CN105468886A - Method for calculating formation pressure based on petrophysical parameters - Google Patents

Abstract

The invention discloses a method for calculating formation pressure based on petrophysical parameters, and uses well measurement data of a velocity of a P-wave VP, a velocity of a shear wave VS, a density Rho and a porosity Phi of formation. The method comprises the following steps: deriving a ratio value between a bulk modulus Kdry of a dry rock and a bulk modulus Kma of a rock matrix material by using a Gassmann equation; calculating an effective bulk modulus Kma of a mineral component according to a V-G-H model, calculating a bulk modulus Kf of a pore fluid according to a Wood model to calculate an effective stress coefficient Alpha and an Skempton coefficient B; and estimating the formation pressure according to an effective stress between the Skempton coefficient B and a porous media, the effective stress coefficient Alpha and the Skempton coefficient B. The method is suitable for a mixed lithology and a single lithology, the formation pressure is estimated without relying on a conventional under compaction theory of a mudstone or a shale, so that the calculated formation pressure is more close to real formation pressure.

Description

The method of reservoir pressure is calculated based on petrophysical parameters

Technical field

The present invention relates to exploration geophysics information Processing Technology field, particularly relate to a kind of method calculating reservoir pressure based on petrophysical parameters in petrophysics.

Background technology

The application that current reservoir pressure (formation pore fluid pressure) is predicted mainly is divided into two aspects, one is utilize seismic velocity formation pressure to carry out prediction before drilling, for drilling engineering service, the surpressure that mainly formation may exist is predicted, prevent drilling failure from occurring, drilling mud proportion is generally between the normal pressure and formation-parting pressure on stratum.Two is utilize well-log information to carry out reservoir pressure estimation to drilling well, and the stress of further predicting formation, parting pressure and caving pressure, to carry out pressure break to reservoir, are petroleum exploration and development service.In addition, some sand smellers expect the evidence that accurate prediction of formation pressure can provide some favourable for oil and gas accumulation research, to carry out the analysis of Hydrocarbon Formation Reservoirs.

Accurate prediction of formation pressure is a great problem faced in petroleum exploration and development always, and due to the complex genesis of reservoir pressure, the pressure characteristic of different regions is also different.Occupy an leading position in prediction of formation pressure research for a long time with the Formation pressure prediction method that mud stone or shale (hereinafter referred to as mud shale) undercompaction and equivalent depth method are theoretical foundation.In the origin cause of formation and performance of stratigraphic anormaly high pressure, it is generally acknowledged the low compaction of mud shale, because the fluid in hole can not be discharged, volume of voids maintains the state (larger than the volume of voids under normal compaction state) before compacting, now mud shale velocity of longitudinal wave can be lower than the velocity of longitudinal wave in normal compaction situation, and mud shale can cause stratum to produce surpressure in this case; And in actual well drilled, the surpressure on stratum all shows that interval is grown on permeability stratum (as sandstone).According to real data analysis, even the factor of porosity of undercompacted mud shale is also low-down, pore throat radius very small, capillary pressure very large, fluid in hole exists with the state of irreducible water, simultaneously the permeability of mud shale is low-down (except mud shale crack except), and its inside and outside fluid cannot pass through mud shale, so brill runs into mud shale interval stratum and generally can not show surpressure in drilling process.

