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Visualization and Quantification of Thermally Induced Porosity Alteration of Immature Source Rock Using X-ray Computed Tomography Guenther Glatz, Louis M. Castanier, and Anthony R Kovscek Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b01430 • Publication Date (Web): 07 Sep 2016 Downloaded from http://pubs.acs.org on September 12, 2016

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Visualization and Quantification of Thermally Induced Porosity Alteration of Immature Source Rock Using X-ray Computed Tomography Guenther Glatz, Louis Castanier, and Anthony R. Kovscek∗ Energy Resources Engineering Department, Stanford University E-mail: [email protected]

Abstract This paper summarizes results of a successful laboratory investigation to visualize and quantify pyrolysis induced porosity evolution of Uinta Basin organic-rich source rock using X-ray computed tomography (CT). Combining CT imaging techniques with a radio-opaque gas as a pore contrast fluid allowed for the description of porosity changes within source rock rather than limiting quantification to a single bulk value as obtained by conventional porosity measurement techniques. The porosity of the immature and thermally matured rock sample, a Green River oil shale, increased from 9% to 25% due to kerogen conversion and delamination. Porosity distributions of immature samples showed unimodal behavior whereas matured samples displayed multimodal characteristics. These new measurements indicate that porosity evolution during maturation is not well-described by bulk measurements. ∗

To whom correspondence should be addressed

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Introduction

A source rock can be broadly defined as any fine-grained, organic-rich rock that is capable of generating petroleum, given sufficient exposure to heat and pressure. 1 It is a mixture of fined grained sedimentary rocks containing organic material (i.e., kerogen). The inorganic matrix of a source rock consists of minerals including clays, carbonates, feldspars, quartz, pyrite. With respect to the organic matter, we distinguish between two constituents. On the one hand, kerogen is the macromolecular and organic solvent-insoluble (e.g. carbon disulphide) organic matter. On the other hand, bitumen is characterized as the solvent-soluble portion of source rock organic matter. 2,3 Kerogen is converted into oil and gas during thermal maturation. The maturation might occur at moderately low temperature (100-200◦ C) over millions of years. This is the natural generation of a petroleum system. It might also be artificially induced at larger temperature in situ or ex situ in an industrial process referred to as retorting. In the last case, the source rock is called oil shale, emphasizing its strong oil generation potential. Oil shales are usually specific source rocks that are very rich in kerogen and immature. Gavin and Harding Burroughs 4 provided a more formal definition and defines oil shale as a ”‘compact laminated rock of sedimentary origin yielding over 33 percent of ash and containing organic matter that yields oil when distilled”’. Oil shale is different from shale oil in the sense that a shale-oil (or tight-oil) resource commonly refers to producible oil from organic-rich mudstones, calcareous mudstones and so on. 5 Prominent examples of this type of oil-bearing formation are the Bakken, Barnett, and the Eagle Ford shale. The significance of oil shale stems from its enormous potential as an energy resource. The World Energy Council conservatively estimated total world resources of oil shale at 4.8 trillion barrels in 2013 of which about 1.3 trillion barrels are attributed to the United States. 7 The United States Geologic Survey estimates resources for Colorado, Utah, and Wyoming alone total 4.2 trillion barrels of shale oil. 8 Crude-oil resources, for comparison, are estimated 2


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to be at 1.3 trillion barrels. 7 Already in 1920, Victor Clifton Alderson commented that if oil is the ”king”, then ”oil shale” is the ”heir apparent”. 9 It has to be pointed out, however, that it is not easy to assess the extent to which shale resources are economically recoverable or, in other words, what it takes to turn a resource into a reserve. One estimate is that global oil shale resources may yield up to 1 trillion barrels of economically recoverable oil. 10 Companies have conceived different approaches to produce oil from oil shale. A very sophisticated approach is presented by Symington et al. using an electrically conductive proppant to form an in-situ resistive heating element. 11 Additional approaches include the CRUSH process and the in-situ conversion process (ICP) for short. 12 Other authors propose microwaves for rapid heating to pyrolysis temperature. 13 An overview of respective approaches is given in the U.S. DOE secure fuels survey. 14 Commercial projects have been limited to ex-situ projects, as no in-situ method so far was able to demonstrate large-scale production on a commercial level. 15 The understanding of porosity creation during thermal maturation is an essential element for both (1) natural petroleum system and (2) retorting modeling. In (1) and (2), it is important to model porosity evolution and eventually final porosity. For conventional plays, as porosity is strongly correlated to permeability, the porosity evaluation indirectly provides expulsion potential, whereas for unconventional plays it informs the volume-in-place. For retorting processes, enhancing porosity is mandatory because oil shale is an immature source rock with a bad connected porosity and accordingly very low permeability. Conventional porosity measurement techniques for low permeability specimens such as helium porosimetry 16 yield a single effective porosity. We believe that subcore scale measurements are important to understanding oil shale evolution because it has a multiscale laminated structure with strong spatial heterogeneities in organic content as it can be seen in Fig.1. The object of this research is to provide a basis for better understanding of the physics and

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matured shale samples studied. We evaluate the extent to which fracture generation and porosity evolution induced by kerogen maturation and conversion are quantifiable using CT.

