Carbon Storage and Enhanced Oil Recovery in Pennsylvanian Morrow Formation Clastic Reservoirs: Controls on Oil–Brine and Oil–CO2 Relative Permeability from Diagenetic Heterogeneity and Evolving Wettability

Abstract

The efficiency of carbon utilization and storage within the Pennsylvanian Morrow B sandstone, Farnsworth Unit, Texas, is dependent on three-phase oil, brine, and CO2 flow behavior, as well as spatial distributions of reservoir properties and wettability. We show that end member two-phase flow properties, with binary pairs of oil–brine and oil–CO2, are directly dependent on heterogeneity derived from diagenetic processes, and evolve progressively with exposure to CO2 and changing wettability. Morrow B sandstone lithofacies exhibit a range of diagenetic processes, which produce variations in pore types and structures, quantified at the core plug scale using X-ray micro computed tomography imaging and optical petrography. Permeability and porosity relationships in the reservoir permit the classification of sedimentologic and diagenetic heterogeneity into five distinct hydraulic flow units, with characteristic pore types including: macroporosity with little to no clay filling intergranular pores; microporous authigenic clay-dominated regions in which intergranular porosity is filled with clay; and carbonate–cement dominated regions with little intergranular porosity. Steady-state oil–brine and oil–CO2 co-injection experiments using reservoir-extracted oil and brine show that differences in relative permeability persist between flow unit core plugs with near-constant porosity, attributable to contrasts in and the spatial arrangement of diagenetic pore types. Core plugs “aged” by exposure to reservoir oil over time exhibit wettability closer to suspected in situ reservoir conditions, compared to “cleaned” core plugs. Together with contact angle measurements, these results suggest that reservoir wettability is transient and modified quickly by oil recovery and carbon storage operations. Reservoir simulation results for enhanced oil recovery, using a five-spot pattern and water-alternating-with-gas injection history at Farnsworth, compare models for cumulative oil and water production using both a single relative permeability determined from history matching, and flow unit-dependent relative permeability determined from experiments herein. Both match cumulative oil production of the field to a satisfactory degree but underestimate historical cumulative water production. Differences in modeled versus observed water production are interpreted in terms of evolving wettability, which we argue is due to the increasing presence of fast paths (flow pathways with connected higher permeability) as the reservoir becomes increasingly water-wet. The control of such fast-paths is thus critical for efficient carbon storage and sweep efficiency for CO2-enhanced oil recovery in heterogeneous reservoirs.

Full text

energies
Article
Carbon Storage and Enhanced Oil Recovery in
Pennsylvanian Morrow Formation Clastic Reservoirs:
Controls on Oil–Brine and Oil–CO2Relative
Permeability from Diagenetic Heterogeneity and
Evolving Wettability
Lindsey Rasmussen 1, †, Tianguang Fan 2, Alex Rinehart 3, Andrew Luhmann 4,
William Ampomah 2, Thomas Dewers 5,* , Jason Heath 6, Martha Cather 2and Reid Grigg 2
1Petroleum Engineering Department, New Mexico Institute of Mining and Technology,
Socorro, NM 87801, USA; linrasmussen09@gmail.com
2Petroleum Recovery Research Center, New Mexico Institute of Mining and Technology,
Socorro, NM 87801, USA; tianguang.fan@nmt.edu (T.F.); William.ampomah@nmt.edu (W.A.);
martha.cather@nmt.edu (M.C.); reid.grigg@nmt.edu (R.G.)
3Earth and Environmental Science Department, New Mexico Institute of Mining and Technology,
Socorro, NM 87801, USA; Alex.Rinehart@nmt.edu
4Geology and Environmental Science Department, Wheaton College, Wheaton, IL 60187, USA;
luhm0031@umn.edu
5
Nuclear Waste Disposal Research and Analysis, Sandia National Laboratories, Albuquerque, NM 87123, USA
6Geomechanics Department, Sandia National Laboratories, Albuquerque, NM 87123, USA;
jeheath@sandia.gov
*Correspondence: tdewers@sandia.gov
†Now at Timber Creek Energy LLC, Trinidad, CO 81082, USA.
Received: 20 July 2019; Accepted: 16 September 2019; Published: 25 September 2019


Abstract:
The efficiency of carbon utilization and storage within the Pennsylvanian Morrow B
sandstone, Farnsworth Unit, Texas, is dependent on three-phase oil, brine, and CO
2
flow behavior,
as well as spatial distributions of reservoir properties and wettability. We show that end member
two-phase flow properties, with binary pairs of oil–brine and oil–CO
2
, are directly dependent on
heterogeneity derived from diagenetic processes, and evolve progressively with exposure to CO
2
and
changing wettability. Morrow B sandstone lithofacies exhibit a range of diagenetic processes, which
produce variations in pore types and structures, quantified at the core plug scale using X-ray micro
computed tomography imaging and optical petrography. Permeability and porosity relationships in
the reservoir permit the classification of sedimentologic and diagenetic heterogeneity into five distinct
hydraulic flow units, with characteristic pore types including: macroporosity with little to no clay
filling intergranular pores; microporous authigenic clay-dominated regions in which intergranular
porosity is filled with clay; and carbonate–cement dominated regions with little intergranular porosity.
Steady-state oil–brine and oil–CO
2
co-injection experiments using reservoir-extracted oil and brine
show that differences in relative permeability persist between flow unit core plugs with near-constant
porosity, attributable to contrasts in and the spatial arrangement of diagenetic pore types. Core plugs
“aged” by exposure to reservoir oil over time exhibit wettability closer to suspected in situ reservoir
conditions, compared to “cleaned” core plugs. Together with contact angle measurements, these
results suggest that reservoir wettability is transient and modified quickly by oil recovery and carbon
storage operations. Reservoir simulation results for enhanced oil recovery, using a five-spot pattern
and water-alternating-with-gas injection history at Farnsworth, compare models for cumulative oil
and water production using both a single relative permeability determined from history matching,
and flow unit-dependent relative permeability determined from experiments herein. Both match
Energies 2019,12, 3663; doi:10.3390/en12193663 www.mdpi.com/journal/energies

Energies 2019,12, 3663 2 of 33
cumulative oil production of the field to a satisfactory degree but underestimate historical cumulative
water production. Differences in modeled versus observed water production are interpreted in terms
of evolving wettability, which we argue is due to the increasing presence of fast paths (flow pathways
with connected higher permeability) as the reservoir becomes increasingly water-wet. The control of
such fast-paths is thus critical for efficient carbon storage and sweep efficiency for CO
2
-enhanced oil
recovery in heterogeneous reservoirs.
Keywords:
enhanced oil recovery; carbon capture; utilization and storage; relative
permeability; wettability
1. Introduction
Enhanced oil recovery (EOR) utilizing reservoir flooding with high density supercritical carbon
dioxide (scCO
2
) is a means to mitigate rising atmospheric carbon dioxide levels while extracting oil
as an energy resource, with a net storage of carbon in geologic units (often termed carbon capture,
utilization, and storage or CCUS). The focus of EOR/CCUS is on depleted oil reservoirs, and an example
of this is the Farnsworth Unit (FWU) of West Texas (Figure 1), which has been in operation since the
1950s [
1
] and a target of EOR operations since 1984 [
2
]. The Southwest Regional Partnership on Carbon
Sequestration (SWP) was established in 2003 by the US Department of Energy’s National Energy
Technology Laboratory, to study the feasibility of capturing and permanently storing CO
2
. Part of the
SWP’s activities has been devoted to reservoir characterization, injection of scCO
2
, and monitoring
CCUS efficiency at the Farnsworth Unit [2–5].
The efficient management of CCUS in a reservoir or field involves assessing the heterogeneity
and behavior of flow for three-phase oil, brine, and scCO
2
transport, and to this end, in this paper we
examine these for the Morrow B sandstone reservoir (part of the Pennsylvanian Morrow Formation)
of the FWU. Using a method developed by [
6
], we quantify Morrow B reservoir heterogeneity in
Well 13-10A of the FWU, based on analysis of fifty-three core plugs from this well (listed in Table A1
in the Appendix A), in terms of five hydrologic flow units. We use this classification as a basis
to sample representative core plugs for relative permeability experiments. X-ray micro-computed
tomography (
µ
CT) along with optical petrography is used to quantify spatial variations in grain size,
macroporosity (i.e., pores resolvable at the scanning resolution), microporosity in clay-rich regions, and
carbonate cement amongst the flow units. Petrographic analysis shows that much of the residual oil
resides in the clay-associated microporosity but also as pore-lining films in macro-pores. Time-varying
measurements of oil and brine contact angles show that wettability is transient and quickly modified
by pore fluid replacement. The relative permeability of oil–scCO
2
and oil–brine binary pairs was
determined for each core plug using a core flooding apparatus, demonstrating that relative permeability
varies between the five flow units, particularly in residual saturations. Similar to the contact angle
tests, the results suggest that wettability is modified during the measurements, especially with the CO
2
flooding experiments. To show how the measured relative permeability variations might influence
flooding at the reservoir scale, these results were included in a five-spot water-alternating-with-gas
(WAG) injection model extracted from the larger FWU model of Ampomah et al. [
7
,
8
]. Results compare
favorably with cumulative historical oil production at Farnsworth but fail to describe the observed
cumulative water production. We argue that fast paths in the reservoir, composed of the highest
permeability flow unit determined in our study, limit the sweep efficiency of CO
2
plumes involved
in CCUS at Farnsworth, activated as the more depleted zones in the reservoir become increasingly
CO2-wetting.

Energies 2019,12, 3663 3 of 33
3

Figure 1. A.PaleogeographyoftheMorrowBsandstoneintheU.S.midcontinent.ModifiedfromR.
Andrews(OklahomaGeologicalSurvey,PersonalCommunication).B.Stratigraphicboundaries
basedonwirelinelogsofMorrowBsandstonesandsurroundingunitsfromwell13‐2,Farnsworth
Unit,TexasPanhandle(Adaptedwithpermissionfrom[3]).Therangeingammaraylogis0to120
gAPI,andtherangeinresistivitylogis0.20to2.0ohms.C.North‐Southcrosssectionacrossthe
FarnsworthUnit,hungonthetopoftheMorrowshale(delineatedbythemagentaline;figure
Adaptedwithpermissionfrom[6]).TheMorrowBsandstonetopsaredelineatedbythegreenline,
andtheformationbottomsaredelineatedbytheorangeline.Well13‐10A(secondfromleft)core
plugsfromtheMorrowBsandstoneintervalareanalyzedforrelativepermeabilityandother
propertiesinthispaper.
2. Background for CCUS/EOR in the Farnsworth Unit
2.1.MorrowBHeterogeneity
Figure 1.
(
A
). Paleogeography of the Morrow B sandstone in the U.S. midcontinent. Modified from
R. Andrews (Oklahoma Geological Survey, Personal Communication). (
B
). Stratigraphic boundaries
based on wireline logs of Morrow B sandstones and surrounding units from well 13-2, Farnsworth Unit,
Texas Panhandle (Adapted with permission from [
3
]). The range in gamma ray log is 0 to 120 gAPI,
and the range in resistivity log is 0.20 to 2.0 ohms. (
C
). North-South cross section across the Farnsworth
Unit, hung on the top of the Morrow shale (delineated by the magenta line; figure Adapted with
permission from [
6
]). The Morrow B sandstone tops are delineated by the green line, and the formation
bottoms are delineated by the orange line. Well 13-10A (second from left) core plugs from the Morrow
B sandstone interval are analyzed for relative permeability and other properties in this paper.
2. Background for CCUS/EOR in the Farnsworth Unit
2.1. Morrow B Heterogeneity
The FWU is located in Ochiltree County in the Texas Panhandle (Figure 1A) and currently contains
thirteen CO
2
injection wells [
9
]. All CO
2
is derived from two anthropogenic sources: the Arkalon
Ethanol Plant in Liberal, Kansas and the Agrium Fertilizer Plant in Borger, Texas. As of June 2018,
~1,180,000 metric tons of CO
2
have been stored at FWU by the operator and since SWP started

Energies 2019,12, 3663 4 of 33
monitoring, ~734,000 metric tons have been stored [
10
]. The Morrow B sandstone is the target
reservoir for the FWU project, located at a depth between 7550 ft (2301 m) and 7950 ft (2432 m) and
spanning approximately 28 square miles (72 km
2
) with a mean thickness of 24.3 ft (7.4 m; Figure 1B,C;
see also [
7
]). The Morrow B sandstone underlies an upper Morrow Formation shale and the Thirteen
Finger limestone caprocks (Figure 1B) and is estimated to be capable of effectively storing 25 million
metric tons of CO
2
[
7
,
8
]. The Thirteen Finger limestone has been determined to be a viable caprock to
successfully hold the stored CO
2
[
11
]. Note that we use the informal names for lithologies as used by
Puckette et al. [12] and Ampomah et al. [8].
The Morrow B sandstone is a transgressive fluvial-estuarine sandstone that filled paleo-valleys
cut into an underlying Morrow Formation shale during the previous low-stand of the Pennsylvanian
interior sea [
12
]. As with many fluvial and estuarine deposits [
13
], the interior sedimentary structure of
the formation is extremely heterolithic, with interwoven coarse sandstones, fine to medium sandstones,
mudstones, and conglomerates, existing in complicated, unpredictable ways [
12
]. Overall, the
sandstone unit fines upward into an upper Morrow Formation shale (Figure 1C). A large part of
SWP activities at FWU is to characterize the heterogeneity of the Morrow B reservoir. Gallagher [
3
]
provided some initial insight into pore-scale heterogeneity of the Morrow B, subdividing the Morrow
B into five porosity facies and eight subfacies. The porosity facies were categorized as, “intergranular
macroporosity dominated”, “grain-size pore dominated”, “microporous authigenic clay dominated”,
“carbonate cement dominated”, and “intragranular porosity dominated.” The subfacies were based on
pore types, pore distributions and controls on permeability, such as authigenic clay and siderite cement.
Based on petrophysical properties and well logging data from multiple wells across the FWU,
Rose-Coss et al. [
5
] defined eight unique hydrologic flow units (HFUs) [
14
,
15
] to characterize
hydrogeologic heterogeneity for the Morrow B using the Winland R35 method (based on correlations
between measured porosity and permeability), and show how these were distributed with an example
Morrow-B core. The R35 method describes the pore throat aperture radius coinciding to 35% mercury
saturation during a mercury porosimetry test [
16
,
17
]. Ampomah et al. [
7
,
8
] used these definitions
to define a reservoir architecture for reservoir simulation purposes (see reference [
8
], their Figure 2,
showing distributions of porosity and permeability using the HFU concept applied to the Morrow B
reservoir). Using a history matching approach, Ampomah et al. [
8
] derived a three-phase permeability
relationship for the Morrow B sandstone that was capable of describing the cumulative oil production
during water-alternating-with-gas (WAG) EOR operations at the FWU.
For this paper, we apply the same method to core plug data from a core obtained by the SWP
from the FWU well 13-10A in Figure 1C. In the Appendix A, we present a data set (Table A1) derived
from Terra Tek (now Schlumberger) analysis of fifty-three well 13-10A core plugs under the auspices of
the SWP. The porosity and permeability relationships of all core plug data in Table A1 are plotted in
Figure 2, along with core plugs used for relative permeability measurements. The HFU designations
we apply to the 13-10A heterogeneity are simpler than those applied to the entire FWU Morrow-B
by Rose-Coss et al. [
6
] and are detailed in a manuscript in review by Rasmussen et al. The five HFU
designations (I through V as Roman numerals) are shown with color in Figure 2. These designations
are validated by mercury porosimetry in the Rasmussen et al. manuscript and are beyond the scope of
our discussion here.
This classification scheme was used for down-sampling of 13-10A core plugs from each of these
five HFUs for oil–brine and oil–CO
2
relative permeability testing in this study. Table 1defines each of
the Morrow B HFUs with respect to dominant pore throat size and pore type. In this paper, we use
µ
CT imaging to obtain quantitative macro-pore size, framework grain size, and pore type useful for
interpreting differences in behavior between HFUs for the two-phase flow testing. The differences
in spatial distribution of so-called macroporosity (pores resolvable from
µ
CT) and microporosity
(micron-sized pores, most commonly residing in between clay grains) are shown to underlie two-phase
flow behavior that is manifest both at the core plug scale and, arguably, at the reservoir scale. This is

