Petrophysical and geochemical characterization of potential unconventional gas shale reservoirs in the southern Karoo Basin, South Africa

International Journal of Coal Geology 212 (2019) 103249

Contents lists available at ScienceDirect

International Journal of Coal Geology journal homepage: www.elsevier.com/locate/coal

Petrophysical and geochemical characterization of potential unconventional gas shale reservoirs in the southern Karoo Basin, South Africa

T

Steffen Noltea, , Claire Geelb, Alexandra Amann-Hildenbranda, Bernhard M. Kroossa, Ralf Littkea ⁎

a

Institute of Geology and Geochemistry of Petroleum and Coal, Energy and Mineral Resources Group (EMR), RWTH Aachen University, Lochnerstr. 4-20, Aachen D52056, Germany b Department for Geoscience, University of Cape Town, Upper Campus, University Avenue, Rondebosch, Cape Town 7701, South Africa

ARTICLE INFO

ABSTRACT

Keywords: Karoo Basin Permian black shales Hydrocarbon potential Porosity Permeability Gas storage capacity

Ten Permian black shale samples from the southern Karoo Basin (South Africa) were investigated regarding their shale gas generation potential, storage capacity and transport properties. Samples originate from a 671 m deep borehole (KZF-1), comprising the Collingham, Whitehill and Prince Albert Formations of the lower Ecca Group (Karoo Supergroup). Based on organic geochemical analyses (TOC, TS, Rock-Eval pyrolysis and vitrinite reflectance), the Whitehill Formation was deposited under anoxic marine depositional conditions and has reached high thermal maturity. The Collingham and Prince Albert Formation were deposited under suboxic to oxic conditions. The amount of total organic carbon (TOC) across all formations ranges between 0.5 and 6.1 wt.-%, and was highest for the Whitehill Formation samples. The organic matter in the different lithologies are highly overmature with vitrinite reflectance values around 4.0% VRr, and almost absent Rock-Eval S1 and S2 peaks. Peak gas generation probably occurred due to tectono-metamorphic overprinting during the Cape Orogeny (240–270 Ma). Permeability ranges from 10−22 to 10−19 m2 (1–100 nDarcy) and is lowest for the Whitehill and Prince Albert Formation. Porosity at ambient stress ranges from 4.1 to 6.3% and is highest within the Whitehill Formation. Neither permeability nor porosity show significant dependence upon induced stress. Excess sorption capacity is highest for the Whitehill Formation, nexcess10MPa ranging from 0.079 to 0.172 mmol/g. For the depth interval investigated here (671 m), the estimated total gas storage capacity (sum of free and adsorbed gas phase) of the Whitehill Formation is approximately 400 to 465 mol CH4 per m3 rock. Using a simple one-dimensional diffusion model, we calculated the potentially remaining stored amount of gas. In a modelled best-case scenario, it is assumed that dissipation of the gas only occurs through the side boundaries (fractured dykes system) whereas top and bottom are assumed to act as perfect seals. Assuming a fracture distance of 1000 m, the model predicts complete gas dissipation to take place within a period of 10−2 to 102 Ma. Regarding the peak gas generation at 240–270 Ma, the remaining shale gas potential is therefore considered extremely low.

1. Introduction The oil and gas industry's interest in unconventional hydrocarbon plays has increased during the last decades. Conventional energy sources are declining while renewable energy sources, such as solar and wind power, cannot cover the growing global energy demand yet. South Africa's motivation to revive hydrocarbon exploration is driven by its current energy demand and rising electricity costs (Twine and Jackson, 2012; Geel et al., 2015; De Kock et al., 2016). In 2017, South Africa's total primary energy consumption consisted of coal (68%), oil (24%), natural gas (3%), nuclear energy (3%), renewables (1%) and hydroelectricity (< 1%) (BP Statistical Review of World Energy, 2018).

⁎

In consideration of a national climate change policy, South Africa faces a major challenge in managing a balancing act between providing sufficient, affordable energy and the need to reduce greenhouse gas emissions (Menyah and Wolde-Rufael, 2010). Based on this premise, natural gas can be considered an alternative pathway to meet climate change and energy supply requirements (Colombo et al., 2016). Unconventional reservoirs are defined as rocks with exceptional low permeabilities. Shales (or mudstones) are heterogeneous formations, which commonly exhibit intrinsic permeability coefficients in the range from nDarcy to μDarcy (Ghanizadeh et al., 2014). They are composed of extremely fine-grained particles, which are primarily clay (< 2 μm) and secondarily silt (< 63 μm) (Passey et al., 2010). As part of evaluating

Corresponding author. E-mail address: [email protected] (S. Nolte).

https://doi.org/10.1016/j.coal.2019.103249 Received 27 March 2019; Received in revised form 17 July 2019; Accepted 18 July 2019 Available online 19 July 2019 0166-5162/ © 2019 Elsevier B.V. All rights reserved.

International Journal of Coal Geology 212 (2019) 103249

S. Nolte, et al.

gas shale plays, either conventional or unconventional, petrophysical characterization of transport properties and gas storage capacity are inevitable. Since unconventional plays are source and reservoir rock at once, geochemical examination of thermal maturation, hydrocarbon potential, kerogen type and depositional environment are essential. In recent years, oil companies have become interested in the shale gas potential of the South African Karoo Basin. Early investigations by SOEKOR (Southern Oil Exploration Corporation (Pty) Ltd) were realized in the southern basin in the context of a conventional drilling campaign that commenced in the 1960's (Rowsell and De Swardt, 1976). Since 2015, two drilling campaigns have been completed by the KARIN (Karoo Research Initiative) project in the Western (KZF-1) and Eastern (KWV-1) Cape, respectively. Open file reports of both boreholes, including i.e. detailed core descriptions, are provided by De Kock et al. (2016, 2017). Core samples from borehole KZF-1 were used in this present study. Recent studies (Geel et al., 2013; Geel et al., 2015; Black et al., 2016; De Kock et al., 2016; De Kock et al., 2017; De Wit, 2018) were implemented in the Eastern and Western Cape with the focus on black shales of the Permian lower Ecca Group, primarily the organic-rich Whitehill, and secondarily the Prince Albert and Collingham Formation's. Geel et al. (2013, 2015) and Black et al. (2016) report geochemical and petrophysical data of the lower Ecca Group originating from wells situated in the Eastern Cape close to the Cape Fold Belt. Potential reserve estimations of the Karoo Basin by Decker and Marot (2012) range from 0.91 to 13.73 Tcm (trillion cubic meters) of recoverable GIP (gas in place), representing low to high case scenarios. In this present study, we investigated gas shales, originating from the South African Karoo Basin, in order to primarily assess their gasstorage potential and transport properties. Core samples of the three lower most formations of the Ecca Group (Prince Albert, Whitehill and Collingham Formation's) are target for shale gas exploration due to their high TOC content. Secondarily, source rock characterization was done by conducting total organic carbon (TOC) and total sulfur (TS) determination, Rock-Eval pyrolysis and vitrinite reflectance analysis. Petrophysical properties were investigated by single-phase gas permeability and pore volume measurements at different stress levels, as well as excess sorption capacity measurements. These measurements have never been performed on all three formations of the Lower Ecca Group within the scope of a study. Pore volume and sorption results were used to calculate total gas storage capacity at standard boundary conditions. For estimates of the present-day storage potential, a simple one-dimensional diffusion model was developed, which yields information about the time required for 100% reservoir depletion.

The depositional environment during the Karoo sedimentation (ca. 300 to 180 Ma) shifted from a glacial period to arid conditions, which was mainly caused by tectonism and climate change attributed to the gradual northward movement of Gondwana (Smith, 1990; Catuneanu et al., 2005). As stated by Johnson et al. (1996), the deposition of the Karoo strata occurred in glacial, deep marine, shallow marine, deltaic, fluvial, lacustrine and aeolian environments. The depositional environment of the Permian Ecca Group was initially dominated by marine conditions but progressed into fluvialdeltaic conditions and consists mostly of shales and sandstones (Smith, 1990; Catuneanu et al., 2005; Johnson et al., 2006). The lower Ecca Group comprises the Prince Albert, Whitehill and Collingham Formation. The Prince Albert strata, which consist of dropstones at the base, mudstones, shales and minor sandstones, was deposited during open marine conditions (Visser, 1993; Johnson et al., 2006; Tankard et al., 2012; Geel et al., 2015). The overlying Whitehill Formation is primarily composed of carbonaceous, fine-grained, finely laminated, organic-rich black shales which comprise pyrite-bearing layers and dolomite lenses at the base. The deposition of the Whitehill black shales occurred under anoxic conditions during a period of absent tectonic activity and during a major transgression event (Visser, 1993; Johnson et al., 2006; Geel et al., 2013; Black et al., 2016; Götz et al., 2018). The continuously succeeding Collingham Formation was deposited in a deep marine to subaerial environment. According to Viljoen (1992, 1994), the Collingham Formation was deposited in a shelf to basin plain depositional environment. Palaeo-environment conditions changed from marine to lacustrine and anoxic to oxic in the Collingham Formation with the inflow of freshwater and sediment laden turbidity currents (Viljoen, 1994). The deposits consists of fine-grained, dark grey mudstones and minor sandstones. These sediments often exhibit intercalations of thin tuff layers (Smith et al., 1993; Johnson et al., 2006; Geel et al., 2015; Black et al., 2016). The strata in the center of the basin are tabular and undeformed. In the south the sediments are strongly deformed, containing predominantly north-verging structures, attributed to the formation of the Cape Fold Belt around 250 Ma. The deformation patterns along and across the Cape Fold Belt vary significantly, indicating complex, multistage deformation events (paroxysms). With at least two major foldand-thrust events each at different angles, the relationship between folding and thrusting seems very complex (Du Toit, 1954; Theron, 1962; Smith, 1990; Booth and Shone, 2002; Black et al., 2016; Linol and De Wit, 2016). Intensified erosion during post-Gondwana time affected the upper part of the Karoo succession, with remaining youngest preserved sediments varying from Triassic to Middle Jurassic age (Catuneanu et al., 2005). Compressional tectonics resulted in duplication and thrust faulting detected in borehole KZF-1 (Fig. 1; De Kock et al., 2017). Similar structural features are identified in Karoo rocks in close proximity to CFB (e.g. De Wit and Ransome, 1992; Booth and Shone, 2002). The breakup of Gondwana (180–160 Ma) initiated the inversion of thrust faults and east-west striking normal and strike-slip faults (Du Toit, 1954; Theron, 1962; De Wit and Ransome, 1992; Booth and Shone, 2002; Booth, 2009; Tankard et al., 2012; Dhansay et al., 2017). Structural deformation may have facilitated routes for gas escape. The Whitehill Formation is described across the basin as a décollement zone, which likely occurred during later stages of the CFB orogeny. The black shale is frequently disrupted by micro-faults, folds and soft sediment deformation (Kingsley, 1981; Lindeque et al., 2007).

