1Department of Physics and Technology, University of Bergen, Bergen, Norway
The ﬂow of CO2 in porous media is fundamental to many engineering applications and geophysical processes. Yet detailed CO2 ﬂow visualization remains challenging. We address this problem via positron emission tomography using11C nuclides and apply it to tight formations—a difﬁcult but relevant rock type to investigate. The results represent an important technical advancement for visualization and quantiﬁcation of ﬂow properties in ultratight rocks and allowed us to observe that local rock structure in a layered, reservoir shale (K = 0.74 μdarcy) sample dictated the CO2 ﬂow path by the presence of high-density layers. Diffusive transport of CO2 in a fractured sample (high-permeable sandstone) was also visualized, and an effective diffusion coefﬁcient (Di=2.2•10-8 m2/s) was derived directly from the dynamic distribution of CO2. During CO2 injection tests for oil recovery from a reservoir shale sample we observed a recovery factor of RF=55% of oil in place without fracturing the sample.
Easily accessible energy sources are a prerequisite for a sustainable future for human kind. Synergy between the need for increased energy production and the needed reduction in anthropogenic CO2 emissions has been suggested through CO2 storage in mature oil ﬁelds, with associated incremental oil recovery [see, e.g., Falcone and Harrison, 2013]. This approach has been termed carbon capture utilization and storage (CCUS) where CO2 emissions from energy production are captured and injected into the subsurface to reduce the carbon footprint associated with fossil fuels in a transitional phase to a more sustainable energy outlook [Chu and Majumdar, 2012]. Speciﬁcally for CCUS, research on transport and trapping mechanisms in storage sites is needed to minimize costs and ensure safe long-term CO2 storage.
Shale formations are considered impermeable layers that restrict upward migration of hydrocarbons and CO2 in sedimentary formations in the subsurface [Eiken et al., 2011]. Recently, shale has also become a target for hydrocarbon exploration and is rapidly becoming a major energy resource worldwide but especially true in the U.S. Economic hydrocarbon production from such reserves was until recently unfeasible mainly related to the very low to ultralow rock permeability, a parameter that determines the connectivity and ﬂow between pores where hydrocarbons are stored. Harvesting the energy stored in a shale formation today relies on creating conduits for ﬂow through high-pressure injection of water to hydraulically fracture the near-well regions. Although hitherto a major economic success, using data from 65,000 shale wells in 30 shale gas and 21 tight oil ﬁelds in the U.S., Hughes argued that the shale revolution will be hard to sustain because well production rates decline rapidly within a few years [Hughes, 2013]. Indeed, production generally falls as the square root of time, indicative of diffusive drive [Patzek et al., 2013]. Molecular diffusion is the mixing of ﬂuids due to random motion of molecules and can be expressed by the following equation derived from Fick’s second law of diffusion in bulk ﬂuids:
where Ci is the concentration of phase i, C0 is the surface concentration, t is time, x is distance, and Di is the molecular diffusion coefﬁcient. Diffusion lengths are determined by tortuosity and are generally longer in porous media compared with bulk systems. Effective diffusion coefﬁcients based on Fickian diffusion may not apply in ultratight formations [Webb and Pruess, 2003], although the error introduced by using an incorrect diffusion model decreases at elevated pressures. We reserve a full investigation of diffusive models in shale samples for future work and use here a fractured sandstone core rather than a shale sample as we here wish to emphasize the use of local CO2 tracking in the determination of Di.
Current production behavior from fractured, tight gas reserves suggests a diffusive drive and similar behavior is expected in tight oil formations during CO2 injection. Although steeply declining production rates and low overall recoveries are observed in shale formations—largely a result from challenging microscopic characteristics such as pore sizes (in the nanometer range), pore connectivity (permeability in microdarcy to nanodarcy range), and surface properties of the rock (to a large degree unknown)—the number of scientiﬁc investigations into the underlying mechanisms is still low. Other possible fracking ﬂuids exist, but water is cheap and (still) readily available, so a switch is unlikely before the increased costs of other ﬂuids are justiﬁed or policies are changed. Advantages using CO2 as a fracking ﬂuid were recently discussed by Middleton et al. , in which large volumes of CO2 could be used for energy production from shale, combined with a signiﬁcant reduction of water usage for fracturing and large-scale storage of CO2. Speciﬁcally, improved CO2 technology must be developed through research on transport and trapping mechanisms in storage sites to minimize costs and ensure safe long-term CO2 storage. Indeed, improved knowledge about ﬂow in unconventional rocks also provides the necessary basis to improve current production rates. In this context, access to detailed ﬂow information is vital. Reactivity between dry supercritical CO2 and the shale is generally low but may potentially extract organic matter [Busch et al., 2008] and may be a beneﬁcial, combined effect during CO2 injection for fracking as suggested by others [see, e.g., Middleton et al., 2015] for CCUS. The oil recovery in oil-bearing U.S. shale reservoirs like the Bakken or Eagleford formation is believed to be less than 10%, and the potential for enhanced oil recovery (EOR) is therefore huge. We present the ﬁrst CCUS experimental results of explicit CO2 ﬂow visualization in porous media using positron emission tomography (PET) and report high oil recoveries during CO2 injection using samples from an oil-producing unit in the U.S. We also use the CO2 tracking data to gain insight to local ﬂows in a layered shale sample and to calculate a diffusion coefﬁcient directly from visualization data in a fractured sandstone core to demonstrate the use of a new imaging tool for explicit CO2 ﬂow tracking in unconventional and fractured formations.
