CN115163015B - Method and device for regulating and controlling output of super-heavy oil in steam flooding later period and electronic equipment - Google Patents
Method and device for regulating and controlling output of super-heavy oil in steam flooding later period and electronic equipment Download PDFInfo
- Publication number
- CN115163015B CN115163015B CN202210743383.6A CN202210743383A CN115163015B CN 115163015 B CN115163015 B CN 115163015B CN 202210743383 A CN202210743383 A CN 202210743383A CN 115163015 B CN115163015 B CN 115163015B
- Authority
- CN
- China
- Prior art keywords
- steam
- temperature
- bottom hole
- determining
- effluent
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Active
Links
- 238000010795 Steam Flooding Methods 0.000 title claims abstract description 61
- 239000000295 fuel oil Substances 0.000 title claims abstract description 48
- 238000000034 method Methods 0.000 title claims abstract description 39
- 230000001105 regulatory effect Effects 0.000 title claims abstract description 38
- 230000001276 controlling effect Effects 0.000 title claims abstract description 31
- 238000004519 manufacturing process Methods 0.000 claims abstract description 71
- 238000004364 calculation method Methods 0.000 claims abstract description 39
- 239000012530 fluid Substances 0.000 claims abstract description 31
- 229920006395 saturated elastomer Polymers 0.000 claims abstract description 30
- 230000033228 biological regulation Effects 0.000 claims abstract description 9
- 238000002347 injection Methods 0.000 claims description 58
- 239000007924 injection Substances 0.000 claims description 58
- 239000007788 liquid Substances 0.000 claims description 51
- 239000003921 oil Substances 0.000 claims description 43
- 238000010793 Steam injection (oil industry) Methods 0.000 claims description 28
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 19
- 238000012546 transfer Methods 0.000 claims description 9
- 239000004568 cement Substances 0.000 claims description 7
- 238000009413 insulation Methods 0.000 claims description 7
- 238000004590 computer program Methods 0.000 claims description 5
- 238000000605 extraction Methods 0.000 claims description 4
- 238000005259 measurement Methods 0.000 claims description 4
- 238000009834 vaporization Methods 0.000 claims description 4
- 230000008016 vaporization Effects 0.000 claims description 4
- 230000003750 conditioning effect Effects 0.000 claims description 3
- 230000005855 radiation Effects 0.000 claims description 3
- 230000001052 transient effect Effects 0.000 claims description 3
- 238000009792 diffusion process Methods 0.000 claims description 2
- 230000008901 benefit Effects 0.000 description 6
- 238000012986 modification Methods 0.000 description 5
- 230000004048 modification Effects 0.000 description 5
- 230000008569 process Effects 0.000 description 5
- 238000005516 engineering process Methods 0.000 description 4
- 238000004080 punching Methods 0.000 description 4
- 238000011161 development Methods 0.000 description 3
- 238000010586 diagram Methods 0.000 description 3
- 238000005065 mining Methods 0.000 description 3
- 239000003208 petroleum Substances 0.000 description 3
- 238000011160 research Methods 0.000 description 3
- 239000010779 crude oil Substances 0.000 description 2
- 230000000694 effects Effects 0.000 description 2
- 230000005484 gravity Effects 0.000 description 2
- 238000011084 recovery Methods 0.000 description 2
- 238000012360 testing method Methods 0.000 description 2
- UUDAMDVQRQNNHZ-UHFFFAOYSA-N (S)-AMPA Chemical group CC=1ONC(=O)C=1CC(N)C(O)=O UUDAMDVQRQNNHZ-UHFFFAOYSA-N 0.000 description 1
- 230000004075 alteration Effects 0.000 description 1
- 238000013459 approach Methods 0.000 description 1
- 230000009286 beneficial effect Effects 0.000 description 1
- 230000015572 biosynthetic process Effects 0.000 description 1
- 238000004422 calculation algorithm Methods 0.000 description 1
- 238000005266 casting Methods 0.000 description 1
- 230000005465 channeling Effects 0.000 description 1
- 238000010276 construction Methods 0.000 description 1
- 238000007872 degassing Methods 0.000 description 1
- 238000013461 design Methods 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 238000002474 experimental method Methods 0.000 description 1
- 230000006872 improvement Effects 0.000 description 1
- 230000002265 prevention Effects 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 238000012216 screening Methods 0.000 description 1
- 239000000243 solution Substances 0.000 description 1
- 230000006641 stabilisation Effects 0.000 description 1
- 238000011105 stabilization Methods 0.000 description 1
- 238000010408 sweeping Methods 0.000 description 1
- 238000012795 verification Methods 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/06—Measuring temperature or pressure
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/06—Measuring temperature or pressure
- E21B47/07—Temperature
Landscapes
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Geophysics (AREA)
- Control Of Turbines (AREA)
Abstract
The invention discloses a method for regulating and controlling the output of super heavy oil in the later steam flooding stage, which comprises the following steps: obtaining a wellbore heat loss calculation parameter and a bottom hole fluid measured pressure of a production well; determining the bottom hole effluent temperature of the production well according to the wellbore heat loss calculation parameters; determining the corresponding bottom hole saturated steam temperature according to the measured pressure of the bottom hole fluid; determining a fluid saturation temperature difference of the production well according to the bottom hole saturated steam temperature and the bottom hole effluent temperature; and regulating and controlling the later-stage yield of the super-heavy oil steam flooding according to the stream saturation temperature difference. The regulation and control method can obviously improve the steam flooding efficiency and ensure the stability of the output of the super-heavy oil in the later steam flooding stage.
Description
Technical Field
The application relates to the technical field of steam flooding super-heavy oil exploitation, in particular to a method and a device for regulating and controlling the steam flooding yield of super-heavy oil and electronic equipment.
Background
The super heavy oil (viscosity of ground degassing crude oil at 50 ℃ is >50000 mpa.s) technology is the next succession technology in the later stage of steam huff and puff of primary oil production. However, because the viscosity of crude oil in the original state of the super heavy oil reservoir is high and far exceeds the screening standard of steam flooding (< 10000 mpa.s), the technology is always in the indoor research and field test stage. In recent years, as petroleum exploration resources are continuously reduced, the quality of an extracted oil reservoir is continuously deteriorated, researchers increase the research strength of super-heavy oil steam flooding, and the success of field test acquisition of super-heavy oil steam flooding (> 50000mpa.s (millipascal seconds, viscosity units)) is mastered, so that an oil reservoir engineering design method is mastered. Meanwhile, the breakthrough is realized for the method for regulating and controlling the later stage of the super-thick oil steam flooding, and the stable yield, the stable water content and the improvement of the oil-gas ratio by 0.03-0.06 are realized by regulating and controlling the later stage of the super-thick oil steam flooding by utilizing the limit of the saturation temperature difference of the flow, so that the economical efficiency of the super-thick oil steam flooding is improved.
