Peter Frykman

Permeability, compressibility and porosity of Jurassic shale from the Norwegian–Danish Basin

The Fjerritslev Formation in the Norwegian–Danish Basin forms the main seal to Upper Triassic–Lower Jurassic sandstone reservoirs. In order to estimate the sealing potential and rock properties, samples from the deep wells Vedsted-1 in Jylland, and Stenlille-2 and Stenlille-5 on Sjælland, were studied and compared to samples from Skjold Flank-1in the Central North Sea. Mineralogical analyses based on X-ray diffractometry (XRD) show that onshore shales from the Norwegian–Danish Basin are siltier than offshore shales from the Central Graben. Illite and kaolinite dominate the clay fraction. Porosity measurements obtained using helium porosimetry–mercury immersion (HPMI), mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) techniques on the shale samples show that MICP porosity is 6–10% lower than HPMI or NMR porosity. Compressibility, from uniaxial loading, and elastic wave velocities were measured simultaneously on saturated samples under drained conditions at room temperature. Uniaxial loading tests indicate that shale is significantly stiffer in situ than is normally assumed in geotechnical modelling. Permeability can be predicted from elastic moduli, and from combined MICP and NMR data. The permeability predicted from Brunauer–Emmett–Teller (BET)-specific surface-area measurements using Kozeny’s formulation for these shales, being rich in silt and kaolinite, falls in the same order of magnitude as permeability measured from constant rate of strain (CRS) experiments but is two–three orders of magnitude higher than the permeability predicted from the 1998 model of Yang & Aplin, which is based on clay fraction and average pore radius. When interpreting CRS data, Biot’s coefficient has a significant and systematic influence on the resulting permeability of deeply buried shale.

The history of hydrocarbon filling of Danish chalk fields

It is well established that dynamic conditions expressed as tilted fluid contacts characterize most hydrocarbon accumulations in North Sea Chalk reservoirs. Chalk is a low-permeability, high-porosity rock and properties grade smoothly from reservoir over baffle to seal. The natural dynamic conditions prevail because pressure dissipation takes place through the rockmatrix, as fracture-supported flow often is minimal. The dynamic conditions are imposed by processes occurring on a geological time-scale and result mainly in lateral pressure differences in the water zone and even in lateral pressure differences in the oil zone. Re-equilibration of fluid contacts also occurs on a geological time-scale. These processes are of paramount importance for trap definition and impose severe restrictions on migration distances. Reservoir simulation techniques are applied, in combination with back-stripping, to the simulation of geological time-scale secondary migration and trapping. Flow simulation of the filling dynamics of a chalk reservoir shows a complex filling geometry due to the high capillary entry pressures in the low-permeability chalks. Such internal barriers will re-direct hydrocarbons and residual oil can be left on the migration route. The process of hydrocarbon charging is slow and equilibration of hydrocarbons with respect to pressure gradients, therefore, also occurs very slowly. The Kraka Field and the Dan and Halfdan fields are subjected to studies of primary oil charging and re-migration in this paper and the dynamic oil on Dan Field west flank is successfully mimicked. Results show that a time span in the order of 2 Ma is required for the hydrocarbons to reach the summit in an approximately equilibrium state from a flanking position. However, even dynamic equilibrium may not be fully obtained due to re-perturbation by tectonic movements and changing water zone pressure gradients. Results show that saturation profiles in drilled wells may appear in drainage equilibrium while under partial re-imbibition, which impairs saturation modelling.

Anisotropy in pore networks analyzed with 2-D autocorrelation (variomaps)

Abstract This paper describes a system for generating variomaps (autocorrelation or variance as a topological map) of binary images. The images are produced from plane sections through porous media. The 2-D autocorrelation function is calculated by Fourier transformation. The resulting map of the autocorrelation illustrates the mean porel size and directionality (anisotropy) in the analyzed section. The method has been tested on porespace combined within simulated grain packs, two types of sandstones, and catalyst material. The software is written in Pascal for PC systems and circumvents the DOS 640K barrier, thus enabling the handling of even large images. Calculation time for a 512 × 512 Fourier transform is less than 2 min on a 33 MHz 486 PC.

A visualbasic program for histogram and variogram scaling

The VarScale program (1) calculates dispersion variances for different support volumes, (2) performs variogram and histogram scaling, and (3) performs scaling of a linear model of coregionalization (LMC). The input variogram may be at any scale. The required dispersion variances (or average variogram values) are calculated. User input is automatically passed between different components of the program. This paper describes the theoretical background of the scaling algorithms, the program structure of varScale and presents three examples. Variogram scaling from core scale to well-log scale is illustrated with data from a Danish North Sea reservoir. Histogram and LMC scaling are illustrated with data from a West Texas reservoir using porosity and seismic data.

Pre-drilling assessments of average porosity and permeability in the geothermal reservoirs of the Danish area

