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Title: An integrated approach to hydrocarbon reservoir characterisation
Author: Bilsland, Mark Christopher
ISNI:       0000 0004 2694 9767
Awarding Body: Imperial College London (University of London)
Current Institution: Imperial College London
Date of Award: 1989
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In this thesis a method of characterisation of reservoir properties has been achieved by integration of petrophysical, geological and reservoir engineering data, at a variety of scales. This approach to characterisation was developed using the Magnus oil field in the United Kingdom Northern North Sea as an example. The Magnus Sandstone is a coarse clastic submarine fan system within the Upper Jurassic Kimmeridge Clay Formation. The data used in this study was obtained from three main sources : reservoir geology, wireline log data and petrophysical core analysis. Techniques used in this reservoir interpretation included X-ray diffraction of the clay fraction, both secondary and back-scattered scanning electron microscopy, interactive log interpretation, and application of quality control rules for core derived petrophysical data. Using the example of the Magnus oil field, this research has shown that:- Secondary porosity generation by isolated grain solution is common across the Magnus Field. This results in high porosities being preserved, with no significant increase in permeability. Isolated occurrences of the leaching of poikilotopic carbonate cement results in the enhancement of both porosity and permeability. Illitic clay matrix is present throughout the Magnus reservoirsandstones. In the oil leg, detrital illitic clay masses are preserved, whilst in the aquifer these are recrystallised to form characteristically wispy authigenic illite-smectite. This is manifested in the significantly reduced permeability observed in the aquifer. Permeability character is controlled by saturating fluid type. Log derived porosity functions specific to zones of different fluid saturations are used to generate permeability algorithms. Reconciliation of well test derived Kh and Kh derived from the log based algorithms provides an enhanced understanding of effective permeability for application to reservoir simulation scale modelling. The well test Kh values although only 1.5 times lower in the oil zone are up to 35 orders of magnitude lower in the water saturated material, confirming the observed distribution of the authigenic illite-smectite material. By making a thorough integration of routine core analysis data, log derived data and sedimentological data, a basis for the effective design of relevant special core analysis tests using preserved core material can be derived. This work has shown that the integration of reservoir data requires the establishment of a model which recognises the constraints bounding each data set, and which reconciles the extreme variation of the investigative scale of the data from microns in the scanning electron microscope, to millions of cubic metres in well tests.
Supervisor: Archer, John ; Shaw, Harry ; Dawe, Richard Sponsor: BP Petroleum Development
Qualification Name: Thesis (Ph.D.) Qualification Level: Doctoral
EThOS ID:  DOI: Not available