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Comments regarding hydrothermal dolomitization and porosity development in the paper “Formation mechanism of deep Cambrian dolomite reservoirs in the Tarim basin, northwestern China” by Zhu et al. (2015)
Marine and Petroleum Geology 76 (2016) 480e481
Contents lists available at ScienceDirect
Marine and Petroleum Geology journal homepage: www.elsevier.com/locate/marpetgeo
Discussion
Comments regarding hydrothermal dolomitization and porosity development in the paper “Formation mechanism of deep Cambrian dolomite reservoirs in the Tarim basin, northwestern China” by Zhu et al. (2015) Stephen Neville Ehrenberg a, *, Knut Bjørlykke b a b
Department of Petroleum Geosciences, The Petroleum Institute, P.O. Box 2533, Abu Dhabi, United Arab Emirates Department of Geosciences, University of Oslo, P.O. Box 1047, Blindern, Oslo, Norway
a r t i c l e i n f o Article history: Received 23 June 2015 Accepted 25 September 2015
Zhu et al. (2015) present a case study that is interpreted as showing porosity creation in the deep subsurface by hydrothermal dolomitization. Zhu et al. (2015) describe the strata as consisting of finely to coarsely crystalline, dark colored “matrix dolomite” containing dissolution pores and fractures partly filled by coarsely crystalline, light colored “filling dolomite.” The matrix dolomite and are suggested to have formed from seawater in near-surface hypersaline environments (presumably in Cambrian time), whereas the filling dolomites formed from hydrothermal water that moved upward along faults and fractures as a result of magmatic activity during Permian time. Pores in the dolostones “are most likely … related to dissolution by meteoric water near the sequence boundaries” (Zhu et al., 2015, p. 240), but most of the present porosity “can be attributed primarily to hydrothermal dissolution” (Zhu et al., 2015, p. 240). We conclude, however, that (1) the data in this study do not support the interpretation of hydrothermal dolomitization and (2) compelling evidence is lacking for increase in total porosity by during deep burial. (1) Hydrothermal dolomitization has not been demonstrated because the data do not show that the temperatures of the dolomitizing waters exceeded the ambient formation
* Corresponding author. E-mail addresses: [email protected] (S.N. Ehrenberg), knut.bjorlykke@ geologi.uio.no (K. Bjørlykke). http://dx.doi.org/10.1016/j.marpetgeo.2015.09.008 0264-8172/© 2015 Elsevier Ltd. All rights reserved.
temperature, as is required by the definition of this term (Machel and Lonnee, 2002). Our point is that, although hydrothermal conditions may well have occurred, this has not been shown to be the case. The fluid inclusion temperatures (80e160 C) are not greater than the present bottom-hole temperature and are thus within the range than can be expected during the burial history. High and variable iron contents in dolomite and the presence of saddle morphology cannot be considered to be evidence of hydrothehermal activity. The 87Sr/86Sr values for both the matrix and the filling dolomites are close to 0.709, which is the approximate composition of Cambrian seawater (McArthur et al., 2001). This similarity supports the interpretation of Zhu et al. (2015) that the matrix dolomite formed shortly after deposition. However, the filling dolomite also has 87Sr/86Sr, of approximately 0.709, consistent with either formation from Cambrian seawater or formation from ions supplied by diffusion from the enclosing dolostone. The interpretation of Zhu et al. (2015) that the filling dolomite formed in Permian time would require a remarkable coincidence for the 87Sr/86Sr values to approximately match the composition of Cambrian seawater. PostCambrian seawater had much lower 87Sr/86Sr, with values near 0.709 occurring again only near modern time (McArthur et al., 2001). We suggest that an interpretation more consistent with the data is that the filling dolomite cement formed from ions
S.N. Ehrenberg, K. Bjørlykke / Marine and Petroleum Geology 76 (2016) 480e481
supplied mostly from the enclosing dolostone at some unknown time during the burial history. (2) Porosity increase during deep burial has also not been demonstrated. The only actual evidence presented by Zhu et al. (2015) for this is the data for the six samples listed in their Table 1, for which the porosity values of 0.6e9.1% show a positive correlation with depths ranging from 7104.7 to 8407.56 m. This correlation is schematically represented in their Fig. 11 as a linear trend of porosity increase with depth from 3% at 5.5 km to 10% at 9 km, which is proposed to be a general relationship describing the Cambrian dolostones of the Tarim basin. To begin with, changes in porosity with depth can, in general, reflect changes in the primary sediment composition and depositional facies in addition to changes in diagenetic conditions during burial. Furthermore, the reported porosity values (and therefore the generalized trend in Fig. 11 of Zhu et