CN113931602A

CN113931602A - Method for exploiting thick oil by steam solvent mixed injection

Info

Publication number: CN113931602A
Application number: CN202010603203.5A
Authority: CN
Inventors: 张胜飞; 王红庄; 张忠义; 苟燕; 李秀峦; 孙新革; 沈德煌
Original assignee: Petrochina Co Ltd
Current assignee: Petrochina Co Ltd
Priority date: 2020-06-29
Filing date: 2020-06-29
Publication date: 2022-01-14

Abstract

The invention discloses a method for exploiting thick oil by steam solvent mixed injection. The method starts to inject solvent in the early development stage, and high-pressure production is carried out firstly to accelerate cavity expansion and oil drainage; in the middle and later development period, the pressure reduction production is carried out, the heat energy utilization efficiency is improved, and simultaneously the solvent recovery is enhanced. The solvent is heated and then changes phase, enters an oil reservoir in a gas phase form, reaches the front edge under the action of convection, and is mixed with crude oil after being condensed, so that the viscosity of the crude oil is reduced; the steam solvent is mixed and injected, so that the steam partial pressure is reduced, the dryness is improved, and the heat loss along the pipeline is reduced; hot water and solvent in the steam cavity are subjected to flash evaporation and heat absorption in the pressure reduction process, so that part of heat energy in the steam cavity is recovered and is transported to the front edge of oil drainage; after the pressure is reduced, the solubility of the solvent in oil water is reduced, the adsorption quantity on the surface of stratum minerals is reduced, and the recovery of the solvent is enhanced.

Description

Method for exploiting thick oil by steam solvent mixed injection

Technical Field

The invention relates to the field of steam injection exploitation of a thick oil horizontal well, in particular to a method for exploiting thick oil by mixed injection of steam and a solvent.

Background

Steam Assisted Gravity Drainage (SAGD) is to deploy double horizontal wells at the bottom of an oil reservoir, continuously inject steam from an upper horizontal well, and continuously produce oil from a lower horizontal well. The steam is continuously expanded upwards under the action of the super-heavy oil, the steam is condensed when encountering a cold oil reservoir to release latent heat, condensed water and heated crude oil flow to a lower production well under the action of gravity, and under the lifting actions of underground pumping, gas lift and the like, an oil-water mixture reaches the ground and is subjected to emulsion breaking and oil-water separation, so that the super-heavy oil is obtained. The SAGD gives full play to the advantages of strong reservoir control capability and high oil production speed of the horizontal well, combines the advantage of high recovery efficiency of the gravity drainage technology, is the main technology for developing the ultra-thick oil at present, and is widely applied to the development of the ultra-thick oil and the oil sand at home and abroad.

However, the steam consumption of the SAGD project is large, a large amount of natural gas needs to be combusted to generate steam, and the input-output ratio is still considerable in a period with high oil price. However, under the background of low oil price, the problem that the economic efficiency of part of SAGD projects is relatively poor is gradually exposed, and part of oil companies quit SAGD production and operation in succession. Meanwhile, each link of SAGD production generates a large amount of greenhouse gas, the emission standard of the greenhouse gas is higher and higher along with the gradual tightening of supervision, and the improvement and the upgrade of the technology are imperative.

The solvent has good intersolubility with the thick oil, the viscosity density of the solvent is lower than that of the thick oil, and the viscosity of crude oil can be greatly reduced when the solvent is dissolved in the thick oil, so that oil drainage is accelerated, and steam consumption is reduced. Therefore, the technical idea of using heat-solvent to synergistically reduce viscosity is increasingly emphasized. One of the biggest challenges in solvent application is the high cost of the solvent, which needs to be separated and recycled to reduce cost. However, the solvent is adsorbed on the surface of pores in the oil reservoir and dissolved in oil water, so that the recovery rate of the solvent is low. Most solvent field trial experience shows that project profitability is poor when solvent recovery is below 90%. Another challenge of solvent application is high investment and long capital recovery time. Therefore, the method improves the oil extraction speed and shortens the development period, and is also the key of the application of the solvent technology.

