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How important is carbonate dissolution in buried sandstones: evidences from petrography, porosity, experiments, and geochemical calculations

How important is carbonate dissolution in buried sandstones: evidences from petrography,... Burial dissolution of feldspar and carbonate minerals has been proposed to generate large volumes of secondary pores in subsurface reservoirs. Secondary porosity due to feldspar dissolution is ubiquitous in buried sandstones; however, extensive burial dissolution of carbonate minerals in subsurface sandstones is still debatable. In this paper, we first present four types of typical selective dissolution assemblages of feldspars and carbonate minerals developed in different sandstones. Under the constraints of porosity data, water–rock experiments, geochemical calculations of aggressive fluids, diagenetic mass transfer, and a review of publications on mineral dissolution in sandstone reservoirs, we argue that the hypothesis for the creation of significant volumes of secondary porosity by mesodiagenetic carbonate dissolution in subsurface sandstones is in conflict with the limited volume of aggressive fluids in rocks. In addition, no transfer mechanism supports removal of the dissolution products due to the small water volume in the subsurface reservoirs and the low mass concentration gradients in the pore water. Convincing petrographic evidence supports the view that the extensive dissolution of carbonate cements in sandstone rocks is usually associated with a high flux of deep hot fluids provided via fault systems or with meteoric fresh- water during the eodiagenesis and telodiagenesis stages. The presumption of extensive mesogenetic dissolution of carbonate cements producing a significant net increase in secondary porosity should be used with careful consideration of the geological background in prediction of sandstone quality. Keywords Mesodiagenetic · Carbonate dissolution · Petrography · Geochemical · Buried sandstones 1 Introduction The term secondary porosity refers to pore space resulting from the post-depositional dissolution of detrital grains or cements (Taylor et al. 2010). Ten genetic mechanisms have Edited by Jie Hao been proposed for the generation of aggressive fluids capa- ble of dissolving minerals in sandstones, which are mete- * Guang-Hui Yuan oric water penetration (Emery et al. 1990), mixing corro- yuan.guanghui@upc.edu.cn sion (Edmunds et al. 1982; Plummer 1975), acidic fluids * Ying-Chang Cao generated from CO produced by the thermal maturation of caoych@upc.edu.cn organic matter (Schmidt and McDonald 1979a; Surdam et al. Key Laboratory of Deep Oil and Gas, School of Geoscience, 1989; Surdam and Boese 1984), carboxylic acids generated China University of Petroleum, Qingdao 266580, Shandong, during the thermal maturation of organic matter (Surdam China et al. 1989; Surdam and Boese 1984), acidic fluids gener - State Key Laboratory of Organic Geochemistry, Guangzhou ated by clay mineral reactions (Giles and Marshall 1986), Institute of Geochemistry, Chinese Academy of Sciences, acid fluids generated by thermogenic sulfate reduction Guangzhou 510640, Guangdong, China 3 (TSR) and bacterial sulfate reduction (BSR) (Machel 2001; Department of Earth Sciences, Durham University, Machel et al. 1995), deep hot fluids (Taylor 1996), acidic Durham DH1 3LE, UK Vol.:(0123456789) 1 3 730 Petroleum Science (2019) 16:729–751 fluids generated by silicate hydrolysis (Hutcheon and Aber - 2012; Giles 1987; Giles and Marshall 1986; Giles and De crombie 1990), acidic fluids generated by silicate–carbonate Boer 1990; Taylor et al. 2010). interactions (Smith and Ehrenberg 1989), aggressive fluids Secondary pores originating from the dissolution of due to cooling of formation fluids (Giles and De Boer 1989), feldspar grains in subsurface rocks are common and eas- and hot alkaline brines (Pye 1985). ily recognizable (Yuan et al. 2015a, b, c, 2019a, b; Dutton The idea that the sandstone porosity can be significantly and Loucks 2010; Giles 1987; Taylor et al. 2010). However, increased via burial dissolution of minerals (e.g., carbonate even until now, there is still much debate about the reality cements, feldspars) at depths of approximately 3 km by CO of the significant dissolution of carbonate cements in buried and organic acids originating from kerogen maturation in sandstones (Bjørlykke 2014; Bjørlykke and Jahren 2012; Li source rocks was proposed in 1970s to 1980s (Schmidt and et al. 2017; Taylor et al. 2010; Yuan et al. 2013a, b, 2015a, McDonald 1979a; Surdam et al. 1989; Surdam and Boese b, c). Recently, rock diagenesis and the significance of sec- 1984) (Fig. 1a). Based on petrographic identification and ondary pores generated by the burial dissolution of feld- interpretation, this idea has been prominent in the literature spars and carbonate minerals have been reviewed within the on sandstone diagenesis for about 40 years (Bjørlykke and constraints of petrography, porosity data, and the openness Jahren 2012; Boggs 2011; Burley 1986; Dutton and Wil- versus closeness of geochemical systems (Bjørlykke 2014; lis 1998; Higgs et al. 2010; Khidir and Catuneanu 2010; Bjørlykke and Jahren 2012; Ehrenberg et al. 2012; Taylor Kordi et al. 2011; Schmidt and McDonald 1979a; Shan- et al. 2010; Yuan et al. 2013a, b). These reappraisals showed mugam 1984; Xi et al. 2016; Wilkinson et al. 1997; Yuan that burial-induced carbonate dissolution in sandstones and et al. 2015a, b, c). At the same time, however, the advent carbonates is commonly insignificant. This conclusion is of the deep burial dissolution proposals has caused intense not new (Ehrenberg et al. 2012); however, the retrospective debates (Fig. 1b). The opposing views are centered on the nature of these new presentations is striking because the sub- apparent lack of viable geochemical mechanisms by which jective idea that up to 20% secondary porosity can be formed dissolution and mass transfer could occur in the subsurface by burial dissolution of minerals still persists in some very rocks (Bjørkum et al. 1998; Bjorlykke 1984; Bjørlykke and recent publications (Khidir and Catuneanu 2010; Kordi et al. Brendsal 1986; Bjørlykke and Jahren 2012; Ehrenberg et al. 2011) and textbooks (Boggs 2011). Particularly, this idea Primary Secondary Porosity Φ, % Φ, % Φ, % Kerogen evolution stage Reservoir spaces evolution 40 20 0 40 20 0 40 20 0 Immature stage: Mainly mechanical reduction of primary porosity Minor Extensive cementation? cementation? Semi-mature stage: Mainly chemical reduction of primary porosity Minor Extensive dissolution? dissolution? Mature stage: Primary porosity at irreducible levels, Secondary porosity may exist Super mature stage: Primary and secondary porosity at irreducible levels Primary pores Secondary pores Quartz grains Feldspar grains Detritus grains Carbonate cements a-Porosity evolution models proposed by Schmidt and McDonald (1979) b-Modified from Giles (1987) Fig. 1 Textural stages of mesodiagenesis of sandstone porosity and the petrographer’s dilemma of secondary porosity (after Schmidt and McDonald 1979a, b; Giles 1987) 1 3 Petroleum Science (2019) 16:729–751 731 is still prominent with regard to the origin of anomalously and carbonate mineral has been discussed a great deal. Pet- high porosity in the deeply buried sandstones in China (Bai rographic evidence has been used to demonstrate the pres- et  al. 2013; Si and Zhang 2008; Tang et al. 2013; Wang ence of secondary porosity in sandstones (Bjørlykke and et  al. 2013; Yuan et al. 2012; Zhu and Zhang 2009; Zhu Jahren 2012; Giles and Marshall 1986). The porosity related et al. 2007). to framework grain dissolution (e.g., feldspars) can be rec- According to laboratory water–rock interaction experi- ognized and statistically quantified (Taylor et  al. 2010). ments, carbonate minerals can be dissolved more easily and Though extensive burial dissolution of carbonate cements to be dissolved much faster than feldspar minerals in open has been suggested by many researchers (Schmidt and geochemical systems under steady-state conditions far from McDonald 1979a; Surdam et al. 1989; Surdam and Boese equilibrium (Bertier et al. 2006; Chen et al. 2008; Liu et al. 1984), intergranular pores without carbonate cements should 2012; Weibel et al. 2011; Yang et al. 1995), and the carbon- not be interpreted as secondary porosity unless considerable ate minerals seem likely to be the most important minerals petrographic evidences of its former presence can be estab- for the development of secondary pores in buried sandstones lished (Taylor et al. 2010). Experiments under steady-state (Giles and Marshall 1986; Schmidt and McDonald 1979a). conditions far from equilibrium illustrate that the dissolution However, things may be different in closed subsurface rates of carbonate minerals are much faster than the rate of sandstone geochemical systems. Based on our studies, we feldspars. In the natural sandstone rocks, however, things are identified four types of selective dissolution assemblages of likely to be more complex. Based on our studies, we identi- feldspar and carbonate minerals in different sandstone rocks fied four types of typical selective dissolution assemblages (Fig. 2), which may have some significant implications for of feldspar and carbonate minerals in sandstone rocks. this debate (Fig. 1) (Yuan et al. 2015a, b, c). At the same time, some recent papers presented the dissolution of silicate (1) Type I: Little feldspar dissolution vs. extensive carbon- minerals with no dissolution of carbonate minerals in the ate precipitation Kimmeridge Clay mudstones (Macquaker et al. 2014) and in the Eocene sandstones in the Bohai Bay Basin (Yuan et al. In buried sandstones and sandstone outcrops, carbonate- 2015a, b, c). Also, Turchyn and DePaolo (2011) suggested cemented concretions are very common (Dos Anjos et al. that the dissolution of carbonate minerals in mudstones can 2000; Dutton 2008; Gluyas and Coleman 1992; Saigal and be significantly suppressed by the presence of silicate min- Bjørlykke 1987; Wang et al. 2016; Yuan et al. 2015a, b, c). erals, and the dissolution rate is much smaller even when Petrography and relevant stable isotope data usually suggest compared with the already-slow rates typical of carbonate- that the carbonate cements in such concretions formed soon rich sediments (Turchyn and DePaolo 2011). after sediment deposition and prior to the occurrence of the Stimulated by these recent reviews and the selective dis- key dissolution period in the rocks (Dutton 2008; Gluyas solution phenomena of feldspars and carbonate minerals in and Coleman 1992). In such concretions, large amounts of buried subsurface sandstones, the objectives of this article carbonate cements precipitated and preserved both the depo- are to: (1) provide detailed petrographic evidence of selec- sitional fabric and the composition of the sand grains with tive dissolution assemblages of feldspars and carbonate little if any grain replacement. The early carbonate cements minerals in buried sandstones; (2) discuss the significance occupied almost all primary intergranular pores (Fig. 2a, of burial carbonate dissolution in buried sandstones with b) and formed flow barriers (Saigal and Bjørlykke 1987), the constraints of porosity-depth data, water–rock experi- which led to little dissolution of both the feldspars and the ments, and geochemical calculations; and (3) review the carbonate cements in such concretions during the later burial literature on the dissolution of carbonate minerals in buried (Fig. 2a, b). In buried sandstones, the development of such sandstones with petrographic and geochemical constraints. concretions usually occurs near the sandstone–mudstone interface and the thickness of these concretions ranges from centimeters to several meters (Dutton 2008; Gluyas and 2 Evidence from the reservoirs Coleman 1992; Mcbride and Milliken 2006). 2.1 Petrography (2) Type II: Little feldspar dissolution vs. extensive car- bonate dissolution Feldspar grains and carbonate cements are common miner- als in subsurface sandstones. As both the feldspar and car- In buried sandstones, the phenomenon of little feldspar bonate minerals can be dissolved by the acids (e.g., C O dissolution versus extensive carbonate dissolution is rare and organic acids) originating from thermal maturation of and few publications have ever reported on it. However, organic matter, the potential to generate secondary pores in one paper reported on the extensive dissolution of early sandstone reservoirs through the dissolution of the feldspar calcite cements (Fig. 2c, cʹ) in Quaternary beach deposits 1 3 732 Petroleum Science (2019) 16:729–751 (a) F (b) F (c) Cd cc Cd cc Q Cc (c′) SC CA Cc cc Q Cc PF SC Q 25 μm Cc cc BC SC CV cc Cd Q PL cd Cc cc Cd F PF SC CV PL CV Cc F Cc Cd 200 μm PF 200 μm 200 μm (d) (e) (f) Fd Fd Fd F Fd Cd Cd Cd Cc Cd Cc Cc Cc Cc Cd Ca Cd Cd Cd Cd Fd F F Fd Cc 200 μm 200 μm 200 μm (g) (h) (i) FD Cc Cc FD Ca Ca Ca FD FD FD FD FD FD FD 200 μm 200 μm 200 μm (j) (k) (l) An Calcisphere test Coccolith Qa-II Kaolinite An Organic carbon Qa-I Quartz Pyrite Coccolith 10 μm 20 μm 25 μm Fig. 2 Micropetrographic evidence of the dissolution of feldspar and carbonate minerals in sandstone or mudstone rocks. a, b Extensive car- bonate cementation and weak feldspar dissolution in buried sandstones in the Dongying Sag, East China (Yuan et  al. 2015a, b, c), and in the Potiguar Basin, Brazil (Dos Anjos et al. 2000); c extensive dissolution of calcite with little dissolution of silicate grains in Quaternary marine terrace rocks (after Cavazza et al. 2009); cʹ dissolution of calcite cements, SEM image; d, e extensive dissolution of carbonate cements and feld- spar grains, Well Yan16, 1929.4 m, Dongying Sag; f extensive dissolution of carbonates and feldspar grains in buried Miocene sandstones from the Picaroon field, offshore Texas (after Taylor 1990); g, h extensive feldspar dissolution with little dissolution of carbonate cement and detrital carbonate grains, in Well T720, 3535.0 m, Dongying Sag; i extensive feldspar dissolution with little dissolution of detrital carbonate grains, Well T720, 2843.56 m, Dongying Sag; j euhedral ankerite wrapped in Qa-II quartz cements T720, 3535.0 m, Dongying Sag; k Intact ankerite, well Tuo764, 4169.8 m, Dongying Sag; l well-preserved calcisphere and precipitated kaolinite in mudstones of Kimmeridge Clay Formation (Mac- quaker et al. 2014). F feldspar grains, Q quartz grains, R rock fragment grains, FD feldspar dissolution pores, An ankerite, Cc carbonate cements, Ca carbonate detrital grain, Cd carbonate dissolution pores, Qa quartz overgrowths, sc silicate grains, cv smectitic cement, PF pore-filling cal- cite by meteoric water during periods of falling of sea levels the meteoric diagenetic environment (Cavazza et al. 2009). (Cavazza et al. 2009). The microphotograph suggests lit- These observations are consistent with the laboratory experi- tle dissolution of the associated silicate minerals (Fig. 2c). ments under steady-state conditions far from equilibrium in The associated silicate minerals were dissolved much less which calcite can be dissolved more easily than silicate min- extensively than the calcite cements, probably due to the erals (Chen et al. 2008; Liu et al. 2012; Weibel et al. 2011). short geological time period and the low temperature in 1 3 Petroleum Science (2019) 16:729–751 733 (3) Type III: Extensive feldspar dissolution and extensive carbonate cements and detrital carbonate grains in the lower carbonate dissolution Es Formation and the Es Formation (Fig. 2g–k). The car- 3 4 bonate cements occurred as connected patches (Fig. 2a), sin- In buried sandstones, the dissolution of feldspar and car- gle crystals (Fig. 2j, k) or grain-coating carbonate (Fig. 2g, bonate minerals has been suggested as common occurrence h), and individual crystals commonly exhibited euhedral by many authors (Schmidt and McDonald 1979a, 1979b; crystals faces abutting open pore space (Fig. 2k). The euhe- Surdam et al. 1989; Surdam and Boese 1984). Little con- dral ankerite engulfed by the stage-II quartz overgrowths vincing petrographic evidence, however, has been reported (Fig.  2j) suggests that the carbonate minerals were not to support the coexistence of extensive feldspar dissolution leached when the stage-II feldspar dissolution and quartz and extensive carbonate dissolution in buried sandstones. cementation occurred in the acidic geochemical system. In