energies
Article Effect of Shale Anisotropy on Hydration and Its Implications for Water Uptake
Yunhu Lu 1,2 , Lingping Zeng 3 , Yan Jin 1,2,*, Guanglei Chen 1,2, Junfan Ren 1,2, Hon Chung Lau 4 and Quan Xie 3,*
1 State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing), Beijing 102249, China; [email protected] (Y.L.); [email protected] (G.C.); [email protected] (J.R.) 2 College of Petroleum Engineering, China University of Petroleum (Beijing), Beijing 102249, China 3 Discipline of Petroleum Engineering, WA School of Mines: Minerals, Energy and Chemical Engineering, Curtin University, 26 Dick Perry Avenue, Kensington 6151, Western Australia, Australia; [email protected] 4 Department of Civil and Environmental Engineering, National University of Singapore, Singapore 117576, Singapore; [email protected] * Correspondence: [email protected] (Y.J.); [email protected] (Q.X.)
Received: 18 September 2019; Accepted: 4 November 2019; Published: 6 November 2019
Abstract: Water uptake induced by fluid–rock interaction plays a significant role in the recovery of flowback water during hydraulic fracturing. However, the existing accounts fail to fully acknowledge the significance of shale anisotropy on water uptake typically under in situ reservoir temperature. Thus we investigated the shale-hydration anisotropy using two sets of shale samples from the Longmaxi Formation in Sichuan Basin, China, which are designated to imbibe water parallel and perpendicular to shale bedding planes. All the samples were immersed in distilled water for one to five days at 80 ◦C or 120 ◦C. Furthermore, samples’ topographical and elemental variations before and after hydration were quantified using energy-dispersive spectroscopy–field-emission scanning electron microscopy. Our results show that shale anisotropy and imbibition time strongly affect the width of pre-existing micro-fracture in hydrated samples. For imbibition parallel to lamination, the width of pre-existing micro-fracture initially decreases and leads to crack-healing. Subsequently, the crack surfaces slightly collapse and the micro-fracture width is enlarged. In contrast, imbibition perpendicular to lamination does not generate new micro-fracture. Our results imply that during the flowback process of hydraulic fracturing fluid, the shale permeability parallel to bedding planes likely decreases first then increases, thereby promoting the water uptake.
Keywords: shale reservoirs; anisotropy; hydraulic fracturing; water uptake; hydration
1. Introduction With an increasing demand for geo-energy, unconventional resources, such as shale gas, play a significant role in meeting demand, and are expected to continue to do so for the foreseeable future [1]. Shale gas production in 2012 accounted for 34% of total natural gas production in the U.S. and is estimated to increase to nearly 50% by 2035 [2,3]. Due to the ultra-low permeability (tens of nano-Darcy to 1 milli-Darcy), a combination of horizontal drilling and multi-stage hydraulic fracturing has been widely used to enhance the formation connectivity by generating new fractures and activating pre-existing micro-fracture to achieve commercial shale gas production [4–8]. However, only 10% to 20% of injected hydraulic fluids are recovered during the flowback period for some shale plays [9,10]. For example, Nicot and Scanlon [11,12] conclude that up to 80% of hydraulic fluids remain underground after hydraulic fracturing in the Eagle Ford shale reservoir. Published works
Energies 2019, 12, 4225; doi:10.3390/en12224225 www.mdpi.com/journal/energies Energies 2019, 12, 4225 2 of 20 show that this large amount of fluid loss is associated with fluid–rock interaction such as hydration of clay minerals [13,14], capillary pressure [13,15,16] and osmotic flow [17,18]. Binazadeh et al. [14] quantified the effect of solution ionic strength on clay hydration. They conclude that low ionic strength may expand the electrostatic double layer (EDL) on clay surface, and generate a thicker hydration shell, which facilitates water imbibition. Fakcharoenphol et al. [18] simulated the effect of osmotic pressure on water and oil flow into and out of the shale plugs with consideration of capillary pressure. Their results indicate that high osmotic pressure likely takes place in shales due to the considerable salinity difference between in situ brine and slick water, which would promote water imbibition and oil counter-current flow. All these mechanisms imply that spontaneous imbibition associated with fluid–shale interaction and capillary forces governs hydraulic fracturing fluids loss [9,13,15,16,19–21]. Moreover, shale reservoirs present strong anisotropy [22], which would significantly affect water imbibition [15,23]. Existing studies show that the rate of water uptake depends significantly on the imbibition direction, whether parallel or perpendicular to the bedding planes [24]. For instance, Makhanov et al. [24] experimentally measured the brine-imbibition rate into shale plugs from Horn River Basin, Canada. They found that compared to the imbibition perpendicular to lamination, parallel imbibition to bedding planes can accelerate water uptake due to the shale layered structure. Moreover, Makhanov et al. [25] and Dehghanpour et al. [26] report that the clay hydration-induced micro-fracture likely increases shales’ permeability, and thus favour water uptake, which may also account for the low recovery of flowback water. However, Dehghanpour et al. [26] and Roychaudhuri et al. [27] draw the opposite conclusions that due to the clay minerals swelling and grains migration, the excess water imbibition would trigger a micro-fracture healing, which may decrease shale permeability and impair the imbibition rate. Hitherto, the nature of shale hydration associated with strong anisotropy still remains to be unveiled. Moreover, few existing studies investigate the effect of shale anisotropy on water uptake with consideration of in situ reservoir temperature and pressure. Furthermore, the time effect on water imbibition with respect to the shale anisotropy has been overlooked. Therefore, in this study, we aim to identify the controlling factors that drive shale hydration by addressing the following questions:
1. How does the imbibition direction (parallel or perpendicular to the bedding planes) influence the shale hydration? 2. How do the temperature and pressure affect shale water uptake? 3. What are the mechanisms of hydration?
To answer these questions, we investigated shale hydration anisotropy experimentally using two sets of shale samples extracted from the Longmaxi Formation in Sichuan Basin, China. The first set of experiments was designed to imbibe water parallel to the bedding plane, whereas the second set of experiments was conducted for the perpendicular imbibition. All samples were immersed in distilled water for one to five days with pressure of 3.5 MPa at 80 ◦C or 120 ◦C. Furthermore, to better characterize the samples’ topographical and elemental variations, energy-dispersive spectroscopy–field-emission scanning electron microscopy (EDS–FE-SEM) was used before and after hydration for quantitative analysis.
2. Experimental Materials and Procedures
2.1. Mineralogy Shale reservoir samples in this work (Figure1) were extracted from the Longmaxi Formation in the Changning-Weiyuan area of Sichuan province, China, which is currently the main commercial exploration and production shale gas target in China (see Figure2). This formation has been characterised by the high total organic carbon content (TOC), high gas content and is a relatively easily to frack [28–30]. Considering that the shale hydration would be strongly affected by the organic matter (kerogen) and inorganic minerals [27,31], a carbon-sulphur analyser and X-ray diffraction Energies 2019, 12, 4225 3 of 20
(XRD) were used to analyse the samples’ organic content and mineral compositions. Results show that theEnergies content 2019, 12 of, x FOR total PEER organic REVIEW carbon (TOC) ranges from 1.78% to 2.85% with kerogen of3 of type 21 III (TableEnergies1). Quartz 2019, 12 is, x theFOR dominantPEER REVIEW mineral followed by calcite and feldspar together with a high3 of content 21 of claycontent minerals, of clay especially minerals, illite especially/smectite illite/smectite (Table2). It(Table is worth 2). It notingis worth that noting the that mineralogy the mineralogy of Longmaxi of contentLongmaxi of claysamples minerals, in this especially study is similar illite/smectite to that of (Table Lower 2). Bakken It is worth and Haynesvillenoting that the shales mineralogy in the U.S., of samples in this study is similar to that of Lower Bakken and Haynesville shales in the U.S., which Longmaxiwhich contain samples a high in this content study of is similarquartz toand that illite/smectite of Lower Bakken [32]. andBesides, Haynesville Xu and shalesSonnenberg in the U.S., [33] contain a high content of quartz and illite/smectite [32]. Besides, Xu and Sonnenberg [33] observed that whichobserved contain that thea high micro-fracture content of quartzsurfaces and of illite/smectitelower Bakken [32].shale Besides, samples Xu are and mainly Sonnenberg covered [33] by the micro-fractureobservedquartz, K-feldspar, that the surfaces micro-fracturecalcite, of dolomite, lower surfaces Bakken and a littleof shale lo amountwer samples Bakken of organic are shale mainly matterssamples covered in are some mainly by areas. quartz, covered Therefore, K-feldspar, by calcite,quartz,we dolomite, assumed K-feldspar, andthat athe calcite, little experimental amount dolomite, of resultsand organic a little for matters Longamountmaxi in of some samplesorganic areas. mattersshould Therefore, inbe some also weareas.applied assumed Therefore, to these that the experimentalweestablished assumed results shale that plays.forthe Longmaxiexperimental samples results shouldfor Long bemaxi also samples applied should to these be establishedalso applied shale to these plays. established shale plays.
