FACIES, DIAGENESIS, AND RELATED RESERVOIR PROPERTIES IN THE GIGAS BEDS (UPPER JURASSIC), NORTHWESTERN GERMANY

1965 ◽  
pp. 124-168 ◽  
Author(s):  
VOLKMAR SCHMIDT
Keyword(s):  
Upper Jurassic ◽  
Reservoir Properties

Geologic Characteristics of Reservoir Accumulation in Suganhu Depression in North Margin of Qaidam Basin

2012 ◽  
Vol 616-618 ◽  
pp. 19-25 ◽  
Author(s):  
Cheng Zhang ◽  
Guang Yang ◽  
Yong Shu Zhang
Keyword(s):  
Organic Matter ◽  
Middle Jurassic ◽  
Qaidam Basin ◽  
Upper Jurassic ◽  
Mature Stage ◽  
Braided River ◽  
Large Area ◽  
Reservoir Properties ◽  
Cap Rock ◽  
Low Porosity

Based on the analysis and testing data of rocks, the basic geologic characteristics of Suganhu depression is discussed. It is concluded that the 200m thickness dark mudstone of inshore shallow lake face in the middle–lower Jurassic stratum is the only source rock of this region. It has the characteristics of high abundance of organic matter and in high mature stage. And the type of organic matter is Ⅱ2.The reservoir properties is controlled by the influences of both the sedimentation and the diagenesis and belong to the low porosity and low permeability ones. The mudstone of Upper Jurassic is the local cap, the ones of braided river face and braided river delta face which existed in the up-middle of the middle Jurassic can be qualified as sealing bed between the sand bodies. Paleocene–eocene mudstone is the regional cap rock. The ability of upper Jurassic sealing bed is good because of the low porosity and permeability and high break pressure. The regional cap rock has the characteristics of big thickness and large area. Both the local and regional cap rock had been able to seal the petroleum and gas before the time of hydrocarbon accumulation of middle Jurassic. In general, Mesozoic formed reservoir–cap combination with the features of lower–generation and upper–reservoir, upper–cap.

The Dunlin Field, Blocks 211/23a and 211/24a, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 95-102 ◽  
Author(s):  
A. Baumann ◽  
B. O'Cathain
Keyword(s):  
North Sea ◽  
Middle Jurassic ◽  
Upper Jurassic ◽  
Reservoir Properties ◽  
Oil Accumulation ◽  
Western Margin ◽  
Shetland Islands ◽  
Fault Block ◽  
Delta System ◽  
Cumulative Production

AbstractThe Dunlin Oilfield is located in the East Shetland Basin, 160 km northeast of the Shetland Islands. It lies in UK Blocks 211/23a and 211/24a in about 500 ft of water. The field was discovered in June 1973 by well 211/23-1. The oil accumulation is trapped, in a north-south oriented, tilted fault block at the western margin of the Viking Graben, at a depth of about 8500 ft TVSS. The reservoir is contained in the formations of the Middle Jurassic Brent Group. In the Dunlin area they form a 450 ft thick sequence of sands and intercalated minor shales, which has been deposited by a shore face and delta system prograding northwards across the Viking Graben. The seal is formed by the shales of the Middle/Upper Jurassic Heather Formation. Reservoir properties of the Brent sands are fair to good with porosities of up to 30% and average permeabilities in the range from 10 to 4000 md. Development of the field is carried out from a single platform, from which production started in 1978. To date 40 development wells have been drilled and the total cumulative production amounts to 282 MMBBL of an ultimate recovery of 363 MMBBL.

scholarly journals PETROGRAPHIC CHARACTERISTICS OF THE RESERVOIR ROCKS IN THE BAT-UPPER JURASSIC DEPOSITS OF THE SOUTH OF WESTERN-SIBERIAN PETROLEUM BASIN