Denmark constitutes a low-enthalpy geothermal area, and currently geothermal production takes places from two sandstone-rich formations: the Bunter Sandstone and the Gassum formations. These formations form major geothermal reservoirs in the Danish area, but exploration is associated with high geological uncertainty and information about reservoir permeability is difficult to obtain. Prediction of porosity and permeability prior to drilling is therefore essential in order to reduce risks. Geologically these two formations represent excellent examples of sandstone diversity, since they were deposited in a variety of environments during arid and humid climatic conditions. The study is based on geological and petrophysical data acquired in deep wells onshore Denmark, including conventional core analysis data and well-logs. A method for assessing and predicting the average porosity and permeability of geothermal prospects within the Danish area is presented. Firstly, a porosity-depth trend is established in order to predict porosity. Subsequently, in order to predict permeability, a porosity–permeability relation is established and then refined in steps. Both one basin-wide and one local permeability model are generated. Two porosity-depth models are established. It is shown that the average permeability of a geothermal prospect can be modelled (predicted) using a local permeability model, i.e. a model valid for a geological province including the prospect. The local permeability model is related to a general permeability model through a constant, and the general model thus acts as a template. The applied averaging technique reduces the scatter that is normally seen in a porosity–permeability plot including all raw core analysis measurements and thus narrows the uncertainty band attached to the average permeability estimate for a reservoir layer. A “best practice” technique for predicting average porosity and permeability of geothermal prospects on the basis of core analysis data and well-logs is suggested. The porosity is primarily related to depth, whereas the permeability also depends on porosity, mineralogy and grain size, which are controlled by the depositional environment. Our results indicate that porosity and permeability assessments should be based on averaged data and not raw conventional core analysis data. The uncertainty range of permeability values is significantly lower, when average values are used.

Quantifying Porosity, Compressibility and Permeability in Shale

The Fjerritslev Formation in the Norwegian-Danish Basin forms the main seal to Upper Triassic-Lower Jurassic sandstone reservoirs. In order to estimate rock properties Jurassic shale samples from deep onshore wells in Danish basin were studied. Mineralogical analysis based on X-ray diffractometry (XRD) of shale samples show about 50% silt and high content of kaolinite in the clay fraction when compared with offshore samples from the Central Graben. Porosity measurements from helium porosimetry-mercury immersion (HPMI), mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) show that, the MICP porosity is 9-10% points lower than HPMI and NMR porosity. Compressibility result shows that deep shale is stiffer in situ than normally assumed in geotechnical modelling and that static compressibility corresponds with dynamic one only at the begining of unloading stress strain data. We found that Kozeny’s modelled permeability fall in the same order of magnitude with measured permeability for shale rich in kaolinite but overestimates permeability by two to three orders of magnitudes for shale with high content of smectite. The empirical Yang and Aplin model gives good permeability estimate comparable to the measured one for shale rich in smectite. This is probably because Yang and Aplin model was calibrated in London clay which is rich in smectite.

Determination of Free Water Levels in Low-Permeability Chalk Reservoirs From Logged Saturations

The present paper describes a technique for determination of the free water level (FWL) in low-permeability chalk reservoirs along slanted or horizontal wells from logged saturations and porosities. The calculation is done by utilizing existing empirical correlations for drainage and imbibition capillary pressure curves. For each logged saturation and corresponding porosity the FWL is determined so that the calculated saturation equals the logged value. The method takes into account possible imbibition, which results in a FWL that is shallower than the original paleo FWL. The method has been applied to field data from the North Sea and it is shown that it can capture a tilting water level along a horizontal well. Introduction Low-permeability chalk reservoirs are characterized by high capillary entry pressures and large oil/water transition zones. Estimation of oil-in-place for a reservoir at any given time requires information on the reservoir history, a good description of the capillary pressure behavior and knowledge of the FWL. The latter is typically non-horizontal and free water level gradients of more than 100 m/km have been observed in the North Sea. In general the information about the FWL is very scarce, and consists of sometimes dubious pressure measurements. If measured at all, it is usually done in a few exploration wells only. By means of the present method the FWL may be estimated from saturations and porosities logged in production wells. It is usually assumed that the reservoir is in drainage equilibrium. However, frequently observed residual oil zones indicate that water influx have affected the saturations. (See f. ex. Albrechtsen et al.). The saturation distribution is a result of drainage as well as imbibition processes and its shape may deviate considerably from the shape of a drainage curve. The present method takes into account possible imbibition, which results in a FWL that is shallower than the original paleo FWL. Adams 2,3 presented an empirical model, the Imbibition from Drainage or IFD model, relating imbibition capillary pressure curves to the corresponding primary drainage curves. The IFD method was, however, developed for siliciclastic rocks in the Eromanga Basin in Australia and it appears to be less suited for tight chalk with high capillary entry pressures. A new technique was presented by Bech et al. 4 for the modeling of initial saturations along vertical wells in water wet oil/water reservoirs with large transition zones that are in imbibition equilibrium. The method determines the locations of the existing and the original free water levels and thus the extent of imbibition that the reservoir has undergone by matching calculated and log derived water saturations. The present paper extends this method to non-vertical wells. The capillary pressure curves including the curves representing the scanning between the drainage and imbibition curves are described by analytical expressions as shown in Skjaeveland et al.. Optionally, the scanning may be described by Killoughs method . The drainage capillary pressure shape function, the irreducible water saturation and the capillary entry pressure are modeled by the EQR method . The method is demonstrated on a synthetic example and applied to field data from the North Sea and it is shown that it can capture a tilting water level along a horizontal well. Determination of Present Free Water Level The FWL is determined for each saturation and corresponding porosity logged along the well. It is assumed that the oil accumulation was originally formed through a pure drainage process resulting in a drainage equilibrium saturation distribution and a palaeo free water level. In case that subsequent burial and/or tectonic events have lead to an influx of water, the free water level has risen and a new saturation distribution has emerged in the reservoir. This new saturation distribution is a result of both drainage and imbibition processes and can therefore not be described by a model which assumes drainage equilibrium. The changes in water saturation and FWL is illustrated in Fig. 1 for a constant-porosity vertical well. It is seen that the oil-water contact is unaltered and that a region with residual oil has been left below the rising water table. SPE 105622 Determination of Free-Water Levels in Low-Permeability Chalk Reservoirs From Logged Saturations N. Bech, SPE, P. Frykman, and O.V. Vejbæk, SPE, Geological Survey of Denmark and Greenland, GEUS