- Email: [email protected]
Possible effects of carbonate content in source rocks on fluid composition and chemical reaction — A preliminary result of simulation
Journal of Geochemical Exploration 89 (2006) 450 – 454 www.elsevier.com/locate/jgeoexp
Possible effects of carbonate content in source rocks on fluid composition and chemical reaction — A preliminary result of simulation Jianhui Zeng ⁎, Guoping Bai, Jilin Peng Key Laboratory for Petroleum Accumulation Mechanism, Petroleum University, Ministry of Education, PR China Basin and Reservoir Research Center, China University of Petroleum, Changping 102249, Beijing, PR China Received 13 August 2005; accepted 14 December 2005 Available online 20 March 2006
Abstract Simulations of the interaction between formation water, source rocks and reservoir rocks suggest that the carbonate content of the source rock not only influences the chemical reactions in the system, but also affects the overall porosity and permeability of the reservoir rock itself. A great deal of organic acid is produced during the interaction of formation water with the source rocks, but if the source rock contains high amounts of carbonate, that organic acid will first react with the carbonate. This initial and primary interaction results in the consumption of a great deal of the acid; the end results of this consumptive process area a), a significant decrease in the overall amount of organic acid in the source rock's fluid content and b), a corresponding (past-saturation) increase in the detectable quantities of Ca and Sr. When those same depleted fluids are expelled from the source rocks into the reservoir rock, the small and residual amounts of organic acid will have little or no impact in their new environment; the diluted acid content is simply not strong enough to promote the dissolution of aluminosilicate and carbonate. Moreover, Ca and Sr precipitate as carbonate because of the high content of Ca and Sr in the fluid; this also serves to decrease the porosity and permeability of the reservoir rock. © 2006 Elsevier B.V. All rights reserved. Keywords: Interactions between the formation water, the source rocks and the reservoir rock; Simulation experiments; Carbonate content in the source rocks; Fluid composition
1. Introduction Research has revealed that source rocks can and do produce large quantities of organic acid during their thermal evolution. These organic acids exert great influence on the porosity and permeability of reservoir rocks, ⁎ Corresponding author. Key Laboratory for Petroleum Accumulation Mechanism, Petroleum University, Ministry of Education, PR China. Fax: +86 10 89733423. E-mail address: [email protected] (J. Zeng). 0375-6742/$ - see front matter © 2006 Elsevier B.V. All rights reserved. doi:10.1016/j.gexplo.2005.12.013
and result in the formation of many secondary pores (Surdam et al., 1984, 1989). All source rocks contain carbonate, although the detectable quantity of carbonate varies greatly because such rocks were formed in a variety of sedimentary environments. There have been few studies that seek to resolve the questions of how, and to what extent, carbonate content influences the fluids resulting from interaction between formation water and source rock, nor has there been much discussion of how the results of that interaction affect the porosity and permeability of reservoir rocks. There has been some
J. Zeng et al. / Journal of Geochemical Exploration 89 (2006) 450–454 Table 1 Chemical constituents of the formation water (ppm) Ca
K
Mg
Fe
Al
Na
451
Table 2 Mineral component and character of source rock Sr
Ba
Si
Formation 2.25 19.27 114.50 0.01 0.07 1010 0.07 0.02 4.65 water
