CN101787884A - Method for judging fluid type of reservoir through acoustic porosity-neutron porosity differential - Google Patents

Abstract

The invention discloses a method for judging the fluid type of a reservoir through an acoustic porosity-neutron porosity differential, which relates to the technical field of oil and gas logging, geology and core test analysis. The method comprises the following steps: 1) accurately calculating shale content, rock compositions, acoustic porosity and neutron porosity of the reservoir through core data calibration logging and logging data environment correction; 2) excluding the influence of factors such as lithology, borehole diameter and mud invasion on an acoustic transit time and neutron data; and 3) establishing a standard for judging the fluid type of the reservoir by comparing the magnitude of the acoustic porosity and the neutron porosity and using the response difference of the acoustic transit time and the neutron data to the gas and formation water. In the method, non-fluid influence factors such as the lithology, borehole conditions, mud invasion and the like are excluded when the fluid type of the reservoir is judged, so the characteristics of the influence of different fluids on the acoustic transit time and the neutron data can be grasped truly, and the coincidence rate of judging the fluid type of the reservoir is improved from 70 percent currently to over 90 percent.

Description

Acoustic porosity and neutron porosity method for judging reservoir fluid type of difference between

Technical field

The present invention relates to petroleum gas well logging, geology and rock core test analysis technical field, exactly relate to a kind of method of utilizing acoustic porosity and neutron porosity difference to carry out distinguishing reservoir fluid type.

Background technology

Distinguishing reservoir fluid type is one of key technology of natural gas exploration and development.Utilize natural gas and formation water to the response of interval transit time and neutron data be not both discrimination of reservoir fluid type common method it

Acoustic porosity-neutron porosity difference fluid type diagnostic method belongs to the scientific research method innovation in the natural gas exploration and development field, mainly be to utilize well-log information, in conjunction with geologic information and core experiment data, research natural gas, formation water are to the Different Effects feature of interval transit time and neutron data, finally set up sound wave, the neutron difference relation of natural gas and formation water, and this values of disparity method, thereby fast, accurately discern gas-bearing formation and water layer, for the construction of natural gas fields provides the test layer position, and then instruct the gas field exploration exploitation.

During formation gas bearing, the neutron well logging data can be diminished by natural gas " excavation effect " influence, and interval transit time is increased obviously by gas influence, even " jumping ripple " occur, and on the well logging complex chart, gas-bearing formation section sound wave curve and neutron curve are " pregnant " shape separation trend.When the stratum was moisture, the interval transit time influence was little, the constant or slightly increase of neutron porosity, and the water layer section presents interval transit time and neutron well logging value variation tendency basically identical feature, in view of the above, can differentiate gas-bearing formation and water layer.But because when degree of porosity is big, because the neutron well logging value is relatively large, simultaneously factors such as lithology, borehole condition, mud immersion are to particularly the influence of neutron data is bigger to interval transit time and neutron data, it is not high directly to utilize tracing pattern discrimination of reservoir fluid type to differentiate coincidence rate, by statistics, the distinguishing reservoir fluid type coincidence rate can only reach about 70% usually, brings very big difficulty to construction of natural gas fields production.

Summary of the invention

For solving the problems of the technologies described above, the present invention proposes a kind of acoustic porosity and neutron porosity method for judging reservoir fluid type of difference between that can improve fluid type differentiation coincidence rate, the present invention has got rid of nonfluid influence factors such as lithology, borehole condition, mud immersion when utilizing interval transit time, neutron data discrimination of reservoir fluid type, thereby can grasp the influencing characterisitic of different fluid truly to interval transit time and neutron data, the distinguishing reservoir fluid type coincidence rate has been brought up to more than 90% by existing 70%.

