CN102356141A - Aqueous displacement fluid injection for enhancing oil recovery from a limestone or dolomite formation - Google Patents

Abstract

A method of enhanced oil recovery (EOR) from a limestone or dolomite formation containing crude oil and connate water, the method comprising: determining the SO ₄ ²⁻ /Ca ²⁺ molar ratio (Mol/Mol) in the connate water; and Injecting into the formation pores an aqueous replacement fluid with a molar ratio of SO ₄ ²⁻ /Ca ²⁺ (Mol/Mol) higher than 1 and a molar ratio of SO ₄ ²⁻ /Ca ²⁺ (Mol/Mol) higher than that of connate water. The method adjusts the wettability of limestone or dolomite formations so that their oil wettability decreases and their water wettability increases. Figure 17 shows that only saline LS2 and LS3 are effective in wettability adjustment. It has been given in Table 5 that the SO ₄ ²⁻ /Ca ²⁺ molar ratio (Mol/Mol) of these brines is higher than 1 and the SO ₄ ²⁻ /Ca ²⁺ molar ratio (Mol/Mol) is higher than that of connate water.

Description

Be used to strengthen moisture displacement fluid injection by the oil recovery on Wingdale or rhombspar stratum

Background technology

The present invention relates to that a kind of the method for enhanced oil recovery (EOR) comprises crude oil and primitive water in the hole of said subsurface formations through in the porous subsurface formations, injecting moisture displacement fluid.

This method is known with WO2008/029131 by International Patent Application WO 2008/029124.

International Patent Application WO 2008/029124 discloses in the stratum that comprises sandstone rock and mineral substance with negative ζDian Shi such as clay; The total dissolved solidss of moisture displacement fluid (TDS) content should be at 200-10; In the scope of 000ppm and the polyvalent cation total content of moisture displacement fluid should be with the ratio of the polyvalent cation total content of primitive water less than 1.

International Patent Application WO 2008/029131 discloses the injection water-bearing media; The free divalent cation content that said water-bearing media comprises the water-soluble cpds that contains at least one oxygen and/or nitrogen-atoms and wherein said medium and the ratio of the free divalent cation content of formation crude unboiled water are less than 1.

Described that salt and other chemical and rock forming mineral and/or crude oil in the moisture displacement fluid interacts and therefore other prior art reference relevant with enhanced oil recovery (EOR) method list in as follows:

1.Appelo，C.A.J.and?Postma?D.，1993，Geochemistry，Groundwater?and?Pollution，A.A.Balkema，Rotterdam/Brookfield.

2.Anderson，W.G.，October?1986，Wettability?Literature?Survey-Part?1：Rock/Oil/Brine?Interactions?and?the?Effects?of?Core?Handling?on?Wettability，J.of?Petr.Techn.，pp.1125-1144.

3.Anderson，W.G.，December?1987，Wettability?Literature?Survey-Part?6：The?Effects?of?Wettability?on?Waterflooding，J.of?Petr.Techn.，pp.1605-1622.

4.Austad，T.，Strand，S.，Hognesen，E.J.and?Zhang，P.，2005，Seawater?as?IOR?fluid?in?Fractured?Chalk，Paper?SPE?93000.

5.Austad，T.，Seawater?in?Chalk：An?EOR?and?Compaction?Fluid，2008，Paper?ARMA?08-100，presented?at?the?American?Rock?Mechanics?Assiociation，San?Francisco，June?29-July?2.

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7.Buckley，J.S.，Takamura，K.and?Morrow，N.R.，August?1989，Influence?of?Electrical?Surface?Charges?on?the?Wetting?Properties?of?Crude?Oils，SPE?Reservoir?Engineering，pp.332-340.

8.Clementz，D.M.，1976，Interaction?of?petroleum?Heavy?Ends?with?Montmorillonite，Clays?and?Clay?Minerals，vol.34，pp.312-319.

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10.Craig，F.F.Jr.，1971，The?Reservoir?Engineering?Aspects?of?Waterflooding，SPE?Monograph?Series，Volume?3，H.L.Doherty?Series.

11.Dubey，S.T.and?Doe，P.H.，August?1993，Base?number?and?Wetting?Properties?of?Crude?Oils，SPE?Reservoir?Engineering，pp.195-200.

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13.Hagoort，December?1974，J.，Displacement?Stability?of?Water?Drives?in?Water-Wet，Connate?Water-bearing?reservoirs.Soc.Petr.Eng.J.，pp.63-71.

14.Jerauld，G.R.，Lin，C.Y.，Webb，K.J.and?Seccombe，J.C.，September?2006，Modeling?Low-Salinity?Waterflooding，SPE?102239，Paper?presented?at?the?2006?SPE?Annual?Technical?Conference?and?Exhibition，San?Antonio，Texas，U.S.A.，24-27.

15.Lager，A.，Webb，K.J.，Black，C.J.J.，Singleton，M.and?Sorbie，K.S.，September?2006，Low?Salinity?Oil?Recovery-An?Experimental?Investigation，SCA?paper?2006-36，presented?at?the?International?Symposium?of?the?Society?of?Core?Analysts，Trondheim，Norway.

16.Lager，A.，Webb，K.J.and?Black，C.J.J.，April?2007，Impact?of?Brine?Chemistry?on?Oil?Recovery，Paper?A24presented?on?14 ^th?European?Symposium?on?Improved?Oil?Recovery-Cairo，Egypt.

17.Lager，A.，Webb，K.J.，Collins，I.R.and?Richmond，D.M.，2008，LoSalTM?Enhanced?Oil?Recovery：Evidence?of?Enhanced?Oil?Recovery?at?the?Reservoir?Scale，paper?SPE?113976.

18.Looyestijn，W.J.and?Hofman，J.p.，Wettability-Index?Determination?by?Nuclear?Magnetic?Resonance，April?2006?SPE?Reservoir?Evaluation?and?Engineering，pp.146-153.

19.Maas，J.G.，Wit，K.and?Morrow，N.R.，2001，Enhanced?Oil?Recovery?by?Dilution?of?Injection?Brine：Further?Interpretation?of?Experimental?Results.Paper?SCA2001-13.

20.McGuire，P.L.，Chatman，J.R.，Paskvan，F.K.，Sommer，D.M.and?Carini，F.H.，2005，Low?Salinity?Oil?Recovery：An?Exciting?New?EOR?Opportunity?for?Alaska′s?North?Slope，paper?SPE?93903?presented?at?2005?SPE?Western?Regional?Meeting，Irvine，Ca.

21.Morrow，N.R.et?al：″Prospects?of?Improved?Oil?Recovery?Related?to?Wettability?and?Brine?Composition″，paper?presented?at?the?1996International?Symposium?on?Evaluation?of?Reservoir?Wettability?and?Its?Effect?on?Oil?Recovery，Montpellier，France，11-13?September.

22.Mysels，K.J.，1967，Introduction?to?Colloid?Chemistry，Interscience?Publishers，New?York.

23.Pope，G.A.，June?1980，The?application?of?Fractional?Flow?Theory?to?Enhanced?Oil?Recovery，SPE?7660；also?Society?of?Petroleum?Engineers?Journal，pp.191-205.

24.Robertson，E.P.，2007，Low-Salinity?Waterflooding?To?Improve?Oil?Recovery-Historical?Field?Evidence，SPE?109965.

25.Rueslatten，H.G.，Hjelmeland，O.and?Selle，O.M.，1994，Wettability?of?Reservoir?Rocks?and?the?influence?of?organo-metallic?compounds，North?Sea?oil?and?gas?reservoir，3：317-324.

26.Shaw，D.J.，1966，Introduction?to?Colloid?and?Surface?Chemistry，Butterworths，London.

27.Strand，S.，Austad，T.，Puntervold，T.，Hognesen，E.J.，Olsen，M.and?Barstad，S.M.F.，2008，″Smart?Water?For?Oil?Recovery?from?Fractured?Limestone：APreliminary?Study，Energy?Fuels，22(5)，3126-3133.

28.Stoll，W.M.，Hofman，J.P.，Ligthelm，D.J.，Faber，M.J.and?van?den?Hoek，P.J.，June?2008，Towards?Field-Scale?Wettability?Modification-The?Limitations?of?Diffusive?Ttansport，SPE?Reservoir?Evaluation?&?Engineering，pp.633-640.

29.Tang，G.and?Morrow，N.R.，November?1997，Salinity，Temperature，Oil?Composition?and?Oil?Recovery?by?Waterflooding，SPE?Reservoir?Engineering，pp.269-276.

