Reservoirs Jurassic

For example, the many deepwater fields located in the Gulf of Mexico are of Tertiary age and are comprised of complex sand bodies which were deposited in a deepwater turbidite sequence. The BP Prudhoe Bay sandstone reservoir in Alaska is of Triassic/ Cretaceous age and was deposited by a large shallow water fluvial-alluvial fan delta system. The Saudi Arabian Ghawar limestone reservoir is of Jurassic age and was deposited in a warm, shallow marine sea. Although these reservoirs were deposited in very different depositional environments they all contain producible accumulations of hydrocarbons, though the fraction of recoverable oil varies. In fact, these three fields are some of the largest in the world, containing over 12 billion barrels of oil each ... 

The Ebro headwaters flow on calcareous substratum, specifically sandstone and calcium marls, from the Triassic, Cretacic, and Jurassic. During the Quaternary, at the plain of La Virga (Reinosa), a shallow lake accumulated the deposits of siliceous sandrocks. This old highland lake is now the Embalse del Ebro reservoir. From that point downstream to Conchas de Haro the main channel flows on calcareous rocks from the Cretacic, highly resistant to the erosion. 

The reservoir rocks that yield crude oil range in age from Precambrian to Recent geologic time but rocks deposited during the Tertiary, Cretaceous, Permian, Pennsylvanian, Mississippian, Devonian, and Ordovician periods are particularly productive. In contrast, rocks of Jurassic, Triassic, Silurian, and Cambrian age are less productive and rocks of Precambrian age yield petroleum only under exceptional circumstances. 

The concentrations of potassium in the samples obtained from the Norphlet Formation in the central Mississippi Salt Dome Basin are those expected from the Louann Salt bittern potassium values in other samples obtained from reservoirs of Jurassic age are lower by a factor of —2 (Kharaka et al., 1987). The decrease in the dissolved potassium in these samples is attributed to the formation of authigenic illite and potassium feldspar (Carpenter et al., 1974 Kharaka et al., 1987). 

Aagaard P., Egeberg P. K., Saigal G. C., Morad S., and Bj0rlykke K. (1990) Diagenetic albitization of detrital K-feldspars in Jurassic, Lower Cretaceous, and Tertiary clastic reservoir rocks from offshore Norway 11. Formation water chemistry and kinetic considerations. J. Sedim. Petrol. 60, 575-581. 

Girard J.-P. (1998) Carbonate cementation in the Middle Jurassic Oseberg reservoir sandstone, Oseberg field, Norway a case of deep burial-high temperature poikilotopic calcite. In Carbonate Cementation in Sandstones. Distribution Patterns and Geochemical Evolution (ed. S. Morad). International Association of Sedimentologists, Oxford, vol. 26, pp. 285-308. 

Figure 3.10 Observed groundwater pressures in Jurassic and Triassic carrier-reservoir rocks in the Viking Graben, North Sea (based on data presented by Buhrig, 1989, in Fig. 6, p, 38, Marine and Petroleum Geology, Vol. 6. Reproduced by permission of the publishers, Butterworth Heinemann Ltd. ).

Liewig, N., Clauer, N. and F. Sommer, 1987. Rb-Sr and K-Ar dating of clay diagenesis in Jurassic sandstone oil reservoir. North Sea. The American Association of Petroleum (Geologists Bulletin, Vol. 71, no. 12, pp. 1467-1474 Lloyd, J.W. and G. Jacobson, 1987. The hydrogeology of the Amadeus Basin, Central... 

In cases where detailed stratigraphies are unknown, or difficult to model, such as the Upper Jurassic and Lower Cretaceous, both of which contain potential reservoir sandstones, it is still possible to gain a good approximation of fault seal probability using... 

Pore pressure gradients are very difficult to estimate with the same accuracy in shales outside the reservoir zones, where RFT or DST measurements are impossible. We have, however, estimated pressure gradients in three wells on the border between the Melke and Gam Formations, based on the drilling data in Fig. 5. We have attempted to calculate the flow of water from the overpressured Upper Jurassic and Lower Cretaceous shales, into the underlying Middle Jurassic sandstones. The main uncertainty in... 

Bjprlykke, K, Aagaard, P., Dypvik, H., Hastings, D.S. and Harper, A S. 1986. Diagenesis and reservoir properties of Jurassic sandstones from the Haltenbanken Area, offshore mid Norway. In E. Holter, A M. Spencer, C.J. Campbell, S.H. Hanslien, P.H.H. Nelson, E. Nysaether and E.G. Ormaasen (Editors), Habitat of Hydrocarbons on the Norwegian Continental Shelf. Graham Trotman, London, pp. 275-286. 

The field is covered by high quality 3-D seismic and has been delineated by seven wells. Four wells proved to have producible hydrocarbons in marginal marine, heterogenous sandstone reservoirs of Early-Middle Jurassic age (Tilje and lie Formations). 

Within single reservoir units, formation pressure data indicate lateral stepwise increasing overpressures from approximately 70 bar above hydrostatic in the south-east to approximately 120 bar in the north-west, controlled by major northeast trending sealing faults, which subdivide the Njord structure into a series of hydraulic compartments. There is also a stepwise formation pressure increase with depth, corresponding to Triassic and Jurassic stratigraphic boundaries. 

Residual hydrocarbons within the Triassic and hydrocarbon shows within the Cretaceous overburden support the concept of a dynamic model with an element of active vertical flux through the Jurassic sequences implying breaching of the reservoir top seal and vertical leakage. 