2. Geological setting and deposition of the Karoo sediments The South African Karoo Basin covers an area of around 600,000 km2 and is bound by the Cape Fold Belt in the South. The Karoo Basin is an intracratonic foreland basin. It was originally interpreted as a retro-arc foreland trough formed by northward subduction of the palaeo-Pacific plate beneath Gondwana. Recent studies show this viewpoint to be controversial with southward subduction possible (Catuneanu et al., 1998; Lindeque et al., 2011; Tankard et al., 2012; Hansma et al., 2015). Further, the basin is filled with a continuous succession of Karoo Supergroup sediments, which are divided into five stratigraphic groups, starting with the oldest: Dwyka, Ecca, Beaufort, Stormberg and Drakensberg. The onset of the Karoo sediment deposition across Gondwana began in the Pennsylvanian (late Carboniferous, ca. 300 Ma) during the assembly of Pangea and lasted until the breakup of Gondwana in the Early Jurassic (ca. 180 Ma) (Johnson et al., 1996; Catuneanu et al., 2005; Tankard et al., 2012). The end of the Karoo sedimentation was terminated by the emplacement of dolerite sills and dykes of the Karoo Large Igneous Province, which mainly intruded into the Ecca and Beaufort Groups (Svensen et al., 2006; Aarnes et al., 2011; Burgess et al., 2015; Geel et al., 2015).

3. Materials and methods 3.1. Samples Ten fine-grained, homogeneous black shale samples from the southwestern Karoo Basin were derived from a 671 m deep borehole (KZF-1) which is located around 170 km northeast of Cape Town 2

International Journal of Coal Geology 212 (2019) 103249

S. Nolte, et al.

Fig. 1. Stratigraphic column of borehole KZF-01 displaying lithologies and their stratigraphic assignment. The approximate stratigraphic positions, from where the provided samples originate, are indicated in green. Map of South Africa indicating borehole location. Note: structural duplication, represented by two intercalated layers of the Prince Albert within the Whitehill Formation, as a result of thrust faulting. Fault gouge/brecciation detected between formations. (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

(Fig. 1) (32°50′30.43″ S, 19°44′33.02″ E). The well was drilled near the Cape Fold Belt, where the Prince Albert, Whitehill and Collingham Formation (L. Permian) occur near the surface. Initial sample information is summarized in Table 1. A lithostratigraphic log of borehole KZF-1 (Fig. 1) indicates the horizons from which the samples were

extracted. Compressional tectonics resulted in duplication and thrust faulting detected in borehole KZF-1 (De Kock et al., 2017). Furthermore, structural duplication and folding of the basal Ecca Group, which was caused by the Cape Orogeny, is evidently shown by two intercalated layers of the Prince Albert within the Whitehill Formation.

Table 1 Formation, depth, orientation with respect to bedding, moisture condition and dimensions of the plugs analyzed in this study. Sample

KZF01P KZF02P KZF03P KZF04P KZF05P KZF06P KZF07P KZF08P KZF09P KZF10P

Formation

Collingham Collingham Collingham Whitehill Whitehill Whitehill Whitehill Whitehill Prince Albert Prince Albert

Depth [m]

376 404 417 426 447 455 474 488 553 594

Plug properties Orientation

Moisture Cond.

Length [mm]

Diameter [mm]

Perpendicular N/A Perpendicular Perpendicular Parallel Perpendicular Perpendicular N/A N/A Perpendicular

Dry N/A Dry Dry Dry Dry Dry N/A N/A Dry

13.05 N/A 14.73 16.91 37.16 14.75 9.21 N/A N/A 17.56

37.72 N/A 37.81 37.69 25.42 37.79 37.80 N/A N/A 37.94

N/A = not available. 3

International Journal of Coal Geology 212 (2019) 103249

S. Nolte, et al.

All experiments were carried out on material originating from the same specimen. Rock-Eval pyrolysis, sulfur and carbon determination were performed on air-dried and pulverized sample material. For vitrinite reflectance, polished sections were prepared by embedding small cuttings perpendicular to bedding in epoxy resin and subsequent polishing. Pore volume and permeability were investigated on core plugs that were drilled either parallel or perpendicular to bedding. Plugs were dried in a vacuum oven at 105 °C. For excess sorption experiments, samples were crushed and then dried in a vacuum oven at 105 °C. Geochemical methods were applied on all samples, whereas petrophysical analyses were conducted on selected samples. The mineral composition of the same sample set of borehole KZF-1 was determined via x-ray diffraction. The most abundant mineral groups throughout all formations are quartz (28–68 wt.-%), feldspar (12–38 wt.-%) and clay (4–30 wt.-%). The Whitehill Formation contains variable contents of carbonate (4–55 wt.-%). Raw data is compiled in Appendix A.

bulk

=1

(1)

grain

SPV =

Vpore m

1

=

1

bulk

(2)

grain

3.4.2. Pore volume measurements under controlled stress Applying the method explained in Fink et al. (2017), pore volume measurements under confined stress were performed by helium expansion using the flow cell setup shown in Fig. 2. Within the isostatic flow cell, a sample plug is placed between two stainless steel pistons, each with two capillary tube inlets. The pistons' surfaces directed towards the plug have circular notches acting as flow diverters. Lead foil and a double layer of rubber are encasing the plug to prevent fluid bypass and separate it from the surrounding confining pressure. Stress is applied solely by a confining fluid that pressurizes the plug isostatically. The temperature was controlled at 30 °C ( ± 0.5 °C). Experiments were performed successively at two confining pressure levels (30, then 20 MPa). Helium expansion tests are composed of filling the known reference volume (Vref) between V3 and V4 with helium and subsequently expanding into the void volume (sample cell volume, Vsc) from the top and bottom conduits. Pressures are recorded within Vref and Vsc using piezo-resistive pressure transducers (Keller AG, model: PA-33X). The volume of gas displacement can be determined by means of the ideal gas law. Vpore is calculated by the following equation:

3.2. Organic geochemical analyses (TOC/TIC/TS/Rock-Eval) Total organic carbon (TOC) and total inorganic carbon (TIC) contents were determined using a LiquiTOC II analyzer (Elementar Analysensysteme GmbH, Germany). The heating protocol is as follows: 1) temperature is increased to 550 °C (with approximately 300 °C/min) and kept constant for 600 s. 2) temperature is increased to 1200 °C and held for 400 s. The combusted carbon reacts with the carrier gas O2 to CO2 and is recorded by a non-dispersive infrared detector (NDIR). Total sulfur (TS) content was measured by a LECO S-200 sulfur analyzer. Rock-Eval Pyrolysis was conducted based on the procedure specified in Espitalié et al. (1977) with a Rock-Eval VI Pyroanalyzer (Vinci Technologies). Sample preparation followed the guide-lines by NIGOGA (Weiss et al., 2000). Parameters derived from this analysis were S1, S2, S3, Tmax, Hydrogen Index (HI), Oxygen Index (OI), and Production Index (PI).

Vpore =

ref

eq

eq

sc

Vref

Vsc

(3)

where ρref and ρsc denote the gas density within the reference and sample cell before the expansion, respectively. ρeq denotes the gas density of the equilibrated/connected system after helium expansion. When investigating pore volume under confined stress, the term porosity is not precise enough since the bulk volume is prone to stressinduced compaction, whereas sample mass remains constant. Therefore, Vpore is converted into SPV according to Eq. (2).

3.3. Organic petrography Vitrinite reflectance measurements at a wavelength of 546 nm were carried out on polished sections of random orientation. Cubic zirconium standard (3.125% VRo) was used for calibration. Reflectance microscopy at random orientated vitrinite particles (VRr) was performed using a Zeiss Axioplan incident light microscope with a Zeiss Epiplan-NEOFLUAR 50×/0.85 oil objective and Zeiss immersion oil (ne = 1.518 at 23 °C). At least 50 vitrinite particles were measured per sample to ensure reliability. Vitrinite anisotropy was investigated by measuring rotational reflectance VRrot with a Zeiss Axio Imager.M2 m equipped with a 50×/ 1.0 Epiplan-NEOFLUAR Oil Pol objective lense, a PI 10×/23 ocular lense and an automated rotating polarizer. The reflectance values were collected at 10° intervals as the polarizer rotates through 180°. A more detailed explanation can be found in Houseknecht and Weesner (1997). Rotational vitrinite reflectance (VRrot) is characterized by several parameters. VRrot denotes the mean of all measured reflectance values through 180° for one particle. VRmin, and VRmax represent the lowest and highest vitrinite reflectance value, respectively. Bireflectance (VRbi) is defined as the difference between VRmax and Rmin.