The present invention realizes by adopting following technical proposals:

A kind of acoustic porosity and neutron porosity method for judging reservoir fluid type of difference between is characterized in that step comprises:

1) by the well logging of rock core information scale, well-log information environmental correction, accurately calculates reservoir shale content, rock composition, acoustic porosity and neutron porosity;

2) get rid of lithology, hole diameter and mud and invade the influence of factor interval transit time and neutron data;

3) utilize interval transit time and neutron data response difference, set up the distinguishing reservoir fluid type standard by the size that compares sound wave hole and neutron porosity to natural gas and formation water, wherein:

A, for the good reservoir of pore structure, the fluid type discrimination standard is:

Gas-bearing formation: PORA-PORN＞0;

Water layer: PORA-PORN＜0;

Do layer (or the low especially layer of output): PORA-PORN ≈ 0;

In the formula: PORA, PORN represent acoustic porosity (%), neutron porosity (%) respectively.

B, slightly different for the relatively poor low porosity and low permeability reservoir discrimination standard of pore structure as Su Lige gas field fluid type discrimination standard is:

Gas-bearing formation: PORA-PORN＞3%;

Water layer: PORA-PORN＜0%;

Air water is layer together :-2%＜PORA-PORN＜5%;

In the formula: PORA, PORN represent acoustic porosity (%), neutron porosity (%) respectively.

Described rock core scale well logging mainly comprises two aspects: be by core analysis data scale logging data processing parameter on the one hand, calculate the parameter of shale content, the parameter that rock electroanalysis data determines to calculate saturation ratio as rock core X diffraction analysis data scale; On the other hand with the means of interpretation of product test WELL LITHOLOGY, degree of porosity, permeability and the saturation ratio of core analysis degree of porosity, permeability and water saturation and adjust, up to satisfying error requirements.

Described well-log information environmental correction specifically is meant: select for use classical theoretical plate and empirical formula to carry out environmental correction according to reality well logging situation and logging program.

Described shale content calculates and is specially: the calculating of shale content needs clay composition and the character according to the work area, select for use different well-log informations to calculate: directly calculate with natural gamma on the low stratum of non-shale composition radioactivity, the high stratum of non-shale composition radioactivity selects for use different power spectrum data to calculate shale content: as the radioactivity of non-shale composition in the stratum based on thorium, just select the potassium curve calculation, the radioactivity of non-shale composition is based on potassium, just select the thorium curve calculation, the stratum that feldspar content is high uranium curve calculation, the non-shale composition in stratum contains radioactivity, uses neutron when not having the power spectrum data again, shale content is calculated in the density intersection.

Described rock composition is calculated as: according to geologic characteristics, set up the log response equation of the rock composition, hole and the fluid that meet the work area actual conditions, calculate mineralogical composition volumn concentration and degree of porosity.

Described acoustic porosity is calculated as: use the interval transit time data after shale correction, environmental correction to calculate acoustic porosity.

Described neutron porosity is calculated as: neutron data using neutron data log response equation calculates neutron porosity after shale correction, environmental correction:

Described eliminating lithology, hole diameter and mud intrusion factor are meant the influence of interval transit time and neutron data: factors such as hole diameter, mud intrusion mainly adopt classical empirical formula of well logging and plate to proofread and correct to the influence of interval transit time, neutron data; The influence of rock forming mineral composition can be proofreaied and correct by calculating each rock composition and volumn concentration, gets rid of the lithology influence and comprises the shale correction of interval transit time and the shale correction of neutron data.

It is exactly the hydrogen index correction of shale that the shale of described neutron data is proofreaied and correct, and divides for three steps carried out: calculate the neutron hydrogen index of shale under the status of criterion earlier, carry out depth correction again, then the neutron data is carried out shale and proofread and correct.

The shale of described interval transit time is proofreaied and correct and was also divided for three steps carried out: calculate the interval transit time value of shale under the status of criterion earlier, carry out depth correction again, then acoustic logging data carried out the shale correction.

