Break-control body oil reservoir gas separation rate calculation chart and application

Abstract

The invention provides a gas separation rate calculation chart of a fault control body oil reservoir and application, and relates to the technical field of oil reservoir gas injection. The fault control body oil reservoir gas separation rate calculation chart comprises the following steps that unit pressure drop produced liquid of an elastic drive stage of an oil well is calibrated; determining the gas distribution rate, wherein the gas distribution rate refers to the percentage of the gas amount acting on effective energy supplement of the oil producing well in the gas injection amount of the gas injection well; determining the oil well pressure at any moment after gas injection of the effective oil well; drawing a gas separation rate chart; and determining the gas-driven well component gas rate change. The gas separation rate calculation plate of the fault control body oil reservoir provides theoretical guidance for optimization of injection and production parameters, adjustment of gas injection development technology policies and the like in the gas drive well group injection process.

Description

Technical Field

[0001] This invention relates to the field of reservoir gas injection technology, specifically to a calculation chart and application of gas distribution rate in fault-controlled reservoirs. Background Technology

[0002] Carbonate reservoirs often form large oil and gas fields with high reserves and high single-well production, making them prone to becoming large-scale oil and gas fields. Of the nine high-yield wells worldwide that have ever produced over 10,000 tons per day, eight are located in carbonate reservoirs. Many important oil and gas producing regions worldwide have carbonate-dominated reservoirs; in my country, carbonate reservoirs are also widely distributed. The physical properties of carbonate reservoirs are mainly controlled by sedimentary facies, diagenesis, and tectonic movements. The reservoir space in carbonate rocks is generally classified into three types: primary pores, caverns, and fractures. Compared to sandstone reservoirs, carbonate reservoirs have more diverse reservoir space types and greater secondary variations, exhibiting greater complexity and diversity.

[0003] The Shunbei oil and gas field is located in the Tarim Basin of Xinjiang and is a marine carbonate oil and gas reservoir. It is influenced by regional tectonics, fault development, and diverse hydrocarbon charging conditions. The reservoir types are complex, including condensate gas reservoirs, volatile oil reservoirs, and black oil reservoirs.

[0004] As exploration and development progresses, the oilfield has transitioned from depletion-driven development to replenishment-driven development, with natural gas flooding and nitrogen flooding being adopted in most well groups. During gas flooding, excessively rapid gas injection can lead to rapid gas leakage in the well, resulting in decreased production capacity, while excessively slow injection rates cannot maintain formation energy stability.

[0005] Chinese patent CN106884633A points out that complex fault-block reservoirs generally have large formation dip angles and low crude oil viscosity, and have now entered the ultra-high water-cut stage. The remaining oil is mainly distributed along the ridgeline of the structural high points and in the fault angle region, and the scale of remaining oil accumulation is small. Utilizing the remaining oil by drilling new wells faces risks such as technical limitations in unlimited drilling close to the fault and poor or even no economic benefits. Therefore, a technical solution is proposed: injecting nitrogen into high-position oil wells to replace the remaining oil in the high-position areas through gravity differentiation. Under certain conditions, high-position gas injection can form a secondary gas cap, which can effectively drive the flow of remaining oil near the fault. In the design of the gas injection development scheme, the reasonable gas dosage is a key issue. On the one hand, insufficient gas injection cannot form an "artificial gas cap" to effectively drive the remaining oil in the high-position areas; on the other hand, excessive gas injection increases the costs of gas production, storage, and transportation, prolongs construction time, and leads to premature gas channeling, reducing the overall development effect and economic benefits of the scheme. Therefore, it is necessary to conduct research on optimizing the gas injection volume. This invention provides a method for predicting the reasonable gas injection volume for forming an artificial gas cap in fault-block reservoirs. Within the injected gas's reach, the gas phase length must meet a certain volume ratio greater than the "critical gas phase length" to form an artificial gas cap that meets design requirements. This method provides guidance for the design of gas injection schemes for closed, complex fault-block reservoirs. However, existing technologies lack research on the effective gas separation rate.

