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Damage mechanism and protection measures of a coalbed methane reservoir in the Zhengzhuang block
Journal of Natural Gas Science and Engineering 26 (2015) 683e694
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Damage mechanism and protection measures of a coalbed methane reservoir in the Zhengzhuang block Weian Huang a, b, *, Ming Lei a, Zhengsong Qiu a, Yee-Kwong Leong b, Hanyi Zhong a, Shifeng Zhang a a b
School of Petroleum Engineering, China University of Petroleum, Qingdao 266580, China School of Mechanical and Chemical Engineering, The University of Western Australia, Crawley 6009, Australia
a r t i c l e i n f o
a b s t r a c t
Article history: Received 23 February 2015 Received in revised form 20 June 2015 Accepted 22 June 2015 Available online 2 July 2015
The Zhengzhuang block is an important development area in Qinshui basin in Shanxi Province, China. In this block, the amount of gas produced in many wells is not consistent with that predicted according to data concerning reservoir properties, even after fracturing (i.e., with clean fracturing fluid) or the implementation of horizontal boreholes through the reservoir. To investigate the damage mechanism, mineral composition and microstructures were analyzed using X-ray diffraction, scanning electron microscopy and thin section analysis; pore parameters were determined by a mercury intrusion test; hydration properties were tested by a dispersion and expansion experiment; the contact angle of water on reservoir cores was measured to analyze the wettability; and the sensitivities of NO. 3 coal cores were analyzed according to core flow experiments and an isothermal adsorption test. Based on the test results, the factors causing damage to the coalbed methane (CBM) reservoir in the NO. 3 coal seam included serious water blocking and stress sensitivity, followed by velocity sensitivity, water sensitivity, alkali sensitivity and acid sensitivity. To eliminate water blocking, an agent to adjust core wettability was chosen. Moreover, a new cheap inhibitor was provided to reduce core water sensitivity. Using the selected wettability adjustment agent, the inhibitor and other necessary additives, drilling fluid and fracturing liquid systems were optimized, causing considerably less damage to CBM reservoir cores, both in the wet and dry states, according to the results of core permeability tests. Compared with surface water and drilling mud applied during drilling in the gas field of the Zhengzhuang block, the optimized drilling fluid and fracturing liquid can promote methane desorption by reducing the Langmuir volume and increasing the Langmuir pressure of coal, thereby increasing gas production and recoverability of the CBM reservoir. © 2015 Elsevier B.V. All rights reserved.
Keywords: Coalbed methane reservoir Isothermal adsorption Water blocking Stress sensitivity Recoverability
1. Introduction Coalbed methane (CBM) is a natural gas that gathers in pores and microfractures of coal seams (Karacan and Okandan, 2000). A coalbed methane reservoir is one type of unconventional petroleum resource where coalbed gas is developed and stored, unlike conventional natural gas reservoirs (Li et al., 2012). Coalbeds are characterized by low mechanical strength, cleat development, strong heterogeneity, a high Poisson's ratio and a large specific surface area compared with sandstone and carbonate rock (Moore,
* Corresponding author. School of Petroleum Engineering, China University of Petroleum, Qingdao 266580, China. E-mail address: [email protected] (W. Huang). http://dx.doi.org/10.1016/j.jngse.2015.06.034 1875-5100/© 2015 Elsevier B.V. All rights reserved.
2012; Keim et al., 2011; Rachmat et al., 2012; Pan, 2010; Ye et al., 2014; Pillalamarry et al., 2011). Thus, it is easier to damage coalbeds during drilling and gas production. Many studies have shown that potential damage in coalbed methane reservoirs include blocking of pores and fractures of the coal seam by solid particles in the drilling fluid (Park et al., 2014), coal culm (cuttings) produced during drilling, high molecular polymers, precipitation created during reactions between the filtrate and coalmine pore water, damage caused by lost circulation of drilling fluid, permeability reduction due to stress sensitivity, hydration swelling and dispersion of clay minerals mingling in the coalbed (Kumar et al., 2012; Huang et al., 2012; Chatterjee and Paul, 2013; Yang et al., 2011; Ke˛ dzior, 2009). Increasingly more gas production wells have been drilled to increase the output of coalbed methane in the Zhengzhuang block
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of Qinshui basin. Nevertheless, the well production rates of many wells have not provided the expected yield, even after fracturing (i.e., with clean fracturing fluid) or in horizontal wells. For example, the daily gas production of wells ZhengShi 30, ZhengPing 1-1, ZhengShi 39 and Wu M1-1 was less than 10,000 m3 (Qu et al., 2011; Tao et al., 2012). Surface water and bentonite drilling fluid are widely used as drilling liquids in the Zhengzhuang block at present. Surface water is recognized as a convenient, cheap, low-damage and fast drilling fluid in oilfields that do not normally contain solids, and in some cases, 0.1 wt% e 0.3 wt% xanthan gum is added to increase the viscosity and thereby allow coal dust to be carried (Mohajir, 2004; Coghlan, 2001). Bentonite drilling fluids decrease down-hole problems because of their better rheological performance and low filter loss (Yang et al., 2010). However, increasingly more stripper wells have been drilled using bentonite drilling fluid, confirming the damage it inflicts on coalbed methane reservoirs. Qu and Gentzis attributed the lower production to borehole instability after drilling, which can clog wellbores or cause shear failure, generating coal fines and again clogging the cleats (Qu et al., 2011; Gentzis, 2009). Certain coalbed features, the manner in which coalbed methane is stored and the methods used to recover coalbed methane lead to a special formation damage mechanism in CBM reservoirs. Any factor that reduces the desorption of natural gas from the surface of coal and the interstitial flow of gas from a coalbed to a well hole will do harm to the corresponding CBM reservoir. The objective of this study was to investigate the potential damage of CBM reservoirs in the Zhengzhuang block based on analyses of mineral composition, pore structure, surface nature and sensitivity of the coal seam. Furthermore, damage due to surface water and drilling mud from the gas field was evaluated to develop a drilling fluid and fracturing liquid that causes less damage to CBM reservoirs. The Zhengzhuang block is located in the south of the Qinshui basin, which is the most important development area and first commercial exploitation area of coalbed methane in China at present. The block belongs to the Jincheng administrative district of Shanxi Province, on the west side of the Fanzhuang block, bounded by the Sitou fault. The region comprises an area of more than 980 km2 and is quite rich in CBM resources (Cai et al., 2011). Coal seams in the Zhengzhuang block are part of the Taiyuan Formation of the Upper Carboniferous and the Shanxi Formation of the Lower Permian. The primary coal seams containing CBM are the NO. 3 coal seam of the Shanxi Formation and the NO. 15 coal seam of the Taiyuan Formation (Tao et al., 2012). The NO. 3 coal seam is the main production layer for CBM because of its larger adsorption saturation (>87%), critical desorption pressure (4.4 MPa), thickness (>5.4 m), gas content (average 21.32 m3/t) and smaller embedded depth and formation pressure (5.24 MPa) (Liu et al., 2013; Jiao et al., 2011).
chloride, hydrochloric acid, and sodium hydroxide were purchased from the Sinopharm Chemical Reagent Co., Ltd (SCRC), Peking, China. 2.2. Methods 2.2.1. Mineral analysis of the coal seam The whole-rock mineral and relative clay mineral contents of the coal seam were determined by X-ray diffraction based on the Rietveld method (Ward et al., 2001; Ruan and Ward, 2002). Sixty grams of coal powder measuring less than 150 mm were oven-dried for 3 h at 105 C to remove moisture and then dried at a low temperature of 200 C in an oxygen plasma low-temperature ash chamber to prevent altering the minerals in the coal (Cao and Li, 1994). The low-temperature ash (LTA) was subjected to powder XRD analysis. Diffractograms of the samples were obtained using a Rigaku D/max-IIIA system with Cu Ka radiation. Samples were analyzed from 2q ¼ 2 e60 in increments of 0.02 and a counting time of 2 s/step (Solanoa et al., 2008). 2.2.2. Microstructure and pore diameter analysis Microstructures of fresh sections were observed using an S4800 scanning electron microscope (SEM) by secondary electron imaging (Cai et al., 2014). Cleat and microfractures were investigated through thin section analysis after thin sections were prepared under low-temperature conditions to avoid burning the coal. The pore diameter of the core samples was measured by the mercury intrusion method (Liu et al., 2009). 2.2.3. Test of hydration properties The hydration properties of cuttings were measured by the hotrolling dispersion and linear swelling test according to API standards (Zhong et al., 2013). Fifty grams of fragments measuring between 2 mm and 5 mm were added to a solution in a conventional fluid cell. The fluid cell with the cuttings was then hot-rolled in a conventional roller oven at 77 C for 16 h. After hot-rolling, the cuttings were screened through a 1 mm sieve and washed with tap water. After drying, the amount and percentage of recovered cuttings were determined. Ten grams of coal powder with a particle size smaller than 150 mm were added to the mold and compressed at a pressure of 15 MPa for 5 min to prepare the core. The height of the core was measured and recorded as H. The mold was then fixed to an NP-02 expansion instrument. The swelling height was recorded once the sample was in contact with the testing fluid. The linear swelling rate could be determined by the following equation:
LSR ¼
DH 100% H
(1)
where DH is the swelling thickness in mm after 420 min and H is the thickness of the coal core in mm.