Some existing technologies provide a method for exploiting a steam driven super heavy oil reservoir, for example CN102278103a discloses a method for improving the recovery ratio of a deep super heavy oil reservoir by gravity drainage assisted steam driving, in which the recovery ratio of a deep massive super heavy oil reservoir is improved by utilizing a gravity drainage assisted steam driving exploitation mode. CN101852074a discloses a method and a system for exploiting a layered super heavy oil reservoir, according to the characteristics of a multi-layer oil reservoir, multiple branch wells are drilled in a main shaft in a side-drilling manner to extend into each oil layer of the oil reservoir, the whole exploitation range is heated three-dimensionally and comprehensively, a steam sweep area as large as possible is formed under the cooperation of a central steam injection well, the fluidity of super heavy oil is improved, the oil-water fluidity ratio is improved, and the problems of high viscosity, difficult driving and small steam sweeping range of the layered super heavy oil are solved.
However, in the later development period of super-heavy oil, problems such as reduced steam flooding efficiency, reduced annual oil production from well groups, reduced oil production speed and the like can occur. In the prior art, a regulation and control scheme for the later-stage yield of the super-heavy oil steam flooding is lacked, so that the steam flooding efficiency of the super-heavy oil steam flooding in the later stage is improved.
Disclosure of Invention
The invention provides a method and a device for regulating and controlling the later-stage yield of super-heavy oil steam flooding and electronic equipment, which are used for improving the steam flooding efficiency of the super-heavy oil steam flooding in the later stage and ensuring the later-stage yield.
In order to solve the technical problems, a first aspect of the embodiments of the present invention provides a method for adjusting and controlling a post-production of a super heavy oil vapor flooding, including:
obtaining a wellbore heat loss calculation parameter and a bottom hole fluid measured pressure of a production well;
determining the bottom hole effluent temperature of the production well according to the wellbore heat loss calculation parameters;
determining the corresponding bottom hole saturated steam temperature according to the measured pressure of the bottom hole fluid;
determining a fluid saturation temperature difference of the production well according to the bottom hole saturated steam temperature and the bottom hole effluent temperature;
and regulating and controlling the later-stage yield of the super-heavy oil steam flooding according to the stream saturation temperature difference.
Optionally, the adjusting and controlling the later-stage output of the super heavy oil steam flooding according to the stream saturation temperature difference includes:
if the stream saturation temperature difference is lower than 30 ℃, the sprint of a production well liquid outlet pump is adjusted, and/or the extraction ratio of a steam flooding is adjusted, so that the stream saturation temperature difference is not lower than 30 ℃.
Optionally, the wellbore heat loss calculation parameters include wellbore size parameters, wellbore heat conduction parameters, and injection steam parameters;
the wellbore dimension parameter comprises at least one of wellbore length, oil pipe inner diameter, oil pipe outer diameter, heat insulation oil pipe outer diameter, casing inner diameter, casing outer diameter and cement sheath outer diameter;
the wellbore heat conduction parameters comprise at least one of stratum heat diffusion coefficient, stratum heat conduction coefficient, cement sheath heat conduction coefficient and heat insulation oil pipe heat conduction coefficient;
the injected steam parameters include steam surface temperature and steam surface dryness.
Optionally, before the calculating the parameter according to the heat loss of the shaft, determining the bottom hole effluent temperature of the production well, the regulating method further comprises:
obtaining an injection steam rate range and an injection steam pressure range;
determining a downhole steam quality dataset at different injection steam rates, different injection steam pressures based on the injection steam rate range, the injection steam pressure range, and the wellbore heat loss calculation parameters;
and determining a target injection steam rate and a target injection steam pressure according to the bottom hole steam dryness data set.
Optionally, the calculating parameters according to the heat loss of the shaft, determining the bottom hole effluent temperature of the production well, includes:
determining a total wellbore conductivity according to the wellbore size parameter and the wellbore heat conduction parameter;
determining heat loss of the shaft according to the shaft dimension parameter, the shaft total conductivity and the steam ground temperature;
determining the theoretical bottom hole steam dryness of the steam injection well according to the steam ground dryness, the shaft heat loss and the target steam injection rate;
and when the difference value between the actually measured bottom hole steam dryness and the theoretical bottom hole steam dryness is smaller than a set value, determining the bottom hole effluent temperature according to the shaft heat loss or determining the bottom hole effluent temperature according to the shaft total conductivity.
Optionally, the determining the bottom hole effluent temperature from the wellbore heat loss comprises:
obtaining wellhead effluent temperature of a production well;
and determining a bottom hole effluent calculated temperature according to the wellhead effluent temperature, the shaft heat loss and the shaft length, and taking the bottom hole effluent calculated temperature as the bottom hole effluent temperature.
Optionally, the determining the bottom hole effluent temperature according to the wellbore total conductivity comprises:
obtaining the unit-time liquid yield, the liquid water content, the air cavity pressure and the wellhead effluent temperature of a production well;
and determining a well bottom effluent calculated temperature according to the total conductivity of the shaft, the well head effluent temperature, the liquid production amount per unit time, the liquid water content and the air cavity pressure, and taking the well bottom effluent calculated temperature as the well bottom effluent temperature.
Optionally, the calculating the bottom hole effluent temperature as the bottom hole effluent temperature includes:
obtaining the actual measurement temperature of the effluent liquid at the bottom of the well;
and when the measured temperature of the bottom-hole effluent liquid and the calculated temperature of the bottom-hole effluent liquid tend to be consistent, the calculated temperature of the bottom-hole effluent liquid is used as the temperature of the bottom-hole effluent liquid.
Based on the same inventive concept, a second aspect of the embodiment of the present invention provides a device for controlling the output of a super heavy oil vapor flooding later stage, including:
the acquisition module is used for acquiring the well bore heat loss calculation parameters of the production well and the measured pressure of the well bottom fluid;
a first determining module for determining a bottom hole effluent temperature of a production well based on the wellbore heat loss calculation parameter;
the second determining module is used for determining the corresponding bottom hole saturated steam temperature according to the measured pressure of the bottom hole fluid;
a third determining module for determining a fluid saturation temperature difference of the production well based on the bottom hole saturated steam temperature and the bottom hole effluent temperature;
and the regulation and control module is used for regulating and controlling the later-stage output of the super heavy oil steam flooding according to the flow saturation temperature difference.
