CN117823127A - Method for evaluating gas layer and post-pressure gas production capacity - Google Patents
Method for evaluating gas layer and post-pressure gas production capacity Download PDFInfo
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- CN117823127A CN117823127A CN202311866761.0A CN202311866761A CN117823127A CN 117823127 A CN117823127 A CN 117823127A CN 202311866761 A CN202311866761 A CN 202311866761A CN 117823127 A CN117823127 A CN 117823127A
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- E—FIXED CONSTRUCTIONS
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Abstract
The invention discloses a method for evaluating gas layer and post-pressure gas production capacity, which comprises the following steps: inverting the stratum pressure by using the logging curve, and qualitatively identifying the gas layer; determining the rock mechanical characteristic parameters and pore structure conditions of the reservoir; reservoir fracturing property and conversion relation between bound water and movable water after fracturing; establishing a gas saturation model under different output conditions; and predicting the liquid production property of the reservoir after fracturing according to the gas saturation model. By utilizing the scheme of the invention, the accurate evaluation of the gas production condition after pressure can be realized, and effective data support is provided for the later gas field development.
Description
Technical Field
The invention relates to the field of petroleum geological exploration, in particular to a method for evaluating gas formation and gas production capacity after pressure.
Background
At present, the development of some gas field blocks is carried out in the middle and later stages, the resource quality of the capacity take-over area is reduced, the geological features of the reservoir are more complex, the gas saturation is obviously reduced compared with that of the main production area, some blocks belong to low-pore permeability reservoirs, the consistency difference between the actual gas production condition after the pressure and the calculated gas saturation is larger, and the coincidence rate is only less than 70 percent, so that how to accurately evaluate the gas content and the capacity of the gas field in the later stage plays a key role in the production of the gas well and the benefit development of the gas field.
Disclosure of Invention
The invention provides a method for evaluating gas layer and post-pressure gas production capacity, which is used for accurately evaluating post-pressure gas production conditions and providing effective data support for later gas field development.
Therefore, the invention provides the following technical scheme:
a method of evaluating gas formation and post-pressure gas production capacity, the method comprising:
inverting the stratum pressure by using the logging curve, and qualitatively identifying the gas layer;
determining the rock mechanical characteristic parameters and pore structure conditions of the reservoir;
reservoir fracturing property and conversion relation between bound water and movable water after fracturing;
establishing a gas-producing gas saturation model under different production conditions;
and predicting the liquid production property of the reservoir after fracturing according to the gas saturation model.
Optionally, the inverting the formation pressure using the log, the qualitatively identifying the gas layer includes:
describing a normal pressure trend by utilizing the relation of neutrons, time difference and depth to obtain a normal pressure trend line;
comparing the measured value with the normal pressure trend line to obtain a pressure coefficient;
carrying out gas-containing correction on the pressure coefficient to obtain a corrected stratum pressure coefficient;
determining a pressure change condition according to the pressure coefficient;
and determining the gas content of the reservoir according to the pressure change condition.
Optionally, the normal pressure trend line comprises: normal pressure trend line of time difference, normal pressure trend line of neutron; the pressure coefficient includes a moveout pressure coefficient and a neutron pressure coefficient.
Optionally, the determining the pressure change condition according to the pressure coefficient includes: and calculating a pressure production value gas indication and a pressure ratio gas indication according to the pressure coefficient.
Optionally, the gas-producing gas saturation model for different production conditions includes: the method comprises a full gas production gas saturation model after fracturing, a minimum gas production gas saturation model after fracturing and a main gas production gas saturation model after fracturing.
Optionally, the determining the reservoir rock mechanical property parameter includes:
determining the correlation between the longitudinal wave time difference and the transverse wave of the array sound wave;
and inverting the transverse wave by utilizing the longitudinal wave time difference and lithology change, and calculating to obtain the rock mechanical characteristic parameter.
Optionally, the rock mechanical property parameters include: shear modulus, young's modulus, bulk modulus, longitudinal-to-transverse wave velocity ratio, transverse wave time difference, and fracking index.
According to the method for evaluating the gas layer and the post-pressure gas production capacity, the post-pressure gas production saturation model is established by combining the middle core and logging data aiming at the situation that the post-pressure actual gas production situation is not matched with the calculated gas saturation, and the accurate evaluation of the post-pressure gas production situation is realized by using the model.
