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2017

Influence of Reservoir Geological Characteristics on

Fracturing Fluid Flowback

Wang, Qiaohong

Wang, Q. (2017). Influence of Reservoir Geological Characteristics on Fracturing Fluid Flowback

(Unpublished master's thesis). University of Calgary, Calgary, AB. doi:10.11575/PRISM/26519

http://hdl.handle.net/11023/4107

master thesis

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UNIVERSITY OF CALGARY

Influence of Reservoir Geological Characteristics on Fracturing Fluid Flowback

by

Qiaohong Wang

A THESIS

SUBMITTED TO THE FACULTY OF GRADUATE STUDIES

IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE

DEGREE OF MASTER OF ENGINEERING

GRADUATE PROGRAM IN CHEMICAL AND PETROLEUM ENGINEERING

CALGARY, ALBERTA

SEPTEMBER, 2017

© Qiaohong Wang 2017

ii

Abstract

Fracturing fluid flowback is a principal process in the successful development of unconventional

oil and gas reservoirs. When a flowback rate is low the fracturing fluid remains in a reservoir,

causing damage to the reservoir and impacting the oil and gas capacity during the development

stage. The current study of the factors that affect a flowback rate of a fracturing fluid is poor.

This thesis is focused on an impact study of the reservoir geological characteristics on the

fracturing fluid flowback. The roles of reservoir lithology, physical properties, formation

pressure, fracture development, and wettability on fracturing fluid flowback are analyzed. The

conclusions are expected to serve as a reference for further development of shale oil and gas

reservoirs.

After the simulation work, we conclude that when the formation pressure is higher, the total

flowback rate increases; for reservoir wettability, the less water wet the reservoir is, the more the

total flowback rate has. The influence of fracture development is diversified; a fracture location

will determine whether it becomes promotion or resistance to the fracture fluid flowback process.

Keywords: flowback, geological characteristics, reservoir, unconventional oil and gas

reservoirs, fracture, reservoir lithology, formation pressure, wettability

iii

Acknowledgements

I want to express my gratitude to my supervisor Dr. Zhangxing (John) Chen, who has provided

valuable support and suggestions to guide my research and study.

I would also like to thank Mr. Qingru Wang and Mr. Longxiang Geng who provided me with

reference data and advised me on my thesis.

My gratitude also goes to Dr. Bing Kong and Dr. Kai Zhang for their patient guidance to help me

with my research and professional skills.

I also appreciate all the members in the Reservoir Simulation Group and all the sponsors of our

research group.

iv

Table of Contents

Abstract .............................................................................................................................. ii Acknowledgements .......................................................................................................... iii Table of Contents ............................................................................................................. iv List of Tables .................................................................................................................... vi List of Figures and Illustrations .................................................................................... vii List of Symbols, Abbreviations and Nomenclature ...................................................... ix

Chapter 1 Introduction......................................................................................................1

Chapter 2 Literature Review ............................................................................................5 2.1 Literature Review of Fracturing Technology .......................................................5

2.1.1 Development of fracturing technology. .........................................................5 2.1.2 Main mechanisms of shale gas reservoir production increasing by

fracturing. .........................................................................................................8 2.1.3 Main technology of shale reservoir fracturing. ..........................................9

2.1.3.1 Multi-fracture (fracture network) fracturing. ...................................12 2.1.3.2 Refracturing technology. ....................................................................13 2.1.3.3 Simultaneous fracturing technology. .................................................15 2.1.3.4 Horizontal well staged fracturing technology. ...................................16 2.1.3.5 CO2 foam fracturing. .........................................................................16 2.1.3.6 Riverfracing treatment. .........................................................................18 2.1.3.7 Hydrajet fracturing. ............................................................................18 2.1.3.8 Summary. ............................................................................................19

2.2 Literature Review of Flowback Technology .......................................................19 2.2.1 Effect of research on fracturing and flowback to exploit shale gas formation.

..........................................................................................................................19 2.2.2 Main technology of flowing back. ................................................................21

2.2.2.1 Liquid nitrogen (or CO2) fracturing assistant. ....................................22 2.2.2.2 Reverse wetting agent fracturing assistant. .........................................23 2.2.2.3 Fiber sand control. ................................................................................23 2.2.2.4 Optimizing flowback. ............................................................................24 2.2.2.5 Physical method. ...................................................................................24 2.2.2.6 Microwave stimulation technology. ......................................................25 2.2.2.7 Ultrasonic stimulation technology. ......................................................26 2.2.2.8 Summary. ..............................................................................................27

2.3 The Effect of Reservoir Properties on Flowback Procedure .............................27 2.3.1 The effect of reservoir lithology on flowback procedure. ..........................28

2.3.1.1 The effect of brittle minerals on reservoir quality and hydraulic fractures. .................................................................................................................29

2.3.1.2 The effect of clay minerals on reservoir quality and flowback procedure. .................................................................................................................30

2.3.2 The effect of reservoir properties on flowback procedure. .......................37 2.3.3 The effect of reservoir pressure on flowback procedure. ..........................39 2.3.4 The effect of fractures on flowback procedure ...........................................41 2.3.5 The effect of wettability on flowback procedure. .......................................42

v

CHAPTER 3 CHARACTERSITICS OF SHALE RESERVOIR AND FLOWBACK TECHNOLOGY .....................................................................................................43

3.1 Shale Reservoir Characteristics ...........................................................................43 3.1.1 Marine facies. .................................................................................................43 3.1.2 Continental facies shale. ................................................................................44 3.1.3 Marine transitional facies shale. ..................................................................44

3.2 Characteristics of Typical Shale Reservoirs Globally ........................................46 3.2.1 Fort Worth basin Barnett shale reservoir. ..................................................47 3.2.2 Wufeng-longmaxi shale formation in Sichuan Basin. ................................48 3.2.3 Ordos Basin continental facies and marine transitional facies shale reservoir.

..........................................................................................................................52 3.3 Case analysis of fracturing flowback in the main shale reservoirs in the world.54

3.3.1 Fort Worth Basin Barnett shale. ..................................................................54 3.3.2 Sichuan Basin Wufeng-longmaxi shale. ......................................................55

3.3.2.1 Horizontal well fracturing technology. ................................................56 3.3.2.2 Fracturing fluid use and effect analysis. .............................................56 3.3.2.3 Technological innovation summary of Fuling shale gas. ...................58

3.3.3 Ordos Basin continental facies and marine transitional facies shale reservoir. .........................................................................................................58

3.3.3.1 Difficulties in continental facies reservoir fracturing technology. .....58 3.3.3.2 Liquid CO2 fracturing technology. .......................................................59 3.3.3.3 CO2 incremental fracturing technology. ..............................................59 3.3.3.4 Suggestions and conclusions. ...............................................................60

3.4 Summary .................................................................................................................61

Chapter 4 Establishment of a Model ..............................................................................63 4.1 Reservoir Setting ....................................................................................................64 4.2 Process Design ........................................................................................................64 4.3 Analysis of the Basic Model ..................................................................................64 4.4 Result Comparison ................................................................................................67

Chapter 5 Reservoir Geological Characteristics Analysis ...........................................69 5.1 Lithology .................................................................................................................69 5.2 Formation Pressure ...............................................................................................70 5.3 Reservoir wettability ..............................................................................................72 5.4 Fracture development ............................................................................................73

5.4.1Dual fractures model. .....................................................................................74 5.4.2 Three fractures reservoir. .............................................................................75 5.4.3 Fracture network reservoir. .........................................................................78

Chapter 6 Conclusions .....................................................................................................80

Reference ..........................................................................................................................81

vi

List of Tables

Table 1-1 Global shale gas reserves by region ……………………….…………………….........1

Table 2 - 1 The development of Barnett shale gas stimulation……………………………….......8

Table 2 - 2 The technical characteristics and applicability of fracturing technologies………...12

Table 2 -3 The technical characteristics and applicability of common flow back technologies...23

Table 2- 4 Comparison between the lithology of Longmaxi, Jiulongdong formation in Sichuan

Basin and Barnett Shale in America …………………………………………………………….30

Table 2-5 The micro-porosity of clay minerals………………………………………………….33

Table 2-6 Sensitivity of clay minerals………………………………………………………….. 36

Table 2-7 Comparison between Longmaxi Formation and North America gas shale………… 41

Table 2-8 Relationship Between Shale Gas Production and Pressure Coefficient For Longmaxi

Formation……………………………………………………………………………………… .41

Table 3-1 Physical property comparison between Barnett Shale, Longmaxi, Jiulongdong

Formations in Sichuan Basin……………………………………………………………………46

Table 3-2 Organic-rich lacustrine shale distribution and geological features…………………..46

Table 3-3 Organic-rich shale reservoir distribution and their geological features………………47

Table 3-4 Shale gas accumulation model………………………………………………………..47

Table 3-5 Characteristic parameters of major shale gas producing areas in the United States….49

Table 3-6 Statistical table of fracture parameters of a horizontal well in Jiaoshiba area………..52

vii

List of Figures and Illustrations

Figure 1-1 Natural gas organic content…………………………………………………………..2

Figure 1- 2 Different reservoir’s organic content ……………………………………………….3

Figure 2-1 Sketch map of vertical well and horizontal well fracturing………………………...11

Figure 2-2 Sketch map of fracture network fracturing ………………………………………...14

Figure 2-3 Sketch map of simultaneous fracturing……………………………………………..16

Figure 2-4 Relationship between CO2 foam quality and viscosity of fracturing fluid ………...18

Figure 3-1 Integrated Histogram of Paleontological Development in Jiaoye 41-5 well ……....51

Figure 3-2 Core sample of Longmaxi shale reservoir …………………………………………53

Figure 3-3 Core sample of Ordos basin Chang-7 member Yanchang reservoir…………….…54

Figure 3-4 Relationship between flowback rate of test gas and the maximum production in

Fuling Jiaoshiba Area…………………………………………………………………………..58

Figure 3-5 Comparison diagram of fracturing process flowback rate in a shale gas well……..61

Figure 4-1 3D model diagram………………………………………………………………...64

Figure 4-2 3D pressure distribution diagram (Stage 1)……………………………………….66

Figure 4-3 3D pressure distribution diagram (Stage 2)……………………………………….67

Figure 4-4 3D pressure distribution diagram (Stage 3)………………………………………...67

Figure 4-5 Flowback quantity curve of basic model…………………………………………...68

Figure 4-6 Real flowback quantity …………………………………………………………….68

Figure 5-1 Pressure set for high formation pressure model……………………………………72

Figure 5-2 Flowback quantity curve for high formation pressure model……………………...72

Figure 5-3 Irreducible water saturation difference between basic model and new model…….73

Figure 5-4 Flowback quantity curve for less water wet model………………………………..74

viii

Figure 5-5 Well location and fracture location for dual fractures model……………………..75

Figure 5-6 Flowback quantity curve for dual fractures model………………………………..76

Figure 5-7 Well location and fracture location for three fractures model…………………….77

Figure 5-8 Pressure distribution diagram for three fractures model…………………………. 77

Figure 5-9 Flowback quantity curve for three fractures model……………………………….78

Figure 5-10 Well location and fracture location for fracture network model………………...79

Figure 5-11 Flowback quantity curve for fracture network model…………………………...80

ix

List of Symbols, Abbreviations and Nomenclature

Symbol Definition USGS United States Geological Survey

USA United States of America

HJF Hydrajet Fracturing

XRD X-ray Diffraction

ECS Elemental Capture Spectroscopy

NGS Natural Gamma Spectroscopy

TOC Total Organic Carbon

m Metre L Litre

m3 meters cubed

min Minute

IMEX a black oil simulation software

CMG Computer Modelling Group

x

mD Milli Darcy

Q Seepage Quantity

K Permeability Coefficient

A Cross-Sectional Area

h2-h1 Head Loss

l Seepage Length

1

Chapter 1 Introduction

Shale gas is an unconventional natural gas, deposited in organic mudstone and its interlayers. It

exists in an adsorption or dissociation state. It is the result of aggregation in source rock layers

after the generation of natural gas. It shows as the typical “in-situ” formation mode [1]. Recently,

shale gas has drawn global attention because of the growing need of energy and the success of

producing shale gas in the United States [2, 3].

