Unconventional resources

Unconventional resources are hosted in fine-grained reservoirs that are enriched in organic carbon. The play can be either thermogenic, where the shale has been deeply buried and thus matured to oil and gas level, or biogenic, where the shale has been degraded by microbes whereby gas was generated. A systematic description of the shale layers is a pre-requisite for a uniform and scientific-based assessment of the shale resource systems. As a first important step, screening criteria are provided below for evaluating any shale. The selection criteria in the table cover both thermogenic and biogenic shale-gas plays.

For thermogenic plays, the selection criteria are chosen to ensure that the right TOC type is present (marine types I-II) in significant volumes (>2% and 20 m thick), that the unit has a significant thickness (>20 m), that the thermal maturity is high enough to ensure generation of HC (at least oil maturity), and that the present-day reservoir has maintained its integrity (present-day depth at least 1.5 km and low to medium structural complexity). Present-day depth larger than 7 km is used to exclude shales that are not within reach of the well bore.

Shale section in southern Sweden.
Shale section in southern Sweden.
Selection criteria for biogenic and thermogenic shale plays. Only maximum thermal maturity and maximum depth cut-offs are applied since both biogenic gas and thermogenic oil and gas plays may be relevant.

For biogenic plays, the criteria are similar to those used for thermogenic plays with respect to TOC and thickness cut-offs. The preferential maturity range for this play is immature-to-wet-gas maturation since the biogenic gas generation depends on depth, biodegradable kerogen and/or bitumen within the shale. Loss of reservoir integrity is typically a requirement for biogenic gas production. This is typically formed in structural complex settings, such as in glacier-induced fractured shales, where microbial activity occurs due to the addition of freshwater into the shale system. Accordingly, basins with biogenic gas shale plays will be rather shallow and hence screened by applying a maximum depth cut-off of 1 km. The structural complexity is typically medium to high for this play type.

Services

  • Characterisation of shales and play definition
  • Estimation of unconventional resource base and identification of main risk components
  • Sweet-spot analysis
  • Organisation of field trips to Lower Palaeozoic shale outcrops in southern Sweden (Scania) and on the Danish island of Bornholm

Rock typing in shales and shaly reservoirs by multivariate data analysis

Shale intervals are naturally heterogenetic so it requires careful analysis of the rock sequence to select the right interval for optimal well-bore placement and stimulation.

For such purposes, GEUS provides principal component analysis (PCA) rock typing defined from properties such as XRF-XRD and/or wireline-log responses.

The PCA is a multivariate data analytical approach. The rock types are not distinguished by their sedimentary facies (i.e. process dependent) but are defined rather by a series of functional properties. 

The HH-XRF apparatus in function.
The HH-XRF apparatus in function. 

A PCA model transforms a matrix of measured values into sets of projection sub-spaces delineated by principal components (each a linear combination of all P variables), which display variance-maximised interrelationships between samples and variables, respectively. The PCA-defined rock types help to:

  1. Reduce the lithological heterogeneity of the reservoir-section classes
  2. Provide the highest possible rock-type resolution at prospective intervals
  3. Reduce the rock-type resolution at non-prospective intervals

Services

  • Geochemical characterisation of relevant sections by high-resolution scanning of cores, cuttings and outcrop samples using handheld XRF apparatus
  • Rock typing by means of principal component analysis (PCA) on geochemical and/or wireline-log data such as flex log or lithoscanner log
  • Calculation and prediction of log responses including prediction of dynamic rock modulus

Processes at the oil/water contact and water type characteristic in reservoirs

General description of the topic

Microbial-mediated carbonate cementation is a result of degradation of organic carbon and the subsequent production of bicarbonate. The process provides an additional source of carbonate cement that may form localised around sites of high microbial activity such as the oil/water contact in a hydrocarbon reservoir or even at the gas/water contact. The source of microbial-mediated cement has a characteristic isotope signature with respect to δ13C, which makes it possible to identify this source of cement. In combination with δ13C, the oxygen isotope signature (δ18O) of the carbonate cement may provide a relative timing of the cementation process with respect to the thermal history (reservoir temperature) or hydrodynamic events. The presence of a cemented oil/water and/or gas/water contact may have huge impact on the reservoir performance since the cementation may create baffling zones and may lead to compartmentalisation of the reservoir. Therefore, knowledge of the microbial processes that are likely to have occurred in a reservoir is of importance when production is planned and when history matching is made in a reservoir simulation.

Relevant competences

GEUS has since 2009 worked on characterising the microbial-mediated carbonate cement in sandstone reservoirs in the North Sea and along the Norwegian continental shelf. The principal senior staff involved from GEUS’ side has been Niels Schovsbo that holds a PhD degree in geochemistry and have more than 10 years of experience in using geochemistry in reservoir characterisation. Relevant competences comprise:

  1. Regional understanding of microbial isotope signature in the Danish part of the North Sea
  2. Best practice of sampling of isotopically heterogenic carbonates
  3. Isotope database of microbial end-member characteristics from the reservoirs in the Danish North Sea

Niels Hemmingsen Schovsbo

Senior Researcher
Reservoir Geology
Phone: +45 91333759