Based on the same inventive concept, a third aspect of the embodiments of the present invention provides an electronic device, which includes a memory, a processor, and a computer program stored on the memory and executable on the processor, the processor implementing the steps of the regulation method according to any one of the first aspects when the computer program is executed.
Through one or more technical schemes of the invention, the invention has the following beneficial effects or advantages:
the invention provides a method for regulating and controlling the later-stage yield of super-heavy oil steam flooding, which comprises the steps of respectively determining the bottom-hole effluent temperature and bottom-hole saturated steam temperature of a production well, then determining the flow saturation temperature difference of the production well based on the bottom-hole saturated steam temperature and the bottom-hole effluent temperature, and establishing a reasonable flow saturation temperature difference control limit through the flow saturation temperature difference to prevent steam breakthrough; the steam flooding yield of the super-thick oil is dynamically regulated and controlled by utilizing the flow saturation temperature difference, so that the steam flooding yield of the well group can be effectively reduced, the water content is kept unchanged, the oil-gas ratio is improved, the steam flooding efficiency is obviously improved, and the stability of the steam flooding later-stage yield of the super-thick oil is ensured.
The foregoing description is only an overview of the present invention, and is intended to be implemented in accordance with the teachings of the present invention in order that the same may be more clearly understood and to make the same and other objects, features and advantages of the present invention more readily apparent.
Drawings
Various other advantages and benefits will become apparent to those of ordinary skill in the art upon reading the following detailed description of the preferred embodiments. The drawings are only for purposes of illustrating the preferred embodiments and are not to be construed as limiting the invention. Also, like reference numerals are used to designate like parts throughout the figures.
In the drawings:
FIG. 1 shows a schematic flow diagram of a method for regulating and controlling the post-production of super heavy oil vapor flooding according to one embodiment of the invention;
FIG. 2 illustrates a schematic view of a wellbore construction according to one embodiment of the invention;
FIG. 3 illustrates a wellhead steam quality variation profile for a steam drive block at different injection steam pressures in accordance with one embodiment of the present invention;
FIG. 4 illustrates a steam quality variation curve at different injection steam rates according to one embodiment of the invention;
FIG. 5 illustrates injection steam pressure profiles at different injection steam rates according to one embodiment of the invention;
FIG. 6 shows a bottom hole effluent temperature data table at different depths according to one embodiment of the invention;
FIG. 7 shows a schematic diagram of a control device for the late production of a super heavy oil vapor flooding according to one embodiment of the invention;
fig. 8 shows a schematic diagram of an electronic device according to an embodiment of the invention.
Detailed Description
In order to make the technical solution more clearly understood by those skilled in the art, the following detailed description is made with reference to the accompanying drawings. Throughout the specification, unless specifically indicated otherwise, the terms used herein should be understood as meaning as commonly used in the art. Accordingly, unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs. In case of conflict, the present specification will control. The various devices and the like used in the present invention are commercially available or can be prepared by existing methods unless otherwise specifically indicated.
In the middle and later stages of development of super heavy oil steam flooding, the water content of oil produced by the well group is more than 85%, the oil-gas ratio is less than 0.12, and the daily oil production of the well group is obviously reduced by more than 10% compared with the prior art. In order to improve the steam flooding efficiency at this stage and ensure the oil production of the later well group, in an alternative embodiment, as shown in fig. 1, a method for regulating and controlling the later production of super heavy oil steam flooding is provided, which comprises steps S1 to S5, specifically as follows:
s1: obtaining a wellbore heat loss calculation parameter and a bottom hole fluid measured pressure of a production well;
specifically, the measured fluid pressure at the bottom of the well is the fluid pressure of the produced fluid at the bottom of the well that is periodically tested and updated at regular intervals, such as daily.
And the wellbore heat loss calculation parameter is a calculation parameter required to calculate wellbore heat loss. Wellbore heat loss calculation parameters can be categorized by type into wellbore size parameters, wellbore heat transfer parameters, and injection steam parameters. The schematic of the section of the shaft in this embodiment is shown in fig. 2, and the calculation parameters of the heat loss of the shaft are shown in table 1:
table 1: wellbore heat loss calculation parameters
In some alternative embodiments, the conditioning methods provided by the present embodiments may further comprise, prior to calculating the bottom hole effluent temperature of the production well:
obtaining an injection steam rate range and an injection steam pressure range; determining a downhole steam quality dataset at different injection steam rates, different injection steam pressures based on the injection steam rate range, the injection steam pressure range, and the wellbore heat loss calculation parameters; and determining a target injection steam rate and a target injection steam pressure according to the bottom hole steam dryness data set.
Specifically, the dryness X of the steam at the bottom of the well j Can be calculated using the following formula:
in the above formula:
X i : steam ground dryness or wellhead steam dryness,%;
M s : rate of steam injection, m 3 /d or t/d;
C s : the vaporization latent heat of the wellhead steam is constant and kcal/kg;
qs: the rate of heat loss.
The wet steam inevitably has pressure loss and heat loss in the whole flow process from the steam injection station to the bottom of the well. Wherein the wellbore heat loss is the heat loss of the fluid in a unit length of the wellbore per unit time. Since the steam injection well bore is unstable heat flow, the heat loss rate Qs of the well bore steam deduced by combining the principle of heat transfer is calculated as follows:
in the above formula:
U to : the total conductivity of the shaft is W.m/. Degree.C;
T s : steam ground temperature, DEG C;
K e : formation thermal conductivity coefficient W.m/. Degree.C;
b: surface (constant temperature layer) temperature, DEG C;
a: ground temperature gradient, DEG C/m;
l: wellbore (total) length, m;
a transient factor.
The calculation formula of the total conductivity of the shaft is as follows:
in the above formula:
h c : the heat transfer coefficient of the heat conduction and natural convection of the annular gas, W.m/°C;
h r : the radiation heat transfer coefficient of annular gas, W.m/. Degree.C;
K cem : the thermal conductivity coefficient of the cement sheath, W.m/. Degree.C;
K ins : thermal conductivity coefficient of the heat insulation oil pipe, W.m/°C;
r to : the outer radius of the oil pipe, m;
r co : the outer radius of the sleeve, m;
r i : the outer radius of the heat insulation oil pipe, m;
r h : wellbore radius, m.
