the united kingdom s largest group investigating carbon dioxide sequestration tony fallick was educated at the university of glasgow scotland in physics b sc and chemistry ph d he did research at mcmaster university ontario canada and cambridge england before moving in 1980 to the scottish universities research and reactor center where he is currently the director

oil charge preserves exceptional porosity in deeply buried overpressured sandstones central north sea uk abstract exceptionally high porosity sandstones are reported from oil provinces worldwide yet the mechanism of porosity preservation remains controversial we present strong evidence that the exceptional porosities in the jurassic fulmar formation within the north sea are the result of early oil charging preventing cementation and chemical compaction in sands with relatively low detrital clay contents although overpressure and grain coatings do have some effect the most dramatic evidence that reservoir quality is related to early oil charge is the spatial distribution of the porosity the maximum porosity of the fulmar formation is systematically highest immediately below the top seal and decreases below this despite uniform sedimentology hence porosity is preferentially preserved where oil first accumulated in these unusually homogeneous overpressured reservoir sandstones at the top oil charge prevents or significantly retards chemical compaction and cementation of a reservoir preserving porosity there is independent evidence for early oil charging of reservoirs within the central graben from fluid inclusion studies and k ar age dates of authigenic illite micro quartz grain coatings which have been proposed to preserve porosity during burial are associated with only 5 extra porosity in sands that exceed the worldwide average sandstone porosity by almost 20

pore network analysis of brae formation sandstone north sea abstract in this work we apply digital rock physics drp to characterize the pore networks of the brae formation sandstones from two different wells in the miller field area north sea uk using x ray micro ct scans we calculate the porosity and permeability and generate pore network models to assess pore shape characteristics the porous samples are marked by macroporosities ranging from 4 9 to 15 2 with the effective porosities varying from 0 to 14 8 the samples also contained some microporosity hosted in secondary and accessory mineral phases varying between 2 6 and 10 7 pore network model results for total porosity indicate that the samples have median pore and throat radii ranging from 5 5 m to 16 8 m and 6 4 m 12 9 m respectively the throat length of all samples has a median value ranging between 36 3 m and 82 4 m the ratio between effective porosity and total porosity varies with total porosity following the exponential relation 0 98 e 0 032 0 028 pore network connectivity is established at a porosity of 3 and full communication is achieved at porosities exceeding 10 permeability was found to vary with total porosity with an exponent of 3 67 based on these observations and the results from our models the connectivity of the pore network has important implications for predicting reservoir performance during large scale subsurface projects such as hydrocarbon production and co2 storage

chlorite meniscus cement implications for diagenetic mineral growth after oil emplacement the possible influence on diagenesis of oil migration into reservoir sandstones is important for understanding their development although many studies have addressed the question of continued growth of diagenetic minerals after oil emplacement there is little clear evidence of the timing of mineral growth relative to oil emplacement nor of the possible mechanisms of continued mineral growth this study presents an example of continued cementation by pore lining chlorite during and after the migration of oil into a palaeocene turbidite sandstone reservoir near the faroe islands chlorite developed in two different textures one texture occurs on framework grain surfaces adjacent to open pore space in contact with oil the other texture occurs close to framework grain contacts where contact with oil appears to have been prevented by residual pore water menisci the meniscus crystals are larger than those from open pore implying that diagenetic clay mineral growth has continued after oil emplacement

late palaeozoic hydrocarbon migration through the clair field west of shetland uk atlantic margin geochemical analysis of bitumen and hydrocarbon bearing fluid inclusions from the devonian carboniferous clair field indicates that the reservoirs contain a mixture of oils from different marine and lacustrine sources reconstruction of the clair field oil charge history using fluid inclusion petrography show that oil charging occurred at times of k feldspar quartz and calcite cementation temperature composition time data yielded from the integration of fluid inclusion microthermometry with high resolution ar ar dating date hydrocarbon bearing k feldspar overgrowths at 247 3 3 ma these data show that in order for oil to be trapped within primary fluid inclusions in k feldspar overgrowths hydrocarbon migration throughout the uk atlantic margin must have been taking place during the late palaeozoic and as such current industry oil play models based solely on oil charging from jurassic cretaceous marine sources are clearly incomplete and need revision apatite fission track analysis and vitrinite reflectance data were used to reconstruct thermal burial histories and assess potential oil generation from middle devonian lacustrine source rocks thermal history data from wells along the rona ridge adjacent to the clair field show that the palaeozoic section was heated to greater than 100 c at some time between 270 and 230 ma confirming that devonian source rocks were mature and expelling oil during the late palaeozoic at the time that authigenic k feldspar overgrowths were growing in the clair field

genetic mechanism of high quality reservoirs in permian tight fan delta conglomerates at the northwestern margin of the junggar basin northwestern china fan delta conglomerate reservoirs in the permian jiamuhe formation in the zhongguai area at the northwestern margin of the junggar basin northwestern china are reservoirs for large accumulations of natural tight gas the tight conglomerates and sandstones are mainly litharenites with a large amount of texturally and compositionally immature volcanic clastic materials core porosities demonstrate the development of anomalously high porosities at depths of 3200 4200 m 10 500 13 800 ft and 4500 4900 m 14 800 16 100 ft the permian reservoirs experienced initial rapid subsidence uplift and further subsidence and diagenetic reactions occurred in these reservoirs involving compaction precipitation of chlorite clays calcites zeolites iron oxides kaolinite and quartz cements and dissolution of unstable minerals including analcite laumontite feldspars and rock fragments low porosity reservoirs with extensive compaction and or cementation of calcite and heulandite ca consist of only few visible secondary pores formed by dissolution of feldspars and rock fragments reservoirs with anomalously high porosity however experienced relatively weak compaction and contain significant amounts of secondary pores formed by dissolution of mainly laumontites some feldspars and rock fragments comprehensive studies of sedimentary features and diagenesis of the reservoirs indicate that these anomalously high porosities originate from chronological coupling of four important geological processes 1 sedimentary facies and detrital compositions controlled distribution of various zeolites in reservoirs with abundant laumonites developed in reservoirs in the fan delta front subfacies 2 early precipitation of the laumontites inhibited compaction during deep burial however they provided unstable minerals for secondary porosity development 3 the permian reservoirs experienced subaerial exposure erosion during the uplift stage and meteoric freshwater leached laumontite cements and aluminosilicate grains to form secondary pores in reservoirs beneath the unconformity 4 hydrocarbon emplacement at relative shallow depth during a second subsidence period preserved the secondary pores in reservoirs by retarding late carbonate cementation