Disclosure of Invention

In order to solve at least one technical problem, the invention provides a method for exploiting thick oil by steam solvent mixed injection, which can greatly reduce the steam consumption and improve the solvent recovery rate.

In order to achieve the purpose, the invention adopts the following technical scheme:

the invention provides a method for exploiting thick oil by steam solvent mixed injection, which comprises the following steps:

s100, carrying out communication starting between double horizontal wells;

s200, injecting steam at high pressure to accelerate the expansion of an initial steam cavity;

s300, when the steam cavity grows to a preset position, keeping the injection rate of the steam unchanged, and starting to inject a solvent according to a certain concentration; the solvent in the produced mixture is separated and recovered after coarse refining;

s400, after continuously injecting the solvent with the preset injection amount, stopping injecting the solvent and only injecting steam; when the steam cavity expands 30-40 meters transversely, the pressure reduction production is started at a constant pressure reduction rate;

s500, when the pressure is reduced to 0-2 MPa lower than the initial pressure of the oil reservoir, stopping reducing the pressure, and changing the pressure reduction into low-pressure SAGD injection production;

s600, when the instantaneous oil-gas ratio is remarkably reduced, non-condensed gas is injected, and solvent recovery is enhanced.

According to the method of the present invention, preferably, when the bi-horizontal well has an adjacent well group, the method further comprises:

s700, when the development of the adjacent well group is close to the tail sound, injecting non-condensed gas from the adjacent well group for displacement, gradually reducing the pressure of a steam cavity, and further recovering the solvent.

If there is no adjacent well group, non-condensable gases are tripped in until the economic limit, i.e., the cost of injecting steam + non-condensable gases is higher than the value of producing crude oil and solvent.

The method for producing the thick oil by steam solvent mixed injection comprises the following key points:

1) solvent injection is started in the early development stage (the steam cavity is still in the vertical development stage and is not yet at the top), high-pressure production is carried out firstly, and cavity expansion and oil drainage are accelerated;

2) the pressure reduction production is carried out in the middle and later development stages, the heat energy utilization efficiency is improved, and meanwhile, the solvent recovery is enhanced;

3) the phase of the heated solvent is changed, and the heated solvent enters an oil reservoir in a gas phase form; reach the leading edge under convection; after condensation, the mixture is mixed with crude oil to reduce the viscosity of the crude oil; the steam solvent is mixed and injected, so that the steam partial pressure is reduced, the dryness is improved, and the heat loss along the pipeline is reduced;

4) hot water and solvent in the steam cavity are subjected to flash evaporation and heat absorption in the pressure reduction process, so that part of heat energy in the steam cavity is recovered and is transported to the front edge of oil drainage;

5) after the pressure is reduced, the solubility of the solvent in oil water is reduced, the adsorption quantity on the surface of stratum minerals is reduced, and the recovery of the solvent is enhanced.

According to the method of the present invention, preferably, the high pressure in S200 is 1MPa to 2MPa higher than the reservoir initial pressure. The step is to inject steam under high pressure to enhance heat transfer, thereby accelerating cavity expansion.

According to the method of the present invention, preferably, the predetermined position in S300 is a thickness of the oil layer from an oil layer top boundary 1/3.

From the viewpoint of accelerating the vertical development and the top of the steam cavity, high-pressure continuous steam injection is generally adopted. The invention selects the solvent to start the co-injection when the steam cavity grows to 1/3 oil layer thickness, takes the phase state characteristic of the solvent into consideration, and under the condition of low concentration co-injection, the solvent can help to improve the oil production speed and simultaneously maintain higher vertical expansion speed of the steam cavity.

According to the method of the present invention, preferably, the solvent is injected at a concentration in S300, wherein the concentration of the solvent is 1 mol% to 5 mol%; the solvent injection temperature is the same as the steam temperature and the injection pressure is the same as the operating pressure.