An example of a downhole steam quality dataset is shown in table 1. In table 1, the wellbore steam quality at a depth of 998 meters is the downhole steam quality in this example.
TABLE 2 statistics of steam dryness at different steam injection rates and steam injection pressures
As can be seen from table 1, at the same wellhead steam quality and injection steam pressure, the steam quality at the destination layer 998m increases with increasing injection steam speed. Moreover, under different steam injection pressures, the dryness of the wellhead steam is also different, as shown in fig. 3; meanwhile, the dryness of the steam is reduced along with the increase of the depth, and the smaller the steam injection rate is, the larger the descending amplitude is; the steam dryness of the horizontal section is basically kept unchanged, the steam dryness at the annular space is steeply reduced, and the smaller the injection steam rate is, the larger the slope is, as shown in fig. 4. For the pressure of the injected steam, if the rate of the injected steam is smaller, the pressure is firstly stable (or slightly rises), the friction is overcome in the steam injection pipe column to be reduced, and the pressure at the annular space is kept stable, as shown in fig. 5.
The optimal conditions and the oil reservoir production requirements are comprehensively considered, the target injection steam pressure is 3-6 MPa, and the target injection steam rate is 90-120 t/d.
S2: determining the bottom hole effluent temperature of the production well according to the wellbore heat loss calculation parameters;
specifically, an optional determination method includes steps S21 to S24, specifically as follows:
s21: determining a total wellbore conductivity using formula (3) based on the wellbore size parameter and the wellbore heat transfer parameter;
s22: determining a wellbore heat loss using (2) according to the wellbore size parameter, the total wellbore conductivity and the steam ground temperature;
s23: determining the theoretical bottom hole steam dryness of the steam injection well according to the steam ground dryness, the shaft heat loss and the target steam injection rate;
the detailed calculation and deduction process of the total conductivity of the shaft, the heat loss of the shaft and the dryness of the steam at the bottom of the shaft in S21-S23 can be referred to the Shuos' treatises: sun Yongtao the preferred study of heat loss and steam injection parameters for steam flooding, daqing Petroleum institute, 2007, pages 19-27, which is not described in any great detail in this example.
S24: and when the difference value between the actually measured bottom hole steam dryness and the theoretical bottom hole steam dryness is smaller than a set value, determining the bottom hole effluent temperature according to the shaft heat loss or determining the bottom hole effluent temperature according to the shaft total conductivity.
Specifically, when the difference between the actually measured bottom hole steam dryness and the theoretical bottom hole steam dryness is smaller than a set value, that is, the actually measured bottom hole steam dryness and the theoretical bottom hole steam dryness tend to be consistent, the calculation of the theoretical bottom hole steam dryness in the process is accurate, and meanwhile, the calculation of the heat loss of a shaft and the total conductivity coefficient of the shaft is proved to be accurate, so that the calculation accuracy in the subsequent calculation of the bottom hole effluent temperature is ensured. If the actually measured bottom hole steam dryness is inconsistent with the theoretical bottom hole steam dryness, the heat conduction parameters of the shaft are required to be adjusted, and the heat conduction parameters of the shaft, the heat loss of the shaft and the theoretical bottom hole steam dryness are sequentially recalculated.
The loss of the calculation of the bottom hole effluent temperature due to the heat loss of the shaft is caused by the high cost of collecting the bottom hole effluent temperature at the bottom hole, and usually, only a few wells in one block can be provided with the bottom hole effluent temperature collecting sensors, and the data cannot be collected at any time. The present embodiment thus uses the wellbore heat loss to calculate the bottom hole effluent temperature.
In determining the bottom hole effluent temperature from wellbore heat loss, two schemes can be used:
scheme one,
Obtaining wellhead effluent temperature of a production well; and determining a bottom hole effluent calculated temperature according to the wellhead effluent temperature, the shaft heat loss and the shaft length, and taking the bottom hole effluent calculated temperature as the bottom hole effluent temperature.
Specifically, the wellhead effluent temperature is measured at any time, and the heat loss Qs of the shaft can reflect the heat loss of the liquid in the shaft although the heat loss of the steam in the shaft in unit time and unit length is shown. Thus, the well head effluent temperature, combined with the heat loss of the effluent in the wellbore, can be used to calculate the bottom hole effluent temperature.
Scheme II,
Obtaining the unit-time liquid yield, the liquid water content, the air cavity pressure and the wellhead effluent temperature of a production well; and determining a well bottom effluent calculated temperature according to the total conductivity of the shaft, the well head effluent temperature, the liquid production amount per unit time, the liquid water content and the air cavity pressure, and taking the well bottom effluent calculated temperature as the well bottom effluent temperature.
Wherein, the total conductivity of the shaft is calculated in step S21, and the partial parameters and the values thereof used in the calculation process are shown in table 3:
table 3: production well bottom effluent temperature calculation parameter example
The method for calculating the bottom hole effluent temperature in the scheme II belongs to the prior art and can be applied to the Shuoshi treatises: sun Yongtao the calculation flow of "iterative algorithm for well bore temperature and pressure during steam injection" in Daqing Petroleum institute, 2007, page 27, which is not described in detail in this embodiment.
FIG. 6 shows exemplary data for calculated downhole effluent changes at different depths. In FIG. 6, length is wellbore depth, fluid temperature is effluent temperature, casting temperature is Casing temperature, fluid Press is effluent pressure, and stem Vap is Steam content.
In some alternative embodiments, for wells that conditionally collect the measured temperature of the downhole effluent, it may be verified whether the downhole effluent calculated temperature is accurate, as follows:
obtaining the actual measurement temperature of the effluent liquid at the bottom of the well; and when the measured temperature of the bottom-hole effluent liquid and the calculated temperature of the bottom-hole effluent liquid tend to be consistent, the calculated temperature of the bottom-hole effluent liquid is used as the temperature of the bottom-hole effluent liquid.
Specifically, the measured temperature of the bottom effluent and the calculated temperature of the bottom effluent tend to be consistent, that is, when the measured temperature of the bottom effluent and the calculated temperature of the bottom effluent are equal or the absolute value of the difference value between the two is smaller than a set value, it is indicated that the calculated temperature of the bottom effluent is consistent with the measured temperature, then the calculated temperature of the bottom effluent can be used to calculate the saturation temperature difference, and all parameters can be applied to super-heavy oil steam flooding production in the current stage in the research block. If calculateThe temperature does not accord with the measured temperature, the total conduction coefficient U of the shaft is recalculated after the heat conduction parameters of the shaft are adjusted to And then repeating the steps to determine the calculated temperature of the well bottom effluent and repeatedly correcting until the calculated temperature of the well bottom effluent is consistent with the actually measured temperature data of the well bottom effluent of the real well logging in the block, so that the correct value of all parameters in the calculation process is indicated.