Pup V1 Pdown

V3 Prc

V2

V4

Sample plug

Gas

3.4. Helium pycnometry/expansion measurements

Confining fluid (Pconf)

3.4.1. Porosity and specific pore volume at unconfined stress Porosity (Φ) and specific pore volume (SPV) were determined from the skeletal volumes measured by helium pycnometry and the bulk volumes calculated from the dimensions of the plugs. SPV is the pore volume (Vpore) normalized to unit sample mass (m). Bulk (ρbulk) and grain (ρgrain) density were used to calculate Φ and SPV according to the following equations:

T = const. Fig. 2. Schematic representations of the isostatic flow cell setup used for permeability and pore volume measurements under stressed conditions. 4

International Journal of Coal Geology 212 (2019) 103249

S. Nolte, et al.

3.5. Permeability under controlled stress

3.6. High-pressure methane sorption measurements

Single-phase gas permeability tests under confined stress conditions were performed using helium as permeating fluid. Experimental setup (Fig. 2) and boundary conditions were the same as used for pore volume measurements under confined stress (3.4.2). Permeability was determined by conducting one of the two non-steady state through-flow techniques: pressure pulse-decay (PPD) or constant downstream pressure (CDP). The PPD method is performed in a closed system with reservoir at the upstream and downstream side of the sample. Prior to each measurement, the system was set to a desired downstream pressure and equilibrated. Hereafter, the upstream pressure was increased, while the downstream pressure initially remained the same. The differential pressure (ΔP) results in a pressure gradient across the sample that declines over time. The pressure decrease/increase was monitored in both reservoirs. For one confining pressure level, five pulse-decay experiments, including a ΔP of 1.2 MPa, were carried out with varying Pup and Pdown, as follows: 1.6–0.4 MPa, 2.0–0.8 MPa, 3.0–1.8 MPa, 3.6–2.4 MPa and 4.2–3.0 MPa. The procedure of the CDP method is similar to the PPD method, but in this case, a pressure pulse was solely applied to the upstream compartment, while the downstream compartment was connected to atmosphere. Hence, gas penetrates the sample and escapes to atmosphere in order to restore equilibration. The ΔP results in a pressure decay in the upstream compartment, which is being recorded. For the evaluation of non-steady state gas permeability experiments, the apparent gas permeability coefficient kgas can be calculated according to the following equation, which is based on fundamental flow equations, as the mass balance equation and Darcy's law (Cui et al., 2009; Ghanizadeh et al., 2014):

High-pressure methane sorption isotherms were measured on dry powder specimen at 45 °C. Sample treatment applied and manometric sorption setup used for this study can be found in Gasparik et al. (2012, 2014) and Shabani et al. (2018). The setup consists of a sample and reference cell, including pressure transducers, which are equally temperature-controlled. Volumes of both empty cells were calibrated by helium expansion. Prior to sample measurements, blank methane expansion tests were conducted in order to reduce systematic errors in instrumentation. Manometric sorption experiments were conducted as described in Gasparik et al. (2012, 2014). The void volume of the sample cell (Vvoid), which denotes the void space that is not allocated by sample powder, is determined by helium expansion since helium is considered a non-sorptive gas. The procedure of sorption measurements comprises repeated filling of the reference cell with methane and expansion into the sample cell. The excess sorption (Gibbs surface excess) is defined as the difference of the total mass of methane transferred into the sample cell (mtotal) and the mass of methane that, according to its density (ρg(Peq, T)), can be stored in Vvoid under corresponding equilibrium pressure (Peq) and temperature (T).

k gas =

cµL

f1APmean

(

1 Vup

+

1 Vdown

)

m excess = mtotal

1+

b Pmean

Vvoid

(6)

Total mass transferred (mtotal) is derived from methane density within the reference cell (Vref) before (ρg(Pini, T)) and after equilibration ((Peq, T)).

mtotal = [ g (Pini , T)

g (Peq , T) ]

Vref

(7)

For practical use and reproducibility, measured excess sorption data is commonly represented by mathematical models that are resting upon concepts of the sorption mechanism. A more detailed discussion about the utilization of models and excess sorption functions can be found in Gensterblum et al. (2009, 2010) and Gasparik et al. (2012, 2014). In this study, an adapted 3-parameter excess sorption function, which is based on the Langmuir equation for absolute sorption, yields the best fits to the measured isotherms.

(4)

with μ being the dynamic viscosity, L being the sample length, f1 being the mass flow correction factor, A being the cross-sectional area of the sample, Pmean being the mean pore pressure, Vup and Vdown representing the upstream and downstream volumes, respectively. Parameter c represents the slope of ln(Pup(t) − Pdown(t)) vs. time, which is calculated from the recorded upstream and downstream pressures. One major difference has to be considered between the evaluation of PPD and CDP, which is that Vdown must be specified almost infinite (e.g. 1040 m3) for CDP since it is connected to atmosphere. Slip flow is a non-linear, non-Darcy effect that occurs in small pores at low gas pressures leading to the mean free path lengths of gas molecules to become similar to the pore throat diameters. This condition results in recurrent collisions with the pore walls causing the slip of particular molecules (Klinkenberg, 1941; Soeder, 1988; Rushing et al., 2004; Tanikawa and Shimamoto, 2009; Amann-Hildenbrand et al., 2012; Ghanizadeh et al., 2014; Gensterblum et al., 2015). In consequence of slip flow, the pressure-dependent gas permeability kgas is overestimated. Klinkenberg (1941) observed this phenomenon and demonstrated a linear relationship between the apparent gas permeability (kgas) and the reciprocal mean pore pressure (Pmean) for dry and porous material. Based on this finding, kgas approaches a limiting value at infinite Pmean. This limiting value is referred to as the intrinsic or Klinkenberg-corrected permeability (k∞) and can be derived from the straight-line intercept on a plot of measured kgas vs. reciprocal Pmean. The Klinkenberg equation is as follows:

k gas = k

g (Peq , T)

n excess (P, T) = nL

P 1 P + PL (T)

g (P, T) a

(8)

In this equation nexcess(P, T) [mmol/g] denotes the excess sorbed amount at pressure P and temperature T, nL [mmol/g] is the maximum Langmuir capacity that corresponds to the ‘absolute’ sorption capacity, PL(T) [MPa] is the Langmuir pressure that corresponds to the pressure at which half of the ‘absolute’ sorption capacity is reached, ρg(P, T) designates the density of the free gas and ρa denotes the density of the adsorbed phase. 4. Results 4.1. Geochemistry (TOC, TIC, TS, Rock-Eval) Measured results for each individual sample are illustrated in Fig. 1. The geochemical analyses of the three stratigraphic formations reveal the highest TS and TOC contents within the Whitehill Formation. Average TOC values for the Collingham, Whitehill and Prince Albert Formation are 1.50, 6.06 and 0.49 wt.-%. TIC values for all formations are below 1 wt.-% apart from KZF07P (6.69 wt.-%) due to its high dolomite content of 55% (Appendix A). An overall, definite correlation between TOC and TIC as well as TOC and TS cannot be observed. Throughout all samples, S1, S2 and S3 values are very low since they do not exceed 0.15 mg HC/g rock, 0.51 mg HC/rock and 0.29 mg CO2/g rock, respectively. The overall Tmax values range from 596 to 609 °C (Fig. 3).

(5)

where parameter b is the gas slippage factor introduced by Klinkenberg. 5

International Journal of Coal Geology 212 (2019) 103249

S. Nolte, et al.

Fig. 3. Results of TS, TOC, TIC and Rock-Eval pyrolysis are illustrated for each sample. Note that the samples are listed according to depth. Raw data of TS, TOC, TIC and Rock-Eval analysis can be found in Appendix B.

4.2. Organic petrography

4.3. Porosity and specific pore volume

The average random vitrinite reflectance, including all samples, is 4.06% VRr. Results of the Collingham, Whitehill and Prince Albert Formation reveal 4.09%, 4.05% and 4.04% VRr on average (Table 2). The large variance between minima and maxima throughout all samples indicates anisotropy and bireflectance of vitrinite particles (Fig. 4a-d). This is supported by the results of rotational vitrinite reflectance VRrot that was measured exemplary on the samples KZF02P and KZF04P. VRmin and VRmax of 3.85 to 4.95% for KZF02P and 3.47 to 4.43% for KZF04P clearly prove the anisotropy of vitrinite particles (Table 2). This is further illustrated by Fig. 5, which displays each rotational reflectance measurement through 180° of polarization angle, revealing a range of approximately 3% to 6% VRrot. For KZF02P and KZF04P, VRbi is 1.10% and 0.97%, and VRrot is 4.45% and 3.90%, respectively. Optical microscopy further revealed solid bitumen in interparticle spaces and as vein fillings (Fig. 4e) in samples of all formations. Furthermore, plenty of euhedral pyrite crystals (recrystallization) were detected within samples of the Whitehill Formation (Fig. 4f).

4.3.1. Pore volume measurements at ambient stress (He-pycnometry) Results of porosity and specific pore volume, deduced from pore volume measurements by helium pycnometry, are compiled in Table 3. Porosities of all intact sample plugs at ambient pressure range from 4.13 to 6.33%. Porosity for the Collingham, Whitehill and Prince Albert Formation spans from 4.37 to 4.90%, 4.25 to 6.33% and 4.13%, respectively. Accordingly, specific pore volume ranges from 0.017 to 0.019 cm3/g, 0.017 to 0.026 cm3/g and 0.016 to 0.017 cm3/g. 4.3.2. Pore volume measurements under confined stress Pore volume measurements at confined stress are presented as porosity and specific pore volume in Table 3. Additionally, Fig. 6 summarizes obtained pore volume results measured at ambient (4.3.1) and confined stress. The Whitehill Formation exhibits the highest average porosities with 3.68% at 30 MPa and 3.96% at 20 MPa confining pressure. Accordingly, the average specific pore volume is 0.015 (0.011 to 0.018 cm3/g) and 0.016 cm3/g (0.013 to 0.019 g/cm3) at 30 and 20 MPa, respectively. Throughout all samples, specific pore volumes are smaller at 30 MPa compared to 20 MPa with the exception of sample KZF07P, where pore volumes are equal. However, the overall

Table 2 Results of random (VRr) and rotational (VRrot) vitrinite reflectance at random oriented particles. Amount of measurements (n) and standard deviation (SD) are included. Sample

Formation

VRrandom n

KZF01P KZF02P KZF03P KZF04P KZF05P KZF06P KZF07P KZF08P KZF09P KZF10P

Collingham Collingham Collingham Whitehill Whitehill Whitehill Whitehill Whitehill Prince Albert Prince Albert

67 65 69 70 66 50 65 66 64 65

VRrotation VRr

SD

[%]

[%]

4.24 4.03 4.01 3.98 4.19 4.01 4.15 3.92 3.97 4.10

0.14 0.22 0.17 0.26 0.21 0.26 0.18 0.16 0.14 0.17

n

N/A 44 N/A 29 N/A N/A N/A N/A N/A N/A

VRrot

SD

VRbi

SD

VRmax

SD

VRmin

SD

[%]

[%]

[%]

[%]

[%]

[%]

[%]

[%]

N/A 4.45 N/A 3.90 N/A N/A N/A N/A N/A N/A

N/A 0.20 N/A 0.36 N/A N/A N/A N/A N/A N/A

N/A 1.10 N/A 0.97 N/A N/A N/A N/A N/A N/A

N/A 0.58 N/A 0.54 N/A N/A N/A N/A N/A N/A

N/A 4.95 N/A 4.43 N/A N/A N/A N/A N/A N/A

N/A 0.35 N/A 0.43 N/A N/A N/A N/A N/A N/A

N/A 3.85 N/A 3.47 N/A N/A N/A N/A N/A N/A

N/A 0.35 N/A 0.45 N/A N/A N/A N/A N/A N/A

N/A = not available. Histograms of random vitrinite reflectance measurements are shown in Appendix C. 6

