CN116047602A - Type II hydrate saturation prediction method based on hydrocarbon production numerical simulation - Google Patents
Type II hydrate saturation prediction method based on hydrocarbon production numerical simulation Download PDFInfo
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Abstract
The invention discloses a method for predicting the saturation of II-type hydrate based on hydrocarbon production numerical simulation, which comprises the steps of firstly adopting seismic data to construct a basin stratum sequence grid, and establishing a simulation grid based on the basin stratum sequence grid; secondly, utilizing attribute analysis such as seismic coherence or amplitude to establish the lithology of the stratum of the basin, fine distribution of faults and cracks, combining geological data such as regional logging and rock cores, establishing parameters such as lithology and physical properties of sediments, and constructing a fine geological model based on fault activity and sand spreading characteristics; then, a stratum temperature model is built by utilizing regional stratum temperature and heat flow data, and a hydrocarbon generation model is built by combining the TOC, the hydrogen index and the hydrocarbon generation dynamics model; and calculating the saturation of the II type hydrate by constructing a II type hydrate phase balance model; according to the scheme, drilling logging data is not relied on, and analysis of influence mechanisms of regional fluid migration, sediment such as favorable sand bodies, faults, cracks and other structures on hydrate enrichment can be realized through seismic data, regional geological data and the like.
Description
Technical Field
The invention belongs to the field of petroleum and natural gas hydrate exploration, and particularly relates to a type II hydrate saturation prediction method based on hydrocarbon generation numerical simulation.
Background
A large number of drilling shows that the occurrence types of the natural gas hydrate are various and are divided into type I (methane gas is the main component) hydrate, type II (thermogenic gas is the main component) hydrate and type H hydrate, the distribution of the type H hydrate in the nature is less, the type I hydrate and the type II hydrate are widely distributed in deep basin and frozen soil zone of the world, and the stable occurrence depth of the type II hydrate is deeper than that of the type I hydrate. From the prior researches, the type II hydrate is mainly distributed in a heat-induced gas enrichment and high-flux fluid migration area, is often associated with a cold spring system, has various forms, can identify the type II hydrate and spatial distribution by combining drilling, coring and seismic data, can calculate the type II hydrate saturation by utilizing a logging and petrophysical model, and is difficult to drill and core the widely-existing type II hydrate potential area due to high drilling and coring cost.
The existing method considers that the formation of high-saturation hydrate in the gulf green canyon of mexico is related to the rapid deposition of sediment through numerical simulation research, and the hydrate stability zone is continuously regulated, so that the hydrate nearby the stability zone is continuously formed, decomposed and reformed, and secondly, the gas source type, the dredging system, the storage condition and the like are discovered through simulation to influence the enrichment degree of the hydrate, and the biological source gas or the thermal source gas moves upwards along the inclined sand-rich stratum, the fold anticline generated by the diving extrusion and the like, so that the enrichment of the hydrate is facilitated. The hydrate formation of the fine sediment of the mouth basin of the pearl river is also found to be commonly controlled by a plurality of factors such as fault activity, regional structure activity, hydrocarbon source rock distribution and the like through numerical simulation, and the high-saturation hydrate enrichment is related to heat-induced gas. Thus, prior studies have shown that simulation techniques are an important method for analyzing hydrate formation and enrichment, but prior methods lack research on the conditions of type II hydrate formation and saturation in thermogenic gas development areas, mainly because in earlier studies, extensive distribution of type II hydrates in marine sediments was not found due to limitations of drilling, coring and research awareness, and simulation techniques for type II hydrate formation have not been pursued.
In recent years, with knowledge of hydrate formation systems and extensive drilling, it has been found that type II hydrates are widely distributed in a thermally induced gas development zone, and that a type II hydrate stability zone having a larger thickness than type I (methane) hydrates may be present in the lower part of an I-BSR identified in the zone, and that a phenomenon in which the hydrates coexist with free gas may occur, and when the formation is present, the logging of the longitudinal wave velocity may be an abnormal low velocity of formation gas, and therefore, in this case, an underestimation of the amount of type II hydrate resources may also occur when the type II hydrates are evaluated by velocity logging. The conventional type II hydrate evaluation technology is to quantitatively calculate the hydrate saturation by constructing a multiparameter combined petrophysical model based on logging data such as longitudinal waves, transverse waves, resistivity, nuclear magnetism and density, and the method needs to drill and obtain high-quality logging data to evaluate the type II hydrate saturation, but for the exploration stage, the research area does not perform drilling and logging yet, and the type II hydrate research is difficult to perform by the method.
Therefore, a new prediction method is needed to be provided, based on regional geological data and seismic data analysis, hydrate reservoir formation is developed through a numerical simulation method, evaluation and research of II-type hydrate reservoir formation and saturation are realized, and the distribution and saturation of the hydrate are found to have important significance for hydrate resource potential evaluation and optimization of drilling target well positions.