One typical example was provided by Taylor (1990, 1996), addition, the detrital carbonate grains and grain-coating car- who presented a striking and convincing microphotograph bonate cements show no evidence of dissolution (Fig. 2g–i); to show the dissolution of carbonate cements and detrital moreover, carbonate overgrowths are often found accompa- carbonate grains at Picaroon field (Fig.  2f) (Taylor 1990, nying the detrital carbonate grains. However, the feldspar 1996; Taylor et al. 2010). In the microphotographs, we can grains engulfed by early grain-coating carbonate cements or also identify the dissolution of feldspar grains (Fig.  2f). close to detrital carbonate grains are dissolved extensively Another example we have identified is the Es sandstones (Fig. 2g–i). from well Yan 16 in the Mingfeng area, Dongying Sag. In Overall, petrography textures suggest that carbonate min- the thin sections from Well Yan16, we observed the typical eral dissolution is not likely to occur all the time. Only in dissolution of feldspar grains and ferroan calcite cements two cases, extensive carbonate dissolution in the sandstone in the sandstones of the middle Es Formation (Fig. 2d, e). reservoirs is likely to occur. These sandstones are located close to some faults, which connect to the unconformity that developed at the end of the Eocene period. In these thin sections, the remnants of 2.2 Porosity‑depth data ferroan calcite cements were irregular and developed dis- solved pores (Fig.  2d, e). The low-oxygen isotope data The porosity evolution model proposed by Schmidt and (− 15.02‰ ~ − 17.20‰ ) of the ferroan calcite cements McDonald (Fig. 1a) was initially accepted and embraced by pdb pdb and the maximum depth (1920 m–1960 m with temperatures many geologists (Bjørlykke and Jahren 2012; Boggs 2011; of 75–80 °C) suggest that the fluid that formed these carbon- Burley 1986; Dutton and Willis 1998; Higgs et al. 2010; ate cements had negative δ O data (lower than − 8‰ ) Khidir and Catuneanu 2010; Schmidt and McDonald 1979a; SMOW (Matthews and Katz 1977), which support massive meteoric Shanmugam 1984; Wilkinson et al. 1997) to explain the water flux in these sandstones (Fayek et al. 2001; Harwood fairly common occurrence of intergranular porosity in sand- et al. 2013). stone buried to signic fi ant depth. However, as a general rule, global porosity-depth data show a steady decrease in the (4) Type IV: Extensive feldspar dissolution vs. little car- sandstone P50, P10, and the maximum porosity trends as the bonate dissolution depth increases (Fig. 3) (Ehrenberg et al. 2009; Ehrenberg and Nadeau 2005), which is inconsistent with the poros- Macquaker et al. (2014) reported the fabric observation of ity evolution model proposed by Schmidt and McDonald in kaolinite precipitation (byproduct of the dissolution of alu- 1979 (Fig. 1a). minosilicate minerals) and no dissolution of the associated Although anomalously high porosities do exist in some calcareous textures (Fig. 2l) in the Kimmeridge Clay Forma- deeply buried sandstones (Bloch et al. 2002; Warren and tion mudstones and regarded the phenomenon as surprising Pulham 2001), studies on the origin of the anomalously high and significant (Macquaker et al. 2014). In both mudstones porosities suggest that the dissolution of grains or preexist- and sandstones, such phenomena have not yet received much ing cements are just one subordinate aspect of this porosity. attention, although they were mentioned in some publica- These anomalously high porosities can be attributed to early tions (Armitage et al. 2010; Baker et al. 2000; Ceriani et al. emplacement of hydrocarbons (Bloch et al. 2002; Gluyas 2002; Dos Anjos et al. 2000; Dutton and Land 1988; Fisher et al. 1993; Wilkinson and Haszeldine 2011), fluid overpres- and Land 1987; Girard et al. 2002; Hendry et al. 1996; Mil- sure, or grain coats and grain rims (Bahlis and De Ros 2013; liken et al. 1994; Salem et al. 2000; Tobin et al. 2010). Using Bloch et al. 2002; Ehrenberg 1993); the mixture of porosity thin sections and scanning electron microscopy (SEM) from of rocks with different lithology from shallow to deep depths samples from the northern steep slope zone of the Dongy- may also lead to the occurrence of anomalously high porosi- ing Sag, we identified the phenomena of typical extensive ties in a porosity-depth profile (Bjørlykke 2014; Bjørlykke dissolution of feldspar grains with no/little dissolution of and Jahren 2012). 1 3 734 Petroleum Science (2019) 16:729–751 P90 P50 P10 Max. data of the samples with overpressure and (or) with high oil-bearing saturation were not employed in the Type-B pro- files. The Type-A porosity-depth profiles of the combined lithology (Fig. 4a1) show that anomalously high porosities do exist at the depth intervals of 2.8–3.7 km and 3.9–4.4 km, and the porosity-depth profiles of each individual lithology also show the existence of anomalously high porosities in some specific depth intervals (Fig.  4a2–a7). However, the Type-B porosity-depth profiles (Fig.  4b1–b7) show no exist- ence of the anomalously high porosities when the impact of the fluid overpressure and hydrocarbon emplacement on the reservoir porosity was removed. This analysis sug- gests that even where anomalously high porosities exist in deeply buried reservoirs, significant dissolution of carbonate cements may not be the cause. This is consistent with the petrographic evidence of selective dissolution of feldspar in the presence of carbonate minerals and the precipitation of authigenic clays and quartz cements following the feldspar 0 10 20 30 40 dissolution in these rocks (Yuan et al. 2013a, b). Porosity, % Fig. 3 Porosity versus depth profile for global petroleum sandstone 3 Water–rock experiments reservoirs. Statistical trends consist of P90 (90% of reservoirs have a porosity greater than this value), P50 (median), and P10. (after 3.1 Samples and methods Ehrenberg and Nadeau 2005) Pure calcite crystals were crushed, and the calcite grains The Eocene sandstones in the northern steep slope zone with a size of 2–4 mm were selected. In each experiment, in the Dongying Sag are an example exhibiting the impact one grain with a polished surface was employed to inves- of fluid overpressure, hydrocarbon emplacement, and min- tigate the dissolution features after the experiments. The eral dissolution. Detailed geological settings are available in grains were ultrasonically cleaned with analytical-grade some papers (Cao et al. 2013; Guo et al. 2010, 2012; Yuan distilled water three times to remove submicron-to-micron- et al. 2013a, b). Subaqueous fans and lacustrine fans were sized particles adhering to the grains. The calcite grains were x z deposited in the Eocene Es –Es Formations in the northern dried at 60 °C for 12 h and examined with a Coxem-EM-30 4 3 steep slope zone together with contemporary organic-rich plus scanning electron microscope (SEM) to check the total mudstones and shales. The development of anomalously removal of the small particles. Calcite grain samples were high porosities in the reservoirs has been reported (Cao prepared using a high-precision electronic balance (error < et al. 2014). In this paper, two types of porosity-depth pro- 0.005 g). High salinity waters with different salinity were files were plotted and presented, using the 7936 core poros- prepared with 99.99% NaCl, 99.99% CaCl , and deionized ity data collected from the Shengli Oilfield Company. The water (DW). Glacial acetic acid with a purity of more than lithology and oil-bearing properties of these samples were 99.5% was used to prepare acidic water with different pH. analyzed with core-logging materials. The fluid pressure The detailed experiment conditions are listed in Table 1. relevant to these samples was analyzed using the equivalent The calcite dissolution experiments at different tempera- depth method (Gao et al. 2008) using acoustic logging data tures (20 °C, 90 °C) were conducted in Hastelloy Reactors. with the constraint of the measured formation fluid pressure. For experiments with participation of C O, CO gas with a 2 2 And a database of the reservoir properties was established purity of more than 99.995% was injected into the reactor by using the information of the porosity, depth, lithology, oil- pumping to reach the designed p of 50 bar. The experi- CO bearing properties, and fluid pressure data. Type-A porosity- ments were conducted for 3, 8, and 15 days, respectively. depth profiles were plotted using the porosity data of all After the experiments at 20 °C, the calcite grains were sepa- reservoir samples (Fig. 4a1), and the porosity data of each rated from the water quickly, while for the experiments at individual lithology (Fig. 4a2–a7). Type-B porosity-depth 90 °C, the reactor was firstly cooled to approximately 20 °C profiles were plotted using the porosity data of the samples using cold water in less than 1 h, and then, the calcite grains with normal pressure and low oil-bearing saturation (oil- were separated from the water. The water pH was tested free, oil trace, fluorescence, and oil patch), and the porosity after the separation of the water from minerals. The reacted 1 3 Depth, km Petroleum Science (2019) 16:729–751 735 Combined Argillaceous Siltstones- Medium sandstones- Pebbly sandstones- Fine Medium-coarse lithology sandstones Fine sandstones Coarse sandstones Sandy conglomerate conglomerate conglomerate 1 1 1 1 1 1 1 (a1) (a2) (a3) (a4) (a5) (a6) (a7) 2 2 2 2 2 2 2 3 3 3 3 3 3 3 4 4 4 4 4 4 4 N=924 N=583 N=7936 N=676 N=1533 N=469 N=3742 5 5 5 5 5 5 5 010203040 010203040 010203040 010203040 010203040 010203040 010203040 Combined Argillaceous Siltsones- Medium sandstones- Pebbly sandstones- Fine Medium-coarse lithology sandstones Fine sandstones Coarse sandstones Sandy conglomerate conglomerate conglomerate 1 1 1 1 1 1 1 (b1) (b2) (b3) (b4) (b5) (b6) (b7) 2 2 2 2 2 2 2 3 3 3 3 3 3 3 4 4 4 4 4 4 4 N=544 N=363 N=3367 N=316 N=511 N=166 N=1461 5 5 5 5 5 5 5 0102030400 10 20 30 40 0102030400 10 20 30 40 0102030400 10 20 30 40 010203040 Porosity, % Porosity, % Porosity, % Porosity, % Porosity, % Porosity, % Porosity, % Fig. 4 Porosity-depth profiles of the sandstone reservoirs in the northern steep slope in the Dongying Sag. a1 Porosity versus depth profiles for the combined lithology; a2–a7 porosity versus depth profiles for a single lithology; b1 porosity versus depth profiles for combined lithology with normal pressure and low hydrocarbon saturation; b2–b7 porosity versus depth profiles for single lithology with normal pressure and low hydro- carbon saturation. The dashed blue lines in a1–a7 are the same as the solid blue lines in b1–b7 calcite minerals were cleaned in DW three times to remove suggests that only a small amount of calcite was dissolved, possible salt precipitated on the mineral surfaces. And the and this can only have resulted in a few secondary pores in reacted calcite minerals were weighed after being dried at the calcite grains (less than 1%); even the dissolved calcite 60 °C for 12 h. was not re-precipitated (Fig. 5). The results of the experi- ments D1–D7 at 90 °C show a similar trend. 3.2 Experimental results and geological implication The results of the experiments B1–B3 show that deion- ized water and saline water with a partial pressure of CO The weight loss and relevant volume changes of the cal- ( p ) at 50 bar can dissolve calcite at 20 °C. A compari- CO cite minerals are presented in Table  1. The experiments son of the results of the experiments B2 and B3 shows a A1–A3 demonstrate that low pH water with acetic acid (pH decrease in the corrosion ability of the acidic water as the = 3.93–3.98) can dissolve calcite at 20 °C. As the water salinity increases. A comparison between the results of the 2+ salinity and the Ca concentration in water increase, the experiments B1 and B3 shows that the calcite–CO interac- dissolution capacity of the acidic water decreases dramati- tions reached dynamic equilibrium in 8 days (maybe in an cally. Even with a high water/rock volume ratio (45:1), the even shorter time) after the dissolution of 0.212 g calcite and ratio between the mass loss after dissolution and the pri- a longer (15 days) exposure of calcite to the CO -charged mary weight of the calcite mineral prior to the experiments water did not result in more dissolution. This result indicates 1 3 Depth, km Depth, km 736 Petroleum Science (2019) 16:729–751 1 3 Table 1 Data of calcite-dissolving experiments at low and high temperatures Expt No. Before interaction p , bar After interaction Weight loss Volume Water/rock T, °C Time, day CO of calcite, g change of volume 2+ Composition of Water pH Water Ca con- Calcite weight, g pH Calcite calcite, % ratio solution volume, salinity, centration, weight, g mL g/L g/L A1 DW + HAC 500 3.97 0 0 30.060 N/A 6.29 29.718 0.283 0.943 45 20 8 A2 DW+HAC + 500 3.93 20 2 30.012 N/A 7.11 29.856 0.156 0.520 45 20 8 NaCl+CaCl A3 DW+HAC + 500 3.98 80 5 30.006 N/A 6.82 29.952 0.054 0.180 45 20 8 NaCl+CaCl B1 DW + NaCl + CaCl 500 8.51 80 5 30.003 50 6.05 29.791 0.212 0.700 45 20 8 B2 DW 500 7.16 0 0 15.007 50 6.92 14.698 0.309 2.059 90 20 15 B3 DW + NaCl + CaCl 500 8.72 80 5 15.000 50 6.33 14.785 0.215 1.433 90 20 15 C1 DW + HAC + NaCl 500 3.97 80 5 29.955 50 6.41 29.259 0.696 2.323 45 20 8 + CaCl D1 DW + HAC 350 3.43 0 0 14.897 N/A 6.66 14.568 0.329 2.208 63 90 3 D2 DW + HAC + NaCl 350 3.44 20 2 14.512 N/A 6.56 14.317 0.141 0.972 65 90 3 + CaCl D3 DW + HAC + NaCl 350 3.46 40 4 14.844 N/A 6.5 14.630 0.214 1.442 63 90 3 + CaCl D7 DW + HAC + NaCl 350 3.46 80 5 15.065 N/A 7.02 15.009 0.056 0.372 63 90 3 + CaCl D5 DW + HAC + NaCl 350 3.46 150 7.5 15.190 N/A 6.13 15.074 0.116 0.764 63 90 3 + CaCl D6 DW + HAC + NaCl 350 3.47 200 10 15.129 N/A 6.4 15.090 0.039 0.258 63 90 3 + CaCl D7 DW + HAC + NaCl 350 3.47 300 15 14.948 N/A 5.28 14.905 0.043 0.288 63 90 3 + CaCl DW distilled water, HAC acetic acid, N/A not applicable Petroleum Science (2019) 16:729–751 737 (a) (b) 10 μm 20 μm (c) (d) 10 μm 20 μm Fig. 5 SEM microphotographs of the calcite grain surfaces prior to and after the experiments. a, b Smooth surface of the polished calcite grain, some intercrystal pores can be identified occasionally (b); c, d dissolution of the polished calcite surface after dissolution experiments that in a relative closed geochemical system with a fixed experiments (Bertier et al. 2006; Liu et al. 2012). As the p , the available water volume dominates the dissolution initial pH values (< 4) of the waters used in the experiments CO volume of the calcite, even if CO is available in sufficient were much lower than those of most formation waters and quantities. Also, with a high water/rock volume ratio (45:1 the water/rock ratios were much higher than those in sub- or 90:1), only a small amount of calcite (less than 2%) was surface rocks (Birkle et al. 2009; Birkle et al. 2002; Egeberg dissolved by the CO -rich water. and Aagaard 1989; Frape et al. 1984; Surdam et al. 1985), A comparison of the results of the experiments C1, A3, we conclude that the calcite dissolution in deeply buried and B1 shows that the coexistence of acetic acid and CO sandstones without a favored pathway (e.g., faults) is likely in saline water promotes more calcite dissolution than with to be weaker than in the experiments. only acetic acid or C O in the saline water. However, no more than 2.5% of the calcite was dissolved in the C1 experi- ments. Overall, the experiments with a high water/rock vol- 4 Aggressive fluids and mass transfer ume ratio, low pH, and sufficient CO resulted in the dissolu- in sediments tion of only a small amount of calcite. As low temperature, low pH, high p , and high water/ 4.1 Pyrolysis experiments of kerogen CO rock ratio cannot generate a large volume of secondary pores by the dissolution of carbonate minerals, it is not likely that Hydrous and anhydrous pyrolysis experiments with pure extensive carbonate dissolution will occur in buried sand- kerogen or source rocks have been used to investigate the stone geochemical systems with high temperature and low maturation of organic matter in source rocks with respect water/rock ratio. Many studies on water–rock interaction to the generation of organic acids and C O (Barth et  al. experiments also support this idea when the data were ana- 1988; Barth et al. 1996; Barth and Bjørlykke 1993). Using lyzed quantitatively, although dissolution does take place worldwide source rocks and different types of kerogens with at low/high temperatures (Weibel et al. 2014). In addition, various total