© copyright 2016, xingbang meng

Investigation of Enhanced Condensate Recovery Potential in Shale Gas Condensate

Reservoir

by Cyclic Gas Injection

by

Xingbang Meng, MS

A Dissertation

In

Petroleum Engineering

Submitted to the Graduate Faculty

of Texas Tech University in

Partial Fulfillment of

the Requirements for

the Degree of

Doctor of Philosophy

Approved

Dr. James J. Sheng

Chair of Committee

Dr. Marshall Watson

Dr. Habib K. Menouar

Dr. Lloyd Heinze

Dr. Amin Ettehadtavakkol

Mark Sheridan

Dean of the Graduate School

December, 2016

Texas Tech University, Xingbang Meng, December, 2016

ii

ACKNOWLEDGMENTS

First and foremost, my deepest appreciation and respect are extended to my

professor, Dr. James J. Sheng, who provided immense support and guidance to me. I am

so thankful for the energy and time he spent on me. All this work could not be finished

without his help. Also, the non-academic talks with Dr. Sheng gave me a positive

influence for my life. Thank you.

Also, I would like to thank my other committee members: Dr. Marshall Watson,

Dr. Habib K. Menouar, Dr. Habib K. Menouar, Dr. Lloyd Heinze, Dr. Amin

Ettehadtavakkol. Thank you for providing valuable comments and serving on my defense

committee.

To parents, for their endless and selfless love to me. Thanks for the fortunate life

they give to me. And no matter what happens, they are always there. I’ll keep everything

they have taught me and keep on moving.

To my aunt Yueduo, Yu. A strong woman. Thanks for her support during the hard

time.

To Yi. Thanks for her waiting. Thanks for her tolerant. Thanks for her love.

To my friend, Abu. Thanks for his encouragement.

Thanks to my friends, Tao, Yao, Ziqi, Yang, Yu Pang, Xiukun, Lei, Wenjin, Jie,

Xiao Chai, Xiao Kong, Xiao Xiong, Aihan, Xiaobin, Lao Pang. Thanks for the help

during these years.

Thanks for the support of the Department of Energy under Award Number DE-

FE0024311 and Petroleum Engineering in Texas Tech University.


iii

TABLE OF CONTENTS

ACKNOWLEDGMENTS ................................................................................................ ii

LISTS OF TABLES ....................................................................................................... viii

LISTS OF FIGURES .........................................................................................................x

CHAPTER 1 .......................................................................................................................1

INTRODUCTION..............................................................................................................1

1.1 Background ..............................................................................................................1

1.2 Problem Statement ...................................................................................................4

1.3 Dissertation Outline .................................................................................................5

CHAPTER 2 .......................................................................................................................7

CONCEPTS AND LITERATURE REVIEW .................................................................7

2.1 Flow regions in Gas Condensate Reservoir .............................................................7

2.2 Material Balance ......................................................................................................9

2.2.1 Reservoir Pressure above Dew Point Pressure ...............................................9

2.2.2 Reservoir Pressure below Dew Point Pressure ...............................................9

2.3 Flow Behavior of Gas Condensate ........................................................................10

2.3.1 Constant Volume Depletion ..........................................................................10

2.3.2 Constant Composition Expansion .................................................................12

2.4 Huff-n-Puff Gas Injection ......................................................................................14

2.5 Literature Review...................................................................................................17

2.4.1 Gas injection or water injection ....................................................................19

2.4.2 Chemical Treatment ......................................................................................23

2.4.3 Horizontal wells and Hydraulic Fracturing ...................................................25

CHAPTER 3 .....................................................................................................................28

LABORATORY STUDY FOR THE EOR POTENTIAL OF HUFF-N-PUFF

METHOD .........................................................................................................................28

3.1 Experiment Setup ...................................................................................................28

3.1.1 Experiment Design Principles.......................................................................28


iv

3.1.2 Material Preparation......................................................................................29

3.1.3 Experimental Procedures ..............................................................................37

3.2 Simulation Model for Experiments ........................................................................43

3.2.1 Experiment A ................................................................................................43

3.2.2 Experiment B1 ..............................................................................................45

3.2.3 Experiment B2 ..............................................................................................48

3.3 Summary ................................................................................................................49

CHAPTER 4 .....................................................................................................................50

EXPERIMENTAL AND SIMULATION RESULTS ...................................................50

4.1 CT analysis.............................................................................................................50

4.2 Phase Behavior Study ............................................................................................53

4.3 Grid Sensitivity Test of Simulation Model ............................................................54

4.4 Results for Experiment A.......................................................................................55

4.5 Results for Experiment B1 and B2 ........................................................................61

4.6 Summary ................................................................................................................72

CHAPTER 5 .....................................................................................................................73

REVAPORIZATION METHCHANISM OF HUFF-N-PUFF GAS INJECTION ...73

5.1 Gas Chromatography (GC) ....................................................................................73

5.2 Experiment Study...................................................................................................76

5.2.1 Material Preparation......................................................................................76

5.2.2 Experiment Procedure ...................................................................................77

5.3 Simulation Model...................................................................................................78

5.4 Results and Discussion ..........................................................................................80

5.5 Summary ................................................................................................................94

CHAPTER 6 .....................................................................................................................95

RESERVOIR SIMULATION OF HUFF-N-PUFF OPERATION .............................95

6.1 Current oil price .....................................................................................................95

6.2 Phase behavior of gas condensate ..........................................................................97

6.3 Reservoir Model Description .................................................................................99

6.4 Fracture Effect .....................................................................................................108


v

6.5 Primary depletion time .........................................................................................112

6.6 Soaking time ........................................................................................................116

6.7 Injection Period ....................................................................................................119

6.8 Number of huff-n-puff cycles and Production period ..........................................125

6.9 Summary ..............................................................................................................133

CHAPTER 7 ...................................................................................................................135

CONCLUSION AND DISCUSSION ...........................................................................135

7.1 General Conclusions ............................................................................................135

7.2 Future work ..........................................................................................................137

NOMENCLATURES ....................................................................................................138

BIBLIOGRAPHY ..........................................................................................................139


vi

ABSTRACT

When a shale gas condensate reservoir is produced, the pressure in the reservoir

falls below the dew point pressure, and liquid condensate is formed in the pore space.

The condensate can accumulate near the wellbore. This condensate blocking reduces the

gas relative permeability and decreases gas production. Since the condensate is formed

by the heavy components, it has great value in industry.

In this dissertation both laboratory study and reservoir scale simulation work were

performed to investigate the potential of huff-n-puff gas injection method to enhance

condensate recovery in shale gas condensate reservoirs.

The laboratory study examines the potential of the huff-n-puff gas injection

method to recover condensate in shale gas condensate reservoir by conducting

experiments on shale cores. Numerical models of the experiments were developed to

verify the experiment results. Our laboratory study shows that condensate recovery was

increased by applying huff-n-puff gas injection on a shale core. We also compared the

efficiency of huff-n-puff gas injection with the gas flooding method, and experiment

results show that huff-n-puff was more effective than gas flooding. During the

experiments, condensate accumulated near the production end region. Since the only well

in the huff-n-puff process was located where the gas was injected into the core from the

same end face that means the condensate region was located near the injection end. The

pressure in the condensate region built up faster than the pressure in the flooding

experiment. Also, due to the ultra-low permeability, the pressure propagation was much

slower in shale cores than in conventional reservoir cores such as a sand core, and the

efficiency of gas flooding is much lower in shale cores.

An experiment was also conducted to investigate the mechanism of huff-n-puff

gas injection. The results show that the main mechanism of huff-n-puff gas injection to

enhance the condensate recovery is re-vaporization. When pressure is increased in the

huff process, condensate is re-vaporized into a gas state and produced from the reservoir.


vii

The results of reservoir scale simulation work also show the effectiveness of huff-

n-puff gas injection to enhance condensate recovery in shale gas condensate reservoirs.

The optimization work of the application of huff-n-puff is also discussed in the

dissertation. It shows that by applying the optimized huff-n-puff gas injection, profits can

be highly increased compared to that of primary depletion.


viii

LISTS OF TABLES

Table 1.1 Decline rate of shale gas wells. (Stand & Poor’s CreditWeek) ...........................2

Table 2.1 Coexistence of different flow regions ..................................................................8

Table 2.2 Compositions of Eagle Ford shale gas condensate reservoir fluid ....................11

Table 2.3 Enhanced condensate recovery methods ...........................................................18

Table 3.1 Core properties ...................................................................................................30

Table 3.2 Reservoir and fluid properties used in the simulation model A ........................44

Table 3.3 Reservoir and fluid properties used in the simulation B1 and B2 .....................46

Table 4.1 Gas condensate mixture compositions ...............................................................54

Table 5.1 Core properties ...................................................................................................76

Table 5.2 Reservoir and fluid properties used in the simulation .......................................80

Table 5.3 Butane% in produced gas ..................................................................................84

Table 6.1 Oil price forecast by The Economy Forecast Agency .......................................96

Table 6.2 Distribution of block sizes in I direction (ft) ...................................................102

Table 6.3 Distribution of block sizes in J direction (ft) (SRV) ........................................103

Table 6.4 Reservoir properties .........................................................................................103

Table 6.5 Peng-Robinson EOS Fluid Description of Eagle Ford Condensate Lumping .104

Table 6.6 Binary interaction coefficients for Eagle Ford gas condensate .......................104

Table 6.7 Primary and incremental recoveries in different natural permeability cases ...111

Table 6.8 Condensate recovery and incremental recovery for different primary depletion

time ..................................................................................................................................114

Table 6.9 Profits for different injection time cases ..........................................................122

Table 6.10 Profits for three different primary depletion ..................................................124

Table 6.11 Profits comparison between huff-n-puff gas injection and primary depletion125

Table 6.12 Profits analysis of different cycle numbers....................................................128


ix

Table 6.13 Profits analysis for different cycle numbers of huff-n-puff gas injection and

primary depletion. ............................................................................................................131

Table 6.14 Profits comparison between primary depletion, 11 cycles with 200 days

production, 6 cycles with 400 days, total exploitation time was same: 8225 days..........132


x

LISTS OF FIGURES

Figure 1.1 Shale sources distribution in United States (U.S. Energy Information

Administration May, 2011) ..................................................................................................1

Figure 1.2 Phase diagram of a retrograde-condensate gas (Fan et al., 2005) ......................3

Figure 1.3 Liquid dropout and pressure profile around a gas condensate well (Ahmed,

1998) ....................................................................................................................................4

Figure 2.1 Schematic gas condensate flow behavior in three regions (Roussennac, 2001) 8

Figure 2.2 A schematic of constant volume depletion experiment (CMG, WinProp, 2014)11

Figure 2.3 Example, result of CVD experiment ................................................................12

Figure 2.4 Schematic of constant composition expansion experiment (Whitson and Brule,

2000) ..................................................................................................................................13

Figure 2.5 Total relative volume as a function of pressure from CCE experiment ...........14

Figure 2.6 Huff-n-puff process (From Wikipedia) ............................................................15

Figure 2.7 Comparison of gas flooding and huff-n-puff injection.....................................16

Figure 2.8 A typical production decline curve in Whelan field. (Lin and Finley, 1985) ..17

Figure 2.9 Determination of wettability (Biolin Scientific)...............................................24

Figure 3.1 Phase diagram of gas condensate mixture used in the experiment ..................29

Figure 3.2 Permeability measure equipment .....................................................................30

Figure 3.3 Butane vapor pressure curve (from The Spudding Handbook) ........................31

Figure 3.4 Liquid butane transfer .......................................................................................33

Figure 3.5 Accumulator filled with gas condensate mixture at 2200 psi ...........................34

Figure 3.6 Principle of CT scanner (Vinegar and Wellington, 1987) ................................35

Figure 3.7 CT scanner ........................................................................................................36

Figure 3.8 Schematic of huff-n-puff gas injection apparatus ............................................38

Figure 3.9 New injection setting in Experiment B ............................................................40

Figure 3.10 Schematic of Experiment B1 ..........................................................................41


xi

Figure 3.11 Schematic of Experiment B2 ..........................................................................42

Figure 3.12 Simulation Model for Experiment A ..............................................................45

Figure 3.13 Simulation model for experiment B1 in JK view, IK view and 3D view ......47

Figure 3.14 Simulation model for Experiment B2.............................................................49

Figure 4.1 CT image for experiment A ..............................................................................50

Figure 4.2 CT image for experiment B1 and B2 ...............................................................51

Figure 4.3 Interactive 3D Surface Plot for the first slice in first cycle in Experiment A ..52

Figure 4.4 CT number comparison between dry core and saturated core (Experiment B1)53

Figure 4.5 Liquid dropout curve for gas mixture at 68°F ..................................................54

Figure 4.6 Condensate saturation variation in experiment A ............................................56

Figure 4.7 Condensate recovery variation in experiment A ..............................................57

Figure 4.8 Primary condensate saturation and pressure variation vs Time .......................58

Figure 4.9 Condensate recovery in simulation model A ....................................................58

Figure 4.10 Condensate comparison between simulation results and experiment results,

experiment A ......................................................................................................................59

Figure 4.11 Effect of injection pressure .............................................................................60

Figure 4.12 Effect of cycle numbers on condensate saturation, experiment B1 ................61

Figure 4.13 Effect of cycle numbers on condensate recovery, experiment B1 .................62

Figure 4.15 Condensate saturation variation in simulation model B1 ...............................63

Figure 4.16 Condensate recovery variation in simulation model B1 .................................64

Figure 4.17 Condensate saturation comparison of simulation results with experimental

data for huff-n-puff ............................................................................................................65

Figure 4.18 Condensate recovery comparison of simulation results with experimental

data for huff-n-puff ............................................................................................................65

Figure 4.19 Condensate recovery vs time, gas flooding experiment B2 ...........................66


xii

Figure 4.20 Simulation results of condensate saturation, injection pressure and reservoir

pressure for gas flooding ....................................................................................................67

Figure 4.21 Condensate recovery in simulation model B2 ................................................67

Figure 4.22 Condensate saturation variation during gas flooding .....................................68

Figure 4.23 Comparison of simulation results with experimental data for gas flooding ...69

Figure 4.24 Effect of soaking time on condensate recovery in huff-n-puff injection ........70

Figure 4.25 Comparison between huff-n-puff and gas flooding ........................................71

Figure 5.1 Compose of GC-MS .........................................................................................74

Figure 5.2 GC-MS used in the study .................................................................................74

Figure 5.3 Principle of Gas Chromatography. (Perry, 1981) .............................................74

Figure 5.4 Schematic of huff-n-puff gas injection for revaporization study .....................78

Figure 5.5 Simulation model of experiment, IJ view and JK view....................................79

Figure 5.6 Variation of condensate saturation ...................................................................81

Figure 5.7 Variation of condensate recovery .....................................................................81

Figure 5.8 GC curves of initial produced gas and produced gas after different cycle .......84

Figure 5.9 Butane content during primary depletion in experiment ..................................85

Figure 5.10 Butane content after primary depletion and huff-n-puff cycles in experiment86

Figure 5.11 Effect of numerical dispersion on the change of condensate saturation ........87

Figure 5.12 Pressure and condensate saturation in simulation ..........................................87

Figure 5.13 Condensate recovery in simulation ................................................................88

Figure 5.14 Condensate saturation in block 50, 1, 5 ..........................................................89

Figure 5.15 Butane content in produced gas in simulation ................................................89


data .....................................................................................................................................90

Figure 5.17 Butane content comparison of simulation results with experimental data .....91


xiii

Figure 5.18 Production rate of gas state butane .................................................................92

Figure 5.19 liquid production rate in simulation ...............................................................93

Figure 5.20 Comparison of cumulative production between methane and butane ............93

Figure 6.1 WTI-Brent oil pricing (from website) ..............................................................96

Figure 6.2 Schematic of simulation model ......................................................................101

Figure 6.3 Phase diagram of Eagle Ford reservoir fluid sample......................................106

Figure 6.4 Relative volume curve of gas condensate fluid ..............................................107

Figure 6.5 The liquid dropout curve for CCE experiment at 200 oF on the gas condensate

mixture .............................................................................................................................107

Figure 6.6 Gas recovery of an un-fractured shale gas condensate reservoir ...................108

Figure 6.7 Condensate recovery comparison ...................................................................109

Figure 6.8 Pressure and condensate saturation comparison between 0.05 mD case and

0.005 mD case, after the 1st cycle injection .....................................................................112

Figure 6.9 Condensate recovery for different primary depletion time ............................113

Figure 6.10 Gas production rate for 25 years primary depletion .....................................115

Figure 6.11 Soaking time effect on condensate recovery ................................................117

Figure 6.12 Pressure and condensate saturation comparison between no soaking case and

100 days soaking time case ..............................................................................................118

Figure 6.13 Condensate recovery for different injection time cases ...............................120

Figure 6.14 Condensate saturation distribution for different injection time cases ..........121

Figure 6.15 Condensate recovery, condensate and oil cumulative production and

cumulative gas injection in 50 days injection time case ..................................................121

Figure 6.16 Condensate saturation after 15 years primary depletion ..............................123

Figure 6.17 Pressure distribution after 1st cycle of injection for different injection time

cases .................................................................................................................................123

Figure 6.18 Condensate recovery and average pressure for 11-cycles huff-n-puff gas

injection............................................................................................................................126


xiv

Figure 6.19 Condensate recovery comparison between huff-n-puff gas injection and

primary depletion .............................................................................................................127

Figure 6.20 Production rate in 11-cycles huff-n-puff simulation work ...........................129

Figure 6.21 Condensate recovery comparison between 11-cycles huff-n-puff and 6-cycles

huff-n-puff........................................................................................................................130

Figure 6.22 Incremental profits by applying huff-n-puff gas injection at different oil

prices ................................................................................................................................133


1

CHAPTER 1

INTRODUCTION

In this chapter, the background of this research is first described. Then, the

motivation and objective of this research is discussed.

1.1 Background

In the last decade, unconventional sources of gas and oil such as shale oil, shale

gas, and shale gas condensate have been widely developed in United States. Production

of gas and liquid from organic-rich shale reservoirs has exploded into the world energy

market. Figure 1.1 shows the shale sources distribution. As we can see, shale sources play

an important role. However, during the past two years, the oil and gas market has been

facing a big challenge. The price of gas and oil goes so low that it makes the oil industry

suffer a “winter time”, especially for shale sources developers. The exploitation of shale

plays is more expensive than conventional reservoirs. Thus, it is very important to seek

ways to maximize hydrocarbon production in the existing explored shale reservoirs, in

order to maximize profits as much as possible. In this study, an effective gas injection

method-cyclic gas injection to enhance the liquid production in shale gas condensate

reservoirs is investigated.