Drawings
FIG. 1 is a flow chart of a method for evaluating gas formation and post-pressure gas production capacity provided by the present invention;
FIG. 2 is a flow chart of qualitative identification of a gas layer in an embodiment of the present invention;
FIG. 3 is a schematic diagram of time difference normal pressure trend lines in an embodiment of the present invention;
FIG. 4 is a schematic diagram of neutron normal pressure trend lines in an embodiment of the invention;
FIG. 5 is a graph showing the correspondence between calculated permeability and core analysis permeability using the permeability model described above in an embodiment of the present invention.
Detailed Description
In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings that are required to be used in the embodiments will be briefly described below. It is apparent that the drawings in the following description are only some embodiments of the present invention, and that other drawings may be obtained from these drawings without inventive effort for a person of ordinary skill in the art.
The present invention will be described in detail below with reference to the drawings and the specific embodiments, which are not described in detail herein, but the embodiments of the present invention are not limited to the following embodiments.
Aiming at the condition that the actual gas production condition after the pressure is not matched with the calculated gas saturation, the invention provides a method for evaluating the gas layer and the gas production capability after the pressure, a gas saturation model after the reservoir layer is built by combining the core and logging data, and the accurate evaluation of the gas production condition after the pressure is realized by using the model.
As shown in fig. 1, a flowchart of a method for evaluating gas formation and post-pressure gas production capacity according to the present invention includes the following steps:
in step 101, the formation pressure is inverted using the log, and the gas layer is qualitatively identified.
The magnitude of the sonic jet lag depends on lithology, degree of compaction, porosity, and fluid content in the pores. Under the condition that lithology and formation water properties are not changed greatly, the acoustic time difference mainly reflects the size of porosity, under the condition of normal compaction, the porosity of mudstone is reduced along with the increase of depth D, the reduction degree of the mudstone is changed in an exponential relation, and therefore inversion formation pressure can be fitted by using a porosity curve such as time difference and the like. However, the time difference is severely affected by gas content and production, and the inverted pressure coefficient needs to be corrected by gas content to react to the pore pressure change of the stratum.
The main derivation process is as follows: for a normal pressure system, the time difference has an exponential relationship with depth, namely:
Δt＝Δt 0 e -cD
the logarithm is taken from two sides, and then:
lnΔt＝-cD ln e+lnΔt 0
in the above formula: Δt is the time difference, D is the depth, and C is a constant.
The pressure coefficient can further be expressed as: and for a certain point the actual pressure coefficient is equal to the ratio of the actual logarithmic value to the normal pressure system logarithmic value.
PPF＝lnΔtx/lnΔt
As shown in fig. 2, a flow chart for qualitatively identifying gas layers in an embodiment of the invention includes the following steps:
and step 201, depicting a normal pressure trend by utilizing the relation of neutrons, time differences and depths in the mudstone section, and obtaining a normal pressure trend line.
The normal pressure trend line includes: normal pressure trend line of time difference, normal pressure trend line of neutron; as shown in fig. 3 and fig. 4, schematic diagrams of a normal pressure trend line of time difference and a normal pressure trend line of neutron in the embodiment of the present invention are shown, wherein the vertical and horizontal coordinates are depth (m) and a time difference logarithmic value and a neutron logarithmic value, respectively.
And 202, comparing the measured value with the normal pressure trend line to obtain a pressure coefficient.
In the embodiment of the invention, the pressure coefficient comprises a time difference pressure coefficient and a neutron pressure coefficient.
Equation of time difference normal pressure trend: the log is obtained by using the real time difference value to build a relationship with the depth, step 201.
PFC＝-6*pow(10,-5)*DEP+6.6574
Neutron normal pressure trend equation: the log is taken from the measured intermediate values and the depth is related, step 201.
PFZ＝-0.0002*DEP+4.9371
The actual pressure equation at a certain point is respectively:
pfs=ln (AC), AC is the time difference log value;
neutron actual pressure equation: pfn=ln (CN), CN being the compensated neutron log;
the actual pressure coefficient at a certain point is the ratio of the actual pressure value of the store to the normal pressure, namely:
time difference pressure coefficient:
PPF＝5*PFS/PFC-3.25
neutron pressure coefficient:
PP＝0.55*PFN/PFZ+0.35
and 203, performing gas-containing correction on the pressure coefficient to obtain a corrected stratum pressure coefficient.
