A method for improving the development effect of steam huff and puff in shallow extra-heavy oil reservoirs

Abstract

This invention provides a method for improving the development effect of steam huff and puff in shallow extra-heavy oil reservoirs. The improvement method includes: step S1, optimizing the steam injection rate of slug one and injecting the first steam slug into the reservoir; step S2, determining the location of the high conductivity channel and calculating the required amount of temporary plugging agent based on the bottom hole temperature measurement curve; step S3, selecting the type of temporary plugging agent and injecting it directionally into the reservoir; step S4, optimizing the steam injection rate of slug two and injecting the second steam slug into the reservoir; step S5, shutting down the well and waiting for the temperature field to expand and the temporary plugging agent to become ineffective before switching to production; step S6, using daily oil production as the cutoff condition for rotating production. This method effectively improves the recovery rate of shallow extra-heavy oil reservoirs and forms a method for improving the development effect of shallow extra-heavy oil reservoirs through directional temporary plugging.

Description

Technical Field

[0001] This invention relates to the field of oilfield development technology, and in particular to a method for improving the steam huff and puff development effect of shallow extra-heavy oil reservoirs. Background Technology

[0002] The Shengli West shallow extra-heavy oil reservoir is relatively shallow, ranging from 200 to 500 meters, with low reservoir pressure (1.2–4.8 MPa) and high crude oil viscosity (400–1000 x 10⁻⁶). 4 mPa·s. This type of heavy oil reservoir lacks a stable rock framework and belongs to the "oil-encased sand" type. During steam injection, the injection pressure is generally more than twice the reservoir pressure, forming a high-conductivity channel. During production, influenced by factors such as crude oil viscosity and pressure field changes, the high-conductivity channel closes, preventing steam entering the deep reservoir from returning to the bottom of the well. The pressure near the wellbore drops rapidly, resulting in short production times and poor development performance in huff-and-puff wells. Figure 2 As shown in the diagram. This also leads to the following problems during shallow extra-heavy oil steam huff and puff: insufficient steam injection results in inadequate heat supply and unsatisfactory viscosity reduction; excessive steam injection causes severe cross-flow, low water recovery rate, and low thermal efficiency. Each high-conductivity channel has an optimal steam injection rate that ensures heating effect while improving thermal efficiency. Therefore, increasing the number of high-conductivity channels is key to improving the development effect of shallow extra-heavy oil steam huff and puff.

[0003] Temporary plugging agents can be used to increase the number of high-conductivity channels and improve the steam huff and puff development effect of shallow extra-heavy oil reservoirs. By calculating the thermal efficiency under different steam injection rates, the amount of pre-steam slug is optimized. After pre-steam injection, the heat concentration area is located using bottom-hole temperature measurement curves to determine the location of high-conductivity channels. The temperature distribution of high-conductivity channels is normalized, and the temporary plugging agent requirement for high-conductivity channels at different locations is calculated. Based on the crude oil viscosity and the size of the high-conductivity channels, the type of temporary plugging agent (inorganic, organic, or a combination of both) is selected. A packer is used to achieve directional injection of high-strength temporary plugging agent, which preferentially enters the high-conductivity channels, increasing the seepage resistance of these channels. The high-conductivity channels are then sealed sequentially. Numerical simulation methods are then used to optimize the subsequent steam injection rate. Another slug of steam is injected, which promotes the emergence of new channels, transforming them from long, narrow channels to short, wide channels. After steam injection, the well is shut down to allow for mass and heat transfer between the steam and the reservoir, and for the temporary plugging agent to deteriorate before production resumes. After production ends, the next cycle of huff and puff development begins.

[0004] In conventional plugging processes, plugging agents typically act on gas channeling pathways between multiple wells. The longer the plugging time in high-conductivity channels, the better, ideally at least one cycle. However, the plugged channels contribute little to production capacity. Shallow extra-heavy oil reservoirs exhibit unique flow patterns, with high-conductivity channels containing high oil saturation and significant development potential. Therefore, prolonged plugging is not suitable. Figure 3 As shown. The temporary plugging agent only temporarily seals the high-conductivity channel. After a period of well shut-in, the plugging agent becomes ineffective, and the sealed channel can continue to supply fluid to the well, such as... Figure 4 As shown. Simultaneously, slug-type steam injection facilitates mass and heat transfer between the pre-steam slug and the reservoir, improves steam thermal utilization, reduces crude oil viscosity more uniformly, and reduces fingering phenomenon in subsequent steam slugs. A single steam injection will form a small number of long and narrow high-conductivity channels. The injection of temporary plugging agent can temporarily plug the channels formed by the pre-steam slug, and subsequent steam slugs will form new high-conductivity channels. This increases the number of channels and promotes concentrated steam heating of crude oil near the huff and puff well, forming wide and short high-conductivity channels, thereby improving the development effect of steam huff and puff for shallow extra-heavy oil.