International Journal of Coal Geology 212 (2019) 103249

S. Nolte, et al.

Fig. 4. Photomicrographs taken in incident white light exemplary for sample KZF04P (Whitehill Formation). (a-d) Overmature vitrinite particle indicating bireflectance and anisotropy at four different polarization angles (0°, 45°, 90° and 135°). (e) Residual solid bitumen in intergranular voids. (f) Pyrite crystals exhibiting euhedral grain shape.

difference between 30 and 20 MPa is minor or even non-existent (KZF07P). The specific pore volume of the Collingham Formation is exceptionally low and dubious with 0.009 cm3/g at 30 and 0.010 cm3/g at 20 MPa confining pressure. Pore volume of sample KZF06P was only determined at ambient and 20 MPa confined stress.

determined for three samples (KZF05P, KZF06P, KZF10P). Hence, apparent gas permeability kgas at a given reciprocal Pmean are presented for comparability. Accordingly, the true permeability k∞ is naturally expected to be even lower. The overall permeability of the Collingham, Whitehill and Prince Albert Formation is in the range of 10−19 to 10−22 m2. Comparing kgas at a reciprocal Pmean value of 1, the Collingham Formation reveals the highest permeability with 10−19 to 10−20 m2, kgas for the Whitehill Formation ranges from 10−20 to 10−22 m2 and for the Prince Albert Formation it is in the range of 10−22 m2. In the case of KZF01P and KZF10P, kgas shows almost no

4.4. Permeability Permeability results are compiled in Table 3. Klinkenberg-corrected permeability coefficients k∞ and associated b-factor could not be

7

International Journal of Coal Geology 212 (2019) 103249

S. Nolte, et al.

6.0

a

5.5

5.5

5.0

5.0

4.5

4.5

VRrot [%]

VRrot [%]

6.0

4.0

4.0

3.5

3.5

3.0

3.0

2.5

2.5

2.0

b

2.0 0

30

60

90 120 Polarizaon angle [°]

150

180

0

30

60

90 120 Polarizaon angle [°]

150

180

Fig. 5. Plot of every rotational reflectance reading vs. polarization angle for KZF02P (a) and KZF04P (b). In both cases, reflectance varies roughly from 3% to 6% VRrot. Table 3 Pore volume (at ambient and confined stress), permeability and methane sorption data for the studied shale samples. Sample

Ambient stress (30 °C, dry)

CH4 excess sorption (45 °C, dry)

Confined stress (30 °C, dry)

SPV [cm3/g]

Φ [%]

nexcess10 MPa [mmol/g]

nL [mmol/g]

PL [MPa]

ρa [kg/m3]

Pconf [MPa]

SPV [cm3/g]

Φ [%]

1/Pmean [MPa−1]

kgas [m2]

k∞ [m2]

b-factor [MPa]

KZF01P

0.017

4.37

0.066

0.109

4.41

511.97

KZF03P

0.019

4.90

N/A

N/A

N/A

N/A

KZF04P

0.025

6.27

0.146

0.256

4.65

421.29

KZF05P

0.023

5.63

0.172

0.254

3.01

584.20

KZF06P

0.026

6.33

0.144

0.205

2.49

549.27

KZF07P

0.017

4.25

0.079

0.111

2.47

601.19

KZF10P

0.016

4.13

N/A

N/A

N/A

N/A

30 20 30 20 30 20 30 20 30 20 30 20 30 20

0.009 0.010 N/A N/A 0.018 0.019 0.011 0.015 0.017 N/A 0.013 0.013 0.010 0.014

2.28 2.54 N/A N/A 4.54 4.90 2.66 3.65 4.12 N/A 3.38 3.32 2.73 3.76

1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00

2.03E-19 2.02E-19 1.66E-20 1.46E-20 8.89E-21 1.01E-20 7.75E-21 4.84E-21 6.94E-22 5.29E-22 7.34E-21 1.42E-20 1.60E-22 1.52E-22

1.67E-19 1.67E-19 1.29E-20 1.21E-20 1.96E-21 2.50E-21 N/A N/A N/A N/A 2.06E-21 4.62E-21 N/A N/A

0.22 0.21 0.25 0.21 3.54 3.05 N/A N/A N/A N/A 2.56 2.03 N/A N/A

N/A = not available.

difference at 30 MPa compared to 20 MPa confining pressure. For KZF04P and KZF07P, kgas is naturally smaller at higher stress levels, whereas kgas for KZF03P, KZF05P and KZF06P is surprisingly higher at 30 MPa compared to 20 MPa confined stress.

0.030

0.025

SPV [cm³/g]

0.020

4.5. Methane sorption isotherms at 45 °C (dry) Methane sorption isotherms (in mmol CH4/g rock) measured on dry samples at 45 °C are presented in Fig. 7. All excess sorption isotherms show a similar shape and reveal a maximum between 10 and 15 MPa. Parameters used for fitting each individual isotherm are reported in Table 3. For reason of comparability, excess sorption at 10 MPa (nexcess10MPa) is reported for each sample. Excess sorption capacity is highest for the Whitehill Fomation (nexcess10MPa ranging from 0.144 to 0.172 mmol/g) with the exception of sample KZF07P (nexcess10MPa = 0.079 mmol/g) which is similarly low as the Collingham Formation (nexcess10MPa = 0.066 mmol/g). Excluding KZF07P, excess sorption at 10 MPa of the Whitehill Formation is more than twice that of the Collingham Formation. A general correlation between TOC content and sorption capacity can be observed.

0.015 KZF01P

0.010

KZF04P

0.005

KZF06P

KZF05P

KZF07P KZF10P

0.000 0

5

10

15 Pconf [MPa]

20

25

30

Fig. 6. Plot illustrating specific pore volume (SPV) vs. confining pressure (Pconf). Differences in SPV between 30 and 20 MPa confined stress are minor.

8

International Journal of Coal Geology 212 (2019) 103249

S. Nolte, et al.

deposition is quantified by doubling the TOC (Uffmann et al., 2012). TS/TOC ratios of all formations are lower than the ‘normal marine’ trend line (Fig. 8a). Therefore, anoxic marine conditions can be excluded since the amount of TS is too low. The amount of TS for the Prince Albert and Collingham Formation is especially low suggesting oxygenated freshwater influence, likely lacustrine depositional conditions (Berner, 1984). Palaeo-environment conditions changed from marine to lacustrine and anoxic to oxic in the Collingham Formation with the inflow of freshwater and sediment laden turbidity currents (Viljoen, 1992, 1994). Findings of the Prince Albert Formation coincide with previous studies indicating deposition in a water body influenced by melting water (deglaciation) (Haldorsen et al., 2001; Geel et al., 2015; Schulz et al., 2016). Samples of the Whitehill Formation reveal a positive, linear correlation between TS and TOC, except for sample KZF05P. The deposition occurred likely in a marine environment since the TS/TOC ratios are relatively high compared to the other formations, which is an indication for anoxia. Moreover, the presence of pyrite, as documented via XRD (Appendix A) and optical microscopy (Fig. 4), is further evidence for microbial sulfate reduction. Previous geochemical studies (Oelofsen, 1986; Visser, 1991; Geel et al., 2015) indicate that environments change from brackish in the Prince Albert to marine in the Whitehill Formation and marine to brackish in the Collingham Formation. The deviation of sample KZF05P might be explained by a short, transitional change in depositional conditions. Based on the low TS/TOC ratio and the high amount of TIC (7.99 wt.-%), oxygenated waters or burial diagenesis promoting carbonate (dolomite) formation are presumed. Deducing the depositional environment and kerogen type based on Rock-Eval results is inconclusive due to very low S2 and S3 values despite high TOC values. Based on the presence of abundant vitrinite in all samples, which is a constituent of terrestrial land plants, it can be inferred that the organic matter within the samples is at least partially of terrestrial origin. Summarizing, all samples were deposited under oxygenated bottom waters, probably lacustrine (Collingham and Prince Albert Fm.) and marine (Whitehill Fm.), but the presence of vitrinite also suggests terrestrial influence.

CH4 excess sorption [mmol/g]

0.20

0.15

0.10

0.05

KZF01P (Col. Fm.; TOC=2.31%) KZF04P (Wh. Fm.; TOC=5.01%) KZF05P (Wh. Fm.; TOC=7.99%) KZF06P (Wh. Fm.; TOC=7.11%) KZF07P (Wh. Fm.; TOC=4.13%)

0.00 0

5

10 15 Pressure [MPa]

20

25

Fig. 7. Excess sorption isotherms for selected samples from the Collingham and Whitehill formations measured in the dry state at a temperature of 45 °C.

5. Discussion 5.1. Depositional environment For the purpose of assessing the environment of deposition, Berner (1984) established an empirical relationship between TS and TOC content which is typical of most marine sediments deposited under aerobic bottom waters (‘normal marine’). This is because the intensity of microbial sulfate reduction is reflected by TS vs. TOC ratios, indicating the redox status of the depositional environment. In order to examine this relationship, the TOC has to be corrected. Due to the overmaturity of all samples, the initial organic carbon content at

5

100.0

a

b

Collingham Fm. Whitehill Fm. Prince Albert Fm.

4

Collingham Fm. Whitehill Fm. Prince Albert Fm.

Excellent

S1+S2 [mg HC/g rock]

TS [wt.-%]

Very good

3

2

10.0 Good

Fair

1.0

Poor

1 KZF05P

0.1

0 0

5

10 2 x TOC [wt.-%]

0.1

15

1.0 TOC [wt.-%]

10.0

Fig. 8. a) TOC (2×) vs. sulfur content for samples of the Collingham, Whitehill and Prince Albert Formation. Due to the overmaturity of samples, it was assumed that TOC values were twice as high before petroleum generation. “Normal marine” line was adapted after Berner (1984). b) Hydrocarbon source potential (S1 + S2) vs. TOC as log-plot showing poor potential for all samples.