According to the method of the present invention, preferably, the predetermined injection amount in S400 is 5% to 10% of the original reservoir volume.

According to the method of the present invention, preferably, the constant depressurization rate in S400 is from 0.5KPa/d to 10 KPa/d.

The mixed injection scheme in the prior art generally adopts isobaric operation, namely, the injection pressure is maintained to be the same as or similar to the steam injection operation pressure, and the pressure is maintained to be unchanged in continuous operation, which is the basic characteristic of the gravity drainage technology and has the advantage of easily controlling SUBCOOL. And the conventional steam injection SAGD scheme adopts the method of injecting steam at high pressure in the early stage and injecting steam at low pressure in the middle and later stages, but the pressure is stepped. The invention requires that when the steam cavity is transversely expanded by 30-40 meters, the pressure reduction production is started at a constant pressure reduction rate, the pressure reduction production is continuous, linear and slow, the newly injected solvent is fully dissolved and mixed in the crude oil, the recovery of the solvent remained in the oil reservoir is promoted as much as possible, and the solvent recovery rate is improved.

The invention starts to inject solvent in the early development stage, accelerates cavity expansion and oil drainage in the first high-pressure production and reduces pressure in the middle and later development stages, and the operation has the advantages that: the high-pressure operation is maintained in the early stage, the cavity is rapidly expanded and oil drainage is carried out, and meanwhile, the pressure of an oil reservoir is reduced (along with the expansion of the steam cavity and the oil reservoir utilization scale, the pressure of the oil reservoir is continuously reduced); the pressure reduction operation after the steam cavity is fully expanded mainly takes the solvent recovery into consideration, reduces the cost and simultaneously considers the optimization of the oil production speed. The beneficial effects of doing so are: the oil extraction speed is increased, the steam consumption is reduced, the oil-steam ratio is increased, and the solvent recovery rate is greatly improved, so that the economic benefit is improved.

According to the method of the present invention, preferably, the conditions of the target heavy oil reservoir include: the mud content is low (less than 15 percent, the lower the content is, the better the mud content is), natural cracks and gas caps do not exist, and the cover layer is complete.

According to the method of the present invention, preferably, the solvent comprises one or more than two of C6, benzene, toluene, xylene and light distillate.

The solvent type selection is different from the solvent selection conditions in the existing mixed injection, and the solvent type selection of the invention needs to meet the following conditions:

a) the solubility with thick oil is good, and asphaltene is not easy to separate out;

b) depending on reservoir pressure, the selected solvent is close to the water vapor saturation vapor pressure at the operating temperature;

c) the viscosity of a mixture of the solvent and the crude oil is lower than 10mPa & s when the mass fraction of the solvent is 2%;

d) the viscosity of the solvent at room temperature is 0.4-100 mPa.s, and the density is 0.7-1.2 g/mL;

e) the solvent can be a single component, such as hydrocarbon, aromatic compound, or a mixture, such as light distillate;

f) the solvent is in liquid phase or gas phase under the condition of steam injection.

According to the method of the present invention, preferably, when the instantaneous oil-to-steam ratio in S600 is less than 0.1, it is considered that a significant drop occurs and the non-condensation gas starts to be injected.

The instantaneous oil-steam ratio generally refers to the ratio of the oil production to the steam injection on a given day.

According to the method of the present invention, preferably, the injection ratio of the non-condensable gas in S600 is gradually increased from 1 mol% in the early stage to 4 mol% in the later stage, and the injection pressure is the same as the injection steam pressure.

The method for producing the thick oil by mixed injection of the steam solvent has the following beneficial effects:

1) because the scale of the early steam cavity is small, although the injected solvent is small in amount, the concentration of the injected solvent reaching the front edge is high, and the advantage of the synergistic viscosity reduction of the solvent can be fully exerted. Is favorable for accelerating the development and oil drainage of the steam cavity and reducing the steam consumption.