[0005] The patent titled "A Step-by-Step Design Method for Multi-Functional Directional Viscosity Reduction after Multiple Rounds of Huff and Puff in Heavy Oil" proposes a method to finely divide the oil layer using the oil layer temperature change curve along the radial direction of the huff and puff well, thereby accurately utilizing the remaining oil, improving steam heat utilization, and enhancing the steam huff and puff development effect. This method addresses the problem of low remaining oil saturation in the near-wellbore zone and difficulty in further effectively expanding the drainage radius during the multiple huff and puff stage. It does not consider the uneven utilization problem in the early stage of shallow extra-heavy oil. Furthermore, the steam is injected into the reservoir in a single injection, and the injection mode is also different. The patent titled "A Method for Late-Stage Development of Multiple Rounds of Huff and Puff in Thin-Layer Heavy Oil Reservoirs" proposes to improve the late-stage development effect of multiple rounds of huff and puff in thin-layer heavy oil reservoirs by using nitrogen and microemulsion-assisted steam. This method addresses the contradiction of rapid decline in production, rapid increase in water cut, and decreased energy leading to poor development effect in the later stage of multiple rounds of huff and puff in thin-layer heavy oil. The aim is to increase formation energy, improve steam sweep and oil washing efficiency. However, the steam is injected in a single injection, and it does not consider the special characteristics of steam injection patterns in shallow and thin extra-heavy oil. The patent "A Method for Plugging and Regulating Oil Reservoirs" proposes a method to determine the type of water drive zone at different locations based on the remaining oil saturation, and to determine the corresponding plugging and regulating system and the amount of system based on the type of water drive zone. This method is for conventional water drive reservoirs and differs from heavy oil steam huff and puff in terms of development patterns and selection of plugging agent types.

[0006] There are currently no precedents, either domestically or internationally, for using directional temporary plugging agents to improve the development of shallow extra-heavy oil reservoirs, and there is a lack of theoretical and practical guidance. Summary of the Invention

[0007] In view of the above problems, the present invention is proposed to provide an improved method for steam huff and puff development of shallow extra-heavy oil reservoirs that overcomes or at least partially solves the above problems.

[0008] According to one aspect of the present invention, a method for improving the steam huff and puff development effect of shallow extra-heavy oil reservoirs is provided, the method comprising:

[0009] Step S1: Optimize the steam injection rate of slug one by injecting the first steam slug into the reservoir;

[0010] Step S2: Based on the bottom-hole temperature measurement curve, determine the location of the high-conductivity channel and calculate the amount of temporary plugging agent required;

[0011] Step S3: Select the type of temporary plugging agent and inject the temporary plugging agent into the reservoir in a directional manner;

[0012] Step S4: Optimize the steam injection rate of slug 2 and inject the second steam slug into the reservoir;

[0013] Step S5: Well shut-in, wait for the temperature field to expand and the temporary plugging agent to become ineffective, then switch to production;

[0014] Step S6: Using daily oil production as the cutoff condition, carry out the cycle production.

[0015] Optionally, step S1, optimizing the steam injection rate of the first steam slug, specifically includes injecting the first steam slug into the reservoir:

[0016] Collect reservoir properties of the target block, establish a numerical simulation model, and optimize the injection rate of the first steam slug using thermal efficiency as the evaluation criterion.

[0017] Optionally, the thermal efficiency is calculated as follows:

[0018]

[0019] Where x, y, and z represent the number of grid cells in the numerical model in the horizontal, vertical, and longitudinal directions, respectively. For the mesh porosity at any location, S wijk S oijk S gijk c represents the water saturation, oil saturation, and gas saturation at any given location. w c o c g c r V represents the specific heat capacity of water, oil, gas, and rock skeleton. ijk For the mesh volume at any location, T ijk Let T be the grid temperature at any location, T0 be the original reservoir temperature, and T be the temperature at any given location. s Where L is the steam temperature, a is the steam dryness fraction, and L is the steam temperature. vV is the latent heat of vapor. w This is the equivalent volume of steam and water injected.

[0020] Optionally, step S2, determining the location of the high-conductivity channel and calculating the required amount of temporary plugging agent based on the bottom-hole temperature measurement curve, specifically includes:

[0021] Based on the bottom hole temperature curve after steam injection in step S1, determine the location of the high-conductivity channel and calculate the amount of temporary plugging agent required at different locations.