FigureFigure 1. Samples 1. Samples from from the the Longmaxi Longmaxi Formation that that were were used used in inimmersion immersion tests. tests. Figure 1. Samples from the Longmaxi Formation that were used in immersion tests.
Figure 2. The location of target reservoir samples from the Longmaxi Formation used in this study FigureFigure(from 2. The Jiang 2. The location et locational., [30]). of oftarget target reservoir reservoir samplessamples from the the Longmaxi Longmaxi Formation Formation used used in this in study this study (from(from Jiang Jiang et al., et [al.,30 ]).[30]).
Energies 2019, 12, 4225 4 of 20 Energies 2019, 12, x FOR PEER REVIEW 4 of 21
Table 1. Organic and inorganic mineral composition of shale samples.
SamplingSampling Depth Depth TOC TOC ** Mineral Mineral Composition Composition (%) (%) (m)(m) (%) (%) Quartz Quartz FeldsparFeldspar CalciteCalcite Dolomite Pyrite Clay Clay 23212321 1.781.78 3131 11.411.4 12.912.9 5.15.1 1.2 38.4 38.4 23242324 2.852.85 31.731.7 5.55.5 8.38.3 5.95.9 3.6 45 45 *TOC* TOC represents represents the the total total organic organic carboncarbon of of the the tested tested samples. samples.
Table 2. Clay minerals composition of shale samples.
SamplingSampling Depth Depth Relative Relative Content Content of of Clay Clay Minerals Minerals (%) (%) Mixed-Laye Mixed-Layerr Ratio Ratio (%S)** (%S) ** (m) I/S* It K C I/S (m) I/S * It K C I/S 2321 53 28 9 10 12 23242321 53 44 28 34 9 10 12 10 12 12 2324 44 34 10 12 12 *I/S: illite/smectite mixed; It: illite; K: kaolinite; C: chlorite. **%S: Portion of smectite in illite/smectite mixed-layer.*I/S: illite/smectite mixed; It: illite; K: kaolinite; C: chlorite. ** %S: Portion of smectite in illite/smectite mixed-layer.
2.2. Sample Sample Preparation Preparation and Characterization The micro-structure micro-structure of ofshale shale plays plays a vital a role vital in roleanisotropy in anisotropy hydration hydration during water during imbibition water [13,24,25].imbibition Therefore, [13,24,25]. it Therefore, is worth investigating it is worth investigating the microscopic the microscopicstructure of the structure bedding of planes. the bedding First, samplesplanes. First, were samples cut either were in parallel cut either or inperpendicular parallel or perpendicular to the lamination to the with lamination a dimension with a of dimension 10 mm × of 10 mm 10 mm 2 mm using a freeze corer with liquid nitrogen. Second, the sample surfaces were 10 mm × 2× mm using× a freeze corer with liquid nitrogen. Second, the sample surfaces were polished bypolished argon byion argonand sprayed ion and with sprayed a pure with carbon a pure film carbon [34]. Focused film [34 ].ion Focused beam (FIB) ion beam combined (FIB) with combined field- withemission field-emission scanning scanningelectron electronmicroscopy microscopy (FE-SEM) (FE-SEM) (type FEI (type Helios FEI Helios NanoLab NanoLab 650) 650)was wasused used to investigateto investigate the the microscopic microscopic features features of of shale. shale. With With the the advance advance of of the the conventional conventional backscatter backscatter (CBS) (CBS) detection mode and secondary electrons. Through-the-lens detection (SE-TLD) mode in FIB–FESEM can characterize the nano-structure of shale beddin beddingg planes with resolution of 0.8 nm under vacuum condition. Results showshow thatthat at at the the surface surface perpendicular perpendicular to theto the bedding bedding planes, planes, the mineralthe mineral grains grains with withdifferent different sizes sizes are homogeneously are homogeneously dispersed dispersed and doand not do presentnot present any any specific specific orientation orientation (Figure (Figure3a). 3a).For For the the surface surface parallel parallel to theto the bedding bedding planes, planes, the the mineral mineral grains grains are are also also arranged arranged parallelparallel to the lamination. In In addition, addition, we we observed observed considerable considerable nanoscale nanoscale fractures and pores on sample sublayer surface. Some Some of of these these pores pores are are filled filled with with kerogen kerogen or asphaltene, implying a strong anisotropy and heterogeneity which is generally in line with existing literature [[35,36]35,36] (Figure(Figure3 3b).b).
(a) (b)
Figure 3. Scanning electron microscopymicroscopy (SEM)(SEM) images images of of Longmaxi Longmaxi shale. shale. (a ()a The) The surface surface is parallelis parallel to tobedding bedding planes, planes, and and (b )(b the) the surface surface is perpendicularis perpendicular to beddingto bedding plane. plane.
2.3. Sample Slice Preparation
Energies 2019, 12, 4225 5 of 20
2.3. Sample Slice Preparation Energies 2019, 12, x FOR PEER REVIEW 5 of 21 To precisely investigate the hydration process during water imbibition on shale surfaces parallel or perpendicularTo precisely to the investigate laminations, the hydration first, we process used a duri freezeng water corer imbibition with liquid on nitrogen shale surfaces to cut parallel shaleslices with dimensionsor perpendicular of 20 to mm the laminations,18 mm 10 first, mm. we The used samples a freeze were corer labelled with liquid with nitrogen odd- and to even-numbers, cut shale slices with dimensions of× 20 mm ×× 18 mm × 10 mm. The samples were labelled with odd- and even- which corresponded to the cases that cut parallel and perpendicular to bedding planes, respectively numbers, which corresponded to the cases that cut parallel and perpendicular to bedding planes, (see Tablerespectively3). Second, (see weTable stabilized 3). Second, the sampleswe stabil withized epoxythe samples and UNNIPOL-80 with epoxy and mechanical UNNIPOL-80 polisher was usedmechanical to grind polisher the samples. was used Third, to grind to betterthe samples. present Third, the mineral to better skeletal present structure the mineral and skeletal nano-pore system,structure we polished and nano-pore the slices system, using we an polished 1060-Argon-Ion-Polisher the slices using an 1060-Argon-Ion-Polisher to smooth the samples’ to surfaces.smooth the samples’ surfaces. 2.4. Experimental Procedures 2.4. Experimental Procedures The depth of shale formation in Changning-Weiyuan area is approximately from 2000 to 3000 m with temperatureThe depth ranging of shale formation from 75 toin 125Changning-Weiyuan◦C[37]. Therefore, area experimentalis approximately temperature from 2000 to in 3000 this m work with temperature ranging from 75 to 125 °C [37]. Therefore, experimental temperature in this work was set as 80 ◦C and 120 ◦C. According to the American Petroleum Institute (API) standards for high-temperaturewas set as 80 °C and and high-pressure120 °C. According (HTHP) to the Amer filtrationican Petroleum tests, the Institute pressure (API) was standards set as 3.5 for MPa high- for the temperature and high-pressure (HTHP) filtration tests, the pressure was set as 3.5 MPa for the fluids fluids saturation [38]. A FEI Qemscan 650F energy-dispersive spectroscopy field-emission scanning saturation [38]. A FEI Qemscan 650F energy-dispersive spectroscopy field-emission scanning electron electron microscope (EDS–FESEM) was used to quantitatively investigate the samples’ topographical microscope (EDS–FESEM) was used to quantitatively investigate the samples’ topographical structurestructure under under vacuum vacuum condition condition (Figure (Figure4 ).4). TheThe samplesample workbench workbench of ofFEI FEI Qemscan Qemscan 650F 650F can can simultaneouslysimultaneously carry carry 14 samples14 samples with with diameter diameter lessless than 30 30 mm mm with with a resolution a resolution of 0.8 of 0.8nm. nm.