2. Experimental methods 2.1. Materials Coal cores and nickings were collected from the NO. 3 coal seam in the Zhengzhuang block from Wells ZS30, ZS39, ZS41 and H-2. Samples 3-1#, 3-2#, 3-3#, 3-4#, and 3-5# of the NO. 3 coalbed were collected from coal mining sites. Surface water, drilling mud, xanthan gum (XC) and non-ionic surfactant SWIA (polyoxyethylene alkyl ether), produced by the CNPC Bohai Drilling Engineering Co., Ltd., were obtained from the gas field in the Zhengzhuang block. Carboxymethyl cellulose (CMC-HV) and carboxymethyl starch (CMS) were supplied by the Weihuishi Tongda Chemical Industry Co., Ltd. Alkyl benzene sulfonate, calcium chloride, potassium
2.2.4. Determination of permeability and sensitivity The permeability and sensitivity of the coal cores were evaluated by core flow experiments using methane as the flow medium, according to the American Petroleum Institute Standard RP-40. Moreover, coal cores were saturated with test liquid through vacuum-pumping, rather than displacement, to prevent samples from being destroyed. 2.2.5. Wettability and adsorption test The wettability of the coal surface was determined from contact angle measurements performed with a JC2000D5M contact angle meter using plate-like coal cores. The adsorption capacity of methane on the coal surface fit the Langmuir adsorption model. The
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adsorption quantity can be calculated through the following formula (Pillalamarry et al., 2011):
V ¼ VL $P=ðP þ PL Þ
(2)
where V is methane adsorption, cm3/g; VL is the Langmuir volume, cm3/g; P is the pressure of methane, MPa; and PL is the Langmuir pressure, MPa. Coal powder with a particle diameter between 178 mm and 250 mm was sieved and dried for 5 h at 105 C before the methane adsorption experiments. Methane adsorption was measured at 30 C under pressures of up to a consistent value of approximately 6.3 MPa. 3. Results and discussion 3.1. Analysis of potential damage 3.1.1. Mineral composition The XRD analysis results listed in Table 1 indicate that nonmineral elements (e.g., carbon, hydrogen, and sulfur) were the main components of samples from the NO. 3 coal seam in the Zhengzhuang block, averaging 85.14% and ranging from 81% to 90%. The clay mineral content ranged from 4% to 9%, with an average of 6.71%. In addition, samples contained small amounts of quartz, calcite, siderite, anorthose, hematite, iron, pyrite, ankerite and tobelite. The clay mineral compositions are presented in Table 2. The main components of the clay in the coalbeds were illite and kaolinite, accounting for 44.86% and 26%, respectively. The third constituent was a mixed-layer of illite and smectite (I/S), with a smaller ratio of expansive clay mineral (averaging 12.86%). The illite scattered when in contact with water, resulting in fine migration. Additionally, coal is easy to grind into a powder during drilling or other operations, causing particle migration. 3.1.2. Microstructure and pore parameters The microstructure of the NO. 3 coal seam had the following characteristics: parallel grains, bedding (Fig. 1c and e) and joints. The cleats (Fig. 1f) of the coal were easily recognizable and showed good tropism; the coal fragments appeared as angular sheets (Fig. 1f); micropores, including moldic pores, blow holes, tissue holes and deformed tissue holes, developed locally (Fig. 1a, b, d, f, g, h), and the pores were partially filled by quartz (Fig. 1a) and clay minerals (Fig. 1b, d, g, h). Parallel grains, bedding, joints and cleats of the coal would provide channels for filtering liquids invading into the coalbed, causing damage if the liquids were incompatible with the coal core. Clay minerals in micropores will hydrate once in contact with water, leading to flow path and particulate output reduction. A large number of microfractures existed in the NO. 3 coal seam (Fig. 2a, b, c, e, f, g, h), with moderate connectivity (i.e., several fractures are not connected on the plane, Fig. 2a, c, g). The main fissures were 0.11e1.2 cm long and 3e34 mm wide, with a distribution density of 6.1e13.1 strips/cm and a breach width of
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1e310 mm. Slits measured 0.03e0.6 cm long and 2e23 mm wide, with a distribution density of 2.2e7.7 strips/cm. The microfracture shapes were anomalous and vertically oriented with the coal bedding; for example, the fracture in sample 3-3# resembles a wild goose tail and is well-connected (Fig. 2e). Several fractures were filled by clay minerals, iron pyrite and calcite (Fig. 2f and h). Joints and cleats of the coal showed grid shaped distributions on the flat surface (Fig. 2d). Micropores with certain connectivity partially developed (Fig. 2a, b, c, g) and were connected through joints and cleats. Results of the intrusive mercury experiment (Table 3, Fig. 3) showed that the NO. 3 coal seam was a representatively low porosity fractured reservoir, with a porosity of 4.9%. The maximum pore radius ranged from 14.39 mm to 180.71 mm, with an average of 50.87 mm. The average pore radius was 12.92 mm, ranging from 2.75 mm to 46.11 mm. The size of the minimum pore contributing to the permeability ranged from 2.75 mm to 36.9 mm, with an average of 13.3 mm, indicating that fractures were the main seepage channel for methane. The uniformity coefficient (average of 0.2347 mm, ranging from 0.1866 to 0.2914 mm) of the samples indicated that the NO. 3 coal seam was strongly heterogeneous. 3.1.3. Hydration properties The recovery rate of nickings from the NO. 3 coal seam averaged 96.61%, ranging from 92.1% to 99.7% (Table 4), suggesting that the coal core in the NO. 3 coal seam had weak hydration dispersing capacity. Linear swelling rates were between 0.45% and 3.78% with an average of 1.74%, indicating that the coal core had lower hydrating and swelling properties. However, the samples swelled rapidly during the early stage when the coal powder was in contact with water, but 20 min later, the expansion was slight until the maximum swelling rate was reached and remained constant within 8 h (Fig. 4). The high recovery rate and low swelling rate indicated that the coal core in the NO. 3 coal seam exhibited poor hydration performance and showed weak water sensitivity due to the low clay mineral content (Lever and Dawe, 1984). 3.1.4. Wettability of the coal surface Table 5 and Fig. 5 show that the contact angles between the water and coal surface ranged from 100.08 to 132.86 , with an average of 115.51 (>90 ), which corroborates the hydrophobicity of the coal core surface. A serious water lock effect occurs in the oilwet reservoir, reducing the permeability of the formation. Moreover, water does not spread on the oil-wet coal surface (average amount of adhesion work is 42.25 mJ m2), existing in the form of water droplets and hindering the flow of methane in the coalbed (Saghafi et al., 2014; Li et al., 2015). 3.2. Sensitivity of coal cores The permeabilities of samples ZS30-1, ZS31-1, ZS39-1 increased during the initial phase of methane flow and decreased as the gasflow rate exceeded 12.45 cm3/min (next flow rate was 15.92 cm3/
Table 1 Mineral compositions determined by X-ray diffraction. Sample
Quartz (%)
Calcite (%)
Siderite (%)
Anorthose (%)
Hematite (%)
Iron Pyrite (%)
Ankerite (%)
Tobelite (%)
Clay (%)
Non mineral (%)
ZS30 ZS39 3-1# 3-2# 3-3# 3-4# 3-5#
2 3 3 1 1 2 1
e 1 e 1 2 e 1
2 e 3 2 1 1 1
e e 2 1 e e e
e e 1 e e e e
2 1 e e e e e
e 1 2 1 1 2 1
2 1 3 2 2 1 3
9 7 5 6 8 4 8
83 86 81 86 85 90 85
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Table 2 The relative contents of clay minerals. Sample
Kaolinite (%)
Chlorite (%)
Illite (%)
I/S (%)
Interlaying ratio of I/S (%)
ZS30 ZS39 3-1# 3-2# 3-3# 3-4# 3-5#
26 33 38 15 23 28 19
9 17 12 15 13 8 11
44 37 50 47 42 51 43
21 13 0 23 22 13 27
20 20 0 5 20 20 5
Fig. 1. Microscopic images of the coal core of the NO. 3 coal seam. (a) e ZS30 (7000 times). (b) e ZS39 (9000 times). (c) e 3-1# (2200 times) (d) e 3-2# (6000 times). (e) e 3-3# (700 times). (f) e 3-4# (3000 times). (g) e 3-5# (9000 times). (h) e 3-5# (8000 times).
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Fig. 2. Thin section analysis images of the coal core of the NO. 3 coal seam. (a) e ZS30 (100 times). (b) e ZS39 (100 times). (c) e 3-1# (25 times) (d) e 3-2# (25 times). (e) e 3-3# (100 times). (f) e 3-4# (25 times). (g) e 3-5# (25 times). (h) e 3-5# (25 times).
Table 3 Pore parameters of the coal core. Sample
Porosity (%)
Maximum pore radius (mm)
Average pore radius (mm)
Minimum pore size with contribution to permeability (mm)
Uniformity coefficient
ZS30 ZS39 3-1# 3-2# 3-3# 3-4# 3-5#
4.86 4.3 5.28 3.62 6.44 5.14 4.66
35.41 28.56 36.43 14.39 180.71 34.86 25.74
7.99 8.24 9.88 2.75 46.11 9.12 6.33
16.05 11.33 12.5 2.75 36.9 8.47 5.09
0.2517 0.1866 0.2914 0.1938 0.2787 0.2334 0.2071
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Fig. 3. Intrusive mercury curves of the coal core of the NO. 3 coal seam.