Energies 2019,12, 3663 5 of 33
relevant to CCUS/EOR at Farnsworth, as most of the residual oil observed within well 13-10A resides
within the microporosity.
5

Figure 2.Absolutepermeability–porosityrelationshipsmeasuredfromMorrowBcoreplugstaken
fromwell13‐10AatFarnsworth,delineatedasperHFUdefinitions.Thesolidsymbolsdenotecore
pluganalysesfromTerraTek(nowSchlumberger)usingN
2
gasasporefluidandlistedinTableA1.
The‘x’symbolsandadjacentnumbersrefertosamplesusedforrelativepermeabilityanalysesinthis
paper,andrefertooilpermeabilitydeterminedatinsituconditions(describedintheSupplementary
Materials).
Table 1.DescriptionofHydraulicFlowUnits(HFUs).Adaptedfrom[6].
Hydraulic
Unit
Pore
Throat
Size
Pore Type Description
HFUI
Micro<bre
ak/>0.25
μm‐1.0
μm
Predominantlyintragranularmicro
porosity
Intergranularporosity
obstructedbycarbonate
cement
HFUII
Meso<bre
ak/>1.0
μm‐2.4
μm
Predominantlyintragranularmicro
porosity
Coarsegrainedwithlesser
cementandincreased
amountofclay
HFUIII
Macro<br
eak/>2.5
μm‐4.7
μm
Intragranularmicrowithagreater
amountofintragranularmacro
porosity,sparseintergranularmicro
andmacroporosity
Poorlysortedmedium
grainedwithcarbonateand
claycement
HFUIV
Macro<br
eak/>4.8
μm‐10
μm
Intragranularmicroandmacro
porosityaswellasintergranular
macroandmicroporosity
Coarsetomediumgrained,
moderatelywellsorted
HFUV
Mega<bre
ak/>>10
μm
Intragranularmicroandmacro
porosity,intergranularmacroporosity
Coarsegrained,moderately
wellsortedwithrelatively
lesscement

Figure 2.
Absolute permeability–porosity relationships measured from Morrow B core plugs taken from
well 13-10A at Farnsworth, delineated as per HFU definitions. The solid symbols denote core plug analyses
from Terra Tek (now Schlumberger) using N
2
gas as pore fluid and listed in Table A1. The ‘x’ symbols and
adjacent numbers refer to samples used for relative permeability analyses in this paper, and refer to oil
permeability determined at in situ conditions (described in the Supplementary Materials).
Table 1. Description of Hydraulic Flow Units (HFUs). Adapted from [6].
Hydraulic Unit Pore Throat Size Pore Type Description
HFU I Micro
0.25 µm-1.0 µm
Predominantly intragranular micro
porosity
Intergranular porosity obstructed
by carbonate cement
HFU II Meso
1.0 µm-2.4 µm
Predominantly intragranular micro
porosity
Coarse grained with lesser cement
and increased amount of clay
HFU III Macro
2.5 µm-4.7 µm
Intragranular micro with a greater
amount of intragranular macro
porosity, sparse intergranular micro
and macro porosity
Poorly sorted medium grained
with carbonate and clay cement
HFU IV Macro
4.8 µm-10 µm
Intragranular micro and macro
porosity as well as intergranular
macro and micro porosity
Coarse to medium grained,
moderately well sorted
HFU V Mega
>10 µm
Intragranular micro and macro
porosity, intergranular macro porosity
Coarse grained, moderately well
sorted with relatively less cement
2.2. Variability and Evolution of Wettability during CCUS/EOR in Sandstones
Wettability in sandstone reservoirs has implications for CO
2
trapping and enhanced oil recovery,
but wettability characterization is challenging due to heterogeneous mineralogy in reservoirs and
modifications that arise from the variability of conditions in or relevant to subsurface reservoirs.
Wettability changes will affect capillary pressure, relative permeability, and brine- and CO
2
- flooding
behavior. In situ or direct wettability measurement is not practical for porous media. Liu and
Buckley [
18
] used water drop contact angles on different mica minerals as rock surfaces to assess their
wetting states at different brine, oil, and temperature conditions. Alotaibi et al. [
19
] used a Drop Shape
Analysis (DSA) system to measure the contact angles of oil captive drops on small core slabs with

Energies 2019,12, 3663 6 of 33
brines of different salinity, temperature, and pressure. Amott or USBM wettability indexes have long
been used to evaluate the wetting state of larger size core samples [
20
,
21
], however measurements are
expensive and time consuming. Their accuracy and repeatability are subject to experiment conditions
and empirical bias.
Even with an individual mineral, wettability experiments in an oil–brine–calcite system have
demonstrated a range of oil-wet to water-wet responses that depend on pH, mineral surface composition,
dissolved ion composition, and whether samples were aged with oil [
22
–
25
]. Still, efforts continue
to improve our fundamental understanding of wettability controls. For example, recent research
suggests that quartz wettability generally depends on the hydrocarbon and non-aqueous fluid density
for a particular set of experimental conditions [
26
]. Most relevant for our study, wettability may be
altered in rock–oil–brine systems [
20
,
21
,
27
]. Low-salinity waterflooding is one such process that causes
wettability modification and leads to higher oil recovery [
28
]; several mechanisms have been proposed
to explain the effect, although there has been no consensus [
29
–
34
]. Wettability modification will also
occur in rock–oil–CO
2
systems [
35
], due to the fact that CO
2
reduces the viscosity of crude oil [
36
] and
leads to asphaltene precipitation [
37
,
38
] during the oil–CO
2
interaction. Thus, wettability should be
expected to evolve during subsurface engineering endeavors involving perturbations of pore fluid
composition, rather than being a simple fixed parameter for a given reservoir rock type.
For the Morrow B lithofacies, we show that two-phase oil–brine and oil–CO
2
relative permeability
behavior can be interpreted in terms of evolving wettability during experimental testing; our
experimental and modeling results suggest that reservoir-scale changes in wettability have occurred in
the Morrow B both because of historical water flooding, and also from more recent WAG operations.
3. Methods
3.1. Core Plug Selection and Preparation
A nearly complete section of four-inch diameter cores from the Morrow B well 13-10A at
Farnsworth was retrieved and cut into approximately three-foot sections and sealed at the wellsite.
The cores were shipped to TerraTek (now Schlumberger) which preserved them in cellophane and foil.
Horizontal core plugs 1.0 and 1.5 inches in diameter (2.5 and 3.8 cm, respectively) and approximately
three inches (7.6 cm) in length (limited by the diameter of the core) were cut and prepared by TerraTek
and were subject to Dean–Stark extraction for hydrocarbons, or “cleaning”. Terra-Tek performed
nitrogen gas permeability and porosimetry measurements on fifty-three of the cleaned plugs, and the
data are summarized in Table A1 in the Appendix A. The values for residual water saturation and
residual hydrocarbon content were determined by TerraTek using this analysis, and are also presented
in Table A1. Six plugs were down-selected based on the HFU classification scheme applied to Morrow
B heterogeneity by Rose-Coss et al. [
5
] and Rasmussen et al. (in review). Cores were shipped to Sandia
National Laboratories (New Mexico) which prepared right-cylinders ground to tolerance for core
flooding, and measured (effective) porosity by helium porosimetry. Additional core was cut from the
higher permeability portions of the Morrow B at New Mexico Tech (NMT) to be used as end pieces for
the core flooding experiments. This was to mitigate capillary end effects [
39
] that could arise in the
relatively short horizontal core plugs that could be sampled from the Morrow B core. The additional
cores were 1.5 inches (3.8 cm) in diameter and were 1.85 inches (4.7 cm) and 2.1 (5.3 cm) inches long.
To achieve a consistent initial wettability for all core plugs (approximating reservoir conditions
at the start of water flooding), we examined two methods for flooding cores with an oil phase taken
directly from a well head at Farnsworth described below. For one core, reservoir oil flowed through
the core at reservoir conditions at a rate of one pore volume per day, for at least seven days. The second
core was aged in a vacuum system at 76
◦
C (reservoir temperature that was used in the relative
permeability experiments) that pulled the oil into the core. Once the oil replaced the air within the
core, it was left stagnant for seven days to age. The necessary time to bring the core back to reservoir
wettability is highly dependent on the reservoir [
20
,
21
,
40
,
41
] but our experience with Morrow B

Energies 2019,12, 3663 7 of 33
wettability, described in the Results section, suggests that seven days of exposure is sufficient to bring
core to a consistent state of oil-wet initial conditions. Both methods using core sample 19 yielded the
same relative permeability results, suggesting that time-exposure to an oil phase was the determining
factor in wettability modification. We measured absolute oil phase permeability in our core-flooding
apparatus, using a temperature of 76
◦
C, a confining pressure of 8000 psi (55.2 MPa), and a downstream
pore pressure of 4000 psi (27.6 MPa). These are in situ reservoir conditions within the Morrow B
surrounding the 13-10A well as determined by Rose-Coss et al. [
5
] and Ampomah et al. [
8
]. In Table 2,
we list core sample numbers, HFU designation, plug depths, final diameter and length used in the
testing, helium-derived porosity, and oil-phase permeability for six core plugs used in the two-phase
oil–brine and oil–CO2flow measurements.
Table 2. Physical properties of core plug samples used in this study.
Core
Sample HFU Length
(cm)
Diameter
(cm)
Depth
(m)
Absolute
Permeability @ In
Situ Effective
Pressure (mD)
Porosity
(%)
19 V 6.27 3.76 2347.4 83.7 18.67
L7 IV 5.51 3.81 2343.5 59.5 15.41
L6 III 5.63 3.79 2437.1 40.1 13.44
L5 III 5.63 3.84 2344.5 22.1 15.34
L4 II 5.03 3.76 2338.4 9.06 15.31
1 I 5.10 3.76 2337.9 0.149 15.35
3.2. Fluid Origin and Preparation
The brine and oil used in this study for relative permeability measurements were collected from
the sampling lines directly located on the wellheads from Farnsworth production wells. For simplicity,
the term “brine” will be used throughout the paper to define the produced water from the Farnsworth
Field, which is better described as a brackish solution. Although brine compositions across the field
vary somewhat with space and time, those used in this study are quite similar. Brine from well 13-14
was used for the contact angle measurements, and brine from well 13-12 was used for the two-phase
flow tests. The oil used for this work was from production well 13-12. Brines were collected in 2017
and stored in a refrigerator until use. Chemical properties of the brine are given in Table 3, physical
properties of the oil are given as a function of temperature in Table 4, and the physical properties of all
three phases at the testing conditions are given in Table 5. The physical and chemical properties of the
brine, and density and viscosity data of the oil at different temperatures, were determined by Core
Laboratories of Houston, TX. CO
2
used in this study was industrial grade and provided by AirGas
TM
.
The density and viscosity of scCO
2
at experimental conditions were calculated from the National
Institute of Standards and Technology (NIST) Chemistry WebBook (webbook.nist.gov); this uses the
NIST Reference Fluid Thermodynamic and Transport Properties Database (REFPROP version 7) based
on data in Span and Wagner [42] and Fenghour et al. [43].

