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Phase Behavior Studies of Three Major Unconventional Oil Reservoirs for Produced
Gas Injection
by
Yiran Liu, B.S.
A Thesis
In
Petroleum Engineering
Submitted to the Graduate Faculty
of Texas Tech University in
Partial Fulfillment of
the Requirements for
the Degree of
MASTER OF SCIENCES
Approved
Dr. Amin Ettehadtavakkol
Chair of Committee
Dr. Sheldon Gorell
Dr. Steven K. Henderson
Mark Sheridan
Dean of the Graduate School
May, 2020
Copyright 2020, Yiran Liu
Texas Tech University, Yiran Liu, May 2020
ii
ACKNOWLEDGMENTS
I would like to begin by expressing sincere gratitude to the members of my
committee, Dr. Amin Ettehadtavakkol, Dr. Sheldon Gorell and Dr. Steven K.
Henderson. I should give strong appreciation to my supervisor and chair of committee,
Dr. Amin Ettehadtavakkol, for working with me patiently and directing me throughout
the whole research process. The completion of this thesis would not have been possible
without his continuing encouragement and instructions.
I’m heartily thankful to my family in China for their encouragement and
financial support. Thanks to all my friends who I met in Lubbock. Two years in Lubbock
is an enjoyable memory.
I would like to acknowledge the software license provided by Computer
Modelling Group (CMG) to Texas Tech University. I am also thankful to Petroleum
Engineering department in Texas Tech University for allowing me the opportunity to
obtain a degree from a distinguished institution.
Texas Tech University, Yiran Liu, May 2020
iii
TABLE OF CONTENTS
ACKNOWLEDGMENTS .................................................................................... ⅱ
ABSTRACT .......................................................................................................... ⅳ
LIST OF TABLES ............................................................................................... ⅵ
LIST OF FIGURES ........................................................................................... ⅷ
1. INTRODUCTION ............................................................................................. 1
2. METHOD .......................................................................................................... 4
3. RESULTS ........................................................................................................ 11
3.1 Northern San Andres Formation ............................................................... 11
3.2 Lower Wolfcamp Formation ..................................................................... 19
3.3 Eagle Ford Formation ............................................................................... 21
4. DISCUSSION .................................................................................................. 30
5. SUMMARY AND CONCLUSIONS ............................................................. 37
REFERENCES .................................................................................................... 38
Texas Tech University, Yiran Liu, May 2020
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ABSTRACT
The injection gas mixture has an important role in the determination of phase
behavior and applicability of miscible produced gas injection for unconventional oil
reservoirs. This study focuses on three major unconventional reservoirs with
considerable EOR potential through produced gas injection: Northern San Andres,
Lower Wolfcamp and Eagle Ford. The objectives of this study, in addition to the
development and tuning of the corresponding phase behavior models, are to minimize
the mole fractions of the valuable intermediate components, and at the same time,
accomplish favorable PVT properties for the produced gas injection process. These two
objectives may conflict each other; therefore, the use of design optimization is
necessary, as we discuss in the results.
The separator liquid and gas samples are collected and analyzed using gas
chromatography to determine the fluid composition, followed by the recombination test.
Reservoir fluid characterization and the bubble point pressure analysis for reservoir
fluids are performed. A comprehensive phase behavior analysis is then conducted to
determine the number of separator stages and the optimum produced gas composition.
A series of separator tests, minimum miscibility pressure (MMP) tests and swelling tests
are performed for different injection gas compositions and the data are analyzed to tune
the corresponding equations of state and phase envelops for the three reservoirs. The
PVT model requires several adjustment stages to properly match the miscibility and
swelling tests results. The tuned PVT models properly predict the phase behavior of
these three reservoirs for the optimized produced gas injection process.
The optimum separator design and injection composition results for three
unconventional reservoirs are presented and discussed. The impact of different
component mole fractions with suitable injection pressure for miscibility development
are successfully quantified. Combining the three individual results, guidelines are
proposed to specify corresponding fractions of major components (CO2, N2, C1, C2,
C3) in oil and produced gas phases, resulting in potentially favorable conditions for
Texas Tech University, Yiran Liu, May 2020
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produced gas injection. This work opens opportunities to improve technical assessments
of produced gas injection in these three reservoirs as well as other unconventional
reservoirs and sets a reference for future EOR operations.
Texas Tech University, Yiran Liu, May 2020
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LIST OF TABLES
Table 2.1: Compositions and component parameters of San Andres
black oil with initial reservoir pressure of 1565 psia and
reservoir temperature of 107 ℉ ............................................................. 5
Table 3.1: Compositions of produced gas based on one-stage separator
design. Pi=1565 psia, T=107 ℉ .......................................................... 12
Table 3.2: Compositions of injection gas based on one-stage separator
design. Pi=1565 psia, T=107 ℉. Injection gas composition
is highlighted ....................................................................................... 14
Table 3.3: Compositions of injection gas based on two-stage separator
design. Pi=1565 psia, T=107 ℉. Injection gas composition
is highlighted ....................................................................................... 16
Table 3.4: Compositions of injection gas based on two-stage separator
design. Oil composition data is provided by Li, Sheng, and
Xu (2017). Pi=6000 psia, T=185 ℉. Injection gas
composition is highlighted ................................................................... 19
Table 3.5: Compositions of injection gas based on two-stage separator
design. Black oil composition data is provided by Orangi, et
al. (2011). Pi=6300 psia, T=237 ℉, GOR=500 scf/stb.