The technique effect that the present invention reached is as follows:

Compared with prior art, because this method has been got rid of nonfluid influence factors such as lithology, borehole condition, mud immersion when utilizing interval transit time, neutron data discrimination of reservoir fluid type, grasped the influencing characterisitic of different fluid truly to interval transit time and neutron data, improve fluid type greatly and differentiated coincidence rate, in 5 peaches, 7 block distinguishing reservoir fluid types were revived in the Su Lige gas field, coincidence rate had brought up to 91% by about 70% of the past; In addition, because this method step 3) in, this method is to reflect fluid type with numerical values recited, fluid is differentiated brought up to quantitative identification, use the more convenient operation that is easier on the one hand, on the other hand by the qualitative discrimination in past, can combine this numerical value and seismic data, carry out the air water prediction in the plane, the well logging fluid is differentiated be converted into complanation, improved directive function greatly oilfield prospecting developing by a peephole view.

Description of drawings

The utility model is described in further detail below in conjunction with specification drawings and specific embodiments, wherein:

Fig. 1 is the graph of a relation of the shale hydrogen index and the degree of depth

Fig. 2 is the graph of a relation of the shale interval transit time and the degree of depth

The specific embodiment

The invention discloses a kind of acoustic porosity and neutron porosity method for judging reservoir fluid type of difference between, it is characterized in that step comprises:

1) by the well logging of rock core information scale, well-log information environmental correction, accurately calculates reservoir shale content, rock composition, acoustic porosity and neutron porosity;

Well-log information reflects indirectly that by the physical parameter of measuring subsurface rock the storage of lithosphere oozes situation and oily situation, needs through the correct interpretation and evaluation reservoir of actual geologic information scales such as rock core.

Described rock core scale well logging mainly comprises two aspects: be by core analysis data scale logging data processing parameter on the one hand, calculate the parameter of shale content, the parameter of the definite calculating of rock electroanalysis data saturation ratio etc. as rock core X diffraction analysis data scale; On the other hand with the means of interpretation of product test WELL LITHOLOGY, degree of porosity, permeability and saturation ratios such as core analysis degree of porosity, permeability, water saturation and adjust, up to satisfying error requirements.

Described well-log information environmental correction specifically is meant: environmental factors such as (as whether " hole enlargement ") influences to some extent to well-log information because the temperature when gathering well-log information, mud property, borehole condition, so need select for use the theoretical plate and the empirical formula of classics to carry out environmental correction according to reality well logging situation and logging program.

Described shale content calculates and is specially:

The calculating of shale content needs clay composition and the character according to the work area, select for use different well-log informations to calculate: directly calculate with natural gamma on the low stratum of non-shale composition radioactivity, the high stratum of non-shale composition radioactivity selects for use different power spectrum data to calculate shale content: as the radioactivity of non-shale composition in the stratum based on thorium, just select the potassium curve calculation, the radioactivity of non-shale composition is based on potassium, just select the thorium curve calculation, the stratum that feldspar content is high uranium curve calculation, the shale content universal calculation equation is:

$\mathrm{SH}=\frac{\mathrm{LOG}-{\mathrm{LOG}}_{\mathrm{nin}}}{{\mathrm{LOG}}_{\max }-{\mathrm{LOG}}_{\min }}$

$V_{\mathrm{SH}}=\frac{2^{2\×\mathrm{SH}}-1}{2^2-1}$

In the formula: V _SH-stratum shale content;

The SH-SI;

LOG, LOG _Max, LOG _Min-be respectively log value, maximum value, the minimum value of the well-log information that calculates shale content.

The non-shale composition in stratum contains radioactivity, can use neutron, density intersection to calculate shale content when not having the power spectrum data again:

Φ _N＝φ _t+Φ _shV _sh+Φ _ma(1-φ _t-V _sh)

ρ _b＝φ _t+ρ _shV _sh+ρ _ma(1-φ _t-V _sh)

In the formula: Φ _N, Φ _Nsh, Φ _Nma, φ _tRepresent respectively in neutron well logging value, the shale subvalue in subvalue, the skeleton, acoustic porosity (%, %, %, f);

ρ _b, ρ _Sh, ρ _MaRepresent density log value, shale density value, matrix density value (g/cm respectively ³, g/cm ³, g/cm ³);

V _Sh-shale content (f).

