Carbon dioxide oil displacement method for improving shale oil recovery ratio

Abstract

The invention discloses a carbon dioxide oil displacement method for improving shale oil recovery ratio, which belongs to the technical field of carbon dioxide oil displacement, and comprises the following steps: before injecting a carbon dioxide slug, estimating the leading edge pressure and leading edge temperature of injecting carbon dioxide, and adjusting the injection pressure and injection temperature of the carbon dioxide to enable the carbon dioxide to be located in a liquid area. The injection pressure and temperature of the carbon dioxide are adjusted according to the estimated leading edge pressure and temperature changing along with the distance from the shaft, and it is ensured that the injected carbon dioxide is kept in a liquid state in the stratum. The liquid carbon dioxide is injected into the oil reservoir, so that the gravity exceeding problem is relieved, the viscosity index phenomenon is reduced, the sweep efficiency is improved, and the petroleum yield is increased.

Description

Technical Field

[0001] The present invention belongs to the technical field of carbon dioxide enhanced oil recovery, and particularly relates to a carbon dioxide enhanced oil recovery method for improving the recovery rate of shale oil. Background Art

[0002] One currently popular method for producing shale oil is gas (CO 2 ) huff and puff, but this method is generally effective for several cycles, and the subsequent oil production is very low. To increase production, other production methods need to be adopted. A commonly used method is gas flooding, which can not only improve the oil recovery rate but also sequester carbon dioxide in the reservoir. To reduce CO 2 emissions, the injected gas can be CO 2 . For the CO 2 flooding process, the density of gaseous CO 2 is much lower than that of liquid oil or water. Gravity override is a well-known problem, and carbon dioxide preferentially reaches the top of the reservoir under the seal cap layer, resulting in low sweep efficiency. Due to the very low viscosity of gaseous CO 2 , the mobility ratio of gaseous CO 2 is higher than that of oil or water, which also causes the viscous fingering phenomenon and results in low sweep efficiency. Summary of the Invention

[0003] To solve the above problems, the present invention provides a carbon dioxide enhanced oil recovery method for improving the recovery rate of shale oil.

[0004] To achieve the above object, the technical solution adopted by the present invention is as follows:

[0005] A carbon dioxide enhanced oil recovery method for improving the recovery rate of shale oil, comprising the following steps:

[0006] Step 1, define the P-T phase diagram of the injected CO 2 ; control the injected CO 2 in the liquid region in the P-T phase diagram;

[0007] Step 2, estimate the front pressure P 2 of the injected CO f in the reservoir;

[0008] Step 3, estimate the front temperature T 2 of the injected CO f through the following equation:

[0009]

[0010] Where: T f is the front temperature of CO 2 , °C; T r0 is the initial reservoir temperature, °C; Ti Injecting liquid CO into the underground wellbore 2 Temperature, °C; ξ is the dimensionless leading edge distance from the wellbore; τ is the dimensionless time;

[0011] ξ is defined as follows:

[0012]

[0013] Where: λ is the reservoir thermal conductivity, W / (m·K); x is the distance from the wellbore, m; b is half of the reservoir thickness, m; (ρC) f is the fluid heat capacity, kJ / (m 3 ·°C); v f is the leading edge velocity, m / s;

[0014] Step 4. Repeat Steps 1 - 3, and adjust the pressure and temperature of the injected CO 2 until the injected CO 2 slug is located in the liquid region.

[0015] Furthermore, in Step 1, the P - T phase diagram of the injected CO 2 is calculated through the equation of state.

[0016] Furthermore, in Step 2, the Darcy equation is used to estimate the leading edge pressure P 2 of the injected CO in the reservoir, and the Darcy equation is as follows: f P

[0017] P f = P i - qμln(r f / r w ) / 2πkh

[0018] Where: P f is the leading edge pressure, Pa; P i is the injection pressure of liquid CO 2 , Pa; q is the injection rate of liquid CO 2 injection velocity, m 3 / s; μ is the viscosity of liquid CO 2 , Pa·s; r f is the distance from the leading edge of liquid CO 2 to the wellbore, m; r w is the wellbore radius, m; k is the permeability, m 2 ; h is the formation thickness, m.

[0019] Furthermore, in Step 3, the dimensionless time τ is calculated by the following formula:

[0020]

[0021] (ρC)r is the heat capacity of the reservoir, kJ / (m 3 ·℃), t is the injection time of liquid CO 2 injection time, s.

[0022] Furthermore, when the initial reservoir temperature is 50 °C and the injected CO 2 temperature is 25 °C, the predicted front temperature varies with the distance from the wellbore: as the distance of the front from the wellbore ranges from 0 m to 500 m, the front temperature is between 25 °C and 27.5 °C.