Injection gas composition is highlighted ............................................. 21
Table 3.6: Compositions of injection gas based on two-stage separator
design. Black oil composition data is provided by Orangi, et
al. (2011). Pi=7350 psia, T=266 ℉, GOR=1000 scf/stb.
Injection gas composition is highlighted ............................................. 22
Table 3.7: Compositions of injection gas based on two-stage separator
design. Volatile oil composition data is provided by Orangi,
et al. (2011). Pi=8050 psia, T=285 ℉, GOR=2000 scf/stb.
Injection gas composition is highlighted ............................................. 24
Texas Tech University, Yiran Liu, May 2020
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Table 3.8: Compositions of injection gas based on two-stage separator
design. Volatile oil composition data is provided by
Gherabati, et al. (2016). Pi=11094 psia, T=320 ℉, Average
GOR=2500 scf/stb. Injection gas composition is highlighted ............. 25
Table 3.9: Compositions of injection gas based on two-stage separator
design. Volatile oil composition is provided by Gong, et al.
(2013). Pi=10155 psia, T=307 ℉, GOR=2781 scf/stb.
Injection gas composition is highlighted ............................................. 27
Table 3.10: Individual results of five Eagle Ford fluids ....................................... 29
Texas Tech University, Yiran Liu, May 2020
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LIST OF FIGURES
Figure 1.1: Cumulative oil production per well change with enhanced
oil recovery project of EOG Resources in Eagle Ford
(Cedric 2016) ........................................................................................ 2
Figure 2.1: Ternary diagrams of two miscibility development
mechanisms: (a) Vaporizing gas drive and (b) Condensing
gas drive (Orr 2007) ............................................................................. 8
Figure 2.2: General diagram of the two-phase envelope in different
conditions ............................................................................................. 9
Figure 3.1: P-T diagram of produced gas based on one-stage separator
design .................................................................................................. 13
Figure 3.2: P-T diagram of injection gas based on one-stage separator
design .................................................................................................. 15
Figure 3.3: P-T diagram of produced gas based on two-stage separator
design .................................................................................................. 17
Figure 3.4: P-T diagram of injection gas based on two-stage separator
design .................................................................................................. 18
Figure 3.5: P-T diagram of produced gas for Wolfcamp oil ................................. 20
Figure 3.6: P-T diagram of produced gas for Eagle Ford black oil,
GOR=500 scf/stb ................................................................................ 22
Figure 3.7: P-T diagram of produced gas for Eagle Ford black oil,
GOR=1000 scf/stb .............................................................................. 23
Texas Tech University, Yiran Liu, May 2020
ix
Figure 3.8: P-T diagram of produced gas for Eagle Ford volatile oil,
GOR=2000 scf/stb .............................................................................. 25
Figure 3.9: P-T diagram of produced gas for Eagle Ford volatile oil,
Average GOR=2500 scf/stb ............................................................... 26
Figure 3.10: P-T diagram of produced gas for Eagle Ford volatile oil,
GOR=2781 scf/stb ............................................................................ 28
Figure 4.1: Two-phase envelopes of reservoir fluid at various stages of
produced gas injection in San Andres. Showing two-phase
envelope at (1) Initial condition, (2) Depleted condition, (3-
5) Three different injection slug sizes ................................................ 31
Figure 4.2: Two-phase envelopes of reservoir fluid at various stages of
produced gas injection in Wolfcamp. Showing two-phase
envelope at (1) Initial condition, (2) Depleted condition, (3-
5) Three different injection slug sizes ................................................ 31
Figure 4.3: Two-phase envelopes of reservoir fluid at various stages of
produced gas injection in Eagle Ford (GOR=500 scf/stb).
Showing two-phase envelope at (1) Initial condition, (2)
Depleted condition, (3-5) Three different injection slug
sizes .................................................................................................... 32
Figure 4.4: Two-phase envelopes of reservoir fluid at various stages of
produced gas injection in Eagle Ford (GOR=1000 scf/stb).
Showing two-phase envelope at (1) Initial condition, (2)
Depleted condition, (3-5) Three different injection slug
sizes .................................................................................................... 33
Figure 4.5: Two-phase envelopes of reservoir fluid at various stages of
produced gas injection in Eagle Ford (GOR=2000 scf/stb).
Showing two-phase envelope at (1) Initial condition, (2)
Depleted condition, (3-5) Three different injection slug
sizes .................................................................................................... 33
Texas Tech University, Yiran Liu, May 2020
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Figure 4.6: Two-phase envelopes of reservoir fluid at various stages of
produced gas injection in Eagle Ford (Average GOR=2500
scf/stb). Showing two-phase envelope at (1) Initial
condition, (2) Depleted condition, (3-5) Three different
injection slug sizes ............................................................................. 34
Figure 4.7: Two-phase envelopes of reservoir fluid at various stages of
produced gas injection in Eagle Ford (GOR=2781 scf/stb).
Showing two-phase envelope at (1) Initial condition, (2)
Depleted condition, (3-5) Three different injection slug
sizes .................................................................................................... 34
Figure 4.8: General guidelines for produced gas injection process ...................... 35
Texas Tech University, Yiran Liu, May 2020
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CHAPTER 1
INTRODUCTION
The method of gas injection for enhanced oil recovery (EOR) in unconventional
reservoirs is systematically studied (Johns and Orr 1996; Nojabaei, Johns and Chu 2013;
Sheng 2020). Produced gas injection in unconventional reservoirs deserves an attention
because the current natural gas price is considerably lower than the equivalent BTU-
based oil price, and the current pipeline capacity in the major U.S. oil fields, especially
the Permian Basin, is not enough to transfer the produced gas to processing facilities.