9

International Journal of Coal Geology 212 (2019) 103249

S. Nolte, et al.

In comparison to Geel et al. (2013, 2015), who investigated the depositional environment of the lower Ecca Group sediments of the Eastern Cape by means of x-ray fluorescence and C/N stable isotope analysis, the findings of this study only partially match. They conclude that the Prince Albert and Whitehill Formation were deposited in an anoxic environment, whereas the Collingham Formation was formed in shallower oxygenated conditions. A marine depositional setting transforming into an increasingly lacustrine environment is inferred. However, the studies by Geel et al. (2013, 2015) were implemented in the eastern Karoo Basin where significant turbidite deposits are present in the Tankwa Karoo basin (Wickens, 1994) and therefore the Collingham Formation is likely more oxygenated. Additionally, they conclude that kerogen in the Collingham, Whitehill and Prince Albert Formation might be derived from a mixture of kerogen type II and III.

during its orogeny. Maturity of the lower Ecca Group will likely decrease away from metamorphic overprint of the CFB. However, further north in the basin the dolerite intrusions will also affect the maturity and lead to partial degassing of the lower Ecca Group (Cole, 2014; Geel et al., 2015; Smithard et al., 2015). In this case, the Whitehill Formation would still represent the most promising gas source rock due to its high TOC contents. 5.3. Gas storage capacity calculation Gas storage capacity was calculated for the two most promising samples of the Whitehill Formation (KZF05P and KZF06P) by means of specific pore volume (Section 4.3), representing the volumetric (free gas) storage capacity, and excess sorption (Section 4.5). The total gas storage capacity ntotal [mol CH4/m3 rock] is then derived by the following equation:

5.2. Hydrocarbon potential Most samples, especially the ones belonging to the Whitehill Formation, reveal high amounts of TOC and therefore fulfil basic requirements of successful hydrocarbon-bearing rocks. Nonetheless, Rock-Eval results clearly indicate that none of the samples exhibit current or remaining potential for hydrocarbons since both S1 (< 0.15 mg/g) and S2 (< 0.51 mg/g) are very low. This is illustrated by Fig. 8b indicating poor source rock potential. Tmax values range around 600 °C but have to be considered inconclusive due to very low S2 values. Nevertheless, thermal maturity can be deduced by vitrinite reflectance. Random vitrinite reflectance VRr of all samples, as well as rotational reflectance VRrot of KZF02P and KZF04P, is approximately 4%, indicating an advanced stage of overmaturity. The presence of vitrinite anisotropy further supports the high level of thermal maturity. Concluding, richness in TOC and overmaturity indicate that all three formations were probably bearing HCs in the past but are completely depleted nowadays since the organic matter has reached an advanced stage of maturity. As proposed by Geel et al. (2013, 2015), the overmaturity and absence of HCs in the samples are probably caused by the proximity to the Cape Fold Belt and induced thermal overprinting

a 0 0 500 1000

Total gas storage capacity [mol CH4/m³ rock] 300 600 900

ntotal = (SPV

b 0

1200 0

Free gas (unstressed) Free gas (stressed) Excess sorbed gas Total gas (unstressed) Total gas (stressed)

500 1000

(9)

bulk

Total gas storage capacity [mol CH4/m³ rock] 300 600 900

1200

Free gas (unstressed) Free gas (stressed) Excess sorbed gas Total gas (unstressed) Total gas (stressed)

1500 Depth [m]

Depth [m]

2500

+ n excess (P, T))

SPV is the specific pore volume of rock [m3/kg], ρg(P, T) is the molar gas density [mol/m3], nexcess(P, T) is the excess sorption capacity [mol/ kg rock] and ρbulk denotes the bulk rock density [kg/m3]. Furthermore, gas storage capacity was calculated as a function of depth by assuming the following boundary conditions: temperature gradient of 30 °C/km, lithostatic and hydrostatic pressure gradient of 25 and 10 MPa/km, respectively, atmospheric pressure and temperature at earth's surface is supposed to be 0.1 MPa and 20 °C, respectively. Free gas, excess sorbed gas and total gas storage capacity are plotted against depth (Fig. 9). Two approaches were carried out for the free gas estimations, i.e. SPV remains constant (‘unstressed’) and decreases with depth (‘stressed’). For the latter, experimental SPV data at different stress levels was fitted by a power law function. Consequentially, free gas and total gas storage capacities are displayed in the unstressed and stressed state. However, these calculations have to be considered best case scenarios since pore volume and excess sorption measurements were conducted on dry sample plugs and powders, respectively. It was

1500 2000

g (P, T)

Experimental limita!on of effec!ve stress (pore volume)

Experimental limita!on of hydrosta!c stress (sorp!on)

3000

2000 2500

Experimental limita!on of effec!ve stress (pore volume)

Experimental limita!on of hydrosta!c stress (sorp!on)

3000

3500

3500

4000

4000

4500

4500

5000

5000

Fig. 9. Free gas (stressed and unstressed), excess sorbed gas and total gas storage capacity (in mol CH4/m3 rock) for sample KZF04P (a) and KZF05P (b) are plotted as a function of depth. Note: experimental limitations are indicated.

10

International Journal of Coal Geology 212 (2019) 103249

S. Nolte, et al.

shown by several studies (Gasparik et al., 2014; Merkel et al., 2015; Shabani et al., 2018) that water generally reduces gas storage capacity. It has to be noted that the depth-dependence of gas storage capacity is only valid within the experimentally applied effective (pore volume) and hydrostatic (sorption) stress limits. Gas storage capacities are naturally higher at unconfined compared to confined stresses. Fig. 9 illustrates the significance of including stressed pore volume measurements since gas storage capacity is considerably overestimated with increasing depth at unstressed conditions. At extraction depth of KZF04P (426 m) and KZF05P (447 m), stressed and unstressed storage capacities do not vary significantly and ranges from approximately 400 to 465 mol CH4/m3 rock. The total gas storage capacity of the Whitehill Formation might even be higher when found in greater depth. The Karoo Basin is up to 6 km deep in some areas (Lindeque et al., 2007; Lindeque et al., 2011). The effect of induced stress becomes more prominent with increasing depth. For an even more realistic approach, excess sorption measurements ought to be performed on plugs under confined stress, which will decrease storage capacity even further. For both samples, sorptive storage capacity seems to dominate at shallow depth (low pressures), whereas the volumetric (free gas) storage capacity appears to be dominant at greater depth (higher pressures).

was applied. Pressure diffusion (Deming, 1994) describes the propagation of an initiated pressure pulse through a compressible medium. This basic assumptions for the geometry of the system and the initial and boundary conditions are illustrated in Fig. 10a. We assume a homogeneous lithologic sequence, overlain by an effective sealing lithology, bearing a defined amount of gas. No further thermal gas is generated. Lithological seals above and below the reservoir are assumed impermeable. Potential top seals might be dolerite sills further towards the center of the basin. As stated in Section 2, the southern Karoo Basin is characterized by thrust, normal and strike-slip faults. This is evidenced by duplication and thrust faulting observed in borehole KZF-1. We infer a pressure diffusion of the stored gas phase sideward towards adjacent fracture zones, that represent open boundaries for dissipation. We apply the mathematical model of diffusion in a plane sheet (Crank, 1975) that describes the concentration/pressure change within a homogeneous body bounded by two parallel planes. The initial pressure concentration C0 between the two boundaries (−l < x < l) is uniform and the concentrations at the two boundaries, representing the fault or fracture planes, at x = l and x = − l are at a constant concentration C1. Parameter C(x, t) denotes the pressure/concentration throughout the formation over time. The following equation is the solution of the differential equation for diffusion subject to the starting and boundary conditions stated above:

5.4. 1D pressure diffusion model

C(x, t) C0 C1 C0

Due to the rapid heating event, transformation of the organic matter occurred within a short period of time. Therefore, it can be assumed that all three formations reached full gas saturation instantaneously on the geologic timescale. With this starting condition and realistic values for permeability and porosity values one can attempt to estimate the maximum time required until the formation is completely depleted by gas leakage across faults or fractures. Based on the petrophysical laboratory data, a simplified one-dimensional pressure diffusion model

=1

4 n=0

( 1) n exp 2n + 1

D(2n + 1) 2 2t 4l2

cos

(2n + 1) x 2l

(10)

In the present context of pressure diffusion the parameter D represents the hydraulic diffusivity [m2/s], t is the time [s] and l is the reservoir length [m]. Normalized pressure/concentration (

C(x, t) C0 C1 C0

Fig. 10. (a) Sketch illustrating the basic approach of the one-dimensional diffusion model. (b) Concentration distribution at various times within the medium −l < x < l with initial uniform concentration C0 and concentration C1 at the planes/faults (x/l = 1 and − 1). Legend numbers are values of Dt/l2. The reservoir is completely depleted for Dt/l2 = 4.

11

International Journal of Coal Geology 212 (2019) 103249

S. Nolte, et al.

Table 4 Variation of hydraulic diffusivity coefficients as a function of permeability, porosity, viscosity, rock and fluid compressibility. Dmin and Dmax represent worst and best case scenarios, respectively. Permeability k [m2]

Porosity Φ [−]

1.0E-19 1.0E-20 1.0E-21 1.0E-22

0.05

Dynamic viscosity μ [Pas]

1.35E-05

Rock compressibility ɑ [Pa−1]

1.0E-09

B)

Dmax (depth = 9000 m)

6.7E-07 6.7E-08 6.7E-09 6.7E-10

4.8E-06 4.8E-07 4.8E-08 4.8E-09

6. Conclusion

profiles computed with Eq. (10) are shown in Fig. 10b for certain values of dimensionless time (Dt/l2). When Dt/l2 = 0.38 the pressure has declined to 50% of its original value at the center of the diffusion system. At Dt/l2 = 4.00 the reservoir is depleted by essentially 100%. To estimate the time required for complete depletion of the reservoir overpressure resulting from “instantaneous” gas generation a value of Dt/l2 = 4.00 is selected and solved for t with different values (1, 10, 100, 1000 m) for the reservoir length l, since the fracture spacing is unknown. The hydraulic diffusivity coefficient D is calculated from the petrophysical data as follows:

k µ( +

Dmin (depth = 500 m)

The parameters μ, α and Φ are known and can be considered constant since their variations have no significant influence. Gas viscosity, μ, at 100 °C is 1.35−5 Pa·s, α for shales is averaging 10−9 Pa−1 (Deming, 1994) and the average porosity, Φ, of all samples investigated here is aproximately 5%. Parameters k∞ and B are more significant and cannot be inferred easily. k∞ is varied in the range of 10−19 to 10−22 m2 according to experimental results. B is deduced from the reciprocal Pmean, which is depending on the formation depth (Phydrostatic = 10 MPa/km). Since the depth is unknown in this scenario, potential minimum (500 m) and maximum (9000 m) burial depths are used as endmembers (Johnson et al., 1996; Catuneanu et al., 2005; De Kock et al., 2017). Table 4 summarizes the variation of hydraulic diffusivity D as a function of the aforementioned parameters. Dmin and Dmax denote the lowest and highest estimated diffusivity coefficient, respectively. Within this range, D = 4.8·10−06 m2/s indicates the highest, whereas D = 6.7·10−10 m2/s represents the lowest depletion rate. These two endmembers are then used for solving Dt/l2 = 4.00 for t, providing maximum (best case) and minimum (worst case) time of 100% reservoir depletion. Best- and worst-case scenarios of reservoir depletion time t can be estimated as a function of D and l (Fig. 11). Following this approach, a reservoir of 1 km length is depleted after approximately 0.03 Ma in the worst- and 188 Ma in the best-case scenario. According to a recently developed 1D petroleum systems model (PetroMod), hydrocarbon generation, migration and accumulation ended around 181 Ma ago. According to this model and its uncertainties, the likelihood of complete reservoir depletion nowadays is high.