petroleum emplacement inhibits quartz cementation and feldspar dissolution in a deeply buried sandstone abstract whether the emplacement of petroleum in sandstone reservoirs can preserve porosity during burial remains controversial in the kessog field uk central north sea average porosities of the crestal sections of the fluvial deltaic pentland formation reservoir can exceed 25 despite burial to 4 km or more the predicted porosity for the reservoir at this depth is only around 14 based on regional data oil saturation data thin section point counts grain size and sorting measurements reservoir pressure and sem images were combined to analyze the cause of the high reservoir porosity petroleum emplacement preventing cementation is the most likely mechanism for porosity preservation facies variation is not responsible as the high porosity sandstones from the crestal well are in terms of average grain size fine grained and sorting coefficient moderately well sorted nearly the same as the lower porosity sandstones from the flanks of the field average porosity 13 15 other potential porosity preservation mechanisms such as overpressure grain coats and feldspar dissolution can be discounted the sandstones with high oil saturations are characterized by 1 most porosity being primary as opposed to secondary 2 there being 2 5 less quartz cement than in the water saturated sandstones 3 there being 2 3 more k feldspar and 2 6 less kaolin than the water saturated counterparts this study demonstrates that petroleum emplacement can effectively inhibit quartz cementation and k feldspar transformation to kaolin in sandstone reservoirs

quantification of quartz cements using combined sem cl and image analysis quartz cement content is often difficult to quantify using conventional petrography developments in equipment and technique reported here show how excellent high contrast images of quartz cements can be produced using combined scanning electron microscopy and cathodoluminescence sem cl in most cases quartz cement can be differentiated readily from detrital quartz image analysis allows the percentage of authigenic quartz to be quantified advantages of this method are 1 it can be readily automated 2 backscatter electron bse and cl images can be compared directly and 3 images can be improved through acquiring and integrating multiple images comparison of results from conventional optical petrography with those from sem cl suggests that the percentages of quartz cement determined by conventional methods are overestimated where quartz cement is present in high proportions and are underestimated where quartz cement is less abundant by adopting a statistically rigorous approach to image collection the abundance of quartz cement can be determined by sem cl with a known accuracy

hydrocarbon filling history from diagenetic evidence brent group uk north sea abstract reconstruction of the hydrocarbon filling history of a reservoir is important for prediction of field scale porosity and permeability and for the calibration of basin models published histories of the brent group show only a single phase of hydrocarbon filling which occurred after the diagenetic reactions had run their course in contrast diagenetic minerals preserve evidence of multiple episodes of hydrocarbon charging in the cormorant field uk north sea authigenic blocky kaolin shows a systematic change in oxygen isotopic composition with depth and the trend displays a conspicuous shift at the mid ness shale a regionally extensive permeability barrier the isotopic data are most readily explained if kaolin recrystallisation from earlier vermiform kaolin was synchronous with hydrocarbon charging with two hydrocarbon pools one above and one below the mid ness shale the filling history begins with a relatively early slow filling phase 45 70 c 80 50 ma that formed an oil column with the oil water contact substantially below the present day position this first hydrocarbon subsequently leaked off allowing renewed diagenetic activity including the formation of quartz overgrowths with aqueous inclusions emplacement of the present day hydrocarbon charge was the last event in the history of the reservoir 90 100 c 10 0 ma

pore water evolution in oilfield sandstones constraints from oxygen isotope microanalyses of quartz cement abstract oxygen isotope microanalyses of authigenic quartz in combination with temperatures of quartz precipitation constrained by fluid inclusion microthermometry and burial history modelling are employed to trace the origin and evolution of pore waters in three distinct reservoirs of the brae formation in the miller and kingfisher fields north sea oxygen isotope ratios of quartz cements were measured in situ in nine sandstone thin sections with a cameca ims 4f ion microprobe in conjunction with quartz cement paragenesis in the reservoirs constrained from textural and cathodoluminescence cl microscopy studies pore water evolution was reconstructed from the time of deposition of the sandstones in the upper jurassic until the present cl photomicrographs of quartz overgrowths in the brae formation sandstones show three cement zones a b and c which can be related to different oxygen isotope compositions 1 the earliest and thinnest zone a homogeneous cl pattern with probable 18 o values between 23 and 26 direct measurements were not possible precipitated in the sandstones at temperatures 18 o values between 15 and 18 precipitated in the sandstones most likely between 70 and 90 c 3 the third zone c homogeneous cl pattern and directly measured 18 o values between 16 and 22 precipitated in the sandstones most likely at temperatures 90 c calculated oxygen isotope compositions of pore waters show that zone a quartz cements and enclosing concretionary calcite precipitated from a meteoric type fluid 7 during shallow burial 18 o 7 to a more 18 o enriched fluid 18 o 4 as burial continued to 3 0 km data from zone c quartz cements are consistent with further fluid evolution from 18 o 4 to basinal type fluids with 18 o similar to the present day formation water oxygen isotope composition 0 6 at 4 0 km burial a similar pore water evolution can be derived for all three reservoirs studied indicating that hydrogeologic evolution was similar across sandstones of the whole brae formation the quartz cement zones observed in the brae formation sandstones and the pore water history derived for the area studied is analogous to published petrographic and pore water evolution data from the nearby brent group reservoirs and from reservoirs located in the haltenbanken area on the atlantic margin offshore norway considering quartz cement is a major porosity occluding phase in many reservoir sandstones and because pore waters both dissolve quartz and carry the dissolved silica to cementation sites the data presented are valuable for improving the understanding and prediction of reservoir quality development in sandstones globally

