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Organic acids in reservoir waters—Relationship with inorganic ion composition and interactions with oil and rock
A ~ m t~OW~ G ~ , t r y 19S9"
Org. Geochem. Vol. 16, Nos 1-3, pp. 489-496, 1990 Printed in Great Britain. All fights reserved
0146-6380/90$3.00+ 0.00 Copyright© 1990PergamonPressplc
Organic acids in reservoir waters--Relationship with inorganic ion composition and interactions with oil and rock TANJA BARTn, ANNE EVA BORGUNDand MONA Pdts Department of Chemistry, University of Bergen, Allegt. 41, N-5007 Bergen, Norway (Received 19 September 1989; accepted 20 March 1990)
Ala~tract--Though the existence of organic acid anions in reservoir waters is well documented, their influence on the multiphase water-rock-oil interactions is not well understood. An overview of several projects directed at some of these aspects is presented. The ionic composition of formation waters from the Norwegian Continental Shelf is analysed by multivariate data analysis to discover correlations between organic acid anion concentrations, inorganic ion composition and reservoir conditions. The effects of realistic levels of aqueous acids are investigated experimentally for migration relevant systems. The partitioning of organic acids between oil and water phases is determined, and their influence on end-point relative permeabilities and breakthrough and irreducible saturations of oil in reservoir type rocks is measured. The effects of organic acid anion levels on mineral dissolution is investigated for two types of sandstone cores, showing significant effects for a mixed sandstone. Key words--formation waters, organic acids, migration, mineral dissolution
INTRODUCTION The occurrence of short-chain organic acids in formation waters from oil-containing reservoirs has been known for a long time, and the advent of modern analytical methods has given the possibility of characterising and quantifying this group of compounds. After the initial work of Carothers and Kharaka (1978), much effort has been used in mapping their occurrence in formation waters, especially of the American continents (Fisher, 1987; Means and Hubbard, 1987; Hanor and Workman, 1986). Acetic acid anions are the major species in most formation waters under conditions that preclude biodegradation, while the higher homologs are found in decreasing concentrations. Our laboratory has performed a similar mapping of the levels of organic acid anions in produced waters from the Norwegian continental shelf (Barth, 1987a; Barth, 1990), with the same general result. Hydrous pyrolysis of immature source rocks has shown that organic acids are generated together with the petroleum compounds in kerogen matu. ration reactions, and can be recovered from the aqueous phase in artificial maturation experiments (Kawamura et al., 1986; Lundegard and Senftle, 1987; Barth et al., 1987). The artificially generated organic acids show a pattern of homolog composition similar to that which is found in reservoir waters. While there is general agreement on the occurrence and source of organic acid anions in formation waters, their importance for chemical equilibria and physical properties of the complex system of formation waters, oil and minerals in reservoir rock is 489
still being explored. This paper gives a brief presentation of our current projects in this field. Several approaches are used, and the aim is to discover in what type of heterogenous interactions the organic acids participate. The knowledge of the distribution of compositions and concentrations of organic acids in different natural formation waters provide the basis for all consideration of their importance in geological systems. Our grasp of the information available from these systems must therefore be developed as far as possible. For this purpose multivariate methods for data exploration and statistical analysis are very suitable, as they can provide an overview of correlation between properties in the whole complex system of chemical compositions and reservoir data for the formation waters. Here, principal component analysis (PCA) has been used to analyse the relationship between organic acid levels, inorganic ionic composition and reservoir conditions for waters from reservoir on the Norwegian continental shelf. In addition, increased understanding of the dynamic relationships between oil, water and mineral phases is necessary, and can best be investigated under controlled conditions in the laboratory. In order to evaluate the possible transport mechanisms of the organic acid compounds from the source to the reservoir, the partitioning of water soluble organic acids between crude oils and water phases with a content of inorganic ions comparable to a typical North Sea formation water has been determined. Two-phase flow measurements on selected core types are used to see whether the content of organic acid anions in the water influences the flow properties of
490
TANJABARTHet al.
the mobile phases or their interactions. In these experiments, the irreducible saturations of oil and water and end-point relative permeabilities (for deftnition of physical parameters see e.g. Donaldson et al., 1985) have been determined for different combinations of sandstone and carbonate rock, refined and crude oils and formation waters with or without organic acid anions added. Together with the partition experiments, this gives information on the transport mechanism of organic acids from source to reservoir, and the possible influence the acid content can have on the multiphase flow properties of the water-oil-rock system. Finally, a major point of interest is the possible effect of organic acid anions on the solubilities of different minerals (Surdam et al., 1989; Surdam and MacGowan, 1987; MacGowan and Surdam, 1988; Bennet and Siegel, 1987) where large effects are suggested by some authors. In addition to analysis of the data from real formation waters aimed at registering such effects, we have carried out laboratory investigations under controlled conditions• Using a recirculating system kept at reservoir temperature, reservoir rock cores have been flushed with formation waters with and without added acetate and propanate, and the levels of Si, Ca and A1 ions in solution have been determined at regular intervals. EXPERIMENTAL
Data analysis of formation waters
Norwegian
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A complete description of the data set and multivariate data exploration by principal component analysis is given in Barth (1990). The data set is given in Table 1 and the main conclusions are referred to in the discussion.
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Partition of organic acids between formation water and crude oil A synthetic formation water was prepared (3.5% NaCI, 0.5% CaCI2, 0.3% MgCI2, 0.08% NaHCO3, 0.04% KCI and 0.009% BaCI2). Acetic, propanoic, octanoic and methyl-benzoic acid anions were added to portions of the water to give a typical reservoir concentration--0.2-2mM; precise initial concentrations for each solution given in Table 2. The ensuing solutions were split in two and the biocide sodium azide (NAN3) was added to one half. 5 ml portions of the solutions were transferred to 12 screw-topped glass tubes. To eight of the tubes 5 ml of a North Sea medium light crude oil was added. The capped tubes were shaken well by hand, and 4 of them were also placed in an ultrasound bath for 2 min. The samples were allowed to equilibrate at room temperature for 23 days before determination of organic acid anion content in the water phase. The analysis was performed by isotachophoresis (ITP) as described in Barth (1987b). Previous experiments where formation water without organic acids was
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Organic acids in reservoir waters
491
Table 2. Distribution of organic acids between synthetic brine and crude oil. Concentration of organic acids in the aqueous phase (millimolars) Crude oil
Biocide (NAN3)
No.
