Method for determining remote source natural gas reservoir forming power adjusting conditions

Abstract

The invention belongs to the technical field of geological evaluation of natural gas exploration and development, and discloses a method for determining reservoir forming power adjustment conditions of far-source natural gas. Comprising the steps of determining the natural gas reservoir forming period of a research interval, determining the buoyancy reservoir forming critical physical property boundary of the sandstone reservoir, carrying out reservoir physical property evolution recovery, determining the densification time of a target reservoir, establishing a reservoir physical property-filling power model and determining the natural gas buoyancy filling reservoir forming power condition in an adjustment period. Based on the method for adjusting the filling reservoir forming power condition of the far-source natural gas, a geological basis is provided for work such as favorable area evaluation, exploration deployment and reserve calculation.

Description

Technical Field

[0001] The present invention belongs to the technical field of geological evaluation in natural gas exploration and development, and particularly relates to a method for determining the dynamic conditions for the adjusted accumulation of far-source natural gas. Background Art

[0002] In recent years, natural gas exploration has been continuously advancing from the middle-shallow layers to the deep layers. In the eastern region of China, the tectonic movement of oil and gas-bearing basins is active, and adjusted and reformed gas reservoirs are well-developed, which is a key area for natural gas exploration and development. However, continental deep reservoirs often have strong heterogeneity. There is no effective research and technical method for how natural gas overcomes the injection resistance of heterogeneous tight reservoirs and realizes differential enrichment and accumulation, that is, the dynamic lower limit of the adjusted enrichment and accumulation of natural gas. Summary of the Invention

[0003] In order to overcome the deficiencies of the prior art, the present invention provides a method for determining the dynamic conditions for the adjusted accumulation of far-source natural gas, and provides a geological basis for work such as favorable area evaluation, exploration deployment, and reserve calculation based on the method for the dynamic conditions of the adjusted injection and accumulation of far-source natural gas provided by the present invention.

[0004] The above object of the present invention is achieved by the following technical solutions: A method for determining the dynamic conditions for the adjusted accumulation of far-source natural gas, the steps are as follows:

[0005] 1. Determine the gas accumulation periods of the research intervals;

[0006] 2. On the basis of step 1, define the critical physical property boundaries for buoyancy accumulation of sandstone reservoirs;

[0007] 3. Carry out the restoration of the evolution of reservoir physical properties to determine the densification time of the target reservoir;

[0008] 4. Establish a reservoir physical property - injection dynamic model to determine the dynamic conditions for buoyancy injection and accumulation of natural gas during the adjustment period.

[0009] Further, step 1 is to determine the gas accumulation periods of the research intervals based on the regional geological background, relevant research, and basin simulation software.

[0010] Further, the model of the basin simulation software is Basin Mod 2015.

[0011] Further, step 2 is specifically:

[0012] (1) Establish a mathematical relationship model between natural gas injection power and resistance to determine the pore throat radius ratio of the reservoir, where the mathematical relationship model between natural gas injection power and resistance is established using Equation 1 and Equation 2;

[0013] Buoyancy generated in a single pore:

[0014]

[0015] Capillary resistance in the throat:

[0016]

[0017] Among them, F 浮 — Buoyancy force, N; F 阻 — Capillary resistance, N; P c — Capillary force, N; r — Throat radius, μm, R — Pore radius, μm, ρ w — Formation water density, kg / m 3 ; ρ g — Natural gas density under formation conditions, kg / m 3 ; α — Formation dip angle, °; g — Acceleration due to gravity, m / s 2 ; δ — Gas-water interfacial tension, N / m; θ — Gas-water contact angle, °;

[0018] (2) Establish models such as temperature-pressure - interfacial tension based on the experimental data in step (1), and determine the interfacial tension and gas density parameters based on the paleo-temperature and pressure conditions during the hydrocarbon accumulation period;

[0019] (3) Determine the physical property boundaries for natural gas buoyancy accumulation in the study area based on the data obtained in steps (1) and (2).

[0020] Furthermore, the specific steps of step 3 are as follows:

[0021] (1) Determine the reservoir physical property differences and clarify the types of tight reservoirs;

[0022] (2) Quantitatively restore the physical property evolution process of the tight reservoir and determine the densification time.