30.Tang，G.and?Morrow，N.R.，1999，Oil?Recovery?by?Waterflooding?and?Imbibition-Invading?Brine?Cation?Valency?and?Salinity，paper?SCA-9911

31.Tang，G.and?Morrow，N.R.，1999，Influence?of?Brine?Composition?and?Fines?Migration?on?Crude?Oil/Brine/Rock?Interactions?and?Oil?Recovery，J.of?Petroleum?Science?and?Engineering?24，99-111.

32.Tang，G.and?Morrow，N.R.，2002，Injection?of?Dilute?Brine?and?Crude?Oil/Brine/Rock?Interactiohs，Environmental?Mechanics：Water，Mass?and?Energy?Transfer?in?the?Biosphere，Geophysical?Monograph?129，pp.171-179.

33.Valocchi，A.J.，Street，R.L.and?Roberts，P.V.，October?1981，Transport?of?Ion-Exchanging?Solutes?in?Groundwater：Chromatographic?Theory?and?Field?Simulation，Water?Resources?Research，vol.17，no.5，pp.1517-1527.

34.Van?Olphen，H.，1963，An?Introduction?to?Clay?Coloid?Chemistry，Interscience?Publishers，John?Wiley?and?Sons，New?York.

35.Webb，K.J.，Black，C.J.J.and?Al-Ajeel，H.，April2003，Low?Salinity?Oil?Recovery-Log-Inject-Log，paper?SPE?81460?presented?at?SPE?13 ^th?Middle?East?Oil?Show?&?Conference，Bahrain?5-8?April.

36.Zhang，P.，Tweneyo，M.T.and?Austad，T.，200.7，Wettability?Alteration?and?Improved?Oil?Recovery?by?Spontaneous?Imbibition?of?Seawater?into?Chalk：Impact?of?the?potential?determining?ions?Ca ²⁺，Mg ²⁺?and?SO ₄ ^2-，Colloids?and?Surfaces.A.Physicochemical?Eng.Aspects?301，199-208.

37.Zhang，Y.and?Morrow，N.R.，2006，Comparison?of?Secondary?and?Tertiary?Recovery?with?Change?in?Injection?Brine?composition?for?Crude?Oil/Sandstone?Combinations，SPE?paper?99757.

The method of the preamble of claim 1 is known by SPE paper 93000 " Seawater as IOR fluid in Fractured Chalk ", and this article is equaled on the 2005 International Symposium International Symposium on Oilfield Chemistry of texas,U.S Houston, to propose 2-4 day in February, 2005 by T.Austad.This SPE article is confined in the fracture chalk, use described IOR fluid; And the instruction of this SPE article can not extend to other stratum different with the chalk stratum of rupturing, and this is that carbonate storage layer is normally unsuccessful through water displacing oil raising oil recovery because the preamble of this article is pointed out to rupture.Reference 36 has also been instructed ion Ca ²⁺, Mg ²⁺And SO ₄ ^2-Separately through seawater in sucking chalk and to wettability modification with to improve oil recovery (IOR) influential.

The purpose of this invention is to provide further improved enhanced oil recovery (EOR) method, wherein moisture displacement fluid is injected in the porous stone lime stone or rhombspar stratum that in hole, contains crude oil and primitive water.

Summary of the invention

According to the present invention, the method for a kind of reinforcement by the oil recovering of porous subsurface formations is provided, in the hole of said subsurface formations, contain crude oil and primitive water, wherein said primitive water comprises SO ₄ ^2-And Ca ²⁺Ion, said method comprises:

Confirm the SO in the primitive water ₄ ^2-/ Ca ²⁺Mol ratio (Mol/Mol); With

In said hole, inject SO ₄ ^2-/ Ca ²⁺Mol ratio (Mol/Mol) is higher than 1 and SO ₄ ^2-/ Ca ²⁺The moisture displacement fluid that mol ratio (Mol/Mol) is higher than primitive water;

Be characterised in that said porous subsurface formations is Wingdale or rhombspar stratum.

Said method can be used for adjusting the wettability on Wingdale or rhombspar stratum, thereby their glossy moist reduction and wettability are increased.

Figure 17 shows that to have only salt solution LS2 and LS3 effective aspect the wettability adjustment.In table 5, provided their SO ₄ ^2-/ Ca ²⁺Mol ratio (Mol/Mol) is higher than 1 and SO ₄ ^2-/ Ca ²⁺Mol ratio (Mol/Mol) is higher than primitive water.

Randomly, moisture displacement fluid is higher than 50 ℃ down and be injected in the said hole and said method also is included in and in hole, injects SO as the slug of 0.2-0.8PV in temperature ₄ ^2-/ Ca ²⁺Mol ratio (Mol/Mol) is injected untreated moisture displacement fluid than after the high moisture displacement fluid slug of primitive water.

Moisture displacement fluid can comprise the water from rivers, fresh water aquifer, lake, ocean or ocean, handles said water and makes it be converted into SO ₄ ^2-/ Ca ²⁺The moisture displacement fluid that mol ratio (Mol/Mol) is higher than primitive water in the hole.

These and other characteristic, embodiment and the advantage of the inventive method is described in appended claim, summary and the detailed description by the indefiniteness embodiment of said accompanying drawing and form description subsequently; In said description, used reference marker, these reference markers refer to the corresponding reference marker in accompanying drawing and form, described.

Description of drawings

Table 1 has provided in the experimental data of 55 ℃ of following Berea centrefuge experiments and undiluted salt solution to be formed.

Table 2 has provided the experimental data and the undiluted salt solution of the inner experiment of Berea and has formed:

The oiliness ability of Dagang class salt solution (Ref.32, Tang et al, 2002) and Berea and BrentBravo.

Table 3 has provided undiluted pure NaCl, CaCl in the Berea experiment ₂And MgCl ₂Brinish is formed.

Table 4 has provided experimental data and the salt solution that Middle East sandstone rock core is experimentized.

Important salt solution characteristic is represented with runic.

Table 5 has provided and in the Wingdale core sample of the Middle East, has carried out self-priming and test applied brinish and form.

Table 6 has provided the composition instance of formation brine.

In table 1-6, possibly important salt solution performance all represent with runic.

Fig. 1 provides:

(a) phenomenon of wettability definition; With

(b) the connection mechanism between clay and the oil.

Fig. 2 has provided oil phase to be reduced along with glossy moist increase perviousness.

Fig. 3 has provided the synoptic diagram that between high salinity and low salinity saltwater environment medium clay soil surface and oil, connects.

Ca ²⁺Ion is represented in the salt solution polyvalent cation as the bridge between clay and the oil particles.

Fig. 4 has provided the total salinity levels TDS and the divalent cation concentration (Ca of inner storage layer local water ²⁺+ Mg ²⁺) between association.

Gray data point is represented the Brent seawater.

Fig. 5 has provided the relation between wettability index W and the total salinity levels.All figure lines have been described different glossy moist levels.

Fig. 6 has provided the moisture phase flow rate to be reduced and reduces along with salinity levels.

Water saturation when Fig. 7 has provided the highrank fuel salinity water displacement of reservoir oil and the fresh water displacement of reservoir oil distributes.

Fig. 8 has provided for one dimension flows, the contrast that the output of the salt water displacing oil (dark-grey colo(u)r streak) and the fresh water displacement of reservoir oil (light grey line) distributes.Dotted line is represented water ratio.

The Characteristic pressures that Fig. 9 has provided during the fresh water displacement of reservoir oil distributes.

Figure 10 has provided at 55 ℃ and has down undilutedly distributed with the centrifugal absorption capillary pressure of dilution salt solution for Berea rock core plug.

Figure 11 A-C has provided in the inside experiment results of 60 ℃ of following divalent cations to the effect of Berea.The NMR wettability determination shows that being replaced by monovalent cation causes the absorption of rock forming mineral confrontation heavy hydrocarbon to reduce.

Figure 12 has provided under envrionment conditions the self-priming experiment to Berea rock core material.Verified the recovery of petroleum production after switching to fresh water.

Figure 13 has confirmed under envrionment conditions through injecting CaCl to Berea rock core material ₂Salt solution and suppress petroleum production.

Figure 14 has provided the SEM figure of Middle East core sample.Pollutent on hole wall possibly be the dispersive kaolin particle.

Figure 15 has confirmed switching to the petroleum production that fresh water injects the recovery under the pressure reduction of reduction of (under the envrionment conditions) back.

When Figure 16 has provided the different injection brine composition of under envrionment conditions application in five continuous times to the experiment of Middle East rock core material:

Period A: local water injects.

Period B: inject 240000mg/l NaCl.

Period C: inject 2000mg/l NaCl.