In this case above-mentioned, there is arguement, somebody thinks that now mud shale does not exist high pressure, and somebody thinks that now mud shale exists high pressure always, and very little, permeability is extremely low, so can not show high pressure for the fluid just in mud shale.Who is correct to come to a conclusion also not have authority at present about this arguement, and who is incorrect.Li Chuanliang (2009) points out whether mudstone stratum exists surpressure and be never proved, because its reservoir pressure cannot be surveyed; And point out equivalent depth method and inequivalence.Shaker (2002) thinks that the term of current reservoir pressure may be confused, the reservoir pressure of prediction is the reservoir pressure of those relative impervious rocks (shale and mud stone), and the reservoir pressure of actual measurement is the reservoir pressure of reservoir characteristics rock (sandstone).Under many circumstances, the not direct relation of the pressure in sandstone pores and the pressure of shaly bed, there are doubtful point and mistaken ideas in the prediction of formation pore pressure.Zoback (2011) thinks has two kinds of situations to need according to geophysical data predict geopressure: the first situation is that carrying out drilling safety design in the high pressure region that may occur needs pore pressure section by earthquake reflective data predict pore pressure before boring; The second situation is the pore pressure in estimation shale, is difficult to direct measurement because perviousness is poor, even if also need to detect after brill.In both cases, likely become inapplicable in other regions in the good technological means of some area applications effect.And point out, pore pressure increase is larger after the larger extrusion stress of existence or deposition and initial compacting, simple compaction curve can not be utilized to predict pore pressure.One is theoretical foundation with mud shale undercompaction or equivalent depth method prediction of formation pressure experimental formula is difficult to the essence disclosing reservoir pressure, this is a bottleneck of Technologies for prediction of pore pressure research always, the research of reservoir pressure also exists some doubtful points at present as can be seen here needs to solve, and the essence finding reservoir pressure is only the most basic approach.

Find according to petroleum prospecting practice, stratigraphic anormaly high pressure and oil-gas accumulation have very close relationship, fluid briefly in formation pore is squeezed or expansion, if fluid can not shift, so just mean and can produce surpressure, this is a principle following petroleum geology oil-gas migration theory.From the angle of petrophysics, if there is the fluid of surpressure in sandstone reservoir, what difference does so petrophysical parameters (as petrophysical parameters such as Poisson ratio, bulk modulus, modulus of shearing) have with the petrophysical parameter under normal-pressure situations? all the time, acknowledged for velocity of longitudinal wave (as acoustic logging speed, VSP logging speed and seismic velocity) be the optimal parameter of predict geopressure, namely

$V_P=\sqrt{\frac{K+4/3\mathrm{\μ}}{\mathrm{\ρ}}}$

Wherein V _pbe the velocity of longitudinal wave of rock, K is the bulk modulus of rock, and μ is the modulus of shearing of rock, and ρ is the density of rock.Can find out, reservoir pressure is a general performance result of formation rock physics parameter in fact, and this just proposes a problem, we are when predict geopressure, what is being predicted in fact, wanting to obtain more accurate prediction of formation pressure result, have and there is no better approach.

Summary of the invention

The object of the invention is the difficult point for current prediction of formation pressure and doubtful point, the research how launching petrophysics aspect from the mechanical characteristic of reservoir pressure will be a good starting point, the research of reservoir pressure will be based upon on the analysis of geologic background and the basis of rock mechanics theory, carry out formation pressure in conjunction with geophysical exploration method to characterize, propose a kind of method calculating reservoir pressure based on petrophysical parameters.The method derives a kind of new formation pressure calculation method according to Skempton coefficient B and porous medium principle of effective stress, by asking for effective stress factor alpha and Skempton coefficient B estimation reservoir pressure.

Object of the present invention is achieved by the following technical measures.

Calculate the method for reservoir pressure (formation pore fluid pressure) based on petrophysical parameters, utilize the velocity of longitudinal wave V on stratum _p, shear wave velocity V _s, density p and factor of porosity φ log data, and as follows:

Step 1, utilizes Gassmann equation inference to go out dry rock bulk modulus K _drywith the bulk modulus K of Rock Matrix material (particle) _maratio expression formula;

Step 2, calculates the effective bulk modulus K of mineral (particle) composition according to V-G-H model _ma, Wood model calculates the bulk modulus K of pore fluid _f, ask for value, ask for effective stress factor alpha and Skempton coefficient B thus;

Step 3, derives a kind of new formation pressure calculation method according to Skempton coefficient B and porous medium principle of effective stress, and according to effective stress factor alpha and Skempton coefficient B estimation reservoir pressure.