Figure 1.1 Shale sources distribution in United States (U.S. Energy Information

Administration May, 2011)


2

Table 1.1 shows the initial well rates and first-year decline rates for wells in the

five major shale plays, reported by Stand & Poor’s Creditweek. In general the first-year

decline rates vary from 63% to 86% while initial well rates vary from 2 MMscfd to 9.5

MMscfd. One reason for this high decline rate is the low pressure gradient due to the

ultra-low permeability of the shale rocks. Another important reason for this phenomenon

is the condensate blockage effect. Among this shale gas plays, parts of them are shale gas

condensate reservoirs. Thus, when the pressure is depleted, the form of the condensate

could decrease the gas productivity.

Table 1.1 Decline rate of shale gas wells. (Stand & Poor’s CreditWeek)

Initial well rates,

MMscfd Early well decline

rates, %/year

Barnett 2 70

Fayetteville 2.5 63

Haynesville 9.5 86

Marcellus 4.5 75

Woodford 3.5 80

Shale gas condensate reservoirs present an important role in hydrocarbon reserves.

Actually, “gas condensate reservoir” has been recognized as a typical reservoir type. Gas

condensate reservoirs produce gas in the range of 30 - 300 STB/MMSCF. The ranges of

pressure and temperature gas condensate reservoir are between 3000 and 8500 psi and

150 - 400F, respectively (Zendehboudi, 2012). Figure 1.2 presents an example diagram of

a gas condensate region.


3

Figure 1.2 Phase diagram of a retrograde-condensate gas (Fan et al., 2005)

During the production of a gas condensate reservoir, the most valuable

components remain in the reservoir. This is the most distinctive character of the gas

condensate reservoir. As Figure 1.2 shows, the reservoir fluids are in gas phase at the

initial reservoir conditions. After the exploitation as the reservoir pressure decreases

below the dew point pressure, liquid condenses from gas phase and forms a ring or bank

around the producing well in the near well region as shown in Figure 1.3. Generally this

formed liquid-condensate cannot flow until the accumulated condensate saturation

exceeds the critical condensate saturation, due to the effect of the relative permeability

and capillary pressure in the pore. As the pressure continues decreasing, the condensate

begins to be revaporized.

The condensate banking or condensate blockage near the wellbore or fracture

reduces the well productivity significantly, by 50% -80%, in many instances by a decline

factor of 2 to 4. (Ayyalasomayajula et al., 2005). Also, according to the research of

Wheaton and Zhang (2000), the condensate banking problem is more significant for low

permeability condensate systems. Additionally, the condensate is formed by the heavy

components of reservoir fluid, and has a high value. Therefore, investigations to enhance

condensate recovery in shale gas condensate reservoirs are of great importance.


4

Figure 1.3 Liquid dropout and pressure profile around a gas condensate well (Ahmed,

1998)

1.2 Problem Statement

This research investigates the potential of cyclic gas injection (huff-n-puff) gas

injection method to recover condensate in shale gas condensate reservoirs by conducting

experimental work and simulation work. Although many researches have studied and

investigated the EOR potential in conventional reservoirs, few researches have been

conducted for shale gas condensate reservoirs. Specifically, this research focused on the

following aspects:


5

EOR potential of huff-n-puff gas injection. The objective of this work was to

investigate the potential of huff-n-puff gas injection to enhance condensate recovery in

shale gas condensate reservoirs. The work examined whether huff-n-puff could enhance

condensate recovery by conducting experimental works. Also, lab simulation models for

the experiment process were built to both verify the experiment results, and to help better

understand experiment results. Except this core scale work, field scale simulation work

was conducted to investigate the application of huff-n-puff gas injection in the field.

Revaporization mechanism of huff-n-puff gas injection. A better understanding of

the mechanism of huff-n-puff gas injection could help in designing the producing

schemes in the field. In this work, gas chromatography was used to analyze the produced

gas compositions and to determine the mechanism of huff-n-puff gas injection.

Application of huff-n-puff gas injection in field. The lab work proves the EOR

potential of huff-n-puff gas injection. Field scale application still needs to be examined.

Different operations of huff-n-puff gas injection could have different condensate and

condensate recovery, and as a result, the economic value would be different. In this study,

field scale simulation work was conducted to examine the efficiency of huff-n-puff in the

field scale, and optimization of huff-n-puff was investigated: what is the better to start

huff-n-puff gas injection, when to stop injection, how long is the puff process, and the

soaking time effect. More reasonable operation of huff-n-puff could help us generate

more profits.

1.3 Dissertation Outline

This dissertation proceeds as follows.

Chapter 1 introduces the background and problem statement of this research.

Chapter 2 presents a literature review on the condensate blockage effect and the

different methods to enhance gas and condensate recovery in gas condensate reservoir.

This chapter includes the advantages and disadvantages of different techniques.

Chapter 3 has two parts. The first part describes core scale experiments with a two

component synthetic gas-condensate mixture. The experiments include: 1) one 2-inch


6

long core was used to measure the efficiency of huff-n-puff gas injection and 2) 4-inch

long cores were used for both the huff-n-puff gas injection and the gas flooding method.

The purpose of this experiment is to compare the efficiency of huff-n-puff to gas flooding.

The second part presents the lab simulation work. Simulation models were built to

simulate the experiments described in the first part of Chapter 3.

Chapter 4 discusses the results of the experiment and simulation work that are

described in the previous chapter. The experiment results confirm the potential of huff-n-

puff gas injection to enhance condensate recovery, and the simulation results are well

matched with the experiment results.

Chapter 5 describes the revaporization mechanism of huff-n-puff gas injection.

Experimental work was conducted on a shale core. The produced gas samples at the end

of different cycles of huff-n-puff were collected and measured by GC. A simulation

model was also built. Both the experiment and simulation results verify the

revaporization mechanism of huff-n-puff gas injection.

In Chapter 6, a field scale simulation is discussed. The efficiency of huff-n-puff in

field is investigated and the differing operation of huff-n-puff gas injection is also

discussed.

Chapter 7 summarizes the results of this research and provides some insight into

possible future research in shale gas condensate reservoirs.


7

CHAPTER 2

CONCEPTS AND LITERATURE REVIEW

When the reservoir is depleted lower than dew point pressure, condensate is

formed in the pore around the wellbore region. This condensate blockage can reduces gas

relatively permeability and affects the well productivity. Thus, a lot of research has been

conducted to remove this condensate blockage or enhance the condensate recovery in

conventional gas condensate recovery. In this chapter, some basic concepts for gas

condensate reservoir are described, and a literature review for the removal of condensate

from gas condensate reservoirs is presented.

2.1 Flow regions in Gas Condensate Reservoir

Generally, there are three flow regions in a depleted gas condensate reservoir, as

shown in Figure 2.1.

Region 1: A near-wellbore region which has both an oil and a gas phase, and both oil and gas

are flowing simultaneously.

Region 2: Condensate exists in this region. However, only gas is flowing, the liquid

condensate is immobile.

Region 3: Due to the pressure in this region being higher than dew point pressure, there is

only gas in this region.

When a gas condensate reservoir is recovered in the region that is far away from

the wellbore, the pressure in this region is still higher than the dew point pressure. Thus,

there is only gas in this region. This region is named Region 3. After Region 3, the

pressures of some regions are lower than the dew point pressure, and liquid condensate

forms in these regions. However, when the condensate saturation is lower than the critical

condensate saturation, the condensate is immobile. This is Region 2. In the near wellbore

region, the pressure is lower than dew point pressure and a lot of condensate is formed

and accumulated in this region. The condensate saturation is much higher than in Region


8

2. Both gas and liquid flow in this region. This is Region 1. The main focus of the

mitigation of condensate blockage is in Region 1. Region 1 is the main reason for the

decrease of production. In this region, the gas relative permeability is significantly

reduced.

Therefore in the different conditions and different periods of a gas condensate

reservoir, there may exist one to three regions. Table 2.1 shows the coexistence of the

different flow regions. As the table illustrates, the coexistence of different regions

depends on the pressure.

Figure 2.1 Schematic gas condensate flow behavior in three regions (Roussennac, 2001)

Table 2.1 Coexistence of different flow regions

Pwf<Pd, Pr>Pd Pr<Pd Pwf>Pd

Region 1 Exist Exist Not Exist

Region 2 May Exist May Exist Not Exist

Region 3 Exist Not Exist Exist


9

2.2 Material Balance

2.2.1 Reservoir Pressure above Dew Point Pressure

There is only gas in the reservoir when the reservoir pressure is higher than dew

point pressure. The p/z and Gp form of the material balance also can be used for this

above dew point gas condensate reservoir. The cumulative gas production is adjusted to

include condensate production. The produced condensate mass can be converted to its

gas equivalent. The assumption is that the condensate can be expressed in terms of an

ideal gas (Fevang, 1995).

(2-1)

GE is the gas equivalent, A2 equals 5.615 ft3/bbl for field units. R is the universal

gas constant, Tsc is the temperature at standard conditions, Psc is pressure at standard

conditions, NP is cumulative STO produced, and Mo are the density and molecular

weight, respectively, of the produced condensate. In summary, the material balance for a

volumetric gas condensate reservoir above the dew point is:

(2-2)

Gw is initial wet gas in place, Gpw is produced wet gas (Fevang, 1995).

2.2.2 Reservoir Pressure below Dew Point Pressure

As mentioned previously, once the reservoir pressure is depleted below the dew

point pressure, liquid condensate is formed. Thus, it is not the proper way to use the gas

material balance equations. A constant volume depletion experiment is a way to model or

simulate the reservoir depletion of a volumetric gas condensate reservoir. A CVD

experiment provides data that can be used directly. A factor named two phase z factor (z2)

is obtained from the experiment data. The assumption is that the gas condensate reservoir

depletes according to the material balance of a gas condensate reservoir above the dew

point (Fevang, 1995).


10

(2-3)

2.3 Flow Behavior of Gas Condensate

2.3.1 Constant Volume Depletion

This experiment is usually performed for a gas condensate to simulate the

conditions encountered in the reservoir (CMG, WinProp, 2014). The sample of reservoir

liquid in the laboratory cell is brought to the dew-point pressure, and the temperature is

set to the reservoir temperature. The CVD procedure is shown in Figure 2.2. Pressure is

reduced by increasing the cell volume. Part of the gas is expelled from the cell until the

volume of the cell equals the volume at the dew point. The gas collected is sent to a

multistage separator. The process is repeated for several pressure steps. However, the

CVD experiment is a good indicator of the reservoir only if the condensate phase is

immobile, which is not true if the condensate saturation exceeds the critical condensate

saturation. As mentioned previously, when the condensate saturation exceeds the critical

condensate saturation, the condensate can flow in the porous medium. Meanwhile, the

liquid dropout obtained from the experiment does not account for the condensate buildup

in the reservoir, and it cannot indicate the maximum possible condensate accumulation in

the reservoir.


11

Figure 2.2 A schematic of constant volume depletion experiment (CMG, WinProp, 2014)

Take an Eagle Ford shale gas condensate reservoir fluid as an example. Table 2.2

shows the compositions of the reservoir fluid.

Table 2.2 Compositions of Eagle Ford shale gas condensate reservoir fluid

CO2 N2 CH4 C2H6 C3H8 IC4 NC4 IC5 NC5 NC6 NC7 NC8 NC9 C10+

0.18 0.13 61.92 14.08 8.35 0.97 3.41 0.84 1.48 1.79 1.58 1.22 0.94 3.11

By simulating the CVD experiment in CMG-WINPROP at 200 oF, the fluid

behavior can be obtained as shown in Figure 2.3. As it can been seen, when the pressure

is higher than dew point pressure at 200 oF, there is only gas phase, after the pressure is

lower than the dew point pressure: 2750 psi, liquid phase is formed in the cell. As the

pressure continues decreasing, the liquid volume increases. After 2490 psi, the liquid is

revaporized to the gas phase again and the liquid volume decreases.


12

Figure 2.3 Example, result of CVD experiment

2.3.2 Constant Composition Expansion

Gas condensate fluid is investigated primarily using Constant Composition

Expansion to obtain the dew point pressure as shown in Figure 2.4. During the

experiment, a sample of the reservoir fluid is placed in a laboratory cell. The pressure is

adjusted to a value equal to or greater than the initial reservoir pressure. The temperature

is set to the reservoir temperature. The pressure is reduced by increasing the volume of

the cell in increments. No gas or liquid is removed from the cell. At each step, the

pressure and total volume of the reservoir fluid (oil and gas) are measured. Additional

data that can be determined include the liquid phase volume, oil and gas densities,

viscosities, compressibility factors or single phase compressibility above the saturation

pressure. The procedure is also called flash vaporization, flash liberation, flash expansion,

or constant mass expansion (Whitson and Brule, 2000).


13

During the CCE experiment, no gas or liquid is removed from the cell. As the

name of this experiment “Constant Composition Expansion” illustrates, the reservoir

fluid composition does not change during the experiment.

Figure 2.4 Schematic of constant composition expansion experiment (Whitson and Brule,

2000)

Also taking the Eagle Ford shale gas condensate reservoir fluid as an example,

Figure 2.5 plots the total relative volume as a function of pressure obtained from the CCE

experiment.


14

Figure 2.5 Total relative volume as a function of pressure from CCE experiment

2.4 Huff-n-Puff Gas Injection

Huff-n-puff injection method is used in conventional reservoir for heated steam

injection. This injection method is different from other traditional gas injection methods.

In shale plays, Sheng (2015b) proposed huff-n-puff gas injection as an effective to

enhance oil recovery in shale oil reservoir. Figure 2.6 shows the procedure of huff-n-puff

gas injection. As we can see from the figure, in huff-n-puff gas injection there is only one

well during the process. This well is used as both an injection well and a production well.

In the first, the well is used as injection, the gas or other injected solvent is injected into

the reservoir. After a period of injection, the well is shut in for a period. This time is

named soaking time. Soaking time allows the injected gas to go further into the formation,

and to increase the wider area’s pressure. After the soaking process, the well is opened

again. Now the well is used as the production well, because the reservoir pressure is

increased during the injection and soaking period. The reservoir fluid will flow to the

wellbore and be recovered. This is huff-n-puff injection.


15

Huff-n-puff has different cycle numbers. Every cycle includes the injection

process, soaking process, and production process. Normally, the efficiency of huff-n-puff

injection depends on how many cycles the recovery process takes, and how long one

cycle will take.

Figure 2.6 Huff-n-puff process (From Wikipedia)

As introduced in Chapter 1, the objective of this research is to investigate the

potential of huff-n-puff gas injection to enhance the condensate recovery in shale gas

condensate reservoirs. Generally, the traditional gas injection method is gas flooding.

Figure 2.7 shows the comparison between huff-n-puff gas injection and gas flooding.

As mentioned previously, when the pressure near the production well falls below

the dew point pressure in a shale gas condensate reservoir, the condensate accumulates

near the wellbore. Thus, as the function of this well is changed into injecting gas, the

pressure of condensate region increases very quickly because the condensate region is

just near the injection well. Consequently, the condensate is re-vaporized and flows into


16

the well during the puff process. Therefore, the huff-n-puff method is more effective than

the gas flooding method, especially in shale gas condensate reservoirs. Since the

condensate region is near the production well, the pressure propagation time or pressure

response time is much shorter, and the efficiency is higher in the huff-n-puff method.

Figure 2.7 Comparison of gas flooding and huff-n-puff injection


17

2.5 Literature Review

The accumulation of condensate near the wellbore reduces the relative

permeability of gas and causes a loss in both gas and condensate productivity. This effect

of condensate blocking has attracted many researchers, including Hichman and Barree

(1985), Aziz (1985) and Vo et al. (1989). Also, research conducted by Wheaton and

Zhang (2000) concluded that the condensate banking problem is more significant for low

permeability condensate systems, because if the pressure gradient near the well is

generally large, the rate of the growth and expansion of the condensate blockage will be

relatively high. The production decline rate can reach a very high value due to the

condensate blockage. According to the research conducted by Ayyalasomayajula et al.

(2005), condensate banking could reduce the well productivity significantly by 50% -

80%, in many instances by a decline factor of 2 to 4. Figure 2.8 shows the production

decline curve attained by Lin and Finley (1985), the data was collected from Whelan

field with an average permeability of 0.15md. The productivity was reduced by a factor

of 10.

Figure 2.8 A typical production decline curve in Whelan field. (Lin and Finley, 1985)


18

Due to this severe condensate effect, a lot of research has been conducted to

remove condensate blockage from gas condensate reservoirs. In another words,

researchers are finding ways to improve the condensate recovery. Less condensate

remaining in the reservoir means greater the economic benefits will be attained.

Generally, until now, there are four main methods to enhance the condensate recovery in

conventional gas condensate recovery as shown in Table 2.3:

1. Gas injection or water injection

2. Chemical Treatment

3. Horizontal wells

4. Hydraulic fracturing

In this section we summarize the different methods, and discuss the application

potential of every method in shale gas condensate reservoirs.

Table 2.3 Enhanced condensate recovery methods

Enhanced

condensate recovery

Gas injection

Produced gas injection

Nonhydrocarbon:N2, CO2

Chemical Treatment

Solvent injection

Wettability alteration

Other

Horizontal wells

Hydraulic fracturing


19

2.4.1 Gas injection or water injection

Generally, gas injection is applied to improve condensate recovery in gas

condensate reservoirs by increasing or maintaining the pressure above dew point pressure.

In different gas injection methods such as gas cycling, CO2 injection, N2 injection, the

aim is to keep the pressure in the reservoir higher than the dew point to prevent

condensate formation. Gas injection also helps to revaporize the liquid condensate to gas

phase again and let the condensate be recovered.

Abel et al. (1970) described two schemes of gas cycling: full pressure

maintenance and partial pressure maintenance. In full pressure maintenance, gas is

continuously injected into the reservoir while at the same time condensate is produced

from the reservoir. In partial pressure maintenance, gas is injected into the reservoir after

primary depletion below the dew point in an attempt to slow further pressure decline and

re-vaporize the condensate.

Luo (2002) conducted experiments on a real rich gas condensate fluid to

investigate condensate recovery based on the two schemes mentioned above. Their

results showed that the condensate recovery is higher when injection is done above the

saturation pressure.

Aziz (1983) discussed gas cycling operations on gas condensate reservoirs. There

are some important factors that affect the efficiency of cycling gas method, including

areal and vertical sweep efficiency, and revaporization of the formed liquid condensate

blockage. The research concluded that the condensate recovery factor can be increased to

75% by cycling dry gas into the reservoir. Also, his research found that mixing nitrogen

with the reservoir gas causes dew point elevation and increased drop out of liquids.

