Rock gas content calculation method based on well site analytic experiment
阅读说明：本技术 一种基于井场解析实验的岩石含气量计算方法 (Rock gas content calculation method based on well site analytic experiment ) 是由 仰云峰 朱地 张焕旭 彭宇 徐志尧 于 2019-09-30 设计创作，主要内容包括：本发明公开了一种基于井场解析实验的岩石含气量计算方法,采用综合考虑了气体膨胀、脱附和滑脱效应的气体流动物理模型,通过拟合井场解析气实验数据确定物理模型中的气体渗透率参数,再结合页岩岩芯深度、泥浆密度、初始地层压力和起钻过程等地质参数,运用已知物理模型数值计算岩芯内气体解析过程,从而确定初始压力条件下岩石原地含气量,以及岩石当为页岩时游离气和吸附气的比例。(The invention discloses a rock gas content calculation method based on a well site analytic experiment, which adopts a gas flow physical model comprehensively considering gas expansion, desorption and slippage effects, determines a gas permeability parameter in the physical model by fitting well site analytic gas experimental data, and calculates a gas analytic process in a rock core by using known physical model numerical values in combination with geological parameters such as shale core depth, mud density, initial formation pressure, a tripping process and the like, thereby determining the in-situ gas content of the rock under an initial pressure condition and the proportion of free gas and adsorbed gas when the rock is shale.)
1. A rock gas content calculation method based on a well site analytic experiment is characterized by comprising the following steps: (1) obtaining an analytic sample and recording a first parameter of the analytic sample; (2) carrying out a well site gas content analysis experiment on the analysis sample to obtain an accumulated analysis gas-time curve graph and an analysis gas amount; (3) determining a second parameter of the analysis sample, and determining zero time and corresponding depth of the analysis sample for starting degassing according to the fact that the mud boundary pressure is equal to the formation pressure; (4) selecting an apparent permeability equation general formula and a gas flow equation to fit the accumulated analytic gas quantity-time curve graph obtained in the step (2) by taking the formation pressure as an initial condition and the mud column pressure in the drill lifting process as a boundary condition, and obtaining a specific apparent permeability equation; (5) calculating the gas loss from the zero point time to the beginning time of the analytical experiment by adopting a gas flow equation containing a specific apparent permeability equation, and measuring the residual gas amount; (6) and obtaining the gas content of the rock according to the lost gas amount, the analyzed gas amount and the residual gas amount.
2. The method for calculating the gas content of the rock based on the wellsite analytic experiment of claim 1, wherein the analytic sample in the step (1) is tight sandstone or shale.
3. The method of claim 1, wherein the first parameters of the analytic sample in step (1) comprise size, depth, time to trip, time to wellhead, analytic experiment start time, formation pressure, mud density.
4. The method of claim 1, wherein the second parameter of the analytical sample in step (3) comprises porosity, rock density, Langmuir volume, Langmuir pressure.
5. The method for calculating gas content in rock based on wellsite analytic experiments as claimed in claim 1, wherein the apparent permeability equation in step (4) has a general formula:
6. The method of claim 5, wherein the first order equation of the general equation of apparent permeability in step (4) is applied to slip flow, the second order equation is applied to slip flow and early transition flow, and the higher order equation is applied to slip flow-transition flow-Knudsen flow.
7. The method for calculating gas content of rocks based on wellsite analytic experiments as claimed in claim 1, wherein the gas flow equation in steps (4) and (5) is:
(1)
(2)wherein formula (1) is used for compact sandstone gas, formula (2) is used for shale gas, rho g is gas density, phi is gas porosity, rho r is rock density, rhostd is gas standard condition density, and V isLAnd PLLangmuir volume and Langmuir pressure, c, respectively, of shalegFor gas compression, r is the core radius.
8. The method of claim 7, wherein the gas flow equation is solved using finite difference, finite element or finite volume methods.
