Method for profile control and channeling sealing of oil wet land layer and application

Abstract

The invention discloses a method for profile control and channeling sealing of an oil wet land layer and application. The method for profile control and channeling sealing of the oil-wet land layer comprises the step that high-hardness saline water is used for displacement, inorganic salt of the high-hardness saline water is in an under-saturation state within the temperature range from the ground to a near wellbore zone, and after the temperature of the deep portion of the stratum is reached, the inorganic salt is converted into an over-saturation state from the under-saturation state, and the inorganic salt begins to precipitate. Due to the fact that the stratum is oil-wet, water preferentially enters fluid channeling cracks and large pore channels, and sediment of inorganic salt is formed due to supersaturation, so that the large pore channels are effectively blocked, and the purposes of profile control and channeling sealing are achieved.

Description

Technical Field

[0001] The invention relates to the technical field of enhanced oil recovery in oil-wet strata, and in particular to a method and application for profile control and channel sealing in oil-wet strata. Background Art

[0002] During water flooding of oil-wet reservoirs, the flow resistance of crude oil is large because the formation is oil-wet and not water-wet, and the injected water can only enter the large pores in the formation due to the influence of capillary force. After a long period of water flooding, the injected water forms crossflow in the large pores and cannot reach the small pores, resulting in a much smaller increase in recovery than that of water-wet reservoirs.

[0003] The exploitation of oil-wet reservoirs mainly focuses on improving wettability by adding wettability modifiers, such as surfactants, which are adsorbed on the huge rock surface, but this increases economic costs. Moreover, for oil-wet reservoirs with large fractures, surfactants and other wettability modifiers are prone to flow in the fractures, and cannot play the role of improving wettability and enhancing recovery.

[0004] Therefore, there is an urgent need for a low-cost method suitable for profile control and channel sealing in oil-wet strata. Summary of the invention

[0005] In order to solve the problems existing in the prior art, the present invention provides a method and application for profile control and sealing of oil-wet formations. In oil fields, there is a lot of produced water with high hardness, and the cost of treating the discharged water is high. The present invention uses it for injection into oil-wet formations, and proposes a low-cost profile control and sealing method to achieve the purpose of profile control and sealing. The present invention uses high-hardness brine for displacement. The brine has a low temperature and is clear and transparent when injected. As it is injected into cracks and large pores deep in the formation, the formation temperature is higher than the ground temperature, and inorganic salts begin to precipitate. Since the formation is oil-wet, water preferentially enters the crossflow cracks and large pores, and supersaturation causes it to form inorganic salt precipitation, thereby effectively blocking the large pores and achieving the purpose of profile control and sealing.

[0006] One of the purposes of the present invention is to provide a method for oil-wet formation profile control and channeling sealing, comprising the step of using high-hardness brine for displacement, wherein the inorganic salt in the high-hardness brine is in an undersaturated state within the temperature range from the ground to the injection near-wellbore zone, and after reaching the temperature deep in the formation, the inorganic salt changes from an undersaturated state to an oversaturated state, and the inorganic salt begins to precipitate.

[0007] In a preferred embodiment of the present invention,

[0008] The high-hardness salt water contains calcium ions, or calcium ions and magnesium ions; and / or,

[0009] The precipitate of the inorganic salt includes calcium carbonate (calcite calcium carbonate) and / or calcium magnesium carbonate (dolomite calcium magnesium carbonate).

[0010] In a preferred embodiment of the present invention,

[0011] The inorganic salt saturation index of the high-hardness brine is less than 0.35 in the temperature range from the ground to the injection near-wellbore zone. After reaching the temperature deep in the formation, the calcium carbonate saturation index increases by >0.1; and / or the calcium carbonate magnesium saturation index increases by >0.3.

[0012] In a preferred embodiment of the present invention,

[0013] The calcium ion concentration in the high-hardness salt water is >10mM; and / or the magnesium ion concentration is >5mM.

