Control strategy and sand prevention process optimization method for cold production of heavy oil in unconsolidated sandstone reservoir

Abstract

The present application belongs to the technical field of oil and gas exploitation engineering, and particularly relates to a loose sandstone reservoir heavy oil cold production sand control strategy and sand control process optimization method, aiming to solve the problem of low efficiency of heavy oil cold production caused by the lack of comprehensive and scientific and reasonable sand control strategy optimization method and sand control process optimization method for heavy oil cold production working conditions in the prior art. The method comprises: obtaining basic parameters during heavy oil cold production of loose sandstone reservoir as input parameters; calculating GPSC characteristic indexes based on the input parameters through a pre-constructed GPSC characteristic index calculation method; obtaining a sand control strategy based on the mapping relationship between the GPSC characteristic indexes and the preset sand control strategy and combining the GPSC characteristic indexes; and obtaining a corresponding sand control process according to the sand control strategy and combining gravel parameters. The present application improves the efficiency of heavy oil cold production.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas extraction engineering technology, specifically relating to a strategy for controlling sand production during cold oil extraction in loose sandstone reservoirs and a method for optimizing sand control technology. Background Technology

[0002] Heavy oil and extra-heavy oil in loose sandstone reservoirs are widely distributed globally and in my country, holding significant positions in both reserves and production. Generally, heavy oil, due to its high viscosity and difficulty in flow, is typically developed using thermal recovery methods (i.e., injecting heat media such as steam into the formation to raise the temperature of the crude oil in the reservoir, thereby reducing its viscosity and making it easier to flow for normal extraction). Simultaneously, loose sandstone reservoirs are prone to sand production, requiring sand control measures. For sand control in thermal recovery of heavy oil in loose sandstone reservoirs, the primary consideration is the impact of the high temperature at the bottom of the well (far exceeding the original reservoir temperature), while the crude oil viscosity is not very high near the sand control medium at the bottom of the well due to the viscosity-reducing effect of thermal recovery. Therefore, sand control in thermal recovery wells of heavy oil in loose sandstone primarily addresses the high-temperature issue.

[0003] Compared to thermal recovery of heavy oil, cold recovery of heavy oil refers to the direct extraction of heavy oil without using thermal energy to heat the oil reservoir. It is a relatively low-cost and simple oil production technology. However, in the cold recovery process of heavy oil from loose sandstone reservoirs, severe sand production problems also exist, damaging downhole equipment, increasing maintenance costs, and seriously affecting oil production efficiency. Cold recovery of heavy oil from loose sandstone reservoirs also requires sand control measures. Currently, there are various commonly used sand control strategies and sand control technologies. Widely used sand control technologies include several major categories such as mechanical, chemical, and composite methods, and the applicability and effectiveness of different sand control methods vary significantly. Therefore, the evaluation and optimization of sand control technologies for cold recovery of heavy oil from loose sandstone reservoirs is a very important task and is crucial for improving the effectiveness of cold recovery of heavy oil from loose sandstone reservoirs.

[0004] The following key issues remain regarding the optimal sand control strategy and sand prevention technology for cold production of heavy oil in loose sandstone reservoirs:

[0005] 1) Compared to thermal recovery of heavy oil, cold recovery wells for heavy oil are characterized by low temperature and high viscosity near the bottom. Currently, there is a lack of comprehensive and scientifically sound methods for optimizing sand production control strategies. In recent years, sand control technologies for loose sandstone heavy oil wells have mainly focused on thermal recovery conditions, while research on sand control technologies for cold recovery of heavy oil is limited. A comprehensive index system and methodology for optimizing sand production control strategies has not yet been developed, taking into account factors such as reservoir cementation strength, sand production characteristics, formation sand particle size, and production capacity.

[0006] 2) Current methods for optimizing sand control processes under conventional conditions and heavy oil thermal recovery are ill-suited to the low temperatures and high viscosity of heavy oil in cold recovery. There is a lack of specific methods for optimizing sand control processes under these conditions. Currently, relatively mature methods for optimizing sand control processes have been developed for both conventional and heavy oil thermal recovery conditions. Under heavy oil cold recovery conditions, reservoir pressure and temperature are relatively low, crude oil viscosity is high and fluidity is poor, and sand production is complex and varied. Common sand control methods such as mechanical screens, chemical sand control, and composite sand control exhibit significantly different effects in heavy oil cold recovery due to differences in their process principles. However, there is no unified method for optimizing these methods, making it difficult to accurately select the sand control process and thus failing to achieve the expected sand control and production results in practical applications.

[0007] Based on this, the present invention proposes a strategy for controlling sand production during cold oil recovery in loose sandstone reservoirs and an optimal method for sand control technology. Summary of the Invention

[0008] To address the aforementioned problems in the prior art, namely the lack of a comprehensive and scientifically sound method for optimizing sand production control strategies and sand control processes for heavy oil cold production conditions, which leads to low efficiency in heavy oil cold production, this invention proposes, in a first aspect, a sand production control strategy and sand control process optimization method for heavy oil cold production in loose sandstone reservoirs. This method includes:

[0009] S100, obtain the basic parameters for cold production of heavy oil in loose sandstone reservoirs as input parameters; the input parameters include reservoir porosity, permeability, rock strength, reservoir thickness, particle size distribution, clay content, reference production, fluid properties, edge and bottom water distance, and wellhead sand production capacity.

[0010] S200, based on the input parameters, calculate the GPSC characteristic index using a pre-constructed GPSC characteristic index calculation method; the GPSC characteristic index includes the formation sand coarseness-fineness boundary index, reservoir sand production risk index, reservoir sand production severity index, reservoir sand retention difficulty index, wellbore sand carrying condition index, and formation sand production wormhole morphology index.

[0011] S300, Based on the mapping relationship between the GPSC characteristic indicators and the preset sand discharge control strategy, and in combination with the GPSC characteristic indicators, the sand discharge control strategy is obtained.

[0012] S400, based on the sand production control strategy and combined with the gravel parameters, obtain the corresponding sand control technology; the gravel parameters include the median formation sand particle size, uniformity coefficient, sand production severity index, and clay content.