Period D: inject 2000mg/l NaCl+10mg/l Ca ²⁺

Period E: inject 2000mg/l NaCl+100mg/l Ca ²⁺

Figure 17 has provided under 60 ℃ the self-priming experimental result to Middle East Wingdale rock core material.

Figure 18 has provided in Middle East sandstone storage layer in recovery well possible fresh water effect in observed water ratio counter-rotating.

Figure 19 has provided in Middle East sandstone storage layer in recovery well in fresh water effect possible aspect the oil production rate.

Figure 20 has provided for the different tackify polyacrylamide polymers with molecular weight M and certain degree of hydrolysis, and intrinsic viscosity is to the dependence of salt solution ionic strength.

Figure 22 has provided in having shown in the table 6 formation brine of forming the tackifying ability of polyacrylamide after the commercially available hydrolysis.

Figure 23 has provided for the polymer concentration data area of 90mPa.s viscosity with based on the current estimate of intrinsic viscosity.

Embodiment

Ref.4 (SPE article 93000 " Seawater as IOR fluid in Fractured Chalk ", by people such as Austad propose) discloses for the chalk material of appearing, possible decisive ion such as Ca in the seawater ²⁺, Mg ²⁺And SO ₄ ^2-Type and the relative concentration wettability modification that might make the material of appearing be Yishui River wetting regime more, this can improve oil recovery.

Chalk is the biosynthesizing material that is formed by planktonic organism.It has reactive surfaces.When by sea water immersion, on geology time scale, its recrystallization becomes Wingdale or rhombspar, for example that kind that takes place in the Middle East.Wingdale and rhombspar all are inorganic materials, than the reactive difference of chalk and more stable on thermodynamics.Therefore, the research that experimentizes has obtained improvement EOR method of the present invention, and said method comprises: confirm the SO in the primitive water ₄ ^2-/ Ca ²⁺Mol ratio (Mol/Mol); With in hole, inject SO ₄ ^2-/ Ca ²⁺The moisture displacement fluid that mol ratio is higher than primitive water.

The inventive method based on understanding be because salt solution is formed deep influence storage layer wettability and therefore influenced microcosmic and drive and sweep; It is the partial strategy that improves existing and following water displacing oil project petroleum production that salt solution is injected in careful design, in sandstone and carbonate storage layer and and EOR projects combo subsequently in all be like this.

According to the present invention, found following result:

(1) local water with high salinity level is associated with higher concentration of multivalent cations.This makes (sandstone) storage layer wettability more be prone to glossy wet;

(2) in having the Middle East sandstone storage layer of high salinity local water, inject during the penetrating of light river, field observation to the temporary transient reduction of water ratio be interpreted as causing by the oil band of leading fresh water slug;

(3) said oil band comes from through wettability and is adjusted to more Yishui River wetting regime and improved driving swept.This explanation has obtained the affirmation of laboratory result;

(4) if far surpass the content of calcium ion invading sulfate anion in brine system ionic content, then the experiment confirm in Wingdale rock core plug similar wettability adjustment.

According to these results, can obtain as drawing a conclusion:

(1) fresh water injects and can make the several at least percentage points of final oil recovery increase;

(2) sweep front end and can further improve petroleum production within the specific limits through in the fresh water slug, adding stable the driving of low concentration polymer;

(3) if plan EOR project in the future, suggestion is washed with fresh water in advance, thereby obtains more favourable oily desaturation distribution and practice thrift the polymkeric substance cost;

(4) when seawater being injected into light local water storage layer, should consider from seawater, to remove polyvalent cation, thereby avoiding said storage layer to become more being prone to glossy wetting causes driving the potentially dangerous of sweeping reduction.

The strategy that control water is formed can extend to carbonate storage layer.

In the description of the inventive method and appended claim, form and accompanying drawing, used following abbreviation and name:

The CEC cation exchange capacity (CEC)

E _dDisplacement (microcosmic) displacement sweep efficiency

E _VolThe volume displacement sweep efficiency

I ionic strength (Mol/l), wherein

C _iBe volumetric molar concentration (Mol/l) and z _iFor specifically ionic valence state and I have amounted to whole negatively charged ion and the positively charged ion in the solution.

IFT interfacial tension (N/m)

M water/oil mobility ratio

N solution equivalent concentration (meq/l)

The PV pore volume

The SEM scanning electronic microscope

S _OrwActual Residual oil is saturated

S _{O, remain}Surplus oil is saturated

The TDS total dissolved solids

W wettability index: W=0 is water-wet; W=1 is glossy wet.

WM salt wettability adjustment salt solution

In the past during the decade, in sandstone and carbonate storage layer, inject the salt solution with selected ion composition and developed into emerging IOR technology, purpose is to improve the microcosmic displacement sweep efficiency; The result makes remaining oil saturation reduce (Ref.29-31, Tang and Morrow, 1997; 1999,2002; Ref.19, Maas et al, 2001; Ref.35, Webb et al, 2003, and Ref.20, McGuire et al, 2005).Recently, some some evidences from the useful influence of the fresh water displacement of reservoir oil of historical field data (Robertson, 2007) are disclosed.

The in-house research of this problem is contained a plurality of subjects, comprise that rock core flows and the experiment of Amott self-priming, colloid chemistry and petroleum engineering.Below in the detailed description about rock wettability and oil recovery mechanism, result of study is provided and has pointed out that this technology uses the most favourable wherein.

Fig. 1 shows that the wettability of storage layer rock can be defined as the mark of the rock surface that is coated by adsorbed hydrocarbon on phenomenon.The parameter that makes things convenient for that is used to characterize is wettability index W.During W=0, when porous medium was complete water-wet (zero hydrocarbon coats) and W=1, porous medium was glossy fully wet (hydrocarbon coats fully).

The phenomenon association that Fig. 2 has provided between wettability index W and the relative permeability causes in big saturation ratio scope, and along with glossy moist increase, the relative permeability of oil reduces and the relative permeability of water increases.When this was illustrated in glossy moist increase, with respect to water, oil was preferred adhering on the rock and is difficult for flowing.This result makes the microcosmic displacement sweep efficiency effective inadequately.Near actual Residual oil saturation ratio S _Orw(no matter this value is for when avoiding peeling off the desaturation that causes by viscosity during the oily saturation levels (Ref.3, Anderson, 1987) how applied pressure reduction all can not further reduce, and oil phase possibly have intersection to the perviousness curve.When glossy wet condition increased, oil film flows to be increased, and this continuous oil owing to rock surface coats and becomes possibility.This oil film flows and allows slow oil extraction to low saturation (Ref.2, Anderson, 1986).This process maybe be effective inadequately in the porous medium that the rock surface that is defined as easier water-wet more cleans.

If because buoyancy result later stage oil extraction in storage floor district has tangible contribution to oil recovery, then this oil film flow process is correlated with after injecting water intrusion.Mainly come from the water displacing oil process of the normal transverse movement of said fluid front end under the diffusion flow condition for oil recovery wherein, then its importance is less better.

Fig. 2 is illustrated under the sort of situation, and oil field or well are abandoned the remaining oil saturation S that the relative permeability of oil will reach the low-level of common 1/1000-1/100 and in the oil field, stay under 95% moisture content level for example _{0, residue}Will be far above actual Residual oil saturation ratio S _OrwThen, the water saturation level that can obtain through water displacing oil may be increased several pore volumes (PV) percentage ratio towards the wettability adjustment of Yishui River wetting regime more, and reduce remaining oil saturation similarly.Therefore, the final oil mass that before abandoning, can exploit also can increase several PV percentage ratios.The raising of microcosmic displacement sweep efficiency can be estimated (Ref.23, Pope, 1980 by the phase-splitting flow theory; Ref.14, Jerauld et al, 2006).

Relation between the salt water chemistry and wettability in the sandstone storage layer will be described in the lower section.

In the pH scope that in sandstone storage layer, runs into usually; Silica sphere (Ref.2; Anderson; 1986) and crude oil (Ref.7, Buckley, 1989) all have negative charge; People will expect that hydrocarbon fully can the coated silica rock; Be that people will expect that silicon-dioxide will keep complete water-wet (Ref.11, Dubey et al, 1993).But there are some pollutents usually, particularly are arranged in the charged clay particle of dispersive on the hole wall.These particles very easily react and have a high specific surface area (Ref.8, Clementz, 1976).The behavior of clay mineral resembles colloidal particle, and in the pH scope that in the storage layer, runs into, they are usually because imperfect and electronegative (Ref.34, Van Olphen, 1963 of lattice; Ref.1, Appelo, 1993).According to the multivalent metal cation such as the Ca that think in the salt solution ²⁺And Mg ²⁺As the bridge between electronegative oil and the clay mineral (Ref.2, Anderson, 1986; Ref.15 & 16, Lager et al, 2006,2007).

