Coalbed methane reservoir stimulation using guar-based fracturing fluid: A review

Accepted Manuscript Coalbed methane reservoir stimulation using guar-based fracturing fluid: a review Qiming Huang, Shimin Liu, Gang Wang, Bing Wu, Yongzhi Zhang PII:

S1875-5100(19)30081-2

DOI:

https://doi.org/10.1016/j.jngse.2019.03.027

Reference:

JNGSE 2860

To appear in:

Journal of Natural Gas Science and Engineering

Received Date: 25 September 2018 Revised Date:

22 March 2019

Accepted Date: 23 March 2019

Please cite this article as: Huang, Q., Liu, S., Wang, G., Wu, B., Zhang, Y., Coalbed methane reservoir stimulation using guar-based fracturing fluid: a review, Journal of Natural Gas Science & Engineering, https://doi.org/10.1016/j.jngse.2019.03.027. This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.

ACCEPTED MANUSCRIPT Coalbed methane reservoir stimulation using guar-based fracturing fluid: a review Qiming Huanga,b,c,d, Shimin Liuc*, Gang Wangb,c*, Bing Wua, Yongzhi Zhange a

College of Resources and Safety Engineering, China University of Mining and Technology (Beijing), Beijing

100083, China b

ABSTRACT

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Mine Disaster Prevention and Control-Ministry of State Key Laboratory Breeding Base, Shandong University of Science and Technology, Qingdao 266590, PR China c Department of Energy and Mineral Engineering, G3 Center and Energy Institute, The Pennsylvania State University, University Park, PA-16802, USA d Collaborative Innovation Center of Coalbed Methane and Shale Gas for Central Plains Economic Region, Henan Province, Henan Polytechnic University, Jiaozuo, Henan, China e Communication & Information Center of the State Administration of Work Safety, Beijing, 100013, PR China

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As a greener and efficient energy source, the development and utilization of coalbed methane (CBM) can not only increase the energy supply for the State, but also reduce the greenhouse gas (GHG)

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emission by replacing other carbon-intense energy sources, such as oil and coal. CBM reservoirs are known as low to ultra-low permeability reservoir and thus the fracturing stimulation is commonly required for commercial gas production from coal seams. This article reviews the main components, rheology, friction pressure, and proppant transport characteristics of the guar-based fracturing fluid, and its field applications. Meanwhile, both advantage and disadvantage for CBM fracturing

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treatment were comprehensively analyzed. Guar-based fracturing fluid is composed of guar gel, and various additives, mainly crosslinker and breaker. As a complex mixture, the effectiveness of guar-based fracturing fluid is not only closely related to the concentration of various chemical additives but also influenced by fluid-coal interactions at the in situ reservoir conditions. The gel

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residual due to low flowback rate can potentially damage the formation and hinder the effectiveness of gas production. The formation damages include impacts on gas adsorption, diffusion, and

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transport in CBM reservoirs. Coal matrix has a strong adsorption capacity for guar-based fluids and is likely to have a sorption induced matrix swelling and reduce the effective permeability. Hence, it is necessary to develop more efficient breakers to increase flowback of guar-based fracturing fluid. The long-term engineering practice shows that the fracturing effect of guar-based fracturing fluid is quite different in field applications at different operation sites. Therefore, the mechanisms of the impact of guar gel on the methane flow in coal should be further studied, and it is important to determine the applicability and improving performance of the guar-based fracturing fluid for site specified application based on the reservoir pressure, temperature, hydrological environment, structural geology and other unique reservoir properties. 1

ACCEPTED MANUSCRIPT Key Words: Guar-based fracturing fluid; Coalbed methane; Limitations; Rheology; Field application 1. Introduction

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With the increasing demand for energy and the growing shortage of conventional oil and gas resources caused by the continuous development of global economy, the forward-looking countries are actively identifying and developing new energy resources to sustain the energy supply through

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replacement of conventional oil and gas by unconventional energy and/or renewables. Meanwhile, the environmental pollution particularly coal-burned particulate pollution urges countries to

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continue to seek cleaner energy resources (Chong et al., 2016). Coalbed methane (CBM), as a unconventional natural gas resource, is one of the options to replace portion of conventional oil and coal. In additional to the natural gas energy supply, the coal mining industry will be beneficial from the CBM development by intentionally reducing the in situ gas content for the subsequent mining

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activities to improve the safety condition of the future mines (Kong et al., 2014; Wang et al., 2017). The root of CBM industry was coal mine gas drainage to ensure the safe underground mining

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conditions and gradually evolves as a separate and commercial development for natural gas supply (Moore, 2012). Since the second half of the 20th century, the United States, Canada, Australia and

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other countries have been involved in the development and utilization of CBM (Flores, 2013; Carpenter, 2018). As CBM industry evolves, significant advancements were made to better characterize, produce and process the natural gas from CBM reservoirs (Moore, 2012). The CBM resources are widely distributed around the world as shown in Figure 1 and they mainly consist with the coal basins. The reported CBM-rich countries include Russia, Canada, China, Australia, and United States as shown in Figure 2 (Thakur et al., 2014). In last a few decades, the annual total production of CBM around the world keeps increasing due to the advancements of 2

ACCEPTED MANUSCRIPT extraction technologies and various incentive programs in different countries (McGladeet al., 2013). The US is the pioneer of CBM extraction and it is still the leading CBM production country with ~50% of world total production as shown in Figure 3. In 2006, it was estimated that of global

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resources totaling 143 trillion cubic meters, only 1 trillion cubic meters has been recovered (Thakuret al.,2014). Thus, the CBM could still be one of the major natural gas supplies over next a few decades with continuous improvement of technologies, such as the long lateral horizontal wells

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and refracturing technologies.

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Fig. 1 Worldwide CBM reserves and activity (Al-jubori et al., 2009): Major CBM reserves (dark blue) are found in Russia, the USA (Alaska alone has an estimated 1,037 Tcf), China, Australia, Canada, the UK, India, Ukraine and Kazakhstan. Of the 69 countries with the majority of coal reserves, 61% have recorded some form of CBM activity-investigation, testing or production.

Fig.2 Global coalbed methane reserves (trillion cubic feet) (Thakuret al., 2014)

3

ACCEPTED MANUSCRIPT Proportion： United States Total of China, Canada and Australia

80

50 60 40 30

40

20

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Production (BCM)

60

Production： United States China Canada Australia

20

10

2002

2004

2006 2008 Year

2010

2012

0 2014

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0 2000

Proportion of total world production (%)

100 70

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Fig. 3 Production changes of coalbed methane from major producing countries after 2000 (Unconventional gas production database): The production of the major CBM produce countries can be divided into two stages, that is I: US CBM production accounts for a large proportion in the world. II: the CBM production of China, Canada and Australia rises, the proportion of their production to the world's total production has risen rapidly, US CBM production has declined. Due to the low permeability of most CBM reservoirs, hydraulic fracturing is usually used to

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create more fractures in the coal seam as gas pathways for gas flow, which in turn allows more gas to flow into the CBM wellbore and achieve the commercial gas flow rate (Wang et al., 2014). The fracturing fluid plays very important roles to effectively stimulate the CBM reservoirs during the

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fracturing job. The oil-based fracturing fluids were the main development direction of fracturing

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fluids in the early 1950s and 1960s (Barati and Liang, 2014). Then the gel-based fracturing fluid which uses the guar powder as a thickener was used and promoted in the early 1960s, the invention of the thickener based on the guar marks the emergence of modern fracturing fluid chemistry. After its invention, the gel fracturing fluid rapidly developed and was widely used in fracturing treatments because of chemical modification of the guar and its improved crosslinking systems in the 1970s (Harris, 1988). In 1980s, another notable feature in the development of the gel fracturing fluid was to intentionally control the crosslinking reaction rate according to the reservoir in situ pressure and 4

ACCEPTED MANUSCRIPT temperature conditions. The development of low permeability gas fields and the increasing difficulty of flowback after the construction of some low-pressure oil wells resulted in the boom of the foam fracturing fluid and the viscoelastic surfactant (VES) fracturing fluid (Kefi et al., 2004; Gu

fluid is still widely used worldwide, especially in the United States.