9. The method for calculating the gas content of the rock based on the wellsite analytic experiment as claimed in claim 1, wherein the step (6) further comprises obtaining the adsorbed gas and the free gas of the shale according to a pneumatic flow equation when the analytic sample is a core of the shale.
10. The method of claim 1, wherein the adsorbed gas and the free gas are calculated separately at each time according to a gas flow equation.
Technical Field
The invention relates to the technical field of unconventional oil and gas exploration and development, in particular to a rock gas content calculation method based on a well site analytic experiment.
Background
Unconventional shale gas and tight sandstone gas have become important components in the global energy structure, but resource amount evaluation data from different sources have great difference, because a unified method and a unified specification are not formed in the calculation of the gas content in situ. The method for determining the in-situ gas content of the shale at the present stage mainly comprises a formula calculation method and a field experiment method. A perfect formula calculation method is proposed by Ambrose et al (Ambrose et al, 2012, Shale gas-in-place calculations Part I: New pore-scale correlations, SPE Journal,219-229), the fundamental core of which is a three-phase pore (water-adsorbed gas-free gas) model, the pore space occupied by the adsorbed gas is corrected, the free gas quantity and the adsorbed gas quantity under the reservoir condition are respectively calculated, and the Shale gas content (CN108593493A) can be more accurately evaluated based on the method and corresponding experimental tests, but the volume method can only provide static gas content data. The field Test Method, The field gas content analysis Test (Canister Test), is widely used to measure The volume of gas released by a coal or shale core sample, and then The USBM Direct Method is used to analyze The gas analysis data to determine The gas content in The core (Bernard et al, 1970, Determination of The desorbable gas concentrations of The chemical (Direct Method), International Journal of rock Mechanics and Mining Science,7: 43-65; Kissell et al, 1973, The Direct of The Determination of The measurement of The process content for The description design, USBureau of The Mines Report of investments 7767, p.22). According to the USBM direct method, the gas content of a rock core is divided into three parts of lost gas, analytic gas and residual gas, the analytic gas and the residual gas are obtained through a field analytic experiment, the lost gas is obtained by fitting analytic gas data and then advancing to zero time, and a linear extrapolation method is firstly adopted to obtain the lost gas, but when the lost gas exceeds 20% of the total gas or the rock core is buried deep and overpressurized (Bertard et al, 1970; Yee et al, 1993), the linear extrapolation method becomes inaccurate, the gas content is underestimated, and the polynomial extrapolation method is often used for overestimating the lost gas (Diamond et al, 2001). For shale gas, the burial depth generally exceeds 2000m, the coring process is time-consuming, the gas loss generally exceeds 20% of the total gas, and the gas loss of the overpressure stratum is larger. In addition, the direct method is empirical for the determination of the zero point time (Kissell et al, 1973). More importantly, the direct method fails to describe the complex flow mechanism of the free gas and the adsorbed gas in the shale. The accurate shale gas content cannot be obtained by a direct method if only the zero point time and the lost time are corrected (CN 105203428B). Just there are many uncertainties in accurate recovery of the lost gas amount in the field experiment method, a series of analytical simulation devices and experimental methods are proposed in succession for evaluating the shale gas amount (CN106168565A, CN106970001A, CN104713802B, CN105675434B, CN106370260B, CN106525637A, CN107192632A, CN107462491A, CN107727530A, CN108254289A, CN108469396A, CN108627414A, CN110095375A), all of these simulation devices basically have complex design structures, and there are many details difficult to implement in the actual implementation process, and more importantly, these ideal simulation devices and experimental methods will be developed once facing the deep ultra-high pressure shale gas (the burial depth is more than 4000 m). The scientific theoretical calculation method has wider application prospect in the aspects of shale gas content and reserve evaluation. The patent CN108240952A proposes an analytical method for calculating shale gas content, which is to perform error analysis on gas content data obtained from well site analytical experiments and a plurality of empirical formulas respectively to obtain an adsorbed gas amount fitting formula and a free gas amount fitting formula. Therefore, the shale gas content calculation method disclosed by the patent CN108240952A has no wide application prospect in practice.