[0023] Furthermore, the specific steps of step 4 are as follows:

[0024] (1) Based on the high-pressure mercury injection experimental data of samples with different physical properties, establish a non-wetting phase saturation - mercury injection pressure relationship model;

[0025] (2) Convert the mercury injection pressure into the gas column height or trap amplitude under formation conditions.

[0026] The beneficial effects of the present invention compared with the prior art are as follows: Based on the method for adjusting the charging and accumulation dynamic conditions of far-source natural gas provided by the present invention, it provides a geological basis for work such as favorable area evaluation, exploration deployment, and reserve calculation. Description of the Drawings

[0027] The present invention will be further described below in conjunction with the drawings and specific embodiments

[0028] Figure 1It is to study the characteristics of natural gas accumulation in the Denglouku Formation in the study area. Among them, a-b is the microscopic fluorescence characteristic diagram of fluid inclusions; c is the distribution diagram of the homogenization temperature of inclusions; d is the burial history-thermal history-hydrocarbon generation history diagram;

[0029] Figure 2 It is the diagram of the relationship between pore-throat radius of sandstone reservoirs in the study area;

[0030] Figure 3 It is the calculation model diagram of parameters such as interfacial tension and gas density;

[0031] Figure 4 It is the diagram for determining the critical throat radius of buoyancy injection and accumulation of natural gas in the Denglouku Formation in the study area;

[0032] Figure 5 It is the schematic diagram for determining the critical physical property value of buoyancy injection based on the relationship between the average throat radius of the reservoir and physical properties;

[0033] Figure 6 It is the schematic diagram of the diagenetic sequence and porosity recovery of fine sandstone reservoirs in the Denglouku Formation of the Fulongquan Structure;

[0034] Figure 7 It is the schematic diagram of capillary pressure corresponding to a gas saturation of 50% in the Denglouku Formation in the Fulongquan area;

[0035] Figure 8 It is the closed height diagram under formation conditions corresponding to a gas saturation of 50% in the Denglouku Formation in the Fulongquan area. Specific implementation mode

[0036] The present invention will be described in detail below through specific embodiments, but the protection scope of the present invention is not limited. Unless otherwise specified, the experimental methods adopted in the present invention are all conventional methods, and the experimental equipment, materials, reagents, etc. used can all be obtained from commercial channels.

[0037] Example 1

[0038] A method for determining the dynamic conditions of adjusted hydrocarbon accumulation of far-source natural gas

[0039] The first step: Determine the hydrocarbon accumulation periods of deep natural gas.

[0040] (1) Based on the regional geological background and related research, it is determined that the trap finalization period in the study area is the structural inversion stage at the end of the Mingshui Formation; at the same time, by means of basin simulation software (Basin Mod 2015), the hydrocarbon generation evolution of the main source rock (Shahezi Formation) is restored, indicating that the period of large-scale gas generation is at the end of the Nenjiang Formation (72 Ma);

[0041] (2) Hydrocarbon inclusions are well developed in the Denglouku Formation, mainly occurring in quartz fractures and cutting through the secondary enlargement margin of quartz. Blue - blue - white fluorescent inclusions are dominant, reflecting the injection of high - maturity oil and gas. The main peak of the homogenization temperature distribution of fluid inclusions is 120 - 130 °C ( Figure 1 a - c). Combining the analysis of burial history - thermal history - trap formation history, the gas accumulation period of the target interval is the end of the Mingshui Formation (about 65 Ma) ( Figure 1 d).

[0042] Step 2: Define the critical physical property limit for buoyancy - driven hydrocarbon accumulation in sandstone reservoirs.

[0043] (1) For conventional reservoirs, natural gas migrates and accumulates along the resultant force direction of buoyancy, capillary resistance, and its own gravity under the action of buoyancy. Buoyancy is the main driving force for hydrocarbon migration and accumulation. For typical tight sandstone gas reservoirs, due to the sufficient tightness of the reservoir, the capillary resistance increases sharply, and buoyancy can no longer overcome the capillary resistance for migration. Most of them enter the tight reservoir under the action of other external forces such as hydrocarbon - generation pressurization, and the oil, gas, and water in the tight reservoir cannot be normally differentiated. The capillary force acting on the gas in the reservoir is related to the pore - throat radius, and the throat radius is related to the physical properties of the reservoir. Therefore, the physical properties of the reservoir when the buoyancy acting on the natural gas is equal to the capillary force can be regarded as the critical physical property limit of the tight sandstone reservoir in a specific area. Generally, natural gas in the study area mainly enters the sandstone reservoir vertically through faults and then undergoes a certain scale of lateral migration and accumulation. Since there is no constant - rate mercury injection data for the tight sandstone reservoir in the study area, the present invention establishes a mathematical relationship model of gas injection power and resistance (Equation 1, Equation 2) based on cast thin sections and combined with previous research results, and determines that the pore - throat radius ratio of the Denglouku Formation reservoir is 149 ( Figure 2 ).