Treatment
la lb
Hand shaken Hand shaken Hand shaken Initial concn
5 ml 5 ml
---
0
--
Hand shaken Hand shaken Hand shaken Initial conco
5 ml 5 ml
+ +
0
+
Ultrasound Ultrasound Initial conch
5 ml 0
Ultrasound Ultrasound Ultrasound Initial concn
5 ml 5 ml 0
2
3a 3b 4
5 6 7a 7b 8
A c e t i c Propanoic acid acid 1.97 2.01 1.92 1.83 1.76 1.79 1.93 1.83
---
2.02 2.07 1.83
+ + +
1.89 1.64 1.82 1.83
Me-benzoic Octanoic acid acid 2.53* 2.51" 2.40* 3.03 1.88
0.51 0.49 0.61 0.38
1.34"
1.15
1.23" 1.27" 1.67 0.52
0.34 0.25 0.18 0.22
1.15
2.55* 2.76" 3.03 1.88
0.48 0.46 0.38
1.15
1.35* I. 12* 1.31 * 1.67 0.52
0.26 0.33 0.20 0.22
1.15
*Only total concentration of propanic and methylbenzoic acid could be determined with accuracy.
s h a k e n with crude oil gave n o m e a s u r a b l e a m o u n t s o f organic acids in the water phase.
Core flooding experiments T h e flooding experiments were p e r f o r m e d o n cores o f pure s a n d s t o n e a n d c a r b o n a t e , representing the extreme types o f reservoir rock. Cores with a d i a m e t e r o f 5 cm a n d a length o f 10 cm were coated with epoxy a n d equipped with plastic e n d pieces a n d fittings, T h e c a r b o n a t e core was strengthened with glass fiber weave in the epoxy. T h e core was connected to a C o n s t a m e t r i c I c h r o m a t o g r a p h y p u m p , a n d the liquid phases p u m p e d t h r o u g h at rates o f 0 . 1 - 1 . 0 m l / m i n . Before each r u n the cores were washed with a solvent sequence o f 600 ml m e t h a n o l , l l 0 0 m l o f h e x a n e : c h l o r o f o r m 9:1 a n d 4 0 0 m l m e t h a n o l . All solvents were saturated with p o w d e r e d core material a n d filtered before use. F o r the experiments a u n i f o r m s a n d s t o n e (from Clashack, Scotland, 9 1 % quartz, 19% porosity, permeability 3 0 0 - 4 5 0 m D ) a n d a u n i f o r m c a r b o n a t e rock ( D a n i s h chalk, 4 2 % porosity, permeability
Exp.
2.2 m D ) were used. Two lengths o f s a n d s t o n e core was used, 10 a n d 19 cm, while the low permeability o f the c a r b o n a t e limited the experiment to a core length o f 10 cm to keep within the pressure limits. A m e d i u m light N o r t h Sea stock-tank oil was diluted with n - p e n t a n e 4:1 to imitate in situ crude oil viscosity a n d density ~ = 4.66 cp, cp = 0.84) a n d used as the p o l a r oil phase, while two refined paraffins were c o m b i n e d to give a similar n o n - p o l a r oil p h a s e = 5.49 cp, cp = 0.8). Synthetic f o r m a t i o n water was p r e p a r e d as specified for the p a r t i t i o n experiments, a n d equilibrated with crushed cor material for at least 24 h before filtering. N o significant changes in core permeability or porosity was observed d u r i n g the experimental period. T o give the p o l a r water phase, sodium acetate ( 5 0 r a M ) a n d sodium p r o p a n o a t e (6 raM) was added to p o r t i o n s of the water. F o r each experiment a c o m b i n a t i o n of core type, oil type a n d water with or w i t h o u t organic acids was chosen, as s h o w n in Table 3. The cleaned core was flushed with at least 10 volumes of the required water phase to remove all solvent traces. F o r the start o f each experiment, the eluted liquids were collected in
Table 3. Experimental conditions and results for core flooding experiments Experimental conditions Results Core Oil Org. Long I. Oil 2. Oil 1. Br. type type acids short kro I krv: sat3 sap %3
2. Br. %4
4
S
Crude
--
7 2 10
S S S
Ref Ref Crude
+ -+
s s I I
0.64 0.67 0.50 0.58
0. I 1 0.10 0.05 0.06
68.4 67.0 59.4 62.0
35.4 38.5 34.4 38.7
76.1 68.4 74.8 78.7
76.1 83.4 82.3 93.3
1 3 6 9
K K K K
Ref Crude Ref Crude
--+ +
s s s s
0.46 0.42 0.46 0.24
0.12 0.09 0.12 0.08
57.6 61.2 55.8 65.2
27.8 33.7 28.7 37.5
41.6 33.9 34.6 54.7
65.1 56.6 67.3 55.6
Endpoint relative permeability of oil (oilflooding) in roD. 2Endpoint relative permeability of water (waterflooding) in mD. 3Oil saturation after oilflooding as % of pore volume. Br: Breakthrough as % of total volume non-flowingphase eluted. 4Oil saturation after waterflooding as % of pore volume. Br: Breakthrough as % of total volume non-flowing phase eluted. O~ [6/I-3--HH
492
TANJABXRTHet al.
a fraction collector, and the respective volumes of oil and water determined by weight and used to calculate the oil saturations. The inlet pressure to the core was continuously registered, and the absolute permeabilities were calculated from the pressure to flow rate relationships. The experimental setup is shown in Fig. 1. For each run, the initially water-saturated core was flooded with oil at a rate of 0,1 ml/min. Breakthrough of oil was registered, and flooding continued at the same rate until end of water elution. For the sandstone the flow rate was then increased to I ml/min and again continued until pure oil elution, while the less permeable carbonate core could not be flooded at high flow because of the pressure limitations. The flowing phase was then changed to formation water and the procedure repeated. The oil and water in each fractions were quantified by separate weighing, and oil and water saturations and end-point relative permeabilities were calculated. The core was then cleaned with solvents before the next run.
Eight runs with different combinations of core, core length, oil phase and water phase were
performed. Effects of dissolved organic acid anions on mineral dissolution Epoxy-coated cores (four altogether) were mounted with plastic end pieces and O-ring gaskets and connected to a peristaltic pump. The cores were saturated with synthetic formation water and placed in a thermostated water bath at 80°C, and the water phase was continuously circulated through the core from a 21 reservoir. The flow rate was 0.1-0.36ml/min. Each experiment lasted 600-1300h, as specified in Table 3. Two sets of cores have been investigated, the Clashach Sandstone described above, and a reservoir sandstone containing a moderate amount of clay minerals (ca. 10% illite, 15% total clay minerals), from the water zone of a North Sea reservoir. Formation waters with and without organic acid anions added (50 mM sodium acetate, 5 mM sodium
Froctlon coLLector
y coating
:ic end piece
Press t rons¢
Pump
Fig. 1. Apparatus for core flooding experiments.