Disclosure of Invention
Aiming at the defects of the prior art on the formation and saturation prediction of the II-type hydrate, the invention provides a II-type hydrate saturation prediction method based on hydrocarbon generation numerical simulation, which takes seismic data as the basis, fully utilizes geological data such as regional logging, rock core, temperature and the like, combines the hydrate hydrocarbon generation simulation based on a II-type hydrate phase balance model to realize the calculation of the II-type hydrate saturation of a high-flux fluid leakage zone, can effectively predict the potential distribution zone of the II-type hydrate, and has important significance in accurately evaluating the hydrate resource quantity and determining the favorable exploration target.
The invention is realized by adopting the following technical scheme: a type II hydrate saturation prediction method based on hydrocarbon production numerical simulation comprises the following steps:
step A, establishing a simulation grid: building a layer sequence stratum grid based on the seismic data, and building a simulation grid based on the layer sequence stratum grid;
step B, constructing a fine geological model: establishing the lithology of the stratum and the fine distribution of faults and cracks; and combining relevant geological data, establishing sediment lithology and physical parameters, and realizing fine geological model construction based on fault activity and sand spreading characteristics;
step C, II type hydrate saturation prediction:
step C1, constructing a stratum temperature model by using regional stratum temperature and heat flow data, performing temperature field simulation, and establishing a stratum depth range of biological and thermal hydrocarbon generation;
step C2, constructing an organic matter hydrocarbon generation model by utilizing the TOC (total organic carbon) content, the hydrogen index and the hydrocarbon generation kinetic model;
and C3, calculating the saturation of the type II hydrate by constructing a type II hydrate phase balance model, analyzing the influence mechanism of regional fluid migration, favorable sand deposition, fault and fracture structure on the hydrate enrichment, and simulating and predicting the potential distribution and saturation of the type II hydrate layer.
Further, the step B specifically includes the following steps:
step B1, extracting seismic root mean square amplitude attribute aiming at seismic data, and establishing sedimentary facies distribution;
step B2, constructing a physical property profile and a lithology profile of the simulated profile, wherein physical property parameters comprise porosity and permeability;
step B3, based on a seismic attribute extraction method, finely identifying regional structural faults and stratum internal cracks;
and B4, combining the step A with the step B1-the step B3, determining the distribution of the simulated earthquake section in a typical earthquake section, assigning values to the simulated grids of the section, defining lithology and physical parameters of each simulated grid, and distributing faults and cracks along the boundaries of a plurality of simulated grids, and constructing a fine geological model.
Further, in the step B2, the following is specifically implemented:
(1) Calculating sand and mudstone contents of different sedimentary phases by using gamma logging data of a target area and a nearby area through a formula (1), and combining rock core data to establish lithology parameters in a model:
I GR ＝(GR log -GR min )/(GR max -GR min )，
V cl ＝0.083(2 3.7×IGR -1) (1)
in which I GR To normalize natural gamma values, GR log For measuring gamma, GR min Is the minimum gamma value (representing pure sandstone), GR max The gamma value is the maximum gamma value (representing pure mudstone), the unit of the gamma value is api, and the value is obtained from the hydrate logging GMGS5-W08 well data, wherein GR min Take the value of 0api, GR max The value is 147api; v (V) cl For the calculated mudstone content;
(2) And (3) fitting and establishing a rock porosity change formula (2) along with depth by utilizing measured porosity data, and establishing porosity physical parameters in a model:
Φ＝1.244×D -0.181 (2)
wherein D is depth and phi is porosity;
and (3) utilizing a Kozeny-Carman model, calculating the permeability based on the calculated porosity phi, and establishing stratum permeability parameters in the model.
Further, the step B3 is specifically implemented by the following manner:
extracting seismic coherence properties, identifying faults and cracks based on coherence and ant tracking methods, analyzing fault characteristics of a research area, and extracting key modes comprises: removing random noise of the seismic data and retaining fault boundary information through construction smoothing; extracting a seismic coherence body, calculating the similarity between seismic channels and performing boundary detection; discontinuous boundaries are tracked using ant tracking techniques.
Further, the step C1 is specifically implemented by the following manner:
b, based on the fine geological model constructed in the step B, inputting actually measured seabed temperature, ground temperature gradient and regional heat flow data to perform stratum temperature profile numerical simulation by utilizing a Mckenzie model, comparing and correcting with actual stratum temperature data of a hydrate enrichment region, and based on temperature distribution of bio-generated hydrocarbon and thermal-generated hydrocarbon, establishing stratum depth ranges of the bio-generated hydrocarbon and the thermal-generated hydrocarbon on a simulated calculated temperature field profile.