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and Mohanty, 2015). However, as a traditional water-based fracturing fluid, guar-based fracturing

In the conventional oil and gas industry, extensive research has been conducted to

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investigate the formulation process and application effects of guar-based fracturing fluids. Because

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of the detailed research studies, the gel formulation process is well understood and its performance can be predicted based on the in situ pressure and temperature conditions for conventional oil and gas wells. However, there are many differences in the physiochemical properties between coal seams and conventional reservoirs, this leads to unique technical requirements for guar-based

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fracturing fluids in the coalbed gas stimulation (Cong et al., 2007; Gall et al., 1988). In this work, the development and evolution of guar-based fracturing fluid for CBM application was comprehensively reviewed and we will cover: 1) Coal seam fracturing stimulation mechanism, 2)

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Main components of guar-based fracturing fluid, 3) Comparative analysis of the advantages and

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disadvantages of guar-based fracturing, 4) Laboratory research achievements, and 5) Field application of guar-based fracturing. 2. Mechanism of CBM reservoir fracturing treatment Coal is known as a dual porous medium with microporous matrix and fractures. The matrix micropores are the primary gas storage house for the gas content (Gray, 1987a; Gray, 1987b; Clarkson and Bustin, 1999; Liu and Harpalani, 2013). Most of the CBM gases are in adsorbed phase as illustrated in Table 1. In addition to matrix micropores, natural fractures, termed as cleats, 5

ACCEPTED MANUSCRIPT were occurred during the coalification process because of the matrix shrinkage and geological stress evolution (Al-jubori et al., 2009; Laubach et al., 1998; Rodrigues et al., 2014; Liu et al., 2016; Liu and Harpalani, 2014). Most of the coal seams are within shallow depth and thus the vertical and

1989).

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horizontal stresses is typically small resulting in a large amount of coal seams (Boyer II and Reeves

Table 1 The difference between CBM reservoirs and conventional gas reservoirs (Zhang et al., 2013). Trap Pores High, insensitive to stress Free phase Seepage

Recovery technique

Self-generation and self-bearing Micropores-cleat Low, sensitive to stress Sorption phase (70% to 95%) Desorption→Diffusion→Seepage Dewater to reduce pressure, Single well or well network

Recovery time

20 to 30 years

Less than 8 years

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Gas accumulation patterns Pore characteristics Permeability Phase Recovery mechanism

Conventional gas reservoirs

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CBM reservoirs

Depletion, well network

As the CBM reservoir depleting with progressive pressure drawdown, the adsorbed methane

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starts to desorb from the coal matrix and then migrates out of the coal matrix through the diffusion process, flows into the fractures, and transports through cleat system toward the wellbore due to

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pressure gradient (Liu and Harpalani, 2013; McKee and Bumb, 1987; Meng et al., 2018). However, most of the pores are micropores, and the number of virgin natural cleats is also very limited, the

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porosity and permeability of CBM reservoirs are lower than that of conventional natural gas reservoirs. Therefore, most coal seam gas fields often require fracturing treatment and stimulation. During the fracturing treatment, a large volume of fracturing fluid associated with proppant will be injected into the CBM formation to not only frack the coal but open up and shear the cleat system which artificially make a high permeability reservoir (Poulsen et al., 1989), so that the commercial gas flow rate can be achieved for the virgin low permeability CBM reservoirs. Fracturing is a traditional technique in oil and gas fields. However, due to the unique 6

ACCEPTED MANUSCRIPT physiochemical properties of coal, CBM fracturing has many unique requirements and sometimes it is quite different from the conventional fracturing treatments. First, unlike sandstone and shale, coal seams have a lower Young's modulus (E), resulting in wider and shorter fractures with the equal

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volume of injected fracturing fluid (Heo et al., 2015). In the CBM field, the fracture fluid volumes sometimes can reach 3,000 to 12,000 lb/ft and it was noted that the effective fracture length rarely exceeds 200 ft due to the low E (Olsen et al., 2003). This because the crack tip opening

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displacement will be proportional to the critical stress intensity factor and inversely proportional to

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the elastic modulus (Jones et al., 1988). In addition, because the E of coal is usually lower than that of adjacent rock strata, the fracture propagation resulting from hydraulic fracturing is always terminated at the coal-rock interfaces. This usually results in fractures in the coal seam producing more "T"-shaped and "I"-shaped induced fractures (Figure 4) (Chen et al., 2015). Nevertheless, due

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is more complicated.

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to the inhomogeneity of the mechanical properties of coal, the overall shape of the fracture network

Fig. 4 "T"-shaped and "I"-shaped induced fractures in coal bed fracturing. Despite the lower E, abnormally high treat pressure often occurs in the process of coal seam fracturing treatment (Nielsen and Hanson, 1987). For example, high fracturing pressure of 1.0-2.0 psi/ft were common in the Black Warrior basin, compared to 1.0 psi/ft for most sandstone reservoirs (Jones et al., 1986; Jones et al., 1987a; Jones et al., 1987b). An important cause of this high 7

ACCEPTED MANUSCRIPT treatment pressure is coal fines and coal chips due to the shear of existing cleats. Because a large number of micro-fractures is typically occurred in coal seam, the pore pressure increases due to the fracture fluid leak-off. As a result, the strength of the coal near the borehole decrease due to the

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decrease of effective stress. This localized coal strength alternation can induce localized shearing and new coal fines and chips can be possibly produced because of the abrasion and broken of coal. The add-in coal fines and chips into the fracturing fluid can enhance the viscosity of the fluid, so

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that the flow resistance of the fracturing fluid increases which will ultimately transfer to a high

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treatment pressure as discussed before. At the same time, the plugging at the tip of the fracture will also increase the role of treatment pressure (Jeffrey et al., 1989; Li et al., 2018). In addition, complexity and irregularity of coalbed fracture network can also lead to high treatment pressure (Zhang et al., 1997). Thus, coal fracturing design should consider the coal-fluid interactions, low

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stress and strength conditions of CBM formation, fast leak-off and complex pre-existing cleat system.

3. Guar-based fracturing fluids and their main components

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In water-based fracturing fluid system, the guar fracturing fluid is the most common one.

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There are many types of additives of guar-based fracturing fluids when using guar fracturing in the oil and gas field: thickener, crosslinker, breaker, anti-swelling agent, fungicide, pH buffer and so on. However, we just review the main components that can reflect the reflect the physical and chemical properties of the guar-based fracturing fluids. These main components include thickener (Guar or modified guar), crosslinker, and breaker. 3.1. Guar and modified guar Guar gel is a natural galactomannan gum extracted from the endosperm of guar produced in 8

ACCEPTED MANUSCRIPT India, Pakistan and other countries as shown in Figure 5. It has a wide range of applications and is often used as a thickener in the food processing, industrial and pharmaceutical industries and other fields. Guar gel thickening mechanism is that guar has a large molecular weight (hundreds of

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thousands to millions) and interactions between various parts of the main chain (Vijayendran and Bone, 1984; Morris et al., 1981; Wientjes et al., 2000; Goycoolea et al., 1995). Natural guar dissolves slowly, has high water-insoluble content, is not easy to control viscosity, and has poor

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temperature stability (Kefi et al., 2004). In many cases, it needs to be modified to improve

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performance (Economides and Kenneth, 2000). Now modified guar products containing hydroxyl

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groups and carboxyl groups are most commonly used in oil and gas field as shown in Figure 6.

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Fig. 5 Guar gel production process: a: Guar beans are native to Asia or tropical Africa, is an excellent crop that is drought tolerant, can enhance soil fertility, and is suitable for machine cultivation. b, c and d: The natural guar bean is used as a raw material to remove the part of the endosperm remaining after the epidermis and the germ, and after drying and crushing, the guar flour can be obtained. The appearance of the guar flour is from white to yellowish free-flowing powder. e: After the guar flour is added to the water, a viscous colloid is formed to achieve a rapid thickening effect. Hydroxypropyl Guar (HPG) is a product modified with propylene oxide on guar. Since plant fibers of the polymer are removed during the reprocessing and washing process, the HPG generally contains less insoluble residue which is preferred as fracturing fluid. Due to the replacement of hydroxyl groups on the macromolecule chain of guar by the hydroxypropyloxy, the temperature stability and biodegradability resistance are both modified to better serve as fracturing fluid 9

ACCEPTED MANUSCRIPT additives. The Carboxymethyl Guar (CMG) can be obtained by reacting guar collagen powder with sodium chloroacetate. The introduction of carboxymethyl groups makes the guar tape partially negatively charged (Parvathy et al., 2005) (Fig. 6). The mutual repulsion between the charges makes

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the polymer structure more stretched. Compare with naive guar and HPG, therefore, CMG has better water solubility and better thickening effect (Cheng et al., 2002).