FigureFigure 4. Experimental 4. Experimental setup setup for shale for shale hydration hydration observation observation under under specific specific temperature temperature and pressure,and (a) shalepressure, rock sample,(a) shale (brock) GGS42 sample, high-temperature (b) GGS42 high-temperature and high-pressure and high-pressure (HTHP) Filtration (HTHP) PressFiltration used for samplePress immersion, used for ( c)sample workbench immersion, of FEI Qemscan(c) workbench 650F energy-dispersiveof FEI Qemscan spectroscopy–field-emission650F energy-dispersive scanningspectroscopy–field-emission electron microscope (EDS–FESEM), scanning electron and microscope (d) data acquisition (EDS–FESEM), system. and (d) data acquisition system. During the hydration tests, all the samples needed to be transferred for re-hydration and re-drying periodically.During To record the hydration the change tests, of all nano-pore the samples structures needed precisely,to be transferred we performed for re-hydration SEM for and all samplesre- and labelleddrying periodically. the feature To points record before the change the experiments. of nano-pore structures Therefore, precisely, the samples we performed could be SEM replaced for to initialall positions samples and by theselabelled featured the feature points points and before coordinates. the experiments. Furthermore, Therefore, to the investigate samples could the e beffect of replaced to initial positions by these featured points and coordinates. Furthermore, to investigate the temperature on hydration anisotropy, 20 samples were divided into two groups and immersed in a effect of temperature on hydration anisotropy, 20 samples were divided into two groups and GGS42 HTHP Filtration Press with a pressure of 3.5 MPa and temperatures of 80 and 120 C. We used immersed in a GGS42 HTHP Filtration Press with a pressure of 3.5 MPa and temperatures of◦ 80 and FD-1A-50120 °C. vacuum We used freezing FD-1A-50 dryer vacuum to dry freezing the samples dryer to and dry ETD-100AF the samplescoating and ETD-100AF machine coating to re-spray carbon film. Finally, EDS–FE-SEM was applied again to characterize the labelled micro-structures.
Energies 2019, 12, x FOR PEER REVIEW 6 of 21
machine to re-spray carbon film. Finally, EDS–FE-SEM was applied again to characterize the labelled micro-structures. Energies 2019, 12, 4225 6 of 20 Table 3. Sample information under different saturation time and temperature conditions.
Table 3. Sample information under different saturation timeTest and Temperature temperature conditions.(oC)* Immersion Time (Day) 120 80 Test Temperature (◦C) * Immersion1 Time (Day) YS-01, YS-02 YS-07, YS-08 2 120 YS-11, YS-12 80 YS-15, YS-16 3 1 YS-01, YS-03, YS-02 YS-04 YS-07, YS-08 YS-09, YS-10 4 2 YS-11, YS-13, YS-12 YS-14 YS-15, YS-16 YS-17, YS-18 3 YS-03, YS-04 YS-09, YS-10 5 YS-05, YS-06 YS-19, YS-20 4 YS-13, YS-14 YS-17, YS-18 *Samples with odd-number imbibe5 water paralle YS-05,l to the YS-06 shale bedding YS-19, planes YS-20 and even-number *imbibe Samples water with perpendicular odd-number imbibe to the water bedding parallel planes. to the shaleAll the bedding tests are planes performed and even-number with pressure imbibe of water 3.5 perpendicularMPa. to the bedding planes. All the tests are performed with pressure of 3.5 MPa.
3. Results and Discussion
3.1. Effect Effect of Time on Hydration Parallel to bedding plane: Figure Figure 3 shows the vari variationation of of shale shale hydration hydration with with time time (from (from 1 1to to 5 5days) days) along along the the direction direction of of parall parallelel to to lamination lamination with with pressure pressure of of 3.5 3.5 MPa MPa at at 80 ◦°C.C. The results indicate that the width of pre-existingpre-existing micro-fracturemicro-fracture gradually decreases from 212 to 142 nm at the end firstfirst day of immersionimmersion (Figure5 5a).a). AtAt thethe endend ofof thethe thirdthird day,day, thethe micro-fracturemicro-fracture appearedappeared toto heal in some some extent extent (Figure (Figure 5b).5b). However, However, at atthe the end end of fifth of fifth day, day, the thefracture fracture surfaces surfaces started started to spall to spalland collapse, and collapse, leading leading to an toincrease an increase of fracture of fracture width width from 476 from to 476 694 to nm. 694 Taken nm. Taken together, together, the shale the shalehydration hydration processes processes with imbibition with imbibition parallel parallel to the bedding to the bedding plane likely plane enlarged likely enlargedthe width the of micro- width offracture micro-fracture due to the due fluid–shale to the fluid–shale interaction. interaction. This physicochemical This physicochemical process may process not only may increase not only the increasetransmissibility the transmissibility of in situ ofmicro-fracture, in situ micro-fracture, but would but would also alsore-activate re-activate these these micro-fracture micro-fracture by connecting thethe individualindividual ones, ones, which which potentially potentially contributes contributes to shaleto shale gas gas production production (Figure (Figure5c). Our 5c). observationsOur observations also accountalso account for the for generation the generation of hydrated of hydrated micro-fractures micro-fractures during during shale imbibition shale imbibition [15,39]. Ghanbari[15,39]. Ghanbari and Dehghanpour and Dehghanpour [15] report [15] a similarreport observationa similar observation on micro-fracture on micro-fracture generation generation due to the claydue to hydration, the clay hydration, although the although details the of wholedetails hydration of whole hydration process are process omitted. are Chakraborty omitted. Chakraborty et al. [39] observedet al. [39] observed the healing the of healing micro-fracture of micro-fracture during shale during spontaneous shale spontaneous imbibition. imbibition. However, However, they did they not reportdid not the report subsequent the subsequent process thatprocess micro-fracture that micro-fr wouldacture re-open would duere-open to clay due (especially to clay (especially the smectite) the hydration-inducedsmectite) hydration-induced surface collapse. surface Incollapse. this work, In wethis observed work, we the observed time effect the on time the generationeffect on the of hydratedgeneration micro-fracture. of hydrated micro-fracture. To be more specific, To be more micro-fracture specific, micro-fracture would close would first, then close heal first, and then finally heal re-openand finally due re-open to the surface due to peeling.the surface peeling.
(a) Micro-fracture before and after 1 day’s saturation.
Figure 5. Cont.
Energies 2019, 12, 4225 7 of 20 Energies 2019, 12, x FOR PEER REVIEW 7 of 21
(b) Micro-fracture before and after 3 day’s saturation.
(c) Micro-fracture before and after 5 days’ saturation.