Further, the step C2 is specifically implemented by the following manner:
(1) Collecting a biological hydrocarbon generation dynamic model and a thermal hydrocarbon generation dynamic model of total organic carbon content TOC, hydrogen index HI of organic matters of source rock of a region and influenced by a temperature field,
the biological hydrocarbon generation dynamics model is a normal distribution model established based on a biological hydrocarbon generation temperature range, the thermal hydrocarbon generation dynamics model is based on hydrocarbon generation dynamics model data obtained by the existing hydrocarbon generation thermal simulation experiment, the organic matter kerogen type in the thermal hydrocarbon generation stratum is determined to be mainly based on regional hydrocarbon source rock geochemistry research basis, and a Burnham III type thermal hydrocarbon generation dynamics model is adopted;
(2) And (3) respectively constructing an organic matter hydrocarbon generation model of biogenic methane and thermal biogenic methane, and calculating hydrocarbon source rock organic matter hydrocarbon generation by combining the stratum temperature profile simulated in the step C1.
Further, the step C3 includes the following steps:
step C31, simulating a methane fluid migration path generated by hydrocarbon generation:
(1) Dividing the geological model into a low-permeability mud-rich stratum and a high-permeability sand-rich stratum according to the permeability calculated in the step B2;
wherein, the gate boundary conditions of the high permeability sand-rich stratum are: porosity of 30% and permeability greater than-2.01 log (mD); simulating and calculating fluid migration characteristics along different stratum by utilizing a Hybrid migration model; for the low-permeability mud-rich stratum, darcy model calculation is adopted, and fluid migration is controlled by the relative permeability and capillary pressure among model grids; in the high-permeability sand-rich stratum, the fluid migration is controlled by buoyancy by adopting a Flowpath model to calculate;
(2) Calculating fluid migration controlled by a fault structure by using a fault migration model, and simulating fluid migration processes of different faults according to the distribution position of the interruption layers in the step B4, wherein whether the thickness of the fault cut-through stratum is different or not is used as a fault opening time setting basis;
step C32, based on the content of gas components, acquiring a temperature-pressure curve of phase equilibrium of the type I hydrate and the type II hydrate, and calculating the bottom boundary depth of the type I hydrate and the type II hydrate through intersection points of the two data;
and C33, calculating the type II hydrate saturation on the basis of the hydrocarbon source rock organic matter hydrocarbon generation and methane migration paths calculated in the step C2 and the step C31.
Further, the step C33 is specifically implemented by:
obtaining a solubility curve of methane in pore water and a pressure curve of methane hydrate decomposition by using a Tishchenko model; when methane enters the hydrate stability zone and exceeds the methane solubility, supersaturated methane immediately forms hydrate, and when the methane solubility is lower than the saturation state, or the formation pressure exceeds the decomposition pressure of methane hydrate, the hydrate is decomposed, and on the basis, the hydrate saturation is determined by the sediment pore parameters calculated in the step B2; and (3) combining the hydrate between the stable band bottom boundaries of the type I and type II hydrates calculated in the step C32 to obtain the type II hydrate.
Compared with the prior art, the invention has the advantages and positive effects that:
the II-type hydrate saturation prediction method based on hydrocarbon production numerical simulation provided by the scheme can obtain the II-type hydrate layer distribution which is difficult to accurately predict by traditional logging calculation methods without depending on logging data, and the II-type hydrate stability zone model is creatively considered in the technical method, and a geological model of refined sand body, fault and crack distribution is constructed, so that the knowledge of hydrate saturation and distribution under different deposition and construction conditions is improved; simulating the influence of different faults by constructing different faults, cracks and distribution differences of favorable sand bodies of the faults, cutting through the thickness of the stratum by the faults, simulating the crack distribution of the sedimentary stratum by the block body, simulating the fluid migration of the low-permeability stratum relative to the favorable dredging system area, analyzing the distribution and continuous characteristics of the sand bodies of the block body transportation sedimentary stratum, adopting different simulation grids for deep stratum and shallow stratum, constructing a mathematical model and a hydrocarbon generation model similar to an actual geological model, and realizing the simulation of the II-type hydrate distribution and saturation;
the method has the advantages that the generation, distribution and saturation of the II-type hydrate are simulated on the basis of the generation of deep stratum thermogenic gas and shallow stratum biogenic gas, upward migration of different types of fluids along various channels, consideration of a II-type hydrate stability zone and the like, the problem that similar free gas is represented by using geophysical parameters of the II-type hydrate layer and the free gas, and the II-type hydrate saturation and distribution are evaluated relatively accurately, and the method does not depend on logging data, so that the II-type hydrate saturation can be semi-quantitatively predicted no matter whether logging data exist in a research area or not, the resource potential of a regional hydrate exploration target is determined, and master control factors, potential hydrate saturation and distribution affecting the hydrate saturation can be analyzed and predicted by combining regional seismic data, seismic attributes and the like; the method has the advantages of realizing relatively accurate prediction of the saturation and distribution of the II-type hydrate, and having important significance for accurately evaluating the amount of the hydrate resources and determining the favorable exploration targets.
