EP2396383A1 - Injection de fluide aqueux de déplacement pour améliorer la récupération de pétrole à partir d'une formation calcaire ou de dolomite - Google Patents

Injection de fluide aqueux de déplacement pour améliorer la récupération de pétrole à partir d'une formation calcaire ou de dolomite

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Publication number
EP2396383A1
EP2396383A1 EP10703469A EP10703469A EP2396383A1 EP 2396383 A1 EP2396383 A1 EP 2396383A1 EP 10703469 A EP10703469 A EP 10703469A EP 10703469 A EP10703469 A EP 10703469A EP 2396383 A1 EP2396383 A1 EP 2396383A1
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Prior art keywords
water
mol
oil
brine
wettability
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EP10703469A
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German (de)
English (en)
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Dirk Jacob Ligthelm
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Shell Internationale Research Maatschappij BV
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Shell Internationale Research Maatschappij BV
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    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids

Definitions

  • the invention relates to a method for enhancing oil recovery (EOR) by injecting an aqueous displacement fluid into a porous subterranean formation of which the pore spaces comprise crude oil and connate water.
  • EOR oil recovery
  • aqueous displacement fluid in a formation containing sandstone rock and minerals, such as clay, having a negative zeta potential the aqueous displacement fluid should have a total dissolved solids (TDS) content in the range of 200 to 10,000 ppm and the fraction of the total multivalent cation content of the aqueous displacement fluid to the total multivalent cation content of the connate water should be less than 1.
  • TDS total dissolved solids
  • EOR Enhanced Oil Recovery
  • a method for enhancing recovery of crude oil from a porous subterranean formation of which the pore spaces contain crude oil and connate water comprising SO 4 2" and Ca 2+ ions comprising:
  • an aqueous displacement fluid with a SO 4 2" / Ca 2+ molar ratio (Mol/Mol) above 1 and a higher SO 4 2" / Ca 2+ molar ratio (Mol/Mol) than the connate water; - characterized in that the porous subterranean formation is a limestone or dolomite formation.
  • the method may be applied to modify the wettability of the limestone or dolomite formation such that its oil wettability is reduced and its water wettability is increased.
  • Figure 17 shows that only brines LS2 and LS3 will be effective in wettability modification.
  • Table 5 it is shown that these have SO 4 2" / Ca 2+ ratio (Mol/Mol) above 1 and a higher SO 4 2" / Ca 2+ molar ratio (Mol/Mol) than the connate water.
  • the aqueous displacement fluid is injected at a temperature above 50°C and as a slug of 0.2-0.8 PV into the pore spaces and the method further comprises injection of an untreated aqueous displacement fluid after injecting the slug of aqueous displacement fluid comprising a higher SO 4 " / Ca + molar ratio
  • the aqueous displacement fluid may comprise water from a river, fresh water aquifer, lake, sea or ocean, which water is treated such that it is converted into an aqueous displacement fluid comprising a higher SO 4 2" / Ca 2+ molar ratio (Mol/Mol) than the connate water in the pore spaces .
  • Table 1 shows experimental data and undiluted brine compositions for Berea centrifuge experiments at 55 0 C.
  • Table 2 shows experimental data and undiluted brine compositions for Berea in-house experiments: Dagang-like brine (after Ref.32, Tang et al, 2002) and Berea and Brent Bravo oil properties.
  • Table 3 shows compositions of undiluted, pure NaCl, CaCl2 and MgCl2 brines in Berea experiments.
  • Table 4 shows experimental data and brines for experiments on Middle Eastern sandstone cores. Important brine characteristics are indicated in bold.
  • Table 5 shows composition of brines, used in spontaneous imbibition experiments in Middle Eastern limestone core samples.
  • Table 6 shows an example of the composition of a formation brine.
  • Figure 1 shows: (a) a phenomenological definition of wettability; and (b) the binding mechanism between clay and oil.
  • Figure 2 shows decreasing oil relative permeability at increasing oil wetness.
  • Figure 3 shows cartoons of bonding between clay surface and oil in a highly saline and low saline brine environment .
  • the Ca + ion represents the multivalent cations in the brine that act as bridge between clay and oil particles.
  • Figure 4 shows the correlation between total salinity level TDS and divalent cation level (Ca 2+ + Mg 2+ ) for formation waters of in-house reservoirs.