Fig. 11. Indicated area illustrates 100% reservoir depletion time in dependence of hydraulic diffusivity D and reservoir length l. Upper (D = 6.7E − 10 m2/s) and lower (D = 4.8E − 06 m2/s) boundary represent best- and worst-case scenarios, respectively. Any formation investigated in this study is represented the properties within this area.

D=

Hydraulic diffusivity D [m2/s]

The discussion of geochemical and petrophysical results, comprising ten black shale samples from the southern Karoo Basin, leads to the following conclusions:

• TS and TOC suggest prevailing oxygenated bottom waters for the

(11)

Here k∞ is the Klinkenberg-corrected permeability coefficient [m2], μ is the dynamic viscosity of the fluid [Pas], α is rock compressibility [Pa−1], Φ is porosity [−] and B denotes fluid compressibility [Pa−1].

•

12

Collingham and Prince Albert Formations. TS/TOC ratios and the presence of pyrite indicate dysoxic to anoxic conditions for the Whitehill Formation. All formations show indications for terrestrial influence. The Prince Albert was likely deposited under lacustrine to marine conditions, the Whitehill Formation deposited in a marine environment and Collingham Formation in a lacustrine setting. Further investigations are necessary for a more conclusive assessment. Samples of all three formations had potential for hydrocarbon

International Journal of Coal Geology 212 (2019) 103249

S. Nolte, et al.

•

•

generation, likely gas, but have presently reached an overmature state. Overmaturity is likely related to thermotectonic overprinting processes induced by the Cape Orogeny. There is a likelihood that maturity decreases farther northeast in the Karoo Basin with increasing distance to the Cape Fold Belt. However, further north in the basin dolerite intrusions might also lead to elevated levels of maturity. Hence, all formations still represent promising source rocks if found in areas of lower maturity, especially the Whitehill Formation based on its particular richness in TOC. Permeability coefficients are in the nDarcy range and lowest within the Whitehill and Prince Albert Formation. Porosity is highest within the Whitehill Formation, promoting it as suitable unconventional source rock. Neither permeability nor porosity show significant dependency upon induced stress (30 vs. 20 MPa). Excess sorption capacity is noticeably highest within the Whitehill Formation. Total gas storage capacity of the Whitehill Formation at extraction depth is approximately 400–465 mol CH4 per m3 rock and further increasing with depth. Since the Karoo Basin is up to 6 km deep in

• •

some areas, the formations are likely to occur at even greater depths. Reservoir depletion across faults is dependent on the individual rock matrix permeability. For this sample set, a 100% gas-bearing reservoir of 1 km length is completely depleted after 0.03 and 188 Ma in the worst and best case approach, respectively. The difference between both endmembers is about four magnitudes. As conclusion deduced from this study is, it is not recommended to further drill here for hydrocarbon exploitation. In general, it is advised to avoid areas of intrusions and tectonic activity due to thermal overprinting (overmaturation and gas loss) and extensive faulting (facilitating routes for gas escape). Gas depletion via faults might occur swiftly in geological times.

Acknowledgements We would like to thank CIMERA and the KARIN (Karoo Research Initiative) Project, run by Prof. Beukes and Dr. de Kock at the University of Johannesburg, for providing samples for this study.

Appendix A. Results from XRD measurements Sample

Formation

Quartz [wt.-%]

Illite/Musocvite [wt.-%]

Albite [wt.-%]

Dolomite [wt.-%]

Clinochlore [wt.-%]

Pyrite [wt.-%]

Kaolinite [wt.-%]

Siderite [wt.-%]

KZF01P KZF02P KZF03P KZF04P KZF05P KZF06P KZF07P KZF08P KZF09P KZF10P

Collingham Collingham Collingham Whitehill Whitehill Whitehill Whitehill Whitehill Prince Albert Prince Albert

42.5 63.0 38.5 42.5 38.6 41.6 27.8 38.7 34.2 67.8

28.0 17.7 37.8 29.6 18.5 24.0 12.3 27.1 30.7 19.2

26.3 16.5 19.8 14.2 29.8 25.0 3.7 10.9 23.6 7.1

0.0 0.7 0.0 0.0 11.5 3.7 55.0 17.8 0.0 0.0

2.7 1.7 2.7 3.7 0.9 3.5 0.4 1.9 5.0 4.5

0.0 0.0 0.7 2.4 0.5 2.0 0.8 3.5 0.2 0.0

0.5 0.4 0.5 0.4 0.1 0.2 0.0 0.2 5.1 1.5

0.0 0.0 0.0 7.2 0.0 0.0 0.0 0.0 1.2 0.0

Appendix B. TS, TOC, TIC and Rock-Eval pyrolysis results sorted by depth and formation Sample

TS [wt.-%]

TOC [wt.-%]

TIC [wt.-%]

S1 [mg HC/g rock]

S2 [mg HC/g rock]

S3 [mg CO2/g rock]

Tmax [°C]

HI [mg HC/g TOC]

OI [mg HC/g TOC]

PI [−]

KZF01P KZF02P KZF03P KZF04P KZF05P KZF06P KZF07P KZF08P KZF09P KZF10P

0.07 0.14 0.24 1.57 0.30 3.20 0.62 2.53 0.08 0.07

2.31 1.23 0.97 5.01 7.99 7.11 4.13 6.06 0.30 0.68

0.22 0.63 0.22 0.25 1.04 0.36 6.69 0.61 0.22 0.20

0.01 0.01 0.08 0.08 0.15 0.14 0.14 0.14 0.06 0.06

0.12 0.08 0.38 0.41 0.51 0.46 0.45 0.42 0.38 0.35

0.22 0.18 0.14 0.19 0.19 0.18 0.22 0.29 0.12 0.10

608 608 604 609 606 603 606 598 596 599

5 6 39 8 6 6 11 7 127 52

10 14 14 4 2 3 5 5 39 15

0.11 0.12 0.18 0.16 0.23 0.24 0.24 0.25 0.13 0.15

13

14

10

8

6

4

14

10

8

4 6

16

14

10 12

8

6

4

25

20

15

10

5

0

Vitrinite reflectance [%]

14

3.40-3.45 3.45-3.50 3.50-3.55 3.55-3.60 3.60-3.65 3.65-3.70 3.70-3.75 3.75-3.80 3.80-3.85 3.85-3.90 3.90-3.95 3.95-4.00 4.00-4.05 4.05-4.10 4.10-4.15 4.15-4.20 4.20-4.25 4.25-4.30 4.30-4.35 4.35-4.40 4.40-4.45 4.45-4.50 4.50-4.55 4.55-4.60 4.60-4.65 4.65-4.70 4.70-4.75

5 Relative abundance [%]

10

3.40-3.45 3.45-3.50 3.50-3.55 3.55-3.60 3.60-3.65 3.65-3.70 3.70-3.75 3.75-3.80 3.80-3.85 3.85-3.90 3.90-3.95 3.95-4.00 4.00-4.05 4.05-4.10 4.10-4.15 4.15-4.20 4.20-4.25 4.25-4.30 4.30-4.35 4.35-4.40 4.40-4.45 4.45-4.50 4.50-4.55 4.55-4.60 4.60-4.65 4.65-4.70 4.70-4.75

12

Relative abundance [%]

3.40-3.45 3.45-3.50 3.50-3.55 3.55-3.60 3.60-3.65 3.65-3.70 3.70-3.75 3.75-3.80 3.80-3.85 3.85-3.90 3.90-3.95 3.95-4.00 4.00-4.05 4.05-4.10 4.10-4.15 4.15-4.20 4.20-4.25 4.25-4.30 4.30-4.35 4.35-4.40 4.40-4.45 4.45-4.50 4.50-4.55 4.55-4.60 4.60-4.65 4.65-4.70 4.70-4.75

Relative abundance [%]

15

3.40-3.45 3.45-3.50 3.50-3.55 3.55-3.60 3.60-3.65 3.65-3.70 3.70-3.75 3.75-3.80 3.80-3.85 3.85-3.90 3.90-3.95 3.95-4.00 4.00-4.05 4.05-4.10 4.10-4.15 4.15-4.20 4.20-4.25 4.25-4.30 4.30-4.35 4.35-4.40 4.40-4.45 4.45-4.50 4.50-4.55 4.55-4.60 4.60-4.65 4.65-4.70 4.70-4.75

3.40-3.45 3.45-3.50 3.50-3.55 3.55-3.60 3.60-3.65 3.65-3.70 3.70-3.75 3.75-3.80 3.80-3.85 3.85-3.90 3.90-3.95 3.95-4.00 4.00-4.05 4.05-4.10 4.10-4.15 4.15-4.20 4.20-4.25 4.25-4.30 4.30-4.35 4.35-4.40 4.40-4.45 4.45-4.50 4.50-4.55 4.55-4.60 4.60-4.65 4.65-4.70 4.70-4.75

Relative abundance [%]

20

3.40-3.45 3.45-3.50 3.50-3.55 3.55-3.60 3.60-3.65 3.65-3.70 3.70-3.75 3.75-3.80 3.80-3.85 3.85-3.90 3.90-3.95 3.95-4.00 4.00-4.05 4.05-4.10 4.10-4.15 4.15-4.20 4.20-4.25 4.25-4.30 4.30-4.35 4.35-4.40 4.40-4.45 4.45-4.50 4.50-4.55 4.55-4.60 4.60-4.65 4.65-4.70 4.70-4.75