2019 ◽  
Vol 2 (1) ◽  
pp. 25-31
Author(s):  
Lyudmila Vakulenko ◽  
Aleksey Popov ◽  
Sergey Rodyakin ◽  
Evgeniy Khabarov ◽  
Peter Yan
Keyword(s):  
Oil And Gas ◽  
Upper Jurassic ◽  
The South ◽  
Reservoir Properties ◽  
Petrographic Composition ◽  
Reservoir Rocks ◽  
Regional Sources ◽  
Porosity And Permeability ◽  
Maximum Parameters ◽  
Petroleum Basin

The features of the petrographic composition of the bath-upper Jurassic silt-sand rocks exposed by wells in the South of the West Siberian oil and gas basin are considered. The study is focused on the parameters that had a significant influence on the reservoir properties of rocks: granulometric and mineral-petrographic composition of the clastic part of rocks, cement content, structure and composition. Some conclusions are drawn on the spatial distribution of rocks of different composition within the subisochronous sedimentary complexes. It is assumed that significant variations in their composition are caused by a complex combination of varying degrees of interdependent factors: influence of local and regional sources of clastic material, peculiarities of redistribution of material during its transportation and sedimentation, and post-sedimentation changes. Most variable values of reservoir properties, with a recorded maximum parameters of porosity and permeability are obtained for the rocks of Medium-Upper Oxford complex on Verkhnetarskaya, Dedovskaya, Basinskaya, Veselovskaya, to a lesser extent, Kasmanskaya, Vostochnaya and Tai-Dasskaya drilling sites.

scholarly journals Sedimentology, geochemistry and reservoir properties of Upper Jurassic deep marine sediments (Hareelv Formation) in the Blokelv-1 borehole, Jameson Land Basin, East Greenland

2018 ◽  
pp. 39-64
Author(s):  
Morten Bjerager ◽  
Claus Kjøller ◽  
Mette Olivarius ◽  
Dan Olsen ◽  
Niels H. Schovsbo
Keyword(s):  
Oxygen Depletion ◽  
Upper Jurassic ◽  
High Density ◽  
Core Analysis ◽  
Reservoir Properties ◽  
East Greenland ◽  
Sea Floor ◽  
The Core ◽  
Trace Metal Content ◽  
Porosity And Permeability

The fully cored Blokelv-1 borehole was drilled through Upper Jurassic strata in the central part of the Jameson Land Basin, central East Greenland. The borehole reached a total depth of 233.8 m with nearly 100% recovery of high-quality core. An extensive analytical programme was undertaken on the core; sedimentological interpretation and reservoir characterisation were based on facies analysis combined with conventional core analysis, bulk geochemistry and spectral gamma and density scanning of the core. The Upper Jurassic Hareelv Formation was deposited in relatively deep water in a slope-to-basin setting where background sedimentation was dominated by suspension settling of organic-rich mud in oxygen-depleted conditions. Low- and high-density gravity-flow sandstone interbeds occur throughout the cored succession. About two-thirds of the high-density turbidite sandstones were remobilised and injected into the surrounding mud-rock. The resulting succession comprises nearly equal amounts of mudstones and sandstones in geometrically complex bodies. Ankerite cementation occurs in 37% of the analysed sandstones in varying amounts from minor to pervasive. Such ankerite-cemented sandstones can be identified by their bulk geochemistry where Ca > 2 wt%, Mg > 1 wt% and C > 1 wt%. The analysed mudstones are rich in Al, Fe, Ti and P and poor in Ca, Mg, Na and Mn. The trace-metal content shows a general increase in the upper part of the core reflecting progressive oxygen depletion at the sea floor. The reservoir properties of the Blokelv-1 sandstones were evaluated by both conventional core analysis and using log-derived porosity and permeability curves. The high-density turbidite beds and injectite bodies are a few centimetres to several metres thick and show large variations in porosity and permeability, in the range of 6–26 % for porosity and 0.05–400 mD for permeability. Individual sandstone units that are 1–7 m thick yield a net vertical reservoir thickness of 40 m with porosities of 15–26% and permeabilities of 1–200 mD. Heterolithic sandstone–mudstone units are generally characterised by poor reservoir quality with porosities of 2–14% and permeabilities of 0.1–0.6 mD.