[0013] In some preferred embodiments, the formation sand coarseness / fineness boundary index is calculated as follows:

[0014] First, obtain the number of particles in the i-th group of formation sand:

[0015]

[0016] Where M represents the total mass of the formation sand sample, ρ s d represents the density of the formation sand material. si w represents the grain size of the i-th stratum sand. i N represents the mass fraction of the sand grain size in the i-th formation. i This represents the number of particles in the i-th group of formation sand.

[0017] Based on the relationship between the number of particles and the particle size of formation sand, a double logarithmic relationship diagram was drawn.

[0018] If the two line segments in the double logarithmic relationship graph do not intersect, then J cx =0, otherwise, fit the two line segments into a joint line segment, and read the transverse particle size d corresponding to the intersection point of the two line segments. cx Calculate J cx :

[0019]

[0020] Among them, J cx Indicates the boundary index between coarse and fine sand in formations, d cx The grain size representing the dividing line between coarse and fine components of formation sand, d s50 J represents the median grain size of the formation sand, α represents the empirical coefficient, and J represents the median grain size of the formation sand. cx Indicator of stratigraphic sand coarseness / fineness boundary index

[0021] In some preferred embodiments, the reservoir sand production risk index is calculated as follows:

[0022]

[0023]

[0024] S zh =S t +0.15×S c +S0

[0025]

[0026]

[0027]

[0028] Among them, J fx K represents the reservoir sand production risk index. S KT K E K B These are dimensionless combined strength, acoustic transit time, combined modulus, and sand production index, representing individual sand production risk indicators. t S represents the uniaxial tensile strength of reservoir rock. c S represents the uniaxial compressive strength of the reservoir rock, and S0 represents the cohesive strength of the reservoir rock. zh Indicates the reservoir composite strength, ΔT s E represents the reservoir P-wave transit time. s B represents the combined modulus obtained from conventional sand production prediction. s S represents the sand production index obtained from conventional sand production prediction. zh1 Indicates the severe combined strength limit of sand production, △T s1 E represents the acoustic time difference limit corresponding to severe sand production. s1 B represents the limit of the combined modulus corresponding to severe sand production. s1 This indicates the sand production index limit corresponding to severe sand production.

[0029] In some preferred embodiments, the reservoir sand production severity index is determined by the following method:

[0030]

[0031] Among them, J yz Indices representing the severity of sand production in reservoirs, ΔP and ΔP'. c P r These represent the production pressure differential, the critical production pressure differential for sand production, and the formation static pressure, respectively.

[0032] In some preferred embodiments, the reservoir sand-control difficulty index is calculated as follows:

[0033] J ds =w dc ·X dc +w nz ·X nz +w xs ·X xs +w UV ·X UV

[0034]

[0035] d c =0.333d 50 +0.387d 70 +0.510d 90

[0036]

[0037]

[0038]

[0039] Among them, J ds The index representing the difficulty of reservoir sand control, d c Characteristic grain size R that represents the coarseness of formation sand VCL0 R represents the characteristic clay content of the calibration. f0 Indicates the specified fines content, C jy0 C represents the characteristic uniformity coefficient of the calibration. fx0 u represents the calibrated characteristic sorting coefficient. o0 This indicates the calibrated viscosity of crude oil at the bottom of a heavy oil cold-production well, v. f0 X represents the near-wellbore pore velocity of the calibrated characteristic reservoir. dc X nz X xs X UV These are four individual indices that characterize the sand grain size, clay and fine content, uniformity and sorting coefficient, and crude oil viscosity index, all of which affect the sand-blocking effect. dc w nz w xs w UV X dc X nz X xs X UV The weight, d 50 d 70 d 90 These represent the particle sizes corresponding to a sample when the cumulative particle size distribution percentage reaches 50%, 70%, and 90%, respectively.

[0040] In some preferred embodiments, the wellbore sand-carrying condition index is calculated as follows:

[0041]

[0042]

[0043]

[0044] d sw =min{d s0 d s1}

[0045] d s1 =W f ×0.8

[0046]

[0047] Among them, J xsRepresents the wellbore sand carrying condition index, A f ρ is the cross-sectional area of ​​the oil pipe. f ρ represents the density of the fluid in the wellbore. s The density of the formation sand material is represented by Q, the oil well production is represented by g, and the mass is represented by v. f C represents the fluid velocity in the wellbore. D Let d be the settlement drag coefficient. s1 The diameter of the sand particles discharged from the screen tube is d. s2 W is the maximum particle size that the wellbore can carry. f The nominal sand-blocking accuracy of independent screen tube sand control is d. s0 d represents the maximum particle size of sand produced from the formation. smax The maximum grain size of the core sand in the formation is d. smin d is the minimum grain size of the core sand in the formation, β is an empirical coefficient, and d sw Indicates the particle size of sand carried in the wellbore.

[0048] In some preferred embodiments, the morphology index of the wormholes in the formation is calculated as follows:

[0049]

[0050] Among them, J wh k represents the morphology index of earthworm holes emerging from sand in the strata. v k represents the vertical permeability of the reservoir. h This indicates the horizontal permeability of the reservoir.

[0051] In some preferred embodiments, the sand discharge control strategy includes production control and sand control strategy, sand discharge production strategy, prevention and discharge coordination strategy, discharge first and then prevention strategy, and direct sand prevention strategy.

[0052] In some preferred embodiments, based on the mapping relationship between the GPSC characteristic indicators and the preset sand discharge control strategy, and in conjunction with the GPSC characteristic indicators, the sand discharge control strategy is obtained. The method is as follows:

[0053] S301, if the J fx Less than the first set value, and the J yz If the value is less than the second set value, a production control and sand control strategy will be adopted; otherwise, proceed to S302.

[0054] S302, if the J fx Greater than the first set value and less than the third set value, and the J yz J is greater than the second set value but less than the fourth set value, and is not protected against sand. xs If the value is greater than the fourth set value, a sand removal production strategy is adopted; otherwise, the process jumps to S303.

[0055] S303, if the J fxGreater than the third set value and less than the fifth set value, and the J yz J is greater than the fourth set value but less than the fifth set value, and is not sand-proof. xs Less than the fourth set value, and the J ds Greater than the sixth set value, and the J cx If the value is greater than the seventh set value, the prevention and control coordination strategy will be adopted; otherwise, the process will jump to S304.