S3: determining the corresponding bottom hole saturated steam temperature according to the measured pressure of the bottom hole fluid;
specifically, the bottom hole saturated steam temperature can be determined according to the measured pressure of the bottom hole fluid and the corresponding relation between saturated water and saturated steam.
S4: determining a fluid saturation temperature difference of the production well according to the bottom hole saturated steam temperature and the bottom hole effluent temperature;
specifically, the temperature of the bottom-hole effluent can be subtracted from the temperature of the bottom-hole saturated steam to obtain the temperature difference of the saturation.
S5: and regulating and controlling the later-stage yield of the super-heavy oil steam flooding according to the stream saturation temperature difference.
Specifically, after the flow saturation temperature difference is obtained, the flow saturation temperature difference limit of the super-heavy oil steam flooding can be determined through repeated experiments and verification. Taking a certain steam flooding of a certain oil field as an example, in order to prevent steam breakthrough, the well group adopts a scheme of reducing the drainage amount, increasing the sinking degree, improving the production flow pressure and improving the saturation temperature. When the water content of the well group is more than 88%, controlling the saturation temperature difference of the flow to be 10-20 ℃, wherein the water content is not increased any more, but the daily oil production of the well group is reduced by 13%; the saturation temperature difference limit of the well group is regulated to be 20-30 ℃, the water content is reduced by 1-3%, the oil-gas ratio is increased by 0.01-0.02, the daily oil production of the well group is still reduced by 8-10% compared with that before regulation, and the effect is still not ideal; when the saturated temperature difference of the regulating flow is more than 30 ℃, the water content is reduced to below 85%, daily oil production of the well group is equal to that before the regulating flow, the oil and steam ratio is 0.08-0.1 higher than that before the regulating flow, the extraction ratio is stabilized at about 1.2, and the goal of oil stabilization, steam reduction and control cost is reached, so that the saturated temperature difference limit of the flow is regulated and determined to be 30 ℃ in the later stage of the super-heavy oil steam flooding.
Therefore, in order to adjust the later output of the super heavy oil vapor flooding, the flow saturation temperature difference is controlled to be more than 30 ℃, and the method mainly comprises two ways: 1. adjusting the sprint of the production well liquid outlet pump according to the flow saturation temperature difference; 2. and adjusting the mining and injecting ratio of the steam flooding according to the stream saturation temperature difference.
For first and second adjustment, the bottom-hole flow pressure of the production well is changed by adjusting the liquid supply capacity, when the bottom-hole pressure is AMPa, the saturated steam temperature of the corresponding saturated pressure is B ℃, the theoretical liquid column height of the production well is Cm, the target layer well depth Dm is D-C=Em, but the actual working liquid level is Fm, which means that the actual liquid column height is D-F=Gm, and the adjustment of the sprint is needed to enable the working liquid level F to be close to the theoretical value E, namely the liquid column height G is close to the theoretical value C, so that the purpose of adjusting the bottom-hole flow pressure of the production well is achieved.
Taking a certain block as an example, when the bottom hole pressure is 2.3MPa, the bottom hole saturated steam temperature of the corresponding saturated pressure is 220 ℃, at this time, the theoretical liquid column height of the production well is 300m, the target layer well depth is 950m, the working fluid level theoretical value is 950-300=650m, but the actual working fluid level is 700-750 m, which means that at this time, the actual liquid column height is 200-250 m, and at this time, the sprint needs to be adjusted to make the working fluid level approach the theoretical value: the height of the 300m liquid column is close to the theoretical value. The block is produced by adopting a 57# screw pump, the pump efficiency is 65%, the discharge capacity is 66t/d, and the production well liquid yield = pump maximum discharge capacity x pump efficiency, when the punching is 4.5-5.5, the flow saturation temperature difference is 10-20 ℃, when the punching is 3.5-4.5, the flow saturation temperature difference is 20-30 ℃, when the punching is 2.5-3.5, the flow saturation temperature difference is >30 ℃, so that the bottom hole flow pressure of the production well can reach a reasonable value by adjusting the punching to 2.5-3.5, and the later-stage yield of the ultra-thick oil steam flooding is improved.
And for the second, the injection ratio is adjusted, and the injection ratio can be changed by adjusting the steam injection quantity or the steam injection rate, so that the flow saturation temperature difference reaches a reasonable value. And determining reasonable well group steam injection quantity according to the mining and injection ratio, increasing the well group steam injection quantity, improving the injection quantity, releasing more heat by more vaporization latent heat in the oil reservoir, increasing the temperature and reducing the viscosity, improving the flow saturation temperature difference value, and improving the later-stage yield of super-heavy oil steam flooding. However, in the later stage of super-heavy oil steam flooding, attention is paid to channeling prevention, and the development effect cannot be simply pursued to increase the steam injection quantity.
The sprint and the mining ratio may be adjusted individually or in combination, and the present invention is not limited thereto.
In general, the embodiment provides a method for regulating and controlling the later-stage output of super-heavy oil steam flooding, which comprises the steps of respectively determining the bottom-hole effluent temperature and the bottom-hole saturated steam temperature of a production well, then determining the flow saturation temperature difference of the production well based on the bottom-hole saturated steam temperature and the bottom-hole effluent temperature, and establishing a reasonable flow saturation temperature difference control limit through the flow saturation temperature difference to prevent steam breakthrough; the steam flooding yield of the super-thick oil is dynamically regulated and controlled by utilizing the flow saturation temperature difference, so that the steam flooding yield of the well group can be effectively reduced, the water content is kept unchanged, the oil-gas ratio is improved, the steam flooding efficiency is obviously improved, and the stability of the steam flooding later-stage yield of the super-thick oil is ensured.
Based on the same inventive concept as the previous embodiment, in another alternative embodiment, as shown in fig. 7, there is provided a device for controlling the post-production of super heavy oil vapor flooding, including:
an acquisition module 10 for acquiring wellbore heat loss calculation parameters and bottom hole fluid measured pressure of the production well;
a first determination module 20 for determining a bottom hole effluent temperature of a production well based on the wellbore heat loss calculation parameters;
a second determining module 30, configured to determine a corresponding bottom hole saturated steam temperature according to the measured bottom hole fluid pressure;
a third determination module 40 for determining a fluid saturation temperature difference of the production well based on the bottom hole saturated steam temperature and the bottom hole effluent temperature;
and the regulation and control module 50 is used for regulating and controlling the later-stage output of the super heavy oil steam flooding according to the flow saturation temperature difference.