Al-Wadhahi et al. (2006) did simulation work to examine the cyclic gas injection

to revaporize liquid dropout in an Omani gas field. In this work, a compositional

simulation model was used to confirm the theory of condensate revaporization. The

results indicated that cyclic gas injection is a viable production method. This method

could improve gas deliverability and enhanced condensate recovery.


20

Meanwhile, different types of injected gas were studied by previous researchers

both from the efficiency of EOR point and the economic view. Nitrogen was applied in

the injection process as an alternative to produced gas for economic benefits. Donohoe

and Buchana (1981) present the results of an investigation of the economic feasibility of

using nitrogen as a substitute for natural gas to maintain reservoir pressure during cycling

operations in gas condensate reservoirs. They concluded that gas reservoirs with a

condensate content in excess of 100 bbl/MMcf should be considered as potential nitrogen

cycling prospects.

Core flooding experiments and simulation work were performed by Renner et al.

(1989) to investigate the mechanism for nitrogen displacement of a typical rich gas

condensate. The nitrogen displacement experiment was conducted at reservoir conditions

in the presence of irreducible water on an 8-ft long, 2-in diameter Berea core. They

concluded that below the dew point, displacement of gas condensate by nitrogen results

in greatly reduced liquid recovery.

Siregar et al. (1992) did simulation work to compare the performance of nitrogen

and gas cycling to enhance condensate recovery in gas condensate reservoirs. The results

show that the efficiency of methane to improve condensate recovery is better than

nitrogen.

Also, one study on gas injection performed by Sanger and Hagoort (1998)

investigated the efficiency of nitrogen to evaporate gas condensate compared to methane.

Their study showed that methane can evaporate more condensate than nitrogen.

Comparison of condensate recovery by hydrocarbon and non-hydrocarbon injection was

presented by Mohamed et al. (2015). They concluded that nitrogen increases the

saturation pressure (dew point pressure) of the field to a reasonably high value that can be

practically achieved in the reservoir. At or below dew point pressure, liquid dropout with

nitrogen injection is much higher than that with HC gas.

Not only nitrogen and hydrocarbon gas are investigated to enhance condensate

recovery. Another attractive gas - CO2 - has also attained attention. Using CO2 can not

only reduce the green effect, but also has a good potential to enhance condensate


21

recovery. In very early ages, CO2 was injected into oil reservoirs to enhance the recovery

of more crude oil. Whorton et al. (1952) received a patent for an oil-recovery method

with CO2. Stalkup (1978) concluded that carbon dioxide miscible flooding could recover

as much as 40% of enhanced recovery oil.

Meanwhile, Odi (2012) conducted both experimental work and a simulation study

to illustrate the potential of using CO2 to remove near wellbore condensate and for CO2

EGR. He concluded that carbon dioxide has the potential to form mixture with reservoir

fluids that have lower dew point pressure. By injecting CO2, the reservoir pressure can be

raised above the dew point pressure. CO2 has the ability to diffuse into the condensate

phase as its concentration increases.

Jessen and Orr (2004) present a detailed analysis of the development of

miscibility during gas cycling in condensates. Their research indicated that CO2 injection

in depleted gas condensate reservoirs can increase the liquid condensate recovery

depending on the mechanism of miscibility. They concluded in their research that CO2

could become widely available for enhanced oil recovery as well as enhanced condensate

recovery. Seto et al (2003) did simulation studies to indicate that CO2 can be used as an

effective solvent in enhanced condensate recovery process at pressures well below the

dew point pressure or the initial condensate.

Also, injection of supercritical CO2 was investigated by Kurdi et al. (2012). They

did simulation work to match experiment results to investigate the physics behind

SCCO2 injection into a gas condensate reservoirs. Their research found that the injection

of SCCO2 increases the density of gas, and the condensate viscosity and surface tension

between gas and condensate are decreased. Thus, the condensate recovery could be

enhanced.

A lot of other research has been conducted to compare the efficiency of different

types of gas. Gachuz—Muro et al. (2011) describes laboratory studies performed to

evaluate the effectiveness of different gases: CO2, N2, lean natural gas in displacing

condensate from naturally fractured gas condensate reservoirs. The experiments were run


22

at reservoir conditions. The results show that CO2 achieved a higher recovery factor than

N2, but lower than natural lean gas.

Moradi et al. (2010) conducted simulation work on enhanced condensate recovery

in five possible scenarios: natural depletion, gas recycling, methane injection, CO2

injection, and N2 injection. Their work showed that CO2 injection yields better recovery

than others, and methane injection has the least amount of recovery time.

Water injection is another technique besides gas injection. Mattews et al. (1988)

conducted experiments to study the feasibility of water flooding gas condensate

reservoirs. Results obtained from experimental and theoretical studies indicated the

recovery of gas and liquids can be increased after water flooding, compared with those

obtained under natural depletion.

In addition, water flooding can be used in combination with gas injection, a

process named the water-alternating-gas process (WAG). Cullick et al. (1993) present

detailed results of a fully compositional reservoir simulation of a synthetic layered system

and discuss the effects of reservoir and parameters on WAG performance. WAG recovers

significantly more condensate with less injected gas than continuous gas.

Also, simulation studies were performed to investigate the effectiveness of cyclic

gas injection method to re-vaporize liquid dropout, which indicate that cyclic gas

injection is an effective way to enhance gas and condensate recovery (Sheng 2015a;

Sheng et al. 2016; Meng and Sheng, 2015).

Gas injection is a widely used way to enhance condensate recovery based on the

research conducted on conventional gas condensate reservoirs. Though different gases

have the different efficiency, there is no doubt of the efficiency of the gas injection

method. Now as the oil industry is suffering in “winter” time, the reinjection of the

produced natural gas is a good solution based on low gas prices. For shale gas condensate

reservoirs, the injection of produced gas seems to be an effective way to enhance

condensate recovery. Also, due to the ultra-low permeability, water injection is probably

not a good practice to enhance the recovery. The results show that the water-alternating-


23

gas process can improve sweep efficiency and gas condensate recovery compared to

continuous cycling in high stratified reservoirs.

2.4.2 Chemical Treatment

The chemical treatment method enhances the relative permeability to gas.

Normally, the chemical treatment includes injection alcohols and solvents, and

wettability alteration.

By injecting the solvents the interfacial between the condensate and gas could be

reduced. Also, the solvent could dissolve the condensate into the gas steam. Al-Anazi did

quite a lot of research on the solvent injection in gas condensate recovery. Bang et al.

(2010) investigated the phase behavior of hydrocarbon, water and methanol mixture at

reservoir conditions. They found that when methanol was added to hydrocarbons, the

dew point increased by 350 psig and the liquid drop out increased from 21.5% to 29.9%.

Al-Anazi et al (2002) conducted core flood experiments on Berea sandstone and

Texas Cream limestone cores to investigate the efficiency of methanol injection treatment.

They found that gas relative permeability decreased about the same percentage in high

permeability cores as in low permeability cores. Also after the methanol treatment,

condensate accumulation is delayed for a certain time. During this time, the productivity

index can be increased in both low and high permeability cores.

Al-Anazi et al. (2003) also conducted field tests to investigate the effectiveness of

methanol as a solvent for removing condensate blockage that forms when pressure in the

near wellbore region falls below the dew point pressure. The gas condensate well

performance indicated that after the methanol treatment, the gas and condensate

production was increased by a factor of 2 over the first four months and 50% thereafter.

Also, the removal of water and condensate phase from the near wellbore region by

methanol resulted in a reduction in skin from 0.68-1.9.

Thus, using solvents such as methanol is an effective way to enhance condensate

recovery. Another chemical treatment is wettability alteration. Actually, wettability

alteration is much more widely used than solvent injection. By changing wettability of


24

the reservoir rock from oil wet or water to gas wet, well productivity could be increased.

As Figure 2.0 shows, when the angle is higher than 90o it indicates a non-wetting phase,

when angle is 90o it is neutral wettability, and when angle is smaller than 90

o it is wetting

phase.

Figure 2.9 Determination of wettability (Biolin Scientific)

Li and Firoozabadi (2000a) conducted an experiment to investigate the wettability

alteration to preferential gas wetting. The experiment results show that the wettability of

gas-oil-rock systems can be altered from strong water wetting to intermediate gas-wetting

by FC754. The oil recovery and phase relative permeability in gas-oil system was also

increased.

Kumar (2006) evaluated several fluorosurfactants at reservoir conditions and

found significant improvements in gas and condensate relative permeability after

chemical treatment in both Berea and reservoir sandstone. The gas and condensate

relative permeability was increased by a factor of 2.

Also, Bang et al. (2008) did experiments to investigate the efficiency of a

chemical treatment by using a fluorinated material. A wettability alteration chemical was

proved to be effective in modifying the wettability of rock surfaces. An improvement in

gas relative permeability of 1.5 to 2.5 was obtained. Another experiment conducted by


25

Bang et al. (2009) shows the efficiency of wettability alteration. The experiment was

conducted on reservoir sand rocks at reservoir conditions. The treatment improved the

gas and condensate relative permeability by a factor of about 2-4 on liquid outcrop and

reservoir sandstone rocks.

Ahmadi et al. (2011) presents the effective chemical treatment to mitigate liquid

blockage in carbonate gas reservoirs. They found that the chemical treatment developed

in this research can be applied to increase well deliverability and final recovery of both

gas and condensate in the field.

Zheng and Rao (2010) conducted experimental work and found both anionic and

non-ionic surfactants are effective in reducing the interfacial tension for condensate.

Anionic surfactants were effective in changing the wettability of the quartz surface from

strong oil wetting to weakly oil wetting.

Simulation works for chemical treatment also have been investigated. Li and

Firoozabadi (2000b) conducted simulation work to study the relative permeabilities of

both liquid and gas in a gas condensate reservoir. They found that the deliverability of

gas wells can be increased significantly by using wettability alteration chemicals.

Thus, both solvent injection and wettability alteration can increase relative

permeabilities of condensate and gas and enhance the productivity. For shale gas

condensate reservoirs, Ganjdanesh et al. (2015) conducted chemical treatment simulation

to remove the condensate blockage in shale gas condensate reservoirs, discovering that

condensate blocking could be treated by chemical treatment.

2.4.3 Horizontal wells and Hydraulic Fracturing

Drilling horizontal wells and hydraulic fracturing are both widely used in shale

gas condensate reservoirs at the beginning of the exploitation, because of the ultra-low

permeability of the reservoir. Horizontal wells were first drilled in 1927, and now are

widely used. By drilling horizontal wells, the condensate blockage problem could be

delayed in gas condensate reservoirs. The pressure drop could be reduced around the

wellbore because a large contact area exists between reservoir and the well. As a


26

consequence, the condensate could be decreased because it takes longer time for the

pressure to decrease lower than dew point pressure for horizontal wells than for vertical

wells.

As the research conducted by Miller et al. (2010) shows, the liquid saturation

around the wellbore is less in the case of drilling a horizontal well than in vertical wells

because of the larger contact area.

Hinchman and Barree (1985) conducted simulation work for the application of

horizontal wells in gas condensate reservoirs. The results show that the production and

drainage efficiency were increased.

Muladi and Pinczewski (1999) also did study to investigate the efficiency of

horizontal wells. They found that the performance of a horizontal well is better than that

of a vertical well when the average reservoir permeability is larger than 1 mD.

Hydraulic fracturing is also a widely used technique. There are millions of

fracturing treatments around the world, and especially for shale reservoirs, hydraulic

fracturing seems to be a necessary technique. A longer conductive path between the

reservoir and wellbore can be created by applying hydraulic fracturing. As a result, the

pressure drop decreases and, hence, reduces the formation of condensate around the

wellbore.

Carlson and Myer (1995) ran simulation work to illustrate that the productivity

loss in wells from gas condensate reservoirs could be reduced by stimulating the wells

through hydraulic fracturing. Aly et al. (2001) also conducted a compositional simulation

to investigate the development plan for a gas condensate reservoir. They concluded that

hydraulic fracturing increased the production rate and extended the production time.

Ignatyev et al. (2011) studied hydraulic fracturing in horizontal wells as a method

for the effective development for gas condensate reservoirs in Russia. They found that the

productivity of horizontal wells with fractures was 9 times greater than the wells without

hydraulic fractures, and the multistage hydraulic fracturing reduced drawdown and

condensate losses.


27

Both horizontal well and hydraulic fracturing reduce the pressure drawdown and

reduce the formation of condensate blockage, and these two techniques are widely used

for shale plays, especially the application of hydraulic fracturing.

In the last chapter of our study, where we discuss the field simulation work, the

hydraulic fracture was also applied in the model to increase the productivity.

The literature review demonstrates that many studies have been conducted for

conventional gas condensate reservoirs. However, very limited research has been

conducted for shale gas condensate. Due to the ultra-low permeability, the application of

these techniques is quite different, and the efficiencies are uncertain.

This study focuses on the huff-n-puff gas injection to enhance the condensate in

shale gas condensate reservoirs. This work or this application has not been studied before,

and thus has a certain novelty. This work proves the application potential of huff-n-puff

gas injection.


28

CHAPTER 3

LABORATORY STUDY FOR THE EOR POTENTIAL OF HUFF-N-

PUFF METHOD

In this chapter, we present the experimental works and simulation studies which

were conducted to examine the EOR potential of huff-n-puff gas injection on an Eagle

Ford Shale Core. There are two parts in this chapter.

In the first part: three experiments are described. The first experiment is designed

to investigate the efficiency of huff-n-puff gas injection. The second and third

experiments are used to compare the efficiency of huff-n-puff gas injection with gas

flooding. The experiments were designed to simulate reservoir conditions by using a

synthetic gas condensate mixture, though the simplified fluid used in the experiment was

not real reservoir fluid. However, the experiments are useful for indicating the potential

of huff-n-puff gas injection.

The second part presents the simulation works that are used to simulate the

experiments described in the previous part.

3.1 Experiment Setup

3.1.1 Experiment Design Principles

For the purpose of investigating the EOR potential of huff-n-puff gas injection

method to enhance the condensate recovery in shale gas condensate reservoirs, an

appropriate gas condensate mixture is needed to conduct the experiments. In this study, a

binary component gas condensate mixture, a methane and butane gas mixture, has been

selected. This binary gas condensate is selected based on the following principles:

1) The gas condensate mixture should be easily handled in the laboratory. Two

components are preferred.

2) The critical temperature of the mixture is preferred to be lower than 68 oF. With this

condition, the experiments can be performed at room temperature, and also the critical

pressure should be low so it can be conducted in a safe pressure range.


29

3) The gas condensate mixture used in the experiments should have a wide condensate

region. Thus a considerable condensate dropout could be attained in the experiments, and

the efficiency of the gas injection could be examined.

Based on these principles above, the methane and butane gas mixture was used in

the experiments. The gas condensate mixture is composed of 85% methane and 15%

butane. Figure 3.1 shows the phase envelope for this binary gas condensate mixture. As it

can be seen, this phase diagram has a wide retrograde region at the room temperature 68

oF.

Figure 3.1 Phase diagram of gas condensate mixture used in the experiment

3.1.2 Material Preparation

3.1.2.1 Shale core

The Eagle Ford outcrop core used in the experiment was 1.5 inches in diameter

and 4 inches in length. Before the experiment, the core was dried in an oven for two days


30

at 160°F. After the drying process, the porosity and permeability of the core were

measured.

The permeability of the core was measured by low permeability measure

equipment (Auto Lab 1000) at a high pressure. The measurement principle is similar to

pressure decay. Figure 3.2 shows the equipment used to measure the permeability. Table

3.1 shows the properties of the core.

Figure 3.2 Permeability measure equipment

Table 3.1 Core properties

Parameters Value Unit

Length 4 inch

Diameter 1.5 inch

Porosity 6.8% value

Permeability 0.0001 mD

3.1.2.2 Gas mixture preparation

The gas condensate mixture is stored in an aluminum accumulator which has a

maximum working pressure 10000 psi. As mentioned previously, the gas condensate


31

mixture is composed of 85% methane and 15% butane. From figure 3.1, it can be seen

that the dew point of this gas condensate mixture has a dew point pressure 1850 psi at

room temperature 68 oF. Thus, for the preparation of the gas mixture, the pressure should

be higher than the dew point pressure. The pressure of the initial gas condensate mixture

was set to 2200 psi in the experiment.

The volume of the accumulator is 1200 ml. Thus, 1.6 moles of n-butane and 9.1

moles of methane were required to be injected into the accumulator at 68°F and 2200 psi.

With this condition, the mole percentage of 85% methane and 15% butane could be

achieved. Butane is normally stored in liquid state, and according to the butane vapor

pressure as shown in Figure 3.3, butane is in liquid phase when the pressure is higher

than 23 psi at room temperature. Thus, the liquid butane can be transferred to the

accumulator by gravity. After the transfer of the butane, the higher pressure 2200 psi

methane can be injected into the accumulator and the pressure of the gas mixture could

reach 2200 psi, which is higher than the dew point pressure.

Figure 3.3 Butane vapor pressure curve (from The Spudding Handbook)


32

First, the piston in the accumulator was on the top of the accumulator and the

space below the position was full of water. Then, the top of the accumulator was

connected with a nitrogen cylinder that had a pressure of 500 psi. When the nitrogen

cylinder was open, the high pressure nitrogen pulled the position down and the water in

the accumulator was pulled out from the accumulator. According the calculation, 154.4

ml of liquid butane was required to be injected into the accumulator. Thus, 154.4 ml of

water should be pulled out from the accumulator. After this process, there was 154.4 ml

space above the position which was full of nitrogen.

The nitrogen cylinder was disconnected, the nitrogen in the accumulator was

depleted, and this space was prepared for the butane transfer. The butane cylinder was

connected to the accumulator. The butane cylinder was put upside down such that the

liquid butane can flow directly into the accumulator. The butane was transferred and

settled in the accumulator in a few minutes. Figure 3.4 shows this process. The vacuum

pump was used before the transfer of liquid butane. The tubes and the 154.4 ml space

above the piston of accumulator were vacuumed first. When the pressure in the butane

cylinder stopped dropping, the valve on the butane cylinder and the valve on the top of

the accumulator were closed. At this point 1.6 moles of butane had been transferred into

the accumulator successfully.