The Statfjord Field, Blocks 33/9, 33/12 Norwegian sector, Blocks 211/24, 211/25 UK sector, Northern North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 335-353 ◽  
Author(s):  
K. A. Gibbons ◽  
C. A. Jourdan ◽  
J. Hesthammer
Keyword(s):  
North Sea ◽  
Water Injection ◽  
Upper Jurassic ◽  
Lower Jurassic ◽  
Oil Field ◽  
Reservoir Properties ◽  
Water Alternating Gas ◽  
Net To Gross ◽  
Northern North Sea ◽  
Dipping Strata

AbstractThe Statfjord Field, the largest oil field in the Northern North Sea, straddles the Norway/UK boundary and is located on the southwestern part of the Tampen Spur within the East Shetland Basin. The accumulation is trapped in a 6-8° W-NW dipping rotated fault block comprised of Jurassic-Triassic strata sealed by Middle to Upper Jurassic and Cretaceous shalesReserves are located in three separate reservoirs: Middle Jurassic deltaic sediments of the Brent Group, Lower Jurassic marine-shelf sandstones and siltstones of the Dunlin Group; and Upper Triassic-lowermost Jurassic fluviatile sediments of the Statfjord Formation. The majority of reserves are contained within the Brent Group; and Statfjord Formation sediments which exhibit good to excellent reservoir properties with porosities ranging from 20-30% permeabilities ranging up to several darcies, and an average net-to-gross of 60-75%. The sandstones and siltstones of the Dunlin Group have poorer reservoir properties where the best reservoir unit exhibits an average porosity of 22%, an average permeability 300 raD and net-to-gross of 45%Structurally, the field is subdivided into a main field area characterized by relatively undeformed W-NW dipping strata, and a heavily deformed east flank area characterized by several phases of 'eastward' gravitational collapseProduction from the field commenced in 1979 and as of January 2000, 176 wells have been drilled. The oil is undersaturated and no natural gas-cap is present. The drainage strategy has been to develop the Brent and Dunlin Group reservoir with pressure maintenance using water injection and the Statfjord Formation reservoir by miscible gas flood. However, a strategy to improve recovery by implementing water alternating gas (WAG) methods is gradually being implemented for both the Brent and Statfjord reservoirs. Current estimates indicate that by 2015 a total of 666 x 106Sm3 (4192 MMBBL) of oil will be recovered and 75 GSm3 (2.66 TCF) gas will be exported from the field

The Maureen Field, Block 16/29a, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 347-352 ◽  
Author(s):  
P. L. Cutts
Keyword(s):  
North Sea ◽  
Water Injection ◽  
Upper Jurassic ◽  
Reservoir Properties ◽  
Injection Wells ◽  
The North ◽  
Clay Shales ◽  
Gravity Flows ◽  
Production Wells ◽  
The Uk

AbstractThe Maureen Oilfield is located on a fault-bounded terrace in Block 16/29a of the UK Sector of the North Sea, at the intersection of the South Viking Graben and the eastern Witch Ground Graben. The field was discovered in late 1972 by the 16/29-1 well, and was confirmed by three further appraisal wells. The reservoir consists of submarine fan sandstones of the Palaeocene Maureen Formation, deposited by sediment gravity flows sourced from the East Shetland Platform. The Palaeocene sandstones, ranging from 140 to 400 ft in thickness, have good reservoir properties, with porosities ranging from 18-25% and permeabilities ranging from 30-3000 md. Hydrocarbons are trapped in a simple domal anticline, elongated NW-SE, which was formed at the Palaeocene level by Eocene/Oligocene-aged movement of underlying Permian salt. The reservoir sequence is sealed by Lista Formation claystones. Geochemical analysis suggests Upper Jurassic Kimmeridge Clay shales have been the source of Maureen hydrocarbons. Estimated recoverable reserves are 210 MMBBL. Twelve production wells have been drilled on the Maureen Field. A further seven water injection wells have been drilled to maintain reservoir pressure.