Reservoir
Organic acids in reservoir waters
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Fig. 2. Loading and score plots on the three principal components, a: Loadings on PCI and PC2. b: Loadings on PCI and PC3. c: Scores on PC1 and PC2. d: Scores on PCI and PC3. Symbols and numbers as in Table 1. propanoate) were used for identical core pieces so that possible effects of the organic acid anion levels could be registered. For the sandstone cores, the inorganic ion composition was the same as in the partitioning experiments. For the reservoir rock cores, the inorganic composition of the synthetic formation water was based on formation water analysis from the reservoir (3.2% NaC1, 1% CaCI2, 0.14% NaHCO3, 0.06% MgC12, 0.05% KCI, 0.015% BaCI 2, and 0.03% SrCI2). Samples of the circulating water were taken at intervals as shown in Tables 4 and 5, and analysed for level of Ca, Si AI ions, pH and content of organic acid anions. Dissolved Si was determined color•metrically as the molybdenium blue complex (Vogel, 1978), with an analytical error _+0.5%. Dissolved Al was also determined color•metrically by the catechol violet method (Dougan and Wilson, 1974), with an analytical error _+20%. Ca was directly determined by ICP (Thompson and Walsh, 1983), with an analytical error _+2.5%.
RESULTS
Formation waters from the Norwegian continental
shelf In the multivariate analysis of the data for the formation waters (organic acid content, reservoir conditions, pH, alkalinity and 9 inorganic ion concentrations, as given in Table 1), principal component analysis (PCA) gave three statistically significant components that explain 41.5, 17.7 and 13.5% of the variance in the data set. Loading plots and score plots are shown in Fig. 2(a--d). The levels of organic acid anions in these waters as compared to other formation waters is shown in Fig. 3 relative to temperature (data from Fisher, 1987; Carothers and Kharaka, 1978). Our interest is focused on possible correlations between the measured properties. Correlations can be evaluated from the loading plots: positively correlated properties plot together, negatively correlated properties plot at opposite sides of the origin and
TAr~JAB~r~ et al.
494
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1
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Fig. 3. Levelsof acetic acid anions in Norwegiancontinental shelf formation waters and literature values plotted relative to reservoir temperatures. II: literature values, (3: Norwegian waters as given in Table I. uncorrelated properties plot orthogonally to each other. Properties which show no systematic variation plot at the origin. We see that the organic acid concentrations are positively correlated with each other and with measured alkalinity on all PC's They are mainly negatively correlated to the concentrations of inorganic cations, implying that for these ions there is no general trend of increased concentrations of dissolution products from minerals with increases in organic acid anion levels. The correlation with depth and temperature is negative on two PC's and weakly positive on the third, implying a general decrease of organic acid anion levels with increasing depth of the reservoir. Pressure and pH are positively correlated with the acid anion levels on two PC's and weakly negatively on the third, suggesting a possible relationship between partial pressure of carbon dioxide, pH, alkalinity and organic acid levels. A more complete discussion of these relationship is given in Barth (1990). The conclusion relevant for the evaluation of results below is that no simple, univariate relationship between organic acid levels and inorganic cation concentrations can be postulated.
Migration behavior of organic acids--partitioning of organic acids between formation water and crude oil If we accept that the organic acids found in reservoir water phases were generated together with the petroleum phase components in the source rock, we face a question of migration mechanisms for these compounds types. Do they migrate in the oil, and partition into the water phase at reservoir conditions? Or are they so water soluble that they immediately dissolve into the first available aqueous water phase? Information on partition behavior of typical organic acids between formation waters and crude oil is necessary for evaluation of the probabilities. An
experimental series was performed to investigate this for a standard formation water and a crude oil. The results are given in Table 2, and show that no significant removal of organic acids from aqueous to organic phase occurs. Thus, the tendency of these compounds to go into aqueous solution is strong, and must be considered a limiting condition for possible migration mechanisms./_/the acids migrate in an oil phase a very limited contact area with surrounding porewater must be postulated, and some loss of organic acid content of oil with migration distance must be expected. This could explain the scatter of organic acid levels relative to reservoir temperatures observed in Fig. 3. Alternatively the acids could migrate in aqueous solution, implying a large-scale flow of water from source to reservoir rock. This is, however, contrary to generally accepted models for oil migration (England et al., 1987).
Core flooding experiments The core flooding experiments are part of a pilot study to determine what chemical parameters are important for oil flow through porous water saturated rock. For this presentation the role of the organic acid anions in the water phase is the point of special interest, and their interactions with both the oil phase and the solid phase must be considered. Polar organic compounds can have surface active properties, and this would influence both the interfacial tension between oil and water phases and the wetting properties of the mineral surface. These properties of the system are important for the physical behavior of the flowing oil, but especially wettability is not easily determined under realistic conditions. Instead, we have chosen to determine standard, easily measured parameters for the twophase flow of oil and water through porous rock, i.e. irreducible saturations for oil and water flooding and end-point relative permeabilities. The effects on wetting may be evaluated from these parameters. The results for the eight different combinations of water, oil, rock and core lengths is given in Table 3. It is clearly seen that both the permeabilities and the saturations are strongly influenced by the different experimental parameters. The rock type gives the largest effects, the sandstone cores having the highest relative permeabilities for oil, the highest oil saturation after oil flooding, and the highest breakthrough volume. This indicates a good front in the oil flooding, with effective elution of water and the main volume of the porosity available for the oil flooding. This is consistent with a mainly water-wet mineral surface. Increasing the polarity of the mobile phases seems to give a slightly less strongly water-wet system, but the present set of data is insufficient for precise evaluation. For the carbonate core, increasing the fluid phase polarities reduces the relative permeability of the oil and increases the residual oil saturations. The breakthrough values are overall low, indicating that the front of the flowing phase is not
495
Organic acids in reservoir waters Table 4. Dissolutionof Si, AI and Ca from Clashach Sandstone Without
Time (h)
r~
Si (ppm)
A1 (ppb)
Ca (ppm)
Si (ppm)
AI (ppb)
0.23
28
900
0.67
11
24
1.46
43
1.53
18
72 168 336 504 596
2.58 3.54 4.8 6.5 7.1
56.5 69 70 62 31
3.79 5.23 6.58
41 37 55
1138
840
8.00
26
I 179
1179
9.19
36
1199
1347
10.04
47
1271
1515
9.79
49
1356
10.72
33
0
903 982 (888) (924) 995
Time
Si
AI
Ca
Si
A1
Ca
(h)
(ppm)
(pph)
(ppm)
(ppm)
(ppb)
(ppm)
0 72 167 336 504 672 840 1008
0.5 12.7 28.9 43.2 53.1 55.6 62.5
30
652.5 657.8 700.5 701.5 723.9 749.6 716.3
0.6 4.7 12.2 14.7 17.3 19.0 20.4
103
663.7 671.7 685.5 680.3 698.3 700.8 716.9
341 381
640 725 609 676
well defined. The relative permeability of water, however, is comparable to the sandstone. This is consistent with a oil-wetting mineral surface, where oil-wetness increases with increasing polarity of the phases. Water flow would then occur in the central part of the pore network, and be less influenced than oil flow, as observed. Further expansion of the experimental series, enabling statistical treatment of the results and numerical evaluation of the effects, including possible concerted effects of several factors, is in progress.