linked debrites in sand rich turbidite systems origin and significance abstract the outer parts of a number of small late jurassic sandy deep water fans in the northern north sea are dominated by the stacked deposits of co genetic sandy and muddy gravity flows sharp based structureless and dewatered sandstone beds are directly overlain by mudclast breccias that are often rich in terrestrial plant fragments and capped by thin laminated sandstones pseudonodular siltstones and mudstones the contacts between the clast rich breccias and the underlying sandstones are typically highly irregular with evidence for liquefaction and upward sand injection the breccias contain fragments up to metre scale of exotic lithologies surrounded by a matrix that is extremely heterogeneous and strewn with multiphase and variably sheared sand injections and scattered coarse and very coarse sand grains often coarser than in the immediately underlying sand bed markov chain analysis establishes that the breccias consistently overlie sandstones and the character of the breccias and their external contacts rule out a post depositional origin via in situ liquefaction intrastratal flowage or bed amalgamation and disruption the breccias are interpreted as debrites that rode on a water rich sand bed just deposited by a co genetic concentrated gravity current as such they are referred to as linked debrites to distinguish them from debrites emplaced in the absence of a precursor sand bed the distinction is important because these linked debris flows can achieve significant mobility through entrainment of both water and sediment from beneath and they ride on a low friction carpet of liquefied sand this explains the paradox presented by fan fringes in which there are common debrites when conventional thinking might predict that deposits of low concentration gravity currents should be more important here in fact evidence for transport by low concentration turbidity currents is rare in these systems several possible mechanisms might explain the formation of linked flows but the ultimate source of both sandy and clast rich flow components must be in shallower water on the basin margin the debrites are not triggered from distal slopes flow partitioning may have occurred by upslope erosion and retardation of the mudclast charged portion of an erosional sandy density current partial flow transformation of a precursor debris flow and or hydraulic segregation and reconcentration of the flaky clasts and carbonaceous matter during transport linked debrites are not restricted to small sand rich fans and similar mechanisms may be responsible for the long runout of debris flows in other systems the recognition of a distinct class of linked debrites is of wider importance for facies prediction reservoir heterogeneity and even carbon fluxes and sequestration on continental margins

vertical effective stress as a control on quartz cementation in sandstones abstract temperature controlled precipitation kinetics has become the overwhelmingly dominant hypothesis for the control of quartz cementation in sandstones here we integrate quantitative petrographic data high spatial resolution oxygen isotope analyses of quartz cement basin modelling and a kinetic model for quartz precipitation to suggest that the supply of silica from stress sensitive intergranular pressure dissolution at grain contacts is in fact a key control on quartz cementation in sandstones we present data from highly overpressured sandstones in which despite the current burial temperature of 190 c quartz cement occurs in low amounts 4 6 1 2 of bulk volume in situ oxygen isotope data across quartz overgrowths suggest that cementation occurred over 100 ma and a temperature range of 80 150 c during which time high fluid overpressures resulted in consistently low vertical effective stress we argue that the very low amounts of quartz cement can only be explained by the low vertical effective stress which occurred throughout the burial history and which restricted silica supply as a result of a low rate of intergranular pressure dissolution at grain contacts

long term performance of a mudrock seal in natural co2 storage the ability of mudrock seals to prevent co 2 leakage is a major concern for geological storage of anthropogenic co 2 the long term performance of a mudrock seal which provides a natural analogue in the north sea miller oil fi eld has been evaluated this mudrock seal is immediately above a natural co 2 rich reservoir the paper reports the stable isotopes of carbon from carbonate minerals in the mudrock that have precipitated in contact with co 2 during 4 km of burial a well defi ned linear trend of upward decreasing 13 c traces the progressive penetration of free phase co 2 causing dissolution and reprecipitation of carbonate minerals the co 2 was emplaced ca 70 80 ma and has only penetrated 12 m vertically in this case the infi ltration rate is estimated as 9 8 10 7 g cm 2 yr 1

coupled alteration of hydrothermal fluids and thermal sulfate reduction tsr in ancient dolomite reservoirs an example from sinian dengying formation in sichuan basin southern china abstract to better understand the fluid activities and their roles in the formation of petroleum reservoirs dolomite was thoroughly studied in the ancient sinian dengying formation in sichuan basin southern china the high homogenization temperatures above 190 c of fluid inclusions positive eu anomaly and o and sr isotopic values of coarse crystalline pore filling dolomite fd in dissolution pore spaces have suggested that the fds are of hydrothermal origin there are also other minerals pyrite organic compounds pyrobitumen and gas components h 2 s co 2 and ch 4 in pore spaces the sulfur isotope compositions of pyrite and h 2 s along with the carbon isotopes of co 2 have shown the involvement of thermochemical sulfate reduction tsr hydrothermal activities during burial diagenesis of the dengying formation provided high temperature environment necessary for tsr to proceed the presence of co 2 and h 2 s in both processes enhanced fluid acidities and consequently porosity and permeability of the dengying formation emplacement of petroleum and acidic fluids helped to maintain pre existing reservoir spaces during deep burial stage overall the coupled hydrothermal activities and tsr provided favorable environments to allow for maintaining high quality reservoirs