Energies 2019,12, 3663 8 of 33
Table 3.
Analysis of wells 13-14 and 13-12 brine composition used in the contact angle measurements
and two-phase flow tests. TDS is total dissolved solids (calculated), and ORP is measured oxidation
reduction potential.
Well 13-14 13-12
pH 7.4 7.1
Conductivity (uS/cm) 7660 6530
Alkalinity as HCO3-(mg/L) 815 752
Chloride (Cl) (mg/L) 1846 1721
Fluoride (F) (mg/L) 1.5 1.6
Bromide (Br) (mg/L) 19.5 21.3
Nitrate (NO3) (mg/L) 0 0
Phosphate (PO4) (mg/L) <0.50 <0.50
Sulfate (SO4) (mg/L) 39 6.8
Lithium (Li) (mg/L) 0.33 0.4
Sodium (Na) (mg/L) 1459 1312
Potassium (K) (mg/L) 7.9 7.4
Magnesium (Mg) (mg/L) 9.2 9.7
Calcium (Ca) (mg/L) 43.9 49.2
TDS Calculation (mg/L) 3807.5 3478.1
ORP (mV) 405 nd
Inorganic Carbon (ppm) 187.7 nd
Non-Purgeable Organic Carbon (ppm)
6.34 nd
Table 4. Density and viscosity of well 13-12 oil as a function of temperature.
Temp (◦C) Viscosity (cP) Density (g/mL)
20 29.2 0.844
25 19.4 0.840
30 14.7 0.844
40 10.3 0.830
50 7.76 0.823
60 5.95 0.816
70 4.74 0.810
Table 5. Physical properties of fluids used for two-phase experiments.
Fluid Density (kg/m3)Viscosity (cP) Salinity (ppt)
scCO2747.6 0.06 -
Brine 975.4 0.40 7.6
Oil 746.6 1.66 -
3.3. Wettability Measurements
To estimate changes in wettability associated with water-flooding, we measured contact angles
using a drop method directly on a 1” diameter core plug subject to sequential oil and brine flooding. We
used a one-inch diameter core plug extracted from well 13-14, corresponding to the HFU V hydrologic
flow unit (Table 1) and cleaned of residual hydrocarbons using the Dean–Stark extraction method.
Initial Brine flood: After checking for leaks, the core was placed in a Core Laboratories core holder,
exposed to vacuum and saturated with brine. Following twenty-four hours of exposure, the brine
permeability of the core was measured at room temperature of 21
◦
C. After brine flooding, the core
was removed from the core holder, wrapped with teflon tape and aluminum foil to prevent water
evaporation, and then transferred to instrumentation for contact angle measurement.
Oil flood and wettability alteration: After contact angle measurement, the brine-flooded core was
reassembled into the core holder and flooded with field oil at room temperature to achieve an oil
saturation corresponding to initial water saturation (S
wi
). After about 10 pore volumes of oil flooding,

Energies 2019,12, 3663 9 of 33
no visible brine was observed at the core holder exit, and its S
wi
was calculated based on collected
brine volume. The core holder was then transferred to a temperature-controlled oven for wettability
alteration. The oven temperature was held at 70
◦
C (158
◦
F), similar to field conditions at Farnsworth,
and the core was aged for two weeks. During this period, at least 3 pore volumes per day of fresh
oil were pumped continuously through the core. To prevent oil evaporation, 100 psi (0.69 MPa) back
pressure was applied to the core holder along with 450 psi (3.1 MPa) overburden pressure. The final
oil permeability was measured at 70
◦
C and determined to be 129 mD. After aging, the core holder was
removed from the oven, cooled, and disassembled, and the core again wrapped in teflon tape and foil
for preservation prior to contact angle measurement.
Brine-displacing-oil flood: After contact angle measurement of the oil-flooded core, the core was
again placed in the core holder, this time for a brine-displacing-oil experiment. The core was flooded
with field brine in a 70
◦
C oven. After about 10 pore volumes of brine flooding, no oil droplets were
observed at the core holder outlet, and the oil phase was considered at residual saturation. The core
holder was then removed from the oven and cooled, with the core again preserved with teflon tape
and foil wrap and transferred to equipment for contact angle measurement.
Contact angle measurement: Contact angles were measured with a DSA system from Dataphysics
(OCA 20 Contact Angle System, SCA20 software, Dataphysics, Charlotte, NC, USA). In this system,
the droplet image is captured via CCD camera and contact angle determined from the images using
the associated software. All contact angles were measured with reference to the water phase.
3.4. Core Flooding Experiments
Experiments were conducted using a high-pressure flow-through system, shown schematically in
Figure 3A. The system is built around a high-pressure core holder (Version DCH, Core Lab Instruments,
Tulsa, OK, USA) shown schematically in Figure 3B and uses high-pressure tubing, valves and fittings
manufactured by High-Pressure Corporation
TM
. A single ISCO 100D syringe pump (Teledyne ISCO,
Lincoln, NE, USA) is used to supply and maintain confining pressure to the sample; two ISCO series
260 syringe pumps supply the pressure and metering of upstream pore fluids and pressure via two
accumulators manufactured by Core Laboratories. A single 500HP ISCO pump supplies downstream
pressure and fluid metering via an additional accumulator. The core holder and accumulators are
housed within an insulated heating box with a Watlow controller, heater, and fan to equilibrate
temperatures within the box.
Within the core holder, three pressure taps are fixed to a Buna-N sleeve containing the sample
enabling determination of axial pressure gradients across the sample. Pore pressure was monitored
via Heise 7500 psi (51.7 MPa) pressure transducers connected to the pressure taps, with an accuracy
of
±
1.875 psi or 0.0129 MPa. All wetted parts of the core holder were composed of Hastelloy C360
including pore lines, sample distribution plugs, and fittings. One sample distribution plug is fixed
to the core holder end while the other floats, enabling measurement of cores of differing lengths and
assuring hydrostatic pressure conditions. The sample core plug was sandwiched in between two rock
end pieces composed of Morrow B core from HFU V; this was done to minimize capillary-end effects,
especially at the downstream end of the core plug sample.
All tests were conducted at 76
◦
C, 4000 psi (27.6 MPa) brine fluid pressure, and 8000 psi (55.2 MPa)
axial and radial confining (overburden) pressure to simulate in situ effective pressure conditions of
the Morrow B reservoir. Prior to the initiation of each two-phase experiment, each fluid pair was
pre-equilibrated in the upstream accumulators. The accumulators were pressurized to experimental
pore pressure by running the pumps at constant pressure mode, and the pump volumes were recorded.
Upon pressurization, pump volumes initially decreased, but phase equilibration was determined when
pump volumes stabilized. For the oil and brine experiments, equilibration took a few hours, while the
oil and gas experiments took approximately six hours to achieve phase equilibration.

Energies 2019,12, 3663 10 of 33
11
equilibration.
Figure 3. A.High‐pressureflow‐throughsystemschematicforoil/brineandoil/CO
2
experiments.B.
High‐pressurehydrostaticcoreholder,showingtheHFUsamplecoreplug,HFUendpiecesmadeof
shortpiecesofcoreplugs,andmultiplepressuretaps,usedtominimizecapillaryendeffectsinthe
measurementandinterpretationofrelativepermeability.
Allcorefloodingexperimentswereperformedundersteady‐stateflowratesandapproximately
tenporevolumesoffluidsweredisplacedpriortothefinalrelativepermeabilitymeasurement
[44,45].Initially,absoluteoilpermeabilityofeachcorewasdeterminedatincreasingconfining
pressures,untilthecoreholderconfiningfluidwasfullypressurizedto8000psi(55.16MPa).Oil
permeabilitywasseentosystematicallydecreasewithincreasingconfiningpressureandeffective
pressure,andthisdataisplottedbyHFUintheSupplementaryMaterials.Pressurevariationswere
determinedatprogressivelyincreasingfractionalflowofbrine,𝑓,(orsupercriticalCO
2
,scCO
2
)
calculatedas
𝑓
 𝑄
𝑄 𝑄(1)
whereQ
wi
istheinjectionrateofbrineatstageiandQ
oi
istheinjectionrateofoilatstagei.Bychanging
theinjectionratioinastepwisemanner,theentireaveragewatersaturation(𝑆)range(irreducible
brinesaturation,S
w,irr
,toresidualoilsaturation,S
or
)canbemeasuredusingmassbalance:
𝑆𝑆, 1𝑆 𝑆,
𝑓
(2)
Figure 3.
(
A
). High-pressure flow-through system schematic for oil/brine and oil/CO
2
experiments.
(
B
). High-pressure hydrostatic core holder, showing the HFU sample core plug, HFU end pieces made
of short pieces of core plugs, and multiple pressure taps, used to minimize capillary end effects in the
measurement and interpretation of relative permeability.
All core flooding experiments were performed under steady-state flow rates and approximately
ten pore volumes of fluids were displaced prior to the final relative permeability measurement [
44
,
45
].
Initially, absolute oil permeability of each core was determined at increasing confining pressures, until
the core holder confining fluid was fully pressurized to 8000 psi (55.16 MPa). Oil permeability was seen
to systematically decrease with increasing confining pressure and effective pressure, and this data is
plotted by HFU in the Supplementary Materials. Pressure variations were determined at progressively
increasing fractional flow of brine, fwi , (or supercritical CO2, scCO2) calculated as
fwi =Qwi
Qwi +Qoi
(1)
where Q
wi
is the injection rate of brine at stage iand Q
oi
is the injection rate of oil at stage i. By changing
the injection ratio in a stepwise manner, the entire average water saturation (
Sw
) range (irreducible
brine saturation, Sw,irr, to residual oil saturation, Sor) can be measured using mass balance:
Sw=Sw,irr +(1−Sor −Sw,irr)×fwi (2)

Energies 2019,12, 3663 11 of 33
Relative permeabilities (kro for oil and krw for brine) are determined from [46]
kro =−Qnwµnw L
A∆Pnwk,krw =−QwµwL
A∆Pwk(3)
where Q(
cm3
s)
is volumetric flow rate for the nonwetting (
nw
) phase and wetting (
w
) phase,
µ
(cp)
is the fluid dynamic viscosity, L (cm) and A(cm
2
) are the core plug length and cross-sectional area,
respectively,
∆
P (MPa) is the pressure difference measured across the core, and k (mD) is the single
phase (oil) permeability.
Following the series of five or six measurements at varying fractional flow values, irreducible
oil saturation (S
o,irr
) is then reached by injecting brine or scCO
2
, until oil is no longer produced and
the pressure difference across the core stabilizes. The sample was then subject to oil displacement to
determine irreducible saturation of the non-wetting phase (S
nw,irr
). This was done by decreasing the
brine or scCO
2
fractional flow in a stepwise manner to evaluate hysteresis during brine displaced by
oil. During all tests, flow rates were limited so that pore fluid pressures did not exceed the confinement
pressure and to ensure isolation between pore and confining pressures via the sleeve.
The Corey and Brooks correlation was used to generate the full relative permeability curve and
predict the imbibition curve, using both the relative permeability endpoint of brine at residual oil
saturation
k◦
rw@Sor
and the relative permeability endpoint of oil at irreducible brine saturation
k◦
ro@Sw,irr
from the imbibition experimental run.
krw =k◦
rw@Sor Sw−Sw,irr
1−Sw,irr −Sor !λ
(4)
kro =k◦
ro@Sw,irr 1−Sw−Sor
1−Sw,irr −Sor !λ
(5)
λ
defines the uniformity of the grain size distribution [
47
] and is calculated using a VBA regression
code that changes the
λ
value until the Nash–Sutcliffe efficiency of the laboratory data and the Brooks
and Corey correlation reaches maximum efficiency. The Nash–Sutcliffe efficiency (NSE) is the sum of
the squared differences between the predicted and the actual values normalized by the variance of the
observed values.
NSE =1−Pn
i=1(YObs
i−YSim
i)2
Pn
i=1(YObs
i−YMean
i)2(6)
3.5. µCT Imaging and Optical Petrography
X-ray micro-computed tomography (X-ray
µ
CT) imaging was performed on Morrow B core
plugs using either a Zeiss Xradia 520 Versa 3D X-ray microscope, which combines geometric and
optical magnification to produce tomographic reconstructions of the plug, or a North Star Imaging
X50 micro-CT scanner and PaxScan 2520DX Digital Image detector, with North Star efX-DR and
efX-CT software used for image acquisition and reconstruction, respectively. Both methods provide
tomographic reconstruction in the form of stacks of registered tiffimages with a voxel size of 3375
µ
m
3
(15
µ
m
×
15
µ
m
×
15
µ
m). Digital image analysis of pore characteristics in the pre- and post-image
sets utilized FIJI
TM
software [
48
] to convert tiffstacks to 8-bit images, to perform a cylindrical
crop which provided clean right-circular cylindrical boundaries, and to equalize grey levels via a
histogram-matching algorithm. The modified image stacks were then examined via FEI’s PERGEOS
TM
v1.7 software, distributed by Thermo Fisher Scientific. A median filter algorithm applied to the
image stacks improved the delineation of phase boundaries. A segmentation algorithm was then
applied to determine, label, and measure pore volume and porosity. Macro-pore space was separated
into pores and pore throats, which then allowed the creation of 3D visualizations of pores and pore
throats, and the generation of pore network models. We used OpenPNM [
49
], an open source suite of

Energies 2019,12, 3663 12 of 33
software for analyzing pore network models, to examine single phase permeability of an example HFU.
Additionally, we used part of the Synapsis
TM
software suite, Simpleware
TM
, to visualize connected
and unconnected portions of pore networks delineated by the µCT reconstructions.
3.6. Reservoir Simulation
We examined the impact of using three-phase relative permeability values calculated in this study
by mapping the HFU distributions onto a portion of a geocellular model used by Ampomah et al. [
8
],
who describe the primary, secondary, and tertiary recovery operations at this field over fifty-five years.
For this study, we have isolated a five-spot injector-producer pattern abstracted from the model of
Ampomah et al. [
8
] and examine tertiary oil recovery occurring since 2011 associated with scCO
2
injection via WAG injection following the Ampomah et al. [
8
] model. Eclipse E300 software was used
in all simulation runs, and we compare a model using a single relative permeability relationship from
Ampomah et al. [
8
] to results using relative permeability measurements from this study, mapped onto
the HFU distribution in the reservoir model of Rose-Coss et al. [5].
Three-phase oil relative permeability was calculated using the Baker Model, due to the complexity
of three-phase laboratory experiments. The Baker Model in (7) (saturation–weight interpolation) is an
interpolation between the two-phase oil/brine relative permeability data and the two-phase oil/CO
2
relative permeability data [50].
kro =(Sw−Swr)kro(w)+Sg−Sgr kro(g)
(Sw−Swr)+Sg−Sgr (7)
where S
wr
is the residual brine saturation, S
g
is the gas saturation, S
gr
is the residual gas saturation,
k
ro
(w) is the two-phase oil relative permeability in the oil/brine system, and k
ro
(g) is the two-phase oil
relative permeability in the oil/CO2system.
The five hydraulic flow units were integrated into the existing geological model of the Farnsworth
unit developed by Ampomah et al. [
8
]. The five-spot pattern subsection, including the four wells
surrounding the injector well where the cores in this study were drilled (well 13-10A), was used for
the simulation analysis (Figure 4). Wells 13-6, 13-16, 13-12, and 13-14 are producers. Brine and oil
from these wells were used in the experiments as previously noted in Section 3.2. Figure 4B shows the
permeability distribution based on the five hydraulic flow units used by Ampomah et [
8
]. Figure 4C
shows the porosity distribution developed by Rose-Coss et al. [
5
], incorporating the Farnsworth Unit
facies model. Hysteresis was not taken into account.
Additionally, constant wettability (i.e., no switching between oil and water-wet conditions),
is implicit in the use of a constant set of absolute and relative permeabilities in both the calibrated and
laboratory-based models.