[0014] In a preferred embodiment of the present invention,

[0015] The calcium ion concentration in the high-hardness salt water is >15mM.

[0016] In a preferred embodiment of the present invention,

[0017] The magnesium ion concentration in the high-hardness salt water is >10mM.

[0018] In a preferred embodiment of the present invention,

[0019] The high-hardness salt water also contains sodium ions; preferably,

[0020] The sodium ion concentration in the high-hardness brine is below 47,000 mg / L, preferably 6,000-46,000 mg / L, and more preferably 6,900-45,600 mg / L.

[0021] The inventors unexpectedly discovered during their research that when the sodium ion concentration in high-hardness brine is too high, the high-hardness brine will begin to precipitate before reaching the temperature deep in the formation. Therefore, for the temperature corresponding to the depth of the formation that needs to be sealed, it is preferable to control the sodium ion content to regulate the precipitation timing of the displaced high-hardness brine.

[0022] In a preferred embodiment of the present invention,

[0023] The temperature range from the ground to the injection wellbore near zone is 0-35°C; and / or the temperature in the deep formation is greater than 35°C, preferably 50-100°C.

[0024] In a preferred embodiment of the present invention,

[0025] After reaching the deep formation temperature, the permeability decreases to 10% to 90% of the original permeability; and / or,

[0026] The permeability should preferably not drop by more than 5% before reaching the deep formation temperature.

[0027] A second object of the present invention is to provide an application of the method of one of the objects of the present invention in enhanced oil recovery from oil-wet formations.

[0028] Beneficial effects of the present invention:

[0029] The present invention uses high-hardness brine for displacement. The brine is low in temperature and clear and transparent when injected. As it is injected into cracks and large pores deep in the formation, the formation temperature is higher than the ground temperature, and inorganic salts begin to precipitate. Since the formation is oil-wet, water preferentially enters the crossflow cracks and large pores, and supersaturation causes it to form inorganic salt precipitation, thereby effectively blocking the large pores and achieving the purpose of profile adjustment and channel sealing.

[0030] In the present invention, it is preferred to use high-hardness produced water from the oil field, which may generally contain Na + , Ca 2+ ,Mg 2+ , Fe 2+ , Cl － , SO4 2－ , HCO3-, and may also contain K + , Fe 3+ , S 2- and HCO3 2- When the produced water cannot meet the usage index of the present invention, the produced water can be adjusted to meet the usage index, thereby maximizing the utilization of the produced water. BRIEF DESCRIPTION OF THE DRAWINGS

[0031] Figure 1 The graph of the change of the saturation index of calcium carbonate and calcium magnesium carbonate with temperature calculated in Example 1, the abscissa is the temperature, the ordinate is the saturation index SI, wherein curve a is the change curve of the saturation index of calcium magnesium carbonate (CaMg(CO3)2) in the produced water of Bin-1 in Example 1 with temperature, and curve b is the change curve of the saturation index of calcium carbonate (CaCO3) in the produced water of Bin-1 in Example 1 with temperature;

[0032] Figure 2 The graph of the change of the saturation index of calcium carbonate and calcium magnesium carbonate with temperature calculated for Example 2, the abscissa is the temperature, the ordinate is the saturation index SI, wherein curve c is the change curve of the saturation index of calcium magnesium carbonate (CaMg(CO3)2) in the produced water of Biner 2 with temperature, and curve d is the change curve of the saturation index of calcium carbonate (CaCO3) in the produced water of Biner 2 with temperature;

[0033] Figure 3The graph of the change of the saturation index of calcium carbonate and calcium magnesium carbonate with temperature calculated for Example 3, the abscissa is the temperature, the ordinate is the saturation index SI, wherein curve e is the change curve of the saturation index of calcium magnesium carbonate (CaMg(CO3)2) in the produced water of Binsan in Example 3 with temperature, and curve f is the change curve of the saturation index of calcium carbonate (CaCO3) in the produced water of Binsan in Example 3 with temperature;