synthetic saline aqueous and hydrocarbon fluid inclusions trapped in calcite at temperatures and pressures relevant to hydrocarbon basins a reconnaissance study abstract we conducted reconnaissance experiments to synthesize aqueous and hydrocarbon inclusions trapped in calcite at conditions relevant to petroleum basins and characterize the microthermometric properties of such inclusions fluid inclusions fis were synthesized in a system of saline aqueous solution 5 or 20 wt nacl coexisting with either heavy crude oil or gasoline under gas undersaturated conditions from 90 to 210 c and 200 550 bar the synthetic inclusions are not representative of gas bearing systems and methane ch 4 was not detected in any aqueous inclusions the fis are mainly distributed along planar healed cracks indicating that the inclusions formed by fracture healing in the calcite crystal microthermometric measurements were conducted on coeval aqueous and hydrocarbon inclusions and raman spectroscopic analyses were done on aqueous inclusions to determine the properties of fis trapped at these conditions homogenization temperatures of synthetic fis are mostly lower than the experimental trapping temperature although the fis show high variability in measured homogenization temperature results allow comparison of t h values for each sample with the expected t h isochores and pressure corrections calculated for the system h 2 o nacl the latter parameters are broadly consistent with the known pvtx properties of h 2 o nacl fluids suggesting little effect of hydrocarbons on the homogenization behavior although the low precision of the t h data limits this assessment nevertheless this result is not unexpected considering that light hydrocarbons gas is not present in the experiments as corroborated by raman spectroscopy a consequence of using dead oil in the experiments simulation of gas bearing petroleum basins will require additional protocols for producing gas either by in situ cracking of the starting hydrocarbon material or by other means the reconnaissance experiments documented here provide a basis for such future experiments

spherical dynamic models of top down tectonics 1 we use the multipole boundary element method mp bem to simulate regional and global geodynamics in a spherical 3 d setting we first simulate an isolated subducting rectangular plate with length llitho and width wlitho varying between 0 5 and 2 times the radius of the earth rearth and with viscosity litho varying between 100 and 500 times the upper mantle um sinking in a layered mantle characterized by lower upper mantle viscosity ratio lm um varying between 1 and 80 in a mantle with small upper lower viscosity contrast 1 trench and plate motions are weakly dependent on wlitho plate motion is controlled by slab pull if llitho rearth while for longer plates plate speed strongly decreases because of the plate basal friction and flow reorganization an increasing viscosity ratio gradually breaks this pattern and for 10 combined with wlitho rearth and greater trench advance and retreat are simultaneously observed these results offer a first order explanation of the origin of the size llitho wlitho rearth of the largest plates observed over the past 150 myr finally two global plate tectonic simulations are performed from reconstructed plates and slabs at 25 ma before present and before 100 ma respectively it is shown that mp bem predicts present plate kinematics if plate mantle decoupling is adopted for the longest plates llitho rearth models for 100 ma show that the slab slab interaction between india and izanagi plates at 100 ma can explain the propagation of the plate reorganization from the indian to the pacific plate

the influence of multiple stage oil emplacement on deeply buried marine sandstone diagenesis a case study on the devonian donghe sandstones tabei uplift tarim basin nw china abstract understanding the oil emplacement influence on diagenesis is one of the most key factors of reservoir quality prediction the devonian donghe sandstones are deeply buried to 5700 6000 m and they are important exploration target in the tarim basin additional the reservoirs experienced multi phase hydrocarbon accumulation and destruction the donghe sandstones contain various diagenetic minerals which are mainly composed of calcite cement a small amount of quartz overgrowth and pyrite trace ankerite and ferrocalctie the current study investigates the influence of multiple stage oil emplacement on the diagenesis with particular attention to calcite and quartz cementation of marine clastic reservoir interval of the donghe sandstones in the tarim basin the samples in the oil leg and water leg have been collected and a series of studies were performed including thin section petrography scanning electron microscopy sem carbon and oxygen isotopes and cathodoluminescence cl analysis the 13cv pdb values of calcite cement from the oil leg and water leg between 4 73 and 1 21 and 3 81 to 0 86 respectively the 18ov pdb values of calcite cement from the oil leg and water leg range from 15 59 to 6 61 and 14 97 to 7 76 respectively both of them display no obviously different in the oil leg and water leg all of the 13cv pdb values in the whole interval of the donghe sandstones show lightly depletion was explained mixing from marine carbon and carbon produced from bacterial sulfate reduction bsr that happens during petroleum degradation associated with sulfate reduced by hydrocarbons bacterially two dull luminescence zones trace fe and mn content and high fe accompanied by low mn content and orange red and bright orange yellow luminescence zones in oil leg indicate four generations of calcite occurred whereas two generations of calcite occurs in water leg which are dull and orange red luminescence zones two origins of calcite cement were clearly identified marine biogenic carbonates and hydrocarbon related from palaeo reservoir bsr during uplift the first generation of calcite cement originated from biogenic carbonate the second and third generations of calcite cement were mixing from predate carbonate cement dissolved and re precipitated and calcite precipitated by bsr directly some quartz grains and k feldspars were dissolved by residual organic acids that remained in the irreducible water and following replaced by the fourth generation of calcite cement some calcite cement in the oil leg precipitated in a temperature higher than the homogeneous temperature of fluid inclusion which indicates oil emplacement has no influence on calcite cementation the quartz overgrowth postdate the first hydrocarbon accumulation and predate the second hydrocarbon accumulation which originated from quartz grains dissolved by organic acids that produced from bsr and re precipitated at a low temperature the current study can promote the understanding of the influence of multiple stage hydrocarbon accumulation on diagenesis and it can also inspire the diagenesis process of other paleozoic hydrocarbon reservoirs in the tarim basin

note on the importance of hydrocarbon fill for reservoir quality prediction in sandstones oil emplacement retarded the rate of quartz cementation in the brae formation deep water sandstone reservoirs of the miller and kingfisher fields united kingdom north sea thus preserving porosity despite the rocks being buried to depths of 4 km and 120 degreesc quartz precipitation rates were reduced by at least two orders of magnitude in the oil legs relative to the water legs important contrasts in quartz cement abundances and porosities have emerged between the oil and water legs where reservoirs have filled with hydrocarbons gradually over a prolonged period of time 15 m y the earlier the hydrocarbon fill the greater is the degree of porosity preservation failure to consider this phenomenon during field development could lead to overestimation of porosity and permeability in the water leg potentially leading in turn to poor decisions about the need for and placement of downflank water injectors during exploration the retarding effect of oil on quartz cementation could lead to the presence of viable reservoirs situated deeper than the perceived regional economic basement