Such scheme comprises further:

In step 1, Gassmann equation inference is utilized to go out dry rock bulk modulus K _drywith the bulk modulus K of Rock Matrix material (particle) _maratio expression formula:

$\frac{K_{\mathrm{dry}}}{K_{\mathrm{ma}}}=\frac{K_{\mathrm{wet}}/K_{\mathrm{ma}}[1+\mathrm{\φ}(K_{\mathrm{ma}}/K_f-1)]-1}{K_{\mathrm{wet}}/K_{\mathrm{ma}}+1+\mathrm{\φ}(K_{\mathrm{ma}}/K_f-1)-2}---(1-1)$

In formula: K _dryfor dry rock bulk modulus, K _wetfor the bulk modulus (wet rock) of saturated rock, K _mafor the bulk modulus of Rock Matrix material (particle), K _ffor the bulk modulus of pore fluid, φ is the factor of porosity of rock.

In step 1, concrete derivation step is as follows:

Obtained by Gassmann equation

$\mathrm{\ρ}{V}_P^2=K_{\mathrm{dry}}+\frac{4}{3}{\mathrm{\μ}}_{\mathrm{dry}}+\frac{{(1-K_{\mathrm{dry}}/K_{\mathrm{ma}})}^2}{(1-\mathrm{\φ}-K_{\mathrm{dry}}/K_{\mathrm{ma}})/K_{\mathrm{ma}}+\mathrm{\φ}/K_f}---(1-2)$

Obtained by wave equation simultaneously $V_P=\sqrt{\frac{K_{\mathrm{wet}}+4/3{\mathrm{\μ}}_{\mathrm{dry}}}{\mathrm{\ρ}}---(1-3)}$

$V_S=\sqrt{\frac{{\mathrm{\μ}}_{\mathrm{dry}}}{\mathrm{\ρ}}}---(1-4)$

According to (1-2), (1-3) two formula obtain the bulk modulus of rock under not drainage situation

$K_{\mathrm{wet}}=K_{\mathrm{dry}}+\frac{{(1-K_{\mathrm{dry}}/K_{\mathrm{ma}})}^2}{(1-\mathrm{\φ}-K_{\mathrm{dry}}/K_{\mathrm{ma}})/K_{\mathrm{ma}}+\mathrm{\φ}/K_f}---(1-5)$

The bulk modulus of dry rock is obtained by (1-5) formula

$K_{\mathrm{dry}}=\frac{K_{\mathrm{wet}}[1/K_{\mathrm{ma}}+\mathrm{\φ}(1/K_f-1/K_{\mathrm{ma}})]-1}{1/K_{\mathrm{ma}}[K_{\mathrm{wet}}/K_{\mathrm{ma}}+1+\mathrm{\φ}(K_{\mathrm{ma}}/K_f-1)-2]}---(1-6)$

Obtained by (1-6) formula

$\frac{K_{\mathrm{dry}}}{K_{\mathrm{ma}}}=\frac{K_{\mathrm{wet}}/K_{\mathrm{ma}}[1+\mathrm{\φ}(K_{\mathrm{ma}}/K_f-1)]-1}{K_{\mathrm{wet}}/K_{\mathrm{ma}}+1+\mathrm{\φ}(K_{\mathrm{ma}}/K_f-1)-2}---(1-7)$

In step 2, the effective bulk modulus K of mineral (particle) composition is calculated according to V-G-H model _ma, Wood model calculates the bulk modulus K of pore fluid _f, ask for value, ask for effective stress factor alpha and Skempton coefficient B thus.

In step 2, concrete derivation step is as follows:

Effective stress factor alpha can be asked for further, namely according to the result of trying to achieve in above-mentioned steps 1 therefore a demand gets the bulk modulus K of rock under not drainage situation _wet, Rock Matrix material (particle) bulk modulus K _mawith the bulk modulus K of pore fluid _f, just can directly try to achieve Biot factor alpha.

According to above-mentioned (1-3), (1-4) two formula derive obtain

$K_{\mathrm{wet}}=\mathrm{\ρ}(V_P^2-\frac{4}{3}{V}_s^2)---(1-8)$

In formula: V _pfor the velocity of longitudinal wave of rock, V _sfor the shear wave velocity of rock, ρ is rock density.

The bulk modulus of pore fluid is asked for by Wood (1955) model:

$V=\sqrt{\frac{K_R}{\mathrm{\ρ}}}$

$\frac{1}{K_R}=\frac{S_w}{K_w}+\frac{(1-S_w)}{K_{\mathrm{hyd}}}$ System of equations (1-9)

ρ＝S _wρ _w+(1-S _w)ρ _hyd

In formula: V is the speed of pore fluid, K _rfor the bulk modulus of pore fluid, ρ is the density of pore fluid, S _wfor water saturation, K _wfor the bulk modulus of water, K _hydfor the bulk modulus of hydro carbons, ρ _wfor the density of water, ρ _hydfor the density of hydro carbons.

