copyright 2020, yiran liu

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

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.


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


iv

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


v

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.


vi

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


design. Oil composition data is provided by Li, Sheng, and

Xu (2017). Pi=6000 psia, T=185 ℉. Injection gas

composition is highlighted ................................................................... 19


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


design. Black oil composition data is provided by Orangi, et

al. (2011). Pi=7350 psia, T=266 ℉, GOR=1000 scf/stb.



design. Volatile oil composition data is provided by Orangi,

et al. (2011). Pi=8050 psia, T=285 ℉, GOR=2000 scf/stb.



vii


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


design. Volatile oil composition is provided by Gong, et al.

(2013). Pi=10155 psia, T=307 ℉, GOR=2781 scf/stb.


Table 3.10: Individual results of five Eagle Ford fluids ....................................... 29


viii

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


ix

Figure 3.8: P-T diagram of produced gas for Eagle Ford volatile oil,

GOR=2000 scf/stb .............................................................................. 25


Average GOR=2500 scf/stb ............................................................... 26


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


produced gas injection in Wolfcamp. Showing two-phase

envelope at (1) Initial condition, (2) Depleted condition, (3-

5) Three different injection slug sizes ................................................ 31


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





sizes .................................................................................................... 33





sizes .................................................................................................... 33


x


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





sizes .................................................................................................... 34

Figure 4.8: General guidelines for produced gas injection process ...................... 35


1

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


2

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


3

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.


4

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.


5

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


6

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


7

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.


8

(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)


9

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


10

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.


11

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.


12

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


13

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.


14

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 (%)



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


15

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.


16

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

(%)





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


17

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


18

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


19

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


(%)






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


20

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.


21

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


(%)






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


22

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 ℉,



(%)






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


23

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


24

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 ℉,



(%)






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


25

Figure 3.8: P-T diagram of produced gas for Eagle Ford volatile oil, GOR=2000

scf/stb


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


(%)






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


26

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


27


oil composition is provided by Gong, et al. (2013). Pi=10155 psia, T=307 ℉,



(%)






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


28

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.


29

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.


30

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.


31

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


injection in Wolfcamp. Showing two-phase envelope at (1) Initial condition, (2)

Depleted condition, (3-5) Three different injection slug sizes


32

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.


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


33


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





34


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





35

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.


36

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.


37

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.


38

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