[0022] Optionally, determining the location of the high-flow-guiding channel specifically includes:

[0023] Temperature curves have inflection points between their peaks and troughs. Several points near these inflection points are used to plot curve segment M. n N n The corresponding horizontal coordinate is [i n i n The regression fits the line segment, and the regression function is as follows:

[0024] f n (i) = ax 3 +bx 2 +cx+d (2)

[0025] Where a, b, c, and d are dimensionless coefficients, obtained through relevant data fitting software;

[0026] Find the curve segment M1N1 in [i n i n The curvature K on '] n The calculation formula is as follows:

[0027]

[0028] When determining the maximum curvature value on curve segment M1N1, the corresponding x-coordinate i nmax ;

[0029] The solution can be obtained by using the first derivative of the function or a mathematical optimization algorithm;

[0030] If n horizontal coordinates are obtained on the temperature curve, then there are n+1 segments in the steam injection process. Among them, the region with the temperature peak has high flow channels, the number of which is m, where m is equal to n / 2 or (n+1) / 2.

[0031] Optionally, calculating the required amount of temporary plugging agent at different locations specifically includes:

[0032] Integrate the temperature curve segment where the high flow channel is located;

[0033] Each temperature curve segment contains multiple temperature measurement points. This is equivalent to differentiating the temperature curve and summing the measurement data to obtain the superimposed temperature of that segment. The calculation formula is as follows:

[0034]

[0035] Among them, T j T0 represents the temperature at the measurement point, and T0 represents the original temperature of the reservoir.

[0036] Optionally, the integration of the temperature curve segments where the high-conductivity channel is located further includes:

[0037] Regression fitting was performed on the curve segments where the high-flow channel is located, denoted as function F. m (i), and then the regression formula is integraled using mathematical methods to obtain the superposition temperature of this segment. The calculation formula is as follows:

[0038]

[0039] Based on the integration results, the percentage of temperature superposition in each segment is calculated using the following formula:

[0040]

[0041] Based on the steam injection rate of slug 1, the temporary plugging agent requirement for each slug is calculated using the following formula:

[0042] V i =x i β max V w (7)

[0043] Where, β max For the optimal temporary congestion coefficient, V w This refers to the steam injection rate of the slug.

[0044] Optionally, the optimal temporary congestion coefficient is obtained through indoor physical simulation, specifically including:

[0045] Two-dimensional visualization experiments were conducted using oil samples from the target reservoir. After injecting a vapor slug, different amounts of temporary plugging agent were injected. The ratio of the amount of temporary plugging agent to the volume of the first vapor slug was the temporary plugging coefficient. The proportion of the second vapor slug's swept volume expansion in different experimental schemes was statistically analyzed, and the optimal temporary plugging coefficient was selected.

[0046] Optionally, the method for selecting the optimal temporary blocking coefficient is as follows:

[0047] The vapor sweep volume expansion ratio under different temporary blocking coefficients was collected, and the regression fitting formula is as follows:

[0048] f(β)=eln(β)+g (8)

[0049] Where e and g are dimensionless coefficients, obtained through relevant data fitting software;

[0050] Find the curvature K on the curve β The calculation formula is as follows:

[0051]

[0052] When determining the maximum curvature value on the curve, the corresponding x-coordinate β max , which is the optimal temporary blocking coefficient;

[0053] The solution is obtained by using the first derivative of the function or a mathematical optimization algorithm.

[0054] Optionally, step S3, preferably involving the directional injection of a temporary plugging agent into the reservoir, specifically includes:

[0055] Based on the crude oil viscosity and the high-conductivity channel size calculated in step 2, the type of temporary plugging agent is selected. The required amount of plugging agent for the high-conductivity channel is calculated according to step S2. The temporary plugging agent is injected directionally into the n-1 section using a packer, with the injection sequence from the bottom of the well to the wellhead.

[0056] Optionally, the screening method for the temporary plugging agent includes:

[0057] A numerical model of shallow extra-heavy oil at a certain viscosity was established. By adjusting the reservoir heterogeneity, high-conductivity channels of different scales were constructed. Inorganic temporary plugging agent, organic temporary plugging agent, and inorganic temporary plugging agent + organic temporary plugging agent were injected respectively. The plugging effect and input cost were compared to obtain the optimal temporary plugging agent at the corresponding scale.

[0058] By varying the viscosity of crude oil and repeating the relevant calculations, the optimal temporary plugging agent under different viscosities and high-conductivity channel scales was obtained.

[0059] Optionally, step S4, optimizing the steam injection rate of slug two, specifically includes: optimizing the steam injection rate of slug two using numerical simulation methods, and selecting cycle production as the evaluation criterion.

[0060] Optionally, step S5, shutting down the well and waiting for the temperature field to expand and the temporary plugging agent to fail before resuming production, specifically includes:

[0061] The well is shut in and left to simmer for 2 to 5 days to allow for mass and heat transfer between the steam and the reservoir, and for the temporary plugging agent to become ineffective. Then the well is opened for production.

[0062] Optionally, step S6, which uses daily oil production as the cutoff condition for cycle production, specifically includes: using daily oil production as the production cutoff condition, selecting 1 to 2 t / d, then injecting steam to proceed with the next cycle of development.