rapid fluid rock interaction in oilfield reservoirs we report here on production data from a north sea oilfield that demonstrates that significant mineral fluid interactions took place in the reservoir on a time scale of months a time series of produced water compositions from the bp operated miller field in the uk sector of the north sea was generated over a period of more than 7 yr when seawater was being injected for secondary recovery and pressure maintenance deviation of the produced water chemistry from linear mixing of seawater and formation water indicates that mineral water interactions took place in the reservoir of particular significance is the evidence for rapid reaction of injected water with silicates the safety case for co 2 storage in such reservoirs is greatly facilitated if it can be shown to react with the host pore waters and rocks on a human time scale and the results of this study indicate that this is indeed the case

illite distribution and morphology explaining basinal variations in reservoir properties of upper jurassic sandstones danish north sea abstract growth of fibrous illite may destroy an otherwise promising sandstone reservoir even sandstones characterized by microquartz coatings therefore detailed petrographical and diagenetic investigations were performed in order to understand the factors that control illite precipitation and other factors affecting the reservoir properties in the upper jurassic heno formation the heno formation is encountered in large parts of the danish central graben where its lower part the gert member was mainly deposited in back barrier environments and its upper part the ravn member was deposited in a shoreface environment in total 215 core samples from 15 wells were investigated petrographically by optical and scanning electron microscopy this was supplemented by plug porosity and permeability measurements and x ray diffraction of bulk and clay fraction the investigations show among other things that microquartz coatings may help to preserve porosity and permeability whereas the permeability is reduced when microquartz occurs combined with fibrous illite illite precipitation is largely governed by the amounts of k feldspar present during burial consequently the initial abundance of k feldspar in the sediment source area and its alteration during and immediately after deposition in particular during subaerial exposure at sequence boundaries has a major influence on the final reservoir properties of the sandstones the risk of illite precipitation can largely be predicted from the available sediment source material depositional environment and burial depth

influence of hydrocarbon injection on the compaction by pressure solution of a carbonate rock an experimental study under triaxial stresses abstract the preservation of good petrophysical properties high porosity high permeability at great depth in carbonate rocks may lead to the existence of a deeply buried reservoir dbr a target of interest for the oil industry one of the key processes controlling diagenesis of the burial environment is pressure solution creep psc an efficient compaction process responsible for the evolution of porosity and permeability in many carbonate reservoirs in this experimental study we examine the effect of i the presence of oil in the pore space and ii its timing of injection on the psc process and the petrophysical properties of a carbonate rock the experiments were performed using a flow through high pressure cell allowing the simulation of the pressure stresses and temperature conditions of a dbr multi disciplinary data mechanical chemical petrographical and petrophysical demonstrate that without oil in the pore space the main diagenetic process is the psc a process reducing by three the initial porosity but having no influence on intrinsic water permeability an early injection of oil prior to water circulation causes the inhibition of psc by the coating of the grains leading to the preservation of porosity conversely a late injection of oil does not preserve initial porosity the dataset obtained from these experiments show the importance of the timing of oil charging in a reservoir in the preservation of initial porosity at great depth by the inhibition of psc however the coating of grains by hydrocarbons may also inhibit further diagenetic processes leading to a creation of secondary porosity at depth

development of early diagenetic silica and quartz morphologies examples from the siri canyon danish north sea abstract the siri canyon has proved to be a perfect area for investigating various morphologies of diagenetic silica in sandstones the development in silica morphologies can be observed from very shallow 1700 m to increased burial depth 3000 m and increased proximity to the central graben distance from 0 to 65 km hydrocarbons and pore fluids now found in the siri fairway have at least partly originated from the central graben the siri canyon is a submarine canyon system eroded into the uppermost chalk deposits and filled with palaeogene hemipelagic and turbiditic marls and mudstones interbedded with sandstone units deposited from sandy mass flows and sandy turbidites which originated on the stavanger platform several hydrocarbon exploration and production wells have been drilled in the siri canyon seven of which are included in this study nini 3 nini 1 na 2p sofie 1 siri 4 celilie 1a and augusta 1 the reservoir sandstones in these wells all contain authigenic silica of various morphologies identified with a combination of traditional optical microscopy and scanning electron microscopy the silica morphologies in some places are classic and well documented in the literature whereas others at least to our knowledge have never previously been described some of the silica morphologies presented here show gradual transition from one to another and others are stand alone forms without clear relationships to other forms the silica morphologies can be expressed in the following way 1 opal rims characteristic of the initial phase of the silica diagenesis in most sandstone units in the siri canyon thick opal rims characterise the sandstone parts adjacent to the mudstone units in the stine segment of the siri field 2 microquartz quartz crystals with a size of 1 5 m seen as coatings on the opal rims both ordered and random 3 cavity overgrowth found as quartz outgrowths in circular and angular cavities formed by dissolution of early authigenic phases angular cavities in the microquartz coatings origin from dissolution of clinoptilolite possibly with a source in volcanic ash whereas dissolution of lepispheres probably resulted in circular cavities 4 quartz ridges syntaxial quartz overgrowths a few micro millimetre in width in parallel lines defined in this paper 5 quartz mountains syntaxial irregular 5 10 m large quartz crystals defined in this paper developed in the water filled sandstone intervals where fluids from the central graben were introduced possibly together with the hydrocarbon and where the continued growth was not retarded by the presence of hydrocarbons in the pore fluids 6 macroquartz syntaxial quartz overgrowths 20 m seen as continued growths from quartz mountains this takes place in the deeper reservoir sandstones promoted by fluids originating from the central graben and increased burial depth 7 quartz with sutured grain contacts occurring only in the deepest well 3000 m

