Devonian Reservoirs Research Articles

Organic geochemical study of source rocks and natural gas and their genetic correlation in the eastern part of the Polish Outer Carpathians and Palaeozoic–Mesozoic basement

Geochemical characteristics of organic matter in the profiles of Dukla, Silesian, Sub-Silesian and Skole units of the Polish Outer Carpathians and of the Palaeozoic–Mesozoic basement in the Dębica-Rzeszów-Leżajsk-Sanok area were established based on Rock-Eval, vitrinite reflectance, isotopic and biomarker analyses of 485 rock samples. The Oligocene Menilite beds have the best hydrocarbon potential of all investigated formations within the Dukla, Silesian, and Skole units. The Ordovician, Silurian, Lower Devonian and locally Middle Jurassic strata of the Palaeozoic–Mesozoic basement are potential source rocks for oil and gas accumulated in Palaeozoic and Mesozoic reservoirs. Thirty one natural gas samples from sandstone reservoirs of the Lower Cretaceous-Lower Miocene strata within the Outer Carpathian sequence and eight from sandstone and carbonate reservoirs of the Palaeozoic–Mesozoic basement were analysed for molecular and isotopic compositions to determine their origin. Natural gases accumulated both in the Outer Carpathian and the Palaeozoic–Mesozoic basement reservoirs are genetically related to thermogenic and microbial processes. Thermogenic gaseous hydrocarbons that accumulated in the Dukla and Silesian units were generated from the Menilite beds. Thermogenic gaseous hydrocarbons that accumulated in the Sub-Silesian Unit most probably migrated from the Silesian Unit. Initial, and probably also secondary microbial methane component has been generated during microbial carbon dioxide reduction within the Oligocene Menilite beds in the Dukla Unit and Oligocene-Lower Miocene Krosno beds in the Silesian Unit. Natural gases that accumulated in traps within the Middle Devonian, Mississippian, Upper Jurassic, and Upper Cretaceous reservoirs of the Palaeozoic–Mesozoic basement were mainly generated during thermogenic processes and only sporadically from initial microbial processes. The thermogenic gases were generated from kerogen of the Ordovician-Silurian and Middle Jurassic strata. The microbial methane component occurs in a few fields of the Dukla and Silesian units and in the two accumulations in the Middle Devonian reservoirs of the Palaeozoic–Mesozoic basement.

Природные резервуары в ордовикских, силурийских и девонских отложениях Джебольской ступени Ижма-Печорской впадины

Природные резервуары в ордовикских, силурийских и девонских отложениях Джебольской ступени Ижма-Печорской впадины

Strontium isotope quantification of siderite, brine and acid mine drainage contributions to abandoned gas well discharges in the Appalachian Plateau

Unplugged abandoned oil and gas wells in the Appalachian region can serve as conduits for the movement of waters impacted by fossil fuel extraction. Strontium isotope and geochemical analysis indicate that artesian discharges of water with high total dissolved solids (TDS) from a series of gas wells in western Pennsylvania result from the infiltration of acidic, low Fe (Fe<10mg/L) coal mine drainage (AMD) into shallow, siderite (iron carbonate)-cemented sandstone aquifers. The acidity from the AMD promotes dissolution of the carbonate, and metal- and sulfate-contaminated waters rise to the surface through compromised abandoned gas well casings. Strontium isotope mixing models suggest that neither upward migration of oil and gas brines from Devonian reservoirs associated with the wells nor dissolution of abundant nodular siderite present in the mine spoil through which recharge water percolates contribute significantly to the artesian gas well discharges. Natural Sr isotope composition can be a sensitive tool in the characterization of complex groundwater interactions and can be used to distinguish between inputs from deep and shallow contamination sources, as well as between groundwater and mineralogically similar but stratigraphically distinct rock units. This is of particular relevance to regions such as the Appalachian Basin, where a legacy of coal, oil and gas exploration is coupled with ongoing and future natural gas drilling into deep reservoirs.

Origin of natural gases in the Paleozoic-Mesozoic basement of the Polish Carpathian Foredeep