Effects of dissolved organic acid anions on mineral dissolution Si, AI and Ca were chosen as the most important elements for monitoring the effects of organic acids 7o F 50~-
~
/
3o
1-
~
./ ~
h
Fig. 5. Concentration curves for the dissolution of Al from Clashach and North Sea reservoir cores, T = 80°C, recirculating system. C + : Clashach sandstone with organic acids in the water phase. C - : Clashach sandstone without organic acids in the water phase. R + : Reservoir sandstone with organic acids in the water phase. R - : Reservoir sandstone without organic acids in the water phase.
on dissolution of minerals. Si and Ca solubilities are strongly affected by the pH levels, and organic acid buffering may change this significantly relative carbonate buffering. Si also may be complexed by organic ligands (Gaffney et al., 1989). Al mobility based on organic complexation has been discussed (Surdam and MacGowan, 1987). However, in the saline formation waters the organic compounds provide a very small fraction of the available complexing agents, and their importance cannot easily be judged. Si and Al are not routinely measured in oilfield waters, and a sufficient data base for statistical evaluation is not available. Also, experimental data from controlled conditions can more easily be interpreted for the specific effects of organic acids on individual mineral types. The results for each of the two core types investigated are given in Tables 4 and 5, where runs with and without organic acids in the water phase are compared. The results for each of the components are compared in Figs 4-6. For the clean sandstone cores, no significant differences can be observed for Si or A1, while the level of dissolved Ca is higher in the water containing organic acids anions. In these experiments, pH and organic acid levels remained constant throughout the experimental period. For the
aC-
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Ca (ppm)
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351
80o
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1000 1200 1400 1600
h
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200
400
600
800
1000
1200
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Fig. 4. Concentration curves for the dissolution of Si from
Fig. 6. Concentration curves for the dissolution of Ca from
Clashach and North Sea reservoir cores, T ffi 80°C, recirculating system. C +: Clashach sandstone with organic acids in the water phase. C - : Clashach sandstone without organic acids in the water phase. R +: Reservoir sandstone with organic acids in the water phase. R - : Reservoir sandstone without organic acids in the water phase.
Clashach and North Sea reservoir cores, T = 80°C, recireulating system. C +: Clashach sandstone with organic acids in the water phase. C - : Clashach sandstone without organic acids in the water phase. R+: Reservoir sandstone with organic acids in the water phase. R - : Reservoir sandstone without organic acids in the water phase.
496
T^NJA BARTHet al.
reservoir sandstone cores more interesting results are
observed. The level of dissolved AI is doubled in the organic acid containing water, while the level of Si is reduced to a third. This may be an effect of organic complexation, as the ionic composition of the water phase otherwise is the same. However, thc p H changes from 7.5 to 5.1 during the experimental period for the core with organic acids and to 3.3 for the core without organic acids, suggesting that buffering effects of the organic ions may be as significant. Further mineralogical investigations should point at which minerals phases are susceptible to the organic acids. But we already can conclude that organic acid anions may influence mineral dissolution processes, depending on the composition of the rock.
CONCLUSION Altogether, we are encouraged to continue investigations on the effects of aqueous organic compounds. While the general occurrence of the organic acid anions in formation waters has been shown by many authors, the consequences of their presence is still poorly understood. The levels of aqueous organic acids clearly influence several processes in the complex rock-oil-water system, and these interactions are probably interdependent for all phases of the system. Continued experimental investigation under controlled conditions is required to increase our basic understanding of the processes that are involved. This must be combined with further data collection and analysis in real systems to increase the basis for realistic evaluation of effects in the natural habitats. Acknowledgements--We thank Statoil for funding A. E. Borgund over the basic research program (Vista), and the Norwegian Research Council for Science and the Humanities (NAVF) for funding T. Barth. We thank Norsk Hydro for providing sample materials and analytical facilities for M. Riis. REFERENCES
Barth T. (1987a) Multivariate analysis of aqueous organic acid concentrations and geological properties of North Sea reservoirs. Chemolab. 2, 155-160.
Barth T. (1987b) Quantitative determination of volatile carboxylic acids in formation waters by isotachophoresis. Anal. Chem. 59, 2232-2237. Barth T. (1990) Organic acids and inorganic ions in waters from petroleum reservoirs on the Norwegian continental shelf. Acc. Appl. Geochem. In press. Barth T., Borgund A. E., Hopland A. L. and Graue A. (1987) Volatile acids produced during kerogen maturation-amounts, composition and role in migration of oil. Org. Geochem. 13, 461-465. Bennet P. and Siegel D. I. (1987) Increased solubility of quartz in water due to complexing by organic compounds. Nature 326, 684--688. Carothers W. W. and Kharaka Y. K. (1978) Aliphatic acid anions in oilfield waters--implications for origin of natural gas. AAPG Bull. 62, 2441-2453. Donaldson E. C., Chilingarian G. V. and Yen T. F. (1985) Enhanced oil recovery, I--fundamentals and analyses. Developments in Petroleum Science 17A, Chap. 4. Elsevier, Amsterdam. Dougan W. K. and Wilson A. L. (1974) The absorptiometric determination of aluminium in water. A comparison of chromogenic reagents. Analyst 99, 413-430. England W. A., Mackenzie A. S., Mann D. M. and Quigley T. M. (1987) The movement and entrapment of petroleum fluids in the subsurface. J. Geol. Soc. Lond. 144, 327-347. Fisher J. B. (1987) Distribution and occurrence of aliphatic acid anions in deep subsurface waters. Geochim. Cosmochim. Acta 51, 2459-2468. Gaffney J. S., Marley N. A. and Janecky D. R. (1989) Critical comment: on "The dissolution of quartz as a function of pH and time at 70°C'' by K. G. Knauss and T. J. Wolery. Geochim. Cosmochim. Acta 53, 1469-1470. Hanor J. S. and Workman A. L. (1986) Distribution of dissolved volatile fatty acids in some Lousiana oil field brines. Appl. Geochem. 1, 37-46. Kawamura K., TannenbaumE., Huizinga N. J. and Kaplan I. B. (1986) Volatile organic acids generated from kerogen during laboratory heating. Geochem. 20, 51-59. Lundegard P. D. and SenftleJ. T. (1987) Hydrous pyrolysis: A tool for the study of organic acid synthesis. Appl. Geochem. 2, 605-612. MacGowan D. B. and Surdam R. C. (1988) Difunctional carboxylic acids in oilfield waters. Org. Geochem. 12, 245-259. Means J. L. and Hubbard N. (1987) Shortchain aliphatic acid anions in deep subsurface brines. Org. Geochem. 11, 177-191. Surdam R. C., Crossey L. J., Hagen E. S. and Heasler H. P. (1989) Organic-inorganic interactions and sandstone diagenesis. AAPG Bull. 73, 1-23. Surdam R. C. and MacGowan D. B. (1987) Oilfield waters and sandstone diagenesis. AppL Geochem. 2, 613-619. Thompson M. and Walsh J. N. (1983) Handbook of inductively coupled plasma spectroscopy. Vogel A. I. (1978) A Textbook of Inorganic Analysis. 4th edn, pp. 757-758. Longman, New York.