Fig. 3 is illustrated in sufficiently high salinity levels and exists down, can obtain enough nominal price positively charged ions and mask their negative charge, and the result has suppressed electrostatic repulsion forces.This makes that slip plane place negative potential (so-called ζDian Shi) level between powered surfaces and salt brine solution is lower.ζDian Shi at the slip plane place is considered to the good approximation of (Stern) electromotive force on the Stern layer.Said Stern layer is defined as the colloid wall and equals the space between the distance of ionic radius, neutral (Ref.26, Shaw, 1966; Ref.22, Mysels, 1967).In the environment of enough high salinity, oil can be formed with organic metal complex (Ref.25, Rueslatten, 1994) with these clay particle reactions.This make surface of clay extremely hydrophobic with cause local glossy wet (Ref.9, Clementz, 1982).

Fig. 4 shows the storage layer data analysis according to inside, and the formation brine with higher salinity levels demonstrates higher divalence/polyvalent cation concentration.

For given crude oil with specific oil wettability (being characterized by asphalt content, acid number and base number), have higher salinity levels and thereby formation brine expection with higher polyvalent cation concentration can produce and more be prone to glossy wet condition.

Fig. 5 provides this point and how to obtain the affirmation of inner storage layer data.

In with the lower section, will be described in the wettability Adjusting Mechanism of the fresh water displacement of reservoir oil in the sandstone storage layer.

Through reducing the total salinity levels in the salt brine solution and particularly reducing polyvalent cation and reduce electrolyte content and (promptly reduce ionic strength I=1/2. ∑ C _i.z _i ², C wherein _iBe the volumetric molar concentration of ionic species i, z _iBe its valence state, and amount to all positively charged ion and negatively charged ion in the salt solution), will reduce cationic screen potential.This causes around the diffusion double layer of clay and oil particles and expands, and has increased the abswolute level of ζDian Shi.

Fig. 3 has provided the how corresponding Coulomb repulsion that has increased between clay particle and the oil of this point.

In case what believe at present is the connection power that repulsive force surpasses the polyvalent cation bridge, then oil particles maybe be from the surface of clay desorption.This will make the rock surface mark that has been coated by oil reduce, and this means that again wetting regime changes towards increasing water-wet.Above-mentioned mechanism can occur between the fresh water slug of stopping up long-pending high salinity local water and intrusion at the interface especially.

If electrolyte concentration further reduces, the inner mutual electrostatic repulsion forces of clay mineral begins to surpass connection power, and this causes clay to separate flocculation and formation damage takes place.People such as Zhang 2006 grades possibly be under the condition of formation damage, to implement to the rock core flowing experiment of the fresh water displacement of reservoir oil, have consequently increased the pressure reduction on the rock core.This will make the wettability adjustment towards the wettability (Ref.30, Tang and Morrow, 1999) that increases through peel off oil-bearing clay fine particle from hole wall.But the displacement of reservoir oil of suggest fresh water keeps limited salinity levels beyond in the formation damage zone, and certificate thinks that wherein adsorbed hydrocarbon is driven away from clay, but clay is kept perfectly.

Base exchange process in the sandstone storage layer will be described in the lower section.

When the fresh water displacement of reservoir oil in the stratum, the cationic polyelectrolyte content of water is less than the cation exchange capacity (CEC) (CEC) on stratum usually.In this case, the cation composition of injection brinish is confirmed by the cation composition on the hole CLAY MINERALS AND THEIR SIGNIFICANCE matter then in the zone (so-called salinity front end) after injecting between water and the local water displacement of reservoir oil front end and then.According to the law of mass action, Na in the salt solution after the salinity front end ⁺Concentration reduces factor-alpha＞1, and this is accompanied by divalent cation concentration (Ca ²⁺, Mg ²⁺) the reduction factor-alpha ²(Ref.1, Appelo, 1993).This effect can make the concentration ratio local water of divalent cation in the zone after the said salinity front end all low with injection water.This low salinity salt solution from injection extracts divalent cation and in fact after the salinity front end penetrates, has observed (Ref.33, Valocchi, 1981; Ref.17, Lager et al, 2008).

Reduce the ionic strength that the brinish concentration of multivalent cations will reduce solution through extracting, and might effect be arranged electrostatic double layer expansion and wettability adjustment.But expection positively charged ion leaching process is not crucial to realizing the wettability adjustment.Having no under the positively charged ion extraction in addition, expection has the salt solution that enough hangs down solution ion strength can obviously adjust wettability.This point is affirmed by the rock core flowing experiment of describing subsequently.

In with the lower section, will be described in the effect of the high salinity displacement of reservoir oil in the sandstone storage layer.

Imagination is injected saliferous salt solution such as the seawater with high polyvalent cation concentration in the oil column of the oil measure layer with low salinity local water (having low polyvalent cation concentration), the wettability of this storage layer possibly changed to by relative water-wet state more to be prone to glossy wet condition.This possibly be to be caused by the chemical reaction between the polyvalent cation of displacement of reservoir oil front end place's oil and clay particle and injection salt solution, and the result increases the hydrocarbon coating of rock surface.This causes more being prone to glossy wet condition and net result and possibly when not have effective water/oily gravity oil extraction process, increase remaining oil saturation and reduce final oil recovery.

Relation between the wettability and oil recovery in the carbonate storage layer will be described in the lower section.

When pH for example is lower than 9.5, carbonate surface positively charged (Ref.2, Anderson, 1986; Ref.1, Apello, 1993).Their clay content is usually enough little so that be left in the basket.Under storage layer pH condition, electronegative oil particles will be adsorbed onto on the carbonate rock surface of positively charged through electrostatic attraction.Therefore, expect that said carbonate is that mixed lubrication is to glossy wet.

Because the carbonate positively charged, it has the negatively charged ion such as the SO of anion exchange capacity and decision electromotive force ₄ ^2-Can be adsorbed onto above it.The fluid of known sulfur-bearing acid group such as seawater can be Yishui River wetting regime (Ref.4-5, Austad, 2005,2008) more with the wettability modification of carbonate.Hypothesis to this mechanism is possible is described (Ref.36, Zhang, 2007) by people such as Zhang.In brief, it is believed that it is near excessive calcium bonded result sulfate radical absorption and the carbonate surface, the latter allows sulfate radical to replace the hydrocarbon of absorption.Under comparatively high temps, magnesium has this replacement process that helps.This is a kind of anion exchange procedures.

The wettability Adjusting Mechanism that can know carbonate surface is different fully with sandstone: wherein need not expand through electrostatic double layer increases electrostatic repulsion forces and does not therefore need low electrolyte content.

In with the lower section, will be described in the relation between the wettability and displacement sweep efficiency under water/oily gravity oil extraction that do not exist.

As described below at homogenous porous media displace (microcosmic) displacement sweep efficiency.When not having water/oily gravity oil extraction, the oil in homogenous porous media under the diffusion flow condition/water replacement process can be described (Ref.23, Pope, 1980 by the phase-splitting flow theory; Ref.14, Jerauld, 2006).

Fig. 6-8 has provided the representative instance that mixes wetting stratum and has calculated.This instance has confirmed reducing through injecting wettability adjustment (WM) brinish wettability adjustment back moisture phase flow rate; By WM brine slug displacement local water; Cause the local water before the WM slug to stop up long-pending; And increased ultimate recovery factor and therefore increased displacement (microcosmic) the displacement sweep efficiency E under the level of abandoning of 95% water ratio _dE _dBe defined as oily saturation ratio mark, this part oil will be from contacting with water or being come out by that part of storage layer displace that water drive is swept.When this method when first day of water displacing oil uses is the most effective, this is to improve that to drive the oil mass of sweeping be its maximum value because possibly benefit from.

To the thoroughly evaluating of oily method of replacing not only needs assessment saturation distribution, the also pressure distribution of needs assessment gained phase.According to impacting front end velocity ratio standard (Ref.13, Hagoort, 1974),, then, possibly there is unsettled displacement as the result of viscous fingering if the pressure gradient of displacement fluid is lower than by the pressure gradient of displacement fluid.Several calculated examples show: because saturation effect is being injected slug and formerly stopped up the impact place WM-displacement of reservoir oil potentially unstable between the long-pending formation brine.

Fig. 9 shows that although the relative permeability of water is owing to the wettability adjustment reduces, the flowability of this slug maybe be than formerly the local water band is higher owing to invade water saturation high relatively in the district (purpose is to improve to replace to drive to sweep) at injectant.