As a result, substantial volumes of produced gas associated with oil production is either
flared or transported subject to a significant pipeline cost. Therefore, the current
solutions are either expensive or hazardous to the environment (Du and Nojabaei 2019).
The miscible produced gas EOR mechanism is often a multi-contact miscibility
process. The injection gas dissolves into the oleic phase over multiple stages to develop
miscibility. The miscibility development is either a vaporizing gas drive or condensing
gas drive (Orr 2007). Upon the miscibility development, the fluid mixture mobility
improves because of the reduced viscosity, enhanced saturation (swelling) and reduced
local capillary pressure (Ettehadtavakkol 2016). In order to optimize the miscible
displacement, the injection pressure should be above the minimum miscibility pressure
(MMP), defined as the lowest pressure above which gas and oil achieve miscibility at
reservoir conditions. As a key to a successful produced gas injection process, the MMP
should be determined based on the phase behavior analysis of the reservoir fluid and the
produced gas.
This thesis investigates the produced gas injection process for three
unconventional reservoirs: Northern San Andres, Lower Wolfcamp and Eagle Ford, all
of which, are important resources in the U.S. with significant EOR potential. From these
Texas Tech University, Yiran Liu, May 2020
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three reservoirs, only Eagle Ford has been explored through produced gas injection
pilots. EOG Resources (EOG) was the first company to report a successful produced
gas injection EOR with 30% to 70% incremental oil production in the Eagle Ford
(Rassenfoss 2017). Figure 1.1 present the result of EOG pilots in Eagle Ford.
Figure 1.1: Cumulative oil production per well change with enhanced oil recovery
project of EOG Resources in Eagle Ford (Cedric 2016)
However, EOG did not disclose any details about the field operation. In 2018,
Hoffman evaluated EOG pilots in the Eagle Ford based on the published data by the
Texas Railroad Commission. Hoffman believed that Eagle Ford pilots have been almost
exclusively hydrocarbon gas injected (presumably due to the availability of the
injectant) with the huff-n-puff method (Hoffman, 2018). That is, gas is injected into the
well, and shut in for several weeks to make sure gas seeps from the fractures into tight
Texas Tech University, Yiran Liu, May 2020
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rocks and dissolves into the oil. Then open the well for production. This method also
called cyclic gas injection.
This study rigorously investigates the keys to a successful produced gas EOR
project from the phase behavior viewpoint, with a critical insight to the advantages and
disadvantages of each of the three candidates. The contributions are to (1) find the
optimum produced gas compositions to achieve the MMP and (2) provide guidelines
for effective gas injection in other reservoirs. The results reveal an important insight to
the successful produced gas injection practice in the Eagle Ford and help with EOR
practices in other unconventional reservoirs in the future.
Texas Tech University, Yiran Liu, May 2020
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CHAPTER 2
METHOD
Peng-Robinson equation of state (1978) and field units are used for all
compositional analyzes. Input data for oil compositions are collected from laboratory
measurements and published papers, including mole fraction, component parameters
and reservoir properties. Twu correlation (Twu 1984) and Lee–Kesler correlation (Lee
and Kesler 1975) are used to estimate unknown physical properties of heavy
components or pseudo components.
For San Andres, the black oil compositions are generated by recombining
separator liquid and gas compositions after collecting and analyzing the gas
chromatography results. Some PVT parameters required tuning to match the
experimental results including bubble-point pressure (Pb), gas oil ratio (GOR) and oil
formation volume factor (Bo). Upon splitting the C7+ component into 6 pseudo
components (C7-C11, C12-C16, C17-C22, C23-C28, C29-C30, C31+) and conducting
parameters regression, the tuned San Andres black oil model is obtained, as presented
in Table 2.1.
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Table 2.1: Compositions and component parameters of San Andres black oil with initial reservoir pressure of 1565 psia and
reservoir temperature of 107 ℉
Component Mole
Fraction (%)
Critical Pressure
(atm)
Critical Temperature
(K)
Acentric Factor
Molecular Weight
Specific Gravity
Boiling Point
(deg F)
Volume Shift
Binary Interaction Coefficient
CO2 N2
CO2 1.31 72.80 304.20 0.225 44.010 0.818 -109.21 0 0 0
N2 0.50 33.50 126.20 0.040 28.013 0.809 -320.35 0 0 0
C1 18.20 45.40 190.60 0.008 16.043 0.300 -258.61 0 0.105 0.025
C2 9.73 48.20 305.40 0.098 30.070 0.356 -127.57 0 0.13 0.01
C3 7.34 41.90 369.80 0.152 44.097 0.507 -43.69 0 0.125 0.09
IC4 1.31 36.00 408.10 0.176 58.124 0.563 10.67 0 0.12 0.095
NC4 3.72 37.50 425.20 0.193 58.124 0.584 31.19 0 0.115 0.095
IC5 1.97 33.40 460.40 0.227 72.151 0.625 82.13 0 0.115 0.1
NC5 2.09 33.30 469.60 0.251 72.151 0.631 96.89 0 0.115 0.11
C6 4.39 32.46 507.50 0.275 86.000 0.690 146.93 0 0.115 0.11
C7-C11 18.63 27.54 605.27 0.424 121.990 0.781 290.91 0.013 0.15 0.12
C12-C16 11.61 20.26 714.23 0.569 192.120 0.842 480.33 0.066 0.15 0.12
C17-C22 8.32 16.29 797.31 0.779 268.059 0.886 636.15 0.089 0.15 0.12
C23-C28 4.71 13.61 869.84 0.925 352.215 0.923 777.63 0.108 0.15 0.12
C29-C30 1.06 12.24 914.31 1.086 411.835 0.944 865.51 0.122 0.15 0.12
C31+ 5.11 9.63 1020.85 1.440 574.624 0.993 1081.28 0.172 0.15 0.12
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Li, Sheng, and Xu (2017) provide Wolfcamp oil composition data. For Lower
Wolfcamp formation, we use the initial reservoir pressure (Pi) of 6000 psia and reservoir
temperature (T) of 185 ℉.