[0034] Figure 4 The graph of the change of the saturation index of calcium carbonate and calcium magnesium carbonate with temperature calculated for Example 4, the abscissa is the temperature, the ordinate is the saturation index SI, wherein curve g is the change curve of the saturation index of calcium magnesium carbonate (CaMg(CO3)2) in the brine of Example 4 with temperature, and curve h is the change curve of the saturation index of calcium carbonate (CaCO3) in the brine of Example 4 with temperature;

[0035] Figure 5 The graph of the change of the saturation index of calcium carbonate and calcium magnesium carbonate with temperature calculated for Example 5, the abscissa is the temperature, the ordinate is the saturation index SI, wherein curve i is the change curve of the saturation index of calcium magnesium carbonate (CaMg(CO3)2) in the brine of Example 5 with temperature, and curve j is the change curve of the saturation index of calcium carbonate (CaCO3) in the brine of Example 5 with temperature;

[0036] Figure 6 The graph of the change of the saturation index of calcium carbonate and calcium magnesium carbonate with temperature calculated for Example 6, the abscissa is the temperature, the ordinate is the saturation index SI, wherein curve k is the change curve of the saturation index of calcium magnesium carbonate (CaMg(CO3)2) in the brine of Example 6 with temperature, and curve l is the change curve of the saturation index of calcium carbonate (CaCO3) in the brine of Example 6 with temperature;

[0037] Figure 7 The graph of the change of the saturation index of calcium carbonate and calcium magnesium carbonate with temperature calculated in Example 7, the abscissa is temperature, the ordinate is the saturation index SI, wherein curve m is the change curve of the saturation index of calcium magnesium carbonate (CaMg(CO3)2) in the brine of Example 7 with temperature, and curve n is the change curve of the saturation index of calcium carbonate (CaCO3) in the brine of Example 7 with temperature. DETAILED DESCRIPTION

[0038] The present invention is described in detail below in conjunction with specific embodiments and drawings. It is necessary to point out that the following embodiments are only used to further illustrate the present invention and cannot be understood as limiting the scope of protection of the present invention. Some non-essential improvements and adjustments made to the present invention by those skilled in the art based on the content of the present invention still fall within the scope of protection of the present invention.

[0039] The raw materials used in the examples are all conventional commercially available raw materials.

[0040] The calcium carbonate and calcium magnesium carbonate saturation indexes in the examples are calculated based on the ion composition of produced water using PHREEQC software.

[0041] The specific implementation is as follows:

[0042] Under different temperature conditions, high-hardness injection water is injected into the sand filling pipe or core, 2PV is injected each time, and the pressure difference after equilibrium is recorded. The permeability is calculated using Darcy's law based on the pressure difference. A lower permeability indicates that effective plugging has been achieved.

[0043] Example 1

[0044] Take Binyi Mining's water as an example.

[0045] Table 1 Ion composition of produced water

[0046] project Concentration, mg / L Concentration mM <![CDATA[Na + ]]> 7540 327.83 <![CDATA[Ca 2+ ]]> 410 10.25 <![CDATA[Mg 2+ ]]> 120 5 <![CDATA[Fe 2+ ]]> 3.1 0.055 <![CDATA[Cl － ]]> 12585 354.50 <![CDATA[SO4 2－ ]]> 31.8 0.33 <![CDATA[HCO3 - ]]> 200 3.28

[0047] According to the ion composition of the produced water, the saturation index of calcium carbonate and calcium magnesium carbonate is calculated as the temperature changes. Figure 1 As shown. With the increase of temperature, the saturation index of calcium carbonate and calcium magnesium carbonate gradually increases, changing from an undersaturated state to a supersaturated state. At 35°C, the saturation index of calcium carbonate and calcium magnesium carbonate is 0.04, and at 50°C, the saturation index of calcium carbonate and calcium magnesium carbonate is 0.21 and 0.46 respectively, and the saturation index of calcium carbonate and calcium magnesium carbonate is greater than 0.45.