[0056] S304, if the J wh If the value is greater than the second set value, a first-release-then-defense strategy is adopted; otherwise, a direct sand control strategy is adopted. In some preferred embodiments, the sand control process is obtained by:

[0057] If the sand discharge control strategy is a combined prevention and discharge strategy: the sand prevention process is selected as an independent screen pipe sand prevention process, and the screen pipe type is a sand prevention screen pipe using regular slit media;

[0058] If the sand discharge control strategy is a discharge-then-prevention strategy: when the sand parameters meet the set first condition, the sand prevention process is selected as the independent screen tube sand prevention process; otherwise, the set sand prevention process is adopted.

[0059] If the sand control strategy is a direct sand prevention strategy: when the sand and gravel parameters meet the set first condition, the sand prevention process is selected as the independent screen tube sand prevention process; otherwise, the set sand prevention process is adopted.

[0060] The established sand control process is as follows:

[0061] For new wells, the ring gravel packing sand control process is generally used; when the formation temperature is higher than the set temperature threshold, the sand coating artificial well wall sand control process is used; when there is a need to increase production, the fracturing packing sand control process is used.

[0062] For older wells, a compression filling sand control process is adopted;

[0063] If the sand control strategy is a production control and sand control strategy and a sand discharge production strategy, there is no need to adopt a sand prevention process.

[0064] The beneficial effects of this invention are:

[0065] 1) This invention addresses the characteristics of heavy oil cold production in loose sandstone reservoirs prone to sand production, characterized by low temperatures and high viscosity. Focusing on the needs of sand production control strategy decision-making and sand control technology selection, it proposes a set of Geology-Production-Sanding Comprehensive (GPSC) evaluation indicators and their calculation methods for loose sandstone heavy oil cold production reservoirs. The GPSC indicator covers key geological, production, and sand production characteristics that influence the aforementioned decision-making processes, providing a comprehensive consideration and identifying key factors. The corresponding calculation methods and processes are simple and easy to implement, providing a direct basis for sand production control strategies and sand control technology selection in loose sandstone heavy oil cold production reservoirs. This solves the problem of unclear understanding and description of reservoir characteristics, and helps improve the rationality of decision-making.

[0066] 2) The sand production control strategy and sand control process optimization method, technical limits, and process proposed in this invention for loose sandstone heavy oil cold production reservoirs are based on the GPSC characteristic index system. Considering factors such as sand production severity, wellbore sand carrying capacity, surface processing capacity, and production requirements, this method achieves scientific and rational decision-making for various sand production control strategies. The method considers comprehensive factors, highlights key factors, is simple and easy to operate, and the results have good scientific validity and rationality. It can quickly achieve standardized sand control process decision-making in engineering sites, improving the efficiency of heavy oil cold production. Attached Figure Description

[0067] Other features, objects, and advantages of this application will become more apparent from the following detailed description of non-limiting embodiments with reference to the accompanying drawings.

[0068] Figure 1 This is a flowchart illustrating the preferred method for controlling sand production during cold oil recovery in loose sandstone reservoirs according to an embodiment of the present invention.

[0069] Figure 2 This is a diagram of the coarse and fine grain size components and critical grain size of formation sand according to an embodiment of the present invention;

[0070] Figure 3 This is a typical sand-producing experimental morphology diagram of an embodiment of the present invention, used to determine and obtain the morphology index of earthworm holes in formation sand production. Detailed Implementation

[0071] To make the objectives, technical solutions, and advantages of this invention clearer, the technical solutions in the embodiments of this invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this invention, not all embodiments. Based on the embodiments of this invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this invention.

[0072] The present application will now be described in further detail with reference to the accompanying drawings and embodiments. It should be understood that the specific embodiments described herein are for illustrative purposes only and are not intended to limit the invention. Furthermore, it should be noted that, for ease of description, only the parts relevant to the invention are shown in the accompanying drawings.

[0073] It should be noted that, unless otherwise specified, the embodiments and features described in this application can be combined with each other.

[0074] A preferred method for controlling sand production during cold oil recovery in loose sandstone reservoirs according to the first embodiment of the present invention, and a preferred method for sand control technology, are as follows: Figure 1 As shown, the method includes:

[0075] S100, obtain the basic parameters for cold production of heavy oil in loose sandstone reservoirs as input parameters; the input parameters include reservoir porosity, permeability, rock strength, reservoir thickness, particle size distribution, clay content, reference production, fluid properties, edge and bottom water distance, and wellhead sand production capacity.

[0076] S200, based on the input parameters, calculate the GPSC characteristic index using a pre-constructed GPSC characteristic index calculation method; the GPSC characteristic index includes the formation sand coarseness-fineness boundary index, reservoir sand production risk index, reservoir sand production severity index, reservoir sand retention difficulty index, wellbore sand carrying condition index, and formation sand production wormhole morphology index.

[0077] S300, Based on the mapping relationship between the GPSC characteristic indicators and the preset sand discharge control strategy, and in combination with the GPSC characteristic indicators, the sand discharge control strategy is obtained.

[0078] S400, based on the sand production control strategy and combined with the gravel parameters, obtain the corresponding sand control technology; the gravel parameters include the median formation sand particle size, uniformity coefficient, sand production severity index, and clay content.

[0079] To more clearly illustrate the sand production control strategy and sand control process optimization method for heavy oil cold production in loose sandstone reservoirs according to the present invention, the steps of one embodiment of the method of the present invention will be described in detail below with reference to the accompanying drawings.

[0080] To address the current lack of evaluation and optimization methods for sand control in loose sandstone reservoirs prone to sand production, characterized by low temperatures and high viscosity during cold oil extraction, this invention provides a set of Geology-Production-Sanding Comprehensive (GPSC) evaluation indicators and calculation methods for loose sandstone heavy oil cold production reservoirs. It also provides sand production control strategies and sand control process optimization methods and technical limitations based on the GPSC indicator system. This provides a comprehensive indicator system and systematic optimization basis for comprehensive decision-making regarding sand production control in loose sandstone reservoirs during heavy oil cold production, considering key reservoir characteristics. It solves the problem of a lack of reliable methods for optimizing sand control processes in heavy oil cold production reservoirs, and helps improve sand control and production efficiency. Details are as follows:

[0081] S100, obtain the basic parameters for cold production of heavy oil in loose sandstone reservoirs as input parameters; the input parameters include reservoir porosity, permeability, rock strength, reservoir thickness, particle size distribution, clay content, reference production, fluid properties, edge and bottom water distance, and wellhead sand production capacity.