[0044] For tight sandstone gas reservoirs, a theoretical physical model for dry gas injection is established, that is, the gas in the formation is regarded as an aggregate of numerous single bubbles, and a single bubble is taken as the research object. A single bubble in the formation is mainly affected by buoyancy and capillary resistance, and its own gravity can be ignored. Among them, buoyancy is affected by the formation dip angle, and the interfacial tension is affected by the pore - throat radius of the reservoir, contact angle, and surface tension.

[0045] Buoyancy generated in a single pore:

[0046]

[0047] Capillary resistance received in the throat:

[0048]

[0049] Among them, F 浮 — buoyancy, N; F 阻 — capillary resistance, N; P c— Capillary force, N; r— Throat radius, μm, R— Pore radius, μm, ρ w — Formation water density, kg / m 3 ; ρ g — Natural gas density under formation conditions, kg / m 3 ; α— Formation dip angle, °; g— Acceleration due to gravity, m / s 2 ; δ— Gas-water interfacial tension, N / m; θ— Gas-water contact angle, °

[0050] (2) Establish models such as temperature-pressure - interfacial tension based on existing experimental data, and determine parameters such as interfacial tension and gas density based on the paleo-temperature and pressure conditions during the hydrocarbon accumulation period.

[0051] According to the characteristics of the natural gas accumulation period in the Denglouku Formation, the corresponding paleo-temperature is 120 °C and the paleo-pressure is 25 MPa. Combining the relationships between gas density, interfacial tension, etc. and formation temperature and pressure conditions established by predecessors, the natural gas density under formation conditions during the hydrocarbon accumulation period is determined to be 200 kg / m 3 , and the gas-water interfacial tension is 0.03 N / m ( Figure 3 ).

[0052] (3) Based on the above basic data, determine the physical property boundaries for natural gas buoyancy accumulation in the study area.

[0053] When the buoyancy is equal to the capillary resistance, that is, the ratio of the two is 1, it corresponds to the critical upper limit of reservoir physical properties where buoyancy has no effect on gas migration. Below this boundary is a tight sandstone reservoir, where gas and water cannot undergo normal differentiation. Above this boundary is a conventional sandstone reservoir, where a conventional gas reservoir can form.

[0054] The critical throat radius for charging and accumulation under the action of natural gas buoyancy obtained by the above method is 0.8 μm. The high-pressure mercury injection experimental data of the reservoir shows that the throat radius of the reservoir is positively correlated with permeability. According to the value of the critical throat radius, the corresponding permeability value can be determined, that is, the permeability boundary for buoyancy accumulation is 1.0 mD; then, according to the relationship between porosity and permeability, the critical porosity value is determined to be 10% ( Figure 5 ).

[0055] Step 3: Restore the physical property evolution of the reservoir and determine the densification time.

[0056] (1) Determine the reservoir physical property differences and clarify the types of tight reservoirs.

[0057] Taking the permeability value of 1.0 mD and porosity of 10% as the physical property boundaries of tight reservoirs, it can be seen that the reservoirs in the Denglouku Formation of the Fulongquan Fault Depression have differential densification, the physical properties are positively correlated with the rock grain size, conventional reservoirs and tight reservoirs coexist, and the heterogeneity is strong.

[0058] (2) Quantitatively restore the physical property evolution process of tight reservoirs and determine the densification time.

[0059] First, the diagenetic evolution sequence of the sandstone reservoir of the Denglouku Formation was established ( Figure 6 The fine sandstone reservoir of the Denglouku Formation has undergone three major diagenetic types: compaction, cementation, and dissolution, which are specifically manifested in mechanical compaction, carbonate cementation, siliceous cementation, I / S mixed layers (autogenic clay cementation), and feldspar / rock fragments dissolution.