al., 2015) are of doubtful significance because it is not established that these values are representative of the stratigraphic section. The use of only six samples to represent 1.3 km of carbonate strata is implausible, especially when the method and criteria of selection of these samples are not mentioned. The extrapolation of this “trend” from 1.3 km (7.1e8.4 km) to a vertical interval of 3.5 km (5.5e9 km) makes the implausibility all the greater. Porosity values in carbonate reservoirs typically display wide variations at any given depth, reflecting lithologic heterogeneity, such that only average values of large numbers of individual measurements are acceptable for defining meaningful trends as a function of depth (as illustrated, for example, by Schmoker and Hally, 1982). The acousticelog profile in Fig. 6 of Zhu et al. (2015) also shows no apparent trend of porosity increase from 6.9 to 8.4 km. We are aware that acoustic velocity is relatively insensitive to vuggy porosity (Schlumberger, 1972). But tools such as the density or neutron logs could be used to show the purported porosity trend, and this confirmation is notably lacking. We also observe that very little information is provided about the porosity measurements or the samples measured. The text (p.236) states only that “The porosity and permeability of selected dolomite cores were measured.” If these measurements were made on plug samples, then the degree to which the values are representative of the cores from which they were taken is doubtful, in view of the heterogeneous distribution of the visible pores in the core photographs in Fig. 6 of Zhu et al. (2015). We conclude, therefore, that, in contrast to the well documented trend of porosity decrease with depth from Schmoker and Hally (1982) shown in Fig. 11, the trend line for the deep Cambrian dolomites in well TS1 has no documented relationship to reality. Despite the uncertainty regarding the trend portrayed in Fig. 11 of Zhu et al. (2015), the existence of individual porosity values as high as 9% at great depth in carbonate reservoirs is consistent with the global compilation of average porosity values from producing carbonate reservoirs reported by Ehrenberg and Nadeau (2005) and more specifically for the Precambrian to Silurian part of this dataset reported by Ehrenberg et al. (2009) in their Fig. 2J. Downward extrapolation of the trends from the above compilations would indicate, however, that average values as high as 9% porosity in carbonate reservoirs at >8 km depth should be highly exceptional. The key question to be asked here is not whether such porosity exists, but how it was formed, and none of the information presented by Zhu et al. (2015) indicates that total porosity in the Cambrian dolostones of the Tarim basin has increased by dissolution during burial. As previously articulated by Loucks (2003) and Ehrenberg et al. (2012), the fact that the pore spaces in a dolostone
481
are enclosed by cement crystals that formed at high temperatures does not necessarily indicate that the pore spaces themselves also formed at high temperatures. Ehrenberg et al. (2012) suggested that deep hydrothermal dolomitization can be expected to result in porosity destruction by cementation rather than net porosity increase by dissolution, even in situations (generally to be expected at shallow depths) where porosity was created by extensional opening of tectonic fractures. Any increase in carbonate porosity due to net dissolution of minerals requires large fluxes of water undersaturated with respect to dolomite or calcite. Calculations show that unrealistically high fluid fluxes are required to significant increase porosity by advective flow in sedimentary basins where the pore water would be in equilibrium with carbonate minerals (Bjørlykke and Jahren, 2012). The requirements for large scale thermal convection are rarely met except very close to igneous intrusions (Bjørlykke et al., 1988). A further consideration that inveighs against the viability of deep exploration targets, whether in the Tarim basin or elsewhere, is the statistical evidence presented by Nadeau et al. (2005) and Nadeau (2011) showing that few reservoirs at temperatures greater than 120 C contain commercial quantities of oil or gas. The information that only “small amounts of liquid hydrocarbons were recovered from the Cambrian dolomite cores at depths of 8406.4 and 8407.5 m” (Zhu et al., 2015, p. 243) is consistent with the expectation that such fluids will be subject to a high probability of leakage due to seal failure in deep, high-temperature reservoirs. In conclusion, we advise against the use of the results presented by Zhu et al. (2015) to support the porosity increase in carbonate strata by hydrothermal dolomitization during deep burial. The authors have not demonstrated that this is the case in the reservoirs of the Tarim basin, and the available literature shows that this has rarely, if ever, been demonstrated to have occurred elsewhere (Ehrenberg et al., 2012).