[0063] This invention provides a method for improving the development effect of steam huff and puff in shallow extra-heavy oil reservoirs. The improvement method includes: step S1, optimizing the steam injection rate of slug one and injecting the first steam slug into the reservoir; step S2, determining the location of the high conductivity channel and calculating the required amount of temporary plugging agent based on the bottom hole temperature measurement curve; step S3, selecting the type of temporary plugging agent and injecting it directionally into the reservoir; step S4, optimizing the steam injection rate of slug two and injecting the second steam slug into the reservoir; step S5, shutting down the well and waiting for the temperature field to expand and the temporary plugging agent to become ineffective before switching to production; step S6, using daily oil production as the cutoff condition for rotating production. This method effectively improves the recovery rate of shallow extra-heavy oil reservoirs and forms a method for improving the development effect of shallow extra-heavy oil reservoirs through directional temporary plugging.

[0064] The above description is merely an overview of the technical solution of the present invention. In order to better understand the technical means of the present invention and to implement it in accordance with the contents of the specification, and in order to make the above and other objects, features and advantages of the present invention more apparent and understandable, specific embodiments of the present invention are described below. Attached Figure Description

[0065] To more clearly illustrate the technical solutions of the embodiments of the present invention, the drawings used in the following description of the embodiments will be briefly introduced. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0066] Figure 1 A flowchart illustrating a method for improving the development effect of steam huff and puff in shallow extra-heavy oil reservoirs, provided in an embodiment of the present invention;

[0067] Figure 2 This is a schematic diagram illustrating the changes in the high conductivity channel during steam huff and puff in a shallow extra-heavy oil reservoir, as provided in an embodiment of the present invention.

[0068] Figure 3 This is a schematic diagram of conventional plugging agents used to block gas channeling in conventional heavy oil reservoirs, provided in an embodiment of the present invention.

[0069] Figure 4 This is a schematic diagram of a temporary plugging agent used to seal a high-conductivity channel in a shallow extra-heavy oil reservoir, provided in an embodiment of the present invention.

[0070] Figure 5 This is a schematic diagram of the steam distribution in the shallow extra-heavy oil reservoir steam huff and puff method of the present invention, specifically for both single-stage and slug-type steam injection.

[0071] Figure 6 This is the screening criterion for the temporary plugging agent in one example of the present invention;

[0072] Figure 7 Optimization curve for steam injection rate of the mid-slug in Example 1;

[0073] Figure 8 The bottom hole temperature curve at the end of steam injection in the intermediate section of Example 1;

[0074] Figure 9 For curve segment M in Example 1 n N n and regression fitting function;

[0075] Figure 10 This is the regression fitting function for the temporary congestion coefficient in Example 1;

[0076] Figure 11 Optimization curve for steam injection rate of plug 2 in Example 1;

[0077] Figure 12 The curves show the recovery rates of conventional steam injection and directional temporary plugging steam injection in Example 1. Detailed Implementation

[0078] Exemplary embodiments of the present disclosure will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure may be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art.

[0079] The terms "comprising" and "having," and any variations thereof, in the specification, embodiments, claims, and drawings of this invention are intended to cover non-exclusive inclusion, such as including a series of steps or units.

[0080] The technical solution of the present invention will be further described in detail below with reference to the accompanying drawings and embodiments.

[0081] Based on the reservoir properties of the target block, a numerical model was established to optimize the injection rate of the first steam slug. According to the bottom hole temperature curve after steam injection, the location of the high conductivity channel was determined, the temporary plugging agent requirement was calculated, and the temporary plugging agent was injected directionally using a packer. The injection rate of the second steam slug was optimized using numerical simulation methods to realize the transformation from a long and narrow channel to a short and wide channel. The well was then shut down to wait for the temperature to expand and the temporary plugging agent to become ineffective before production and development were initiated. Ultimately, the oil drainage volume was expanded, the near-wellbore surface utilization was improved, and the steam huff and puff development effect of shallow extra-heavy oil reservoirs was improved.

[0082] The features and performance of the present invention will be further described in detail below with reference to specific embodiments.

[0083] This invention addresses the challenges of steam injection development in shallow extra-heavy oil reservoirs, where shallow burial depth, thin oil layers, and high crude oil viscosity lead to low formation temperatures, impeded flow of crude oil beneath the formation, rapid heat dissipation during steam injection, and easy steam fingering. It innovatively proposes a concept to utilize temporary plugging agents to redirect steam during thermal recovery steam injection, while simultaneously increasing the number of high-conductivity channels. Combined with an algorithm for calculating steam fingering, the depth of steam fingering and crossflow can be controlled, ensuring concentrated heating of the near-wellbore crude oil and improving the thermal utilization rate of injected steam. Furthermore, it innovatively establishes a high-conductivity channel identification method to guide the selection of temporary plugging agent injection locations and the optimization of process technologies. A corresponding method for calculating temporary plugging agent demand has been developed to guide the optimization of temporary plugging agent dosage in actual production. Finally, a screening and selection standard for temporary plugging agents has been established to guide the selection of temporary plugging agent types. Its core idea is as follows: Figure 4 , Figure 5 As shown.

