Evaluation method for reservoir quality evolution after sandstone is filled with deep-source CO2

Abstract

The invention discloses a method for evaluating reservoir quality evolution after sandstone is filled with deep-source CO2, and belongs to the technical field of petroleum exploration. According to the method, the sandstone in the CO2 filling area is selected as a research object, the sandstone in the undisturbed area adjacent to the CO2 filling area is selected as a reference object, the porosity, permeability and pore structure difference of the sandstone reservoirs in the CO2 filling area and the undisturbed area are compared and analyzed, the diagenesis stages, symbiotic sequences and lithologic characteristics of the sandstone in the CO2 filling area and the undisturbed area are determined, and the sandstone in the CO2 filling area and the undisturbed area is determined. Carbon and oxygen isotope analysis is carried out on the carbonate cement, diagenesis fluid evolution characteristics and differences of the sandstone reservoirs in the CO2 filling area and the undisturbed area are compared and analyzed, and finally the reservoir quality evolution process after the sandstone is filled with the CO2 is clarified. According to the evaluation method, the deep CO2 source and the filling time are determined, the change of the mineral composition and the structure of the reservoir caused by CO2 filling is revealed, the mechanism of changing the reservoir quality by CO2 filling is clarified, and the problem that the time sequence of CO2 filling and organic hydrocarbon filling is not clear is solved.

Description

Technical Field

[0001] The present invention relates to the technical field of oil exploration, and particularly to an evaluation method for the evolution of reservoir quality after deep-source CO 2 is injected into sandstone reservoirs. Background Art

[0002] Carbon capture and storage has attracted extensive attention and consideration as an effective option for reducing CO 2 emissions. After carbon capture, it can be permanently fixed in reservoirs through mineral carbonation (MC). Mineral carbonation refers to the reaction of CO 2 with minerals containing divalent cations and a source of alkalinity (e.g., aluminosilicate minerals containing Ca and / or Mg ions) to form stable carbonate minerals. Natroalunite NaAlCO 3 (OH) 2 is a proxy mineral for the migration or accumulation of CO 2 in reservoirs and is considered an effective mineral for permanently trapping CO 2 in a system maintaining a high CO 2 partial pressure. Natroalunite usually forms in an alkaline to weakly acidic fluid environment rich in Na + and Al 3+ and having a high CO 2 partial pressure. When the high CO 2 partial pressure dissipates, natroalunite will dissolve.

[0003] CO 2 gas reservoirs have been recorded in many oil and gas bearing basins around the world, where natroalunite is widely developed. The CO 2 associated with the formation of natroalunite mainly has two sources: organic source and inorganic source. Organic sources include the decarboxylation of organic matter, the decomposition of type III kerogen in coal, and the contact metamorphism of coal. Inorganic sources include mantle magmatism and carbonate dissolution or pyrolysis. In most basins worldwide, the CO 2 associated with the formation of natroalunite mainly comes from the mantle (magma). For example, the BGS basin system in Australia, the Shabwa basin in Yemen, the Golfo San Jorge basin in Mexico, the San Jorge basin in Argentina, the Bohai Bay basin, the Songliao basin, the Hailar basin, and the Yinggehai basin in China.

[0004] It is reported that natroalunite has been discovered in the southern part of the Songliao basin, with d 13 C values ranging from 4.97‰ to 3.29‰, sourced from mantle magma, and the injection time is approximately 58.8 - 41 Ma. In contrast, the deep inorganic CO 2 associated with natroalite 2The charging time varies in other petroliferous basins in eastern China. For example, it is 110 - 85 Ma in the Hailar Basin. Mantle magma CO 2 The formation and distribution of mantle-derived CO 2 gas reservoirs and their associated dawsonite are mainly controlled by faults of different levels. The lithospheric activity and crustal faults cause mantle CO 2 to degas. CO

[0005] Previous studies mainly focused on isotope evidence of mantle origin 13 C, formation mechanisms, and the spatio-temporal distribution of the above-mentioned dawsonite and CO 2 sources, etc. CO 2 is an important component of the diagenetic fluid in petroliferous basins and has an important impact on reservoir quality. When deep inorganic CO 2 enters the sandstone reservoir, extensive CO 2 -water-rock interactions occur, further changing the reservoir conditions and being the main controlling factor leading to the complexity of reservoir conditions. However, only a few studies have focused on the time of deep inorganic CO 2 migration relative to hydrocarbon charging, and even fewer studies have analyzed the impact of deep inorganic CO 2 on hydrocarbon charging. Summary of the Invention

[0006] Aiming at the above problems, the present invention aims to provide an evaluation method for the evolution of reservoir quality after deep-source CO 2 charging into sandstone. Using the tracer mineral dawsonite as the research carrier, carry out research on the charging time of deep CO 2 and the evolution of diagenetic fluid, clarify the charging time of deep inorganic CO 2 and the characteristics and evolution history of diagenetic fluid, and reveal the transformation effect of deep inorganic CO 2 multiple charging on the reservoir. 2

[0007] To achieve the above object, the technical solution adopted by the present invention is as follows:

[0008] An evaluation method for the evolution of reservoir quality after deep-source CO 2 charging into sandstone, comprising the following steps:

[0009] S1: Select the sandstone in the CO 2 charging area as the research object, select the sandstone in the undisturbed area adjacent to the CO 2 charging area as the reference object, analyze the petrological characteristics of the sandstone reservoirs in the CO 2 charging area and the undisturbed area, and clarify the types, occurrence characteristics and content differences of authigenic minerals in the two types of reservoirs;

[0010] S2: Deep CO 2 The tracer mineral dawsonite was used as the research carrier to compare and analyze CO 2 The lithology and reservoir characteristics of sandstone reservoirs in the charged and undisturbed areas;

[0011] S3: Taking the original sandstone reservoir as a reference object, according to the comparison results of step S2, analyze the CO 2 The diagenesis caused by the filling, and the CO 2 The influence of diagenesis after filling on reservoir quality is determined by CO 2 Reservoir quality evolution after sandstone filling.

[0012] Furthermore, the petrological characteristics of the sandstone reservoir described in step S1 include clastic mineral composition and degree of diagenetic alteration.

[0013] Furthermore, the degree of diagenetic alteration includes quartz content, carbonate cementation type content and authigenic clay mineral type content.

[0014] Furthermore, the specific operation of step S2 includes the following steps:

[0015] S201: Comparative analysis of CO 2 Differences in porosity, permeability and pore structure between sandstone reservoirs in the charged and undisturbed areas;

[0016] S202: Determine CO 2 The respective diagenetic stages and paragenetic sequences of sandstones in the charge and undisturbed areas;

[0017] S203: Comparative analysis of CO 2 Carbon and oxygen isotopes of carbonate cements in sandstones of the filling zone and the original zone are used to determine the characteristics and sources of paleofluids related to the formation of carbonate cements in sandstones of the two zones;

[0018] S204: Targeting CO 2 Fluid inclusion analysis was carried out on the sandstone in the injection area and the sandstone in the original area to determine the injection time of the hydrocarbon fluid in the sandstone in the original area and the CO 2 CO in sandstone of injection area 2 and hydrocarbon charge time series;

[0019] S205: Comparative analysis of CO 2 The diagenetic fluid evolution characteristics and differences of sandstone reservoirs in the charging area and the original area are used to establish the diagenetic evolution paths of sandstone reservoirs in the two zones.

[0020] Further, the analysis of carbon and oxygen isotopes in step S203 includes the d 13 C、d 18 O.87 Sr / 86 Sr ratio.

[0021] Furthermore, the impact of diagenesis occurring after the CO 2 injection on reservoir quality is as follows: the inflow of deep inorganic CO 2 results in the deterioration of the sandstone water resources, reservoir quality, and deasphalting of crude oil in the CO 2 injection area, thus leading to low oil productivity.

[0022] The beneficial effects of the present invention are as follows:

[0023] The present invention uses the deep CO 2 tracer mineral dawsonite as the research carrier to conduct research on the deep CO 2 injection time and diagenetic fluid evolution, clarifying the deep inorganic CO 2 injection time, characteristics and evolution history of diagenetic fluids, revealing the transformation effect of deep inorganic CO 2 multiple injections on reservoir mineral composition and structure; clarifying the mechanism by which CO 2 injection changes reservoir quality. And it solves the problem of unclear timing of CO 2 injection and organic hydrocarbon injection. The results show that the inflow of deep inorganic CO 2 results in an increase in the mineralization of formation water in the CO 2 injection area, deasphalting of crude oil, deterioration of reservoir quality, and low single-well production, providing a theoretical support example reference for the reservoir quality evaluation of other similar oil and gas bearing basins in China. Description of the Drawings

[0024] Figure 1 This shows the general Mesozoic - Quaternary strata in the Songliao Basin and the detailed sedimentary facies of the fourth member of the Quantou Formation in the Lower Cretaceous of the present invention.