Drawings
FIG. 1 is a schematic flow chart of a method for predicting the saturation of a type II hydrate according to an embodiment of the present invention;
FIG. 2 is a superimposed view of a fracture, fissure and seismic profile of a formation identified using three-dimensional seismic data in accordance with an embodiment of the invention;
FIG. 3 is a schematic illustration of a geologic model of a fine sedimentary system distribution and fault, fracture distribution constructed in accordance with an embodiment of the present invention;
FIG. 4 is a schematic diagram of simulation calculation results according to an embodiment of the present invention, wherein (a) is a schematic diagram of comparison between a simulated calculated formation temperature field and a logging temperature; (b) A high-throughput migration path schematic for fluid over the simulated calculated substrate ridge through different migration modes;
FIG. 5 is a schematic diagram of the results of simulated computation of type II hydrate saturation using type II hydrate stability zones in combination with fine fault and fissure and sand-rich sediment spread in an embodiment of the present invention, wherein FIG. (a) is a schematic diagram of a fine geologic model constructed based on seismic interpretation and attribute analysis; fig. b is a schematic diagram of simulated type II hydrate saturation and distribution, and fig. c is a schematic diagram of simulated type II hydrate saturation and distribution for a bulk transfer deposition (MTD) bottom sandstone-free reservoir.
Detailed Description
In order that the above objects, features and advantages of the invention will be more readily understood, a further description of the invention will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. In the following description, numerous specific details are set forth in order to provide a thorough understanding of the present invention, however, the present invention may be practiced otherwise than as described herein, and therefore the present invention is not limited to the specific embodiments disclosed below.
Hydrocarbon production numerical simulation is an important method for understanding oil and gas accumulation, and by constructing a geological model, a temperature model, a hydrocarbon production model and the like, oil and gas accumulation and accumulation are simulated. The hydrate hydrocarbon generation simulation provided by the embodiment is based on oil and gas reservoir simulation, a hydrate phase balance module and a reservoir formation module are added to simulate and calculate the saturation of the hydrate and the resource quantity, hydrocarbon source rock hydrocarbon generation, fluid migration and hydrate reservoir formation can be studied on the basin scale, and the basic principle is as follows: firstly, constructing a key stratum sequence stratum grid by adopting seismic data, and constructing a simulation grid based on the key stratum sequence stratum grid; secondly, utilizing attribute analysis such as seismic coherence or amplitude to establish the lithology of the stratum of the basin, fine distribution of faults and cracks, combining geological data such as regional logging and rock cores, establishing parameters such as lithology and physical properties of sediments, and constructing a fine geological model based on fault activity and sand spreading characteristics; then, a stratum temperature model is built by using regional stratum temperature and heat flow data, and a hydrocarbon generation model is built by using total organic carbon content (TOC), hydrogen index, hydrocarbon generation dynamics model and the like; and by constructing a phase balance model of II type hydrate, calculating the saturation of II type hydrate, analyzing the influence mechanism of regional fluid migration, favorable sand body and other sediments, faults, cracks and other structures on the enrichment of the hydrate, simulating and predicting the distribution and saturation of a potential II type hydrate layer, and the method can realize the prediction of the saturation of II type hydrate without drilling logging data. Even without drilling data, the distribution and saturation of the high-flux fluid development zone II hydrate layer can be analyzed by constructing hydrocarbon-producing models through seismic data, regional geological data, and the like.
Specifically, as shown in fig. 1, the embodiment provides a method for predicting the saturation of a II-type hydrate based on hydrocarbon generation simulation, which is used for developing a high-flux fluid development zone II-type hydrate generation potential simulation, and the method is used for finely identifying faults and fracture characteristics of formation development based on three-dimensional seismic data, calculating a II-type hydrate stability zone bottom boundary, constructing a fine formation grid, a regional formation temperature field and a hydrocarbon source rock gas production model, selecting a proper fluid migration model, fault activity time, II-type hydrate formation simulation and the like, and establishing a quantitative evaluation method suitable for the formation and saturation of a II-type hydrate in a thermal cause gas development zone, and comprises the following steps:
establishing a simulation grid:
step 1: a typical seismic section is selected, a layer sequence stratum grid of key stratum is established by utilizing basic geological data of a research area, and a simulation grid is established on the basis of the layer sequence stratum grid, wherein in the embodiment, the transverse resolution of the model grid is 10m, the longitudinal resolution of deep stratum (> 500 m) of a vertical depth grid is 20m-50m (related to the resolution of the seismic data), and the longitudinal resolution of shallow stratum (< 500 m) is 5m.