research and discussion on pore fluid evolution in source rocks and its effect on the diagenesis of reservoirs (Barth and Bjørlykke, 1993; Scotchman et al., 2002), but again, those studies do not touch on the effect of the carbonate content of the source rock on the compositions of the pore fluid and the chemical reactions in reservoirs. This paper seeks to document, examine and discuss these hitherto largely unexplored areas of research. 2. Materials for experiment The formation water was drawn from the Tertiary Guantao Formation in the Dongying Depression of the Bohai Bay Basin, East China. The TDS is 4000 ppm, and its chemical composition is given in Table 1. The samples of the source rocks (mud rocks) were taken from the Third Section of the Shahejie Formation (Es3) of the Tertiary in the Dongying Depression of the Bohai Bay Basin, and were crushed or ground to 100 mesh. Its mineral components and other characteristics are given in Table 2. The carbonate content in the samples CH 11, CQ 13 and Y 10 vary greatly. Core samples (reservoir rocks) were taken from Well W107 in the Dongying Depression of the Bohai Bay Basin; this formation has a demonstrated depth of 1887.4∼1887.5 m. Samples comprise of siltstone or fine-grained sandstone that originates in the Second Section of the Shahejie formation (Es2) of the Tertiary. Their mineral and chemical components, and their porosity and permeability are nearly identical (Table 3). 3. Experimental methods A series of static simulation experiments were carried out to examine the interaction between the formation water, the source rocks and the reservoir rock, and to provide the reaction solution required for the necessary core flood experiments. Those core flood experiments were performed after the initial and necessary interactive simulations were conducted, and are outlined as follows. A mixture of source rock samples and formation water was placed within a 1000 ml. stainless steel cylindrical vessel. This vessel contained a piston; the mixture is placed on one side of the piston, and a small amount of kerosene in the other. Both sides were connected by a pump that helped maintain a constant
Samples
CH11
CQ13
Y10
Depth (m)
2147– 2156 3.5 I 0.32 17 40
1271– 1279 2.29 II 1 0.32 4 20
2716– 2727 1.19 II 2 0.48 24 20
2 1 42 2 2
2 8 28 0 2
12 7 2 0 0
Total organic carbon(TOC) (%) Kerogen type Ro (%) Illite and smectite mixed layer (%) Montmorillonite/illite and smectite mixed layer (%) Illite (%) Kaolinite (%) Calcite (%) Dolomite (%) Pyrite (%)
pressure within the container as a whole; a registered pressure ranging from 3.0–3.8 Mpa prevented the liquid within from vaporizing at the required experimental temperature of 120 °C. The flow experiment involved placing the core samples in a core-flood experiment, in which the set-up and methods are similar to those used by Larter et al. (2000). The core samples were clamped in a core holder; one end of the holder was connected with the stainless cylindrical vessel that contains the reaction solution, while the other end was linked to a backpressure regulator and an exit for the liquid. The circumferential pressure on the sample was maintained at 30 MPa, and the temperature was maintained at a steady 120 °C. The piston, powered by the kerosene, allowed the reacting solution to pass through the core samples. The experimental conditions are listed in Table 4; the chemical constituents of the fluid were measured by ICP-AES, and the organic acids were tested using a DX-120 ionic chromatography. 4. Experiment results and discussion 4.1. Experiments that examine the interaction between the sample formation water and the sample source rocks A comparative chemical analysis of the pre and postexperimental formation waters reveals that concentrations of Ca, K, Na, Sr and Si increased after interaction Table 3 Basic character of reservoir rock Samples Depth (m) Core Core Porosity Permeability length (m) diameter (%) (× 10 − 3μm2) (cm) W-1 W-2 W-3
1887.42 1887.45 1887.48
6.926 7.041 7.011
2.399 2.490 2.438
23.624 21.961 21.465
28.191 25.191 25.323
452
J. Zeng et al. / Journal of Geochemical Exploration 89 (2006) 450–454
Table 4 Condition of experiments Number of experiment
Solid samples
Weight of solid samples (g)
Reaction solution
Liquid volume (ml)
Water / rock ratio
HT-1 HT-2 HT-3 FT-1
CH11 CQ13 Y10 W-1
300 300 300
750 750 750 300
2.5 2.5 2.5
FT-2
W-2
FT-3
W-3
Formation water Formation water Formation water Reaction solution of HT-1 Reaction solution of HT-2 Reaction solution of HT-3