The global shale resources are huge: about 456.24×1012m3. It is distributed in North America,

Central Asia, China, Latin America, the Middle East, North Africa and the former Soviet Union

(Table 1-1) [4, 5, 6]

Region and Country Shale Gas Reserves North America 108.79 Latin America 59.95 West Europe 14.44 Middle and East Europe 1.10 Soviet Union 17.75 Middle East and North Africa 72.15 Sahara region 7.76 Middle Asia and China 99.90 Pacific region 65.50 Asia & pacific 8.89 South Asia 0 World Total 456.24

Table 1-1 Global shale gas reserves by region [4,5,6]

The fiure 1-1 and 1-2 Shows how we define reservoir type and gas type by the organic content in

reservoir.Shale gas forms when natural gas is retained in a source rock. A shale gas reservoir is

an in-situ gas reservoir. Because the porosity of a shale gas reservoir is low, fractures are

commonly used to recover the gas from this formation. The highest range of porosity in a shale

gas reservoir is four to five percent, with permeability less than 1×10-3 μm2. The main source of

2

space is provided by fractures. Shale rock is formed from thin interbeds of dark coloured

mudstone and light coloured sandstone. The deposition of natural gas in shale rock is very

diverse. Most of the shale gas is absorbed in rock particles, interfaces of organisms, or it remains

in an unbound state in the spaces of pores and fractures, in addition to that some natural gas is

resolved. The deposition of adsorption natural gas is related to the organism and mineral content

of clay. The percentage of adsorption natural gas varies from 20 to 85 percent. Shale gas is in the

middle of coal seam adsorption gas (adsorption gas content over 85 percent) and conventional

trapped gas (normal adsorption gas content is zero).

Figure 1-1 Natural gas organic content [8] The United States Geological Survey (USGS) describes shale gas as a continuous phase from a

gas reservoir. USGS has identified 16 features. All the features may be found in a continuous gas

reservoir. Unique characteristics related to shale rock containing gas are regional distribution,

lack of obvious cap rock and trap, no clear interface of gas and liquid and natural fracture

generation, a recovery factor is lower than a conventional gas reservoir and there is extremely

3

low bedrock permeability. The economical production of shale gas depends on the technology

used in the well completion [7, 8, 9].

Figure 1- 2 Different reservoir’s organic content [8]

The resistance of gas in shale is greater than that of conventional natural gas because the

permeability of a shale gas reservoir is low making it more difficult to produce. In shale rock,

permeability caused by fractures in gas source rock can make up for the low permeability of

matrix in some instances. The degree of development of fractures is the main control factor for

the shale gas migration, deposition and the economical production. Only a few well developed

natural fracture shale gas wells can be simply produced. More than 90 percent need enhanced

recovery methods including fracturing to channel natural fractures and improving the formation

flow conductivity near wellbore. Horizontally drilled wells are applied to utilize natural fractures

in a formation and to ensure that the wells go through more of the formation. This technology

4

has significantly improved the success rate of shale gas production. The recovery factor for

horizontal wells is three times that of vertical wells and yet the cost is only twice as much.

Enhanced oil recovery methods and special drilling and well completion methods are needed to

produce shale gas. Normally large-scale fracturing for a horizontal well is used. The rate of

fracturing fluid flowback is low in a shale gas reservoir when compared to a tight sandstone gas

reservoir. The fracturing fluid flowback rate is around 35 to 60 percent after one year of shale

gas production. This is interpreted to indicate a large amount of the fracturing fluid residual in a

formation. The residual needs to be studied to create an economical shale gas recovery process.

Fracturing and flowback play a significant role in the production of shale gas. The development

of the fracturing technology requires a fundamental study to learn how to improve a flowback

rate while reducing the impact on the formation. The desired outcome is to increase the

efficiency of shale gas production.

This thesis considers technology features, flexibility and development tendency of fracturing and

flowback, comparison of shale gas formation characteristics, physical features, and influence of

the main minerals in a shale gas reservoir, especially clay minerals. The work demonstrates that

to transform a shale rock formation needs to be based on its lithology, physical properties

fracturing layers, technologies, fluids and flowback methods. The application of this novel

information will provide a basis for the development of shale gas recovery that is economical.

5

Chapter 2 Literature Review

2.1 Literature Review of Fracturing Technology

2.1.1 Development of fracturing technology.

Nearly 30 years of technological innovation have been developed to get to a state where the

production of shale gas is a commercially viable energy source. The development of positive

national policy support has played a key role in the technological progress and promotion in the

rapid development of shale gas. The key to the technological revolution lies in the fast growth of

drilling and completion methods and the development of the fracturing technology. From the

earliest nitroglycerin explosion technology to the latest synchrotron fracturing technology, the

advance of the fracturing technology has positively changed the recovery efficiency of shale gas.

The historical development of the fracturing technology is quite interesting (Table2-1). A

nitroglycerin explosion in an open hole vertical well was implemented in the 1970s. The method

caused major damage to wellbore and the scale of formation cracks was very limited. In 1981,

the method of nitrogen and carbon dioxide foam fracturing was applied to vertical wells in shale

gas reservoirs, reducing formation damage and increasing shale gas production 3-4 times. Then

in 1992, the first shale gas horizontal well was drilled in the HAMETT basin. Horizontal wells

gradually replaced the use of vertical wells. A fracturing fluid system used a cross-linked gel as a

thickening agent or crosslinking agent during the 1980s and most of the 1990s. Horizontal well

fracturing was found to be effective in generating fractured networks and expanding a natural gas

discharge area. This was very favourable because it provided cost savings while increasing oil

and gas recovery. The development of large-scale hydraulic fracturing in horizontal wells

contributed to the economic development of shale gas resources

6

In 1998, the fracturing technology made a breakthrough; it was determined that a fracture fluid

should be a water-based liquid instead of gel. The new fracturing fluid that was primarily water

and has a low sand ratio; the usage of proppants was about 90 percent less than in the gelled

fracturing. The cost of a fracture fluid was reduced by more than 50 percent and this water-based

fracture fluid provided better fracturing performance increasing the recovery efficiency by more

than 30 percent.

The Segmental Fracturing Technology for Horizontal Wells was developed rapidly after 2000

and the commercial prospects for shale gas exploitation was now realistic. Segmental fracturing

has continued to improve going from two segments to 20 or more segments. A drainage area and

recovery efficiency have been enhanced. The use of the applied horizontal Segmental Fracturing

Technology in the development of shale gas in the United States increased to over the standard

method in 85 percent of new wells.

After 2005, the combination of the microseismic crack monitoring technique and Segmental

Fracturing Technology for Horizontal Wells became the key technology applied in the

development of shale gas recovery. This was followed quickly in 2006 with a new type of

fracturing technology. The Synchronous Fracturing Technology is being applied in the Barnett

shale gas basin. Jaripatke et al. [10] summarized the history of shale gas development in the

Barnett Basin in the United States and the development of drilling and completion techniques

7

Phase Period Accumulated

Well Number

Fracturing Technology

Initial 1979 5 High energy gas fracturing 1981 6 N2，CO2 foam fracturing 1984 17 Cross linked gel fracturing,liquid quantity

100000gal（378m3） 1985 49 Cross linked gel fracturing,liquid quantity

500000gal（1892m3） 1988 62 Cross linked gel fracturing 1991 96 Horizontal well and cross linked gel fracturing 1995 200 Horizontal well fracturing and Cross linked gel

fracturing 1997 300 Riverfracing treatment, liquid quantity

500000gal(1892m3） 1999 450 Riverfracing treatment, inclinometer fracture

monitor 2001 750 Riverfracing treatment, micro seismic fracture

monitor 2002 1700 Horizontal well fracturing, Riverfracing treatment

Development 2003 2600 New well with 85 horizontal wells，117 directional wells，719 vertical wells

2004 3500 150 wells with horizontal well stage fracturing， 2-4 stages

2005 4500 600 new horizontal wells drilling time is greatly reduced

2006 5500 Synchronous fracturing,lower development costs 2007 7000 Horizontal well fracturing, synchronous fracturing 2008 9000 Repeated fracturing

Steady 2009- 13000 Maintain capacity, lower costs, enhancing oil recovery

Table 2 - 1 The development of Barnett shale gas stimulation [10]

8

The development process of the Barnett shale gas fracturing technology represents the growing

trend of shale gas in the world today.

The development process of the shale gas fracturing technology progressed from the well type

(horizontal and incline vs. vertical). A fracturing fluid was developed moving from high energy

gas, foam fracturing, cross-linked gel fracturing and then transitioning to water fracturing to

updating the process to consider environmental protection [11]. The number of fracture segments

was developed from a single stage of fracturing to multi-stage fracturing. The use of a fracturing

fluid has increased significantly because of economic benefits. The movement from segmental

fracturing to synchronous fracturing and then repeated fracturing has provided a better reservoir

transformation impact. Finally, fracturing effect monitoring was established from nothing, and

the work has progressed from inclinometer crack monitoring to microseismic crack monitoring.

The commercial development of shale gas exploitation is based on continuous innovation and

progress of a fracturing technology driven by horizontal well fracturing, water fracturing and the

microseismic crack monitoring technology. Simultaneously, the application of synchronous

fracturing and repeating fracturing played a huge role in reviving the economics of shale gas

production.

2.1.2 Main mechanisms of shale gas reservoir production increasing by fracturing.

Because of the particularity of shale gas reservoirs, the mechanism of its fracturing stimulation is

different from that of a conventional gas reservoir or sandstone gas reservoir. Shale gas

reservoirs do not exist in a form of conventional traps; they are self-generating and self-storage

9

gas reservoirs. Only a natural fracture network can increase the low permeability of shale [12].

The capacity of a shale gas is determined by micro fractures in a shale reservoir. The fractures

are both a storage space and a percolation path for the shale gas. They provide the necessary path

for the shale gas to reach wellbore. Recoverable shale gas is determined by reservoir fractures’

occurrence, the density, characteristic and opening degree in the reservoir. Shale reservoirs are

generally well developed with good natural fractures and bedding. A high brittleness coefficient

of the shale is connected to the shear failure during fracturing, which can connect natural

fractures and form a complex fracture network. Therefore, the main stimulation mechanism for a

shale gas reservoir is to create an effective fracture network to increase the volume of

reconstruction and increase the capacity for the shale gas. The special characteristics of shale gas

reservoirs result in shale fracturing that does not form a single fracture. Rather, a complex

network in both the horizontal and vertical directions is the outcome found in microseismic

fracture tests [13].

2.1.3 Main technology of shale reservoir fracturing.

A shale reservoir fracturing technology can be divided into vertical wells, inclined wells and

horizontal wells fracturing (Figure 2-1) by the well difference. It can also be divided into gas,

foam, gel and hydraulic fracturing based on the type of a fracturing fluid used. The fracturing

section difference is divided into single section and multi-section fracturing [14]. The depth,

natural fractures, a well completion technology, capacity and formation sensitivity of a shale gas

reservoir all play a role in the choice of a fracturing fluid and a fracturing technology.

10

At present, commonly used technologies are multi-section fracturing, riverfracing, hydrajet

fracturing, fracture network fracturing, refracturing and simultaneous fracturing. Recently, more

attention is being paid to CO2 and N2 fracturing.

Figure 2 - 1 Sketch map of vertical well and horizontal well fracturing [12]

These fracturing technology’s characteristics and applicability is different, detailed information

is shown in Table 2-2 below.

11

Fracturing Technology Technical Characteristics Applicability

Stage Fracturing Fracturing with several stages. Having high

technology maturity, widely used.

Vertical stack tight reservoir and the horizontal

well with multiple production layers

Riverfracing Treatment Simple fracturing fluid formulation, main

component of fracturing fluid is drag-reducing

water, to form a denser fracture network,

producing additional permeability, forcing the gas

in the reservoir to flow into the well with greater

ease, producing more gas from the reservoir.

Requires simple construction, lower cost, less

pollution on formation, limited sand carrying

capacity.

Medium depth (1500 - 3000m), natural fracture

system developed reservoir

Hydraulic Jet Fracturing Used to produce new fractures in different

directions and enlarge the fracture network to

enhance production. This technology locate

accurate, no requirement for mechanical seal and

saves operational time.

Barefoot well completion production well

Repeated Fracturing Reopens the fracture or redirects the fracture to

enhance oil recovery. Fracturing multiple wells at

the same time.

Well that has been developed and the capacity

decline production well.

Simultaneous Fracturing This is a simultaneous operation for multiple

wells, saving operation time, having a better

impact on the reservoir than fracture networks.

For reservoirs with large borehole density and

close well location.

Network Fracturing Using high displacement fracturing fluid during

fracturing, open natural fracture and form network

fractures. Improves reservoir permeability and

reconstruction achievement.

Low-permeability reservoir where natural

fractures are not developed

CO2、N2 Foam Fracturing Less reservoir damage and pollution, low

filtration, good sand carrying capacity, good for

shale gas desorption.

Water sensitive reservoir, shallow buried (<

1500m) reservoir and low pressure well

Large Hydraulic Fracturing Uses a large amount of gel, high cost for well

completion, causes more damage to the reservoir.