Origin of natural gases in the Paleozoic-Mesozoic basement of the Polish Carpathian ForedeepHydrocarbon gases from Upper Devonian and Lower Carboniferous reservoirs in the Paleozoic basement of the Polish Carpathian Foredeep were generated mainly during low-temperature thermogenic processes ("oil window"). They contain only insignificant amounts of microbial methane and ethane. These gaseous hydrocarbons were generated from Lower Carboniferous and/or Middle Jurassic mixed Type III/II kerogen and from Ordovician-Silurian Type II kerogen, respectively. Methane, ethane and carbon dioxide of natural gas from the Middle Devonian reservoir contain a significant microbial component whereas their small thermogenic component is most probably genetically related to Ordovician-Silurian Type II kerogen. The gaseous hydrocarbons from the Upper Jurassic and the Upper Cretaceous reservoirs of the Mesozoic basement were generated both by microbial carbon dioxide reduction and thermogenic processes. The presence of microbial methane generated by carbon dioxide reduction suggests that in some deposits the traps had already been formed and sealed during the migration of microbial methane, presumably in the immature source rock environment. The traps were successively supplied with thermogenic methane and higher hydrocarbons generated at successively higher maturation stages of kerogen. The higher hydrocarbons of the majority of deposits were generated from mixed Type III/II kerogen deposited in the Middle Jurassic, Lower Carboniferous and/or Devonian strata. Type II or mixed Type II/III kerogen could be the source for hydrocarbons in both the Tarnów and Brzezówka deposits. In the Cenomanian sandstone reservoir of the Brzezowiec deposit and one Upper Jurassic carbonate block of the Lubaczów deposit microbial methane prevails. It migrated from the autochthonous Miocene strata.

Wellbore-Instability Predictions in Cretaceous Mudstones: Clair Field, West of Shetlands

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124464, ’Wellbore-In stability Predictions Within the Cretaceous Mudstones of Clair Field, West of Shetlands,’ by R. Narayanasamy, SPE, D. Barr, SPE, and A. Milne, BP plc, prepared for the 2009 SPE Offshore Europe Oil &amp; Gas Conference &amp; Exhibition, Aberdeen, 8-11 September. Wellbore instability in Cretaceous mudstones overlying the Clair oil field has prevented successful drilling of high inclination wells in the past. Rock-failure analysis, based on a planes-of-weakness theory, fit previous drilling observations. Minimum-required-mud-weight predictions were made for a range of well configurations. The results of this study were used to plan an extended-reach-drilling (ERD) development well targeting a previously undeveloped part of the Clair field. Introduction The Clair oil field is on the UK Continental Shelf, 75 km west of the Shetland Islands in 140-m water depth. Discovered in 1977, first production was in February 2005 from a fixed steel platform with pipeline export to the Sullom Voe terminal on Shetland. The Clair field covers more than 200 sq km and contains more than 5 billion BO equivalent (BOE), of which 1.5 billion BOE is targeted by the Phase-1 development. The currently producing Clair Phase-1 development comprises fractured Devonian sandstone reservoirs and is produced by waterflooding with a mix of downflank and pattern injection. The Devonian reservoir is more than 500 m thick, but only the upper zones (V and VI—250- to 300-m total thick-ness) are producing, principally through high-inclination or subhorizontal wells designed to target a combination of permeable natural fractures and the best-quality matrix. The reservoir is highly compacted and cemented and does not present wellbore-stability issues while drilling. However, the combination of shallow targets [gas/oil contact at 1550 m true vertical depth subsea (TVDSS) and oil/water contact at 2100 m TVDSS] and moderate water depth requires inclination to be built rapidly in shallow unconsolidated overburden formations. Core from Well A09 was obtained to characterize rock failure through various tests. The tests revealed anisotropic strength behavior. Analyzing several existing wells with the test results enabled predictions of minimum mud weight required for stability in future wells. The full-length paper details the mud-weight predictions for an ERD well and observations made while drilling it. Drilling History Conventional wellbore-stability analysis based on a Mohr-Coulomb failure criterion was consistent with drilling observations in most of the early wells. Subsequently, however, borehole collapse was experienced while drilling through Upper Cretaceous mudstones in Wells A06 and A08. Static mud weights of up to 1.42 SG were used in Well A06 and its two unsuccessful sidetracks at an inclination of 76° (measured from vertical). Similar problems were experienced while drilling Well A08, at a lower inclination of 57° and with 1.36-SG mud weight. An increase in mud weight to 1.54 SG enabled successful drilling of a side-track (Well A08Z) and another well with a similar inclination (Well A11). An intermediate-casing shoe was set in the Cretaceous mudstones in Well A11, and a 65° section then was drilled successfully with 1.58-SG mud weight. A challenging ERD well with 76° inclination (Well A15) was drilled successfully with 1.61-SG mud weight.