The last step was the transfer of methane. The butane cylinder was disconnected

and the high pressure 2200 psi methane cylinder was connected to the accumulator,

which was partially filled with liquid butane in the previous step. The tubes were also

vacuumed before the injection of methane. When the valve of methane cylinder was open,

the methane was directly injected into the accumulator, and all the remaining water was

discharged below the piston in the accumulator. When the pressure reached 2200 psi and

was not changing anymore, the methane cylinder was disconnected. The mole percentage

of the methane and butane were 85% and 15% respectively.

Then, the accumulator which was filled with butane and methane was shaken 100

times, and laid on the table to allow the methane and butane to be fully mixed with each

other and reach the steady state as shown in Figure 3.5.


33

By doing these steps, the gas condensate mixture composed of 85% methane and

15% n-butane was prepared in the accumulator at 2200 psi and 68 oF. During the

experiments, the accumulator was directly connected with the core holder, and it

saturated the core with the gas condensate mixture.

Figure 3.4 Liquid butane transfer


34

Figure 3.5 Accumulator filled with gas condensate mixture at 2200 psi

3.1.2.3 CT scanner

An X-ray computed tomography (CT) scanner was used in this research to

measure the condensate saturation in the core. CT is a powerful tool for non-destructive

measurement of variables in rock properties and fluid saturation in reservoir rocks. Many

studies have been conducted by using CT scanner for the measurement of two phase and

three phase fluid saturation.

Computed tomography is a system which combines the physics of x-rays,

computer technology, and reconstructive mathematics to produce diagnostic quality

cross-sectional images. The first total body CT system was used in a clinical environment

in 1974. There have been several generations of CT-scanners since then. The first

generation scanners had a single-beam source and a detector. Second generation scanners

used rotating multiple detectors, resulting in better image quality. Third generation

scanners use a rotational fan-beam geometry with the source and detectors rotating

together around the object. Fourth generation scanners use a fan-beam geometry with the


35

source rotating within a fixed ring of detectors to gain higher resolution and to improve

image quality. The current fifth generation scanners use a stationary-geometry method in

which both the sources and the detectors are fixed, and the data is collected without any

physical movement (Vo, 2010). Figure 3.6 shows the basic measurement principle of CT

scanner.

Figure 3.6 Principle of CT scanner (Vinegar and Wellington, 1987)

A collimated X-ray source rotates around the object and the X-ray penetrates a

thin slice of the object “A” at different angles. The transmitted X-ray intensity is recorded.

From the projections, a cross-sectional image is constructed. Three-dimensional CT

images can also be reconstructed from sequential cross-sectional slices taken as the object

moves through the scanner. The basic quantity measured in each volume element is linear

attenuation coefficient, μA as defined from the Beer’s law:

(3-1)

Where Io is the incident X-ray intensity, I is the intensity after passing through the

material “A” with a thickness of h. Beer’s Law assumes that the X-ray beam is narrow

and monochromatic.


36

After image construction, the computer coverts the linear attenuation coefficient

into CT number by normalizing with the linear attenuation coefficient of water (µW):

(3-2)

The unit of CT number are Hounsfield (H). Air is -1000 H and water is 0 H. In

this study, a HiSpeed CT scanner was used to determine the condensate saturation in the

shale core as shown in Figure 3.7.

Figure 3.7 CT scanner

In this case, after the pressure of core was depleted lower than the dew point

pressure, two phases would exist in the core: gas and condensate. According to the

previous contents, the CT number in different situations are shown below. 3-3 shows the

CT number of the core when the pressure is depleted to the value lower than dew point

pressure; 3-4 shows the CT number of the core which is saturated with the methane, and

3-5 shows the CT number of the core which is saturated with butane.

(3-3)

(3-4)


37

(3-5)

From the above three equations, Equation 3-6 could be derived:

(3-6)

In the above equation, CTexp is the CT number of the core containing both liquid

and gas phases in the experiment when the pressure is depleted. CTgr is the CT number of

the core when it is only saturated with methane, and CTcr is the CT number of the core

when it is only saturated with n-butane (condensate). CTcr and CTgr are measured

individually in the experiment. , , are the attenuation coefficients for the

rock matrix, the core fully saturated with butane and methane, respectively (Shi and

Horne, 2008).

Thus, the condensate saturation in the core can be determined by using the

equation 3-6. In equation 3-6, the CT number of the core saturation with methane and

butane, respectively, was measured at the same pressure as the pressure in the experiment.

3.1.3 Experimental Procedures

3.1.3.1 Experiment A

Experiment A was conducted to examine the efficiency of huff-n-puff gas

injection. Figure 3.8 shows the schematic of huff-n-puff gas injection.


38

Figure 3.8 Schematic of huff-n-puff gas injection apparatus

The process was designed at room temperature based on the phase envelope of the

gas mixture. The accumulator, which was full of gas mixture at 2200 psi, was connected

with the vacuumed core holder and gas mixture was injected into the core holder. The

core inside of the core holder was saturated with gas mixture. After that, the pressure of

the core holder would be depleted to 1460 psi. The pressure of the core holder was

controlled by a back pressure regulator.

A CT scan was then used to measure the condensate saturation in the core. By

analyzing the CT Number, the liquid saturation could be calculated. The purpose of this

study was to investigate whether the huff-n-puff method could effectively remove the

condensate saturation in the core to increase the recovery of gas-condensate.

After the primary condensate saturation measurement, the core holder was

connected to a methane cylinder which had a pressure of 2400 psi. Methane could be

injected into core holder to increase the pressure of core to 1900 psi, which is higher than

dew point pressure. Then the valve was closed and we waited for the pressure to reach a


39

stable value. This was the soaking process. After soaking, the pressure was depleted to

1460 psi and the condensate saturation was measured. This was one cycle of the huff-n-

puff process. The process was repeated for 5 cycles.

In this experiment, the core holder was used as a vessel, and there was no

confining pressure added around the core. The space between the core and the inside of

the core holder was used as the fracture.

By conducting this experiment, the efficiency of the huff-n-puff gas injection

could be determined.

3.1.3.2 Experiment B

This part includes two experiments: B1 and B2. In experiment A, the efficiency of

huff-n-puff gas injection should be determined. However, a comparison between huff-n-

puff gas injection and traditional gas flooding is necessary for this research. In order to

compare these two different gas injection methods, a different huff-n-puff experiment

design needs to be used, because in Experiment A, space exists between the core and the

inside of the core holder. However, in the gas flooding experiment there is no space

between the core and inside of the core holder because the confining pressure is added

first. Thus, in the new huff-n-puff gas injection, the confining pressure was also added.

Another new characteristic of the comparison was the injection. As we can see in

the primary depletion both of the two end faces of the core were used for the depletion. In

gas flooding the gas flows through the whole core, from one end face to another face. For

real huff-n-puff gas injection, the injection position of the huff-n-puff should be in the

middle of the core so the efficiency of huff-n-puff could be compared with gas flooding.

However, this injection position cannot be achieved in the experiment. For equal

efficiency, gas was injected into core and produced from both end faces as shown in

Figure 3.9.


40

Figure 3.9 New injection setting in Experiment B

Experiment B1:

The huff-n-puff process is shown in Figure 3.10. The experiment was designed at

68°F based on the phase envelope of gas mixture. The core holder was used as a vessel in

the huff-n-puff experiment, in which the core was placed. A confining pressure of 2,500

psi was added around the core so that the gas could be injected into the core from both

two-end faces. The accumulator, which was full of a gas mixture at 2,200 psi, was

connected to a vacuumed core holder and the core inside the core holder was saturated by

the gas condensate mixture. A CT scanner was used to measure the change in the core’s

CT number during the core-saturation process. After saturation, the pressure of the core

holder was depleted to 1,460 psi from both two-end faces. By injecting the gas from both


41

two-end faces, the efficiency of huff-n-puff to enhance the condensate recovery was

compared with the efficiency of the gas flooding.

After the depletion, a CT scanner was used to measure the condensate saturation

in the core. Liquid saturation was calculated by analyzing the CT number.

After the existing condensate saturation was measured, the core holder was

connected to a methane cylinder which had a pressure of 2,400 psi. The injection pressure

was set to 1,900 psi, which was higher than the dew point pressure of the gas condensate

mixture. The methane was injected into the core holder from both two-end faces. The

injection time was set to 30 minutes. After injection the methane cylinder was

disconnected, and the pressure of the core holder was depleted to 1,460 psi at a low-

pressure depletion rate for 30 minutes. Condensate saturation was measured by using a

CT scanner after every puff process. The experiment was run for 5 cycles of the huff-n-

puff process. The condensate recovery was attained from the condensate saturation.

Figure 3.10 Schematic of Experiment B1


42

Experiment B2:

Experiment B2 actually was a gas flooding gas injection experiment. The core

was put in the core holder with a confining pressure of 2,500 psi. The core was saturated

with a gas condensate mixture at 2,200 psi, which was the same as in the huff-n-puff

experiment. Then, the pressure of the core was depleted to 1,460 psi. Methane was then

injected into the core from an inlet at a constant pressure of 1,900 psi. A back-pressure

regulator was used to maintain a constant production pressure of 1,460 psi. A CT scanner

was used to determine the condensate saturation every 30 minutes. Figure 3.11 shows the

schematic of gas flooding.

Figure 3.11 Schematic of Experiment B2


43

3.2 Simulation Model for Experiments

Numerical simulations were conducted in this study to verify the experimental

results and to help better understand the results. A simulation model simulated the

experiment process. The simulation parameters are the same as the experiment, including

the core size, permeability, porosity, constraints of the injection, and production wells.

The models are described below.

3.2.1 Experiment A

A numerical simulation model whose validity is established by accurately

simulating the huff-n-puff gas injection results performed in the experiment. A basic

Cartesian model and Computer Modeling Group (CMG-GEM) reservoir simulator were

used to simulate the huff-n-puff gas injection process in the experiment. The shape of the

core is transferred to a rectangle in the simulation model, which has same volume as the

real core sample. The space between the core holder and core presents a fracture in the

model. All the faces of the shale sample are open during the huff, soaking, and puff

processes.

The permeability of the fracture, which presents the space between the shale core

and inside core holder, are set as 1000 mD. The permeability of core sample is around

0.0001 md by gas flooding method. Input parameters such as fracture permeability,

matrix permeability, and relative permeability are adjusted to historically match the

experiment data. Table 3.2 shows the reservoir rock and fluid properties in this

simulation work. The Grid blocks of the simulation model are 12×10×10. As mentioned,

the volume of the grids which represent the core sample and the space between the core

and core holder are same as the experiment value. The simulation domain is separated

into two sectors in order to get the oil saturation on a regional basis.

The core sample is set as sector 1 and space region is set as sector 2. Figure 3.12

shows the simulation model. The injection well is constrained to inject at a maximum

injection pressure at 1900 psi. The production well is subjected to minimum bottom-hole

pressure at 1460 psi.


44

Table 3.2 Reservoir and fluid properties used in the simulation model A

Initial core pressure 2200 psi

Soaking pressure 1900 psi

Reservoir temperature 68 F

Porosity of matrix 6.8% value

Permeability of Fracture 1000 md


45

Figure 3.12 Simulation Model for Experiment A

3.2.2 Experiment B1

A basic Cartesian model using a Computer Modeling Group (CMG-GEM)

reservoir simulator was used to simulate the huff-n-puff gas injection process in this

experiment. The model had the same size as the core used in the experiment. In the

simulation work, the shape of the core was transferred to a rectangle, which had the same

surface of the core that was used in the experiment. The permeability of the core sample

was 0.0001 mD.

Table 3.3 shows the reservoir rock and fluid properties in this simulation work,

and Figure 3.13 shows the huff-n-puff simulation model. The grid blocks of the

simulation model were 66×1×11 and the model had the same size as the core used in the

experiment. Since the gas was injected from both two-end faces during the experiment,

the production well and the injection well were perforated on both sides at the same

position. Also in the experiment the gas was injected into the core from the whole end

face. In order to simulate this injection process, the wells were perforated in all layers.


46

The injection well was constrained to inject at a maximum injection pressure of 1,900 psi.

The production well was subjected to minimum bottom-hole pressure at 1,460 psi.

Table 3.3 Reservoir and fluid properties used in the simulation B1 and B2

Parameters Value Unit

Initial pressure 2,200 psi

Injecting pressure 1,900 psi

Reservoir temperature 68 °F


Permeability of Matrix 0.0001 mD


47

JK view

IK view

3D view

Figure 3.13 Simulation model for experiment B1 in JK view, IK view and 3D view


48

3.2.3 Experiment B2

Experiment B2 was the gas flooding experiment. The simulation model to

simulate the gas flooding experiment process was similar to that of the huff-n-puff

process, except that the injection well is at one end, while the production well is at the

other end as shown in Figure 3.14. The reservoir and fluid properties are shown in Table

3.3. The constraints of the injection well and the production well were the same as those

in the huff-n-puff injection model.

IJ view

IK view


49

3D view

Figure 3.14 Simulation model for Experiment B2

3.3 Summary

Three experiments were conducted to examine the potential of huff-n-puff gas

injection to enhance condensate recovery in shale gas condensate reservoirs. Also, the

efficiency of huff-n-puff was compared with gas flooding through these experiments.

Simulation models simulated the experimental processes and verify the results. The

results of these three experiments and simulation models are discussed in Chapter 4.


50

CHAPTER 4

EXPERIMENTAL AND SIMULATION RESULTS

In this chapter, the results of the experiments described in the previous chapter are

discussed. Also, the simulation results of the experiment process are presented. The

simulation results are historically matched with the experimental results. The results

indicate the potential of huff-n-puff gas injection to enhance condensate recovery in shale

gas condensate, and also indicate that the efficiency of huff-n-puff gas injection is higher

than that of gas injection method.

4.1 CT analysis

Figure 4.1 shows the CT images of experiment A, and Figure 4.2 shows the CT

images of experiment B1. In the gas flooding experiment B2, the CT images looked

similar. The greyscale in the figures represents different CT numbers.

Figure 4.1 CT image for experiment A


51

Figure 4.2 CT image for experiment B1 and B2

In order to get precise CT numbers for the core area, accurate coordinates for the

core part needed to be determined. By determining the points' coordinates, we could

determine the exact coordinates for the core, and the same coordinates would be used for

the determination of condensate saturation for every cycle, as shown in Figure 4.3.

The CT number reflects the density of the core, where a higher density has a

higher CT number. The CT numbers were higher for the saturated core than the numbers

for the dry core, because when the pore in the core was saturated with the gas mixture,

the density became higher. During the saturation process, the CT number was

continuously measured. When there was no addition to the CT number, the core was fully

saturated. Figure 4.4 shows the CT number comparison at different time of saturation


52

process. As seen in Figure 4.3, as time increased, the CT number increased, but after 260

minutes, the CT number remained the same. This means that the core was fully saturated

with the gas mixture.

Figure 4.3 Interactive 3D Surface Plot for the first slice in first cycle in Experiment A


53

Figure 4.4 CT number comparison between dry core and saturated core (Experiment B1)

When the pressure is below a dew point, there are two phases: condensate and gas.

According to Akin and Kovscek (2003), the CT number of the core lies on the straight

line connecting the complete saturation by condensate to the complete saturation by gas

methane. Equation 3-6 is used to calculate the condensate saturation in the core. For huff-

n-puff gas injection, the condensate saturation is determined after every cycle. For gas

flooding, the condensate saturation is measured every 30 minutes after the gas injection.

The CT number used to calculate the condensate saturation is the average condensate

saturation.

4.2 Phase Behavior Study

As mentioned previously, the gas condensate mixture used in this study was 85%

methane and 15% n-butane. By using CMG WinProp, the liquid dropout curve and the

1630

1640

1650

1660

1670

1680

1690

1700

0 5 10 15 20 25

CT

num

ber

s

Time, hours

0 min

260 mins

320 mins


54

dew point pressure could be determined. Table 4.1 shows the composition of this gas

condensate mixture, and Figure 4.4 shows the liquid dropout curve of this gas condensate

mixture. As seen from the figure, the methane and butane gas mixture had a wide

condensate region at 68°F. The dew point pressure of this gas condensate mixture at 68°F

was 1,860 psi. Based on these numbers, this gas mixture had very good gas condensate

properties, which made it suitable for use in the experiment.

Table 4.1 Gas condensate mixture compositions

Component Mole fraction

Methane 85%

n-Butane 15%

Figure 4.5 Liquid dropout curve for gas mixture at 68°F

4.3 Grid Sensitivity Test of Simulation Model

It is necessary to conduct grid sensitivity of the simulation model to verify the

simulation results. Take the model which simulated Experiment B1 as an example. Figure


55

4.5 illustrates that using 66×1×11 grid blocks produced similar results to the more refined

100×1×11 grid blocks and 150×1×11 grid blocks, which was good enough to eliminate

the error caused by numerical dispersion.

Figure 4.5 Effect of numerical dispersion on the change of condensate saturation for

experiment B1

All three models examined in the grid test and grid blocks construction were

proven to be effective enough to simulate the experiment process.

4.4 Results for Experiment A

Experiment A was conducted to investigate the efficiency of huff-n-puff. The core

was scanned after every cycle. Therefore, condensate saturation after every cycle could

be attained.

0

2

4

6

8

10

12

0 1 2 3 4 5 6

Co

nd

en

sate

satu

rati

on

, %

Cycle number

10*1*11

66*1*11

100*1*11

150*1*11


56

One cycle of huff-n-puff in our experiment included an injection (huff) process

and a production (puff) process. Gas was injected into the core first during the huff period.

The pressure of the core was increased. Then a production (puff) process was conducted

at the same end face. The condensate saturation was measured after every cycle. After the

application of huff-n-puff in the experiment, the condensate saturation in the core was

decreased. Figure 4.6 shows the condensate saturation of every cycle. Condensate

saturation after the primary depletion was 10.4%, and after the first cycle of huff-n-puff,

at the end of puff process, the condensate saturation was decreased to 6.9%.

Figure 4.6 Condensate saturation variation in experiment A

The condensate recovery was obtained by using Equation 4-1 below. Sp was the

condensate saturation after primary depletion, and Sc was the condensate saturation after

a specific cycle. Figure 4.7 shows the condensate recovery for five huff-n-puff cycles in

experiment A.

0

0.02

0.04

0.06

0.08

0.1

0.12

0 1 2 3 4 5 6

Co

nd

ensa

te s

atu

rati

on

Cycle number


57

(4-1)

Figure 4.7 Condensate recovery variation in experiment A

The experiment results show that the condensate recovery by using huff-n-puff

method could be increased to 70%. It can prove that huff-n-puff method could effectively

improve the condensate recovery in shale gas condensate reservoirs.

The simulation model was conducted to historically match the experiment data.