No special requirement for the reservoir, widely

applicable

Table 2 - 2 The technical characteristics and applicability of fracturing technologies [15]

12

2.1.3.1 Multi-fracture (fracture network) fracturing.

The fracture network fracking technique uses the relationship between the two horizontal

principal stress differences and the net pressure of the fracture expansion. When the net pressure

of the fracture extension is greater than the difference between the two principal stresses and the

tensile strength of the rock, a bifurcation fracture is produced (Figure 2-2). A plurality of

bifurcation fractures form a fracture network system. In the system the main fractures are the key

part of the network system. The bifurcated fractures may return to the original fracture azimuth

after extending a certain length from the main fractures. Finally, a vertical and horizontal fracture

network system is formed. This use of spatial reflection of a fracture with volume fracturing

creates a network and hence the name ‘fracture network’ technology [16].

The target of fracture network fracturing is a low to extra low permeability sandstone/shale

reservoir. The reservoir’s fractures only expand into a well control area because the permeability

perpendicular to the direction of the artificial fracture fold surface is poor. There is not enough to

provide effective vertical seepage resulting in low capacity or fast capacity decline challenges

after fracturing. Using the fracture network technique to form artificial multi-fractures

perpendicular to the main fractures increases the permeability of a reservoir, which results in

production gains.

13

Figure 2 - 2 Sketch map of fracture network fracturing [16]

Network fracturing relies on a large amount of liquid and high displacement creating high

pressure in fractures, opening natural fractures, extending natural fractures, and forming fracture

networks by injecting slick water. This reliable method uses fracture pressure control, tip screen

out fracturing and multi-section fracturing techniques for crosscut fractures in horizontal wells

[16].

2.1.3.2 Refracturing technology.

Refracturing means fracturing more than once on the same layer. After the first fracturing of a

section, two or more fracturing processes are executed on the same section. When the initial

fracturing treatment of shale gas wells is ineffective or the existing proppants are damaged due to

time relations, the result is a significant decrease in gas production. This is when refracturing

techniques can be effective. Refracturing redirects the fractures pushing the capacity of the shale

gas wells back to the initial state or even higher [12].

14

The refracturing technology is very effective for low permeability, natural fracture growth,

layered and heterogeneous formations and especially shale gas reservoirs. Refracturing can

reconstruct the linear flow from the reservoir to the borehole and induces new fractures at the

bottom of the reservoir. The result is to increase the number and space of fractures and increase

the capacity of an operation well.

The determining factor for achieving a good outcome when using repeated fracturing of shale

gas is fracture turning. Repeated fracturing is not a new fracturing technology. It is a common

process in fracturing operations and the key lies in the selection of the candidate wells. In

fracturing, application of a chemical plugging agent has the impact to temporarily plug the

fractures previously generated in sand seams. The result is to change the static bottom hole

pressure, fracturing fluid steering in the formation and forming new fractures with different

directions compared to the previous fractures. It also opens new channels in a reservoir [14]. A

wide range of gas reservoirs that are not affected by fractures can be connected by this network.

According to statistics, refracturing can increase shale gas production by $3.53-7.06 /103m3. It

can increase the final recovery ratio of a shale gas well by eight to ten percent and the

recoverable reserves are increased by 60 percent. Refracturing restores productivity in low yield

wells, but it is also used to increase the flow in wells with higher capacity. Refracturing in

vertical wells re-perforates the original production layer and the injected fracturing fluid volume

is increased by at least 25 percent more than its initial hydraulic fracturing. The recovery factor

is increased by 30-80 percent [17].

15

2.1.3.3 Simultaneous fracturing technology.

The simultaneous fracturing of two or more matched wells is called the simultaneous fracturing

technology [12]. This is a key technology developed over the years while developing the Barnett

shale reservoir formation. Simultaneous fracturing uses the shortest well-to-well distance to

make the fracturing fluid and proppants migrate from well to well under high pressure (Figure 2-

3). The expected outcome is an increase in the network density and surface area of fractures.

Utilizing the advantages of inter-well connection, the width and intensity of fractures in the

working area are increased as are natural fractures. Simultaneous fracturing began with the

simultaneous fracturing of two horizontal wells at approximately the same depth but today there

are three and four wells simultaneously fractured. Simultaneous fracturing has an obvious

impact on the short-term capacity of shale gas wells. There is little environment impact in the

working area. The completion rate is fast and simultaneous fracturing provides strong cost saving.

Simultaneous fracturing is a common fracturing technology used in the middle and late stages of

shale gas reservoir development [18].

Figure 2 - 3 Sketch map of simultaneous fracturing

16

2.1.3.4 Horizontal well staged fracturing technology.

A horizontal well staged fracturing technology uses a packer or other material to achieve a slug

[12]. A horizontal well can be fractured with one section at a time fracturing gradually and

forming several fractures on the horizontal well. Generally, staged fracturing can be divided into

three parts: 1) pumping a pad fluid into a reservoir; 2) pumping a fracturing fluid with a specific

concentration of proppants into the reservoir; 3) using the fracturing fluid containing a higher

concentration of proppants than previously used to push for the desired requirement. This

technology is effective in a single reservoir area or in a reservoir with a few unconnected areas.

The operator can use a bridge plug, coiled tubing, or a packer and isolation system to shorten the

production time and reduce costs [19].

Initially, fractured sections of horizontal wells employed only one or two segments, but now

there can be a dozen or more. Extensive use of the staged fracturing technology of horizontal

wells makes the original low or no shale gas flow reservoirs have the potential to increase in

value because it extends the shale gas development in horizontal and vertical directions. This is

the critical technology development responsible for the rapid development of shale gas recovery

in the USA.

2.1.3.5 CO2 foam fracturing.

The CO2 foam fracturing technology is based on the unique physical and chemical properties of

CO2. It has been used in oilfield development since the 1960s in CO2 flooding and CO2 fracturing,

17

all providing a positive impact on recovery. The CO2 fracturing technology is a fracturing

process using CO2 as an additive to a fracturing fluid or sand carrying fluid. The CO2 content in

the fracturing fluid system has three common structures: CO2 incremental fracturing, CO2 foam

fracturing and liquid CO2 fracturing [20,21]. CO2 foam fracturing is based on a CO2 gas-liquid

two-phase foam fluid. By optimizing the quality of CO2 foam and a fracturing fluid formula, and

the amount of the fluid in wells the damage to a reservoir is reducing, which serves to increase

capacity. The relationship between CO2 foam quality and viscosity of fracturing fluid is shown in

figure 2-4. It can guide the selection of fracturing fluid composition for specific conditions.

Foam fracturing is a relatively new process suitable for low pressure and low permeable water

sensitive formations. CO2 foam fracturing has several advantages when compared to traditional

hydraulic fracturing: 1) solid proppants with only a small amount of fracturing fluid in the

reservoir, 2) it forms a block layer on a fracture wall, decreasing the filtration rate of the

fracturing fluid and reducing the filtrate loss and the reservoir damage, and 3) it has a better

flowback rate [22].

Figure 2- 4 Relationship between CO2 foam quality and viscosity of fracturing fluid [21]

18

2.1.3.6 Riverfracing treatment.

The riverfracing (also called slickwater fracturing or drag reduction water fracturing) technology

involves the addition of small amounts of additives such as surfactants, stabilizers and drag

reducing agents into clear water. The intention is to get the fracturing fluid carrying less

proppants and then the fracturing operation is carried out with a large volume of liquid resulting

in a large displacement. The process of riverfracing is: 1) pump ‘rock acid’ to clear a wellbore

area that may have been blocked by a drilling fluid; 2) inject water with some proppants into

natural fractures to make fractures extend; 3) remove the proppants from the well. Riverfracing

uses natural fractures in a reservoir, injecting the fracturing fluid into the natural fractures and

inducing fractures in the reservoir. During the fracturing process, debris falls into fractures and

acts as a proppant with the injected coarse sand, causing the fractures to remain open after

scouring.

The advantage of riverfracing is that it requires less additive in a fracturing fluid, causing less

damage to the reservoir and achieving a higher capacity compared to a gel fracturing fluid. The

fracturing fluid in riverfracing is mainly water, leaving behind less residue after the fracturing

operation which is more conducive to the extension of fractures [23]. This technology achieves a

good result in the low permeability gas reservoir reconstruction. Lower costs can save the

producer up to 30 percent and that saving is complimented by riverfracing being a cleaner and

thus a more environmentally respectful process.

2.1.3.7 Hydrajet fracturing.

Hydrajet fracturing (HJF) is a hydraulic fracturing technology using high speed and pressure ore

carrying sand during perforation to open access between a reservoir and a well. This technology

19

is a stimulation treatment including perforation, fracturing and isolation. It has unique

positioning, there is no requirement for a packer and it uses jetting tools that are on an operating

tool string. This arrangement forms one or several injection channels by a hydraulic action. The

technique can achieve multi-section fractures using only one tool string. The advantage of HJF is

not limited to the horizontal well completion method. The fracturing process is achieved in both

open hole and other completion methods. The disadvantage is that it is restricted by well depth

and sand-carrying capacity. The HJF technology is best for shale reservoirs with low pressure,

low capacity and low permeability [24].

2.1.3.8 Summary.

The desired outcome from fracturing is to reconstruct a shale reservoir. The selection and

application of a fracturing technology is based on the geological condition of a reservoir, the

minerals content and physical properties. Each fracturing technology in use has a different

preferred environment for application to achieve the maximal results. During the fracturing

procedure, the content of a fracturing fluid should change based on the mineral content and

physical properties of the reservoir to refine the permeability of the reservoir and reduce the

damage to the reservoir.

2.2 Literature Review of Flowback Technology

2.2.1 Effect of research on fracturing and flowback to exploit shale gas formation.

2.2.1.1 Enhanced oil recovery factor.

Fracturing and flowback are the primary exploitation technologies currently used by industry to

recover shale gas. The best method to produce shale oil and gas is flowing back a fracturing fluid

20

to drive or bring shale oil and gas to the surface. The objective in conducting this research is to

optimize fracturing and flowback to enhance flowback effectiveness of the fracturing fluid.

When flowback effectiveness is high, more fracturing fluid flows back from the formation

bringing more shale oil and gas with it achieving enhanced oil and gas recovery.

2.2.1.2 Decrease reservoir damage.

When a fracturing fluid is used to fracture a reservoir, fluid residual is left behind in rock layers.

This is a product of the flowback not conducting completely and it can cause reservoir damage.

That reservoir damage can decrease formation permeability and negatively impact follow-up

exploitation. The objective of this research is to study the fracturing and flowback technologies

to enhance a fracturing fluid flowback rate and to decrease the residual in a reservoir and the

damage to the reservoir.

2.2.1.3 Cost saving.

Different industry materials are used widely in a fracturing technology. The research will also

consider how to reduce costs while reducing the environmental impact. The goal will be to

identify the fracturing fluid with the best effect, lowest cost and least damage to the reservoir. At

the same time, research on a fracturing fluid and the role of recycling has the potential to

decrease costs during the exploitation of shale oil and gas reservoirs.

21

2.2.2 Main technology of flowing back.

There are two methods used to enhance a flowback rate. One is a physical method and the other

is an injection method. During injection a fracturing assistant fluid changes the reservoir

permeability, surface tension and wettability. The fracturing fluid then flows back from the

reservoir with greater ease. The flowing back technology to use is dependent on different

geological characteristics because the characteristics are known to enhance a flowing back rate.

In the table 2-3 below, I sum up the characteristics and applicability of common flowback

technologies which will further introduce in the text below to see the difference of each flowback

technology.

Flowback

Method

Flowback Technology Technical Characteristics Application

Cleanup

Additive

method

Liquid nitrogen cleanup A cross-linking technique that adds

nitrogen into fracturing fluid, forming a

homogeneous foam jelly to further

Water sensitive reservoirs

22

distraction reservoir. After fracturing, the

nitrogen released from fracturing fluid will

push the breaking glue out of the reservoir.

Wettability reversal agent

cleanup

Changes the reservoir’s wettability through

surface adsorption to enhance flowback

rate and oil/gas recovery.

Widely used in conventional

and unconventional oil/gas

development

Fiber sand control cleanup Adds a fiber material into sand carrying

liquid and this is injected into the reservoir.

Fiber helps with holding fractures and

preventing proppant flowback from the

reservoir.

Widely used

Optimized blowout cleanup Used with liquid nitrogen injection, no shut

in after fracturing, using big glib during a

rapid blowout to achieve high efficient

flowback.

Water sensitive reservoirs

Physical

method

Microwave excitation Microwaves are used for shale reservoir

excitation, heating residual fracturing fluid,

and/or generating steam blowout with gas.

reservoirs that have low

fracturing fluid flowback rate or

have water lock phenomenon.

Ultrasonic excitation Based on the coupling results in

micromechanical vibration, cavitation

effect and heat effect

Useful for most shale gas

production well, especially for

those that have clay swell and

migration damage.