Building a fine geological model:
step 2: extracting seismic root mean square amplitude attribute from seismic data by using a traditional technical method, and establishing sedimentary facies distribution; extracting root mean square amplitude attribute along 5m below layers of different ages, combining logging, rock core and regional geology and other data analysis, identifying the relationship between the seismic phase and the sedimentary facies of a typical seismic section, wherein weak-medium amplitude abnormality is mudstone sediment, strong amplitude abnormality is sandstone sediment, and developing sandstone sediment and mudstone sediment identification and distribution depiction (shown in figure 2);
step 3: constructing a physical property such as porosity, permeability and the like of the simulated section and a lithologic section;
calculating sand and mudstone contents of different sedimentary phases by using gamma logging data of a target area and a nearby area through a formula (1), and combining rock core data to establish lithology parameters in a model:
I GR ＝(GR log -GR min )/(GR max -GR min )，
V cl ＝0.083(2 3.7×IGR -1) (1)
in which I GR To normalize natural gamma values, GR log For measuring gamma, GR min Is the minimum gamma value (representing pure sandstone), GR max The gamma value is the maximum gamma value (representing pure mudstone), the unit of the gamma value is api, and the value is obtained from the hydrate logging GMGS5-W08 well data, wherein GR min Take the value of 0api, GR max The value is 147api; v (V) cl For the calculated mudstone content;
and (3) fitting and establishing a rock porosity change formula (2) along with depth by utilizing measured porosity data, and establishing porosity physical parameters in a model:
Φ＝1.244×D -0.181 (2)
wherein D is depth, the unit is m, and phi is porosity;
the permeability was determined based on the porosity (Φ) calculated in equation 2 using the Kozeny-Carman model, and the formation permeability parameters in the model were established.
Step 4: by utilizing conventional seismic attribute extraction methods such as coherence and ant tracking, the regional structural faults and the internal cracks of the stratum are finely identified;
the seismic coherence attribute is extracted, faults and cracks are identified based on a coherence and ant tracking method, fault characteristics of a research area are analyzed (figure 2), and in the embodiment, the key extraction method comprises the following steps: removing random noise of seismic data and retaining fault boundary and other information through construction smoothing, wherein a processed filtering window is 1; extracting a seismic coherence body, calculating the similarity between seismic channels, and carrying out boundary detection, wherein a calculated seismic channel window is 3; tracking discontinuous boundaries by using an ant tracking technology, wherein the ant distribution radius is 5, the ant searching step length is 3, the tracking deviation, the effective step length and the ineffective step length are all 2, and when the number of the ineffective step length is 10% of the searching space, the tracking is stopped;
specifically, as shown in fig. 2, fig. 2 is a superimposed graph of a three-dimensional seismic data, identifying sand-rich sediments, coherence and ant tracking technologies based on root mean square attribute, identifying formation fractures and fissures, and a seismic profile, wherein an interposed layer 1 extracts root mean square amplitude along a bulk carrier sediment 3 (MTD), a window is 5m down from the horizon, and the spatial distribution of fractures and fissures in a research area is interpreted, so as to provide a fluid migration path and a fine geological model for simulation.
Step 5: in combination with steps 1-4, the simulated grids are assigned values according to the established layer sequence stratigraphic framework and simulated grids (step 1), sedimentary facies distribution (step 2), lithology, porosity parameters, permeability parameters (step 3), and identified faults and cracks (step 4), physical parameters such as lithology, porosity, permeability and the like of each simulated grid are defined, and the faults and cracks are distributed along the boundaries of a plurality of simulated grids, and the elements jointly construct a fine geological model as shown in fig. 3. The fault opening time is the opening through the stratum thickness difference of the stratum cut through the fault, when the stratum thickness is different, the fault activity time is different, and the fault is the opening, so that the fluid migration time difference and the influence of the fluid migration time difference on the type II hydrate reservoir are simulated.
Type II hydrate saturation prediction:
step 6: based on the fine geological model constructed in the step 5, the Mckenzie model is utilized, data such as actually measured seabed temperature, ground temperature gradient, regional heat flow and the like are input to carry out stratum temperature profile numerical simulation, the stratum temperature profile numerical simulation is compared and corrected with actual stratum temperature data of a hydrate enrichment region, based on temperature distribution of bio-generated hydrocarbon (stratum temperature range is 35-75 ℃) and thermally generated hydrocarbon (temperature is more than 100 ℃), stratum depth ranges of the bio-generated hydrocarbon and the thermally generated hydrocarbon are established on a simulated calculated temperature field profile, as shown in fig. 4a, the simulated calculated stratum temperature field is compared with logging temperature, and a schematic diagram of the depth distribution ranges of the bio-generated hydrocarbon and the thermally generated hydrocarbon is divided according to the bio-generated hydrocarbon temperature and the thermally generated hydrocarbon temperature.