[0025] Figure 2 This is the ternary diagram of the sandstone rock composition in the original area and the CO 2 injection area of the present invention.

[0026] Figure 3 This shows the diagenetic characteristics of sandstone in the original area of the present invention.

[0027] Figure 4 This is the percentage of the total amount of clay minerals and the relative contents of illite, kaolinite, chlorite, and illite / smectite mixed layer (I / S) in sandstone in the original area and the CO 2 injection area of the present invention.

[0028] Figure 5 This shows the diagenetic characteristics of sandstone in the CO 2 injection area of the present invention.

[0029] Figure 6 Histogram of porosity and permeability of sandstone in the in-situ area and the CO 2 injection area studied in the present invention.

[0030] Figure 7 Porosity, permeability, primary apparent porosity, dissolution apparent porosity, microporosity, carbonate cement content, and quartz cement content in sandstone in the in-situ area and the CO 2 injection area of the present invention.

[0031] Figure 8 Microscopic photographs of fluid inclusions in sandstone in the in-situ area and the CO 2 injection area of the present invention.

[0032] Figure 9 Histogram of the homogenization temperature T of inclusions in sandstone in the in-situ area and the CO 2 injection area of the present invention. hs

[0033] Figure 10 Syngenetic sequence of the diagenetic history of sandstone in the in-situ area and the CO 2 injection area of the present invention.

[0034] Figure 11 Comparison chart of carbon isotopes of CO forming dawsonite in the study area of the present invention and inorganic / organic origin CO 2 2

[0035] Figure 12 Variation of Sr / 2 Sr ratio of carbonate cement in sandstone in the in-situ area and the CO 87 86 injection area of the present invention.

[0036] Figure 13 Deep fault and gas reservoir map in the study area of the present invention.

[0037] Figure 14 Crossplot of dawsonite, feldspar, and quartz cement in sandstone of the present invention.

[0038] Figure 15 Burial and thermal history map of Well Gu-27 of the present invention.

[0039] Figure 16 Crossplot of the relationship between carbonate cement and porosity and permeability of northern sandstone of the present invention.

[0040] Figure 17 Stability of dawsonite, Al(OH) 3 , kaolinite, and albite at 100 °C and 300 bar of the present invention.

[0041] Figure 18 For the mantle-derived CO in the present invention 2 The effects on the diagenesis and reservoir quality of sandstones in the CO2 injection area and the virgin area.

[0042] Figure 19 For the virgin area and CO in the present invention 2 Comparison diagram of the storage properties of clay content in sandstones in the injection area.

[0043] Figure 20 For the virgin area and CO in the present invention 2 Relationship between the visual dissolution porosity of sandstones in the injection area and the reservoir quality. Detailed implementation manners

[0044] In order to enable those of ordinary skill in the art to better understand the technical solutions of the present invention, the technical solutions of the present invention will be further described below with reference to the accompanying drawings and embodiments.

[0045] The present invention takes the sandstone reservoir of the Quantou Formation of the Lower Cretaceous in the southern Songliao Basin as an example to explain the specific implementation process of the research method for the influence of CO injection on the quality of sandstone reservoirs. 2

[0046] The fourth member of the Quantou Formation of the Lower Cretaceous (K 1q4 ) is the most important oil-bearing formation in the southern Songliao Basin. Overlying the Qingshankou Formation source rock and underlying the K 1q4 tight sandstone reservoir, a large-scale continuous lithologic oil reservoir with upper-source and lower-reservoir and relatively short source-reservoir distance is formed. The K 1q4 tight sandstone oil reservoir in the southern Songliao Basin has been put into development. By 2019, the cumulative proven oil reserves have reached 70 million tons, and the production capacity has reached 0.3 million tons. This study takes the K 2 tight sandstone with typical deep inorganic CO injection records in the southern Songliao Basin as the research object. Comparative studies were carried out on sandstone reservoirs in K 1q4 sandstones with and without dawsonite to determine the source and time of CO 1q4 related to dawsonite during intrusion, and the mechanism of its influence on reservoir quality was discussed. The research process mainly includes three steps: (1) establishing the paragenetic sequence of dawsonite-bearing sandstones through lithofacies analysis; (2) studying the time series of CO 2 during intrusion and hydrocarbon injection using fluid inclusion microthermometry; (3) estimating the CO 2 injection time by combining the burial-thermal history and homogenization temperature (T hs ) of hydrocarbon inclusions. 2

[0047] 1. Geological environment

[0048] The Songliao Basin is a large Mesozoic-Cenozoic sedimentary basin on the Northeast China Plate. The basin is tectonically divided into the northern and southern parts, including six major tectonic belts: the western slope belt, the northern depression belt, the central depression belt, the northeastern uplift belt, the southeastern uplift belt, and the southwestern uplift belt. The central depression belt is the main oil-producing area in the southern part of the Songliao Basin, covering four secondary tectonic units: the Honggang terrace, the Changling depression, the Huazijing terrace, and the Fuxin uplift. The study area is located in the southern part of the Fuxin uplift belt, with an area of ​​400km 2 The central part of the study area is the Gudian Fault, which is one of the three major reverse faults in the southern Songliao Basin and is located at the junction of the Changling Sag and the Central China Terrace. The Gudian Fault strikes NW and dips NNE. The plane extends for 25 km. The lower part of the fault is a normal fault and the upper part is a reverse fault. The lower part has a gentle dip and the upper part has a steep dip.

[0049] The evolution of the southern Songliao Basin has gone through three stages: syn-rift stage, post-rift stage, and tectonic and inversion stage. The tectonic stratigraphic units deposited during the syn-rift period include the Upper Jurassic Huoshiling Formation (K 1h ) pyroclastic rocks and pyroclastic rocks, the Lower Cretaceous Shahezi Formation (K 1sh ) and Yingcheng Group (K 1yc ) of alluvial fans, fan deltas, rivers, deltas and lake clastic sediments. 1d ), Quantou Group (K 1q ) and the Qingshankou Formation (K 2qn ), Yao Family Group (K 2y ), Nengjiang Group (K 2n ) represents a post-rift tectonic stratigraphic unit consisting of deltaic and deep lake sediments. 1d ) and Izumizu Group (K 1q ) is composed of fine-grained sandstone, siltstone, and mudstone deposited in fluvial deltaic and lacustrine environments. 2qn ), Yao Family Group (K 2y ), Nengjiang Group (K 2n ) are deltaic and deep lake sediments. 2s ) to Quaternary plain (Q) sediments (tectonic inversion, tectonic stratigraphic unit) are mainly composed of fine-grained fluvial deltaic clastic deposits.

[0050] Quantou Formation (K 1q ) is composed of thick fan delta and lacustrine sandstone deposited after the rift in the southern part of the Songliao Basin. It is located in the Qingshankou Formation (K 2qn ) directly below the thick source rock, thus forming an interesting source-reservoir system, with the source rock overlying the reservoir sandstone, as shown in the Figure 1 As shown, the research focus of this invention is the fourth section of the Quantou Formation (K 1q4 ), which is the main oil-bearing formation in the area.1q4 Mainly siltstone and fine-grained sandstone deposited in underwater distributary channels of the delta, with a small amount of siltstone and argillaceous sandstone deposited in fissure fan-shaped sandstone or sheet sandstone with relatively low hydrodynamic conditions, K 1q4 The hydrocarbon source in the sandstone is the first member of the Qingshankou Formation (K 2qn1 ).

[0051] 2. Research methods

[0052] The porosity of core plugs with a diameter of 2.5 cm in the reservoir interval was measured using an UltraPore-300 porosimeter. The permeability was measured in a gas autoclave using pressure transient techniques, with nitrogen as the permeating medium. Petrographic analysis was carried out on 31 reservoir sandstone samples from 5 wells (Gu 27, Qian 57, Qian 48, Qian 59, and Qian 61), and 10 samples were selected from them for XRD analysis of the whole sample and clay components. A total of 123 K 1q4 sandstone samples from 8 wells (Gu 27, Qian 39, Qian 57, Qian 48, Qian 59, Qian 61, Qian 68, and Qian 70) were studied for petrography in the depth interval of 1100 to 1300 m. Thin sections were impregnated with blue epoxy resin to highlight the pores. Then they were semi-stained with alizarin red S and potassium ferricyanide for carbonate mineral determination. The composition of the sandstone was statistically determined by counting 300 points on each thin section. Point counting was carried out on 15 representative thin sections provided by Jilin Oilfield Company to verify the compositional data collected from another 31 samples, with a standard deviation of 5.5%.