[0084] The specific method involved in this invention includes: optimizing the amount of pre-steam slug by calculating the thermal efficiency under different steam injection rates; after pre-injecting steam, identifying the heat concentration area and determining the location of the high-conductivity channel by measuring the bottom hole temperature curve, normalizing the temperature distribution of the high-conductivity channel, and calculating the temporary plugging agent requirement for high-conductivity channels at different locations; selecting the type of temporary plugging agent (inorganic temporary plugging agent, organic temporary plugging agent, inorganic temporary plugging agent + organic temporary plugging agent) according to the crude oil viscosity and the size of the high-conductivity channel, and using a packer to achieve directional injection of high-strength temporary plugging agent; optimizing the subsequent steam injection rate using numerical simulation methods to achieve the transition from a long and narrow channel to a short and wide channel; after steam injection, shutting down the well and waiting for the steam to transfer mass and heat to the reservoir and for the temporary plugging agent to fail before switching to production.

[0085] like Figure 1 As shown, the specific steps of the present invention include:

[0086] Step 1: Optimize the steam injection rate of slug 1 by injecting the first steam slug into the reservoir;

[0087] Step 2: Based on the bottom-hole temperature measurement curve, determine the location of the high-conductivity channel and calculate the required amount of temporary plugging agent;

[0088] Step 3: Select the appropriate type of temporary plugging agent and inject it into the reservoir in a directional manner;

[0089] Step 4: Optimize the steam injection rate of slug 2 and inject the second steam slug into the reservoir;

[0090] Step 5: Boil in a closed well and wait for the temperature field to expand and the temporary plugging agent to become ineffective before resuming production;

[0091] Step 6: Use daily oil production as the cutoff condition to carry out the cycle production.

[0092] The objective of this invention can also be achieved through the following technical measures:

[0093] In step 1, reservoir properties of the target block are collected, a numerical simulation model is established, and the injection rate of the first steam slug is optimized using thermal efficiency as the evaluation criterion.

[0094] The method for calculating thermal efficiency is as follows:

[0095]

[0096] Where x, y, and z represent the number of grid cells in the numerical model in the horizontal, vertical, and longitudinal directions, respectively. For the mesh porosity at any location, S wijk S oijk S gijk c represents the water saturation, oil saturation, and gas saturation at any given location. w c o c g c r V represents the specific heat capacity of water, oil, gas, and rock skeleton. ijk For the mesh volume at any location, T ijk Let T be the grid temperature at any location, T0 be the original reservoir temperature, and T be the temperature at any given location. s Where L is the steam temperature, a is the steam dryness fraction, and L is the steam temperature. v V is the latent heat of vapor. w This is the equivalent volume of steam and water injected.

[0097] The parameters in the calculation method are all collected in the numerical model.

[0098] In step 2, the location of the high-conductivity channel is determined based on the bottom hole temperature curve after steam injection in step 1, and the amount of temporary plugging agent required at different locations is calculated.

[0099] like Figure 2 The diagram shows the changes in high conductivity channels during steam huff and puff in shallow extra-heavy oil reservoirs. Figure 3 The diagram shows a conventional plugging agent used to seal gas channeling pathways in a conventional heavy oil reservoir.

[0100] The location of the high-flow channel can be determined using the following methods.

[0101] Temperature curves have inflection points between their peaks and troughs. Several points near these inflection points are used to plot curve segment M. n N n The corresponding horizontal coordinate is [i n i n The regression fits the line segment, and the regression function is as follows:

[0102] f n (i) = ax 3+bx 2 +cx+d (2)

[0103] Among them, a, b, c, and d are dimensionless coefficients, which can be obtained through relevant data fitting software.

[0104] Find the curve segment M1N1 in [i n i n The curvature K on '] n The calculation formula is as follows:

[0105]

[0106] When determining the maximum curvature value on curve segment M1N1, the corresponding x-coordinate i nmax The solution is obtained by using the first derivative of the function or a mathematical optimization algorithm.

[0107] Using the same method, n horizontal coordinates are obtained on the temperature curve. Then there are n+1 segments in the steam injection process, where the region with the temperature peak has high flow channels, the number of which is m, where m is equal to n / 2 or (n+1) / 2.

[0108] The demand for temporary plugging agent can be calculated using the following methods.

[0109] There are two methods for integrating the temperature curve segments where the high conductivity channel is located.

[0110] Method 1: Each temperature curve segment contains multiple temperature measurement points. This is equivalent to differentiating the temperature curve and summing the temperature measurement data to obtain the superimposed temperature of that segment. The calculation formula is as follows:

[0111]

[0112] Among them, T j T0 represents the temperature at the measurement point, and T0 represents the original temperature of the reservoir.