Figure 5. Micro-fracture variations before and after (a) 1 day’s, (b) 3 days’ and (c) 5 days’ saturation Figure 5. Micro-fracture variations before and after (a) 1 day’s, (b) 3 days’ and (c) 5 days’ saturation with the imbibition parallel to bedding planes at pressure of 3.5 MPa and temperature of 80 C. The ‘+’ with the imbibition parallel to bedding planes at pressure of 3.5 MPa and temperature of 80◦ °C. The in figure highlights the different ions and mineral, where red is for Mg in smectite, yellow is for Fe in ‘+’ in figure highlights the different ions and mineral, where red is for Mg in smectite, yellow is for Fe smectite, blue is for illite and brown is for feldspar. in smectite, blue is for illite and brown is for feldspar. Smectite likely peels off from the pore surfaces, thus increasing the width of micro-fracture. This Smectite likely peels off from the pore surfaces, thus increasing the width of micro-fracture. This is largely due to the incompatible deformation between smectite and illite. When shale imbibes is largely due to the incompatible deformation between smectite and illite. When shale imbibes water water along the bedding planes, the fluids contact with the surface of existing micro-fractures, which along the bedding planes, the fluids contact with the surface of existing micro-fractures, which facilitates the expansion of smectite and illite [13,17,40]. Initially, the clay expansion may decrease facilitates the expansion of smectite and illite [13,17,40]. Initially, the clay expansion may decrease the the width of micro-fracture and gradually heal these cracks. However, further expansion of smectite width of micro-fracture and gradually heal these cracks. However, further expansion of smectite would trigger fracture surface collapse and generate new fractures as shown in Figure5. This process would trigger fracture surface collapse and generate new fractures as shown in Figure 5. This process depends considerably on the clay mineral compositions in the sublayers of laminations [41]. Previous depends considerably on the clay mineral compositions in the sublayers of laminations [41]. Previous studies point out that the expansion degree of smectite and illite would increase with increasing water studies point out that the expansion degree of smectite and illite would increase with increasing water content, but smectite has a higher swelling capacity than illite [42,43]. Therefore, the strong swelling of content, but smectite has a higher swelling capacity than illite [42,43]. Therefore, the strong swelling smectite may not only increase the width of micro-fracture due to the peeling-off process, but could of smectite may not only increase the width of micro-fracture due to the peeling-off process, but could also loosen the surrounding minerals attachment. As a result, it is possible that some grains are forced also loosen the surrounding minerals attachment. As a result, it is possible that some grains are forced out from the free micro-fracture surfaces because of the smectite swelling (see the top left corner of out from the free micro-fracture surfaces because of the smectite swelling (see the top left corner of Figure5c), which may also contribute to the water imbibition and shale gas production. Figure 5c), which may also contribute to the water imbibition and shale gas production. Perpendicular to bedding plane: compared to hydration along the direction of parallel to shale Perpendicular to bedding plane: compared to hydration along the direction of parallel to shale bedding planes, we did not observe induced micro-fracture on the sublayer surfaces when the bedding planes, we did not observe induced micro-fracture on the sublayer surfaces when the imbibition was perpendicular to the bedding planes (Figure6). However, the dissolved pores area imbibition was perpendicular to the bedding planes (Figure 6). However, the dissolved pores area on the sample surfaces increased with immersion time (Figure 7). It is worth noting that the image processing program ImageJ was used to analyze the variation of dissolved pores area on the shale
Energies 2019, 12, 4225 8 of 20
on theEnergies sample 2019, surfaces 12, x FOR PEER increased REVIEW with immersion time (Figure7). It is worth noting that the8 of image21 processing program ImageJ was used to analyze the variation of dissolved pores area on the shale surfacesurface before before and afterand immersion.after immersion. Figure Figure6 shows 6 shows that compared that compared to initial to initial condition, condition, area ofarea dissolved of poresdissolved increased pores significantly increased significantly with increasing with increasing immersion immersion time from time 1 tofrom 5 days. 1 to 5 Ourdays. resultsOur results indicate that waterindicate saturation that water likely saturation dissolves likely minerals dissolves on minerals shale surfaces, on shale surfaces, especially especially feldspar feldspar (Figure (Figure6a–c),thus generating6a–c), dissolvedthus generating pores, dissolved although pores, more although quantitative more work quantitative remains work to be remains made toto furtherbe made quantify to further quantify the dissolved minerals. the dissolved minerals.
(a) Shale sublayer surface before and after 1 day’s saturation.
(b) Shale sublayer surface before and after 3 days’ saturation.
(c) Shale sublayer surface before and after 5 days’ saturation.
FigureFigure 6. Shale 6. Shale sublayer sublayer surface surface variations variations beforebefore and and after after (a ()a 1) 1day’s, day’s, (b) (b3 )days’ 3 days’ and and(c) 5 (days’c) 5 days’ saturationsaturation for the for imbibitionthe imbibition perpendicular perpendicular to to bedding bedding planes at at pressure pressure of of3.5 3.5 MPa MPa and and temperature temperature of 80 ◦ofC. 80 °C. Energies 2019, 12, 4225 9 of 20 Energies 2019, 12, x FOR PEER REVIEW 9 of 21
FigureFigure 7. 7.The The percentage percentage of of dissolved dissolved pores pores areaarea onon samplesample surface varies with with time time at at pressure pressure of of 3.5 3.5 Mpa and temperature of 80 C. Mpa and temperature of 80 °C.◦ Feldspar dissolution likely yields additional pore spaces, which contributes to the low recovery Feldspar dissolution likely yields additional pore spaces, which contributes to the low recovery of flowback water. When water uptake is perpendicular to laminations, the hydrophobic kerogens of flowback water. When water uptake is perpendicular to laminations, the hydrophobic kerogens that lie along the sublayer surfaces act as a nano-filter to prevent water from flowing [44]. Therefore, that lie along the sublayer surfaces act as a nano-filter to prevent water from flowing [44]. Therefore, the interaction between water and minerals inside the porous rock would be minimized. Rather, the interaction between water and minerals inside the porous rock would be minimized. Rather, the the water would react with rock surface, especially feldspar, thus generating dissolved pores. water would react with rock surface, especially feldspar, thus generating dissolved pores. For For example, Heydari and Wade [45] point out that feldspar may react with water under temperatures example, Heydari and Wade [45] point out that feldspar may react with water under temperatures of 80 to 120 C and release ions and other minerals, which leads to the generation of dissolved pores. of 80 to 120◦ °C and release ions and other minerals, which leads to the generation of dissolved pores. Besides, it is also reported that the dissolution of feldspar can increase the formation porosity and Besides, it is also reported that the dissolution of feldspar can increase the formation porosity and permeability [46]. During the field shut-in period, a large amount of hydraulic fracturing fluid with permeability [46]. During the field shut-in period, a large amount of hydraulic fracturing fluid with additives is trapped in the shale fracture networks. These fluids can generate dissolved pores on the rock additives is trapped in the shale fracture networks. These fluids can generate dissolved pores on the surface, thus enhancing the flow conductivity of the shale formation and increasing communication rock surface, thus enhancing the flow conductivity of the shale formation and increasing among the flowing channels. Moreover, the dissolution of feldspar may also consume huge amounts communication among the flowing channels. Moreover,+ the dissolution of feldspar+ may also of water on the basis of the reaction. KAISiO8 + 6H2O + H AIO(OH) + 3H4SiO4 + K [47,48] consume huge amounts of water on the basis of the reaction⇔ 𝐾𝐴𝐼𝑆𝑖𝑂 6𝐻 𝑂 𝐻 ⇔𝐴𝐼𝑂 𝑂𝐻 although more quantitative work on this remains to be made. 3𝐻 𝑆𝑖𝑂 𝐾 [47,48] although more quantitative work on this remains to be made. 3.2. Effect of Temperature on Hydration 3.2. Effect of Temperature on Hydration Parallel to bedding plane: increasing temperature increased the rate and degree of shale hydration, Parallel to bedding plane: increasing temperature increased the rate and degree of shale implying that shale hydration likely plays an important role in deep shale reservoirs. Figure8 shows hydration, implying that shale hydration likely plays an important role in deep shale reservoirs. the effect of temperature on shale hydration with immersion time from 1 to 5 days under the pressure Figure 8 shows the effect of temperature on shale hydration with immersion time from 1 to 5 days of 3.5 MPa. Compared to the low temperature (80 ◦C), for a higher temperature (120 ◦C), the existing under the pressure of 3.5 MPa. Compared to the low temperature (80 °C), for a higher temperature micro-fracture appeared to close at the end of first day and completely heal at the end of three days. (120 °C), the existing micro-fracture appeared to close at the end of first day and completely heal at Although new fractures were generated after five days’ immersion for both temperature conditions, the end of three days. Although new fractures were generated after five days’ immersion for both the high temperature significantly enlarged the surface stretching degree as shown in Figure8. temperature conditions, the high temperature significantly enlarged the surface stretching degree as shown in Figure 8.
