Basin-level carbon dioxide gas injection capacity planning method

Abstract

The invention discloses a basin-level carbon dioxide gas injection capacity planning method. The method is specifically implemented according to the following steps that 1, basic data parameters of different oil reservoirs of a target basin are collected; 2, according to the data parameters obtained in the step 1, a mathematical model of the oil reservoir carbon dioxide flooding annual gas injection amount is established, and the annual gas injection amount of different oil reservoirs is calculated; 3, the minimum miscible pressure of crude oil of different oil reservoirs in the target basin is obtained, and the types of carbon dioxide flooding of the oil reservoirs in the basin are divided; and 4, obtaining a source-sink distance, screening the annual gas injection amount obtained in the step 2 and the mixed phase type in the step 3, and planning the basin-level carbon dioxide gas injection and flooding capability. According to the method, the problems of long period and poor applicability of existing basin-level CCUS carbon dioxide gas injection capacity prediction are solved.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field development technology, specifically relating to a basin-level carbon dioxide injection capacity planning method. Background Technology

[0002] Carbon capture, utilization, and storage (CCUS) technology is one of the important pathways for the low-carbon development of coal-fired power, and the large-scale development of coal-fired power CCUS is one of the key measures for the low-carbon transformation of the power industry. The rational deployment of CCUS projects requires optimal planning and layout in advance, and source-sink matching of CCUS projects. The optimization results of source-sink matching are crucial for the future large-scale deployment of CCUS projects.

[0003] In the planning and design of basin-level CCUS (Carbon Dioxide Injection System), hundreds of small reservoirs and blocks are typically involved, resulting in complex reservoir types. When planning and designing different reservoirs separately, basin-level reservoir numerical simulation methods are mainly used to predict and plan the basin-level carbon dioxide injection capacity. Through detailed geological modeling, accurate input of reservoir fluid properties, and extensive reservoir history fitting, a large amount of basic static and dynamic data is collected and organized to optimize parameters for different reservoirs. The accuracy depends on the accuracy of the basic data and is also affected by factors such as the subjectivity of history fitting. This results in a long planning cycle and poor applicability. Summary of the Invention

[0004] The purpose of this invention is to provide a basin-level carbon dioxide injection capacity planning method, which solves the problems of long cycle and poor applicability in existing basin-level CCUS carbon dioxide injection capacity planning.

[0005] The technical solution adopted in this invention is a basin-level carbon dioxide injection capacity planning method, which is implemented according to the following steps:

[0006] Step 1: Collect basic data parameters of different reservoirs in the target basin;

[0007] Step 2: Based on the data parameters obtained in Step 1, establish a mathematical model for the annual gas injection volume of carbon dioxide flooding in the reservoir, and calculate the annual gas injection volume for different reservoirs.

[0008] Step 3: Obtain the minimum miscibility pressure of crude oil from different reservoirs in the target basin and classify the carbon dioxide flooding type of the reservoirs in the basin.

[0009] Step 4: Obtain the source-sink distance, filter the annual gas injection volume obtained in Step 2 and the miscibility type in Step 3, and plan the basin-level carbon dioxide flooding gas injection capacity.

[0010] The invention is further characterized by:

[0011] Step 1: Based on the target basin reservoir development plan, obtain basic data parameters including geological reserves, crude oil density, crude oil volume factor, formation pressure, and formation temperature of different reservoirs and blocks.

[0012] Step 2 is as follows:

[0013] Based on the empirical formula method, a mathematical model for the relationship between geological reserves and annual gas injection volume is established, namely, the annual gas injection volume of carbon dioxide flooding in different oil reservoirs. The calculation formula is as follows:

[0014]

[0015] Among them, Q i E represents the carbon dioxide injection volume for the i-th reservoir in one year, in tens of thousands of tons. i Let ρ be the geological reserves of the i-th oil reservoir, in tens of thousands of tons; gi Let be the underground carbon dioxide density of the i-th reservoir under the average pressure, in g / cm³. 3 B oi Let be the formation crude oil volume factor under the original formation pressure of the i-th reservoir, in g / cm³. 3 ;ρ oi Let be the density of the surface degassed crude oil in the i-th reservoir, in g / cm³. 3 .

