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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(Unpublished master's thesis).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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