Geochemistry of crude oil from Bent Horn field (Canadian Arctic Archipelago) and its possible Paleozoic origin

Geochemical analysis shows that oil from Devonian reservoirs at Bent Horn field in the Canadian Arctic Archipelago is non-biodegraded and has a maturity corresponding to the mid-late part of the oil window. It is characterized by a smooth n-alkane profile, low concentration of acyclic isoprenoids and saturated hydrocarbon biomarkers, with some variability in sterane composition. Compared with oil from Mesozoic strata of the Canadian Arctic Islands, the Bent Horn oil shows higher paraffin indices and aromatic hydrocarbon maturity indicators (MPI, MDR), dominant tricyclic terpanes and different distribution of regular steranes. Geological evidence suggests a Paleozoic source rock for the oil. Rock–Eval pyrolysis and total organic carbon (TOC) data indicate good source rock potential for the Silurian basinal facies and Upper Silurian–Lower Devonian clastics of the Boothia Uplift. These intervals are enriched in Type II oil-prone organic matter (commonly 2.0–5.0% TOC, maximum 13.6%) and are mature with respect to petroleum generation. Based on preliminary biomarker analysis, maturity, and stratigraphic and geographic proximity to the Bent Horn oil field, the Cape Phillips Formation appears to be the most likely source rock for the hydrocarbon accumulation at Bent Horn.

Remembering First Oil in Nevada

In June 1954 Nevada became the twenty-ninth oil-producing state in the United States (Picard 1955). Interestingly, production was from volcanic rocks from the open-hole interval 6,450 to 6,730 ft (1,966 to 2,051 m) in the Oligocene Garrett Ranch volcanics, an unexpected reservoir in the kind of rocks rarely productive anywhere in the world. The pour-point (65-80° F) and gravity (26-29° API) of the crude were high, similar to oils found in the Eocene Green River Formation of the Uinta Basin, northeast Utah. Cumulative production in the field through September 1978 was 3.3 million barrels of oil. An early estimate of ultimate primary reserves was four million barrels of oil (Bortz and Murray, 1979). The trap is a faulted truncated wedge of Oligocene and Cretaceous-Eocene rocks with a top seal of impermeable valley fill, a bottom seal of Paleozoic rocks, and an east-side seal formed by a basin boundary fault and impermeable Paleozoic rocks. The new field in Railroad Valley of east-central Nevada, finally totaling fourteen producing wells, was called Eagle Springs after the locality and the name of the discovery well drilled by the Shell Oil Company. Twenty-two years after the Eagle Springs discovery a larger oil field, Trap Spring, was discovered by Northwest Exploration Company less than ten miles west of Eagle Springs, in Tertiary ash-flow tuffs. Two hundred dry holes had been drilled in Nevada between the two discoveries. In 1982, six years after the Trap Spring discovery, Amoco Production Company drilled the first well outside of Railroad Valley at Blackburn field on the east side of Pine Valley in Eureka County. Blackburn, a structural trap above a Tertiary low-angle extensional fault, produces from Devonian reservoirs. In 1983, Northwest Production brought in the Grant Canyon field about 10 mi (6 km) south of Eagle Springs. The oil reservoir of Devonian carbonates there is entrapped in a ‘buried-hill’. The discovery in 2004 of the Covenant field in Central Utah, because of similarities to large oil fields in the thrust belt of Wyoming and Utah and some resemblance to the Nevada fields of the Great Basin, ignited a frenzy of leasing which still goes on when land is available. Located along the thrust-belt (hingeline), Covenant produces oil from the Jurassic Navajo Sandstone that apparently originated in the Paleozoic.

Seismic anisotropy as an indicator of reservoir quality in siliciclastic rocks

Abstract Improving the accuracy of subsurface imaging is commonly the main incentive for including the effects of anisotropy in seismic processing. However, the anisotropy itself holds valuable information about rock properties and, as such, can be viewed as a seismic attribute. Here we summarize results from an integrated project that explored the potential to use observations of seismic anisotropy to interpret lithological and fluid properties (the SAIL project). Our approach links detailed petrofabric analyses of reservoir rocks, laboratory based measurements of ultrasonic velocities in core samples, and reservoir-scale seismic observations. We present results for the Clair field, a Carboniferous–Devonian reservoir offshore Scotland, west of the Shetland Islands. The reservoir rocks are sandstones that are variable in composition and exhibit anisotropy on three length-scales: the crystal, grain and fracture scale. We have developed a methodology for assessing crystal-preferred-orientation (CPO) using a combination of electron back-scattered diffraction (EBSD), X-ray texture goniometry (XRTG) and image analysis. Modal proportions of individual minerals are measured using quantitative X-ray diffraction (QXRD). These measurements are used to calculate the intrinsic anisotropy due to CPO via Voigt-Reuss-Hill averaging of individual crystal elasticities and their orientations. The intrinsic anisotropy of the rock is controlled by the phyllosilicate content and to a lesser degree the orientation of quartz and feldspar; the latter can serve as a palaeoflow indicator. Our results show remarkable consistency in CPO throughout the reservoir and allow us to construct a mathematical model of reservoir anisotropy. A comparison of CPO-predicted velocities and those derived from laboratory measurements of ultrasonic signals allows the estimation of additional elastic compliance terms due to grain-boundary interactions. The results show that the CPO estimates are good proxies for the intrinsic anisotropy of the clean sandstones. The more micaceous rocks exhibit enhanced anisotropy due to interactions between the phyllosilicate grains. We then compare the lab-scale predictions with reservoir-scale measurements of seismic anisotropy, based on amplitude variation with offset and azimuth (AVOA) analysis and non-hyperbolic moveout. Our mathematical model provides a foundation for interpreting the reservoir-scale seismic data and improving the geological modelling of complex reservoirs. The observed increases in AVOA signal with depth can only be explained with an increase in fracturing beneath the major unit boundaries, rather than a change in intrinsic CPO properties. In general, the style and magnitude of anisotropy in the Clair field appears to be indicative of reservoir quality.