Can solve V by last equation group _ShAnd φ _t

Described rock composition is calculated as:

According to the geologic feature of reservoir, set up the log response equation of the rock composition, hole and the fluid that meet the work area actual conditions, calculate mineralogical composition volumn concentration and degree of porosity.Log response equation if any three kinds of rock compositions is:

$\left\{\begin{array}{c}\mathrm{DT}=V_{\mathrm{SH}}\&times;{\mathrm{DT}}_{\mathrm{SH}}+{\mathrm{<figure-callout\; id="1"\; label="C"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">C</figure-callout>}}_1\&times;{\mathrm{<figure-callout\; id="1"\; label="DTma"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">DTma</figure-callout>}}_1+{\mathrm{<figure-callout\; id="2"\; label="C"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">C</figure-callout>}}_2\&times;\mathrm{<figure-callout\; id="2"\; label="DT\; ma"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">DT</figure-callout>}{\mathrm{ma}}_{}{}_2+{\mathrm{<figure-callout\; id="3"\; label="C"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">C</figure-callout>}}_3\&times;{\mathrm{<figure-callout\; id="3"\; label="DTma"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">DTma</figure-callout>}}_3+\mathrm{\&Phi;}\&times;{\mathrm{DT}}_f\\ \mathrm{CNL}=V_{\mathrm{SH}}\&times;N_{\mathrm{SH}}+{\mathrm{<figure-callout\; id="1"\; label="C"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">C</figure-callout>}}_1\&times;{\mathrm{<figure-callout\; id="1"\; label="CNL"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">CNL</figure-callout>}}_1+{\mathrm{<figure-callout\; id="2"\; label="C"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">C</figure-callout>}}_2\&times;{\mathrm{<figure-callout\; id="2"\; label="CNL"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">CNL</figure-callout>}}_2+{\mathrm{<figure-callout\; id="3"\; label="C"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">C</figure-callout>}}_3\&times;{\mathrm{<figure-callout\; id="3"\; label="CNL"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">CNL</figure-callout>}}_3+\mathrm{\&Phi;}\&times;N_f\\ \mathrm{DEN}=V_{\mathrm{SH}}\&times;{\mathrm{\&rho;}}_{\mathrm{SH}}+{\mathrm{<figure-callout\; id="1"\; label="C"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">C</figure-callout>}}_1\&times;{\mathrm{\&rho;}}_1+{\mathrm{<figure-callout\; id="2"\; label="C"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">C</figure-callout>}}_2\&times;{\mathrm{\&rho;}}_2+{\mathrm{<figure-callout\; id="3"\; label="C"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">C</figure-callout>}}_3\&times;{\mathrm{\&rho;}}_3+\mathrm{\&Phi;}\&times;{\mathrm{\&rho;}}_f\\ \mathrm{\&Phi;}+V_{\mathrm{SH}}+\mathrm{<figure-callout\; id="1"\; label="C"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">C</figure-callout>}1+\mathrm{<figure-callout\; id="2"\; label="C"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">C</figure-callout>}2+{\mathrm{<figure-callout\; id="3"\; label="C"\; filenames="HSA00000013470000021.png"\; state="\{\{state\}\}">C</figure-callout>}}_3=1\end{array}\right.$

In the formula: C ₁, C ₂, C ₃-represent respectively first kind, second kind and the third mineral the percentage volume content (%, %, %);

DT _f, ρ _f, N _f-represent interval transit time, density and middle subvalue (us/ft, the g/cm of fluid respectively ³, p.u);

DT _Ma1, DT _Ma2, DT _Ma3-represent respectively first kind, second kind, the skeleton sound wave value of the third mineral (us/ft, us/ft, us/ft);

CNL _Ma1, CNL _Ma2, CNL _Ma3-represent subvalue (p.u, p.u, p.u) in the skeleton of first, second and the third mineral respectively;

ρ _Ma1, ρ _Ma2, ρ _Ma3-represent the skeletal density value (g/cm of first kind, second kind and the third mineral respectively ³, g/cm ³);

DT, CNL, DEN-represent interval transit time, neutron, density log value (us/ft, p.u, g/cm respectively ³);

V _SH, Φ-represent respectively shale content, degree of porosity (f, f).