between the formation water and the source rocks, and that those of Ca and Sr demonstrated the most dramatic increases (the Ca and Sr content increases 17∼34 and 45∼73 times, respectively) (Table 5). The Mg content decreased slightly. Moreover, the Ca and Sr contents show a positive correlation with the carbonate content in the source rocks. The Ca content can be listed as follows: HT-1 N HT-2 N HT-3. Calcium and Sr exist chiefly in the form of carbonate in clastic rocks (sandstone and mud rock), and the fact that their concentrations increased after the interaction would suggest that the carbonate dissolved. This is supported by the following; the higher the Ca and Sr content in the source rocks, the more intensive the dissolution of carbonate, and the higher the concentrations of Ca and Sr in the post-experimental fluids (Tables 2 and 5). Organic acids and CO2 are the chief factors controlling the dissolution of carbonate. Previous research indicates that the interaction of formation water and source rock produces organic acid, and only a little CO2, at maintained temperatures of 120 °C (Surdam et al., 1984). Our experimental data indicates that the dissolution of Ca-and Sr-bearing carbonates by organic
Flow rate (ml/min)
Reaction time (h)
0.02
168 168 168 250
300
0.02
250
300
0.02
250
acids causes a post-experimental change in Ca and Sr content; the measurable chemical ratios in the fluid increased dramatically after the formation water/source rock interaction had taken place. The interaction between formation water and source rock produces a great deal of organic acid. Our data indicates that sample HT-2 gave rise to the highest concentration of acid, while sample HT-1 produced the lowest (Table 5). Generally speaking, the total quantity of organic acids produced after the interaction between formation water and source rock depends on the amount of total organic carbon (TOC) in the source rocks at similar stages of thermal evolution (Barth and Bjørlykke, 1993). Sample CH11 had more TOC than the other two samples, but the organic acid content of HT-1 was less than that of HT-2. The most probable explanation for these disparities ties into the fact that the carbonate content of CH11 is higher than that of CQ13; CH11, and therefore required more organic acid to dissolve the contained minerals. The organic acid content of HT-1 was consequently less than that of HT-2, while the Ca content of HT-1 was far more than that of HT-2 (Tables 2 and 5).
Table 5 Organic acid and ion content in the post-experimental solution (ppm)
Ca K Mg Fe Al Na Sr Ba Si Formic acid Acetic acid Oxalic acid Total organic acid
Formation water
HT-1
HT-2
HT-3
FT-1
FT-2
FT-3
2.25 19.27 114.50 0.01 0.07 1010 0.07 0.02 4.45 0.02 0.26 0.17 0.45
76.75 38.32 64.35 0.01 0.06 1435 3.98 0.10 20.56 0.14 20.7 12.71 33.55
46.67 57.88 82.75 0.02 0.09 1358 5.14 0.08 19.73 0.05 17.21 22.74 40.00
39.83 19.61 34.55 0.01 0.04 1484 3.15 0.06 20.20 0.1 1.76 25.08 26.94
27.63 39.68 46.81 0.03 0.13 1373 2.58 0.07 19.73
44.77 37.89 31.74 0.09 0.10 1305 2.89 0.07 24.35
46.05 34.06 14.83 0.05 0.17 1488 4.42 0.09 16.11
J. Zeng et al. / Journal of Geochemical Exploration 89 (2006) 450–454
Fig. 1. Relationship between the content of Ca and organic acid in the fluid revealed in the simulation experiment demonstrating the interaction between the formation water and the source rock.
A comparison of organic acid content vs. Ca and Sr content in samples HT-1, HT-2 and HT-3 demonstrates a gradual increase in the amounts of acetic acid, a decrease in that of oxalic acid, and an increase in the Ca and Sr content of the post-experimental fluids (Table 5, Fig. 1). It indicates that organic acid reacts as below: CaðSrÞCO3 þ HAC⇔CaðSrÞ2þ þ HCO−3 þ AC− This would seem, therefore, to confirm that different types of organic acids have different effects, and that while the formation of acetic acid has a positive (strong) effect on the dissolution of carbonate, the formation of oxalic acid does not; the more oxalic acid present relative to the proportions of acetic acid, the weaker the dissolution.