[0053] Petrographic (mineralogical and structural relationships) studies were carried out on six representative gold-coated sandstone samples using a Hitachi S-4800 scanning electron microscope (SEM) at an accelerating voltage of 20 kV. Double-polished wafers of fluid inclusions were cut from 10 sandstone samples for microthermometric measurements. Microthermometry of fluid inclusions was carried out using a Linkam THMSG600 heating and cooling stage, and the phase change temperature was in the range of 180 °C to 500 °C. T hs and the final ice temperature (T ms ) were determined using a calibrated heating and cooling stage. T hs and T msThe measured temperature accuracies are -1°C and -0.2°C respectively. The salinity of fluid inclusions is calculated according to Bodnar (1993). A total of 14 sandstone samples without organic matter were selected in this study, and oxygen, carbon, and strontium isotope analyses were carried out on their carbonate cements. Approximately 60 mg of powder samples were extracted for strontium isotope analysis. Strontium was further separated by conventional cation exchange techniques using ion exchange resin (filled with Bio-Rad AG 50W-X8). Neptune multi-collector inductively coupled plasma mass spectrometry (ICP-MS) was used to measure the Sr / Sr isotope ratio, with an accuracy of -0.007‰ relative to the US National Institute of Standards and Technology Standard Reference Material (NIST SRM) 987 reference standard solution.

[0054] For carbon and oxygen isotope ratios, CO₂ was extracted from the powder samples by reacting with 100% ultra-pure phosphoric acid in an inert atmosphere at 25°C for 2 hours (calcite) and more than 3 days for dawsonite (ankerite). 2 The extracted CO₂ 2 was transported to Thermo Finnigan MAT 253 and the isotope ratios were measured using the international standard NBS-18 (relative to Vienna Peedee Belemnite [VPDB], δ¹⁸O = -23.0‰ and δ¹³C = -5.01‰). Incremental values (δ¹³CO₂ = 442 and δ¹⁸CO₂ = 442) were corrected for the ¹⁷O effect, and the temperature-dependent kinetic oxygen isotope fractionation was adjusted using fractionation factors of 1.01025 and 1.01177 for calcite. For dawsonite-ankerite, the values are expressed in δ / mil notation relative to the VPDB standard. The uncertainty of the analysis was determined to be >0.15‰ by repeated measurements of GBW04405 (relative to VPDB, δ¹³C = +0.57‰ and δ¹⁸O = 8.49‰) and GBW04406 (δ¹³C = 10.85‰ and δ¹⁸O = 12.40‰). 18 O = -23.0‰ and d 13 C = -5.01‰). Incremental values (d CO 45 = 442 and d CO 46 = 442) were corrected for the 17 O effect, and the temperature-dependent kinetic oxygen isotope fractionation was adjusted using fractionation factors of 1.01025 and 1.01177 for calcite. For dawsonite-ankerite, the values are expressed in d / mil notation relative to the VPDB standard. By repeated measurements of GBW04405 (relative to VPDB, d 13 C = +0.57‰ and d 18 O = 8.49‰) and GBW04406 (d 13 C = 10.85‰ and d 18 O = 12.40‰), the uncertainty of the analysis was determined to be >0.15‰.

[0055] 3. Research Results

[0056] 3.1 Research Area Division

[0057] The K 1q4 sandstones in the study area were divided into in-situ sandstones and CO 2 -filled sandstones. The in-situ sandstones are normal sandstones, and the CO 2 -filled sandstones are deep CO 2The tracer mineral dawsonite is the research object. The original zone is located more than 10 km away from the Gudian Fault. The authigenic minerals in the sandstone are mainly quartz, mixed-layer I / S (illite / montmorillonite), kaolinite, illite, chlorite, ferrocalcite, ankerite, etc. CO 2 The injection zone is mainly distributed near the Gudian Fault (<7.8 km), and is mainly composed of quartz, mixed-layer I / S, illite, ankerite, and dawsonite. The burial depths of the two zones are the same, both 1100 - 1300 m, and there are significant differences in the types of carbonate cements, clay minerals, and reservoir quality.

[0058] 3.2 Detrital Mineral Composition

[0059] The original zone and CO 2 The results of the lithofacies analysis of the injection zone are shown in the appendix Figure 2 as follows. It can be seen from the appendix Figure 2 that the K 1q4 sandstones in these two zones are mainly lithic arkose and feldspathic litharenite, characterized by silt to medium sand grain size, mostly moderately to well sorted, and sub-angular to sub-rounded grains.

[0060] The diagenetic characteristics of the sandstone in the original zone are shown in the appendix Figure 3 as follows. In the sandstone of the original zone, the quartz grains are single crystals, and the quartz content is 25.8% - 52.2% (average 34.7%). The total feldspar content is 22% - 40% (average 32.4%), the potassium feldspar content is 15% - 30% (average 22.7%), and the plagioclase content is 7% - 17% (average 10.1%). The lithic content is 25% - 40% (average 33.2%), including volcanic rocks (14.6% - 38%, average 28.1%), sedimentary rocks (1% - 2%, average 1.3%), metamorphic rocks (1% - 2%, average 1.3%), and debris (1% - 12%, average 4.4%).

[0061] The original zone and CO 2 The modal component point count data of the injection zone are shown in Table 1 below (where the modal component values are expressed as percentages. The total content of detrital components, diagenetic minerals, and porosity is 100%, and the contents of quartz, feldspar, and lithic fragments in the detrital components are converted to 100%). It can be seen from Table 1 below that in the sandstone of the CO 2 injection zone, the detrital grains are mainly single-crystal quartz (content 30% - 58%, average 48.1%), showing wavy extinction. The total feldspar content ranges from 10% to 35% (average 21.7%), consisting of plagioclase (9% - 18%, average 13.7%) and potassium feldspar (1% - 18%, average 8.7%). The lithic composition ranges from 22% to 42% (average 30.2%), mainly volcanic fragments, with a small amount of sedimentary rock and metamorphic rock fragments. CO 2 The feldspar content in the sandstone of the injection zone is relatively lower than that in the sandstone of the original zone.

[0062] Table 1 Modal Component Statistics Summary of the Original Zone and the CO 2 Injection Zone

[0063]

[0064] 3.3 Diagenetic Alteration

[0065] The original zone and the CO 2 The degree of diagenetic alteration of sandstone in the injection zone is mainly reflected by the quartz content, carbonate cement type content, and authigenic clay mineral type content.

[0066] The characteristics of diagenetic minerals in the original zone sandstone are as follows: The authigenic carbonate cements in the original zone sandstone are composed of ferrocalcite (0% - 6.4%, average 1.1%) and ankerite (0% - 18.8%, average 2.2%). Both of these minerals have subhedral to euhedral crystals and can fill intergranular pores and secondary dissolution pores or replace quartz, feldspar, and rock fragments. As shown in the attached Figure 3 (C), ferrocalcite exhibits uniform deep orange cathodoluminescence (CL), as shown in the attached Figure 3 (D), while ankerite shows non-CL under the fluorescence microscope. In addition, ankerite may replace ferrocalcite, as shown in the attached Figure 3 (A).

[0067] The XRD data and SEM analysis results of the original zone sandstone are as shown in the attached Figure 4 As can be seen from the attached Figure 4 , the authigenic clay minerals in the original zone are mainly mixed-layer I / S, kaolinite, illite, and chlorite. The total clay mineral content ranges from 6.3% to 22.5% (average 13.3%). Mixed-layer I / S (3.2% - 12.8%, average 7.1%) is the main clay mineral in the sandstone, containing 70% - 85% illite. It mainly appears in the form of flaky aggregates, covering the grains and sometimes filling the intergranular pores (cement), presenting a honeycomb-like morphology, as shown in the attached Figure 3 (E) and (F). Kaolinite (1.2% - 8.1%, average value of 2.6%) exists in the form of euhedral brochures and worm-like aggregates, filling the intergranular pores and usually accompanied by authigenic quartz, illite, or mixed-layer I / S, as shown in the attached Figure 3 (F) and (G). Illite (0.5% - 4.6%, average value of 1.3%) mainly exists in the form of intergranular pore filling and grain coating cement, with a flaky morphology, as shown in the attached Figure 3 (F)-(H). Authigenic chlorite (0.2% - 6.3%, average 2.4%) is composed of pseudo-hexagonal platelets arranged perpendicular to the grain surface and forms pore-lining rosette aggregates, as shown in the attached Figure 3As shown in (I). Authigenic quartz cement (1.0% - 2.5%, average 1.6%) occurs in the form of synthetic quartz.