Clair Field: Development of a Waterflooded Fractured Reservoir

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 96316, "Clair Field - Managing Uncertainty in the Development of a Waterflooded Fractured Reservoir," by P.J. Clifford, SPE, A.R. O'Donovan, SPE, K.E. Savory, SPE, G. Smith, and D. Barr, BP plc, prepared for the 2005 Offshore Europe, Aberdeen, 6–9 September. Clair is the largest naturally fractured reservoir developed in the U.K. Recovery is by waterflood. Its 28-year appraisal period reflects the high reservoir complexity, relatively poor-quality conventional-seismic image, and uncertain effect of the conductive fractures. Clair is not predrilled, and the preferred well locations and design will change. Introduction Clair is a naturally fractured Devonian sandstone reservoir with a 1,970-ft reservoir interval containing 23°API oil 47 miles west of Shetland in 500 ft of water. Clair was discovered in 1977 and appraised by a series of vertical wells with disappointing rates. Field potential finally was demonstrated by the drilling of high-angle appraisal wells 206/8-9z and 206/8-10z, culminating in an extended well test (EWT) of 206/8–10z in 1996, which produced 500,000 STB of oil and demonstrated communication with a minimum of 500 million STB. The EWT led to sanction of the Clair Phase 1 development in 2001 and first oil in February 2005. The Clair Phase 1 development comprises the core, graben, and horst fault blocks (Fig. 1) believed to contain approximately 1.5 million STB of oil. Appraisal of the remaining areas of the field is continuing and may lead to sub-sequent development phases. Phase 1 is a single fixed-platform development. The field will be developed by drilling 22 additional wells over a 3-year period. The principal recovery mechanism is waterflood, with a planned ratio of approximately 2 producers per injector. Matrix permeability averages approximately 30 md, and oil viscosity is 3.5 cp at reservoir conditions. Recovery strategy begins with development of the more productive relatively high-permeability fluvial sands of Unit V in the large core segment and proceeds with development of the interbedded lake-margin fluvial sands of Unit VI on the basis of learning from Unit V wells. Drilling in the smaller and less appraised graben and horst blocks proceeds in parallel with the later core development. Natural-Fracture Description. The controlling feature of reservoir development in Clair is the system of natural fractures. Core and image logs demonstrate widespread granulation seams, conductive fractures, and cemented fractures. Use of seismic techniques to distinguish conductive from nonconductive faults and fractures is a key methodology in Clair reservoir description. To describe the possible fracture distributions, and to allow their incorporation into reservoir models, a number of scenarios have been generated. In these scenarios, stochastic distributions of conductive faults or joints have been generated with use of conditioning to seismic data, and these have been upscaled into fracture permeability arrays for incorporation into dynamic reservoir models.

Fault and conduit controlled burial dolomitization of the Devonian west-central Alberta Deep Basin