[0016] In step 2, for undeveloped reservoirs, the reserves are estimated by combining the predicted area of ​​the actual undeveloped reservoirs with the reserve abundance of similar blocks; then, relevant parameters of reservoirs in the same development stratum similar to the target reservoir are referenced, including crude oil density, crude oil volume factor, formation pressure and formation temperature, and the formation density of carbon dioxide is obtained based on the formation pressure and formation temperature.

[0017] Step 3 is as follows:

[0018] Step 3.1: For reservoirs or blocks where the minimum miscibility pressure is tested using the capillary tube method, the result of the capillary tube test is the minimum miscibility pressure; for reservoirs where the capillary tube test cannot be carried out, the minimum miscibility pressure is calculated using the empirical formula method.

[0019] Step 3.2: Using the minimum miscibility pressure of different reservoirs or blocks obtained in Step 3.1, and combining it with the formation pressure of the corresponding reservoir in Step 1, the reservoir miscibility type is classified.

[0020] In step 3.1, the empirical formula method uses the NPC calculation formula or a modified NPC formula for calculation.

[0021] In step 3.2, when the formation pressure is greater than the minimum miscibility pressure, it is miscible flooding; otherwise, it is immiscible flooding. Finally, different reservoirs are divided into two major categories according to carbon dioxide miscible flooding and immiscible flooding.

[0022] Step 4 is as follows: The source-sink distance is the distance between the carbon source and the oil reservoir, with 200 km as the benchmark and an annual gas injection volume of 500,000 tons as the benchmark; when planning, 5 years is used as the near term, 10 years as the medium term, and 20 years as the long term.

[0023] In step 4, when the reservoir simultaneously meets the three conditions of source-sink distance not exceeding 200 km, miscible flooding, and annual gas injection capacity exceeding 500,000 tons, carbon dioxide flooding is carried out using the near-term plan; when the reservoir meets two of the three conditions, carbon dioxide flooding is carried out using the medium-term plan; when the reservoir meets only one of the three conditions, carbon dioxide flooding is carried out using the long-term plan; when the reservoir does not meet any of the three conditions, it is not suitable for carbon dioxide flooding and is not within the scope of the planning and design.

[0024] In step 3.1, the minimum miscibility pressure is calculated using the American NPC method. The NPC calculation formula is as follows:

[0025] MMP=-329.558+(7.727*MW*1.005 T )-(4.377*MW) (2)

[0026]

[0027]

[0028] Where MMP is the minimum miscibility pressure, Psi (1Psi = 1 / 145MPa); MW is the carbon content in the surface degassed crude oil. 5+ Average molecular weight; T is reservoir temperature, °F; ρ o Density of degassed crude oil at ground surface, g / cm³ 3 .

[0029] The beneficial effects of this invention are as follows: The basin-level carbon dioxide injection capacity planning method of this invention establishes a mathematical model of the annual injection volume of basin-level carbon dioxide flooding, which enables more efficient and scientific planning and design of basin-level CCUS carbon dioxide injection capacity. It has a short planning cycle, low cost, and strong applicability, and is of great significance for achieving the best matching optimization of CCUS project sources and sinks and promoting the industrial application of CCUS. Attached Figure Description

[0030] Figure 1 This is a schematic diagram of the basin carbon dioxide flooding plan in Embodiment 3 of the present invention. Detailed Implementation

[0031] The present invention will now be described in detail with reference to the accompanying drawings and specific embodiments.

[0032] Example 1

[0033] The basin-level carbon dioxide injection capacity planning method of this invention is implemented according to the following steps:

[0034] Step 1: Collect basic data parameters of different reservoirs in the target basin;

[0035] Step 2: Based on the data parameters obtained in Step 1, establish a mathematical model for the annual gas injection volume of carbon dioxide flooding in the reservoir, and calculate the annual gas injection volume for different reservoirs.