  • the grey data point indicates Brent seawater.
  • Figure 5 shows the relationship between wettability index W and overall salinity level. The full lines depict various levels for oilwetting.
  • Figure 6 shows the decreasing water fractional flow at decreasing salinity level.
  • Figure 7 shows water saturation profiles for a highly saline water flood and a fresh water flood.
  • Figure 8 shows a comparison of production profiles for a saline water flood (dark grey lines) and a Fresh Water Flood (light grey lines) for 1-D flow. Dashed lines indicate water cut.
  • Figure 9 shows a characteristic pressure profile during Fresh Water Flooding.
  • Figure 10 shows imbibition capillary pressure curves from the centrifuge for Berea core plugs for undiluted and diluted brines at 55 0 C.
  • Figures 11A-C show result of an in-house experimental validation of the role of divalent cations on Berea at 60 0 C. NMR wettability determination indicates that change to mono-valent cations leads to reduction in adsorption of heavy hydrocarbons to rock minerals.
  • Figure 12 shows a spontaneous imbibition experiment on Berea core material at ambient conditions. Demonstration of resumed oil production upon switching to fresh water.
  • Figure 13 shows a demonstration of suppression of oil production by injection of CaCl2 brine on Berea core material under ambient conditions.
  • Figure 14 shows a SEM picture of Middle East core sample.
  • the contaminations on the pore walls are probably dispersed kaolinite particles.
  • Figure 15 demonstrates resumed oil production at reduced differential pressure after switching to fresh water injection (ambient conditions) .
  • Figure 16 shows an experiment on Middle Eastern core material when using various injection brine compositions under ambient conditions, during 5 consecutive periods: Period A: Formation water injection.
  • Period B Injection of 240000 mg/1 NaCl.
  • Period C Injection of 2000 mg/1 NaCl.
  • Period D Injection of 2000 mg/1 NaCl + 10 mg/1 Ca 2+ .
  • Period E Injection of 2000 mg/1 NaCl + 100 mg/1 Ca 2 .
  • Figure 17 shows results from spontaneous imbibition experiments on Middle Eastern limestone core material at 60 0 C.
  • Figure 18 shows a possible fresh water effect in observed water cut reversal in production well in Middle East sandstone reservoir.
  • Figure 19 shows a possible fresh water effect on oil production rate in a production well in a Middle Eastern sandstone reservoir.
  • Figure 20 shows the dependence of intrinsic viscosity on brine ionic strength for various viscosifying polyacrylamide polymers with molecular weight M and a degree of hydrolysis.
  • Figure 22 shows the viscosifying power of commercially available hyrolysed polyacrylamide in a formation brine with the composition shown in Table 6.
  • Figure 23 shows an indication of the range of polymer concentration data and current estimate based on intrinsic viscosities for 90 mPa.s viscosity.
  • an aqueous displacement fluid comprising a higher SO 4 2" / Ca 2+ ratio than the connate water.
  • the method according to the invention is based on the insight that as brine composition profoundly influences reservoir wettability and hence microscopic sweep, careful design of injection brine is part of a strategy to improve on oil production in existing and future water flooding projects, in both sandstone and carbonate reservoirs and in combination with follow-up EOR projects.
  • Middle Eastern sandstone reservoir with highly saline formation water was interpreted to be caused by an oil bank ahead of the fresh water slug;
  • Fresh water injection may increase the Ultimate Recovery of oil by at least a few percent;
  • FIG 1 shows that wettability of reservoir rock can be phenomenologically defined as the fraction of the rock surface that is coated by adsorbed hydrocarbons.
  • a convenient parameter for characterisation is the wettability index W.
  • Figure 2 shows that phenomenological correlations between wettability index W and relative permeabilities result in reduced oil relative permeability and increased water relative permeability at increase in oilwetness over a large saturation range. This shows that for increasing oilwetness, oil prefers to stick to the rock and to flow less easy, relative to water. The result is a less efficient microscopic sweep efficiency.
  • the process of oil film flow is relevant if there is significant contribution to the oil recovery by oil- after-drainage in reservoir zones, invaded by injection water, as result of buoyancy forces. It is of less importance for waterflood processes, where the oil recovery is mainly the result from a normal lateral movement of the fluid front under diffuse flow conditions .