[0048] Blocking experiment:

[0049] The sand-filled tube filled with 80-200 mesh quartz sand has a water drive permeability of 4390mD and a pore volume of 140mL. At 15℃, the pressure difference at both ends of the sand-filled tube is 0.2KPa when the brine is injected at a flow rate of 0.2mL / min. At 35℃, the pressure difference at both ends of the sand-filled tube is 0.13KPa when the brine is injected at a flow rate of 0.2mL / min. The temperature is increased to 50, 70, and 90℃ respectively. At each temperature, 2PV (280mL) is displaced. The pressure difference and calculated permeability at different temperatures are shown in Table 2 below:

[0050] Table 2

[0051] Temperature ℃ Pressure difference, kPa Permeability mD 15 0.20 4390 35 0.13 4390 50 0.11 3910 70 0.51 625 90 3.70 69

[0052] After the temperature rises to 50°C, the pressure difference begins to increase and the permeability decreases, indicating that as the temperature rises, the inorganic salts in the brine are supersaturated and precipitate significantly, thereby blocking the large pores and reducing the permeability.

[0053] Example 2

[0054] Taking Bin-2 produced water as an example, Bin-2 produced water has a higher calcium chloride concentration than Bin-1, and the calcium ion concentration has nearly doubled to 810 mg / L.

[0055] Table 3 Ion composition of Bin II produced water

[0056]

[0057]

[0058] According to the ion composition of the produced water, the saturation index of calcium carbonate and calcium magnesium carbonate is calculated as the temperature changes. Figure 2 As shown. With the increase of temperature, the saturation index of calcium carbonate and calcium magnesium carbonate gradually increases, changing from an undersaturated state to a supersaturated state. At 35°C, the saturation indexes of calcium carbonate and calcium magnesium carbonate are 0.32 and 0.30 respectively, and at 50°C, the saturation indexes of calcium carbonate and calcium magnesium carbonate are 0.49 and 0.71 respectively. The saturation indexes of calcium carbonate and calcium magnesium carbonate are both greater than 0.45.

[0059] Blocking experiment:

[0060] The sand-filled pipe filled with 80-200 mesh quartz sand has a water drive permeability of 4010mD and a pore volume of 139mL. At 15℃, when the brine is injected at a flow rate of 0.2mL / min, the pressure difference at both ends of the sand-filled pipe is 0.22KPa. At 35℃, when the brine is injected at a flow rate of 0.2mL / min, the pressure difference at both ends of the sand-filled pipe is 0.15KPa. The increasing temperatures are 50, 70, and 90℃, respectively. At each temperature, 2PV (278mL) is displaced. The pressure difference and calculated permeability at different temperatures are shown in Table 4 below:

[0061] Table 4

[0062] Temperature ℃ Pressure difference, kPa Permeability mD 15 0.22 4010 35 0.15 3820 50 0.27 1600 70 0.64 501 90 4.30 60

[0063] When the temperature rises to 50℃, the pressure difference increases significantly and the permeability decreases significantly, indicating that the inorganic salts in the brine precipitate significantly in a supersaturated state as the temperature rises, thereby blocking the large pores and reducing the permeability. Compared with Binyishui, the purpose of reducing the applicable temperature for plugging can be achieved by adjusting the calcium ion concentration of the injected water.

[0064] Example 3

[0065] Taking Binsan produced water as an example, Binsan produced water has a higher sodium chloride concentration than Biner, with sodium ions more than five times higher at 41,000 mg / L.