Table 4 Test results of hydration properties of the coal cores. Sample
ZS30
ZS39
3-1#
3-2#
3-3#
3-4#
3-5#
Recovery rate (%) Expansion rate (%)
98.9 0.71
97.8 1.39
99.7 2.38
92.1 3.78
93.7 0.45
96.5 1.75
97.3 1.69
Fig. 4. Linear swelling rate of the coal core from the NO. 3 coal seam with time.
min), which is the critical flow velocity (Fig. 6). Weak velocity sensitivity damage was verified by the small permeability reduction of less than 20% (Table 6). The average permeability reduction rate of the samples was 65.97% after the ambient pressure exceeded 0.5 MPa, which was confirmed as the critical pressure (Fig. 7). The
stress sensitivity indexes of samples ZS30-2, ZS30-3 and ZS44-1 were 66.76%, 58.71% and 72.44%, respectively (Table 6), suggesting that they possessed moderate stress sensitivity, even higher than that of tight sandstone, which shows a sensitivity index of 30%e60%. The stress sensitivity damage of the samples cannot be recovered after releasing the ambient pressure because the fractures in the main flow channel of the CBM reservoir will close once the confining pressure exceeds the closure pressure. Samples ZS304, H-1 and ZS31-2 were weakly sensitive to water, as demonstrated by their higher water sensitivity indexes and lower critical salinity of 5000 mg/L (Fig. 8, Table 6) due to a low clay content. Small alkali sensitivity indexes (i.e., 6.73%, 7.7%, 4.91%), listed in Table 6, and a high critical pH value (i.e., 13; Fig. 8) indicate that samples ZS30-5, ZS39-2 and ZS41-2 are weakly sensitive to alkaline conditions. The permeabilities of samples ZS30-6 and H-2 decreased from 0.0728 103 mm2 to 0.0689 103 mm2 and from 0.2133 103 mm2 to 0.1924 103 mm2 after being acidified with 15 wt% hydrochloric acid (Fig. 9), suggesting weak acid sensitivity (94.6% and 90.2%, respectively; Table 6) to small amounts of siderite and ankerite in the coal. As discussed above, water blocking can cause severe damage to the NO. 3 coal seam. The permeability of the dry cores is far greater that of the saturated cores, and the dry cores contain 0.5 wt% salt water. The water blocking indexes of samples ZS30-7, ZS30-8 and ZS31-3 are 27.32%, 22.77% and 26.41%, respectively (Fig. 10). Based on the potential damage and sensitivity evaluations, it can be concluded that the damage mechanisms of the NO. 3 coal seam in the Zhengzhuang block are as follows: severe water blocking, moderate stress sensitivity, weak velocity sensitivity, water sensitivity, alkali sensitivity and acid sensitivity. The water block damage can be reduced by using surfactants in a water-based working fluid by reducing the capillary force of water in cracks and modifying the
Table 5 Wettability test results of the coal cores. Sample
ZS30
ZS39
3-1#
3-2#
3-3#
3-4#
3-5#
Left contact angle ( ) Right contact angle ( ) Average contact angle ( ) Adhesion work (mJ m2)
131.44 134.29 132.86 23.28
128.87 133.4 131.13 24.91
115.7 121.39 118.55 38.01
120.26 122.28 121.27 35.01
99.92 100.39 100.16 59.96
103.55 105.51 104.53 54.54
99.60 100.55 100.08 60.07
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Fig. 5. Photographs of water drops on a coal core surface. (a) e ZS30 b e 3-3#.
3.3. Optimization of the operating fluid with low damage 3.3.1. Composition optimization of the operating fluid To reduce damage due to severe water blocking and certain degrees of water sensitivity in the NO. 3 coal seam of the Zhengzhuang block, an inhibitor and a waterproof lock agent were selected to form a newly solid-free drilling fluid and activated water fracturing fluid. Inorganic salts represent one type of inexpensive hydration swelling inhibitor by compressing the diffuse double layer of clay particles (Arasan et al., 2010). Potassium chloride and calcium chloride are widely used in drilling fluids and fracturing liquids. Their inhibition of coal powder hydration was measured in a swelling experiment, the results of which are presented in Fig. 11. The expansion rate of sample 3-2# decreased with the increase in the concentration of the test liquid. Calcium chloride showed better inhibition of coal powder hydration than did potassium chloride. The swelling rate of CaCl2 was reduced by 80.69% when its content was 0.5 wt% and then showed little change. Therefore, CaCl2 was selected as the inhibitor to reduce damage due to the core water sensitivity of the operating liquid; its dosage was 0.5 wt%. To modify the hydrophobicity of the coal surface, two watersoluble surfactants were chosen in this study. Anionic sodium alkyl benzene sulfonate is often used in operating liquids as a waterproof locking agent for tight sandstone reservoirs and fractured carbonate reservoirs. SWIA is another non-ionic surfactant. SWIA is a commercial product used as a coal powder dispersing
Fig. 6. Velocity sensitivity evaluation of samples ZS30-1, ZS31-1 and ZS39-1.
wettability of the coal surface (Zhang et al., 2012). Excessive differential pressures and discharge rates should be prohibited to avoid stress and velocity sensitivity (Yang et al., 2015; Bai et al., 2009). Working fluid inhibition should be enhanced by adding a suitable inhibitor, such as inorganic salt or organic cations (Zuo et al., 2014). Although the alkali sensitivity was weak, the pH of the working liquid should be adjusted below 12 to prevent materials from being dissolved during operation. Acidification is not recommended because of the weak acid sensitivity of coal and the environmental problems it may cause (Tian and Wu, 2014).
Table 6 Sensitivity evaluation results of the coal cores. Type
Criterion for judgement
Test result
Damage degree
Remarks
Velocity sensitivity
Weak: <30% Moderate: 30%e70% Strong: >70% Weak: <30% Moderate: 30%e70% Strong: 70%e100% Extremely strong:>100% Weak: >70% Moderate: 70%e30% Strong: <30% Weak: <30% Moderate: 30%e70% Strong: >70% Weak: >70% Moderate: 70%e30% Strong: <30% Weak: >70% Moderate: 70%e30% Strong: <30%
ZS30-1: ZS31-1: ZS39-1: ZS30-2: ZS30-3: ZS41-1:
ZS30-1: ZS31-1: ZS39-1: ZS30-2: ZS30-3: ZS41-1:
Critical velocity: 12.45 cm3/min
Stress sensitivity
Water sensitivity
Sensitivity to alkaline
Acid sensitivity
Water blocking
14% 18.1% 12.7% 66.76% 58.71% 72.44%
Weak Weak Weak Moderate Moderate Strong
Critical pressure: 0.5 MPa
ZS30-4: 91.13% H-1: 87.96% ZS31-2: 90.1% ZS30-5:6.73% ZS39-2: 7.7% ZS41-2: 4.91% ZS30-6: 94.6% H-2: 90.2%
ZS30-4: Weak H-1: Weak ZS31-2: Weak ZS30-5:Weak ZS39-2: Weak ZS41-2: Weak ZS30-6: Weak H-2: Weak
Critical salinity: 5000 mg/L
ZS30-7: 27.32% ZS30-8: 22.77% ZS31-3: 26.41%
ZS30-7: Strong ZS30-8: Strong ZS31-3: Strong
e
Critical pH: 13
e
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Fig. 7. Stress sensitivity evaluation of samples (a) ZS30-2 and (b) ZS30-3.
Fig. 8. (a) Water sensitivity and (b) alkaline sensitivity of samples.
agent and cleaning additive in fracturing liquids. Both surfactants can transform the hydrophobic surface of coal into a strongly hydrophilic one (Fig. 12; Table 7). As the concentration of the surfactant increased in the soak solution, the contact angle between the water and coal surface decreased, and the adhesion energy increased, allowing the water to spread easily on the coal surface. SWIA has a stronger effect than ABS at the same content and was selected as the wettability adjustment agent in the working fluid, with a concentration of 0.3 wt%. Carboxymethyl cellulose (high viscosity, with a degree of polymerization greater than 600 CMC-HV), which causes low damage to coalbed methane reservoirs, was used to improve the viscosity of the drilling fluid and decrease the friction of the fracturing liquid (Table 8). Carboxymethyl starch (CMS) was chosen as a fluid loss additive in the drilling fluid to reduce filtrate formation and
damage to the coal seam (Table 8). CMC-HV and CMS can be degraded using cellulose enzymes or amylase as needed. 3.3.2. Reservoir protection performance During drilling, completion, fracturing and water withdrawing for production, the CBM reservoir is mostly wet. The permeability of the coal seam in a hygrometric state played an important role in methane movement and flowback of the fracturing liquid. The effects of the experimental liquid on coal seam permeability in the hygrometric and dry states were investigated using core flow tests. Coal cores from the Zhengzhuang block showed lower permeability than did those from the Heshun and Yanchuannan blocks, with an average permeability of 0.267 103 mm2 (Table 8) (Huang et al., 2012). XC and CMC-HV both caused damage to the coal seam by adhering onto the internal walls of pores. The permeability
W. Huang et al. / Journal of Natural Gas Science and Engineering 26 (2015) 683e694
Fig. 9. Acid sensitivity evaluation of samples ZS30-6 and H-2.