organic carbon (TOC) contents and different the dissolved carbonate minerals were commonly reported maturities, more than 110 pyrolysis experiments have been to be re-precipitated in long-term numerical simulation conducted in the last 40 years to analyze the yield of organic 1 3 738 Petroleum Science (2019) 16:729–751 acids and CO during kerogen maturation (Table 2) (Barth The concentrations of organic acids are lower when et al. 1988; Barth et al. 1996; Barth and Bjørlykke 1993; the temperatures are below 80 °C or above 120 °C due Chen et al. 1994; Kawamura et al. 1986; Kawamura and to the bacterial destruction and thermal destruction of Kaplan 1987; Meng et al. 2008; Zeng et al. 2007; Zhang the short-chained organic acids, respectively (Surdam et al. 2009). The results of the experiments demonstrate that et al. 1989; Surdam and Crossey 1987). The concentra- the maximum yield of acetic acids and total organic acids tion data of the organic acids in the formation waters −3 −3 (TOA) is 0.685 × 10 mol/g TOC and 1.34 × 1 0 mol/g from global petroleum sandstone reservoirs show that TOC, respectively. The experiments with the acetic acids more than 90% of the pore waters contain organic acids −3 yield more than 0.5 × 10 mol/g TOC account for only at concentrations less than 3000 mg/L (Fig. 6a) (Cai approximately 5% of the total experiments, and the experi- et al. 1997; Fisher 1987; Kharaka 1986; MacGowan −3 ments with the TOA yield more than 0.6 × 10 mol/g TOC and Surdam 1988; Meng et al. 2006; Meng et al. 2011; account for 10% of the total experiments. In the pyrolysis Surdam et al. 1989; Surdam and Crossey 1987; Wang experiments, CO has a yield equivalent to (0.30–10.9) × et al. 1995, 2007; Xiao et al. 2005). In the petroliferous −3 10 mol/g TOC, which is higher than that of the organic basins in China, the concentrations of organic acids in acids. Commonly, high TOC and high maturation result in the formation waters are usually less than 2500 mg/L low yields of organic acids and CO of one unit kerogen. (Fig. 6b). With high geothermal gradients (around 35 °C/1 km), the highest concentrations of organic acids 4.2 Acids in pore water developed at the depth of 1500–3500 m in the basins in East China; in contrast, the highest concentrations The dissolution of feldspar grains is a natural consequence developed at the depth of 4500–6000 m in the basins of water–rock interactions under conditions of increasing in West China with low geothermal gradients (approxi- burial depth and temperatures (Giles and De Boer 1990; mately 20 °C/1 km) (Fig. 6b) (Cai et al. 1997; Fisher Taylor et al. 2010). Although organic acids and CO were 1987; Kharaka 1986; MacGowan and Surdam 1988; commonly suggested as the cause of feldspar dissolution Meng et al. 2006; Meng et al. 2011; Surdam et al. 1989; (Giles and De Boer 1989; Schmidt and McDonald 1979a; Surdam and Crossey 1987; Wang et al. 1995, 2007; Surdam et al. 1989; Surdam and Boese 1984), Giles and Xiao et al. 2005). De Boer (1990) suggested that no unusual or special source of acidic pore fluids is required for this dissolution process In rocks with a high mudstone/sandstone ratio (e.g., (Giles and De Boer 1990). To dissolve carbonate minerals 10:1), about 60 mol of acetic acids can be produced in 1 m characterized by retrograde solubility (Giles and De Boer source rocks if an average TOC of 5% in the mudstone and −3 1989), however, there must be a supply of a large amount of an organic acid yield of 0.5 × 10 mol/g TOC (Table 2) acidic water that has the capacity to provide H . are available in the source rocks. Because organic acids concentrate at temperatures of 80–120 °C, most organic (1) Various organic acids from kerogens are present in most acids are assumed to be released from the source rocks to of the formation waters in petroliferous basins. Ace- the reservoirs in the depth interval of 1500–4000 m. From tic acid with a relative content of approximately 80% 1500–4000 m, the sandstone porosities generally decrease dominates the organic acids in most cases (Surdam and from 35% to 15% and the mudstone porosities decrease from Crossey 1987; Surdam et al. 1989; Surdam and Boese 20% to 5% (Gluyas and Cade 1997; Pittman and Larese 1984). It was suggested by Surdam et al. (1984, 1987, 1991; Ramm 1992). As organic acids are water soluble 1989) and Meshri (1986) that organic acids were more (Barth and Bjørlykke 1993), we assume that all the pore aggressive than CO and could be responsible for the water expelled from the mudstones to the sandstone reser- dissolution of silicate and carbonate minerals (Meshri voirs have a high concentration of organic acids (10,000 ppm 1986; Surdam and Crossey 1987; Surdam et al. 1989; acetic acid). In this case, the organic acids expelled to the Surdam and Boese 1984). The leaching of calcite by reservoirs can dissolve only 0.46% volume of calcite with acetic acid can be expressed as CaC O + CH COOH— a thorough consumption of the available acids. In another 3 3 2+ − − Ca + HCO + CH COO . Using the data of the case, if diffusion or hydrocarbon migration can transport 3 3 concentration of organic acid in oilfield waters, Surdam more organic acids to the sandstone reservoirs (Barth and (1984, 1987) further suggested that large volumes of Bjørlykke 1993; Thyne 2001), only 2% volume of calcite can water-soluble organic acids are generated during the be dissolved in the sandstone reservoirs. The organic acids thermocatalytic degradation of kerogen in the range are weak acids and the equilibrium constant of the calcite- −4 of 80–120 °C and the concentration of organic acids leaching reaction by organic acids decreases from 8.5 × 10 −5 can even reach up to 10000 ppm (Surdam et al. 1989; at 25 °C to 7.9 × 10 at 100 °C (Giles and Marshall 1986). Surdam and Crossey 1987; Surdam and Boese 1984). Under constraints of the equilibrium constant, the calcite 1 3 Petroleum Science (2019) 16:729–751 739 Table 2 Pyrolysis experiment data of global source rocks and kerogen. (data from Kawamura et al. 1986; Kawamura and Kaplan 1987; Barth et al. 1988; Barth and Bjørlykke 1993; Chen et al. 1994; Barth et al. 1996; Zeng et al. 2007; Meng et al. 2008; Zhang et al. 2009) Sample loca- Sample type Sample Kerogen type TOC, % R , % CO , Acetic acid, Total organic Publications o 2 −3 −3 tion amount 10 mol/ 10 mol/ acids, −3 gTOC gTOC 10 mol/ gTOC Well C11 in Mudstone 13 II-1 2.46 0.42 – – 0.010–0.081 Meng et al. Huanghua (2008) Depression Es Formation Mudstone 1 – 1.04 0.33 – – 0.175–0.608 Zeng et al. in Dongying (2007) Sag Es Formation Mudstone 1 – 2.11 0.40 – – 0.084–0.220 in Dongying Sag Es Formation Mudstone 1 – 3.70 0.42 – – 0.086–0.128 in Dongying Sag Es Formation Mudstone 1 – 1.73 0.24 – – 0.160–0.445 in Dongying Sag Well Chun11 Mudstone 5 I 3.50 0.32 – – 0.134–0.330 Zhang et al. in Dongying (2009) Sag Well Cao Mudstone 3 II-1 2.29 0.32 – – 0.024–0.177 13-15 in Dongying Sag Well Ying 10 Mudstone 3 II-2 1.19 0.48 – – 0.051–0.341 in Dongying Sag Well YMian4- Mudstone 1 I 1.32 0.36 – – 0.676 5-165 in Dongying Sag Well Lunnan Mudstone 4 II-III 8.04 0.61 – 0.002–0.005 0.010–0.04 Chen et al. 54 in Tarim (1994) Basin Well Lunnan Mudstone 12 II-III 8.04 0.61 – 0.004–0.084 0.011–0.110 54 in Tarim Basin Well Tan26 Mudstone 1 II-III – 0.41 – 0.612 0.700 in Jianghan Basin Green River Kerogen 7 I 2.30 – – 0.007–0.036 0.010–0.048 Kawamura Shale et al. (1986) Monterey Kerogen 2 II 10.0 – – 0.015–0.035 0.023–00060 Formation Monterey Kerogen 1 II – – – 0.025 0.036 Kawamura Formation and Kaplan (1987) Green River Kerogen 1 I – – – 0.04 0.056 Shale Tanner Basin Kerogen 1 II – Immature – 0.149 0.278 Sierra Bog Humic acid 1 III – – – 0.14 0.249 sediments 1 3 740 Petroleum Science (2019) 16:729–751 Table 2 (continued) Sample loca- Sample type Sample Kerogen type TOC, % R , % CO , Acetic acid, Total organic Publications o 2 −3 −3 tion amount 10 mol/ 10 mol/ acids, −3 gTOC gTOC 10 mol/ gTOC Kimmeridge Oil shale 5 – 12.6 Immature – 0.057–0.215 0.104–0.345 Barth et al. oil shale, (1988) Dorset, Upper Juras- sic Jurassic, the Coaly shale 3 – 14.3 Mature – 0.009–0.013 0.011–0.016 Norwegian continental shelf Lower Juras- Coal 3 – 39.6 Immature – 0.069–0.100 0.081–0.123 sic, the Norwegian continental shelf Upper Juras- Mudstone 3 – 5.03 Immature – 0.151–0.284 0.263–0.412 sic, the Norwegian continental shelf Mudstone 3 II 12.60 Immature 2.86–8.73 0.141–0.231 0.252–0.346 Barth and Kimmeridge Bjørlykke ourcrop, Dorset, UK (1993) Kimmeridge, Coal 3 II 5.03 Immature 7.95–10.93 0.154–0.282 0.262–0.414 North Sea Kimmeridge Mudstone 3 II 51.30 0.29 1.65–4.70 0.052–0.116 0.110–0.244 outcrop, Dorset, UK Heather, Mudstone 3 II 6.49 0.40 1.23–2.16 0.142–0.273 0.177–0.341 North Sea The Nor- Mudstone 3 III 14.30 Mature – 0.009–0.013 0.011–0.017 wegian continental shelf The Nor- Coaly shale 3 Coal 39.60 Immature 3.18–4.72 0.069–0.100 0.081–0.124 wegian continental shelf The Nor- Coal 3 Coal 23.10 0.38 0.30–1.99 0.124–0.276 0.160–0.377 wegian continental shelf Western Ger- Coal 3 Coal 70 0.26 1.72–2.41 0.518–0.552 0.609–0.705 many 1 3 Petroleum Science (2019) 16:729–751 741 Table 2 (continued) Sample loca- Sample type Sample Kerogen type TOC, % R , % CO , Acetic acid, Total organic Publications o 2 −3 −3 tion amount 10 mol/ 10 mol/ acids, −3 gTOC gTOC 10 mol/ gTOC Draupne, the Dicarbonated 6 – 3.70–7.19 – 1.00–2.36 0.048–0.455 0.081–0.659 Barth et al. Norwegian mudstone (1996) continental shelf Draupne, the Mudstone 3 – 3.52–6.21 – 1.58–8.31 0.082–0.315 0.181–0.497 Norwegian continental shelf Heather, the Dicarbonated 4 – 1.06–5.49 – 0.77–6.61 0.038–0.399 0.077–0.601 Norwegian mudstone continental shelf Heather, the Mudstone 2 – 1.85–7.79 – 3.45–3.78 0.086–0.125 0.148–0.218 Norwegian continental shelf Brent, he Dicarbonated 2 – 3.46–5.25 – 0.38–1.53 0.085–0.103 0.144–0.151 Norwegian mudstone continental shelf Dulin, the Dicarbonated 2 – 1.32–3.13 – 0.35–10.00 0.008–0.695 0.105–1.349 Norwegian mudstone continental shelf — Not measured (a) Organic acids, ppm (b) Organic acids, ppm 0 2000 4000 6000 8000 10000 0 500 1000 1500 2000 2500 0.5 Basins in East China 1.0 1.5 2.0 2.5 3.0 100 3.5 Basins in 4.0 West China 4.5 Alaska 5.0 Texas Raton Basin 5.5 California Santa Maria Basin Piceance Basin Wamsuttter anticline 6.0 Weshakle Basin Gulf Coast Basin Northern part of Songliao Basin Red Dessert Basin Louisiana Gulf Coast Qikou Sag Yuanyanggou area in Liaohe Basin 6.5 San-Juan Basin Weatern overthrust fault Tabei Basin Xujiaweizi Rift in Songliao Basin San Joaquin Basin Eastern Venezuela Basin Tarim Basin Qingshui Sag in Liaohe Basin 250 7.0 Fig. 6 Concentrations of organic acids in the pore water of sandstone reservoirs in oil and gas basins. a Organic acids in global sedimentary basins; b organic acids in sedimentary basins in China. (data from Kharaka 1986; Fisher 1987; Surdam and Crossey 1987; MacGowan and Sur- dam 1988; Surdam et al. 1989; Wang et al. 1995; Cai et al. 1997; Xiao et al. 2005; Meng et al. 2006; Wang et al. 2007; Meng et al. 2011) 1 3 T, °C Depth, km 742 Petroleum Science (2019) 16:729–751 volume that can be dissolved in the reservoirs is reduced 1984). Because of the constraints of the mass balance significantly. In addition, most source rocks contain consid- calculation, Lundegard et al. (1984) suggested that even erable carbonate minerals and silicate minerals (Ehrenberg if all the C O generated from kerogen was expelled et al. 2012; Giles and Marshall 1986; Taylor et al. 2010); from the source rocks to the sandstones, only 1%–2% these minerals first consume some of the organic acids gen- of secondary porosity could be generated (Lundegard erated in the mudstones, which also decreases the volume et al. 1984). of acids expelled to the reservoirs and the leaching ability of the organic acids in the reservoirs (Barth et al. 1996; Barth In contrast to Schmidt (1979a, b) and Surdam (1984), and Bjørlykke 1993). Smith and Ehrenberg (1989) proposed that the increased CO abundance results in precipitation rather than dis- (2) CO is present in most oil-gas sandstone reservoirs, solution of carbonate minerals at the depth interval with though most natural gas accumulations contain less temperature ranging from 80°C to 120 °C, in which the than 10% C O (Seewald 2003). It was suggested by organic acids have the highest concentrations and control Smith and Ehrenberg (1989), Ribstein et al. (1998), and the alkalinity of the carbonate–silicate–organic acid–car- Seewald (2003) that the C O content in natural gases bonic acid–p system. 2 CO generally increases with increasing temperature and Using numerical simulations with the constraints of burial depth, and the p increases systematically in thermodynamics, Huang et al. (2009) calculated the pH CO the temperature range from 40 to 200 °C (Fig. 7) (Cur- values of different carbonate–H O–CO geochemical sys- 2 2 tis 1978; Ribstein et al. 1998; Schmidt and McDonald tems in the equilibrium state (Fig. 8a) and the dissolution/ 1979a; Seewald 2003; Smith and Ehrenberg 1989). The precipitation volumes of the calcite or dolomite minerals CO in the reservoirs originates from the degradation in these systems at temperatures of 28–235 °C, pressure of of organic matter or from water–rock interactions (Cur- 1–70 MPa, depth of 1–7 km, and a specific molar content tis 1978; Ribstein et al. 1998; Schmidt and McDonald of CO (Fig. 8b–d). The results show that the systems with 1979a; Seewald 2003; Smith and Ehrenberg 1989). a higher C O content have lower pH values and this results In the range of 80–120 °C, the release of C O from in the dissolution of more carbonate minerals at depths kerogen in the source rocks is inevitably one important shallower than 2000 m. At depths deeper than 2000 m, source and it was suggested by Schmidt (1979a, b), however, more carbonate minerals are precipitated in the Surdam (1984), and Surdam and Crossey 1987) that systems with more C O , even if the systems have lower pH this CO source is one of the most important carbonic values of approximately 4.8 (Fig. 8) (Huang et al. 2009). acids for carbonate dissolution (Schmidt and McDonald Using laboratory water–rock interaction experiments, 1979a; Surdam and Crossey 1987; Surdam and Boese Song and Huang (1990) also demonstrated that calcite can be precipitated even when the pH is lower than 5 (Song and Huang 1990). 