The Eagle Ford formation is composed of four distinct fluid windows, namely
black oil, volatile oil, gas condensate and dry gas. Our focus is on the black oil and
volatile oil windows. We collected five oil compositions with different reservoir
pressures and temperatures: two black oil compositions and three volatile oil
compositions. Orangi et al. (2011) report three oil compositions with GOR values of
500 scf/stb, 1000 scf/stb and 2000 scf/stb. Gherabati et al. (2016) report one composition
with average GOR of 2500 scf/stb, and Gong et al. (2013) report one composition with
GOR of 2781 scf/stb.
The separator test determines the separator liquid and produced gas
compositions. The gas is separated at the surface as reservoir fluid passes through the
separator and into the stock tank. The produced gas may not be readily suitable for
injection, because the heavy components may liquefy at the injection pressure.
Therefore, only the light components (CO2, N2, C1, C2, C3) should make up the
injection gas.
Phase behavior of produced gas should be analyzed because the produced gas
should turn into supercritical fluid. Before injection, temperature of produced gas may
need a temperature increase to achieve supercritical conditions. The P-T diagram of
produced gas determines the two-phase boundary at the surface condition.
Three important PVT experiments or mechanisms determine the potential
success of a gas injection process from the phase behavior viewpoint: (1) minimum
miscibility pressure (MMP), which determines the displacement efficiency (2) swelling
test, which determines the saturation pressure and the mixture fluid mobility, and (3)
constant volume depletion test, which determines the primary depletion recovery
Texas Tech University, Yiran Liu, May 2020
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performance and the residual fluid composition. A brief description of these
experiments is presented in the following. Further discussions are available in the
literature (Pedersen et al. 2006).
The minimum miscibility pressure (MMP) is a key success factor for the
produced gas injection. We assume the solvent injection cycle is set to 0.01 and final
injection gas slug is set to 10% mole of the hydrocarbon. The Cell-to-Cell method is
applied to determine the MMP. Miscibility development is characterized by a
composition path which is calculated through a system of equations, honoring the
material balance and component velocity profiles. The composition path is
conventionally illustrated on ternary diagram for a three component system. The MMP
can be determined when either the vapor locus or the liquid locus of the intermediate
compositions converges to the plait point of the two-phase envelop. When the
miscibility is developed, the line connecting either the injection gas or the oil
composition and the plait point would fall into the single phase region (Orr 2007).
Depending on the position of the mixture composition with respect to the plait point,
one may define two possible miscibility development mechanisms, namely vaporizing
gas drive and condensing gas drive. Figure 2.1 shows the multi-contact (vaporizing gas
drive and condensing gas drive) miscibility development for a three-component system
on ternary diagram.
Texas Tech University, Yiran Liu, May 2020
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(a) Vaporizing Gas Drive
(b) Condensing Gas Drive
Figure 2.1: Ternary diagrams of two miscibility development mechanisms: (a)
Vaporizing gas drive and (b) Condensing gas drive (Orr 2007)
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The swelling test determines the reservoir fluid saturation pressure which
typically increases through the produced gas injection process, and decreases through
the depletion process. The saturation pressure is below initial reservoir pressure for the
undersaturated reservoirs, and above initial reservoir pressure for saturated reservoirs.
The volume of injection gas does affect the saturation pressure: increasing the injection
gas slug size usually increases the saturation pressure. Figure 2.2 schematically shows
the expansion of two-phase envelope and increase of saturation pressure with the
increase of injection gas slug size.
Figure 2.2: General diagram of the two-phase envelope in different conditions
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Constant volume depletion test (CVD) determines the composition and
subsequently provides the two-phase envelope of depleted reservoir fluid. The CVD test
is important for modeling of primary depletion process for unconventional horizontal
wells in ultra-tight formations, because the ultra-low permeability of the stimulated
reservoir volume does not allow for an effective flow of hydrocarbon into the drainage
area. The significance of this observation is better explained when we present the Lower
Wolfcamp and Eagle Ford results.
Texas Tech University, Yiran Liu, May 2020
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CHAPTER 3
RESULTS
A key step to a successful produced gas injection project is to determine the
optimum injection gas composition and slug size, which are subject to the separator
design and the composition of reservoir fluid. The separator may consist of one or two
stages with a specific operational pressure and temperature. The objective is to adjust
the separator stages and operating conditions, such that: (1) the separator gas has
sufficient volume per produced liquid, (2) methane content is maximized and the
valuable ethane and propane content is minimized, and (3) the MMP is minimized to
ensure the miscibility and low injection cost. These objectives evidently conflict, and
thus, our goal is to adjust the separator design to optimize the gas injection performance
subject to the operational and economic constraints. This section presents the results of
this optimization effort for Northern San Andres, Lower Wolfcamp and Eagle Ford
formations.
3.1 Northern San Andres Formation
We investigated multiple separator design candidates to optimize the gas
injection performance, and we only present the final results. For San Andres, the
optimum design consists of one separator (Separator 1) with operational pressure (PSP)
of 50 psia. Separator temperature (TSP) has little influence on optimum gas composition
and 75 ℉ is commonly reported by the operators. Table 3.1 and Figure 3.1 respectively
show the composition and P-T diagram of the produced gas.