thermogenetic degradation of early zeolite cement an important process for generating anomalously high porosity and permeability in deeply buried sandstone reservoirs abstract diagenetic explanations to anomalously high porosities and permeabilities in deeply buried sandstones have been presented for many reservoirs for example grain coatings of microquartz or chlorite can preserve porosity by preventing succeeding quartz overgrowths and dissolution of grains or cement can generate secondary porosity anomalously high porosity and permeability up to 25 and 500 md respectively characterize the deeply buried 5 km upper jurassic shoreface sandstones of the gert member heno formation in the hejre field in the danish central graben optical cathodoluminescence and scanning electron microscopy were used to characterize the petrography and diagenetic changes that resulted in this high pressure and high temperature hpht reservoir this was supplemented by chemical analyses icp oes and icp ms mineralogical composition xrd and oxygen isotope composition of quartz and calcite cement sims the petrographic investigation shows that none of the known explanations for anomalously high porosity and permeability can be applied hence a new hypothesis for deeply buried sandstones in contact with lavas and volcaniclastic lithologies is proposed the new hypothesis includes reducing mechanical compaction due to early patchy zeolite cement which was sourced from adjacent lavas and volcaniclastic rocks locally stylolites developed where zeolite cement was less effective hence the present overpressure formed at a later stage increased temperatures during burial resulted in thermal instability of the zeolite cement which was dissolved and authigenic k feldspar and quartz precipitated instead this resulted in a reduction of the cement volume of up to 70 if the zeolite was k heulandite and a corresponding relative porosity increase thus a reduction in cement volume was generated by replacing zeolite of an open crystal structure with mineral phases k feldspar and quartz of denser crystal structures the thermogenetic breakdown of zeolite was forced by increased temperatures during burial this process may explain previously enigmatic highly porous and permeable deeply buried sandstone reservoirs

dynamics of cementation in response to oil charge evidence from a cretaceous carbonate field u a e abstract oil charge is thought to inhibit the growth of cements within subsurface pore systems we explore this phenomenon in a giant cretaceous carbonate field from u a e where the oil filled crest porosity ranges from 10 to 50 and permeability from 0 08 to 830 md but coeval water leg porosity is reduced to 10 to 23 and permeability to 0 1 to 4 md only 5 of primary interparticle pores 30 m diameter in the crest are fully cemented compared to 99 of pores in the water leg syntaxial calcite burial cements 10 m diameter in the oil leg show 12 cathodoluminescence zones with oil inclusions n 27 occurring in four of the five final zones mean in situ ion microprobe 18ovpdb data from the oil leg cements range from 1 2 in the oldest zone decreasing to 10 3 in zone 11 returning to 7 7 in the final zone the oldest distinguishable cement zone in the water leg shows highly variable 18o from 3 6 to 9 3 with a mean of 7 3 and with subsequent zones decreasing to a mean value of 9 4 for the youngest cement zone decreasing 18o values are interpreted as indicating increasing temperature reflecting burial and the evolution of pore water composition broadly similar trends in the oil and water legs suggest precipitation under the same general conditions unlike the oil leg cements the final zone in the water leg occludes nearly all remaining pore space the 18ovpdb of bulk micrite from the water leg shows an average of 7 4 n 9 compared to 6 2 n 10 from the oil leg suggesting the precipitation of further micrite cement at greater burial depths we infer that burial cementation slowed in the presence of oil due to a reduction of potential nucleation sites as well as porewater and solute movement within weakly oil wet pores whereas continued flow and solute movement through all pores including the micropores

postaccumulation sandstone porosity evolution by mechanical compaction and the effect on gas saturation case study of the lower shihezi formation in the bayan aobao area ordos basin china abstract porosity evolution and reservoir quality are strongly affected by mechanical compaction however the compaction induced porosity reduction process in sandstone reservoirs during the postaccumulation period and its effect on gas saturation remain poorly understood by studying the sandstones in the bayan aobao area we were able to quantify the porosity evolution and gas saturation variations caused by mechanical compaction during the postaccumulation period through fluid inclusion analysis and mathematical modeling moreover we verified our findings by compaction experiments and geological statistics fluid inclusion microthermometry was employed to determine the hydrocarbon accumulation periods and the highest homogenization temperature of the two phase aqueous fluid inclusions coexisting with natural gas fluid inclusions i e 115 c with a corresponding geological age of 140 ma was regarded as the beginning of the postaccumulation stages with these data we constructed an inversion evolution model based on the geologic statistical model of sandstone mechanical compaction for the postaccumulation period and determined the gas saturation changes based on compaction porosity evolution the modeling results indicate that the sandstone porosity decreased greatly during postaccumulation subsidence and increased slightly during late stage uplift while the gas saturation increased with both the porosity decrease during the postaccumulation subsidence and the porosity increases during the later uplift the modeling results of subsidence are concordant with the compaction experiments which also show that the larger the initial porosity the greater the porosity reduction the uplift modeling results demonstrate that an erosion induced decrease in burial depth allowed the sandstone porosity to increase which is supported by some scholars findings e g neuzil and pollock 1983 jiang et al 2004 zhang 2013 and by the positive correlation between sandstone porosities and restored geologic unit thicknesses in the study area however the inversion modeling indicates that the reason for the porosity rebound in litharenites is that the increase in elastic porosity slightly exceeds the decrease in viscoplastic porosity which would have been different if the uplift induced erosion rate had been distinctly lower gas production test data and restored geologic unit thicknesses indicate that uplift and erosion may be able to enrich sandstone gas reservoirs to a certain extent consistent with the calculated gas saturation variation results but a full understanding of gas saturation evolution awaits further studies the inversion model can provide a powerful tool for quantitative analysis of the sandstone compaction process during the postaccumulation period which could be used for reference in other similar regions