In order to overcome the influence of the gas content change on the logging curve, the pressure coefficient corrected by the gas content is more accurate. The equation is based on the actual pressure measurement data, and the correction equation is obtained after regression:
YLXS＝(0.5*(SGAV+240)/300*PP+(1-0.5*(SGAV+240)/300)*PPF)
and 204, determining the pressure change conditions of the two according to the pressure coefficient.
The larger the pressure coefficient, the larger the pressure, and the overpressure is larger than 1.
Step 205, determining the gas content of the reservoir according to the pressure change condition.
And determining the pressure change difference of the time difference and the neutron pressure coefficient according to the time difference and the neutron pressure coefficient, so as to indicate the gas-containing condition, wherein the time difference is mainly caused by the fact that the time difference is larger and the neutron is smaller after the gas is contained, so that the calculated time difference pressure coefficient is larger and the neutron pressure coefficient is smaller, and the difference is the gas-containing indication.
Specifically, a pressure difference gas indication and a pressure ratio gas indication may be calculated from the pressure coefficients.
The differential pressure gas indication may be expressed as follows:
AIR＝PPF-PP
the pressure ratio gas indication may be expressed as follows:
PTO＝PPF/PP
permeability is an important parameter for evaluating reservoir properties and seepage capability, and has close relation with rock particle thickness, clay content and effective porosity, so that core analysis permeability (Perm or K) can be used for establishing a correlation with porosity and natural gamma.
The permeability is proportional to the effective porosity and inversely proportional to the clay content or natural gamma.
The permeability model was built as follows: and establishing a relation between the permeability experimental data and the effective porosity and natural gamma regression.
PERM＝K*f(PSWE，GR，Kp，Kg)
Wherein, the meaning of each parameter is as follows:
PSWE-effective porosity in units;
gr—natural gamma, unit API;
kp, kg-coefficients, constants, dimensionless related to PSWE, GR;
k-permeability equation total coefficient, constant, dimensionless.
As shown in FIG. 5, in the embodiment of the invention, the permeability model is used to calculate the permeability and the permeability intersection chart of the core experiment analysis, the abscissa is the permeability calculated after regression, and the ordinate is the permeability data of the core experiment, and the consistency of the permeability and the permeability is good.
Through comprehensive analysis of the core and logging data, the main reasons for errors are deposition heterogeneity, permeability directionality, logging curve resolution, and curve distortion caused by borehole irregularities, and the average absolute error between the permeability model calculation result and the core analysis data is 0.35mD.
With continued reference to FIG. 1, in step 102, reservoir rock mechanical property parameters (such as shear modulus, young's modulus, and bulk modulus) and pore structure conditions are determined.
Specifically, determining the correlation between the longitudinal wave time difference and the transverse wave of the array sound wave; and inverting the transverse wave by utilizing the longitudinal wave time difference and lithology change, and calculating to obtain the rock mechanical characteristic parameter.
The rock mechanical property parameters may include, but are not limited to, any one or more of the following: shear modulus, young's modulus, bulk modulus, longitudinal-to-transverse wave velocity ratio, transverse wave jet lag, fracking index, and the like.
The specific calculation formula is as follows:
shear modulus:
SMOD＝ρVs 2
young's modulus:
bulk modulus:
in the above equation, vp and Vs are rock longitudinal and transverse wave velocities, respectively, derived from well logging.
Using array acoustic logging data to establish the correlation between the longitudinal and transverse wave velocity ratios and natural gamma:
SCRAP＝0.0042*(100*(GR-GRmin)/(GRmax-GRmin))+1.45
then inverting to obtain transverse wave time difference:
AS＝SCRP*AC
in the above formula, AC and AS are the time difference values of logging longitudinal and transverse waves, respectively.
By inverting the resulting shear waves, a fractable index can be calculated, which characterizes the fractability and remodelling of the rock, the fractable index being calculated as follows:
FRAC＝100·YMOD 0.36
in step 103, the reservoir is determined for frawability and the bound water released as mobile water after fracturing.