[0023] Compared with the prior art, the technical progress achieved by the present invention lies in:

[0024] By adjusting the injection pressure and temperature of carbon dioxide, the present invention ensures that the injected carbon dioxide remains in a liquid state in the formation. By injecting a liquid carbon dioxide slug, the present invention alleviates the gravity override problem, reduces the viscous fingering phenomenon, and thereby improves the sweep efficiency and increases the oil production. BRIEF DESCRIPTION OF THE DRAWINGS

[0025] The drawings are used to provide a further understanding of the present invention and constitute a part of the specification. Together with the embodiments of the present invention, they are used to explain the present invention and do not constitute a limitation to the present invention.

[0026] In the drawings:

[0027] Figure 1 is the P-T phase diagram of pure carbon dioxide;

[0028] Figure 2 is the P-T phase diagram of a mixture of carbon dioxide and other gases;

[0029] Figure 3 is the curve of the viscosity of carbon dioxide varying with pressure and temperature;

[0030] Figure 4 is the curve of the density of carbon dioxide varying with pressure and temperature;

[0031] Figure 5 is the front temperature of liquid CO 2 at different distances from the wellbore. DETAILED DESCRIPTION OF THE EMBODIMENTS

[0032] The following specific embodiments can be combined with each other, and the same or similar concepts or processes may not be repeated in some embodiments. The embodiments of the present invention will be described below with reference to the drawings.

[0033] A carbon dioxide flooding method for improving the recovery rate of shale oil provided by an embodiment of the present invention includes the following steps:

[0034] Step 1. Define the injection of CO2 P-T phase diagram; CO is injected into the reservoir 2 is controlled in the liquid region of the P-T phase diagram. CO 2 The P-T diagram of the mixture can be obtained by software such as WINPROP of the Computer Modeling Group. The principle therein is the equation of state (this is prior art and will not be elaborated here). The P-T phase diagram of the injected CO 2 is calculated. Similarly, the P-T phase diagram of component A (CO Figure 2 ) in 2 is calculated. Figure 1 is the P-T phase diagram of CO 2 , indicating that above low temperature and medium pressure, CO 2 is in a liquid state.

[0035] In view of the fact that the density, viscosity and phase diagram of carbon dioxide change with pressure and temperature.

[0036] Figure 3 shows the change of CO 2 viscosity with pressure and temperature. It shows that the viscosity is almost a linear function of temperature and is not sensitive to pressure.

[0037] Figure 4 shows the change of CO 2 density with pressure and temperature. This shows that when the temperature is below 31 °C, even at moderate pressure, the CO 2 density is very high and is like a liquid. Therefore, it is very important to ensure a low temperature at the carbon dioxide front.

[0038] If other gases are contained in CO 2 , the gas-phase P-T diagram will change. In Figure 2 , component A is a typical gas mainly composed of CO 2 , while component B has other gases with a high mole fraction. The P-T phase diagrams of the two fluids are different and the critical points are also different. The yellow triangle represents the reservoir state. This figure shows that under the same reservoir conditions, component A exists like a liquid, while component B exists like a gas. Therefore, the fluid composition can also change the fluid state under reservoir conditions.

[0039] In summary, by changing the pressure, temperature and / or composition to guide the CO 2 flow to a liquid state.

[0040] Step 2, estimate the front pressure P 2 of the CO injected into the reservoir; use Darcy's equation to estimate the front pressure P f of the CO injected into the reservoir. Darcy's equation is as follows: 2 of the CO injected into the reservoir, f Darcy's equation is as follows:

[0041] P f = P i - qμln(r f / r w ) / 2πkh

[0042] In the formula: P f is the front pressure, Pa; P i is the injection pressure of liquid CO 2 , Pa; q is the injection rate of liquid CO 2 , m 3 / s; μ is the viscosity of liquid CO 2 , Pa·s; r f is the distance from the front of liquid CO 2 to the wellbore, m; r w is the wellbore radius, m; k is the permeability, m 2 ; h is the formation thickness, m.

[0043] Step 3. Estimate the front temperature T 2 of the injected CO f through the following equation:

[0044]

[0045] In the formula: T f is the front temperature of CO 2 , °C; T r0 is the initial reservoir temperature, °C; T i is the injection temperature of CO 2 downhole in the wellbore, °C; ξ is the dimensionless front distance from the wellbore; τ is the dimensionless time.

[0046] ξ is defined as follows:

[0047]

[0048] In the formula: λ is the reservoir thermal conductivity, W / (m·K); x is the distance from the wellbore, m; b is half of the reservoir thickness, m; (ρC) f is the fluid heat capacity, kJ / (m 3 ·°C); v f is the front velocity, m / s.