The flowability of fresh water slug further increases owing to the brine viscosity that reduces to a certain extent.Make the more tacky a little unstable that can avoid viscosity of WM brine slug through adding some low concentration polymers.Particularly under the fresh waterflood oil condition, when the polyacrylamide after using polymer such as the hydrolysis (this polymkeric substance in low salinity salt solution viscosity increase and the absorption reduction aspect effective especially) time, relevant chemical expense maybe be relatively low.

The additional contribution of small size low-permeability point to the displacement displacement sweep efficiency will be described in the lower section.

In layer, the stratum will demonstrate wide perviousness level and change, and comprise the low-permeability point, and they possibly mainly keep bypass in the highrank fuel salinity water oil displacement process.If the stratum is wetting to glossy wet for mixing, then, the adverse current of capillary drive possibly almost have no petroleum production from these bypass points because drawing.If but these spot sizes enough little (for example several centimetres), then WM salt solution can be invaded these points (Ref.28, Stoll et al, 2008) through molecular diffusion.Time scale for molecular diffusion; It can be several years; These small size points can be drawn through adverse current and produce more oil, and this is the result of wettability adjustment, and said wettability adjustment maybe and be driven the increase of sweeping to displacement owing to molecular diffusion becomes has contribution.

The volume displacement sweep efficiency of enhanced oil recovery method will be described in the lower section.

To the evaluation of whole potential benefits of in sandstone storage layer, using fresh water displacement of reservoir oil needs assessment displacement displacement sweep efficiency E not only _d, and needs assessment volume displacement sweep efficiency E _VolE _VolBe defined as the storage layer volume fraction that will contact with injection water.It is by vertical displacement sweep efficiency E _vWith area displacement sweep efficiency E _aProduct form.Decision E _VolThe single most important characteristic of water displacing oil be that water/oil mobility compares M; It is according in storage layer, being in the displacement fluid that relates in the displacement of reservoir oil and being defined by the effective permeability of displacement fluid and viscosity at two differences and the point that separates; The relative permeability of water is estimated (Ref.10 under average water saturation after the displacement front end; Craig, 1971).Can show area displacement sweep efficiency E by the association that the laboratory experiment to the pattern displacement of reservoir oil that amplifies obtains _aAlong with M increases and reduces.There is not the linear laminar flow storage layer model (Ref.12,1950) of Dykstra and Parsons cross-flow to show, vertical displacement sweep efficiency E _vAlong with increasing similarly, reduces M.Cross-flow causes this trend further to increase (Ref.10, Craig, 1971).

As explained earlier, the WM slug possibly experience mobile increasing.Unstable except possible viscosity noted earlier, this also might cause mobile some increases than M, and some losses that therefore cause the volume displacement sweep efficiency.Therefore, it possibly be useful in WM salt solution, adding some low concentration polymers, and this is not only avoided the viscosity unstable, and compensates some possible volume displacement sweep efficiency losses.

The synergy of preparatory flushing of wettability adjustment and EOR will be described in the lower section.

It is believed that in optimal design the make up water that is used for polymer flooding should meet WM salt solution standard.Then, owing to adsorbing the preflush that the slug fore-end that exhausts its chemical possibly partly be used as the wettability adjustment.Subsequently basic surface promoting agent polymer slug (in fact causing violent the reduction but still the interfacial tension of non-zero) possibly have benefited from maybe be more favourable oily desaturation distribute (Ref.6, Baviere, 1991).

The experimental verification of internal lab experiment will be described in the lower section.

Recover core sample to be carried out two types of experiments after the wettability through cleaning and aging careful, with checking because WM salt solution is invaded towards the more wettability adjustment of Yishui River wetting regime:

1.Amott self-priming experiment.To use the rock core of crude oil and formation brine cleaning and aging (Ref.2, Anderson, 1986) to put into Glass tubing, and soak with identical formation brine.Recover the oil through self-priming, up to reaching the kapillary balance.Subsequently, soak the formation brine of usefulness with the displacement of WM salt solution.Recover to recover the oil and confirm in rock core, to have produced positive capillary pressure.Have only when the inner salt solution of rock core and form because molecular diffusion changes and made that the adsorbed hydrocarbons amount reduces on the rock surface, this ability is possible.

2. low speed rock core oil displacement experiment.For fear of formation damage, the WM salt solution of in experiment, using has sufficiently high salinity levels.Formation damage can be observed by the increase gradually of pressure reduction during rock core flowing experiment, and should avoid to prevent when explaining experiment because that so-called kapillary terminal effects causes is unnecessary complicated.The typical consequence of rock core flowing experiment is following: when injection period of local water finishes, set up stable state, wherein recovering the oil has stopped and water pressure reduction is maintenance level.In this case, the water saturation in the rock core distributes and makes that except the medium and small buoyancy of vertical orientated rock core, capillary pressure negative on rock core just in time balances each other with water pressure, and this is because the result of the fixedly viscosity pressure drop that water flows causes.After switching to WM salt solution, can identical or even lower a little rock core on recover to recover the oil under the water pressure reduction.This is just possible when only the capillary pressure force level on rock core reduces.Then, the water saturation in the rock core increases (with therefore increasing some petroleum productions), and the capillary pressure force level on said rock core is increased to and the water pressure equilibrium once more.Owing to recover the oil, the water in the said rock core is mobile to be increased, and causes some additional pressure reduction reductions on the rock core.After switching to the injection of WM salt solution, additional petroleum production itself does not confirm to have taken place towards the more wettability adjustment of Yishui River wetting regime uniquely.Oil/water termination tension force reduces will produce similar result.Very clearly explanation above:, be necessary for high and additional measurement of low salinity brinish oil/water termination tensile for the proper interpretation experimental result.Ensuing internal lab work is verified: in the experimental error scope, do not have evidence to show that water/oily interfacial tension depends on salinity levels.If people still try to find some trend, for the system of our research, trend towards increasing rather than reducing at least at dilution rear interface tension force.In addition; Need carry out fluid viscosity and density measurement, definite original position saturation distribution and the digital simulation of reaching of NMR wettability; Thereby for example possibly changing of relative permeability curve provided conclusion more accurately, the sign that said relative permeability curve change is the wettability adjustment and relevant with raising petroleum production on storage layer scale.

The conclusion that can know rock core flowing experiment always will just can draw by simulation model and some inevitable hypothesis, and the error territory of experimental result will make conclusion strong inadequately.Therefore, in order to obtain the strong evidence of relevant wettability adjustment, make the rock core displacement of reservoir oil be accompanied by the experiment of Amott self-priming and carry out.Although there is already mentioned difficulty; But rock core flowing experiment (comprising that monitoring pressure reduction distributes and the original position saturation distribution) is for be necessary with the information that obtains the relative permeability curve afterwards in the wettability adjustment before, and this is next to estimating that to field scale it possibly benefit also be necessary.

Figure 10 has provided a series of absorption capillary pressures that obtain through the laboratory experiment that utilizes Berea sandstone rock core plug and has distributed, and they are at 55 ℃ of following centrifugal measurements.Used oil is CS crude oil, available from Wyoming university (Ref.32, Tang et al, 2002).In these experiments, be used for aging and oily metathetical salt solution and form identical.

Table 1 provides the tabulation of gained experimental data.These data clearly illustrate that: obtained the capillary pressure distribution with 100 times the experiment of weak brine under lower ionic strength I=0.0025Mol/l of dilution, those more can represent relatively more Yishui River wetting regime to this Billy with the undiluted brinish of I=0.25Mol/l.

Figure 11 has provided the series of results for the Amott self-priming test of Berea sandstone rock core plug under 60 ℃.In addition, in these experiments, be used for aging and oily metathetical salt solution through the salt solution intrusion and form identical.Applied oil is that one of Brent Bravo crude oil and undiluted brine composition are benchmark (Ref.32, Tang et al, 2002) with Dagang salt solution, and it is mainly by Na ⁺And K ⁺And interpolation number of C a ²⁺And Mg ²⁺Form.To pure NaCl, CaCl ₂And MgCl ₂Salt solution is also tested.

Table 2 and table 3 provide the tabulation of experimental detail, and have listed undiluted salt solution and formed.

The trend of being found is to pure MgCl ₂Especially pure CaCl ₂Salt solution, self-priming is effective not as pure NaCl and Dagang salt solution.Therefore, experimental result shows that the polyvalent cation in the salt solution makes storage layer rock more be difficult for water-wet.This discovery is by definite NMR wettability index supported (Ref.18, Looyestijn, 2006), and the latter shows that changing into univalent cation will cause heavy hydrocarbon that the absorption of rock forming mineral matter is reduced.Morrow et al (Ref.21,1996) has reported similar result.Except these experiments; Verified is: with 24000,2400 and and the pure NaCl salt solution of 240mg/l aging and reach the kapillary balance after; When with the Dagang salt solution instead of pure NaCl salt solution of 100 times of dilutions, the Berea sample does not show any petroleum production and recovers.This has affirmed that pure NaCl salt solution makes sample keep the water-wet state.The result (2006) of reports such as this discovery and Lager is consistent.