[0006] To determine the effective gas injection volume of injection wells and the actual gas distribution volume of effective wells, it is urgent to develop an effective gas distribution rate identification chart to provide a theoretical basis for subsequent adjustments to development technology policies. Summary of the Invention

[0007] To address the aforementioned problems, this invention provides a gas fractionation calculation chart for fault-controlled reservoirs. Based on the pressure changes in the effective wells, it establishes a pressure change template under different gas fractionation rates. This template is used to determine the gas fractionation changes of oil wells under different well types and injection intensities. Based on these changes, it identifies the types of inter-well channels and qualitatively determines whether high-permeability channels exist. This is crucial for subsequent measures to prevent gas channeling and optimize injection-production relationships to improve oil recovery.

[0008] To achieve the above objectives, the technical solution adopted by the present invention is as follows:

[0009] On one hand, the present invention provides a calculation chart for the gas distribution rate of a fault-controlled reservoir, comprising the following steps:

[0010] S1: Fluid production per unit pressure drop during the elastic drive phase of the calibrated oil well;

[0011] S2: Fixed gas distribution rate, which refers to the percentage of gas volume that effectively replenishes the oil well to the gas volume injected into the gas injection well.

[0012] S3: The pressure of the oil well at any moment after gas injection into the effective oil well;

[0013] S4: Draw the gas fractionation chart;

[0014] S5: Determine the changes in gas ratio of components in gas-driven wells.

[0015] Preferably, in S1, the unit pressure drop produced fluid is the amount of fluid produced when the average formation pressure drops by 1 MPa.

[0016] Preferably, in S1, the formula for calculating the unit pressure drop product fluid in the elastic drive stage is:

[0017] The unit pressure drop in fluid production during the elastic drive stage = total fluid production of the oil well during the elastic drive stage / pressure drop of the oil well before water injection.

[0018] Preferably, in S2, the formula for calculating the gas separation rate is:

[0019] Gas separation rate = (Replenishment volume of the effective well / Underground volume of injected gas) × 100%.

[0020] Preferably, in step S2, the calculation of the gas separation rate includes the following steps:

[0021] (1) Determine the baseline value: Calculate the liquid production per unit pressure drop during the elastic drive stage and convert it to the underground volume;

[0022] (2) Calculate the gas distribution volume: Based on the pressure drop of the effective well stage and the liquid production per unit pressure drop in the elastic drive stage, and referring to the production trend before gas injection, calculate the normalized underground volume to be produced under the stage pressure drop; calculate the supplementary volume based on the difference between the actual underground volume produced in the stage and the normalized underground volume.

[0023] (3) Calculate the natural gas compression ratio: By statistically analyzing the PVT data of different oil and gas wells in the Shunbei oil and gas field, the variation of natural gas compression ratio under different temperature and pressure conditions is established.

[0024] Preferably, in step (1), the unit pressure drop liquid production (converted to underground volume) = unit pressure drop liquid production / crude oil density × crude oil volume coefficient.

[0025] Preferably, in step (2), the normalized underground volume = stage pressure drop × liquid production per unit pressure drop (converted to underground volume).

[0026] Preferably, in S3, the formula for calculating the well pressure at any moment after gas injection into the effective oil well is:

[0027] P = P i -(Wp-Winj / Natural gas compression ratio × gas separation rate) / Liquid production per unit pressure drop during the elastic drive stage.

[0028] in,

[0029] Pi Initial pressure;

[0030] Wp represents the stage output liquid;

[0031] Winj represents the amount of gas injected during the stage.

[0032] Preferably, in S4, the specific operation of drawing the gas fractionation chart is as follows: predict the change in pressure of the effective oil well in 10% increments according to the gas fractionation rate from 0% to 100%, and establish a correlation diagram between the pressure of the effective oil well and the cumulative gas injection volume.