Disclosure of Invention
The invention mainly solves the technical problem of providing a rock gas content calculation method based on a well site analytic experiment, which can be applied to the evaluation of the in-situ gas content of compact rocks (shale and compact sandstone) and the resource amount calculation.
In order to solve the technical problems, the invention adopts a technical scheme that: the rock gas content calculation method based on the well site analytic experiment comprises the following steps: (1) obtaining an analytic sample and recording a first parameter of the analytic sample; (2) carrying out a well site gas content analysis experiment on the analysis sample to obtain an accumulated analysis gas-time curve graph and an analysis gas amount; (3) determining a second parameter of the analysis sample, and determining zero time and corresponding depth of the analysis sample for starting degassing according to the fact that the mud boundary pressure is equal to the formation pressure; (4) selecting an apparent permeability equation general formula and a gas flow equation to fit the accumulated analytic gas quantity-time curve graph obtained in the step (2) by taking the formation pressure as an initial condition and the mud column pressure in the drill lifting process as a boundary condition, and obtaining a specific apparent permeability equation; (5) calculating the gas loss from the zero point time to the beginning time of the analytical experiment by adopting a gas flow equation containing a specific apparent permeability equation, and measuring the residual gas amount; (6) and obtaining the gas content of the rock according to the lost gas amount, the analyzed gas amount and the residual gas amount.
In a preferred embodiment of the present invention, the desorption sample in the step (1) is tight sandstone or shale.
In a preferred embodiment of the present invention, the first parameters of the analysis sample in step (1) include size, depth, tripping time, time to reach wellhead, analysis experiment start time, formation pressure, and mud density.
In a preferred embodiment of the present invention, the second parameter of the resolved sample in step (3) comprises porosity, rock density, Langmuir volume, Langmuir pressure.
In a preferred embodiment of the present invention, the apparent permeability equation in step (4) has the general formula:
In a preferred embodiment of the present invention, the first order equation of the general equation of apparent permeability in step (4) is applied to slip flow, the second order equation is applied to slip flow and early transition flow, and the high order equation is applied to slip flow-transition flow-Knudsen flow.
In a preferred embodiment of the present invention, the gas flow equation in steps (4) and (5) is:
In a preferred embodiment of the invention, the gas flow equations are solved using finite difference, finite element or finite volume methods.
In a preferred embodiment of the present invention, the step (6) further comprises obtaining adsorbed gas and free gas of the shale according to a pneumatic flow equation when the sample is analyzed to be a shale core.
In a preferred embodiment of the invention, the adsorbed gas and the free gas are calculated separately at each instant according to the gas flow equation.
The invention has the beneficial effects that: the invention discloses a rock gas content calculation method based on a well site analytic experiment, which adopts a gas flow physical model comprehensively considering gas expansion, desorption and slippage effects, determines a gas permeability parameter in the physical model by fitting well site analytic gas experimental data, and calculates a gas analytic process in a rock core by using a known physical model numerical value in combination with geological parameters such as shale core depth, mud density, initial formation pressure, a tripping process and the like, thereby determining the in-situ gas content of the rock under an initial pressure condition and the proportion of free gas and adsorbed gas when the rock is shale.
Drawings
In order to more clearly illustrate the technical solutions in the embodiments of the present invention, the drawings needed to be used in the description of the embodiments are briefly introduced below, it is obvious that the drawings in the following description are only some embodiments of the present invention, and other drawings can be obtained by those skilled in the art without inventive efforts, wherein:
FIG. 1 is a graph of on-site gas content of a J2 well Longmaxi shale sample (2545.65m) in an example of the present invention
Analyzing an experimental data graph;
FIG. 2 is a graph of model fitting results in an embodiment of the invention;
FIG. 3 is a graph of the recovery of the amount of lost gas in an embodiment of the present invention;
fig. 4 is a graph of evolution of gas content over time in an embodiment of the invention.