Optionally, the regulation module 50 is configured to:
if the stream saturation temperature difference is lower than 30 ℃, the sprint of a production well liquid outlet pump is adjusted, and/or the extraction ratio of a steam flooding is adjusted, so that the stream saturation temperature difference is not lower than 30 ℃.
Optionally, the acquiring module 10 is configured to:
obtaining an injection steam rate range and an injection steam pressure range;
the first determining module 20 is configured to:
determining a downhole steam quality dataset at different injection steam rates, different injection steam pressures based on the injection steam rate range, the injection steam pressure range, and the wellbore heat loss calculation parameters; and determining a target injection steam rate and a target injection steam pressure according to the bottom hole steam dryness data set.
Optionally, the first determining module 20 is configured to:
determining a total wellbore conductivity according to the wellbore size parameter and the wellbore heat conduction parameter;
determining heat loss of the shaft according to the shaft dimension parameter, the shaft total conductivity and the steam ground temperature;
determining the theoretical bottom hole steam dryness of the steam injection well according to the steam ground dryness, the shaft heat loss and the target steam injection rate;
and when the difference value between the actually measured bottom hole steam dryness and the theoretical bottom hole steam dryness is smaller than a set value, determining the bottom hole effluent temperature according to the shaft heat loss or determining the bottom hole effluent temperature according to the shaft total conductivity.
Optionally, the first determining module 20 is configured to:
obtaining wellhead effluent temperature of a production well;
and determining a bottom hole effluent calculated temperature according to the wellhead effluent temperature, the shaft heat loss and the shaft length, and taking the bottom hole effluent calculated temperature as the bottom hole effluent temperature.
Optionally, the first determining module 20 is configured to:
obtaining the unit-time liquid yield, the liquid water content, the air cavity pressure and the wellhead effluent temperature of a production well;
and determining a well bottom effluent calculated temperature according to the total conductivity of the shaft, the well head effluent temperature, the liquid production amount per unit time, the liquid water content and the air cavity pressure, and taking the well bottom effluent calculated temperature as the well bottom effluent temperature.
Optionally, the first determining module 20 is configured to:
obtaining the actual measurement temperature of the effluent liquid at the bottom of the well;
and when the measured temperature of the bottom-hole effluent liquid and the calculated temperature of the bottom-hole effluent liquid tend to be consistent, the calculated temperature of the bottom-hole effluent liquid is used as the temperature of the bottom-hole effluent liquid.
Based on the same inventive concept as the previous embodiments, in yet another alternative embodiment, as shown in fig. 8, an electronic device 800 is provided, comprising a processor 820 and a memory 810, said memory 810 being coupled to said processor 820, said memory 810 storing a computer program 811, which when executed by said processor 820 causes said electronic device 800 to perform the steps of the regulation method described in the previous embodiments.
The electronic device 800 may be a server, desktop computer, notebook computer, tablet computer, smart phone, etc., without limitation.
Through one or more embodiments of the present invention, the present invention has the following benefits or advantages:
the embodiment provides a method, a device and electronic equipment for regulating and controlling the later-stage yield of super-heavy oil steam flooding, wherein the regulating and controlling method is characterized in that the bottom-hole effluent temperature and the bottom-hole saturated steam temperature of a production well are respectively determined, then the flow saturation temperature difference of the production well is determined based on the bottom-hole saturated steam temperature and the bottom-hole effluent temperature, a reasonable flow saturation temperature difference control limit can be established through the flow saturation temperature difference, and steam breakthrough is prevented; the steam flooding yield of the super-thick oil is dynamically regulated and controlled by utilizing the flow saturation temperature difference, so that the steam flooding yield of the well group can be effectively reduced, the water content is kept unchanged, the oil-gas ratio is improved, the steam flooding efficiency is obviously improved, and the stability of the steam flooding later-stage yield of the super-thick oil is ensured.
While the preferred embodiments of the present application have been described, additional variations and modifications in those embodiments may occur to those skilled in the art once they learn of the basic inventive concepts. It is therefore intended that the following claims be interpreted as including the preferred embodiments and all such alterations and modifications as fall within the scope of the application.
It will be apparent to those skilled in the art that various modifications and variations can be made in the present application without departing from the spirit or scope of the application. Thus, if such modifications and variations of the present application fall within the scope of the claims and the equivalents thereof, the present application is intended to cover such modifications and variations.
Claims (9)
1. The method for regulating and controlling the output of the super heavy oil in the later steam flooding stage is characterized by comprising the following steps:
s1: obtaining a wellbore heat loss calculation parameter of a production well and a measured pressure of a well bottom fluid, wherein the wellbore heat loss calculation parameter comprises a wellbore size parameter, a wellbore heat conduction parameter and an injection steam parameter;
s2: determining a downhole steam quality dataset at different injection steam rates, different injection steam pressures based on an injection steam rate range, an injection steam pressure range, and the wellbore heat loss calculation parameters; determining a target injection steam rate and a target injection steam pressure according to the downhole steam dryness data set; determining a bottom hole effluent temperature of a production well according to the wellbore heat loss calculation parameter and the target steam injection rate;
s3: determining the corresponding bottom hole saturated steam temperature according to the measured pressure of the bottom hole fluid;
s4: determining a fluid saturation temperature difference of the production well according to the bottom hole saturated steam temperature and the bottom hole effluent temperature;
s5: regulating and controlling the later-stage yield of the super-heavy oil steam flooding according to the stream saturation temperature difference;
wherein the downhole steam quality dataset at different injection steam rates, different injection steam pressures is determined using the following formula:
；
X j is the dryness of steam at the bottom of well, X i Steam ground dryness or wellhead steam dryness is given in units of; m is M s Is the steam injection rate, in m 3 /d or t/d; c (C) s The vaporization latent heat of wellhead steam is constant and the unit is kcal/kg; qs is the rate of heat loss, determined using the following equation:
；
T s the ground temperature of steam is expressed as the unit of the temperature; k (K) e Is the heat conductivity coefficient of stratum with the unit of W.m/DEGC; b is the surface temperature in degrees celsius; a is the ground temperature gradient in ℃/m; l is the length of the wellbore in m;is a transient factor; u (U) to Is the total conductivity of the shaft, the unit is W.m/DEG C, and is determined by adopting the following formula:
；
h c the heat transfer coefficient of heat conduction and natural convection of annular gas is expressed as W.m/DEG C; h is a r Is the radiation heat transfer coefficient of annular gas, and the unit is W.m/DEG C; k (K) cem The thermal conductivity coefficient of the cement sheath is expressed as W.m/. Degree.C; k (K) ins The heat conduction coefficient of the heat insulation oil pipe is expressed as W.m/DEG C; r is (r) to Is the outer radius of the oil pipe, and the unit is m; r is (r) co Is the outer radius of the sleeve, and the unit is m; r is (r) i The outer radius of the heat-insulating oil pipe is m; r is (r) h Is the radius of the wellbore in m.