Org. Geochem. Vol. 16, Nos 1-3, pp. 489-496, 1990 Printed in Great Britain. All fights reserved
0146-6380/90$3.00+ 0.00 Copyright© 1990PergamonPressplc
Organic acids in reservoir waters--Relationship with inorganic ion composition and interactions with oil and rock TANJA BARTn, ANNE EVA BORGUNDand MONA Pdts Department of Chemistry, University of Bergen, Allegt. 41, N-5007 Bergen, Norway (Received 19 September 1989; accepted 20 March 1990)
Ala~tract--Though the existence of organic acid anions in reservoir waters is well documented, their influence on the multiphase water-rock-oil interactions is not well understood. An overview of several projects directed at some of these aspects is presented. The ionic composition of formation waters from the Norwegian Continental Shelf is analysed by multivariate data analysis to discover correlations between organic acid anion concentrations, inorganic ion composition and reservoir conditions. The effects of realistic levels of aqueous acids are investigated experimentally for migration relevant systems. The partitioning of organic acids between oil and water phases is determined, and their influence on end-point relative permeabilities and breakthrough and irreducible saturations of oil in reservoir type rocks is measured. The effects of organic acid anion levels on mineral dissolution is investigated for two types of sandstone cores, showing significant effects for a mixed sandstone. Key words--formation waters, organic acids, migration, mineral dissolution
INTRODUCTION The occurrence of short-chain organic acids in formation waters from oil-containing reservoirs has been known for a long time, and the advent of modern analytical methods has given the possibility of characterising and quantifying this group of compounds. After the initial work of Carothers and Kharaka (1978), much effort has been used in mapping their occurrence in formation waters, especially of the American continents (Fisher, 1987; Means and Hubbard, 1987; Hanor and Workman, 1986). Acetic acid anions are the major species in most formation waters under conditions that preclude biodegradation, while the higher homologs are found in decreasing concentrations. Our laboratory has performed a similar mapping of the levels of organic acid anions in produced waters from the Norwegian continental shelf (Barth, 1987a; Barth, 1990), with the same general result. Hydrous pyrolysis of immature source rocks has shown that organic acids are generated together with the petroleum compounds in kerogen matu. ration reactions, and can be recovered from the aqueous phase in artificial maturation experiments (Kawamura et al., 1986; Lundegard and Senftle, 1987; Barth et al., 1987). The artificially generated organic acids show a pattern of homolog composition similar to that which is found in reservoir waters. While there is general agreement on the occurrence and source of organic acid anions in formation waters, their importance for chemical equilibria and physical properties of the complex system of formation waters, oil and minerals in reservoir rock is 489
still being explored. This paper gives a brief presentation of our current projects in this field. Several approaches are used, and the aim is to discover in what type of heterogenous interactions the organic acids participate. The knowledge of the distribution of compositions and concentrations of organic acids in different natural formation waters provide the basis for all consideration of their importance in geological systems. Our grasp of the information available from these systems must therefore be developed as far as possible. For this purpose multivariate methods for data exploration and statistical analysis are very suitable, as they can provide an overview of correlation between properties in the whole complex system of chemical compositions and reservoir data for the formation waters. Here, principal component analysis (PCA) has been used to analyse the relationship between organic acid levels, inorganic ionic composition and reservoir conditions for waters from reservoir on the Norwegian continental shelf. In addition, increased understanding of the dynamic relationships between oil, water and mineral phases is necessary, and can best be investigated under controlled conditions in the laboratory. In order to evaluate the possible transport mechanisms of the organic acid compounds from the source to the reservoir, the partitioning of water soluble organic acids between crude oils and water phases with a content of inorganic ions comparable to a typical North Sea formation water has been determined. Two-phase flow measurements on selected core types are used to see whether the content of organic acid anions in the water influences the flow properties of
490
TANJABARTHet al.
the mobile phases or their interactions. In these experiments, the irreducible saturations of oil and water and end-point relative permeabilities (for deftnition of physical parameters see e.g. Donaldson et al., 1985) have been determined for different combinations of sandstone and carbonate rock, refined and crude oils and formation waters with or without organic acid anions added. Together with the partition experiments, this gives information on the transport mechanism of organic acids from source to reservoir, and the possible influence the acid content can have on the multiphase flow properties of the water-oil-rock system. Finally, a major point of interest is the possible effect of organic acid anions on the solubilities of different minerals (Surdam et al., 1989; Surdam and MacGowan, 1987; MacGowan and Surdam, 1988; Bennet and Siegel, 1987) where large effects are suggested by some authors. In addition to analysis of the data from real formation waters aimed at registering such effects, we have carried out laboratory investigations under controlled conditions• Using a recirculating system kept at reservoir temperature, reservoir rock cores have been flushed with formation waters with and without added acetate and propanate, and the levels of Si, Ca and A1 ions in solution have been determined at regular intervals. EXPERIMENTAL
Data analysis of formation waters
Norwegian
I~ ....
~
~
-
~
o
÷
z
! i
e~
continental
shelf
A complete description of the data set and multivariate data exploration by principal component analysis is given in Barth (1990). The data set is given in Table 1 and the main conclusions are referred to in the discussion.