2 As carbonate minerals are characterized by retrograde solubility, cooling of hot fluids have been suggested to dissolve carbonate minerals during the uplift stage of the formation or during injection of deep hot water to shal- low formations. Using numerical simulations with the constraints of thermodynamics, Yuan et al (2015a, b, c) modeled the calcite dissolution in two systems with tem- perature decreasing from 200 °C to 50 °C (Fig. 9). In the -1 system with fixed p (223 bar) during the cooling pro- CO cesses, 1 kg of water may dissolve 5.01 g calcite (Case-1), -2 while in the system when p decreases from 223 bar at CO 200 °C to 0.32 bar at 50 °C (according to the equation log p = −1.45 + 0.019 T) (Smith and Ehrenberg 1989), -3 CO 40 80 120 160 200 1  kg of water can dissolve only 0.027  g calcite (Case- Temperature, °C 2). In such cases, the pore water in sandstones with 20% porosity can only dissolve calcite (with specific gravity of Fig. 7 Partial pressure of C O ( p ) in sedimentary basins (after 2 CO 2.7 g/cm ) to increase porosity by 0.037% and 0.0002%, Coudrain-Ribstein et al. 1998). The dashed line represents CO fixed respectively, with the occurrence of retrograde dissolution. by equilibrium between calcite, dolomite, chlorite, kaolinite, and chalcedony (Coudrain-Ribstein et al. 1998). The solid line represents fitted line for US Gulf Coast data after Smith and Ehrenberg (1989) 1 3 log p CO 2 Mole, %CO2 = 0.1% Mole,%CO2 = 1.0% Mole,%CO = 10.0% Petroleum Science (2019) 16:729–751 743 3 3 3 (a) pH of Calcite-H O-CO balance system (b) (c) (d) 2 2 ΔV, cm /L ΔV, cm /L ΔV, cm /L 4.65.1 5.66.1 6.67.1 7.6 -0.06 -0.01 0.04 -0.14 -0.07 0 0.07 -0.3 -0.2 -0.1 00.1 0.2 0 0 0 0 Dolomite Dolomite Dolomite 1 1 1 1 Calcite Calcite Calcite 2 2 2 2 3 3 3 3 4 4 4 4 5 5 5 5 6 6 6 6 7 7 7 7 Mole, %CO2 = 0.1% Mole, %CO2 = 1.0% Mole, %CO2 = 10.0% Fig. 8 a Plot of pH values versus depth for CaC O –H O–CO equilibrium systems with different CO contents; b–d volume increment of calcite 3 2 2 2 and dolomite by per liter liquid (V) versus depth for CaC O –H O–CO , CaMg(CO ) –H O–CO systems, the CO  mol fractions are 0.1%, 1%, 3 2 2 3 2 2 2 2 and 10%, respectively, after the systems reached equilibrium. (after Huang et al. 2009) 3 7.0 (a) (b) 6.5 6.0 1 5.5 5.0 4.5 -1 4.0 200 175 150 125 100 75 50 200 175 150 125 100 75 50 Temperature, °C Temperature, °C 10 11 1 (c) (d) HCO3 10 g 9,973 g HCO3 0.1 ++ Ca 0.01 ++ 4.987 g Ca 0.001 4 200 175 150 125 100 75 50 200 175 150 125 100 75 50 Temperature, °C Case 1 Case 2 Temperature, °C Fig. 9 Numerical simulation results of the cooling of hot fluids from 200 to 50 °C in a calcite–CO –H O system with initial log ( p ) values of 2 2 CO 2.35. Case-1: Simulation was conducted with a fixed p ; Case-2: Simulation was conducted with a variable p (Yuan et al. 2015a, b, c) CO CO 2 2 4.3 Buffer system and pH needed for burial are mutually rock buffered (Bjørlykke and Jahren 2012; Hutcheon and Abercrombie 1990; Macquaker et al. 2014; carbonate dissolution Smith and Ehrenberg 1989; Taylor et al. 2010; Turchyn and DePaolo 2011). The carbonate minerals were commonly Diagenetic reactions in intermediate to deep burial regimes 1 3 Fluid components concentration, molal log p Depth, km CO Calcite, g pH 744 Petroleum Science (2019) 16:729–751 suggested to react faster with acids than the aluminosili- without favorable flow conduits (e.g., faults and fractures) cate minerals (Bjørlykke and Jahren 2012). In the buried in the mesodiagenetic stage (Bjørlykke and Jahren 2012; aluminosilicate–carbonate mineral–acid system, however, Ehrenberg et al. 2012; Giles 1987; Taylor et al. 2010). Smith and Ehrenberg (1989), Hutcheon and Abercrombie (1990), and Turchyn and DePaolo (2011) suggested that (1) Advective transfer the aluminosilicate minerals–water interaction rather than the carbonate mineral–water reaction was the main acid- Mass transport of a component by the advective flow in buffering mechanism (Bjørlykke and Jahren 2012; Hutcheon subsurface porous rocks can be expressed by and Abercrombie 1990; Macquaker et al. 2014; Smith and q = qC (1) Ehrenberg 1989; Taylor et al. 2010; Turchyn and DePaolo where q is the advective flux of the species, q is the spe- 2011). The buffer intensity of silicate minerals can be ten cific discharge, and C is the component’s concentration. The times that of calcite in an acidic system at high temperature solubility of calcite is a function of the p and temperature CO (Hutcheon and Abercrombie 1990). The pH of most cur- in the burial sediments, and the calcite solubility is less than rent oil–gas waters is higher than 5.5 due to the buffering 0.01 mol/L in systems at temperatures ranging from 80 °C effect of various aluminosilicate mineral–water interactions (with 1 bar p ) to 160 °C (20 bar p ) (Giles and De Boer CO CO (Birkle et al. 2009; Birkle et al. 2002; Egeberg and Aagaard 2 2 1989). Assuming that a set of sediments has a mudstone/ 1989; Frape et al. 1984; Surdam et al. 1985), and the exten- sandstone ratio of 10:1 and the mudstone porosity decreases sive dissolution of carbonate minerals is unlikely in reser- from 20% to 5% as the burial depth increases from 2000 m to voirs with such a relative weaker acidity. This concept is a 4000 m (Pittman and Larese 1991), all the water in the mud- rather radical departure from the conventional system, but stone units would be expelled to the sandstone units. The it is now being verified by the significant fabric observation water from the mudstone, even with very low salinity, can of extensive feldspar dissolution and no/little carbonate dis- dissolve and remove only approximately 0.05% volume of solution in many buried sandstones (Armitage et al. 2010; the calcite mineral in the sandstone units under the mecha- Baker et al. 2000; Ceriani et al. 2002; Dos Anjos et al. 2000; nism of advective flow. Dutton and Land 1988; Fisher and Land 1987; Girard et al. 2002; Hendry et al. 1996; Milliken et al. 1994; Salem et al. (2) Diffusive transfer 2000; Tobin et al. 2010) and some mudstones (Macquaker et al. 2014; Turchyn and DePaolo 2011). Yuan et al. (2015a, Mass transport by diffusion (M ) in porous rocks can be b, c) proposed the mechanism of selective dissolution of expressed by Fick’s law: feldspars in the presence of carbonate minerals to generate secondary minerals in buried sandstones by organic-original dC M =−D ×  × (2) t 0 CO (Yuan et al. 2015a, b, c). In addition, the dissolution of dX feldspars can, in turn, promote the precipitation of carbon- where M is the diffusion flux, D is the diffusion coefficient t 0 ate minerals (Tutolo et al. 2015). The C–O isotopic data of of solutes in water (cm /s), C is the component’s concentra- carbonate cements developed in subsurface rocks suggest the tion, and θ is the tortuosity factor of the sedimentary rock. generation of organic-derived and inorganic-derived C O . Tortuosity is generally a ratio of pore connectivity length The most carbon in these various types of CO , however, is to sediment sample length; thus, its value is always greater subsequently sequestered by the precipitation of carbonate than 1. In porous sedimentary rocks, the tortuosity of the cements in both source rocks and reservoirs (Curtis 1978; flow path is determined by porosity, permeability, and pore Giles and Marshall 1986; Seewald 2003). structure. Tortuosity can be expressed by Archie’s equation (Archie 1942) as: 4.4 Mass transfer problem 2 1− =  (3) In order to generate enhanced secondary porosity, the solutes where η is an adjustable exponent (Boudreau 1996). The 2+ 2+ − 2− (Ca, Mg, HCO, CO ) released by the dissolution of 3 3 empirical fit value of η reported by Boudreau (1996) is 2.14 carbonate minerals need to be removed from the dissolu- ± 0.03, with an average value of 2.14. Diffusion in a porous tion zone in the sandstone reservoirs (Bjørlykke and Jahren sediment system is much slower than in an equivalent vol- 2012; Ehrenberg et al. 2012; Giles 1987; Taylor et al. 2010). ume of water because the convoluted path the solutes must Advection, diffusion, and convection are the three possible follow to circumvent sediment particles (Boudreau 1996). mechanisms that control the mass transfer in the sedimentary The pore water composition in the middle-deep buried basins. However, none of the advective, diffusive, or convec- sandstones is generally close to saturation with respect to tive mass transfer supports significant transfer of the solutes most minerals after long-term contact of the pore water and released from carbonate dissolution in the buried sandstones 1 3 Petroleum Science (2019) 16:729–751 745 2+ 2+ minerals. The solute concentration gradients (Ca , Mg , were interpreted as secondary pores formed by the dissolu- − 2− HCO , CO ) are generally very low in the sandstone beds tion of carbonate cements (Taylor et al. 2010). Based on 3 3 with relative homogeneous composition (Bjørlykke 2014; the CO /organic acids leaching hypothesis, and the negative Bjørlykke and Jahren 2012), which prevents the large-scale relationship between porosity and the amount of carbonate diffusive transfer of these masses, even in a long geological cements in reservoirs, extensive burial dissolution of carbon- time. ate minerals has also been suggested by many other authors in the last few decades (Dutton and Willis 1998; Gibling (3) Convective transfer et al. 2000; Harris and Bustin 2000; Higgs et al. 2010; Irwin and Hurst 1983; Khidir and Catuneanu 2010; Kordi et al. Thermal convection is a potential mechanism for mass 2011; Mcbride 1988; Shanmugam 1984; Wilkinson et al. transfer in buried sandstones with high porosity and perme- 1997). Similar to Schmidt and McDonald (1979a, b), no ability. Mathematical calculations of thermal convection, convincing petrography evidence on carbonate dissolution however, demonstrated that even thin interbedded layers was provided in these publications. of mudstones within permeable sandstone sequences will split potentially larger convection cells into smaller units 5.2 Papers with convincing petrographic evidence of sandstone beds which may then be too small to exceed the critical Rayleigh number. After extensive compaction Some studies with convincing petrographic evidence of the and cementation, convective circulation of pore water is dissolution of carbonate cements in buried sandstones have not likely to occur in the sandstone beds with interbedded been published. Review of these works suggests that most mudstones characterized by extremely low porosity and of the extensive dissolutions were related to deep hot fluids low permeability (Bjørlykke 1993; Bjørlykke et al. 1988), (Taylor 1996; Taylor et al. 2010) and cold meteoric fresh particularly after the formation of tight marginal cemented water (Bouch et al. 2006; Cavazza et al. 2009; Khidir and barriers formed by precipitation of eodiagenetic carbonate Catuneanu 2003; Poursoltani and Gibling 2011; Yuan et al. cements in the marginal sandstones close to the mud/sand 2017; Zaid 2012), while organic CO leaching resulting in surfaces (Saigal and Bjørlykke 1987). very limited dissolution (Lu et al. 2011; Weedman et al. Overall, large-scale carbonate dissolution is not supported 1996). by any of the mass transfer mechanisms in buried geochemi- cal systems without favorable flow conduits. (1) Dissolution related to deep hot fluids. Taylor (1996, 2010) presented a striking exception in the deeply bur- ied (4.9–5.2 km) Miocene sandstones in the Picaroon 5 Published examples of carbonate field, offshore Texas. The anomalously high porosities dissolution in sandstones (20%–29%) in the sandstone reservoirs are largely a result of the porosity enhancement by the dissolution Many papers on mineral dissolution in buried sandstones of carbonate minerals (Taylor 1996; Taylor et al. 2010). have been published in the last 40 years. After a careful A detailed petrographic study has established evidence analysis of the included petrography evidence on the dissolu- for the partial dissolution of pore-filling calcite cements tion of carbonate minerals, we categorize these publications and detrital carbonate grains in the most porous sands into three groups. (Fig.  2f), and 6%–15% of the calcite cements were estimated to have been removed from the reservoirs. 5.1 Papers lacking convincing petrography However, the aggressive fluids that leached the cements evidence but including hypothesis were not acids originating from kerogen maturation but deep hot fluids with high salinity and high con- Schmidt and McDonald (1979a, b) first proposed the idea centrations of Sr, Ba, Fe, Pb and Zn. The Corsair fault that significant secondary porosity (up to 20%) can be gen- systems played a very important role in introducing erated through burial dissolution of carbonate cements by such hot fluids into the Miocene sandstones. As Taylor CO during the organic maturity stage (Fig. 1) (Schmidt and et al. (2010) suggested, the geological conditions in the McDonald 1979a). In their paper, however, no convincing Picaroon field that provide access to deep fluid sources carbonate dissolution phenomena such as the microscope are somewhat extraordinary (Taylor 1996; Taylor et al. photography in Taylor (1996) or the SEM microphotogra- 2010). phy in Weedman et al. (1996) and Khidir and Catuneanu (2) Dissolution related to meteoric water. Convincing pet- (2003) were presented (Khidir and Catuneanu 2003; Schmidt rographic evidence of carbonate dissolution in sand- and McDonald 1979b; Taylor 1996; Weedman et al. 1996). stones with meteoric freshwater incursion was provided Instead, most intergranular pores without carbonate cements by some studies. The isotopic composition of the car- 1 3 746 Petroleum Science (2019) 16:729–751 bonate cements or the burial history of the rocks sug- presence of carbonate minerals including detrital carbonate gests that the dissolutions were induced by meteoric grains and early precipitated calcite cements. These carbon- freshwater during the early eodiagenetic stage or the ate cements display euhedral crystal faces where they border uplift telodiagenetic stage (Bouch et al. 2006; Cavazza open primary pores, and the detrital carbonate grains show et al. 2009; Khidir and Catuneanu 2003; Poursoltani no corroded fabrics that occur in feldspar grains. Aside from and Gibling 2011; Yuan et al. 2017; Zaid 2012). For the geological examples of buried sandstones, numerical example, Khidir and Catuneanu (2003) presented con- simulation results also demonstrated that the feldspar disso- vincing SEM photomicrographs to show the dissolution lution induced by carbonic acid in the subsurface sandstones of carbonate cements in the Scollard sandstones out- would be accompanied by carbonate precipitation in sys- crop. The sandstones were not buried at depths where tems in the long term, and these relevant carbonate cements the temperature reached 120 °C, and the δ O composi- serve as an analogue of late-stage carbonate cements in the tion of the included calcite cements and relevant cal- subsurface sandstones (Barclay and Worden 2000; Wilson culated water δ O composition suggested a meteoric et al. 2000). origin of the diagenetic fluids. Poursoltani and Gibling (2011) provided an example of the dissolution of car- bonate cements in sandstones with developed fault sys- 6 Conclusions tems that were formed during an uplift period; the cal- cite cements were suggested to be leached by meteoric (1) Four types of selective dissolution assemblages of water. Cavazza et al. (2009) provided excellent outcrop feldspar and carbonate minerals can be identified in photographs, microscope photos, and SEM images to sandstones. A critical eye must be cast on the identifica- show carbonate cement dissolution in the Quaternary tion of mineral dissolution and intergranular secondary marine terraces outcrop sandstones; the dissolution was pores in sandstones so that possible subjective conclu- the leaching result of meteoric flow during the falling sions can be avoided. period of sea level. (2) Petrographic data, porosity data, water–rock experi- (3) Organic CO leaching with weak dissolution. Some ments, geochemical calculations of aggressive fluids, authors have presented convincing petrographic evi- and mass transfer do not support significant mesodia- dence of carbonate dissolution that was induced by genetic carbonate dissolution in buried sandstones. A organic CO originating from the thermal evolution of review of relevant publications suggests that the exten- kerogen. The authors, however, also stated that only sive dissolution of carbonate minerals was generally a small amount of carbonate minerals were dissolved attributed to a high flux of deep hot fluids provided via under the constraints of fluid chemistry modeling or fractures or the meteoric freshwater available during mass balance calculation (Lu et al. 2011; Weedman the eodiagenetic and telodiagenetic stages. et al. 1996). Overall, review of the published papers suggests that the Acknowledgements This study was funded by the Natural Sci- ence Foundation of China Project (Nos. 41602138, 41872140, extensive dissolution of carbonate minerals in the sandstones 41911530189), the National Science and Technology Special Grant was generally attributed to the high flux of deep hot fluids (No. 2016ZX05006-007; No. 2016ZX05006-003), the Fundamen- provided via fractures or the meteoric freshwater available tal Research Funds for the Central Universities (18CX07007A), and during the eodiagenetic and telodiagenetic stages. the State Key Laboratory of Organic Geochemistry, GIGCAS (No. SKLOG-201709). 5.3 Papers with dissolution of feldspars Open Access This article is distributed under the terms of the Crea- but no carbonate tive Commons Attribution 4.0 International License (http://creat iveco mmons.or g/licenses/b y/4.0/), which permits unrestricted use, distribu- Some studies have reported the phenomena of extensive tion, and reproduction in any medium, provided you give appropriate credit to the original author(s) and the source, provide a link to the feldspar dissolution in buried sandstones, but the carbon- Creative Commons license, and indicate if changes were made. ate cements and detrital carbonate grains in the sandstones showed no signs of extensive dissolution (Armitage et al. 2010; Baker et  al. 2000; Ceriani et  al. 2002; Dos Anjos et al. 2000; Dutton and Land 1988; Fisher and Land 1987; References Girard et al. 2002; Hendry et al. 1996; Milliken et al. 1994; Archie GE. 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How important is carbonate dissolution in buried sandstones: evidences from petrography, porosity, experiments, and geochemical calculations

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Springer Journals