[0082] In this embodiment, the GPSC characteristic index of heavy oil cold production in loose sandstone reservoirs takes into account reservoir geological characteristics, production conditions, and sand production patterns. Its calculation is mainly based on basic parameters and information such as reservoir porosity, permeability, rock strength, reservoir thickness, particle size distribution, clay content, reference production, fluid properties, edge and bottom water distance, and wellhead sand production capacity, as shown in Table 1:

[0083] Table 1

[0084] S200, based on the input parameters, calculate the GPSC characteristic index using a pre-constructed GPSC characteristic index calculation method; the GPSC characteristic index includes the formation sand coarseness-fineness boundary index, reservoir sand production risk index, reservoir sand production severity index, reservoir sand retention difficulty index, wellbore sand carrying condition index, and formation sand production wormhole morphology index.

[0085] In this embodiment, the calculation process of each index in the GPSC characteristic index is as follows:

[0086] 1) Stratigraphic Sand Coarseness / Fineness Boundary Index

[0087] The formation sand coarseness / fineness separation index proposed in this invention characterizes the degree to which formation sand is clearly divided into coarse and fine components, using J... cx J indicates. cx An index of 0 indicates that the coarseness and fineness of the formation sand are not very distinct. cx A value of 1 indicates that the sorting of the coarse and fine components of the formation sand is very obvious.

[0088] According to a further preferred embodiment of the present invention, the stratigraphic sand coarseness / fineness boundary index J cx The method to obtain it is as follows:

[0089] First, obtain the formation sand screening data, i.e., the particle size distribution (PSD) data. Convert the mass cumulative weight to the quantity cumulative weight using the following formula;

[0090]

[0091] Where M represents the total mass of the formation sand sample, kg; ρ s Density of formation sand material, kg / m³ 3 ;d si The w represents the grain size of the i-th stratum sand in the sequence number, in meters. i N represents the mass fraction of the sand grain size in the i-th formation; i This represents the number of particles in the i-th group of formation sand.

[0092] Based on the obtained data on the relationship between the number and size of formation sand particles, a double logarithmic relationship diagram with base 10 was plotted, as shown below. Figure 2 As shown.

[0093] exist Figure 2 In the process, observe whether the distribution of data points clearly distinguishes between two intersecting linear relationships (i.e., Figure 2 The coarse and fine particle sizes are fitted with straight lines (i.e., particle size is divided into coarse and fine categories according to a threshold, and then straight lines are fitted separately to obtain the fitted straight lines for the coarse and fine particles). If it is difficult to observe two distinct intersecting straight line segments, then J... cx =0.

[0094] If two intersecting line segments can be clearly observed, then fit the two line segments into a joint line segment. Figure 2 And read the transverse particle size d corresponding to the intersection of the two straight line segments. cx The formation sand coarseness separation index is calculated using the following formula:

[0095]

[0096] In the formula, d cx Indicates by Figure 2 The boundary grain size for classifying the coarse and fine components of the formation sand obtained above is mm; d s50 α represents the median sand grain size in mm; α represents an empirical coefficient, with a recommended value of 0.35; J cx This index represents the boundary between coarse and fine sand in formations and is dimensionless.

[0097] According to the preferred formation sand coarseness / fineness boundary index and its acquisition method of the present invention, formation sand can be easily and quickly determined to be easily and clearly divided into coarse and fine components based on PSD data that is readily available in the laboratory, and quantitative calculation can be achieved. This index is used for subsequent decision analysis of sand control strategies for sand retention, sand removal, and sand production control.

[0098] 2) Reservoir sand production risk index

[0099] The reservoir sand production risk index J proposed in this invention fx J represents the general level of sand production risk of a reservoir without considering specific production conditions. fx The smaller or closer to 0, the lower or no risk of sand production; J fx The larger the value, or the closer it is to 1, the higher the risk of sand production.

[0100] According to a further preferred embodiment of the present invention, based on the existing empirical qualitative sand production prediction results data of acoustic transit time, combined modulus, and sand production index, a new combined intensity index characterizing the comprehensive strength characteristics of the reservoir is added; and the four characteristic indices are further compared with their respective corresponding severe sand production critical limits, and a weighted average is used to obtain the dimensionless reservoir sand production risk index J. fx .

[0101] The present invention proposes a method for calculating the strength index of reservoir rock composites:

[0102] S zh =S t +0.15×S c +S0 (3)

[0103] Among them, S t The tensile strength of reservoir rock is expressed in MPa; S c S0 represents the uniaxial compressive strength of the reservoir rock, in MPa; S0 represents the cohesive strength of the reservoir rock, in MPa; ... zh This indicates the reservoir composite strength, expressed in MPa.

[0104] The dimensionless combined strength, acoustic transit time, combined modulus, and sand production index proposed in this invention are calculated using the following formula:

[0105]

[0106] Furthermore, the comprehensive reservoir sand production risk index is obtained by averaging and weighting individual indicators:

[0107]

[0108] In the formula, K S K T K E KB These are dimensionless combined strength, acoustic transit time, combined modulus, and sand production index, representing individual sand production risk indicators; △T s E represents the reservoir P-wave transit time, μs / m; s MP represents the combined modulus obtained from conventional sand production prediction; B represents the combined modulus. s MP represents the sand production index obtained from conventional sand production prediction. 2 S zh The strength limit for severe sand production is indicated; this invention recommends a value of 5.0 MPa. △T s1 This indicates the acoustic time difference limit corresponding to severe sand production, with a value of 312 μs / m; E s1 This represents the limit of the combined modulus corresponding to severe sand production, with a value of 1.4 × 10⁻⁶. 4 MPa 2 B s1 —The sand production index threshold corresponding to severe sand production is set at 1.5 × 10⁻⁶. 4 MPa 2 .

[0109] 3) Severity index of reservoir sand production

[0110] The reservoir sand production severity index J proposed in this invention yz Characterizes the actual severity of sand production in the reservoir under specific production conditions (production rate and pressure differential). J yz The smaller or closer to 0, the less severe or no sand production; J yz The larger the value, or the closer it is to 1, the more severe the sand production.