453
The above experiments indicate that the interaction between formation water and source rock can produce a lot of organic acid. These organic acids will react with the carbonate contained in the source rock, and will initiate a decrease of those acids and a simultaneous increase in the amounts of Ca and Sr in the postinteractive fluids. As the proportionate carbonate ratio in the source rocks increases, the organic acidic content will gradually decrease; this will result in a gradual increase of Ca and Sr in the post-interactive fluids, even to the point of super-saturation. The fluids are then expelled to the adjacent reservoir, but this is not a beneficial process with respect to the dissolution of aluminosilicate and carbonate; the smaller residual amounts of organic acids and the presence of significant quantities carbonate will result in precipitation, and will adversely affect the porosity and permeability of the reservoir rock. 4.2. The core flood experiments in the interaction between the formation water, the source rocks and the reservoir rock The chemical composition of the fluids before and after the flow experiments show that Ca and Sr concentrations decrease in the fluids after the conduction of flow experiments FT-1 and FT-2; the source rocks involved in those experiments have higher base concentrations of carbonate (Table 5, Fig. 2). These results would seem to indicate that the precipitation of carbonates containing Ca and Sr took place during the flow experiments and resulted in a decrease in the Ca and Sr content of the post-experimental fluids. This is not good insofar as the formation of secondary pores is
Fig. 2. A comparison of the concentrations of the chemical composition in the fluids before and after the flow experiments. Note: Concentration ratio refers to the ratio of each component concentrations before and after the experiments. When it is less than 1.0, it means the components have been precipitated during the experiment, showing a decreased concentration. While it is more than 1.0, it suggests the component has been dissolved during the experiment, showing an increased concentration.
454
J. Zeng et al. / Journal of Geochemical Exploration 89 (2006) 450–454
Table 6 A contrast of porosity and permeability before and after the flow experiments Samples Porosity before flow experiment (%)
Porosity after flow experiment (%)
Permeability before flow experiment (×10− 3μm2)
Permeability after flow experiment (×10− 3μm2)
W-1 W-2 W-3
19.435 20.763 25.869
28.191 25.191 25.323
23.483 23.324 29.978
23.624 21.961 21.465
the fluids will not favor the dissolution of aluminosilicate and carbonate because of low organic acid concentrations; conversely, the high Ca and Sr content will contribute to the precipitation of carbonate, and will result in poor porosity and permeability of the reservoir rock. In conclusion, one should always consider the quantitative carbonate content in the source rock when calculating the effect of organic acids on the transformation of a reservoir. Acknowledgments
concerned; such results may trigger a decrease in the porosity and permeability of the reservoir rock. Experiment FT-1 employed those source rocks that had the highest carbonate content; the precipitation of carbonate is stronger than in any other experiment, and the Ca content of the post-experimental fluid was the lowest measured. It also proves most harmful in terms of the formation of secondary pores and overall porosity and permeability (Table 6). Experiment FT-3, on the other hand, employed those source rocks lowest in carbonate. The carbonate dissolved, and Ca content in the postexperimental fluids increases. It is the most helpful in terms of aiding the formation of secondary pores and for the improvement of the porosity and permeability of the reservoir (Table 6). 5. Conclusions Source rocks will react with formation waters (fluids) during thermal evolution, and will produce a great deal of organic acid. These acids will react with the carbonate in the source rock; that interaction will initiate a drop of the content of the organic acids contained in those fluids. If the carbonate content in the source rock is high, the interactive process will cause the Ca and Sr content of the fluids to increase even past the point of saturation. The excess will be expelled to the adjacent reservoir, but
This work was financially supported by the National Natural Science Foundation of China (Grant No.40472075). We offer heartfelt thanks to Hongyu Jia and Shouchun Zhang for their help with this study. The authors wish to thank two anonymous reviewers for their thoughtful comments and helpful suggestions. References Barth, T., Bjørlykke, K., 1993. Organic acids from source rock maturation: generation potentials transport mechanisms and relevance for mineral diagenesis. Applied Geochemistry 8, 325–337. Larter, S., Bowler, Berni, Clarke, Ed, Wilson, Colin, Moffatt, Brian, Bennett, Barry, Yardley, Gareth, Carruthers, Dan, 2000. An experimental investigation of geo-chromatography during secondary migration of petroleum performed under subsurface conditions with a real rock. Geochemical Transactions 9. Scotchman, I.C., Carr, A.D., Astin, T.R., Kelly, J., 2002. Pore fluid evolution in the Kimmeridge clay formation of the UK Outer Moray Firth: implications for sandstone diagenesis. Marine and Petroleum Geology 19, 247–273. Surdam, R.C., Boese, S.W., Crossey, L.J., 1984. The chemistry of secondary porosity. In: McDonald, D.A., Surdam, R.C. (Eds.), Clastic Diagenesis: AAPG Memoir, vol. 37, pp. 127–151. Surdam, R.C., Crossey, L.J., Svenhagen, E., Heasler, H.P., 1989. Inorganic and organic interaction and sandstone diagenesis. AAPG Bulletin 73 (1), 1–23.