fault charged mantle fluid contamination of united kingdom north sea oils insights from re os isotopes 187 os 188 os as expected from a kimmer idge clay formation source however oils from the viking graben with which the brent fi eld is associated and main east shetland basin display unradiogenic 187 os 188 os in this study we seek to demonstrate that these anomalous results are due to interaction with a mantle like fl uid that propagated through the main fault zone of the viking graben and east shetland basin this study enhances our understanding of the re os oil systematics and supports cur rent ideas regarding fault architecture crustal thinning and associated fl uid fl ow and interac tion in the north sea oil system abstract united kingdom north sea oils sourced from the kimmeridge clay formation contain unradiogenic 0 17 to 0 48 and radiogenic 1 04 to 3 34 187 os 188 os values the unra diogenic 187 os 188 os values are spatially associated with the main basin bounding faults of the viking graben and east shetland basin in contrast the radiogenic 187 os 188 os values are associated with north sea basins located farther away from the basin boundary faults we suggest that crustal thinning and strain localization within the viking graben and east shetland basin are suffi cient to have allowed basin bounding faults to propagate to suffi cient depth to act as conduits for mantle derived fl uids to interact with oil this hypothesis is sup ported by previous geochemical data for north sea oil fi elds furthermore we demonstrate the use of os isotopes as an important tracker of crustal scale fl uid dynamics and petroleum migration pathways in extensional basins

the effect of oil saturation on the mechanism of compaction in granular materials higher oil saturations lead to more grain fracturing and less pressure solution abstract whether addition of oil to sandstones slows stops or has no influence upon pressure solution and quartz cementation has long been disputed despite having major implications for petroleum exploration and appraisal strategies to elucidate the effect of addition of oil to compaction pressure solution and cementation processes this study utilizes an experimental approach simulating isochemical volumetric compaction using granular halite in the presence of variable brine oil mixtures each experiment at 500 kpa effective stress lasted 48 hours and involved repeated measurements of volumetric strain the lithified products of experiments were examined using sem techniques after 30 hours approximately 4 volumetric strain occurs when the brine oil ratio is 100 0 pure brine fractures are rare in samples from experiments undertaken with pure brine so that pressure solution and concomitant cementation must be the compaction mechanism when the brine oil ratio is decreased from 100 0 to 40 60 the volumetric strain remains about 4 but there are more fractures as quantified from sem image analysis these observations suggest that although pressure solution has occurred some of the volumetric strain is the result of fracturing implying that pressure solution has been less effective in the presence of some oil than it is in the presence of pure brine when the brine oil ratio is decreased further from 40 60 to 5 95 the volumetric strain increases up to 7 3 sem image analysis reveals that the strain is predominantly due to grain fracturing this change from pressure solution to grain fracturing is likely due to heterogeneous pressure solution resulting from heterogeneous distribution of stresses brine coated grain contacts undergo pressure solution but oil coated grain contacts experience increasing stress up to the point of failure as the surrounding grain pack compacts when the brine oil ratio is decreased to less than 5 95 volumetric strain decreased to about 1 with few induced fractures and little pressure solution compaction is negligible when the brine oil ratio is 0 100 only oil in the pores and fractures are negligible halite is more water soluble and more hygroscopic than quartz so that water will cling to halite surfaces more tenaciously than to quartz since even halite has its mechanism of volumetric strain affected when the brine oil ratio is less than 40 60 quartz pressure solution and subsequent cementation is even more likely to be affected by oil filling this experimental study suggests that the mechanism and extent of compaction and subsequent cementation in sandstones is strongly affected by the addition of oil

impact of diagenesis on reservoir quality and heterogeneity of the upper triassic chang 8 tight oil sandstones in the zhenjing area ordos basin china abstract reservoir quality and heterogeneity are critical risk factors in tight oil exploration the integrated analysis of the petrographic characteristics and the types and distribution of diagenetic alterations in the chang 8 sandstones from the zhenjing area using core log thin section sem petrophysical and stable isotopic data provides insight into the factors responsible for variations in porosity and permeability in tight sandstones the results indicate that the chang 8 sandstones mainly from subaqueous distributary channel facies are mostly moderately well to well sorted fine grained feldspathic litharenites and lithic arkose the sandstones have ultra low permeabilities that are commonly less than 1 md a wide range of porosities from 0 3 to 18 1 and two distinct porosity permeability trends with a boundary of approximately 10 porosity these petrophysical features are closely related to the types and distribution of the diagenetic alterations compaction is a regional porosity reducing process that was responsible for a loss of more than half of the original porosity in nearly all of the samples the wide range of porosity is attributed to variations in calcite cementation and chlorite coatings the relatively high porosity reservoirs formed due to preservation of the primary intergranular pores by chlorite coatings rather than burial dissolution however the chlorites also obstruct pore throats which lead to the development of reservoirs with high porosity but low permeability in contrast calcite cementation is the dominant factor in the formation of low porosity ultra low permeability reservoirs by filling both the primary pores and the pore throats in the sandstones the eogenetic calcites are commonly concentrated in tightly cemented concretions or layers adjacent to sandstone mudstone contacts while the mesogenetic calcites were deposited in all of the intervals and led to further heterogeneity this study can be used as an analogue to understand the variations in the pathways of diagenetic evolution and their impacts on the reservoir quality and heterogeneity of sandstones and is useful for predicting the distribution of potential high quality reservoirs in similar geological settings

vertical effective stress and temperature as controls of quartz cementation in sandstones evidence from north sea fulmar and gulf of mexico wilcox sandstones abstract we present quantitative petrographic data high spatial resolution oxygen isotope analyses of quartz cement basin modelling and a kinetic model for quartz precipitation for two paleocene eocene wilcox group sandstones from texas and two jurassic fulmar formation sandstones from the central north sea at each location one sandstone has been buried to ca 145 c and one to ca 185 c a key difference between the wilcox and fulmar burial histories is that the wilcox sandstones are currently at higher vertical effective stresses and from basin modelling studies have been subjected to generally higher vertical effective stresses through their burial history the amounts of quartz cement in the wilcox sandstones are between 12 and 18 and between 2 and 6 in the fulmar sandstones high spatial resolution oxygen isotope data obtained from the quartz cements suggest temperature ranges for quartz precipitation from 60 to 80 c to values approaching maximum burial temperature factors such as grain coatings or the timing of petroleum emplacement cannot explain the differences in the amounts of quartz cement petrographic data show that most of the silica for quartz cement can be derived from intergranular pressure dissolution although the sample set is small we interpret the results to suggest that the differences in quartz cementation in fulmar and wilcox sandstones can be explained better by differences in their vertical effective stress history than their temperature history in this case the supply of silica rather than the precipitation of quartz becomes an important control on the rate and extent of cementation