The relationships between the pore-pressures of the Jurassic reservoirs, the estimated overburden pore pressures and the formation integrity trends of the structure are taken to suggest that capillary entry pressures (membrane seal failure), possibly in combination with cap rock microfracturing, are the main controlling mechanisms for vertical leakage. 

The main reservoir unit is the Lower Jurassic Tilje Formation, which has its shallowest depth at 2700 m MSL and proven oil down to 3098 m MSL (Fig. 3). Recoverable oil reserves are estimated to be 32 MS m. The secondary He reservoir contains a saturated oil accumulation with a free gas cap. 

The pore-pressure profiles further show that pressure equalization has been reached between the Jurassic reservoirs and the lowermost Cretaceous-Upper Jurassic caprock of the Njord structure as there is no drop in pressure when entering into the Jurassic reservoir units (as seen in many other fields on Halten-banken Koch and Heum, 1995). 

Fig. 14. Relationships between pore-pressures, the hydrostatic gradient, the fracture pressure gradient (approximation to the minimal horizontal stress, Sf,) and the lithostatic pressure gradient (approximation to the vertical stress, S ). Pore-pressures from sea floor to base Pliocene equals hydrostatic. The yellow, dark blue and red pore-pressure trend-lines represent the pore-pressure versus depth gradients for the Paleocene-Eocene, Mid-late Cretaceous and Upper Jurassic-lowermost Cretaceous, respectively. The portion of the red trend-line below approximately 2550 m MSL equals the maximum reservoir pore-pressure trend-line of Fig. 13 and reflects the counter-pressure of the topseal controlling the pore-pressure distribution of hydraulic compartments II, III and (probably) IV.

The apparent pressure equalization between the Jurassic reservoirs and the lowermost Cretaceous-Upper Jurassic cap rock, and the vertical distribution of oil and gas shows (Fig. 4) provides clear indications of vertical leakage from the Njord structure. This is further supported by the indications of vertical fluid flux upwards through the Triassic-Jurassic sequences as discussed above. 

For apexes below 3500 m, i.e., the deepest subcompartments of the north Hank, there is an increased possibility of actual breaching (vertical fracturing) of the Spekk Formation cap rock. This could cause direct coupling between the Jurassic reservoirs (overpressured to the extent controlled by the Spekk Formation prior to breaching) and the overlying less overpressured Lower Cretaceous semi-permeable silty (occasionally sandy) claystones. Once attained, this situation might be expected to cause relatively dramatic pulses of vertical leakage (e.g., Mandl and Harkness, 1987). 

It is reasonable to assume that ineffective seals are the cause of exploration failure where porous water-wet reservoirs occur in clearly defined closures, and where the reservoirs are also in direct contact with mature, organic-rich source rocks. We refer to these as proven seal failures. Accordingly, seal failure can be proven in only seven cases, all of which are associated with young inversions. One reason for this is that most exploration wells have not been drilled deep enough to prove or disprove the presence of sealed reservoirs underlying the thick Upper Jurassic claystones that occur in many inversion structures. 

In Canada, the town of McMurray, about 240 miles north-north-east of Edmonton, Alberta lies at the eastern margin of the largest accumulation in the world There are, in effect, three major accumulations within the Lower Cretaceous deposits. The McMurray-Wabasca reservoirs are found toward the base of the formation and the deposit dips at between 5 ft and 25 ft per mile (1.5 m and 8 m per mile) to the south-west. The Bluesky-Gething sands overlie several unconformities between the Mississippian and Jurassic deposits. 

Morad, S. (1990) Mica alteration reactions in Jurassic reservoir sandstones from the Haltenbanken area, offshore Norway. Clays Clay Miner., 38, 584-590. 

Morton, N. (1993) Potential reservoir and source rocks in relation to Upper Triassic to Middle Jurassic sequence stratigraphy, Atlantic margin basins of the British Isles. In Petroleum Geology of Northwest Europe. Proceedings of the 4th Conference (Ed. Parker, J.R.), pp. 285-297. London. 

Nystuen, J.P. Falt, L.-M. (1995) Upper Triassic-Lower Jurassic reservoir rocks in the Tampen Spur area, Norwegian North Sea. In Petroleum Exploration in Norway, Vol. 4 (Ed. Hanslien, S. et al). Norwegian Petroleum Society. Elsevier, Amsterdam, 41 pp. 

Calcite-cemented layers and lensoid concretions commonly form low-permeability barriers in shallow marine reservoir sandstones. In the porous and permeable Lower Jurassic Luxemburg Sandstone such calcite-cemented lenses form permeability barriers with lateral continuities of a few decimetres to hundreds of metres. Deposition of these sandstones ( 90 m thick) occurred in a wave- and storm-reworked tidal delta that formed where a seaway through the Ardennes and Rhenish Massifs entered the shallow Paris basin. 

Searl, a. (1994) Diagenetic destruction of reservoir potential in shallow marine sandstones of the Broadford Beds (Lower Jurassic), north-west Scotland deposi-tional versus burial and thermal history controls on porosity destruction. Mar. Petrol Geol, 11, 131-147. 

Carbonate cementation in the Middle Jurassic Oseberg reservoir sandstone, Oseberg field, Norway a case of deep burial-high temperature poikilotopic calcite... 

Carbonate cement of variable mineralogy (siderite, calcite, dolomite and ankerite) is a common diagenetic feature in North Sea Jurassic reservoir sandstones (e.g. Saigal Bjorlykke, 1987 Walderhaug et al., 1989 Bjorlykke et al., 1992 Giles et al., 1992 ... 

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