Fig. 10. Water blocking damage evaluation of samples ZS30-7, ZS30-8 and ZS31-3.
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72.82%) and larger recovery rate of permeability (86.16%, 88.34%) in the dry state compared with those of surface water. Drilling mud 07-1#, 07-2#, 4#, and 5# from a gas field in the Zhengzhuang block all caused severe damage to the coal seam, with the same loss ratio of 100% in the wet state. The main reason for this behavior is the clogging of solids in the drilling fluid (the particle size distributions were 0.149e1.495 mm, 0.351e1.758 mm, 0.49e66.5 mm, 0.49e48.27 mm, respectively) without any surfactant. The permeability reduction ratios of the optimized drilling fluid and fracturing liquid were 64.68% and 54.92% less than the permeability reduction ratio of the drilling fluid from the field, with higher recovery rates of permeability (95.9%, 96.2%) in the dry state. Amylase could reduce the damage of CMC-HV and CMS by biodegradation, which decreased the permeability reduction ratio of the optimized drilling fluid and increased the recovery rate of permeability in the dry state. The Langmuir volume of coal represents the largest adsorption quantity of methane on its surface. The Langmuir pressure indicates the steepness of the adsorption isotherm; the lower the Langmuir pressure is, the steeper the adsorption isotherm becomes, which determines the accessibility rate and range of depressurization and recoverability of the CBM reservoir. The methane-adsorbing capacity of coal powder saturated by experimental liquid was lower than that of the dry samples (Fig. 13), and the Langmuir volume also decreased (Table 9). There were two reasons for this behavior. First, the surface wettability of the coal was altered after saturation by the experimental liquid, and the hydrophobicity of the coal surface decreased to a different degree. Second, several adsorption sites on the coal surface were occupied by components in the experimental liquid (Gosiewska et al., 2002). The Langmuir pressure of the sample saturated by the experimental liquid was greater than that of the dry coal powder (Table 9), indicating that methane desorbed easier from the surface of coal after saturation by the experimental liquid. The surface water and drilling muds from the gas field clearly improved the Langmuir pressure but only slightly reduced the amount of methane adsorbed on the coal surface, to the disadvantage of its desorption from coal. Although the optimized drilling fluid decreased the Langmuir volume from 51.28 cm3/g of dry coal to 37.96 cm3/g, it increased the Langmuir pressure from 1.14 MPa to 3.17 MPa, benefitting gas production and the recoverability of CBM reservoirs. The optimized fracturing liquid containing less CMC-HV and no CMS showed the best performance by reducing the Langmuir volume, increasing the Langmuir pressure and causing the least damage to the CBM reservoir among the evaluated liquids. 4. Conclusions
Fig. 11. Water blocking damage evaluation of samples ZS30-7 and ZS30-8.
reduction ratio of 0.05 wt% of the XC solution was 100% (methane could not be driven through the core under the experimental pressure), greater than that of CMC-HV and CMS. ABS and SWIA could effectively decrease water blocking, as demonstrated by their lower permeability loss ratio in the hygrometric state (77.68%,
(1) The NO. 3 coal seam in the Zhengzhuang block is a representative low-porosity fractured reservoir. Parallel grains, bedding, joints and cleats are the primary flow channels of methane and provide paths for filtering invading liquids into the coalbed to cause damage. The breach width (3e34 mm) and average pore radius (2.75e46.11 mm) distribution characteristics of coal make it more easily damaged by solids such as coal dust and particles in operating fluids. (2) The coal core from the NO. 3 seam was mainly composed of carbon and a certain amount of clay minerals, such as siderite and ankerite, making it sensitive to water and possibly hydrochloride. The hydrophobicity of the coal core surface caused a water blocking effect and could reduce the permeability of methane in the coal seam. (3) Severe water blocking, moderate stress sensitivity, weak velocity sensitivity, water sensitivity, alkali sensitivity and acid sensitivity were the main damage mechanisms for the
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Fig. 12. Photographs of water drops on the surface of a coal core soaked with the surfactant solution. (a) 0.2% ABS (b) 0.3% ABS (c) 0.4% ABS. (d) 0.2% SWIA (e) 0.3% SWIA (f) 0.4% SWIA.
Table 7 Wettability test results of the coal core surface modified with the surfactant. Test status Polished flat Soaked by 0.2% Soaked by 0.3% Soaked by 0.4% Soaked by 0.2% Soaked by 0.3% Soaked by 0.4%
ABS ABS ABS SWIA SWIA SWIA
Left contact angle ( )
Right contact angle ( )
Average contact angle ( )
Adhesion work (mJ m2)
131.44 10.29 7.44 5.20 8.22 5.37 4.73
134.29 12.27 5.75 6.41 14.24 4.70 4.01
132.86 11.28 6.60 5.81 11.23 5.04 4.37
23.28 144.19 145.12 145.23 144.21 145.32 145.39
Table 8 Wettability test results of the coal core surface modified with surfactant. Core number
Experimental liquid
KO (103 mm)
KO1 (103 mm)
S1 (%)
KO2 (103 mm)
R2 (%)
3-3-1# 3-3-2# 3-3-3# 3-3-4# 3-3-5# 3-3-6# 3-3-7# 3-3-8# 3-3-9# 3-3-10# 3-3-11#
0.05% XC solution 0.1% CMC-HV solution 1.2% CMS solution 0.3% ABS solution 0.3% SWIA solution Surface water 07-1# drilling mud 07-2# drilling mud 4# drilling mud 5# drilling mud Optimized drilling fluid Optimized drilling fluid degraded by 0.1% amylase Optimized fracturing liquid
0.3527 0.5712 0.2783 0.1698 0.301 0.2263 0.1095 0.0701 0.1021 0.1104 0.4436 0.4254 0.2948
0 0.0703 0.0462 0.0379 0.0818 0.024 0 0 0 0 0.1567 0.2231 0.1329
100.00 87.69 83.40 77.68 72.82 89.39 100.00 100.00 100.00 100.00 64.68 47.56 54.92
0.2981 0.5124 0.2345 0.1463 0.2659 0.1893 0.0611 0.0506 0.0896 0.0756 0.4254 0.4189 0.2836
84.52 89.71 84.26 86.16 88.34 83.65 55.80 72.18 87.76 68.48 95.90 98.47 96.20
3-3-12#
Note: KO is the original permeability of cores for methane; KO1 is the permeability of cores after they were saturated by experimental liquid and tested in the wet state; S1 ¼ (1KO1/KO) 100%; KO2 is the permeability of cores after the saturated experimental liquid was discharged by heating at a temperature of 105 C; R2 ¼ (KO2/KO) 100%. Optimized drilling fluid: Surface water þ 0.5% CaCl2 þ 0.3 wt% CMC-HV þ 1.2 wt% CMS þ 0.3 wt% SWIA; optimized fracturing liquid: Surface water þ 0.5% CaCl2 þ 0.06 wt% CMC-HV þ 0.3 wt% SWIA. The core samples are saturated by 0.1% amylase solution at 50 C for 2 h.
CBM reservoir in the Zhengzhuang block. Water sensitivity and alkali sensitivity damage can be eliminated by controlling the salinity and pH within a critical value range. Acidification is not recommended due to the weak acid sensitivity of coal and the risk of environmental problems. (4) CaCl2 was selected as an inhibitor to reduce water sensitivity, and SWIA could adjust the core wettability. CMC-HV and CMS were chosen as viscosifiers, friction-reducing agents and fluid loss additive operating liquids because they cause little damage to the permeability of coalbed methane reservoirs.
(5) The optimized drilling fluid and fracturing liquid caused less permeability loss of the cores and less damage to the CBM reservoir in both the wet and dry states than did surface water and drilling muds from the gas field in the Zhengzhuang block. Moreover, the optimized drilling fluid and fracturing liquid could decrease the Langmuir volume, increase the Langmuir pressure of the coal to promote desorption of methane from coal surface and enhance the recoverability of CBM reservoirs.
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Fig. 13. Adsorption isotherms of coal before and after saturation by experimental liquids.