Abstract Devonian reservoirs in the Swan Hills, Leduc and Wabamun formations in the west-central Alberta deep basin occur at present day depths of 3000 m to 3600 m and are generally restricted to dolomitized strata. Pervasive dolomite occurs; 1) along bank margins (Kaybob South Field and Fox Creek Field) of the Swan Hills Formation; 2) in the Leduc Formation rimmed reefs (Pine Creek and Pine Creek Northwest fields) and; 3) in the Wabamun Formation above the up dip edge of the Pine Creek Leduc Field. Dolomites have variable crystal size (50 to 800 μm) and morphology (planar euhedal rhombs to non-planar anhedral). Type I dolomite (< 5% of all dolomite) is a fine-grained (planar subhedral–euhedral) dolomite that overlaps with low amplitude stylolites and is prevalent as a burrow replacement at the Wabamun Pine Creek Field. Type II pervasive dolomite that postdates low amplitude stylolites is a medium to coarse-grained (non-planar, subhedral–anhedral) dolomite that occurs as the predominant replacement of matrix and fossils in all the fields. The pervasive replacement dolomite Type II has low δ18O values of −7.9 to −3.6‰ (relative to PDB) and low to moderate Sr ratios (87Sr/86Sr of 0.7083 to 0.7118). Wabamun Fm Type I dolomite of burrow mottled intervals (Type IA), have depleted δ18O (−8.78 to −9.77 ‰, mean −9.15 ‰) and moderately radiogenic 87Sr/86Sr signatures (0.7095). Type I dolomite from pervasive dolomite intervals (Type IB), have less depleted δ18O (−3.86 to −7.34 ‰ PDB, mean −5.67 ‰) and moderate 87Sr/86Sr signatures (0.7099). Although there is a wide spread in oxygen isotope values, estimated temperatures of Type II dolomite formation range from 45 to 75°C, equivalent to burial depths of 700–1500 m. Samples with 87Sr/86Sr ranging from Devonian sea water values to more radiogenic (0.7093 to 0.7118), indicate that pore waters were modified by water-rock reactions during burial and dolomitization. Type IA dolomites may have undergone neomorphism during burial at high temperatures. Type IB dolomites may have been altered from fluids that precipitated the Type II dolomites, or formed from fluids that precipitated the Type II dolomite. Seismic evidence, detailed log marker correlation and fractured and brecciated dolomite occurrences indicate that fault-controlled conduits may have controlled local and restricted dolomite occurrences in the Swan Hills and the middle Wabamun Fm. Widespread dolomite in the Leduc level indicates that porous Leduc dolomites may also have been connected via the underlying dolomitized part of the Lower Leduc platform, forming a basin-wide conduit system. Basin fluid flow could have been initiated by tectonically stacked thrust sheets and sedimentary loading by a clastic wedge causing mechanical compaction that squeezed the fluids out of the still compactable basin sediments. This may have occurred during two orogenies, the Late-Devonian to Early-Carboniferous Antler Orogeny, and the Late-Jurassic to Early-Tertiary Columbian/Laramide Orogeny. Presumably, the basin fluids flowed laterally updip along the conduit systems and vertically up fault systems until they reached stratigraphic conduits along the eastern flank of the Alberta Basin.

Ardmore Field: rebirth of the first offshore oil field, UKCS

The UK’s first offshore oil production began in June 1975 from the Argyll Field. In a 17-year period the field produced 72.6 million barrels of sweet, light crude. However, in 1992, production from the field became uneconomic, the field was abandoned, all wells were plugged and the facilities removed. In January 2002 two new oil companies, Tuscan Energy and Acorn Oil and Gas, were awarded the licence to redevelop the Argyll Field – now renamed Ardmore. A field development plan was submitted to the DTI and approval granted in October 2002. The first Ardmore well was drilled in the summer of 2003 and ‘second’ oil flowed in September 2003. Ardmore is a geologically complex field with four distinct reservoirs, of which the three oldest appear to be in both pressure and fluid communication. During the ‘Argyll’ production years (1975–1992), vuggy, karstified, Zechstein carbonates were then interpreted to have delivered about 80% of their oil in place. Rather than reflecting an error in volumetrics (underestimated STOIIP) the oil is interpreted to have come from the underlying Rotliegend and Devonian sandstone reservoirs. Natural aquifer support was significant for the Rotliegend, and probably the Zechstein reservoirs, while the volumetrically dominant Devonian reservoir produced via pressure depletion. Recovery from Jurassic sandstones on the west flank of Ardmore was minimal. Vertical and low deviation subsea wells tied back to a floating production system were used for the initial development of Argyll. As production progressed, the increasing water cut and lower reservoir pressure required artificial lift for most wells. The limited amount of gas available restricted the number of wells which could be produced. There were several wells drilled late in field life which tested oil using nitrogen gas lift but which were abandoned without being produced due to the restrictions of the gas lift system. Argyll was abandoned in 1992 with an average water cut of about 70%. Detailed subsurface studies, integrating the geology, geophysics and petrophysics with the 17 years of dynamic data, have led to a better understanding of the field performance and have allowed new development targets to be identified. The redevelopment of the field targets a combination of attic oil in Zechstein, bypassed oil in the Rotliegend, resegregated oil in the Zechstein and Rotliegend and unproduced but proven oil in the Devonian.

