Reservoir quality and rock properties modeling – Triassic and Jurassic sandstones, greater Shearwater area, UK Central North Sea

2015 ◽  
Vol 65 ◽  
pp. 1-21 ◽  
Author(s):  
Thomas R. Taylor ◽  
Mark G. Kittridge ◽  
Peter Winefield ◽  
L. Taras Bryndzia ◽  
Linda M. Bonnell
Keyword(s):  
North Sea ◽  
Rock Properties ◽  
Reservoir Quality ◽  
Central North Sea

The Machar Field, Block 23/26a, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 523-536 ◽  
Author(s):  
Zoë Sayer ◽  
Jonathan Edet ◽  
Rob Gooder ◽  
Alexandra Love
Keyword(s):  
North Sea ◽  
Debris Flows ◽  
Water Injection ◽  
Salt Diapir ◽  
Reservoir Quality ◽  
Complex Interplay ◽  
Light Oil ◽  
High Matrix ◽  
The Uk ◽  
Central North Sea

AbstractMachar is one of several diapir fields located in the Eastern Trough of the UK Central North Sea. It contains light oil in fractured Cretaceous–Danian chalk and Paleocene sandstones draped over and around a tall, steeply-dipping salt diapir that had expressed seafloor relief during chalk deposition. The reservoir geology represents a complex interplay of sedimentology and evolving structure, with slope-related redeposition of both the chalk and sandstone reservoirs affecting distribution and reservoir quality. The best reservoir quality occurs in resedimented chalk (debris flows) and high-density turbidite sandstones. Mapping and characterizing the different facies present has been key to reservoir understanding.The field has been developed by water injection, with conventional sweep in the sandstones and imbibition drive in the chalk. Although the chalk has high matrix microporosity, permeability is typically less than 2 mD, and fractures are essential for achieving high flow rates; test permeabilities can be up to 1500 mD. The next phase of development is blowdown, where water injection is stopped and the field allowed to depressurize. This commenced in February 2018.

scholarly journals Organic content and maturation effects on elastic properties of source rock shales in the Central North Sea

2019 ◽  
Vol 7 (2) ◽  
pp. T477-T497 ◽  
Author(s):  
Jørgen André Hansen ◽  
Nazmul Haque Mondol ◽  
Manzar Fawad
Keyword(s):  
Elastic Properties ◽  
Source Rock ◽  
North Sea ◽  
Empirical Relation ◽  
Organic Content ◽  
Rock Properties ◽  
Geochemical Data ◽  
Well Log ◽  
Seismic Properties ◽  
Central North Sea

We have investigated the effects of organic content and maturation on the elastic properties of source rock shales, mainly through integration of a well-log database from the Central North Sea and associated geochemical data. Our aim is to improve the understanding of how seismic properties change in source rock shales due to geologic variations and how these might manifest on seismic data in deeper, undrilled parts of basins in the area. The Tau and Draupne Formations (Kimmeridge shale equivalents) in immature to early mature stages exhibit variation mainly related to compaction and total organic carbon (TOC) content. We assess the link between depth, acoustic impedance (AI), and TOC in this setting, and we express it as an empirical relation for TOC prediction. In addition, where S-wave information is available, we combine two seismic properties and infer rock-physics trends for semiquantitative prediction of TOC from [Formula: see text] and AI. Furthermore, data from one reference well penetrating mature source rock in the southern Viking Graben indicate that a notable hydrocarbon effect can be observed as an addition to the inherently low kerogen-related velocity and density. Published Kimmeridge shale ultrasonic measurements from 3.85 to 4.02 km depth closely coincide with well-log measurements in the mature shale, indicating that upscaled log data are reasonably capturing variations in the actual rock properties. Amplitude variation with offset inversion attributes should in theory be interpreted successively in terms of compaction, TOC, and maturation with associated generation of hydrocarbons. Our compaction-consistent decomposition of these effects can be of aid in such interpretations.

Regional study of controls on reservoir quality in the Triassic Skagerrak Formation of the Central North Sea

2017 ◽  
Vol 8 (1) ◽  
pp. 125-146 ◽  
Author(s):  
M. Akpokodje ◽  
A. Melvin ◽  
J. Churchill ◽  
S. Burns ◽  
J. Morris ◽  
...  
Keyword(s):  
North Sea ◽  
Clay Content ◽  
Reservoir Quality ◽  
Primary Control ◽  
Regional Study ◽  
Thin Sections ◽  
Porosity Evolution ◽  
Heterogeneous Reservoirs ◽  
Low Degree ◽  
Central North Sea

AbstractAn improved understanding of the controls on reservoir quality is key to ongoing and future exploration of the Central North Sea Triassic play. This paper presents a regional integrated study of 50 000 ft of wireline log data, 10 000 ft of core, 4431 routine core analyses measurements and 377 thin sections from 86 cored wells.Triassic Skagerrak Formation sandstones represent thin-bedded heterogeneous reservoirs deposited in a dryland fluvial–lacustrine setting. Fluvial-channel facies are typically fine–medium grained and characterized by a low clay content, whilst lake-margin terminal splay facies are finer grained, more argillaceous and micaceous. Lacustrine intervals are mud-dominated. Primary depositional textures retain a primary control on porosity evolution through burial. Optimal reservoir quality occurs in aerially and stratigraphically restricted fluvial-channel tracts on the Drake, Greater Marnock, Puffin and Gannet terraces, and the J-Ridge area. These primary textural and compositional controls are overprinted by mechanical compaction, the development of early overpressure and diagenesis. Anomalously high porosities are retained at depth in fluvial sandstones that have a low degree of compaction and cementation, including chlorite. Forward modelling of reservoir quality using Touchstone™ software has been validated using well UK 30/8-3 where reservoir depths are >16 000 ft TVDSS (true vertical depth subsea).