Described acoustic porosity is calculated as:

Calculate acoustic porosity with the interval transit time data after shale correction, environmental correction:

$\mathrm{\&phi;}=\frac{\mathrm{\&Delta;t}-{\mathrm{\&Delta;t}}_{\mathrm{mac}}}{{\mathrm{\&Delta;t}}_f-{\mathrm{\&Delta;t}}_{\mathrm{mac}}}$

In the formula: Δ t _Mac, Δ t, Δ t _f-represent respectively formation rock skeleton interval transit time, acoustic travel time logging value, fluid interval transit time (us/ft, us/ft, us/ft);

φ-degree of porosity (f).

Rock matrix interval transit time (Δ t _Mac) take advantage of its skeleton interval transit time value to add up and get by the volumn concentration of each rock composition:

Δt _mac＝∑V _ma×Δt _ma

In the formula: Δ t _Mac, Δ t _Ma-represent respectively formation rock skeleton interval transit time, each rock composition skeleton interval transit time (us/ft, us/ft);

V _MaRepresent each rock component content (f).

Described neutron porosity is calculated as:

Neutron data using neutron data log response equation calculates neutron porosity after shale correction, environmental correction.

$\mathrm{\&phi;}=\frac{{\mathrm{\&Phi;}}_N-{\mathrm{\&Phi;}}_{\mathrm{N\; mac}}}{{\mathrm{\&Phi;}}_{\mathrm{N\; f}}-{\mathrm{\&Phi;}}_{\mathrm{N\; mac}}}$

In the formula: Φ _Nmac, Φ _Nmac, Φ _Nmac-represent respectively subvalue in subvalue in the formation rock skeleton, neutron well logging value, the fluid (p.u, p.u, p.u);

φ-degree of porosity (f).

Subvalue (Φ in the formation rock _Nmac) take advantage of its Φ with each rock component content _Nmac=∑ V _Ma* Φ _NmaThe subvalue adds up and gets in the skeleton:

In the formula: Φ _Nma, Φ _Nmac-represent respectively in each rock composition skeleton subvalue in subvalue, the formation rock skeleton (p.u, p.u);

V _MmaRepresent each rock composition percentage composition (f).

2) get rid of of the influence of factors such as lithology, hole diameter and mud intrusion to interval transit time and neutron data;

Factors such as hole diameter, mud intrusion mainly adopt classical empirical formula of well logging and plate to proofread and correct to the influence of interval transit time, neutron data.

The influence of rock forming mineral composition can be proofreaied and correct (face rock composition calculating section sees before) by calculating each rock composition and volumn concentration, and therefore, what the eliminating lithology influenced most critical is the shale correction of interval transit time and neutron data.

The shale of neutron data is proofreaied and correct:

The shale of neutron data is proofreaied and correct the hydrogen index correction of shale just.Shale in the stratum, not only the neutron hydrogen index is higher, and it is also quite big with change in depth, therefore, shale to hydrogen index is proofreaied and correct, must divide for three steps carried out: to calculate the neutron hydrogen index of shale under the status of criterion earlier, carry out depth correction again, then the neutron data is carried out shale and proofread and correct.

(1) calculates the neutron hydrogen index of shale under the status of criterion

The neutron hydrogen index of clay mineral is made up of hydrogen index (mainly being the hydrogen index of water or oil) and the hydrogen index two parts of clay skeleton of contained fluid in the hole.According to rock, the mineral logging parameter list that Si Lunbeixie company provides, can calculate the fluid hydrogen index and the skeleton hydrogen index (as table 1) of various clay minerals under the status of criterion:

The hydrogen index of table 1 differed clay mineral

Clay mineral	Montmorillonite	Illite	Kaolinite	Chlorite
					Total hydrogen index %	??44	??30	??37	??52
Skeleton hydrogen index %	??4	??10	??9	??26
					Fluid hydrogen index %	??40	??20	??28	??26

Calculate the average hydrogen index Φ of shale according to the average percentage composition of the clay mineral composition of study area and each composition _Nsh:

Φ _Nsh＝Φ _NmV _m+Φ _NiV _i+Φ _NgV _g+Φ _NcV _c

In the formula: Φ _Nsh, Φ _Nm, Φ _Ni, Φ _Ng, Φ _Nc-represent respectively shale, montmorillonite, illite, chlorite the neutron hydrogen index (%, %, %, %);

V _m, Vi, Vg, Vc-represent respectively montmorillonite, illite, kaolinite, chlorite percentage composition (f, f, f, f).