[0033] Preferably, in S5, the specific operation of determining the gas fraction change of the gas-driven well is as follows: the actual pressure of the oil well at different stages is obtained through downhole pressure testing, and the actual pressure is plotted in the gas fraction chart in S4 to obtain the change of gas fraction with the change of gas injection volume.

[0034] Furthermore, this invention provides the application of the aforementioned fault-controlled reservoir gas distribution rate calculation chart in adjusting the gas injection strategy of fault-controlled reservoirs.

[0035] Compared with the prior art, the present invention has the following beneficial effects:

[0036] This invention provides a gas fractionation calculation chart for fault-controlled reservoirs. It can determine the inter-well gas fractionation variation based on measured formation pressure in oil wells, and further analyze the inter-well channel types based on the characteristics of the gas fractionation variation. Different inter-well channel types will lead to different changes in gas fractionation. Based on the gas fractionation template, it is possible to qualitatively determine whether the inter-well channel is a high-permeability channel (gas fractionation remains consistently high) or a single channel (gas fractionation remains unchanged). This provides a basis for subsequent optimization of injection and production parameters and adjustment of development technology policies. Attached Figure Description

[0037] Figure 1 This is the gas distribution rate diagram described in S4 of the fault-controlled reservoir gas distribution rate calculation diagram scheme of the present invention.

[0038] Figure 2 This is the gas distribution rate diagram described in S5 of the fault-controlled reservoir gas distribution rate calculation diagram scheme of the present invention, wherein the measured flow pressure is under the condition that the gas distribution rate is 30%.

[0039] Figure 3 This is a graph showing the change in gas fraction of well B in Example 1. Detailed Implementation

[0040] To make the technical means, creative features, achieved objectives, and effects of this invention readily understandable, the invention is further illustrated below with specific embodiments. However, these embodiments are merely preferred embodiments and not all embodiments. Other embodiments obtained by those skilled in the art based on the embodiments described herein without creative effort are all within the scope of protection of this invention. It is worth noting that the raw materials used in this invention are all common commercially available products, and their sources are not specifically limited. The technical and scientific terms used in the embodiments have the meanings commonly understood by those skilled in the art to which this invention pertains.

[0041] This invention provides a calculation chart for the gas distribution rate of a fault-controlled reservoir, comprising the following steps:

[0042] S1: Fluid production per unit pressure drop during the elastic drive phase of the calibrated oil well;

[0043] S2: Fixed gas distribution rate, which refers to the percentage of gas volume that effectively replenishes the oil well to the gas volume injected into the gas injection well.

[0044] S3: The pressure of the oil well at any moment after gas injection into the effective oil well;

[0045] S4: Draw a gas fractionation rate chart; the specific operation of drawing the gas fractionation rate chart is as follows: predict the change in pressure of the effective oil well in 10% increments according to the gas fractionation rate from 0% to 100%, and establish a correlation chart between the pressure of the effective oil well and the cumulative gas injection volume. The gas fractionation rate chart is as follows: Figure 1 As stated above.

[0046] S5: Determine the gas fraction variation of components in the gas-driven well. The specific operation for determining the gas fraction variation of components in the gas-driven well is as follows: Obtain the actual well pressure at different stages through downhole pressure testing, and plot the actual pressure onto the gas fraction chart described in S4 to obtain the change in gas fraction with varying injection volume. The gas fraction chart is shown below. Figure 2 As shown.

[0047] Example 1

[0048] A calculation chart for gas distribution ratio in a fault-controlled reservoir includes the following steps:

[0049] For well group A in the fault-controlled reservoir, which consists of three wells: gas injection well A, and production wells B and C, both wells B and C benefited during gas injection. As the injection volume increased, the gas-oil ratio in production well B gradually rose, indicating a significant risk of gas channeling.