Detailed Description
The technical solutions in the embodiments of the present invention will be clearly and completely described below, and it is obvious that the described embodiments are only a part of the embodiments of the present invention, and not all embodiments. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present invention.
Taking the example of shale of Longmaxi group of J2 well in Fuling area, the implementation process of calculating the shale gas content based on the gas content data of the wellsite analytic experiment is specifically explained.
(1) Well site gas content analysis experiment and relevant parameters of experiment conditions
A sample of shale core from Longmaxi group of J2 well in Fuling area is obtained from burial depth 2545.55-2545.75m, and the sample has a geometric shape of regular cylinder, diameter of 10cm, length of 20cm and weight of 3555 g. The formation pressure is 37.7MPa, and the mud density is 1550kg/m3. The core drilling time is 7 months, 24 days, 23:30:00, the well head reaching time is 7 months, 25 days, 6:00:00, and the analysis experiment starting time is 7 months, 25 days, 6:17: 00. And (3) carrying out a gas content analysis experiment on the well site where the analysis sample is located, wherein the water bath temperature of the analysis experiment is 53 ℃, and is the same as the mud circulation temperature. And analyzing the gas quantity data, automatically recording once every 30 seconds, and simultaneously monitoring the environmental temperature and the environmental pressure in real time. The gas content analysis data is converted into the gas volume under standard conditions, and a cumulative analysis gas quantity-time curve graph is obtained, as shown in fig. 1. Fig. 1 is a plot of cumulative desorbed gas (standard) versus time for the first 2.81 hours of a sample of a shale core from ramstream (2545.65m), for a total desorbed gas volume of 1790 ML.
The most important experimental test in the drilling field in the exploration process of shale gas and tight sandstone gas is a gas content analysis experiment, a constant-temperature water bath and drainage gas collection (or mass flow meter) device is adopted to measure the degassing process of a rock core, and the change curve of the analysis gas content along with time is recorded. Specific references may be made to: the shale gas field gas content testing technology of the experimental geological technology of the national petrochemical tin-free petroleum geological research institute, the petroleum experimental geology 2015,37(4) 535 + 535; CN108982289A, a shale gas on-site analysis device and method; CN103063545A, a novel shale gas content tester and a shale gas content measuring method; CN103808592A, shale gas content tester; CN105203428A, a method for determining the content of lost gas in shale gas content; CN105223099A, shale gas content tester and test method thereof. Parameters such as size, depth, tripping time, time to reach the wellhead, analysis experiment start time, formation pressure, mud density and the like are needed to be used in calculation, and the fitted equation is a function of the pressure variation in time (drilling time and analysis time) and space (core size).
(2) After the well site analytical experiment is completed, a plunger sample and a chip sample are taken from the analytical sample, and porosity determination and isothermal adsorption experiments are carried out, wherein the porosity determination and isothermal adsorption experiments are carried out through indoor experiments. The porosity of the shale is 5%, the porosity of the gas is 3.5%, the volume of the Langmuir is 2.02ml/g, the pressure of the Langmuir is 2.86MPa, and the rock density is 2556kg/m3. The core withstood a mud boundary pressure of 38.76MPa greater than the formation pressure of 37.7MPa at the starting depth, so the zero time corresponds to a depth of 2475.8m, and the zero time is 7 months, 24 days, 23:40: 42. The second parameter is different for shale and tight sandstone.
Initial pressure conditions were formation pressure 37.7MPa, mud pressure [0.01519 (2475.8-0.1088 t) +0.093(MPa)]For the boundary condition, an apparent permeability second order equation and a gas flow equation (2) are selected to fit the experimental data in fig. 1, the model calculation result is very consistent with the measured data, as shown in fig. 2, and the specific apparent permeability second order equation is obtained as follows: k is-5.0806/P2+68.734/P+3.5597。
(3) Using an equation involving a specific apparent permeability (k-5.0806/P)2+68.734/P +3.5597) to the initial gas content, the total gas loss is 19986.64ML as shown in fig. 3.