Table 2-3 The technical characteristics and applicability of common flowback technologies

2.2.2.1 Liquid nitrogen (or CO2) fracturing assistant.

A liquid nitrogen fracturing assistant technology uses a delay crosslinking technology to inject

nitrogen/CO2 to form a uniform foam jelly and open a formation. After fracturing, the fracturing

fluid flowback rate is enhanced by nitrogen or CO2 push back gel, breaking water out of the

formation to decrease the fracturing fluid damage to a reservoir. The advantages of liquid

23

nitrogen or CO2 fracturing assistant are: 1) nitrogen (or CO2) does no damage to the reservoir

and it is suitable for use in reservoirs with low permeability, 2) nitrogen (or CO2) foam is able to

control fluid loss and decrease fracturing fluid damage to the formation, and 3) nitrogen (or CO2)

foam has low water saturation making it suitable for use in a water sensitive reservoir [25].

2.2.2.2 Reverse wetting agent fracturing assistant.

Reservoir wettability is to expand or attach tendency of a fluid when another immiscible fluid

exists. Under certain conditions, hydrophilic and hydrophobic can mutually transform on solid

surfaces. The reverse wetting agent changes the reservoir wettability through surface absorption

enhancing reservoir exploitation efficiency.

There are three types of surfactant of reverse wetting in a field: 1) cation surfactant, alkyl

trimethyl ammonium bromide is widely used, 2) anion surfactant, mainly polyoxyethylene alkyl

alcohol ether sulfate or sulfonate, 3) nonionic surfactant, mainly polyxyethylated alkylphenol

[26,27]. Reverse wetting agent application is helpful in conventional and unconventional

exploitation making it widely applied.

2.2.2.3 Fiber sand control.

Flexible fiber is mixed with a sand-carrying fluid and then injected into a reservoir. A compound

propping agent is formed in an artificial fracture. The propping agent is a primary structure and

the fiber is a wild phase. There are several mechanisms used to ensure that the fiber stabilizes a

propping agent packing layer. Every fiber and propping agent contact each other. A space grid

structure is formed by the contact pressure and the force of friction enhances the cohesion of the

24

propping agent. The propping agent is stabilized in the original place and a fluid can pass

through it freely. Propping agent flowback can be prevented [28].

There is less impact from a formation fluid, bottom hole temperature, fracture closure pressure

and well shut down time when fiber sand control is implemented. Fiber sand uses physical

stabilization mechanisms rather than a chemical curing reaction. The fiber sand control is a

compatible additive with fracturing fluids, crosslinking agents and gel breaking agents [29,30].

2.2.2.4 Optimizing flowback.

Optimizing flowback normally needs to consider co-injection of liquid nitrogen. To utilize liquid

nitrogen assisted drainage, wells do not shut in but drain immediately after fracturing. Fractures

are forced to be closed and a large nozzle relief is quickly implemented to ensure effective

flowback. The nozzle should be optimized for this process. The design order of the nozzle is:

Φ4-6mm nozzle control under 0.5h, Φ8-10mm nozzle control in 0.5 – 1h, and a nozzle greater

than Φ10mm after 1h [31].

2.2.2.5 Physical method.

When shale gas wells use hydraulic fracturing, the fracturing fluid flowback is impacted by the

expansion of the clay mineral when it meets water. This causes damage to a formation, which

decreases the gas phase permeability, and thus the extraction of the shale gas is negatively

impacted.

25

The physical method of enhanced oil recovery after shale gas well fracturing is a technology that

implements physical methods to form a physical field (a mechanical force field, electromagnetic

field, sound field, light field or thermal field). This secondary physical change enhances the

target formation with the chosen fracturing treatment. The physical method addresses the

damage problem created when expanding clay minerals block pores and the residual fracturing

fluid creates a water lock phenomenon. The physical method can increase shale gas production

by establishing an effective permeability and reservoir temperature for the shale rock to fracture.

The most common physical methods applied in a shale gas well after fracturing are the

microwave stimulation and ultrasonic stimulation technologies [32].

2.2.2.6 Microwave stimulation technology.

The microwave stimulation theory indicates that a microwave is an electromagnetic wave with a

frequency between 300MHZ to 300GHZ. It has the ability to pass through an insulator and

radiate energy into material with dielectric properties. There are three different types of

interactions between materials and microwaves. The first is ‘reflex of conductor’. The second is

the ‘transmission effect’ of an insulator (direct transmit through a vacuum insulator). The third is

the ‘adsorption of a dielectric medium’ [33]. Electromagnetic energy converts to internal energy

of a dielectric medium when microwaves meet the dielectric medium. At the micro level, the

internal molecules have intense thermal motion. Temperature increases at the macro level. When

this occurs, the microwave stimulation technology is used to stimulate a shale rock reservoir. The

temperature of the reservoir rock, shale gas and the residual fluid after fracturing rises upward

because they all belong to the dielectric medium and can absorb electromagnetic energy from

microwave energy. This process can accelerate desorption of shale gas in the adsorption state

26

while enhancing gas production. On the other hand, when the residual fracturing fluid is heated

up, it is released with the shale gas as a vapour phase. This process is effective in shale gas wells

with poor performance due to fracturing fluid flowback and water lock phenomenon [34].

Microwave stimulation is different from a hot water injection or steam injection flowback

method. Hot fluid injection uses heat conduction to reduce desorption and increase reservoir

pressure in super-low permeability shale reservoirs. The injected hot fluid blocks pore media and

decreases the effective permeability of the gas phase.

2.2.2.7 Ultrasonic stimulation technology.

The ultrasonic stimulation technology theory uses a sound wave frequency over 20KHZ. This

high frequency can spread through many different media and travel a long distance. The sound

intensity is in positive proportion to the frequency squared. Ultrasonic stimulation creates a

significant sound pressure on the media particles. Ultrasonic can generate a mechanical or

thermal physical effect, including micromechanical vibration, a cavitation effect and a thermal

effect. The theory of the ultrasonic stimulation technology is based on a mechanical wave

medium such as reservoir rock, shale gas and residual water; they can convert the mechanical

energy from ultrasonic into their internal energy in the process of ultrasonic wave spread. The

internal energy heats up a reservoir from the cavitation effect and friction from the vibration of

residual water in porous media. Closed micro cracks from a slippage effect can be reopened by

powerful ultrasonic stimulation at a right frequency. The ultrasonic wave has a micromechanical

vibration effect that reopens the closed micro cracks. Ultrasonic stimulation is also useful in

shale reservoirs where it can be applied to expand the impact of clay mineral particles and a

27

migration effect. The ultrasonic waves break particles when energy from the cavitation effect of

water in the clay mineral particles gets released. This is effective in removing a plug and

reducing the reservoir damage caused by clay mineral particles that are blocking pores [35,36].

The ultrasonic stimulation technology is useful in most shale gas wells, but it is especially good

to apply in shale gas wells that have been damaged by a clay mineral expansion and migration

effect. The process does not cause further damage and can heat a reservoir up.

2.2.2.8 Summary.

Using a physical field stimulation technology can solve water locking phenomenon causing poor

performance of fracturing fluid flowing back after fracturing and damage by a clay mineral

expansion and migration effect. These changes enhance production. The microwave stimulation

technology uses a thermal effect from microwave adsorption to raise temperature; desorption of

adsorption state shale gas occurs and shale gas production is improved. The ultrasonic

stimulation technology is useful for reservoirs damaged by clay mineral particle migration.

When water from clay mineral particles releases energy from the cavitation effect, some of

particles are broken and plugs can be removed.

2.3 The Effect of Reservoir Properties on Flowback Procedure

A flowback procedure is influenced by many factors: a well completion method, a hydraulic

fracturing method, a hydraulic fracturing treatment, and reservoir properties. This thesis explores

the impact of shale gas reservoir properties on a flowback procedure; all other factors will be

ignored.

28

The geologic characteristics of a shale gas reservoir that are considered in this thesis are:

lithology, reservoir properties, reservoir pressure, natural fractures and rock wettability. These

characteristics will have different influences on flowback.

2.3.1 The effect of reservoir lithology on flowback procedure.

A shale gas reservoir contains approximately two to twenty-five percent organic matter. The rest

of the components are primarily inorganic matter: clay minerals, silica minerals and carbonate

minerals [37,38]. A rock is classified according to its physical properties of silica and calcareous

minerals, and clay minerals as brittle minerals or clay minerals (Table 2-4). The content of these

minerals plays a role in defining the reservoir quality, gas content and reservoir development.

Index Basin and

Barnett

Longmaxi Liulongdong

Vitrinite reflectance（%） 2.2 2．4-3．3 1.87~2.76

TOC/（%） ›3 1．88-4．36 0,85~3.5

Silicon content/（%） 55 41 66（including feldspar）

Clay content/（%） ‹40 19.1 17~32

29

Table 2- 4 Comparison between the lithology of Longmaxi, Jiulongdong formation in Sichuan

Basin and Barnett Shale in America [39]

2.3.1.1 The effect of brittle minerals on reservoir quality and hydraulic fractures.

The previous research indicates that the type and content of minerals determine the hardness and

brittleness of rock. The brittleness of shale determines the feasibility of a fracture network.

Rickman et al. [40] used well logging data to calculate the Young modulus and Poisson ratio.

Then they used a cross plot of the Young modulus and Poisson ratio to characterize the

brittleness of shale. A decreasing Poisson ratio and an increasing Young’s modulus indicate that

the rock is brittle. The shape of network fractures becomes more complex as the brittleness

increases. The more complex the network is, the greater the volume of reformed rock and the

surface area that is exposed by fractures.

Shale is composed of quartz, feldspar, calcite, silica and calcareous, all brittle minerals that break

easily. In shale gas reservoirs the brittle minerals have two positive impacts. When a reservoir

has many natural fractures due to the brittle minerals it provides a good environment for free gas

to be stored and brittle shale gas reservoirs tend to have a network of fractures.

Marine clastic rocks also increase the brittleness of the formation in a reservoir. The largest

feature of the Fuling gas field is the marine debris, which increases the reservoir fragility, greatly

improving the fracturing impact (see the analysis in Chapter 5).

30

2.3.1.2 The effect of clay minerals on reservoir quality and flowback procedure.

Clay is the main component of mud shale and it is widely distributed in a reservoir with unique

crystal structure and properties. The clay content impacts a flowback procedure. The common

minerals found in clay are kaolinite, illite, chlorite, and montmorillonite [41]. The content of clay

varies dramatically and even clay found in a single area will have variations in the content

structure. Clay is not stable and may change minerals based on depth, temperature and a pH

value.

A shale reservoir containing large amounts of clay minerals will impact permeability and the

ability to store oil and gas. Clay natural fractures are easily formed in the clay minerals and this

makes them a good candidate for fracturing. The imbibition process occurs in clay content and

the clay reacts readily with other fluids; this action is not good for fracturing and it has a negative

impact on the flowback procedure and production [42,43,44].

2.3.1.2.1 The effect of clay minerals on reservoir quality.

The reservoir quality is determined by the type, content and distribution of clay. In a shale gas

reservoir, the grain size of clay is small, the clay is macro porous and mesoporous, and this

allows the adsorbed gas to be stored in these nanoscale pores increasing the storage of natural

31

gas [45-48]. The type of pores in the clay mineral content are classified as: 1) micro pores, 2)

pores which are formed by a flocculation process, 3) the space between clay and clay, and 4) the

space between clay and other minerals [49].

Natural gas in shale reservoirs is stored as free gas in both mineral pores and natural fractures. It

is also absorbed on shale surfaces, where the adsorbed gas can range from 20 to 80 percent [50].

Ross et al. found that the adsorbed gas is primarily stored in microporous and mesoporous

regions of the organic content and clay content. The free gas is primarily stored in macro pores

and fractures. As the content of the clay increases, the porosity, the number of micro pores

(Table 2-5), and surface areas increase, increasing the gas adsorption ability [51,52]. The

adsorption ability of methane is proportional to the surface area of the clay content [53]. There

are different conclusions in the literature on the adsorption ability of same type clay minerals

[54,55]. This discrepancy may be due to the microporous and surface areas of the clay which is

not only related to the type of clay but also determined by the grain size, clay structure, mode of

origin and maturation. Clay with different modes of origin, development of micro pores and

communication will be different and the adsorption ability of methane will not be the same.

Although clay has a weaker adsorption ability compared to total organic content, the amount of

clay can make up for the weaker adsorption because of the positive impact of the adsorbed gas in

a shale gas reservoir.

Clay type Variation（%） Average（%） Standard Deviation Sample

Kaolinite 15—61 43 10．6 52

32

Chlorite 44—58 51 4．2 10

Illite 47—76 63 10．3 5

Table 2-5 The micro-porosity of clay minerals --From Hurst and Nadeau (1995) [56]

The methane adsorbing capacity of shale decreases under a water balance condition. Water can

fill throats and stop the gas flow due to the wettability of the clay. The water molecules hold the

adsorption position and prevent the gas molecule adsorb on rock, reducing the effective

adsorption surface area for the shale gas [57].