Energies 2019, 12, 4225 10 of 20 Energies 2019, 12, x FOR PEER REVIEW 10 of 21
(a) Micro-fracture before and after 1 day’s saturation at 80 °C (① and ②) and 120 °C (③ and ④).
Figure 8. Cont.
Energies 2019, 12, 4225 11 of 20 Energies 2019, 12, x FOR PEER REVIEW 11 of 21
(b) Micro-fracture before and after 3 days’ saturation at 80 °C (① and ②) and 120 °C (③ and ④).
Figure 8. Cont.
Energies 2019, 12, 4225 12 of 20 Energies 2019, 12, x FOR PEER REVIEW 12 of 21
(c) Micro-fracture before and after 5 days’ saturation at 80 °C (① and ②) and 120oC (③ and ④).
Figure 8. Micro-fracture variations before and after (a) 1 day’s, (b) 3 days’ and (c) 5 days’ saturation Figure 8. Micro-fracture variations before and after (a) 1 day’s, (b) 3 days’ and (c) 5 days’ saturation with the temperature of 80 and 120 C, respectively. with the temperature of 80 and 120 ◦°C, respectively. The high temperature accelerated shale hydration and the micro-fracture healing due to a greater The high temperature accelerated shale hydration and the micro-fracture healing due to a swelling rate of smectite and illite on rock surface. This process also promotes the fracture surface greater swelling rate of smectite and illite on rock surface. This process also promotes the fracture collapse and the creation of new fractures that are parallel to the bedding planes thus enhances surface collapse and the creation of new fractures that are parallel to the bedding planes thus formation conductivity. Besides, literature show that the interaction between hydraulic fracturing enhances formation conductivity. Besides, literature show that the interaction between hydraulic fluids and shale during well shut-in period may weaken the shale surface and trigger proppants fracturing fluids and shale during well shut-in period may weaken the shale surface and trigger embedment at in-situ temperature [49]. Therefore, we tentatively conclude that temperature would proppants embedment at in-situ temperature [49]. Therefore, we tentatively conclude that affect the formation conductivity variation through shale hydration as a complex result of micro-fracture temperature would affect the formation conductivity variation through shale hydration as a complex generation and mineral dissolution. result of micro-fracture generation and mineral dissolution. Perpendicular to bedding plane: increasing temperature increased the dissolved area on shale surfaces when the imbibition was perpendicular to bedding planes (Figure 9). Compared to 80 °C, immersing samples at 120 °C for 1 day and 5 days increased the percentage of dissolved pores area from 1.22% to 1.66% and 14.61% to 29.99%, respectively (Figure 10). Our results indicated that high temperature accelerated the rate and degree of shale-water interaction and thus prompted the K- feldspar and Na-feldspar dissolution. We did not observe new generated micro-fracture even at high
Energies 2019, 12, 4225 13 of 20
Perpendicular to bedding plane: increasing temperature increased the dissolved area on shale surfaces when the imbibition was perpendicular to bedding planes (Figure9). Compared to 80 ◦C, immersing samples at 120 ◦C for 1 day and 5 days increased the percentage of dissolved pores areaEnergies from 2019 1.22%, 12, x FOR to 1.66%PEER REVIEW and 14.61% to 29.99%, respectively (Figure 10). Our results indicated13 thatof 21 high temperature accelerated the rate and degree of shale-water interaction and thus prompted the temperature for imbibition perpendicular to bedding planes, which is in line with previous K-feldspar and Na-feldspar dissolution. We did not observe new generated micro-fracture even at high observations. temperature for imbibition perpendicular to bedding planes, which is in line with previous observations.
(a) Sublayer surface before and after 1 day’s saturation at 80 °C (① and ②) and 120oC (③ and ④)
Figure 9. Cont.
Energies 2019, 12, 4225 14 of 20 Energies 2019, 12, x FOR PEER REVIEW 14 of 21
(b) Sublayer surface before and after 3 days’ saturation at 80 °C (① and ②) and 120 °C (③ and ④)
Figure 9. Cont.
Energies 2019, 12, 4225 15 of 20 Energies 2019, 12, x FOR PEER REVIEW 15 of 21
(c) Sublayer surface before and after 5 days’ saturation at 80 °C (① and ②) and 120 °C (③ and ④)
FigureFigure 9.9. ShaleShale sublayersublayer surfacesurface variationsvariations before and after (a)) 11 day’s,day’s, ((b)) 33 days’days’ andand ((cc)) 55 days’days’ saturationsaturation for for the the imbibition imbibition perpendicular perpendicular to to bedding bedding planes. planes.
Energies 2019, 12, x FOR PEER REVIEW 16 of 21 Energies 2019, 12, 4225 16 of 20
Figure 10. The percentage of dissolved pores area on sample surface varies with time at pressure of
3.5Figure Mpa and 10. temperatureThe percentage of 80of anddissolved 120 ◦C. pores area on sample surface varies with time at pressure of 3.5 Mpa and temperature of 80 and 120 °C. K-feldspar and Na-feldspar are the main dissolved minerals which contributes to increase of the porosityK-feldspar at micro-fracture and Na-feldspar surfaces. are When the themain imbibition dissolved is minerals perpendicular which tocontributes the bedding to increase planes, high of the temperatureporosity at slightlymicro-fracture facilitates surfaces. the feldspar When dissolution. the imbibition This is is perpendicular because the Gibbs to the energy bedding of K-feldsparplanes, high andtemperature Na-feldspar slightly decreases facilitates with increasing the feldspar temperature dissolution. so thatThis the is dissolvingbecause the process Gibbs would energy occur of K- withfeldspar lower and energy Na-feldspar barrier [decreases50–52]. In with contrast, increasing the dissolution temperature of so Ca-feldspar that the dissolving is restricted process at highwould temperatureoccur with [52lower]. To energy summarize, barrier increasing [50–52]. In temperature contrast, the increases dissolution the percentage of Ca-feldspar of dissolved is restricted pores at areahigh on temperature shale sublayer [52]. surface, To summari whichze, significantly increasing enhances temperature the waterincreases uptake the inpercentage shale. of dissolved pores area on shale sublayer surface, which significantly enhances the water uptake in shale. 3.3. Proposed Mechanisms and Implications 3.3.In Proposed this work, Mechanisms our first and goal Implications was to acknowledge the significance of shale anisotropy on water uptake,In typically this work, under our in first situ goal reservoir was temperatureto acknowledge and anthe elevated significance pressure. of shale Our anisotropy second goal on was water to characterizeuptake, typically the micro-fracture under in situ initiation reservoir and temperat propagationure and with an respect elevated to shalepressure. anisotropy Our second during goal water was uptake.to characterize To understand the micro-fracture how the anisotropy initiation of shaleand pr affopagationects water with uptake respect during to hydraulicshale anisotropy fracturing during in shales,water thus uptake. building To understand an overall conceptual how the anisotropy framework of that shale supports affects the water optimization uptake during and prediction hydraulic offracturing flowback waterin shales, and shalethus building gas production, an overall we proposedconceptual ashale framework hydration that mechanism supports the that optimization drives the evolutionand prediction of micro-fracture of flowback initiation water and and propagation shale gas dueproduction, to the complex we proposed physiochemical a shale processes. hydration mechanism that drives the evolution of micro-fracture initiation and propagation due to the complex 1. Surfaces in parallel to bedding planes govern the micro-fracture initiation and propagation. Upon physiochemical processes. the contact of fluid and shale samples, clay minerals such as smectite and illite on the surface of 1 pre-existingSurfaces in micro-fracture parallel to bedding would planes swell initially, govern whichthe micro-fracture would lead micro-fracture initiation and topropagation. close and heal.Upon Finally, the contact smectite of wouldfluid and collapse, shale thussamples, generating clay minerals new micro-fracture such as smectite with aand greater illite width on the (Figuresurface 11 of). pre-existing micro-fracture would swell initially, which would lead micro-fracture to 2. Imbibitionclose and along heal. theFinally, direction smectite perpendicular would collapse to bedding, thus planes generating would new contribute micro-fracture the increase with of a porositygreater atwidth micro-fracture (Figure 11). due to feldspar dissolution (Figure 11). 3. 2 HydrationImbibition process along atthe both direction parallel perpendicular and perpendicular to bedding to the planes bedding would planes contribute would be the accelerated increase of withporosity increasing at micro-fracture reservoir temperature. due to feldspar dissolution (Figure 11). 3 Hydration process at both parallel and perpendicular to the bedding planes would be
Energies 2019, 12, x FOR PEER REVIEW 17 of 21
Energiesaccelerated2019, 12, 4225 with increasing reservoir temperature. 17 of 20
Figure 11. Schematic of the generation of hydrated fractures parallel to shale bedding planes.