For when being water entirely in hole, the bulk modulus of pore fluid is

$K_f={\mathrm{\ρ}}_f{V}_f^2---(1-10)$

In formula: K _ffor the bulk modulus of pore fluid, V _ffor the speed of pore fluid, ρ _ffor pore fluid density.

By the bulk modulus K of modulus model assessment Rock Matrix material (particle) of Voigt, Reuss and Hill (also known as V-R-H modulus model) _ma:

K _malower bound (Russ) be

$K_R=\frac{K_{\mathrm{wet}}{K}_f(1-\mathrm{\φ})}{K_f-\mathrm{\φ}{K}_{\mathrm{wet}}}---(1-11)$

K _mathe upper bound (Voigt) be

$K_V=\frac{K_{\mathrm{wet}}-\mathrm{\φ}{K}_f}{(1-\mathrm{\φ})}---(1-12)$

Hill is averaging

K _ma＝(K _R+K _V)/2(1—13)

By trying to achieve K above _wet, K _maand K _f, substitute into the formula (1-7) of above-mentioned correspondence, can calculate value, thus can basis calculate effective stress factor alpha.The method calculates the velocity of longitudinal wave V that effective stress coefficient factor alpha only needs rock _p, shear wave velocity V _s, density p and factor of porosity φ, and the speed V of pore fluid _fand density p _fetc. data, just efficacy coefficient factor alpha can be obtained easily, simple and practical in actual applications, convenient operation.

In step 2, the stiffness K of the relational expression between the pore pressure dP provided according to Skempton (1954) and the compression stress d σ of applying and the dry pore space of rock _φ(Jaeger and Cook, 1969; Zimmerman, 1991) what expression formula derived Skempton coefficient B can calculation expression, and its derivation is

$B=\frac{\mathrm{dP}}{\mathrm{d\σ}}=\frac{1}{1+K_{\mathrm{\φ}}(\frac{1}{K_f}-\frac{1}{K_{\mathrm{ma}}})}---(1-14)$

$K_{\mathrm{\φ}}=\frac{1}{\frac{1}{K_{\mathrm{dry}}}-\frac{1}{K_{\mathrm{ma}}}}---(1-15)$

By (1-14) and (1-15) two formula derive and obtain the calculation expression of Skempton coefficient B:

$B=\frac{\mathrm{dP}}{\mathrm{d\σ}}=\frac{1}{1+\frac{\mathrm{\φ}\frac{K_{\mathrm{dry}}}{K_{\mathrm{ma}}}(\frac{K_{\mathrm{ma}}}{K_f}-1)}{(1-\frac{K_{\mathrm{dry}}}{K_{\mathrm{ma}}})}}---(1-16)$

In formula: dP is pore-fluid pressure, d σ is mean stress.According to what ask for value, K _maand K _festimate Skempton coefficient B.

In step 3, derive a kind of new formation pressure calculation method according to Skempton coefficient B and porous medium principle of effective stress, and according to effective stress factor alpha and Skempton coefficient B estimation reservoir pressure.Its basic derivation is:

Skempton coefficient B can be obtained easily according to formula (1-16), simultaneously can according to the expression formula of the relation derivation blowhole hydrodynamic pressure of Skempton coefficient B, pore-fluid pressure dP and mean stress d σ, replace the effective stress on stratum here by the mean stress on stratum, namely mean stress is

$\mathrm{d\σ}=\frac{({\mathrm{\σ}}_x+{\mathrm{\σ}}_y+{\mathrm{\σ}}_z)}{3}---(1-17)$

Wherein σ _x, σ _yand σ _zbe respectively three principle stresses in x, y and z direction.P can be made simultaneously _f=dP, σ=d σ, so σ=P _f/ B, substitutes into formula (1-18)

αP _f＝P _ov-σ(1—18)

The computation model of a new formation pore fluid pressure can be obtained

$P_f=\frac{P_{\mathrm{ov}}}{(\mathrm{\α}+\frac{1}{B})}---(1-19)$

Here a demand gets overlying formation pressure P _ov, effective stress factor alpha and Skempton coefficient B just can estimate the pore pressure on stratum.