Energies 2019,12, 3663 13 of 33
14

Figure 4.A.Thefive‐spotgeologicalmodeloftheFarnsworthUnitusedinthisstudy.WellLocations,
withwell13‐10Abeingtheinjectorsurroundedbyproducerwells.B.Permeabilitydistribution
followingAmpomahetal.[8].C.PorositydistributionfollowingAmpomahetal.[8]andRose‐Coss
etal.[5].
4. Results
4.1.DiageneticCapillaryHeterogeneityinMorrowBSandstones
CapillaryheterogeneityintheMorrowBwasdiscussedbyGallagher[3]intermsofporetypes
orporosityfaciesandwasplacedinthecontextoftheHFUconceptbyRasmussenetal.(inreview)
andhereininFigure2.Hereweprovidedetailsonporeconnectivityandshowhowdiagenesis,and
inparticularthedevelopmentofsecondarymicroporosityassociatedwithclayalterationoffeldspars,
underliestheHFUconceptandultimatevariabilityofmultiphaseflowbehaviorintheMorrowB
reservoir.Figure5showsphotomicrographsofthinsectionsfromcoreplugendbutts,representative
ofeachHFUcoreplugusedinthisstudy.AsshowninFigure2,HFUVisrepresentativeofMorrow
Bsandstoneswithhigherpermeabilityatagivenporosity;HFUIisrepresentativeofsandstoneswith
theleastpermeabilityatagivenporosity.HFUV(core19)inFigure5Ashowsthat,generally,the
HFUVsamplesarerelativelywellsortedandhaveahighdegreeofconnectedmacroporosityand
lesseramountsofclay‐associatedmicroporositycomparedtotheotherunits.HFUIV(Figure5B)
samplesaremoderatelysorted,withagreaterextentofclay‐associatedmicroporosityandcarbonate
cements.HFUIIIsamples(Figure5C,D)arepoorlysorted,withvirtuallynoconnectedpathways
involvingmacropores,whichareisolatedandsurroundedbymicroporosityofferingtheonly
connectedflowpathwaysintheunit.HFUIIandI(Figure5EandF)aremoderatelywellsortedvery
coarse‐grainedsandstoneswithmuchoftheirintergranularvolumeoccludedbyauthigenicferroan
carbonatecement,mostimpressivelyinHFUIwherelittleconnectedmacroporosityisobserved.
Secondaryporosityassociatedwithfeldspardissolutionismostlyintheformofclay‐associated
microporosity.Thesethinsectionsshowthatporosityandbyextensionpermeabilitydifferences
betweentheHFUsisrelatedinparttodepositionalheterogeneity,butrelativelyminor
heterogeneitiesareamplifiedbydiageneticalterationtoproducemuchlargervariabilityin
permeability.
Figure 4.
(
A
). The five-spot geological model of the Farnsworth Unit used in this study. Well Locations,
with well 13-10A being the injector surrounded by producer wells. (
B
). Permeability distribution following
Ampomah et al. [8]. (C). Porosity distribution following Ampomah et al. [8] and Rose-Coss et al. [5].
4. Results
4.1. Diagenetic Capillary Heterogeneity in Morrow B Sandstones
Capillary heterogeneity in the Morrow B was discussed by Gallagher [
3
] in terms of pore types or
porosity facies and was placed in the context of the HFU concept by Rasmussen et al. (in review) and
herein in Figure 2. Here we provide details on pore connectivity and show how diagenesis, and in
particular the development of secondary microporosity associated with clay alteration of feldspars,
underlies the HFU concept and ultimate variability of multiphase flow behavior in the Morrow B
reservoir. Figure 5shows photomicrographs of thin sections from core plug end butts, representative
of each HFU core plug used in this study. As shown in Figure 2, HFU V is representative of Morrow B
sandstones with higher permeability at a given porosity; HFU I is representative of sandstones with
the least permeability at a given porosity. HFU V (core 19) in Figure 5A shows that, generally, the HFU
V samples are relatively well sorted and have a high degree of connected macroporosity and lesser
amounts of clay-associated microporosity compared to the other units. HFU IV (Figure 5B) samples
are moderately sorted, with a greater extent of clay-associated microporosity and carbonate cements.
HFU III samples (Figure 5C,D) are poorly sorted, with virtually no connected pathways involving
macropores, which are isolated and surrounded by microporosity offering the only connected flow
pathways in the unit. HFU II and I (Figure 5E,F) are moderately well sorted very coarse-grained
sandstones with much of their intergranular volume occluded by authigenic ferroan carbonate cement,
most impressively in HFU I where little connected macroporosity is observed. Secondary porosity
associated with feldspar dissolution is mostly in the form of clay-associated microporosity. These thin
sections show that porosity and by extension permeability differences between the HFUs is related in
part to depositional heterogeneity, but relatively minor heterogeneities are amplified by diagenetic
alteration to produce much larger variability in permeability.

Energies 2019,12, 3663 14 of 33
15

Figure 5.Thinsectionphotomicrographsofcoreplugbuttendsepoxiedwithafluorescent‐dyed
epoxy.PhotomicrographsA–FcorrespondtoHFUsVthroughIaslabelledintheimages.Evident
betweentheHFUsarevaryinggrainsize,sorting,amountsandtypeofiron‐bearingcarbonate
mineral,andextentofmacroporosityversusmicroporosity.Q–quartz;c–claybearingmicroporosity
includingblackbitumen;I–undeterminedironcarbonatephase;k–kaoliniteandbitumen‐bearing
microporosity;s–sideritewithsphalerohedralcrystalhabit.
Tomorecloselyexaminedifferencesbetweentheintergranularvolumeofthedepositional
frameworkbetweentheHFUs,weshowinFigure6fourfull‐coreCTscansofHFUunits.Atthe
resolutionoftheimages(~31μm×31μm×31μmvoxelsize)onecanonlyobservequalitativelythat
porosities(inblue)fortheHFUVthroughHFUIIIsamplesarenearlythesame.InFigure6D,itis
evidentthatporosityintheHFUIsampleisoccludedinnearlyhalfofthecorebysideritecements,
whichappearaswhitepatchesinthewholecorescan.
Figure 5.
Thin section photomicrographs of core plug butt ends epoxied with a fluorescent-dyed epoxy.
Photomicrographs (
A
–
F
) correspond to HFUs V through I as labelled in the images. Evident between the
HFUs are varying grain size, sorting, amounts and type of iron-bearing carbonate mineral, and extent
of macroporosity versus microporosity. Q—quartz; c—clay bearing microporosity including black
bitumen; I—undetermined iron carbonate phase; k—kaolinite and bitumen-bearing microporosity;
s—siderite with sphalerohedral crystal habit.
To more closely examine differences between the intergranular volume of the depositional
framework between the HFUs, we show in Figure 6four full-core
µ
CT scans of HFU units. At the
resolution of the images (~31
µ
m
×
31
µ
m
×
31
µ
m voxel size) one can only observe qualitatively that
porosities (in blue) for the HFU V through HFU III samples are nearly the same. In Figure 6D, it is
evident that porosity in the HFU I sample is occluded in nearly half of the core by siderite cements,
which appear as white patches in the whole core scan.

Energies 2019,12, 3663 15 of 33
16

Figure 6.CTreconstructionsoffullcorescansat31μm×31μm×31μmvoxelsizethatshowporosity
ofthedifferentHFUunits(inblue).A.HFUVSample19.B.HFUIV,Sample18fromRasmussenet
al.(inreview).C.HFUIII,Sample14fromRasmussenetal.(inreview).D.HFUI,Sample1.
UsingthefunctionalitiesofthePergeos
TM
software,wecanextractandsegmentindividual
frameworkgrains,macropores,andmicroporousdomains,calculateporeconnectivity,andextract
porenetworksformodeling.PlottedinFigure7areframeworkgrainsizedistributionplotsforeach
ofthecores,basedonextractinga500×500×500voxel(7.5×7.5×7.5mm)domainfromtheinterior
ofthewholecorescansofFigure6.TheseshowthattheHFUcoresrepresentativeofthosechosenfor
two‐phaseflowtestingarecoarsetoverycoarse‐grained,moderatelytopoorlysortedsandstoneand
granularconglomerates,whichagreeswiththeassessmentoftheMorrowBbyGallagher[3]andalso
byCatherandCather[51],whodidathoroughassessmentofthecoredwellsatFWU.HFUIVis
moderatelysortedandthecoarsestgrainedofthesamples,whereasHFUVisslightlybettersorted
andslightlyfinergrained.Asevidentfromthegraindistributions,ifoneweretoconsiderjustthe
compactedframeworkgrains,onewouldexpectrelativelyhighpermeabilitywithminorvariation
betweenthesamples.Itisclearthenthatotherprocesses,suchasdiagenesis,mustbecontrollingthe
observedpermeabilityvariations.IntheSupplementaryMaterials,weshowfrequencyhistogramsof
macro‐poresizeandthroatdistributionsandporeconnectivity,consideringjusttheporousnetwork
consistingofthecompactedframeworkgrainsonly.DifferencesbetweentheHFUsinporeandpore‐
throatsizedistributionsandmacro‐poreconnectivityshowatexturalbasisforthemeasured
permeabilityobservedfortheHFUs.Forexample,HFUVhasthelargestmacroporesize,macropore
throatsize,andlargestconnectivityofmacroporescomparedtotheotherHFUs.Connectivitydata
comparingconnectionsbetweenmicroporouszonesandmacro‐poresshowthatinHFUIV‐HFUII,
connectedporenetworksrequiretransportviamicro‐porousdomains,withmoreisolatedmacro‐
poresfromHFUIVtoII.
HFUVistheunitclosesttothisidealofcompactedframeworkgrainporosityapproximating
actualporosity(i.e.,withcomparativelyminimalmicroporosity).Figure8Ashowsasubsetof1000×
1000×1000pixelsfromthewholecore19(HFUV),examinedindetailforthetwo‐phaseflow
experiments.ThemacroporosityisvisualizedinFigure8BandC,whereweseeallmacropores(in
Figure 6. µ
CT reconstructions of full core scans at 31
µ
m
×
31
µ
m
×
31
µ
m voxel size that show
porosity of the different HFU units (in blue). (
A
). HFU V Sample 19. (
B
). HFU IV, Sample 18 from
Rasmussen et al.
(in review). (
C
). HFU III, Sample 14 from Rasmussen et al. (in review). (
D
). HFU I,
Sample 1.
Using the functionalities of the Pergeos
TM
software, we can extract and segment individual
framework grains, macropores, and microporous domains, calculate pore connectivity, and extract
pore networks for modeling. Plotted in Figure 7are framework grain size distribution plots for each of
the cores, based on extracting a 500
×
500
×
500 voxel (7.5
×
7.5
×
7.5 mm) domain from the interior
of the whole core scans of Figure 6. These show that the HFU cores representative of those chosen
for two-phase flow testing are coarse to very coarse-grained, moderately to poorly sorted sandstone
and granular conglomerates, which agrees with the assessment of the Morrow B by Gallagher [
3
] and
also by Cather and Cather [
51
], who did a thorough assessment of the cored wells at FWU. HFU IV is
moderately sorted and the coarsest grained of the samples, whereas HFU V is slightly better sorted
and slightly finer grained. As evident from the grain distributions, if one were to consider just the
compacted framework grains, one would expect relatively high permeability with minor variation
between the samples. It is clear then that other processes, such as diagenesis, must be controlling the
observed permeability variations. In the Supplementary Materials, we show frequency histograms of
macro-pore size and throat distributions and pore connectivity, considering just the porous network
consisting of the compacted framework grains only. Differences between the HFUs in pore and
pore-throat size distributions and macro-pore connectivity show a textural basis for the measured
permeability observed for the HFUs. For example, HFU V has the largest macro pore size, macro pore
throat size, and largest connectivity of macropores compared to the other HFUs. Connectivity data
comparing connections between micro porous zones and macro-pores show that in HFU IV- HFU II,
connected pore networks require transport via micro-porous domains, with more isolated macro-pores
from HFU IV to II.

Energies 2019,12, 3663 16 of 33
HFU V is the unit closest to this ideal of compacted framework grain porosity approximating actual
porosity (i.e., with comparatively minimal microporosity). Figure 8A shows a subset of 1000
×
1000
×
1000 pixels from the whole core 19 (HFU V), examined in detail for the two-phase flow experiments.
The macroporosity is visualized in Figure 8B,C, where we see all macropores (in red in Figure 8B)
compared to three connected networks of macropores (cyan, green, and purple colored voxels form
individual distinct porous networks in Figure 8C). The cyan network in Figure 8C forms a connected
pathway across the subset volume, showing that in HFU V, connected networks of macropores exist that
likely control the flow properties of this unit. These are separated from other isolated pore networks a
few millimeters in size, separated by clay-rich domains containing microporosity.
17
redinFigure8B)comparedtothreeconnectednetworksofmacropores(cyan,green,andpurple
coloredvoxelsformindividualdistinctporousnetworksinFigure8C).ThecyannetworkinFigure
8Cformsaconnectedpathwayacrossthesubsetvolume,showingthatinHFUV,connectednetworks
ofmacroporesexistthatlikelycontroltheflowpropertiesofthisunit.Theseareseparatedfromother
isolatedporenetworksafewmillimetersinsize,separatedbyclay‐richdomainscontaining
microporosity.

Figure 7.Grainsizedistributionsin‘phi’units(logtobase2)determinedfromimageanalysisofthe
wholecorescansofFigure6,forfourofthefiveHFUsinthisstudy.Theplotsarecolorcodedtomatch
thecolorsusedinFigure2.GreenisforHFUV,darkblueforHFUIV,lightblueforHFUIII,andred
forHFUI.Grainsizedescriptorsarethefollowing:fsisfinesand,msismediumsand,csiscoarse
sand,vcsisverycoarsesand,andvfgisveryfinegravel.
Network(orso‐calledball‐and‐stick)modelsofporousdomainsareanumericallytractableand
relativelysimplewaytoexaminesingleandmultiphaseflowpropertiesofporousmedia[52].In
Figure8D‐F,weshowa500×500×500pixelsubvolumeintheinteriorofthenetworkshownin
Figure8BandC.Figure8Ddepictstherawtomographicreconstruction,andFigure8Eshows
segmentationintomacropores(red)andmicroporousdomains(blue).AlsovisibleinDandEare
frameworkgrains(lightgrey)andFe‐carbonatecements(whitespecks).Usinganalgorithmin
Pergeos
TM
,wereconstructporenetworkmodelsofconnectedmacropores(Figure8F)andconnected
macroporesplusmicroporousdomains—butnotincludingcarbonatecement(whichformsaminor
portionofsample19)—andcalculatesinglephasepermeabilityusingtheOpenPNMporenetwork
simulationpackage.Wefindthatthepermeabilityvaluesforthissmalldomainwiththesample19
determinedbyporenetworkmodelingareclosetothevaluedeterminedexperimentallyof84mD
(foroil).Thevalueforthemacropore‐onlyporenetworkmodelis77mD,whilethevaluesforthe
macroporeplusmicroporousdomains(i.e.,theframeworkgrain‐onlyporosity)is110mD.This
suggeststhatflowthroughmicroporousdomainscontributesonlyasmallfractionoftheoverallflow
response,andthatmostoftheflowisaccommodatedbyconnectedmacroporousnetworksforHFU
V.