Loss amount 19986.64ML, solutionGas evolution quantity is 1790ML, residual gas quantity is 1650ML, total gas quantity is 23.43L, thus the original gas content of the Longmaxi group shale sample is 6.59m3T is calculated. The adsorbed gas and the free gas are calculated independently at each moment according to the gas flow equation, so that the initial free gas amount and the initial adsorbed gas amount are respectively 4.82m3T and 1.77m3T, and the evolution of free and adsorbed gas over time, as shown in FIG. 4.
The invention provides a numerical method for calculating in-situ gas content of a rock based on well site analytic experimental data. The method comprises the steps of adopting a physical model comprehensively considering gas expansion, desorption and slippage effects, determining gas permeability parameters in the physical model by fitting well field gas analysis experimental data, and calculating a core gas analysis process by using known physical model numerical values in combination with geological parameters such as shale core depth, mud density, initial formation pressure and a tripping process, so as to determine the in-situ gas content of rocks under initial conditions and the proportion of free gas and adsorbed gas when the rocks are formed.
The invention discloses a gas flow physical model based on porous medium seepage mechanics, and a numerical calculation method for evaluating shale in-situ gas content under stratum conditions by simultaneously considering shale adsorption/desorption effect and a real gas state equation, and has advanced scientificity and wide applicability. Of course, for tight sand gas, the method is equally applicable without taking into account adsorption/desorption effects. The method mainly comprises the steps of combining a well site gas content analysis experiment and a gas flow physical model, determining physical model parameters through fitting analysis experiment gas content data, calculating a change process of gas concentration in a rock core along with time according to initial formation pressure and boundary pressure condition values in a drill lifting process, and determining initial gas content and gas content evolution.
For a core of constant temperature and regular shape (cylindrical shape with fixed radius), the time of change of the gas concentration in the rock with time is equal to the mass of gas flowing out of the rock, i.e. the mass of gas flowing out of the rock
The gas concentration composition is determined by the occurrence of gas in different tight rocks, and for tight sandstone gas, the gas concentration is only related to free gas, while the gas concentration in shale comprises free gas and adsorbed gas.
Flow rate of flowFor dense rock, k is the apparent permeability and μ is the gas viscosity. Gas viscosity can be calculated directly from The LGE equation (Lee et al, 1966, The viscocity of natural gases) or other equations. The apparent permeability is a function of gas pressure, and according to the basic principle of micro-nano scale gas flow, three functional relations exist between the apparent permeability and the pressure:
first order k ═ k∞(1+c/P)
K being the second order∞(1+c1/P+c2/P2)
High order
k∞Absolute permeability, P is pressure, c1、c2And alpha and A are unknown coefficients. The first order equation is applicable to slip flow, the second order equation is applicable to slip flow and early transition flow, and the high order equation is applicable to slip flow-transition flow-Knudsen flow. Therefore, in practical applications, it is necessary to select an appropriate formula for calculating the gas flow rate for specific situations (pore pressure and pore size distribution). See in particular the choices in the examples above.
The gas flow equation can be rewritten as:
(1)
(2)
formula (1) is used for tight sandstone gas, and formula (2) is used for shale gas. ρ g is the gas density, φ is the gas porosity, ρ r is the rock density, ρ std is the gas standard density, and VL and PL are the Langmuir volume and Langmuir pressure, respectively, of the shale. Considering the true gas equation of state and core radial flow, the gas flow equation can be written as:
(1)
(2)
the above equations can be solved by finite difference method, finite element method or finite volume method. In the formula cgIs gas compression and r is core radius.
The above description is only an embodiment of the present invention, and not intended to limit the scope of the present invention, and all modifications of equivalent structures and equivalent processes, which are made by the present specification, or directly or indirectly applied to other related technical fields, are included in the scope of the present invention.
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