The method calculating reservoir pressure (formation pore fluid pressure) based on petrophysical parameters of the present invention, by Skempton coefficient B (Skempton, 1954) relation of reservoir pressure and rock mean stress is set up, in the ordinary course of things, the mean stress of country rock can be equivalent to the effective stress of rock, calculate reservoir pressure in conjunction with porous medium principle of effective stress, a final calculating reservoir pressure demand gets three crucial parameters, i.e. overlying formation pressure P _ov, effective stress factor alpha (Biot and Willis, 1957; Also Biot coefficient is claimed) and Skempton coefficient B, just can estimate formation pore fluid pressure.The implementation procedure of the method, needs to ask for two crucial parameters, effective stress factor alpha and Skempton coefficient B, and uses Skempton coefficient B and porous medium principle of effective stress to set up new prediction of formation pressure model dexterously.The method from rock physics theory, according to the compressional wave logging speed V on stratum _p, SWAL speed V _s, well logging density p and factor of porosity φ can estimate the pore-fluid pressure on stratum effectively.

Dry rock bulk modulus K is related to for effective stress factor alpha and asking for of Skempton coefficient B _drywith the bulk modulus K of Rock Matrix material (particle) _maask for.In actual applications, usually measure effective stress factor alpha by laboratory techniques, be actually and measure dry rock bulk modulus K _drywith the bulk modulus K of Rock Matrix material (particle) _maratio dry rock bulk modulus K is derived here by Gassmann equation (Gassmann, 1951) _drywith the bulk modulus K of Rock Matrix material (particle) _maratio expression formula, then calculate the effective bulk modulus K of mineral (particle) composition according to V-G-H model _ma, Wood model calculates the bulk modulus K of formation pore fluid _f, can obtain value, effective stress factor alpha and Skempton coefficient B can be asked for further.

Method of the present invention, is applicable to mixing lithology and single lithology, and the undercompaction theory not relying on traditional mud stone or shale carries out the pressure estimation on stratum, and the reservoir pressure calculated more approaches the true pressure on stratum.The precision of this method calculating reservoir pressure depends on the velocity of longitudinal wave V on stratum _p, shear wave velocity V _s, density p and factor of porosity φ log data precision, the particularly computational accuracy of formation porosity φ.Along with the progress of logging technology, this method calculates reservoir pressure will play huge effect in oilfield prospecting developing, produces huge economic benefit.

Accompanying drawing explanation

Fig. 1 is the process flow diagram calculating a specific embodiment of the method for reservoir pressure based on petrophysical parameters of the present invention

Fig. 2 is the effective bulk modulus K calculating mineral (particle) composition according to V-G-H model _ma

Fig. 3 is Yi186 well effective stress factor alpha (Biot coefficient) and the Skempton coefficient B analysis chart of the inventive method calculating

Fig. 4 is the Yi186 well prediction of formation pressure analysis chart that the inventive method calculates

Embodiment

For making above and other object of the present invention, feature and advantage can become apparent, cited below particularly go out preferred embodiment, and coordinate institute's accompanying drawings, be described in detail below.

As shown in Figure 1, Fig. 1 is the process flow diagram calculating the method for reservoir pressure based on petrophysical parameters of the present invention.In step 101, the log data preparing to need (comprises the velocity of longitudinal wave V on stratum _p, shear wave velocity V _s, density p and factor of porosity φ log data.Flow process enters into step 102.

In step 102, calculated the bulk modulus K of saturated rock (wet rock) by log data _wet, the effective bulk modulus K of mineral (particle) composition is calculated according to V-G-H model _ma, Wood model calculates the bulk modulus K of pore fluid _f.Flow process enters step 103.