Characterisation of a highly heterogeneous geothermal reservoir based on geophysical well logs

2021 ◽  
Author(s):  
Johanna Bauer ◽  
Daniela Pfrang ◽  
Michael Krumbholz
Keyword(s):  
Reservoir Characterization ◽  
Sustainable Use ◽  
District Heating ◽  
Upper Jurassic ◽  
Geothermal Reservoir ◽  
Rock Properties ◽  
Reservoir Properties ◽  
Geophysical Logging ◽  
Matrix Permeability ◽  
Geophysical Well Logs

<p>For successful exploitation of geothermal reservoirs, temperature and transmissibility are key factors. The Molasse Basin in Germany is a region in which these requirements are frequently fulfilled. In particular, the Upper Jurassic Malm aquifer, which benefits from high permeability due to locally intense karstification, hosts a large number of successful geothermal projects. Most of these are located close to Munich and the “Stadtwerke München (SWM)” intends to use this potential to generate most of the district heating demands from geothermal plants by 2040.</p><p>We use geophysical logging data and sidewall cores to analyse the spatial distribution of reservoir properties that determine porosity, permeability, and temperature distribution. The data are derived from six deviated wells drilled from one well site. The reservoir rocks are separated by faults and lie in three different tectonic blocks. The datasets include image logs, GR, sonic velocities, temperature, flowmeter- and mud logs. We not only focus on correlations between rock porosity and matrix permeability, but also on how permeability provided by fractures and karstification correlate with inflow zones and reservoir temperature. In addition, we correlate individual parameters with respect to their lithology, dolomitisation and the rock’s image fabric type, adapted from Steiner and Böhm (2011).  </p><p>Our results show that fracture intensity and orientations vary strongly, between and within individual wells. However, we observed local trends between fracture systems and rock properties. For instance fracture intensities and v<sub>p</sub> velocities (implying lower porosities) are higher in rock sections classified as dolomites without bedding contacts. As these homogeneous-appearing dolomites increase, from N to S, the mean fracture intensities and v<sub>p</sub> velocities also increase. Furthermore, we observed most frequently substantial karstification in dolomites and dolomitic limestones. Nevertheless, an opposing trend for the percentage of substantial karstification can be also found, i.e., the amount of massive karstification is higher in the northern wells. The interpretation of flowmeter measurements show that the main inflow zones concentrate in those Upper Malm sections that are characterised by karstification and/or intense fracturing.</p><p>In the next step, we will correlate laboratory measurements of outcrop- and reservoir samples (e.g. porosity, permeability, and mechanical rock properties) with the logging data. The aim is to test the degree to which analogue samples can contribute to reservoir characterization in the Upper Jurassic Malm Aquifer (Bauer et al., 2017).</p><p>This work is carried out in the research project REgine "Geophysical-geological based reservoir engineering for deep-seated carbonates" and is financed by the German Federal Ministry for Economic Affairs and Energy (FKZ: 0324332B).</p><p>Bauer, J. F., Krumbholz, M., Meier, S., and Tanner, D. C.: Predictability of properties of a fractured geothermal reservoir: The opportunities and limitations of an outcrop analogue study, Geothermal Energy, 5, 24, https://doi.org/10.1186/s40517-017-0081-0, 2017.</p><p>Steiner, U., Böhm, F.: Lithofacies and Structure in Imagelogs of Carbonates and their Reservoir Implications in Southern Germany. Extended Abstract 1st Sustainable Earth Sciences Conference & Exhibition – Technologies for Sustainable Use of the Deep Sub-surface, Valencia, Spain, 8-11 November, 2011.</p>

Log-derived reservoir properties and porosity preservation of Upper Jurassic Arab Formation in Saudi Arabia

1993 ◽  
Vol 10 (4) ◽  
pp. 352-363 ◽  
Author(s):  
K. Magara ◽  
M.S. Khan ◽  
F.A. Sharief ◽  
H.N. Al-Khatib
Keyword(s):  
Saudi Arabia ◽  
Upper Jurassic ◽  
Reservoir Properties
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