Table 9 Effect of experimental liquids on the Langmuir volume and Langmuir pressure of coal. Experimental condition
Langmuir volume (cm3/g)
Langmuir pressure (MPa)
Original Saturated Saturated Saturated Saturated Saturated Saturated Saturated fluid Saturated liquid
51.28 48.37 46.33 47.39 46.73 44.81 46.30 37.96
1.14 2.69 2.12 2.16 2.41 2.34 2.35 3.17
by optimized fracturing 35.34
3.29
by by by by by by by
distilled water Surface water 07-1# drilling mud 07-2# drilling mud 4# drilling mud 5# drilling mud optimized drilling
Acknowledgments This work was financially supported by the National Science Foundation of China (No. 51374233; No. 41072094), Shandong Province Science Foundation (No. ZR2013EEM032), the Fundamental Research Funds for the Central Universities (No. 13CX02044A) and the Project of China Scholarship Council (201306455021). Abbreviations ABS API CBM CMC CMS I/S LTA SEM XC XRD
Alkyl benzene sulfonate American Petroleum Institute Coalbed methane Carboxymethyl cellulose Carboxymethyl starch Mixed-layer of illite and smectite Low-temperature ash Scanning electron microscope Xanthan gum X-ray diffraction analysis
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Damage mechanism and protection measures of a coalbed methane reservoir in the Zhengzhuang block Weian Huang a, b, *, Ming Lei a, Zhengsong Qiu a, Yee-Kwong Leong b, Hanyi Zhong a, Shifeng Zhang a a b
School of Petroleum Engineering, China University of Petroleum, Qingdao 266580, China School of Mechanical and Chemical Engineering, The University of Western Australia, Crawley 6009, Australia
a r t i c l e i n f o
a b s t r a c t
Article history: Received 23 February 2015 Received in revised form 20 June 2015 Accepted 22 June 2015 Available online 2 July 2015
The Zhengzhuang block is an important development area in Qinshui basin in Shanxi Province, China. In this block, the amount of gas produced in many wells is not consistent with that predicted according to data concerning reservoir properties, even after fracturing (i.e., with clean fracturing fluid) or the implementation of horizontal boreholes through the reservoir. To investigate the damage mechanism, mineral composition and microstructures were analyzed using X-ray diffraction, scanning electron microscopy and thin section analysis; pore parameters were determined by a mercury intrusion test; hydration properties were tested by a dispersion and expansion experiment; the contact angle of water on reservoir cores was measured to analyze the wettability; and the sensitivities of NO. 3 coal cores were analyzed according to core flow experiments and an isothermal adsorption test. Based on the test results, the factors causing damage to the coalbed methane (CBM) reservoir in the NO. 3 coal seam included serious water blocking and stress sensitivity, followed by velocity sensitivity, water sensitivity, alkali sensitivity and acid sensitivity. To eliminate water blocking, an agent to adjust core wettability was chosen. Moreover, a new cheap inhibitor was provided to reduce core water sensitivity. Using the selected wettability adjustment agent, the inhibitor and other necessary additives, drilling fluid and fracturing liquid systems were optimized, causing considerably less damage to CBM reservoir cores, both in the wet and dry states, according to the results of core permeability tests. Compared with surface water and drilling mud applied during drilling in the gas field of the Zhengzhuang block, the optimized drilling fluid and fracturing liquid can promote methane desorption by reducing the Langmuir volume and increasing the Langmuir pressure of coal, thereby increasing gas production and recoverability of the CBM reservoir. © 2015 Elsevier B.V. All rights reserved.
Keywords: Coalbed methane reservoir Isothermal adsorption Water blocking Stress sensitivity Recoverability
1. Introduction Coalbed methane (CBM) is a natural gas that gathers in pores and microfractures of coal seams (Karacan and Okandan, 2000). A coalbed methane reservoir is one type of unconventional petroleum resource where coalbed gas is developed and stored, unlike conventional natural gas reservoirs (Li et al., 2012). Coalbeds are characterized by low mechanical strength, cleat development, strong heterogeneity, a high Poisson's ratio and a large specific surface area compared with sandstone and carbonate rock (Moore,
* Corresponding author. School of Petroleum Engineering, China University of Petroleum, Qingdao 266580, China. E-mail address: [email protected] (W. Huang). http://dx.doi.org/10.1016/j.jngse.2015.06.034 1875-5100/© 2015 Elsevier B.V. All rights reserved.
2012; Keim et al., 2011; Rachmat et al., 2012; Pan, 2010; Ye et al., 2014; Pillalamarry et al., 2011). Thus, it is easier to damage coalbeds during drilling and gas production. Many studies have shown that potential damage in coalbed methane reservoirs include blocking of pores and fractures of the coal seam by solid particles in the drilling fluid (Park et al., 2014), coal culm (cuttings) produced during drilling, high molecular polymers, precipitation created during reactions between the filtrate and coalmine pore water, damage caused by lost circulation of drilling fluid, permeability reduction due to stress sensitivity, hydration swelling and dispersion of clay minerals mingling in the coalbed (Kumar et al., 2012; Huang et al., 2012; Chatterjee and Paul, 2013; Yang et al., 2011; Ke˛ dzior, 2009). Increasingly more gas production wells have been drilled to increase the output of coalbed methane in the Zhengzhuang block
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of Qinshui basin. Nevertheless, the well production rates of many wells have not provided the expected yield, even after fracturing (i.e., with clean fracturing fluid) or in horizontal wells. For example, the daily gas production of wells ZhengShi 30, ZhengPing 1-1, ZhengShi 39 and Wu M1-1 was less than 10,000 m3 (Qu et al., 2011; Tao et al., 2012). Surface water and bentonite drilling fluid are widely used as drilling liquids in the Zhengzhuang block at present. Surface water is recognized as a convenient, cheap, low-damage and fast drilling fluid in oilfields that do not normally contain solids, and in some cases, 0.1 wt% e 0.3 wt% xanthan gum is added to increase the viscosity and thereby allow coal dust to be carried (Mohajir, 2004; Coghlan, 2001). Bentonite drilling fluids decrease down-hole problems because of their better rheological performance and low filter loss (Yang et al., 2010). However, increasingly more stripper wells have been drilled using bentonite drilling fluid, confirming the damage it inflicts on coalbed methane reservoirs. Qu and Gentzis attributed the lower production to borehole instability after drilling, which can clog wellbores or cause shear failure, generating coal fines and again clogging the cleats (Qu et al., 2011; Gentzis, 2009). Certain coalbed features, the manner in which coalbed methane is stored and the methods used to recover coalbed methane lead to a special formation damage mechanism in CBM reservoirs. Any factor that reduces the desorption of natural gas from the surface of coal and the interstitial flow of gas from a coalbed to a well hole will do harm to the corresponding CBM reservoir. The objective of this study was to investigate the potential damage of CBM reservoirs in the Zhengzhuang block based on analyses of mineral composition, pore structure, surface nature and sensitivity of the coal seam. Furthermore, damage due to surface water and drilling mud from the gas field was evaluated to develop a drilling fluid and fracturing liquid that causes less damage to CBM reservoirs. The Zhengzhuang block is located in the south of the Qinshui basin, which is the most important development area and first commercial exploitation area of coalbed methane in China at present. The block belongs to the Jincheng administrative district of Shanxi Province, on the west side of the Fanzhuang block, bounded by the Sitou fault. The region comprises an area of more than 980 km2 and is quite rich in CBM resources (Cai et al., 2011). Coal seams in the Zhengzhuang block are part of the Taiyuan Formation of the Upper Carboniferous and the Shanxi Formation of the Lower Permian. The primary coal seams containing CBM are the NO. 3 coal seam of the Shanxi Formation and the NO. 15 coal seam of the Taiyuan Formation (Tao et al., 2012). The NO. 3 coal seam is the main production layer for CBM because of its larger adsorption saturation (>87%), critical desorption pressure (4.4 MPa), thickness (>5.4 m), gas content (average 21.32 m3/t) and smaller embedded depth and formation pressure (5.24 MPa) (Liu et al., 2013; Jiao et al., 2011).
chloride, hydrochloric acid, and sodium hydroxide were purchased from the Sinopharm Chemical Reagent Co., Ltd (SCRC), Peking, China. 2.2. Methods 2.2.1. Mineral analysis of the coal seam The whole-rock mineral and relative clay mineral contents of the coal seam were determined by X-ray diffraction based on the Rietveld method (Ward et al., 2001; Ruan and Ward, 2002). Sixty grams of coal powder measuring less than 150 mm were oven-dried for 3 h at 105 C to remove moisture and then dried at a low temperature of 200 C in an oxygen plasma low-temperature ash chamber to prevent altering the minerals in the coal (Cao and Li, 1994). The low-temperature ash (LTA) was subjected to powder XRD analysis. Diffractograms of the samples were obtained using a Rigaku D/max-IIIA system with Cu Ka radiation. Samples were analyzed from 2q ¼ 2 e60 in increments of 0.02 and a counting time of 2 s/step (Solanoa et al., 2008). 2.2.2. Microstructure and pore diameter analysis Microstructures of fresh sections were observed using an S4800 scanning electron microscope (SEM) by secondary electron imaging (Cai et al., 2014). Cleat and microfractures were investigated through thin section analysis after thin sections were prepared under low-temperature conditions to avoid burning the coal. The pore diameter of the core samples was measured by the mercury intrusion method (Liu et al., 2009). 2.2.3. Test of hydration properties The hydration properties of cuttings were measured by the hotrolling dispersion and linear swelling test according to API standards (Zhong et al., 2013). Fifty grams of fragments measuring between 2 mm and 5 mm were added to a solution in a conventional fluid cell. The fluid cell with the cuttings was then hot-rolled in a conventional roller oven at 77 C for 16 h. After hot-rolling, the cuttings were screened through a 1 mm sieve and washed with tap water. After drying, the amount and percentage of recovered cuttings were determined. Ten grams of coal powder with a particle size smaller than 150 mm were added to the mold and compressed at a pressure of 15 MPa for 5 min to prepare the core. The height of the core was measured and recorded as H. The mold was then fixed to an NP-02 expansion instrument. The swelling height was recorded once the sample was in contact with the testing fluid. The linear swelling rate could be determined by the following equation:
LSR ¼
DH 100% H
(1)
where DH is the swelling thickness in mm after 420 min and H is the thickness of the coal core in mm.