18 KZF01P Mean: 4.240% Stdev.: 0.144

18

0

Vitrinite reflectance [%]

KZF03P Mean: 4.011% Stdev.: 0.169 14

2 2

0 0

Vitrinite reflectance [%]

KZF05P Mean: 4.192% Stdev.: 0.207

2

0

KZF07P Mean: 4.150% Stdev.: 0.181

0 2

KZF09P

Mean: 3.972% Stdev.: 0.135 20 18 16 14 12 10 8 6 4 2 0

Vitrinite reflectance [%]

20 18 16 14 12 10 8 6 4 2 0

Vitrinite reflectance [%]

20 18 16 14 12 10 8 6 4 2 0

3.40-3.45 3.45-3.50 3.50-3.55 3.55-3.60 3.60-3.65 3.65-3.70 3.70-3.75 3.75-3.80 3.80-3.85 3.85-3.90 3.90-3.95 3.95-4.00 4.00-4.05 4.05-4.10 4.10-4.15 4.15-4.20 4.20-4.25 4.25-4.30 4.30-4.35 4.35-4.40 4.40-4.45 4.45-4.50 4.50-4.55 4.55-4.60 4.60-4.65 4.65-4.70 4.70-4.75

12

Relative abundance [%]

16

Relative abundance [%]

3.40-3.45 3.45-3.50 3.50-3.55 3.55-3.60 3.60-3.65 3.65-3.70 3.70-3.75 3.75-3.80 3.80-3.85 3.85-3.90 3.90-3.95 3.95-4.00 4.00-4.05 4.05-4.10 4.10-4.15 4.15-4.20 4.20-4.25 4.25-4.30 4.30-4.35 4.35-4.40 4.40-4.45 4.45-4.50 4.50-4.55 4.55-4.60 4.60-4.65 4.65-4.70 4.70-4.75

Relative abundance [%]

16

Relative abundance [%]

3.40-3.45 3.45-3.50 3.50-3.55 3.55-3.60 3.60-3.65 3.65-3.70 3.70-3.75 3.75-3.80 3.80-3.85 3.85-3.90 3.90-3.95 3.95-4.00 4.00-4.05 4.05-4.10 4.10-4.15 4.15-4.20 4.20-4.25 4.25-4.30 4.30-4.35 4.35-4.40 4.40-4.45 4.45-4.50 4.50-4.55 4.55-4.60 4.60-4.65 4.65-4.70 4.70-4.75

Relative abundance [%]

25

3.40-3.45 3.45-3.50 3.50-3.55 3.55-3.60 3.60-3.65 3.65-3.70 3.70-3.75 3.75-3.80 3.80-3.85 3.85-3.90 3.90-3.95 3.95-4.00 4.00-4.05 4.05-4.10 4.10-4.15 4.15-4.20 4.20-4.25 4.25-4.30 4.30-4.35 4.35-4.40 4.40-4.45 4.45-4.50 4.50-4.55 4.55-4.60 4.60-4.65 4.65-4.70 4.70-4.75

Relative abundance [%]

S. Nolte, et al.

International Journal of Coal Geology 212 (2019) 103249

Appendix C. Histograms representing random vitrinite reflectance VRr results

16

KZF02P Mean: 4.034% Stdev.: 0.217

14

12

10 8

6

4

2

0

Vitrinite reflectance [%] KZF04P

12 Mean: 3.980% Stdev.: 0.255

10 8

6

4

Vitrinite reflectance [%] KZF06P Mean: 4.006% Stdev.: 0.253

Vitrinite reflectance [%]

KZF08P Mean: 3.923% Stdev.: 0.160

Vitrinite reflectance [%]

KZF10P

Mean: 4.104% Stdev.: 0.171

Vitrinite reflectance [%]

International Journal of Coal Geology 212 (2019) 103249

S. Nolte, et al.

Geel, C., De Wit, M., Booth, P., Schulz, H.-M., Horsfield, B., 2015. Palaeo-environment, diagenesis and characteristics of Permian black shales in the Lower Karoo Supergroup flanking the Cape Fold Belt near Jansenville, Eastern Cape, South Africa: Implications for the shale gas potential of the Karoo Basin. S. Afr. J. Geol. 118, 249–274. Gensterblum, Y., van Hemert, P., Billemont, P., Busch, A., Charriére, D., Li, D., Krooss, B.M., de Weireld, G., Prinz, D., Wolf, K.H.A.A., 2009. European inter-laboratory comparison of high pressure CO2 sorption isotherms. I: Activated carbon. Carbon 47, 2958–2969. Gensterblum, Y., van Hemert, P., Billemont, P., Battistutta, E., Busch, A., Krooss, B.M., De Weireld, G., Wolf, K.H.A.A., 2010. European inter-laboratory comparison of high pressure CO2 sorption isotherms II: natural coals. Int. J. Coal Geol. 84, 115–124. Gensterblum, Y., Ghanizadeh, A., Cuss, R.J., Amann-Hildenbrand, A., Krooss, B.M., Clarkson, C.R., Harrington, J.F., Zoback, M.D., 2015. Gas transport and storage capacity in shale gas reservoirs – a review. Part A: Transport processes. J. Unconventional Oil Gas Resour. 12, 87–122. Ghanizadeh, A., Gasparik, M., Amann-Hildenbrand, A., Gensterblum, Y., Krooss, B.M., 2014. Experimental study of fluid transport processes in the matrix system of the European organic-rich shales: I. Scandinavian Alum Shale. Mar. Pet. Geol. 51, 79–99. Götz, A.E., Ruckwied, K., Wheeler, A., 2018. Marine flooding surfaces recorded in Permian black shales and coal deposits of the Main Karoo Basin (South Africa): implications for basin dynamics and cross-basin correlation. Int. J. Coal Geol. 190, 178–190. Haldorsen, S., Von Brunn, V., Maud, R., Truter, E.D., 2001. A Weichselian deglaciation model applied to the Early Permian glaciation in the northeast Karoo Basin, South Africa. J, Quater. Sci. 16 (6), 583–593. Hansma, J., Tohver, E., Jourdan, F., Schrank, C., Adams, D., 2015. The timing of the Cape Orogeny: New 40Ar/39Ar age constraints on deformation and cooling of the Cape Fold Belt, South Africa. Gondwana Res. 32, 122–137. Houseknecht, D.W., Weesner, C.M.B., 1997. Rotational reflectance of dispersed vitrinite from the Arkoma basin. Org. Geochem. 26, 191–206. Johnson, M.R., Van Vuuren, C.J., Hegenberger, W.F., Key, R., Show, U., 1996. Stratigraphy of the Karoo Supergroup in southern Africa: an overview. J. Afr. Earth Sci. 23, 3–15. Johnson, M.R., Van Vuuren, C.J., Visser, J.N.J., Cole, D.I., Wickens, H.d.V., Christie, A.D.M., Roberts, D.L., Brandl, G., 2006. Sedimentary rocks of the Karoo Supergroup. In: Johnson, M.R., Anhaeusser, C.R., Thomas, R.J. (Eds.), The Geology of South Africa. Council for Geoscience, Pretoria, South Africa, pp. 461–499. Kingsley, C.S., 1981. A Composite Submarine Fan-Delta-Fluvial Model for the Ecca and Lower Beaufort Groups of Permian Age in the Eastern Cape Province. vol. 84. Transactions of the Geological Society of South Africa, South Africa, pp. 27–40. Klinkenberg, L.J., 1941. The Permeability of Porous Media to Liquids and Gases, Drilling and Production Practice. American Petroleum Institute, New York, New York, pp. 1–14. Lindeque, A.S., Ryberg, T., Stankiewicz, J., Weber, M.H., De Wit, M.J., 2007. Deep Crustal Seismic Reflection Experiment across the Southern Karoo Basin, South Africa. S. Afr. J. Geol. 110, 419–438. Lindeque, A.S., de Wit, M.J., Ryberg, T., Weber, M., Chevallier, L., 2011. Deep crustal profile across the Southern Karoo basin and Beattie magnetic anomaly, South Africa: an integrated interpretation with tectonic implications. S. Afr. J. Geol. 114, 265–292. Linol, B., De Wit, M.J., 2016. Origin and Evolution of the Cape Mountains and Karoo Basin. Springer International Publishing Switzerland. Menyah, K., Wolde-Rufael, Y., 2010. Energy consumption, pollutant emissions and economic growth in South Africa. Energy Econ. 32, 1374–1382. Merkel, A., Gensterblum, Y., Krooss, B.M., Amann, A., 2015. Competitive sorption of CH4, CO2 and H2O on natural coals of different rank. Int. J. Coal Geol. 150-151, 181–192. Oelofsen, B.W., 1986. A fossil shark neurocranium from the Permo-Carboniferous (lowermost Ecca Formation) of South Africa. In: Proceedings of the 2nd International Conference of Indo-Pacific Fishes, Tokyo, pp. 107–124. Passey, Q.R., Bohacs, K., Esch, W.L., Klimentidis, R., Sinha, S., 2010. From oil-prone source rock to gas-producing shale reservoir - geologic and petrophysical characterization of unconventional shale gas reservoirs. In: International Oil and Gas Conference and Exhibition in China. Society of Petroleum Engineers, Beijing, China, pp. 1–29. Rowsell, D.M., De Swardt, A.M.J., 1976. Diagenesis in Cape and Karroo sediments, South Africa, and its bearing on their hydrocarbon potential. Trans. R. Soc. South Africa 79, 81–145. Rushing, J.A., Newsham, K.E., Lasswell, P.M., Cox, J.C., Blasingame, T.A., 2004. Klinkenerg-corrected permeability measurements in Tight Gas Sands: steady-state versus unsteady-state techniques. In: SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, Houston, Texas, pp. 1–11. Schulz, H.M., Chere, N., Geel, C., Booth, P., De Wit, M.J., 2016. Is the Postglacial History of the Baltic Sea an Appropriate Analogue for the Formation of Black Shales in the Lower Ecca Group (Early Permian) of the Karoo Basin, South Africa? In: Origin and Evolution of the Cape Mountains and Karoo Basin. Springer, Cham, pp. 111–117. Shabani, M., Moallemi, S.A., Krooss, B.M., Amann-Hildenbrand, A., Zamani-Pozveh, Z., Ghalavand, H., Littke, R., 2018. Methane sorption and storage characteristics of organic-rich carbonaceous rocks, Lurestan province, Southwest Iran. Int. J. Coal Geol. 186, 51–64. Smith, R.M.H., 1990. A review of stratigraphy and sedimentary environments of the