Figure 4.8 shows the primary depletion. As we can see, when the pressure was lower than

the dew point pressure, condensate forms.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

0 1 2 3 4 5 6

Co

nd

ensa

te r

eco

very

Cycle number


58

Figure 4.8 Primary condensate saturation and pressure variation vs Time

By running 5 cycles, the condensate saturation and condensate recovery could be

attained. Figure 4.9 shows condensate recovery results by simulation.

Figure 4.9 Condensate recovery in simulation model A

By comparing the simulation results and experiment results in Figure 4.10, it can

be seen that the experiment results was historically matched with the simulation results.

The simulation results verify the experimental results. From another point, the simulation

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

0 1 2 3 4 5 6

Co

nd

ensa

te r

eco

very

Cycle numbers


59

model was proven by experiment results to be stable enough to simulate the experiment

process.

Figure 4.10 Condensate comparison between simulation results and experiment results,

experiment A

Thus, from both experimental and simulation results, it can be seen that huff-n-

puff has the potential to enhance the condensate recovery in shale gas condensate

reservoirs. From the results of experiment A, the condensate recovery from the shale core

was increased to about 76%. Huff-n-puff is really an effective method to improve the

recovery. The efficiency of huff-n-puff is compared with that of gas flooding in part 4.4.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

0 1 2 3 4 5 6

Co

nd

ensa

te r

eco

very

Cycle numbers

simulation results

experimental results


60

Figure 4.11 illustrates the effect of injection pressure. Three different injection

pressures are injected into the core in simulation work. One injection pressure is 1770 psi,

which is slightly lower dew point pressure. The other two injection pressures, 1900 psi

and 2100 psi, are higher than dew point pressure. The results indicate that setting the

injection pressure higher than dew point pressure would more effectively recover the

condensate. When the pressure is higher than dew point pressure, the continued increase

of pressure would not improve much.

Figure 4.11 Effect of injection pressure

0

0.02

0.04

0.06

0.08

0.1

0.12

0 1 2 3 4 5 6

Co

nd

ensa

te S

atu

rati

on

Cycle Number

1900 psi

1770 psi

2100 psi


61

4.5 Results for Experiment B1 and B2

Figure 4.12 shows the condensate saturation calculated from the CT numbers. The

condensate saturation decreased as the cycle number increased because the condensate

was recovered during the puff process in every cycle. The experiment results show that

the condensate recovery reaches 23% by applying the huff-n-puff method, which

validates the efficiency of the huff-n-puff method.

Figure 4.12 Effect of cycle numbers on condensate saturation, experiment B1

0

2

4

6

8

10

12

0 1 2 3 4 5 6

cond

ensa

te s

atura

tio

n,

%

Cycle number


62

As mentioned previously, the condensate recovery could be obtained by applying

equation 4-1. The condensate recovery variation of experiment B1 is shown in Figure

4.13.

Figure 4.13 Effect of cycle numbers on condensate recovery, experiment B1

Figure 4.14 shows the simulation results. It clearly illustrates that in the huff

process part of the condensate was re-vaporized as the pressure increased. In the puff

process, the pressure decreased and the condensate was recovered. Figure 4.15 shows the

simulation results of condensate saturation.

0

0.05

0.1

0.15

0.2

0.25

0.3

0 1 2 3 4 5 6

cond

ensa

te r

eco

ver

y

cycle number


63

Figure 4.14 Pressure and condensate saturation in experiment B1 model

Figure 4.15 Condensate saturation variation in simulation model B1

0

2

4

6

8

10

12

0 1 2 3 4 5 6

Co

nd

ensa

te s

atura

tio

n,

%

Cycle numbers


64

And Figure 4.16 shows the condensate recovery of the simulation model.

Figure 4.16 Condensate recovery variation in simulation model B1

The simulation results were historically matched with the results of Experiment

B1, as shown in Figure 4.17 and Figure 4.18. It demonstrates a positive agreement

between the condensate saturation measured by the CT and condensate saturation

attained by the simulation. From another point of view, the figure indicates that the

simulation model was stable enough to simulate the huff-n-puff process.

0

0.05

0.1

0.15

0.2

0.25

0 1 2 3 4 5 6

Co

nd

ensa

te r

eco

ver

y

cycle numbers


65

Figure 4.17 Condensate saturation comparison of simulation results with experimental

data for huff-n-puff


data for huff-n-puff

0

2

4

6

8

10

12

0 1 2 3 4 5 6

Co

nd

ensa

te s

atura

tio

n,

%

Cycle numbers

experiment results

simulation results

0

0.05

0.1

0.15

0.2

0.25

0.3

0 1 2 3 4 5 6

Co

nd

ensa

te r

eco

ver

y

cycle numbers

experiment results

simulation results


66

Although the experiment and simulation results of Experiment B1 illustrate the

efficiency of the huff-n-puff method, it is also necessary to compare the efficiency of

huff-n-puff with gas flooding-Experiment B2. Both of the methods are applied to

increase the reservoir pressure and re-vaporize the condensate. The gas flooding

experiment was conducted on the same shale core. The constraint conditions of injection

pressure and depletion pressure were the same as the huff-n-puff experiment-Experiment

B1. Figure 4.19 shows the condensate recovery in the gas flooding experiment.

Figure 4.19 Condensate recovery vs time, gas flooding experiment B2

The gas flooding experiment was simulated during this study. The simulation

results of the condensate saturation are shown in Figure 4.20. As we can see from Figure

4.20, as the pressure was depleted lower than the dew point pressure in the primary

depletion, the condensate saturation was increased. After the gas was injected into the

0

0.02

0.04

0.06

0.08

0.1

0.12

0.14

0.16

0.18

0.2

0 1 2 3 4 5 6

cond

ensa

te r

eco

ver

y

time, hours


67

core, the pressure was increased and the condensate saturation was decreased in the core.

Figure 4.21 shows the condensate recovery in the gas flooding simulation work.

Figure 4.20 Simulation results of condensate saturation, injection pressure and reservoir

pressure for gas flooding

Figure 4.21 Condensate recovery in simulation model B2

0

0.05

0.1

0.15

0.2

0.25

0 1 2 3 4 5 6

Co

nd

ensa

te r

eco

ver

y

Time, hours


68

Gas flooding time: 1 hour

Gas flooding time: 3 hours

Gas flooding time: 5 hours

Figure 4.22 Condensate saturation variation during gas flooding


69

As Figure 4.22 shows, the condensate saturation decreased during the process.

When the pressure was increased as the pressure transmitted from inlet to outlet, the

condensate re-vaporized and flowed to the outlet. However, the pressure propagation

time was slow during gas flooding. The simulation results are also historically matched

with the experiment data, as shown in Figure 4.23.

Figure 4.23 Comparison of simulation results with experimental data for gas flooding

The condensate recovery was measured along with time for gas flooding.

However, for the huff-n-puff method, the condensate recovery was measured with the

cycle number. In order to compare the efficiency of huff-n-puff and gas flooding, the

cycle number was transferred to time. The time of each cycle includes injection time,

soaking time, and production. In the experiment, there was no soaking time. First,

methane was injected. When the pressure inside the core holder was stable the injected

0

0.05

0.1

0.15

0.2

0.25

0 1 2 3 4 5 6

Co

nd

ensa

te r

eco

ver

y

Time, hours

experiment results

simulation results


70

methane cylinder was disconnected, and the process was immediately followed by the

puff process. The soaking time effect was examined in the simulation work, and the

simulation results showed that soaking time had no effect on the condensate recovery, as

shown in Figure 4.24. This is because during the experiment the gas was easier to diffuse

into the core than in the field scale. Further study needs to be conducted for soaking time

effect in the field scale.

Figure 4.24 Effect of soaking time on condensate recovery in huff-n-puff injection

For our experiments, one cycle took 30 minutes of injection time and 30 minutes

of production time, totaling 1 hour. Five cycles took 5 hours. Therefore, the efficiency of

huff-n-puff gas injection could be compared to the gas flooding as shown in Figure 4.25.

It can be seen that for the same period of time of 5 hours, the condensate recovery

increased to 23.3% using huff-n-puff gas injection. However, the condensate recovery

was only increased to 18% using gas flooding.

0

0.05

0.1

0.15

0.2

0.25

0 1 2 3 4 5 6

cond

ensa

te r

eco

ver

y

cycle number

No soaking time

soaking time: 30 mins


71

This laboratory work shows the potential of huff-n-puff gas injection to enhance

condensate recovery in shale. When the pressure near the production end fell below the

dew point pressure, condensate accumulated near the production end. Thus, as the

function of this end was changed into injecting gas, the pressure in condensate region

increased very quickly because the condensate region was just near the injection end.

Consequently, the condensate was re-vaporized and flowed out from the core during the

puff process. Since the condensate region was near the production end, the pressure

propagation time or pressure response time was much shorter, and the efficiency was

higher in the huff-n-puff method. Therefore, the huff-n-puff method was more effective

than the gas flooding method.

Figure 4.25 Comparison between huff-n-puff and gas flooding

0

0.05

0.1

0.15

0.2

0.25

0 1 2 3 4 5 6

Co

nd

ensa

te r

eco

ver

y

Time, hour

huff-n-puff

gas flooding


72

4.6 Summary

There is a reasonable agreement between the recovery factors obtained from the

experiments and those obtained from the simulation models. The simulation results verify

the experimental results.

Both Experiment A and Experiment B1 for huff-n-puff gas injection show a good

potential of huff-n-puff gas injection to enhance condensate recovery in the core scale.

An increase in condensate recovery in both huff-n-puff gas injection (B1) and gas

flooding experiment (B2) was observed. The efficiency of huff-n-puff (25%) was higher

than that of gas flooding (19%). This is because the pressure of the condensate region

increased faster than in gas flooding. The pressure increased higher than the dew point

pressure and the condensate re-vaporized and flowed out from the core.

Simulation models based on the experiment show that the soaking time has no

effect on recovery. During huff process period, the pressure of the condensate region in

the small core was increased to be higher than the dew point. Therefore, soaking time has

no effect. However, in the field scale the injection time, soaking time, and production

time may need to be optimized for better performance.

Thus, from these three experiments we can conclude that huff-n-puff gas injection

has a good potential to enhance condensate recovery in shale gas condensate reservoirs,

and the efficiency of huff-n-puff gas injection is higher than that of the gas flooding

method.


73

CHAPTER 5

REVAPORIZATION METHCHANISM OF HUFF-N-PUFF GAS

INJECTION

The complex flow behavior of gas condensate reservoirs is caused by

compositional changes and the creation of condensate blockage around the wellbore. In

the previous chapters, the experimental and simulation results show that huff-n-puff has a

potential to enhance the condensate recovery in shale gas condensate reservoirs.

In this chapter, the revaporization mechanism of huff-n-puff gas injection is

investigated from both experimental and numerical works. In huff-n-puff gas injection,

when pressure is increased higher than the dew point pressure part of the condensate

could be re-vaporized, and flows to the production well mixed with gas during the puff

process since there is only one well in the huff-n-puff gas injection. From another

perspective, the condensate region is just near the injection well. When gas is injected

into the reservoir, the pressure of the condensate region would rapidly increase.

5.1 Gas Chromatography (GC)

Gas Chromatography is an important technique used in this chapter.

Chromatography is a separation technique used to separate and analyze a mixture of

compounds which are composed of individual components. If the moving phase which

flows though the chromatography is gas, then the process is named gas chromatography.

Similarly, if the moving phase is liquid, then the process is called liquid chromatography.

Figure 5.1 and Figure 5.2 show compositions of GC-MS and GC-MS equipment

used in this study. Figure 5.2 also shows the principle of gas chromatography by Perry

(1981). The sample of the gas mixture which needs to be analyzed is injected into a

heated inlet, vaporized and swept by an inert carrier gas into a column packed with a

stationary liquid or solid phase. This results in the partitioning of the injected substances.

Different components are moved along the column at different rates. The eluted

components are then carried by the carrier gas into the detector. The concentration is

normally related to the area under the detector time response curve.


74

Figure 5.1 Compose of GC-MS

Figure 5.2 GC-MS used in the study

Figure 5.3 Principle of Gas Chromatography. (Perry, 1981)


75

The inlet pressure of the GC can be nearly atmospheric because an internal

vacuum pump connected to the column exit eliminates column back pressure. The GC

module is the most important part of the equipment. GC module includes a heated

injector, sample column, reference column, thermal conductivity detector, electronic

pressure control, and control board. For the GC test there are three major steps, as shown

below (Vo, 2010):

1) Injection

The gas sample enters the GC heated manifold. The manifold regulates the

sample temperature and directs it into the injector. The injector then drives the sample

into the column, while a vacuum pump helps draw the sample through the system.

2) Separation

After passing through the injector, the sample gas enters the column, which

separates it into its component gases typically in less than 180 seconds. Gas

chromatography works because different volatile molecules have unique partitioning

characteristics between the column substrate and the carrier gas. These differences allow

for component separation and eventual detection. The columns built into this GC are

Molecular Sieves and Porous Layer Open Tubular. The Molecular Sieve is used for the

separation of small molecular weight gases by an exclusion process. Porous Layer Open

Tubular (PLOT) columns are capillary columns where the stationary phase is based on an

adsorbent or a porous polymer.

3) Detection

After separation in the column, the sample gas flows through a thermal

conductivity detector (TCD). Carrier and sample gases feed separately into this detector,

each passing over different hot filaments. The varying thermal conductivity of sample

molecules causes a change in the electrical resistance of the filaments when compared to

the reference or carrier filaments.

Before being used for compositional analysis, the GC needs to be calibrated.

Calibration is the process of relating detector response to the amount of material with


76

known concentrations. For example in this study, the standard gas mixture with the mole

composition of 85% methane and 15% butane was used to calibrate the GC. Then the real

gas samples were tested.

By using GC-MS, the compositions of gas samples could be determined.

5.2 Experiment Study

The experiment in this study was also the huff-n-puff gas injection. However, the

experiment design was different from Experiments A and B2. In this study, the confining

pressure was added around the core, and only one end face was used to inject the gas and

produce the fluid.

The produced gas samples were also collected and the GC was used to analyze the

compositions of the gas samples.

5.2.1 Material Preparation

An Eagle Ford core with 1.5-in in diameter and 2-in in length was also used in the

experiment. Table 5.1 shows the properties of the core.

Table 5.1 Core properties

Value Unit

Length 2 inch

Diameter 1.5 Inch

Porosity 6.8 %

Permeability 0.0001 mD

A synthetic gas condensate mixture was used during the experiment. The gas

mixture was composed of 85% methane and 15% n-butane. Figure 4.4 shows the liquid

dropout curve of this gas condensate mixture at 68 oF. As the pressure increases, the


77

volume of the liquid first increases, then decreases. This is because when the pressure

continues increasing, part of the condensate is re-vaporized to gas state. When the

pressure is higher than the dew point pressure, all of the condensate is gaseous.

5.2.2 Experiment Procedure

A schematic of the huff-n-puff gas injection apparatus is shown in Figure 5.4. The

experiment was designed at room temperature 68 oF based on the phase envelope of the

gas condensate mixture. The core holder was used as a vessel in the experiment. A

confining pressure of 2500 psi was added around the core in order to inject the methane

during the huff-n-puff gas injection process.

The gas condensate mixture was first prepared in the accumulator at 2200 psi

which was higher than the dew point pressure. A pump was used to maintain the pressure

of the accumulator at 2200 psi. During the saturating process, a CT scanner was used to

measure the change of the core CT number. When the CT number was not changing, the

core was fully saturated.

After it, primary depletion was conducted. Two depletion stages were set: 2200

psi to 1850 psi, and 1850 psi to 1500 psi. The produced gas samples were collected by

vacuumed air bags.

After primary depletion, huff-n-puff gas injection was applied. The methane was

injected into the core at 2000 psi for 2 hours. After it, the pressure of the core holder was

depleted to 1500 psi. The produced gas was also collected by vacuumed air bag. This was

one cycle of huff-n-puff gas injection, and 5 cycles were operated.

A CT scanner was used to determine the core CT number after every production

process. Moreover, GC-MS was used to analyze the components compositions of

produced gas samples.


78

Figure 5.4 Schematic of huff-n-puff gas injection for revaporization study

5.3 Simulation Model

A basic Cartesian model was built to simulate the experiment process to

investigate the revaporization mechanism of huff-n-puff gas injection to enhance the

condensate recovery. The model simulated the application of huff-n-puff gas injection in

the core as shown in Figure 5.5. The grid blocks of the simulation model was 66×1×11.

The initial fluid in the model was composed of methane (85%) and butane (15%). The

production well and injection well were perforated at the same position because in the

huff-n-puff process, the injection well and the production well were the same well. The

injection well was constrained to inject at a maximum injection pressure of 2000 psi, and

the production well was subjected to minimum bottom-hole pressure of 1500 psi. The

permeability of the matrix in the model was 0.0001md and the porosity was 6.8%. Table

5.2 shows the reservoir rock and fluid properties in this simulation work.


79

IJ view

IK View

Figure 5.5 Simulation model of experiment, IJ view and JK view


80

Table 5.2 Reservoir and fluid properties used in the simulation

Parameters value unit

Initial core pressure 2500 psi

Injecting pressure 2000 psi

Producing pressure 1500 psi

Reservoir temperature 68 oF



5.4 Results and Discussion

In this experiment, condensate saturation of the core was determined by the CT

number. A CT scanner was used to determine the CT numbers of the core after primary

depletion and every puff process. After the primary depletion, the pressure was lower

than the dew point pressure and condensate was formed in the core. A primary

condensate saturation was attained. After the application of every cycle of huff-n-puff gas

injection, the condensate saturation of the core was determined again. By comparing the

condensate saturation, the condensate recovery could be determined. Figure 5.6 shows

the variation of the condensate saturation. And Figure 5.7 shows the condensate recovery

by applying huff-n-puff gas injection. Reduction of the condensate saturation indicates

that the condensate was produced from the core. However, understanding the way

condensate produced is an important issue for the application of huff-n-puff gas injection

in reservoir.


81

Figure 5.6 Variation of condensate saturation

Figure 5.7 Variation of condensate recovery

0

0.02

0.04

0.06

0.08

0.1

0.12

0 1 2 3 4 5

cond

ensa

te s

atura

tio

n

cycle number

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0 1 2 3 4 5

cond

ensa

te r

eco

ver

y

cycle number


82

The composition of produced gas was measured by GC. Different components

could have the different peaks on the chart. To determine the percent composition, the

area under each curve needs to be determined. Equation 5-1 shows the determination of

the area.

Area = height * (width at ½ height)

(5-1)

After that, by using Equation 5-2, the component percentage could be obtained.