  • Figure 2 shows that in that case, at field or well abandonment at say 95 % watercut level, the oil relative permeability will have reached a low level of typically 1/1000 - 1/100 and there will be left in the field a remaining oil saturation S 0 , remain, that is well above the true residual oil saturation S or w • Then, wettability modification towards more waterwet state may increase by several percent of Pore Volume (PV) the water saturation level that can be obtained by water flooding and similarly reduce the remaining oil saturation. By consequence, the ultimate amount of oil that can be produced prior to abandonment may increase by several percent of PV as well.
  • PV Pore Volume
  • Multivalent metal cations in the brine such as Ca 2+ and Mg + are believed to act like bridges between the negatively charged oil and clay minerals (Ref.2, Anderson, 1986; Ref.l5&16, Lager et al, 2006, 2007) .
  • Figure 3 shows that in presence of a sufficiently high salinity level, sufficient positive cations are available to screen-off their negative electrical charges with suppression of the electrostatic repulsive forces as result. This causes a low level of the negative electrical potential at the slipping plane between the charged surfaces and the brine solution (the so-called zeta potential) .
  • the zeta potential at the slipping plane is thought to be a good approximation of the (Stern) potential on the Stern layer.
  • the Stern layer is defined as the space between the colloid wall and a distance equal to the ion radius, being free of electrical charge (Ref.26, Shaw, 1966; Ref.22, Mysels, 1967) .
  • oil can react with these clay particles to form organo-metallic complexes (Ref.25, Rueslatten, 1994) . It makes the clay surface extremely hydrophobic and causes local oilwetness (Ref.9, Clementz, 1982) .
  • Figure 4 shows that, based on an analysis of in- house reservoir data, formation brines with a higher salinity level display a higher level of divalent/multivalent cations.
  • Figure 3 shows how this in turn yields increased electrostatic repulsion between the clay particle and the oil . It is currently believed that once the repulsive forces exceed the binding forces via the multivalent cation bridges, the oil particles may be desorbed from the clay surfaces. This would result in a reduction in the fraction of the rock surface that has been coated by oil and this in turn implies a change in wetting state towards increased waterwetness . The above mechanism would especially occur at the interface between banked-up highly saline formation water and the invading Fresh Water Slug.
  • Fresh Water Flooding is recommended to remain restricted to salinity levels outside the region of formation damage, where the adsorbed hydrocarbons are thought to be expelled from the clays but the clays remain intact.
  • the cation electrolyte content of the water will often be small compared to the Cation Exchange Capacity (CEC) of the formation.
  • CEC Cation Exchange Capacity
  • the cation composition of the injection brine is then determined by the cation composition on the clay minerals in the pore space. Based on the law of mass action, reduction in Na + concentration by a factor OC > 1 in the brine behind the salinity front is accompanied by a reduction in divalent cation concentration (Ca 2+ , Mg 2+ ) by a factor OC 2 (Ref.l, Appelo, 1993) .
  • This effect may cause the concentration of divalent cations in the zone behind the salinity front to be lower than in both the formation water and in the injection water.
  • This stripping of divalent cations from injected low saline brine has been actually observed after breakthrough of the salinity front (Ref.33, Valocchi, 1981; Ref.17, Lager et al, 2008) .
  • FIGS. 6-8 show typical a typical example calculation for a mixed-wet formation.
  • the example demonstrates the reduction in water fractional flow upon wettability modification by injection of a Wettability Modifying (WM) -brine, the displacement of formation water by the WM-brine slug, leading to a formation water bank ahead of the WM-slug and increase in ultimate recovery and hence in displacement (microscopic) sweep efficiency E d at 95 % water cut abandonment level.
  • E d is defined as the fraction of the oil saturation, which will be displaced from that portion of the reservoir that is contacted or swept by water. The process is most efficient when applied from day one of a water flood, because then the amount of oil that may benefit from the improved sweep is at its maximum.
  • Figure 9 shows that, due to the relatively high water saturation in the injectant-invaded zone (aiming for improved displacement sweep) , the mobility of this slug may be higher than that of the preceding formation water bank, despite the reduction in water relative permeability by wettability modification.
  • the mobility of a fresh water slug is further increased because of somewhat reduced brine viscosity. Viscous instabilities may be avoided by making the WM- brine slug slightly more viscous by addition of some low concentration polymer.