The impact of clay minerals on reservoir quality are summarized below:

1) Clay minerals influence the formation and occurrence of organic content in a

reservoir, which is good for the concentration of organic content and hydrocarbon

generation.

2) A high content of clay minerals provides a good condition for the development of

original micro pores and fractures, which afford space in the reservoir for shale gas.

3) The shale adsorption ability of methane is impacted by the content of clay minerals.

The occurrence of methane in clay minerals is determined by its development of

micro pores and a surface area, and the different types and sizes of clay minerals

which dictate the adsorption ability.

4) Clay minerals have a weak adsorption ability of methane with water content.

2.3.1.2.2 The effect of clay minerals on reservoir damage and flowback procedures.

33

Clay minerals have unique structures, components and properties. Illite and smectite have a

multilayer structure and they are easily broken. Kaolinite has good water adsorption and

dispersion properties. Chlorite has strong adsorption and cation exchangeable properties.

Wellbore fluids flow into a formation during the drilling, well completion, formation acidizing,

hydraulic fracturing or well development processes causing the formation of water and creating

velocity and acid sensitivity in a reservoir. These all damage the formation, reduce the

permeability, affect flowback and reduce productivity [58].

The damage of illite and a mixed layer of illite/smectite to a reservoir – the water and velocity

sensitivity is because swelling clay is sensitive to the salinity of the foreign fluid. The swelling

clay contains exchangeable cations and other polar molecules that swell and disperse when they

interact with fresh water. When this type of clay is located at throats, the clay swelling reduces

the radius of the throats and reduces permeability. The dispersion can also plug the throats,

reducing permeability and creating a negative impact on the flowback procedure. A low

mineralization medium has a big impact on the dispersion of clay minerals without kaolinite and

illite [58].

Chlorite is damaging a reservoir because of acid sensitivity. Chlorite commonly contains cations

such as 𝐹𝑒3+,𝐹𝑒2+, 𝑎𝑎𝑎 𝑀𝑔2+. When they react with acid fluids they readily

form 𝐹𝑒(𝑂𝑂)3 𝑎𝑎𝑎 𝑀𝑔(𝑂𝑂)2. As the pH in the clay increases (pH > 5.3),

𝐹𝑒(𝑂𝑂)3 𝑎𝑎𝑎 𝑀𝑔(𝑂𝑂)2 are formed, causing colloidal precipitation, plugging pores, reducing

permeability and negatively impacting the flowback procedure [58].

34

Kaolinite damages a reservoir, impacting the water and velocity sensitivity. Kaolin particles are

small and scattered when they interact with the fluids in a reservoir. These particles are

suspended in the fluids, plug pore throats and reduce permeability. The clogs are related to the

size, number of particles and the radius of throats. The pores can be unclogged as the flow

direction changes or the pressure decreases. The particle migration is sensitive to the velocity of

the fluid flow generally reducing permeability as the velocity of the fluid flow increases.

Pittman et. al. (1986) [59] determined that kaolinite in sandstone is stable in two percent salt

water and the permeability of the sandstone is stable. The permeability decreases as fresh water

is injected. Fresh water injection causes kaolinite to disperse and migrate reducing the

permeability, as the content of salt in water reduces.

Clay Type Sensitivity Potential Impact

Illite Water sensitive Particle migration plugging micro pores

Chlorite Acid-sensitive Fe(OH)3 precipitate plugging micro pores

Kaolinite Water sensitive, salinity sensitive, Particle migration plugging micro gap

35

velocity sensitive , alkali sensitive

Illite mixed layer Water sensitive, salinity sensitive, velocity

sensitive, alkali sensitive

Expand, dispersed plugging micro gap

Table 2-6 Sensitivity of clay minerals

The physical properties of clay minerals are widely presented in a reservoir. During a flowback

procedure, a working fluid will flow into the reservoir and impact the flowback result. Before

determining a fracturing fluid, the reservoir lithologic character must be considered. The clay

mineral composition, the damage caused by the foreign fluid and formation sensitivity must be

known to achieve the optimal result.

The evaluation of shale sensitivity includes the velocity strength of particles under a high flow

rate, the water sensitive strength of the foreign fluid, the salinity sensitive strength of the water

sensitive formation, the acid sensitive strength and the alkali sensitive strength (Table 2-6).

These types of sensitivity and sensitive strength are determined by the component and content of

the clay minerals.

Velocity sensitivity describes how unconsolidated clays and particles disperse, migrate and pile

up at narrow throats. These actions impact the rock permeability. A study of velocity sensitivity

considers water sensitivity, acid sensitivity, salinity sensitivity and alkali sensitivity to determine

the critical velocity. Velocity sensitivity is dependent on the velocity of the foreign fluid, the

36

radius of throats and the sensitive strength of the minerals. The consolidated clay is the main

component of shale and the velocity sensitivity is related to clay swelling and migration. The

pores of shale are small and sensitive to fine migration. The less kaolinite contained in the clay

minerals, the worse the velocity sensitivity is [60-64].

Under the original reservoir condition, clay minerals are steady with formation water. Water

sensitivity occurs when a foreign fluid from drilling, well completion, water flooding and low-

salinity fluids invades a reservoir. This addition of water causes the clay minerals to swell,

disperse, migrate and even pile up at throats reducing permeability. The water sensitivity index

of shale indicates the degree of permeability damage caused by the foreign fluids. The damage of

permeability is related to the type and content of clay minerals and the structure and radius of

throats. There is a good connection between the montmorillonite crystal layers. The anion with a

small radius on the clay surface is easy to escape and diffuse to form an electric double layer.

Negatively charged layers repel each other allowing water to invade the layers and increasing the

distance between layers 10 to 20 times. Montmorillonite readily reacts with the foreign fluids.

Shale pore throats are small and complex, so clay swelling and clogging causes damage to the

rock permeability. The most water sensitive clay mineral is montmorillonite followed by mixed

clay layers, then illite and then any others [60-64].

Acid sensitivity occurs when acidizing fluids flow into a reservoir and react with acid sensitive

minerals. The precipitate and released particles plug throats and reduce permeability. Chlorite

has the strongest acid sensitivity in clay minerals. It commonly contains 𝐹𝑒3+,𝑀𝑔2+ and other

37

cations. When it meets acidizing fluids, the pH increases and forms 𝐹𝑒(𝑂𝑂)3,𝑀𝑔(𝑂𝑂)2 and

other precipitates that reduce permeability [60-64].

Alkaline sensitivity occurs when alkaline fluids invade a reservoir, reacting with clay minerals

and forming precipitates that reduce reservoir permeability. There are three kinds of influences

when alkaline fluids invade into the reservoir: 1) alkaline fluids react with cations such as

𝐹𝑒3+ and 𝑀𝑔2+,form precipitates and plug pores, 2) the anion 𝑂𝑂− absorbs on the clay surface

and negatively charged layers repel each other causing the clay to swell reducing permeability,

and 3) alkaline minerals such as quartz and kaolin dissolve in the alkaline fluids and form silicic

acid precipitation [60-64].

Salinity sensitivity occurs when the formation water is decreased or increased by an invading

fluid. The clay minerals swell, shrink, disperse, migrate and plug pores, all reducing permeability.

2.3.2 The effect of reservoir properties on flowback procedure.

The reservoir properties that are considered are porosity, permeability, a natural fracture system,

and a brittleness index. Permeability and porosity are the main parameters used to evaluate

seepage characteristics of a reservoir. Unconventional source rocks usually have low porosity

and permeability. Some reservoirs may have good porosity but low effective porosity, small pore

spaces and poor connectivity. To enhance oil recovery, the hydraulic fracturing technique is

necessary. As the network of fractures forms, the oil and gas can flow to wellbore more freely.

During a flowback procedure, the capillary force is one of many resistances impacted by the

38

radius of pores. The smaller the radius, the larger the capillary force, the stronger the imbibition,

and the worse the flowback result.

The index of brittleness can be used to describe the difficulty of fracturing and the complexity of

fracture networks [65]. The index of fracturing is based on elastic modulus and Poisson’s ratio;

rock with large elastic’s modulus and small Poisson’s ratio have a high brittleness index. The

rocks with a high brittleness index are usually hard and brittle, contain more natural fractures and

are sensitive to hydraulic fracture treatments forming complex fracture networks. The measure of

a brittleness index is based on a qualitative and quantitative analysis. A qualitative analysis

determines the mineral composition. Using X-ray diffraction (XRD) techniques the composition

of rock can be determined. By creating a ternary plot, the mineral composition, including

brittleness minerals and clay minerals, can be established. Elemental capture spectroscopy (ECS)

and natural gamma spectroscopy (NGS) data can indicate the content of clay, quartz, feldspar

and pyrite. The data reconciliation, distribution of the clay mineral and brittleness mineral can be

analyzed. A quantitative analysis is based on elastic modulus and Poisson’s ratio, using

calculations with 0.5 weight for each factor [66].

The formation brittleness index is dependent on the content of the brittle minerals. If the content

of brittle minerals is high (due to the properties of brittle minerals), the formation will contain

more fractures and pores. Fracture stimulation will have a positive impact on performance in this

type of formation because it is easy to form fracture networks and flowback fluids easily flow

back to the ground. The lower content of clay reduces the surface hydraulic force and permeation

hydraulic force in reservoirs. The resistance of flowback fluids is small and flowback fluids flow

39

easily back to the ground. The formation with a high content of clay minerals contains fewer

fractures and pores. The effect of hydraulic fracturing is not strong because the formation can be

distorted rather than fractured and fracture networks have hard time forming. When fracturing

fluids flow into the formation, the hydration of clay minerals plays a role. Some of the fluids will

be absorbed by clay minerals reducing the efficiency of a flowback procedure. The clay minerals

swell and reduce the volume of fractures and the radius of pores by absorbing fracturing fluids.

The result is the resistance of a capillary force increase reducing the efficiency of a flowback

procedure.

2.3.3 The effect of reservoir pressure on flowback procedure.

The effect of reservoir pressure on flowback relates to the stage of the flowback procedure.

There are three identified stages. The first stage occurs when fracture pressure is higher than the

formation pressure and flowback is impacted by the difference in pressure. During the second

and third stages, the fracture pressure is less than the formation pressure. The fracturing fluids

are driven by the formation pressure. In the second and third stages the fracture pressure is

restricted by the current technology. The low reservoir pressure means that the first stage will be

the main stage during the flowback procedure and the result will be better. The reservoir pressure

tends to be dependent on the depth; as the depth increases, the reservoir pressure also increases.

Table 2-7 and 2-8 shows the relationship between reservoir pressure and output for different

reservoir.

40

Basin Shale Area Thickness

（m）

TOC

(%）

Formation

pressure

coefficient

Daily output of

single

well(103m3)

Abba La Cilla Marcellus 15-305 3.0-12.0 1.1-1.4 7.1-76.5

Michigan Antrim 21-36 0.3-24.0 0.81 0.1-1.4

Gulf coast Hsynesville 60-90 0.5-4.0 1.6-2.0 14.2-70.8

Fort Worth Barnett 61-91 4.5 0.9-1.2 2.8-48.1

Sichuan Jiaoshiba 38-80 2.1-6.3 1.35-1.55 11.6-54.7

Sichuan Changning 30-60 1.89-5.3 1.25-2.0 1.9-20.0

Table 2-7 Comparison between Longmaxi Formation and North America gas shale [67]

Type Pressure Coefficient Daily Output of Single Well（103m3）

Atmospheric area 0.85-1.2 <2.5

Overpressure area 1.2-1.5 2.5-7.0

Ultrahigh pressure area >1.5 7.0-43

Table 2-8 Relationship Between Shale Gas Production and Pressure Coefficient for Longmaxi

Formation [68]

41

2.3.4 The effect of fractures on flowback procedure

Shale has extremely low permeability and porosity; the matrix pores develop very little and most

are capillary pores with low permeability. Some shale gas reservoirs contain well-developed

fractures. The reservoir conditions are dependent on the lithology and sedimentary condition

providing favorable conditions for shale gas development. The existence of fractures improves

the permeability of mud shale and the effect of fracturing stimulation. The existing fractures also

increase the space for gas to store in the reservoir [69].

When there are natural micro fractures and the fractures are filled with carbonate cements the

efficiency of hydraulic fracturing and the permeability of shale improve creating channels for the

gas to flow to wellbore [70,71]. It is the combination of these factors that sets the environment

for fracturing and that determines the value of reservoir exploration and development.

Natural micro fractures exist in the mud shale. Micro fractures are narrow in width, and some are

even closed, sealed by calcite and arranged as an echelon. Narrow closed fractures do not

contribute to productivity. It requires fracturing stimulation to reopen the closed fractures and

enhance the recovery of shale gas [72]. When mud shale narrow and closed micro fractures are

fracked, the fracturing fluids can easily flow through fractures and break them increasing the

width, length and density of the fractures. The outcome is an increase in the efficiency of the

fracture networks.