Possible effects of carbonate content in source rocks on fluid composition and chemical reaction — A preliminary result of simulation Jianhui Zeng ⁎, Guoping Bai, Jilin Peng Key Laboratory for Petroleum Accumulation Mechanism, Petroleum University, Ministry of Education, PR China Basin and Reservoir Research Center, China University of Petroleum, Changping 102249, Beijing, PR China Received 13 August 2005; accepted 14 December 2005 Available online 20 March 2006
Abstract Simulations of the interaction between formation water, source rocks and reservoir rocks suggest that the carbonate content of the source rock not only influences the chemical reactions in the system, but also affects the overall porosity and permeability of the reservoir rock itself. A great deal of organic acid is produced during the interaction of formation water with the source rocks, but if the source rock contains high amounts of carbonate, that organic acid will first react with the carbonate. This initial and primary interaction results in the consumption of a great deal of the acid; the end results of this consumptive process area a), a significant decrease in the overall amount of organic acid in the source rock's fluid content and b), a corresponding (past-saturation) increase in the detectable quantities of Ca and Sr. When those same depleted fluids are expelled from the source rocks into the reservoir rock, the small and residual amounts of organic acid will have little or no impact in their new environment; the diluted acid content is simply not strong enough to promote the dissolution of aluminosilicate and carbonate. Moreover, Ca and Sr precipitate as carbonate because of the high content of Ca and Sr in the fluid; this also serves to decrease the porosity and permeability of the reservoir rock. © 2006 Elsevier B.V. All rights reserved. Keywords: Interactions between the formation water, the source rocks and the reservoir rock; Simulation experiments; Carbonate content in the source rocks; Fluid composition
1. Introduction Research has revealed that source rocks can and do produce large quantities of organic acid during their thermal evolution. These organic acids exert great influence on the porosity and permeability of reservoir rocks, ⁎ Corresponding author. Key Laboratory for Petroleum Accumulation Mechanism, Petroleum University, Ministry of Education, PR China. Fax: +86 10 89733423. E-mail address: [email protected] (J. Zeng). 0375-6742/$ - see front matter © 2006 Elsevier B.V. All rights reserved. doi:10.1016/j.gexplo.2005.12.013
and result in the formation of many secondary pores (Surdam et al., 1984, 1989). All source rocks contain carbonate, although the detectable quantity of carbonate varies greatly because such rocks were formed in a variety of sedimentary environments. There have been few studies that seek to resolve the questions of how, and to what extent, carbonate content influences the fluids resulting from interaction between formation water and source rock, nor has there been much discussion of how the results of that interaction affect the porosity and permeability of reservoir rocks. There has been some
J. Zeng et al. / Journal of Geochemical Exploration 89 (2006) 450–454 Table 1 Chemical constituents of the formation water (ppm) Ca
K
Mg
Fe
Al
Na
451
Table 2 Mineral component and character of source rock Sr
Ba
Si
Formation 2.25 19.27 114.50 0.01 0.07 1010 0.07 0.02 4.65 water
research and discussion on pore fluid evolution in source rocks and its effect on the diagenesis of reservoirs (Barth and Bjørlykke, 1993; Scotchman et al., 2002), but again, those studies do not touch on the effect of the carbonate content of the source rock on the compositions of the pore fluid and the chemical reactions in reservoirs. This paper seeks to document, examine and discuss these hitherto largely unexplored areas of research. 2. Materials for experiment The formation water was drawn from the Tertiary Guantao Formation in the Dongying Depression of the Bohai Bay Basin, East China. The TDS is 4000 ppm, and its chemical composition is given in Table 1. The samples of the source rocks (mud rocks) were taken from the Third Section of the Shahejie Formation (Es3) of the Tertiary in the Dongying Depression of the Bohai Bay Basin, and were crushed or ground to 100 mesh. Its mineral components and other characteristics are given in Table 2. The carbonate content in the samples CH 11, CQ 13 and Y 10 vary greatly. Core samples (reservoir rocks) were taken from Well W107 in the Dongying Depression of the Bohai Bay Basin; this formation has a demonstrated depth of 1887.4∼1887.5 m. Samples comprise of siltstone or fine-grained sandstone that originates in the Second Section of the Shahejie formation (Es2) of the Tertiary. Their mineral and chemical components, and their porosity and permeability are nearly identical (Table 3). 