[0066] Table 5 Ion composition of the water produced by Binsan

[0067] project Concentration, mg / L Concentration mM <![CDATA[Na + ]]> 41000 1782.63 <![CDATA[Ca 2+ ]]> 810 20.25 <![CDATA[Mg 2+ ]]> 120 5 <![CDATA[Fe 2+ ]]> 3.1 0.055 <![CDATA[Cl － ]]> 64940 1829.30 <![CDATA[SO4 2－ ]]> 31.8 0.33 <![CDATA[HCO3 - ]]> 200 3.28

[0068] According to the ion composition of the produced water, the saturation index of calcium carbonate and calcium magnesium carbonate is calculated as the temperature changes. Figure 3 As shown. With the increase of temperature, the saturation index of calcium carbonate and calcium magnesium carbonate gradually increases, changing from an undersaturated state to a supersaturated state. At 35°C, the saturation indexes of calcium carbonate and calcium magnesium carbonate are 0.28 and 0.30 respectively. At 50°C, the saturation indexes of calcium carbonate and calcium magnesium carbonate are 0.44 and 0.71 respectively. The saturation index of calcium carbonate and calcium magnesium carbonate is greater than 0.45.

[0069] Blocking experiment:

[0070] The sand-filled tube filled with 80-200 mesh quartz sand has a water drive permeability of 4210mD and a pore volume of 138.5mL. At 15℃, when the brine is injected at a flow rate of 0.2mL / min, the pressure difference at both ends of the sand-filled tube is 0.21KPa. At 35℃, when the brine is injected at a flow rate of 0.2mL / min, the pressure difference at both ends of the sand-filled tube is 0.14KPa. The increasing temperatures are 50, 70, and 90℃, respectively. At each temperature, 2PV (277mL) is displaced. The pressure difference and calculated permeability at different temperatures are shown in Table 6 below:

[0071] Table 6

[0072] Temperature ℃ Pressure difference, kPa Permeability mD 15 0.21 4210 35 0.14 4076 50 0.21 2100 70 0.45 701 90 3.6 70

[0073] When the temperature rises to 50°C, the pressure difference increases significantly and the permeability decreases significantly, indicating that as the temperature rises, the inorganic salts in the brine are supersaturated and precipitate significantly, thereby blocking the large pores and reducing the permeability.

[0074] Example 4

[0075] The calcium chloride concentration in the brine of this example is between that of Bin II produced water and Bin I produced water, with a calcium ion concentration of 610 mg / L.

[0076] Table 7 Salt water ion composition

[0077] project Concentration, mg / L Concentration mM <![CDATA[Na + ]]> 7540 327.83 <![CDATA[Ca 2+ ]]> 610 15.25 <![CDATA[Mg 2+ ]]> 120 5 <![CDATA[Fe 2+ ]]> 3.1 0.055 <![CDATA[Cl － ]]> 12940 364.50 <![CDATA[SO4 2－ ]]> 31.8 0.33 <![CDATA[HCO3 - ]]> 200 3.28

[0078] According to the ion composition of the produced water, the saturation index of calcium carbonate and calcium magnesium carbonate is calculated as the temperature changes. Figure 4 As shown. With the increase of temperature, the saturation index of calcium carbonate and calcium magnesium carbonate gradually increases, changing from an undersaturated state to a supersaturated state. At 35°C, the saturation indexes of calcium carbonate and calcium magnesium carbonate are 0.20 and 0.19 respectively. At 50°C, the saturation indexes of calcium carbonate and calcium magnesium carbonate are 0.36 and 0.58 respectively. The saturation index of calcium carbonate and calcium magnesium carbonate is greater than 0.45.

[0079] Blocking experiment:

[0080] The sand-filled tube filled with 80-200 mesh quartz sand has a water drive permeability of 4600mD and a pore volume of 138mL. At 15℃, the pressure difference at both ends of the sand-filled tube is 0.19KPa when the brine is injected at a flow rate of 0.2mL / min. At 35℃, the pressure difference at both ends of the sand-filled tube is 0.13KPa when the brine is injected at a flow rate of 0.2mL / min. The temperature is increased to 50, 70, and 90℃ respectively. At each temperature, 2PV (276mL) is displaced. The pressure difference and calculated permeability at different temperatures are shown in Table 8 below:

[0081] Table 8

[0082] Temperature ℃ Pressure difference, kPa Permeability mD 15 0.19 4600 35 0.13 4390 50 0.19 2260 70 0.37 860 90 3.23 75

[0083] After the temperature rises to 50°C, the pressure difference begins to increase and the permeability decreases significantly, indicating that as the temperature rises, the inorganic salts in the brine are supersaturated and precipitate significantly, thereby blocking the large pores and reducing the permeability.