[0060] The late Nenjiang Formation in the study area was strongly squeezed in an east-west direction, and the controlling fault zone was strongly reversed. The Denglouku Formation began to reverse and uplift as a whole since the late Nenjiang Formation. The mechanical compaction lasted from the early diagenetic stage to the middle diagenetic A2 stage. The compaction was generally strong and gradually weakened after the overall uplift of the strata (about 72Ma). Carbonate cementation persisted from the intermediate diagenesis A1 stage to the intermediate diagenesis A2 stage (about 72 Ma). After the overall uplift of the stratum, carbonate cementation gradually weakened. Siliceous cementation was slightly earlier than carbonate cementation. From the intermediate diagenesis A1 stage to the intermediate diagenesis A2 stage, authigenic quartz crystals and quartz secondary enlarged edges were relatively developed. After the intermediate diagenesis A2 stage (about 75 Ma), siliceous cementation continued to decrease. I / S mixed-layer cementation existed in the intermediate diagenesis A2 stage (85-72 Ma), and the cementation was relatively strong. At the same time, the organic acid filling period of the Denglouku Formation was from the intermediate diagenesis A1 stage to the intermediate diagenesis A2 stage (about 82 Ma). In terms of the development characteristics of dissolution, the stage with a strong effect of feldspar / rock fragments dissolution in the Denglouku Formation reservoir was from the intermediate diagenesis A1 stage to the intermediate diagenesis A2 stage (about 82 Ma).

[0061] Then, the reservoir densification time ( Figure 6 ). Taking into account the differences in the diagenetic evolution sequence of the fine sandstone reservoir of the Denglouku Formation in the study area, combined with the diagenetic characteristics of the reservoir in each diagenetic stage and its influence on the pore development, the reservoir pore evolution was quantitatively restored and calculated. The results show that the fine sandstone reservoir of the Denglouku Formation has been compacted. The porosity recovery shows that the original porosity of the fine sandstone reservoir is 35%, and the compaction reduction in the geological history is 19.1%. Among the cementation reduction, the siliceous cementation reduction is 3.6%, the carbonate cementation reduction is 7.7%, and the dissolution increase is 5.4%. The current reservoir porosity is about 10%, and the densification time is about 72Ma.

[0062] The main accumulation period of natural gas in the Denglouku Formation is the late stage of the Mingshui Formation (about 65 Ma), which corresponds to the end of the deposition of the Mingshui Formation and is slightly later than the late adjustment accumulation period of natural gas. During the accumulation period, conventional reservoirs and tight reservoirs of the Denglouku Formation coexisted, with strong heterogeneity.

[0063] Step 4: Establish a reservoir physical property-charging dynamics model to determine the dynamic conditions for natural gas buoyancy charging and accumulation.

[0064] (1) Based on the high-pressure mercury injection experimental data of samples with different physical properties, establish a relationship model between the non-wetting phase (mercury or natural gas) saturation and mercury injection pressure (Sg = 50%)

[0065] In the process of natural gas charging and reservoir formation in the distal traps of the Denglouku Formation, buoyancy is the main factor, which is controlled by the height of the continuous gas column or the trap amplitude. The charging resistance is controlled by the physical properties of the reservoir. The better the physical properties, the lower the capillary resistance of the reservoir, and the easier it is for natural gas to charge and form a reservoir; conversely, it is not easy to form a reservoir. The high-pressure mercury injection process is a non-wetting mercury, which, under the drive of an external pressure, displaces the fluid in the reservoir pores and enters the reservoir, which can be regarded as the process of natural gas entering the reservoir under the drive of an external force. Select a series of reservoir samples with different physical properties and conduct high-pressure mercury injection experiments. Taking the mercury injection saturation of 50% as the benchmark, as the porosity of the sample increases from 3.9% to 14.4%, the corresponding mercury injection pressure decreases from 68.9 MPa to 1.9 MPa ( Figure 7 ). It can be seen that the better the physical properties of the reservoir, the lower the natural gas charging resistance.

[0066] (2) Convert the mercury injection pressure into the height of the gas column or the trap amplitude under formation conditions

[0067] Combined with the formation temperature and pressure conditions in the study area, convert the capillary pressure of mercury under experimental conditions into the capillary pressure of gas under formation conditions (Equations 3, 4, 5). When natural gas uses buoyancy as the charging power, the buoyancy size depends on the height of the continuous gas column or the closure height of the trap. The larger the closure height, the higher the continuous gas column that can be formed, the greater the buoyancy of natural gas, and the more capable it is to break through the higher capillary resistance of the reservoir and enter the reservoir pore space.