2. The method of regulating and controlling of claim 1, wherein regulating and controlling the post-production of the super heavy oil vapor flooding based on the stream saturation temperature difference comprises:
and if the flow saturation temperature difference is lower than 30 ℃, adjusting the stroke frequency of a production well liquid outlet pump and/or adjusting the extraction and injection ratio of a steam flooding so that the flow saturation temperature difference is not lower than 30 ℃.
3. The method of regulating and controlling of claim 1, wherein the wellbore dimension parameter comprises wellbore length and at least one of tubing inner diameter, tubing outer diameter, insulating tubing outer diameter, casing inner diameter, casing outer diameter, cement sheath outer diameter;
the wellbore heat conduction parameters comprise at least one of stratum heat diffusion coefficient, stratum heat conduction coefficient, cement sheath heat conduction coefficient and heat insulation oil pipe heat conduction coefficient;
the injected steam parameters include steam surface temperature and steam surface dryness.
4. The method of regulating of claim 3, wherein said determining a bottom hole effluent temperature of a production well based on said wellbore heat loss calculation parameters comprises:
determining a total wellbore conductivity according to the wellbore size parameter and the wellbore heat conduction parameter;
determining heat loss of the shaft according to the shaft dimension parameter, the shaft total conductivity and the steam ground temperature;
determining the theoretical bottom hole steam dryness of a steam injection well according to the steam ground dryness, the shaft heat loss and the target steam injection rate;
and when the difference value between the actually measured bottom hole steam dryness and the theoretical bottom hole steam dryness is smaller than a set value, determining the bottom hole effluent temperature according to the shaft heat loss, or determining the bottom hole effluent temperature according to the shaft total conductivity.
5. The conditioning method of claim 4, wherein said determining said bottom hole effluent temperature from said wellbore heat loss comprises:
obtaining wellhead effluent temperature of a production well;
and determining a bottom hole effluent calculated temperature according to the wellhead effluent temperature, the shaft heat loss and the shaft length, and taking the bottom hole effluent calculated temperature as the bottom hole effluent temperature.
6. The method of regulating of claim 4, wherein said determining the bottom hole effluent temperature based on the total conductivity of the wellbore comprises:
obtaining the unit-time liquid yield, the liquid water content, the air cavity pressure and the wellhead effluent temperature of a production well;
and determining a well bottom effluent calculated temperature according to the total conductivity of the shaft, the well head effluent temperature, the liquid production amount per unit time, the liquid water content and the air cavity pressure, and taking the well bottom effluent calculated temperature as the well bottom effluent temperature.
7. The conditioning method of claim 5 or 6, wherein said calculating the bottom hole effluent temperature as the bottom hole effluent temperature comprises:
obtaining the actual measurement temperature of the effluent liquid at the bottom of the well;
and when the measured temperature of the bottom-hole effluent liquid and the calculated temperature of the bottom-hole effluent liquid tend to be consistent, the calculated temperature of the bottom-hole effluent liquid is used as the temperature of the bottom-hole effluent liquid.
8. A regulating and controlling device for the output of super heavy oil in the later steam flooding stage, which is characterized in that the regulating and controlling device comprises:
the system comprises an acquisition module, a control module and a control module, wherein the acquisition module is used for acquiring a shaft heat loss calculation parameter of a production well and a measured pressure of a well bottom fluid, and the shaft heat loss calculation parameter comprises a shaft size parameter, a shaft heat conduction parameter and an injection steam parameter;
a first determination module for determining a downhole steam quality dataset at different injection steam rates, different injection steam pressures based on an injection steam rate range, an injection steam pressure range, and the wellbore heat loss calculation parameters; determining a target injection steam rate and a target injection steam pressure according to the downhole steam dryness data set; determining a bottom hole effluent temperature of a production well according to the wellbore heat loss calculation parameter and the target steam injection rate;
the second determining module is used for determining the corresponding bottom hole saturated steam temperature according to the measured pressure of the bottom hole fluid;
a third determining module for determining a fluid saturation temperature difference of the production well based on the bottom hole saturated steam temperature and the bottom hole effluent temperature;
the regulation and control module is used for regulating and controlling the later-stage output of the super-heavy oil steam flooding according to the flow saturation temperature difference;
wherein the downhole steam quality dataset at different injection steam rates, different injection steam pressures is determined using the following formula:
；
X j is the dryness of steam at the bottom of well, X i Steam ground dryness or wellhead steam dryness is given in units of; m is M s Is the steam injection rate, in m 3 /d or t/d; c (C) s The vaporization latent heat of wellhead steam is constant and the unit is kcal/kg; qs is the rate of heat loss, determined using the following equation:
；
T s the ground temperature of steam is expressed as the unit of the temperature; k (K) e Is the heat conductivity coefficient of stratum with the unit of W.m/DEGC; b is the surface temperature in degrees celsius; a is the ground temperature gradient in ℃/m; l is the length of the wellbore in m;is a transient factor; u (U) to Is the total conductivity of the shaft, the unit is W.m/DEG C, and is determined by adopting the following formula:
；
h c the heat transfer coefficient of heat conduction and natural convection of annular gas is expressed as W.m/DEG C; h is a r Is the radiation heat transfer coefficient of annular gas, and the unit is W.m/DEG C; k (K) cem The thermal conductivity coefficient of the cement sheath is expressed as W.m/. Degree.C; k (K) ins The heat conduction coefficient of the heat insulation oil pipe is expressed as W.m/DEG C; r is (r) to Is the outer radius of the oil pipe, and the unit is m; r is (r) co Is the outer radius of the sleeve, and the unit is m; r is (r) i The outer radius of the heat-insulating oil pipe is m; r is (r) h Is the radius of the wellbore in m.