2) Because of the early high-pressure operation, a steam cavity with a certain scale is formed, and the pressure reduction of the oil reservoir is realized. When the pressure reduction production is transferred to the later stage, the natural energy of the oil reservoir is fully applied, and the oil drainage speed reduction caused by pressure reduction and temperature reduction is compensated.

3) With the implementation of the pressure reduction process, hot water and solvent in the steam cavity are flashed and flow to the oil drainage front edge, and heat energy in the steam cavity is recovered. Meanwhile, the decompression operation enhances the recovery of the solvent and improves the recovery rate of the solvent.

4) The scheme of the invention can greatly improve the oil-gas ratio, save the steam consumption, promote the solvent recovery and improve the economic efficiency.

Drawings

FIG. 1 is a graph of the operating pressure of the simulation process in the example.

FIG. 2 is a graph of the temperature field during the simulation for 416 days in the example.

FIG. 3 is a 1590 day temperature field diagram during the simulation in the example.

FIG. 4 is a graph of the temperature field during the simulation for 2500 days in the example.

FIG. 5 is a plot of the oil saturation field over 416 days of the simulation procedure in the examples.

FIG. 6 is a plot of the oil saturation field at 1590 days during the simulation in the examples.

FIG. 7 is a graph of the oil saturation field for 2500 days of the simulation procedure in the examples.

FIG. 8 is a plot of solvent saturation field over 416 days of the simulation procedure in the examples.

FIG. 9 is a plot of the solvent saturation field at 1590 days during the simulation in the examples.

FIG. 10 is a plot of the solvent saturation field over 2500 days of the simulation process in the examples.

FIG. 11 is a development production dynamic diagram of the simulation process in the example.

FIG. 12 is a drawing of the extraction degree of the simulation process in the example.

FIG. 13 is a diagram illustrating the development and production effects of the simulation process in the example.

FIG. 14 is a comparison chart of development effects of different development modes in the examples.

Detailed Description

In order to more clearly illustrate the invention, the invention is further described below in connection with preferred embodiments. It is to be understood by persons skilled in the art that the following detailed description is illustrative and not restrictive, and is not to be taken as limiting the scope of the invention.

All numerical designations of the invention (e.g., temperature, time, concentration, weight, and the like, including ranges for each) may generally be approximations that vary (+) or (-) in increments of 0.1 or 1.0 as appropriate. All numerical designations should be understood as preceded by the term "about".

Example 1

This example performs steam solvent co-injection recovery on the following heavy oil reservoir

The heavy oil reservoir has the buried depth of 440 meters, the viscosity of the degassed crude oil at 50 ℃ is 106000mPa & s, the porosity is 30%, the permeability is 1.4 Daxi, the oil saturation is 90%, the reservoir thickness is 25m, the single well group controlled reserve is 25 multiplied by 100 multiplied by 400 multiplied by 0.3 multiplied by 0.85 which is 25.5 ten thousand tons of original reservoir reserve,

the mud content of the heavy oil reservoir is 1.5 percent, natural cracks and gas caps are not found by well logging explanation, and a mud cover layer with the continuous thickness of more than 5 meters is developed at the top of the oil reservoir. The method meets the heavy oil reservoir conditions applicable to the method.

The horizontal section of the double horizontal wells is 400 meters long, the diameter of each well hole is 8.5in, the distance between wells is 5 meters, the horizontal production wells are positioned 1 meter above the bottom basement rock, and temperature and pressure measuring points are arranged in the wells; and long and short pipe columns are put into the horizontal well screen pipe.

The steam injection pressure in the circulation preheating stage is 4MPa, the underground steam flow is 95 square/well/day (the two wells are 190 square/day in total), the well head steam dryness is 95%, and the communication is judged to be good after 3 months of circulation.

And transferring to normal SAGD production for 282 days after transferring to half SAGD transition. The short time of the circulating preheating stage can be higher than 4MPa, in the embodiment, the short time reaches 4.65MPa, and the pressure is 4MPa after the SAGD is converted to normal.