[0068] Overgrowths on the edges of clay (kaolinite and illite) are easily distinguishable from detrital grains in thin sections. Authigenic quartz is clearly discrete, euhedral microquartz crystals, 10 to 50 mm, partially or completely filling intergranular pores, as shown in Figure 3 (G) below.

[0069] CO 2 The diagenetic characteristics of sandstones in the charging area are shown in Figure 5 below. Carbonate cements in the sandstones include dawsonite and ankerite, as well as some ferrocalcite, as shown in Figure 5 (A) below. The contents of dawsonite, ankerite, and ferrocalcite are 0.5% - 10% (average 4.8%), 0% - 9% (average 3.4%), and 0% - 7.0% (average 0.7%), respectively. Dawsonite mainly occurs in radial, clustered, or hairy aggregates filling intergranular pores or replacing detrital grains (as shown in Figure 5 (A)-(D) below), although it is occasionally observed in feldspar dissolution pores (as shown in Figure 5 (C), (E) below.

[0070] The total clay content in the sandstones is 9.3% - 20.5% (average 13.5%), mainly consisting of mixed-layer I / S (7.0% - 16.8%, average 10.9%) and illite (1.1% - 3.4%, average 2.4%). Kaolinite (0% - 1.2%, average 0.2%) and chlorite (0% - 0.4%, average 0.1%) are less common and sometimes even absent (as shown in Figure 4 and Table 1 above). Mixed-layer I / S (≥90% illite; Reichweite order R = 3) appears as a grain coating cement with platy crystals (as shown in Figure 5 (F) below), or as a primary intergranular pore filling cement with honeycomb aggregates. Illite usually exists as an intergranular pore filler and a grain coating with a fibrous or platy morphology, sometimes locally bridging pore throats (as shown in Figure 5 (G) below). Illite may also fill dissolution pores in feldspars (as shown in Figure 5 (H) below). The transformation of kaolinite to illite seems to occur sometimes (as shown in Figure 5 (I) below).

[0071] The quartz cement content ranges from 1.3% to 3.3% (average 2.5%), and is characterized by well-developed synthetic quartz overgrowths (as shown in Figure 5In addition, two generations of quartz accretion bodies (such as the attached Figure 5 In (J) and (K)), dawsonite and asphalt fill the residual pores (such as the attached Figure 5 Middle (L).

[0072] 3.4 Reservoir quality

[0073] Untouched area and CO 2 The porosity and permeability histogram of the sandstone in the injection area is shown in the attached figure. Figure 6 As shown, K 1q4 It is a low-permeability dense sandstone. The porosity of the original sandstone is 4.2% to 20.5% (average 13.7%) and the permeability is 0.01 to 126.41 md (average 3.27 md). 2 The porosity of the sandstone in the injection area is 3% to 16.7% (10.1% on average), and the permeability is 0.01 to 21.06 md (0.4 md on average). The drilling cuttings and well test data are shown in Table 2. It can be seen from Table 2 that CO 2 The oil production capacity of the oil-bearing strata in the injection area is relatively poor, and it mainly produces water, while the oil production capacity of the undisturbed area is relatively high.

[0074] Table 2 Sandstone cuttings and well test data in the study area

[0075]

[0076] Petrographic examination (optical and SEM) revealed that K 1q4 Primary intergranular pores, secondary dissolution pores and micropores related to clay minerals in the reservoir. The pores in the two regions of primary intergranular pores are generally triangular or polygonal and are larger than the secondary dissolution pores (20.0-500 mm) (see Appendix Figure 3 Secondary dissolution pores in both areas are irregular (5.0-50 mm) and appear in feldspar grains along cleavage planes (see Figure 2). Figure 3 Middle (B) and attached Figure 5 (A)), especially at grain edges, and in some cases merged with adjacent primary intergranular pores (see Appendix Figure 5 (C)). Micropores (0.05~5mm; attached Figure 3 (E)-(I)) are clearly present in clay aggregates (e.g., mixed layer I / S, illite, kaolinite, and chlorite). Microporosity was estimated by the difference between the measured porosity and the porosity visually estimated from thin sections. Point count data are shown in the Appendix. Figure 7 As shown in Figure 2, the original porosity of sandstone in the original area is between 0.1% and 10.4% (average 2.8%), which is higher than that of CO 2Sandstone in the injection area (0.1% - 2.5%, average 0.7%); the secondary dissolution porosity of sandstone in the in-situ area is 0.2% - 4% (average 1.6%), CO 2 The secondary dissolution porosity of sandstone in the injection area is 0.1% - 1% (average 0.4%). CO 2 The microporosity of sandstone in the injection area is 5.4% - 12.4% (average 9.2%), which is similar to the microporosity of sandstone in the in-situ area (1.7% - 14.6%, average 9.9%).

[0077] 3.5 Isotopic composition of carbonate cement

[0078] The composition and isotopic characteristic data of carbonate cements in the study area are shown in Table 3 below. The δ 13 C and δ 18 O values of ferrocalcite in the in-situ area are 2.3‰ and 18.3‰ VPDB respectively, and the 87 Sr / 86 Sr ratio of ferrocalcite is 0.712448. The δ 13 C value of ankerite in the in-situ area is between 4.5‰ and 10.5‰ VPDB, and the δ 18 O value is between 19.3‰ and 14.9‰ VPDB, while 87 Sr / 86 Sr ratio ranges from 0.712060 to 0.714030.

[0079] It can also be seen from Table 3 that the δ 2 C and δ 13 C and δ 18 O value ranges of the injection area are 3.8‰ to 0.8‰ VPDB and 20.6‰ to 17.1‰ VPDB respectively. CO 2 The δ 13 C value of ankerite in the injection area varies between 5.7‰ - 2.6‰ VPDB, while the δ 18 O value varies between 20.5‰ - 17.9‰ VPDB. While 87 Sr / 86 Sr ratio ranges between 0.710216 and 0.712472.

[0080] Table 3 Composition and isotopic characteristic data of carbonate cements in the study area

[0081]

[0082] 3.6 Fluid inclusions

[0083] Micrographs of fluid inclusions in sandstone in the in-situ area and the CO 2 injection area are shown in the appendix Figure 8As shown, most of the hydrocarbon inclusions are liquid, and gas inclusions are rare. The inclusions mainly occur in (1) the zone along the microfractures within quartz grains, as shown in (A) and (B) of the appendix Figure 8 as shown in (A) and (B) therein; (2) along the microfractures cutting through the quartz overgrowth layers, as shown in (C) and (D) of the appendix Figure 8 as shown in (C) and (D) therein; (3) randomly occurring late carbonate cements (e.g., ferrocalcite-ferrodolomite-natrite), as shown in (E) and (F) of the appendix Figure 8 as shown in (E) and (F) therein. The hydrocarbon inclusions are light brown to brown, and the inclusions in quartz grains exhibit white fluorescence, as shown in (B) of the appendix Figure 8 as shown in (B) therein, while the inclusions in the late carbonate cements exhibit blue-white fluorescence, as shown in (F) of the appendix Figure 8 as shown in (F) therein.

[0084] Original state area and CO 2 Homogenization temperature T of inclusions in sandstone in the injection area hs as shown in the appendix Figure 9 and Table 4 below. It can be seen from the appendix Figure 9 and Table 4 below that the T h values of aqueous inclusions vary between 72.2 °C and 112.1 °C, and the peaks of aqueous inclusions coexisting with hydrocarbon inclusions in both areas fall within the comparable range of 70 °C to 90 °C. The estimated salinity ranges from 0.53 to 5.41 wt.%.

[0085] The aqueous inclusions in quartz overgrowths are mainly distributed in bands, as shown in (G) and (H) of the appendix Figure 8 as shown in (G) and (H) therein, while the aqueous inclusions in carbonate (ferrocalcite-ferrodolomite-natrite) cements are randomly distributed. The T h values of aqueous inclusions in quartz overgrowths in the original state area range from 81 °C to 108.7 °C, and the T 2 values of aqueous inclusions in the CO h injection area range from 75.2 °C to 165.2 °C, and the estimated salinity is 1.4 wt.%, as shown in Table 5 below. The T h values of the four types of aqueous inclusions in natrite are from 92.8 °C to 97.3 °C, while the T h values in ferrocalcite and ferrodolomite are 89.8 °C–92.7 °C and 102.7 °C–115.9 °C respectively.