[0050] S1: The unit pressure drop fluid production of calibrated oil well B during the elastic drive stage; the cumulative fluid production of oil well B during the self-flowing stage is 39,900 tons, and the pressure drops from 85 MPa to 32 MPa. The unit pressure drop fluid production of calibrated oil well B during the elastic drive stage is 1247 tons / MPa.

[0051] S2:

[0052] The first step is to convert the unit pressure drop production fluid of oil well B into the underground volume.

[0053] Underground unit pressure drop fluid production = elastic stage unit pressure drop fluid production 1247 tons / MPa / crude oil density 0.88 / crude oil volume coefficient 2.4 = 3442 cubic meters / MPa;

[0054] The second step is to calculate the gas distribution. After the gas injection in oil well B is effective, the formation energy increases from 32 MPa to 37 MPa. Therefore, the gas distribution from the gas well to the oil well is (37-32) MPa × underground unit pressure drop production 3442 = 17210 cubic meters.

[0055] The third step is to calculate the gas fractionation rate. Based on the established empirical formula for pressure and natural gas compression ratio, the current natural gas compression ratio is calculated to be 208. During the effective phase of oil well B, injection well A injected a total of 5.97 million cubic meters of gas.

[0056] The calculated underground volume of injected gas is 5.97 million cubic meters / 208 = 28,702 cubic meters.

[0057] The gas distribution rate of oil well B is equal to the gas distribution volume of oil well B (17210 cubic meters) / the gas injection volume of gas well A (28702 cubic meters).

[0058] Table 1. Statistics on natural gas compression ratio under different temperature and pressure conditions

[0059] Temperature K Pressure MPa Natural gas compression ratio 430 5 32 430 10 65 430 15 98 430 20 129 430 25 158 430 30 184 430 35 208 430 40 229 430 45 248 430 50 266 430 55 281 430 60 295 430 65 308 430 70 319 430 75 330 430 80 340 430 85 349 430 90 358

[0060] S3: The well pressure at any moment after gas injection in well B is effective = formation pressure before gas injection (32 MPa) - (daily fluid production of well B - daily injection rate of gas well A / natural gas compression ratio × gas fractionation rate) / fluid production per unit pressure drop during the elastic drive stage (3442 cubic meters / MPa). Assuming a gas fractionation rate of 0-100%, divided into 10% increments, the theoretical pressure of well B under different injection rates and gas fractionation rates can be obtained.

[0061] S4: Plot the measured formation pressure of oil well B onto the chart. The position of the measured pressure on the chart is the gas fraction of the oil well (e.g., ...). Figure 3 (As shown).

[0062] By establishing a gas distribution rate chart, it was found that there is strong connectivity and a high gas distribution rate (60%) between oil well B and injection well A, but the channel is singular, resulting in a high risk of gas channeling. Therefore, by increasing the production of oil well C and widening the pressure difference between it and injection well A, the gas distribution rate of well C was increased, while the gas distribution rate of well B was decreased, thus delaying the gas channeling time of well B. Ultimately, by increasing the production rate of oil well C to divert the flow, the gas distribution rate of this well was reduced (60%↓40%), gas channeling was delayed by 180 days, and oil production increased by 0.9 million tons.

[0063] Practice has shown that the application of gas fractionation charts has identified the types of inter-well channels and clarified the risk of gas channeling in oil wells. In subsequent adjustments, the gas fractionation charts can also be used to evaluate the adjustments and provide theoretical guidance for the analysis of similar oil wells in the future.

[0064] Finally, it should be noted that the above content is only used to illustrate the technical solution of the present invention, and is not intended to limit the scope of protection of the present invention. Simple modifications or equivalent substitutions made by those skilled in the art to the technical solution of the present invention do not depart from the essence and scope of the technical solution of the present invention.