relationships between stylolites and cementation in sandstone reservoirs examples from the north sea u k and east greenland abstract the reservoir potential of hydrocarbon sandstone reservoirs may be significantly reduced by compartmentation as a result of the development of stylolites a petrographic and fluid inclusion microthermometric study was performed on sandstones containing abundant stylolites from the buchan galley and scott fields in the outer moray firth offshore scotland and from a palaeo oil bearing sequence in east greenland the main objective of this study was to further constrain the temperatures and burial depths at which stylolitization occurs in sandstone reservoirs the sandstones containing abundant stylolites are also characterized by their highly cemented nature numerous occurrences of quartz overgrowths clearly truncated by sutured stylolites are evident in all of the samples fluid inclusion microthermometry reveals that quartz cementation which is interpreted to be coeval with stylolitization occurred at minimum temperatures of between 86 and 136 c basin modelling of the scott and galley fields indicates that quartz cementation and stylolite development formed at depths greater than 2 5 km which were attained during rapid tertiary burial the occurrence of hydrocarbon fluid inclusions within healed microfractures orientated at high angles to the stylolites suggests that these microfractures provided pathways for hydrocarbon migration in the highly cemented low permeability zones associated with highly stylolitized sandstones

the effect of oil emplacement on quartz cementation in a deeply buried sandstone reservoir quartz is an important porosity occluding cement in sandstone reservoirs that have been subjected to elevated temperature 80 c to 100 c for a substantial period of time the effect of oil emplacement on quartz cementation in reservoir sandstones is controversial some studies have concluded that early oil emplacement can inhibit quartz cementation leading to the preservation of porosity whereas other studies have concluded that quartz cementation appears largely unaffected by oil emplacement here we have studied shallow marine upper jurassic sandstones from ula field norwegian north sea with reservoir temperatures of approximately 150 c to determine whether oil emplacement had a significant impact on diagenesis with particular attention to quartz cementation following sedimentological description of cores samples above and below the oil water contact have been collected adjacent to core analysis plug points these samples then underwent a series of studies including petrographic point counting with a transmitted light microscope scanning electron microscopy sem backscattered electron microscopy sem cathodoluminescence microscopy and fluid inclusion studies these data were integrated with routine core analysis and petrophysical log data density and resistivity log data have been used to determine the precise oil saturation of each sample studied the distributions of all potential controls on porosity and permeability such as grain size sorting matrix clay content and degree of bioturbation the presence of grain coatings and dolomite cement and the amount of quartz cement have been assessed the presence of primary oil inclusions within quartz cement shows that oil ingress into the ula reservoir commenced prior to the onset of quartz cementation very fine grained matrix rich bioturbated microquartz cemented sandstones have uniformly low quartz cement contents irrespective of oil saturation medium grained graded matrix poor microquartz poor sandstones have quartz cement ranging from 1 to greater than 17 associated with core porosities of approximately 22 and 7 respectively higher oil saturations equate to higher porosities and permeabilities in the medium grained graded matrix poor microquartz poor sandstones which cannot be explained by any control other than the amount of quartz cement as a function of pore fluid type oil emplacement therefore appears to have inhibited quartz cementation at high oil saturations and can be viewed as an important control on reservoir quality the significance of this study is that the presence of oil in a sandstone reservoir at the time that quartz cement was growing can have a considerable impact on reservoir quality models that seek to predict quartz cement and reservoir quality in sandstones need to account for the timing of oil emplacement compared with other diagenetic processes

tectonics alteration and the fractal distribution of hydrothermal veins in the lower ocean crust abstract gabbros from hole 735b preserve the igneous structural and metamorphic history beneath the southwest indian ridge down to middle amphibolite facies conditions the gabbro was isolated from the zone of lithospheric necking by detachment faulting unroofing and block uplift at the inside corner high of the atlantis ii transform lower crustal accretion as preserved in the core is a complex integration of igneous hydrothermal and tectonic processes alteration began at anhydrous granulite conditions as surface faulting penetrated the brittle ductile transition to form brittle ductile shear zones in the amphibolite facies hydrous alteration around these zones was extensive while undeformed sections remained virtually unaltered amphibole veins formed during the brittle ductile deformation have a high fractal dimension reflecting an unclustered distribution consistent with high strain and cracking rates in the zone of lithospheric necking beneath the ridge however the fractal dimensions of the two major gneissic amphibolite zones in hole 735b are different and suggest that they represent discrete fault zones formed at different times below middle amphibolite facies a dramatic drop in the extent of alteration reflects cooling cracking and alteration under static conditions similar to layered intrusions initially fracture and vein formation exploited undeformed sections where elastic strain accumulated during cooling from high temperatures was unrelieved by recrystallization plagioclase diopside veins formed at this time have the same orientation as higher temperature veins but a mineralogy reflecting much lower rock permeabilities and a low fractal dimension reflecting a tight clustering of veins as would be anticipated for crack formation at low strain rates late zeolite and carbonate veins and irregular smectite lined near vertical cracks also have a very low fractal dimension reflecting clustering appropriate to low strain near static conditions these however show no preference for undeformed sections of the core and are oriented with subvertical and subhorizontal maxima this indicates crack formation under the present day stress field thus elastic strain due to cooling from high temperatures and extension during lithospheric necking dissipated after plagioclase diopside vein formation