[0086] Table 4 Comparison of homogenization temperatures of fluid inclusions in sandstone from different areas

[0087]

[0088]

[0089] Table 5 Characteristics of isotope (3He / He) ratios from different sources

[0090] Source Helium isotope ratio (3He / He) Atmosphere <![CDATA[1.39 - 1.4×10 -8 > Buried water <![CDATA[1.4×10 -8 > Mantle origin / MORB <![CDATA[1.1-1.4×10 -5 > Deep crust / Radioactive decay <![CDATA[n×10 -8 >

[0091] 3.7 Diagenetic sequence

[0092] Appendix Figure 10 Summarizes the paragenetic sequences of the diagenetic history of sandstones in the virgin zone and the CO 2 injection zone, and the paragenetic sequences are established based on lithofacies relationships, authigenic mineral textures, isotope compositions, and microthermometry. Due to mechanical filtration or bioturbation of sediments exposed at the surface, feldspar dissolution and the formation of grain-coated clays may occur immediately after deposition. Therefore, the main early diagenetic events in both zones are (1) compaction and (2) montmorillonite development and alteration of feldspar and kaolinite.

[0093] Microthermometry measurements show that the T h range of the aqueous inclusions coexisting with hydrocarbon inclusions is from 72.2 °C to 112.1 °C, and the temperatures of the aqueous inclusions in the quartz growths in the virgin zone and the CO 2 injection zone are from 81 °C to 108.7 °C and from 75.2 °C to 165.2 °C, respectively. This indicates that the time when oil began to flow in both zones was slightly earlier than the start of quartz cementation.

[0094] For the sandstones in the virgin zone, the results of lithofacies examination show that authigenic quartz cements exist in the intergranular pores at the edges of the original potassium feldspar grains, as shown in Appendix Figure 3 (G), indicating that quartz cementation occurred after potassium feldspar dissolution. Feldspar dissolution caused by organic CO 2 and organic acids derived from kerogen maturation mainly occurred before or during the oil injection process. The overgrowth of quartz was engulfed by ferrocalcite, and ferrocalcite was engulfed by ankerite, as shown in Appendix Figure 3 (A) and (B), indicating that ferrocalcite formed before ankerite but after the start of quartz cementation. Mesodiagenesis includes (1) progressive compaction; (2) the start of oil flow; (3) feldspar dissolution; (4) precipitation of quartz cements, kaolinite, I / S, illite, and chlorite; (5) precipitation of ferrocalcite and ankerite (the end of the oil in the solvent).

[0095] For the sandstones in the CO 2 injection zone, it is first necessary to establish the injection sequence of hydrocarbons and deep inorganic CO 2 . According to the occurrence and T h values of the aqueous inclusions coexisting with hydrocarbons in the natrolite-bearing sandstones, it is found that only one oil injection occurred in the reservoir. This is consistent with the research results of the reservoir sandstones in the Fuxin Uplift in the southern Songliao Basin. As mentioned above, T hHydrocarbon inclusions at 70 °C to 90 °C usually exhibit white ultraviolet (UV) fluorescence and occur within quartz grains or along microfractures, but do not cross the quartz overgrowth layer, as shown in Figure 8 (A) and (B) in the appendix. In contrast, h hydrocarbon inclusions at 90 °C to 120 °C mainly show blue-white ultraviolet fluorescence and occur in late carbonate cements (e.g., dawsonite; as shown in Figure 8 (A) and (B) in the appendix). This indicates that the precipitation of dawsonite occurred after the main period of hydrocarbon flow. Hydrocarbon fluid inclusions in the quartz overgrowth layer mainly show white fluorescence, which means that they formed simultaneously with or slightly later than the main period of oil filling during the precipitation overgrowth of quartz overgrowth bodies, I / S, and illite. In addition, dawsonite mainly fills the residual pores of quartz overgrowth bodies, as shown in Figure 5 (K) and (L) in the appendix, indicating that dawsonite precipitated after the main quartz cementation period. Therefore, the inflow of inorganic CO 2 occurred later than the main periods of hydrocarbon filling and quartz overgrowth.

[0096] CO 2 The diagenetic alteration before CO inflow is similar to the normal zone. Mesodiagenesis is characterized by: (1) progressive compaction; (2) the start of oil flow; (3) feldspar dissolution; (4) the precipitation of quartz overgrowths, kaolinite, I / S, illite, and chlorite; (5) the precipitation of ferrocalcite and ankerite (the end of oil in the solvent); (6) CO 2 injection caused the second-stage feldspar dissolution and enhanced the precipitation of dawsonite, ankerite, quartz overgrowths, I / S, and illite. Since each step of diagenesis occurs over a period of time, some overlap in time is expected. For example, the deep inorganic CO 2 injection seems to start at the end of oil intrusion, and when CO 2 injection and dawsonite precipitation occur, some final-stage oil intrusion may still be ongoing.

[0097] Dawsonite is a trace mineral that effectively traces the migration and / or accumulation of CO 2 -rich fluids underground. The d 13 C of dawsonite (3.8‰ - 0.8‰ VPDB; Table (3)) is slightly lighter than that of dawsonite derived from magmatic activity-related inorganic CO 2 . Early studies showed that the d 13 C values of dawsonite in the BGS basin system in Australia varied between 4‰ and 4.1‰; in the Upper Hunter Valley in Australia, it was 1.7‰ to 2.4‰; and in the southern Songliao Basin in China, it was 4.97‰ to 3.29‰. In this study, the CO 2 in isotopic equilibrium with dawsonite (d 13Cco 2 )'s d 13 The C value (9.8‰ - 6.9‰ VPDB, average 8.17‰) is heavier than that of inorganic CO 2 (>8‰). Organic CO 2 's d 13 Cco 2 values (10‰ to 26‰) are relatively lighter by 8‰ to 10‰ than those of inorganic and organic CO in the mixed range, as shown in 2 's d 13 Cco 2 values, as shown in Figure 12 indicated. Half of the δ 2 C values of CO 13 exist in quartz overgrowth, dawsonite, ankerite, and ferrocalcite.

[0098] In the study area, the CO 13 Cco 2 in equilibrium with dawsonite (δ 2 ) generally falls within the range of inorganic CO 2 (>8‰), and half falls within the mixed range of inorganic and organic CO 2 (8‰ to 10‰; as shown in Figure 11 ), which means it belongs to the mixed source of organic and inorganic CO 2 . Therefore, the slightly lighter carbon isotope value of dawsonite in this study can be attributed to the contribution of organic CO 2 produced by the decarboxylation of organic matter in the source rock and possibly adjacent mudstone.

[0099] The 87 Sr / 86 Sr ratios of dawsonite (0.710996 and 0.712472, average 0.711720; Table 3) are much lower than the average 87 Sr / 86 Sr ratio of the upper continental crust (0.720 - 0.005), and slightly lower than that compared with coeval lacustrine limestone (average 0.71320), but higher than that of the mantle (average 0.7035, as shown in Figure 12 ). Lithofacies examination shows the lack of detrital carbonate grains and bioclasts in K 1q4 sandstone, indicating the absence of an internal inorganic carbon source. The relatively low 87 Sr / 86 Sr ratio of dawsonite indicates that the inflow of inorganic CO 2 has contributions from mantle and crust sources.

[0100] The deep fault and gas reservoir map of the study area is shown in Figure 13 , and as can be seen from Figure 13 , adjacent to CO 2The wells in the gas field (Gu 9, Gu 7, Gu 12, and Gu 34) are also rich in dawsonite. The d 13 C values of dawsonite in these wells range from 5.3% to 0.67%, while for the CO 2 gas in the gas field, the d 2 C values of the dawsonite in isotopic equilibrium with the CO 13 gas range from 9.35% to 3.74%. These values are consistent with the d 13 C and d 13 Cco 2 values of dawsonite in the current study area, indicating similar carbon sources. The Gu 9 well and the Gu 12 well are rich in CO 2 natural gas, and their 3 He / 4 He ratios are (4.51 - 0.14)·10 6 and (4.53 - 0.13)·10 6 respectively. The R ratios are relatively high, being 3.22 and 3.24 respectively. The study of the 3 He / 4 He characteristics from different sources is shown in Table 6 below. The 3 He / 4 He ratios in the Gu 9 well and the Gu 12 well are higher than those in the deep crust but lower than those in the mantle, indicating a mixed origin. This also shows that the CO 2 in the study area and adjacent gas reservoirs is sourced from a mixed origin (magma and crust).