Step 7: collecting a biological and thermal hydrocarbon generation kinetic model influenced by a temperature field and total organic carbon content (TOC) and hydrogen index of organic matters of source rock in a region, wherein the biological hydrocarbon generation kinetic model is a normal distribution model established based on a biological hydrocarbon generation temperature range, and the optimal hydrocarbon generation temperature is 55 ℃; the thermal hydrocarbon generation dynamics model is based on hydrocarbon generation dynamics model data obtained by previous human hydrocarbon generation thermal simulation experiments, and based on regional hydrocarbon source rock geochemistry research basis, the organic matter kerogen type in the thermal hydrocarbon generation stratum is determined to be mainly based on type III kerogen, and the Burnham type III thermal hydrocarbon generation dynamics model is adopted. Because the simulated hydrate generation is based on the calculation of the solubility of methane in pore water, hydrocarbon source rock hydrocarbon generation only considers methane generation, respectively constructs an organic matter hydrocarbon generation model of biogenic methane and thermal genic methane, and calculates hydrocarbon source rock organic matter hydrocarbon generation by combining the formation temperature profile simulated in the step 6;
step 8: and (3) simulating a methane fluid migration path generated by hydrocarbon generation on the basis of the organic matter hydrocarbon generation calculated in the step (7).
(1) Based on the permeability difference calculated in step 3, the low permeability mud-rich formation and the high permeability sand-rich formation can be classified in a geologic model:
wherein the gate conditions of the high permeability sand-rich formation are when the porosity is 30% and the permeability is greater than-2.01 log (mD). Simulating and calculating fluid migration characteristics along different stratum by utilizing a Hybrid migration model (figure 4 b), and calculating by adopting a Darcy model for the stratum with low permeability, wherein the fluid migration is controlled by the relative permeability and capillary pressure among the model grids; in the stratum with high permeability, the fluid migration is controlled by buoyancy by adopting a Flowpath model to calculate;
FIG. 4b is a graph of the calculated high flux migration paths of fluid above the substrate ridge through different migration modes, showing that the fluid migration along the faults above the substrate is different, and the fluid migration along different distribution areas is different, and from the result of the fluid migration simulated in FIG. 4b, the result shows that the high flux fluid accumulation area above the substrate ridge, the lateral migration of deep biological and thermal cause gas along the stratum on two sides of the substrate, and the migration along the faults above the substrate are the main control factors of the hydrate enrichment of the area, the distribution areas of the faults are different, the scale of the fluid migration is different, and the difference can be simulated by constructing different faults.
(2) Calculating fluid migration controlled by structures such as faults and the like by using a fault migration model, simulating fluid migration processes of different faults according to distribution positions of the interruption layers in the step 5, and taking whether the thickness of the fault cut-through stratum is different as a fault opening time setting basis;
the fault activity time is selected in the simulation as follows: the open times of faults 1a, b, c and 2 distributed along the substrate are 5Ma to today, the open times of faults 3 distributed along the upper side of the substrate are 1Ma to today, the open times of internal cracks along MTD1, MTD2 and MTD3 are 0.2Ma, 0.3Ma and 0.4Ma to today, respectively, and the open times of cracks distributed along fault 1a are 0.4Ma to today.
Step 9: based on the contents of gas components such as methane, ethane, propane and the like, acquiring a temperature-pressure curve of phase equilibrium of the type I hydrate and the type II hydrate by using an open source conventional method (CSMGem software), and calculating the depths of bottom boundaries of the type I hydrate and the type II hydrate through intersection points of the two temperature gradient data of a simultaneous region;
step 10: and (3) calculating the type II hydrate saturation on the basis of the hydrocarbon source rock organic matter hydrocarbon generation and methane migration paths calculated in the step (7) and the step (8). Obtaining a solubility curve of methane in pore water and a pressure curve of methane hydrate decomposition by using a Tishchenko model; when methane enters the hydrate stability zone and exceeds methane solubility, supersaturated methane will immediately form hydrates, and methane solubility is lower than saturation, or formation pressure exceeds the decomposition pressure of methane hydrate, which will decompose. According to the principle, the hydrate saturation is obtained by dividing the volume of supersaturated methane forming hydrate by the total pore volume through the sediment pore parameters calculated in the step 3. And (3) the hydrate between the methane (I type) and the II type hydrate stability zone bottom boundary calculated in the step (9) is the II type hydrate.
Step 11: and 7, analyzing the simulation results of the steps 7, 8, 9 and 10, predicting the difference of the saturation and distribution of the type II hydrate formed by different structures such as a fluid migration path, a favorable sand body, a fault, a crack and the like and a deposition change region, and summarizing the saturation and spatial distribution main control factors of the type II hydrate layer.