Although primarily used as a clinical diagnostic tool, PET has previously been used to visualize ﬂuids in porous structures [see, e.g., Boutchko et al., 2012; Kulenkampff et al., 2008]. PET is based on positron-emitting radionuclides where a positron is emitted from the nucleus accompanied by an electron to balance atomic charge. The positron loses kinetic energy by interactions with the surroundings, and at near-zero momentum the positron combines with an electron and annihilates. The physics of nucleus decay and annihilation limits the spatial resolution of PET, and the achieved resolution depends on the distance to the detectors. A detector array registers the electromagnetic radiation in the form of two 511 keV photons emitted in opposite directions to conserve momentum. For practical purposes, the beta decay is insensitive to temperature and pressure [Emery, 1972], which, combined with high photon energy, makes making PET particularly suitable for visualization of ﬂow in porous rocks because the photons penetrate the aluminum conﬁnement vessel holding the rock sample at elevated pressures.
Throughout this article, we will also use the phrase explicit imaging when discussing PET imaging. We use the term explicit imaging to emphasize that PET provides a direct measurement of the labeled ﬂuid saturation, which is CO2 in this work. In contrast, attenuation methods, such as X-ray and the more common computed tomography (CT), measure ﬂuid saturation indirectly, through the gradual loss in X-ray ﬂux intensity through the medium that produces a time-averaged density distribution image of the rock, if ﬂuids with sufﬁcient density difference are used. Comparison and use of PET and CT for ﬂow visualization in porous rocks is detailed elsewhere [Fernø et al., 2015].
Cylindrical core plugs were installed in an aluminum biaxial core holder (CoreLab Hassler Core Holder) with a rubber sleeve to apply a radial conﬁnement pressure to ensure that the injected ﬂuid was transported through the pore space. The core holder with the rock samples was placed in the center of the PET/CT (Siemens Biograph Truepoint PET-CT) bore (diameter 700 mm). A CT image (voxel size 0.156 mm3: 0.51 × 0.51 × 0.6 mm3) was obtained to ensure that the rock sample was positioned correctly in the PET detector array and adjusted if needed. Unlike normal diagnostic operations, the rock system was stationary positioned within detector array, with an axial ﬁeld of view of 169 mm. This allowed for dynamic scans with extended PET recording times (up to 17 h continuous scanning was successfully tested) with a spatial voxel size of 8.49 mm3 (2.04 × 2.04 × 2.04 mm3). Signals were continuously recorded, and temporal resolution was set during postprocessing and determined based on a balance between image quality, expressed as signal-to-noise ratio (SNR), and temporal resolution: the higher temporal resolution (shorter time between each image), the lower SNR. An excellent SNR of 200:1 was achieved using temporal resolutions of 10–30 s.
Figure 1. Oil recovery by CO2 injection in ultratight unconventional stacked core system. Graph: Average oil recovery versus time (pore volumes injected) resulting in ﬁnal oil recovery of 55% OOIP during 3.7 PV CO2 injected using Cores A, B, and C. Inset: Visualization of rock characteristics through CT imaging (grey scale), coupled with explicit CO2 signal through PET imaging in Core A. Aligning a threshold CT image (i) and CO2 PET image (ii), obtained after 1 h injection, we observe that the emerged CO2 ﬂow pattern correlated to local rock structure and layered high-low density bands. The injected CO2 ﬂowed in the lower density regions of the core sample, indicative of a layered permeability system, leading to viscous ﬁngers and a highly irregular displacement front.