[0084] Example 5

[0085] The sodium chloride in the brine of this embodiment is further increased than that of the produced water of Binsan, and the sodium ion concentration reaches 45600 mg / L.

[0086] Table 9 Salt water ion composition

[0087] project Concentration, mg / L Concentration mM <![CDATA[Na + ]]> 45600 1982.63 <![CDATA[Ca 2+ ]]> 810 20.25 <![CDATA[Mg 2+ ]]> 120 5 <![CDATA[Fe 2+ ]]> 3.1 0.055 <![CDATA[Cl － ]]> 72040 2029.30 <![CDATA[SO4 2－ ]]> 31.8 0.33 <![CDATA[HCO3 - ]]> 200 3.28

[0088] According to the ion composition of the produced water, the saturation index of calcium carbonate and calcium magnesium carbonate is calculated as the temperature changes. Figure 5 As shown. With the increase of temperature, the saturation index of calcium carbonate and calcium magnesium carbonate gradually increases, changing from an undersaturated state to a supersaturated state. At 35°C, the saturation indexes of calcium carbonate and calcium magnesium carbonate are 0.30 and 0.35 respectively, and at 50°C, the saturation indexes of calcium carbonate and calcium magnesium carbonate are 0.46 and 0.76 respectively. The saturation indexes of calcium carbonate and calcium magnesium carbonate are both greater than 0.45.

[0089] Blocking experiment:

[0090] The sand-filled pipe filled with 80-200 mesh quartz sand has a water drive permeability of 4880mD and a pore volume of 141.5mL. At 15℃, the pressure difference at both ends of the sand-filled pipe is 0.18KPa when the brine is injected at a flow rate of 0.2mL / min. At 35℃, the pressure difference at both ends of the sand-filled pipe is 0.12KPa when the brine is injected at a flow rate of 0.2mL / min. The temperature is increased to 50, 70, and 90℃ respectively. At each temperature, 2PV (283mL) is displaced. The pressure difference and calculated permeability at different temperatures are shown in Table 10 below:

[0091] Table 10

[0092] Temperature ℃ Pressure difference, kPa Permeability mD 15 0.18 4880 35 0.12 4750 50 0.27 1600 70 0.68 469 90 4.5 57

[0093] When the temperature rises to 50℃, the pressure difference increases significantly and the permeability decreases significantly, indicating that the inorganic salts in the brine precipitate out in a supersaturated state as the temperature rises, thereby blocking the large pores and reducing the permeability. Compared with Binsanshui, the further increase in sodium chloride salinity strengthens the sedimentation plugging.

[0094] Comparative Example 1

[0095] The sodium chloride in the brine of this comparative example is further increased than that in Example 5, and the sodium ion concentration reaches 47900 mg / L.

[0096] Table 11 Salt water ion composition

[0097] project Concentration, mg / L Concentration mM <![CDATA[Na + ]]> 47900 2082.63 <![CDATA[Ca 2+ ]]> 810 20.25 <![CDATA[Mg 2+ ]]> 120 5 <![CDATA[Fe 2+ ]]> 3.1 0.055 <![CDATA[Cl － ]]> 75590 2129.30 <![CDATA[SO4 2－ ]]> 31.8 0.33 <![CDATA[HCO3 - ]]> 200 3.28

[0098] According to the ion composition of the brine, the saturation index of calcium carbonate and calcium magnesium carbonate was calculated. At 35°C, the saturation index of calcium carbonate and calcium magnesium carbonate was 0.31 and 0.39 respectively.