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Copyright © 2019 by The Author(s)
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Earth Sciences; Mineral Resources; Industrial Chemistry/Chemical Engineering; Industrial and Production Engineering; Energy Policy, Economics and Management
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1672-5107
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1995-8226
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10.1007/s12182-019-0344-4
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Abstract

Burial dissolution of feldspar and carbonate minerals has been proposed to generate large volumes of secondary pores in subsurface reservoirs. Secondary porosity due to feldspar dissolution is ubiquitous in buried sandstones; however, extensive burial dissolution of carbonate minerals in subsurface sandstones is still debatable. In this paper, we first present four types of typical selective dissolution assemblages of feldspars and carbonate minerals developed in different sandstones. Under the constraints of porosity data, water–rock experiments, geochemical calculations of aggressive fluids, diagenetic mass transfer, and a review of publications on mineral dissolution in sandstone reservoirs, we argue that the hypothesis for the creation of significant volumes of secondary porosity by mesodiagenetic carbonate dissolution in subsurface sandstones is in conflict with the limited volume of aggressive fluids in rocks. In addition, no transfer mechanism supports removal of the dissolution products due to the small water volume in the subsurface reservoirs and the low mass concentration gradients in the pore water. Convincing petrographic evidence supports the view that the extensive dissolution of carbonate cements in sandstone rocks is usually associated with a high flux of deep hot fluids provided via fault systems or with meteoric fresh- water during the eodiagenesis and telodiagenesis stages. The presumption of extensive mesogenetic dissolution of carbonate cements producing a significant net increase in secondary porosity should be used with careful consideration of the geological background in prediction of sandstone quality. Keywords Mesodiagenetic · Carbonate dissolution · Petrography · Geochemical · Buried sandstones 1 Introduction The term secondary porosity refers to pore space resulting from the post-depositional dissolution of detrital grains or cements (Taylor et al. 2010). Ten genetic mechanisms have Edited by Jie Hao been proposed for the generation of aggressive fluids capa- ble of dissolving minerals in sandstones, which are mete- * Guang-Hui Yuan oric water penetration (Emery et al. 1990), mixing corro- yuan.guanghui@upc.edu.cn sion (Edmunds et al. 1982; Plummer 1975), acidic fluids * Ying-Chang Cao generated from CO produced by the thermal maturation of caoych@upc.edu.cn organic matter (Schmidt and McDonald 1979a; Surdam et al. Key Laboratory of Deep Oil and Gas, School of Geoscience, 1989; Surdam and Boese 1984), carboxylic acids generated China University of Petroleum, Qingdao 266580, Shandong, during the thermal maturation of organic matter (Surdam China et al. 1989; Surdam and Boese 1984), acidic fluids gener - State Key Laboratory of Organic Geochemistry, Guangzhou ated by clay mineral reactions (Giles and Marshall 1986), Institute of Geochemistry, Chinese Academy of Sciences, acid fluids generated by thermogenic sulfate reduction Guangzhou 510640, Guangdong, China 3 (TSR) and bacterial sulfate reduction (BSR) (Machel 2001; Department of Earth Sciences, Durham University, Machel et al. 1995), deep hot fluids (Taylor 1996), acidic Durham DH1 3LE, UK Vol.:(0123456789) 1 3 730 Petroleum Science (2019) 16:729–751 fluids generated by silicate hydrolysis (Hutcheon and Aber - 2012; Giles 1987; Giles and Marshall 1986; Giles and De crombie 1990), acidic fluids generated by silicate–carbonate Boer 1990; Taylor et al. 2010). interactions (Smith and Ehrenberg 1989), aggressive fluids Secondary pores originating from the dissolution of due to cooling of formation fluids (Giles and De Boer 1989), feldspar grains in subsurface rocks are common and eas- and hot alkaline brines (Pye 1985). ily recognizable (Yuan et al. 2015a, b, c, 2019a, b; Dutton The idea that the sandstone porosity can be significantly and Loucks 2010; Giles 1987; Taylor et al. 2010). However, increased via burial dissolution of minerals (e.g., carbonate even until now, there is still much debate about the reality cements, feldspars) at depths of approximately 3 km by CO of the significant dissolution of carbonate cements in buried and organic acids originating from kerogen maturation in sandstones (Bjørlykke 2014; Bjørlykke and Jahren 2012; Li source rocks was proposed in 1970s to 1980s (Schmidt and et al. 2017; Taylor et al. 2010; Yuan et al. 2013a, b, 2015a, McDonald 1979a; Surdam et al. 1989; Surdam and Boese b, c). Recently, rock diagenesis and the significance of sec- 1984) (Fig. 1a). Based on petrographic identification and ondary pores generated by the burial dissolution of feld- interpretation, this idea has been prominent in the literature spars and carbonate minerals have been reviewed within the on sandstone diagenesis for about 40 years (Bjørlykke and constraints of petrography, porosity data, and the openness Jahren 2012; Boggs 2011; Burley 1986; Dutton and Wil- versus closeness of geochemical systems (Bjørlykke 2014; lis 1998; Higgs et al. 2010; Khidir and Catuneanu 2010; Bjørlykke and Jahren 2012; Ehrenberg et al. 2012; Taylor Kordi et al. 2011; Schmidt and McDonald 1979a; Shan- et al. 2010; Yuan et al. 2013a, b). These reappraisals showed mugam 1984; Xi et al. 2016; Wilkinson et al. 1997; Yuan that burial-induced carbonate dissolution in sandstones and et al. 2015a, b, c). At the same time, however, the advent carbonates is commonly insignificant. This conclusion is of the deep burial dissolution proposals has caused intense not new (Ehrenberg et al. 2012); however, the retrospective debates (Fig. 1b). The opposing views are centered on the nature of these new presentations is striking because the sub- apparent lack of viable geochemical mechanisms by which jective idea that up to 20% secondary porosity can be formed dissolution and mass transfer could occur in the subsurface by burial dissolution of minerals still persists in some very rocks (Bjørkum et al. 1998; Bjorlykke 1984; Bjørlykke and recent publications (Khidir and Catuneanu 2010; Kordi et al. Brendsal 1986; Bjørlykke and Jahren 2012; Ehrenberg et al. 2011) and textbooks (Boggs 2011). Particularly, this idea Primary Secondary Porosity Φ, % Φ, % Φ, % Kerogen evolution stage Reservoir spaces evolution 40 20 0 40 20 0 40 20 0 Immature stage: Mainly mechanical reduction of primary porosity Minor Extensive cementation? cementation? Semi-mature stage: Mainly chemical reduction of primary porosity Minor Extensive dissolution? dissolution? Mature stage: Primary porosity at irreducible levels, Secondary porosity may exist Super mature stage: Primary and secondary porosity at irreducible levels Primary pores Secondary pores Quartz grains Feldspar grains Detritus grains Carbonate cements a-Porosity evolution models proposed by Schmidt and McDonald (1979) b-Modified from Giles (1987) Fig. 1 Textural stages of mesodiagenesis of sandstone porosity and the petrographer’s dilemma of secondary porosity (after Schmidt and McDonald 1979a, b; Giles 1987) 1 3 Petroleum Science (2019) 16:729–751 731 is still prominent with regard to the origin of anomalously and carbonate mineral has been discussed a great deal. Pet- high porosity in the deeply buried sandstones in China (Bai rographic evidence has been used to demonstrate the pres- et  al. 2013; Si and Zhang 2008; Tang et al. 2013; Wang ence of secondary porosity in sandstones (Bjørlykke and et  al. 2013; Yuan et al. 2012; Zhu and Zhang 2009; Zhu Jahren 2012; Giles and Marshall 1986). The porosity related et al. 2007). to framework grain dissolution (e.g., feldspars) can be rec- According to laboratory water–rock interaction experi- ognized and statistically quantified (Taylor et  al. 2010). ments, carbonate minerals can be dissolved more easily and Though extensive burial dissolution of carbonate cements to be dissolved much faster than feldspar minerals in open has been suggested by many researchers (Schmidt and geochemical systems under steady-state conditions far from McDonald 1979a; Surdam et al. 1989; Surdam and Boese equilibrium (Bertier et al. 2006; Chen et al. 2008; Liu et al. 1984), intergranular pores without carbonate cements should 2012; Weibel et al. 2011; Yang et al. 1995), and the carbon- not be interpreted as secondary porosity unless considerable ate minerals seem likely to be the most important minerals petrographic evidences of its former presence can be estab- for the development of secondary pores in buried sandstones lished (Taylor et al. 2010). Experiments under steady-state (Giles and Marshall 1986; Schmidt and McDonald 1979a). conditions far from equilibrium illustrate that the dissolution However, things may be different in closed subsurface rates of carbonate minerals are much faster than the rate of sandstone geochemical systems. Based on our studies, we feldspars. In the natural sandstone rocks, however, things are identified four types of selective dissolution assemblages of likely to be more complex. Based on our studies, we identi- feldspar and carbonate minerals in different sandstone rocks fied four types of typical selective dissolution assemblages (Fig. 2), which may have some significant implications for of feldspar and carbonate minerals in sandstone rocks. this debate (Fig. 1) (Yuan et al. 2015a, b, c). At the same time, some recent papers presented the dissolution of silicate (1) Type I: Little feldspar dissolution vs. extensive carbon- minerals with no dissolution of carbonate minerals in the ate precipitation Kimmeridge Clay mudstones (Macquaker et al. 2014) and in the Eocene sandstones in the Bohai Bay Basin (Yuan et al. In buried sandstones and sandstone outcrops, carbonate- 2015a, b, c). Also, Turchyn and DePaolo (2011) suggested cemented concretions are very common (Dos Anjos et al. that the dissolution of carbonate minerals in mudstones can 2000; Dutton 2008; Gluyas and Coleman 1992; Saigal and be significantly suppressed by the presence of silicate min- Bjørlykke 1987; Wang et al. 2016; Yuan et al. 2015a, b, c). erals, and the dissolution rate is much smaller even when Petrography and relevant stable isotope data usually suggest compared with the already-slow rates typical of carbonate- that the carbonate cements in such concretions formed soon rich sediments (Turchyn and DePaolo 2011). after sediment deposition and prior to the occurrence of the Stimulated by these recent reviews and the selective dis- key dissolution period in the rocks (Dutton 2008; Gluyas solution phenomena of feldspars and carbonate minerals in and Coleman 1992). In such concretions, large amounts of buried subsurface sandstones, the objectives of this article carbonate cements precipitated and preserved both the depo- are to: (1) provide detailed petrographic evidence of selec- sitional fabric and the composition of the sand grains with tive dissolution assemblages of feldspars and carbonate little if any grain replacement. The early carbonate cements minerals in buried sandstones; (2) discuss the significance occupied almost all primary intergranular pores (Fig. 2a, of burial carbonate dissolution in buried sandstones with b) and formed flow barriers (Saigal and Bjørlykke 1987), the constraints of porosity-depth data, water–rock experi- which led to little dissolution of both the feldspars and the ments, and geochemical calculations; and (3) review the carbonate cements in such concretions during the later burial literature on the dissolution of carbonate minerals in buried (Fig. 2a, b). In buried sandstones, the development of such sandstones with petrographic and geochemical constraints. concretions usually occurs near the sandstone–mudstone interface and the thickness of these concretions ranges from centimeters to several meters (Dutton 2008; Gluyas and 2 Evidence from the reservoirs Coleman 1992; Mcbride and Milliken 2006). 2.1 Petrography (2) Type II: Little feldspar dissolution vs. extensive car- bonate dissolution Feldspar grains and carbonate cements are common miner- als in subsurface sandstones. As both the feldspar and car- In buried sandstones, the phenomenon of little feldspar bonate minerals can be dissolved by the acids (e.g., C O dissolution versus extensive carbonate dissolution is rare and organic acids) originating from thermal maturation of and few publications have ever reported on it. However, organic matter, the potential to generate secondary pores in one paper reported on the extensive dissolution of early sandstone reservoirs through the dissolution of the feldspar calcite cements (Fig. 2c, cʹ) in Quaternary beach deposits 1 3 732 Petroleum Science (2019) 16:729–751 (a) F (b) F (c) Cd cc Cd cc Q Cc (c′) SC CA Cc cc Q Cc PF SC Q 25 μm Cc cc BC SC CV cc Cd Q PL cd Cc cc Cd F PF SC CV PL CV Cc F Cc Cd 200 μm PF 200 μm 200 μm (d) (e) (f) Fd Fd Fd F Fd Cd Cd Cd Cc Cd Cc Cc Cc Cc Cd Ca Cd Cd Cd Cd Fd F F Fd Cc 200 μm 200 μm 200 μm (g) (h) (i) FD Cc Cc FD Ca Ca Ca FD FD FD FD FD FD FD 200 μm 200 μm 200 μm (j) (k) (l) An Calcisphere test Coccolith Qa-II Kaolinite An Organic carbon Qa-I Quartz Pyrite Coccolith 10 μm 20 μm 25 μm Fig. 2 Micropetrographic evidence of the dissolution of feldspar and carbonate minerals in sandstone or mudstone rocks. a, b Extensive car- bonate cementation and weak feldspar dissolution in buried sandstones in the Dongying Sag, East China (Yuan et  al. 2015a, b, c), and in the Potiguar Basin, Brazil (Dos Anjos et al. 2000); c extensive dissolution of calcite with little dissolution of silicate grains in Quaternary marine terrace rocks (after Cavazza et al. 2009); cʹ dissolution of calcite cements, SEM image; d, e extensive dissolution of carbonate cements and feld- spar grains, Well Yan16, 1929.4 m, Dongying Sag; f extensive dissolution of carbonates and feldspar grains in buried Miocene sandstones from the Picaroon field, offshore Texas (after Taylor 1990); g, h extensive feldspar dissolution with little dissolution of carbonate cement and detrital carbonate grains, in Well T720, 3535.0 m, Dongying Sag; i extensive feldspar dissolution with little dissolution of detrital carbonate grains, Well T720, 2843.56 m, Dongying Sag; j euhedral ankerite wrapped in Qa-II quartz cements T720, 3535.0 m, Dongying Sag; k Intact ankerite, well Tuo764, 4169.8 m, Dongying Sag; l well-preserved calcisphere and precipitated kaolinite in mudstones of Kimmeridge Clay Formation (Mac- quaker et al. 2014). F feldspar grains, Q quartz grains, R rock fragment grains, FD feldspar dissolution pores, An ankerite, Cc carbonate cements, Ca carbonate detrital grain, Cd carbonate dissolution pores, Qa quartz overgrowths, sc silicate grains, cv smectitic cement, PF pore-filling cal- cite by meteoric water during periods of falling of sea levels the meteoric diagenetic environment (Cavazza et al. 2009). (Cavazza et al. 2009). The microphotograph suggests lit- These observations are consistent with the laboratory experi- tle dissolution of the associated silicate minerals (Fig. 2c). ments under steady-state conditions far from equilibrium in The associated silicate minerals were dissolved much less which calcite can be dissolved more easily than silicate min- extensively than the calcite cements, probably due to the erals (Chen et al. 2008; Liu et al. 2012; Weibel et al. 2011). short geological time period and the low temperature in 1 3 Petroleum Science (2019) 16:729–751 733 (3) Type III: Extensive feldspar dissolution and extensive carbonate cements and detrital carbonate grains in the lower carbonate dissolution Es Formation and the Es Formation (Fig. 2g–k). The car- 3 4 bonate cements occurred as connected patches (Fig. 2a), sin- In buried sandstones, the dissolution of feldspar and car- gle crystals (Fig. 2j, k) or grain-coating carbonate (Fig. 2g, bonate minerals has been suggested as common occurrence h), and individual crystals commonly exhibited euhedral by many authors (Schmidt and McDonald 1979a, 1979b; crystals faces abutting open pore space (Fig. 2k). The euhe- Surdam et al. 1989; Surdam and Boese 1984). Little con- dral ankerite engulfed by the stage-II quartz overgrowths vincing petrographic evidence, however, has been reported (Fig.  2j) suggests that the carbonate minerals