[0113] Method 2: Perform regression fitting on the curve segments where the high-flow channel is located, denoted as function F. m (i), and then the regression formula is integraled using mathematical methods to obtain the superposition temperature of this segment. The calculation formula is as follows:

[0114]

[0115] Based on the integration results, the percentage of temperature superposition in each segment is calculated using the following formula:

[0116]

[0117] Based on the steam injection rate of slug 1, the temporary plugging agent requirement for each slug is calculated using the following formula:

[0118] V i =x i β max V w (7)

[0119] Where, β max For the optimal temporary congestion coefficient, V w This refers to the steam injection rate of the slug.

[0120] The optimal temporary blocking coefficient β max This can be obtained through indoor physical simulation:

[0121] Two-dimensional visualization experiments were conducted using oil samples from the target reservoir. After injecting a vapor slug, different amounts of temporary plugging agent were injected. The ratio of the amount of temporary plugging agent to the volume of the first vapor slug was the temporary plugging coefficient. The proportion of the second vapor slug's swept volume expansion in different experimental schemes was statistically analyzed, and the optimal temporary plugging coefficient was selected.

[0122] The optimal method for selecting the temporary plugging factor is to collect the vapor sweep volume expansion ratio under different temporary plugging factors, and the regression fitting formula is as follows:

[0123] f(β)=eln(β)+g (8)

[0124] Where e and g are dimensionless coefficients, which can be obtained through relevant data fitting software.

[0125] Find the curvature K on the curve β The calculation formula is as follows:

[0126]

[0127] When determining the maximum curvature value on the curve, the corresponding x-coordinate β max This is the optimal temporary blocking coefficient; it can be obtained by using the first derivative of the function or a mathematical optimization algorithm.

[0128] In step 3, based on the crude oil viscosity and the high-conductivity channel size calculated in step 2, the type of temporary plugging agent is selected. Based on the high-conductivity channel plugging agent demand calculated in step 2, the temporary plugging agent is injected directionally into section n-1 using a packer, with the injection sequence from the bottom of the well to the wellhead.

[0129] Temporary plugging agents can be screened using the following methods.

[0130] A numerical model of shallow extra-heavy oil at a certain viscosity was established. By adjusting the reservoir heterogeneity, high-conductivity channels of different scales were constructed, and inorganic, organic, and a combination of inorganic and organic plugging agents were injected respectively. The plugging effects and input costs were compared to determine the optimal plugging agent at this scale. The crude oil viscosity was varied, and related calculations were repeated to obtain the optimal plugging agents for different viscosities and high-conductivity channel scales. Figure 6 As shown. The preferred criteria for the temporary plugging agent are as follows:

[0131] For reservoirs with high-conductivity channels less than 50m in size and crude oil viscosity less than 20000mPa·s, inorganic or organic temporary plugging agents should be selected for temporary plugging; for reservoirs with high-conductivity channels less than 50m in size and crude oil viscosity greater than 20000mPa·s, organic temporary plugging agents should be selected; for reservoirs with high-conductivity channels greater than 50m in size and crude oil viscosity less than 20000mPa·s, inorganic temporary plugging agents should be selected for temporary plugging; for reservoirs with high-conductivity channels greater than 50m in size and crude oil viscosity greater than 20000mPa·s, a mixture of inorganic and organic temporary plugging agents in a volume ratio of 5:5 should be selected.

[0132] In step 4, the steam injection rate of slug 2 is optimized using numerical simulation, and the cycle oil production rate is selected as the evaluation criterion.

[0133] In step 5, the well is shut in and left to simmer, waiting for mass and heat transfer between the steam and the reservoir, as well as for the temporary plugging agent to become ineffective. The simmering time is generally 2 to 5 days, after which the well is opened for production.

[0134] In step 6, the daily oil production is used as the production cutoff condition, generally selected as 1-2 t / d.

[0135] Then steam is injected to begin the next development cycle.

[0136] Example 1

[0137] This invention takes shallow, extra-heavy oil reservoir A as an example to carry out targeted temporary plugging to improve steam huff and puff development, including the following steps:

[0138] Step 1: Reservoir A has a burial depth of 346–357 m and an effective thickness of 3.5 m. The first steam slug injection volume is optimized using numerical simulation to be 600 t. Figure 7 As shown;

[0139] Step 2: The horizontal well is 200m long, and the temperature curve is as follows. Figure 8 As shown, the curve segment is selected for regression analysis to obtain... Figure 9 The regression formula was calculated to show that the high-conductivity channels are distributed in the range of 0–46 m. ​​Since there is only one high-conductivity channel, the superimposed temperature ratio is 1. The temporary blockage coefficient and the proportion of swept volume expansion were obtained through indoor experiments. Figure 10As shown, the calculated optimal temporary plugging coefficient is approximately 0.15, which indicates that the required amount of temporary plugging agent is 90 cubic meters.