0
I
Partition of organic acids between formation water and crude oil A synthetic formation water was prepared (3.5% NaCI, 0.5% CaCI2, 0.3% MgCI2, 0.08% NaHCO3, 0.04% KCI and 0.009% BaCI2). Acetic, propanoic, octanoic and methyl-benzoic acid anions were added to portions of the water to give a typical reservoir concentration--0.2-2mM; precise initial concentrations for each solution given in Table 2. The ensuing solutions were split in two and the biocide sodium azide (NAN3) was added to one half. 5 ml portions of the solutions were transferred to 12 screw-topped glass tubes. To eight of the tubes 5 ml of a North Sea medium light crude oil was added. The capped tubes were shaken well by hand, and 4 of them were also placed in an ultrasound bath for 2 min. The samples were allowed to equilibrate at room temperature for 23 days before determination of organic acid anion content in the water phase. The analysis was performed by isotachophoresis (ITP) as described in Barth (1987b). Previous experiments where formation water without organic acids was
•
0
o t~
~d
~
~
-
~
~
i z
i
Organic acids in reservoir waters
491
Table 2. Distribution of organic acids between synthetic brine and crude oil. Concentration of organic acids in the aqueous phase (millimolars) Crude oil
Biocide (NAN3)
No.
Treatment
la lb
Hand shaken Hand shaken Hand shaken Initial concn
5 ml 5 ml
---
0
--
Hand shaken Hand shaken Hand shaken Initial conco
5 ml 5 ml
+ +
0
+
Ultrasound Ultrasound Initial conch
5 ml 0
Ultrasound Ultrasound Ultrasound Initial concn
5 ml 5 ml 0
2
3a 3b 4
5 6 7a 7b 8
A c e t i c Propanoic acid acid 1.97 2.01 1.92 1.83 1.76 1.79 1.93 1.83
---
2.02 2.07 1.83
+ + +
1.89 1.64 1.82 1.83
Me-benzoic Octanoic acid acid 2.53* 2.51" 2.40* 3.03 1.88
0.51 0.49 0.61 0.38
1.34"
1.15
1.23" 1.27" 1.67 0.52
0.34 0.25 0.18 0.22
1.15
2.55* 2.76" 3.03 1.88
0.48 0.46 0.38
1.15
1.35* I. 12* 1.31 * 1.67 0.52
0.26 0.33 0.20 0.22
1.15
*Only total concentration of propanic and methylbenzoic acid could be determined with accuracy.
s h a k e n with crude oil gave n o m e a s u r a b l e a m o u n t s o f organic acids in the water phase.
Core flooding experiments T h e flooding experiments were p e r f o r m e d o n cores o f pure s a n d s t o n e a n d c a r b o n a t e , representing the extreme types o f reservoir rock. Cores with a d i a m e t e r o f 5 cm a n d a length o f 10 cm were coated with epoxy a n d equipped with plastic e n d pieces a n d fittings, T h e c a r b o n a t e core was strengthened with glass fiber weave in the epoxy. T h e core was connected to a C o n s t a m e t r i c I c h r o m a t o g r a p h y p u m p , a n d the liquid phases p u m p e d t h r o u g h at rates o f 0 . 1 - 1 . 0 m l / m i n . Before each r u n the cores were washed with a solvent sequence o f 600 ml m e t h a n o l , l l 0 0 m l o f h e x a n e : c h l o r o f o r m 9:1 a n d 4 0 0 m l m e t h a n o l . All solvents were saturated with p o w d e r e d core material a n d filtered before use. F o r the experiments a u n i f o r m s a n d s t o n e (from Clashack, Scotland, 9 1 % quartz, 19% porosity, permeability 3 0 0 - 4 5 0 m D ) a n d a u n i f o r m c a r b o n a t e rock ( D a n i s h chalk, 4 2 % porosity, permeability
Exp.
2.2 m D ) were used. Two lengths o f s a n d s t o n e core was used, 10 a n d 19 cm, while the low permeability o f the c a r b o n a t e limited the experiment to a core length o f 10 cm to keep within the pressure limits. A m e d i u m light N o r t h Sea stock-tank oil was diluted with n - p e n t a n e 4:1 to imitate in situ crude oil viscosity a n d density ~ = 4.66 cp, cp = 0.84) a n d used as the p o l a r oil phase, while two refined paraffins were c o m b i n e d to give a similar n o n - p o l a r oil p h a s e = 5.49 cp, cp = 0.8). Synthetic f o r m a t i o n water was p r e p a r e d as specified for the p a r t i t i o n experiments, a n d equilibrated with crushed cor material for at least 24 h before filtering. N o significant changes in core permeability or porosity was observed d u r i n g the experimental period. T o give the p o l a r water phase, sodium acetate ( 5 0 r a M ) a n d sodium p r o p a n o a t e (6 raM) was added to p o r t i o n s of the water. F o r each experiment a c o m b i n a t i o n of core type, oil type a n d water with or w i t h o u t organic acids was chosen, as s h o w n in Table 3. The cleaned core was flushed with at least 10 volumes of the required water phase to remove all solvent traces. F o r the start o f each experiment, the eluted liquids were collected in
Table 3. Experimental conditions and results for core flooding experiments Experimental conditions Results Core Oil Org. Long I. Oil 2. Oil 1. Br. type type acids short kro I krv: sat3 sap %3
2. Br. %4
4
S
Crude
--
7 2 10
S S S
Ref Ref Crude
+ -+
s s I I
0.64 0.67 0.50 0.58
0. I 1 0.10 0.05 0.06
68.4 67.0 59.4 62.0
35.4 38.5 34.4 38.7
76.1 68.4 74.8 78.7
76.1 83.4 82.3 93.3
1 3 6 9
K K K K
Ref Crude Ref Crude
--+ +
s s s s
0.46 0.42 0.46 0.24
0.12 0.09 0.12 0.08
57.6 61.2 55.8 65.2
27.8 33.7 28.7 37.5
41.6 33.9 34.6 54.7
65.1 56.6 67.3 55.6
Endpoint relative permeability of oil (oilflooding) in roD. 2Endpoint relative permeability of water (waterflooding) in mD. 3Oil saturation after oilflooding as % of pore volume. Br: Breakthrough as % of total volume non-flowingphase eluted. 4Oil saturation after waterflooding as % of pore volume. Br: Breakthrough as % of total volume non-flowing phase eluted. O~ [6/I-3--HH
492
TANJABXRTHet al.
a fraction collector, and the respective volumes of oil and water determined by weight and used to calculate the oil saturations. The inlet pressure to the core was continuously registered, and the absolute permeabilities were calculated from the pressure to flow rate relationships. The experimental setup is shown in Fig. 1. For each run, the initially water-saturated core was flooded with oil at a rate of 0,1 ml/min. Breakthrough of oil was registered, and flooding continued at the same rate until end of water elution. For the sandstone the flow rate was then increased to I ml/min and again continued until pure oil elution, while the less permeable carbonate core could not be flooded at high flow because of the pressure limitations. The flowing phase was then changed to formation water and the procedure repeated. The oil and water in each fractions were quantified by separate weighing, and oil and water saturations and end-point relative permeabilities were calculated. The core was then cleaned with solvents before the next run.