(2) the average hydrogen index of shale is carried out depth correction

Because the neutron hydrogen index of shale is bigger with change in depth, therefore, when reservoir when the shale layer depth difference of statistical analysis is big, need carry out depth correction.

According to shale hydrogen index (φ _Nsh) with the variation relation (as Fig. 1) of the degree of depth (h), the following empirical formula of match is proofreaied and correct:

φ _Nsh＝91.1-39.75×10 ^-3·h+5.15×10 ^-6·h ²；

Can extend according to this Trendline for the shale hydrogen index of the above shallow gas pay of 1500m and the relation of the degree of depth, proofread and correct with same relation formula.

The degree of depth according to the study area reservoir, the average hydrogen index of shale under the status of criterion is marked in the plate, if just in time fall among the figure on the relation curve, illustrate that the clay mineral composition of both shales is basic identical, then can directly try to achieve the hydrogen index of other degree of depth place shale with this plate; If do not fall among the figure on the relation curve, the clay mineral composition difference of both shales is described, at this moment can cross this point and make a relation curve that is parallel in the plate, thereby on this new relation curve, find the solution the hydrogen index of other degree of depth place shale.Do having certain error like this, because different clay minerals, the relation of its neutron hydrogen index and the degree of depth is difference to some extent, but studies show that by real data this species diversity is little, calculates the error of bringing for the shale hydrogen index and can ignore substantially.

(3) neutron well logging data shale is proofreaied and correct

In two steps above comprehensive, the neutron hydrogen index is after shale is proofreaied and correct:

Φ _Nco＝Φ _N-Φ _Nsh*V _sh。

In the formula: Φ _Nco, Φ _N, Φ _Nsh-represent respectively neutron hydrogen index after shale is proofreaied and correct, neutron well logging value, the shale hydrogen index behind depth correction (%, %, %);

V _Sh-shale content (%).

The shale of interval transit time is proofreaied and correct:

Equally, the shale of interval transit time is proofreaied and correct and was also divided for three steps carried out: calculate the interval transit time value of shale under the status of criterion earlier, carry out depth correction again, then acoustic logging data carried out the shale correction.

The rock, the mineral logging parameter list that utilize Si Lunbeixie company to provide can calculate average interval transit time (the Δ t of shale according to the average percentage composition of the clay mineral composition of research area and each composition _Sh):

Δt _sh＝Δt _mV _m+Δt _iV _i+Δt _gV _g+Δt _cV _c

In the formula: Δ t _Sh, Δ t _m, Δ t _i, Δ t _g, Δ t _c-represent respectively shale, montmorillonite, illite, chlorite the neutron hydrogen index (us/ft, us/ft, us/ft us/ft, us/ft);

V _m, Vi, Vg, Vc-represent respectively montmorillonite, illite, kaolinite, chlorite percentage composition (%, %, %, %);

The buried depth and the distribution form of shale have the greatest impact to interval transit time, and be all the more so with the bigger montmorillonite of spacing of lattice especially.Experimental study shows: the dispersed shale so contain more irreducible water, makes the velocity of sound of its velocity of sound near water because of not being subjected to the overburden pressure effect substantially, and little with the buried depth relation; Laminar shale and structure are excluded most of irreducible water because of will directly bearing the overburden pressure effect, so the velocity of sound obviously increases, and increase with the degree of depth, therefore need make depth correction to the interval transit time of shale especially.

According to the shale time difference (Δ t _Sh) with the relation (as Fig. 2) of the degree of depth (H), set up fitting formula:

Δt _sh＝166-48.5×10 ^-3H+6.5×10 ^-6H ²

Try to achieve the interval transit time of its shale by the reservoir place degree of depth.