Aforementioned shale hydration anisotropy not only explains the imbibition difference parallel Figure 11. Schematic of the generation of hydrated fractures parallel to shale bedding planes. and perpendicular to laminations, but also sheds light on how the fluid–rock interaction affects shale strength properties. When drilling fluids enter the shale matrix along the bedding planes or pre-existing Aforementioned shale hydration anisotropy not only explains the imbibition difference parallel micro-fracture, the induced hydrated fractures and dissolved pores likely weaken the rock strength and perpendicular to laminations, but also sheds light on how the fluid–rock interaction affects shale thus impairing the wellbore stability [53–55]. Therefore, to prevent the wellbore from collapsing, it is strength properties. When drilling fluids enter the shale matrix along the bedding planes or pre- important to enhance the plugging performance of drilling fluids so as to keep the fluids from imbibing existing micro-fracture, the induced hydrated fractures and dissolved pores likely weaken the rock into shale sublayers. Most current designs on drilling mud plugging only consider the prevention strength thus impairing the wellbore stability [53–55]. Therefore, to prevent the wellbore from of fluid flowing into fractures that are parallel to bedding planes [56,57]. Our study indicates that a collapsing, it is important to enhance the plugging performance of drilling fluids so as to keep the proper drilling mud should also be able to minimize the feldspar dissolution, which likely occurs at fluids from imbibing into shale sublayers. Most current designs on drilling mud plugging only the subsurface perpendicular to bedding planes, thus further weakening shale. Besides, the inhibitive consider the prevention of fluid flowing into fractures that are parallel to bedding planes [56,57]. Our ability of drilling mud should also be accounted for to keep clay minerals, especially the smectite, from study indicates that a proper drilling mud should also be able to minimize the feldspar dissolution, swelling [58]. which likely occurs at the subsurface perpendicular to bedding planes, thus further weakening shale. 4.Besides, Conclusions the inhibitive ability of drilling mud should also be accounted for to keep clay minerals, especially the smectite, from swelling [58]. A combination of horizontal drilling and multi-stage hydraulic fracturing is an important means for4. Conclusions shale gas production [9,16,59,60]. While published work shows that shale hydration would trigger water uptake and wellbore instability due to complex physicochemical processes [54,55], the existing A combination of horizontal drilling and multi-stage hydraulic fracturing is an important means accounts fail to fully acknowledge the significance of shale anisotropy on water uptake and wellbore for shale gas production [9,16,59,60]. While published work shows that shale hydration would trigger instability, typically under in situ reservoir temperature and an elevated pressure. Thus, we designed water uptake and wellbore instability due to complex physicochemical processes [54,55], the existing two sets of imbibition experiments using shale samples from Longmaxi Formation in Sichuan Basin, accounts fail to fully acknowledge the significance of shale anisotropy on water uptake and wellbore by designing shale substrates in parallel or perpendicular to the bedding planes. All the samples instability, typically under in situ reservoir temperature and an elevated pressure. Thus, we designed were immersed in distilled water for 1 to 5 days with pressure of 3.5 MPa at either 80 ◦C or 120 ◦C. two sets of imbibition experiments using shale samples from Longmaxi Formation in Sichuan Basin, Furthermore, EDS-FE-SEM was used to quantitatively characterize the samples’ topographical and by designing shale substrates in parallel or perpendicular to the bedding planes. All the samples were elemental variations before and after hydration. immersed in distilled water for 1 to 5 days with pressure of 3.5 MPa at either 80 °C or 120 °C. Results show that shale anisotropy plays a vital role in micro-fracture evolution, and thus water Furthermore, EDS-FE-SEM was used to quantitatively characterize the samples’ topographical and uptake and wellbore stability. In particular, for the shale surface in parallel to the bedding planes, shaleelemental hydration variations initially before leads and to after a close hydration. of pre-existing micro-fracture due to the smectite and illite Results show that shale anisotropy plays a vital role in micro-fracture evolution, and thus water swelling. However, micro-fracture then reopens with a wider fracture width due to the incompatible uptake and wellbore stability. In particular, for the shale surface in parallel to the bedding planes, deformation between smectite and illite. In contrast, for a shale surface perpendicular to the bedding shale hydration initially leads to a close of pre-existing micro-fracture due to the smectite and illite plane, micro-fracture widening was not observed. Rather, shale hydration results in a large amount swelling. However, micro-fracture then reopens with a wider fracture width due to the incompatible of dissolved pores on the sublayer surface as a result of feldspar dissolution. Moreover, increasing deformation between smectite and illite. In contrast, for a shale surface perpendicular to the bedding temperature accelerates the hydration rate and degree, implying that the impact of shale anisotropy plane, micro-fracture widening was not observed. Rather, shale hydration results in a large amount would play a greater role in water uptake and wellbore instability with increasing shale reservoir of dissolved pores on the sublayer surface as a result of feldspar dissolution. Moreover, increasing depth. Although a mathematical model relating the heat dissipation to fluid flow and imbibition of temperature accelerates the hydration rate and degree, implying that the impact of shale anisotropy water within the system will be investigated as part of future work, our results provide a first look would play a greater role in water uptake and wellbore instability with increasing shale reservoir at how shale anisotropy affects water uptake, and underscore the importance of hydration time and depth. Although a mathematical model relating the heat dissipation to fluid flow and imbibition of temperature on micro-fracture evolution.
Energies 2019, 12, 4225 18 of 20
Author Contributions: Conceptualization, Y.L., Y.J. and Q.X.; data curation, Y.L.; formal analysis, Y.L., L.Z., Y.J., G.C., J.R. and Q.X.; funding acquisition, Y.L. and Y.J.; investigation, G.C.; Methodology, Y.L., L.Z., H.L. and Q.X.; project administration, Y.L., Y.J. and Q.X.; resources, Y.L., Y.J. and Q.X.; software, Y.L.; Validation, Y.L., L.Z., G.C. and J.R.; writing—original draft, Y.L., L.Z., G.C. and Q.X.; writing—review & editing, Y.L., L.Z., Y.J., H.C.L. and Q.X. All authors revised and approved the publication of the paper. Funding: This research was funded by the National Natural Science Foundation of China, grant number 51774305, and the Major Projects of the National Natural Science Foundation, grant number 51490651. Acknowledgments: The authors gratefully acknowledge the constructive comments from John Hooker, three anonymous reviewers and Assistant Editor Allison Wang for the improvements in this work. Conflicts of Interest: The authors declare no conflict of interest.