As shown in fig. 5, fig. 5 (a) shows a fine geologic model constructed based on seismic interpretation, with faults as shown in fig. 4b; fig. 5 (b) simulates type II hydrate saturation and distribution, and fig. 5 (c) bulk handling sediment bottom sandstone-free reservoir simulates type II hydrate saturation and distribution. Indicating that at the high flux fluid blowby zone, the hydrate is distributed in the sand-rich deposit, and near the fault and the fracture, the type II hydrate is affected by sandstone near the stable zone, and is distributed under the methane stable zone in a transverse semi-continuous mode with the saturation degree being more than 20 percent and the thickness being more than 20 m.
From the results of simulation calculation of type II hydrate saturation using type II hydrate stability zone in combination with fine faults and fissures and sand-rich sediment spread in FIG. 5, it can be seen that the hydrate layer in the stability zone is mainly distributed along faults, fissures and in the sand-rich sediment, and the hydrate layer with high saturation (more than 50%) is more easily formed near the faults, which is consistent with the hydrate distribution characteristics found by drilling in the research area. The hydrate distribution in the different zones is different and is directly related to the fluid migration scale along the fault above the substrate. Simulation results show that there is a semi-continuous distribution of type II hydrate layers below the methane stability zone with a saturation greater than 20% and a thickness that can be greater than 20m, consistent with verification of the distribution of type II hydrate layers identified by earthquakes and W08 wells, and that such hydrate layers cannot be formed in simulations without favorable sand spread, indicating that the distribution of favorable sand has a critical impact on the saturation and distribution of hydrate layers within the stability zone.
The present invention is not limited to the above-mentioned embodiments, and any equivalent embodiments which can be changed or modified by the technical content disclosed above can be applied to other fields, but any simple modification, equivalent changes and modification made to the above-mentioned embodiments according to the technical substance of the present invention without departing from the technical content of the present invention still belong to the protection scope of the technical solution of the present invention.
Claims (8)
1. The method for predicting the type II hydrate saturation based on hydrocarbon production numerical simulation is characterized by comprising the following steps of:
step A, establishing a simulation grid: building a layer sequence stratum grid based on the seismic data, and building a simulation grid based on the layer sequence stratum grid;
step B, constructing a fine geological model: establishing the lithology of the stratum and the fine distribution of faults and cracks; and combining relevant geological data, establishing sediment lithology and physical parameters, and realizing fine geological model construction based on fault activity and sand spreading characteristics;
step C, II type hydrate saturation prediction:
step C1, constructing a stratum temperature model by using regional stratum temperature and heat flow data, performing temperature field simulation, and establishing a stratum depth range of biological and thermal hydrocarbon generation;
step C2, constructing an organic matter hydrocarbon generation model by utilizing the TOC (total organic carbon) content, the hydrogen index and the hydrocarbon generation kinetic model;
and C3, calculating the saturation of the type II hydrate by constructing a type II hydrate phase balance model, analyzing the influence mechanism of regional fluid migration, favorable sand deposition, fault and fracture structure on the hydrate enrichment, and simulating and predicting the potential distribution and saturation of the type II hydrate layer.
2. The method for predicting the saturation of type II hydrates based on hydrocarbon generation numerical modeling of claim 1, wherein: the step B specifically comprises the following steps:
step B1, extracting seismic root mean square amplitude attribute aiming at seismic data, and establishing sedimentary facies distribution;
step B2, constructing a physical property profile and a lithology profile of the simulated profile, wherein physical property parameters comprise porosity and permeability;
step B3, based on a seismic attribute extraction method, finely identifying regional structural faults and stratum internal cracks;
and B4, combining the step A with the step B1-the step B3, determining the distribution of the simulated earthquake section in a typical earthquake section, assigning values to the simulated grids of the section, defining lithology and physical parameters of each simulated grid, and distributing faults and cracks along the boundaries of a plurality of simulated grids, and constructing a fine geological model.
3. The method for predicting the saturation of type II hydrates based on hydrocarbon generation numerical modeling of claim 2, wherein: in the step B2, the following steps are specifically implemented:
(1) Calculating sand and mudstone contents of different sedimentary phases by using gamma logging data of a target area and a nearby area through a formula (1), and combining rock core data to establish lithology parameters in a model:
I GR ＝(GR log -GR min )/(GR max -GR min )，
V cl ＝0.083(2 3.7×IGR -1)(1)
in which I GR To normalize natural gamma values, GR log For measuring gamma, GR min At minimum gamma, GR max At maximum gamma value, V cl For the calculated mudstone content;
(2) And (3) fitting and establishing a rock porosity change formula (2) along with depth by utilizing measured porosity data, and establishing porosity physical parameters in a model:
Φ＝1.244×D -0.181 (2)
wherein D is depth and phi is porosity;
and (3) utilizing a Kozeny-Carman model, calculating the permeability based on the calculated porosity phi, and establishing stratum permeability parameters in the model.