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

2003 ◽  
Vol 20 (1) ◽  
pp. 587-601 ◽  
Author(s):  
Peter M. Chandler ◽  
Barbara Dickinson
Keyword(s):  
North Sea ◽  
Upper Jurassic ◽  
Salt Dome ◽  
Reservoir Quality ◽  
Shelf Area ◽  
Clay Formation ◽  
Central North Sea

abstractThe Maureen field comprises the Maureen, Mary and Morag Accumulations, the reservoirs being Palaeocene Sandstones, Upper Jurassic sandstones and Permian dolomites respectively. The field lies about 10 km NNE of the Moira Palaeocene field. Maureen was discovered in 1973, came on-stream in 1983 and produced 217.4 MMBBL (from an estimated STOIIP of 397 MMBBL). The field ceased production in October 1999. It is trapped in a four-way dip closure over a salt dome and scaled by the overlying Lista Formation mudstones. The reservoir is up to 450 ft gross thickness, with core porosity from 18-28% and good sand connectivity. Morag was discovered in 1979. came on-stream in 1991 and produced 2.6 MMBBL before being shut-in in 1994. It produced from clean fractured dolomites in a stratigraphic trap. Mary was discovered and came on-stream in 1991. The initial well died after 1 year. A later well was put on-stream in 1997. Mary produced 2.83 MMBBL before final shut-in in June 1999. Reservoir quality is reasonable, but sand distribution is problematic. All the oils are sourced from the Kimmeridge Clay formation on the adjacent Maureen Shelf area.

A new parameter set for anisotropic multiparameter full-waveform inversion and application to a North Sea data set

Geophysics ◽  
2016 ◽  
Vol 81 (4) ◽  
pp. U25-U38 ◽  
Author(s):  
Nuno V. da Silva ◽  
Andrew Ratcliffe ◽  
Vetle Vinje ◽  
Graham Conroy
Keyword(s):  
North Sea ◽  
Waveform Inversion ◽  
Real Data ◽  
Model Parameters ◽  
Full Waveform Inversion ◽  
Radiation Patterns ◽  
Data Set ◽  
Full Waveform ◽  
Seismic Image ◽  
Central North Sea

Parameterization lies at the center of anisotropic full-waveform inversion (FWI) with multiparameter updates. This is because FWI aims to update the long and short wavelengths of the perturbations. Thus, it is important that the parameterization accommodates this. Recently, there has been an intensive effort to determine the optimal parameterization, centering the fundamental discussion mainly on the analysis of radiation patterns for each one of these parameterizations, and aiming to determine which is best suited for multiparameter inversion. We have developed a new parameterization in the scope of FWI, based on the concept of kinematically equivalent media, as originally proposed in other areas of seismic data analysis. Our analysis is also based on radiation patterns, as well as the relation between the perturbation of this set of parameters and perturbation in traveltime. The radiation pattern reveals that this parameterization combines some of the characteristics of parameterizations with one velocity and two Thomsen’s parameters and parameterizations using two velocities and one Thomsen’s parameter. The study of perturbation of traveltime with perturbation of model parameters shows that the new parameterization is less ambiguous when relating these quantities in comparison with other more commonly used parameterizations. We have concluded that our new parameterization is well-suited for inverting diving waves, which are of paramount importance to carry out practical FWI successfully. We have demonstrated that the new parameterization produces good inversion results with synthetic and real data examples. In the latter case of the real data example from the Central North Sea, the inverted models show good agreement with the geologic structures, leading to an improvement of the seismic image and flatness of the common image gathers.

Triassic-age salt tectonics of the Central North Sea

2014 ◽  
Vol 2 (4) ◽  
pp. SM19-SM28 ◽  
Author(s):  
John F. Karlo ◽  
Frans S. P. van Buchem ◽  
Jan Moen ◽  
Katie Milroy
Keyword(s):  
North Sea ◽  
Lateral Displacement ◽  
Salt Tectonics ◽  
Structural Relief ◽  
Tectonic Style ◽  
Thermal Doming ◽  
Central North Sea ◽  
Extensional Structures

The framework of salt tectonics in the Central North Sea was set early in the Triassic. We defined and illustrated five major domains of differing salt tectonic style. The differing structural styles were all interpreted as having evolved under a component of lateral displacement pairing extensional and contractional structures, produced by some combination of decoupled rift extension and gravity sliding. However, the extensional structures are located toward the basin center and the contractional structures near the original updip limits of salt. This suggests a framework driven by gravity sliding of the sediments overlying the Zechstein away from the Central Graben. Possible mechanisms for structural relief away from the Central Graben are the Triassic focus of rifting lying further east at the Norwegian-Danish basin, footwall uplift of a Triassic Central Graben precursor and significant thermal doming occurring much earlier than had previously been thought. The mechanisms are not mutually exclusive and may have acted in concert.

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