According to the rock mechanical properties and pore structure conditions of the reservoir, the reservoir fracturing property and the conversion relation between the bound water and the movable water after fracturing are analyzed, and the larger the fracturing index is, the larger the fracturing transformation degree is, and the larger the amount of the bound water converted into the movable water is. This parameter is used primarily to qualitatively evaluate the reservoir's remodelling ability and the amount of likelihood of bound water being converted to mobile water.
In step 104, a gas production and gas saturation model is built for different production conditions.
And according to different requirements on gas saturation when gas is produced from reservoirs with different permeability, simultaneously combining the conversion of bound water and movable water after fracturing, and establishing a gas saturation model under different production conditions so as to predict the gas production condition after fracturing.
In an embodiment of the present invention, the gas-producing gas saturation model under different output conditions may include: a full gas production gas saturation model after fracturing, a minimum gas production gas saturation model after fracturing, and a main gas production gas saturation model after fracturing.
The saturation required by the complete gas content, the main gas content and the minimum gas content is respectively obtained by utilizing an actual gas-water permeability relation equation, and then the fracturing property is brought into the conversion from the bound water to the movable water, and the method comprises the following specific steps:
predicting the gas saturation of complete gas production after fracturing:
CSSGY＝10.8878*log(FRAC*PERM)+33.625
predicting the minimum gas-bearing saturation of produced gas after fracturing:
CSSGY0＝3.4122*log(FRAC*PERM)+5.8203
and predicting the gas saturation of main gas production after fracturing:
CSSGY1＝5.9784*log(FRAC*PERM)+20.5360
where PERM is the calculated permeability and FRAC is the fractable index.
In step 105, predicting the liquid production performance of the reservoir after fracturing according to the gas saturation model.
The specific reservoir gas production condition can be compared and judged according to the gas saturation SGAV and the predicted gas saturation, and the specific steps are as follows:
when SGAV > CSSGY, the reservoir is fully gas producing;
when CSSGY1< SGAV < CSSGY, the reservoir is primarily gas producing, but water containing;
when CSSGY0< SGAV < CSSGY1, the reservoir produces mainly water, but contains gas;
when SGAV < CSSGY0, the reservoir produced only water and no gas.
According to the method for evaluating the gas layer and the post-pressure gas production capacity, the post-pressure gas production saturation model is established by combining the middle core and logging data aiming at the situation that the post-pressure actual gas production situation is not matched with the calculated gas saturation, and the accurate evaluation of the post-pressure gas production situation is realized by using the model.
The term "plurality" as used in the embodiments of the present invention means two or more.
It is noted that the terms "comprises" and "comprising," and any variations thereof, in the description and claims of the present invention and in the foregoing figures, are intended to cover a non-exclusive inclusion, such that a process, method, system, article, or apparatus that comprises a list of steps or elements is not necessarily limited to those steps or elements expressly listed or inherent to such process, method, article, or apparatus.
In this specification, each embodiment is described in a progressive manner, and identical and similar parts of each embodiment are all referred to each other, and each embodiment mainly describes differences from other embodiments. Moreover, the system embodiments described above are illustrative only, and the modules and units illustrated as separate components may or may not be physically separate, i.e., may reside on one network element, or may be distributed across multiple network elements. Some or all of the modules may be selected according to actual needs to achieve the purpose of the solution of this embodiment. Those of ordinary skill in the art will understand and implement the present invention without undue burden.
In a specific implementation, regarding each apparatus and each module/unit included in each product described in the above embodiments, it may be a software module/unit, or a hardware module/unit, or may be a software module/unit partially, or a hardware module/unit partially.
In addition, each functional unit in each embodiment of the present application may be integrated in one processing unit, or each unit may be physically disposed separately, or two or more units may be integrated in one unit. The integrated units may be implemented in hardware or in hardware plus software functional units.
While the embodiments of the present invention have been described in detail, the detailed description of the invention is provided herein, and the description of the embodiments is provided merely to facilitate the understanding of the method and system of the present invention, which is provided by way of example only, and not by way of limitation. All other embodiments, which can be made by those skilled in the art based on the embodiments of the present invention without making any inventive effort, shall fall within the scope of the present invention, and the present description should not be construed as limiting the present invention. It is therefore contemplated that any modifications, equivalents, improvements or modifications falling within the spirit and principles of the invention will fall within the scope of the invention.