Eight runs with different combinations of core, core length, oil phase and water phase were
performed. Effects of dissolved organic acid anions on mineral dissolution Epoxy-coated cores (four altogether) were mounted with plastic end pieces and O-ring gaskets and connected to a peristaltic pump. The cores were saturated with synthetic formation water and placed in a thermostated water bath at 80°C, and the water phase was continuously circulated through the core from a 21 reservoir. The flow rate was 0.1-0.36ml/min. Each experiment lasted 600-1300h, as specified in Table 3. Two sets of cores have been investigated, the Clashach Sandstone described above, and a reservoir sandstone containing a moderate amount of clay minerals (ca. 10% illite, 15% total clay minerals), from the water zone of a North Sea reservoir. Formation waters with and without organic acid anions added (50 mM sodium acetate, 5 mM sodium
Froctlon coLLector
y coating
:ic end piece
Press t rons¢
Pump
Fig. 1. Apparatus for core flooding experiments.
Reservoir
Organic acids in reservoir waters
0.4
493
(b)
(a)
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OBo
0.4
OP
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ONe
rlp
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~c~ °eL
--0.2
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--0.4
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-0.4
I -0.2
I -0.4
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I 0.2
I --0.4
I 0.4
14 ~
11
8 ,\f,~_
• 21
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9m
15
• 2 ma
6m
0 0 ft.
(d)
•42
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O
• 20
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PCI
20
14 m5
--4 I 0
• 19 •
i
•19
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15 • •18
112
t
U
13
I -4
0.4
~PC1
PC 1
(c)
I
I 0
I 0
I 4
I 8
PCl
Fig. 2. Loading and score plots on the three principal components, a: Loadings on PCI and PC2. b: Loadings on PCI and PC3. c: Scores on PC1 and PC2. d: Scores on PCI and PC3. Symbols and numbers as in Table 1. propanoate) were used for identical core pieces so that possible effects of the organic acid anion levels could be registered. For the sandstone cores, the inorganic ion composition was the same as in the partitioning experiments. For the reservoir rock cores, the inorganic composition of the synthetic formation water was based on formation water analysis from the reservoir (3.2% NaC1, 1% CaCI2, 0.14% NaHCO3, 0.06% MgC12, 0.05% KCI, 0.015% BaCI 2, and 0.03% SrCI2). Samples of the circulating water were taken at intervals as shown in Tables 4 and 5, and analysed for level of Ca, Si AI ions, pH and content of organic acid anions. Dissolved Si was determined color•metrically as the molybdenium blue complex (Vogel, 1978), with an analytical error _+0.5%. Dissolved Al was also determined color•metrically by the catechol violet method (Dougan and Wilson, 1974), with an analytical error _+20%. Ca was directly determined by ICP (Thompson and Walsh, 1983), with an analytical error _+2.5%.
RESULTS
Formation waters from the Norwegian continental
shelf In the multivariate analysis of the data for the formation waters (organic acid content, reservoir conditions, pH, alkalinity and 9 inorganic ion concentrations, as given in Table 1), principal component analysis (PCA) gave three statistically significant components that explain 41.5, 17.7 and 13.5% of the variance in the data set. Loading plots and score plots are shown in Fig. 2(a--d). The levels of organic acid anions in these waters as compared to other formation waters is shown in Fig. 3 relative to temperature (data from Fisher, 1987; Carothers and Kharaka, 1978). Our interest is focused on possible correlations between the measured properties. Correlations can be evaluated from the loading plots: positively correlated properties plot together, negatively correlated properties plot at opposite sides of the origin and
TAr~JAB~r~ et al.
494
40
•
0
--
5•
l
%: .qz eo:...~J,6_,/• rd•o• ~ z
4
I 40
•
150l ~dn • •
il
•ill •
• | =|'=
•
14
I 80
3
I 120
1
I 160
T(*C)
Fig. 3. Levelsof acetic acid anions in Norwegiancontinental shelf formation waters and literature values plotted relative to reservoir temperatures. II: literature values, (3: Norwegian waters as given in Table I. uncorrelated properties plot orthogonally to each other. Properties which show no systematic variation plot at the origin. We see that the organic acid concentrations are positively correlated with each other and with measured alkalinity on all PC's They are mainly negatively correlated to the concentrations of inorganic cations, implying that for these ions there is no general trend of increased concentrations of dissolution products from minerals with increases in organic acid anion levels. The correlation with depth and temperature is negative on two PC's and weakly positive on the third, implying a general decrease of organic acid anion levels with increasing depth of the reservoir. Pressure and pH are positively correlated with the acid anion levels on two PC's and weakly negatively on the third, suggesting a possible relationship between partial pressure of carbon dioxide, pH, alkalinity and organic acid levels. A more complete discussion of these relationship is given in Barth (1990). The conclusion relevant for the evaluation of results below is that no simple, univariate relationship between organic acid levels and inorganic cation concentrations can be postulated.
Migration behavior of organic acids--partitioning of organic acids between formation water and crude oil If we accept that the organic acids found in reservoir water phases were generated together with the petroleum phase components in the source rock, we face a question of migration mechanisms for these compounds types. Do they migrate in the oil, and partition into the water phase at reservoir conditions? Or are they so water soluble that they immediately dissolve into the first available aqueous water phase? Information on partition behavior of typical organic acids between formation waters and crude oil is necessary for evaluation of the probabilities. An
experimental series was performed to investigate this for a standard formation water and a crude oil. The results are given in Table 2, and show that no significant removal of organic acids from aqueous to organic phase occurs. Thus, the tendency of these compounds to go into aqueous solution is strong, and must be considered a limiting condition for possible migration mechanisms./_/the acids migrate in an oil phase a very limited contact area with surrounding porewater must be postulated, and some loss of organic acid content of oil with migration distance must be expected. This could explain the scatter of organic acid levels relative to reservoir temperatures observed in Fig. 3. Alternatively the acids could migrate in aqueous solution, implying a large-scale flow of water from source to reservoir rock. This is, however, contrary to generally accepted models for oil migration (England et al., 1987).