9. An electronic device comprising a memory, a processor and a computer program stored on the memory and executable on the processor, characterized in that the processor implements the steps of the regulating method according to any one of claims 1 to 7 when the computer program is executed by the processor.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN202210743383.6A CN115163015B (en) | 2022-06-27 | 2022-06-27 | Method and device for regulating and controlling output of super-heavy oil in steam flooding later period and electronic equipment |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN202210743383.6A CN115163015B (en) | 2022-06-27 | 2022-06-27 | Method and device for regulating and controlling output of super-heavy oil in steam flooding later period and electronic equipment |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CN115163015A CN115163015A (en) | 2022-10-11 |
| CN115163015B true CN115163015B (en) | 2024-04-09 |
Family
ID=83487413
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CN202210743383.6A Active CN115163015B (en) | 2022-06-27 | 2022-06-27 | Method and device for regulating and controlling output of super-heavy oil in steam flooding later period and electronic equipment |
Country Status (1)
| Country | Link |
|---|---|
| CN (1) | CN115163015B (en) |
Citations (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US6257334B1 (en) * | 1999-07-22 | 2001-07-10 | Alberta Oil Sands Technology And Research Authority | Steam-assisted gravity drainage heavy oil recovery process |
| CN104695922A (en) * | 2015-02-06 | 2015-06-10 | 江苏万兴石油装备有限公司 | Intelligent steam regulation real-time control method and device |
| CN105160161A (en) * | 2015-08-17 | 2015-12-16 | 中国石油天然气股份有限公司 | Shaft internal thermal parameter calculation method and apparatus |
| CN109033565A (en) * | 2018-07-06 | 2018-12-18 | 中国石油天然气股份有限公司 | A kind of horizontal wells in heavy oil reservoir superheated steam is handled up Dynamic Productivity Calculation prediction technique |
| CN111581585A (en) * | 2020-06-01 | 2020-08-25 | 中国石油大学(华东) | Horizontal well steam throughput thermal diffusion radius calculation method considering wellbore on-way energy loss |
Family Cites Families (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CA2807713C (en) * | 2010-09-14 | 2016-04-05 | Conocophillips Company | Inline rf heating for sagd operations |
-
2022
- 2022-06-27 CN CN202210743383.6A patent/CN115163015B/en active Active
Patent Citations (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US6257334B1 (en) * | 1999-07-22 | 2001-07-10 | Alberta Oil Sands Technology And Research Authority | Steam-assisted gravity drainage heavy oil recovery process |
| CN104695922A (en) * | 2015-02-06 | 2015-06-10 | 江苏万兴石油装备有限公司 | Intelligent steam regulation real-time control method and device |
| CN105160161A (en) * | 2015-08-17 | 2015-12-16 | 中国石油天然气股份有限公司 | Shaft internal thermal parameter calculation method and apparatus |
| CN109033565A (en) * | 2018-07-06 | 2018-12-18 | 中国石油天然气股份有限公司 | A kind of horizontal wells in heavy oil reservoir superheated steam is handled up Dynamic Productivity Calculation prediction technique |
| CN111581585A (en) * | 2020-06-01 | 2020-08-25 | 中国石油大学(华东) | Horizontal well steam throughput thermal diffusion radius calculation method considering wellbore on-way energy loss |
Non-Patent Citations (1)
| Title |
|---|
| 超稠油油藏蒸汽吞吐稳产技术对策研究;徐家年;冯国庆;任晓;黄显德;刘虹利;;西南石油大学学报;20071015(05);全文 * |
Also Published As
| Publication number | Publication date |
|---|---|
| CN115163015A (en) | 2022-10-11 |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| CN106651610B (en) | Dynamic analysis method for water injection development of shallow ultra-low permeability sandstone reservoir | |
| US5273111A (en) | Laterally and vertically staggered horizontal well hydrocarbon recovery method | |
| US7621326B2 (en) | Petroleum extraction from hydrocarbon formations | |
| Stone et al. | Thermal simulation with multisegment wells | |
| CN103174403B (en) | Thick-layer drives unitized production method containing the gravity every interlayer common heavy oil reservoir with steam | |
| US9482081B2 (en) | Method for preheating an oil-saturated formation | |
| US20140216732A1 (en) | Hydrocarbon recovery control system and method | |
| Fallah et al. | Globally scalable geothermal energy production through managed pressure operation control of deep closed-loop well systems | |
| CN102654048B (en) | Injection-production two-trip pipe string balanced well killing control method | |
| CN103590798B (en) | A kind of super-viscous oil steam injection recovery is boiled in a covered pot over a slow fire the determination method of well time and calculates device | |
| CN102682195B (en) | Semisubmersible platform transient state bored shaft temperature computation method | |
| CN107269254A (en) | A kind of well group structures and methods using ground die mould geothermal energy extracting hydrate on bottom of sea | |
| CN116108572A (en) | Shale gas condensate well volume fracturing outer zone productivity contribution analysis method | |
| CN106194135A (en) | Circulation pre-heating mean during dual horizontal well SAGD and device | |
| CN105134151B (en) | Hot nitrogen energization Viscosity Reduction And Stimulation | |
| CN115163015B (en) | Method and device for regulating and controlling output of super-heavy oil in steam flooding later period and electronic equipment | |
| CN109403957B (en) | High-pressure formation pressure acquisition method | |
| CN108627436B (en) | Method for predicting water inflow of underground water seal oil depot based on construction dynamic monitoring data | |
| Zhao et al. | Production optimizaton and application of combined artificial-lift systems in deep oil wells | |
| US20150198023A1 (en) | Systems and methods for producing viscous hydrocarbons | |
| CN110895627A (en) | Decision-making method for dynamically optimizing heating parameters of shaft | |
| CN115292870A (en) | Method for establishing hydrate exploitation numerical model based on starting pressure gradient | |
| CN115045642A (en) | Well and oil well push-pull linkage thickened oil exploitation method | |
| CN110359892B (en) | Steam flooding scheme optimization design method based on oil reservoir conditions | |
| CN107630688B (en) | Novel technical evaluation method for dilution-doping cold recovery of high-pour-point oil reservoir stratum |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| PB01 | Publication | ||
| PB01 | Publication | ||
| SE01 | Entry into force of request for substantive examination | ||
| SE01 | Entry into force of request for substantive examination | ||
| GR01 | Patent grant | ||
| GR01 | Patent grant |