[0068]

[0069]

[0070]

[0071] The physical property boundary between the tight reservoir and the conventional reservoir in the study area is a porosity of 10%. Taking the gas saturation reaching 50% as the benchmark, for a conventional reservoir with a porosity of 10%, when the gas saturation reaches 50%, the required trap amplitude or continuous gas column height is 18 m ( Figure 8 ). The fine-grained sandstone in the Denglouku Formation of the Fulongquan Fault Depression was densified at the end of the Nenjiang Formation sedimentation, and the medium-coarse sandstone reservoir was not densified. This coexistence state of conventional-tight reservoirs has basically remained until now with the reverse uplift of the formation. Therefore, for the traps developed in the "coarse-grained facies" reservoirs of the Denglouku Formation in the Fulongquan area, the paleo-trap amplitude during the reservoir formation period is greater than 18 m, and high-gas-saturation gas layers can be formed.

[0072] Therefore, in the deep natural gas exploration of Denglouku Formation, when other geological conditions are approximately the same and the trap amplitude is greater than 18 m, it should have good gas-bearing property and can be used as the target for priority deployment.

[0073] The above-described embodiments are only the preferred embodiments of the present invention, rather than all the feasible embodiments of the present invention. For those of ordinary skill in the art, any obvious changes made without departing from the principle and spirit of the present invention should be considered to be included within the scope of protection of the claims of the present invention.

Claims

1. A method for determining the dynamic conditions of adjusted hydrocarbon accumulation of far - sourced natural gas, characterized in that, The steps are as follows: S1. Determine the gas accumulation periods of the research intervals. S2. On the basis of step S1, define the critical physical property limits for buoyancy-driven gas accumulation in sandstone reservoirs. S3. Conduct the restoration of reservoir physical property evolution and determine the densification time of the target reservoir. S4. Establish a reservoir physical property - injection dynamic model to determine the dynamic conditions for buoyancy-driven gas injection and accumulation during the adjustment period.

2. The method for determining the dynamic conditions of adjusted hydrocarbon accumulation of far - sourced natural gas according to claim 1, characterized in that, The above step S1 determines the gas accumulation periods of the research intervals based on the regional geological background, relevant research, and basin simulation software.

3. The method for determining the dynamic conditions of adjusted hydrocarbon accumulation of far - sourced natural gas according to claim 2, characterized in that, The model of the basin simulation software is Basin Mod 2015.

4. The method for determining the dynamic conditions of adjusted hydrocarbon accumulation of far - sourced natural gas according to claim 1, characterized in that, The specific content of step S2 is as follows: (1) Establish a mathematical relationship model between gas injection dynamics and resistance to determine the pore throat radius ratio of the reservoir. The mathematical relationship model between gas injection dynamics and resistance is established using Equation 1 and Equation 2. Buoyancy generated in a single pore: Capillary resistance in the throat: Among them, F 浮 — Buoyancy force, N; F 阻 — Capillary resistance, N; P c — Capillary force, N; r — Throat radius, μm, R — Pore radius, μm, ρ w — Formation water density, kg / m 3 ; ρ g — Natural gas density under formation conditions, kg / m 3 ; α — Formation dip angle, °; g — Acceleration due to gravity, m / s 2 ; δ — Gas-water interface tension, N / m; θ — Gas-water contact angle, °; (2) Establish a temperature - pressure - interfacial tension model based on the experimental data in step (1). Based on the paleo-temperature and pressure conditions during gas accumulation, determine the interfacial tension and gas density parameters. (3) Determine the physical property limits for buoyancy-driven gas accumulation in the study area based on the data obtained in steps (1) and (2).

5. The method for determining the dynamic conditions of adjusted hydrocarbon accumulation of far - sourced natural gas according to claim 1, characterized in that, The specific content of step S3 is as follows: (a) Determine the differences in reservoir physical properties and clarify the types of tight reservoirs. (b) Quantitatively restore the evolution process of tight reservoir physical properties and determine the densification time.

6. The method for determining the dynamic conditions of adjusted hydrocarbon accumulation of far - sourced natural gas according to claim 1, characterized in that, The specific content of step S4 is as follows: (A) Based on the high-pressure mercury injection experimental data of samples with different physical properties, establish a relationship model between non-wetting phase saturation and mercury injection pressure. (B) Convert the mercury injection pressure into the gas column height or trap amplitude under formation conditions.

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