References
1. Melikoglu, M. Shale Gas: Analysis of Its Role in the Global Energy Market. Renew. Sustain. Energy Rev. 2014, 37, 460–468. [CrossRef] 2. EIA, United States Energy Information Administration. Annual Energy Outlook: With Projections to 2040; EIA: Washington, DC, USA, 2013. 3. EIA, United States Energy Information Administration. Annual Energy Outlook 2011: With Projections to 2035; EIA: Washington, DC, USA, 2011. 4. Fisher, M.K.; Heinze, J.R.; Harris, C.D.; Davidson, B.M.; Wright, C.A.; Dunn, K.P. Optimizing horizontal completion techniques in the Barnett shale using microseismic fracture mapping. In SPE Annual Technical Conference and Exhibition; Society of Petroleum Engineers: Richardson, TX, USA, 2004. 5. Gale, J.F.; Reed, R.M.; Holder, J. Natural fractures in the Barnett Shale and their importance for hydraulic fracture treatments. AAPG Bull. 2007, 91, 603–622. [CrossRef] 6. Lu, Y.; Zeng, L.; Xie, Q.; Jin, Y.; Hossain, M.M.; Saeedi, A. Analytical modelling of wettability alteration-induced micro-fractures during hydraulic fracturing in tight oil reservoirs. Fuel 2019, 249, 434–440. [CrossRef] 7. Feng, R.; Zhang, Y.; Rezagholilou, A.; Roshan, H.; Sarmadivaleh, M. Brittleness Index: From Conventional to Hydraulic Fracturing Energy Model. Rock Mech. Rock Eng. 2019.[CrossRef] 8. Feng, R.; Chen, R.; Sarmadivaleh, M. A practical fracability evaluation for tight sandstone reservoir with natural interface. APPEA J. 2019, 59, 221–227. [CrossRef] 9. Cheng, Y. Impact of water dynamics in fractures on the performance of hydraulically fractured wells in gas shale reservoirs. In SPE International Symposium and Exhibition on Formation Damage Control; Society of Petroleum Engineers: Richardson, TX, USA, 2010. 10. King, G.E. Hydraulic fracturing 101: What every representative, environmentalist, regulator, reporter, investor, university researcher, neighbor and engineer should know about estimating frac risk and improving frac performance in unconventional gas and oil wells. In SPE Hydraulic Fracturing Technology Conference; Society of Petroleum Engineers: Richardson, TX, USA, 2012. 11. Nicot, J.P.; Scanlon, B.R.; Reedy, R.C.; Costley, R.A. Source and Fate of Hydraulic Fracturing Water in the Barnett Shale: A Historical Perspective. Environ. Sci. Technol. 2014, 48, 2464–2471. [CrossRef] 12. Scanlon, B.R.; Reedy, R.C.; Nicot, J.P. Will water scarcity in semiarid regions limit hydraulic fracturing of shale plays? Environ. Res. Lett. 2014, 9, 124011. [CrossRef] 13. Makhanov, K.; Habibi, A.; Dehghanpour, H.; Kuru, E. Liquid uptake of gas shales: A workflow to estimate water loss during shut-in periods after fracturing operations. J. Unconv. Oil Gas Resour. 2014, 7, 22–32. [CrossRef] 14. Binazadeh, M.; Xu, M.; Zolfaghari, A.; Dehghanpour, H. Effect of electrostatic interactions on water uptake of gas shales: the interplay of solution ionic strength and electrostatic double layer. Energy Fuels 2016, 30, 992–1001. [CrossRef] 15. Ghanbari, E.; Dehghanpour, H. Impact of rock fabric on water imbibition and salt diffusion in gas shales. Int. J. Coal Geol. 2015, 138, 55–67. [CrossRef] 16. Lu, G.; Gordeliy, E.; Prioul, R.; Aidagulov, G.; Bunger, A. Modeling simultaneous initiation and propagation of multiple hydraulic fractures under subcritical conditions. Comput. Geotech. 2018, 104, 196–206. [CrossRef] 17. Roshan, H.; Ehsani, S.; Marjo, C.E.; Andersen, M.S.; Acworth, R.I. Mechanisms of water adsorption into partially saturated fractured shales: An experimental study. Fuel 2015, 159, 628–637. [CrossRef] Energies 2019, 12, 4225 19 of 20
18. Fakcharoenphol, P.; Kurtoglu, B.; Kazemi, H.; Charoenwongsa, S.; Wu, Y.S. The effect of osmotic pressure on improve oil recovery from fractured shale formations. In Spe Unconventional Resources Conference; Society of Petroleum Engineers: Richardson, TX, USA, 2014. 19. Bennion, D.B.; Thomas, F.B. Formation damage issues impacting the productivity of low permeability, low initial water saturation gas producing formations. J. Energy Resour. Technol. 2005, 127, 240–247. [CrossRef] 20. Zeng, L.; Chen, Y.; Lu, Y.; Lau, H.C.; Hossain, M.M.; Saeedi, A.; Xie, Q. Interpreting Water Uptake by Shale with Ion Exchange, Surface Complexation, and Disjoining Pressure. Energy Fuels 2019, 33, 8250–8258. [CrossRef] 21. Zeng, L.; Chen, Y.; Hossain, M.M.; Saeedi, A.; Xie, Q. Wettability alteration induced water uptake in shale oil reservoirs: A geochemical interpretation for oil-brine-OM interaction during hydraulic fracturing. Int. J. Coal Geol. 2019, 213, 103277. [CrossRef] 22. Sone, H.; Zoback, M.D. Mechanical properties of shale-gas reservoir rocks—Part 1: Static and dynamic elastic properties and anisotropy. Geophysics 2013, 78, D381–D392. [CrossRef] 23. Zhang, S.; Sheng, J.J. Effect of water imbibition on fracture generation in Mancos shale under isotropic and anisotropic stress conditions. J. Geotech. Geoenviron. Eng. 2017, 144, 04017113. [CrossRef] 24. Makhanov, K.K. An Experimental Study of Spontaneous Imbibition in Horn River Shales. Master’s Thesis, University of Alberta, Edmonton, AB, Canada, 2013. 25. Makhanov, K.; Dehghanpour, H.; Kuru, E. An experimental study of spontaneous imbibition in Horn River shales. In SPE Canadian Unconventional Resources Conference; Society of Petroleum Engineers: Richardson, TX, USA, 2012. 26. Dehghanpour, H.; Lan, Q.; Saeed, Y.; Fei, H.; Qi, Z. Spontaneous imbibition of brine and oil in gas shales: Effect of water adsorption and resulting microfractures. Energy Fuels 2013, 27, 3039–3049. [CrossRef] 27. Roychaudhuri, B.; Tsotsis, T.; Jessen, K. An experimental and numerical investigation of spontaneous imbibition in gas shales. Paper SPE 147652. In Proceedings of the SPE Annual Technical Conference and Exhibition, Denver, CO, USA, 30 October–2 November 2011. 28. Guo, X.; Hu, D.; Li, Y.; Liu, R.; Wang, Q. Geological features and reservoiring mode of shale gas reservoirs in Longmaxi Formation of the Jiaoshiba Area. Acta Geol. Sin. 2014, 88, 1811–1821. [CrossRef] 29. Chen, L.; Lu, Y.; Jiang, S.; Li, J.; Guo, T.; Luo, C. Heterogeneity of the Lower Silurian Longmaxi marine shale in the southeast Sichuan Basin of China. Mar. Pet. Geol. 2015, 65, 232–246. [CrossRef] 30. Jiang, Y.; Chen, L.; Qi, L.; Luo, M.; Chen, X.; Tao, Y.; Wang, Z. Characterization of the Lower Silurian Longmaxi marine shale in Changning area in the south Sichuan Basin, China. Geol. J. 2018, 53, 1656–1664. [CrossRef] 31. Shen, Y.; Ge, H.; Meng, M.; Jiang, Z.; Yang, X. Effect of water imbibition on shale permeability and its influence on gas production. Energy Fuels 2017, 31, 4973–4980. [CrossRef] 32. Akrad, O.M.; Miskimins, J.L.; Prasad, M. The effects of fracturing fluids on shale rock mechanical properties and proppant embedment. In SPE Annual Technical Conference and Exhibition; Society of Petroleum Engineers: Richardson, TX, USA, 2011. 