H

OH H2 C

O

HO

OH H

H

HO H

H

H2 C

O H

OH

CH2

O

HO

H

HO

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H

H

O

H

HO O

O

H

H

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H

OH

H

H

a Guar

b HPG

c CMG

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Fig. 6 Structural formula of Guar gel and its derivative: Guar gel is a nonionic compound having a semi-flexible, random coiled conformation. Its structure can be described statistically as a structure that is copolymerized with α-D galactose and β-D mannose. The degree of substitution of galactose units and the uniformity of distribution affects the solubility of guar gel. The galactose branch chains hinder the formation of the helix structure of the mannose backbone, making the molecule soluble in water. The ratio of mannose to galactose units ranges from 1.6:1 to 1.8:1. Modification of guar molecular chains by chemical modification (degradation, oxidation, hydroxyalkylation, carboxymethylation, cationization, sulfonation, etc.), especially in regions that are not replaced by galactose, can lead to molecular chains fully hydrated to improve its solubility. The degraded and oxidized galactomannan exhibits good solubility, shear resistance, salt resistance, fast dissolvability, resistance to enzymatic degradation, dispersion, powder flow, and temperature resistance (Duxenneuner et al., 2008; Weaver et al., 2003; Guo et al., 2010). 3.2. Crosslinker

Fracturing fluids that are thickened with guar without cross-linking are called linear fracturing fluids. Linear gel fracturing fluid, also known as thickened water, has slightly better gas production performance than active water after treatments. However, because of the shear sensitivity and the poor temperature stability, they are only adopted in plug removal fracturing in

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ACCEPTED MANUSCRIPT shallow wells which have a low temperature, a small amount of sand, and a low sand ratio. The crosslinked guar fracturing fluid is a crosslinked linear gel fracturing fluid. Crosslinker and thickener can form a three-dimensional network structure of gel. The crosslinked gel has better

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viscoelasticity, good fracturing capacity, sand-carrying capacity and temperature-resistant shear resistance.

For the guar gel, Boron and several metals including Titanium and Zirconium can be used as

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crosslinkers. Wang et al. (2016) found that the crosslinked gel formed from organic zirconium has

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excellent performance of high-temperature resistance capability. In addition to these materials, Iron, Chromium and Aluminum also crosslink guar but are not commonly used (Cawiezel and Elbel, 1992; Kruijf et al., 1993; Dawson, 1991). Borax is the first crosslinker used in water-based fracturing fluid. It has the advantages of being non-toxic, easy to crosslink, low cost, and easy to

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break. However, it has the disadvantages of excessive crosslinking speed and poor temperature resistance. Currently widely used in the gas field is the organic boron crosslinker. Figure 7 shows that the concentration of borate ion produced after hydrolysis of the cross-linking agent also varies

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with temperature and pH. Therefore, it is usually necessary to use a pH buffer for viscosity

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adjustment (Nimerick et al., 1997). The viscosity increase of a fracturing fluid crosslinked by a mixed boro-zirconium crosslinker can be explained by two superimposed mechanisms. At low temperatures, the increase in viscosity is mainly due to the interaction of boron ions and polysaccharides in water, whereas at high temperatures, the increase in viscosity depends mainly on the complexation of zirconium ions with polysaccharides (Jiang et al., 2009).

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Fig. 7 Influence of temperature and pH on borate ion concentration (After Rae and Lullo, 1996): Both borax and organic boron, they all produce a large amount of borate ion after being dissolved in water. The borate ion combines with the ortho-cis hydroxy group of the guar macromolecular chain to promote the formation of crosslinked gel structure. 3.3. Breaker

In the flowback stage of the fracturing treatment, due to the high viscosity of the guar-based fracturing fluid, it is necessary to do the gel breaking work to reduce the viscosity of the fracturing

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fluid, and accelerates the flowback. The breaking mechanism of most breakers is to promote the decomposition of guar gel or crosslinked guar gel macromolecules to reduce the viscosity through

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strong oxidation (Romaine et al., 1996; Rae and Lullo, 1996). Ammonium persulfate is the most common gel breaker during guar gel fracturing process. However, it is not very effective at relative

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low temperature, so it always be used with breaker catalyst or compounding with other type of breaker (Wang et al., 2010; Sarwar et al., 2011; Wang et al., 2015). Acids such as HCl or Acetic acid will attach the polymer back bone and break the gel similar to the oxidizing breaker but they are much less selective and can cause considerable amount of insoluble material to be formed (Jeffrey et al., 2013). Compared with oxidizing breakers, enzyme breakers are easy to degrade and less residual to contaminate the reservoir. In addition, enzyme breakers can be used in low temperature reservoirs (typically used below 60 °C) (Harris, 1988). However, they require relatively low pH for 12

ACCEPTED MANUSCRIPT better performance. In general, the enzyme has the highest efficiency at pH=6 as illustrated in Figure 8, and high temperature and high pH will make the enzyme inactive. The efficiency of the enzyme breaker can be further improved, and the scope of application can be broadened by adding

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additional new additives to adapt the extremes of pH and temperature (Chopade et al., 2015). Previous field observations showed that the wells used the enzyme breaker can get better production compared with the wells used conventional breaker according to long-term production data analysis

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from 170 fracture stimulated wells (Brannonet al., 2003). The possible reason is that the enzyme

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breaker has better performance on the gel breaking (Loznyuk et al., 2015), and thus, it can ensure an effective flowback which can reduce the damage of the fracturing fluid to the formation

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permeability and enhances the CBM production.

Fig. 8 Enzymes and oxidizers with their operating conditions (After Al-Muntasheri, 2014): LTE = low-temperature enzymes, HTE = high-temperature enzymes, LTO = low-temperature oxidizers (sodium and potassium persulfates), MTO = mid-temperature oxidizers (calcium and magnesium oxides), HTO = high-temperature oxidizers (sodium and potassium bromates). 3.4. Gel crosslinking and breaking mechanisms The crosslinking mechanism of borax is to crosslink with or tho-hydroxy groups on the HPG molecular chain and crosslinked by polar and divalent bonds. While in the crosslinking process of organoboron, there are more complex bonds formed by boron ions and polysaccharides 13

ACCEPTED MANUSCRIPT at each cross-linking bond point as shown in Figure 9. Although the amount of crosslinking bonds generated by the organoboron crosslinker is relatively small, the crosslinking strength is significantly increased which ultimately turns to improve the temperature resistance and shear

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resistance of the fracturing fluid. And the organic boron solution contains an excessive amount of organic ligands, which can generate affinity with the borate ion and compete with the o-hydroxyl

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groups on the guar to delay the crosslinking.

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Fig. 9 Crosslinking and breaking process of the guar gel.

For breaking mechanism of ammonium persulfate, when ammonium persulfate dissolves in the water, it can produce persulfate to decompose and generate free radicals which attack the main

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chains of the polymer and increase macromolecular chain degradation and gel breaking. The guar

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molecules are mannans linked by mannose via β (1, 4) glycosidic bonds (Puchart et al. 2004). The enzyme breakers is to cleave the β (1,4) glycosidic bond on the surface of the guar molecule, and the glycan form of guar molecules will be cleaved to an irreducible monosaccharide or disaccharide eventually (Al-Muntasheri , 2014). From Figure 10, the apparent viscosity of crosslinked guar fracturing fluids varies with different pH and temperature conditions (Shah and Asadi, 1997). Each coal formation will have unique geological and hydrodynamic conditions determining unique temperature, pH value, mineral 14

ACCEPTED MANUSCRIPT composition and rank condition. Therefore, the experimental study of the performance of guar-based fracturing fluid at specific in situ condition will be essential before the actual CBM

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stimulation treatments.

Fig. 10 Apparent viscosity at various pH and temperatures for borate-crosslinked 35 lb/mgal guar gel at a shear rate 65/s and shear history of 5 min at 1400/s (After Shah and Asadi, 1997).

fluids 4.1. Rheology characteristics

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4. Rheology, friction pressure and proppant transport characteristics of guar-based fracturing

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Guar-based fracturing fluid, as a widely used water-based fracturing fluid (Williams et al.,

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2012), has been extensively study over years. Higher viscosity increases fracture aperture, so it can have higher concentrations of proppant (Middleton et al., 2015). It reduces the leak-off to improve fluid efficiency, improves proppant transport and reduces the friction pressure (Jeffrey et al., 2013). However, excessive viscosity will reduce the fracture length. Hence, viscosity will directly affect the final fracturing operation, and many previous studies have been devoted to investigate the guar gel viscoelasticity and its influencing factors.