4. The method for predicting the saturation of type II hydrates based on hydrocarbon generation numerical modeling of claim 2, wherein: the step B3 is specifically realized by the following steps:
extracting seismic coherence properties, identifying faults and cracks based on coherence and ant tracking methods, analyzing fault characteristics of a research area, and extracting key modes comprises: removing random noise of the seismic data and retaining fault boundary information through construction smoothing; and is combined with
Extracting a seismic coherence body, calculating the similarity between seismic channels and performing boundary detection; discontinuous boundaries are tracked using ant tracking techniques.
5. The method for predicting the saturation of type II hydrates based on hydrocarbon generation numerical modeling of claim 1, wherein: the step C1 is specifically realized by the following steps:
b, based on the fine geological model constructed in the step B, inputting actually measured seabed temperature, ground temperature gradient and regional heat flow data to perform stratum temperature profile numerical simulation by utilizing a Mckenzie model, comparing and correcting with actual stratum temperature data of a hydrate enrichment region, and based on temperature distribution of bio-generated hydrocarbon and thermal-generated hydrocarbon, establishing stratum depth ranges of the bio-generated hydrocarbon and the thermal-generated hydrocarbon on a simulated calculated temperature field profile.
6. The hydrocarbon generation numerical simulation-based type II hydrate saturation prediction method according to claim 5, wherein: the step C2 is specifically realized by the following steps:
(1) Collecting a biological hydrocarbon generation dynamic model and a thermal hydrocarbon generation dynamic model of total organic carbon content TOC, hydrogen index HI of organic matters of source rock of a region and influenced by a temperature field,
the biological hydrocarbon generation dynamics model is a normal distribution model established based on a biological hydrocarbon generation temperature range, the thermal hydrocarbon generation dynamics model is based on hydrocarbon generation dynamics model data obtained by the existing hydrocarbon generation thermal simulation experiment, the organic matter kerogen type in the thermal hydrocarbon generation stratum is determined to be mainly based on regional hydrocarbon source rock geochemistry research basis, and a BurnhamIII type thermal hydrocarbon generation dynamics model is adopted;
(2) And (3) respectively constructing an organic matter hydrocarbon generation model of biogenic methane and thermal biogenic methane, and calculating hydrocarbon source rock organic matter hydrocarbon generation by combining the stratum temperature profile simulated in the step C1.
7. The hydrocarbon generation numerical simulation-based type II hydrate saturation prediction method according to claim 6, wherein: the step C3 comprises the following steps:
step C31, simulating a methane fluid migration path generated by hydrocarbon generation:
(1) Dividing the geological model into a low-permeability mud-rich stratum and a high-permeability sand-rich stratum according to the permeability calculated in the step B2;
wherein, the gate boundary conditions of the high permeability sand-rich stratum are: porosity of 30% and permeability greater than-2.01 log (mD); simulating and calculating fluid migration characteristics along different stratum by utilizing a Hybrid migration model; for a low-permeability mud-rich stratum, darcy model calculation is adopted, and fluid migration is controlled by the relative permeability and capillary pressure among model grids; in the high-permeability sand-rich stratum, the fluid migration is controlled by buoyancy by adopting a Flowpath model to calculate;
(2) Calculating fluid migration controlled by a fault structure by using a fault migration model, and simulating fluid migration processes of different faults according to the distribution position of the interruption layers in the step B4, wherein whether the thickness of the fault cut-through stratum is different or not is used as a fault opening time setting basis;
step C32, based on the content of gas components, acquiring a temperature-pressure curve of phase equilibrium of the type I hydrate and the type II hydrate, and calculating the bottom boundary depth of the type I hydrate and the type II hydrate through intersection points of the two data;
and C33, calculating the type II hydrate saturation on the basis of the hydrocarbon source rock organic matter hydrocarbon generation and methane migration paths calculated in the step C2 and the step C31.
8. The hydrocarbon generation numerical simulation-based type II hydrate saturation prediction method according to claim 7, wherein: the step C33 is specifically implemented by the following manner:
a solubility curve of methane in pore water and a pressure curve of methane hydrate decomposition are given by using a Tishchenko model; when methane enters the hydrate stability zone and exceeds the methane solubility, supersaturated methane immediately forms hydrate, and when the methane solubility is lower than the saturation state, or the formation pressure exceeds the decomposition pressure of methane hydrate, the hydrate is decomposed, and on the basis, the hydrate saturation is determined by the sediment pore parameters calculated in the step B2; and (3) combining the hydrate between the stable band bottom boundaries of the type I and type II hydrates calculated in the step C32 to obtain the type II hydrate.
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