Fractures filled or half full with carbonate cements do not make contribution to the porosity and

permeability of a reservoir, and they are not an obstacle during the fracturing. The contact

surface of carbonate cements and the reservoir tend to have a weak tensile strength. As the

42

pressure increases, the carbonate filled fractures will break again [73, 74]. The new fracture

networks connect with wells and gas spreads through the networks into the wells [75].

Large-scale width and length are described as large-scale natural fractures. These large-scale

fractures raise the partial permeability of a reservoir, but may have negative effects on the

hydraulic fracturing process. During hydraulic fracturing, large-scale natural fractures absorb

large amounts of a fracturing fluid and proppants, hindering the formation of new fractures.

The fracturing fluid spreads into upper and lower layers through natural fractures reducing the

pressure of fluid and the fracturing effect [76]. Large-scale fractures need to be systematically

analyzed before executing hydraulic fracturing to optimize the fracturing process and enhance

the effectiveness of a fracturing treatment.

2.3.5 The effect of wettability on flowback procedure.

Wettability is a basic parameter affecting the relative permeability of oil and water and thus a

flowback procedure. Fracturing fluids are classified as either water-based or oil-based. The

fracturing fluid performance is dependent on the reservoir rock wettability.

When the fracturing pressure is the same as the formation pressure, the fracturing fluids are

mainly driven by a capillary force. The rock wettability determines the displacement process. For

an oil-wet formation, the oil phase distributes on fracture walls and the water phase will

distribute to the centers of fractures. Since the water phase displaces the oil phase in this case,

the water-based fracturing fluid is recovered more than when an oil-based fracturing fluid is used.

When rock wettability is water-wet, an oil-based fracturing fluid is a more effective choice [77].

43

CHAPTER 3 CHARACTERSITICS OF SHALE RESERVOIR AND FLOWBACK

TECHNOLOGY

3.1 Shale Reservoir Characteristics

Shale reservoirs are classified by their sedimentary facies: marine, continental and marine

transitional.

3.1.1 Marine facies.

Marine facies shale reservoir main characteristics are widely distributed. The overall lithology of

a reservoir is stable, the mineral composition is singular, the heterogeneity is weak, organic

matter is rich with an average content of 1% to 5.12%, the thickness of the high total organic

content (TOC) rich shale reservoir is generally 20-180m, and the thermal evolution is at the stage

of pyrolysis gas generation (1%<Ro<5.2%). Matrix porosity and organic micro scale pores

develop in marine facies shale with porosity usually between 4-10%, providing a good reservoir

space. Marine facies shale has continuous distribution vertically and horizontally making them

suitable for large-scale multi-stage fracturing. Fracture networks form easily because the

porosity is relatively high. Flowback of a fracturing fluid occurs in these well-developed fracture

networks due to the brittle minerals and homogeneous clay minerals. Compared to other shale

gas reservoirs, developing marine facies shale reservoirs has a better success rate because of the

fracturing fluid flowback. The marine facies shale reservoirs have a high commercial

exploitation value in North America.

44

3.1.2 Continental facies shale.

Continental facies shale gas reservoir characteristics are a relatively small distribution, rapid

lateral lithology change, complex mineral composition, strong heterogeneity and thin thickness.

Porosity is usually between 2.5%-5% and the organic type is mixed.

It is difficult to carry out large-scale fracturing and form good fractures in continental facies

shale reservoirs. The economic development is challenged by the fracturing fluid flowback and

the best process is still in the exploratory stage.

3.1.3 Marine transitional facies shale.

Marine transitional facies shale is a transitional type between continental and marine facies.

Beside marine geology, it is also influenced by continental geology. Marine transitional facies

shale is usually interbedded with sandstone. The thickness of a single layer is small, but the

number of layers and accumulated thickness is large. The interbedded condition of the shale is

dependent on the sedimentary environment. A thin interbedded sandstone has a small impact on

a fracture network. Thick dense sandstone will influences the extension of a fracture network and

a fracturing fluid. Generally speaking, the difficulty of fracturing fluid flowback in marine

transitional facies shale is between marine and continental facies shales

45

Index Barnett

Formation

Longmaxi Formation Jiulongdong Formation

Vitrinite reflectance/（%） 2.2 2．4-3．3 1.87~2.76

TOC/（%） ›3 1．88-4．36 0,85~3.5

Silicon content/（%） 55 41 66（include feldspar）

Clay content/（%） ‹40 19.1 17~32

Porosity /（%） 4.5 4.8 2

Permeability /mD 2.5×10-4 1.96×10-3 2.25×10-13~1.48×10-7

Table 3-1 Physical property comparison between Barnett Shale, Longmaxi, Jiulongdong

Formations in Sichuan Basin [84]

Basin Shale Location

Formation Area/ 104km2

Thickness (ｍ)

ＴＯＣ (％)

Thermal Maturity Ｒｏ／％

Songliao Basin

Cretaceous Nenjiang Formation 7.5 100-150 0.7-10.0 0.4-1.1

Qingshankou Formation 9.2 50-609 0.5-5.4 0.4-1.3

Bohai Bay Basin

Paleogene Shahejie Formation 2.3 400-1200 0.8-33.0 0.3-1.8

Kongdian Formation 0.6-1.0 200-800 0.3-7.0 0.63-2.2

Ordos Basin Triassic Yanchang Formation 7.5 10-166 1.18-22.0 0.50-1.16

Sichuan Basin

Jurassic Ziliujing-Shaximiao Formation

15.2 40-180 0.4-1.6 1.0-1.87

Triassic Xujiahe Formation 14 50-1000 10.-4.5 1.0-2.2

Qaidam Basin

Neogene 1.0 200-560 0.29-1.81 0.45-0.6 Paleogene 0.92 300-600 0.4-3.85 0.8-0.9 Jurassic Shuixigou

Formation 10 300-850 0.8-40.0 0.4-1.36

Turpan Hami Junggar Basin

Triassic Baijiantan Formation 7.5 40-300 1-5.14 0.52-1.4

Permian 6.4 200-1250 1.73-34.42 0.54-1.8 Tarim Basin

Middle lower Jurassic

10 242-795 0.42-6.33 0.8-2.0

Triassic Huangshan-Taliqike Formation

12 550-800 0.4-7.9 0.8-2.25

Table 3-2 Organic-rich lacustrine shale distribution and geological features [78-83]

46

Basin or Region

Shale Location Formation

Area (104km2)

Thickness(m) ＴＯＣ(%)

Thermal maturity Ｒｏ／％

Bohai Bay Basin

Perma Carboniferous

Shanxi Formation 5.0 40-160 0.94-23.2 0.56-2.96

Taiyuan Formation 5.0 30-180 0.16-19.5 0.74-2.54

Yangtze Region

Permian

Longtan Formation 20-50 20-260 0.5-12.6 1.2-3.2

Liangshan Formation 10-30 5-20 1.0-7.0 1.8-3.2

Ordos Basin

Permo Carboniferous

Shanxi Formation 12.5 50-202 2.25-19.29 0.5-3.0

Taiyuan Formation 12 20-60 3.33-23.38 0.5-2.6

Benxi Formation 10 10-50 0.54-11.71 0.7-2.8

Junggar Basin

Carboniferous

Bashan Formation 7.4 60-250 0.4-28.94 0.55-1.72

Dishuiquan Formation 10 100-300 0.17-26.76 0.93-1.86

Table 3-3 Organic-rich shale reservoir distribution and their geological features [78,79]

3.2 Characteristics of Typical Shale Reservoirs Globally

Table 3-1,3-2,3-3,3-4,3-5 are the main properties for the main shale reservoir all over the world.

By comparing them we can obtain the influence of reservoir sedimentary facies.

America America America America America Canada China Shale formation

Barnett

Ohio

Antrim

New Albany Lewis

White Speckled Longmaxi

Basin Fort Worth Basin

Appalachian Basin

Michigan Basin

Illinois Basin San Juan Basin

Western Basin（WCSB）

Sichuan Basin

Region

Mississippi Devonian Devonian Devonian Cretaceous Cretaceous Silurian

TOC(%） 1.0-12

1.0-4.5

1.0- 20

1.0-25

1.0-2.5

1.0-11.9

0.5-4

Adsorption gas

40-60 50 70-75 40-60 60-85 -- --

Po（%） 0.6-1.6 0.4-1.3 0.4-0.6 0.4-1.0 1.6-1.9 Immature -post mature

2.0-4.5

Gas type Pyrolysis gas

Pyrolysis gas

Pyrolysis gas

Pyrolysis gas

Pyrolysis gas, Biogas

Pyrolysis gas

Pyrolysis gas, Dry gas

Table 3-4 Shale gas accumulation model

47

3.2.1 Fort Worth basin Barnett shale reservoir.

The Barnett shale reservoir in the Fort Worth basin, Texas is America’s representative success

case for shale gas production.

The primary sedimentary environment of Barnett shale is Mississippian marine facies continental

shelf. Barnett shale and its upper and lower adjacent layers are composed of different lithofacies.

Three lithofacies can be identified; they are thin bedded siliceous mudstone, thin gray mudstone

containing clay and massive gray matter argillaceous limestone. The main gas producing

formation is siliceous mudstone, consisting of small particles of matter. The thickness of the best

gas producing formation is 91-168m.

Carbonate rock content in Barnett shale is < 25%, quartz, feldspar and pyrite content is 20 - 80%,

and the clay content is also 20 - 80%. In Barnett siliceous mudstone the clay content is < 40%

and the quartz content is >50%. The total porosity of Barnett shale is 4 - 5% depending on the

buried depth. It is generally held that the greater the depth, the stronger the compaction and the

smaller the porosity. The permeability of Barnett shale is between 0.00007md and 0.005md.

48

Characteristic Appalachian

Basin Michigan Basin

Illinois Basin

Fort Worth Basin

San Juan Basin

Shale Ohio Antrim New Albany

Barnett Lewis

Time C D D D K2 Depth /(m) 610-1524 183-730 183-1494 1891-2591 914-1829 Thickness /(m) 91-610 49 22-31 61-300 152-579 TOC/（%） 0.5-2.3 0.3-2.4 1-2.5 1-4.5 0.45-2.5 Ro/(%) 0.4-1.3 0.4-1.6 0.4-1.3 1-1.4 1.6-1.88 Gas Content/(m3/t) 1.698-2.830 1.132-2.83 1.132-

2.264 8.49-9.905 0.425-2.3

Recovery/（%） 10-20 20-60 10-20 8-15 5-15 Single Well Reserves/104m3

425-1699 566-3398 425-1699 1416-4248 1699-5663

Total Resources/108m3

63713-70792 3398-5663 566-5663 ›7419 28317

Table 3-5 Characteristic parameters of major shale gas producing areas in the United States [85]

3.2.2 Wufeng-longmaxi shale formation in Sichuan Basin.

The Fuling shale gas field is the first large shale gas field in China. It is the largest shale gas

field in the world, excluding some American fields. The primary shale reservoir in the Fuling

shale gas field is the Wufeng-longmaxi formation, a sedimentary environment of deep/shallow

marine shelf. The thickness of the Wufeng-longmaxi formation is 250m-280m, the main

lithology is black carbonaceous graptolite shale and horizontal bedding is developed (Figure 3-2).

The brittle mineral content of the Wufeng-longmaxi shale is between 50.9 - 80.3%. The average

is 62.4%. This brittle mineral is made of mostly siliceous mineral content; maximum content is

70.6% and the average is 44.4%. Beside siliceous mineral, the brittle minerals also include

plagioclase and dolomite. Clay minerals of the Wufeng-longmaxi shale are illite, chlorite and

illite montmorillonite mixed. These have a low total content between 16.6 - 49.1%, with an

average of 34.49%.

49

The porosity of the Wufeng-longmaxi shale is 1.17 - 8.61%, and the average porosity is 4.87%

characterized by low-medium porosity. The vertical permeability of the reservoir is far below the

horizontal permeability. The vertical permeability is generally lower than 0.0003md with an

average of 0.0001539md. The horizontal permeability at the same depth tends to be higher than

0.0003md with a geometric mean that is 0.00004908md, characterized by extra low permeability.

The biological types found in the lower black shale of the Wufeng-longmaxi reservoir are

graphistone, radiolarian, spongy bone needle, algae and plant fossils (Figure 3-1). Bio

abundance and differentiation are high. The development practice shows the impact of

bioclasitics on post-fracturing. Different biological types and content impact a fracturing

treatment due to the composition of the shale minerals. The sponge spicules in this formation are

of two axis types: internal to pyritization or a combination of siliceous minerals and organic

matter. The edges of siliceous mineral packages are generally siliceous minerals. Most

radiolarians have sophisticated silicon bone structures, so sponges and radiolarians are an

important source of self-generated silicon. In the lower part of the Fuling area there is low

terrigenous supply. A rapid increase in silica content caused by the prosperity of the siliceous

creatures results in the shale brittleness increasing and the fracturing reconstruction effect is

better.