% component I = [(area under peak I)/ (total area)]*100%

(5-2)

In this experiment, the components were methane and butane, thus, there were

only two peaks in the GC analysis. Figure 5.8 shows the GC curves of initial produced

gas and produced gas after different cycles. As the figure illustrates, in the beginning of

the primary production the produced gas contained large amount of butane. When the

pressure was decreased, the produced butane was also reduced. Once the huff-n-puff gas

injection was applied in the puff process the produced butane was enhanced again. With

the increase of cycling times, the produced butane was decreased.

Initial


83

1st cycle

2nd Cycle

3rd cycle

4th cycle


84

5th cycle

Figure 5.8 GC curves of initial produced gas and produced gas after different cycle

The compositions of produced gas samples were measured by GC. In this

experiment, the components were methane and butane. Table 5.3 shows the butane

content in produced gas at different period. Figure 5.9 shows butane content variation

during the primary depletion. As Figure 5.9 illustrates, produced butane was reduced. In

the beginning, the pressure was higher than the dew point pressure, and the produced gas

contained a high content of butane. Once the pressure was lower than the dew point

pressure, butane was formed as a liquid and remained in the core. As a consequence, the

produced butane was reduced.

Table 5.3 Butane% in produced gas

Stage %

Initial production 12.04

After 40 minutes primary depletion 4

End of primary depletion 2

1st cycle 10.7

2nd

cycle 8.7

3rd

cycle 5.53

4th

cycle 5.4

5th

cycle 5.185


85

Figure 5.9 Butane content during primary depletion in experiment

When the huff-n-puff gas injection method was applied in the experiment, the

butane content in produced gas was increased as shown in Figure 5.10. The butane

content in the produced gas collected at the end of primary depletion was 2%. However,

after the 1st cycle of huff-n-puff gas injection, the butane content increased to 10%. More

butane was produced from the core in gas state. This incremental of butane in gas state in

Figure 5.10 visually illustrates the re-vaporization mechanism of huff-n-puff gas injection

from experiment view. During the huff process in the experiment the pressure of the core

was increased higher than dew point pressure, and the liquid condensate was re-vaporized

into gas. Hence, in the puff period, condensate was produced mixed with methane in gas

state.

0

2

4

6

8

10

12

14

16

0 20 40 60 80 100 120

buta

ne

conte

nt,

%

time, minutes


86

Figure 5.10 Butane content after primary depletion and huff-n-puff cycles in experiment

The simulation model of this experiment also proves the efficiency and re-

vaporization mechanism of huff-n-puff gas injection. Exactly like the grid sensitivity in

Chapter 4, Figure 5.11 illustrates that using 66×1×11 grid blocks produced similar results

with more refined 100×1×11 grid blocks, which was good enough to eliminate the error

caused by numerical dispersion. Figure 5.12 and Figure 5.13 show the simulation results

of condensate saturation and condensate recovery by huff-n-puff gas injection. The oil

saturation in Fig. 10 indicates the condensate saturation because in the initial condition,

there was no liquid in the model.

0

2

4

6

8

10

12

0 1 2 3 4 5 6

buta

ne

per

centa

ge,

%

cycle number


87

Figure 5.11 Effect of numerical dispersion on the change of condensate saturation

Figure 5.12 Pressure and condensate saturation in simulation

0

0.02

0.04

0.06

0.08

0.1

0.12

0 1 2 3 4 5 6

cond

ensa

te s

atura

tio

n,%

cycle numbers

33*1*11

66*1*11

100*1*11


88

Figure 5.13 Condensate recovery in simulation

From Figure 5.12 it can be seen that as the pressure was depleted lower than the

dew point pressure, condensate was formed and the condensate saturation increased.

After applying huff-n-puff gas injection, the condensate saturation was reduced.

Reduction of the condensate saturation indicates that the condensate was produced from

the core. Figure 5.14 shows the change of condensate saturation in a specific block: 50 1

5. This block was near the wellbore, after first cycle the condensate saturation was

increased a bit because the condensate in blocks which were away from the well were re-

vaporized to gas and flowed into block 50 1 5. When the pressure was depleted, the re-

vaporized condensate was formed as liquid again in block 50 1 5. In the later cycles,

condensate saturation was reduced because the condensate in this block was re-vaporized

into gas state and produced from the core.

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0 1 2 3 4 5 6

cond

ensa

te r

eco

ver

y

cycle number


89

Figure 5.14 Condensate saturation in block 50, 1, 5

Figure 5.15 shows the butane content in produced gas in simulation work. Butane

content in produced gas increased when huff-n-puff gas injection was applied, compared

to the butane content at the end of primary depletion.

Figure 5.15 Butane content in produced gas in simulation


90

Figure 5.16 and Figure 5.17 show the historically matching works for condensate

recovery and butane content in produced gas. It demonstrates a positive agreement

between the condensate saturation and butane content measured by the experiment and

attained by simulation. From another point of view, it indicates that the simulation model

is stable enough to simulate the huff-n-puff gas injection process.


data

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0 1 2 3 4 5 6

Co

nd

ensa

te r

eco

ver

y

Cycle numbers

experiment results

simulation results


91

Figure 5.17 Butane content comparison of simulation results with experimental data

The gas butane production rate during the primary depletion process and huff-n-

puff gas injection process is shown in Figure 5.18. Due to the pressure being higher than

the dew point pressure in the initial reservoir condition, there was only gas phase, and

butane was in gas state. Thus in the beginning of primary depletion the production of

butane was very high. As the pressure was depleted lower than the dew point pressure

liquid butane was formed and accumulated in the core. Therefore, the production of gas

state butane was reduced to almost 0.005 gmole/day in the later period of primary

depletion, as shown in Figure 5.18.

After primary depletion, the huff-n-puff gas injection was applied. In the puff

process of every cycle of huff-n-puff gas injection, there had the production of gas state

butane. Compared with the later period of the primary depletion, the production of gas

0

2

4

6

8

10

12

1 1.5 2 2.5 3 3.5 4 4.5 5 5.5

Bu

tan

e co

nte

nt

of

pro

du

ced

gas

, %

Cycle number

experiment results

simulation results


92

state butane was increased after the application of huff-n-puff. This indicates the

incremental of the gas state butane in the core. In the huff process, condensate was re-

vaporized into a gas state and was produced in the puff process.

Figure 5.18 Production rate of gas state butane

It also can be seen that in the period of huff-n-puff gas injection, the production

rate of gas state butane in first cycle was higher than the later ones. This was because

after every cycle of huff-n-puff gas injection, less butane remained in the core. Thus, the

production rate was reduced during the huff-n-puff gas injection as shown in Figure 5.18.

Furthermore, as Figure 5.19 illustrates, in the beginning of primary depletion,

there was very little liquid production, and this liquid was the condensate. Also during

period of huff-n-puff gas injection, there was no liquid production from the well.

However, the liquid condensate remaining in the reservoir was recovered, and condensate

(butane) content in produced gas was increased. This indicates that the condensate was


93

re-vaporized and produced as a gas state from the core. It proves the re-vaporization

mechanism of huff-n-puff as injection.

Figure 5.19 liquid production rate in simulation

Figure 5.20 Comparison of cumulative production between methane and butane


94

The injected gas used in the huff-n-puff process was methane. Thus, the

production of methane was increased much higher than the production of butane. More

produced gas means the less butane content in produced gas as the huff-n-puff cycle

number increased. In this way, though more condensate was re-vaporized and produced

from as gas state, a fraction of the condensate in the produced gas was reduced as shown

in Figure 5.20.

5.5 Summary

In the previous chapters, both experiment and simulation work proved that huff-n-

puff gas injection is an effective method to enhance condensate recovery in shale gas

condensate reservoirs. In this chapter, the revaporization of the huff-n-puff gas injection

is investigated.

The main mechanism of huff-n-puff gas injection to enhance the condensate

recovery is re-vaporization. When pressure is increased in the huff process, condensate is

re-vaporized into a gas state and produced from the reservoir.

The fraction of the butane in produced gas was reduced with the increase of huff-

n-puff cycle numbers. This was because when methane was injected into the reservoir to

increase the pressure, more methane production was attained during the puff process.

Meanwhile, butane was recovered after every cycle of huff-n-puff, and less butane

remained in the reservoir. Thus, though more butane was re-vaporized into gas state and

produced, butane content in produced gas was reduced.


95

CHAPTER 6

RESERVOIR SIMULATION OF HUFF-N-PUFF OPERATION

In the previous chapters, the experimental works were performed on shale cores

to prove the EOR potential of huff-n-puff gas injection. Also, simulation models were

built to simulate the experimental processes, and the simulation results verify the

experiment results. Both of these works prove that huff-n-puff gas injection method has

the potential to enhance condensate recovery in shale gas condensate reservoirs.

Meanwhile, the previous studies are based on the laboratory work, and the application of

huff-n-puff gas injection to enhance condensate recovery on reservoir scale needs to be

investigated.

In this chapter, a reservoir scale study has been performed. Huff-n-puff gas

injection method is applied in the Eagle Ford shale gas condensate reservoir by

simulation study. An Eagle Ford reservoir model was built in this chapter, and the

application of huff-n-puff gas injection has been proved to be feasible. Also, the

operation of huff-n-puff gas injection was also learned in this chapter.

Optimization work of huff-n-puff gas injection has been conducted to get more

economic profits, including the start of huff-n-puff gas injection, different injection time,

soaking time and production time, cycle numbers.

By investigating all these factors, the general principles of huff-n-puff gas

injection to enhance condensate recovery in shale gas condensate reservoir are performed.

In general, this chapter discusses the reservoir scale application of huff-n-puff gas

injection, and the efficiency of this gas injection method has been proven.

6.1 Current oil price

Currently, the oil industry is suffering during “winter season”. The oil price has

dropped lower than 40 USD/bbl. Figure 6.1 shows the variation of WTI-Brent oil price.

The gas price is around 2 USD/BTU. Table 6.1 shows the oil price forecast by The

Economy Forecast Agency. As it can be seen, the price will not increase higher than 50

USD/bbl. The average price will probably be around 40 USD/bbl. Thus, whether seeking


96

economic ways to improve the recovery for the wells which have already gone though

many years primary depletion recover.

Previous laboratory work proves the efficiency of huff-n-puff gas injection. Here,

this gas injection is performed in field scale, and an economic evaluation is also

performed by using the current low oil and gas prices.

Figure 6.1 WTI-Brent oil pricing (from website)

Table 6.1 Oil price forecast by The Economy Forecast Agency

Year Month Open Max Min Close Average

2016 April 39.57 46.07 37.27 41.88 41.20

2016 May 41.88 48.37 39.57 43.97 43.45

2016 June 43.97 50.79 41.55 46.17 45.62

2016 July 46.17 52.58 43.02 47.80 47.39

2016 August 47.80 49.95 40.87 45.41 46.01

2016 September 45.41 47.45 38.83 43.14 43.71

2016 October 43.14 45.08 36.88 40.98 41.52

2016 November 40.98 43.97 35.97 39.97 40.22

2016 December 39.97 46.17 37.77 41.97 41.47

2017 January 41.97 44.45 36.37 40.41 40.80

2017 February 40.41 46.67 38.19 42.43 41.93

2017 March 42.43 48.07 39.33 43.70 43.38

2017 April 43.70 48.95 40.05 44.50 44.30


97

Year Month Open Max Min Close Average

2017 May 44.50 46.51 38.05 42.28 42.83

2017 June 42.28 48.83 39.95 44.39 43.86

2017 July 44.39 46.39 37.95 42.17 42.73

2017 August 42.17 48.71 39.85 44.28 43.75

2017 September 44.28 51.14 41.84 46.49 45.94

2017 October 46.49 53.69 43.93 48.81 48.23

2017 November 48.81 56.38 46.13 51.25 50.64

2017 December 51.25 59.19 48.43 53.81 53.17

2018 January 53.81 60.78 49.73 55.25 54.89

2018 February 55.25 63.81 52.21 58.01 57.32

2018 March 58.01 62.10 50.81 56.45 56.84

2018 April 56.45 61.33 50.18 55.75 55.93

6.2 Phase behavior of gas condensate

Kuenen (1892) used the term “retrograde condensation” to describe the

anomalous behavior of a mixture that forms a liquid by an isothermal decrease in

pressure, or by an isobaric increase in temperature. Kurata and Katz (1942) gave the most

concise and relevant discussion of retrograde phenomena related to petroleum

engineering. Retrograde vaporization can be used to describe the formation of vapor by

an isothermal increase in pressure or by an isobaric decrease in temperature. Neither form

of retrograde behavior occurs in single component systems.

Gas condensate reservoirs typically exhibit GOR’s between 3000 and 150000

scf/STB and liquid gravities between 40 and 60o API (Standing, 1977; Moses, 1986). The

color of the stock-tank is expected to lighten from volatile-oil to gas condensate systems.

Light volatile oils may be yellow or water-white, and some condensate liquid can be dark

brown or even black. Dark colors indicate the presence of heavy hydrocarbons.

Normally for a gas condensate reservoir, only gas exists in the reservoir, as the

pressure is higher than the dew point pressure. When the pressure is decreased lower than

the dew point pressure, the heavy components of reservoir fluids could be condensed and

a liquid phase could be formed in the reservoir. This formed liquid is named condensate.

Liquid dropout will continue to increase until the pressure reaches a specific value. At


98

this pressure the maximum liquid dropout has accumulated in the reservoir. After this

occurs, further pressure reduction will revaporize most of the condensed liquid-

condensate.

These conclusions assume that the overall composition of the reservoir mixture

remains constant during depletion. In reality, the behavior of liquid dropout differs from

that suggested by constant composition analysis. The condensate saturation is usually less

than the saturation needed to mobilize the liquid phase. This is because the heavier

components in the original mixture constitute most of the immobile condensate saturation,

and the overall molecular weight of the remaining reservoir fluid increases during

depletion. The phase envelope of this heavier reservoir mixture is pushed down and to the

right of the original phase diagram, and the critical point is shifted to the right toward a

higher temperature. This results in less revaporization at lower pressures. Also, this

makes the condensate accumulate in the formation and reduces the relative permeability

of gas. The productivities of gas and liquid in gas condensate reservoirs are reduced due

to this condensate accumulation- condensate blockage.

The study of the flow behavior in gas condensate reservoir is based on the

equations of state. Equations of state (EOS) are simple equations relating pressure,

volume, and temperature. They accurately describe the volumetric and phase behavior of

pure compounds and mixture, requiring critical properties and acentric factor of each

component. The same equation is used to calculate the properties of all phases, ensuring

consistency in reservoir processes that approach critical conditions. These EOS equations

are most widely used as shown below: RK, SRK and PR.

Redlich and Kwong (1949) proposed RK EOS:

(6-1)

(6-2)

Where = 0.42748;


99

(6-3)

Where = 0.08664.

In 1972, Soave used vapor pressures to determine the functional relation for the

correction factor used in Equation 6-4.

And 0.176 (6-4)

In 1976, Peng and Robinson proposed a two constant equation that raised

expectations for improved EOS predictions and improved liquid density predictions.

Equation 6-1 shows the Peng and Robinson EOS.

(6-5)

Or, in terms of Z factor, Zc = 0.3074

(6-6)

The constants are given by

(6-7)

Where = 0.45724;

(6-8)

Where = 0.0778.

6.3 Reservoir Model Description

Before the description of our simulation model, which was used to simulate the

huff-n-puff gas injection in shale gas condensate reservoir, a concept was first introduced:

stimulated reservoir volume (SRV). Ultra-low permeability shale reservoirs require a


100

large fracture network to maximize well performance. Actually, for shale reservoirs, the

large scale fracture network formed by hydraulic fracturing-stimulated reservoir volume

(SRV) is required to make the network profit. (Cipolla et al. 2008; Mayerhofer et al.

2008). They also model the physics of flow within a fractured shale reservoir using

numerical simulations of explicit fracture networks created in a stimulated reservoir

volume. They added the SRV to obtain reasonable results. In actuality, the mechanism of

SRV is not well known.

SRV is also added in our simulation model. Thus, the simulation model includes

two regions: the stimulated reservoir region and the un-stimulated reservoir volume.

The whole shale reservoir is stimulated with 9 transverse fractures. In this

simulation work, only one single hydraulic fractured reservoir region was simulated on

the basis of flow symmetry. Thus, the cumulative condensate and gas production could

be obtained simply by multiplying by the number of effective fractures. The simulation

model is shown in Figure 6.2.


101

IJ-view

3D view

Figure 6.2 Schematic of simulation model


102

The reservoir simulation work for the application of huff-n-puff gas injection was

performed by using the compositional simulator, GEM in Computer Modeling Group.

The dimension of the shale gas condensate reservoir was 592 ft wide in the I direction,

2724 ft in the J direction, with 724 ft in the SRV area as shown in Figure 6.2, and 50 ft in

the K direction. In this reservoir model, the half fracture spacing was 296.25 ft in I

direction, the fracture length was 724 ft in the J direction, and the fracture height was 50

ft in the K direction. The half-hydraulic fracture width was 0.5 ft. Symmetric flow

geometry allows results to be extrapolated to a larger scale. The reservoir was also

modeled as a 21×31×1 Cartesian grid. The grids were designed to be smaller, as shown

below, but the effects were the same as the grid refinement, as shown in Table 6.2 and

Table 6.3. For this model, increasing the number of grid blocks has no effect on the

simulation results, but the greater number of grid blocks required much longer

computation times. Thus, these grid blocks were selected to simulate the huff-n-puff gas

injection project.

The reservoir rock properties used in this model were also based on the published

data in Eagle Ford shale (Wan et al, 2013). The properties of the reservoir are shown in

Table 6.4.

Table 6.2 Distribution of block sizes in I direction (ft)

150.1331714 73.984627 36.459131 17.966817 8.8539278 4.3631567 2.1501345

1.059571985 0.52215 0.2573121 0.5 0.2573121 0.52215 1.059572

2.150134547 4.3631567 8.8539278 17.966817 36.459131 73.984627 150.13317


103

Table 6.3 Distribution of block sizes in J direction (ft) (SRV)

187.1636568 90.395053 43.658399 21.085842 10.183899 4.9185517 2.3755293

1.147317264 0.5541236 0.2676269 0.5 0.2676269 0.5541236 1.1473173

2.375529264 4.9185517 10.183899 21.085842 43.658399 90.395053 187.16366

Table 6.4 Reservoir properties

Parameters value unit

Initial reservoir pressure 5000 psi

Reservoir Temperature 200 oF

Thickness 50 ft

Matrix Permeability 0.0001 mD

Matrix Porosity 0.06

Rock Compressibility 5.0E-06

Hydraulic Fracture Permeability 100 mD

Hydraulic Fracture Porosity 0.9


PVT and compositional data for an Eagle Ford shale gas condensate reservoir

fluid sample were obtained from published data (Seo and Anderson, 2012; Li et al., 2015).