References Bjørlykke, K., Mo, A., Palm, E., 1988. Modelling of thermal convection in sedimentary basins and its relevance to diagenetic reactions. Mar. Pet. Geol. 5, 338e351. Bjørlykke, K., Jahren, J., 2012. Open or closed geochemical systems during diagenesis in sedimentary basins: constraints on mass transfer during diagenesis and the prediction of porosity in sandstone and carbonate reservoirs. AAPG Bull. 96, 2193e2214. Ehrenberg, S.N., Nadeau, P.H., 2005. Sandstone versus carbonate petroleum reservoirs: a global perspective on porosity-depth and porosity-permeability relationships. AAPG Bull. 89, 435e445. Ehrenberg, S.N., Nadeau, P.H., Steen, Ø., 2009. Petroleum reservoir porosity versus depth: influence of geological age. AAPG Bull. 93, 1281e1296. Ehrenberg, S.N., Walderhaug, O., Bjørlykke, K., 2012. Carbonate porosity creation by mesogenetic dissolution: reality or illusion? AAPG Bull. 96, 217e233. Loucks, R.G., 2003. Origin of Lower Ordovician Ellenburger Group brecciated and fractured reservoirs in west Texas: paleocave, thermobaric, tectonic, or all of the above? AAPG Search and Discovery article 90013. In: AAPG Annual Meeting, Salt Lake City, Utah, May 11e14, 2003 (accessed 01.05.11.). Machel, H.G., Lonnee, J., 2002. Hydrothermal dolomite - a product of poor definition and imagination. Sediment. Geol. 152, 163e171. McArthur, J.M., Howarth, R.J., Bailey, T.R., 2001. Strontium isotope stratigraphy: LOWESS version 3: best fit to the marine Sr-isotope curve for 0-509 Ma and accompanying lokk-up table for deriving numerical age. J. Geol. 109, 155e170. Nadeau, P.H., Bjorkum, P.A., Walderhaug, O., 2005. Petroleum system analysis: impact of shale diagenesis on reservoir fluid pressure,hydrocarbon migration, , A.G., Vining, B.A. (Eds.), Petroleum Geology: and biodegradation risks. In: Dore North-West Europe and Global Perspectivesdproceedings of the 6th Petroleum Geology Conference. The Geological Society, London, pp. 1267e1274. Nadeau, P.H., 2011. Earth's energy “Golden Zone”: a synthesis from mineralogical research. Clay Miner. 46, 1e24. Schlumberger, 1972. Log Interpretationdprinciples, vol. 1. Schlumberger Limited, New York, p. 113. Schmoker, J.W., Hally, R.B., 1982. Carbonate porosity versus depth: a predictable relation for South Florida. AAPG Bull. 66, 2561e2570. Zhu, D., Meng, Q., Jin, Z., Liu, Q., Hu, W., 2015. Formation mechanism of deep Cambrian dolomite reservoirs in the Tarim basin, northwestern China. Mar. Pet. Geol. 59, 232e244.