  • the associated chemical costs might be relatively low when using a polymer such as hydrolyzed polyacrylamide, which is especially effective in low saline brine with respect to viscosity increase and reduction in adsorption.
  • a formation will display a wide variation in permeability levels, including low permeability spots, which may largely remain bypassed during a highly saline water flood. If the formation is mixed-to-oilwet , there may be hardly any oil production from these bypassed spots by capillary-driven countercurrent imbibition. However, if these spots are of sufficiently small scale (e.g. a few cm), the WM-brine will be able to invade these spots by molecular diffusion (Ref.28, Stoll et al, 2008) .
  • E vo i is defined as the fraction of the reservoir volume that will be contacted by injected water. It is composed of the product of vertical sweep efficiency E v and areal sweep efficiency E a .
  • the single most important characteristic of a waterflood that determines E vo i is the water/oil mobility ratio M, which is defined in terms of the effective permeability and viscosity of the displacing and displaced fluids involved in the flood at two different and separated points in the reservoir, with the water relative permeability being evaluated at the average water saturation behind the displacement front (Ref.lO, Craig, 1971) .
  • M water/oil mobility ratio
  • WM-slugs may experience increased mobility. Apart from possible viscous instabilities mentioned before, this might also lead to some increase in mobility ratio M and by consequence to some loss in volumetric sweep efficiency. Therefore, adding some low concentration polymer to the WM-brine may be useful, not only to avoid viscous instabilities but also to compensate for some possible loss in volumetric sweep efficiency.
  • the WM-brines which are used in the experiments, are sufficiently high in salinity level to avoid formation damage. Formation damage can be observed from a gradual increase in differential pressure during a core flow experiment and should be avoided to prevent unnecessary complications as a result of the so-called capillary end effect in the interpretation of the experiments.
  • the typical result from a core flow experiment would be as follows: At the end of the injection period of Formation Water, a stationary situation is established in which oil production has ceased and the differential water phase pressure is at a stable level.
  • the water saturation distribution in the core is such that - apart from a small buoyancy force in a vertically oriented core - the negative capillary pressure over the core is exactly in balance with the water phase pressure, which results from the stationary viscous pressure drop due to the water flow.
  • oil production may resume at the same or at even a somewhat lower differential water phase pressure over the core. This is only possible if the capillary pressure level over the core is reduced. Then the water saturation in the core will increase (with as a consequence some oil production) until the capillary pressure level over the core has increased to balance the water phase pressure again. Due to the oil production, the water phase mobility in the core has increased, leading to some additional drop in differential pressure over the core.
  • NMR wettability determination and in situ saturation profiles and numerical simulations are required to draw more refined conclusions, e.g. on possible changes in relative permeability curves, which are indicative for wettability modification and relevant for improved oil production on reservoir scale. It follows that conclusions from core flow experiments are always drawn with help of simulation models and some inevitable assumptions, whereas error bars in the experimental results will tend to make conclusions less firm. Therefore, to obtain firm evidence for wettability modification, core floods were accompanied by Amott spontaneous imbibition tests.
  • Figure 10 shows a series of imbibition capillary pressure curves obtained by laboratory experiments with Berea sandstone core plugs, which were measured with the centrifuge at 55 0 C.
  • the oil used was CS crude, obtained from the University of Wyoming (Ref .32, Tang et al, 2002) .
  • the brine compositions for ageing and oil displacement were chosen identical.
  • FIG 11 shows the results of a series of spontaneous Amott imbibition tests at 60 0 C for Berea sandstone core plugs. Also in these tests, the brine compositions for ageing and oil displacement by brine invasion were chosen identical. The oil used was Brent Bravo crude and one of the undiluted brine compositions was based on that of Dagang brine (Ref.32, Tang et al, 2002), which consists of mainly Na + and K + with addition of some Ca 2+ and Mg 2+ . Pure NaCl, CaCl 2 and MgCl 2 brines were tested as well. — Z O Qo —
  • Tables 2 and 3 provide lists of the experimental details and the undiluted brine compositions are listed.
  • Figure 12 shows that, in an Amott spontaneous imbibition experiment at ambient conditions for a Berea sandstone core plug aged with undiluted Dagang brine as connate water and Brent Bravo crude, - once oil production has ceased after imbibition of undiluted
  • Dagang brine - oil production resumes after switching to 100-fold diluted Dagang brine as invading brine. This demonstrates that fresh brine invasion makes the core material more waterwet.