were not to support the coexistence of extensive feldspar dissolution leached when the stage-II feldspar dissolution and quartz and extensive carbonate dissolution in buried sandstones. cementation occurred in the acidic geochemical system. In One typical example was provided by Taylor (1990, 1996), addition, the detrital carbonate grains and grain-coating car- who presented a striking and convincing microphotograph bonate cements show no evidence of dissolution (Fig. 2g–i); to show the dissolution of carbonate cements and detrital moreover, carbonate overgrowths are often found accompa- carbonate grains at Picaroon field (Fig.  2f) (Taylor 1990, nying the detrital carbonate grains. However, the feldspar 1996; Taylor et al. 2010). In the microphotographs, we can grains engulfed by early grain-coating carbonate cements or also identify the dissolution of feldspar grains (Fig.  2f). close to detrital carbonate grains are dissolved extensively Another example we have identified is the Es sandstones (Fig. 2g–i). from well Yan 16 in the Mingfeng area, Dongying Sag. In Overall, petrography textures suggest that carbonate min- the thin sections from Well Yan16, we observed the typical eral dissolution is not likely to occur all the time. Only in dissolution of feldspar grains and ferroan calcite cements two cases, extensive carbonate dissolution in the sandstone in the sandstones of the middle Es Formation (Fig. 2d, e). reservoirs is likely to occur. These sandstones are located close to some faults, which connect to the unconformity that developed at the end of the Eocene period. In these thin sections, the remnants of 2.2 Porosity‑depth data ferroan calcite cements were irregular and developed dis- solved pores (Fig.  2d, e). The low-oxygen isotope data The porosity evolution model proposed by Schmidt and (− 15.02‰ ~ − 17.20‰ ) of the ferroan calcite cements McDonald (Fig. 1a) was initially accepted and embraced by pdb pdb and the maximum depth (1920 m–1960 m with temperatures many geologists (Bjørlykke and Jahren 2012; Boggs 2011; of 75–80 °C) suggest that the fluid that formed these carbon- Burley 1986; Dutton and Willis 1998; Higgs et al. 2010; ate cements had negative δ O data (lower than − 8‰ ) Khidir and Catuneanu 2010; Schmidt and McDonald 1979a; SMOW (Matthews and Katz 1977), which support massive meteoric Shanmugam 1984; Wilkinson et al. 1997) to explain the water flux in these sandstones (Fayek et al. 2001; Harwood fairly common occurrence of intergranular porosity in sand- et al. 2013). stone buried to signic fi ant depth. However, as a general rule, global porosity-depth data show a steady decrease in the (4) Type IV: Extensive feldspar dissolution vs. little car- sandstone P50, P10, and the maximum porosity trends as the bonate dissolution depth increases (Fig. 3) (Ehrenberg et al. 2009; Ehrenberg and Nadeau 2005), which is inconsistent with the poros- Macquaker et al. (2014) reported the fabric observation of ity evolution model proposed by Schmidt and McDonald in kaolinite precipitation (byproduct of the dissolution of alu- 1979 (Fig. 1a). minosilicate minerals) and no dissolution of the associated Although anomalously high porosities do exist in some calcareous textures (Fig. 2l) in the Kimmeridge Clay Forma- deeply buried sandstones (Bloch et al. 2002; Warren and tion mudstones and regarded the phenomenon as surprising Pulham 2001), studies on the origin of the anomalously high and significant (Macquaker et al. 2014). In both mudstones porosities suggest that the dissolution of grains or preexist- and sandstones, such phenomena have not yet received much ing cements are just one subordinate aspect of this porosity. attention, although they were mentioned in some publica- These anomalously high porosities can be attributed to early tions (Armitage et al. 2010; Baker et al. 2000; Ceriani et al. emplacement of hydrocarbons (Bloch et al. 2002; Gluyas 2002; Dos Anjos et al. 2000; Dutton and Land 1988; Fisher et al. 1993; Wilkinson and Haszeldine 2011), fluid overpres- and Land 1987; Girard et al. 2002; Hendry et al. 1996; Mil- sure, or grain coats and grain rims (Bahlis and De Ros 2013; liken et al. 1994; Salem et al. 2000; Tobin et al. 2010). Using Bloch et al. 2002; Ehrenberg 1993); the mixture of porosity thin sections and scanning electron microscopy (SEM) from of rocks with different lithology from shallow to deep depths samples from the northern steep slope zone of the Dongy- may also lead to the occurrence of anomalously high porosi- ing Sag, we identified the phenomena of typical extensive ties in a porosity-depth profile (Bjørlykke 2014; Bjørlykke dissolution of feldspar grains with no/little dissolution of and Jahren 2012). 1 3 734 Petroleum Science (2019) 16:729–751 P90 P50 P10 Max. data of the samples with overpressure and (or) with high oil-bearing saturation were not employed in the Type-B pro- files. The Type-A porosity-depth profiles of the combined lithology (Fig. 4a1) show that anomalously high porosities do exist at the depth intervals of 2.8–3.7 km and 3.9–4.4 km, and the porosity-depth profiles of each individual lithology also show the existence of anomalously high porosities in some specific depth intervals (Fig.  4a2–a7). However, the Type-B porosity-depth profiles (Fig.  4b1–b7) show no exist- ence of the anomalously high porosities when the impact of the fluid overpressure and hydrocarbon emplacement on the reservoir porosity was removed. This analysis sug- gests that even where anomalously high porosities exist in deeply buried reservoirs, significant dissolution of carbonate cements may not be the cause. This is consistent with the petrographic evidence of selective dissolution of feldspar in the presence of carbonate minerals and the precipitation of authigenic clays and quartz cements following the feldspar 0 10 20 30 40 dissolution in these rocks (Yuan et al. 2013a, b). Porosity, % Fig. 3 Porosity versus depth profile for global petroleum sandstone 3 Water–rock experiments reservoirs. Statistical trends consist of P90 (90% of reservoirs have a porosity greater than this value), P50 (median), and P10. (after 3.1 Samples and methods Ehrenberg and Nadeau 2005) Pure calcite crystals were crushed, and the calcite grains The Eocene sandstones in the northern steep slope zone with a size of 2–4 mm were selected. In each experiment, in the Dongying Sag are an example exhibiting the impact one grain with a polished surface was employed to inves- of fluid overpressure, hydrocarbon emplacement, and min- tigate the dissolution features after the experiments. The eral dissolution. Detailed geological settings are available in grains were ultrasonically cleaned with analytical-grade some papers (Cao et al. 2013; Guo et al. 2010, 2012; Yuan distilled water three times to remove submicron-to-micron- et al. 2013a, b). Subaqueous fans and lacustrine fans were sized particles adhering to the grains. The calcite grains were x z deposited in the Eocene Es –Es Formations in the northern dried at 60 °C for 12 h and examined with a Coxem-EM-30 4 3 steep slope zone together with contemporary organic-rich plus scanning electron microscope (SEM) to check the total mudstones and shales. The development of anomalously removal of the small particles. Calcite grain samples were high porosities in the reservoirs has been reported (Cao prepared using a high-precision electronic balance (error < et al. 2014). In this paper, two types of porosity-depth pro- 0.005 g). High salinity waters with different salinity were files were plotted and presented, using the 7936 core poros- prepared with 99.99% NaCl, 99.99% CaCl , and deionized ity data collected from the Shengli Oilfield Company. The water (DW). Glacial acetic acid with a purity of more than lithology and oil-bearing properties of these samples were 99.5% was used to prepare acidic water with different pH. analyzed with core-logging materials. The fluid pressure The detailed experiment conditions are listed in Table 1. relevant to these samples was analyzed using the equivalent The calcite dissolution experiments at different tempera- depth method (Gao et al. 2008) using acoustic logging data tures (20 °C, 90 °C) were conducted in Hastelloy Reactors. with the constraint of the measured formation fluid pressure. For experiments with participation of C O, CO gas with a 2 2 And a database of the reservoir properties was established purity of more than 99.995% was injected into the reactor by using the information of the porosity, depth, lithology, oil- pumping to reach the designed p of 50 bar. The experi- CO bearing properties, and fluid pressure data. Type-A porosity- ments were conducted for 3, 8, and 15 days, respectively. depth profiles were plotted using the porosity data of all After the experiments at 20 °C, the calcite grains were sepa- reservoir samples (Fig. 4a1), and the porosity data of each rated from the water quickly, while for the experiments at individual lithology (Fig. 4a2–a7). Type-B porosity-depth 90 °C, the reactor was firstly cooled to approximately 20 °C profiles were plotted using the porosity data of the samples using cold water in less than 1 h, and then, the calcite grains with normal pressure and low oil-bearing saturation (oil- were separated from the water. The water pH was tested free, oil trace, fluorescence, and oil patch), and the porosity after the separation of the water from minerals. The reacted 1 3 Depth, km Petroleum Science (2019) 16:729–751 735 Combined Argillaceous Siltstones- Medium sandstones- Pebbly sandstones- Fine Medium-coarse lithology sandstones Fine sandstones Coarse sandstones Sandy conglomerate conglomerate conglomerate 1 1 1 1 1 1 1 (a1) (a2) (a3) (a4) (a5) (a6) (a7) 2 2 2 2 2 2 2 3 3 3 3 3 3 3 4 4 4 4 4 4 4 N=924 N=583 N=7936 N=676 N=1533 N=469 N=3742 5 5 5 5 5 5 5 010203040 010203040 010203040 010203040 010203040 010203040 010203040 Combined Argillaceous Siltsones- Medium sandstones- Pebbly sandstones- Fine Medium-coarse lithology sandstones Fine sandstones Coarse sandstones Sandy conglomerate conglomerate conglomerate 1 1 1 1 1 1 1 (b1) (b2) (b3) (b4) (b5) (b6) (b7) 2 2 2 2 2 2 2 3 3 3 3 3 3 3 4 4 4 4 4 4 4 N=544 N=363 N=3367 N=316 N=511 N=166 N=1461 5 5 5 5 5 5 5 0102030400 10 20 30 40 0102030400 10 20 30 40 0102030400 10 20 30 40 010203040 Porosity, % Porosity, % Porosity, % Porosity, % Porosity, % Porosity, % Porosity, % Fig. 4 Porosity-depth profiles of the sandstone reservoirs in the northern steep slope in the Dongying Sag. a1 Porosity versus depth profiles for the combined lithology; a2–a7 porosity versus depth profiles for a single lithology; b1 porosity versus depth profiles for combined lithology with normal pressure and low hydrocarbon saturation; b2–b7 porosity versus depth profiles for single lithology with normal pressure and low hydro- carbon saturation. The dashed blue lines in a1–a7 are the same as the solid blue lines in b1–b7 calcite minerals were cleaned in DW three times to remove suggests that only a small amount of calcite was dissolved, possible salt precipitated on the mineral surfaces. And the and this can only have resulted in a few secondary pores in reacted calcite minerals were weighed after being dried at the calcite grains (less than 1%); even the dissolved calcite 60 °C for 12 h. was not re-precipitated (Fig. 5). The results of the experi- ments D1–D7 at 90 °C show a similar trend. 3.2 Experimental results and geological implication The results of the experiments B1–B3 show that deion- ized water and saline water with a partial pressure of CO The weight loss and relevant volume changes of the cal- ( p ) at 50 bar can dissolve calcite at 20 °C. A compari- CO cite minerals are presented in Table  1. The experiments son of the results of the experiments B2 and B3 shows a A1–A3 demonstrate that low pH water with acetic acid (pH decrease in the corrosion ability of the acidic water as the = 3.93–3.98) can dissolve calcite at 20 °C. As the water salinity increases. A comparison between the results of the 2+ salinity and the Ca concentration in water increase, the experiments B1 and B3 shows that the calcite–CO interac- dissolution capacity of the acidic water decreases dramati- tions reached dynamic equilibrium in 8 days (maybe in an cally. Even with a high water/rock volume ratio (45:1), the even shorter time) after the dissolution of 0.212 g calcite and ratio between the mass loss after dissolution and the pri- a longer (15 days) exposure of calcite to the CO -charged mary weight of the calcite mineral prior to the experiments water did not result in more dissolution. This result indicates 1 3 Depth, km Depth, km 736 Petroleum Science (2019) 16:729–751 1 3 Table 1 Data of calcite-dissolving experiments at low and high temperatures Expt No. Before interaction p , bar After interaction Weight loss Volume Water/rock T, °C Time, day CO of calcite, g change of volume 2+ Composition of Water pH Water Ca con- Calcite weight, g pH Calcite calcite, % ratio solution volume, salinity, centration, weight, g mL g/L g/L A1 DW + HAC 500 3.97 0 0 30.060 N/A 6.29 29.718 0.283 0.943 45 20 8 A2 DW+HAC + 500 3.93 20 2 30.012 N/A 7.11 29.856 0.156 0.520 45 20 8 NaCl+CaCl A3 DW+HAC + 500 3.98 80 5 30.006 N/A 6.82 29.952 0.054 0.180 45 20 8 NaCl+CaCl B1 DW + NaCl + CaCl 500 8.51 80 5 30.003 50 6.05 29.791 0.212 0.700 45 20 8 B2 DW 500 7.16 0 0 15.007 50 6.92 14.698 0.309 2.059 90 20 15 B3 DW + NaCl + CaCl 500 8.72 80 5 15.000 50 6.33 14.785 0.215 1.433 90 20 15 C1 DW + HAC + NaCl 500 3.97 80 5 29.955 50 6.41 29.259 0.696 2.323 45 20 8 + CaCl D1 DW + HAC 350 3.43 0 0 14.897 N/A 6.66 14.568 0.329 2.208 63 90 3 D2 DW + HAC + NaCl 350 3.44 20 2 14.512 N/A 6.56 14.317 0.141 0.972 65 90 3 + CaCl D3 DW + HAC + NaCl 350 3.46 40 4 14.844 N/A 6.5 14.630 0.214 1.442 63 90 3 + CaCl D7 DW + HAC + NaCl 350 3.46 80 5 15.065 N/A 7.02 15.009 0.056 0.372 63 90 3 + CaCl D5 DW + HAC + NaCl 350 3.46 150 7.5 15.190 N/A 6.13 15.074 0.116 0.764 63 90 3 + CaCl D6 DW + HAC + NaCl 350 3.47 200 10 15.129 N/A 6.4 15.090 0.039 0.258 63 90 3 + CaCl D7 DW + HAC + NaCl 350 3.47 300 15 14.948 N/A 5.28 14.905 0.043 0.288 63 90 3 + CaCl DW distilled water, HAC acetic acid, N/A not applicable Petroleum Science (2019) 16:729–751 737 (a) (b) 10 μm 20 μm (c) (d) 10 μm 20 μm Fig. 5 SEM microphotographs of the calcite grain surfaces prior to and after the experiments. a, b Smooth surface of the polished calcite grain, some intercrystal pores can be identified occasionally (b); c, d dissolution of the polished calcite surface after dissolution experiments that in a relative closed geochemical system with a fixed experiments (Bertier et al. 2006; Liu et al. 2012). As the p , the available water volume dominates the dissolution initial pH values (< 4) of the waters used in the experiments CO volume of the calcite, even if CO is available in sufficient were much lower than those of most formation waters and quantities. Also, with a high water/rock volume ratio (45:1 the water/rock ratios were much higher than those in sub- or 90:1), only a small amount of calcite (less than 2%) was surface rocks (Birkle et al. 2009; Birkle et al. 2002; Egeberg dissolved by the CO -rich water. and Aagaard 1989; Frape et al. 1984; Surdam et al. 1985), A comparison of the results of the experiments C1, A3, we conclude that the calcite dissolution in deeply buried and B1 shows that the coexistence of acetic acid and CO sandstones without a favored pathway (e.g., faults) is likely in saline water promotes more calcite dissolution than with to be weaker than in the experiments. only acetic acid or C O in the saline water. However, no more than 2.5% of the calcite was dissolved in the C1 experi- ments. Overall, the experiments with a high water/rock vol- 4 Aggressive fluids and mass transfer ume ratio, low pH, and sufficient CO resulted in the dissolu- in sediments tion of only a small amount of calcite. As low temperature, low pH, high p , and high water/ 4.1 Pyrolysis experiments of kerogen CO rock ratio cannot generate a large volume of secondary pores by the dissolution of carbonate minerals, it is not likely that Hydrous and anhydrous pyrolysis experiments with pure extensive carbonate dissolution will occur in buried sand- kerogen or source rocks have been used to investigate the stone geochemical systems with high temperature and low maturation of organic matter in source rocks with respect water/rock ratio. Many studies on water–rock interaction to the generation of organic acids and C O (Barth et  al. experiments also support this idea when the data were ana- 