[0111] According to the preferred embodiment of the present invention, the reservoir sand production severity index J yz The following formula is used to calculate:

[0112]

[0113] The present invention selects the reservoir sand production severity index J. yz The calculation method mainly considers the comparison between the actual production pressure difference of the reservoir and the critical sand production pressure difference (the greater the actual production pressure difference exceeds the critical sand production pressure difference, the more severe the sand production). It also considers the proportion of production pressure difference, critical sand production pressure difference, and formation static pressure. The higher this proportion, the more severe the oil well production conditions and the more aggravated the sand production. A weighting coefficient of 0.25 is used to supplement the calculation, while neglecting the influence of the latter two auxiliary factors.

[0114] 4) Difficulty index of reservoir sand control

[0115] The reservoir sand-control difficulty index J proposed in this invention ds Characterizes the difficulty of sand control in reservoir sand production. J ds The smaller or closer to 0, the easier it is to block sand; Jds The larger the value, or the closer it is to 1, the more difficult it is to block sand (difficult to block or severely clogged).

[0116] According to the present invention, the reservoir sand-blocking difficulty index considers four key factors affecting the sand-blocking river flow effect: formation sand particle size, clay and fine content, uniformity and sorting coefficient, and crude oil viscosity rate index, and provides a specific calculation method.

[0117]

[0118]

[0119]

[0120]

[0121] J ds =w dc ·X dc +w nz ·X nz +w xs ·X xs +w UV ·X UV (11)

[0122] Where, d c Characteristic grain size representing the coarseness of formation sand (emphasizing the coarseness of the finer components in formation sand), mm; R VCL0 This indicates the calibrated characteristic clay content, with a recommended value of 15%; R f0 This indicates the calibrated fines content; a value of 30% is recommended. (C) jy0 This represents the characteristic uniformity coefficient of the calibration; a value of 5 is recommended. fx0 This represents the calibrated feature sorting coefficient; a value of 3.5 is recommended. o0 This indicates the calibrated bottom-hole viscosity of heavy oil cold-production wells; a value of 200 mPa·s is recommended. f0 This represents the near-wellbore pore velocity of the calibrated characteristic reservoir; a recommended value is 0.075 cm / s. dc X nz X xs X UV These represent four individual indices that influence sand-blocking effectiveness: sand grain size, clay and fine content, uniformity and sorting coefficient, and crude oil viscosity index; all are dimensionless. dc w nz w xs w UV The recommended weights for the four factors mentioned above are 0.4, 0.3, 0.15, and 0.15, respectively. 50 d 70d 90 These represent the particle sizes corresponding to a sample when the cumulative particle size distribution percentage reaches 50%, 70%, and 90%, respectively.

[0123] 5) Wellbore sand carrying condition index

[0124] The wellbore sand-carrying condition index J proposed in this invention xs The technical conditions characterizing whether an oil well has reached the point of sand-carrying production are: that is, the particle size of the formation sand produced from the reservoir or the particle size of the formation sand discharged by the bottom-hole sand-control system can be carried by fluid in the wellbore. xs =1 indicates that the sand-carrying condition has just been met. The smaller the value is than 1, the farther away from the sand-carrying condition in the wellbore. The larger the value is than 1, the higher the degree of exceeding the critical sand-carrying condition.

[0125] The formation sand particle size d under the production pressure difference ΔP is predicted using the empirical model for sand particle size prediction (Equation 4). s0 :

[0126]

[0127] Where, d s0 Indicates the maximum particle size of sand produced in the formation, in mm; d smax Indicates the maximum grain size of the core sand in the formation, in mm; d smin ΔP represents the minimum particle size of the formation core sand, in mm; ΔP represents the production pressure difference of the oil well, in MPa; α and β represent empirical coefficients, and this invention recommends taking α = 0.45 and β = 0.85 respectively.

[0128] If there is an independent screen pipe sand control system at the bottom of the well, calculate the formation sand particle size of the sand discharged from the screen pipe based on the screen pipe precision:

[0129] d s1 =W f ×0.8 (13)

[0130] Where wf represents the nominal sand-blocking accuracy of the independent screen tube sand control, in mm.

[0131] The sand-carrying particle size in the wellbore is:

[0132] d sw =min{d s0 d s1} (14)

[0133] Calculate the maximum particle size that the wellbore can carry under production rate Q:

[0134]

[0135]

[0136] Where A fρ is the cross-sectional area of ​​the oil pipe. f Density of fluid in the wellbore, kg / m³; ρ s Density of formation sand material, kg / m³ 3 Q represents oil well production, in tons per day (t / d); v f C represents the fluid velocity in the wellbore, in m / s; D d represents the settlement drag coefficient, which is dimensionless. s2 Let m be the maximum particle size that the wellbore can carry.

[0137] Wellbore sand carrying condition index:

[0138]

[0139] 6) Formation wormhole morphology index

[0140] The formation sand-producing wormhole morphology index proposed in this invention refers to the probability of sand production forming tortuous and interconnected wormholes. The formation of wormholes during reservoir sand production is beneficial for clearing near-well throats and improving flow capacity. This index is used to evaluate whether a reservoir is suitable for early-stage sand removal production.

[0141] According to the preferred embodiment of the present invention, the acquisition of the wormhole morphology index of sand-emerging strata is divided into an empirical analysis method and an experimental method, wherein the experimental method is as follows:

[0142] A simulated sand production displacement experiment was conducted using actual reservoir cores. The experimental flow rate was set to 2-3 times the actual reservoir fluid flow rate, and the displacement time was set to 3 days. After displacement was completed, the clamp was opened, and the surface morphology of the core was observed. Figure 3 As shown.

[0143] If the morphology of the core end face or side face does not change significantly (e.g.) Figure 3 (a) in J wh The value is 0;

[0144] If the core sample is completely damaged and appears incomplete (e.g.) Figure 3 (c)), J wh The value is 0;

[0145] If the surface of the core shows a shape similar to earthworm holes (such as...) Figure 3 In (b) of the core, and the wormhole morphology is clear, and the overall core skeleton is intact, then J wh The value is set to 1.0; depending on the clarity of the wormholes and the integrity of the core, J wh It takes a value between 0 and 1.

[0146] The preferred method for determining the morphological index of wormholes in formation sand production according to the present invention is as follows:

[0147]

[0148] Where, k v k represents the vertical permeability of the reservoir. h This indicates the horizontal permeability of the reservoir.

[0149] S300, Based on the mapping relationship between the GPSC characteristic indicators and the preset sand discharge control strategy, and in combination with the GPSC characteristic indicators, the sand discharge control strategy is obtained.