Contents lists available at ScienceDirect
Marine and Petroleum Geology journal homepage: www.elsevier.com/locate/marpetgeo
Discussion
Comments regarding hydrothermal dolomitization and porosity development in the paper “Formation mechanism of deep Cambrian dolomite reservoirs in the Tarim basin, northwestern China” by Zhu et al. (2015) Stephen Neville Ehrenberg a, *, Knut Bjørlykke b a b
Department of Petroleum Geosciences, The Petroleum Institute, P.O. Box 2533, Abu Dhabi, United Arab Emirates Department of Geosciences, University of Oslo, P.O. Box 1047, Blindern, Oslo, Norway
a r t i c l e i n f o Article history: Received 23 June 2015 Accepted 25 September 2015
Zhu et al. (2015) present a case study that is interpreted as showing porosity creation in the deep subsurface by hydrothermal dolomitization. Zhu et al. (2015) describe the strata as consisting of finely to coarsely crystalline, dark colored “matrix dolomite” containing dissolution pores and fractures partly filled by coarsely crystalline, light colored “filling dolomite.” The matrix dolomite and are suggested to have formed from seawater in near-surface hypersaline environments (presumably in Cambrian time), whereas the filling dolomites formed from hydrothermal water that moved upward along faults and fractures as a result of magmatic activity during Permian time. Pores in the dolostones “are most likely … related to dissolution by meteoric water near the sequence boundaries” (Zhu et al., 2015, p. 240), but most of the present porosity “can be attributed primarily to hydrothermal dissolution” (Zhu et al., 2015, p. 240). We conclude, however, that (1) the data in this study do not support the interpretation of hydrothermal dolomitization and (2) compelling evidence is lacking for increase in total porosity by during deep burial. (1) Hydrothermal dolomitization has not been demonstrated because the data do not show that the temperatures of the dolomitizing waters exceeded the ambient formation
* Corresponding author. E-mail addresses: [email protected] (S.N. Ehrenberg), knut.bjorlykke@ geologi.uio.no (K. Bjørlykke). http://dx.doi.org/10.1016/j.marpetgeo.2015.09.008 0264-8172/© 2015 Elsevier Ltd. All rights reserved.
temperature, as is required by the definition of this term (Machel and Lonnee, 2002). Our point is that, although hydrothermal conditions may well have occurred, this has not been shown to be the case. The fluid inclusion temperatures (80e160 C) are not greater than the present bottom-hole temperature and are thus within the range than can be expected during the burial history. High and variable iron contents in dolomite and the presence of saddle morphology cannot be considered to be evidence of hydrothehermal activity. The 87Sr/86Sr values for both the matrix and the filling dolomites are close to 0.709, which is the approximate composition of Cambrian seawater (McArthur et al., 2001). This similarity supports the interpretation of Zhu et al. (2015) that the matrix dolomite formed shortly after deposition. However, the filling dolomite also has 87Sr/86Sr, of approximately 0.709, consistent with either formation from Cambrian seawater or formation from ions supplied by diffusion from the enclosing dolostone. The interpretation of Zhu et al. (2015) that the filling dolomite formed in Permian time would require a remarkable coincidence for the 87Sr/86Sr values to approximately match the composition of Cambrian seawater. PostCambrian seawater had much lower 87Sr/86Sr, with values near 0.709 occurring again only near modern time (McArthur et al., 2001). We suggest that an interpretation more consistent with the data is that the filling dolomite cement formed from ions
S.N. Ehrenberg, K. Bjørlykke / Marine and Petroleum Geology 76 (2016) 480e481
supplied mostly from the enclosing dolostone at some unknown time during the burial history. (2) Porosity increase during deep burial has also not been demonstrated. The only actual evidence presented by Zhu et al. (2015) for this is the data for the six samples listed in their Table 1, for which the porosity values of 0.6e9.1% show a positive correlation with depths ranging from 7104.7 to 8407.56 m. This correlation is schematically represented in their Fig. 11 as a linear trend of porosity increase with depth from 3% at 5.5 km to 10% at 9 km, which is proposed to be a general relationship describing the Cambrian dolostones of the Tarim basin. To begin with, changes in porosity with depth can, in general, reflect changes in the primary sediment composition and depositional facies in addition to changes in diagenetic conditions during burial. Furthermore, the reported porosity values (and therefore the generalized trend in Fig. 11 of Zhu et al., 2015) are of doubtful significance because it is not established that these values are representative of the stratigraphic section. The use of only