STRATIGRAPHIC CONTROLS ON PALAEOZOIC PETROLEUM SYSTEMS, GHADAMES BASIN, LIBYA

The distribution of oil‐ and gasfields in the Libyan Ghadames Basin is strongly influenced by the stratigraphic architecture of the Silurian‐Devonian succession. This interval encompasses part of two (second‐order) super‐sequences separated by the Caledonian unconformity: (i) a late Ashgillian‐Silurian super‐sequence, comprising the Melez Chograne‐Memouniat periglacial lowstand, the Tanezzuft transgressive to early highstand shales and the Acacus Formation late highstand systems tracts; and (ii) the lower part of a composite Devonian‐Carboniferous super‐sequence terminated by the Hercynian unconformity, which includes the lowstand Tadrart fluvial‐shallow marine sands, the Ouan Kasa (transgressive) and the Aouinet Ouinene transgressive to early highstand systems tracts of Devonian age.Hydrocarbon accumulations in Acacus, Tadrart and later Devonian reservoirs have been charged from a basal Silurian (Tanezzuft Formation) “hot” radioactive shale source rock. The Acacus and Tadrart sandstones provided regional migration conduits sealed by intra‐Acacus, intra‐Devonian (Emghaet Formation) and Permian (Bir Al Jaja Formation) shales. Regional stratigraphic continuity of these migration conduits permitted the development of low to moderate impedance petroleum systems dominated by lateral migration.Basin reconstructions and burial history modelling suggest three expulsion peaks from the basal Tanezzuft Formation source rock, preceding major periods of Hercynian, Austrian and Alpine (mid‐late Tertiary) uplift and exhumation. Hydrocarbons trapped prior to the Hercynian event were dispersed during later periods of structural deformation. Some pre‐Austrian accumulations may have survived locally in more robust traps. However, most if not all of the oil‐ and gasfields discovered in the Late Silurian ‐ Devonian succession were probably charged during the Late Cretaceous—Early Tertiary, only to suffer partial dispersal during later uplift, tilting and flushing. Three petroleum systems can be distinguished within the basin: (i) a Tanezzuft ‐Acacus system to the north; (ii) a Tanezzuft ‐ Tadrart system to the south; and (iii) a Tanezzuft ‐Acacus/Tadrart(+) system in the centre, with some leakage into overlying Devonian and Carboniferous sandstones locally.

Devonian hydrocarbon source rocks and their derived oils in the Western Canada Sedimentary Basin

Research Article| March 01, 2001 Devonian hydrocarbon source rocks and their derived oils in the Western Canada Sedimentary Basin* Martin G. Fowler; Martin G. Fowler Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Search for other works by this author on: GSW Google Scholar Lavern D. Stasiuk; Lavern D. Stasiuk Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Search for other works by this author on: GSW Google Scholar Mark Hearn; Mark Hearn Shell Canada Ltd., 400 - 4 Avenue SW, Calgary, AB, T2P 2H5 Search for other works by this author on: GSW Google Scholar Mark Obermajer Mark Obermajer Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Search for other works by this author on: GSW Google Scholar Author and Article Information Martin G. Fowler Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Lavern D. Stasiuk Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Mark Hearn Shell Canada Ltd., 400 - 4 Avenue SW, Calgary, AB, T2P 2H5 Mark Obermajer Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Publisher: Canadian Society of Petroleum Geologists Received: 12 Sep 2000 Accepted: 16 Nov 2000 First Online: 02 Mar 2017 Online ISSN: 2368-0261 Print ISSN: 0007-4802 © The Society of Canadian Petroleum Geologists Bulletin of Canadian Petroleum Geology (2001) 49 (1): 117–148. https://doi.org/10.2113/49.1.117 Article history Received: 12 Sep 2000 Accepted: 16 Nov 2000 First Online: 02 Mar 2017 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn MailTo Tools Icon Tools Get Permissions Search Site Citation Martin G. Fowler, Lavern D. Stasiuk, Mark Hearn, Mark Obermajer; Devonian hydrocarbon source rocks and their derived oils in the Western Canada Sedimentary Basin. Bulletin of Canadian Petroleum Geology 2001;; 49 (1): 117–148. doi: https://doi.org/10.2113/49.1.117 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentBy SocietyBulletin of Canadian Petroleum Geology Search Advanced Search Abstract Devonian strata within the Western Canada Sedimentary Basin contain large reserves of oil and gas. These vast hydrocarbon reserves can be largely attributed to the occurrence of abundant mature, excellent to good quality Devonian source rocks. The Middle Devonian Elk Point Group contains several units with hydrocarbon potential including the Evie Formation in British Columbia, the Keg River Formation in northern Alberta, and the Winnipegosis Formation in east-central Alberta and southern Saskatchewan. Many of these are proven source rocks of oils occurring in Middle Devonian reservoirs. Elk Point Group potential source rocks contain a wide variety of organic matter types reflecting the diversity of their depositional environments. No hydrocarbons have been definitively linked to a Beaverhill Lake Group source rock but it is possible that such a unit is the source of Slave Point Formation reservoired oils in northwest Alberta. The Late Devonian Woodbend Group contains the Duvernay Formation, the most prolific Devonian source rock in the Alberta Basin. It is characterized by marine Type II/I organic matter with TOC contents up to 15% in immature samples and is the source of most oils in the Bashaw Reef Complex, the Rimbey-Meadowbrook Reef Trend, and in the Swan Hills Formation in Alberta. The stratigraphically equivalent Muskwa Formation in northern Alberta has a much lower hydrocarbon potential than the Duvernay Formation. Oils have been correlated to Winterburn Group source rocks within the Nisku Formation of east-central Alberta, Camrose Member/Nisku Formation of southern Alberta, and the time-equivalent Birdbear Formation of southeast Saskatchewan. Winterburn Group potential source rocks in central to southern Alberta can have high TOC contents (up to 15%) and contain Type I and Type II organic matter deposited in open marine to lagoonal palaeoenvironments. The Cynthia Member shale of the Nisku Formation in west-central Alberta, previously thought by some workers to be a source rock, is actually organic-lean. The underlying Bigoray Member is more organic-rich and may be a minor contributor to hydrocarbons in the West Pembina area. The Wabamun Group contains no regionally extensive potential source rocks. Almost all the oil generated from Devonian source rocks appears to have remained within Devonian-aged reservoirs and very little is biodegraded. In contrast, where Exshaw Formation sourced oil is found in Devonian reservoirs, such as in the Grosmont and Nisku formations in the vicinity of the Athabasca Mannville Group bitumen deposit (i.e. “Carbonate Trend”), it tends to be biodegraded. You do not have access to this content, please speak to your institutional administrator if you feel you should have access.