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CT Imaging Using a Radio-Opaque Gas

This study makes extensive use of X-ray CT images and uses krypton, as discussed next. CT imaging is an excellent technique for nondestructive imaging of internal features of rock. Given two CT scans at the same location, porosity, φ, is calculated according to Akin and Kovscek 19 as follows

φ=

µ11P − µ21P µ1f − µ2f

(1)

In Eq.1, µ1P is the linear attenuation coefficient for a voxel (i.e., the three-dimensional analog of a pixel) comprised of the rock matrix and a single fluid with the superscripts identifying the particular fluid. For our purposes, µ11P is equivalent to the CT number of a krypton saturated volume element, µ21P , accordingly, corresponds to the CT number of an air saturated volume element. The coefficients µ1f and µ2f represent the CT numbers for pure krypton and air at operating pressures respectively. In this context, Eq.1 refers to a three-dimensional matrix of porosity values representing the entire core sample. Working directly with porosity also avoids any bias that is potentially introduced by conventional image segmentation techniques. As pointed out by Iassonov et al. 20 porosity values can differ significantly depending on the segmentation technique employed. Krypton is used because it presents sufficient X-ray attenuation to permit visualization of in-situ porosity. 21 Note that the result of computed tomography after normalization and truncation for a voxel is given in Hounsfield units (HU) or CT numbers, a quantitative scale of radiodensity. 22 The numbers are related to the attenuation coefficient of distilled water at standard temperature and pressure as follows: 22,23

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HU = 1000 ×

µvoxel − µH2 0 µH 2 0

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(2)

In Eq. 2, µH2 0 is the linear attenuation coefficient of water and µvoxel is the linear attenuation coefficient of the matter in the irradiated voxel. 19,22,24 Accordingly, greater density matter (greater atomic number, greater electron density) yields greater CT numbers due to its increased ability to attenuate X-rays and vice versa. Typical CT numbers are -1000 HU for dry air, 0 HU - as per definition - for water. 25 Given that the accuracy of the CT scanner is ±1 HU, the minimum change in density ∆ρ/ρ detectable is ±0.1%. Consequently, the smallest change in porosity that can be quantified using krypton as a contrast agent at a pressure of 100 psi is about ±1.5% of the calculated value when porosity is obtained from a single scan. The uncertainty can be reduced by averaging multiple scans. 26

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Experimental

Figure 2 shows a schematic of the experimental setup that was placed in the CT scanner. The core holder was a Hassler-sleeve design. 27 CT images were collected using a GE HiSpeed CT fifth generation medical scanner. The end caps on each end of the core holder were machined from 316 stainless steel whereas the outer sleeve was hard-anodized aluminum. The inner sleeve was heat-shrinkable teflon tubing. Threaded aluminum rods passed through the end caps. Once secured with nuts, endcap movement was prevented thereby allowing an o-ring seal between the endcap and the outer sleeve. A second apparatus (see Fig. 3), referred to as the pyrolysis cell, was used to heat the samples in an unconfined setting and induce kerogen maturation. The pyrolysis cell was a gas-tight, large diameter tube through which nitrogen flowed. It housed a ceramic furnace heater allowing for heating rates up to 70 ◦ C/min with final temperatures of at least 840 ◦

C uniformly distributed across the sample (see Fig. 4). Accordingly, the cell was fully 6


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capable of Fischer Assay type investigations that require a heating rate of 12 ◦ C/min with final temperatures of about 500 ◦ C. 28–31 In its current configuration, the cell body was rated for 800 psi (5.6 MPa) for a cell wall temperature of 460 ◦ C as per ASME Sec VIII. 32

Figure 4: Inside view of the cell shown in Fig. 3. The sample is placed inside a ceramic fiber heater. The heater is held in place by insulation material, the sample is loosely held in place by thermowells. As previously mentioned, the samples studied are from the Uinta Basin. Standard thermogravimetric analysis (not shown) revealed that the samples were relatively lean (16 gallons/ton) compared to the median value of the Mahagony zone of about 25 gallons/ton. 33 The kerogen content based on conversion was estimated as 10 % by mass. The samples were intentionally selected to be lean. Rich samples are known to undergo dramatic mechanical degradation 34,35 making it difficult to transfer a matured sample from the pyrolysis cell to the core holder intact. Samples were scanned at 140 kV and with a tube current of 120 mA. The exposure time was 1 s. The spatial resolution of the CT scanner was set to the highest resolution available (voxel size of 0.25 mm by 0.25 mm by 1 mm) to capture as much of sample heterogeneity as possible. A detailed description of the porosity imaging protocol is given elsewhere by Vega 8


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et al. 21 . The general sequence of events during a test were as follows: • Core samples were mounted in the core holder and evacuated to remove any fluids or gases residing in the pores and reference CT scans were collected. • After setting the confining pressure to 200 psi using nitrogen, the samples were then flooded with krypton at 100 psi (0.7 MPa) until the upstream and downstream pressures equalized. The images of the same rock saturated with different gases were sufficient to compute porosity as given by Eq. (1). • The samples were then removed from the core holder and placed in the pyrolysis cell. • The pyrolysis cell was evacuated of air and residual krypton. It was then flooded with nitrogen. Typically, a sample was heated to 400 ◦ C and maintained at this temperature for a period of 10-20 hours in an unconfined setting. • Samples were then cooled and removed from the pyrolysis cell, re-sleeved, mounted in the core-holder, and the imaging procedures for porosity repeated.