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Table 3.1: Compositions of produced gas based on one-stage separator design.
Pi=1565 psia, T=107 ℉
Component Reservoir Oil
Mole Fraction (%)
Separator 1 Gas Mole Fraction (%)
PSP=50 psia TSP=75 deg F
CO2 1.31 3.45
N2 0.50 1.39
C1 18.20 50.02
C2 9.73 24.04
C3 7.34 13.58
IC4 1.31 1.58
NC4 3.72 3.59
IC5 1.97 0.91
NC5 2.09 0.76
C6 4.39 0.61
C7-C11 18.63 0.07
C12-C16 11.61 0.00
C17-C22 8.32 0.00
C23-C28 4.71 0.00
C29-C30 1.06 0.00
C31+ 5.11 0.00
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Figure 3.1: P-T diagram of produced gas based on one-stage separator design
The separator test results in the field and simulation both show that the volume
of produced gas is 325 scf/stb. The minimum single-phase supercritical temperature is
135 ℉, which is much higher than separator temperature. A temperature increase should
be conducted to turn produced gas into supercritical fluid before injection.
In addition to the temperature adjustment, adding a compressor before injection
is another design to deal with the produced gas. A compressor can actively liquefy heavy
components and leave light components (CO2, N2, C1, C2, C3) to make up the injection
gas. Table 3.2 and Figure 3.2 respectively show the composition and P-T diagram of the
injection gas.
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Table 3.2: Compositions of injection gas based on one-stage separator design. Pi=1565
psia, T=107 ℉. Injection gas composition is highlighted
Component Reservoir Oil
Mole Fraction (%)
Separator 1 Gas Mole Fraction (%)
PSP=50 psia TSP=75 deg F
Normalized Injection Gas
Composition (%)
CO2 1.31 3.45 3.73
N2 0.50 1.39 1.50
C1 18.20 50.02 54.09
C2 9.73 24.04 26.00
C3 7.34 13.58 14.68
IC4 1.31 1.58
NC4 3.72 3.59
IC5 1.97 0.91
NC5 2.09 0.76
C6 4.39 0.61
C7-C11 18.63 0.07
C12-C16 11.61 0.00
C17-C22 8.32 0.00
C23-C28 4.71 0.00
C29-C30 1.06 0.00
C31+ 5.11 0.00
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Figure 3.2: P-T diagram of injection gas based on one-stage separator design
Based on compressor design, the minimum single-phase supercritical
temperature is 58 ℉, which is sufficiently low for the injection gas to remain at
supercritical condition.
After injection, the MMP is 2011 psia at reservoir temperature, which ensures
the miscibility achievement at a reasonable injection cost. The Saturation pressure of
fluid mixture at reservoir temperature is 1507 psia, which is less than both reservoir
pressure and MMP. Under this condition, injection pressure should set at or above MMP
to achieve miscibility. The injection gas slug, however, should be monitored to ensure
the reservoir fluid will remain undersaturated. The latter will be further discussed in the
Discussion section.
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The MMP is affected by reservoir temperature, oil composition and injection
gas composition. Among these three factors, the injection gas composition is the only
parameter that can be adjusted. The key to achieve favorable miscibility conditions is to
decrease mole fraction of C1 and increase mole fraction of C2 and C3. Adding a second
separator (Separator 2) is an effective way to adjust the composition at an additional
operational cost and reduced injection gas volume. To balance the cost and benefit, the
first separator pressure and temperature are optimized to 600 psia and 75 ℉. The second
separator pressure and temperature are optimized at 50 psia and 75 ℉. The second
separator pressure considerably affects MMP value. Table 3.3 presents the composition
of produced gas and injection gas. Figure 3.3 presents the P-T diagram of produced gas.
Figure 3.4 presents the P-T diagram of injection gas based on compressor design.
Table 3.3: Compositions of injection gas based on two-stage separator design. Pi=1565
psia, T=107 ℉. Injection gas composition is highlighted
Component Reservoir Oil Mole Fraction
(%)
Separator 1 Gas Mole Fraction (%)
PSP=600 psia TSP=75 deg F
Separator 2 Gas Mole Fraction (%)
PSP=50 psia TSP=75 deg F
Normalized Injection Gas Composition
(%)
CO2 1.31 2.95 3.88 4.22
N2 0.50 3.13 0.65 0.71
C1 18.20 75.16 41.42 45.07
C2 9.73 13.67 29.40 32.00
C3 7.34 3.72 16.54 18.00
IC4 1.31 0.31 1.78
NC4 3.72 0.65 3.94
IC5 1.97 0.15 0.94
NC5 2.09 0.13 0.77
C6 4.39 0.11 0.61
C7-C11 18.63 0.02 0.07
C12-C16 11.61 0.00 0.00
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Table 3.3 Continued
C17-C22 8.32 0.00 0.00
C23-C28 4.71 0.00 0.00
C29-C30 1.06 0.00 0.00
C31+ 5.11 0.00 0.00
Figure 3.3: P-T diagram of produced gas based on two-stage separator design
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Figure 3.4: P-T diagram of injection gas based on two-stage separator design
The two-separator solution reduces the produced gas volume down to 208 scf/stb
and increases the minimum single-phase supercritical temperature to 142 ℉. If we use
the compressor design, the minimum single-phase supercritical temperature of injection
gas will increase to 76 ℉. On the positive side, the MMP and saturation pressure
respectively decrease to 1888 psia and 1436 psia.