In step 103, obtain according to Gassmann equation inference expression formula calculate value calculate effective stress factor alpha (Biot coefficient) and Skempton coefficient B.Here α and B can represent respectively:

$\frac{K_{\mathrm{dry}}}{K_{\mathrm{ma}}}=\frac{K_{\mathrm{wet}}/K_{\mathrm{ma}}[1+\mathrm{\φ}(K_{\mathrm{ma}}/K_f-1)]-1}{K_{\mathrm{wet}}/K_{\mathrm{ma}}+1+\mathrm{\φ}(K_{\mathrm{ma}}/K_f-1)-2}$

$\mathrm{\α}=1-\frac{K_{\mathrm{dry}}}{K_{\mathrm{ma}}}$

$B=\frac{\mathrm{dP}}{\mathrm{d\σ}}=\frac{1}{1+\frac{\mathrm{\φ}\frac{K_{\mathrm{dry}}}{K_{\mathrm{ma}}}(\frac{K_{\mathrm{ma}}}{K_f}-1)}{(1-\frac{K_{\mathrm{dry}}}{K_{\mathrm{ma}}})}}$

In formula: K _dryfor dry rock bulk modulus, K _wetfor the bulk modulus (wet rock) of saturated rock, K _mafor the bulk modulus of Rock Matrix material (particle), K _ffor the bulk modulus of pore fluid, φ is the factor of porosity of rock; DP is pore-fluid pressure, and d σ is mean stress.

According to the K calculated in step 102 _wet, K _maand K _feffective stress factor alpha and Skempton coefficient B can be calculated.Flow process enters into step 104.

In step 104, derive a kind of new formation pressure calculation method expression formula according to Skempton coefficient B and porous medium principle of effective stress:

$P_f=\frac{P_{\mathrm{ov}}}{(\mathrm{\α}+\frac{1}{B})}$

In formula: P _ffor pore-fluid pressure, P _ovfor overlying formation pressure, α is effective stress coefficient, and B is Skempton coefficient.

Thus can according to overlying formation pressure P _ov(being calculated by the average density of overlying strata), effective stress factor alpha and Skempton coefficient B estimation reservoir pressure.Fig. 2 is according to compressional wave logging speed V _p, SWAL speed V _s, well logging density p and factor of porosity φ first obtain the bulk modulus K of saturated rock (wet rock) _wet, then according to the bulk modulus K of V-G-H model reverse Rock Matrix material (particle) _ma.Fig. 3 is the Yi186 well effective stress factor alpha (Biot coefficient) and Skempton coefficient B analysis chart that are calculated by the inventive method, and result of calculation is very identical with the theoretical span defined.Fig. 4 is the Yi186 well prediction of formation pressure analysis chart that the inventive method calculates, and Yi186 well has 5 pressure taps, 1., 3., 4., is 5. wherein the reservoir pressure of the sandstone surveyed, and is 2. the reservoir pressure of the mud shale surveyed.From predicting the outcome, the reservoir pressure complex distribution of Yi186 well, first pressure measurement 1. and 3. Measured formation pressure be greater than drilling mud proportion, this is unallowed in drilling well, illustrates that observed pressure also has larger error sometimes; Wherein pressure measurement place observed pressure 1. with predict the outcome identical very well, but contradict with drilling mud proportion; Observed pressure 2., 4., 5. with predict the outcome identical very well, can find out simultaneously, these superpressures are all from thin layer, according to drilling well and log data analysis, 2. superpressure is from mud shale, 1. superpressure is from the thin sandstone in mudstone foundation, and 3., 4., 5. superpressure is from flagstone in gypsum-salt rock interlayer.These reservoir pressures have the feature of jump in the vertical, are not to increase progressively continuously or successively decrease continuously.Fig. 4 predicts the outcome, and reflects the change of reservoir pressure very truly, continues raising and predicts the outcome, and needs the precision, the particularly explanation of formation factor of porosity that improve log data.Because in petroleum exploration and development, just the factor of porosity of reservoir is explained and analyzed with carrying out emphasis at present, explanation for the factor of porosity of non-reservoir is general and think little of, particularly to the explanation of the factor of porosity of the extremely low mud stone of perviousness or shale, an often artificial given very little numerical value or think that the factor of porosity of mud stone or shale is zero.In fact the factor of porosity of mud stone or shale is non-vanishing, therefore factor of porosity calculating to this invention carry out prediction of formation pressure continue improve precision extremely important.This invention is expected to the development promoting petrophysics and logging technology.