  • Figure 13 shows the results of a low rate core flow experiment at 0.32 m/day under ambient conditions that was carried out to test the hypothesis that High Salinity Flooding might make reservoir rock more oilwet and jeopardize sweep. The experiment was conducted by:
  • Table 4 indicates that Amott imbibition cell experiments on Middle Eastern core samples at ambient conditions show no spontaneous imbibition of highly saline formation water at all at nevertheless a low level of initial water saturation. This indicates that the sample is rather oilwet.
  • Figure 14 shows pictures from a Scanning Electronic Microscope ( SEM) which illustrate that the clay is dispersed as fines over the whole pore space, although the clay content of the sample is low by only a few percent kaolinite of rock bulk weight.
  • SEM Scanning Electronic Microscope
  • Table 4 shows that, after changing the invading formation brine to fresh water, oil production slowly sets on, with an ultimate oil recovery of 24 PV %. This shows the ability of fresh water to change wettability of the core to more waterwet state.
  • Figure 15 shows the ability of fresh water to change wettability to more waterwet state is also recognized in the low rate core flow experiment at ambient conditions at 0.32 M/day. After switching to fresh water injection, oil production resumes at lower differential pressure over the core because of reduction in brine viscosity. This points into the direction of reduced level of
  • Table 4 provides the experimental data of this core flow experiment.
  • FIG 16 shows the results thereof on production. The following experimental stages A-E were applied:
  • Period A Injection of over 50 Pore Volumes of formation water of about 238000 mg/1 TDS with 84300 mg/1 Na + , 6800 mg/1 Ca 2+ and 1215 mg/1 Mg 2+ until a stationary state of no oil production any more is reached. During this stage, a certain fraction of the clay particles is expected to become occupied by Ca 2+ and Mg 2+ .
  • Period B Injection of about 30 Pore Volumes of 240000 mg/1 pure NaCl brine, that is free from any multivalent cations and has a similar ionic strength as the formation water.
  • Period B Injection of about 30 Pore Volumes of 240000 mg/1 pure NaCl brine, that is free from any multivalent cations and has a similar ionic strength as the formation water.
  • Period C Injection of 2000 mg/1 pure NaCl brine, that is free from any multivalent cations and has hundred-fold reduction in ionic strength. As both the clays and the solution now only contain Na + , no cation exchange or stripping effects are expected to occur. Nevertheless, a significant increase in oil production rate is observed at an even lower level of differential pressure, indicating further removal of adsorbed hydrocarbons from the clays and change to more waterwet state. The only mechanism left to achieve this is by increased repulsive electrostatic forces due to double layer expansion. The low saline brine injection continues until a stationary state of no any more oil production is reached.
  • Period D Injection of 2000 mg/1 NaCl brine, containing 10 mg/1 Ca 2+ .
  • Ca 2+ is expected to reduce the double layer expansion (Schulze-Hardy rule) and to promote adsorption of hydrocarbons to clays, during this stage no significant increase in oil production rate is expected. This is confirmed by the experiment.
  • Period E Injection of 2000 mg/1 NaCl brine, containing 100 mg/1 Ca 2+ does not yield increase in oil production rate for the same reasons as outlined for period D.
  • one core sample was surrounded by brine LSI, the second one by brine LS2 and the third one by brine LS3.
  • Figure 17 shows the results of these experiments and that Brines LS2 and LS3 yielded a response, indicating wettability modification towards increased waterwet state.
  • the absence of a response for brine LSI is attributed to a still to low value for the sulphate to calcium ratio.
  • the pH varied between 6.6 and 7.8.
  • a fresh water effect has (possibly) been observed in an oil production well in a Middle Eastern sandstone reservoir.
  • the formation wettability is thought to be in- between mixed-wet and oil-wet.
  • the field contains light oil of 0.15 mPa.s viscosity. Oil is produced from an aquifer drive.
  • March 2000 additional support is obtained from fresh water injection in an injector well.
  • the salinity of the aquifer water is typically 100000 mg/1 TDS and the salinity of the fresh water is around 1000 mg/1 TDS.
  • Figure 18 shows the observed temporary drop in water cut around 2003, which coincides with breakthrough of the fresh water.
  • the history match of the development of the water cut was much improved upon the assumption that the fresh water injection reduced the fractional flow.