[0036] Step 3: Obtain the minimum miscibility pressure of crude oil in different reservoirs and classify the types of carbon dioxide flooding for reservoirs in the basin.

[0037] Step 4: Obtain the source-sink distance, filter the annual gas injection volume obtained in Step 2 and the miscibility type in Step 3, and plan the basin-level carbon dioxide flooding gas injection capacity.

[0038] Example 2

[0039] The basin-level carbon dioxide injection capacity planning method of this invention is implemented according to the following steps:

[0040] Step 1: Collect basic data parameters of different reservoirs in the target basin;

[0041] Based on the target basin reservoir development plan, the basic data parameters obtained include geological reserves, crude oil density, crude oil volume factor, formation pressure, and formation temperature of different reservoirs and blocks.

[0042] Step 2: Based on the data parameters obtained in Step 1, establish a mathematical model for the annual gas injection volume of carbon dioxide flooding in the reservoir, and calculate the annual gas injection volume for different reservoirs.

[0043] Based on the empirical formula method, a mathematical model for the relationship between geological reserves and annual gas injection volume is established, namely, the annual gas injection volume of carbon dioxide flooding in different oil reservoirs. The calculation formula is as follows:

[0044]

[0045] Among them, Q i E represents the carbon dioxide injection volume for the i-th reservoir in one year, in tens of thousands of tons. i Let ρ be the geological reserves of the i-th oil reservoir, in tens of thousands of tons; gi Let be the underground carbon dioxide density of the i-th reservoir under the average pressure, in g / cm³. 3 B oi Let be the formation crude oil volume factor under the original formation pressure of the i-th reservoir, in g / cm³. 3 ;ρ oi Let be the density of the surface degassed crude oil in the i-th reservoir, in g / cm³. 3 .

[0046] For undeveloped oil reservoirs, the reserves are estimated by combining the predicted area of ​​the actual undeveloped oil reservoirs with the reserve abundance of similar blocks; then, relevant parameters of oil reservoirs in the same development stratum similar to the target oil reservoir are referenced, including crude oil density, crude oil volume factor, formation pressure and formation temperature, and the formation density of carbon dioxide is obtained based on the formation pressure and formation temperature.

[0047] Step 3: Obtain the minimum miscibility pressure of crude oil from different reservoirs in the target basin and classify the carbon dioxide flooding type of the reservoirs in the basin.

[0048] Step 3.1: For reservoirs or blocks where the minimum miscibility pressure is tested using the capillary tube method, the result of the capillary tube test is the minimum miscibility pressure; for reservoirs where the capillary tube test cannot be carried out, the minimum miscibility pressure is calculated using the empirical formula method.

[0049] In step 3.1, the empirical formula method uses the NPC calculation formula or a modified NPC formula for calculation.

[0050] Step 3.2: Using the minimum miscibility pressure of different reservoirs or blocks obtained in Step 3.1, and combining it with the formation pressure of the corresponding reservoir in Step 1, the reservoir miscibility type is classified.

[0051] When the formation pressure is greater than the minimum miscibility pressure, it is called miscible flooding; otherwise, it is called immiscible flooding. Ultimately, different reservoirs are divided into two major categories according to carbon dioxide miscible flooding and immiscible flooding.

[0052] Step 4: Obtain the source-sink distance, filter the annual gas injection volume obtained in Step 2 and the miscibility type in Step 3, and plan the basin-level carbon dioxide flooding gas injection capacity.

[0053] The source-sink distance is the distance between the carbon source and the oil reservoir, with 200 km as the benchmark and an annual gas injection volume of 500,000 tons as the benchmark. When planning, 5 years is used as the near term, 10 years as the medium term, and 20 years as the long term.

[0054] Example 3

[0055] Based on Example 2, step 4 of this invention plans the basin-level carbon dioxide flooding and injection capacity, such as... Figure 1 As shown:

[0056] When an oil reservoir simultaneously meets the three conditions of a source-sink distance not exceeding 200 km, miscible flooding, and an annual gas injection capacity exceeding 500,000 tons, it is considered a reservoir. Figure 1 In area a, carbon dioxide flooding will be carried out using the near-term plan.