Therefore, the interval transit time after shale is proofreaied and correct is:

Δt _co＝Δt-V _sh·Δt _sh

In the formula: Δ t _Co, Δ t, Δ t _Sh-represent respectively interval transit time correcting value, acoustic travel time logging value, the shale interval transit time behind depth correction (us/ft, us/ft, us/ft);

V _Sh---shale content (%).

Illustrate: curve among Fig. 2 (1) is the Trendline of 0～1500m, promptly is suitable for shallow gas pay; Curve (2) is the Trendline of 1500～4000m, and curve (3) is the following Trendline of 4000m.

3) utilize interval transit time and neutron data response difference, set up the distinguishing reservoir fluid type standard by the size that compares sound wave hole and neutron porosity to natural gas and formation water.

Research is thought: the reservoir water-gas distribution is relevant with pore structure, easier gas or the water of being full of of the reservoir that pore structure is good, and its air water difference is also more obvious.The reservoir fluid log response feature of different pore structures is different, so set up discrimination standard by pore structure is good with relatively poor two kinds of situations, carries out fluid identification, more realistic geological condition, and it is also higher to differentiate coincidence rate.

Wherein:

A, for the good reservoir of pore structure, the fluid type discrimination standard is:

Gas-bearing formation: PORA-PORN＞0;

Water layer: PORA-PORN＜0;

Do layer (or the low especially layer of output): PORA-PORN ≈ 0.

In the formula: PORA, PORN represent acoustic porosity (%), neutron porosity (%) respectively.

That is to say: for the good reservoir of pore structure, the fluid type discrimination standard is: the difference of acoustic porosity and neutron porosity is gas-bearing formation greater than zero, less than zero be water layer, near zero for doing layer or tolerance, reservoir that the water yield is all very low.The rare air water of such reservoir rock generally is the air water layer of going up under the gas with layer, differentiates because this method is pointwise, so be easy to discern the air water layer and judge gas-water interface.

B, slightly different for the relatively poor low porosity and low permeability reservoir discrimination standard of pore structure as Su Lige gas field fluid type discrimination standard is:

Gas-bearing formation: PORA-PORN＞3%;

Water layer: PORA-PORN＜0%;

Air water is layer together :-2%＜PORA-PORN＜5%.

In the formula: PORA, PORN represent acoustic porosity (%), neutron porosity (%) respectively.

That is to say: slightly different for the relatively poor reservoir discrimination standard of pore structure, as the Su Lige gas field fluid type discrimination standard of low porosity and low permeability be: the difference of acoustic porosity and neutron porosity is gas-bearing formation greater than 3%, less than zero be water layer.The air water layer of such reservoir rock is mainly air water with layer, and its discrimination standard is that the difference of acoustic porosity and neutron porosity is between-2%～5%.There is a small amount of air water layer of going up water under the gas simultaneously, the also relatively good identification of such reservoir: the top reservoir has the difference of the depth point acoustic porosity of certain thickness (greater than 0.5m) and neutron porosity continuously greater than zero, and the depth point acoustic porosity that the bottom reservoir has a certain thickness (greater than 0.5m) and the difference of neutron porosity are continuously less than zero.

Claims (10)

1. acoustic porosity and neutron porosity method for judging reservoir fluid type of difference between is characterized in that step comprises:

1) by the well logging of rock core information scale, well-log information environmental correction, accurately calculates reservoir shale content, rock composition, acoustic porosity and neutron porosity;

2) get rid of lithology, hole diameter and mud and invade the influence of factor interval transit time and neutron data;

3) utilize interval transit time and neutron data response difference, set up the distinguishing reservoir fluid type standard by the size that compares sound wave hole and neutron porosity to natural gas and formation water, wherein:

A, for the good reservoir of pore structure, the fluid type discrimination standard is:

Gas-bearing formation: PORA-PORN＞0;

Water layer: PORA-PORN＜0;

Do layer (or the low especially layer of output): PORA-PORN ≈ 0;

In the formula: PORA, PORN represent acoustic porosity (%), neutron porosity (%) respectively;

B, for the relatively poor low porosity and low permeability reservoir of pore structure, the fluid type discrimination standard is:

Gas-bearing formation: PORA-PORN＞3%;

Water layer: PORA-PORN＜0%;

Air water is layer together :-2%＜PORA-PORN＜5%;

In the formula: PORA, PORN represent acoustic porosity (%), neutron porosity (%) respectively.