2. Experimental methods 2.1. Materials Coal cores and nickings were collected from the NO. 3 coal seam in the Zhengzhuang block from Wells ZS30, ZS39, ZS41 and H-2. Samples 3-1#, 3-2#, 3-3#, 3-4#, and 3-5# of the NO. 3 coalbed were collected from coal mining sites. Surface water, drilling mud, xanthan gum (XC) and non-ionic surfactant SWIA (polyoxyethylene alkyl ether), produced by the CNPC Bohai Drilling Engineering Co., Ltd., were obtained from the gas field in the Zhengzhuang block. Carboxymethyl cellulose (CMC-HV) and carboxymethyl starch (CMS) were supplied by the Weihuishi Tongda Chemical Industry Co., Ltd. Alkyl benzene sulfonate, calcium chloride, potassium
2.2.4. Determination of permeability and sensitivity The permeability and sensitivity of the coal cores were evaluated by core flow experiments using methane as the flow medium, according to the American Petroleum Institute Standard RP-40. Moreover, coal cores were saturated with test liquid through vacuum-pumping, rather than displacement, to prevent samples from being destroyed. 2.2.5. Wettability and adsorption test The wettability of the coal surface was determined from contact angle measurements performed with a JC2000D5M contact angle meter using plate-like coal cores. The adsorption capacity of methane on the coal surface fit the Langmuir adsorption model. The
W. Huang et al. / Journal of Natural Gas Science and Engineering 26 (2015) 683e694
adsorption quantity can be calculated through the following formula (Pillalamarry et al., 2011):
V ¼ VL $P=ðP þ PL Þ
(2)
where V is methane adsorption, cm3/g; VL is the Langmuir volume, cm3/g; P is the pressure of methane, MPa; and PL is the Langmuir pressure, MPa. Coal powder with a particle diameter between 178 mm and 250 mm was sieved and dried for 5 h at 105 C before the methane adsorption experiments. Methane adsorption was measured at 30 C under pressures of up to a consistent value of approximately 6.3 MPa. 3. Results and discussion 3.1. Analysis of potential damage 3.1.1. Mineral composition The XRD analysis results listed in Table 1 indicate that nonmineral elements (e.g., carbon, hydrogen, and sulfur) were the main components of samples from the NO. 3 coal seam in the Zhengzhuang block, averaging 85.14% and ranging from 81% to 90%. The clay mineral content ranged from 4% to 9%, with an average of 6.71%. In addition, samples contained small amounts of quartz, calcite, siderite, anorthose, hematite, iron, pyrite, ankerite and tobelite. The clay mineral compositions are presented in Table 2. The main components of the clay in the coalbeds were illite and kaolinite, accounting for 44.86% and 26%, respectively. The third constituent was a mixed-layer of illite and smectite (I/S), with a smaller ratio of expansive clay mineral (averaging 12.86%). The illite scattered when in contact with water, resulting in fine migration. Additionally, coal is easy to grind into a powder during drilling or other operations, causing particle migration. 3.1.2. Microstructure and pore parameters The microstructure of the NO. 3 coal seam had the following characteristics: parallel grains, bedding (Fig. 1c and e) and joints. The cleats (Fig. 1f) of the coal were easily recognizable and showed good tropism; the coal fragments appeared as angular sheets (Fig. 1f); micropores, including moldic pores, blow holes, tissue holes and deformed tissue holes, developed locally (Fig. 1a, b, d, f, g, h), and the pores were partially filled by quartz (Fig. 1a) and clay minerals (Fig. 1b, d, g, h). Parallel grains, bedding, joints and cleats of the coal would provide channels for filtering liquids invading into the coalbed, causing damage if the liquids were incompatible with the coal core. Clay minerals in micropores will hydrate once in contact with water, leading to flow path and particulate output reduction. A large number of microfractures existed in the NO. 3 coal seam (Fig. 2a, b, c, e, f, g, h), with moderate connectivity (i.e., several fractures are not connected on the plane, Fig. 2a, c, g). The main fissures were 0.11e1.2 cm long and 3e34 mm wide, with a distribution density of 6.1e13.1 strips/cm and a breach width of
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1e310 mm. Slits measured 0.03e0.6 cm long and 2e23 mm wide, with a distribution density of 2.2e7.7 strips/cm. The microfracture shapes were anomalous and vertically oriented with the coal bedding; for example, the fracture in sample 3-3# resembles a wild goose tail and is well-connected (Fig. 2e). Several fractures were filled by clay minerals, iron pyrite and calcite (Fig. 2f and h). Joints and cleats of the coal showed grid shaped distributions on the flat surface (Fig. 2d). Micropores with certain connectivity partially developed (Fig. 2a, b, c, g) and were connected through joints and cleats. Results of the intrusive mercury experiment (Table 3, Fig. 3) showed that the NO. 3 coal seam was a representatively low porosity fractured reservoir, with a porosity of 4.9%. The maximum pore radius ranged from 14.39 mm to 180.71 mm, with an average of 50.87 mm. The average pore radius was 12.92 mm, ranging from 2.75 mm to 46.11 mm. The size of the minimum pore contributing to the permeability ranged from 2.75 mm to 36.9 mm, with an average of 13.3 mm, indicating that fractures were the main seepage channel for methane. The uniformity coefficient (average of 0.2347 mm, ranging from 0.1866 to 0.2914 mm) of the samples indicated that the NO. 3 coal seam was strongly heterogeneous. 3.1.3. Hydration properties The recovery rate of nickings from the NO. 3 coal seam averaged 96.61%, ranging from 92.1% to 99.7% (Table 4), suggesting that the coal core in the NO. 3 coal seam had weak hydration dispersing capacity. Linear swelling rates were between 0.45% and 3.78% with an average of 1.74%, indicating that the coal core had lower hydrating and swelling properties. However, the samples swelled rapidly during the early stage when the coal powder was in contact with water, but 20 min later, the expansion was slight until the maximum swelling rate was reached and remained constant within 8 h (Fig. 4). The high recovery rate and low swelling rate indicated that the coal core in the NO. 3 coal seam exhibited poor hydration performance and showed weak water sensitivity due to the low clay mineral content (Lever and Dawe, 1984). 3.1.4. Wettability of the coal surface Table 5 and Fig. 5 show that the contact angles between the water and coal surface ranged from 100.08 to 132.86 , with an average of 115.51 (>90 ), which corroborates the hydrophobicity of the coal core surface. A serious water lock effect occurs in the oilwet reservoir, reducing the permeability of the formation. Moreover, water does not spread on the oil-wet coal surface (average amount of adhesion work is 42.25 mJ m2), existing in the form of water droplets and hindering the flow of methane in the coalbed (Saghafi et al., 2014; Li et al., 2015). 3.2. Sensitivity of coal cores The permeabilities of samples ZS30-1, ZS31-1, ZS39-1 increased during the initial phase of methane flow and decreased as the gasflow rate exceeded 12.45 cm3/min (next flow rate was 15.92 cm3/
Table 1 Mineral compositions determined by X-ray diffraction. Sample
Quartz (%)
Calcite (%)
Siderite (%)
Anorthose (%)
Hematite (%)
Iron Pyrite (%)
Ankerite (%)
Tobelite (%)
Clay (%)
Non mineral (%)
ZS30 ZS39 3-1# 3-2# 3-3# 3-4# 3-5#
2 3 3 1 1 2 1
e 1 e 1 2 e 1
2 e 3 2 1 1 1
e e 2 1 e e e
e e 1 e e e e
2 1 e e e e e
e 1 2 1 1 2 1
2 1 3 2 2 1 3
9 7 5 6 8 4 8
83 86 81 86 85 90 85
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Table 2 The relative contents of clay minerals. Sample
Kaolinite (%)
Chlorite (%)
Illite (%)
I/S (%)
Interlaying ratio of I/S (%)
ZS30 ZS39 3-1# 3-2# 3-3# 3-4# 3-5#
26 33 38 15 23 28 19
9 17 12 15 13 8 11
44 37 50 47 42 51 43
21 13 0 23 22 13 27
20 20 0 5 20 20 5
Fig. 1. Microscopic images of the coal core of the NO. 3 coal seam. (a) e ZS30 (7000 times). (b) e ZS39 (9000 times). (c) e 3-1# (2200 times) (d) e 3-2# (6000 times). (e) e 3-3# (700 times). (f) e 3-4# (3000 times). (g) e 3-5# (9000 times). (h) e 3-5# (8000 times).
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Fig. 2. Thin section analysis images of the coal core of the NO. 3 coal seam. (a) e ZS30 (100 times). (b) e ZS39 (100 times). (c) e 3-1# (25 times) (d) e 3-2# (25 times). (e) e 3-3# (100 times). (f) e 3-4# (25 times). (g) e 3-5# (25 times). (h) e 3-5# (25 times).
Table 3 Pore parameters of the coal core. Sample
Porosity (%)
Maximum pore radius (mm)
Average pore radius (mm)
Minimum pore size with contribution to permeability (mm)
Uniformity coefficient
ZS30 ZS39 3-1# 3-2# 3-3# 3-4# 3-5#
4.86 4.3 5.28 3.62 6.44 5.14 4.66
35.41 28.56 36.43 14.39 180.71 34.86 25.74
7.99 8.24 9.88 2.75 46.11 9.12 6.33
16.05 11.33 12.5 2.75 36.9 8.47 5.09
0.2517 0.1866 0.2914 0.1938 0.2787 0.2334 0.2071
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Fig. 3. Intrusive mercury curves of the coal core of the NO. 3 coal seam.