six samples to represent 1.3 km of carbonate strata is implausible, especially when the method and criteria of selection of these samples are not mentioned. The extrapolation of this “trend” from 1.3 km (7.1e8.4 km) to a vertical interval of 3.5 km (5.5e9 km) makes the implausibility all the greater. Porosity values in carbonate reservoirs typically display wide variations at any given depth, reflecting lithologic heterogeneity, such that only average values of large numbers of individual measurements are acceptable for defining meaningful trends as a function of depth (as illustrated, for example, by Schmoker and Hally, 1982). The acousticelog profile in Fig. 6 of Zhu et al. (2015) also shows no apparent trend of porosity increase from 6.9 to 8.4 km. We are aware that acoustic velocity is relatively insensitive to vuggy porosity (Schlumberger, 1972). But tools such as the density or neutron logs could be used to show the purported porosity trend, and this confirmation is notably lacking. We also observe that very little information is provided about the porosity measurements or the samples measured. The text (p.236) states only that “The porosity and permeability of selected dolomite cores were measured.” If these measurements were made on plug samples, then the degree to which the values are representative of the cores from which they were taken is doubtful, in view of the heterogeneous distribution of the visible pores in the core photographs in Fig. 6 of Zhu et al. (2015). We conclude, therefore, that, in contrast to the well documented trend of porosity decrease with depth from Schmoker and Hally (1982) shown in Fig. 11, the trend line for the deep Cambrian dolomites in well TS1 has no documented relationship to reality. Despite the uncertainty regarding the trend portrayed in Fig. 11 of Zhu et al. (2015), the existence of individual porosity values as high as 9% at great depth in carbonate reservoirs is consistent with the global compilation of average porosity values from producing carbonate reservoirs reported by Ehrenberg and Nadeau (2005) and more specifically for the Precambrian to Silurian part of this dataset reported by Ehrenberg et al. (2009) in their Fig. 2J. Downward extrapolation of the trends from the above compilations would indicate, however, that average values as high as 9% porosity in carbonate reservoirs at >8 km depth should be highly exceptional. The key question to be asked here is not whether such porosity exists, but how it was formed, and none of the information presented by Zhu et al. (2015) indicates that total porosity in the Cambrian dolostones of the Tarim basin has increased by dissolution during burial. As previously articulated by Loucks (2003) and Ehrenberg et al. (2012), the fact that the pore spaces in a dolostone
481
are enclosed by cement crystals that formed at high temperatures does not necessarily indicate that the pore spaces themselves also formed at high temperatures. Ehrenberg et al. (2012) suggested that deep hydrothermal dolomitization can be expected to result in porosity destruction by cementation rather than net porosity increase by dissolution, even in situations (generally to be expected at shallow depths) where porosity was created by extensional opening of tectonic fractures. Any increase in carbonate porosity due to net dissolution of minerals requires large fluxes of water undersaturated with respect to dolomite or calcite. Calculations show that unrealistically high fluid fluxes are required to significant increase porosity by advective flow in sedimentary basins where the pore water would be in equilibrium with carbonate minerals (Bjørlykke and Jahren, 2012). The requirements for large scale thermal convection are rarely met except very close to igneous intrusions (Bjørlykke et al., 1988). A further consideration that inveighs against the viability of deep exploration targets, whether in the Tarim basin or elsewhere, is the statistical evidence presented by Nadeau et al. (2005) and Nadeau (2011) showing that few reservoirs at temperatures greater than 120 C contain commercial quantities of oil or gas. The information that only “small amounts of liquid hydrocarbons were recovered from the Cambrian dolomite cores at depths of 8406.4 and 8407.5 m” (Zhu et al., 2015, p. 243) is consistent with the expectation that such fluids will be subject to a high probability of leakage due to seal failure in deep, high-temperature reservoirs. In conclusion, we advise against the use of the results presented by Zhu et al. (2015) to support the porosity increase in carbonate strata by hydrothermal dolomitization during deep burial. The authors have not demonstrated that this is the case in the reservoirs of the Tarim basin, and the available literature shows that this has rarely, if ever, been demonstrated to have occurred elsewhere (Ehrenberg et al., 2012).