[0101] Therefore, the CO 2 source related to the formation of dawsonite in the study area is likely from the CO 2 mixture of mantle magma and crust, with a small amount from organic CO 2 from organic matter, rather than simply from a mantle source of CO 2 . The CO2 injection area in the study area is located near the Gudian Fault (<7.8 km). This fault connects the deep magma chamber with the shallow strata, providing a migration channel for mantle magma CO 2 and crustal CO 2 .

[0102] Table 6 Isotope ratios 3 He / 4 He characteristics of sources

[0103]

[0104] CO 2 The d 13 C values (5.7‰ and 2.6‰ VPDB) of ankerite in the CO 13 injection area are comparable to the d13 Cco 2 values range between 11.56‰ and 8.52‰ VPDB (average 9.99‰), and largely fall within the range of mixed inorganic and organic CO 2 (8‰ to 10‰). In addition, the 87 Sr / 86 Sr ratios of ankerite (0.710216 and 0.711520, average 0.710791) are slightly lower than those of dawsonite, indicating that mantle magmatic CO 2 and crustal CO 2 also participated in the formation of ankerite.

[0105] The δ 13 C values of ferrocalcite and ankerite in the pristine zone sandstones are lower than the corresponding values in the CO 2 -charged zone sandstones. The calculated δ 2 Cco 13 values of CO 2 in isotopic equilibrium with ferrocalcite and ankerite range between 16.66‰ and 8.08‰ (VPDB; average 11.68‰). Since most of the CO 2 causing carbonate cementation in the pristine zone is of organic origin (10‰ - 26‰), this indicates that the decarboxylation of organic matter in the adjacent mudstones and upper source rocks of the Qingshankou Formation is mainly organic matter.

[0106] The 87 Sr / 86 Sr ratios of the carbonate cements in the pristine zone (0.712060 - 0.714030, average 0.712702) are slightly higher than the average of dawsonite (0.711720) and ankerite (0.710791), slightly lower than that of contemporaneous lacustrine limestone (0.71320), but higher than that of the mantle (0.7035). This implies a relatively minor contribution of mantle-derived Sr to mantle formation.

[0107] In addition, petrological evidence for the carbon sources of ferrocalcite and ankerite has been studied in depth in the K 2 sandstones outside the CO 1q4 -charged zone. The results show that the contents of ferrocalcite and ankerite decrease with increasing distance from the adjacent sandstone - mudstone contact. Therefore, the carbon sources of ferrocalcite and ankerite in the pristine zone mainly come from the organic matter of decarboxylation of adjacent mudstones and source rocks, and the contributions of mantle magmatic CO 2 and crustal CO 2 are smaller.

[0108] The crossplots of dawsonite, feldspar, and quartz cements in the sandstones of this study area are shown in the appendix Figure 14 as shown, from the appendix Figure 14It can be seen that the contents of feldspar and dawsonite are negatively correlated, while the contents of dawsonite and quartz cement are positively correlated. This indicates that the dissolution of feldspar provides most of the cations for the formation of dawsonite and is also the source of silica for the relevant quartz cement. Formation water, hydrothermal fluids rich in inorganic CO 2 and the dissolution of volcanic rock fragments may also provide some alkali metal cations.

[0109] The precipitation of ferrocalcite and ankerite (as shown in (A)-(D) in Figure 3 and (A) in Figure 5 ) requires Ca 2+ , Mg 2+ and Fe 2+ ions, which may come from formation water. The dissolution of volcanic rock fragments in sandstone (as shown in (A)-(C) in Figure 3 and (A) in Figure 5 ) may also provide Ca 2+ , Mg 2+ and Fe 2+ . In addition, the transformation of clay minerals (such as montmorillonite to illite) in sandstone (as shown in (E)-(G) in Figure 3 and (F) in Figure 5 ) and adjacent mudstones and source rocks may provide a small amount of alkali metal cations for ferrocalcite and ankerite.

[0110] 3.8 Timing of deep inorganic CO 2 charging

[0111] Combined with the burial-thermal history curve of Well Gu 27 and the T h values of aqueous inclusions coexisting with hydrocarbon inclusions in dawsonite-bearing sandstone, the time of hydrocarbon outflow was estimated (as shown in Figure 9 ). The zonal data of Well Gu 27 were obtained by synthesizing seismic records on the seismic profile, and then the burial-thermal history of Well Gu 27 was calculated. It was reconstructed using PetroMod software, and the results are as shown in Figure 15 .

[0112] This method shows that the entire hydrocarbon charging process occurred during the period of 82 - 65 Ma (i.e., the late Mingwater period). The homogenization temperatures of aqueous inclusions in quartz overgrowths are mostly between 80 °C and 120 °C, corresponding to the period of 77 to 58 Ma. Therefore, the T h values (92.8 °C - 97.3 °C) of the four types of aqueous inclusions in dawsonite may correspond to 73 - 67 Ma or 50 - 44 Ma. Lithofacies examination shows that the precipitation of dawsonite occurred after hydrocarbon charging (as shown in (L) in Figure 5 ); therefore, based on the above analysis, the estimated reasonable CO 2 charging time is about 50 to 44 Ma.

[0113] To address data deficiencies related to estimating the T value in dawsonite, the dO carbohydrate value is used to estimate the precipitation temperatures of dawsonite and ankerite. The pore water in the K sandstone in the southern Fuxin Uplift mainly originates from fresh water with a small amount of saline water input. Therefore, dawsonite precipitation will occur in pore water with a dO SMOW (Standard Mean Ocean Water) of 7.0‰. The precipitation temperature of dawsonite is calculated using the dolomite water fractionation equation, and the calculated precipitation temperature of dawsonite ranges between 93.64°C and 124.98°C, corresponding to the period from 65 to 45 Ma. In addition, deep inorganic CO gas reservoirs in the central depression of the Songliao Basin are also confirmed to be related to tectonic inversion activities and Shuangliao volcanic activities. h The CO is transported upward through basement faults and paleovolcanic channels and accumulates in suitable traps. Tectonic inversion activities began at the end of the Mingshui period, and the Shuangliao volcanic eruptions occurred between 51 and 41 Ma, which is consistent with the charging time of deep inorganic CO determined in this study. Therefore, it is speculated that the influx of deep inorganic CO occurred around 65 - 44 Ma, later than the main period of hydrocarbon influx and quartz overgrowth formation. 18 3.9 Impact of the influx of deep inorganic CO on reservoir quality 1q4 The influx of deep inorganic CO (a mixture of mantle magma and crustal CO) causes a series of diagenetic alterations in the CO charging area (<7.8 km), including carbonate cementation, clay mineral alteration, quartz cementation, and feldspar dissolution, etc. This results in a difference in reservoir quality between the normal layer and the dawsonite layer (as shown in the appendix). 18 The carbonate cementation caused by deep inorganic CO blocks the intergranular and secondary dissolution pore spaces and also blocks the pore throats (as shown in (A)-(D) in appendix, (A)-(C) in appendix). The relationship between carbonate cement and the porosity and permeability of the northern sandstone is shown in appendix. It can be seen from appendix that sandstone reservoirs rich in carbonate cement tend to have lower reservoir quality, indicating that carbonate cementation is an important factor controlling the reservoir quality of sandstone reservoirs in the two areas. 2

[0114] CO 2 2 2

[0115] 2

[0116] 2 (mixture of mantle magma and crustal CO 2 ) causes a series of diagenetic alterations in the CO charging area (<7.8 km), including carbonate cementation, clay mineral alteration, quartz cementation, and feldspar dissolution, etc. This results in a difference in reservoir quality between the normal layer and the dawsonite layer (as shown in the appendix). 2 Figure 7

[0117] 2 The carbonate cementation caused by deep inorganic CO blocks the intergranular and secondary dissolution pore spaces and also blocks the pore throats (as shown in (A)-(D) in appendix, (A)-(C) in appendix). The relationship between carbonate cement and the porosity and permeability of the northern sandstone is shown in appendix. It can be seen from appendix that sandstone reservoirs rich in carbonate cement tend to have lower reservoir quality, indicating that carbonate cementation is an important factor controlling the reservoir quality of sandstone reservoirs in the two areas. Figure 3 Figure 5 Figure 16 Figure 16

[0118] ​​​​​​​​​​​​​​Deep inorganic CO 2 mainly migrates upward through deep faults. The Gudian Fault is the migration channel for deep inorganic CO 2 in the study area. Due to the overlying mudstone in the Qingshankou Formation, deep inorganic CO 2 migrates upward along the Gudian Fault to the K 1q4 sandstone accumulation. The influx of CO 2 first makes the pore fluid weakly acidic, promotes another stage of feldspar dissolution in the sandstone near the Gudian Fault, forms secondary dissolution pores, and leads to the generation of Na + and K + . The rich pore fluid is rich in Na + and K + , and the presence of the pore fluid promotes the transformation of montmorillonite to illite to a certain extent. As the partial pressure of CO 2 increases, the gas may continue to react with feldspar (especially albite) to form dawsonite, accompanied by quartz precipitation.