Then, steam solvent co-injection is started, and the steam injection rate is maintained, the solvent injection concentration is 2 mol%, and the total injection amount of the solvent is 10% of the original oil reservoir. The solvent injection temperature was the same as the steam temperature and the injection pressure was the same as the operating pressure (4 MPa). The solvent is one or more of C6, benzene, toluene, xylene, etc. (C6 + toluene is selected in this embodiment).

And (5) entering a pressure reduction production stage after 850 days of development, wherein the pressure reduction rate is 2.4KPa/d, and after 2 years of pressure reduction production, performing low-pressure production stably under the pressure of 2 MPa.

The above process is simulated, the operating pressure curve is shown in figure 1, the operating pressure is 4MPa in the early stage, then the pressure is reduced at a constant pressure reduction rate for production, and the pressure is converted into 2MPa low-pressure production in the middle and later stages. The solvent recovery in the whole process was 97%. Compared with a pure steam process, the steam consumption is saved by 58 percent.

The temperature fields during the simulation for 416 days (vapor chamber development to the top), 1590 days (vapor chamber expansion to the edge), and 2500 days (vapor chamber depression to 1/2% of reservoir thickness) are shown in fig. 2-4.

A pair of black dots in the field pattern is located in the center of the model, near the bottom of the model. Where the point with the arrow represents the steam injection horizontal well and the lower point is the production horizontal well. The color scale on the right of the field indicates the temperature range (22-250 c) in different order colors. In the field diagram, the blue color is 22 ℃ at room temperature, the red color part is 250 ℃ at steam temperature corresponding to 4MPa, and the orange color part is 212 ℃ at steam temperature corresponding to 2 MPa.

At 282 days, the steam cavity developed to 2/3 mm of the reservoir thickness and steam-solvent co-injection began.

By day 416, the vapor chamber reached the top, the lower portion of the vapor chamber was at the vapor saturation temperature, and the temperature at the top was slightly lower, indicating some enrichment of the solvent at the top, resulting in a decrease in the vapor partial pressure. The overall shape of the steam chamber resembles a standing egg.

By 850 days, the step-down operation at a constant step-down speed was started.

By 1126 days, the solvent injection was stopped after the solvent injection was completed.

On day 1590, the steam chamber had expanded to the border.

At 2500 days, the vapor chamber dropped to 1/2 f of reservoir thickness.

The oil saturation fields at 416, 1590, 2500 days during the simulation are shown in fig. 5-7.

A pair of black dots in the field pattern is located in the center of the model, near the bottom of the model. Where the point with the arrow represents the steam injection horizontal well and the lower point is the production horizontal well. The color scale on the right of the plot indicates the oil saturation range (0-1) in different order colors. In the field pattern, the red color is the original oil saturation of 0.9, and the green portion is the residual oil saturation.

When the temperature reaches 416 days, the crude oil extraction degree in the steam cavity is high, the oil saturation degree is low (green-red from inside to outside), and a certain corresponding relation exists between the saturation field and the temperature field.

1590, the steam cavity has been expanded to the edge, and an abnormal stripe (yellow) appears near the leading edge of the oil discharge, and the oil saturation of the stripe is higher than that of other regions (green) in the steam cavity, and is a rich zone of the solvent.

At 2500 days, the steam cavity dropped to 1/2 of the reservoir thickness, and the oil saturation in the steam cavity was greatly reduced to an average of 0.16, with the oil saturation at the top being the lowest of 0.04. Residual oil at the bottom corners on two sides is influenced by the technical characteristics of gravity drainage and cannot be extracted. Depending on the oil-to-gas ratio, the crude oil production process may now be terminated.

The molar concentration field patterns of the solvent in the gas phase for 416, 1590, 2500 days during the simulation are shown in fig. 8-10.