3. Experimental methods A series of static simulation experiments were carried out to examine the interaction between the formation water, the source rocks and the reservoir rock, and to provide the reaction solution required for the necessary core flood experiments. Those core flood experiments were performed after the initial and necessary interactive simulations were conducted, and are outlined as follows. A mixture of source rock samples and formation water was placed within a 1000 ml. stainless steel cylindrical vessel. This vessel contained a piston; the mixture is placed on one side of the piston, and a small amount of kerosene in the other. Both sides were connected by a pump that helped maintain a constant
Samples
CH11
CQ13
Y10
Depth (m)
2147– 2156 3.5 I 0.32 17 40
1271– 1279 2.29 II 1 0.32 4 20
2716– 2727 1.19 II 2 0.48 24 20
2 1 42 2 2
2 8 28 0 2
12 7 2 0 0
Total organic carbon(TOC) (%) Kerogen type Ro (%) Illite and smectite mixed layer (%) Montmorillonite/illite and smectite mixed layer (%) Illite (%) Kaolinite (%) Calcite (%) Dolomite (%) Pyrite (%)
pressure within the container as a whole; a registered pressure ranging from 3.0–3.8 Mpa prevented the liquid within from vaporizing at the required experimental temperature of 120 °C. The flow experiment involved placing the core samples in a core-flood experiment, in which the set-up and methods are similar to those used by Larter et al. (2000). The core samples were clamped in a core holder; one end of the holder was connected with the stainless cylindrical vessel that contains the reaction solution, while the other end was linked to a backpressure regulator and an exit for the liquid. The circumferential pressure on the sample was maintained at 30 MPa, and the temperature was maintained at a steady 120 °C. The piston, powered by the kerosene, allowed the reacting solution to pass through the core samples. The experimental conditions are listed in Table 4; the chemical constituents of the fluid were measured by ICP-AES, and the organic acids were tested using a DX-120 ionic chromatography. 4. Experiment results and discussion 4.1. Experiments that examine the interaction between the sample formation water and the sample source rocks A comparative chemical analysis of the pre and postexperimental formation waters reveals that concentrations of Ca, K, Na, Sr and Si increased after interaction Table 3 Basic character of reservoir rock Samples Depth (m) Core Core Porosity Permeability length (m) diameter (%) (× 10 − 3μm2) (cm) W-1 W-2 W-3
1887.42 1887.45 1887.48
6.926 7.041 7.011
2.399 2.490 2.438
23.624 21.961 21.465
28.191 25.191 25.323
452
J. Zeng et al. / Journal of Geochemical Exploration 89 (2006) 450–454
Table 4 Condition of experiments Number of experiment
Solid samples
Weight of solid samples (g)
Reaction solution
Liquid volume (ml)
Water / rock ratio
HT-1 HT-2 HT-3 FT-1
CH11 CQ13 Y10 W-1
300 300 300
750 750 750 300
2.5 2.5 2.5
FT-2
W-2
FT-3
W-3
Formation water Formation water Formation water Reaction solution of HT-1 Reaction solution of HT-2 Reaction solution of HT-3
between the formation water and the source rocks, and that those of Ca and Sr demonstrated the most dramatic increases (the Ca and Sr content increases 17∼34 and 45∼73 times, respectively) (Table 5). The Mg content decreased slightly. Moreover, the Ca and Sr contents show a positive correlation with the carbonate content in the source rocks. The Ca content can be listed as follows: HT-1 N HT-2 N HT-3. Calcium and Sr exist chiefly in the form of carbonate in clastic rocks (sandstone and mud rock), and the fact that their concentrations increased after the interaction would suggest that the carbonate dissolved. This is supported by the following; the higher the Ca and Sr content in the source rocks, the more intensive the dissolution of carbonate, and the higher the concentrations of Ca and Sr in the post-experimental fluids (Tables 2 and 5). Organic acids and CO2 are the chief factors controlling the dissolution of carbonate. Previous research indicates that the interaction of formation water and source rock produces organic acid, and only a little CO2, at maintained temperatures of 120 °C (Surdam et al., 1984). Our experimental data indicates that the dissolution of Ca-and Sr-bearing carbonates by organic
Flow rate (ml/min)
Reaction time (h)
0.02
168 168 168 250
300
0.02
250
300
0.02
250