[0049] The dimensionless time τ is calculated by the following formula:

[0050]

[0051] (ρC) r is the reservoir heat capacity, kJ / (m 3 ·°C), t is the injection time of the injected liquid CO 2 , s.

[0052] As Figure 5 shown, when the initial reservoir temperature is 50 °C and the injection CO 2 temperature is 25 °C, the predicted front temperature changes with the distance from the wellbore: as the distance of the front from the wellbore ranges from 0 m to 500 m, the front temperature is between 25 °C and 27.5 °C.

[0053] Step 4. Repeat Step 1 - Step 3 to find the estimated front pressure P 2 and front temperature T f on the P - T phase diagram of the injected liquid CO f . Adjust the injection pressure and injection temperature of CO 2 until the front pressure P f and front temperature T f are located in the liquid region. The specific operation is as follows:

[0054] First, find the above - estimated P f and T f in the P - T diagram defined in Step 1. In the example used above, P f is 80 bara and T f is 25 - 27.5 °C. Refer to the Figure 2 phase diagram. If its position is in the liquid region, then the parameters defining each P f and T f are determined.

[0055] Otherwise, repeat Steps 1 to 3 until p f and T f are located in the liquid region.

[0056] In summary, the present invention injects a liquid carbon dioxide slug into a formation (reservoir), estimates the front pressure and front temperature of the injected liquid carbon dioxide, and by adjusting the injection pressure and temperature of carbon dioxide, makes it located in the liquid region, ensuring that the injected carbon dioxide remains in a liquid state in the formation, alleviating the gravity override problem, reducing the fingering phenomenon, thereby improving the sweep efficiency and increasing the oil production.

[0057] Finally, it should be noted that the above - described are only the preferred embodiments of the present invention and are not used to limit the present invention. Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art can still modify the technical solutions recorded in the foregoing embodiments, or perform equivalent replacements for some of the technical features. Any modifications, equivalent replacements, improvements, etc. made within the spirit and principle of the present invention shall be included within the scope of the protection of the claims of the present invention.

Claims

1. A carbon dioxide flooding method for improving shale oil recovery, characterized in that: The following steps are involved: Step 1, define the PT phase diagram of injected CO2; the CO2 injected into the reservoir is controlled in the liquid region of the PT phase diagram; Step 2: Estimate the front pressure P of injected CO2 in the reservoir f ; Step 3: Estimate the front temperature T of injected CO2 by the following equation: f : Where: T f is the front temperature of CO2, ℃; T r0 is the initial reservoir temperature, °C; T i is the temperature of liquid CO2 injected into the wellbore, °C; ξ is the dimensionless front distance from the wellbore; τ is the dimensionless time; ξ is defined as follows: Where: λ is the thermal conductivity of the reservoir, W / (m·K); x is the distance from the wellbore, m; b is half the thickness of the reservoir, m; (ρC) f is the heat capacity of the fluid, kJ / (m 3 ℃); v f is the front velocity, m / s; Step 4: Repeat steps 1 to 3 to adjust the pressure and temperature of the injected CO2 until the injected CO2 plug is located in the liquid area.

2. A carbon dioxide flooding method for improving shale oil recovery according to claim 1, characterized in that: In step 1, the PT phase diagram of injected CO2 is calculated by the equation of state.

3. A carbon dioxide flooding method for improving shale oil recovery according to claim 2, characterized in that: In step 2, the Darcy equation is used to estimate the front pressure P of the injected CO2 in the reservoir. f , Darcy's equation is as follows: P f =P i -qμln(r f / r w ) / 2πkh Where: P f is the front pressure, Pa; P i is the liquid CO2 injection pressure, Pa; q is the liquid CO2 injection rate, m 3 / s; μ is the viscosity of liquid CO2, Pa.s; r f is the distance of the liquid CO2 front from the wellbore, m; r w is the wellbore radius, m; k is the permeability, m 2 ; h is the formation thickness, m.

4. A carbon dioxide flooding method for improving shale oil recovery according to claim 3, characterized in that: In step 3, the dimensionless time τ is calculated by the following formula: (ρC) r is the reservoir heat capacity, kJ / (m 3 ·℃), t is the injection time of liquid CO2, s.

5. A carbon dioxide flooding method for improving shale oil recovery according to claim 4, characterized in that: When the initial reservoir temperature is 50℃ and the injected liquid CO2 temperature is 25℃, the predicted front temperature varies with the distance from the wellbore: the front temperature is between 25℃ and 27.5℃ when the distance from the wellbore ranges from 0m to 500m.

Images