1988; Barth et al. 1996; Barth and Bjørlykke 1993). Using lyzed quantitatively, although dissolution does take place worldwide source rocks and different types of kerogens with at low/high temperatures (Weibel et al. 2014). In addition, various total organic carbon (TOC) contents and different the dissolved carbonate minerals were commonly reported maturities, more than 110 pyrolysis experiments have been to be re-precipitated in long-term numerical simulation conducted in the last 40 years to analyze the yield of organic 1 3 738 Petroleum Science (2019) 16:729–751 acids and CO during kerogen maturation (Table 2) (Barth The concentrations of organic acids are lower when et al. 1988; Barth et al. 1996; Barth and Bjørlykke 1993; the temperatures are below 80 °C or above 120 °C due Chen et al. 1994; Kawamura et al. 1986; Kawamura and to the bacterial destruction and thermal destruction of Kaplan 1987; Meng et al. 2008; Zeng et al. 2007; Zhang the short-chained organic acids, respectively (Surdam et al. 2009). The results of the experiments demonstrate that et al. 1989; Surdam and Crossey 1987). The concentra- the maximum yield of acetic acids and total organic acids tion data of the organic acids in the formation waters −3 −3 (TOA) is 0.685 × 10 mol/g TOC and 1.34 × 1 0 mol/g from global petroleum sandstone reservoirs show that TOC, respectively. The experiments with the acetic acids more than 90% of the pore waters contain organic acids −3 yield more than 0.5 × 10 mol/g TOC account for only at concentrations less than 3000 mg/L (Fig. 6a) (Cai approximately 5% of the total experiments, and the experi- et al. 1997; Fisher 1987; Kharaka 1986; MacGowan −3 ments with the TOA yield more than 0.6 × 10 mol/g TOC and Surdam 1988; Meng et al. 2006; Meng et al. 2011; account for 10% of the total experiments. In the pyrolysis Surdam et al. 1989; Surdam and Crossey 1987; Wang experiments, CO has a yield equivalent to (0.30–10.9) × et al. 1995, 2007; Xiao et al. 2005). In the petroliferous −3 10 mol/g TOC, which is higher than that of the organic basins in China, the concentrations of organic acids in acids. Commonly, high TOC and high maturation result in the formation waters are usually less than 2500 mg/L low yields of organic acids and CO of one unit kerogen. (Fig. 6b). With high geothermal gradients (around 35 °C/1 km), the highest concentrations of organic acids 4.2 Acids in pore water developed at the depth of 1500–3500 m in the basins in East China; in contrast, the highest concentrations The dissolution of feldspar grains is a natural consequence developed at the depth of 4500–6000 m in the basins of water–rock interactions under conditions of increasing in West China with low geothermal gradients (approxi- burial depth and temperatures (Giles and De Boer 1990; mately 20 °C/1 km) (Fig. 6b) (Cai et al. 1997; Fisher Taylor et al. 2010). Although organic acids and CO were 1987; Kharaka 1986; MacGowan and Surdam 1988; commonly suggested as the cause of feldspar dissolution Meng et al. 2006; Meng et al. 2011; Surdam et al. 1989; (Giles and De Boer 1989; Schmidt and McDonald 1979a; Surdam and Crossey 1987; Wang et al. 1995, 2007; Surdam et al. 1989; Surdam and Boese 1984), Giles and Xiao et al. 2005). De Boer (1990) suggested that no unusual or special source of acidic pore fluids is required for this dissolution process In rocks with a high mudstone/sandstone ratio (e.g., (Giles and De Boer 1990). To dissolve carbonate minerals 10:1), about 60 mol of acetic acids can be produced in 1 m characterized by retrograde solubility (Giles and De Boer source rocks if an average TOC of 5% in the mudstone and −3 1989), however, there must be a supply of a large amount of an organic acid yield of 0.5 × 10 mol/g TOC (Table 2) acidic water that has the capacity to provide H . are available in the source rocks. Because organic acids concentrate at temperatures of 80–120 °C, most organic (1) Various organic acids from kerogens are present in most acids are assumed to be released from the source rocks to of the formation waters in petroliferous basins. Ace- the reservoirs in the depth interval of 1500–4000 m. From tic acid with a relative content of approximately 80% 1500–4000 m, the sandstone porosities generally decrease dominates the organic acids in most cases (Surdam and from 35% to 15% and the mudstone porosities decrease from Crossey 1987; Surdam et al. 1989; Surdam and Boese 20% to 5% (Gluyas and Cade 1997; Pittman and Larese 1984). It was suggested by Surdam et al. (1984, 1987, 1991; Ramm 1992). As organic acids are water soluble 1989) and Meshri (1986) that organic acids were more (Barth and Bjørlykke 1993), we assume that all the pore aggressive than CO and could be responsible for the water expelled from the mudstones to the sandstone reser- dissolution of silicate and carbonate minerals (Meshri voirs have a high concentration of organic acids (10,000 ppm 1986; Surdam and Crossey 1987; Surdam et al. 1989; acetic acid). In this case, the organic acids expelled to the Surdam and Boese 1984). The leaching of calcite by reservoirs can dissolve only 0.46% volume of calcite with acetic acid can be expressed as CaC O + CH COOH— a thorough consumption of the available acids. In another 3 3 2+ − − Ca + HCO + CH COO . Using the data of the case, if diffusion or hydrocarbon migration can transport 3 3 concentration of organic acid in oilfield waters, Surdam more organic acids to the sandstone reservoirs (Barth and (1984, 1987) further suggested that large volumes of Bjørlykke 1993; Thyne 2001), only 2% volume of calcite can water-soluble organic acids are generated during the be dissolved in the sandstone reservoirs. The organic acids thermocatalytic degradation of kerogen in the range are weak acids and the equilibrium constant of the calcite- −4 of 80–120 °C and the concentration of organic acids leaching reaction by organic acids decreases from 8.5 × 10 −5 can even reach up to 10000 ppm (Surdam et al. 1989; at 25 °C to 7.9 × 10 at 100 °C (Giles and Marshall 1986). Surdam and Crossey 1987; Surdam and Boese 1984). Under constraints of the equilibrium constant, the calcite 1 3 Petroleum Science (2019) 16:729–751 739 Table 2 Pyrolysis experiment data of global source rocks and kerogen. (data from Kawamura et al. 1986; Kawamura and Kaplan 1987; Barth et al. 1988; Barth and Bjørlykke 1993; Chen et al. 1994; Barth et al. 1996; Zeng et al. 2007; Meng et al. 2008; Zhang et al. 2009) Sample loca- Sample type Sample Kerogen type TOC, % R , % CO , Acetic acid, Total organic Publications o 2 −3 −3 tion amount 10 mol/ 10 mol/ acids, −3 gTOC gTOC 10 mol/ gTOC Well C11 in Mudstone 13 II-1 2.46 0.42 – – 0.010–0.081 Meng et al. Huanghua (2008) Depression Es Formation Mudstone 1 – 1.04 0.33 – – 0.175–0.608 Zeng et al. in Dongying (2007) Sag Es Formation Mudstone 1 – 2.11 0.40 – – 0.084–0.220 in Dongying Sag Es Formation Mudstone 1 – 3.70 0.42 – – 0.086–0.128 in Dongying Sag Es Formation Mudstone 1 – 1.73 0.24 – – 0.160–0.445 in Dongying Sag Well Chun11 Mudstone 5 I 3.50 0.32 – – 0.134–0.330 Zhang et al. in Dongying (2009) Sag Well Cao Mudstone 3 II-1 2.29 0.32 – – 0.024–0.177 13-15 in Dongying Sag Well Ying 10 Mudstone 3 II-2 1.19 0.48 – – 0.051–0.341 in Dongying Sag Well YMian4- Mudstone 1 I 1.32 0.36 – – 0.676 5-165 in Dongying Sag Well Lunnan Mudstone 4 II-III 8.04 0.61 – 0.002–0.005 0.010–0.04 Chen et al. 54 in Tarim (1994) Basin Well Lunnan Mudstone 12 II-III 8.04 0.61 – 0.004–0.084 0.011–0.110 54 in Tarim Basin Well Tan26 Mudstone 1 II-III – 0.41 – 0.612 0.700 in Jianghan Basin Green River Kerogen 7 I 2.30 – – 0.007–0.036 0.010–0.048 Kawamura Shale et al. (1986) Monterey Kerogen 2 II 10.0 – – 0.015–0.035 0.023–00060 Formation Monterey Kerogen 1 II – – – 0.025 0.036 Kawamura Formation and Kaplan (1987) Green River Kerogen 1 I – – – 0.04 0.056 Shale Tanner Basin Kerogen 1 II – Immature – 0.149 0.278 Sierra Bog Humic acid 1 III – – – 0.14 0.249 sediments 1 3 740 Petroleum Science (2019) 16:729–751 Table 2 (continued) Sample loca- Sample type Sample Kerogen type TOC, % R , % CO , Acetic acid, Total organic Publications o 2 −3 −3 tion amount 10 mol/ 10 mol/ acids, −3 gTOC gTOC 10 mol/ gTOC Kimmeridge Oil shale 5 – 12.6 Immature – 0.057–0.215 0.104–0.345 Barth et al. oil shale, (1988) Dorset, Upper Juras- sic Jurassic, the Coaly shale 3 – 14.3 Mature – 0.009–0.013 0.011–0.016 Norwegian continental shelf Lower Juras- Coal 3 – 39.6 Immature – 0.069–0.100 0.081–0.123 sic, the Norwegian continental shelf Upper Juras- Mudstone 3 – 5.03 Immature – 0.151–0.284 0.263–0.412 sic, the Norwegian continental shelf Mudstone 3 II 12.60 Immature 2.86–8.73 0.141–0.231 0.252–0.346 Barth and Kimmeridge Bjørlykke ourcrop, Dorset, UK (1993) Kimmeridge, Coal 3 II 5.03 Immature 7.95–10.93 0.154–0.282 0.262–0.414 North Sea Kimmeridge Mudstone 3 II 51.30 0.29 1.65–4.70 0.052–0.116 0.110–0.244 outcrop, Dorset, UK Heather, Mudstone 3 II 6.49 0.40 1.23–2.16 0.142–0.273 0.177–0.341 North Sea The Nor- Mudstone 3 III 14.30 Mature – 0.009–0.013 0.011–0.017 wegian continental shelf The Nor- Coaly shale 3 Coal 39.60 Immature 3.18–4.72 0.069–0.100 0.081–0.124 wegian continental shelf The Nor- Coal 3 Coal 23.10 0.38 0.30–1.99 0.124–0.276 0.160–0.377 wegian continental shelf Western Ger- Coal 3 Coal 70 0.26 1.72–2.41 0.518–0.552 0.609–0.705 many 1 3 Petroleum Science (2019) 16:729–751 741 Table 2 (continued) Sample loca- Sample type Sample Kerogen type TOC, % R , % CO , Acetic acid, Total organic Publications o 2 −3 −3 tion amount 10 mol/ 10 mol/ acids, −3 gTOC gTOC 10 mol/ gTOC Draupne, the Dicarbonated 6 – 3.70–7.19 – 1.00–2.36 0.048–0.455 0.081–0.659 Barth et al. Norwegian mudstone (1996) continental shelf Draupne, the Mudstone 3 – 3.52–6.21 – 1.58–8.31 0.082–0.315 0.181–0.497 Norwegian continental shelf Heather, the Dicarbonated 4 – 1.06–5.49 – 0.77–6.61 0.038–0.399 0.077–0.601 Norwegian mudstone continental shelf Heather, the Mudstone 2 – 1.85–7.79 – 3.45–3.78 0.086–0.125 0.148–0.218 Norwegian continental shelf Brent, he Dicarbonated 2 – 3.46–5.25 – 0.38–1.53 0.085–0.103 0.144–0.151 Norwegian mudstone continental shelf Dulin, the Dicarbonated 2 – 1.32–3.13 – 0.35–10.00 0.008–0.695 0.105–1.349 Norwegian mudstone continental shelf — Not measured (a) Organic acids, ppm (b) Organic acids, ppm 0 2000 4000 6000 8000 10000 0 500 1000 1500 2000 2500 0.5 Basins in East China 1.0 1.5 2.0 2.5 3.0 100 3.5 Basins in 4.0 West China 4.5 Alaska 5.0 Texas Raton Basin 5.5 California Santa Maria Basin Piceance Basin Wamsuttter anticline 6.0 Weshakle Basin Gulf Coast Basin Northern part of Songliao Basin Red Dessert Basin Louisiana Gulf Coast Qikou Sag Yuanyanggou area in Liaohe Basin 6.5 San-Juan Basin Weatern overthrust fault Tabei Basin Xujiaweizi Rift in Songliao Basin San Joaquin Basin Eastern Venezuela Basin Tarim Basin Qingshui Sag in Liaohe Basin 250 7.0 Fig. 6 Concentrations of organic acids in the pore water of sandstone reservoirs in oil and gas basins. a Organic acids in global sedimentary basins; b organic acids in sedimentary basins in China. (data from Kharaka 1986; Fisher 1987; Surdam and Crossey 1987; MacGowan and Sur- dam 1988; Surdam et al. 1989; Wang et al. 1995; Cai et al. 1997; Xiao et al. 2005; Meng et al. 2006; Wang et al. 2007; Meng et al. 2011) 1 3 T, °C Depth, km 742 Petroleum Science (2019) 16:729–751 volume that can be dissolved in the reservoirs is reduced 1984). Because of the constraints of the mass balance significantly. In addition, most source rocks contain consid- calculation, Lundegard et al. (1984) suggested that even erable carbonate minerals and silicate minerals (Ehrenberg if all the C O generated from kerogen was expelled et al. 2012; Giles and Marshall 1986; Taylor et al. 2010); from the source rocks to the sandstones, only 1%–2% these minerals first consume some of the organic acids gen- of secondary porosity could be generated (Lundegard erated in the mudstones, which also decreases the volume et al. 1984). of acids expelled to the reservoirs and the leaching ability of the organic acids in the reservoirs (Barth et al. 1996; Barth In contrast to Schmidt (1979a, b) and Surdam (1984), and Bjørlykke 1993). Smith and Ehrenberg (1989) proposed that the increased CO abundance results in precipitation rather than dis- (2) CO is present in most oil-gas sandstone reservoirs, solution of carbonate minerals at the depth interval with though most natural gas accumulations contain less temperature ranging from 80°C to 120 °C, in which the than 10% C O (Seewald 2003). It was suggested by organic acids have the highest concentrations and control Smith and Ehrenberg (1989), Ribstein et al. (1998), and the alkalinity of the carbonate–silicate–organic acid–car- Seewald (2003) that the C O content in natural gases bonic acid–p system. 2 CO generally increases with increasing temperature and Using numerical simulations with the constraints of burial depth, and the p increases systematically in thermodynamics, Huang et al. (2009) calculated the pH CO the temperature range from 40 to 200 °C (Fig. 7) (Cur- values of different carbonate–H O–CO geochemical sys- 2 2 tis 1978; Ribstein et al. 1998; Schmidt and McDonald tems in the equilibrium state (Fig. 8a) and the dissolution/ 1979a; Seewald 2003; Smith and Ehrenberg 1989). The precipitation volumes of the calcite or dolomite minerals CO in the reservoirs originates from the degradation in these systems at temperatures of 28–235 °C, pressure of of organic matter or from water–rock interactions (Cur- 1–70 MPa, depth of 1–7 km, and a specific molar content tis 1978; Ribstein et al. 1998; Schmidt and McDonald of CO (Fig. 8b–d). The results show that the systems with 1979a; Seewald 2003; Smith and Ehrenberg 1989). a higher C O content have lower pH values and this results In the range of 80–120 °C, the release of C O from in the dissolution of more carbonate minerals at depths kerogen in the source rocks is inevitably one important shallower than 2000 m. At depths deeper than 2000 m, source and it was suggested by Schmidt (1979a, b), however, more carbonate minerals are precipitated in the Surdam (1984), and Surdam and Crossey 1987) that systems with more C O , even if the systems have lower pH this CO source is one of the most important carbonic values of approximately 4.8 (Fig. 8) (Huang et al. 2009). acids for carbonate dissolution (Schmidt and McDonald Using laboratory water–rock interaction experiments, 1979a; Surdam and Crossey 1987; Surdam and Boese Song and Huang (1990) also demonstrated that calcite can be precipitated even when the pH is lower than 5 (Song and Huang 1990). 