Figure 7.
Grain size distributions in ‘phi’ units (log to base 2) determined from image analysis of the
whole core scans of Figure 6, for four of the five HFUs in this study. The plots are color coded to match
the colors used in Figure 2. Green is for HFU V, dark blue for HFU IV, light blue for HFU III, and red
for HFU I. Grain size descriptors are the following: fs is fine sand, ms is medium sand, cs is coarse
sand, vcs is very coarse sand, and vfg is very fine gravel.
Network (or so-called ball-and-stick) models of porous domains are a numerically tractable
and relatively simple way to examine single and multiphase flow properties of porous media [
52
].
In Figure 8D–F, we show a 500
×
500
×
500 pixel sub volume in the interior of the network shown in
Figure 8B,C. Figure 8D depicts the raw tomographic reconstruction, and Figure 8E shows segmentation
into macropores (red) and microporous domains (blue). Also visible in D and E are framework
grains (light grey) and Fe-carbonate cements (white specks). Using an algorithm in Pergeos
TM
,
we reconstruct pore network models of connected macropores (Figure 8F) and connected macropores
plus microporous domains—but not including carbonate cement (which forms a minor portion of
sample 19)—and calculate single phase permeability using the OpenPNM pore network simulation
package. We find that the permeability values for this small domain with the sample 19 determined by
pore network modeling are close to the value determined experimentally of 84 mD (for oil). The value
for the macropore-only pore network model is 77 mD, while the values for the macropore plus
microporous domains (i.e., the framework grain-only porosity) is 110 mD. This suggests that flow
through microporous domains contributes only a small fraction of the overall flow response, and that
most of the flow is accommodated by connected macroporous networks for HFU V.

Energies 2019,12, 3663 17 of 33
18

Figure 8.A.WholecoreCTscanofsample19witharectangularsubvolumeinscribedinsidethe
corecylinder,delineatedinblue.B.Subsection(1000×1000×1000pixels,withpixelsizeof22.5μm×
22.5μm×22.5μm)showinglocationofallsegmentedmacroporesinred.C.Connectednetworksof
macropores(shownasgreen,teal,andpurple),isolatedfromeachotherbymicroporousdomains.
Thetealnetworkextendsacrosstheentiresubvolume,suggestingthataconnectednetworkof
macroporosityextendsacrosstheentiresample19core.D.500×500×500pixelsubvolumesampled
fromtheinteriorofthedomaininBandC,showingrawtomographicreconstructionofsample19. E.
Segmentedmacropores(red)andmicroporousdomains(blue)ofthesubvolumeshowninD.F.Pore
networkmodelofconnectedmacropores,withsizeofspheresscaledtoporesize,connectedby
throats,correspondingtothesubvolumeinDandE.

AviewofasmallcoreplugbuttendofanHFUIIIsample(sampleE1inTableA1)atahigher
voxelresolutionof11μm×11μm×11μm,showsthesamefourmainattributesofMorrowBtexture
discernablefromCTimagingasarevisibleinFigure8D,includingquartzgrains,carbonatecement,
macroporosity,andclay‐filledporescontainingmicroporosity(Figure9A).Ananalysisofthemedial
axisofconnectedpathways(connectedpointsequidistantfromporeedges)ofmacropores(Figure
9B)andclay‐filledregionswithmicroporosity(Figure9C)usingPergeos
TM
showsthatmacropores
formisolatednetworks—whereasconnectedpathwaysacrossthevolumeinvolvemicroporous
regions—forthisHFU.Ingeneral,flowpathwaysinHFUIVthroughInecessarilyinvolveflow
throughmicroporousdomainscontainingclay,whereasHFUVconsistsofflowpathwayswithat
leastsomeconnectedmacroporosity.HFUIVandIIIcontainprogressivelymoreofthese
microporousdomainsthanHFUV.
Tosummarize,frameworkgrainsacrosstheHFUsexaminedherehaveexperiencedasimilar
amountofcompactionandyieldsimilarintergranularvolumes.Largedifferencesinpermeability
betweenHFUV,IVandIIIcanbeattributedtoconnectedflowpathsconsistingofprogressivelymore
clay‐richmicroporousdomainsconnectedwithisolatednetworksofmacropores.HFUsIIandIhave
porositylargelyoccludedbyextensiveFe‐carbonatecements,withisolatedmacroporesandrelatively
fewermicroporousdomains.AsdeterminedbyGallagher([3],herFigure41),carbonatecementation
Figure 8.
(
A
). Whole core
µ
CT scan of sample 19 with a rectangular subvolume inscribed inside
the core cylinder, delineated in blue. (
B
). Subsection (1000
×
1000
×
1000 pixels, with pixel size of
22.5
µ
m
×
22.5
µ
m
×
22.5
µ
m) showing location of all segmented macropores in red. (
C
). Connected
networks of macropores (shown as green, teal, and purple), isolated from each other by microporous
domains. The teal network extends across the entire subvolume, suggesting that a connected network
of macroporosity extends across the entire sample 19 core. (
D
). 500
×
500
×
500 pixel subvolume
sampled from the interior of the domain in (
B
) and (
C
), showing raw tomographic reconstruction
of sample 19. (
E
). Segmented macropores (red) and microporous domains (blue) of the subvolume
shown in D. (
F
). Pore network model of connected macropores, with size of spheres scaled to pore size,
connected by throats, corresponding to the subvolume in D and E.
A view of a small core plug butt end of an HFU III sample (sample E1 in Table A1) at a higher
voxel resolution of 11
µ
m
×
11
µ
m
×
11
µ
m, shows the same four main attributes of Morrow B texture
discernable from
µ
CT imaging as are visible in Figure 8D, including quartz grains, carbonate cement,
macroporosity, and clay-filled pores containing microporosity (Figure 9A). An analysis of the medial
axis of connected pathways (connected points equidistant from pore edges) of macropores (Figure 9B)
and clay-filled regions with microporosity (Figure 9C) using Pergeos
TM
shows that macropores form
isolated networks—whereas connected pathways across the volume involve microporous regions—for
this HFU. In general, flow pathways in HFU IV through I necessarily involve flow through microporous
domains containing clay, whereas HFU V consists of flow pathways with at least some connected
macroporosity. HFU IV and III contain progressively more of these microporous domains than HFU V.

Energies 2019,12, 3663 18 of 33
To summarize, framework grains across the HFUs examined here have experienced a similar
amount of compaction and yield similar intergranular volumes. Large differences in permeability
between HFU V, IV and III can be attributed to connected flow paths consisting of progressively more
clay-rich microporous domains connected with isolated networks of macropores. HFUs II and I have
porosity largely occluded by extensive Fe-carbonate cements, with isolated macropores and relatively
fewer microporous domains. As determined by Gallagher ([
3
], her Figure 41 carbonate cementation
including Fe-rich phases of ankerite and siderite formed early in the paragenetic sequence of the
Morrow B, followed by significant compaction, feldspar dissolution and clay mineral formation and
lastly calcite cementation. These events were then followed by hydrocarbon emplacement. It is clear
that diagenesis is the primary factor in determining flow properties in the Morrow B HFUs, which in
turn is likely influenced by primary depositional features.
19
includingFe‐richphasesofankeriteandsideriteformedearlyintheparageneticsequenceofthe
MorrowB,followedbysignificantcompaction,feldspardissolutionandclaymineralformationand
lastlycalcitecementation.Theseeventswerethenfollowedbyhydrocarbonemplacement.Itisclear
thatdiagenesisistheprimaryfactorindeterminingflowpropertiesintheMorrowBHFUs,whichin
turnislikelyinfluencedbyprimarydepositionalfeatures.


Figure 9.A.μCTreconstructionofHFUIIIcoreplugbuttendat11μm×11μm×11μmvoxelsize,
9.5×8.4×3.2mminsize.Easilydiscernablefromthescangreylevelsarequartzgrains(lightgrey),
Fe‐bearingcarbonatecement(white),macroporosity(darkgrey)andclayfilledporeswith
microporosity(intermediategrey).B.Macropores,realizedingreen(above),alongwithmedialaxis
ofmacropores,showingthatmacroporesinthisHFUIIIsamplearelargelyisolatedanddonotform
connectedpathways.C.Clay‐filledporescontainingmicroporosity,realizedinblue(above),along
withmedialaxisofmicroporousregions,showingthatconnectedflowpathsthroughHFUIII
necessarilymustflowthroughthemicroporousdomains.SampleisE1fromTableA1,FWUwell13‐
10A,7684.75’bgs.
4.2.WettabilityVariabilityintheOil–BrineMorrowBSandstoneSystem
Contactanglemeasurementsatroomconditionsprovideanestimateofwettabilityvariations
andevolutioninanoil‐andbrine‐floodedMorrowBsandstonecoreplugfromtheHFUVgroup.
ThisplugwasinitiallycleanedofresidualoilusingDean–Starkmethods,andsoisinitiallywater‐
wetting.WearguethatthisparticularHFUprobablywasatleastpartiallywater‐wettinginsituat
FWU,giventheextensivewaterfloodingandrelativelylowerresidualoilsaturationslistedforHFU
VsamplesinTableA1.Weexaminemeasurementsofbrineandoilsingledropsonthecoresurface
justsubsequenttoaninitialbrineflood,anoilflood,andabrine‐displacingoilflood.Theresultsare
summarizedinFigure10andshowthewettabilityofthisHFUiseasilymodifiedaccordingtothe
poresolutionfloodinghistory.
Brinedropcontactangleofbrine‐floodedcore: Followingbrine‐floodingoftheHFUVcore,adrop
ofbrinewasdeliveredtothetopsurfaceofthebrine‐floodedcorebyasyringepump.Oncethebrine
drop(~5

L)contactedthecoreplugsurface,itspreadinstantaneouslyandastablebrinedropwas
notformed(notshowninFigure10).Thisindicatedthatthebrinecontactangleapproached0°and
thesurfacewasstronglywater‐wet.
Oildropcontactangleofbrine‐floodedcore: Todooil‐dropcontactanglemeasurements,acaptive
oildropwasformedbeneaththebottomsurfaceofthebrinefloodedcoreplug,whichwashungover
anopticalcellthatwasfilledwithfieldbrine.Theimageofacaptivedropbeneaththebottomsurface
ofbrinefloodedcoreisshowninFig.10A(inset)alongwithcontactanglesofsixcaptiveoildrops.
Theaverage(water)contactanglewas24.7°±3.1°.Theoildropletcontactanglesindicatethatthe
Figure 9.
(
A
).
µ
CT reconstruction of HFU III core plug butt end at 11
µ
m
×
11
µ
m
×
11
µ
m voxel size,
9.5
×
8.4
×
3.2 mm in size. Easily discernable from the scan grey levels are quartz grains (light grey),
Fe-bearing carbonate cement (white), macroporosity (dark grey) and clay filled pores with microporosity
(intermediate grey). (
B
). Macropores, realized in green (above), along with medial axis of macropores,
showing that macropores in this HFU III sample are largely isolated and do not form connected
pathways. (
C
). Clay-filled pores containing microporosity, realized in blue (above), along with medial
axis of microporous regions, showing that connected flow paths through HFU III necessarily must flow
through the microporous domains. Sample is E1 from Table A1, FWU well 13-10A, 7684.75’ bgs.
4.2. Wettability Variability in the Oil–Brine Morrow B Sandstone System
Contact angle measurements at room conditions provide an estimate of wettability variations and
evolution in an oil- and brine-flooded Morrow B sandstone core plug from the HFU V group. This
plug was initially cleaned of residual oil using Dean–Stark methods, and so is initially water-wetting.
We argue that this particular HFU probably was at least partially water-wetting in situ at FWU, given
the extensive water flooding and relatively lower residual oil saturations listed for HFU V samples in
Table A1. We examine measurements of brine and oil single drops on the core surface just subsequent
to an initial brine flood, an oil flood, and a brine-displacing oil flood. The results are summarized
in Figure 10 and show the wettability of this HFU is easily modified according to the pore solution
flooding history.
Brine drop contact angle of brine-flooded core: Following brine-flooding of the HFU V core, a drop of
brine was delivered to the top surface of the brine-flooded core by a syringe pump. Once the brine
drop (~5
µ
L) contacted the core plug surface, it spread instantaneously and a stable brine drop was not
formed (not shown in Figure 10). This indicated that the brine contact angle approached 0
◦
and the
surface was strongly water-wet.

Energies 2019,12, 3663 19 of 33
Oil drop contact angle of brine-flooded core: To do oil-drop contact angle measurements, a captive oil
drop was formed beneath the bottom surface of the brine flooded core plug, which was hung over an
optical cell that was filled with field brine. The image of a captive drop beneath the bottom surface of
brine flooded core is shown in Figure 10A (inset) along with contact angles of six captive oil drops.
The average (water) contact angle was 24.7
◦±
3.1
◦
. The oil droplet contact angles indicate that the
brine flooded core plug is strongly water-wet. It was observed that the contact angles of an oil drop
were constant and did not change over two hours of measurement.
Brine drop contact angle of oil-flooded core: Figure 10B (inset) shows the image of a brine sessile drop
(SD) on the top of the oil-flooded core plug. Contact angles of five drops including two needles in SDs
and three normal SDs are plotted in Figure 10B. The average water contact angle was 106.5
◦±
4.4
◦
.
This angle indicates that the surface of the oil-flooded core plug was mildly oil-wet. It was observed
that the manually formed brine drops on the surface of oil flooded core plug were not stable, and their
contact angles decreased with time. In about two hours (Figure 10B), the contact angle of a brine drop
decreased to 0
◦
and brine would eventually spread on the core plug surface and penetrate to the core
plug body.
Oil drop contact angle of oil-flooded core: Figure 10C (inset) shows an image of a captive oil drop
beneath the end surface of the oil-flooded core plug. The average (brine) contact angle of six drops was
117.3
◦±
6.1
◦
(Figure 10C). This angle was comparable to the brine drop contact angle of 106.5
◦±
4.4
◦
.
The oil drop contact angles were not stable and increased with time. In about two hours, the oil drop
contact angle increased to 180
◦
and the oil would eventually spread on the core surface and penetrate
to the core body.
Brine drop contact angle of oil-displaced core: Figure 10D (inset) shows an image of a brine SD on the
top of brine-displacing-oil for the same HFU 5 core. The contact angles of five brine drops including
two needles in SDs and three normal SDs are shown in Figure 10D. The average brine contact angle
was 98.2
◦±
8.3
◦
. The behavior of water droplets on the surface of the oil-displaced core was similar to
those on the surface of the oil-flooded core. They were unstable, and the contact angles decreased
with time. In about two hours, the contact angles of a brine drop decreased to 0
◦
and brine would
eventually spread on the core surface and penetrate to the core body.
Oil drop contact angle of oil-displaced core: The behaviors of oil drops beneath the bottom surface of
the oil-displaced core (not shown) were similar to those of the oil-flooded core. They were unstable,
and the contact angles increased with time. In about two hours, an oil drop contact angle increased to
180◦and the oil would eventually spread on the core surface and penetrate to the core body.
To summarize, when brine was delivered to the surface of the initially cleaned and brine-flooded
core, it spread instantaneously, and a stable brine SD could not be formed, indicating that the original
wettability of this core was strong water-wet. This was also confirmed by the average oil drop contact
angle, which was 24.7
◦±
3.1
◦
. After oil flooding, the oil drop contact angle beneath the surface of
the oil flooded core increased from 24.7
◦±
3.1
◦
to 117.3
◦±
6.1
◦
, indicating that the wettability had
been changed from strong water-wet to mildly oil-wet. This was also confirmed by brine drop contact
angles, which increased from about 0
◦
to 106.5
◦±
4.4
◦
. After the second brine flooding, the oil in the
core was displaced. The oil drop contact angle was 119.8
◦±
7.1
◦
. This angle was about the same as
that of the oil flooded core, which was 117.3
◦±
6.1
◦
. This suggests that the wettability remained the
same after oil had been displaced with brine. While the brine drop contact angle had larger deviation,
it decreased from 106.5
◦±
4.4
◦
to 98.2
◦±
8.3
◦
. These simple measurements show that Morrow B
sandstone wettability can be quickly modified on an experimental time scale during brine and/or oil
flooding. They also suggest that the wettability of the Morrow B sandstone has been altered from
oil-wet to water-wet—at least in HFU V during water flooding in EOR operations at Farnsworth.