acids causes a post-experimental change in Ca and Sr content; the measurable chemical ratios in the fluid increased dramatically after the formation water/source rock interaction had taken place. The interaction between formation water and source rock produces a great deal of organic acid. Our data indicates that sample HT-2 gave rise to the highest concentration of acid, while sample HT-1 produced the lowest (Table 5). Generally speaking, the total quantity of organic acids produced after the interaction between formation water and source rock depends on the amount of total organic carbon (TOC) in the source rocks at similar stages of thermal evolution (Barth and Bjørlykke, 1993). Sample CH11 had more TOC than the other two samples, but the organic acid content of HT-1 was less than that of HT-2. The most probable explanation for these disparities ties into the fact that the carbonate content of CH11 is higher than that of CQ13; CH11, and therefore required more organic acid to dissolve the contained minerals. The organic acid content of HT-1 was consequently less than that of HT-2, while the Ca content of HT-1 was far more than that of HT-2 (Tables 2 and 5).
Table 5 Organic acid and ion content in the post-experimental solution (ppm)
Ca K Mg Fe Al Na Sr Ba Si Formic acid Acetic acid Oxalic acid Total organic acid
Formation water
HT-1
HT-2
HT-3
FT-1
FT-2
FT-3
2.25 19.27 114.50 0.01 0.07 1010 0.07 0.02 4.45 0.02 0.26 0.17 0.45
76.75 38.32 64.35 0.01 0.06 1435 3.98 0.10 20.56 0.14 20.7 12.71 33.55
46.67 57.88 82.75 0.02 0.09 1358 5.14 0.08 19.73 0.05 17.21 22.74 40.00
39.83 19.61 34.55 0.01 0.04 1484 3.15 0.06 20.20 0.1 1.76 25.08 26.94
27.63 39.68 46.81 0.03 0.13 1373 2.58 0.07 19.73
44.77 37.89 31.74 0.09 0.10 1305 2.89 0.07 24.35
46.05 34.06 14.83 0.05 0.17 1488 4.42 0.09 16.11
J. Zeng et al. / Journal of Geochemical Exploration 89 (2006) 450–454
Fig. 1. Relationship between the content of Ca and organic acid in the fluid revealed in the simulation experiment demonstrating the interaction between the formation water and the source rock.
A comparison of organic acid content vs. Ca and Sr content in samples HT-1, HT-2 and HT-3 demonstrates a gradual increase in the amounts of acetic acid, a decrease in that of oxalic acid, and an increase in the Ca and Sr content of the post-experimental fluids (Table 5, Fig. 1). It indicates that organic acid reacts as below: CaðSrÞCO3 þ HAC⇔CaðSrÞ2þ þ HCO−3 þ AC− This would seem, therefore, to confirm that different types of organic acids have different effects, and that while the formation of acetic acid has a positive (strong) effect on the dissolution of carbonate, the formation of oxalic acid does not; the more oxalic acid present relative to the proportions of acetic acid, the weaker the dissolution.
453
The above experiments indicate that the interaction between formation water and source rock can produce a lot of organic acid. These organic acids will react with the carbonate contained in the source rock, and will initiate a decrease of those acids and a simultaneous increase in the amounts of Ca and Sr in the postinteractive fluids. As the proportionate carbonate ratio in the source rocks increases, the organic acidic content will gradually decrease; this will result in a gradual increase of Ca and Sr in the post-interactive fluids, even to the point of super-saturation. The fluids are then expelled to the adjacent reservoir, but this is not a beneficial process with respect to the dissolution of aluminosilicate and carbonate; the smaller residual amounts of organic acids and the presence of significant quantities carbonate will result in precipitation, and will adversely affect the porosity and permeability of the reservoir rock. 4.2. The core flood experiments in the interaction between the formation water, the source rocks and the reservoir rock The chemical composition of the fluids before and after the flow experiments show that Ca and Sr concentrations decrease in the fluids after the conduction of flow experiments FT-1 and FT-2; the source rocks involved in those experiments have higher base concentrations of carbonate (Table 5, Fig. 2). These results would seem to indicate that the precipitation of carbonates containing Ca and Sr took place during the flow experiments and resulted in a decrease in the Ca and Sr content of the post-experimental fluids. This is not good insofar as the formation of secondary pores is
Fig. 2. A comparison of the concentrations of the chemical composition in the fluids before and after the flow experiments. Note: Concentration ratio refers to the ratio of each component concentrations before and after the experiments. When it is less than 1.0, it means the components have been precipitated during the experiment, showing a decreased concentration. While it is more than 1.0, it suggests the component has been dissolved during the experiment, showing an increased concentration.