33. Xu, J.; Sonnenberg, S.A. An SEM Study of Porosity in the Organic-Rich Lower Bakken Member and Pronghorn Member, Bakken Formation, Williston Basin. In Proceedings of the Unconventional Resources Technology Conference, Austin, TX, USA, 24–26 July 2017; pp. 3213–3225. 34. Sondergeld, C.H.; Ambrose, R.J.; Rai, C.S.; Moncrieff, J. Micro-structural studies of gas shales. In SPE Unconventional Gas Conference; Society of Petroleum Engineers: Richardson, TX, USA, 2010. 35. Kwon, O.; Kronenberg, A.K.; Gangi, A.F.; Johnson, B.; Herbert, B.E. Permeability of illite-bearing shale: 1. Anisotropy and effects of clay content and loading. J. Geophys. Res. Solid Earth 2004, 109.[CrossRef] 36. Ma, Y.; Zhong, N.; Cheng, L.; Pan, Z.; Dai, N.; Zhang, Y.; Yang, L. Pore structure of the graptolite-derived OM in the Longmaxi Shale, southeastern Upper Yangtze Region, China. Mar. Pet. Geol. 2016, 72, 1–11. [CrossRef] 37. Zou, C.; Yang, Z.; Dai, J.; Dong, D.; Zhang, B.; Wang, Y.; Deng, S.; Huang, J.; Liu, K.; Yang, C.; et al. The characteristics and significance of conventional and unconventional Sinian–Silurian gas systems in the Sichuan Basin, central China. Mar. Pet. Geol. 2015, 64, 386–402. [CrossRef] 38. American Petroleum Institute. Recommended Practice for Field Testing of Water-Based Drilling Fluids, 4th ed.; API: Washington, DC, USA, 2009. 39. Chakraborty, N.; Karpyn, Z.T.; Liu, S.; Yoon, H. Permeability evolution of shale during spontaneous imbibition. J. Nat. Gas Sci. Eng. 2017, 38, 590–596. [CrossRef] Energies 2019, 12, 4225 20 of 20
40. Zhou, Z.; Abass, H.; Li, X.; Teklu, T. Experimental investigation of the effect of imbibition on shale permeability during hydraulic fracturing. J. Nat. Gas Sci. Eng. 2016, 29, 413–430. [CrossRef] 41. Paukert Vankeuren, A.N.; Hakala, J.A.; Jarvis, K.; Moore, J.E. Mineral reactions in shale gas reservoirs: Barite scale formation from reusing produced water as hydraulic fracturing fluid. Environ. Sci. Technol. 2017, 51, 9391–9402. [CrossRef] 42. Rahromostaqim, M.; Sahimi, M. Molecular Dynamics Simulation of Hydration and Swelling of Mixed-Layer Clays. J. Phys. Chem. C 2018, 122, 14631–14639. [CrossRef] 43. Chenevert, M.E. Shale alteration by water adsorption. J. Petroleum Technol. 1970, 22, 1–141. [CrossRef] 44. Wang, F.P.; Reed, R.M. Pore networks and fluid flow in gas shales. In SPE Annual Technical Conference and Exhibition; Society of Petroleum Engineers: Richardson, TX, USA, 2009. 45. Heydari, E.; Wade, W.J. Massive recrystallization of low-Mg calcite at high temperatures in hydrocarbon source rocks: Implications for organic acids as factors in diagenesis. AAPG Bull. 2002, 86, 1285–1303. 46. Baruch, E.T.; Kennedy, M.J.; Löhr, S.C.; Dewhurst, D.N. Feldspar dissolution-enhanced porosity in Paleoproterozoic shale reservoir facies from the Barney Creek Formation (McArthur Basin, Australia). AAPG Bull. 2015, 99, 1745–1770. [CrossRef] 47. Land, L.S.; Milliken, K.L. Feldspar diagenesis in the Frio Formation, Brazoria County, Texas Gulf Coast. Geology 1981, 9, 314–318. [CrossRef] 48. Dieterich, M.; Kutchko, B.; Goodman, A. Characterization of Marcellus Shale and Huntersville Chert before and after exposure to hydraulic fracturing fluid via feature relocation using field-emission scanning electron microscopy. Fuel 2016, 182, 227–235. [CrossRef] 49. Ghanizadeh, A.; Clarkson, C.R.; Deglint, H.; Vahedian, A.; Aquino, S.; Wood, J.M. Unpropped/propped fracture permeability and proppant embedment evaluation: A rigorous core-analysis/imaging methodology. In Unconventional Resources Technology Conference, San Antonio, TX, USA, 1–3 August 2016; Society of Exploration Geophysicists: Tulsa, OK, USA; American Association of Petroleum: Washington, DC, USA, 2016.
50. Knauss, K.G.; Wolery, T.J. Dependence of albite dissolution kinetics on pH and time at 25 ◦C and 70 ◦C. Geochim. Cosmochim. Acta 1986, 50, 2481–2497. [CrossRef] 51. Wild, B.; Daval, D.; Guyot, F.; Knauss, K.G.; Pollet-Villard, M.; Imfeld, G. pH-dependent control of feldspar dissolution rate by altered surface layers. Chem. Geol. 2016, 442, 148–159. [CrossRef] 52. Gruber, C.; Kutuzov, I.; Ganor, J. The combined effect of temperature and pH on albite dissolution rate under far-from-equilibrium conditions. Geochim. Cosmochim. Acta 2016, 186, 154–167. [CrossRef] 53. Liang, C.; Chen, M.; Jin, Y.; Lu, Y. Wellbore stability model for shale gas reservoir considering the coupling of multi-weakness planes and porous flow. J. Nat. Gas Sci. Eng. 2014, 21, 364–378. [CrossRef] 54. Lu, Y.H.; Chen, M.; Jin, Y.; Zhang, G.Q. A mechanical model of borehole stability for weak plane formation under porous flow. Pet. Sci. Technol. 2012, 30, 1629–1638. [CrossRef] 55. Lu, Y.H.; Chen, M.; Jin, Y.; Ge, W.F.; An, S.; Zhou, Z. Influence of porous flow on wellbore stability for an inclined well with weak plane formation. Pet. Sci. Technol. 2013, 31, 616–624. [CrossRef] 56. Cai, J.; Chenevert, M.E.; Sharma, M.M.; Friedheim, J.E. Decreasing water invasion into Atoka shale using nonmodified silica nanoparticles. SPE Drill. Complet. 2012, 27, 103–112. [CrossRef] 57. Sharma, M.M.; Zhang, R.; Chenevert, M.E.; Ji, L.; Guo, Q.; Friedheim, J. A new family of nanoparticle based drilling fluids. In SPE Annual Technical Conference and Exhibition; Society of Petroleum Engineers: Richardson, TX, USA, 2012. 58. O’Brien, D.E.; Chenevert, M.E. Stabilization of Sensitive Shales Using Inhibited, Potassium-Based Drilling Fluids; Dell Medical School: Austin, TX, USA, 2017. 59. Liu, S.; Wang, J.; He, H.; Wang, H. Mechanism on imbibition of fracturing fluid in nanopore. Nanosci. Nanotech. Lett. 2018, 10, 87–93. [CrossRef] 60. Bello, R.O.; Wattenbarger, R.A. Multi-stage hydraulically fractured horizontal shale gas well rate transient analysis. In North Africa Technical Conference and Exhibition; Society of Petroleum Engineers: Richardson, TX, USA, 2010.
© 2019 by the authors. Licensee MDPI, Basel, Switzerland. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (http://creativecommons.org/licenses/by/4.0/).