3-D Modelling of Geochemical and Reservoir Properties of the Lower Paleozoic Gas/Oil Shale in the Baltic Basin (N Poland)

Abstract

The current paper integrates in a coherent 3D model for the central Baltic Basin (BB) the results of modelling of burial/thermal history, geochemical and reservoir properties of the shale, with the aims to predict oil and gas composition and well production flows. The model is calibrated with data from 20 legacy wells and 9 new exploration wells (including one vertical). Burial depth of the shale reservoir in the studied area increases from NE towards SW, from 2400–3000 m to 4000–4500 m respectively. The same direction reconstructed thickness of the missing section increases, from 1000–1200 m to more than 3000 m, affecting burial and thermal history significantly. A few phases of shale source rock maturation are revealed, though their importance varies laterally. In the major part of the studied area the shale obtained its recent level of maturation during late Mesozoic time, while towards the North the major phase of maturation is of Variscan age. Each of the individual shale reservoir is characterized by relatively low net pay thickness: from a few to 1622 m. The most important Caradoc and Llandovery reservoirs are separated by 8–10 m of Ashgill marly frac barrier, though common fracturing of the both at once aiming production for the two together is a main current challenge. Their average TOC contents is laterally variable, though usually in a range of 2–4%. Thermal maturity of the shale increases from 0.95% Ro in the NW to 2.0–2.5% Ro in the SW, and well correlates with hydrocarbon composition, measured GOR and API. In the NW part light oil and condensate dominate (30–40 API), and GOR is in a range of 100–500. However in the SW part of the area the shale is saturated only with a dry gas. Measured and modelled permeability of the shale reservoir in a range of 4–10%, while permeability is usually 150–250 nD. Brittleness factor is commonly in a range of 0.5–0.7. Gas saturation varies in a section and laterally, though saturations of 50–100 scf/ton are commonly observed. The modelling results indicate that relatively low gas flows from current tests (~10 Mcm/d) are related mainly to the low net pay thickness of the individual formations, and to a presence of liquids in the shale reservoir characterized by the moderate permeability.

AAPG Datapages/Search and Discovery Article #90217 © 2015 International Conference & Exhibition, Melbourne, Australia, September 13-16, 2015