[0150] In this embodiment, the sand discharge control strategy is divided into the following five types:

[0151] 1) Production and sand control strategy: This involves appropriately or to a limited extent controlling production pressure differential and output to prevent formation sand production. Excessive production pressure differential and output are direct factors inducing formation sand production.

[0152] 2) Sand removal production strategy: That is, without taking sand control measures, the sand produced in the formation is carried to the surface by the fluid in the wellbore.

[0153] 3) Sand control and drainage synergy strategy: This involves simultaneously implementing sand control measures and producing sand through the wellbore. Appropriate sand control measures are taken to block coarser sand particles and drain finer sand particles, which are then carried to the surface by the wellbore fluid.

[0154] 4) First discharge, then prevention strategy: that is, first discharge sand production, remove fine sand from near-wellbore reservoirs, properly unclog pore throats, and improve near-wellbore reservoir flow capacity; then take sand prevention measures at the appropriate time.

[0155] 5) Direct sand control strategy: This involves directly implementing sand control measures. Based on the oil well's geological conditions, production characteristics, and sand production patterns, an appropriate sand control technology type is evaluated and selected, and sand control measures are then implemented.

[0156] The specific process for determining which sand control strategy to apply is as follows:

[0157] S301, if the J fx Less than a first set value (preferably 0.65 in this invention), and the J yz If the value is less than the second set value (preferably 0.75 in this invention), a production control and sand control strategy is adopted; otherwise, proceed to S302.

[0158] S302, if the J fx The value is greater than the first set value but less than the third set value (the third set value is preferably 1.15, i.e., 0.65). <J fx <1.15), and the J yz The value is greater than the second setting value but less than the fourth setting value (the fourth setting value is preferably 1.25, i.e., 0.75). <J yz <1.25), and under conditions without sand control J xsIf the value is greater than the fourth set value, a sand removal production strategy is adopted; otherwise, the process jumps to S303.

[0159] S303, if the J fx The value is greater than the third set value but less than the fifth set value (the fifth set value is preferably 1.5, i.e., 1.15). <J fx <1.5), and the J yz Greater than the fourth set value and less than the fifth set value (i.e., 1.25) <J yz <1.5), and under conditions without sand prevention J xs Less than the fourth set value, and the J ds Greater than the sixth preset value (preferably 1.0 in this invention), and the J cx If the value is greater than the seventh preset value (preferably 0.5 in this invention), then the prevention and control coordination strategy is adopted; otherwise, the process jumps to S304.

[0160] S304, if the J wh If the value exceeds the second set value, a "drain first, then prevent" strategy is adopted; otherwise, a direct sand control strategy is adopted. In actual production, the set value range for each sand control strategy can be set according to the actual situation; the above only provides one optimal range.

[0161] S400, based on the sand production control strategy and combined with the gravel parameters, obtain the corresponding sand control technology; the gravel parameters include the median formation sand particle size, uniformity coefficient, sand production severity index, and clay content.

[0162] In this embodiment, the sand control process is obtained as follows:

[0163] If the sand discharge control strategy is a combined prevention and discharge strategy: the sand prevention process is selected as an independent screen pipe sand prevention process, and the screen pipe type is a sand prevention screen pipe using regular slit media (e.g., slotted screen pipe, wire-wound screen pipe);

[0164] If the sand production control strategy is a first-discharge-then-prevention strategy: when the sand and gravel parameters meet the set first condition (specifically: median formation sand grain size d), s50 >0.1mm, uniformity coefficient <7.5, sand production severity index J yz <1.75, clay content R v If the sand control rate is less than 15%, then the independent screen tube sand control process should be selected; otherwise, the set sand control process should be used.

[0165] If the sand control strategy is a direct sand prevention strategy: when the sand and gravel parameters meet the set first condition, the sand prevention process is selected as the independent screen tube sand prevention process; otherwise, the set sand prevention process is adopted.

[0166] The established sand control process is as follows:

[0167] For new wells, the ring gravel packing sand control process is generally used; when the formation temperature is greater than the set temperature threshold (preferably 30°C in this invention), the coated sand artificial well wall sand control process is used (coated sand packing fills the near-wellbore void left by sand discharge); when there is a need to increase production, the fracturing packing sand control process is used.

[0168] For older wells, a compression filling process for sand control is adopted.

[0169] If the sand control strategy is a production control and sand control strategy or a sand discharge production strategy, then sand prevention technology is not required.

[0170] The sand control process optimization method proposed in this invention considers reservoir geological characteristics, production conditions, and sand production patterns when implementing sand control measures. Based on technical indicators and their limits, it evaluates sand control process types for specific reservoirs and oil wells, derives comprehensive adaptability indicators, and selects the optimal sand control process method based on the ranking of these indicators. This sand control strategy and sand control process optimization method considers all factors comprehensively, highlighting key factors, quantifying the indicators and standardizing the process for process strategy optimization, making it more scientific and rational.

[0171] In summary, this invention categorizes sand production control strategies into three types: controlling production pressure differential and output, coordinated sand-carrying production with sand control measures, and implementing sand control technology. The proposed sand control strategy decision-making method considers factors such as the severity of sand production, wellbore sand-carrying capacity, surface treatment capacity, and production requirements, based on the GPSC characteristic indicators of loose sandstone heavy oil cold-production reservoirs, to achieve a scientific and rational decision on the three sand production control strategies. The proposed sand control technology optimization method considers reservoir geological characteristics, production conditions, and sand production patterns for sand control strategies. Based on technical indicators and their limits, it evaluates the sand control technology type for specific reservoirs and wells, derives a comprehensive adaptability index, and selects the optimal sand control technology based on the index ranking. Both the sand production control strategy and sand control technology optimization methods consider comprehensive factors and highlight key factors, achieving quantification of indicators and standardization of processes for process strategy optimization, making them more scientific and rational.

[0172] A second embodiment of the present invention provides a system for optimizing sand production control strategies and sand control processes in the cold production of heavy oil in loose sandstone reservoirs. The system includes:

[0173] The parameter acquisition module is configured to acquire basic parameters for cold production of heavy oil in loose sandstone reservoirs as input parameters. The input parameters include reservoir porosity, permeability, rock strength, reservoir thickness, particle size distribution, clay content, reference production, fluid properties, edge and bottom water distance, and wellhead sand production capacity.