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Fig. 11 Viscosity changes with the increase of the concentration of the guar gel: C* = Critical overlap concentration; C' = Crosslinking concentration; C** = Critical entanglement concentration.

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The relationship between polymer viscosity and concentration has been analyzed experimentally and theoretically. From Figure 11, as the amount of polymer material added to the solvent increases, the viscosity of the solution is nonlinearly modified. Whenever a single polymer molecule dissolves in a good solvent, the molecule first swells as the solvent penetrates into the

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molecule (Lei and Clark, 2007). In the dilute solution stage (before point C* in Figure 11), due to the mutual repulsion of the guar polymer chains, the swelling coils began to shrink but did not contact, so the viscosity of the guar gel solution did not increase significantly. After the point of

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critical overlap concentration (C*), polymer chains begin to contact and overlap with neighboring

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molecules, and solution viscosity begins to increase significantly. After the point of critical entanglement concentration (C**), the polymeric polymer chains interpenetrate each other and form a tightly tangled network structure. Meanwhile, because the gel is over-crosslinked, water can be "squeezed out" from the gel matrix. In actual fracturing operations, the over-loaded polymer can result in impaired proppant conductivity (Jeffrey et al., 2013). The critical crosslinking concentration (C') exists between C* and C **. Only at this concentration, the gel can form a spatial three-dimensional network structure with good viscoelasticity (Abad et al., 2009). However, the 16

ACCEPTED MANUSCRIPT relationship between the critical crosslinking concentration and the polymer and crosslinker has not yet been clearly defined. A reasonable pH range is an important condition for ensuring the viscosity of crosslinked

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guar fluid. No matter either the strong acidity or strong alkaline conditions, the viscosity of guar-based fluid will be reduced (Harris, 1988). For example, the addition of sodium bicarbonate reduces the viscosity because the change of pH will weaken the steric hindrance effect and the

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entwine effect of guar molecules (Srichamroen, 2007). Kruijf et al. (1993) found that the viscosity

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of the crosslinked guar-based fracturing fluid is related to the number and strength of the crosslinking bonds, and the temperature will affect the ionization equilibrium state of the borate and eventually affect the viscosity of the guar-based fracturing fluid. In the initial stage of formation of the crosslinked gel, a moderately high temperature is good for increasing the rate of the crosslinking

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reaction, thereby increasing the viscosity of the gel. However, after the crosslinking reaction is completed, if the gel is exposed to a high temperature for a long time, the cross-linking bonds will be degraded and the gel structure will be destroyed (Gliko-Kabir et al., 1999). In addition, Wientjes

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weight of guar.

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et al. (2000) found that the zero shear viscosity of guar gel can be influenced by the molecular

Because the guar gel is a flowing fluid during the fracturing process, the dynamic rheological characteristic of the guar gel attracted much attention from researchers and was studied combining lab test and common rheological models for a long time. The most widely used one in early time is the power law of Ostwald (1925) among these models because of its simplicity (Table 2). Figure 12 shows the viscosity changes of the guar solution with the shear rate increases and the data was fitted by the power law. It can be found that the K (Consistency index) increases with the increasing of 17

ACCEPTED MANUSCRIPT guar concentration while n (Flow behavior index) decreases (Whitcomb et al., 1980). In addition, Doublier and Launay (1981) found n for guar solution was essentially temperature independent. Table 2 Commonly used models in guar gum rheology study.

Carreau

= =

= Maxwell

+ +

" #

=

1+

− ( )( −

[1 + (

(

( ) , 1+( )

)

η Apparent viscosity K Consistency index Shear rate (s-1) n Flow behavior index η0 Zero-shear rate viscosity η∞ Infinite shear rate viscosity kCR, kCA Time constant m Number of Maxwell elements Gi Spring constant ηi Dashpot viscosity λi Relaxation time of the ith Maxwell element ω Angular frequency

Carreau P J, 1968

= Maxwell J C, 1867

" #

Ostwald W, 1925 Cross M M, 1965

)

) ]

Nomenclature

1+(

)

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Cross

(n-1)

η=K

Power law

Founder, year

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Equation

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Model

Many researches showed that the guar solution is a pseudoplastic fluid that has the

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shear-thinning behavior, and Doublier and Launay (1981) found that the decrease rate of the viscosity may change as the shear rate increases, which lead to the failure of power law fitting in the regions of very low shear rate range (Figure12). This characteristic was also observed by Lapasin et

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al. (1991) in hydroxyethyl guar solution. Graessley (1974) gave the explanation of the mechanism

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that in the upper Newtonian plateau, the disruption of entanglements by the imposed shear is dynamically balanced by the formation of new interactions between different chain segments.

18

ACCEPTED MANUSCRIPT 104

K=136 n=0.14

102

100 Newtonian plateau K=2.37 n=0.39

10-1 10-2 10-3 10-4

2% Guar concentration 0.5% Guar concentration

10-3

10-2

10-1

100

101

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101

102

103

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η, Viscosity (Pa·s)

103

104

Shear rate (Sec-1)

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Fig. 12 Viscosity vs. shear rate of purified guar solutions showing power law fit (after Whitcomb et al., 1980). Compare with the power law model, the Cross model (Cross, 1965) and the Carreau model (Carreau et al., 1968) have better performance because it can be used over the entire range of shear rate, which can be verified in Figure 13 and Figure14. These two models have a similar formation

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that both them have four parameters. However, the four parameter models are difficult to apply

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because there is seldom enough data to allow good model fitting (Garakani et al., 2011).

a Guar b HPG Fig. 13 Flow curve of Guar and HPG solutions (with concentration of polymer from 0.1% to 2.0%) as a function of the shear rate, at temperature of 40 ℃: 19

ACCEPTED MANUSCRIPT The full lines represent the calculated values according to the Cross equation (after Risica et al., 2010). 104

103

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λ=0.666 n=0.4285 η0=2459

102 0.8% Guar concentration 1% Guar concentration 1.2% Guar concentration

λ=0.1818 n=0.3655 η0=790

101 10-2

10-1

100

101

102

103

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Shear rate (Sec-1)

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η, Viscosity (Pa·s)

λ=1.02 n=0.5874 η0=5419

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Fig. 14 Flow curve of Guar solutions (with concentration of guar at 0.8%, 1.0%, and 1.2%) as a function of the shear rate at pH of 6.4: The full lines represent the calculated values according to the Carreau equation (after Venugopal and Abhilash, 2010).

Fig. 15 The change of the G’ and G’’ with the angular frequency increases: Solid lines indicate the best fitting of the generalized Maxwell Model (after Meidav, 1964). Meanwhile, many pieces of research showed that the crosslinked guar gel is a viscoelastic fluid (Kesavan and Prud' Homme, 1992), and the viscoelastic properties of fluid are well described by two functions: the storage modulus (G') and loss modulus (G''), which represent the elastic of the polymer network and the local fraction of the polymer chain respectively (Pezron et al., 1990). 20

ACCEPTED MANUSCRIPT Some researchers found that the changes of G' and G'’ with the increasing angular frequency are fitted extremely well by the Maxwell model (Figure 15) (Coviello et al., 2013; Meidav, 1964). The substance of the Maxwell model is composed of a spring and dashpot in series, which can reflect

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the stress relaxation characteristics of viscoelastic fluids. Gittings et al. (2001) studied the effect of sodium ion on the viscoelasticity of guar gel by rheological method combined with fractal theory. The results showed that the fractal dimension of

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guar gel in salt solution was significantly larger than that of guar gel in pure water due to the salt

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ion can cause the collapse of the guar molecular chain, resulting in a very low G' and G'' of the solution. As shown in Figure 16, both G' and G'' of the solution were related to the HPG or crosslinker concentration. The G' increases as a function of pH between 7.5 and 10.5 and then decreases at higher pH values (Figure 16a), while Figure 16b shows that with pH increases, there is

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no notable increase or decrease trend of the G'' (Kruijf et al., 1993). HPG/Crosslinker concentration (lbm/1,000 gal) 40/8 40/4 40/3 20/8 20/4

30

20 Positive correlation

Negative correlation

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G'(N/m 2 )

25

15

5 0 7

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10

8

9

10

35

20/3

HPG/Crosslinker concentration (lbm/1,000 gal) 40/8 40/4 40/3 20/8 20/4

30

20/3

25 G''(N/m2)

35

20 15 10 5

11

12

13

0

14

7

8

9

10

11

12

13

14

pH

pH

a

b

Fig. 16 G' and G'' of a borate-crosslinked HPG as function of pH at 25 ℃ (After Kruijf et al., 1993). Much work has been done about the rheological characteristic of the guar gel. However, in term of the guar-based fracturing fluid which prepared with s series of additives besides the guar, the influence of the other additives (eg. anti-swelling agent, cleanup additive) on the rheological 21

ACCEPTED MANUSCRIPT characteristic of the fracturing fluid should be further studied by using the common rheological models. 4.2. Friction pressure

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Compare with the slickwater fracturing, the guar gel fracturing always has higher friction pressure. The greater the friction of the fracturing fluid in the wellbore, the less effective hydraulic horsepower to make the fractures. Excessive fracturing fluid friction tends to elevate the wellhead

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pressure and potentially results in fracturing system failure. Tanet al. (1992) found that the friction

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pressure of the guar-based fracturing fluid was impacted by many parameters of the fluid, like the pH, guar and crosslinker concentrations, temperature.