ABSTRACT: Sedimentary Architecture of the Fluvial Devonian Reservoirs in the Illizi Basin (Algeria)

ABSTRACT: Sedimentary Architecture of the Fluvial Devonian Reservoirs in the Illizi Basin (Algeria)

Late Laramide dolomite recrystallization of the Husky Rainbow "A" hydrocarbon Devonian reservoir, northwestern Alberta, Canada: paleomagnetic and geochemical evidence

The Rainbow Field is in reefal carbonates of the Middle Devonian Keg River Formation in the Western Canada Sedimentary Basin. Alternating field and thermal step demagnetization was done on specimens from unoriented core from a vertical, an inclined, and a horizontal well core in the dolomite reservoir. Although they had no viscous remanent magnetization component to use for orientation, most specimens had a well-defined characteristic remanent magnetization (ChRM) that resides in single to pseudosingle domain magnetite. By rotating the mean ChRM direction around its core axis, a small circle can be generated for each core and the small circles intersect in the true ChRM direction of D = 168°, I = -73.5o (α95 = 5.8°, k = 32.2). Its paleopole of 164°E, 83°N (A95 = 10°) defines a Tertiary age with one sigma limits of Middle Eocene to Middle Miocene age. Petrographic examination defines four generations of dolomite. Matrix dolomite has 60-100 µm diameter crystals that were later recrystallized to 200-400 µm. Dolomite cements are represented by vug-filling coarse dolomite (100-200 µm) and saddle dolomite (1000 µm). All four generations of dolomite give similar δ18O values of -10.7 to -16.5‰ (Peedee Belemnite, PDB), δ13C values of +0.7 to +3.2‰ (PDB), and Sr isotopic ratios of 0.70826 to 0.70846 that do not match the expected Middle Devonian carbonate or seawater values. We interpret these data to indicate that mixed pre-Laramide basinal fluids, heated by burial during the Laramide Orogeny, were present during late Laramide time when the dolomites were recrystallized and (or) precipitated prior to petroleum migration and accumulation in the Rainbow "A" reservoir. Thus the combined use of paleomagnetism, geochemistry, and petrography has been proven to be a useful technique to date and identify dolomitization events and pathways for the migration of hydrocarbons.

ABSTRACT: Middle Devonian Reservoirs of Ontario: Rediscovering a Historic Play Using Modern Methods and Technology

ABSTRACT: Middle Devonian Reservoirs of Ontario: Rediscovering a Historic Play Using Modern Methods and Technology

Late Laramide dolomite recrystallization of the Husky Rainbow "A" hydrocarbon Devonian reservoir, northwestern Alberta, Canada: paleomagnetic and geochemical evidence

Late Laramide dolomite recrystallization of the Husky Rainbow "A" hydrocarbon Devonian reservoir, northwestern Alberta, Canada: paleomagnetic and geochemical evidence

Oil Families and Their Potential Sources in the Northeastern Timan Pechora Basin, Russia