Claims (5)

1. calculate the method for reservoir pressure based on petrophysical parameters, it is characterized in that the velocity of longitudinal wave V utilizing stratum _p, shear wave velocity V _s, density p and factor of porosity φ log data, and as follows:

Step 1, utilizes Gassmann equation inference to go out dry rock bulk modulus K _drywith the bulk modulus K of Rock Matrix material _maratio expression formula;

Step 2, calculates the effective bulk modulus K of mineralogical composition according to V-G-H model _ma, Wood model calculates the bulk modulus K of pore fluid _f, ask for value, ask for effective stress factor alpha and Skempton coefficient B thus;

Step 3, derives formation pressure calculation method according to Skempton coefficient B and porous medium principle of effective stress, and according to effective stress factor alpha and Skempton coefficient B estimation reservoir pressure.

2. the method calculating reservoir pressure based on petrophysical parameters according to claim 1, is characterized in that, in step 1, utilize Gassmann equation inference to go out dry rock bulk modulus K _drywith the bulk modulus K of Rock Matrix material _maratio expression formula:

$\frac{K_{\mathrm{dry}}}{K_{\mathrm{ma}}}=\frac{K_{\mathrm{wet}}/K_{\mathrm{ma}}[1+\mathrm{\φ}(K_{\mathrm{ma}}/K_f-1)]-1}{K_{\mathrm{wet}}/K_{\mathrm{ma}}+1+\mathrm{\φ}(K_{\mathrm{ma}}/K_f-1)-2}$

In formula: K _dryfor dry rock bulk modulus, K _wetfor the bulk modulus of saturated rock, K _mafor the bulk modulus of Rock Matrix material, K _ffor the bulk modulus of pore fluid, φ is the factor of porosity of rock.

3. the method calculating reservoir pressure based on petrophysical parameters according to claim 1 and 2, is characterized in that, in step 2, and the bulk modulus K of known saturated rock _wet, the bulk modulus K of reverse Rock Matrix material is carried out according to V-G-H model _ma, rudimentary algorithm is represented by formula below:

By the bulk modulus K of V-R-H modulus model assessment Rock Matrix material _ma:

K _malower bound be

$K_R=\frac{K_{\mathrm{wet}}{K}_f(1-\mathrm{\φ})}{K_f-\mathrm{\φ}{K}_{\mathrm{wet}}}$

K _mathe upper bound be

$K_V=\frac{K_{\mathrm{wet}}-\mathrm{\φ}{K}_f}{(1-\mathrm{\φ})}$

Be averaging

K _ma＝(K _R+K _V)/2

Calculate the bulk modulus K of formation pore fluid in step 2 according to Wood model simultaneously _f, then by K _maand K _fcalculate can obtain thus value, effective stress factor alpha can be asked for.

4. the method calculating reservoir pressure based on petrophysical parameters according to claim 3, is characterized in that, in step 2, according to what ask for value estimate Skempton coefficient B, its rudimentary algorithm is represented by formula below:

$B=\frac{\mathrm{dP}}{\mathrm{d\σ}}=\frac{1}{1+\frac{\mathrm{\φ}\frac{K_{\mathrm{dry}}}{K_{\mathrm{ma}}}(\frac{K_{\mathrm{ma}}}{K_f}-1)}{(1-\frac{K_{\mathrm{dry}}}{K_{\mathrm{ma}}})}}$

In formula: dP is pore-fluid pressure, d σ is mean stress.

5. the method calculating reservoir pressure based on petrophysical parameters according to claim 4, is characterized in that, in step 3, derive a kind of new formation pressure calculation method, its expression formula according to Skempton coefficient B and porous medium principle of effective stress:

$P_f=\frac{P_{\mathrm{ov}}}{(\mathrm{\α}+\frac{1}{B})}$

In formula: P _ffor pore-fluid pressure, P _ovfor overlying formation pressure, α is effective stress coefficient, and B is Skempton coefficient.Thus can according to overlying formation pressure, effective stress factor alpha and Skempton coefficient B estimation reservoir pressure.