Water-based fracturing fluids are generally a two-phase slurry consisting of a base gel and proppant. The addition of the proppant to the guar gel increases the non-Newtonian character of the

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fluid system (Keck et al., 1992). It can be seen from the research conducted by Shah and Lee (1986) that both the proppant concentration and proppant size have influence on the friction pressure drop during guar-based fracturing treatment (Figure 17).

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A great number of studies are available on estimating friction pressures losses for

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polymer-based pseudoplastic power fluids (Pandey, 2001). Typical experimental methods for these studies involves pipe flow test, and some empirical equations and theoretical models were proposed based on lab experiment and field pressure data analysis (Harris and Heath, 1998; Pandey, 2001). However, the roughness of the wall of the pipe was always neglected. By conducting the pipe flow test with two nominal stainless steel pipes (one smooth and the other rough), Subhash found that pipe roughness effects are very significant when estimating friction pressures of fracturing fluids. These effects are more pronounced with less viscous fluids than with more viscous fluids and are 22

ACCEPTED MANUSCRIPT also more pronounced at higher rates with both fluids (Shah, 1989). However, the roughness should be quantitatively evaluated so that the influence of the roughness on the friction pressure loss can be deeply investigated. Meanwhile, the friction pressure results from that the guar gel flows along the

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wall of the coal fractures should be considered when analyzing the friction pressure during coalbed fracturing. 120

50 40

10/20 mesh sand 20/40 mesh sand

100 80 60

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Pressure drop, psi/100 ft

60

Percentage friction pressure increase over base gel (%)

Base gel (40lb HPG/Mgal) 2 lb/gal 4 lb/gal 6 lb/gal 8 lb/gal

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70

30 20 10

40 20

0

0 2

4

6

0

8 10 12 14 16 18 20

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0

Flow Rate, bbl/min

2

4

6

8

10

12

14

Sand Concentration, lb/gal

2- 7

8

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a b Fig. 17 The friction pressure change with the increase of the proppant concentration and size: a: Comparison of actual friction pressures at various flow rates for 40 lbm HPG/1000 gal and sand-laden 40 lbm. b: Effect of proppant size on friction pressures of 50 lbm HPG/1000 gal fluid in in. tubing at 20 bbl/min (After Shah and Lee, 1986).

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4.3. Proppant transport characteristics

In addition to the pressure required for the transmission of pressure in the fracturing fluid used for fracturing, it is necessary to have the proppant carried into the fracture to maintain the opening of the fracture so as to ensure the flowability of methane gas in CBM reservoirs. Sand carrying capacity testing of fracturing fluids is one of conventional methods of evaluating fracturing fluid performance. Notably, the early test method was mainly static sand test, which can estimate the settling time of the sand in the pipe at static or low shear rate, but it has limitations and cannot 23

ACCEPTED MANUSCRIPT accurately characterize the dynamic sand carrying capacity of the fluid (Holtsclaw et al., 2011). Meanwhile, some scholars have tried both experimental and numerical methods to study the dynamic sand carrying capacity (Jin and Penny, 1995; Harrington et al., 1979; Barreeand Conway,

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1994). For example, Padhy et al., (2013) performed simulations for a sphere sedimenting in an elastic guar gum solution with a cross-shear flow and found that the shear thinning of the

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guar-based fracturing fluid lead to the decrease in the drag (or increase in settling velocity).

a 0.4% linear HPG solution

b 0.5% linear HPG solution

c 0.5% crosslinked HPG solution

Fig. 18 SEM image of the linear and crosslinked guar gel (After He et al., 2015).

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The stronger sand carrying capacity of the guar-based fracturing fluid is attributed to two reasons: (1) it has a higher viscosity that can increase the drag force for suspended sands and (2) the

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polymer network structure can create the mesh-like structure improve the sand ratio during construction (Wang et al., 2014; Lebas et al., 2013), which can carry the sand towards the toes of

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the induced fractures. As shown in Figure 18, in the linear HPG solution, the guar gel units are intertwined to form a multi-layered spatial network structure with pores of different sizes. The linking structure is loose and porous in the solution with 0.4% mass fraction of linear HPG (Figure 18a). With an increase of HPG mass fraction, the linking structure becomes denser and stronger (Figure 18b), so that the network structure has higher strength resulting in higher sand carrying capacity. With crosslinking, the internal guar gel unit of the fracturing fluid overlap with each other to form a complex and crosslinked network with very few pores, which has better viscoelasticity 24

ACCEPTED MANUSCRIPT and sand carrying capacity compare with linear HPG solution (Figure 18c). 0.001 Viscosity, CC* Settling velocity, CC*

10

0.01 0.1

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1

Settling velocity (cm/min)

0.1

1

C*viscosity=0.225 wt.%

10

0.01

100

0.001

C*Settling=0.237 wt.%

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viscosity (Pa·s) at suspension shear rate

100

1E-4

1000

0.01

0.1 Guar concentration (wt.%)

1

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Fig. 19 Comparison of viscosity at suspension shear rate with settling velocity of 20 wt.% slurry in guar solutions (After Goel et al., 2002): For suspensions settling in non-crosslinked guar solution, there is a critical guar concentration above which the suspension settling velocity decreases considerably with an increase in the guar concentration. This concentration is analogous to the overlap concentration defined for viscosity measurements.

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For non-crosslinked guar gel, the sand carrying capacity mainly depends on the viscosity as illustrated in Figure 19 (Goel et al., 2002), and some researches showed that the proppant transport is mainly governed by zero shear viscosity of the fluid (Asadi et al., 2002; Shah et al., 1998). While

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viscosity has a weaker effect on sand carrying capacity of crosslinked guar gel. Kramer et al. (1987)

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found that HPG solutions have similar surface viscosities after crosslinked by two different titanium crosslinkers, but they have different fracturing fluid network structures and have different sand-carrying capabilities within fractures. Improving the shear stability of the gel helps to maintain the gel structure and thus can guarantee good sand carrying capacity. In addition, pH has an impact on the sand carrying capacity of borax-crosslinked HPG. Goel et al. (2002) found that the guar gel with a good sand carrying capacity has the similar storage modulus, but the loss modulus is quite different, and for the viscoelastic fluid, the viscosity is considered less important on sand carrying 25

ACCEPTED MANUSCRIPT capacity. However, many fracturing design models consider fracturing fluids as power law fluids without considering fracturing fluid elasticity (Acharya, 1988). Roodhart (1985) also found that in boron-crosslinked HPG, the settling velocity of the proppant is determined by the storage modulus

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rather than the loss modulus. 5. Advantages and disadvantages of guar-based fracturing fluid used in CBM reservoirs 5.1. Advantages of guar-based fracturing fluids

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Depending on the guar concentration, the viscosity of the guar-based fracturing fluid can be

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several orders of magnitude higher than that of slickwater (Li et al., 2016). Sufficient viscosity can promote the fracturing fluid to make enough fracture aperture, then the stimulated fracture network will have better connectivity and permeability and higher stimulated reservoir volume. Howard and Fast (1957) found that high-viscosity fracturing fluids are most effective in reservoirs where the

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differential-treating pressure is low, increases in the viscosity will result in increases in the fracture area. Meanwhile, according to theoretical calculations and field results, the fluid-loss has a significant effect on fracture extension during treatment (Howard and Fast, 1957; Barbati et al.,

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2016). Compare with the slickwater, the guar gel has low fluid-loss, which promotes the fracture

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extension thereby enhance the flowability of the CBM (Barati and Liang, 2014). As mentioned in Section 4.3, the guar-based fracturing fluid, especially the crosslinked guar gel, has good sand carrying capacity compared with the slickwater, this ensures that the proppant can be transported into the fracture during treatment and will maintain the opening of the fracture, thereby enhance the flowability of the CBM. Moreover, some new technologies are developed to further enhance the sand carrying capacity of guar-based fracturing fluid (eg. fiber fracturing) (Bivins et al., 2002). In addition, the guar-based fracturing fluid is less costly than VES fracturing 26

ACCEPTED MANUSCRIPT fluids which also have good viscoelasticity, because the surfactants needed for VES fracturing fluids are usually slightly more expensive. This is an important factor that makes the guar-based fracturing fluid widely used worldwide in CBM industry.