Claims (7)
1. A method of evaluating gas formation and post-compaction gas production capacity, the method comprising:
inverting the stratum pressure by using the logging curve, and qualitatively identifying the gas layer;
determining the rock mechanical characteristic parameters and pore structure conditions of the reservoir;
reservoir fracturing property and conversion relation between bound water and movable water after fracturing;
establishing a gas-producing gas saturation model under different production conditions;
and predicting the liquid production property of the reservoir after fracturing according to the gas saturation model.
2. The method of evaluating gas formation and post-pressure gas production capacity of claim 1, wherein said inverting formation pressure using a log, qualitatively identifying gas formation comprises:
describing a normal pressure trend by utilizing the relation of neutrons, time difference and depth to obtain a normal pressure trend line;
comparing the measured value with the normal pressure trend line to obtain a pressure coefficient;
carrying out gas-containing correction on the pressure coefficient to obtain a corrected stratum pressure coefficient;
determining a pressure change condition according to the pressure coefficient;
and determining the gas content of the reservoir according to the pressure change condition.
3. The method of evaluating gas formation and post-pressure gas production capacity of claim 2, wherein:
the normal pressure trend line includes: normal pressure trend line of time difference, normal pressure trend line of neutron;
the pressure coefficient includes a moveout pressure coefficient and a neutron pressure coefficient.
4. The method of assessing a gas formation and post-pressure production capacity of claim 2 wherein said determining a pressure change from said pressure coefficients comprises:
and calculating a pressure production value gas indication and a pressure ratio gas indication according to the pressure coefficient.
5. The method of evaluating gas formation and post-pressure gas production capacity of claim 1, wherein the gas production gas saturation model for different production conditions comprises:
the method comprises a full gas production gas saturation model after fracturing, a minimum gas production gas saturation model after fracturing and a main gas production gas saturation model after fracturing.
6. The method of evaluating gas formation and post-pressure gas production capacity of claim 1, wherein the determining reservoir rock mechanical property parameters comprises:
determining the correlation between the longitudinal wave time difference and the transverse wave of the array sound wave;
and inverting the transverse wave by utilizing the longitudinal wave time difference and lithology change, and calculating to obtain the rock mechanical characteristic parameter.
7. The method of evaluating gas formation and post-pressure gas production capacity of claim 6, wherein the rock mechanical property parameters include: shear modulus, young's modulus, bulk modulus, longitudinal-to-transverse wave velocity ratio, transverse wave time difference, and fracking index.
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Citations (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US4806153A (en) * | 1981-01-22 | 1989-02-21 | Kisojiban Consultants Co., Ltd. | Method and apparatus for investigating subsurface conditions |
| CN103046914A (en) * | 2011-10-14 | 2013-04-17 | 中国石油化工股份有限公司 | Hypotonic gas deposit horizontal well staged fracturing effect judging method |
| CN103698494A (en) * | 2013-12-30 | 2014-04-02 | 中国石油大学(北京) | Method and device for determining saturation degree of hydrocarbon in lithologic trap |
| CN114893166A (en) * | 2022-04-13 | 2022-08-12 | 中国石油大学(华东) | Formation pressure coefficient calculation method |
| CN116522583A (en) * | 2023-03-03 | 2023-08-01 | 成都理工大学 | Horizontal well stratum pressure prediction method based on linear regression method |
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- 2023-12-29 CN CN202311866761.0A patent/CN117823127A/en active Pending
Patent Citations (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US4806153A (en) * | 1981-01-22 | 1989-02-21 | Kisojiban Consultants Co., Ltd. | Method and apparatus for investigating subsurface conditions |
| CN103046914A (en) * | 2011-10-14 | 2013-04-17 | 中国石油化工股份有限公司 | Hypotonic gas deposit horizontal well staged fracturing effect judging method |
| CN103698494A (en) * | 2013-12-30 | 2014-04-02 | 中国石油大学(北京) | Method and device for determining saturation degree of hydrocarbon in lithologic trap |
| CN114893166A (en) * | 2022-04-13 | 2022-08-12 | 中国石油大学(华东) | Formation pressure coefficient calculation method |
| CN116522583A (en) * | 2023-03-03 | 2023-08-01 | 成都理工大学 | Horizontal well stratum pressure prediction method based on linear regression method |
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