Figure 12 shows: under envrionment conditions in Amott self-priming experiment; For with undiluted Dagang salt solution as primitive water and Brent Bravo crude oil aged Berea sandstone rock core plug; After undiluted Dagang brinish suction effect; Stop in case recovering the oil; As after invading salt solution, petroleum production will be recovered at the Dagang salt solution that switches to 100 times of dilutions.This has confirmed that the light salt brine intrusion will make the rock core material more be prone to water-wet.

Figure 13 has provided under envrionment conditions the low speed rock core flowing experiment result all over the world at 0.32m/, and implementing said experiment is in order to verify following hypothesis: the high salinity displacement of reservoir oil possibly make storage layer rock more be prone to glossy wet and harm and drive and sweep.Experiment is carried out as follows:

(1) with Brent Bravo crude oil and the aging Berea sandstone rock core material of 2400mg/l NaCl;

(2) the 24000mg/l CaCl of injection 45PV ₂Salt solution stops and pressure-stabilisation up to oil recovery;

(3) continue to inject 2400mg/l NaCl salt solution.

In this experiment, observe at the CaCl that injects about 15PV ₂Behind the salt solution, when more or less reaching stable state, water pressure reduction begins to increase gradually.

As verified, this CaCl ₂Salt solution can not produce formation damage, and water pressure reduction increase shows that water and oil redistributes and particularly reduced water saturation and the water that has therefore reduced said rock core outside to perviousness on sample.This means that said rock core becomes easier glossy wet gradually.After switching to 2400mg/l NaCl salt solution, petroleum production is restored under the water pressure reduction (partly cause is the reduction of brine viscosity) reducing gradually.This is illustrated in and injects CaCl ₂Recover the oil during the salt solution and be suppressed.If at the CaCl that injects 45PV ₂During the salt solution, said rock core has in fact become gradually and more has been prone to glossy wetting, and then this oil recovery is suppressed at CaCl ₂Salt solution injection period generation gradually that is to say, at a PV CaCl ₂The just extraction under near the initial wetting conditions probably of the oil of injection period institute's extraction, but in wetting regime during gradually towards glossy moist changes that increase, oil recovery more and more is suppressed.CaCl ₂The ability that the salt water generates is difficult for the water-wet state is consistent with Amott self-priming experimental result shown in Figure 11, and consistent with the result of Tang et al (Ref.29,1997) and McGuire et al (Ref.20,2005).

In with the lower section, the experiment that utilizes Middle East sandstone will be described.

Table 4 points out that under envrionment conditions, Middle East core sample being carried out Amott draws the metering experiment, although under low initial water saturation levels, the high salinity local water does not have self-priming to take place fully yet.This shows that said sample is more near glossy wet.

Figure 14 has provided scanning electronic microscope (SEM) image, and wherein described clay and be dispersed in the whole hole as particulate, although the clay content of said sample is low, only be several percentage points the kaolin of this body weight of rock.

This can explain that it makes adsorbed hydrocarbons cover the ability of most of rock surface.

Table 4 shows that after the formation brine of will invade was changed to fresh water, petroleum production slowly rose, and final oil recovery is 24PV%.This has shown that fresh water changes to the more ability of Yishui River wetting regime with core wettability.

Figure 15 shows,, under envrionment conditions, verified also that in low flow velocity rock core flowing experiment fresh water is the ability of Yishui River wetting regime more with wettability modification at 0.32M/ all over the world.After switching to the fresh water injection, because brine viscosity reduces, under lower rock core pressure reduction, oil recovery is restored.This has pointed out the direction of reduction (negative) absorption capillary pressure.Because oil/brinish interfacial tension lowering when not having evidence to be illustrated in to switch to fresh water by formation brine, therefore, the reduction of capillary pressure must be given the credit to wettability and is adjusted to more Yishui River wetting regime.This conclusion is consistent with the experimental result of Amott.

In conjunction with obtainable SCAL association the detailed analysis of experimental result is reached a conclusion: after injecting light salt brine wettability by more near glossy wet change into mix wetting.Application phase-splitting flow theory is amplified to a storage layer scale with experimental result and shows, possibly increase about 10% through the oil mass that improves the extraction of displacement efficiency institute.

The wettability Adjusting Mechanism of having described the fresh water displacement of reservoir oil before resonable controversy is debated depends on electrostatic double layer and expands.Following to more supporting this conclusion near the rock core flowing experiment of glossy wet Middle East rock core material.

Table 4 provides the experimental data of this rock core flowing experiment.

Figure 16 has provided the production result of said conclusion.

Used following experimental phase A-E:

A) period A: inject the local water of the about 238000mg/l TDS that exceeds 50 times of pore volumes, wherein contain 84300mg/l Na ⁺, 6800mg/l Ca ²⁺With 1215mg/l Mg ²⁺, up to reaching the stable state that no longer includes any petroleum production.In this stage, expect that some clay particle is by Ca ²⁺And Mg ²⁺Occupy.

B) period B: inject the pure NaCl salt solution of 240000mg/l of about 30 times of pore volumes, wherein do not contain any polyvalent cation and have and the similar ionic strength of local water.In view of having low cation exchange capacity (CEC) (7.3meq/l hole), rock has relative high cations or solution equivalent concentration N (4107meq/l) with NaCl salt solution; We are expected at this injection period and have set up new chemical equilibrium when finishing, wherein whole Ca ²⁺And Mg ²⁺Develop and by Na from clay ⁺Substitute.People will expect that connecting the hydrocarbon that is adsorbed onto on the clay through pure positively charged ion will be removed, and the result makes the wettability adjustment towards the water-wet state that increases.This point is affirmed by experimental result: under approximately identical rock core pressure reduction level, have the recovery of petroleum production really, but be relatively small amount.This shows that only from exchanger, rinsing out polyvalent cation through obvious reduction ionic strength does not have electrostatic double layer to expand, and Yishui River wetting regime also must obtain the obviously petroleum production of raising to be not sufficient to make wettability obviously to change to more.This and Webb et al, 2003 result is consistent.

C) period C: inject the pure NaCl salt solution of 2000mg/l, wherein do not contain any polyvalent cation and ionic strength and be reduced to one of percentage.Because clay and solution all only contain Na at present ⁺, cationic exchange can not take place or extract effect in expection.However, in addition lower pressure reduction level under still observe oil production rate and obviously increase, this shows further and has removed adsorbed hydrocarbon from clay, and becomes more Yishui River wetting regime.Unique mechanism of remaining realization this point is to cause electrostatic repulsion forces to increase because electrostatic double layer expands.Continue to inject and to hang down salinity salt solution, up to reaching the stable state that no longer includes any petroleum production.

D) period D: inject 2000mg/l NaCl salt solution, wherein contain 10mg/l Ca ²⁺Because expection Ca ²⁺Reduce electrostatic double layer expansion (Schulze-Hardy principle) and promote that hydrocarbon is adsorbed onto on the clay, therefore during this stage, the expection oil production rate can obviously not increase.This point is affirmed by experiment.

E) period E: inject 2000mg/l NaCl salt solution, wherein contain 100mg/l Ca ²⁺, since with the same reasons of being summarized to period D, this injection does not increase oil production rate.

The Main Conclusions that is obtained by this experiment is wettability that base exchange process maybe be partly be adjusted to increase to wettability work (period B).But the main contribution to this wettability adjustment should be from the abundant reduction (period C) of salt solution ionic strength.The result of period B and period C is illustrated under the situation that does not have base exchange process, and the salt solution with enough low solution ion strength can obviously be adjusted wettability.

The experimental result of utilizing the core sample that contains montmorillonite or chlorite clay will be described in the lower section.

With light salt brine the rock core material that is rich in the clay mineral montmorillonite is carried out rock core flowing experiment, experiment shows that the fresh water injection has some benefits, but shortcoming is because formation damage causes rock core pressure reduction to increase gradually.Must be used for beyond the formation damage scope because fresh water injects, therefore, in the stratum of these types, fresh water injects possibly be confined to the high salinity level, and making maybe be moderate relatively to the benefit of recovering the oil.

Zhang et al (Ref.37,2006) has been found that and is rich in the validity that fresh water insensitivity chlorite clay mineral may reduce the fresh water displacement of reservoir oil.