Claims

1. A calculation chart for gas fractionation in a fault-controlled reservoir, characterized in that, Includes the following steps: S1: Fluid production per unit pressure drop during the elastic drive phase of the calibrated oil well; S2: Fixed gas distribution rate, which refers to the percentage of gas volume that effectively replenishes the oil well to the gas volume injected into the gas injection well. S3: The pressure of the oil well at any moment after gas injection into the effective oil well; S4: Draw the gas fractionation chart; S5: Determine the changes in gas ratio of components in gas-driven wells.

2. The calculation chart for gas distribution rate of a fault-controlled reservoir according to claim 1, characterized in that, In S1, the unit pressure drop produced fluid is the amount of fluid produced when the average formation pressure drops by 1 MPa.

3. The calculation chart for gas distribution rate of a fault-controlled reservoir according to claim 1, characterized in that, In S1, the formula for calculating the unit pressure drop of the produced fluid in the elastic drive stage is: The unit pressure drop in fluid production during the elastic drive stage = total fluid production of the oil well during the elastic drive stage / pressure drop of the oil well before water injection.

4. The calculation chart for gas distribution rate of a fault-controlled reservoir according to claim 1, characterized in that, In S2, the formula for calculating the gas separation rate is: Gas separation rate = (Replenishment volume of the effective well / Underground volume of injected gas) × 100%.

5. The calculation chart for gas distribution rate of a fault-controlled reservoir according to claim 1, characterized in that, In S2, the calculation of the gas separation rate includes the following steps: (1) Determine the baseline value: Calculate the liquid production per unit pressure drop during the elastic drive stage and convert it to the underground volume; (2) Calculate the gas volume: Based on the pressure drop of the effective well stage and the liquid production per unit pressure drop in the elastic drive stage, and with reference to the production trend before gas injection, calculate the normalized underground volume to be produced under the stage pressure drop. The supplementary volume is calculated based on the difference between the actual underground volume produced in the stage and the normalized underground volume; (3) Calculate the natural gas compression ratio: By statistically analyzing the PVT data of different oil and gas wells in the Shunbei oil and gas field, the variation of natural gas compression ratio under different temperature and pressure conditions is established.

6. The calculation chart for gas distribution rate of a fault-controlled reservoir according to claim 5, characterized in that, In step (1), the unit pressure drop liquid production = unit pressure drop liquid production / crude oil density × crude oil volume coefficient, where the unit pressure drop liquid production is the value converted to underground volume.

7. The calculation chart for gas distribution rate of a fault-controlled reservoir according to claim 5, characterized in that, In step (2), the normalized underground volume = stage pressure drop × liquid production per unit pressure drop, where the liquid production per unit pressure drop is the value converted to underground volume.

8. The calculation chart for gas distribution rate of a fault-controlled reservoir according to claim 1, characterized in that, In S3, the formula for calculating the well pressure at any moment after gas injection in the effective oil well is: P = P i -(Wp-Winj / Natural Gas Compression Ratio × Gas Separation Rate) / Liquid Production per Unit Pressure Drop in Elastic Drive Stage; in, P i Initial pressure; Wp represents the stage output liquid; Winj represents the amount of gas injected during the stage.

9. The calculation chart for gas distribution rate of a fault-controlled reservoir according to claim 1, characterized in that, In S4, the specific operation of drawing the gas fractionation chart is as follows: predict the change of effective oil well pressure in 10% increments according to the gas fractionation rate from 0% to 100%, and establish a correlation chart between effective oil well pressure and cumulative gas injection volume.

10. The calculation chart for gas distribution rate of a fault-controlled reservoir according to claim 1, characterized in that, In S5, the specific operation for determining the change in the gas fraction of the gas-driven well is as follows: the actual pressure of the oil well at different stages is obtained through downhole pressure testing, and the actual pressure is plotted on the gas fraction chart in S4 to obtain the change in the gas fraction as the gas injection volume changes.

11. The application of the gas distribution rate calculation chart of fault-controlled reservoir as described in any one of claims 1-10 in adjusting the gas injection strategy of fault-controlled reservoir.

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