In Table 3-6, the fracturing pressure, construction pressure and shut-in pressure in numbers 1 and

3 sublayers are much lower than those in the upper layer with lower siliceous content. There is a

compressibility decline as the siliceous content declines.

50

Figure 3-1 Integrated Histogram of Paleontological Development in Jiaoye 41-5 well

Different biological type and content influence gas capacity by impacting the TOC of shale. An

analysis of the correlation between TOC and the biological content in Fuling shows that the

distribution of radiolarian/sponge spicules and TOC have a relatively strong correlation. The

51

abundance of radiolarian can be divided into three parts. The first part is the reservoir at 2618.3-

2619.36m, where the content of sponge spicules is high but radiolarian content lacks. The result

is relatively low TOC and SiO2/Al2O3; both are < 4.3%. The second part of the reservoir at

2582.26-2618.3m where a high abundance of both sponge spicules and radiolarian drive high

TOC and SiO2/Al2O3 measures. The third part is the reservoir at 2516.25-2582.26m, and now

there is an absence of both sponge spicules and radiolarian content creating extremely low TOC

and SiO2/Al2O3. These samples demonstrate that radiolarian has strong positive correlations with

TOC; the radiolarian is not the only source of raw silica but is the primary contributor of TOC.

Fracture Section

Penetrating Horizon

Fracture Pressure (MPa）

Construction Pressure （MPa）

Stopping Pump Pressure（MPa）

1 ⑥ 89.91 56.3-87.0 34.7

2 ⑥ 90.44 61.59-81.12 35.68

3 ⑤、⑥ 89.49 63.23-82.79 36

4 ⑤ 87.77 59.1-81.41 36.16

5 ④、⑤ 83.3 57.87-83.22 35.05

6 ③、④ 81.21 54.35-58.79 34.16

7 ①、③ 82.83 57.78-75.35 32.8

8 ① 85.97 60.09-82.19 30.78

9 ①、② 80.03 58.17-69.26 31.92

10 ① 76.93 54.87-76.81 31.27

Table 3-6 Statistical table of fracture parameters of a horizontal well in Jiaoshiba area

52

Figure 3-2 Core sample of Longmaxi shale reservoir

3.2.3 Ordos Basin continental facies and marine transitional facies shale reservoir.

An important petroliferous basin in China, Ordos Basin has developed a series of continental and

marine transitional facies shale formations with better reservoir forming conditions. Among them,

the upper Paleozoic shale belongs to transitional facies coal bearing formation, mainly

developing in the Benxi formation of the middle Carboniferous and Shanxi formation of the

lower Permian. The distribution is a large area with medium thickness and high organic matter

abundance, buried at a depth of 2000 - 3500m. The Mesozoic continental shale is mainly

distributed in the Ordos Basin upper Triassic Yanchang formation. It is composed of a deep lake

and semi-deep lacustrine shale, rich in organic matter, sedimentary continuous and stable, it has

53

a wide distribution, and its buried depth is 1500 - 2500m. The shale reservoir is thin, generally <

20m.

The Ordos Basin lower Permian Shanxi formation has a high quartz content between 46.5 -

54.04%. The clay content is also high generally around 43.6 - 47.81%. The residual contains a

small amount of plagioclase. The lithology of the whole formation varies little. The clay minerals

are mainly illite and kaolinite. The Chang-7 member in the Yanchang formation has brittle

mineral contents high in quartz and feldspar (50-75%). The clay content is low, mineral

composition changes greatly, and mainly illite and other clay minerals are distributed

(Figure 3-3). It has less clay content conducive to the formation of cracks. The Shanxi formation

has both brittle mineral content and a high clay content making reconstruction of the reservoir

more difficult than the Chang -7 Member in the Yanchang formation.

Figure 3-3 Core sample of Ordos basin Chang-7 member Yanchang reservoir

54

The porosity of the Chang -7 Yanchang formation is 1.69-6.83% (average 3.83%), and

permeability is between 0.00001md and 0.00043md (average 0.000068md). The porosity of the

Shanxi shale reservoir is between 0.28%-11.01% (average 3.98%), a low porosity formation.

Permeability is between 0.000104md and 0.000161 md (average 0.000133 md) and it is a low

permeability reservoir.

3.3 Case analysis of fracturing flowback in the main shale reservoirs in the world.

At present, the world’s large-scale shale gas developments take place in a limited number of

countries. The typical shale gas fields are concentrated in China, the United States and Canada.

Analyzing typical shale reservoir characteristics and the corresponding shale gas fields can

provide guidance for identifying shale reservoirs that have not been developed to determine a

flowback technology suitable for each reservoir.

3.3.1 Fort Worth Basin Barnett shale.

The United States Barnett shale development has been taking place since the last century. In

1997, the efforts were through vertical wells and large-scale hydraulic fracturing, using gelling

fluids and proppants. The crosslinked gel solution was difficult to be discharged and caused a lot

of damage to a formation. Productive removal was hindered by high costs and poor economic

benefits. After 1997, the United States began to use slickwater fracturing on Barnett shale and

the effect was better than large-scale fracturing. In 1998, slickwater fracturing was applied to

other shale reservoirs. The new output increased by about 25% compared to the historical

55

findings. In 2002, to enlarge the appearance of the reservoir in well numbers, a horizontal well

test was carried out. Although drilling costs are two times those of a vertical well, the recovery

rate increased to three times that of vertical well fracturing. In 2004, the technology combined

horizontal well segmented reconstruction and slickwater fracturing to further optimize the

reservoir reconstruction and improve the reservoir recovery and hence the economics [86-90].

With the continuous development of fracturing technologies, the difficulty of flowback of a

fracturing fluid is decreasing. From the initial gelling of large-scale hydraulic fracturing to

slickwater fracturing, the composition of fracturing fluids has changed. Viscosity has decreased

and formation damage has been reduced. The fracturing fluids flow more readily and the

flowback efficiency has increased without changing a fracture network. When the United States

replaced vertical wells with horizontal wells more advantages were experienced. Without a big

change to the fracturing fluid component, a complicated fracture network has become easier and

a fracturing fluid remains in a formation, resulting in a decrease in the flowback rate. To solve

challenges caused by the expansion of the scale of fracturing, a fracturing fluid can be adapted to

optimize the outcome by using additives and reconstructing the wettability of the reservoir and

the diversion capacity of fractures. The outcome is reducing the reservoir’s negative influence on

the fracturing fluid flowback and increasing the economic gain [86-90].

3.3.2 Sichuan Basin Wufeng-longmaxi shale.

The application of a fracturing technology in the Sichuan Basin gas field is based on the

technology used to develop the Barnett shale in the USA. The technology was adapted to reflect

56

the specific characteristics of Wufeng-longmaxi shale maintaining the advantages from the

original technology.

3.3.2.1 Horizontal well fracturing technology.

Horizontal well pumping bridge plug fracturing is the main reservoir reconstruction technology

in shale gas development in Fuling. This technology is used because it is not limited by the

number of staged fracturing layers and simple columns. The application of a horizontal well

fracturing technology has resulted in a significant gas production increase.

3.3.2.2 Fracturing fluid use and effect analysis.

During the shale gas development, the performance of a fracturing fluid plays a key role in the

fracturing impact. The Fuling shale reservoir has 300 wells using drag reducing water fracturing.

The field application has shown that the drag reducing water system has excellent drag reducing

performance, it is easy to use and produce, and it causes less harm to the reservoir. Field

measurements indicate that the drag reduction rate is close to 77.4%, achieving a good

reconstruction effect.

The shale gas wells at Fulinig use casing injection after fracturing. To avoid the sand coming

from layers, the initial speed of flowback is generally less than 200L/min. 10, 12mm nozzles are

used to release the fluid and each nozzle’s release time is 4-6 hours. The fluid released and

wellhead pressure determine the production stage start time. The Fuling Jiaoshiba block has a

relativity low flowback rate after fracturing. The characteristics and result of fracturing fluid

flowback change in different areas. The first producing block is in the north and middle parts of

57

the block and has a lower flowback rate. The average rate is 1.3%. The flowback average rate in

the east and south parts of the block is much higher at 2.7%. The flowback rate difference is

attributed to the geological structure difference. Large-scale fracturing is applied in the south part

of the block where the flowback rate is high. The middle part of the south block has a moderate

flowback rate and some fractures were developed. Wells in the same part of the block can

produce different flowback rates depending on the production system, geology and engineering

parameters. The known relationship between a flowback rate and gas output has shown that

wells with a higher flowback rate will have lower capacity (Figure 3-4). This figure is based on

the data obtained for the Fuling basin. It summarizes the well data in the Jiaoshiba area and

shows the fitting process to get the relation curve between a flowback rate and a production rate.

Figure 3-4 Relationship between flowback rate of test gas and the maximum production in

Fuling Jiaoshiba Area

58

3.3.2.3 Technological innovation summary of Fuling shale gas.

Development of the Fuling shale gas field is also based on the fracturing technology applied to

the USA. The Fuling shale gas field has added some innovative ideas to this basic technology.

The bioclastic rich characteristic of the Wufeng-longmaxi reservoir is optimized using horizontal

well fracturing that creates a ‘well factory’ mode of operation. This includes a shortened drilling

cycle that reduces the cost of the fracturing fluid. By understanding the relationship between the

reverse discharge rate and productivity, the reservoir development is further guided.

3.3.3 Ordos Basin continental facies and marine transitional facies shale reservoir.

The sedimentary environment of the shale reservoir in Ordos Basin is different from that in other

commercial shale gas reservoirs globally. The Ordos shale reservoir is a continental facies

reservoir. In comparison to the other shale gas reservoirs of marine facies, the technological

development of fracturing processes in continental facies reservoirs is still at the initial stage.

3.3.3.1 Difficulties in continental facies reservoir fracturing technology.

A challenge when fracturing continental facies is created by the less brittle mineral, a larger mud

component and the difficulty forming fracture networks. Proppants are easily embedded in the

fractures, requiring novel modifications to the applied fracturing technology [90-99].

A high clay mineral content has a strong water sensitivity. This creates difficulties in the

conventional fracturing cleanup agent because adsorption is strong. An ordinary slickwater

fracturing fluid system cannot meet the low cost and high efficiency requirements of industry.

59

A continental facies reservoir is a normal or subnormal pressure reservoir (e.g., the Chang- 7

member Yanchang pressure coefficient is 0.6-0.8). The mud shales generally have small pores

and high displacement pressure, the fracturing fluid water lock effect is obvious, the flowback

velocity is slow, and production costs are increased due to an increase in time required to

produce [90-99].

3.3.3.2 Liquid CO2 fracturing technology.

Based on the analysis of lithologic and physical characteristics of the continental shale gas

reservoir, a CO2 fracturing technique is suitable for a continental shale gas reservoir fracturing

modification. Liquid CO2 fracturing has no requirement for water and chemical additives so

there is no fracturing fluid flowback problem and no damage to the continental facies shale gas

reservoir with a high clay mineral content [90-99].

To determine the most efficient mass flow for CO2 fracturing, several application tests were

proposed and the outcome was that a pure liquid CO2 with a flow rate greater than or equal to 2.0

m3/min can achieve the fracturing target for the Chang -7-member Yanchang reservoir with a

very quick flowback speed.

3.3.3.3 CO2 incremental fracturing technology.

Shale gas reservoirs need to communicate with natural fractures to form a large-scale fracture

network and high production. Continental shale gas wells all use slickwater fracturing with a low

flowback speed for a fracturing fluid and a long production cycle. To solve these problems,

Ordos basin uses a CO2 incremental fracturing technology to obtain better results. This is

60

achieved by applying a CO2 pre-incremental fracturing technology. The discharge starts

immediately after the fracturing, and test data is shown below.

Figure 3-5 Comparison diagram of fracturing process flowback rate in a shale gas well [99]

In Figure 3-5, the discharge flowback rate increased 17%, and the final flowback rate increased

35% using three CO2 incremental fracturing technologies.

3.3.3.4 Suggestions and conclusions.

Continental shale gas reservoirs are characterized by dense lithology, low permeability of matrix,

low brittle mineral content and high clay mineral content creating an environment with high

technical requirements for fracturing production.

61

A CO2 fracturing technology is one application that has benefits. The impact to the environment

is less harmful and provides easy flowback suitable for continental facies shale gas reservoir

development. The CO2 incremental fracturing technology significantly improves the flowback

velocity and flowback rate of a fracturing fluid, reduces fracturing fluid retention and water lock

damage, and improves the reconstruction effect. The optimum injection rate of CO2 is optimized

based on the characteristic parameters of the continental shale gas reservoir. The pressure

coefficient can reduce the cost and improve the flowback rate of the fracturing fluid.