[0119] In addition to the high CO 2 partial pressure, the stability of dawsonite is also related to pH, temperature, and the activity of chemical components. In the Na 2 O-Al 2 O 3 -SiO 2 -CO 2 -H 2 O system, the stability of dawsonite is considered to be a function of the logarithmic activity ratio of log a SiO 2 and CO 2 partial pressures at 100 °C and 300 bar conditions for Na + versus H + , as shown in Appendix Figure 17 . At low silica saturation, dawsonite is stable relative to albite, while at higher Na + / H + ratios, dawsonite is stable relative to kaolinite.

[0120] The influx of inorganic CO 2 may lead to a flow-limiting process in the CO2 injection area. As the lateral migration distance of deep inorganic CO 2 along the Gudian Fault increases, the partial pressure and content of CO 2 in the pore fluid decrease as CO 2 dissolves in the formation water and is stored in the minerals, resulting in a decrease in the content of dawsonite. The remaining CO 2 is likely to be consumed by the precipitation of ankerite, which leads to a higher ankerite abundance in wells far from the Gudian Fault than near the fault (Appendix Figure 16 ). In addition, as the deep inorganic CO 2With the increase of the horizontal migration distance, due to the CO 2 dissipation, the partial pressure of CO in the pore fluid drops below the threshold for the formation of natrite. The fluid temperature decreases with the increase of the distance from the CO 2 injection area, and the remaining CO 2 is likely to be consumed by the precipitation of ankerite, resulting in a higher proportion of ankerite in the normal zone than in the CO 2 injection area, as shown in Attachment 2 . Therefore, the carbonate cement type changes from natrite and ankerite to ferrocalcite and ankerite, and the precipitation temperature of the carbonate cement decreases (Attachment Figure 18 and Tables 3 and 4). The carbon sources of ferrocalcite and ankerite in the virgin zone mainly come from the decarboxylation of adjacent mudstones and source rocks. As mentioned above, compared with the carbonate cements in the sandstones in the normal zone with relatively low content, in the CO Figure 18 injection area, the porosity of the sandstones damaged by carbonate cements is 4% - 14.8%, with an average of 8.9%. This average value is higher than the average value of the virgin zone sandstones (the average value is 3.3%, ranging from 1% - 19%), indicating that the formation of carbonate cements induced by CO 2 injection leads to additional pore space damage. 2 2 2 In summary, deep inorganic CO

[0121] promotes the precipitation of natrite and ankerite, resulting in poor quality of sandstone reservoirs in this area. The negative correlation between the total amount of authigenic clay minerals caused by deep inorganic CO 2 and porosity and permeability is shown in Attachment 2 . The results show that the increase of authigenic clay minerals has a negative impact on reservoir quality. For the sandstones in the natrite zone, the results show that mixed-layer I / S (≥90% illite) and illite are the main authigenic clay minerals. The Reichweite grade of the mixed-layer I / S is R = 3, which is the highest in the sandstones in the CO2 injection area (Attachment Figure 19 ). In addition, the contents of illite and mixed-layer I / S are higher than those in the normal zone sandstones. The mixed-layer I / S appears in the form of honeycomb pore-filling cements (Figure (F) in Attachment Figure 4 ), which blocks the primary intergranular pores and pore throats, thus leading to a decrease in porosity and permeability (Figure (F) in Attachment Figure 5 ). Illite mainly appears in the form of fibrous or sheet-like pore-filling cements (Figures (G)-(I) in Attachment Figure 19 ), and usually locally bridges the pore throats, which reduces the reservoir quality, especially the permeability. Figure 5

[0122] The influx of deep inorganic CO 2 may accelerate the dissolution of potassium feldspar, thus releasing K + ​Released into the pore water, which may have promoted the transformation of montmorillonite to illite. Kaolinite and chlorite are not common in albite zone sandstones. Since kaolinite and chlorite occur in the adjacent normal zones, the possibility that kaolinite and chlorite precursors are absent or dissolved by meteoric water or organic acidic fluids can be excluded. Therefore, it is suggested that the lack of kaolinite and chlorite is related to the inflow of deep inorganic CO 2 The dissolution of chlorite can be represented by Equation (1), and is accompanied by the precipitation of dickite, quartz, and kaolinite.

[0123] (Fe,Mg) 5 Al 2 Si 3 O 10 (OH) 8 +CaCO 3 +5CO 2 →5Ca(Mg,Fe)(CO 3 )+Al 2 (Si 2 O 5 )OH 4 +

[0124] SiO 2 +2H 2 O(1)

[0125] The inflow of deep inorganic CO 2 can also cause the transformation of kaolinite to albite through Equation (2), and this reaction requires the input of Na + and CO 2 , which can be achieved by the inflow of deep CO 2 . In addition, the high temperature (>120 °C) and K + -rich pore fluid environment provided by the inflow, combined with the addition of CO 2 -rich hydrothermal fluids and the dissolution of potassium feldspar can promote the transformation of kaolinite to illite, which is consistent with the abundant fibrous illite (attached Figure 5 in (G)) represented by Equation (3).

[0126] Al 2 Si 2 O 5 (OH) 4 + 2CO 2 + H 2 O + 2Na + → 2NaAlCO 3 (OH) 2 + 2SiO 2 + 2H + (2)

[0127] KAlSi 3 O 8 + Al 2 Si 2 O 5 (OH) 4 → Kal 3 Si 3 O 10 (OH) 2 + 2SiO 2 + H 2 O (3)

[0128] For CO 2 In the sandstone of the charging area, kaolinite and chlorite have no constructive effect on reservoir quality, which is consistent with the negative correlation between mixed-layer I / S and illite and porosity and permeability (Appendix Figure 19 ).

[0129] For the virgin area sandstone, the results show that the authigenic clay minerals are composed of mixed-layer I / S (70% - 85%, illite; Reichweite series R = 1), illite, chlorite and kaolinite. Since these minerals have different degrees of influence on reservoir quality, the correlation between the content of authigenic clay minerals and reservoir quality is poor. Mixed-layer I / S mainly appears as honeycomb pore-filling cements (Appendix Figure 3 (E) and (F)), plugging the primary intergranular pores, thus reducing porosity and permeability and degrading the quality of the sandstone reservoir (Appendix Figure 19 ). Similarly, fibrous or flaky illite fills the pores, mostly accompanied by mixed-layer I / S (Appendix Figure 3 (G) and (H)), reducing reservoir quality. The positive correlation between kaolinite content and porosity and permeability (Appendix Figure 19 ) reflects the influence of feldspar dissolution in an open diagenetic system and can effectively improve reservoir quality through the formation of moldic pores. However, there is no obvious correlation between chlorite content and reservoir quality (Appendix Figure 19 ).

[0130] Therefore, although the clay mineral contents in the two zones are similar, it is speculated that the clay mineral content in the sodalite-bearing zone has a more direct impact on reducing porosity and permeability (Appendix Figure 19 ).

[0131] 3.9 Deep inorganic CO 2 Influx-induced quartz cementation

[0132] Quartz cements are commonly present in the sandstones of both areas. CO 2The quartz overgrowth content in the injection area is relatively higher (1.3% - 3.3%, with an average of 2.5%) than that in the original area (1.0% - 2.5%, with an average of 1.6%); thus, quartz cement destroys the porosity and the CO 2 values of the associated aqueous inclusions. The quartz overgrowth areas in both sandstones mostly fall within the range of 80°C to 110°C, corresponding to the period of 77 - 63 Ma. Further research shows that the source of quartz overgrowths is mainly internal, and there may be three main sources of silica. For the quartz cements in K h sandstones, their sources include: (1) montmorillonite to illite reaction; (2) pressure solution; (3) conversion of potassium feldspar and kaolinite to illite. The formation of dawsonite is mainly related to feldspar, kaolinite, and chlorite. These reactions can also provide additional silica for the quartz cements in dawsonite. 1q4 The dissolution porosity caused by deep inorganic CO