Energies 2019,12, 3663 20 of 33
21

Figure 10.Oilandwatercontactanglemeasurements,showingvariablewettabilityfollowingbrine‐
andoil‐flooding.
4.3.Oil–brineRelativePermeabilityforMorrowBHFUs
Inthissectionweexamineco‐injectionoil–brinerelativepermeabilityinthesixMorrowBcore
plugslistedinTable2,forthefiveHFUs.Backgrounddataandinformationforthetestsareprovided
intheSupplementaryMaterials,andtheresultsaresummarizedinTable6.
GiventheevidenceintheprevioussectionthatMorrowBwettabilityistransientanddependent
onhistoryofexposuretooilorbrine,itisnecessarytoreturncorestoasimilarwettabilitytoallow
forcomparableresults.Figure11Ashowsoil–brinerelativepermeabilityinacorefollowingDean–
Starkextractionofresidualoilandwater,beginningwithaninitialoilfloodandthenfollowedwith
sequentialfloodswithincreasingfractionalflowrateofbrine.Resultsareplottedasafunctionof
brinesaturation.Thesameprocedurewithacorethatexperiencedagingbyexposuretotheoilphase
isshowninFigure11B.The“cleaned”samplehasahigherresidualwatersaturationandhigherend‐
pointrelativepermeabilityrelativetotheagedsample,whichhasanextremelylowend‐pointbrine
relativepermeability.Thisshowstheimportanceofagingeachcorebyexposuretotheoilphase,
whichmodifiesthewettabilitytobe(atleastintermediately)oil‐wetting.
Figure 10.
Oil and water contact angle measurements, showing variable wettability following brine-
and oil-flooding.
4.3. Oil–brine Relative Permeability for Morrow B HFUs
In this section we examine co-injection oil–brine relative permeability in the six Morrow B core
plugs listed in Table 2, for the five HFUs. Background data and information for the tests are provided
in the Supplementary Materials, and the results are summarized in Table 6.
Given the evidence in the previous section that Morrow B wettability is transient and dependent
on history of exposure to oil or brine, it is necessary to return cores to a similar wettability to allow for
comparable results. Figure 11A shows oil–brine relative permeability in a core following Dean–Stark
extraction of residual oil and water, beginning with an initial oil flood and then followed with
sequential floods with increasing fractional flow rate of brine. Results are plotted as a function of
brine saturation. The same procedure with a core that experienced aging by exposure to the oil phase
is shown in Figure 11B. The “cleaned” sample has a higher residual water saturation and higher
end-point relative permeability relative to the aged sample, which has an extremely low end-point
brine relative permeability. This shows the importance of aging each core by exposure to the oil phase,
which modifies the wettability to be (at least intermediately) oil-wetting.
22
Figure 11.ThedifferenceinrelativepermeabilityfromA.acleanedcoreandB.anoil‐agedcore.
Relativepermeabilityillustratestheneedforagingthecoretoanoriginalwettability,likely
approximatingthatpriortoEORoperationsatFWU.
Oil–brinerelativepermeabilitycurvesforHFUsthatexperiencedtheagingprocessareshown
inFigure12asafunctionofbrinesaturation.Sample19(HFUV;Figure12A)isthemostpermeable
(initialabsolutepermeabilityof83.7mD,Table2;seealsotheSupplementaryMaterials)inthisstudy.
Asdiscussedpreviously,core19(HFUV)containsconnectednetworksofmacropores,andrelatively
littleclay.Asthebrinesaturationoccupiesmoreporespace,thebrineprovidesmoreresistanceon
oilflow,andrelativepermeabilityoftheoilslowlydecreasesuntiltheoilbecomesimmobile.This
experimenthadthehighestrangeofsaturationoverwhichtwo‐phaseflowoccurs,withan
irreduciblewatersaturation(S
w,irr
)of0.201andaresidualoilsaturation(S
or
)of0.169.
Similarto19,sampleL7(HFUIV)containsmacropores,althoughnotaswellconnected,and
abundantclay‐bearingmicroporousdomains(Figure12B).Theinitialabsolutepermeabilitywas59.5
mD(Table2).Thetotalflowrateforthisexperimentwas1.0mL/min.Thesaturationregionofflow
decreasescomparedtosample19resultsinbetweenaS
w,irr
of0.334andS
or
of0.241.Thedecreasein
permeabilityandlargerS
w,irr
islikelyduetotheincreaseofclayinL7andlessconnectivitybetween
macropores.ThelargerS
or
forHFUIVcomparedtoHFUVisduetothegreatercapillary
heterogeneityowingtothemoreabundantclay‐bearingmicroporosity.Thesetrendscontinuewhen
comparingHFUIIItoHFUIV.
TwoexperimentswererunondifferentHFUIIIcoreplugstoconfirmconsistentresultsforthese
HFUs(Figure12CandD).SamplesL6andL5(bothHFUIII)weretested,andtheinitialabsolute
permeabilitieswere40.1mDand22.1mD,respectively(Table2).L6containsabundantclay‐bearing
microporousdomains.TotalflowratefortheL6experimentwasat0.5mL/min.L5similarlycontains
clay‐richmicroporositywithpoorlysortedgrainsize,andtheL5experimentusedatotalflowrateof
1.0mL/min.L6resultsshowamorenarrowrangeoftwo‐phaseflowcomparedtoHFUVandIV,
withS
w,irr
=0.439andS
or
=0.270.CoreL5resultsshowalargerregionoftwo‐phaseflowwithS
w,irr
=
0.375andS
or
=0.260.
Figure 11.
The difference in relative permeability from (
A
). a cleaned core and (
B
). an oil-aged
core. Relative permeability illustrates the need for aging the core to an original wettability, likely
approximating that prior to EOR operations at FWU.

Energies 2019,12, 3663 21 of 33
Oil–brine relative permeability curves for HFUs that experienced the aging process are shown in
Figure 12 as a function of brine saturation. Sample 19 (HFU V; Figure 12A) is the most permeable (initial
absolute permeability of 83.7 mD, Table 2; see also the Supplementary Materials) in this study. As
discussed previously, core 19 (HFU V) contains connected networks of macropores, and relatively little
clay. As the brine saturation occupies more pore space, the brine provides more resistance on oil flow,
and relative permeability of the oil slowly decreases until the oil becomes immobile. This experiment
had the highest range of saturation over which two-phase flow occurs, with an irreducible water
saturation (Sw,irr) of 0.201 and a residual oil saturation (Sor) of 0.169.
Similar to 19, sample L7 (HFU IV) contains macropores, although not as well connected, and
abundant clay-bearing microporous domains (Figure 12B). The initial absolute permeability was
59.5 mD (Table 2). The total flow rate for this experiment was 1.0 mL/min. The saturation region of
flow decreases compared to sample 19 results in between a S
w,irr
of 0.334 and S
or
of 0.241. The decrease
in permeability and larger S
w,irr
is likely due to the increase of clay in L7 and less connectivity between
macropores. The larger S
or
for HFU IV compared to HFU V is due to the greater capillary heterogeneity
owing to the more abundant clay-bearing microporosity. These trends continue when comparing
HFU III to HFU IV.
23

Figure 12.Oilandbrinetwo‐phaserelativepermeabilitycurvesforeachHFU.A)HFUV,B)HFUIV,
C)HFUIIIa,D)HFUIIIb,E)HFUII,F)HFUI.
ForsampleL4(HFUII),theinitialabsolutepermeabilitywas9.06mD(Table2).SampleL4
testingwasconductedusingatotalflowrateof0.75mL/min.ThisHFUshowsthenarrowest
saturationrangeofflowoutofthesixcoreplugstested,withS
w,irr
=0.453andS
or
=0.338(Fig.12E).
Fewerfractionalflowrateswereimplementedfortheexperimentonsample1(HFUI,Figure
12F)becauseofthesignificanttimerequiredtoreachsteady‐stateconditionsateachstep.Witha
permeabilityof0.149mD(Table2),extremelysmallporethroatsizes,andalotofcementandclay,
theflowratewaslimitedto0.02mL/minsoasnottoproduceinletporepressuresexceedingthe
confiningpressure.ResultsindicatethatS
w,irr
=0.371andS
or
=0.274,whichisalargersaturationflow
regionthanHFUII,andthismaybeafunctionoftheslowertotalflowrateusedinthetesting.As
Figure 12.
Oil and brine two-phase relative permeability curves for each HFU. (
A
) HFU V, (
B
) HFU IV,
(C) HFU IIIa, (D) HFU IIIb, (E) HFU II, (F) HFU I.

Energies 2019,12, 3663 22 of 33
Two experiments were run on different HFU III core plugs to confirm consistent results for
these HFUs (Figure 12C,D). Samples L6 and L5 (both HFU III) were tested, and the initial absolute
permeabilities were 40.1 mD and 22.1 mD, respectively (Table 2). L6 contains abundant clay-bearing
microporous domains. Total flow rate for the L6 experiment was at 0.5 mL/min. L5 similarly contains
clay-rich microporosity with poorly sorted grain size, and the L5 experiment used a total flow rate of
1.0 mL/min. L6 results show a more narrow range of two-phase flow compared to HFU V and IV, with
S
w,irr
=0.439 and S
or
=0.270. Core L5 results show a larger region of two-phase flow with S
w,irr
=0.375
and Sor =0.260.
For sample L4 (HFU II), the initial absolute permeability was 9.06 mD (Table 2). Sample L4 testing
was conducted using a total flow rate of 0.75 mL/min. This HFU shows the narrowest saturation range
of flow out of the six core plugs tested, with Sw,irr =0.453 and Sor =0.338 (Figure 12E).
Fewer fractional flow rates were implemented for the experiment on sample 1 (HFU I, Figure 12F)
because of the significant time required to reach steady-state conditions at each step. With a permeability
of 0.149 mD (Table 2), extremely small pore throat sizes, and a lot of cement and clay, the flow rate
was limited to 0.02 mL/min so as not to produce inlet pore pressures exceeding the confining pressure.
Results indicate that S
w,irr
=0.371 and S
or
=0.274, which is a larger saturation flow region than HFU II,
and this may be a function of the slower total flow rate used in the testing. As observed earlier, in this
HFU, the reservoir quality is diminished from a significant amount of siderite cementation.
Hysteresis (drainage) floods were performed on all cores with the exception of HFU I (due to time
restrictions). The results, illustrated as the dashed black curves on Figure 12, indicate no apparent
trend from one HFU to another, although all drainage curves show lower relative permeability than the
initial imbibition curves. The drainage flood in HFU V had the most change in relative permeability
between imbibition and drainage steps while HFU IV had almost no change.
4.4. Oil-scCO2Relative Permeability for Morrow B HFUs
Relative permeability curves for oil and scCO
2
are shown in Figure 13 as a function of CO
2
saturation. Three experiments each were performed using HFU V sample 19 and using HFU III sample
L5, with three different injection pressures. For 19 (HFU V) experiments (7 through 9 in Table 6,
and Figure 13A–C), the CO
2
relative permeability curves were somewhat surprising, having very
low values. For all three experiments, they appear to start nearly horizontal, with very little relative
permeability and eventually increase slightly near residual oil saturation. In part this is due to the
relatively low viscosity of scCO
2
relative to oil. For experiment 7 with 3000 psi (20.7 MPa) downstream
pressure, the residual gas saturation (S
gr
) equals 0.193 and the residual oil saturation (S
or
) equals 0.164
(Figure 13A). In experiment 8, 3600 psi (24.8 MPa) downstream pressure, the saturation range of flow
increases to S
gr
of 0.154 and a S
or
of 0.156 (Figure 13B). The region of flow increases for experiment 9,
4000 psi (27.6 MPa) downstream pressure, with a Sgr of 0.127 and a Sor of 0.140 (Figure 13C).
For L5 (HFU III) experiments (#10-12 in Table 6and Figure 13D–F), the oil relative permeability
curves become more linear as the minimum miscibility pressure (MMP) is approached (for the
Morrow-B at FWU this was determined to be ~4000 psi, or 27.6 MPa, at the experimental temperature
by Gunda et al. [
4
]). For experiment 10 at 3000 psi (20.7 MPa), S
gr
equals 0.094 and S
or
equals 0.231
(Figure 13D). For experiment 11, at 3600 psi (24.8 MPa) injection pressure, the saturation range of flow
decreases to a S
gr
of 0.183 and a S
or
of 0.221 (Figure 13E). For experiment 12, 4000 psi downstream
pressure (27.6 MPa), the oil relative permeability curve was approximately linear as expected as the
MMP was achieved. The experiment resulted in a Sgr of 0.132 and a Sor of 0.175 (Figure 13F).
The oil and gas experiments, with the exception of experiment 9, show a small change or drop in
oil relative permeabilities around 40%–60% CO
2
. For experiment 10, the effluent oil was examined
after each run to look for any inconsistencies that could offer an explanation as to why the CO
2
relative
permeability increases slightly (or experiences a small jump, compared with a drop in the oil relative
permeability) with fractional flow during this range, indicated by arrows on Figure 13. At this specific
CO
2
saturation, the oil at the outlet separator became foamy with its appearance and texture changed,

Energies 2019,12, 3663 23 of 33
with a lighter brown color (Figure 14). It appears that little mixing of the two phases occurs at lower
CO
2
saturations, but CO
2
dissolves (i.e., is miscible) in the oil at higher CO
2
saturations. This suggests
that with increasing pore volumes of scCO
2
passing though the core plugs, the wettability changes
from an initial state of intermediately oil-wet to more scCO
2
wet, and this corresponds to an increasing
amount of produced, and altered, oil phase. This frothy brown oil has been observed at Farnsworth
well heads by one of the authors (R. Grigg), and so the changes in the oil properties induced by a
relatively modest exposure to scCO2are also occurring in the subsurface.
25
Figure 13.Oilandgasrelativepermeabilitycurves.(A‐C)HFUVrelativepermeabilityexperiments
performedat20.68MPa(3000psi),24.82MPa(3600psi),and27.58MPa(4000psi),respectively.(D‐
F)HFUIIIrelativepermeabilityexperimentsperformedat20.68MPa(3000psi),24.82MPa(3600psi),
and27.58MPa(4000psi),respectively.
ForbothHFUVandHFUIIItests,thescCO
2
endpointrelativepermeabilitiesareextremelylow.
Theendpointsfromcore19rangefrom0.058to0.145comparedto0.045to0.175forcoreL5.
Figure 13.
Oil and gas relative permeability curves. (
A
–
C
) HFU V relative permeability experiments
performed at 20.68 MPa (3000 psi), 24.82 MPa (3600 psi), and 27.58 MPa (4000 psi), respectively.
(
D
–
F
) HFU III relative permeability experiments performed at 20.68 MPa (3000 psi), 24.82 MPa
(3600 psi), and 27.58 MPa (4000 psi), respectively.