The fluid model was generated using CMG WinProp. The sample was taken at a depth of

9800 ft, the initial pressure was 5000 psi, and the temperature was 200 oF. The

components of the reservoir fluid were lumped into 14 pseudo-components. Table 6.5

presents the pseudo-components description used in this model, and input for Peng-

Robinson equation of state calculations. Table 6.6 shows binary interaction coefficients.


104

Since the simulation work was used to determine the application of huff-n-puff

gas injection in field, there was only one well in this model, and this well was used as

both an injection well and a production well. The location of this well was shown in

Figure 6.2. The producer was subjected to minimum bottom-hole pressure constraint of

1500 psi. The injection well was subjected to maximum injection pressure constraint of

4000 psi. The injection and production time are discussed in a later section.

Table 6.5 Peng-Robinson EOS Fluid Description of Eagle Ford Condensate Lumping

Fraction Pc(atm) Tc(K) Acentric Factor MW

CO2 0.18 72.8 304.2 0.225 44.01

N2 0.13 33.5 126.2 0.04 28.013

CH4 61.92 45.4 190.6 0.008 16.043

C2H6 14.08 48.2 305.4 0.098 30.07

C3H8 8.35 41.9 369.8 0.152 44.097

IC4 0.97 36 408.1 0.176 58.124

NC4 3.41 37.5 425.2 0.193 58.124

IC5 0.84 33.4 460.4 0.227 72.151

NC5 1.48 33.3 469.6 0.251 72.151

NC6 1.79 29.3 507.4 0.296 86.178

NC7 1.58 27 540.2 0.351 100.205

NC8 1.22 24.5 568.8 0.394 114.232

NC9 0.94 22.8 594.6 0.444 128.259

C10+ 3.11 20.686 617.7 0.4902 142.3

Table 6.6 Binary interaction coefficients for Eagle Ford gas condensate


105

Figure 6.3 shows the the phase diagram of this Eagle Ford reservoir fluid, and as

we can see from the figure, at the temperature 200 oF the fluid is in the region which

indicates the gas condensate fluids. Figure 6.4 shows the simulated relative volumes in

the costant composiiton expansion experiment at 200 oF for the gas condensate mixture.

The simulated liquid dropout curve in the constant volume depletion experiment at 200

oF for this gas condensate fluid is shown in Figure 6.5. The liquid dropout curve can be

expressed by appling the Equation 6-9:

(6-9)

Relative oil volume is defined as the volume of oil at a given pressure divided by

the original saturation volume. The relative volume provides a measurement of the

average reservoir oil (condensate) saturation that will develop during the depletion of a

gas condensate reservoir (Whitson and Brule, 2000). The reservoir oil saturation is

calculated from Vro with So = (1-Sw) Vro.

As it can be seen from the Figure 6.5, liquid dropout, also known as condensate,

starts to be formed when the pressure is lower than the dew point pressure 2750 psi. Then,

the condensate volume continues to increase until the pressure reduces to 2500 psi, when

CO2 N2 CH4 C2H6 C3H8 IC4 NC4 IC5 NC5 NC6 NC7 NC8 NC9 C10+

CO2 0.0000

N2 0.0000 0.0000

CH4 0.1050 0.0250 0.0000

C2H6 0.1300 0.0100 0.0027 0.0000

C3H8 0.1250 0.0900 0.0085 0.0017 0.0000

IC4 0.1200 0.0950 0.0157 0.0055 0.0011 0.0000

NC4 0.1150 0.0950 0.0147 0.0049 0.0009 0.0000 0.0000

IC5 0.1150 0.1000 0.0209 0.0087 0.0028 0.0004 0.0006 0.0000

NC5 0.1150 0.1100 0.0206 0.0086 0.0027 0.0003 0.0005 0.0000 0.0000

NC6 0.1150 0.1100 0.0283 0.0138 0.0060 0.0019 0.0023 0.0006 0.0006 0.0000

NC7 0.1150 0.1100 0.0352 0.0188 0.0094 0.0041 0.0046 0.0020 0.0021 0.0004 0.0000

NC8 0.1150 0.1100 0.0415 0.0236 0.0129 0.0065 0.0072 0.0037 0.0039 0.0014 0.0003 0.0000

NC9 0.1150 0.1100 0.0470 0.0279 0.0162 0.0089 0.0097 0.0056 0.0058 0.0026 0.0009 0.0002 0.0000

C10+ 0.0000 0.0000 0.0528 0.0326 0.0198 0.0117 0.0125 0.0079 0.0080 0.0041 0.0020 0.0008 0.0002 0.0000


106

the maximum condensate liquid is reached. After that, as the pressure continues to

decrease, the liquid is revaporized and the condensate volume is reduced.

Figure 6.3 Phase diagram of Eagle Ford reservoir fluid sample.


107

Figure 6.4 Relative volume curve of gas condensate fluid

Figure 6.5 The liquid dropout curve for CCE experiment at 200 oF on the gas condensate

mixture

0

50

100

150

200

250

300

0 500 1000 1500 2000 2500 3000

Rel

ativ

e V

olu

me

Pressure, psia

0

5

10

15

20

25

30

35

0 500 1000 1500 2000 2500 3000

Liq

uid

vo

lum

e, %

Pressure, Psia


108

6.4 Fracture Effect

The successful commercial production of shale reservoirs mainly relies on the

advancement in hydraulic fracturing technique. The shale resources usually cannot be

produced at profitable rates or volume without the stimulation of near well-bore regions.

Figure 6.6 shows the recovery in an un-fractured reservoir. As it can be seen, the

recovery is so low that the exploitation has no economic value.

Figure 6.6 Gas recovery of an un-fractured shale gas condensate reservoir

The hydraulic fracture was modeled as a 2-ft wide pseudo fracture in order to

increase numerical stability (Rubin, 2010). Effective fracture grid block permeability was

calculated from Equation 6-10:

(6-10)

Kf is the actual fracture permeability, Wf is the actual fracture width and Weff is

the width of the grid blocks representing the fracture (CMG, 2012).


109

In this simulation, a fracture with a permeability of 100 mD and a width of 0.5 ft

was modeled as a 2 ft wide fracture with a permeability of 25 mD. This was done to

improve the stability of the model.

Numerical errors occur when the simulation fails to converge due to the extreme

variations in pressure, saturation, or composition from one time step to another. These

errors are especially likely to happen in the fracture and near fracture region.

Also, a large difference in permeability between the fracture and the matrix

creates severe transmissibility contrasts that may result in ill-conditioned systems (Daniel

et al. 2015). The fracture half-length was 362 ft. The porosity of the fracture was found to

have a negligible effect on recovery as shown in Figure 6.7. The recovery in the case, in

which the fracture had a porosity of 90%, was same as the recovery in the case in which

the fracture had a porosity of 50%.

Figure 6.7 Condensate recovery comparison

0

2

4

6

8

10

12

14

16

0 1000 2000 3000 4000 5000 6000 7000 8000

Co

nd

ensa

te r

eco

ver

y,

%

Time, days

Fracture porosity: 90%

Fracture porosity: 50%


110

Compare Figure 6.7 with Figure 6.6. It can be seen that the hydraulic fracture

could effectively improve the condensate recovery in shale gas condensate reservoir. The

primary depletion condensate was increased to 13.3% in 20 years. The hydraulic fracture

provided a very high conductivity pathway to allow the flow of gas and condensate.

Without the hydraulic fracture, the recovery was so low that the exploitation had no

economic value.

The effect of the natural fractures was also taken into account in this simulation

work. Natural fractures also provide higher conductivity paths for reservoir fluids.

Different permeabilities of natural fractures were tested in this work to perform a

qualitative analysis of the impact of natural conduits on huff-n-puff gas injection

effectiveness. Two cases were considered: the originally natural fracture permeability-

0.005 mD, which was 50 times higher than the matrix permeability, and another case in

which the permeability of the natural fractures were set to 0.05 md, which was 10 times

higher than the original setting. 15 years of primary depletion were performed first to

determine the effect of natural conduits on primary recovery. Table 6.7 shows that in the

0.005 mD case, the condensate recovery was 13% after 15 years, while in the 0.05 case,

the condensate recovery was 13.5%.

After the primary depletion, one cycle of huff-n-puff gas injection was applied in

the work. The results were also shown in Table 6.7. The additional condensate recovery

in both two cases was about 0.6%. The condensate incremental is related to the injection

time when the injection pressure is constant.

Compared to the 0.005 mD case, during the injection time the pressure

transmission area was larger than that in the 0.05 mD case, as shown in Figure 6.8.

However, in the gas condensate reservoir, a very important mechanism is the

revaporization. Thus, during the same injection time in the 0.05 md case, gas could flow

into the further region, but the region which had the pressure higher than dew point

pressure was smaller than that in the 0.005 mD case. Thus, the condensate in near

fracture region revaporized more condensate in the 0.005 mD case than that in the 0.05

mD case. In this way, the condensate recovery incremental in these two cases was the


111

same. However from the pressure distribution figure it can be seen that huff-n-puff gas

injection works better in naturally fractured reservoirs, because the gas can be injected

into a further area of the reservoir. Also, if the injected pressure is higher enough, the

pressure of the larger area could be increased higher than the dew point pressure, and

more condensate could be revaporized.

Since the purpose of this study is to investigate the incremental condensate

recovery performed by huff-n-puff gas injection, the natural fracture permeability was set

to 0.005 mD based on this same incremental recovery. It will not affect the investigation

of huff-n-puff gas injection.

Table 6.7 Primary and incremental recoveries in different natural permeability cases

Natural fracture permeability (mD) RF, primary RF, 1st huff-n-puff Incremental RF

0.05 13.5 14.1 0.6

0.005 13 13.6 0.6


112

Figure 6.8 Pressure and condensate saturation comparison between 0.05 mD case and

0.005 mD case, after the 1st cycle injection

6.5 Primary depletion time

The Eagle Ford shale well life expectancy could be as long as thirty years

according to the report from EOG resources. According to that report, 40% of production

from an Eagle Ford shale well can come in the first five years, and this production can

then be followed by a long decline curve as long as thirty years. This means in the later

years, the wells produce oil and gas at very low volume. Thus, the beginning of huff-n-

puff gas injection, or in other words, the end of primary depletion is important for the

exploitation of shale gas condensate reservoir. In this section, the primary depletion time

is discussed.


113

One cycle of huff-n-puff gas injection was applied in the simulation model at

different start times: 5 years, 10 years, and 15 years. The total exploitation time in this

work was 25 years. The results of different cases were compared with 25 years primary

depletion. For this single cycle, the injection time was 200 days and was then followed by

the production period. The results are shown in Figure 6.9 and Table 6.8.

Figure 6.9 Condensate recovery for different primary depletion time

0

2

4

6

8

10

12

14

16

18

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

Co

nd

ensa

te r

eco

very

, %

Time, days

25 years primary depletion

start at 5 years

start at 10 years

start at 15 years


114

Table 6.8 Condensate recovery and incremental recovery for different primary depletion

time

Primary depletion time

(years)

Condensate

Recovery (%)

Incremental

recovery (%)

25 13.7 N/A

5 15.2 1.5

10 15.5 1.8

15 15.6 1.9

As it can be seen from Figure 6.9 and Table 6.8, primary depletion time has a

noticeable effect on the recovery. Compared with the 25 year primary depletion case, the

application of huff-n-puff gas injection could increase the condensate recovery. The

initial primary depletion recovery factor was 1.7%. Starting the single cycle of huff-n-

puff gas injection after 15 years had an incremental recovery of 1.9%. Meanwhile,

starting huff-n-puff after 5 years had an incremental recovery factor of 1.5%.

From the primary depletion period, Figure 6.10 shows the gas production rate. As

Figure 6.10 indicates, the production decreased very fast in the first 5 years and in the

following 20 years, the production rate was very slow. In the first year, the gas

production rate was 158950 ft3/day, and after 15 years, the rate decreased to 11767.18

ft3/day. The decline rate was almost 92%, which is a very high value. At 10 years, the

decline rate was about 85%. For this shale gas condensate reservoir, the high decline rate

is not only due to the ultra-low permeability, but also because of the accumulation of

condensate in the formation. Thus, at 15 years, both heavy and light hydrocarbon

components were left in the reservoir.


115

Combined with the gas production decline rate and the effect of the starting time

of huff-n-puff, it is more effective to start huff-n-puff gas injection at the later period of

primary depletion (when the decline rate is around 90%). If the huff-n-puff is applied too

early the primary production rate is not that low, and compared to the incremental

recovery with the cost of injection process, it is not necessary. Also, when the huff-n-puff

gas injection is applied in the later time the application of huff-n-puff gas injection can

effectively enhance the recovery and gain value, since the production rate is so low.

Figure 6.10 Gas production rate for 25 years primary depletion

0

200000

400000

600000

800000

1000000

1200000

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

Gas

pro

du

ctio

n r

ate,

ft3 /

day

Time, days

Decline rate:

92%, 15 years

Decline rate:

85%, 10 years


116

6.6 Soaking time

The effect of a soaking period on condensate recovery is investigated in this

section for the application of huff-n-puff on a shale oil reservoir. In this study, a series of

simulations was conducted using different soaking period: 0, 50 days, and 100 days. In

these three cases, two cycles were simulated: 100 days of injection and 200 days of

production. It can been seen from Figure 6.11 that all three cases had similar condensate

recovery, however, the simulation without soaking period had the largest condensate

recovery (14.5%), while the simulation with the longest soaking time (100 days) had the

smallest recovery (14.23%).

All these results from three simulation works indicate that there are no benefits to

applying a longer soaking time. Longer soaking time means a longer waiting time, which

reduces the production period. Also, the longer soaking time had the smallest recovery in

these three simulation cases. This means that for the application of huff-n-puff gas

injection in shale gas condensate reservoir, short soaking time or even no soaking time

would be better.

The reason why soaking time has negative effect in this case is related to the gas

condensate fluid property. In these three simulation cases, the injection pressure was

already set to a high value: 4000 psi. When the gas was injected into the formation, the

pressure of the region near the fracture increased very quickly. The pressure increased to

higher than dew point pressure, and thus the condensate was revaporized to gas phase and

the oil (condensate) saturation was decreased.

When the well was shut in and the soaking period was applied, though the

injected gas could flow further into the reservoir and increase the further region pressure,

the pressure of the region near the fracture decreased compared to the value when the

well was just shut in. Because the pressure in this near fracture region transferred to the

further region in the reservoir. When the pressure decreased, the revaporized condensate

could be formed into liquid again, and the condensate saturation was increased again in

the near fracture region as shown in Figure 6.12.


117

For the application of huff-n-puff in shale gas condensate reservoirs, shorter

injection or even no soaking time is preferred. If the dew point pressure of the reservoir is

low and the injection pressure is higher, then adding a short soaking time will be better

because even when the near fracture region pressure transfers to further region, the

pressure is still higher than dew point pressure and condensate is revaporized to gas phase.

However, if the injection pressure is not that much higher than dew point pressure, the

soaking time could have a negative effect.

In a large scale shale gas condensate reservoir, the condensate is mainly

accumulated near the fracture region, thus, for the purpose of increasing condensate

recovery, incremental of this condensate region’s pressure is the main objective.

The study in this section indicates that shorter time or no soaking is needed during

huff-n-puff operation in shale gas condensate reservoirs.

Figure 6.11 Soaking time effect on condensate recovery

0

2

4

6

8

10

12

14

16

0 1000 2000 3000 4000 5000 6000 7000

Co

nd

ensa

te r

eco

very

, %

Time, days

without sokaing

50 days soaking


118

No soaking 100 days soaking

No soaking 100 days soaking

Figure 6.12 Pressure and condensate saturation comparison between no soaking case and

100 days soaking time case


119

6.7 Injection Period

In this section, the effect of the huff-n-puff injection period is investigated. Based

on the investigation of huff-n-puff application on other kinds of reservoirs (Sheng, 2015;

Meng and Sheng, 2015, Yu et al. 2014), injection time can have a very large impact on

incremental recovery.

Longer injection time means longer pressure build up time in the reservoir. For

shale gas condensate reservoirs, the longer pressure build time means more condensate

can be revaporized to gas phase, and then more condensate can be recovered during the

production period. Though longer injection has more recovery, the longer injection time

also indicates that more gas is needed to be injected into the reservoir. This means there

will be more costs during the injection. If the costs of injection cannot achieve more

profits, the application of huff-n-puff gas injection is unnecessary.

In this section, a series of cases were conducted simulating three cycles of huff-n-

puff gas injection after primary depletion. The injection time was varied from case to

case while the production time remained same: 200 days. Based on the study of previous

section, soaking time was not applied. The three injection times were: 10 days, 50 days,

and 100 days. Figure 6.13 shows the condensate recovery for different cases.

It can be seen from Figure 6.13 that as the injection time increased, the

condensate recovery increased. It is obvious that when the injection time increased, the

incremental of pressure in the reservoir increased. Thus, more condensate was recovered.

Figure 6.14 shows the condensate saturation after three cycles of huff-n-puff. The

condensate that remained in the reservoir or remained near the fracture in 100 days

injection time case was less than in the 10 days injection time case and 50 days injection

time case.

More condensate was recovered from the reservoir when the injection time was

longer. However, as mentioned before, longer injection time means higher costs. Thus,

the profits of every case were investigated before taxes and OPEX. The oil and gas prices


120

are discussed in the first section of this chapter. In this investigation of profits, the low oil

price: 40 USD/bbl and gas price: 2 USD/Mscf were used.

Figure 6.13 Condensate recovery for different injection time cases

0

2

4

6

8

10

12

14

16

0 1000 2000 3000 4000 5000 6000 7000

Co

nd

ensa

te r

eco

very

, %

Time, days

10 days

50 days

100 days

12.5

13

13.5

14

14.5

15

15.5

5400 5500 5600 5700 5800 5900 6000 6100 6200 6300 6400 6500

Co

nd

ensa

te r

eco

very

, %

Time, days

10 days

50 days

100 days


121

10 days 50 days 1 00 days

Figure 6.14 Condensate saturation distribution for different injection time cases

Figure 6.15 Condensate recovery, condensate and oil cumulative production and

cumulative gas injection in 50 days injection time case


122

From Figure 6.15, for the 50 days injection time case, the production of

condensate, the production of gas, and the volume of injected gas after three cycles were

obtained. The same principles were used for the 10 days injection time case and the 100

days case. The profits for three cases are shown in Table 6.9.