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5.2. Disadvantages of guar-based fracturing fluids The primary disadvantage of guar-based fracturing fluid is its damage to the CBM reservoir. The high viscosity leads to the difficulty of gel breaking. Ammonium persulfate usually has good

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gel-breaking efficiency at temperature of 48.9 ℃(Hinkel, 1981). However, most CBM reservoirs

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are in shallow depth and the temperature is relatively low, thus low reservoir temperature can degrade the performance of breakers. The effective flowback of guar-based fracturing fluid is very poor for some CBM reservoirs (Zheng et al., 2013). Palmer et al. (1991a) found that although the concentration of colloids in the returning fluid gradually decreased through long-term cleaning up,

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20% to 30% of gel was permanently left in the CBM formation. Higher guar concentration are expected to have a higher polymer residue. Unfortunately, a high guar concentration is typically required to transport sand particles through the induced fracture (Goel et al., 2002). The optimized

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guar concentration, thus, needs to be carefully studied for each specific CBM formation to not only

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effectively induce the fracture and transport the sands, but also achieve the highest polymer flowback to minimize the reservoir damage for the CBM production. The guar gel retained in the CBM formation has large amount of organic matter, which causes corruption, contaminate groundwater, and endangers the surrounding environment and underground local ecological system (Kreipl and Kreipl, 2017). From the production point of view, the leftover guar gel can cause a series of damage to the gas flow in the reservoir. Figure 20 shows the possible reservoir damage with gel-leftover. Figure 20a shows the filter cake formed by the solid 27

ACCEPTED MANUSCRIPT residue of the fracturing fluid on the surface of the fracture (Barati and Liang, 2014). Figure 20b shows that the capillary force in the reservoir can cause the water block effect (Holditch, 1979). Figure 20c shows clay swelling after invasion of the filtrate, result in pore blockage (Wang et al.,

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2012). Figure 20d shows the residual solid particles flow with the filtrate and accumulate in the pore throat, causing pore blockage (Gall et al., 1988). Figure 20e shows due to the fluid leak off and fracture closure, the gel concentration is increased, so that it is difficult to break the gel and stay in

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the reservoir (Barati and Liang, 2014). Figure 20f shows the gel is adsorbed on the surface of the

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coal, causing coal swelling, which reduces the fracture aperture and thus reduces the permeability (Olsen et al., 2003). The illustrated reservoir damages will affect the conductivity of the fracture, impair the permeability of the coal seam, modify the gas desorption kinetics, alter the gas diffusion capability and ultimately decease the gas production for the fractured CBM wells. Palmer pointed

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out that despite the poor sand-carrying capacity of water, the production of water fracturing is higher than that of crosslinked guar gel for some CBM wells. The reason is that the guar gel fracturing fluid induces the gas transport damage to the CBM formation (Palmer et al., 1991a;

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Palmer et al., 1991b). Kefiet al. (2004) compared the damaged of VES fracturing fluid and guar

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fracturing fluid to coal seam permeability and the result is summarized in Figure 21. From the results, it can be seen that the VES fluids have less permeability damage compared to the gel-based fluids. It is unexpected that the gelled fluid with breaker can damage more than without breaker. Brannon and Pulslnelli (1990) have investigated the damage of crosslinked HPG and uncrosslinked HPG on sand and the results are shown in Figure 22. It can be concluded that despite the addition of breakers (Ammonium persulfate) to promote flowback, damage cannot always be completely avoided. In addition, due to the strong adsorption of coal on the gel, it can be inferred that the 28

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damage to coal permeability will be more serious.

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Fig. 20 Coal seam fracturing stimulation and fracturing fluid damage: The damage of the residue to the coal reservoir includes the following types: 1) Damage of the filter cake and the concentrated fluid: Because of the leak off, a compacted filter cake forms on the surface of the fracture generated by fracturing (Figure 20a). 2) the water blocking will occur once the filtrate come into the pore throat (Figure 20b). 3) the filtrate will cause the swelling, dispersion, and migration of the clay, then the pore may be plugged (Figure 20c). 4) Some residual solid particles may cause clogging of the throat or the fracture (Figure 20d). 5) The concentrated fluid will form after the filtrate comes into the fracture, and will hinder the gel breaking (Figure 20e). 6) Adsorption of guar gel on the coal surface causes the coal matrix to swell, resulting in reduced porosity, which in turn leads to a decrease in permeability (Figure 20f).

Fig. 21 Coalbed retained permeability after damage of VES fracturing fluid and gel fracturing fluid (After Kefi et al., 2004).

29

ACCEPTED MANUSCRIPT 100 Borate-Crosslinked Guar or HPG Non-crosslinked Guar or HPG

80 70 60 50 40

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Retain Permeability (%)

90

30 20 10 0

1 2 3 4 5 Pounds APS per 100 Pounds Guar or HPG

6

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0

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Fig. 22 Effect of the Ammonium Persulfate (APS) /polymer concentration on the retained permeability of proppant packs (After Brannon and Pulsinelli, 1990). Cooke (1975) has proposed a model that can be used to predict the local reduction in fracture conductivity from fluid residue (Figure 23). As the model characterized after the fracture closed during fracturing, the pore volume of fractures was occupied by proppants and the gel residue

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(Figure 23). The volume of the proppant in the fracture can be calculated first as follows:

VsF =

Cs

ρs

(1)

proppant.

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where, Cs is the local concentration of proppant in the fluid when closure begins, ρs is the density of

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Then the pore volume of closed fracture in absence of residue can be drawn as:

 φ  Cs  φ  VpF = VsF  =    1-φ ρs  1-φ

(2)

The volume of the fluid residue can be further divided into two part that results from the polymer and fluid-loss additive respectively (Figure 23). Therefore, the local volume of residue-forming material in the fracture after closure is:

30

ACCEPTED MANUSCRIPT c VrF =  f ρ  f

  cp   m +   n   ρp 

(3)

where, VrF is the volume of residue in closed fracture, cf is the local concentration of fluid-loss additive in the fluid, ρf is the density of fluid-loss additive in degraded fracturing fluid, cp is the

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local concentration of polymer in the fluid, ρp is the density of residue after polymer degrades, m is the fraction of fluid-loss additive that remains in the fracture after closure or enters the fracture after

enters the fracture after production begins.

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Then, the reduction of permeability of the fracture is:

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production begins, n is the fraction of injected polymer that remains in the fracture after closure or

3

 VpF −VrF  k / k0 =    V pF  

(4)

where, k is the permeability of the propped fracture after damage of the fracturing fluid, k0 is the

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permeability of the propped fracture without residue.

Fig. 23 Model for predicting concentrations of solids in the fracture (After Cooke, 1975). Eq. 4 reflects the reduction mechanism of the propped fracture during hydraulic fracturing in some extent. However, it is worth noting that due to the unique physiochemical properties of coal, the guar-based fracturing fluid may cause some unique damages. First, the coal matrix has a strong ad-/ab-sorption capacity on liquid, and this fluid sorption is irreversible and can permanently damage the formation. In other words, it is impossible to remove gel chemicals and other additives 31

ACCEPTED MANUSCRIPT absorbed on coal by subsequent pressure depletion and well cleaning. Even a slight swelling can cause a significant drop in coal permeability because of low porosity of coal as illustrated in Figure 20f (Puri et al., 1991).