Table 4 Test results of hydration properties of the coal cores. Sample
ZS30
ZS39
3-1#
3-2#
3-3#
3-4#
3-5#
Recovery rate (%) Expansion rate (%)
98.9 0.71
97.8 1.39
99.7 2.38
92.1 3.78
93.7 0.45
96.5 1.75
97.3 1.69
Fig. 4. Linear swelling rate of the coal core from the NO. 3 coal seam with time.
min), which is the critical flow velocity (Fig. 6). Weak velocity sensitivity damage was verified by the small permeability reduction of less than 20% (Table 6). The average permeability reduction rate of the samples was 65.97% after the ambient pressure exceeded 0.5 MPa, which was confirmed as the critical pressure (Fig. 7). The
stress sensitivity indexes of samples ZS30-2, ZS30-3 and ZS44-1 were 66.76%, 58.71% and 72.44%, respectively (Table 6), suggesting that they possessed moderate stress sensitivity, even higher than that of tight sandstone, which shows a sensitivity index of 30%e60%. The stress sensitivity damage of the samples cannot be recovered after releasing the ambient pressure because the fractures in the main flow channel of the CBM reservoir will close once the confining pressure exceeds the closure pressure. Samples ZS304, H-1 and ZS31-2 were weakly sensitive to water, as demonstrated by their higher water sensitivity indexes and lower critical salinity of 5000 mg/L (Fig. 8, Table 6) due to a low clay content. Small alkali sensitivity indexes (i.e., 6.73%, 7.7%, 4.91%), listed in Table 6, and a high critical pH value (i.e., 13; Fig. 8) indicate that samples ZS30-5, ZS39-2 and ZS41-2 are weakly sensitive to alkaline conditions. The permeabilities of samples ZS30-6 and H-2 decreased from 0.0728 103 mm2 to 0.0689 103 mm2 and from 0.2133 103 mm2 to 0.1924 103 mm2 after being acidified with 15 wt% hydrochloric acid (Fig. 9), suggesting weak acid sensitivity (94.6% and 90.2%, respectively; Table 6) to small amounts of siderite and ankerite in the coal. As discussed above, water blocking can cause severe damage to the NO. 3 coal seam. The permeability of the dry cores is far greater that of the saturated cores, and the dry cores contain 0.5 wt% salt water. The water blocking indexes of samples ZS30-7, ZS30-8 and ZS31-3 are 27.32%, 22.77% and 26.41%, respectively (Fig. 10). Based on the potential damage and sensitivity evaluations, it can be concluded that the damage mechanisms of the NO. 3 coal seam in the Zhengzhuang block are as follows: severe water blocking, moderate stress sensitivity, weak velocity sensitivity, water sensitivity, alkali sensitivity and acid sensitivity. The water block damage can be reduced by using surfactants in a water-based working fluid by reducing the capillary force of water in cracks and modifying the
Table 5 Wettability test results of the coal cores. Sample
ZS30
ZS39
3-1#
3-2#
3-3#
3-4#
3-5#
Left contact angle ( ) Right contact angle ( ) Average contact angle ( ) Adhesion work (mJ m2)
131.44 134.29 132.86 23.28
128.87 133.4 131.13 24.91
115.7 121.39 118.55 38.01
120.26 122.28 121.27 35.01
99.92 100.39 100.16 59.96
103.55 105.51 104.53 54.54
99.60 100.55 100.08 60.07
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Fig. 5. Photographs of water drops on a coal core surface. (a) e ZS30 b e 3-3#.
3.3. Optimization of the operating fluid with low damage 3.3.1. Composition optimization of the operating fluid To reduce damage due to severe water blocking and certain degrees of water sensitivity in the NO. 3 coal seam of the Zhengzhuang block, an inhibitor and a waterproof lock agent were selected to form a newly solid-free drilling fluid and activated water fracturing fluid. Inorganic salts represent one type of inexpensive hydration swelling inhibitor by compressing the diffuse double layer of clay particles (Arasan et al., 2010). Potassium chloride and calcium chloride are widely used in drilling fluids and fracturing liquids. Their inhibition of coal powder hydration was measured in a swelling experiment, the results of which are presented in Fig. 11. The expansion rate of sample 3-2# decreased with the increase in the concentration of the test liquid. Calcium chloride showed better inhibition of coal powder hydration than did potassium chloride. The swelling rate of CaCl2 was reduced by 80.69% when its content was 0.5 wt% and then showed little change. Therefore, CaCl2 was selected as the inhibitor to reduce damage due to the core water sensitivity of the operating liquid; its dosage was 0.5 wt%. To modify the hydrophobicity of the coal surface, two watersoluble surfactants were chosen in this study. Anionic sodium alkyl benzene sulfonate is often used in operating liquids as a waterproof locking agent for tight sandstone reservoirs and fractured carbonate reservoirs. SWIA is another non-ionic surfactant. SWIA is a commercial product used as a coal powder dispersing
Fig. 6. Velocity sensitivity evaluation of samples ZS30-1, ZS31-1 and ZS39-1.
wettability of the coal surface (Zhang et al., 2012). Excessive differential pressures and discharge rates should be prohibited to avoid stress and velocity sensitivity (Yang et al., 2015; Bai et al., 2009). Working fluid inhibition should be enhanced by adding a suitable inhibitor, such as inorganic salt or organic cations (Zuo et al., 2014). Although the alkali sensitivity was weak, the pH of the working liquid should be adjusted below 12 to prevent materials from being dissolved during operation. Acidification is not recommended because of the weak acid sensitivity of coal and the environmental problems it may cause (Tian and Wu, 2014).
Table 6 Sensitivity evaluation results of the coal cores. Type
Criterion for judgement
Test result
Damage degree
Remarks
Velocity sensitivity
Weak: <30% Moderate: 30%e70% Strong: >70% Weak: <30% Moderate: 30%e70% Strong: 70%e100% Extremely strong:>100% Weak: >70% Moderate: 70%e30% Strong: <30% Weak: <30% Moderate: 30%e70% Strong: >70% Weak: >70% Moderate: 70%e30% Strong: <30% Weak: >70% Moderate: 70%e30% Strong: <30%
ZS30-1: ZS31-1: ZS39-1: ZS30-2: ZS30-3: ZS41-1:
ZS30-1: ZS31-1: ZS39-1: ZS30-2: ZS30-3: ZS41-1:
Critical velocity: 12.45 cm3/min
Stress sensitivity
Water sensitivity
Sensitivity to alkaline
Acid sensitivity
Water blocking
14% 18.1% 12.7% 66.76% 58.71% 72.44%
Weak Weak Weak Moderate Moderate Strong
Critical pressure: 0.5 MPa
ZS30-4: 91.13% H-1: 87.96% ZS31-2: 90.1% ZS30-5:6.73% ZS39-2: 7.7% ZS41-2: 4.91% ZS30-6: 94.6% H-2: 90.2%
ZS30-4: Weak H-1: Weak ZS31-2: Weak ZS30-5:Weak ZS39-2: Weak ZS41-2: Weak ZS30-6: Weak H-2: Weak
Critical salinity: 5000 mg/L
ZS30-7: 27.32% ZS30-8: 22.77% ZS31-3: 26.41%
ZS30-7: Strong ZS30-8: Strong ZS31-3: Strong
e
Critical pH: 13
e
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Fig. 7. Stress sensitivity evaluation of samples (a) ZS30-2 and (b) ZS30-3.
Fig. 8. (a) Water sensitivity and (b) alkaline sensitivity of samples.
agent and cleaning additive in fracturing liquids. Both surfactants can transform the hydrophobic surface of coal into a strongly hydrophilic one (Fig. 12; Table 7). As the concentration of the surfactant increased in the soak solution, the contact angle between the water and coal surface decreased, and the adhesion energy increased, allowing the water to spread easily on the coal surface. SWIA has a stronger effect than ABS at the same content and was selected as the wettability adjustment agent in the working fluid, with a concentration of 0.3 wt%. Carboxymethyl cellulose (high viscosity, with a degree of polymerization greater than 600 CMC-HV), which causes low damage to coalbed methane reservoirs, was used to improve the viscosity of the drilling fluid and decrease the friction of the fracturing liquid (Table 8). Carboxymethyl starch (CMS) was chosen as a fluid loss additive in the drilling fluid to reduce filtrate formation and
damage to the coal seam (Table 8). CMC-HV and CMS can be degraded using cellulose enzymes or amylase as needed. 3.3.2. Reservoir protection performance During drilling, completion, fracturing and water withdrawing for production, the CBM reservoir is mostly wet. The permeability of the coal seam in a hygrometric state played an important role in methane movement and flowback of the fracturing liquid. The effects of the experimental liquid on coal seam permeability in the hygrometric and dry states were investigated using core flow tests. Coal cores from the Zhengzhuang block showed lower permeability than did those from the Heshun and Yanchuannan blocks, with an average permeability of 0.267 103 mm2 (Table 8) (Huang et al., 2012). XC and CMC-HV both caused damage to the coal seam by adhering onto the internal walls of pores. The permeability
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Fig. 9. Acid sensitivity evaluation of samples ZS30-6 and H-2.