In with the lower section, the experimental result of utilizing Middle East Wingdale will be described.

Though formed the mechanism of carrying out wettability adjustment through anion exchange procedures to chalk materials, we can not confirm fully that the work to chalk for example is equally applicable to the microlite lime stone in Middle East discovery.In fact, Strand et al (2008) shows that to the firstling of Middle East Wingdale rock core material said process maybe be suitable equally to Middle East Wingdale.

For further checking, under 60 ℃, be that about 29% Middle East Wingdale core sample has carried out a plurality of self-primings and tests for about 3mD and porosity to perviousness.Oil viscosity is 4.4mPas.Table 5 has provided the salt solution performance, the ionic strength that comprises total salinity levels of representing with mg/l TDS, representes with Mol/l, with solution equivalent concentration and the solubility product of meq/l.

Said formation brine is taken from the water of fresh water aquifer well based on the composition of taking from typical Middle East Wingdale storage layer and said wettability adjustment salt solution LS1 representative.Thereby salt solution LS2 and LS3 LS1 variant for avoiding through increase sulfate radical content and reduction calcium contents surpassing the critical solubility constant and avoiding calcium sulfate precipitation to obtain.

Utilizing after local water accomplishes self-priming, a core sample is soaked with salt solution LS1, second is soaked with salt solution LS3 with salt solution LS2 immersion and the 3rd.Figure 17 has provided these result of experiment, and salt solution LS2 and LS3 produce response, shows that the wettability adjustment is towards the water-wet state that increases.Salt solution LS1 is response not, and this is because it still has the low sulfate radical and the ratio of calcium.The pH value changes between 6.6-7.8.

Press 1: 1 mixed performance of ratio of mixture in the latter half detection formation brine and wettability adjustment salt solution, the result shows certain number of C aSO that produced ₄And CaCO ₃Deposition.Can know in the cut-and-try work in future, guarantee not deposition of salt solution, because this will reduce wettability adjustment brinish calcium and sulfate radical content.And this can reduce its wettability adjustment capability.

Field observation result to the fresh water displacement of reservoir oil in Middle East sandstone storage layer will be described in the lower section.

(possibility) observed the fresh water effect in producing well in Middle East sandstone storage layer.According to thinking that said stratum wettability is between mixing between wetting and glossy the wetting.The light oil that viscosity is 0.15mPa.s is contained in the oil field.Recover the oil from the aquifer displacement of reservoir oil.But, obtained more support by the fresh water injection of injecting well since in March, 2000.The salinity of aquifer water is generally 100000mg/l TDS, and the salinity of fresh water is about 1000mg/l TDS.

Figure 18 has provided the temporary transient decline of about 2003 o'clock observed water ratio, and this penetrates with fresh water and conforms to.After supposition fresh water injected the reduction separate phase flow rate, the history matching of water ratio development had obtained significantly improving.Provided viewed oil production rate among Figure 19, comprised having occurred amassing with the temporary transient little heap soil or fertilizer over and around the roots that conforms to that descends of water ratio.Cause separate phase flow rate to reduce if supposition is injected by fresh water, then the history matching of mimic oil production rate obviously improves.When having only half stratum,, fresh water made petroleum production increase 4-5% according to estimates because injecting by the displacement of reservoir oil.According to thinking that the temporary transient reduction of water ratio is the result of the oil bank before the fresh water slug, this is because the wettability adjustment makes displacement efficiency be improved (Figure 18 begins) towards Yishui River wetting regime more.This explanation has obtained the support that is directed against the laboratory result of Middle East core sample described above, and said sample has been represented this specific storage layer.

Detailed description by a plurality of embodiments of aforementioned the inventive method can obtain as drawing a conclusion:

1. inner cut-and-try work has proved that the fresh water displacement of reservoir oil can make the wettability adjustment towards the water-wet state that increases in mixing wetting/glossy damp sand stone.When not having effective water/oily gravity oil extraction process, on storage layer scale, use and to make the displacement displacement sweep efficiency increase several percentage points.

2. seem and under the salinity levels beyond the formation damage zone, to use the fresh water displacement of reservoir oil, wherein drive away adsorbed hydrocarbon, but clay is kept perfectly from clay particle.

3. for some possible losses of displacement of reservoir oil stabilization and compensation volume displacement sweep efficiency, it possibly be useful adding low concentration polymer.

4. inner cut-and-try work shows, possibly partly adjust towards the water-wet that increases wettability as fresh water displacement of reservoir oil result's base exchange process and work.But the main contribution of this wettability adjustment is come from the abundant reduction of salt solution ionic strength.Therefore, we believe that the mechanism of the fresh water displacement of reservoir oil mainly depends on the electrostatic double layer expansion and on less degree, depends on base exchange process at present.

5. fresh water displacement of reservoir oil design is characterized as the basis via solution ion strength with salt solution probably.

6. possibly, clay has determined in the distribution on the rock surface (particle coating) rather than its total amount whether the fresh water displacement of reservoir oil can use effectively in specific sandstone storage layer.

7. the fresh water displacement of reservoir oil is proposing specific requirement to sandstone storage layer aspect initial wetting property and the clay mineralogy, such as, should not be rich in montmorillonite and chlorite clay.Therefore, not all oil field all can be adopted.

8. having calcium in the local water is the storage layer to be become more be prone to a glossy wet principal element.Therefore, in storage layer oil column, inject seawater rather than inject light local water that these storage layers more are prone to is glossy wet.And this might suppress to recover the oil.

9. in carbonate storage layer, might carry out through anion exchange procedures, and be to improve process chalk materials through the wettability adjustment that control salt solution ion is formed.Inner cut-and-try work shows that this method also possibly work to the microlite ash stone material of for example finding in the Middle East.

The moisture displacement fluid of Ying Yonging can comprise Tackified polymeric in the methods of the invention; With the following embodiment 1 and 2 of basis; Can be interpreted as in the particular polymers displacement of reservoir oil that utilizes relative high polymers concentration like 200ppmw at least, be higher than 1mPa.s and will improve mobile control through injecting water tackify to levels of viscosity.

This will cause following two aspect benefits:

1. the principle of identity of summarizing according to the front is compared as the polymer flooding of make up water with utilizing conventional water source, and utilization as make up water, can improve petroleum production with moisture displacement fluid of the present invention through the wettability adjustment.

2. with based on conventional water source compare as the polymer flooding of make up water, if the ionic strength of the make up water of polymer fluid is lower than 0.15Mol/l, preferably be lower than 0.1Mol/l, then needed polymkeric substance (kg) quality amount is reduced to many about 1/2nd.

Further explain these benefits based on following embodiment 1 and 2.

Embodiment 1:

In this embodiment, use following formula (1)-(5) to the polymer viscosified ability.

Characterize the intrinsic viscosity (m of particular polymers solution ³/ kg) define as follows:

$\left[{\mathrm{\η}}_o\right]=\frac{\mathrm{\η}\left(c\right)-{\mathrm{\μ}}_w}{c\·{\mathrm{\μ}}_w}---\left(1\right)$

(condition is zero shearing rate and polymer concentration c, kg/m ³).

Here, η (c) refers to a polymer concentration c in the viscosity of the polymer, and

as one dissolved salt of said polymer viscosity.

According to the instruction of handbook " Viscosity of Polymer Solutions " (M.Bohdaneky and J.Kovar show, and are published in nineteen eighty-two by Elsevier Scientific Publishing), the viscosity of polymers soln can be write under low the shearing:

η(c)＝μ _w.(1+[η _o]c+k ₁.[η _o] ²c ²+k ₂.[η _o] ³c ³+....)(2)

K here ₁And k ₂Be constant.

Term k ₁Be called the Huggins coefficient.The common scope of Huggins coefficient is (the 177th page of above-mentioned handbook " Viscosity of Polymer Solutions ") between 0.4 to 1.22-2.26.

Therefore can know, under low the shearing, can be subjected to product c.[η through the viscosity raising that the adding polymkeric substance is realized ₀] control.

According to the series of measured values of 25 ℃ of following polyacrylamides, intrinsic viscosity is provided by following formula:

$\left[{\mathrm{\η}}_o\right]={\left[{\mathrm{\η}}_o\right]}^{*}{.[1.0+\frac{p^{*}.Z}{{(M.{\left[{\mathrm{\η}}_o\right]}^{*}.I)}^{1/2}}]}^{3/2}---\left(3\right)$

Wherein:

p*＝0.027

I refers to solution ion strength (salt solution and polymkeric substance all have contribution), with kmol/m ³Expression.