Therefore, applying the two-stage separator design provides better injection gas
composition at the cost of reduced gas volumes and increased minimum supercritical
gas temperature. There is no clear optimum solution for this case. The decision on the
optimum number of separator stages for the Northern San Andres formation requires a
Texas Tech University, Yiran Liu, May 2020
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separate study which we leave for future. In addition, the compressor design is an ideal
design and will not be discussed any more.
3.2 Lower Wolfcamp Formation
The optimum separator design for the Lower wolfcamp formation consists of
two separators with operating pressures of 600 psia and 50 psia, and an operating
temperature of 150 ℉. Table 3.4 shows the composition of injection gas and Figure 3.5
shows the P-T diagram of produced gas.
Table 3.4: Compositions of injection gas based on two-stage separator design. Oil
composition data is provided by Li, Sheng, and Xu (2017). Pi=6000 psia, T=185 ℉.
Injection gas composition is highlighted
Component Reservoir Oil Mole Fraction
(%)
Separator 1 Gas Mole Fraction (%)
PSP=600 psia TSP=150 deg F
Separator 2 Gas Mole Fraction (%)
PSP=50 psia TSP=150 deg F
Normalized Injection Gas
Composition (%)
CO2 0.35 0.61 0.57 0.75
N2 1.16 2.75 0.56 0.74
C1 33.32 70.88 31.79 41.98
C2 8.66 12.77 17.85 23.57
C3 9.55 8.52 24.96 32.96
IC4 1.06 0.59 2.58
NC4 4.86 2.20 10.95
C5-C6 8.66 1.37 9.05
C7-C12 18.70 0.31 1.69
C13-C21 7.50 0.00 0.00
C22-C80 6.23 0.00 0.00
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Figure 3.5: P-T diagram of produced gas for Wolfcamp oil
Simulation results show the volume of produced gas is 261 scf/stb and the
minimum single-phase supercritical temperature is 257 ℉, MMP is 1882 psia and
saturation pressure is 2735 psia. Saturation pressure is smaller than reservoir pressure
and much bigger than the MMP. Because increasing the pressure above the saturation
pressure does not further improve the recovery once the miscibility is achieved, the
injection pressure should fall between the MMP and saturation pressure. This is a
favorable condition because one may select the injection pressure slightly above the
MMP and ensure that the reservoir fluid may not get saturated for a large range of
injection slug sizes.
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3.3 Eagle Ford Formation
Five Eagle Ford fluid compositions are prepared through the literature review.
The composition of injection gas and the P-T diagram of the produced gas for each of
the five fluids are shown in Table 3.5 through Table 3.9 and Figure 3.6 through Figure
3.10. The optimum separator design consists of two stages with operating pressures of
600 psia and 50 psia, and temperature of 150 ℉.
Table 3.5: Compositions of injection gas based on two-stage separator design. Black
oil composition data is provided by Orangi, et al. (2011). Pi=6300 psia, T=237 ℉,
GOR=500 scf/stb. Injection gas composition is highlighted
Component Reservoir Oil Mole Fraction
(%)
Separator 1 Gas Mole Fraction (%)
PSP=600 psia TSP=150 deg F
Separator 2 Gas Mole Fraction (%)
PSP=50 psia TSP=150 deg F
Normalized Injection Gas
Composition (%)
CO2 1.282 2.47 3.40 4.23
N2 0.073 0.23 0.06 0.08
C1 31.231 83.40 50.95 63.46
C2 4.314 6.94 12.84 15.99
C3 4.148 3.58 13.04 16.24
IC4 1.350 0.67 3.42
NC4 3.382 1.35 7.57
IC5 1.805 0.38 2.47
NC5 2.141 0.38 2.50
C6 4.623 0.40 2.69
C7-C10 16.297 0.19 1.04
C11-C14 12.004 0.01 0.02
C15-C19 10.044 0.00 0.00
C20+ 7.306 0.00 0.00
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Figure 3.6: P-T diagram of produced gas for Eagle Ford black oil, GOR=500 scf/stb
Table 3.6: Compositions of injection gas based on two-stage separator design. Black
oil composition data is provided by Orangi, et al. (2011). Pi =7350 psia, T=266 ℉,
GOR=1000 scf/stb. Injection gas composition is highlighted
Component Reservoir Oil Mole Fraction
(%)
Separator 1 Gas Mole Fraction (%)
PSP=600 psia TSP=150 deg F
Separator 2 Gas Mole Fraction (%)
PSP=50 psia TSP=150 deg F
Normalized Injection Gas
Composition (%)
CO2 1.821 2.80 3.65 4.59
N2 0.104 0.21 0.05 0.06
C1 44.522 81.32 47.31 59.45
C2 5.882 8.08 14.33 18.01
C3 4.506 4.03 14.24 17.89
IC4 1.298 0.75 3.74
Texas Tech University, Yiran Liu, May 2020
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Table 3.6 Continued
NC4 2.978 1.43 7.86
IC5 1.507 0.41 2.62
NC5 1.711 0.39 2.58
C6 3.28 0.38 2.57
C7-C10 11.563 0.19 1.03
C11-C14 8.94 0.01 0.02
C15-C19 7.127 0.00 0.00
C20+ 4.762 0.00 0.00
Figure 3.7: P-T diagram of produced gas for Eagle Ford black oil, GOR=1000 scf/stb
Texas Tech University, Yiran Liu, May 2020
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Table 3.7: Compositions of injection gas based on two-stage separator design. Volatile
oil composition data is provided by Orangi, et al. (2011). Pi=8050 psia, T=285 ℉,