[0140] Step 3: The length of the high-conductivity channel is less than 50m, and the crude oil viscosity of reservoir A is 50,000 to 70,000 mPa·s. Therefore, an organic temporary plugging agent is selected.

[0141] Step 4: Optimize the second steam slug injection rate to 1200t using numerical simulation methods, such as... Figure 11 As shown;

[0142] Step 5: After the well has been sealed for 3 days, the temporary plugging agent will become ineffective, and the well can be opened for production.

[0143] Step 6: After oil production decreases to 1 t / d, steam is reinjected to begin cycle development. The recovery rate within the well control area is projected to be 27.8%. Figure 12 As shown.

[0144] Beneficial effects: Through slug injection, the steam fingering phenomenon is reduced and mainly concentrated in the near-wellbore area. Directional injection of temporary plugging agent can effectively increase the swept volume of injected steam, improve thermal efficiency, and improve the development effect of steam huff and puff. This invention can effectively improve the recovery rate of shallow extra-heavy oil reservoirs and form a method for improving the development effect of shallow extra-heavy oil reservoirs through directional temporary plugging.

[0145] The above specific embodiments further illustrate the purpose, technical solution, and beneficial effects of the present invention. It should be understood that the above are merely specific embodiments of the present invention and are not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A method for improving the effect of steam stimulation development of a shallow super heavy oil reservoir, characterized in that, The improvement method comprises: Step S1, optimizing steam injection volume of the first steam slug, and injecting the first steam slug into the reservoir; Step S2, judging the position of the high-conductivity channel according to the bottom-hole temperature curve, and calculating the required amount of the temporary plugging agent; The position of the high-conductivity channel is judged according to the bottom-hole temperature curve after the steam injection in step S1, and the required amount of the temporary plugging agent at different positions is calculated; The position of the high-conductivity channel specifically comprises: There is a temperature inflection point between the peak and the trough of the temperature curve, take several points near the inflection point of the curve, draw the curve segment M n N n , the corresponding horizontal coordinate is marked as [i n , i n ’ ], the regression fitting line segment, the regression function is as follows: （2） Wherein, a, b, c, d are dimensionless coefficients, which are obtained by related data fitting software; Finding the curve segment M n N n In [i n , i n ’ ] curvature K n , the calculation formula is as follows: （3） Finding the maximum curvature value on a curve segment M n N n and the corresponding abscissa i nmax ; The solving method adopts a function first derivative method or a mathematical optimization algorithm for solving; n coordinate points are obtained on the temperature curve, and there are n+1 segments in the steam injection process, wherein the region with the temperature peak value has the high-conductivity channel, and the number of the high-conductivity channel is m, m is equal to n / 2 or (n+1) / 2; Step S3, selecting the type of the temporary plugging agent, and injecting the temporary plugging agent into the reservoir in a directional manner; Step S4, optimizing steam injection volume of the second steam slug, and injecting the second steam slug into the reservoir; Step S5, huff and puff, and after waiting for the temperature field to expand and the temporary plugging agent to fail, switching to production; Step S6, performing cyclic production with daily oil production as a cutoff condition.

2. The method for improving the effect of steam stimulation development of a shallow super-heavy oil reservoir according to claim 1, characterized in that, The step S1, optimizing steam injection volume of the first steam slug, and injecting the first steam slug into the reservoir specifically comprises: Reservoir properties of a target block are collected, a numerical simulation model is established, and the injection volume of the first steam slug is optimized with thermal efficiency as an evaluation standard.

3. The method for improving the effect of steam stimulation development of a shallow super-heavy oil reservoir according to claim 2, characterized in that, The calculation method of the thermal efficiency is: （1） wherein x, y, z are the number of grid in horizontal, vertical, and longitudinal direction of the numerical model, S is the porosity of any position grid, wijk S is the porosity of any position grid, oijk S is the porosity of any position grid, gijk S is the water saturation, oil saturation, gas saturation of any position grid, c w S is the water saturation, oil saturation, gas saturation of any position grid, c o S is the water saturation, oil saturation, gas saturation of any position grid, c g S is the water saturation, oil saturation, gas saturation of any position grid, c r C is the specific heat capacity of water, oil, gas, rock matrix, V ijk V is the grid volume of any position, ijk T is the grid temperature of any position, T0 is the original reservoir temperature, T s T is the steam temperature, a is the steam quality, L v L is the latent heat of steam, V w V is the water equivalent volume of injected steam.