References Aarnes, I., Svensen, H., Polteau, S., Planke, S., 2011. Contact metamorphic devolatilization of shales in the Karoo Basin, South Africa, and the effects of multiple sill intrusions. Chem. Geol. 281, 181–194. Amann-Hildenbrand, A., Ghanizadeh, A., Krooss, B.M., 2012. Transport properties of unconventional gas systems. Mar. Pet. Geol. 31, 90–99. Berner, R.A., 1984. Sedimentary pyrite formation: an update. Geochim. Cosmochim. Acta 48 (4), 605–615. Black, D.E., Booth, P.W.K., de Wit, M.J., 2016. Petrographic, geochemical and petrophysical analysis of the Collingham Formation near Jansenville, Eastern Cape, South Africa – potential cap rocks to shale gas in the Karoo. S. Afr. J. Geol. 119, 171–186. Booth, P.W.K., 2009. A review of the structural geology of the Cape Fold Belt and challenges towards future research. In: 11th SAGA Biennial Technical Meeting and Exhibition, Swaziland, pp. 481–485. Booth, P.W.K., Shone, R.W., 2002. A review of thrust faulting in the Eastern Cape Fold Belt, South Africa, and the implications for current lithostratigraphic interpretation of the Cape Supergroup. J. Afr. Earth Sci. 34, 179–190. BP Statistical Review of World Energy, 2018. British Petroleum Company, London. Retrieved from. https://www.bp.com/content/dam/bp/en/corporate/pdf/energyeconomics/statistical-review/bp-stats-review-2018-full-report.pdf. Burgess, S.D., Bowring, S.A., Fleming, H., Elliot, D.H., 2015. High precision geochronology links the Ferrar large igneous province with early-Jurassic Ocean anoxia and biotic crisis. Earth Planet. Sci. Lett. 415, 90–99. Catuneanu, O., Hancox, P.J., Rubidge, B.S., 1998. Reciprocal flexural behaviour and contrasting stratigraphies: a new basin development model for the Karoo retroarc foreland system, South Africa. Basin Res. 10, 417–439. Catuneanu, O., Wopfner, H., Eriksson, P.G., Cairncross, B., Rubidge, B.S., Smith, R.M.H., Hancox, P.J., 2005. The Karoo basins of south-Central Africa. J. Afr. Earth Sci. 43, 211–253. Cole, D.I., 2014. Geology of Karoo Shale Gas and how this can Influence Economic Gas Recovery. Presentation, Gas – the Game Changer for Southern Africa? Fossil Fuel Foundation, Glen Hove, Johannesburg, pp. 11–12 21 May 2014, Abstracts. Colombo, S., El Harrak, M., Sartori, N., 2016. The Future of Natural Gas : Markets and Geopolitics. Lenthe/European Energy Review. Crank, J., 1975. The Mathematics of Diffusion. Oxford University Press. Cui, X., Bustin, A.M.M., Bustin, R.M., 2009. Measurements of gas permeability and diffusivity of tight reservoir rocks: different approaches and their applications. Geofluids 9, 208–223. De Kock, M.O., Beukes, N.J., Götz, A.E., Cole, D., Robey, K., Birch, A., Withers, A., van Niekerk, H.S., 2016. Open file progress report on exploration of the southern Karoo Basin through CIMERA-KARIN borehole KZF-1 in the Tankwa Karoo. Witzenberg (Ceres) district. CIMERA DST-NRF Centre of Excellence for Integrated Mineral and Energy Resource Analysis, pp. 1–12. De Kock, M.O., Beukes, N.J., Adeniyi, E.O., Cole, D., Götz, A.E., Geel, C., Ossa, F.-G., 2017. Deflating the shale gas potential of South Africa's Main Karoo basin. S. Afr. J. Sci. 113, 1–12. De Wit, M.J., 2018. (T)(C)racking the shale-gas debate. Baseline data and citizen science. AEON Report Series, Nelson Mandela University. No. 4. pp. 6–26. Retrieved from. http://aeon.org.za/wp-content/uploads/2018/12/AEON-Shale-Gas-Report-2018. pdf. De Wit, M.J., Ransome, I.G.D., 1992. Regional inversion tectonics along the southern margin of Gondwana. In: De Wit, M.J., Ransome, I.G.D. (Eds.), Inversion Tectonics of the Cape Fold Belt. Karoo and Cretaceous Basins of Southern Africa, Balkema, Rotterdam, Netherlands, pp. 15–20. Decker, J., Marot, J., 2012. Investigation of hydraulic fracturing in the Karoo of South Africa. Resource Assessment, Petroleum Agency SA. pp. 1–153. Deming, D., 1994. Factors necessary to define a pressure seal. AAPG Bull. 78, 1005–1009. Dhansay, T., Navabpour, P., de Wit, M., Ustaszewski, K., 2017. Assessing the reactivation potential of pre-existing fractures in the southern Karoo, South Africa: evaluating the potential for sustainable exploration across its Critical Zone. J. Afr. Earth Sci. 134, 504–515. Du Toit, A.L., 1954. The Geology of South Africa, 3rd Ed. Oliver and Boyd, Edinburgh, U.K., pp. 611. Espitalié, J., Laporte, J.L., Madec, M., Marquis, F., Leplat, P., Paulet, J., Boutefeu, A., 1977. Méthode rapide de caractérisation des roches mètres, de leur potentiel pétrolier et de leur degré d'évolution. Revue de l'Institut français du Pétrole 32, 23–42. Fink, R., Krooss, B.M., Amann-Hildenbrand, A., 2017. Stress-Dependence of Porosity and Permeability of the Upper Jurassic Bossier Shale: An Experimental Study. Geological Society, London, pp. 452 Special Publications 454, SP454. Gasparik, M., Ghanizadeh, A., Bertier, P., Gensterblum, Y., Bouw, S., Krooss, B.M., 2012. High-pressure methane Sorption Isotherms of Black Shales from the Netherlands. Energy Fuel 26, 4995–5004. Gasparik, M., Bertier, P., Gensterblum, Y., Ghanizadeh, A., Krooss, B.M., Littke, R., 2014. Geological controls on the methane storage capacity in organic-rich shales. Int. J. Coal Geol. 123, 34–51. Geel, C., Schulz, H.-M., Booth, P., De Wit, M., Horsfield, B., 2013. Shale Gas Characteristics of Permian Black Shales in South Africa: results from recent Drilling in the Ecca Group (Eastern Cape). Energy Procedia 40, 256–265.

15

International Journal of Coal Geology 212 (2019) 103249

S. Nolte, et al. Karoo Basin of South Africa. J. Afr. Earth Sci. (and the Middle East) 10, 117–137. Smith, R., Eriksson, P., Botha, W., 1993. A review of the stratigraphy and sedimentary environments of the Karoo-aged basins of southern Africa. J. Afr. Earth Sci. (and the Middle East) 16 (1–2), 143–169. Smithard, T., Bordy, E.M., Reid, D.L., 2015. The effect of dolerite intrusions on the hydrocarbon potential of the lower Permian Whitehill Formation (Karoo Supergroup) in South Africa and southern Namibia: a preliminary study. S. Afr. J. Geol. 118 (4), 489–510. Soeder, D.J., 1988. Porosity and Permeability of Eastern Devonian Gas Shale. SPE-15213PA. vol. 3. pp. 116–124. Svensen, H., Jamtveit, B., Planke, S., Chevallier, L., 2006. Structure and evolution of hydrothermal vent complexes in the Karoo Basin. J. Geol. Soc. Lond. 163, 671–682. Tanikawa, W., Shimamoto, T., 2009. Comparison of Klinkenberg-corrected gas permeability and water permeability in sedimentary rocks. Int. J. Rock Mech. Min. Sci. 46, 229–238. Tankard, A., Welsink, H., Aukes, P., Newton, R., Stettler, E., 2012. Geodynamic interpretation of the Cape and Karoo basins, South Africa. In: Regional Geology and Tectonics: Phanerozoic Passive Margins, Cratonic Basins and Global Tectonic Maps. Elsevier, pp. 868–945. Theron, J.N., 1962. An analysis of the Cape folding in the district of Willowmore, Cape Province. Ann. Univ. Stellenbosch 37A (5), 347.

Twine, T., Jackson, M., 2012. Karoo Shale Gas Report by Econometrix (Pty) Ltd. pp. 74. Uffmann, A.K., Littke, R., Rippen, D., 2012. Mineralogy and geochemistry of Mississippian and Lower Pennsylvanian black shales at the northern margin of the Variscan Mountain Belt (Germany and Belgium). Int. J. Coal Geol. 103, 92–108. Viljoen, J.H.A., 1992. Lithostratigraphy of the Collingham Formation (Ecca Group), including the Zoute Kloof, Buffels River and Wilgehout River Members and the Matjiesfontein Chert Bed. Lithostr. Ser. S. Afr. Comm. Strat. 22 (10 pp). Viljoen, J.H.A., 1994. Sedimentology of the Collingham Formation, Karoo Supergroup. S. Afri. J. Geol. 91 (2), 167–183. Visser, J.N.J., 1991. Self-destructive collapse of the Permo-Carboniferous marine ice sheet in the Karoo Basin: evidence from the southern Karoo. S. Afr. J. Geol. 94, 255–262. Visser, J.N.J., 1993. Sea-level changes in a back-arc-foreland transition: the late Carboniferous-Permian Karoo Basin of South Africa. Sediment. Geol. 83, 115–131. Weiss, H.M., Wilhelms, A., Mills, N., Scotchmer, J., Hall, P.B., Lind, K., Brekke, T., 2000. NIGOGA: The Norwegian Industry Guide to Organic Geochemical analyses. In: Norsk Hydro, Statoil, Geolab Nor, SINTEF Petroleum Research and the Norwegian Petroleum Directorate, pp. 1–102. Wickens, H. de V., 1994. Basin Floor Fan Building Turbidites of the Southwestern Karoo Basin, Permian Ecca Group, South Africa. Unpublished PhD Thesis. University of Port Elizabeth, South Africa, pp. 223.

16