GOR=2000 scf/stb. Injection gas composition is highlighted
Component Reservoir Oil Mole Fraction
(%)
Separator 1 Gas Mole Fraction (%)
PSP=600 psia TSP=150 deg F
Separator 2 Gas Mole Fraction (%)
PSP=50 psia TSP=150 deg F
Normalized Injection Gas
Composition (%)
CO2 2.306 2.98 3.70 4.72
N2 0.132 0.19 0.04 0.05
C1 56.447 79.70 44.32 56.48
C2 7.288 8.84 15.05 19.18
C3 4.827 4.48 15.35 19.57
IC4 1.251 0.85 4.15
NC4 2.615 1.54 8.33
IC5 1.240 0.46 2.90
NC5 1.325 0.42 2.74
C6 2.076 0.35 2.38
C7-C10 7.316 0.18 1.02
C11-C14 5.924 0.01 0.02
C15-C19 4.509 0.00 0.00
C20+ 2.745 0.00 0.00
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Figure 3.8: P-T diagram of produced gas for Eagle Ford volatile oil, GOR=2000
scf/stb
Table 3.8: Compositions of injection gas based on two-stage separator design. Volatile
oil composition data is provided by Gherabati, et al. (2016). Pi=11094 psia, T=320 ℉,
Average GOR=2500 scf/stb. Injection gas composition is highlighted
Component Reservoir Oil Mole Fraction
(%)
Separator 1 Gas Mole Fraction (%)
PSP=600 psia TSP=150 deg F
Separator 2 Gas Mole Fraction (%)
PSP=50 psia TSP=150 deg F
Normalized Injection Gas
Composition (%)
CO2 1.025 1.20 1.55 2.01
N2 0.102 0.13 0.03 0.04
C1 60.537 76.70 39.48 51.30
C2 11.131 12.66 19.61 25.48
C3 5.521 5.16 16.29 21.17
IC4 1.262 0.92 4.27
Texas Tech University, Yiran Liu, May 2020
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Table 3.8 Continued
NC4 2.365 1.55 7.98
IC5 1.122 0.49 3.08
NC5 1.11 0.43 2.77
C6 1.464 0.32 2.20
C7 2.011 0.23 1.50
C8 2.608 0.15 0.93
C9 2.042 0.06 0.31
C10+ 7.7 0.00 0.00
Figure 3.9: P-T diagram of produced gas for Eagle Ford volatile oil, Average
GOR=2500 scf/stb
Texas Tech University, Yiran Liu, May 2020
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Table 3.9: Compositions of injection gas based on two-stage separator design. Volatile
oil composition is provided by Gong, et al. (2013). Pi=10155 psia, T=307 ℉,
GOR=2781 scf/stb. Injection gas composition is highlighted
Component Reservoir Oil Mole Fraction
(%)
Separator 1 Gas Mole Fraction (%)
PSP=600 psia TSP=150 deg F
Separator 2 Gas Mole Fraction (%)
PSP=50 psia TSP=150 deg F
Normalized Injection Gas
Composition (%)
CO2 1.12 1.27 1.74 2.24
N2 0.14 0.18 0.04 0.05
C1 62.54 76.17 38.50 49.56
C2 11.76 13.09 20.50 26.39
C3 5.59 5.26 16.90 21.76
IC4 1.36 1.03 4.84
NC4 2.32 1.58 8.31
IC5 1.17 0.55 3.49
NC5 1.10 0.46 2.99
C6 1.55 0.38 2.57
C7+ 11.36 0.03 0.12
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Figure 3.10: P-T diagram of produced gas for Eagle Ford volatile oil, GOR=2781
scf/stb
The individual results for the five reservoir fluids are shown in the Table 3.9 in
an increasing order of GOR. All the MMPs are less than 2500 psia and minimum single-
phase supercritical temperatures are reasonably achievable at surface conditions. With
the increase of GOR, the MMP shows a downward trend. The saturation pressures are
all smaller than initial reservoir pressure, which implies the injection gas is unlikely to
evolve from oil and affect the miscibility at reservoir conditions.
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Table 3.10: Individual results of five Eagle Ford fluids
Eagle Ford Fluid MMP (psia)
Saturation Pressure
(psia)
Volume of Injection Gas
(scf/stb)
Minimum Single-Phase Supercritical Temperature
(deg F)
1.Black Oil
(GOR=500 scf/stb) 2416 2424 155 234
2.Black Oil
(GOR=1000 scf/stb) 2162 3777 170 234
3.Volatile Oil
(GOR=2000 scf/stb) 2040 5298 186 235
4.Volatile Oil
(GORavg=2500 scf/stb) 1927 4419 249 248
5.Volatile Oil
(GOR=2781 scf/stb) 1909 4011 277 224
For the first Eagle Ford fluid, saturation pressure is slightly greater than the
MMP. To achieve maximum recovery, the injection pressure should be more than the
saturation pressure upon the complete injection of the slug to enable complete
dissolution of injection gas into reservoir oil. Similar to the Wolfcamp, the saturation
pressure for the remaining four fluids is much greater than the MMP and the injection
pressure favorably falls between the MMP and saturation pressure. This important
observation is a key to success of produced gas injection in Eagle Ford, as well as the
favorable potential of the Lower Wolfcamp formation, as we discuss in the Discussion
section.
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CHAPTER 4
DISCUSSION
The saturation pressure plays an important role in the determination of the
optimum injection pressure and the injection slug size. For a fixed target slug size and
a saturation pressure smaller than MMP, achieving the MMP is the primary factor for
successful produced gas injection; and when the saturation pressure is above the MMP,
the decision to increase the injection pressure above the MMP depends on injection cost.
Meeting or exceeding the saturation pressure for a target slug size, in any case,
significantly improves the mobility of the oleic phase.