4. The method for improving the effect of steam stimulation development of a shallow super-heavy oil reservoir according to claim 1, characterized in that, The calculation of the required amount of the temporary plugging agent at different positions specifically comprises: The temperature curve segments where the high-conductivity channel is located are summed up respectively; （4） No. From the first temperature measurement point to the... The cumulative sum of all temperature measurement points; where T j is the temperature of the measuring point, and T0 is the initial temperature of the reservoir. According to the summation result, the proportion of the superimposed temperature of each segment is calculated, and the calculation formula is as follows: （6） Combined with the steam injection volume of the first steam slug, the required amount of the temporary plugging agent of each segment is calculated, and the calculation formula is as follows: （7） where β max is the optimum temporary plugging coefficient, V w is the slug-steam injection volume; The region with the temperature peak value has the high-conductivity channel, and the number of the high-conductivity channel is m, m is equal to n / 2 or (n+1) / 2.

5. The method for improving the effect of steam stimulation development of a shallow super-heavy oil reservoir according to claim 1, characterized in that, The calculation of the required amount of the temporary plugging agent at different positions comprises: The temperature curve segments where the high-conductivity channel is located are integrated respectively; The curve segment where the high-conductivity channel is located is fitted by regression, denoted as function F n (i), and then the regression formula is integrated to obtain the superposition temperature of the segment, and the calculation formula is as follows: （5） According to the integration result, the proportion of the superimposed temperature of each segment is calculated, and the calculation formula is as follows: （6） Combined with the steam injection volume of the first steam slug, the required amount of the temporary plugging agent of each segment is calculated, and the calculation formula is as follows: （7） where β max is the optimum temporary plugging coefficient, V w is the slug-steam injection volume.

6. The method for improving the effect of steam stimulation development of a shallow super-heavy oil reservoir according to claim 4, characterized in that, The best temporary plugging coefficient is obtained through indoor physical simulation, and specifically comprises: An oil sample of a target reservoir is selected to carry out a two-dimensional visual experiment, different amounts of temporary plugging agents are injected after a steam slug is injected, the ratio of the temporary plugging agent volume to the volume of the first steam slug is the temporary plugging coefficient, the expansion ratio of the second steam slug swept volume in different experimental schemes is counted, and the best temporary plugging coefficient is selected.

7. The method for improving the effect of steam stimulation development of a shallow super-heavy oil reservoir according to claim 4, characterized in that, The selection method of the best temporary plugging coefficient is: The expansion ratios of the steam swept volume under different temporary plugging coefficients are collected, and the regression fitting formula is as follows: （8） Wherein, e, g are dimensionless coefficients, which are obtained by related data fitting software; Finding the curvature K on a curve β The calculation formula is as follows: （9） The corresponding abscissa β when the maximum curvature value on the curve is sought max is the optimum temporary plugging coefficient; The solving method adopts a function first derivative method or a mathematical optimization algorithm for solving.

8. The method for improving the effect of steam stimulation development of a shallow super-heavy oil reservoir according to claim 1, characterized in that, The step S3, selecting the type of the temporary plugging agent, and injecting the temporary plugging agent into the reservoir in a directional manner specifically comprises: According to the crude oil viscosity and the high flow channel size calculated in step 2, the type of temporary plugging agent is selected, the demand of the high flow channel plugging agent is calculated according to step S2, the temporary plugging agent is injected into n-1 segments by using packers, and the injection sequence is from the bottom to the top of the well.

9. The method for improving the effect of steam stimulation development of a shallow super-heavy oil reservoir according to claim 8, characterized in that, The screening method of the temporary plugging agent comprises: A numerical model of shallow layer super heavy oil under a certain viscosity is established, high flow channels of different scales are constructed by adjusting the reservoir heterogeneity, inorganic temporary plugging agent, organic temporary plugging agent and inorganic temporary plugging agent+organic temporary plugging agent are injected respectively, and the plugging effect and the input cost are compared to obtain the best temporary plugging agent under the corresponding scale; The related calculation is repeated by changing the crude oil viscosity to obtain the best temporary plugging agent under different high flow channel scales and different viscosities.

10. The method for improving the effect of steam stimulation development of a shallow super-heavy oil reservoir according to claim 1, characterized in that, The step S4, which optimizes the steam injection amount of the second slug, specifically comprises: the steam injection amount of the second slug is calculated by using a numerical simulation method, and the evaluation standard is the cycle oil production.

11. The method for improving the effect of steam stimulation development of a shallow super-heavy oil reservoir according to claim 1, characterized in that, The step S5, which is soaking, specifically comprises: The well is shut down for soaking, waiting for the mass transfer and heat transfer between the steam and the reservoir and the failure of the temporary plugging agent, the soaking time is 2-5 days, and then the well is opened for production.

12. The method for improving the effect of steam stimulation development of a shallow super-heavy oil reservoir according to claim 1, characterized in that, The step S6, which is production with a cycle, specifically comprises: the daily oil production is selected as the production cutoff condition, the production is 1-2t / d, then steam is injected, and the next cycle development is carried out. The step S6, which is production with a cycle, specifically comprises: the daily oil production is selected as the production cutoff condition, the production is 1-2t / d, then steam is injected, and the next cycle development is carried out.

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