Table 6.9 Profits for different injection time cases

Injection

time, days

Condensate

RF,% Produced oil, bbl Injected gas, ft3

Produced

gas, ft3 Profit, $USD

10 13.3 12933.2 30000000 315000000 1087328

50 14.5 14113.4 117000000 381000000 1092536

100 15.1 14678.5 164000000 407000000 1073140

As it can be seen from Table 6.9, the 100 days injection time case had the highest

condensate recovery 15.1%. However, the profits of the 100 days injection time case

were the lowest. The reason is that compared to the 10 days injection time case and the

50 days injection time case, the 100 days injection time case had a much larger volume of

injected gas, and the cost of the injection period was much higher. Compared with the 10

days injection time case, the 50 days injection time case had higher condensate recovery,

and the profit was higher.

Thus, from these results, it can be concluded that longer injection time does not mean the

higher profits. Longer injection time can produce greater condensate recovery, but the

costs are much higher and the profits are lower. During the design of the injection period

of huff-n-puff gas injection, it is very important to choose an optimized injection time. As

it mentioned before, the condensate saturation is mainly in this near fracture region as

shown in Figure 6.16. From Figure 6.17, it can be seen that for the 50 days injection time

case, the condensate saturation near the fracture region was lower, and this means that


123

during the 50 day injection the pressure of this near fracture region was increased, and the

condensate was revaporized.

Figure 6.16 Condensate saturation after 15 years primary depletion

Figure 6.17 Pressure distribution after 1st cycle of injection for different injection time

cases


124

As we discovered in the previous discussion, the optimized injection time is that

during the injection time at an injection pressure, the pressure of the main condensate

region in the reservoir can be increased. Thus, the condensate can be revaporized to gas

phase, and both condensate production and gas production can be increased.

Though a proper injection time of huff-n-puff gas injection could generate more

profits, it is also very important to compare the profits of huff-n-puff with primary

depletion. The total exploitation time for the three cases in this study were: 6105 days (10

days injection), 6225 days (50 days injection), and 6375 days (100 days injection). The

three primary depletion cases were conducted based on these total exploitation times.

Table 6.10 shows the profits of these cases, and Table 6.11 shows the comparison

between huff-n-puff and primary.

Table 6.10 Profits for three different primary depletion

Injection

time

Condensate

RF,% Produced oil, bbl

Injected gas,

ft3

Produced

gas, ft3 Profit, $USD

10 13.1 12758.8 N/A 288000000 1086352

50 13.16 12784.5 N/A 289700000 1090780

100 13.2 12814.9 N/A 291000000 1094596


125

Table 6.11 Profits comparison between huff-n-puff gas injection and primary depletion

Huff-n-Puff Profit, $USD

Primary depletion Profit,

$USD

Difference,

$USD

10 days injection 1087328 1086352 976

50 days injection 1092536 1090780 1756

100 days injection 1073140 1094596 -21456

From Table 6.11 it also can be seen that the profits of the 100 day injection time

was even less than that of primary depletion. For the 10 day injection time case and 50

day injection case, the profits were higher than that of the primary. This also proves the

efficiency of huff-n-puff gas injection.

6.8 Number of huff-n-puff cycles and Production period

The huff-n-puff cycle number is also a very important operation that needs to be

seriously taken into account during the application of the huff-n-puff gas injection

method in shale gas condensate reservoirs.

In this section, 11 cycles of huff-n-puff were simulated to investigate the

efficiency of huff-n-puff over multiple cycles. Every cycle consisted of 50 days injection

and 200 days production. Based on the previous study in this chapter, the soaking time

was not taken in this model. Figure 6.18 shows the condensate recovery and the pressure.


126

Figure 6.18 Condensate recovery and average pressure for 11-cycles huff-n-puff gas

injection

As it can be seen from Figure 6.19, the condensate recovery was increased to

16.12% after 11-cycles of huff-n-puff gas injection. The total exploitation time including

primary depletion time and huff-n-puff gas injection time was 8225 days. The

comparison of this 11-cycle gas injection after 15 years primary depletion and 8225 days

primary depletion is shown in Figure 6.19. The incremental condensate recovery by the

application of huff-n-puff gas injection was 3%.


127

Figure 6.19 Condensate recovery comparison between huff-n-puff gas injection and

primary depletion

Table 6.12 shows the profits analysis of different cycles of huff-n-puff gas

injection. The oil price used was 40 USD/bbl and the gas price was 2 USD/Mscf. As it

can be seen from Table 6.12, in this 11-cycle huff-n-puff gas injection work, as the cycle

numbers increased, the incremental of condensate recovery decreased. Every cycle’s

profit was not the same. In the first several cycles as the cycle numbers increased, profit

increased. After 5 cycles, the profits decreased. Thus, it can be seen that at the 5th

cycle,

0

2

4

6

8

10

12

14

16

18

0 1000 2000 3000 4000 5000 6000 7000 8000 9000

Co

nd

ensa

te r

eco

very

, %

Time, days

8225 days primary depletion

huff-n-puff gas injection


128

the cycle profits reached their highest, and then the profits decreased. For 11 cycles of

huff-n-puff gas injection, the total profits reached 1158168.821 USD.

Table 6.12 Profits analysis of different cycle numbers

Condensate

RF,% Incremental

Produced oil,

bbl

Injected

gas, ft3

Produced

gas, ft3

Cumulative

Profits, $USD

Every cycle

profits,

$USD

0 12.99 N/A 12590.76074 0 280921312 1065473.054 N/A

1 13.56 0.57 13176.4 40048064 312526144 1072012.16 6539.106312

2 14.08 0.52 13680.8916 79345976 346389568 1081322.848 9310.688063

3 14.53 0.45 14113.37891 117708504 381154080 1091426.308 10103.46019

4 14.91 0.38 14482.25098 155331360 416925600 1102478.519 11052.21081

5 15.22 0.31 14786.73438 192593120 453879200 1114041.535 11563.01594

6 15.47 0.25 15027.95996 229691776 490948000 1123630.846 9589.311438

7 15.67 0.2 15220.46875 266758272 528252032 1131806.27 8175.423562

8 15.82 0.15 15373.33301 303578592 565877120 1139530.376 7724.106313

9 15.95 0.13 15493.35742 338846784 602448000 1146936.729 7406.352562

10 16.05 0.1 15591.8125 375797696 640225984 1152529.076 5592.347125

11 16.12 0.07 15675.51172 412651936 678226112 1158168.821 5639.74475

Figure 6.20 shows the gas production rate during the production period of every

cycle. The production rate was high at the end of the production period. According to the

section studying primary depletion, it is better to start huff-n-puff gas injection when the

decline rate is very high. In this 11-cycle huff-n-puff, the decline rate at the end of every

production period was 65%. Thus, the production period should be increased. In a fixed

exploitation time, the increasing production time means less cycles of huff-n-puff gas

injection, at less cost. According to this production rate, when the production time was

increased to about 400 days, then the decline rate in the production period reaches 90%.


129

Based on this relationship between the decline rate and the production time,

another huff-n-puff gas injection project was conducted. In this simulation work, the

injection time was same as the previous one: 50 days, and based on the previous study,

soaking time was also not taken into account. The production time was increased from

200 days to 400 days. The total exploitation time of this case was the same as the 11-

cycle huff-n-puff gas injection: 8825 days. Based on this different time period, in this

new huff-n-puff gas injection project only 6 cycles were run. Figure 6.21 shows the

condensate recovery comparison between 11-cycle huff-n-puff and 6-cycle huff-n-puff.

Figure 6.20 Production rate in 11-cycles huff-n-puff simulation work


130

Figure 6.21 Condensate recovery comparison between 11-cycles huff-n-puff and 6-cycles

huff-n-puff

The condensate recovery was 16% in the 6-cycle huff-n-puff gas injection, and

for the 11-cycle huff-n-puff gas injection, the condensate recovery was only 0.12%

higher than that in the 6-cycle huff-n-puff. This indicates that the start of production time

in huff-n-puff gas injection should follow the same optimization principle for the end

time of primary depletion. By following this principle, less huff-n-puff cycles are needed

to increase the condensate recovery. Also, less cycle numbers means less volume of gas

is needed to be injected into reservoir. This means fewer costs in huff-n-puff gas injection

projects. Table 6.13 shows the profits analysis for different cycle numbers of huff-n-puff

gas injection and primary depletion. 5 cycles of huff-n-puff with 400 days production

time had higher profits.

0

2

4

6

8

10

12

14

16

18

0 1000 2000 3000 4000 5000 6000 7000 8000 9000

Co

nd

ensa

te r

eco

very

, %

Time, days

11 cycles-200 days production


131

Table 6.13 Profits analysis for different cycle numbers of huff-n-puff gas injection and

primary depletion.

Condensate

RF,%

Produced

oil, bbl

Produced

gas, ft3

Injected gas,

ft3

Cumulative

Profits,

$USD

Profits

incremental,

$USD

Primary 13.5 13136.2 300000000.0 N/A 1125448.0 N/A

11 cycles, 200

days production 16.1 15675.5 678226112.0 412651936.0 1158168.8 32720.8

6 cycles, 400 days

production 16.0 15453.5 234300000.0 526000000.0 1201540.0 76092.0

As mentioned before, this simulation work simulated 1 hydraulic fracture work,

and there were 9 hydraulic fractures in total. Thus, the total profit was the profit of

simulation work times 9.

Since only one well exists in huff-n-puff gas injection, thus, there is no additional

cost to drilling a new injection well. Also, for the operating cost of the well, from another

perspective, compared with huff-n-puff gas injection with primary depletion, both cases

have only one well. Thus, the operating cost comparison between primary depletion and

huff-n-puff gas injection cannot been taken into account. Thus, the additional cost for

huff-n-puff gas injection compared with primary depletion includes: the injection

equaipment costs and the injected gas cost. Since the injected gas in this case was the

produced gas. Thus, produced gas × gas price + oil × oil price – additional costs = total

profits for application of huff-n-puff. From the EIA report, the cost of the injection

equaipment 167554 $USD/year. In 6 cycles, the total injection time was 300 days. Thus,

the cost of injection equipment for 6-cycles case was $167554. And for 11-cycles case,

the injection equipment cost was $335109.The incremental profit is shown in Table 6.14.


132

Table 6.14 Profits comparison between primary depletion, 11 cycles with 200 days

production, 6 cycles with 400 days, total exploitation time was same: 8225 days

Total profits, $USD

Profit Incremental,

$USD

Primary 10129032

11 cycles, 200 days

production 10423519 -40622

6 cycles, 400 days

production 10813860 517274

As Table 6.14 shows, at this lower oil and gas prices, there was no economic

profit for 11-cycles case. However, by applying the optimized huff-n-puff gas injection,

the profits were highly increased. The profit of 6-cycles huff-n-puff with 400 days

production was almost 510000 higher than that of primary depletion.

One important aspect that needs to be pointed out is that all of these economic

analyses used the low oil price: 40 USD/bbl and 2 USD/Mscf. Figure 6.22 shows the

incremental profits at different oil prices for this simulation work. It can be seen that if

the oil price is increased, the profits are increased rapidly by applying huff-n-puff gas

injection.

Even in this “winter” situation, by applying the optimized huff-n-puff gas

injection, 694828 dollars could be attained compared to the primary depletion.


133

Figure 6.22 Incremental profits by applying huff-n-puff gas injection at different oil

prices

From the results in this section, it can be concluded that the cycle number of huff-

n-puff gas injection and production time has a large impact on the condensate and the

final profits of huff-n-puff gas injection. More condensate is recovered from the reservoir,

and also more gas can be recovered from the reservoir.

6.9 Summary

This chapter proves the efficiency of huff-n-puff gas injection in shale gas

condensate reservoirs, and the optimization of huff-n-puff gas injection to obtain the

highest profits is also discussed.

The hydraulic fracture provides a high conductivity path for the flow of reservoir

fluids. Hydraulic fracture is necessary for the exploitation of shale gas condensate

reservoirs.

0

200000

400000

600000

800000

1000000

1200000

1400000

1600000

0 10 20 30 40 50 60 70 80 90

Pro

fits

, $U

SD

Oil Price, $USD/bbl


134

The starting time of huff-n-puff gas injection is an important issue. Early starting

time does not mean higher condensate recovery can be obtained. Combined with the gas

production decline rate and the effect of the starting time of huff-n-puff, it can be seen

that huff-n-puff gas injection is more effective to start at the later period of primary

depletion (when the decline rate is around 90%). If the huff-n-puff is applied too early the

primary production rate is not that low, and compared to the incremental recovery with

the cost of injection process, it is not necessary.

Also, the simulation results indicate that there are no benefits to applying a longer

soaking time. Longer soaking time means longer waiting time, and this reduces the

production period. Also, longer soaking time had the smallest recovery in these three

simulation cases. This means that for the application of huff-n-puff gas injection in the

shale gas condensate reservoir, short soaking time or even no soaking time would be

better.

Injection time is another important factor. It can be concluded from this study that

longer injection time does not mean higher profits. Longer injection time can produce

greater condensate recovery, but the costs are much higher and the profits are lower.

During the design of the injection period of huff-n-puff gas injection, it is very important

to choose an optimized injection time. The optimized injection time is that during the

injection time, the pressure of the main condensate region in the reservoir can be

increased. Thus, the condensate can be revaporized to gas phase, and both condensate

production and gas production can be increased.

The cycle number of the huff-n-puff gas injection and the production time both

have a large impact on the condensate and the final profits of huff-n-puff gas injection.

The cycle number design depends on the injection time and production time. The

injection time has been discussed before. The best production time is during the

production period, when the decline rate of production reaches about 90% and is then

followed by another cycle.

By following these principles, the greatest profits can be obtained by applying

huff-n-puff gas injection in shale gas condensate reservoirs.


135

CHAPTER 7

CONCLUSION AND DISCUSSION

In this chapter, general conclusions are drawn from the experiment work and

simulation studies. Also, in the second part, possible improvements on current work are

discussed.

7.1 General Conclusions

The objective of this research is to investigate the EOR potential of huff-n-puff

gas injection in shale gas condensate reservoirs.

In a shale gas condensate reservoir, when the pressure near the production well

falls below the dew point pressure, the condensate accumulates near the wellbore. Thus,

as the function of this well is changed into injecting gas, the pressure of the condensate

region increases very quickly because the condensate region is near the injection well.

Consequently, the condensate is re-vaporized and flows into the well during the puff

process. Therefore, the huff-n-puff method is more effective than the gas flooding

method, especially in shale gas condensate reservoirs. Since the condensate region is near

the production well, the pressure propagation time or pressure response time is much

shorter, and the efficiency is higher in the huff-n-puff method.

In order to investigate the efficiency of huff-n-puff, both experimental work and

simulation studies (Lab scale simulation and field scale simulation) were conducted in

this research. In Chapter 3 and Chapter 4, three experiments and simulation models

which were used to simulate the experiment processes were performed. Huff-n-puff gas

injection produced a good condensate recovery on shale cores. This indicates that huff-n-

puff gas injection has the potential to improve condensate recovery in shale gas

condensate reservoirs.

The mechanism of huff-n-puff gas injection was investigated in Chapter 5. Both

experimental work and simulation study were performed. It can be concluded that re-

vaporization is the main mechanism of huff-n-puff gas injection to enhance the


136

condensate recovery. When pressure is increased in the huff process, condensate is re-

vaporized into gas state and produced from the reservoir.

In this mechanism study, the fraction of the butane (condensate) in produced gas

was reduced with the increase of huff-n-puff cycle numbers. This was because when

methane was injected into the reservoir to increase the pressure, more methane

production occurred during the puff process. Meanwhile, butane was recovered after

every cycle of huff-n-puff, but less butane was remained in the reservoir. Thus, though

more butane was re-vaporized into gas state and produced, butane content in produced

gas was reduced.

Since the efficiency of huff-n-puff gas injection has been proven from lab scale

study, the application of huff-n-puff gas injection in field scale is necessary. Reservoir

simulation work was performed to investigate the efficiency of huff-n-puff gas injection

to enhance condensate recovery in shale gas condensate reservoirs, and optimization

work of huff-n-puff gas injection was also performed.

Simulation work in Chapter 6 proves the efficiency of huff-n-puff gas injection in

shale gas condensate reservoirs. Actually, even at a low oil price, huff-n-puff gas

injection still can obtain more profits compared to the primary depletion.

For the operation of huff-n-puff gas injection in field, combined with the gas

production decline rate and the effect of the starting time of huff-n-puff, it can be seen

huff-n-puff gas injection is more effective to start at the later period of primary depletion

(when the decline rate is around 90%). If the huff-n-puff is applied too early the primary

production rate is not that low, and compared to the incremental recovery with the cost of

injection process, it is not necessary. Also, an optimized injection time should be

selected: during this injection time, the pressure of the main condensate region in the

reservoir can be increased.

Also, the cycle number of huff-n-puff gas injection is very important. The cycle

number of huff-n-puff is connected to the injection time, soaking time, and production

time. For a fixed time of exploitation, more cycles of huff-n-puff gas injection does not


137

mean higher profits. The cycle number should depend on the optimized injection time

and optimized production time.

By following these operation principles, or in other words, optimization principles

of the application huff-n-puff gas injection in shale gas condensate reservoirs, higher

recovery can be achieved and more profits can be obtained.

7.2 Future work

1) In this experiment, the gas condensate mixture used was a mixture of methane

and butane. The phase behavior of real gas condensate fluids is more complex than this

methane and butane gas mixture. Thus, conducting experiments by using reservoir gas

condensate fluid samples at reservoir conditions is necessary.

2) The reservoir model we used in Chapter 6 was independent, not related with

the lab study. Developing a reservoir scale model by upscaling the experiment model

could help to investigate the efficiency of huff-n-puff gas injection in field scale.


138

NOMENCLATURES

Pwf = wellbore pressure

Pr = reservoir pressure

Pd = dew point pressure

GE = gas equivalent

R = universal gas consatant

Tsc = temperature at standard conditions

Psc = pressure at standard conditions

NP = cumulative production

= density

Mo = molecular weight

Gw = initial wet gas

Gpw = produced wet gas

Io = incident X-ray intensity

I = intensity after passing through the material

µ = attenuation coefficient

CTexp = CT number of the core containing both liquid and gas phases

CTgr = CT number of the core when it is only saturated with methane

CTcr = CT number of the core when it is only saturated with n-butane

Sc = condensate saturation after a specific cycle

Sp = condensate saturation after primary depletion


139

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