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Due to size limitations, laboratory tests may not be able to realistically simulate the flow of fracturing fluid in coal fracture. In fact, the width of these fractures is large enough so that gel can flow through them. Therefore, some researchers believe that the essence of the permeability damage

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of coal seam is due to matrix swelling induced by absorption of fracturing fluid instead of gel

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plugging (Palmer et al., 1991b). Because of the fluid adsorption induced coal matrix swelling, the in situ stress profile can be significantly modified due the lateral confinement (Liu and Harpalani, 2014; Fan and Liu, 2018; Saurabh and Harpalani, 2018a; Saurabh and Harpalani, 2018b). The excessive horizontal stress can be generated in situ and therefore, the cleat and induced fracture

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apertures will be compressed and significantly decrease the effective permeability of the treated coal. Unfortunately, this phenomenon has never been studied under in situ boundary condition and future studies will be essential to comprehensively evaluate the permeability damage due the

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gel-based fluid injections (Figure 24).

32

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Fig. 24 Reduction of fracture aperture of coal reservoir induced by adsorption of fracturing fluid: After the guar gel is injected into the coal reservoir, the gel is adsorbed on the surface of the fracture, and the adsorption swelling occurs, resulting in a decrease in the fracturing aperture (Fig. 24b). In addition, the CBM formation maintains a constant strain in the horizontal direction due to the in situ boundary confinement, namely, uniaxial strain boundary condition (Fig. 24d). Therefore, the swelling caused by the gel adsorption will increase the horizontal stress which will transfer to an increase of effective stress in the horizontal direction, and this excess horizontal stress will lead to further reduction of the fracture aperture (Fig. 24c).

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As mentioned before, coal seam fracture propagation always terminates at the coal-rock interface. The dashed region in Figure 25 represents the invaded region due to lateral leak off from

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a vertical fracture. For simplification, the elliptical invasion area can be represented by a rectangular area of length twice the fracture half-length, L and width 2D as illustrated in Figure 25 of solid

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black rectangular. If the total height of the stimulated coal is H, then the volume of fracture fluid invasion into the coal reservoir can be estimated from a mass balance calculation as Eq. 5 (Palmer et al., 1991b). It can be seen that when the lost volume (V) and the total fracture length (2L) are constant, the depth of invasion area D is greater due to the small thickness and the low porosity of the coal seam. Therefore, the guar-based fracturing fluid may have severe formation damage to the CBM reservoirs.

V = 2L × 2D × H ×φ × (1− Swc ) 33

(5)

ACCEPTED MANUSCRIPT where, V is the pore volume accessible to the fracturing fluid which leaks off, L is the half-length of the invasion area, D is the half-width of the invasion area, H is the thickness of the coal reservoir,

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φ is coal porosity, Swc is connate water saturation (about 0.5).

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Fig. 25 Conceptual prediction model of fracturing fluid invasion area for a CBM reservoir (after Palmer et al., 1991a). Gall BL et al. (1988) found that a high concentration (ten times as usual concentration) of breakers can reduce the impact of HPG residue on reservoir permeability and restore permeability

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to some extent. In some cases, however, the fracturing fluid added with breakers further reduces the permeability of the reservoir (Kefi et al., 2004). Ammonium persulfate is often used as a surface modification of coal. Many studies have found that ammonium persulfate solution has an effect on

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the adsorption characteristics of coal surface (Beck et al., 2002; Hao et al., 2013). Similarly,

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inappropriate amount of hypochlorite may cause changes in the wettability of the coal surface due to oxidation thereby affecting the water permeability (Nimerick et al., 1991). The coal surface contains a large number of diverse functional groups that may undergo complex chemical reactions with breakers and other additives and affect the adsorption properties and even pore structure of the coal surface (Li and Kang, 2016), the microscopic mechanism of this effect deserves further study. Most of the fracturing fluids including guar gel used in the CBM stimulation are originated from conventional oil and gas operations, as well as the breaker like ammonium persulfate. These 34

ACCEPTED MANUSCRIPT additives of the fracturing fluid may be suitable for the conventional oil and gas operations but may not well serve for CBM stimulation. The combination of the high viscosity of the guar-based fracturing fluid and the strong adsorption of the coal may lead to difficulties for effective guar gel

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flowback. Therefore, it is necessary to develop new gel-breaking additives which can promote the flowback of the guar-based fracturing fluid effectively to minimize the damage of the guar gel to the coal permeability.

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In addition to fluid induced reservoir damage, the guar-based fluid is known for poor

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flowability in the fracture due to its high viscosity and this pose a negative impact on the efficiency of the hydraulic horsepower. Nevertheless, the crosslinked guar gel fracturing process may be more complicated than the slickwater fracturing because of the need for careful mixing of various additives and careful control of viscosity. According to the previous analysis, we can know that the

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guar-based fracturing fluid may cause many types of damage to the coal reservoir. However, the mechanism of these damages has not been given a systematic investigation. As we mentioned, during the CBM extraction process, the methane molecule desorbed from the coal surface firstly,

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then diffused to the outside of the coal matrix, and comes into the gas well by seepage process.

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Thus, the process of desorption, diffusion, and seepage may all be affected by the fracturing fluid invasion and have their own influence mechanism. In recent years, limited efforts have been devoted to investigating the influence of fracturing fluid on the desorption, diffusion and seepage characteristics of the coal. Some researchers compared the impact of guar gel, slickwater, and VES fracturing fluid on the desorption, diffusion and seepage of CBM by sorption or seepage experiments, and some influence mechanism was revealed (Kang et al., 2016; You et al., 2015; Lu et al., 2017; Lu et al., 2015; Li and Kang, 2016). However, most of the studies only focused on the 35

ACCEPTED MANUSCRIPT effects of a single fracturing fluid, or simply compared the effects of several fracturing fluids. For guar-based fracturing fluid, different concentration of each additive lead to different properties of guar gel, thereby pose to a different degree of damage to the CBM desorption, diffusion and

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seepage. Therefore, the systematic investigation is required to clarify the damage mechanism of the guar-based fracturing fluid to the CBM flowability. On the other hand, it is necessary to build better theoretical models to characterize the damage of fracturing fluid to the CBM flowability. Both Eq. 4

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and Eq. 5 are very simple models proposed early. They can only semiquantitatively predict the

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damage degree to the gas flow. However, less new theoretical model to reflect the fracturing fluid damage to the natural gas reservoir, let alone the damage of the guar gel to the CBM flowability.

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6. Field applications

Fig. 26 Fracturing fluid application distribution in the US (Flores , 2013; Palmer, 2010; Pashin, 2007): The linear gel and crosslinked gel are still widely used in the United States despite the differences in coal ranks and geological conditions in the basins. The US CBM industry is mature and has commercially produced gas over three decades. The linear gel and cross-linking gel were commonly used for CBM stimulation and they were used in major CBM basins, including San Juan Basin, Black Warriors Basin, Arkoma Basin, Raton Basin 36

ACCEPTED MANUSCRIPT and others as shown in Figure 26. Even through gel-based fracturing fluid and other fracturing fluids were commonly used in CBM industry, only a few literatures have compared the effectiveness of guar-based and other types of fracturing fluids. In this work, comparison analysis

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was carried out to investigate the field performance of guar gel, slickwater or foam for CBM stimulation from the literature.

During the Deep Coal Seam Project conducted at Red Mountain Site, two wells (1 DS and 2

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DS) were stimulated by using nitrogen foam and linear gel, respectively (Schwoebel et al., 1987). It

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can be seen from Table 3 and Figure 27 that in the fracturing process, the consumption of linear gel is slightly larger than nitrogen foam, and the consumption of proppant in two wells is very similar, but the stimulation used by the linear gel is clearly better than nitrogen foam. 120

1DS with nitrogen foam 2DS with linear gel

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80 60 40

Shut-in pump

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Gas rate (MCFD)

100

Fracturing

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20

0

0

2

4

6

8 Months

10

12

14

Fig. 27 Gas production of 1 DS and 2 DS wells (after Schwoebel et al., 1987). Table 3 Fracturing parameters and gas production of 1 DS and 2 DS (Schwoebel et al., 1987). Well No.