[0057] When the reservoir meets two of the three conditions, a medium-term plan is adopted to carry out carbon dioxide flooding.

[0058] Figure 1Region b in the text indicates a source-sink distance of no more than 200 km, non-miscible drive, and an annual gas injection capacity of more than 500,000 tons; Figure 1 Region c in the text indicates a source-sink distance exceeding 200 km, a mixed-phase drive, and an annual gas injection capacity exceeding 500,000 tons; Figure 1 The d region in the text represents a source-sink distance of no more than 200 km, a mixed-phase drive, and an annual gas injection capacity of no more than 500,000 tons.

[0059] When the reservoir meets only one of the three conditions, a long-term plan is adopted to carry out carbon dioxide flooding.

[0060] Figure 1 The region 'e' in the text indicates a source-sink distance of no more than 200 km, non-miscible drive, and an annual gas injection capacity of no more than 500,000 tons; Figure 1 The f region in the text represents a source-sink distance exceeding 200 km, a mixed-phase drive, and an annual gas injection capacity not exceeding 500,000 tons; Figure 1 The g region in the text represents a source-sink distance of more than 200 km, non-miscible drive, and an annual gas injection capacity of more than 500,000 tons.

[0061] Figure 1 The h region in the diagram indicates that when none of the three conditions of the reservoir are met, it is not suitable for carbon dioxide flooding and is not within the scope of planning and design.

[0062] Example 4

[0063] A basin B containing 20 oil reservoirs was selected. The basin-level carbon dioxide injection capacity planning method of this invention was implemented according to the following steps:

[0064] Step 1: Collect basic data parameters for different reservoirs in the target basin; including geological reserves, formation crude oil density, formation crude oil volume factor, formation pressure, and formation temperature of the reservoirs (blocks), as shown in Table 1 below:

[0065] Table 1 shows the basic physical property parameters of different oil reservoirs within the basin.

[0066]

[0067]

[0068] Step 2: Based on the data parameters obtained in Step 1, establish a mathematical model for the annual gas injection volume of carbon dioxide flooding in the reservoir, calculate the annual gas injection volume of different reservoirs, and obtain the annual carbon dioxide injection capacity of different reservoirs in the basin, as shown in Table 2 below:

[0069] Table 2 shows the annual carbon dioxide injection capacity of different reservoirs within the basin.

[0070] Serial Number reservoir name Annual gas injection capacity: 104t 1 A1 53.9 2 A2 22.8 3 A3 104.6 4 A4 124.4 5 A5 230.1 6 A6 12.2 7 A7 42.5 8 A8 159.8 9 A9 15.1 10 A10 37.4 11 A11 48.2 12 A12 33.3 13 A13 48.4 14 A14 26.2 15 A15 61.3 16 A16 110.5 17 A17 372.9 18 A18 18.7 19 A19 20.6 20 A20 88.6

[0071] Step 3: Obtain the minimum miscibility pressure of crude oil in different reservoirs and classify the types of carbon dioxide flooding for reservoirs in the basin.

[0072] Assuming that the minimum miscibility pressure has not been determined by capillary tests in different reservoirs within the basin, the minimum miscibility pressure is calculated using the American NPC method. The NPC calculation formula is as follows:

[0073] MMP=-329.558+(7.727*MW*1.005 T )-(4.377*MW) (2)

[0074]

[0075] Where MMP is the minimum miscibility pressure, Psi (1Psi = 1 / 145MPa); MW is the carbon content in the surface degassed crude oil. 5+ Average molecular weight; T is reservoir temperature, °F; ρ o Density of degassed crude oil at ground surface, g / cm³ 3 .

[0076] Table 3 below shows the prediction results of minimum miscibility pressure and the classification of oil displacement types for different reservoirs in the basin.

[0077] Table 3 shows the predicted minimum miscibility pressures and classification of oil displacement types for different reservoirs in the basin.