The liquid CO2 fracturing technology is a water free fracturing technology with almost no

damage to the reservoir and no fracturing fluid treatment is needed. Liquid CO2 is the most

promising technology for continental facies shale gas reservoirs.

3.4 Summary

The development of a reservoir fracturing technology is a key to the commercial development of

shale gas reservoirs. Different fracturing technologies fit different reservoir environments and

cannot be applied mechanically. The fracturing technology decision should be made according to

the reservoir lithology, physical properties, stress and geological structure characteristics.

Reservoir lithology is the decisive factor impacting fracturing flowback. Reservoir lithology

determines reservoir characteristics. It is a key factor affecting porosity, permeability and a

brittleness coefficient of a reservoir. The content of brittle minerals and their components

determine the brittleness coefficient and the fracture properties of the reservoir. The development

of reservoir fractures and the proportion of free gas directly impact the fracturing outcome. The

62

clay mineral content and composition of the reservoir determine micro pores and adsorbed gas

content. The different clay minerals have a variety of physical and chemical properties that

create adverse effects in the reservoir fracturing fluid flowback process.

Typical cases of shale gas development have shown that it is necessary to deepen the

fundamental understanding of reservoir lithology, physical properties and geological stress. This

knowledge is necessary to select the most appropriate fracturing technology, a fracturing fluid

and a flowback technology. Considering the information gained about the above characteristics

of a reservoir will determine the reservoir reconstruction and best method to target reduced

reservoir damage, lower operating costs and increased production capacity.

63

Chapter 4 Establishment of a Model

Previously in this thesis, the effects of reservoir lithology, formation pressure, physical

properties, wettability and fracture development on fracturing fluid flowback were introduced

theoretically. To expand the research on the reservoir geological characteristics’ impact on

fracturing fluid flowback in a more visual way, a homogeneous reservoir model was developed

using CMG software and setting the basic fracture parameters. The model will be used to

simulate a fracturing fluid flowback process (Figure 4-1).

Figure 4-1 3D model diagram

64

4.1 Reservoir Setting

Reservoir heterogeneity is not the focus of this thesis. A simple homogeneous model is chosen to

eliminate the influence of other factors on the fracturing fluid flowback. The reservoir is set up

according to available field data: The top layer depth is 3000m, sublayer thickness is 2m, and the

reservoir porosity and permeability are referenced to the reservoir average porosity and

permeability data. Reservoir wettability is initially set as water wet. A transverse fracture is set

up in the reservoir. Because the reservoir is in the initial stage of a flowback process just after

fracturing, the fracture porosity, permeability and water saturation settings are much higher than

in other parts of the reservoir.

4.2 Process Design

The fracture is preset and the model cannot reproduce the steps of reservoir fracturing. The

saturation of the fracturing fluid (simplified as water) in the reservoir is pre-determined through

obtained field data. The initial stage of the model is defined as the end of the short-term shut in

after fracturing. After a period of prophase flowback, the production well is shut in for a longer

time to achieve enough reconstruction effects and reduce reservoir damage. The production well

flowback restart proceeds until the gas production reaches the requirements of the gas producing

phase and the end of the flowback process.

4.3 Analysis of the Basic Model

By simulating the basic model in IMEX, the pressure differential in the reservoir is obtained

using a 3D pressure distribution diagram that indicates the flowback condition in different

positions in the reservoir. From the 3D pressure distribution diagram, the pressure of the fracture

65

and its surrounding part drops more rapidly than in other parts of the reservoir after the initial

opening of the well (Figure 4-2).

Figure 4-2 3D pressure distribution diagram (Stage 1)

During the second shut in of the production well, the reservoir pressure tended to be

homogeneous. This demonstrates that the fracturing fluid in the fracture is supplemented by the

fracturing fluid in the reservoir. A portion of the fracturing fluid is discharged back from the

reservoir and the overall pressure of the reservoir decreases than in the initial stage (Figure 4-3).

66

Figure 4-3 3D pressure distribution diagram (Stage 2)

Like in Stage 1 in the open well, the pressure decreases significantly at the fracture point and

surrounding area during Stage 2 in the open well. This suggests that the fracturing fluid in the

fracture is preferentially discharged from the reservoir. The overall pressure in the reservoir

gradually decreases until the flowback process is complete (Figure 4-4).

Figure 4-4 3D pressure distribution diagram (Stage 3)

67

4.4 Result Comparison

In Figure 4-4 the 3D simulation of the process design and IMEX simulation revealed that the

homogeneous model basically meets the requirements of the simulation of the fracturing

flowback process. To better observe the flowback rate, a curve of flowback water quantity was

drawn; see Figure 4–5.

Figure 4-5 Flowback quantity curve of the basic model

Using the well data in the gas field, the relationship curve between the flowback water quantity

and time t is found in Figure 4–6.

Figure 4-6 Real flowback quantity

68

In comparing the two curves, the model curve generally conforms to the actual curve. Because

the model is an ideal model, many actual reservoir characteristics are ignored, so the curves will

be different in detail, but the differential of the overall trend is small, indicating that this model

can reflect the actual flowback process.

69

Chapter 5 Reservoir Geological Characteristics Analysis

5.1 Lithology

The main influence of reservoir lithology on the flowback of a fracturing fluid depends on the

content of the brittle minerals and clay minerals. The brittle mineral content is characterized by

the brittleness coefficient which impacts the formation of fractures during the reservoir fracturing

stage. The fracture development indirectly influences the flowback of the fracturing fluid. It is

not considered as a main research aspect in this thesis.

In contrast, clay minerals effects on fracturing fluid flowback are more direct and larger. Clay

minerals impact the reservoir’s compressive property and the fracture development due to the

plastic characteristics. The hydration of clay minerals allows them to readily react with the

fracturing fluid resulting in the imbibition of the clay minerals and decreasing in the reservoir

porosity and permeability. These drive the increasing difficulty of fracturing fluid flowback.

Q=K*A*(h2-h1)/l

Darcy’s law (see the equation above) states that the mobility of a liquid in a reservoir is

positively related to the formation osmotic coefficient and a channel section area. The hydration

of clay minerals causes the fracturing fluid to enter the clay crystal layer. This part of the

fracturing fluid cannot flowback because it is locked between the clay layers, decreasing the

flowback efficiency. At the same time, the clay expands after hydration decreases the existing

fracture channel radius. This drives a reduction in the parameters K and A, which results in a

70

decrease in the liquid mobility. The increasing capillary force of the fracturing fluid increases the

resistance of the fracturing fluid during the flowback process.

CMG software cannot express lithology characteristics of a reservoir directly. The clay mineral

and brittle mineral content can only be represented by the permeability and porosity differences

in the reservoir. There are many parameters that determine permeability and porosity of the

reservoir. The clay mineral and brittle mineral characteristics cannot represent lithology

characteristics so using CMG to simulate the clay minerals content’s effect on fracturing fluid

flowback is not the best tool. These aspects are important influences on the fracturing fluid

flowback and need further research.

5.2 Formation Pressure

Formation pressure directly acts on the fracturing fluid flowback. In theory, the higher formation

pressure should increase the pressure difference between a formation and a well, improving the

duration of the first stage of flowback, thus increasing the total flowback rate.

To study the relationship between the formation pressure and a flowback effect, a model with

relatively high formation pressure is established by adjusting the formation pressure of the basic

model, shown in Figure 5-1.

71

Figure 5-1 Pressure set for high formation pressure model

After simulating the model using IMEX, the flowback water quantity curve is found in

Figure 5–2.

Figure 5-2 Flowback quantity curve for high formation pressure model

72

In Figure 5-2, high formation pressure shows the peak of the flowback water quantity curve

shifting to the mid-stage of the process. This may be attributed to the extent of Stage 1 flowback.

5.3 Reservoir wettability

Reservoir wettability mainly impacts the contact between a fracturing fluid and fracture walls

and the location of the fracturing fluid in fractures. To show the effect of reservoir wettability on

flowback in a visual manner a new model with more oil wet characteristics was developed. There

are only gas and water two phases in the basic model and a lack of an oil permeability curve in

the oil-water relative permeability plot. These factors limit using the intersection of the two

curves to show the wettability of the reservoir. The method of decreasing irreducible water

saturation is used to show a decrease in reservoir hydrophilic.

Figure 5-3 Irreducible water saturation difference between basic model and new model

After simulating the new model, a curve of flowback water quantity is developed; see

Figure 5-4.

73

Figure 5-4 Flowback quantity curve for a less water wet model

Compared with the curve of the initial model (Figure 4-5 to Figure 5-4), with a decrease in

reservoir hydrophilicity, the flowback quantity at Stage 1 and Stage 2 increased, and the

proportion of each stages has a limited variation. The wettability increases the upper limit of the

flowback rate with no change to the flowback process.

5.4 Fracture development

The effect of reservoir fracture development during fracturing fluid flowback is complicated.

The fracture system improves the percolation capacity of a fracturing fluid in a reservoir. But

complex fracture networks can cause more fracturing fluid to remain in fractures. To study the

effect of fracture development on the fracturing fluid flowback, reservoir models with different

levels of fractures are established and compared.

74

5.4.1Dual fractures model.

Based on a single fracture model, a new horizontal well to perform fracturing is set in the J

direction perpendicular to the original fracture. This design is implemented to increase the

connection level between the fractures. Fractures perpendicular to each other form a better

network than parallel fractures (Figure 5-5).

Figure 5-5 Well location and fracture location for dual fractures model

After simulating the new model, the curve of flowback water quantity is shown in Figure 5-6.

75

Figure 5-6 Flowback quantity curve for dual fractures model

In Figure 5-6 the flowback quantity at each stage of the dual fracture model is lower than in the

basic single fracture model. This may be attributed to the fact that the distance between the

production well and the new fracture is large. The fracture increases the permeability of the

fracturing fluid in the reservoir, but the distance effect results in more fracture fluid remaining in

the fractures, making the overall flowback rate to decrease.

5.4.2 Three fractures reservoir.

Based on the dual fractures reservoir model, adding a new horizontal well at (4.4.6) position,

fracturing is in the J direction (similar with the second fracture) and the fractures are

perpendicular in the I direction, creating a complex model (Figure 5-7).

76

Figure 5-7 Well location and fracture location for three fractures model

After simulating the new model, a 3D pressure distribution diagram is produced in Figure 5-8.

Figure 5-8 Pressure distribution diagram for three fractures model

77

The fractures further connect the reservoir, and the proportion of the fractures and the fracture

control area increase, making the pressure to drop rapidly in these cases.

Figure 5-9 Flowback quantity curve for three fractures model

A flowback water quantity curve in Figure 5-9 shows that the flowback quantity is similar to that

in the dual fractures model during Stage 1. During Stage 2, the flowback quantity decreases

significantly. According to the reservoir pressure change, the reader can conclude that the

flowback velocity is raised by the fractures and the same as the pressure drop. After the reservoir

pressure drops the flowback enters Stage 2. Without the high pressure difference between the

reservoir and the wells, the residual fracturing fluid in the complex fracture system has a

difficulty to flowback into the wells.

78

5.4.3 Fracture network reservoir.

Based on the dual fractures model, performing multistage fracturing at the well two location

forms a complicated fracture network. Compared to the dual fractures model, the fracture

network model connects with the reservoir around well two in a better way (Figure 5-10).

Figure 5-10 Well location and fracture location for fracture network model

After simulating the new model, the curve of flowback water quantity is shown in Figure 5-11.

79

Figure 5-11 Flowback quantity curve for fracture network model

The total flowback rate increased slightly compared to the dual fractures model. This is

attributed to the increase of flowback water in Stage 2 caused by the network of fractures

extending toward the development well. The impact is to make the fracturing fluid migration

easier after the pressure drops allowing fracturing fluid flowback from the reservoir.

80

Chapter 6 Conclusions

1. Reservoir geological characteristics have a strong impact on fracturing fluid flowback,

and this is reflected by the improvement in the total flowback rate and positive changes to

the flowback velocity at each stage.

2. As a geological characteristic, reservoir wettability has no impact on each stage of the

flowback process. The residual amount of a fracturing fluid in the reservoir is affected by

wettability, which is reflected in the increase of the total flowback rate.

3. The influence of reservoir pressure on flowback is the extension of the first flowback

stage and leads to high flowback efficiency in the mid-stage of the process. Reservoir

pressure has little impact on the ability of the reservoir to retain the fracturing fluid.

There is little change in the final stage of the fracturing fluid flowback.

4. The influence of fracture development on fracturing fluid flowback is diversified.

Fractures can connect the reservoir and that is beneficial to the permeability improvement

of the fracturing fluid in the reservoir. The location of fractures will determine if the

connecting characteristic becomes a resistance to the fracturing fluid flowback. Fractures

near a production well promote the flowback while the fractures separated from a

production well may increase the difficulty of fracture fluid flowback.

81

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