Positron-emitting radionuclides were produced using particle accelerators on site due to the relatively short half-life (approximately 20 min). Reduction in signal intensity by radioactive decay during ﬂow tests was correctly compensated for using algorithms imbedded in the standard PET/CT software provided by the manufacturer. The use of 11C as a radionuclide tag for methane (CH4) has previously been proposed [Maucec, 2013] but experimentally veriﬁed in this work, for the ﬁrst time, to characterize CO2 ﬂow in porous systems. The 11CO2 phase was produced in a cyclotron by bombarding the target media (N2+1% O2) with 16.5 MeV protons. A batch of 78 ml 11CO2 (and traces of nitrogen) was mixed with CO2 in a 1dm3 injection pump (ST Stigma 1000) and pressurized to experimental conditions. Each injection test started approximately one half-life after initial 11C delivery. Injected radioactive CO2 was collected at the outlet in a production pump set to maintain a constant pressure.
With nanodarcy level permeability, properties like effective diffusion coefﬁcients, CO2 capillary entry pressure, and CO2 ﬂow description in the shale are generally very difﬁcult to measure accurately in the laboratory [Liu et al., 2012]. In this context, alternative approaches to measure these properties are useful, and we report here the ﬁrst experimental demonstration of CO2 tracking for ﬂow characterization in shale using PET/CT imaging. We also evaluate the oil recovery by CO2 injection (see Figure 1), without fracking, in ultratight, unconventional shale core plugs using three stacked 1.5 in diameter cores (Core A: K = 0.74 μdarcy, L = 3.92 cm; Core B: K = 1.7 μdarcy, L= 3.80 cm; Core C: K = 0.12 μdarcy, L = 2.45 cm). Injection conditions (ΔP=7.09MPa; Pinlet= 22.1MPa and Poutlet= 15.0 MPa; T = 60°C) were above minimum miscibility pressure (MMP) between CO2 and crude oil (American Petroleum Institute gravity 38). The initial oil saturation was SO = 0.80. Oil recovery was determined from volumetric measurements downstream of a back pressure regulator (Equilibar HC276-5) at ambient conditions. The injected CO2 was exposed to the inlet end face for 5 days before the injection rate gradually increased for the subsequent 3 days, with an average rate of 6°•10-3 cm3/min. Injection conditions were not changed during the entire test. Final oil recovery factor was RF=55.0 ± 9.2% Original oil in place (OOIP), and oil was still produced (albeit at a very low rate) when the test was terminated.
Coupled ﬂuid-rock interactions during CO2 injection (Ppore= 10MPa, T ambient; injection rate 0.5 cm3/min) in Core A were studied in detail through aligned CO2 ﬂow PET data and rock structures CT data (see Figure 1, inset). The imaging results demonstrated that (1) the layered nature of the sample dictated the preferred ﬂow pattern of the injected CO2 and (2) there is a potential for CO2 to displace oil without fracturing the tight rock. Using dynamic explicit imaging, we observed the development of a dispersed CO2 front and accurately pinpoint the underlying cause for this behavior. The observed shape is indicative of a combination of viscous displacement and molecular diffusion, where local high-density horizontal layers reduce transverse ﬂux. Furthermore, with access to local CO2 ﬂow paths, we learn that the injected CO2 does not fracture the formation when entering the pore space to produce oil. The high oil recovery reported in the stacked system, with RF=55% OOIP, corroborate the second point.
Figure 2. Visualization of diffusive CO2 transport and mixing in a fractured (1 mm constant fracture aperture held open with a spacer) oil-saturated (n-decane) Bentheim core plug. (left) Dynamic longitudinal 11CO2 proﬁles showing increased CO2 saturation over time. Slight intensity dips along the length correlate to support columns in spacer. (right) Symmetric, transverse diffusive CO2 transport from the CO2 saturated fracture (RD=0.0) into the oil-saturated matrix at location XD=0.5. Analytical proﬁles (dashed lines) using equation (1) were ﬁtted to dynamic imaging data with an effective diffusion coefﬁcient of 2.2•108m2/s.