[0078]

[0079]

[0080] Step 4: Obtain the source-sink distance, filter the annual gas injection volume obtained in Step 2 and the miscibility type in Step 3, and plan the basin-level carbon dioxide flooding gas injection capacity.

[0081] The distances to carbon sources in different reservoirs within the basin are shown in Table 4.

[0082] Table 4 shows the statistical table of carbon source distances for different oil reservoirs in the basin.

[0083]

[0084] Table 5 shows the overall planning statistics for carbon dioxide flooding in different reservoirs within the basin:

[0085] Table 5 is a statistical table of the overall carbon dioxide flooding plan for different reservoirs in the basin.

[0086]

[0087] Table 6 shows the statistics of the recent planning for carbon dioxide flooding in the basin:

[0088] Table 6 is a statistical table of the recent planning for carbon dioxide flooding in the basin.

[0089]

[0090]

[0091] Table 6 outlines the near-term plan: 6 oil reservoirs with an annual gas injection capacity of 10.516 million tons.

[0092] Table 7 shows the statistics for the medium-term planning of carbon dioxide flooding in the basin:

[0093] Table 7 is a statistical table of the medium-term plan for carbon dioxide flooding in the basin.

[0094] reservoir name <![CDATA[Annual gas injection capacity, 10 4 t]]> A3 104.6 A6 12.2 A11 48.2 A15 61.3 A19 20.6 A20 88.6 total 335.4

[0095] Table 7 Mid-term plan: 6 oil reservoirs, with an annual gas injection capacity of 3.354 million tons.

[0096] Table 8 shows the statistics for the long-term carbon dioxide flooding plan in the basin:

[0097] Table 8 is a statistical table of the long-term carbon dioxide diversion plan for the basin.

[0098] reservoir name <![CDATA[Annual gas injection capacity, 10 4 t]]> A2 22.8 A7 42.5 A10 37.4 A13 48.4 A14 26.2 A18 18.7 total 196.0

[0099] Table 8 Long-term plan: 6 oil reservoirs, with an annual gas injection capacity of 1.96 million tons.

[0100] This invention presents a basin-level carbon dioxide injection capacity planning method. The required geological reserves and formation fluid properties are the most fundamental static data for reservoir development. Compared to conventional numerical simulation methods and reservoir engineering methods, which require large amounts of static and dynamic production data, this method is not limited by reservoir type, lithology, or development stage. Besides basin-level CCUS annual injection capacity planning, it can also be used for regional (provincial, municipal) or single-reservoir carbon dioxide flooding annual injection capacity planning. This basin-level carbon dioxide injection capacity planning method only requires static reservoir parameters to design CCUS planning capacity, featuring high efficiency and wide applicability. Data acquisition is simple, and compared to numerical simulation methods, it greatly improves planning efficiency. It effectively solves the problem of high prediction difficulty in basin-level CCUS source-sink matching, and has positive significance for accelerating the large-scale application of CCUS.

Claims

1. A basin-level carbon dioxide injection capacity planning method, characterized in that, The specific steps are as follows: Step 1: Collect basic data parameters of different reservoirs in the target basin; Step 2: Based on the data parameters obtained in Step 1, establish a mathematical model for the annual gas injection volume of carbon dioxide flooding in the reservoir, and calculate the annual gas injection volume for different reservoirs. Step 3: Obtain the minimum miscibility pressure of crude oil from different reservoirs in the target basin and classify the carbon dioxide flooding type of the reservoirs in the basin. Step 4: Obtain the source-sink distance, filter the annual gas injection volume obtained in Step 2 and the miscibility type in Step 3, and plan the basin-level carbon dioxide flooding gas injection capacity.

2. The basin-level carbon dioxide injection capacity planning method according to claim 1, characterized in that, Step 1: Based on the target basin reservoir development plan, obtain basic data parameters including geological reserves, crude oil density, crude oil volume factor, formation pressure, and formation temperature of different reservoirs and blocks.