Oil and rock samples collected throughout the northeastern Timan Pechora basin identify key oil families and correlate these oil families to stratigraphic units that sourced them based on distinctive molecular characteristics. Three distinctive hydrocarbon systems have been identified within the northeastern Timan Pechora basin. Hydro carbons, both oil and gas, are found in clastic and carbonate reservoirs from the Lower Silurian to the Triassic. Three major oil families have been identified based on physical properties, gas chromatography, liquid chromatography, and gas chromatography- mass spectrometry. Family A oils are found in Permian-Silurian reservoirs within the Sorokin swell and Upper Devonian reservoirs within the eastern and western edges of the Khoreyver depression. This oil family is sourced from an Upper Devonian bitumen-laminated carbonate mudstone informally known as the domanik facies. Family B oils are found only in Upper Devonian reservoirs within the central Khoreyver depression. This oil family is most likely sourced from Upper Devonian hypersaline marine mudstones with significant bacterial input. Many of the family B oils were generated at temperatures less than that for peak oil generation. Family C oils are found in Carboniferous-Lower Devonian reservoirs within the northern Sorokin swell. This family is sourced from marine mudstones that have Gloecapsamorpha prisca, as well as other marine algae, present. Organic-rich Lower Devonian and Silurian shales contain similar molecular characteristics and are potential sources for the family C oils.

Geochemistry and Origin of Some Natural Gases in the Plateau Province, Central Appalachian Basin, Pennsylvania and Ohio

The Appalachian Plateau is a large, elongate structural basin in the western part of the central Appalachians. In western Pennsylvania and eastern Ohio, the Plateau is a mostly wet gas (mean C{sub 2}-C{sub 5}/C{sub 1}-C{sub 5}=6.08%) district which has produced approximately one-third of all the natural gas produced in the entire Appalachian basin. We sampled gases from 22 wells and 5 cores to determine the possible utility of stable isotope geochemistry for interpreting the origin of the gases and correlating them with their probable sources. Methane {delta}{sup 13} C and {delta}C and {delta}D values range from -55.1 to -27.24% and -303 to -150% respectively. Corresponding ethane and propane values of selected samples range from -41.79 to -29.61% and -38.21 to -26.71%. Several gas samples exhibit isotopic reversals amoung the C{sub 1} to C{sub 3} hydrocarbons. The isotope data provide some potential insight into the origin of these gases and the timing and direction of their migration into different reservoirs. With few exceptions, the gases we analyzed are secondary, i.e. mixtures of gases varying origins or primary gases (original gas from a single, active source rock) which were altered by geological processes. Most samples originated as associated thermogenic gases generated frommore » Types I/II kerogens at source rock maturities ranging from early mature to overmature. Coalbed gases and some Upper Devonian gases appear to be mixtures of thermogenic and microbial hydrocarbons. We interpret several other gases from various Cambrian through Devonian reservoirs as mixtures of thermogenic gases.« less

Thirtyone Formation, Permian Basin, Texas: Structural and Lithologic Heterogeneity in a Lower Devonian Chert Reservoir&amp;nbsp;

Chert and carbonate reservoirs of the Early Devonian Thirtyone Formation comprise a major regional reservoir in the Permian basin, with more than 700 Mbbl production to date and roughly an equal amount of potentially producible reserves remaining. Most major pools in the Thirtyone Formation were discovered several decades ago and are now in relatively advanced stages of enhanced recovery, with significant variation apparent in response to waterflooding among different fields. As shown by comparison between Dollarhide and Three Bar fields, reservoirs display significant heterogeneity due to structure and to depositional/diagenetic factors affecting porosity development. Most studies of these fields to date have tended to emphasize depositional and diagenetic factors as the reason for observed variation in enhanced recovery performance; however, structural factors may be of nearly equal importance. Enhanced recovery at Dollarhide field, for example, has been extremely successful, with waterflood recoveries more than double those under primary production, and a tertiary CO2 flood expected to do nearly as well. This extraordinary level of success is understood as a result of a combination of reservoir character and compartmentalization, with the latter especially related to division of the field into several fault block portions. Mapping of these fault blocks and their related structures has been greatly advanced by a recent 3-D (three-dimensional) seismic survey. Ultimate recovery at Dollarhide is projected at 62% of original oil in place. In comparison, production history at Three Bar field shows a lower level of overall recovery, yet a very similar increase between primary and secondary production. Reservoir heterogeneity related to depositional/diagenetic factors appears more pronounced at Three Bar field than at Dollarhide field, but faulting is also significant with respect to division of the field into separate blocks with distinct productive histories. A 3-D seismic survey may provide important discriminating data useful for a future CO2 flood or other tertiary recovery project at Three Bar field.