1 DS 3

2 DS 3

Fracturing fluid Proppant Average treating pressure

315 m of Nitrogen foam 116121 kg of 20/40 mesh sand 27.6 to 41.8 MPa

463 m of Linear gel 117936 kg of 20/40 mesh sand 17.24 to 20.56 MPa

Gas production (Prior stimulation)

255 m3/d

113 m3/d

Gas production (After stimulation)

1047 m3/d

2265 m3/d

37

ACCEPTED MANUSCRIPT Zuber and Kuuskraa (1990) used COMET to simulate and predict the production effect of fracturing within 10 years with different well space by collecting the on-site reservoir parameters and production cost of Oak Grove Field (Table 4 and Table 5). Both the high permeability (k = 20

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md) and low permeability (k = 6 md) were simulated, respectively. The result showed that gel-based fractures are superior to water-based treatments because they achieve peak production rates at earlier times at nearly twice the peak rates of water-based treatments as demonstrated in Figure 28.

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The recovery increase created by gel-based fracturing treatments more than compensates for the additional cost of these treatments over water-based treatments.

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Table 4 Reservoir parameters used for simulator (Zuber and Kuuskraa, 1990). Value

Temperature (℉) Gas specific gravity, air=1 Thickness (ft) Porosity (%)

75 0.6 8 2.5

Langmuir volume (scf/ft3)

27.2

Langmuir pressure (psi) Gas content (scf/ton) Initial pressure (psi) Initial water saturation (%) Bottomhole well pressure (psi) Desorption pressure (psi) Cleat spacing (inch) Sorption time (days)

147 430 450 100 40 400 0.1 5

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Parameter

Table 5 Representative well costs (Zuber and Kuuskraa, 1990). Cost category

Cost (1987 dollars)

Drilling and completion Production and lease equipment Stimulation Water-based hydraulic fracture Gel-based hydraulic fracture Total investment Water-based hydraulic fracture Gel-based hydraulic fracture Annual operating costs (per well)

50000 40000

38

20000 35000 110000 125000 8000

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180 20 Acre Water-based 40 Acre Water-based 80 Acre Water-based 20 Acre Gel-based 40 Acre Gel-based 80 Acre Gel-based

120 100 80 60

140 120 100 80 60

40

40

20

20 0

0 0

500

1000

1500

2000

2500

3000

3500

0

4000

500

Producing time (Days)

1000

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140

40 Acre Water-based 80 Acre Water-based 160 Acre Water-based 40 Acre Gel-based 80 Acre Gel-based 160 Acre Gel-based

160 Methane rate (Mscf/D)

Methane rate (Mscf/D)

160

1500

2000

2500

3000

3500

4000

Producing time (Days)

a low-permeability setting

b high-permeability setting

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Fig. 28 Simulated methane rates at high and low permeability setting with different treatment (after Zuber and Kuuskraa, 1990).

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In addition, a project aimed at determining the best stimulation treatment for multiple coal seams has been carried in the Mary Lee coal group at Rock Creek in Warrior basin, a total of 153 wells were subjected to fracturing operation. Twenty-seven used cross-linked gels to enhance production. Twenty-seven used foam fluids and 97 used water. Over 600 days of gas production

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data showed that gel fracturing was better than water fracturing and foam fracturing illustrated in Figure 29 (Schraufragel et al., 1991).

160

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Foam fractured Water fractured Gel fractured

140 120

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Daily gas production (Mcf/D)

180

100

80 60 40 20

0 0

100

200

300

400

500

600

Days

Fig. 29 Team project, Oak Grove Field of Black Warrior basin, as production VS stimulation fluid (after Schraufragel et al., 1991).

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Fig. 30 Random distribution of water-fractured wells and gel-fractured wells in the Oak Grove Field pilot (after Palmer et al., 1991a; Palmer, 1992).

Fracture fluid

Max sand concentration

Crosslinked gel Water

10 ppg 5 ppg

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Table 6 Comparison between gel fracture and water fracture treatment in Oak Grove Field (Palmer et al., 1991a). Sand load/zone

Try to prop all coal seams?

Cost/Well

100,000 lb 70,000 lb

√ ×

$50,000 $28,000

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However, some studies also showed that water fracturing sometime is better than guar gel fracturing. To compare the performance of water and gel stimulations, 23 CBM wells were designed in the western portion of the Oak Grove Field in Black Warrior Basin. Thirteen wells were

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gel-fractured, and 10 were water-fractured. To eliminate deviations caused by changes in geological

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conditions, these wells are distributed evenly and randomly as shown in Figure 30. The fractured coal seams include Mary Lee, Blue Creek, and Black Creek seams. Notably, for the crosslinked gel fractured well, all coal seams were tried to be propped (Table 6). Over twelve months of production data shown that water fracturing was better than gel fracturing (Figure 31) (Palmer et al., 1991a; Palmer, 1992). Researchers believed that the reason for the lower production of the wells after gel fracturing is that the gel has caused serious damage to the formation's permeability. It should be noted that the observation duration of the gas production in the abovementioned projects was relatively short and all were within a few years, so the conclusion may not be able to infer for the 40

ACCEPTED MANUSCRIPT whole well life. In long term, it is still questionable which treatment is superior. For example, it can be seen from Figure 29 that the gas production of gel fracturing began to exceed that of water fracturing after about 240 days of production (Schraufragel et al., 1991). With more than three

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decades of CBM production from San Juan basin and Black Warrior Basin, some of the wells continuously produce commercial volume of gas after more than 30 years and they are still active for production. Therefore, we should re-evaluate the effectiveness of treatment over a long period

225

225 Gas Water

175 150 125 100 75 50 25

200 Daily gas production (Mcf/D)

200

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Daily gas production (Mcf/D)

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time given the super long life span for CBM wells.

175

Gas Water

150 125 100 75 50 25

0

0

50

100

150

200

250

300

350

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0

Days

a Gel-fractured well

0

50

100

150 200 Days

250

300

350

b Water-fractured well

Fig. 31 Average gas and water production from water-fractured and gel-fractured wells (all wells shifted to start at the same time) (Palmer et al., 1991a; Palmer, 1992).

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In general, for coal seams with different geological conditions, the performance of

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guar-based fracturing may be quite different. How to distinguish the applicability of guar-based fracturing according to the geological conditions of the coal seam is very important (Weaver et al., 2003). This needs a further investigation of the influence of the guar gel on the sorption, diffusion, and permeability of the CBM, and physical properties of fractures in the coal seam with guar-based fracturing. 7. Summary As the most widely used fracturing fluid in the world, guar-based fracturing fluid has long 41

ACCEPTED MANUSCRIPT been studied by researchers and field engineers in the oil and gas industry. In this work, the application of guar-based fracturing fluids in CBM treatment was reviewed and the main points can be summarized as follows:

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1. Because of the unique physiochemical and mechanical properties of the coal formation, the fracture morphology produced by fracturing is quite different from that of conventional gas reservoirs. In the CBM field, the fracturing treatment tends to produce wider and shorter

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fractures. Due to the inhomogeneity of the mechanical properties of coal, the overall

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characteristic of the induced fracture network is relatively complicated.

2. It is expected that guar-based fracturing fluid will have poor overall flowback due to its high viscosity. The gel residual can potential damage the formation and hinder the effectiveness of gas production. The formation damages include impacts on gas adsorption, diffusion, and

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transport in CBM reservoirs. Coal matrix has a strong adsorption capacity for guar-based fluids and is likely to have a sorption induced matrix swelling and reduce the effective permeability. Oxidizing breakers and enzyme breakers may have their own limitations. It is necessary to

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develop more efficient and highly applicable breakers to increase the flowback of guar-based

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fracturing fluids during coalbed stimulation. As a viscoelastic fluid, sand carrying capacity of guar-based fracturing fluid is more closely related to its storage modulus. 3. Both advantages and disadvantages of guar-based fracturing coexist, and there are different application effects of CBM reservoirs under different geological conditions. The mechanism of the impact of guar gel on the methane flow in coal should be further studied and the more theoretical models should be built to characterize the damage of the guar-based fracturing fluid to the coal formation. It is very important to distinguish the applicability of guar gel according 42

ACCEPTED MANUSCRIPT to the reservoir geological conditions for improving the guar-based fracturing technology. 4. Because of the super long life of CBM wells, the long-term evaluation of fracturing treatment effectiveness should be conducted to ensure an appropriate best fracturing fluid selection to

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achieve the best practice of CBM fracturing stimulation.

43

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Highlight: • Reviews of 50 years of CBM guar-based fracturing technology • Unique interactions between coal and guar-based fracturing fluid

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• Limitations of applicability of guar-based fracturing fluid in coal

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application in CBM reservoirs.

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• Identifying research gaps for guar-based fracturing fluid and its