We use a fractured sandstone core rather than a shale sample as we here wish to emphasize the use of CO2 tracking in the determination of Di and not attempt an investigation of validity of Fickian diffusion in shale. Explicit CO2 tracking was utilized in fractured, high-permeable (ϕ=0.22 and K=1.2D) Bentheim sandstone to determine an effective diffusion coefﬁcient directly from PET CO2 tracking data (Figure 2) during miscible CO2 ﬂow (P=8.3MPa, T = 25°C, and Q = 0.15 cm3/min). The fracture was held open with a constant aperture of 0.5mm using a spacer to assure a high conduit ﬂow path to limit viscous forces. Transverse CO2 transport from the CO2 saturated longitudinal fracture to the completely oil-saturated (n-decane) matrix occurred by molecular diffusion only. An effective diffusion coefﬁcient (Di) was estimated using equation (1), with Di as a ﬁtting parameter. With boundary conditions Ci(0, t)=C0 for t>0 (i.e., constant SCO2 at RD=0.0) and Ci(∞, t)=0 for all t (i.e., SCO2=0) at RD=[-1, 1] and the initial condition Ci(x,0)=0 for all x, we derived an effective CO2 diffusion coefﬁcient of 2.2•10-8 m2/s (slightly overestimated due to decreasing volume in the transverse direction of a cylindrical core plug). The diffusion coefﬁcient varies both with temperature and pressure, in addition to rock type (due to variations in pore sizes and distribution, i.e., diffusion path tortuosity), and the reported coefﬁcient agrees reasonably well to other CO2-decane diffusion coefﬁcient ranging between 0.83 and 5.05•10-9 m2/s [Eide et al., 2015; Renner, 1988; Tenga et al., 2014; Trivedi and Babadagli, 2006], although the literature did not use the same temperature and pressure conditions and the rock type as studied in this work. The measured 11CO2 intensity proﬁles deviate from equation (1) over time as the boundary condition is violated, as expected, when the CO2 reach the outer end of the core.
We demonstrate the potential to evaluate CO2 ﬂow and diffusion coefﬁcient with direct, dynamic, and explicit CO2 tracking, rather than using indirect methods, through scouting experiments with combined PET/CT imaging. In particular, access to CO2 ﬂow in challenging tight formations represents a scientiﬁc advancement with potentially large impact. The main advantage with PET is its high sensitivity, requiring a tracer activity as low as 10-12mol/l [Kulenkampff et al., 2008], which enables accurate determination of ﬂow, even in the ultra-tight samples used in this work. Indeed, separate CT imaging cannot provide the same high-quality imaging, especially in low porous rocks, although recent advances are promising [Vega et al., 2014]. Combined PET/CT imaging, however, provides complementary information that exceeds the imaging capability from each method separately. This approach is utilized here to study the ﬂuid-rock interactions relevant for ﬂow in tight formations but can be applied to a larger range of rock types and displacement processes.
Due to the short half-life of 11C (20 min), injection tests must be carefully designed and planned, and 11CO2 cannot be used to evaluate, e.g., long-term carbon capture and storage processes like cap rock integrity [Iglauer et al., 2015] or geochemical effects [Liu et al., 2012]. For these processes, we propose the use of 22Na (half-life 2.6 years and NaCl occurs in most brines), which enables long-term evaluation CO2-brine-shale interaction through direct PET visualization. Based on the experimental results presented herein, we report the following key observations:
API American Petroleum Institute
CCUS Carbon capture utilization and storage
CT Computed tomography
EOR Enhanced oil recovery
MMP Minimum miscibility pressure
PET Positron emission tomography
PV Pore volume
Ci concentration of phase i
C0 surface concentration
darcy darcy (unit for permeability: 1 darcy = 0.9863•10-12 m2)
Di molecular diffusion coefﬁcient for phase i
K absolute permeability
Pinlet absolute pressure at inlet (MPa)
Poutlet absolute pressure at outlet (MPa)
Ppore pore pressure (MPa)
Q injection rate (cm3/min)
RD dimensionless radius
SCO2 CO2 saturation
Sg gas saturation
So oil saturation
Sor residual oil saturation
Sw water saturation
Swi initial water saturation
XD dimensionless length
The authors are indebted to the Norwegian Research Council under Climit project 200032 “In- situ imaging of CO2 ﬂow, storage and entrapment in subsurface aquifers and hydrocarbon,” Petromaks project 200538 “Integrated Enhanced Oil Recovery in Fractured and Heterogeneous Reservoirs,” and Statoil. We also acknowledge Geir-Espen Abell and Tom Christian Holm Adamsen at Centre for Nuclear Medicine and PET, Department of Radiology, Haukeland University Hospital for the operation of PET/CT scanner. The experimental data are available upon request by contacting the corresponding author.
The Editor thanks Stefan Iglauer and an anonymous reviewer for their assistance evaluating this manuscript.
Correspondence to: M. A. Fernø, Martin.Ferno@uib.no
Fernø, M. A., L. P. Hauge, A. Uno Rognmo, J. Gauteplass, and A. Graue (2015), Flow visualization of CO2 in tight shale formations at reservoir conditions, Geophys. Res. Lett., 42, 7414–7419, doi:10.1002/2015GL065100.
Received 6 JUL 2015
Accepted 25 AUG 2015
Accepted article online 29 AUG 2015
Published online 18 SEP 2015
©2015. The Authors. This is an open access article under the terms of the Creative Commons Attribution-NonCommercial-NoDerivs License, which permits use and distribution in any medium, provided the original work is properly cited, the use is non-commercial and no modiﬁcations or adaptations are made.
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