[0133] is positively correlated with the porosity and permeability of the reservoir. In the sandstones of the original area, feldspar dissolution is an important diagenetic process, which significantly increases the porosity and permeability of the reservoir, thus improving the quality of the reservoir. While in the sandstones of the CO 2 injection area, this correlation is weaker, possibly related to the occupation of a large number of intergranular / intragranular dissolution pores by dawsonite and ankerite caused by CO 2 injection, as shown in the attachment 2 . Petrographic examination reveals some bitumen in the dawsonite-bearing sandstones (in the attachment Figure 20 (L)). Generally speaking, only thermal alteration or degassing can produce both oil and bitumen simultaneously. Thermal alteration occurs only at >170°C. In this study, the highest temperature inferred from fluid inclusions is 1114 ± 165.2°C. The formation of bitumen may be caused by deasphalting of crude oil. The oil reservoirs in the sandstones of the oil-bearing zone are lower than those in the normal zone, but the salinity of formation water is higher (Table 2), which means that the critical point temperature of deasphalted crude oil > 31.3°C, pressure > 7.3 MPa), which also indicates that CO Figure 5 may have dissolved bitumen and extracted the light components of crude oil, resulting in deasphalting of crude oil and enhanced secondary migration of accumulated oil, which may damage the original oil reservoirs in the CO 2 injection area, but contribute to the oil enrichment in the normal zone located in a favorable structural position. 2 Therefore, the influx of deep inorganic CO

[0134] results in poor reservoir quality and deasphalting of crude oil, thus leading to poor oil production capacity of the dawsonite-bearing sandstones. 2 In summary, in the study area of this research, K

[0135] sandstones 1q4The reservoir sandstones can be divided into two zones according to the occurrence of dawsonite and the distance from the Gudian Fault: the virgin zone and the CO 2 injection zone. The virgin zone is mainly composed of quartz, ankerite, ferroan dolomite and clay minerals (mixed-layer I / S, illite, kaolinite and chlorite), while the CO 2 injection zone contains quartz, dawsonite, ferroan dolomite and clay minerals (mixed-layer I / S and illite).

[0136] CO 2 The carbon sources of dawsonite and ferroan dolomite in the injection zone are a mixture of mantle magma and crustal CO 2 and contain a small amount of organic CO from the decarboxylation of organic matter in adjacent mudstones and source rocks 2 . However, the carbon in ankerite and ferroan dolomite in the virgin zone mainly comes from the organic CO formed by the decarboxylation of organic matter in source rocks and adjacent mudstones 2 and is mixed with a small amount of mantle magma and crustal CO 2 . The precipitation of dawsonite is related to the influx of inorganic CO 2 and occurs after the main period of hydrocarbon injection. According to fluid inclusions, the CO 2 injection associated with dawsonite occurred around 65 to 44 Ma, which corresponds to the time of hydrocarbon injection and deep inorganic CO 2 injection.

[0137] The sandstones in the virgin zone and the CO 2 injection zone have experienced different deep diagenetic processes. For the sandstones in the virgin zone, these processes include (1) compaction; (2) feldspar dissolution (caused by organic acids); (3) the start of oil flow; (4) the precipitation of quartz cement and the formation of kaolinite, I / S, illite and chlorite; (5) the precipitation of ankerite and ferroan dolomite (the end of oil in the solvent). For the sandstones in the CO 2 injection zone, the processes are (1) compaction; (2) the start of oil flow; (3) feldspar dissolution (caused by organic acids); (4) the precipitation of quartz cement and the formation of kaolinite, I / S, illite and chlorite; (5) the precipitation of ankerite and ferroan dolomite (the end of oil in the solvent); (6) the influx of CO 2 , feldspar dissolution and the precipitation of dawsonite, ferroan dolomite, quartz overgrowths, I / S and illite.

[0138] CO 2 The reservoir quality of the sandstones in the injection zone is poorer than that of the sandstones in the virgin zone, which is related to the higher contents of carbonate rocks and quartz cements and specific clay mineral types (mainly I / S and illite), due to the influx of deep inorganic CO 2 .

[0139] The distribution of carbonate cements is affected by the inflow of deep inorganic CO 2 For dawsonite-bearing sandstone, the dawsonite content decreases with increasing distance from the Gudian Fault, while the ankerite content shows the opposite trend. In the sandstone of the original state area, the authigenic clay minerals are mainly composed of mixed-layer I / S (Reichweite series, R = 1), illite, chlorite, and kaolinite, which have different degrees of influence on the reservoir quality. Mixed-layer I / S and illite reduce the reservoir quality. Although kaolinite has a positive effect, chlorite has no obvious relationship with the reservoir quality. For dawsonite-bearing zone sandstone, the authigenic clay minerals are composed of mixed-layer I / S (Reichweite series, R = 3) and illite, reducing the quality of this area.

[0140] The dissolution of feldspar, kaolinite, and chlorite is related to the injection of deep inorganic CO 2 This reaction provides a source of silica for the formation of secondary quartz overgrowth in the CO 2 injection area; in the CO 2 injection area, the cementation and feldspar dissolution in the sandstone consume the inflowing deep inorganic CO 2 and precipitate to form dawsonite and ankerite. The inflow of deep inorganic CO 2 results in poor water resources, reservoir quality, and crude oil deasphalting in the sandstone of the CO 2 injection area, thus leading to low oil productivity.

[0141] The above shows and describes the basic principles, main features, and advantages of the present invention. Those skilled in the art should understand that the present invention is not limited by the above embodiments. The above embodiments and the descriptions in the specification only illustrate the principles of the present invention. Without departing from the spirit and scope of the present invention, the present invention will have various changes and improvements, and these changes and improvements fall within the scope of the present invention claimed. The scope of protection of the present invention is defined by the appended claims and their equivalents.

Claims

1. A method for evaluating reservoir quality evolution after deep CO2 injection into sandstone, characterized in that: The following steps are involved: S1: The sandstone in the CO2-charged area was selected as the research object, and the sandstone in the original area adjacent to the CO2-charged area was selected as the reference object. The petrological characteristics of the sandstone reservoirs in the CO2-charged area and the original area were analyzed to clarify the authigenic mineral types, occurrence characteristics and content differences of the two types of reservoirs; S2: Using the deep CO2 tracer mineral dawsonite as the research carrier, the lithology and reservoir characteristics of the sandstone reservoirs in the CO2-charged area and the original area were compared and analyzed; S3: Taking the sandstone reservoir in the original area as a reference object, according to the comparison results of step S2, the diagenesis caused by CO2 injection and the influence of the diagenesis after CO2 injection on the reservoir quality are analyzed to determine the reservoir quality evolution process after CO2 injection into the sandstone.

2. The method for evaluating reservoir quality evolution after deep source CO2 injection into sandstone according to claim 1 is characterized in that: The petrological characteristics of the sandstone reservoir described in step S1 include the clastic mineral composition and the degree of diagenetic alteration.

3. The method for evaluating reservoir quality evolution after deep source CO2 injection into sandstone according to claim 2 is characterized in that: The degree of diagenetic alteration includes quartz content, carbonate cementation type content and authigenic clay mineral type content.

4. The method for evaluating reservoir quality evolution after deep source CO2 injection into sandstone according to claim 3 is characterized in that: The specific operation of step S2 includes the following steps: S201: Comparative analysis of the porosity, permeability and pore structure differences of sandstone reservoirs in the CO2-charged area and the original area; S202: Determine the diagenesis stage and paragenesis sequence of the sandstones in the CO2 injection area and the original area; S203: Compare and analyze the carbon and oxygen isotopes of carbonate cements in the sandstones of the CO2-charged area and the original area to determine the characteristics and sources of paleofluids related to the formation of carbonate cements in the sandstones of the two zones; S204: Conduct fluid inclusion analysis on the sandstone in the CO2-charged area and the sandstone in the original area to determine the charging time of hydrocarbon fluids in the sandstone in the original area, as well as the CO2 and hydrocarbon charging time series of the sandstone in the CO2-charged area; S205: Compare and analyze the diagenetic fluid evolution characteristics and differences of the sandstone reservoirs in the CO2 injection area and the original area, and establish the diagenetic evolution path of the sandstone reservoirs in the two zones.

5. The method for evaluating reservoir quality evolution after deep source CO2 injection into sandstone according to claim 4 is characterized in that: The analysis of carbon and oxygen isotopes in step S203 includes the d 13 C、d 18 O. 87 Sr / 86 Sr ratio.

6. The method for evaluating reservoir quality evolution after deep source CO2 injection into sandstone according to claim 5 is characterized in that: The impact of the diagenesis after CO2 injection described in step S3 on reservoir quality is that the influx of deep inorganic CO2 leads to the deterioration of sandstone water resources, reservoir quality and crude oil deasphalting in the CO2 injection area, thereby resulting in low oil productivity.

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