2 As carbonate minerals are characterized by retrograde solubility, cooling of hot fluids have been suggested to dissolve carbonate minerals during the uplift stage of the formation or during injection of deep hot water to shal- low formations. Using numerical simulations with the constraints of thermodynamics, Yuan et al (2015a, b, c) modeled the calcite dissolution in two systems with tem- perature decreasing from 200 °C to 50 °C (Fig. 9). In the -1 system with fixed p (223 bar) during the cooling pro- CO cesses, 1 kg of water may dissolve 5.01 g calcite (Case-1), -2 while in the system when p decreases from 223 bar at CO 200 °C to 0.32 bar at 50 °C (according to the equation log p = −1.45 + 0.019 T) (Smith and Ehrenberg 1989), -3 CO 40 80 120 160 200 1  kg of water can dissolve only 0.027  g calcite (Case- Temperature, °C 2). In such cases, the pore water in sandstones with 20% porosity can only dissolve calcite (with specific gravity of Fig. 7 Partial pressure of C O ( p ) in sedimentary basins (after 2 CO 2.7 g/cm ) to increase porosity by 0.037% and 0.0002%, Coudrain-Ribstein et al. 1998). The dashed line represents CO fixed respectively, with the occurrence of retrograde dissolution. by equilibrium between calcite, dolomite, chlorite, kaolinite, and chalcedony (Coudrain-Ribstein et al. 1998). The solid line represents fitted line for US Gulf Coast data after Smith and Ehrenberg (1989) 1 3 log p CO 2 Mole, %CO2 = 0.1% Mole,%CO2 = 1.0% Mole,%CO = 10.0% Petroleum Science (2019) 16:729–751 743 3 3 3 (a) pH of Calcite-H O-CO balance system (b) (c) (d) 2 2 ΔV, cm /L ΔV, cm /L ΔV, cm /L 4.65.1 5.66.1 6.67.1 7.6 -0.06 -0.01 0.04 -0.14 -0.07 0 0.07 -0.3 -0.2 -0.1 00.1 0.2 0 0 0 0 Dolomite Dolomite Dolomite 1 1 1 1 Calcite Calcite Calcite 2 2 2 2 3 3 3 3 4 4 4 4 5 5 5 5 6 6 6 6 7 7 7 7 Mole, %CO2 = 0.1% Mole, %CO2 = 1.0% Mole, %CO2 = 10.0% Fig. 8 a Plot of pH values versus depth for CaC O –H O–CO equilibrium systems with different CO contents; b–d volume increment of calcite 3 2 2 2 and dolomite by per liter liquid (V) versus depth for CaC O –H O–CO , CaMg(CO ) –H O–CO systems, the CO  mol fractions are 0.1%, 1%, 3 2 2 3 2 2 2 2 and 10%, respectively, after the systems reached equilibrium. (after Huang et al. 2009) 3 7.0 (a) (b) 6.5 6.0 1 5.5 5.0 4.5 -1 4.0 200 175 150 125 100 75 50 200 175 150 125 100 75 50 Temperature, °C Temperature, °C 10 11 1 (c) (d) HCO3 10 g 9,973 g HCO3 0.1 ++ Ca 0.01 ++ 4.987 g Ca 0.001 4 200 175 150 125 100 75 50 200 175 150 125 100 75 50 Temperature, °C Case 1 Case 2 Temperature, °C Fig. 9 Numerical simulation results of the cooling of hot fluids from 200 to 50 °C in a calcite–CO –H O system with initial log ( p ) values of 2 2 CO 2.35. Case-1: Simulation was conducted with a fixed p ; Case-2: Simulation was conducted with a variable p (Yuan et al. 2015a, b, c) CO CO 2 2 4.3 Buffer system and pH needed for burial are mutually rock buffered (Bjørlykke and Jahren 2012; Hutcheon and Abercrombie 1990; Macquaker et al. 2014; carbonate dissolution Smith and Ehrenberg 1989; Taylor et al. 2010; Turchyn and DePaolo 2011). The carbonate minerals were commonly Diagenetic reactions in intermediate to deep burial regimes 1 3 Fluid components concentration, molal log p Depth, km CO Calcite, g pH 744 Petroleum Science (2019) 16:729–751 suggested to react faster with acids than the aluminosili- without favorable flow conduits (e.g., faults and fractures) cate minerals (Bjørlykke and Jahren 2012). In the buried in the mesodiagenetic stage (Bjørlykke and Jahren 2012; aluminosilicate–carbonate mineral–acid system, however, Ehrenberg et al. 2012; Giles 1987; Taylor et al. 2010). Smith and Ehrenberg (1989), Hutcheon and Abercrombie (1990), and Turchyn and DePaolo (2011) suggested that (1) Advective transfer the aluminosilicate minerals–water interaction rather than the carbonate mineral–water reaction was the main acid- Mass transport of a component by the advective flow in buffering mechanism (Bjørlykke and Jahren 2012; Hutcheon subsurface porous rocks can be expressed by and Abercrombie 1990; Macquaker et al. 2014; Smith and q = qC (1) Ehrenberg 1989; Taylor et al. 2010; Turchyn and DePaolo where q is the advective flux of the species, q is the spe- 2011). The buffer intensity of silicate minerals can be ten cific discharge, and C is the component’s concentration. The times that of calcite in an acidic system at high temperature solubility of calcite is a function of the p and temperature CO (Hutcheon and Abercrombie 1990). The pH of most cur- in the burial sediments, and the calcite solubility is less than rent oil–gas waters is higher than 5.5 due to the buffering 0.01 mol/L in systems at temperatures ranging from 80 °C effect of various aluminosilicate mineral–water interactions (with 1 bar p ) to 160 °C (20 bar p ) (Giles and De Boer CO CO (Birkle et al. 2009; Birkle et al. 2002; Egeberg and Aagaard 2 2 1989). Assuming that a set of sediments has a mudstone/ 1989; Frape et al. 1984; Surdam et al. 1985), and the exten- sandstone ratio of 10:1 and the mudstone porosity decreases sive dissolution of carbonate minerals is unlikely in reser- from 20% to 5% as the burial depth increases from 2000 m to voirs with such a relative weaker acidity. This concept is a 4000 m (Pittman and Larese 1991), all the water in the mud- rather radical departure from the conventional system, but stone units would be expelled to the sandstone units. The it is now being verified by the significant fabric observation water from the mudstone, even with very low salinity, can of extensive feldspar dissolution and no/little carbonate dis- dissolve and remove only approximately 0.05% volume of solution in many buried sandstones (Armitage et al. 2010; the calcite mineral in the sandstone units under the mecha- Baker et al. 2000; Ceriani et al. 2002; Dos Anjos et al. 2000; nism of advective flow. Dutton and Land 1988; Fisher and Land 1987; Girard et al. 2002; Hendry et al. 1996; Milliken et al. 1994; Salem et al. (2) Diffusive transfer 2000; Tobin et al. 2010) and some mudstones (Macquaker et al. 2014; Turchyn and DePaolo 2011). Yuan et al. (2015a, Mass transport by diffusion (M ) in porous rocks can be b, c) proposed the mechanism of selective dissolution of expressed by Fick’s law: feldspars in the presence of carbonate minerals to generate secondary minerals in buried sandstones by organic-original dC M =−D ×  × (2) t 0 CO (Yuan et al. 2015a, b, c). In addition, the dissolution of dX feldspars can, in turn, promote the precipitation of carbon- where M is the diffusion flux, D is the diffusion coefficient t 0 ate minerals (Tutolo et al. 2015). The C–O isotopic data of of solutes in water (cm /s), C is the component’s concentra- carbonate cements developed in subsurface rocks suggest the tion, and θ is the tortuosity factor of the sedimentary rock. generation of organic-derived and inorganic-derived C O . Tortuosity is generally a ratio of pore connectivity length The most carbon in these various types of CO , however, is to sediment sample length; thus, its value is always greater subsequently sequestered by the precipitation of carbonate than 1. In porous sedimentary rocks, the tortuosity of the cements in both source rocks and reservoirs (Curtis 1978; flow path is determined by porosity, permeability, and pore Giles and Marshall 1986; Seewald 2003). structure. Tortuosity can be expressed by Archie’s equation (Archie 1942) as: 4.4 Mass transfer problem 2 1− =  (3) In order to generate enhanced secondary porosity, the solutes where η is an adjustable exponent (Boudreau 1996). The 2+ 2+ − 2− (Ca, Mg, HCO, CO ) released by the dissolution of 3 3 empirical fit value of η reported by Boudreau (1996) is 2.14 carbonate minerals need to be removed from the dissolu- ± 0.03, with an average value of 2.14. Diffusion in a porous tion zone in the sandstone reservoirs (Bjørlykke and Jahren sediment system is much slower than in an equivalent vol- 2012; Ehrenberg et al. 2012; Giles 1987; Taylor et al. 2010). ume of water because the convoluted path the solutes must Advection, diffusion, and convection are the three possible follow to circumvent sediment particles (Boudreau 1996). mechanisms that control the mass transfer in the sedimentary The pore water composition in the middle-deep buried basins. However, none of the advective, diffusive, or convec- sandstones is generally close to saturation with respect to tive mass transfer supports significant transfer of the solutes most minerals after long-term contact of the pore water and released from carbonate dissolution in the buried sandstones 1 3 Petroleum Science (2019) 16:729–751 745 2+ 2+ minerals. The solute concentration gradients (Ca , Mg , were interpreted as secondary pores formed by the dissolu- − 2− HCO , CO ) are generally very low in the sandstone beds tion of carbonate cements (Taylor et al. 2010). Based on 3 3 with relative homogeneous composition (Bjørlykke 2014; the CO /organic acids leaching hypothesis, and the negative Bjørlykke and Jahren 2012), which prevents the large-scale relationship between porosity and the amount of carbonate diffusive transfer of these masses, even in a long geological cements in reservoirs, extensive burial dissolution of carbon- time. ate minerals has also been suggested by many other authors in the last few decades (Dutton and Willis 1998; Gibling (3) Convective transfer et al. 2000; Harris and Bustin 2000; Higgs et al. 2010; Irwin and Hurst 1983; Khidir and Catuneanu 2010; Kordi et al. Thermal convection is a potential mechanism for mass 2011; Mcbride 1988; Shanmugam 1984; Wilkinson et al. transfer in buried sandstones with high porosity and perme- 1997). Similar to Schmidt and McDonald (1979a, b), no ability. Mathematical calculations of thermal convection, convincing petrography evidence on carbonate dissolution however, demonstrated that even thin interbedded layers was provided in these publications. of mudstones within permeable sandstone sequences will split potentially larger convection cells into smaller units 5.2 Papers with convincing petrographic evidence of sandstone beds which may then be too small to exceed the critical Rayleigh number. After extensive compaction Some studies with convincing petrographic evidence of the and cementation, convective circulation of pore water is dissolution of carbonate cements in buried sandstones have not likely to occur in the sandstone beds with interbedded been published. Review of these works suggests that most mudstones characterized by extremely low porosity and of the extensive dissolutions were related to deep hot fluids low permeability (Bjørlykke 1993; Bjørlykke et al. 1988), (Taylor 1996; Taylor et al. 2010) and cold meteoric fresh particularly after the formation of tight marginal cemented water (Bouch et al. 2006; Cavazza et al. 2009; Khidir and barriers formed by precipitation of eodiagenetic carbonate Catuneanu 2003; Poursoltani and Gibling 2011; Yuan et al. cements in the marginal sandstones close to the mud/sand 2017; Zaid 2012), while organic CO leaching resulting in surfaces (Saigal and Bjørlykke 1987). very limited dissolution (Lu et al. 2011; Weedman et al. Overall, large-scale carbonate dissolution is not supported 1996). by any of the mass transfer mechanisms in buried geochemi- cal systems without favorable flow conduits. (1) Dissolution related to deep hot fluids. Taylor (1996, 2010) presented a striking exception in the deeply bur- ied (4.9–5.2 km) Miocene sandstones in the Picaroon 5 Published examples of carbonate field, offshore Texas. The anomalously high porosities dissolution in sandstones (20%–29%) in the sandstone reservoirs are largely a result of the porosity enhancement by the dissolution Many papers on mineral dissolution in buried sandstones of carbonate minerals (Taylor 1996; Taylor et al. 2010). have been published in the last 40 years. After a careful A detailed petrographic study has established evidence analysis of the included petrography evidence on the dissolu- for the partial dissolution of pore-filling calcite cements tion of carbonate minerals, we categorize these publications and detrital carbonate grains in the most porous sands into three groups. (Fig.  2f), and 6%–15% of the calcite cements were estimated to have been removed from the reservoirs. 5.1 Papers lacking convincing petrography However, the aggressive fluids that leached the cements evidence but including hypothesis were not acids originating from kerogen maturation but deep hot fluids with high salinity and high con- Schmidt and McDonald (1979a, b) first proposed the idea centrations of Sr, Ba, Fe, Pb and Zn. The Corsair fault that significant secondary porosity (up to 20%) can be gen- systems played a very important role in introducing erated through burial dissolution of carbonate cements by such hot fluids into the Miocene sandstones. As Taylor CO during the organic maturity stage (Fig. 1) (Schmidt and et al. (2010) suggested, the geological conditions in the McDonald 1979a). In their paper, however, no convincing Picaroon field that provide access to deep fluid sources carbonate dissolution phenomena such as the microscope are somewhat extraordinary (Taylor 1996; Taylor et al. photography in Taylor (1996) or the SEM microphotogra- 2010). phy in Weedman et al. (1996) and Khidir and Catuneanu (2) Dissolution related to meteoric water. Convincing pet- (2003) were presented (Khidir and Catuneanu 2003; Schmidt rographic evidence of carbonate dissolution in sand- and McDonald 1979b; Taylor 1996; Weedman et al. 1996). stones with meteoric freshwater incursion was provided Instead, most intergranular pores without carbonate cements by some studies. The isotopic composition of the car- 1 3 746 Petroleum Science (2019) 16:729–751 bonate cements or the burial history of the rocks sug- presence of carbonate minerals including detrital carbonate gests that the dissolutions were induced by meteoric grains and early precipitated calcite cements. These carbon- freshwater during the early eodiagenetic stage or the ate cements display euhedral crystal faces where they border uplift telodiagenetic stage (Bouch et al. 2006; Cavazza open primary pores, and the detrital carbonate grains show et al. 2009; Khidir and Catuneanu 2003; Poursoltani no corroded fabrics that occur in feldspar grains. Aside from and Gibling 2011; Yuan et al. 2017; Zaid 2012). For the geological examples of buried sandstones, numerical example, Khidir and Catuneanu (2003) presented con- simulation results also demonstrated that the feldspar disso- vincing SEM photomicrographs to show the dissolution lution induced by carbonic acid in the subsurface sandstones of carbonate cements in the Scollard sandstones out- would be accompanied by carbonate precipitation in sys- crop. The sandstones were not buried at depths where tems in the long term, and these relevant carbonate cements the temperature reached 120 °C, and the δ O composi- serve as an analogue of late-stage carbonate cements in the tion of the included calcite cements and relevant cal- subsurface sandstones (Barclay and Worden 2000; Wilson culated water δ O composition suggested a meteoric et al. 2000). origin of the diagenetic fluids. Poursoltani and Gibling (2011) provided an example of the dissolution of car- bonate cements in sandstones with developed fault sys- 6 Conclusions tems that were formed during an uplift period; the cal- cite cements were suggested to be leached by meteoric (1) Four types of selective dissolution assemblages of water. Cavazza et al. (2009) provided excellent outcrop feldspar and carbonate minerals can be identified in photographs, microscope photos, and SEM images to sandstones. A critical eye must be cast on the identifica- show carbonate cement dissolution in the Quaternary tion of mineral dissolution and intergranular secondary marine terraces outcrop sandstones; the dissolution was pores in sandstones so that possible subjective conclu- the leaching result of meteoric flow during the falling sions can be avoided. period of sea level. (2) Petrographic data, porosity data, water–rock experi- (3) Organic CO leaching with weak dissolution. Some ments, geochemical calculations of aggressive fluids, authors have presented convincing petrographic evi- and mass transfer do not support significant mesodia- dence of carbonate dissolution that was induced by genetic carbonate dissolution in buried sandstones. A organic CO originating from the thermal evolution of review of relevant publications suggests that the exten- kerogen. The authors, however, also stated that only sive dissolution of carbonate minerals was generally a small amount of carbonate minerals were dissolved attributed to a high flux of deep hot fluids provided via under the constraints of fluid chemistry modeling or fractures or the meteoric freshwater available during mass balance calculation (Lu et al. 2011; Weedman the eodiagenetic and telodiagenetic stages. et al. 1996). Overall, review of the published papers suggests that the Acknowledgements This study was funded by the Natural Sci- ence Foundation of China Project (Nos. 41602138, 41872140, extensive dissolution of carbonate minerals in the sandstones 41911530189), the National Science and Technology Special Grant was generally attributed to the high flux of deep hot fluids (No. 2016ZX05006-007; No. 2016ZX05006-003), the Fundamen- provided via fractures or the meteoric freshwater available tal Research Funds for the Central Universities (18CX07007A), and during the eodiagenetic and telodiagenetic stages. the State Key Laboratory of Organic Geochemistry, GIGCAS (No. SKLOG-201709). 5.3 Papers with dissolution of feldspars Open Access This article is distributed under the terms of the Crea- but no carbonate tive Commons Attribution 4.0 International License (http://creat iveco mmons.or g/licenses/b y/4.0/), which permits unrestricted use, distribu- Some studies have reported the phenomena of extensive tion, and reproduction in any medium, provided you give appropriate credit to the original author(s) and the source, provide a link to the feldspar dissolution in buried sandstones, but the carbon- Creative Commons license, and indicate if changes were made. ate cements and detrital carbonate grains in the sandstones showed no signs of extensive dissolution (Armitage et al. 2010; Baker et  al. 2000; Ceriani et  al. 2002; Dos Anjos et al. 2000; Dutton and Land 1988; Fisher and Land 1987; References Girard et al. 2002; Hendry et al. 1996; Milliken et al. 1994; Archie GE. 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