454
J. Zeng et al. / Journal of Geochemical Exploration 89 (2006) 450–454
Table 6 A contrast of porosity and permeability before and after the flow experiments Samples Porosity before flow experiment (%)
Porosity after flow experiment (%)
Permeability before flow experiment (×10− 3μm2)
Permeability after flow experiment (×10− 3μm2)
W-1 W-2 W-3
19.435 20.763 25.869
28.191 25.191 25.323
23.483 23.324 29.978
23.624 21.961 21.465
the fluids will not favor the dissolution of aluminosilicate and carbonate because of low organic acid concentrations; conversely, the high Ca and Sr content will contribute to the precipitation of carbonate, and will result in poor porosity and permeability of the reservoir rock. In conclusion, one should always consider the quantitative carbonate content in the source rock when calculating the effect of organic acids on the transformation of a reservoir. Acknowledgments
concerned; such results may trigger a decrease in the porosity and permeability of the reservoir rock. Experiment FT-1 employed those source rocks that had the highest carbonate content; the precipitation of carbonate is stronger than in any other experiment, and the Ca content of the post-experimental fluid was the lowest measured. It also proves most harmful in terms of the formation of secondary pores and overall porosity and permeability (Table 6). Experiment FT-3, on the other hand, employed those source rocks lowest in carbonate. The carbonate dissolved, and Ca content in the postexperimental fluids increases. It is the most helpful in terms of aiding the formation of secondary pores and for the improvement of the porosity and permeability of the reservoir (Table 6). 5. Conclusions Source rocks will react with formation waters (fluids) during thermal evolution, and will produce a great deal of organic acid. These acids will react with the carbonate in the source rock; that interaction will initiate a drop of the content of the organic acids contained in those fluids. If the carbonate content in the source rock is high, the interactive process will cause the Ca and Sr content of the fluids to increase even past the point of saturation. The excess will be expelled to the adjacent reservoir, but
This work was financially supported by the National Natural Science Foundation of China (Grant No.40472075). We offer heartfelt thanks to Hongyu Jia and Shouchun Zhang for their help with this study. The authors wish to thank two anonymous reviewers for their thoughtful comments and helpful suggestions. References Barth, T., Bjørlykke, K., 1993. Organic acids from source rock maturation: generation potentials transport mechanisms and relevance for mineral diagenesis. Applied Geochemistry 8, 325–337. Larter, S., Bowler, Berni, Clarke, Ed, Wilson, Colin, Moffatt, Brian, Bennett, Barry, Yardley, Gareth, Carruthers, Dan, 2000. An experimental investigation of geo-chromatography during secondary migration of petroleum performed under subsurface conditions with a real rock. Geochemical Transactions 9. Scotchman, I.C., Carr, A.D., Astin, T.R., Kelly, J., 2002. Pore fluid evolution in the Kimmeridge clay formation of the UK Outer Moray Firth: implications for sandstone diagenesis. Marine and Petroleum Geology 19, 247–273. Surdam, R.C., Boese, S.W., Crossey, L.J., 1984. The chemistry of secondary porosity. In: McDonald, D.A., Surdam, R.C. (Eds.), Clastic Diagenesis: AAPG Memoir, vol. 37, pp. 127–151. Surdam, R.C., Crossey, L.J., Svenhagen, E., Heasler, H.P., 1989. Inorganic and organic interaction and sandstone diagenesis. AAPG Bulletin 73 (1), 1–23.