Tracking the saturation pressure for different target slug sizes also provides an
insight to the PVT characteristics of the reservoir fluid mixture. Figure 4.1 through
Figure 4.2 show the phase envelope development for Northern San Andres and Lower
Wolfcamp formations at different injection gas slug sizes based on two-stage separator
design. For San Andres, the saturation pressure is more than initial reservoir pressure
when injection gas slug increases to 15% mole of hydrocarbon, which means the
miscibility conditions change when the evolved gas is produced. On the contrary, the
acceptable injection gas slug size is bigger in Wolfcamp. The reservoir mixture fluid of
Wolfcamp remains undersaturated even if the injection gas slug increases to 50% mole
of hydrocarbon.
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Figure 4.1: Two-phase envelopes of reservoir fluid at various stages of produced gas
injection in San Andres. Showing two-phase envelope at (1) Initial condition, (2)
Depleted condition, (3-5) Three different injection slug sizes
Figure 4.2: Two-phase envelopes of reservoir fluid at various stages of produced gas
injection in Wolfcamp. Showing two-phase envelope at (1) Initial condition, (2)
Depleted condition, (3-5) Three different injection slug sizes
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For Eagle Ford formations, no matter black oil window or volatile oil window,
the highest initial reservoir pressure ensures that saturation pressure will remain below
the reservoir pressure even for the large injection gas slug size. Figure 4.3 through
Figure 4.7 show the phase envelope development for Eagle Ford formations at different
injection gas slug sizes based on two-stage separator design. Comparing two black oil
figures and three volatile oil figures, the two phase envelopes of volatile oil have
relatively small expansion with the increase of injection gas slug size and may even
shrink when formation GOR increase to 2500 scf/stb, which means the acceptable
injection gas slug size is bigger in volatile oil.
Figure 4.3: Two-phase envelopes of reservoir fluid at various stages of produced gas
injection in Eagle Ford (GOR=500 scf/stb). Showing two-phase envelope at (1) Initial
condition, (2) Depleted condition, (3-5) Three different injection slug sizes
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Figure 4.4: Two-phase envelopes of reservoir fluid at various stages of produced gas
injection in Eagle Ford (GOR=1000 scf/stb). Showing two-phase envelope at (1)
Initial condition, (2) Depleted condition, (3-5) Three different injection slug sizes
Figure 4.5: Two-phase envelopes of reservoir fluid at various stages of produced gas
injection in Eagle Ford (GOR=2000 scf/stb). Showing two-phase envelope at (1)
Initial condition, (2) Depleted condition, (3-5) Three different injection slug sizes
Texas Tech University, Yiran Liu, May 2020
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Figure 4.6: Two-phase envelopes of reservoir fluid at various stages of produced gas
injection in Eagle Ford (Average GOR=2500 scf/stb). Showing two-phase envelope at
(1) Initial condition, (2) Depleted condition, (3-5) Three different injection slug sizes
Figure 4.7: Two-phase envelopes of reservoir fluid at various stages of produced gas
injection in Eagle Ford (GOR=2781 scf/stb). Showing two-phase envelope at (1)
Initial condition, (2) Depleted condition, (3-5) Three different injection slug sizes
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To summary, the slug size is usually constrained in black oil reservoirs with low
initial reservoir pressure, such as San Andres. For reservoirs with high initial reservoir
pressure and volatile oil, such as Eagle Ford, a flexible operation process can be applied,
because a large slug size will not cause the two-phase envelope of injection conditions
to expand above the initial reservoir pressure. In addition, the volume of produced gas
in volatile oil reservoir is large enough to apply a two-stage separator design and collect
sufficient volume of enriched separator gas for injection.
Based on the above results, general guidelines are proposed for the produced gas
injection process, as shown in the Figure 4.8.
Figure 4.8: General guidelines for produced gas injection process
1. Depending on the reservoir fluid and GOR, one or two separators may
optimize produced gas composition to achieve favorable MMP, saturation pressure and
slug size.
Texas Tech University, Yiran Liu, May 2020
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2. The produced gas needs a temperature adjustment to maintain supercritical
gas state before injection.
3. The minimum single-phase supercritical temperature can be determined by
the P-T diagram of produced gas.
4. For the injection facility, the injection pressure depends on the relation
between saturation pressure and MMP as discussed.
5. The range of injection gas slug size depends on initial reservoir pressure and
formation gas oil ratio.
This study did not investigate the optimum design of the huff-n-puff injection
cycles for these reservoirs. We leave this important subject for future studies.
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CHAPTER 5
SUMMARY AND CONCLUSIONS
This study conducted the phase behavior analysis to optimize the produced gas
injection composition for EOR in Northern San Andres, Lower Wolfcamp and Eagle
Ford formation. The conclusions follow.
1. Optimum produced gas compositions to achieve favorable MMP in three
reservoirs are determined separately. General guidelines are provided for optimizing the
produced gas injection process. These guidelines give an insight to the successful EOR
operation for Eagle Ford pilots, as well as other reservoirs.
2. For San Andres, one or two separator stages may be applicable. Using one
separator could obtain more produced gas volumes and using two separators could
achieve lower MMP. The trade-off between these two designs should be further
investigated.
3. Five Eagle Ford oil compositions are analyzed. The higher GOR usually
results in a lower MMP.
4. Black oil reservoirs with low initial reservoir pressure are usually constrained
by injection gas slug size. Applying large injection gas slug size deteriorates the
miscibility conditions. On the contrary, the acceptable range of slug size is bigger in
volatile oil reservoirs with high initial reservoir pressure.
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