[0099] Blocking experiment:

[0100] The permeability of the sand-filled pipe filled with 80-200 mesh quartz sand is 4680mD and the pore volume is 140mL. When the above brine is injected at a flow rate of 0.2mL / min at 35℃, the pressure difference at both ends of the sand-filled pipe is 0.15KPa, and the calculated permeability is reduced to 3800mD, which is significantly reduced at 35℃, and the permeability reduction at 35℃ reaches 19%.

[0101] Example 6

[0102] The sodium chloride concentration in the brine of this embodiment is 6900 mg / L.

[0103] Table 12 Salt water ion composition

[0104] project Concentration, mg / L Concentration mM <![CDATA[Na + ]]> 6900 300 <![CDATA[Ca 2+ ]]> 810 20.25 <![CDATA[Mg 2+ ]]> 120 5 <![CDATA[Fe 2+ ]]> 3.1 0.055 <![CDATA[Cl － ]]> 12307 346.67 <![CDATA[SO4 2－ ]]> 31.8 0.33 <![CDATA[HCO3 - ]]> 200 3.28

[0105] According to the ion composition of the produced water, the saturation index of calcium carbonate and calcium magnesium carbonate is calculated as the temperature changes. Figure 6 As shown. With the increase of temperature, the saturation index of calcium carbonate and calcium magnesium carbonate gradually increases, changing from an undersaturated state to a supersaturated state. At 35°C, the saturation indexes of calcium carbonate and calcium magnesium carbonate are 0.32 and 0.31 respectively, and at 50°C, the saturation indexes of calcium carbonate and calcium magnesium carbonate are 0.49 and 0.72 respectively. The saturation indexes of calcium carbonate and calcium magnesium carbonate are both greater than 0.45.

[0106] Blocking experiment:

[0107] The sand-filled tube filled with 80-200 mesh quartz sand has a water drive permeability of 4880mD and a pore volume of 141.5mL. At 15℃, the pressure difference at both ends of the sand-filled tube is 0.18KPa when the brine is injected at a flow rate of 0.2mL / min. At 35℃, the pressure difference at both ends of the sand-filled tube is 0.12KPa when the brine is injected at a flow rate of 0.2mL / min. The temperature is increased to 50, 70, and 90℃ respectively. At each temperature, 2PV (283mL) is displaced. The pressure difference and calculated permeability at different temperatures are shown in Table 13 below:

[0108] Table 13

[0109] Temperature ℃ Pressure difference, kPa Permeability mD 15 0.18 4880 35 0.12 4750 50 0.19 2263 70 0.62 514 90 4.12 62

[0110] When the temperature rises to 50°C, the pressure difference increases significantly and the permeability decreases significantly, indicating that as the temperature rises, the inorganic salts in the brine are supersaturated and precipitate significantly, thereby blocking the large pores and reducing the permeability.

[0111] Example 7

[0112] The magnesium chloride in the brine of this embodiment is doubled compared with the produced water of Bin-1, and the magnesium ion content is 240 mg / L.

[0113] Table 14 Salt water ion composition

[0114] project Concentration, mg / L Concentration mM <![CDATA[Na + ]]> 7540 327.83 <![CDATA[Ca 2+ ]]> 410 10.25 <![CDATA[Mg 2+ ]]> 240 10 <![CDATA[Fe 2+ ]]> 3.1 0.055 <![CDATA[Cl － ]]> 12940 364.50 <![CDATA[SO4 2－ ]]> 31.8 0.33 <![CDATA[HCO3 - ]]> 200 3.28

[0115] According to the ion composition of the produced water, the saturation index of calcium carbonate and calcium magnesium carbonate is calculated as the temperature changes. Figure 7 As shown. With the increase of temperature, the saturation index of calcium carbonate and calcium magnesium carbonate gradually increases, changing from an undersaturated state to an oversaturated state. At 35°C, the saturation indexes of calcium carbonate and calcium magnesium carbonate are 0.03 and 0.32 respectively. At 50°C, the saturation indexes of calcium carbonate and calcium magnesium carbonate are 0.20 and 0.73 respectively. The saturation index of calcium carbonate and calcium magnesium carbonate is greater than 0.45.