Core flooding experiments The core flooding experiments are part of a pilot study to determine what chemical parameters are important for oil flow through porous water saturated rock. For this presentation the role of the organic acid anions in the water phase is the point of special interest, and their interactions with both the oil phase and the solid phase must be considered. Polar organic compounds can have surface active properties, and this would influence both the interfacial tension between oil and water phases and the wetting properties of the mineral surface. These properties of the system are important for the physical behavior of the flowing oil, but especially wettability is not easily determined under realistic conditions. Instead, we have chosen to determine standard, easily measured parameters for the twophase flow of oil and water through porous rock, i.e. irreducible saturations for oil and water flooding and end-point relative permeabilities. The effects on wetting may be evaluated from these parameters. The results for the eight different combinations of water, oil, rock and core lengths is given in Table 3. It is clearly seen that both the permeabilities and the saturations are strongly influenced by the different experimental parameters. The rock type gives the largest effects, the sandstone cores having the highest relative permeabilities for oil, the highest oil saturation after oil flooding, and the highest breakthrough volume. This indicates a good front in the oil flooding, with effective elution of water and the main volume of the porosity available for the oil flooding. This is consistent with a mainly water-wet mineral surface. Increasing the polarity of the mobile phases seems to give a slightly less strongly water-wet system, but the present set of data is insufficient for precise evaluation. For the carbonate core, increasing the fluid phase polarities reduces the relative permeability of the oil and increases the residual oil saturations. The breakthrough values are overall low, indicating that the front of the flowing phase is not
495
Organic acids in reservoir waters Table 4. Dissolutionof Si, AI and Ca from Clashach Sandstone Without
Time (h)
r~
Si (ppm)
A1 (ppb)
Ca (ppm)
Si (ppm)
AI (ppb)
0.23
28
900
0.67
11
24
1.46
43
1.53
18
72 168 336 504 596
2.58 3.54 4.8 6.5 7.1
56.5 69 70 62 31
3.79 5.23 6.58
41 37 55
1138
840
8.00
26
I 179
1179
9.19
36
1199
1347
10.04
47
1271
1515
9.79
49
1356
10.72
33
0
903 982 (888) (924) 995
Time
Si
AI
Ca
Si
A1
Ca
(h)
(ppm)
(pph)
(ppm)
(ppm)
(ppb)
(ppm)
0 72 167 336 504 672 840 1008
0.5 12.7 28.9 43.2 53.1 55.6 62.5
30
652.5 657.8 700.5 701.5 723.9 749.6 716.3
0.6 4.7 12.2 14.7 17.3 19.0 20.4
103
663.7 671.7 685.5 680.3 698.3 700.8 716.9
341 381
640 725 609 676
well defined. The relative permeability of water, however, is comparable to the sandstone. This is consistent with a oil-wetting mineral surface, where oil-wetness increases with increasing polarity of the phases. Water flow would then occur in the central part of the pore network, and be less influenced than oil flow, as observed. Further expansion of the experimental series, enabling statistical treatment of the results and numerical evaluation of the effects, including possible concerted effects of several factors, is in progress.
Effects of dissolved organic acid anions on mineral dissolution Si, AI and Ca were chosen as the most important elements for monitoring the effects of organic acids 7o F 50~-
~
/
3o
1-
~
./ ~
h
Fig. 5. Concentration curves for the dissolution of Al from Clashach and North Sea reservoir cores, T = 80°C, recirculating system. C + : Clashach sandstone with organic acids in the water phase. C - : Clashach sandstone without organic acids in the water phase. R + : Reservoir sandstone with organic acids in the water phase. R - : Reservoir sandstone without organic acids in the water phase.
on dissolution of minerals. Si and Ca solubilities are strongly affected by the pH levels, and organic acid buffering may change this significantly relative carbonate buffering. Si also may be complexed by organic ligands (Gaffney et al., 1989). Al mobility based on organic complexation has been discussed (Surdam and MacGowan, 1987). However, in the saline formation waters the organic compounds provide a very small fraction of the available complexing agents, and their importance cannot easily be judged. Si and Al are not routinely measured in oilfield waters, and a sufficient data base for statistical evaluation is not available. Also, experimental data from controlled conditions can more easily be interpreted for the specific effects of organic acids on individual mineral types. The results for each of the two core types investigated are given in Tables 4 and 5, where runs with and without organic acids in the water phase are compared. The results for each of the components are compared in Figs 4-6. For the clean sandstone cores, no significant differences can be observed for Si or A1, while the level of dissolved Ca is higher in the water containing organic acids anions. In these experiments, pH and organic acid levels remained constant throughout the experimental period. For the
aC-
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~
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Table 5. Dissolution of Si, AI and Ca from reservoir sandstone, North Sea
R+
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Ca (ppm)
( ): Uncertain measurements.
351
80o
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organic acids
1000 1200 1400 1600
h
,oo 0
I
I
I
I
I
I
I
200
400
600
800
1000
1200
1400
h
Fig. 4. Concentration curves for the dissolution of Si from
Fig. 6. Concentration curves for the dissolution of Ca from
Clashach and North Sea reservoir cores, T ffi 80°C, recirculating system. C +: Clashach sandstone with organic acids in the water phase. C - : Clashach sandstone without organic acids in the water phase. R +: Reservoir sandstone with organic acids in the water phase. R - : Reservoir sandstone without organic acids in the water phase.
Clashach and North Sea reservoir cores, T = 80°C, recireulating system. C +: Clashach sandstone with organic acids in the water phase. C - : Clashach sandstone without organic acids in the water phase. R+: Reservoir sandstone with organic acids in the water phase. R - : Reservoir sandstone without organic acids in the water phase.
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reservoir sandstone cores more interesting results are
observed. The level of dissolved AI is doubled in the organic acid containing water, while the level of Si is reduced to a third. This may be an effect of organic complexation, as the ionic composition of the water phase otherwise is the same. However, thc p H changes from 7.5 to 5.1 during the experimental period for the core with organic acids and to 3.3 for the core without organic acids, suggesting that buffering effects of the organic ions may be as significant. Further mineralogical investigations should point at which minerals phases are susceptible to the organic acids. But we already can conclude that organic acid anions may influence mineral dissolution processes, depending on the composition of the rock.
CONCLUSION Altogether, we are encouraged to continue investigations on the effects of aqueous organic compounds. While the general occurrence of the organic acid anions in formation waters has been shown by many authors, the consequences of their presence is still poorly understood. The levels of aqueous organic acids clearly influence several processes in the complex rock-oil-water system, and these interactions are probably interdependent for all phases of the system. Continued experimental investigation under controlled conditions is required to increase our basic understanding of the processes that are involved. This must be combined with further data collection and analysis in real systems to increase the basis for realistic evaluation of effects in the natural habitats. Acknowledgements--We thank Statoil for funding A. E. Borgund over the basic research program (Vista), and the Norwegian Research Council for Science and the Humanities (NAVF) for funding T. Barth. We thank Norsk Hydro for providing sample materials and analytical facilities for M. Riis. REFERENCES
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