2. acoustic porosity according to claim 1 and neutron porosity method for judging reservoir fluid type of difference between, it is characterized in that: described rock core scale well logging mainly comprises two aspects: be by core analysis data scale logging data processing parameter on the one hand, calculate the parameter of shale content, the parameter that rock electroanalysis data determines to calculate saturation ratio as rock core X diffraction analysis data scale; On the other hand with the means of interpretation of product test WELL LITHOLOGY, degree of porosity, permeability and the saturation ratio of core analysis degree of porosity, permeability and water saturation and adjust, up to satisfying error requirements.

3. acoustic porosity according to claim 2 and neutron porosity method for judging reservoir fluid type of difference between is characterized in that: described well-log information environmental correction specifically is meant: select for use classical theoretical plate and empirical formula to carry out environmental correction according to reality well logging situation and logging program.

4. acoustic porosity according to claim 3 and neutron porosity method for judging reservoir fluid type of difference between, it is characterized in that: described shale content calculates and is specially: the calculating of shale content needs clay composition and the character according to the work area, select for use different well-log informations to calculate: directly calculate with natural gamma on the low stratum of non-shale composition radioactivity, the high stratum of non-shale composition radioactivity selects for use different power spectrum data to calculate shale content: as the radioactivity of non-shale composition in the stratum based on thorium, just select the potassium curve calculation, the radioactivity of non-shale composition is based on potassium, just select the thorium curve calculation, the stratum that feldspar content is high uranium curve calculation, the non-shale composition in stratum contains radioactivity, uses neutron when not having the power spectrum data again, shale content is calculated in the density intersection.

5. acoustic porosity according to claim 4 and neutron porosity method for judging reservoir fluid type of difference between, it is characterized in that: described rock composition is calculated as: according to geologic characteristics, foundation meets the log response equation of rock composition, hole and the fluid of work area actual conditions, calculates mineralogical composition volumn concentration and degree of porosity.

6. acoustic porosity according to claim 5 and neutron porosity method for judging reservoir fluid type of difference between is characterized in that: described acoustic porosity is calculated as: use the interval transit time data after shale correction, environmental correction to calculate acoustic porosity.

7. acoustic porosity according to claim 6 and neutron porosity method for judging reservoir fluid type of difference between is characterized in that: described neutron porosity is calculated as: neutron data using neutron data log response equation calculates neutron porosity after shale correction, environmental correction:

8. acoustic porosity according to claim 7 and neutron porosity method for judging reservoir fluid type of difference between is characterized in that: described eliminating lithology, hole diameter and mud intrusion factor are meant the influence of interval transit time and neutron data: factors such as hole diameter, mud intrusion mainly adopt classical empirical formula of well logging and plate to proofread and correct to the influence of interval transit time, neutron data; The influence of rock forming mineral composition can be proofreaied and correct by calculating each rock composition and volumn concentration, gets rid of the lithology influence and comprises the shale correction of interval transit time and the shale correction of neutron data.

9. acoustic porosity according to claim 8 and neutron porosity method for judging reservoir fluid type of difference between, it is characterized in that: it is exactly the hydrogen index correction of shale that the shale of described neutron data is proofreaied and correct, divided for three steps carried out: to calculate the neutron hydrogen index of shale under the status of criterion earlier, carry out depth correction again, then the neutron data is carried out shale and proofread and correct.

10. acoustic porosity according to claim 9 and neutron porosity method for judging reservoir fluid type of difference between, it is characterized in that: the shale of described interval transit time is proofreaied and correct and was also divided for three steps carried out: calculate the interval transit time value of shale under the status of criterion earlier, carry out depth correction again, then acoustic logging data carried out the shale correction.

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