Fig. 10. Water blocking damage evaluation of samples ZS30-7, ZS30-8 and ZS31-3.
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72.82%) and larger recovery rate of permeability (86.16%, 88.34%) in the dry state compared with those of surface water. Drilling mud 07-1#, 07-2#, 4#, and 5# from a gas field in the Zhengzhuang block all caused severe damage to the coal seam, with the same loss ratio of 100% in the wet state. The main reason for this behavior is the clogging of solids in the drilling fluid (the particle size distributions were 0.149e1.495 mm, 0.351e1.758 mm, 0.49e66.5 mm, 0.49e48.27 mm, respectively) without any surfactant. The permeability reduction ratios of the optimized drilling fluid and fracturing liquid were 64.68% and 54.92% less than the permeability reduction ratio of the drilling fluid from the field, with higher recovery rates of permeability (95.9%, 96.2%) in the dry state. Amylase could reduce the damage of CMC-HV and CMS by biodegradation, which decreased the permeability reduction ratio of the optimized drilling fluid and increased the recovery rate of permeability in the dry state. The Langmuir volume of coal represents the largest adsorption quantity of methane on its surface. The Langmuir pressure indicates the steepness of the adsorption isotherm; the lower the Langmuir pressure is, the steeper the adsorption isotherm becomes, which determines the accessibility rate and range of depressurization and recoverability of the CBM reservoir. The methane-adsorbing capacity of coal powder saturated by experimental liquid was lower than that of the dry samples (Fig. 13), and the Langmuir volume also decreased (Table 9). There were two reasons for this behavior. First, the surface wettability of the coal was altered after saturation by the experimental liquid, and the hydrophobicity of the coal surface decreased to a different degree. Second, several adsorption sites on the coal surface were occupied by components in the experimental liquid (Gosiewska et al., 2002). The Langmuir pressure of the sample saturated by the experimental liquid was greater than that of the dry coal powder (Table 9), indicating that methane desorbed easier from the surface of coal after saturation by the experimental liquid. The surface water and drilling muds from the gas field clearly improved the Langmuir pressure but only slightly reduced the amount of methane adsorbed on the coal surface, to the disadvantage of its desorption from coal. Although the optimized drilling fluid decreased the Langmuir volume from 51.28 cm3/g of dry coal to 37.96 cm3/g, it increased the Langmuir pressure from 1.14 MPa to 3.17 MPa, benefitting gas production and the recoverability of CBM reservoirs. The optimized fracturing liquid containing less CMC-HV and no CMS showed the best performance by reducing the Langmuir volume, increasing the Langmuir pressure and causing the least damage to the CBM reservoir among the evaluated liquids. 4. Conclusions
Fig. 11. Water blocking damage evaluation of samples ZS30-7 and ZS30-8.
reduction ratio of 0.05 wt% of the XC solution was 100% (methane could not be driven through the core under the experimental pressure), greater than that of CMC-HV and CMS. ABS and SWIA could effectively decrease water blocking, as demonstrated by their lower permeability loss ratio in the hygrometric state (77.68%,
(1) The NO. 3 coal seam in the Zhengzhuang block is a representative low-porosity fractured reservoir. Parallel grains, bedding, joints and cleats are the primary flow channels of methane and provide paths for filtering invading liquids into the coalbed to cause damage. The breach width (3e34 mm) and average pore radius (2.75e46.11 mm) distribution characteristics of coal make it more easily damaged by solids such as coal dust and particles in operating fluids. (2) The coal core from the NO. 3 seam was mainly composed of carbon and a certain amount of clay minerals, such as siderite and ankerite, making it sensitive to water and possibly hydrochloride. The hydrophobicity of the coal core surface caused a water blocking effect and could reduce the permeability of methane in the coal seam. (3) Severe water blocking, moderate stress sensitivity, weak velocity sensitivity, water sensitivity, alkali sensitivity and acid sensitivity were the main damage mechanisms for the
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Fig. 12. Photographs of water drops on the surface of a coal core soaked with the surfactant solution. (a) 0.2% ABS (b) 0.3% ABS (c) 0.4% ABS. (d) 0.2% SWIA (e) 0.3% SWIA (f) 0.4% SWIA.
Table 7 Wettability test results of the coal core surface modified with the surfactant. Test status Polished flat Soaked by 0.2% Soaked by 0.3% Soaked by 0.4% Soaked by 0.2% Soaked by 0.3% Soaked by 0.4%
ABS ABS ABS SWIA SWIA SWIA
Left contact angle ( )
Right contact angle ( )
Average contact angle ( )
Adhesion work (mJ m2)
131.44 10.29 7.44 5.20 8.22 5.37 4.73
134.29 12.27 5.75 6.41 14.24 4.70 4.01
132.86 11.28 6.60 5.81 11.23 5.04 4.37
23.28 144.19 145.12 145.23 144.21 145.32 145.39
Table 8 Wettability test results of the coal core surface modified with surfactant. Core number
Experimental liquid
KO (103 mm)
KO1 (103 mm)
S1 (%)
KO2 (103 mm)
R2 (%)
3-3-1# 3-3-2# 3-3-3# 3-3-4# 3-3-5# 3-3-6# 3-3-7# 3-3-8# 3-3-9# 3-3-10# 3-3-11#
0.05% XC solution 0.1% CMC-HV solution 1.2% CMS solution 0.3% ABS solution 0.3% SWIA solution Surface water 07-1# drilling mud 07-2# drilling mud 4# drilling mud 5# drilling mud Optimized drilling fluid Optimized drilling fluid degraded by 0.1% amylase Optimized fracturing liquid
0.3527 0.5712 0.2783 0.1698 0.301 0.2263 0.1095 0.0701 0.1021 0.1104 0.4436 0.4254 0.2948
0 0.0703 0.0462 0.0379 0.0818 0.024 0 0 0 0 0.1567 0.2231 0.1329
100.00 87.69 83.40 77.68 72.82 89.39 100.00 100.00 100.00 100.00 64.68 47.56 54.92
0.2981 0.5124 0.2345 0.1463 0.2659 0.1893 0.0611 0.0506 0.0896 0.0756 0.4254 0.4189 0.2836
84.52 89.71 84.26 86.16 88.34 83.65 55.80 72.18 87.76 68.48 95.90 98.47 96.20
3-3-12#
Note: KO is the original permeability of cores for methane; KO1 is the permeability of cores after they were saturated by experimental liquid and tested in the wet state; S1 ¼ (1KO1/KO) 100%; KO2 is the permeability of cores after the saturated experimental liquid was discharged by heating at a temperature of 105 C; R2 ¼ (KO2/KO) 100%. Optimized drilling fluid: Surface water þ 0.5% CaCl2 þ 0.3 wt% CMC-HV þ 1.2 wt% CMS þ 0.3 wt% SWIA; optimized fracturing liquid: Surface water þ 0.5% CaCl2 þ 0.06 wt% CMC-HV þ 0.3 wt% SWIA. The core samples are saturated by 0.1% amylase solution at 50 C for 2 h.
CBM reservoir in the Zhengzhuang block. Water sensitivity and alkali sensitivity damage can be eliminated by controlling the salinity and pH within a critical value range. Acidification is not recommended due to the weak acid sensitivity of coal and the risk of environmental problems. (4) CaCl2 was selected as an inhibitor to reduce water sensitivity, and SWIA could adjust the core wettability. CMC-HV and CMS were chosen as viscosifiers, friction-reducing agents and fluid loss additive operating liquids because they cause little damage to the permeability of coalbed methane reservoirs.
(5) The optimized drilling fluid and fracturing liquid caused less permeability loss of the cores and less damage to the CBM reservoir in both the wet and dry states than did surface water and drilling muds from the gas field in the Zhengzhuang block. Moreover, the optimized drilling fluid and fracturing liquid could decrease the Langmuir volume, increase the Langmuir pressure of the coal to promote desorption of methane from coal surface and enhance the recoverability of CBM reservoirs.
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Fig. 13. Adsorption isotherms of coal before and after saturation by experimental liquids.
Table 9 Effect of experimental liquids on the Langmuir volume and Langmuir pressure of coal. Experimental condition
Langmuir volume (cm3/g)
Langmuir pressure (MPa)
Original Saturated Saturated Saturated Saturated Saturated Saturated Saturated fluid Saturated liquid
51.28 48.37 46.33 47.39 46.73 44.81 46.30 37.96
1.14 2.69 2.12 2.16 2.41 2.34 2.35 3.17
by optimized fracturing 35.34
3.29
by by by by by by by
distilled water Surface water 07-1# drilling mud 07-2# drilling mud 4# drilling mud 5# drilling mud optimized drilling
Acknowledgments This work was financially supported by the National Science Foundation of China (No. 51374233; No. 41072094), Shandong Province Science Foundation (No. ZR2013EEM032), the Fundamental Research Funds for the Central Universities (No. 13CX02044A) and the Project of China Scholarship Council (201306455021). Abbreviations ABS API CBM CMC CMS I/S LTA SEM XC XRD
Alkyl benzene sulfonate American Petroleum Institute Coalbed methane Carboxymethyl cellulose Carboxymethyl starch Mixed-layer of illite and smectite Low-temperature ash Scanning electron microscope Xanthan gum X-ray diffraction analysis
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