[0116] Blocking experiment:

[0117] The sand-filled pipe filled with 80-200 mesh quartz sand has a water drive permeability of 4210mD and a pore volume of 137mL. At 15℃, when the brine is injected at a flow rate of 0.2mL / min, the pressure difference at both ends of the sand-filled pipe is 0.21KPa. At 35℃, when the brine is injected at a flow rate of 0.2mL / min, the pressure difference at both ends of the sand-filled pipe is 0.14KPa. The increasing temperatures are 50, 70, and 90℃, respectively. At each temperature, 2PV (274mL) is displaced. The pressure difference and calculated permeability at different temperatures are shown in Table 15 below:

[0118] Table 15

[0119] Temperature ℃ Pressure difference, kPa Permeability mD 15 0.21 4210 35 0.14 4076 50 0.23 1870 70 0.57 559 90 3.81 67

[0120] After the temperature rises to 50°C, the pressure difference begins to increase and the permeability decreases significantly, indicating that as the temperature rises, the inorganic salts in the brine are supersaturated and precipitate significantly, thereby blocking the large pores and reducing the permeability.

[0121] It can be seen from Examples 1-7 that the present invention uses high-hardness brine with a calcium ion concentration of >10mM and a magnesium ion concentration of >5mM for displacement. The brine has a low temperature when injected and the inorganic salt is in an undersaturated state. As the temperature rises to 50°C, the undersaturated state is transformed into an oversaturated state, and the inorganic salt begins to precipitate, thereby effectively blocking the large pores, reducing the permeability, and achieving the purpose of profile adjustment and sealing. Furthermore, it can be seen from Examples 3, 5, 6 and Comparative Example 1 that when the sodium ion concentration in the high-hardness brine is too high, the inorganic salt will begin to precipitate before the temperature rises to the temperature of the deep formation, which is not conducive to blocking the large pores. Therefore, the sodium ion concentration in the high-hardness brine is preferably below 47000mg / L.

Claims

1. A method for oil-wet formation profile control and channeling prevention, comprising the step of using high-hardness brine for displacement, wherein the inorganic salt in the high-hardness brine is in an undersaturated state within the temperature range from the ground to the injection zone near the wellbore, and when the temperature reaches the deep formation, the inorganic salt changes from an undersaturated state to an oversaturated state, and the inorganic salt begins to precipitate.

2. The method according to claim 1, characterized in that: The high-hardness salt water contains calcium ions, or calcium ions and magnesium ions; and / or, The precipitate of the inorganic salt includes calcium carbonate and / or calcium magnesium carbonate.

3. The method according to claim 2, characterized in that: The inorganic salt saturation index of the high-hardness brine is less than 0.35 in the temperature range from the ground to the injection near-wellbore zone. After reaching the temperature deep in the formation, the calcium carbonate saturation index increases by >0.1; and / or the calcium carbonate magnesium saturation index increases by >0.

3.

4. The method according to claim 2, characterized in that: The calcium ion concentration in the high-hardness salt water is >10mM; and / or the magnesium ion concentration is >5mM.

5. The method according to claim 4, characterized in that: The calcium ion concentration in the high-hardness salt water is >15mM.

6. The method according to claim 4, characterized in that: The magnesium ion concentration in the high-hardness salt water is >10mM.

7. The method according to claim 1, characterized in that: The high-hardness salt water also contains sodium ions; preferably, The sodium ion concentration in the high-hardness brine is below 47000 mg / L, preferably 6000-46000 mg / L.

8. The method according to any one of claims 1 to 7, characterized in that: The temperature range from the ground to the injection wellbore near zone is 0-35°C; and / or the temperature in the deep formation is greater than 35°C, preferably 50-100°C.

9. The method according to claim 1, characterized in that: After reaching the deep formation temperature, the permeability drops to 10% to 90% of the original permeability.

10. Use of the method according to any one of claims 1 to 9 in enhanced oil recovery from oil-wet formations.

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