3. The basin-level carbon dioxide injection capacity planning method according to claim 1, characterized in that, Step 2 is as follows: Based on the empirical formula method, a mathematical model for the relationship between geological reserves and annual gas injection volume, i.e., the annual gas injection volume of reservoir carbon dioxide flooding, is established. The calculation formula is as follows: Among them, Q i E represents the carbon dioxide injection volume for the i-th reservoir in one year, in tens of thousands of tons. i Let ρ be the geological reserves of the i-th oil reservoir, in tens of thousands of tons; gi Let be the underground carbon dioxide density of the i-th reservoir under the average pressure, in g / cm³. 3 B oi Let be the formation crude oil volume factor under the original formation pressure of the i-th reservoir, in g / cm³. 3 ;ρ oi Let be the density of the surface degassed crude oil in the i-th reservoir, in g / cm³. 3 .

4. The basin-level carbon dioxide injection capacity planning method according to claim 3, characterized in that, In step 2, for undeveloped reservoirs, the reserves are estimated by combining the predicted area of ​​the actual undeveloped reservoirs with the reserve abundance of similar blocks; then, relevant parameters of reservoirs in the same development stratum similar to the target reservoir are referenced, including crude oil density, crude oil volume factor, formation pressure and formation temperature, and the formation density of carbon dioxide is obtained based on the formation pressure and formation temperature.

5. The basin-level carbon dioxide injection capacity planning method according to claim 1, characterized in that, Step 3 is as follows: Step 3.1: For reservoirs or blocks where the minimum miscibility pressure is tested using the capillary tube method, the result of the capillary tube test is the minimum miscibility pressure; for reservoirs where the capillary tube test cannot be carried out, the minimum miscibility pressure is calculated using the empirical formula method. Step 3.2: Using the minimum miscibility pressure of different reservoirs or blocks obtained in Step 3.1, and combining it with the formation pressure of the corresponding reservoir in Step 1, the reservoir miscibility type is classified.

6. The basin-level carbon dioxide injection capacity planning method according to claim 5, characterized in that, In step 3.1, the empirical formula method uses the NPC calculation formula or a modified NPC formula for calculation.

7. The basin-level carbon dioxide injection capacity planning method according to claim 5, characterized in that, In step 3.2, when the formation pressure is greater than the minimum miscibility pressure, it is miscible flooding; otherwise, it is immiscible flooding. Finally, different reservoirs are divided into two major categories according to carbon dioxide miscible flooding and immiscible flooding.

8. The basin-level carbon dioxide injection capacity planning method according to claim 1, characterized in that, Step 4 is as follows: The source-sink distance is the distance between the carbon source and the oil reservoir, with 200 km as the benchmark and an annual gas injection volume of 500,000 tons as the benchmark; when planning, 5 years is used as the near term, 10 years as the medium term, and 20 years as the long term.

9. The basin-level carbon dioxide injection capacity planning method according to claim 8, characterized in that, In step 4, when the reservoir simultaneously meets the three conditions of source-sink distance not exceeding 200 km, miscible flooding, and annual gas injection capacity exceeding 500,000 tons, carbon dioxide flooding is carried out using the near-term plan; when the reservoir meets two of the three conditions, carbon dioxide flooding is carried out using the medium-term plan; when the reservoir meets only one of the three conditions, carbon dioxide flooding is carried out using the long-term plan; when the reservoir does not meet any of the three conditions, it is not suitable for carbon dioxide flooding and is not within the scope of the planning and design.

10. The basin-level carbon dioxide injection capacity planning method according to claim 6, characterized in that, In step 3.1, the minimum miscibility pressure is calculated using the American NPC method. The NPC calculation formula is as follows: MMP=-329.558+(7.727*MW*1.005 T )-(4.377*MW) (2) Where MMP is the minimum miscibility pressure, Psi (1Psi = 1 / 145MPa); MW is the carbon content in the surface degassed crude oil. 5+ Average molecular weight; T is reservoir temperature, °F; ρ o Density of degassed crude oil at ground surface, g / cm³ 3 .

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