Energies 2019,12, 3663 24 of 33
For both HFU V and HFU III tests, the scCO
2
endpoint relative permeabilities are extremely low.
The endpoints from core 19 range from 0.058 to 0.145 compared to 0.045 to 0.175 for core L5.
26

Figure 14.Photographsofdownstreamoil.Theblackoil(left)beforethechangeinrelative
permeability.Brownfrothyoil(right)istheproducedoil(withCO2exsolved)duringtherelative
permeabilitychangesaround40%to60%CO2saturation.
Table 6.Resultsfromeachtwo‐phasecorefloodexperimentperformedinthisstudy.
Experiment
Number
Core
Sample
Fluid
Pairs
Down‐
stream
Pressure
(MPa)
Flow
Rate
(ml/min)
Sw,irrSorSgrk˚rw
@sor
k˚gr
@sor
119(HFUV)Oil/
Brine27.582.000.20
10.169‐0.091‐
2L7(HFUIV)Oil/
Brine27.581.000.33
40.241‐0.215‐
3L6(HFUIII)Oil/
Brine27.580.500.43
90.27‐0.186‐
4L5(HFUIII)Oil/
Brine27.581.000.37
50.26‐0.102‐
5L4(HFUII)Oil/
Brine27.580.750.45
30.338‐0.166‐
61(HFUI)Oil/
Brine27.580.020.37
10.274‐0.183‐
719(HFUV)Oil/
Gas20.6810.0‐0.1640.193‐0.058
819(HFUV)Oil/
Gas24.8210.0‐0.1560.154‐0.145
919(HFUV)Oil/
Gas27.5810.0‐0.140.127‐0.141
10L5(HFUIII)Oil/
Gas20.680.50‐0.2310.094‐0.045
11L5(HFUIII)Oil/
Gas20.680.50‐0.2210.183‐0.175
12L5(HFUIII)Oil/
Gas27.580.50‐0.1750.132‐0.142
Figure 14.
Photographs of downstream oil. The black oil (left) before the change in relative permeability.
Brown frothy oil (right) is the produced oil (with CO
2
exsolved) during the relative permeability
changes around 40% to 60% CO2saturation.
Table 6. Results from each two-phase core flood experiment performed in this study.
Experiment
Number
Core
Sample
Fluid
Pairs
Down-stream
Pressure
(MPa)
Flow
Rate
(ml/min)
Sw,irr Sor Sgr k◦rw@sor k◦gr@sor
1 19 (HFU V) Oil/Brine 27.58 2.00
0.201
0.169 - 0.091 -
2 L7 (HFU IV) Oil/Brine 27.58 1.00
0.334
0.241 - 0.215 -
3 L6 (HFU III) Oil/Brine 27.58 0.50
0.439
0.27 - 0.186 -
4 L5 (HFU III) Oil/Brine 27.58 1.00
0.375
0.26 - 0.102 -
5 L4 (HFU II) Oil/Brine 27.58 0.75
0.453
0.338 - 0.166 -
6 1 (HFU I) Oil/Brine 27.58 0.02
0.371
0.274 - 0.183 -
7 19 (HFU V) Oil/Gas 20.68 10.0 - 0.164 0.193 - 0.058
8 19 (HFU V) Oil/Gas 24.82 10.0 - 0.156 0.154 - 0.145
9 19 (HFU V) Oil/Gas 27.58 10.0 - 0.14 0.127 - 0.141
10 L5 (HFU III) Oil/Gas 20.68 0.50 - 0.231 0.094 - 0.045
11 L5 (HFU III) Oil/Gas 20.68 0.50 - 0.221 0.183 - 0.175
12 L5 (HFU III) Oil/Gas 27.58 0.50 - 0.175 0.132 - 0.142
4.5. Reservoir Simulation
To examine the consequences of the relative permeability analysis in the previous section
on CCUS/EOR, we conduct simulations of the WAG injection scenario at FWU explored by
Ampomah et al. [8]
. We examine a five-spot injector producer pattern extracted from the larger
FWO model of Ampomah et al. [
8
] for the years 2011–2017. This base model was developed by
Ampomah et al. [
8
], based on a synthesis of well log and core data across the FWU by
Rose-Coss et al. [5]
and Rose-Coss [
6
]. In their model, Ampomah et al. [
8
] used a single relative permeability relationship
derived from history matching of produced oil. For our purposes here, two models were compared
using different relative permeability methods to analyze reservoir performance for the five-spot
injector-extractor pattern. Both models take into account the dissolution of CO
2
into oil as CO
2
is
being injected. The first model (A) was abstracted from the Ampomah et al. [
8
] history matched
WAG model. The model employed a single relative permeability curve for the Morrow B but uses
absolute permeability for the Morrow B HFUs determined herein. This relative permeability curve was
developed specifically for SWP history matching analyses. The second model (Model B) used the same
five-spot subsection and absolute permeability HFU data as Model A but integrated the three-phase

Energies 2019,12, 3663 25 of 33
relative permeability data presented in this study using equation 7. Data for the relative permeability
model used in this study are given in the Supplementary Materials.
The cases were compared to actual production and WAG injection data (termed “Sector Model”)
from the Farnsworth well 13-10A pattern from December 2010 to July 2018, given by
Ampomah et al.
(2017b). Model A and Model B accurately modeled the cumulative oil production, compared to the
historical data (Figure 15A). This is a surprising result, in that the laboratory relative permeability
data produce results which are basically the same as the history-matched result of Ampomah et al. [
8
],
without any upscaling procedure. Model B results on oil recovery efficiency are also comparable to
Model A results, underestimating by about 3% (Figure 15B). Model B however underestimates the
cumulative water injection and production amounts (Figure 15C,D). This underestimate could be
caused by low brine relative permeability determined at the core scale in this study, for the oil-aged
core plugs, and is addressed further in the Discussion section.
27
4.5.ReservoirSimulation
Toexaminetheconsequencesoftherelativepermeabilityanalysisintheprevioussectionon
CCUS/EOR,weconductsimulationsoftheWAGinjectionscenarioatFWUexploredbyAmpomah
etal.[8].Weexamineafive‐spotinjectorproducerpatternextractedfromthelargerFWOmodelof
Ampomahetal.[8]fortheyears2011–2017.ThisbasemodelwasdevelopedbyAmpomahetal.[8],
basedonasynthesisofwelllogandcoredataacrosstheFWUbyRose‐Cossetal.[5]andRose‐Coss
[6].Intheirmodel,Ampomahetal.[8]usedasinglerelativepermeabilityrelationshipderivedfrom
historymatchingofproducedoil.Forourpurposeshere,twomodelswerecomparedusingdifferent
relativepermeabilitymethodstoanalyzereservoirperformanceforthefive‐spotinjector‐extractor
pattern.BothmodelstakeintoaccountthedissolutionofCO
2
intooilasCO
2
isbeinginjected.The
firstmodel(A)wasabstractedfromtheAmpomahetal.[8]historymatchedWAGmodel.Themodel
employedasinglerelativepermeabilitycurvefortheMorrowBbutusesabsolutepermeabilityfor
theMorrowBHFUsdeterminedherein.Thisrelativepermeabilitycurvewasdevelopedspecifically
forSWPhistorymatchinganalyses.Thesecondmodel(ModelB)usedthesamefive‐spotsubsection
andabsolutepermeabilityHFUdataasModelAbutintegratedthethree‐phaserelativepermeability
datapresentedinthisstudyusingequation7.Datafortherelativepermeabilitymodelusedinthis
studyaregivenintheSupplementaryMaterials.

Figure 15. Simulationresults.A.Cumulativeoilproduction,STB(stocktankbarrelatsurface
conditions).B.Oilrecoveryefficiency(theamountofoildisplacedfromthereservoir).C.Cumulative
waterinjection,STB.D.Cumulativewaterproduction,STB
.
ThecaseswerecomparedtoactualproductionandWAGinjectiondata(termed“SectorModel”)
fromtheFarnsworthwell13‐10ApatternfromDecember2010toJuly2018,givenbyAmpomahetal.
(2017b).ModelAandModelBaccuratelymodeledthecumulativeoilproduction,comparedtothe
Figure 15.
Simulation results. (
A
). Cumulative oil production, STB (stock tank barrel at surface
conditions). (
B
). Oil recovery efficiency (the amount of oil displaced from the reservoir). (
C
). Cumulative
water injection, STB. (D). Cumulative water production, STB.
5. Discussion
5.1. Integrating Pore-Scale Observations with Experimental and Modeling Results
The wettability and relative permeability of Morrow B sandstones are seen experimentally to be
transient and sensitive to flooding history, and likewise the Morrow B reservoir at FWU is expected
to form a transient, spatially heterogeneous system. Transient relative permeability is not accounted
for in the modeling. By comparing stationary models to the estimated productions from a field likely
experiencing transient changes in wettability, we can nonetheless draw insights that bear on CCUS/EOR
efficiencies at FWU.

Energies 2019,12, 3663 26 of 33
Initially Model B, using measured relative permeabilities, can perform as well as Model A,
the extracted history-matched model. Over the long-term, this holds true with oil-production, implying
that a significant portion of the reservoir remains oil-wet and relative permeability functions remain
constant. For example, we see in the thin section images of Figure 5that substantial residual oil
remains in the Morrow B (particularly in kaolinite-rich microporous regions) following decades of
water flooding. However, with CO
2
WAG EOR, the presence of CO
2
both changes the character
of remaining oil (as in Figure 14) and lowers pH of the low salinity injectate water. This would be
expected to drive the system to be water-wet over time during water flooding [
30
,
53
,
54
]. This change
in wettability invalidates the relative permeability functions used in the models, as the functions would
become more like the non-aged rather than the aged relative permeability measurements (Figure 11).
What is the mechanism of wettability modification?
Silicate minerals have different regions of surface charge controlled by isomorphous substitution
and lattice imperfections, both causing fixed surface charge, and broken or unsatisfied bonds, which
lead to variable surface charge [
55
]. Minerals such as kaolinite or quartz experience more variation
in surface charge, due to changes in pH or the concentration of other charged ligands, than those
with more extensive isomorphic substitution such as illite or smectite [
55
]. The variation is caused
by the adsorption/desorption of charged ligand, H
+
or others, onto the broken bonds at the surface.
Similarly, carbonate minerals have pH or charged ligand concentration-dependent surface charges,
with reversals of effective surface charge possible as in ’pure’ silicate mineral phases [55].
The reversal of surface charge due to changes in fluid composition is one mechanism for changing
the wettability of a mineral from oil-wet to water-wet or vice versa [
56
]. This is most likely to occur in
quartz, feldspar, and kaolinite-rich sandstones that do not have high concentrations of more reactive,
higher fixed surface charge clay minerals such as smectite or illite [
55
]. The Morrow B sandstone
mostly contains minerals with more variable (pH and ligand-dependent) surface charges and we
would expect that wettability throughout the formation would be highly pH and ligand dependent;
we do observe this, in fact, in HFU V. However, if ligands cannot penetrate the wetting phase to alter
the effective mineral surface charge, the surface change will not change, and the wetting phase will not
be desorbed [
57
]. A higher curvature and more variable patterns of the wetting phase, that are allowed
by large pore throats that cannot be easily bridged, are ways to ensure that ligands can penetrate the
wetting phase and disperse it. Conversely, continuous, lower curvature wetting phases—as allowed by
micro-pore throats such as in authigenic kaolinite ’books’—will discourage the penetration of ligands
to the mineral surface, decreasing the rate or even occurrence of changes in wettability, independent of
the underlying per-existing surface charge of the minerals [56].
Simply put, oil–mineral surface tension is broken by changes in pH of the water when pH or
other ligands can penetrate to the mineral surface [
30
,
53
,
54
,
57
], allowing the water to intrude and
sheet the mineral surface. This change in surface wetting, in turn, changes the relative permeability
of this portion of the rock but does not do so uniformly or instantaneously [
53
,
54
]. Thus, there is
a time- and space-dependence on the validity of the water relative permeability that is tied to (a)
intrusion of low salinity, low pH water; (b) presence of CO
2
, which lowers the pH and reacts with the
oil phase; (c) presence of secondary minerals, particularly kaolinite and carbonates; and (d) the variable
capillary heterogeneity observed between the HFUs. In the Morrow B, these combined effects likely
correspond to what is observed for HFU V and possibly HFU IV, where, because of larger pore-throat
sizes, water and CO
2
more easily intrude, and where there are abundant secondary clay minerals. This
interpretation is further supported by the agreement early in WAG operations of Model B in Figure 15
with produced waters, that then shifts to a strong mismatch later in time, with water production far
exceeding Model B predictions.
At the reservoir scale, however, we observe that the calibrated model and the measured relative
permeability measurements produce roughly indistinguishable responses, both matching the historical
oil production records. This is not simply a control via absolute permeability. Rather, it is controlled
by the time-invariance (stability) of wettability, and thus relative permeability, within a significant