A pair of black dots in the field pattern is located in the center of the model, near the bottom of the model. Where the point with the arrow represents the steam injection horizontal well and the lower point is the production horizontal well. The color scale on the right of the field indicates the concentration range of the solvent in the gas phase (0-1) with different order colors. Blue in the field diagram is a solvent undistributed area, and the concentration is 0; the molar concentration field pattern of the solvent in the gas phase clearly shows the distribution characteristics of the solvent.

By day 416, the steam cavity developed to the top and was shaped like an egg. The vapor chamber contains mainly vapor and solvent, with a small amount of residual oil. Due to the phase state characteristics of the solvent, the solvent is enriched at the front edge to form an egg shell.

On day 1590, the vapor chamber had expanded to the sides, and the solvent was less distributed within the vapor chamber (blue portion of the field pattern), mainly concentrated near the leading edge of the drain (green).

At 2500 days, the vapor chamber dropped to 1/2 f of the reservoir thickness, and the solvent content inside the vapor chamber was very low, with a small residue at the leading edge of the vapor chamber, indicating that most of the solvent had been extracted.

The development and production dynamic diagram of the simulation process is shown in fig. 11, the extraction degree diagram is shown in fig. 12, and the effect diagram is shown in fig. 13.

A comparison graph of the development effects of the different development modes is shown in fig. 14. Description of the drawings: the invention represents a decompression scheme, and the specific process and parameters are the above embodiments of the invention; whereas conventionally the comparative scheme, the operating parameters were identical to those of the above examples of the invention, except for the depressurisation operating section (conventionally developed for maintaining 4MPa throughout). After about 8 years (2920 days) of production, the production levels are very close (indicating that the cumulative oil production is similar regardless of depressurization), about 70% (ultimate recovery of typical gravity drainage techniques); the cumulative oil-gas ratio is also very similar (because the cumulative steam injection is completely the same, the cumulative oil production is similar), and is 0.33; but the solvent extraction rate is very different, namely 0.97 in the invention and 0.35 in the conventional method, and the difference has very large influence on development cost (because the solvent cost is relatively high), so the invention has very favorable economic benefit compared with the conventional co-injection scheme.

It should be understood that the above-mentioned embodiments of the present invention are only examples for clearly illustrating the present invention, and are not intended to limit the embodiments of the present invention, and it will be obvious to those skilled in the art that other variations or modifications may be made on the basis of the above description, and all embodiments may not be exhaustive, and all obvious variations or modifications may be included within the scope of the present invention.

Claims

1. A method for producing thick oil by steam solvent co-injection is characterized by comprising the following steps:

s100, carrying out communication starting between double horizontal wells;

2. The method of claim 1, wherein when a bi-level well has an adjacent well group, the method further comprises:

3. The method of claim 1, wherein the high pressure in S200 is 1MPa to 2MPa above the reservoir initial pressure.

4. The method of claim 1, wherein the predetermined location in S300 is a reservoir thickness from a reservoir top boundary 1/3.

5. The method according to claim 1, wherein the solvent is injected at a concentration in S300, wherein the concentration of the solvent is 1 mol% to 5 mol%;

the solvent injection temperature is the same as the steam temperature and the injection pressure is the same as the operating pressure.

6. The method of claim 1 wherein the predetermined injection amount in S400 is 5% -10% of the original reservoir volume.

7. The method of claim 1, wherein the constant depressurization rate in S400 is from 0.5KPa/d to 10 KPa/d.

8. The method of claim 1, wherein the conditions of the target heavy oil reservoir comprise: the mud content is less than 15%, no natural crack and gas cap exist, and the cover layer is complete.

9. The method of claim 1, wherein the solvent comprises one or more of C6, benzene, toluene, xylene, and light distillate.

10. The method according to claim 1, wherein when the instantaneous oil-to-steam ratio in S600 is lower than 0.1, the non-condensed gas is injected;

the injection proportion of the non-condensed gas is gradually increased from 1 mol% in the early stage to 4 mol% in the later stage, and the injection pressure is the same as the injection steam pressure.