[0174] The index calculation module is configured to calculate GPSC characteristic indices based on the input parameters using a pre-constructed GPSC characteristic index calculation method. The GPSC characteristic indices include the formation sand coarseness-fineness boundary index, reservoir sand production risk index, reservoir sand production severity index, reservoir sand retention difficulty index, wellbore sand carrying condition index, and formation sand production wormhole morphology index.

[0175] The strategy acquisition module is configured to obtain the sand discharge control strategy based on the mapping relationship between the GPSC characteristic indicators and the preset sand discharge control strategy, combined with the GPSC characteristic indicators.

[0176] The sand control process acquisition module is configured to acquire the corresponding sand control process based on the sand discharge control strategy and the sand and gravel parameters; the sand and gravel parameters include the median sand particle size, uniformity coefficient, sand discharge severity index, and clay content.

[0177] It should be noted that the above-described system for controlling sand production in heavy oil cold recovery from loose sandstone reservoirs and optimizing sand control techniques is merely an example of the division of functional modules. In practical applications, these functions can be assigned to different functional modules as needed, meaning the modules or steps in the embodiments of this invention can be further decomposed or combined. For example, the modules in the above embodiments can be merged into one module or further divided into multiple sub-modules to complete all or part of the functions described above. The names of the modules and steps involved in the embodiments of this invention are merely for distinguishing between modules or steps and are not considered as improper limitations on the invention.

[0178] An electronic device according to a third embodiment of the present invention includes: at least one processor; and a memory communicatively connected to at least one of the processors; wherein the memory stores instructions executable by the processor, the instructions being executed by the processor to implement the above-described preferred method for controlling sand production and sand control technology in the cold production of heavy oil in loose sandstone reservoirs.

[0179] A computer-readable storage medium according to a fourth embodiment of the present invention stores computer instructions, which are executed by a computer to implement the above-described preferred method for controlling sand production and sand control technology in the cold production of heavy oil in loose sandstone reservoirs.

[0180] Those skilled in the art will understand that, for the sake of convenience and brevity, the specific working process and related descriptions of the above-described electronic device and computer-readable storage medium can be referred to the corresponding process in the foregoing method examples, and will not be repeated here.

[0181] Those skilled in the art will recognize that the modules and method steps of the various examples described in conjunction with the embodiments disclosed herein can be implemented in electronic hardware, computer software, or a combination of both. The programs corresponding to the software modules and method steps can be placed in random access memory (RAM), main memory, read-only memory (ROM), electrically programmable ROM, electrically erasable programmable ROM, registers, hard disks, removable disks, CD-ROMs, or any other form of storage medium known in the art. To clearly illustrate the interchangeability of electronic hardware and software, the components and steps of the various examples have been generally described in terms of functionality in the foregoing description. Whether these functions are implemented in electronic hardware or software depends on the specific application and design constraints of the technical solution. Those skilled in the art can use different methods to implement the described functions for each specific application, but such implementation should not be considered beyond the scope of the invention.

[0182] The terms “first”, “second”, etc., are used to distinguish similar objects, not to describe or indicate a specific order or sequence.

[0183] The term "comprising" or any other similar term is intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus / device that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent in such process, method, article, or apparatus / device.

[0184] The technical solution of the present invention has been described above with reference to the preferred embodiments shown in the accompanying drawings. However, it will be readily understood by those skilled in the art that the scope of protection of the present invention is obviously not limited to these specific embodiments. Without departing from the principles of the present invention, those skilled in the art can make equivalent changes or substitutions to the relevant technical features, and the technical solutions after such changes or substitutions will all fall within the scope of protection of the present invention.

Claims

1. A method for optimizing sand production control strategies and sand prevention technologies in the cold production of heavy oil in loose sandstone reservoirs, characterized in that, The method includes: S100, obtain the basic parameters for cold production of heavy oil in loose sandstone reservoirs as input parameters; the input parameters include reservoir porosity, permeability, rock strength, reservoir thickness, particle size distribution, clay content, reference production, fluid properties, edge and bottom water distance, and wellhead sand production capacity. S200, based on the input parameters, calculate the GPSC characteristic index using a pre-constructed GPSC characteristic index calculation method; the GPSC characteristic index includes the formation sand coarseness-fineness boundary index, reservoir sand production risk index, reservoir sand production severity index, reservoir sand retention difficulty index, wellbore sand carrying condition index, and formation sand production wormhole morphology index. S300, Based on the mapping relationship between the GPSC characteristic indicators and the preset sand discharge control strategy, and in combination with the GPSC characteristic indicators, the sand discharge control strategy is obtained. S400, based on the sand production control strategy and combined with the gravel parameters, obtain the corresponding sand control technology; the gravel parameters include the median formation sand particle size, uniformity coefficient, sand production severity index, and clay content.

2. The preferred method for controlling sand production during cold oil recovery in loose sandstone reservoirs according to claim 1, characterized in that, The method for calculating the stratigraphic sand coarseness / fineness boundary index is as follows: First, obtain the number of particles in the i-th group of formation sand: Where M represents the total mass of the formation sand sample, ρ s d represents the density of the formation sand material. si w represents the grain size of the i-th stratum sand. i N represents the mass fraction of the sand grain size in the i-th formation. i This represents the number of particles in the i-th group of formation sand. Based on the relationship between the number of particles and the particle size of formation sand, a double logarithmic relationship diagram was drawn. If the two line segments in the double logarithmic relationship graph do not intersect, then J cx =0, otherwise, fit the two line segments into a joint line segment, and read the transverse particle size d corresponding to the intersection point of the two line segments. cx Calculate J cx : Among them, J cx Indicates the boundary index between coarse and fine sand in formations, d cx The grain size representing the dividing line between coarse and fine components of formation sand, d s50 J represents the median grain size of the formation sand, α represents the empirical coefficient, and J represents the median grain size of the formation sand. cx This indicates the boundary index between coarse and fine sand in the formation.