Energies 2019,12, 3663 27 of 33
portion of the reservoir. Because of smaller pore sizes, this likely is the case in the lower flow units,
HFU I through HFU III. The smaller pores allow the oil phase to bridge across pore-throats, leading to
a more continuous, lower surface area oil–water–mineral interface [
57
,
58
]. This decreased interface
combined with a lower water-relative-permeability and lower absolute permeability restricts low-pH,
CO
2
-altered waters from intruding as easily, allowing the minerals to remain oil-wet [
58
]. Because they
remain oil-wet and are in the portions of the reservoir most likely to have retained the most oil, the
relative permeability measurements and the initial calibrated model assumptions will remain valid,
offering a good approximation of EOR observed at Farnsworth.
To summarize, we interpret the agreement of the calibrated model (Model A) and the relative
permeability measurements (Model B) with produced oil, and the mismatch of these models with
produced waters later in time, to demonstrate heterogeneous, time-dependent wetting behavior.
This line of field-scale evidence is consistent with the laboratory and petrographic evidence: the
microporosity controls the stability of wetting and the relative permeability by isolating oil behind
continuous interfaces of oil and brine.
5.2. CO2-Oil Interactions during EOR-CCUS
In the oil–CO
2
experiments, we argue that the step-down or drop in oil relative permeability in all
of the experiments with HFU V and HFU III (Figure 13) is caused by a change in composition and
perhaps system wettability in the presence of CO
2
(Figure 14). In HFU V (Figure 13A–C), the decrease
in oil relative permeability occurs at a range of saturations but has a discrete drop of 0.4 to 0.7 proceeded
by a relatively constant oil relative permeability. In one of the tests (Figure 13C), there appears to
be two drops in oil relative permeability. In HFU III (Figure 13D–F), the step decrease in oil relative
permeability occurs at a CO
2
saturation of 0.4 to 0.6 consistently and drops by 0.2 to 0.4. These, too,
show a shallowing of slope before the drop in relative permeability. In HFU V, the CO
2
has relatively
uniform access to the entire pore network even at low saturations; it has large pores throats, so filling
pores with CO
2
will be a largely random process with few if any “ink-bottle” effects. However, once
CO
2
has intruded into the sample, it will react with the oil still lining the pores. The CO
2
appears to be
oxidizing the oil, likely changing its wetting behavior and allowing CO
2
to penetrate into dead-ended
or otherwise inaccessible pores.
The random nature of macro-pore network intrusion in HFU V explains the wide range of CO
2
saturations over which the drop in oil relative permeability occurs, and perhaps the presence of a
‘double-drop’. HFU III samples, however, have limited macro-pore pathways across the sample. CO
2
flow pathways in this HFU are controlled by the pervasive microporosity that, if covered with an oil
film, restricts CO
2
into smaller volumes of the pore network effective CO
2
–oil interface. To have a
penetrative network of CO
2
across the sample, a critical threshold of microporosity would need to
be intruded with CO
2
. Percolation theory predicts average thresholds of approximately 0.5 to have
connection across a media. The percolation threshold is consistent with our observed drop. Before then,
oil–covered micropores and the limited penetration of CO
2
through the sample restrict the reaction of
CO2with oil, delaying the drop in relative permeability to flooding with higher CO2saturations.
All relative permeability drops are preceded by a period of nearly unchanging oil relative
permeability and do not show a corresponding sharp increase in CO
2
relative permeability.
An unchanging relative permeability indicates that the pore network occupied by oil is not
changing—that somehow CO
2
relative saturation is increasing without changing the oil-filled pore
network. This is consistent with CO
2
reacting and being incorporated into the oil, suggesting that the
geometry of CO
2
–oil interfaces remain relatively constant. It also implies that for configurations with
limited CO
2
–oil interface surface area, much of the oil will remain in its initial, higher-viscosity state
for longer. Given the restriction of CO
2
–oil surface area likely found with oil-bridging of micropores,
this is also consistent with both the smaller and more consistent CO
2
relative saturations over which
the drops occur in HFU III when compared to HFU V. While the reaction between CO
2
and in situ oil is

Energies 2019,12, 3663 28 of 33
likely a redox reaction from the presence of oxidizing CO2-and O2-in the CO2flooding, partitioning
of certain preferred oil compounds from oil surface chemistry could be occurring as well.
6. Conclusions
The results of this study indicate that transient wettability exists within Morrow B reservoir
flow units in the West Texas Farnsworth field, based on room temperature contact angle experiments,
relative permeability measurements at in situ conditions, and a comparison of modeled oil and brine
production to actual production. Controls on wettability, such as pore size distribution and mineralogy,
lead to preferential flow, or fast paths in the most permeable flow unit and preferential trapping in the
lower permeable flow units. These are important considerations for efficient CCUS for the Morrow B
but would also be relevant in other depleted clastic reservoirs.
(1).
Morrow B heterogeneity in Well 13-10A in the Farnworth Unit of West Texas is examined
using core acquired by the SWP. Based on fifty-three core plug measurements, we apply a
hydrologic flow unit concept (done for the entire Farnsworth field by Rose-Coss et al. 2016) to
quantify core heterogeneity, down-selecting to six core plugs across five units for detailed relative
permeability measurements. The HFU characterization, along with detailed petrographic and
µ
CT characterization, reveals that pore (capillary)-to-core scale heterogeneity is largely due to
diagenetic processes. Although porosities are largely similar between the flow units, permeability
varies over four orders of magnitude due in large part to the presence and spatial distribution of
clay-bearing microporosity and carbonate cement, and this has a direct influence in reservoir-scale
CCUS behavior from sweep to storage.
(2).
Morrow B wettability is sensitive to and easily modified with flooding history, shown here via
simple contact angle experiments, and by effects of aging on oil–brine relative permeability
behavior. The current reservoir appears to be at least slightly water-wetting, due to the long history
of water-flooding at Farnsworth. Most residual oil resides within the clay-hosted microporosity,
which would be accessible to CO
2
-flooding only at higher capillary pressures. Indeed, in
CO
2
–oil co-injection experiments, more oil is produced, and residual oil saturations decrease,
as injection pressures approach the minimum miscibility pressure. CO
2
relative permeability
curves show a small jump as CO
2
saturation increases, which suggests that initially oil-wet, aged
Morrow-B samples quickly become at least partially CO
2
wetting during even moderate CO
2
flooding. Produced oil properties change with progressive exposure to CO
2
in the experiments,
and similar changes have been observed at Farnsworth associated with CO
2
-flooding. This
suggests that CCUS activity at Farnworth might be altering in situ wettability similar to that
observed experimentally.
(3).
Measured two-phase relative permeability data were used to estimate three-phase relative
permeability, which in turn was applied in the reservoir model of Ampomah et al. [
8
] to
calculate oil recovery and gas storage at the field scale. The numerical simulation yielded results
comparable to the actual oil production data, but underestimated water injection and production.
We conjecture that this is due to evolving and heterogeneous wettability in the Morrow B at
Farnsworth (not accounted for in modeling), particularly in the highest permeability HFU V,
which has apparently yielded most of its original oil in place. This shift in wettability, from oil-wet
to at least moderately water-wetting, probably has produced fast pathways in the Morrow B that
influence and limit the sweep of CO2during EOR/CCUS activities.
Supplementary Materials:
The following are available online at http://www.mdpi.com/1996-1073/12/19/3663/s1,
Figure S1: Pore radii and pore throat radii statistics for Morrow B HFUs determined from
µ
CT image analysis using
the Pergeos
TM
software suite; Figure S2: Coordination number between connected macro-pores, and between
macro-pores and microporous regions; Figure S3: Single phase oil permeability as a function of effective pressure,
for all core plugs used in relative permeability experiments described in the text. Table S1: Conditions and values
of single-phase oil permeability for Morrow B HFU core plugs plotted in Figure S-3; Table S2: Pressure gradients,
saturations, and relative permeability values used in plotting Figure 12 in the text for all oil and brine co-injection

Energies 2019,12, 3663 29 of 33
experiments; Table S3: Pressure gradients, saturations, and relative permeability values used in plotting Figure 13
in the text for all oil and CO2co-injection experiments.
Author Contributions:
Conceptualization, L.R., A.R., R.G., J.H. and T.D.; methodology, A.L., W.A., J.H. and T.D.;
formal analysis, L.R., W.A., T.D., T.F. and R.G.; investigation, L.R.; data curation, L.R.; writing—original draft
preparation, L.R., T.F., T.D., A.L., A.R.; writing—review and editing, all authors; supervision, M.C., W.A., A.L.,
R.G., A.R.; project administration, M.C.; funding acquisition, R.G., M.C.
Funding:
Funding for this project is provided by the U.S. Department of Energy’s National Energy Technology
Laboratory through the Southwest Regional Partnership on Carbon Sequestration (SWP) under Award
No. DE-FC26-05NT42591.
Acknowledgments:
Thanks to historical site operator Chaparral Energy, L.L.C., Schlumberger Carbon Services,
TerraTek (now Schlumberger), Wagner Petrographic, and Steve Cather at the NM Bureau of Geology, for valuable
contributions. Michelle Williams (Sandia) performed the helium porosimetry measurements. We thank Charles
Bryan (at Sandia) for comments on an earlier version of the paper. Eric Bower and James Griegos (both at
Sandia) performed the X-ray scanning and tomographic reconstructions. Comments from four anonymous
reviewers greatly improved the manuscript. This paper describes objective technical results and analysis. Any
subjective views or opinions that might be expressed in the paper do not necessarily represent the views of the
U.S. Department of Energy or the United States Government. Sandia National Laboratories is a multimission
laboratory managed and operated by National Technology & Engineering Solutions of Sandia, LLC, a wholly
owned subsidiary of Honeywell International Inc., for the U.S. Department of Energy’s National Nuclear Security
Administration under contract DE-NA0003525.
Conflicts of Interest:
The authors declare no conflict of interest. The funders had no role in the design of the
study; in the collection, analyses, or interpretation of data; in the writing of the manuscript, or in the decision to
publish the results.
Appendix A
This appendix lists the results of core plug analyses conducted during the routine core analysis
procedure by Terra Tek (now Schlumberger). It summarizes petrophysical measurements of fifty-three
core plugs from the Morrow B formation, samples from the core extracted from the well 13-10A at
the FWU.
Table A1. Results of Terra Tek Routine Core Analysis and Flow Unit Designation.
Sample
Number
Sample
Depth(m)
Dry
Bulk
Density
(kg/m3)
Ambient
Porosity
(%)
Water
Saturation
(%)
Oil
Saturation
(%)
Gas Perm.
NOB Stress
2.75 MPa
(md)
R35 Flow Unit
Designation
E1A 2339.6 2160 19.37 15.78 23.81 26.14 2.85 III
E6A 2337.2 2430 10.72 58.03 <1.00 N/A
23 2337.4 2280 15.27 23.29 22.64 11.02 2.10 II
43 2337.7 2260 18.42 22.54 17.69 24.91 2.89 III
44 2337.7 2090 22.69 16.69 14.66 22.87 2.30 II
1 2337.9 2440 15.56 34.28 25.11 0.56 0.36 I
24 2338.4 2140 19.76 14.60 23.70 13.58 1.90 II
25 2338.6 2130 20.08 15.66 23.17 21.54 2.46 II
45 2338.8 2250 17.35 20.54 22.10 14.91 2.25 II
46 2338.8 2220 17.57 14.76 23.89 1.89 0.66 I
3 2338.9 2160 18.83 20.54 26.39 89.27 6.01 IV
53 2338.9 2120 20.48 17.69 21.10 44.09 3.69 III
26 2339.2 2120 20.28 22.40 24.43 44.83 3.76 III
E1B 2339.6 2160 19.73 14.22 25.00 30.25 3.05 III
5 2339.9 2130 19.93 28.23 26.58 171.59 8.41 IV
27 2340.2 2120 19.96 27.34 19.41 274.03 11.07 V
28 2340.6 2160 18.75 19.63 11.95 27.06 2.99 III
7 2341.0 2210 16.80 25.66 22.45 27.98 3.35 III
29 2341.3 2290 13.94 11.68 18.54 2.61 0.97 I
30 2341.6 2260 14.74 19.96 20.65 4.09 1.21 II
9 2342.1 2360 11.78 21.95 29.30 1.06 0.66 I
E2A 2342.3 2260 14.78 25.24 8.69 4.59 1.29 II
E2B 2342.3 2240 16.49 N/A N/A 4.25 1.12 II
31 2342.5 2290 13.41 15.65 22.88 4.80 1.44 II

Energies 2019,12, 3663 30 of 33
Table A1. Cont.
Sample
Number
Sample
Depth(m)
Dry
Bulk
Density
(kg/m3)
Ambient
Porosity
(%)
Water
Saturation
(%)
Oil
Saturation
(%)
Gas Perm.
NOB Stress
2.75 MPa
(md)
R35 Flow Unit
Designation
E3A 2342.8 2260 14.52 28.82 18.57 11.27 2.22 II
E3B 2342.8 2290 13.76 26.24 13.68 9.18 2.07 II
11 2343.2 2190 16.80 28.93 23.35 96.45 6.94 IV
55 2343.2 2280 13.82 33.96 30.69 139.09 10.20 V
32 2343.5 2160 18.23 24.57 20.53 100.09 6.61 IV
33 2343.7 2200 16.88 23.77 20.48 56.15 5.03 IV
47 2344.0 2190 17.96 17.04 22.15 12.82 2.00 II
48 2344.0 2230 16.74 13.40 25.53 3.92 1.06 II
13 2344.2 2090 21.08 28.05 26.05 45.65 3.68 III
57 2344.3 2140 19.06 16.53 22.83 42.67 3.85 III
34 2344.6 2150 18.81 17.15 25.20 30.06 3.17 III
35 2344.9 2190 17.27 17.42 19.58 39.42 4.00 III
15 2345.3 2130 19.55 28.61 23.30 50.60 4.17 III
36 2345.6 2180 17.99 17.57 19.41 19.09 2.52 III
E4A 2345.8 2090 21.07 21.27 16.38 64.58 4.51 III
E4B 2345.8 2080 21.83 19.43 18.37 70.40 4.60 III
37 2346.1 2200 16.62 16.98 20.11 32.52 3.70 III
17 2346.3 2280 13.77 27.91 28.01 3.42 1.15 II
49 2346.6 2140 19.17 15.93 22.30 63.01 4.82 IV
50 2346.6 2140 18.69 13.19 23.92 49.09 4.26 III
38 2346.9 2150 18.66 17.33 24.06 126.12 7.43 IV
51 2347.1 2190 16.49 15.09 23.89 128.54 8.36 IV
52 2347.1 2180 17.25 18.74 21.27 44.63 4.31 III
59 2347.3 2190 17.22 16.51 20.86 324.57 13.89 V
19 2347.4 2150 18.83 24.58 22.45 783.50 21.60 V
39 2347.7 2150 18.57 29.54 17.16 449.20 15.76 V
40 2348.0 2460 7.45 10.68 19.14 0.32 0.48 I
41 2348.3 2510 5.49 15.15 20.05 0.20 0.48 I
21 2348.5 2720 6.78 44.24 9.15 2.53 1.78 II
Sample E6A contains clay and more water was recovered than total weight loss (negative oil saturation); Sample
E6A not suitable for permeability test; Sample E2B contained an unknown contaminant which made the water
volume undeterminable.
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