  • Figure 19 shows the observed oil production rate, including the occurrence of a small bank, which coincides with the temporary drop in water cut.
  • the simulated history match of the oil production rate is clearly improved, if a reduction in fraction flow caused by the fresh water injection is assumed. It is estimated that the amount of produced oil has increased by 4 - 5% due to the fresh water injection, with only half of the layers flooded.
  • Fresh Water Flooding design can probably be based on brine characterization via solution Ionic Strength. 6. Probably, the distribution over the rock surface (grain coating) rather than the bulk amount of clay determines whether Fresh Water Flooding can be usefully applied in a particular sandstone reservoir.
  • Fresh Water Flooding puts specific requirements to sandstone reservoirs with respect to initial wettability and clay mineralogy, e.g. there should be no abundancy of smectite and chlorite clays. Hence, not all fields apply.
  • aqueous displacement fluid used in the method according to the invention may comprise a viscosifying polymer and on the basis of the following EXAMPLES 1 and 2 it is explained that in particular Polymer Flooding with relatively high polymer concentrations, for example at least 200 ppm (mass), will improve mobility control by viscosification of the injection water phase to viscosity levels above 1 mPa.s. This results in two benefits:
  • the intrinsic viscosity (m /kg) that characterizes a particular polymer solution is defined as:
  • ⁇ (c) denotes the polymer viscosity at polymer concentration c and ⁇ w (c) , being the viscosity of
  • ki is called: Huggins coefficient.
  • a typical range for the Huggins coefficient is between 0.4 and 1.22 - 2.26 (page 177 of the above-mentioned handbook "Viscosity of Polymer Solutions”) . It thus follows that at low shear, the enhancement in viscosity that can be achieved by polymer addition is governed by the product c.[ ⁇ o ].
  • M denotes polymer molecular weight and Z the number of elementary electrical charges along the polymer chain. Z is given by:
  • ⁇ denotes the degree of ionization
  • CC denotes the degree of hydrolysis
  • Example 2 The composition of a formation brine used in Example 2 is shown in Table 6. It is characterized by overall salinity level of
  • the polymer type chosen is a commercially available hydrolyzed polyacrylamide with molecular weight between 18 x 10 6 and 20 x 10 6 and degree of hydrolysis about 25%. It is experimentally determined that about 1750 ppm of this polymer dissolved in the example formation brine at 51 0 C (example formation temperature) at low shear rate 1 s "1 will yield a solution viscosity of 90 mPa.s.

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  • Organic Chemistry (AREA)
  • Water Treatment By Sorption (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Abstract

La présente invention concerne un procédé permettant d'améliorer la récupération de pétrole à partir d'une formation calcaire ou de dolomite contenant du pétrole brut et de l'eau connée comprenant : la détermination d'un rapport(mole/mole) SO4 2- / Ca2+ dans l'eau connée; et l'injection dans les espaces poreux de la formation d'un fluide aqueux de déplacement avec un rapport molaire (mole/mole) SO4 2- / Ca2+ supérieur à 1 et un rapport molaire (mole/mole) SO4 2- / Ca2+ supérieur à celui de l'eau connée. Le procédé modifie la mouillabilité de la formation calcaire ou de dolomite de sorte que sa mouillabilité par le pétrole est réduite et sa mouillabilité par l'eau est accrue. La figure 17 montre que seuls les saumures LS2 et LS3 vont être efficace dans la modification de mouillabilité. La table 5 montre que des saumures on un rapport molaire (mole/mole) SO4 2- / Ca2+ supérieur à 1 et un rapport molaire (mole/mole) SO4 2- / Ca2+ supérieur à celui de l'eau connée.
EP10703469A 2009-02-13 2010-02-11 Injection de fluide aqueux de déplacement pour améliorer la récupération de pétrole à partir d'une formation calcaire ou de dolomite Withdrawn EP2396383A1 (fr)

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EP09163147 2009-06-18
PCT/EP2010/051676 WO2010092095A1 (fr) 2009-02-13 2010-02-11 Injection de fluide aqueux de déplacement pour améliorer la récupération de pétrole à partir d'une formation calcaire ou de dolomite
EP10703469A EP2396383A1 (fr) 2009-02-13 2010-02-11 Injection de fluide aqueux de déplacement pour améliorer la récupération de pétrole à partir d'une formation calcaire ou de dolomite

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