3. The preferred method for controlling sand production during cold oil recovery in loose sandstone reservoirs according to claim 1, characterized in that, The reservoir sand production risk index is calculated as follows: Among them, J fx K represents the reservoir sand production risk index. S K T K E K B These are dimensionless combined strength, acoustic transit time, combined modulus, and sand production index, representing individual sand production risk indicators. t S represents the uniaxial tensile strength of reservoir rock. c S represents the uniaxial compressive strength of the reservoir rock, and S0 represents the cohesive strength of the reservoir rock. zh Indicates the reservoir composite strength, ΔT s E represents the reservoir P-wave transit time. s B represents the combined modulus obtained from conventional sand production prediction. s S represents the sand production index obtained from conventional sand production prediction. zh1 Indicates the severe combined strength limit of sand production, △T s1 E represents the acoustic time difference limit corresponding to severe sand production. s1 B represents the limit of the combined modulus corresponding to severe sand production. s1 This indicates the sand production index limit corresponding to severe sand production.

4. The preferred method for controlling sand production during cold oil recovery in loose sandstone reservoirs according to claim 3, characterized in that, The method for the reservoir sand production severity index is as follows: Among them, J yz Indices representing the severity of sand production in reservoirs, ΔP and ΔP'. c P r These represent the production pressure differential, the critical production pressure differential for sand production, and the formation static pressure, respectively.

5. The preferred method for controlling sand production during cold oil recovery in loose sandstone reservoirs according to claim 4, characterized in that, The reservoir sand-control difficulty index is calculated as follows: J ds =w dc ·X dc +w nz X nz +w xs ·X xs +w UV ·X UV d C =0.333d 50 +0.387d 70 +0.510d 90 Among them, J ds The index representing the difficulty of reservoir sand control, d c Characteristic grain size R that represents the coarseness of formation sand VCL0 R represents the characteristic clay content of the calibration. f0 Indicates the specified fines content, C jy0 C represents the characteristic uniformity coefficient of the calibration. fx0 U represents the calibrated characteristic sorting coefficient. o0 This indicates the calibrated viscosity of crude oil at the bottom of a heavy oil cold-production well, v. f0 X represents the near-wellbore pore velocity of the calibrated characteristic reservoir. dc X nz X xs X UV These are four individual indices that characterize the sand grain size, clay and fine content, uniformity and sorting coefficient, and crude oil viscosity index, all of which affect the sand-blocking effect. dc w nz w xs w UV X dc X nz X xs X UV The weight, d 50 d 70 d 90 These represent the particle sizes corresponding to a sample when the cumulative particle size distribution percentage reaches 50%, 70%, and 90%, respectively.

6. The preferred method for controlling sand production during cold oil recovery in loose sandstone reservoirs according to claim 5, characterized in that, The wellbore sand-carrying condition index is calculated as follows: the sw =min{d s0 ,d s1 } d s1 =W f ×0.8 Among them, J xs Represents the wellbore sand carrying condition index, A f ρ is the cross-sectional area of ​​the oil pipe. f ρ represents the density of the fluid in the wellbore. s The density of the formation sand material is represented by Q, the oil well production is represented by g, and the mass is represented by v. f C represents the fluid velocity in the wellbore. D Let d be the settlement drag coefficient. s1 The diameter of the sand particles discharged from the screen tube is d. s2 W is the maximum particle size that the wellbore can carry. f The nominal sand-blocking accuracy of independent screen tube sand control is d. s0 d represents the maximum particle size of sand produced from the formation. smax The maximum grain size of the core sand in the formation is d. smin d is the minimum grain size of the core sand in the formation, β is an empirical coefficient, and d sw Indicates the particle size of sand carried in the wellbore.

7. The preferred method for controlling sand production during cold oil recovery in loose sandstone reservoirs according to claim 6, characterized in that, The method for calculating the morphology index of earthworm holes in the formation is as follows: Among them, J wh k represents the morphology index of earthworm holes emerging from sand in the strata. v represents the vertical permeability of the reservoir, and k represents the horizontal permeability of the reservoir.

8. The preferred method for controlling sand production during cold oil recovery in loose sandstone reservoirs according to claim 7, characterized in that, The sand control strategies include production control and sand control strategies, sand discharge production strategies, prevention and discharge coordination strategies, discharge first and then prevention strategies, and direct sand control strategies.

9. The preferred method for controlling sand production during cold oil recovery in loose sandstone reservoirs according to claim 8, characterized in that, Based on the mapping relationship between the GPSC characteristic indicators and the preset sand discharge control strategy, and in conjunction with the GPSC characteristic indicators, the sand discharge control strategy is obtained, and the method is as follows: S301, if the J fx Less than the first set value, and the J yz If the value is less than the second set value, a production control and sand control strategy will be adopted; otherwise, proceed to S302. S302, if the J fx Greater than the first set value and less than the third set value, and the J yz J is greater than the second set value but less than the fourth set value, and is not protected against sand. xs If the value is greater than the fourth set value, a sand removal production strategy is adopted; otherwise, the process jumps to S303. S303, if the J fx Greater than the third set value and less than the fifth set value, and the J yz J is greater than the fourth set value but less than the fifth set value, and is not sand-proof. xs Less than the fourth set value, and the J ds Greater than the sixth set value, and the J cx If the value is greater than the seventh set value, the prevention and control coordination strategy will be adopted; otherwise, the process will jump to S304. S304, if the J wh If the value is greater than the second set value, a first-release-then-defense strategy is adopted; otherwise, a direct sand prevention strategy is adopted.

10. The preferred method for controlling sand production during cold oil recovery in loose sandstone reservoirs according to claim 9, characterized in that, The sand control process is obtained as follows: If the sand discharge control strategy is a combined prevention and discharge strategy: the sand prevention process is selected as an independent screen pipe sand prevention process, and the screen pipe type is a sand prevention screen pipe using regular slit media; If the sand discharge control strategy is a first discharge followed by a second prevention strategy: when the sand and gravel parameters meet the set first condition, the sand prevention process is selected as an independent screen tube sand prevention process. Otherwise, the established sand control process shall be adopted; If the sand control strategy is a direct sand prevention strategy: when the sand and gravel parameters meet the set first condition, the sand prevention process is selected as the independent screen tube sand prevention process; otherwise, the set sand prevention process is adopted. The established sand control process is as follows: For new wells, the ring gravel packing sand control process is generally used; when the formation temperature is higher than the set temperature threshold, the sand coating artificial well wall sand control process is used; when there is a need to increase production, the fracturing packing sand control process is used. For older wells, a compression filling sand control process is adopted; If the sand control strategy is a production control and sand control strategy and a sand discharge production strategy, there is no need to adopt sand prevention technology.

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