[η ₀] ^*For not having the intrinsic viscosity under the electrocharge effect (z=0) and providing by following formula:

[η ₀] ^*＝1.34.10 ^-5.M ^0.713(4)

M refers to that polymericular weight and Z are the element charge number along polymer chain.Z is provided by following formula:

$Z=\frac{\mathrm{\δ}.\mathrm{\α}.M}{(1-\mathrm{\α}).71+\mathrm{\α}.94}---\left(5\right)$

δ refers to that degree of ionization and α refer to degree of hydrolysis here.

The work that when pH=8, experimentizes, we suppose complete ionization (δ=1) here.

Providing among Figure 20 for the different polymkeric substance with molecular weight M and certain degree of hydrolysis, intrinsic viscosity is to the dependency of salt solution ionic strength.

As described below inside is tested proofreaied and correct.

Polyacrylamide after using commercially available hydrolysis under 50 ℃ is characterized in that molecular weight M=18 * 10 ⁶-20 * 10 ⁶And degree of hydrolysis is 25%, measures following two polymer viscosities:

These data are as described below:

μ _w(255mg/l TDS and 50 ℃)=0.6mPa.s

μ _w(25500mg/l TDS and 50 ℃)=0.6 * 1.05=0.63 mPa.s ≌ 0.6mPa.s.

If supposition during viscosity is described in 25-50 ℃ of scope at least other parameter all more or less with temperature correlation, then for this particular polymers, we have:

Formula (4) → [η _o] ^*=1.34.10 ^-5(18.10 ⁶) ^0.713=2.0m ³/ kg

Formula (5) → Z=5.86 * 10 ⁴

For salinity 25500mg/g TDS (0.4kmol/m ³) salt solution in polymkeric substance:

Formula (3) → [η ₀]=3.36m ³/ kg

For salinity 255mg/g TDS (0.004kmol/m ³) salt solution in polymkeric substance:

Formula (3) → [η ₀]=23.5m ³/ kg

Consideration formula (2) this means in order to reach identical polymer viscosity, polymer concentration c _pNeed to satisfy:

c _p(25500mg/l).3.36＝c _p(255mg/l).23.5，

This means:

$\frac{c_p(25500\mathrm{mg}/l)}{c_p(255\mathrm{mg}/l)}=\frac{23.5}{3.36}=7$

The factor 7.25 of actual discovery that ratio 7 is corresponding well.

Embodiment 2:

The composition of the formation brine of in embodiment 2, using is shown in the table 6.

It is characterized in that total salinity levels is that 7878mg/l and ionic strength I are about 0.133kmol/m ³(consideration principal element).Brinish pH is 7.9, therefore can suppose complete ionization (δ=1).

There is relatively significantly 100mg/l Ca ²⁺, showing that the storage layer wettability of this embodiment possibly obviously depart from pure water-wet state and use the inventive method, possibly exist through wettability to be adjusted to the more IOR scope of Yishui River wetting regime.

In the embodiment formation brine at low shear rate 1s ^-1Under the viscosity of polymkeric substance be shown among Figure 22.

Selected polymer type is a polyacrylamide after the commercially available hydrolysis, and its molecular weight is 18 * 10 ⁶-20 * 10 ⁶With degree of hydrolysis be about 25%.This polymkeric substance that about 1750ppm is confirmed in experiment under 51 ℃ (embodiment formation temperature) at low shear rate 1s ^-1Under be dissolved in the embodiment formation brine, will produce the soltion viscosity of 90mPa.s.

Tested the viscosity number strong point as follows in the water in approximately identical temperature range under about 1000ppm TDS salinity levels: at 1s ^-1Under 1000ppm TDS, the needed polymer concentration of levels of viscosity that produces 90mPa.s is 1050ppm.

The data point that experiment obtains is summarized as follows.

When using than the flat salt solution of low salinity water, obtaining the needed polymer quality amount of the horizontal 90mPa.s of identical viscosities, to reduce by two iterative step I of application as described below definite with II.

According to thinking that following salt solution is under embodiment stores 50 ℃ of layer temperature:

μ _w(200mg/l TDS and 50 ℃)=0.6mPa.s

μ _w(1000mg/l TDS and 50 ℃)=0.6 * 1.002 ≌ 0.6mPa.s.

μ _w(7000mg/l TDS and 50 ℃)=0.6 * 1.015 ≌ 0.6mPa.s.

Similarly, as the front, can using iterative step I and II calculate intrinsic viscosity:

I) first iterative step:

Ignore the contribution of polymkeric substance to ionic strength:

Salt salinity water (mg/l TDS)	Salt solution ionic strength I (kmol/m 3) *)	Intrinsic viscosity (m 3/kg)
			200	0.0034	25.8
1000	0.0171	10.5
			7000	0.1198	4.7

^*) approximate: only form by pure NaCl.

In order to obtain identical levels of viscosity, so we have:

C _p(200mg/l TDS) .25.8=C _p(1000mg/l TDS) .10.5=C _p(7000mg/l TDS) .4.7 this means:

$\frac{c_p(7000\mathrm{mg}/l)}{c_p(1000\mathrm{mg}/l)}=\frac{10.5}{4.7}=2.2$

With

$\frac{c_p(1000\mathrm{mg}/l)}{c_p(200\mathrm{mg}/l)}=\frac{25.8}{10.5}=2.5$

This means: if C _p(7000mg/l)=1750ppm, then C _p(1000mg/l)=795ppm and C _p(200mg/l)=318ppm.

II) secondary iteration step:

Comprise the contribution of polymkeric substance to the total ionic strength adjustment buffer degree:

In order to reach identical levels of viscosity, so we have:

C _p(200mg/l TDS) * 22.0=C _p(1000mg/l TDS) * 9.76=C _p(7000mg/l TDS) * 4.60 this means:

$\frac{c_p(7000\mathrm{mg}/l)}{c_p(1000\mathrm{mg}/l)}=\frac{9.76}{4.60}=2.12$

With

$\frac{c_p(1000\mathrm{mg}/l)}{c_p(200\mathrm{mg}/l)}=\frac{22.0}{9.76}=2.25$

This means: if C _p(7000mg/l)=1750ppm, then C _p(1000mg/l)=825ppm and C _p(200mg/l)=365ppm.

The data point that these results and experimental observation are arrived (1000ppm TDS salt under water the 1050ppmw polymkeric substance and at 7000ppm TDS salt 1750ppmw polymkeric substance under water, the two is all at 1s ^-1With about 50 ℃ of levels of viscosity that produce 90mPa.s down) shown in Figure 22.

Claims (10)

1. a reinforcement contains crude oil and primitive water by the method for the oil recovering of porous subsurface formations in the hole of said subsurface formations, and wherein said primitive water comprises SO ₄ ^2-And Ca ²⁺Ion, said method comprises:

-confirm the SO in the primitive water ₄ ^2-/ Ca ²⁺Mol ratio (Mol/Mol); With

-in said hole, inject SO ₄ ^2-/ Ca ²⁺Mol ratio (Mol/Mol) is higher than 1 and SO ₄ ^2-/ Ca ²⁺The moisture displacement fluid that mol ratio (Mol/Mol) is higher than primitive water;

-be characterised in that said porous subsurface formations is Wingdale or rhombspar stratum.

2. the process of claim 1 wherein that said method can be used for adjusting the wettability on Wingdale or rhombspar stratum, thereby their glossy moist reduction and wettability are increased.

3. claim 1 or 2 method wherein are higher than said moisture displacement fluid under 50 ℃ in temperature and are injected in the hole.

4. each method of claim 1-3 is wherein with SO ₄ ^2-/ Ca ²⁺Be injected in the hole than the slug of the high moisture displacement fluid of primitive water than (Mol/Mol) as 0.2-0.8PV (the estimation pore volume of PV=formation pore).

5. the method for claim 4, wherein said method also are included in injects SO ₄ ^2-/ Ca ²⁺The moisture displacement fluid slug higher than primitive water than (Mol/Mol) injects untreated moisture displacement fluid afterwards.

6. each method of claim 1-5, wherein said moisture displacement fluid comprises the water that is got by rivers, fresh water aquifer, lake, ocean or ocean.

7. the method for claim 5 is wherein handled said water, thereby makes it be converted into SO ₄ ^2-/ Ca ²⁺Than (Mol/Mol) the moisture displacement fluid higher than primitive water in the hole.

8. each method of aforementioned claim, wherein said moisture displacement fluid comprises Tackified polymeric.

9. the method for claim 8, the levels of viscosity of wherein said moisture displacement fluid is higher than 1mPa.s and comprises the Tackified polymeric of 200ppmw at least.

10. claim 8 or 9 method, wherein said Tackified polymeric comprises the polyacrylamide after the hydrolysis.

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