References Bjørlykke, K., Mo, A., Palm, E., 1988. Modelling of thermal convection in sedimentary basins and its relevance to diagenetic reactions. Mar. Pet. Geol. 5, 338e351. Bjørlykke, K., Jahren, J., 2012. Open or closed geochemical systems during diagenesis in sedimentary basins: constraints on mass transfer during diagenesis and the prediction of porosity in sandstone and carbonate reservoirs. AAPG Bull. 96, 2193e2214. Ehrenberg, S.N., Nadeau, P.H., 2005. Sandstone versus carbonate petroleum reservoirs: a global perspective on porosity-depth and porosity-permeability relationships. AAPG Bull. 89, 435e445. Ehrenberg, S.N., Nadeau, P.H., Steen, Ø., 2009. Petroleum reservoir porosity versus depth: influence of geological age. AAPG Bull. 93, 1281e1296. Ehrenberg, S.N., Walderhaug, O., Bjørlykke, K., 2012. Carbonate porosity creation by mesogenetic dissolution: reality or illusion? AAPG Bull. 96, 217e233. Loucks, R.G., 2003. Origin of Lower Ordovician Ellenburger Group brecciated and fractured reservoirs in west Texas: paleocave, thermobaric, tectonic, or all of the above? AAPG Search and Discovery article 90013. In: AAPG Annual Meeting, Salt Lake City, Utah, May 11e14, 2003 (accessed 01.05.11.). Machel, H.G., Lonnee, J., 2002. Hydrothermal dolomite - a product of poor definition and imagination. Sediment. Geol. 152, 163e171. McArthur, J.M., Howarth, R.J., Bailey, T.R., 2001. Strontium isotope stratigraphy: LOWESS version 3: best fit to the marine Sr-isotope curve for 0-509 Ma and accompanying lokk-up table for deriving numerical age. J. Geol. 109, 155e170. Nadeau, P.H., Bjorkum, P.A., Walderhaug, O., 2005. Petroleum system analysis: impact of shale diagenesis on reservoir fluid pressure,hydrocarbon migration, , A.G., Vining, B.A. (Eds.), Petroleum Geology: and biodegradation risks. In: Dore North-West Europe and Global Perspectivesdproceedings of the 6th Petroleum Geology Conference. The Geological Society, London, pp. 1267e1274. Nadeau, P.H., 2011. Earth's energy “Golden Zone”: a synthesis from mineralogical research. Clay Miner. 46, 1e24. Schlumberger, 1972. Log Interpretationdprinciples, vol. 1. Schlumberger Limited, New York, p. 113. Schmoker, J.W., Hally, R.B., 1982. Carbonate porosity versus depth: a predictable relation for South Florida. AAPG Bull. 66, 2561e2570. Zhu, D., Meng, Q., Jin, Z., Liu, Q., Hu, W., 2015. Formation mechanism of deep Cambrian dolomite reservoirs in the Tarim basin, northwestern China. Mar. Pet. Geol. 59, 232e244.