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Results and Discussion

A variety of experimental tests were conducted to establish that porosity distributions within immature and retorted oil shale were measurable non-destructively. In all figures, warmer colors indicate greater density whereas cooler colors indicate smaller density. CT numbers larger than 2200 HU are shown in white and CT numbers lower than 1800 HU are shown in black. Given that organic matter has a lower density compared to the inorganic matter, the cooler is the color, the richer is the voxel. Very high density features such as pyrite are white.

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Figure 14: Individual shale layers show a normally distributed behavior with respect to porosity. The individual layer shown has a mean porosity of 24%. The position of the individual shale layer with respect to the entire core sample is shown in Fig. 13.

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(a)

(b)

(c)

(d)

(e)

Figure 15: 3D reconstruction of the matured sample in terms of porosity showing only voxels with porosity smaller or equal than (a) 1%, (b) 10%, (c) 20%, (d) 50%, (e) 70%

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4.3

Repeatability

To establish the generality of trends observed for this sample type, a second set of experiments are reported for another sample. Figure 16 also shows a shift from a unimodal porosity distribution with a bulk krypton porosity of 9.0% to a multimodal distribution with a bulk porosity of 21.5%. Porosity measurements were again conducted at an effective stress of 100 psi (0.7 MPa). In all samples tested, porosity within a given lamina tends to maintain a unimodal distribution whereas the core-scale distribution evolves from unimodal to multimodal with heating.

Future Work We have shown that the details of sub-core scale porosity evolution accompanying thermal maturation of a type 1 source rock are quantified using X-ray CT imaging. Next steps include heating samples in a stepwise fashion to permit characterization of porosity change (bulk porosity and its connection to the modes of porosity distribution) at various extents of kerogen conversion. Importantly, we seek to develop a CT compatible cell that permits source rock maturation under a realistic stress state resembling the stress encountered in geological formations. To obtain maturation at rates compatible with laboratory time scales, elevated temperatures are needed. Accordingly, a major challenge includes designing the experimental cell for temperatures up to 450 ◦ C and effective stresses of about 15 MPa for oil shale formations and of about 40–50 MPa for active source rocks while maintaining X-ray transparency under all conditions.

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Summary

This paper summarizes results of a successful laboratory investigation to develop a technique to visualize and quantify sub-core scale porosity evolution with time as a result of source rock pyrolysis, here oil shale containing type 1 kerogen, using X-ray computed tomography (CT). 18


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Figure 16: (a) Histogram for voxels and associated porosity for the second sample (see histogram shown in Fig. 9 for the first sample). Again, the histogram shows a physical cutoff value for porosity at 25%. (b) Porosity histogram for the second sample after maturation (bulk porosity 21.5% at 400 ◦ C for 20 hours). Again, a dramatic shift in porosities yielding a multimodal behavior is observed, similar to the first sample (compare with histogram shown in Fig. 12

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Combining CT imaging techniques with krypton as a pore contrast fluid reveals the in-situ porosity distribution of the immature and thermally matured shale sample on a volumetric scale of about 0.06 mm3 . Porosity values rise dramatically due to the conversion of organic matter into hydrocarbons and thermal expansion of the shale matrix. In the sample studied, bulk porosity to krypton increased from about 9% to 25%. For this particular well-laminated source rock, we noticed that porosity distributions for the immature samples show unimodal behavior. After maturation, the distributions shift to dramatically greater porosities and the distributions are multimodal. Within individual laminations, porosity remains normally distributed. The multimodality of matured samples reflects the varying kerogen content of the various laminations. Conventionally, the description of porosity of a core sample is limited by the number of bulk porosity measurements taken using, for example, Helium porosimetry. This work shows that porosity evolution during pyrolysis (maturation) of a type I kerogen is not described adequately by bulk measurements. We suspect similar trends to be obtained with other types of source rocks, but this remains an open question. Porosity needs to be described on a local level to capture the heterogeneity of the sample as well as the mechanism of kerogen conversion as a function of temperature. Heterogeneity and mechanisms below the size scale of a core appear to be important to understand source rock maturation in general and the oil shale in-situ conversion processes in particular.

6

Acknowledgment

The authors thank TOTAL S.A. for its support through the STEMS project, a research collaboration between TOTAL S.A. and Stanford University. Additionally, we thank Dr. A. Lapene for a critical review of the first draft and Mr. Y. Elkady for the TGA analysis of samples.

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