CN107575219A - A kind of shale gas reservoir formation fracture pressure gradient computational methods - Google Patents

Abstract

The invention relates to a method for calculating the fracture pressure gradient of a shale gas reservoir formation, which collects conventional logging curve data of the entire well section, calculates the rock skeleton density ρma, and determines the average porosity Φ and fluid density ρw of the formation; collects the shale gas well reservoir section Depth, vertical depth, acoustic AC, density DEN, neutron CNL log data; calculate the average formation density by ρ=(1‑Φ)*ρma+Φ*ρw; determine the fracture pressure coefficient K by fitting regression method: K=P0+P1*AC+P2*DEN+P3*CNL, calculate the fracture pressure gradient of the shale reservoir formation according to the formula FRAC=K*ρ, then use the formula: FP=FRAC*H to calculate the fracture pressure, and finally output the result. The present invention has been applied to more than 200 shale gas wells in the Fuling shale gas field, and the calculated stratum fracture pressure gradient is closer to the stratum fracture pressure gradient obtained by actual construction, with an error of less than 15%.

Description

A Calculation Method of Formation Fracture Pressure Gradient in Shale Gas Reservoir

technical field

The invention relates to a method for calculating and determining the fracture pressure of a shale reservoir formation by using conventional logging data, in particular to a method for calculating the fracture pressure gradient of a shale gas reservoir formation.

Background technique

Shale gas is a new type of clean energy and an important unconventional natural gas resource. The development of shale gas requires the drilling of horizontal wells in the "well factory" mode, and the shale gas reservoirs in the horizontal section of horizontal wells need to undergo multi-stage large-scale fracturing, which is costly and risky. The accuracy of calculation or prediction of formation fracture gradient and formation fracture pressure parameters in shale gas reservoirs is very important, which directly affects the effect of reservoir stimulation.

The traditional calculation methods of formation fracture pressure gradient mainly include Eaton method, Matthews and Kelly method, and Christman method. These methods were mainly formed during the 1960s and 1970s to solve the problem of calculating or predicting the formation fracture gradient and formation fracture pressure parameters of conventional reservoirs such as sandstone and carbonate rock.

With the discovery of domestic shale gas fields and the expansion of shale gas exploration and development test scale, the cost and risk of multi-stage fracturing of shale gas horizontal wells are high, and the calculation accuracy of formation fracture pressure gradient and formation fracture pressure of shale gas reservoirs As the requirements are getting higher and higher, the traditional calculation method of formation fracture pressure gradient is difficult to meet the production needs, and the problem of large calculation errors is becoming more and more prominent.

Contents of the invention

The purpose of the present invention is to aim at the present technical situation mentioned above, aiming to provide a kind of method that can calculate reliable fracture pressure of shale gas reservoir stratum by using conventional logging curve data.

The method for realizing the object of the present invention is a method for calculating the fracture pressure gradient of a shale gas reservoir formation, and the specific steps are:

1) Collect the conventional well logging curve data of the whole well section. The conventional well logging curve data include natural gamma ray, neutron, density, acoustic wave and resistivity logging curves; the weighted average method is used to calculate the rock skeleton density using the conventional well logging curve data ρma, using the conventional logging curve data of the whole well section and the core porosity analysis data of core wells taken from regional exploratory wells, determine the average porosity Φ and fluid density ρw of the formation;

The dimension of rock skeleton density ρma is g/cm ³ ,

The dimension of formation average porosity Φ is percentage,

The dimension of fluid density ρw is g/cm ³ ;

2) Collect shale gas well reservoir depth, vertical depth, acoustic AC, density DEN, neutron CNL logging curve data;

The dimension of density DEN is g/cm ³ ,

The AC dimension of sound wave is μs/m,

The dimension of neutron CNL is percentage,

3) Calculate the formation average density ρ from the formation rock skeleton density ρma, porosity Φ and fluid density ρw obtained in step 1):

ρ=(1-Φ)*ρma+Φ*ρw;

The dimension of formation average density ρ is g/cm ³ ,

4) Combine the acoustic wave, density DEN, and neutron logging curve data of the shale reservoir section collected in step 2) with the fracture pressure of the fractured wells in the area, and determine the fracture pressure coefficient K by fitting regression method: K=P0+ P1*AC+P2*DEN+P3*CNL,

In the formula, P0 to P3 are regional empirical coefficients, which are related to the formation lithology of the fracturing section, and the formation lithology is related to the logging curve;

5) Calculate the formation fracture pressure gradient FRAC of the shale gas reservoir section by the formula: FRAC=K*ρ;

In the formula, the fracture pressure gradient FPAC dimension of the shale reservoir is MPa/100m,

The dimension of formation average density ρ is g/cm ³ ,

6) Output calculation results.

The present invention has been applied to more than 200 shale gas wells in the Fuling shale gas field, and the calculated stratum fracture pressure gradient is closer to the stratum fracture pressure gradient obtained by actual construction, with an error of less than 15%.

Description of drawings

Fig. 1 is a block diagram of the workflow of the present invention.

detailed description

With reference to Fig. 1, concrete steps of the present invention are:

1) Collect the conventional logging curve data of the whole well section. The conventional logging curve data include natural gamma ray, neutron, density, acoustic wave, resistivity and other logging curves; use the weighted average method to calculate the rock skeleton using the density logging curve data Density ρma, the average porosity Φ and fluid density ρw of the formation are determined by using the conventional logging curve data of the whole well section and the core porosity analysis data of the core well of the regional exploration well;

The dimension of rock skeleton density ρma is g/cm ³ ,

The dimension of formation average porosity Φ is percentage,

The dimension of fluid density ρw is g/cm ³ .

Among them, the conventional logging curve data are used to exclude bad boreholes and unreliable data. Fluid density ρw is generally taken as 1.1±0.1g/cm ³ .

2) Collect shale gas well reservoir depth, vertical depth, acoustic AC, density DEN, neutron CNL logging curve data;

The dimension of density DEN is g/cm ³ ,

The AC dimension of sound wave is μs/m,

The dimension of neutron CNL is percentage.

3) Calculate the formation average density ρ from the formation rock skeleton density ρma, porosity Φ and fluid density ρw obtained in step 1):

ρ=(1-Φ)*ρma+Φ*ρw;

The dimension of formation average density ρ is g/cm ³ ,

4) Combine the acoustic wave, density DEN, and neutron logging curve data of the shale reservoir section collected in step 2) with the fracture pressure of the fractured wells in the area, and determine the fracture pressure coefficient K by fitting regression method: K=P0+ P1*AC+P2*DEN+P3*CNL,

The fracture pressure coefficient is related to the formation lithology of the fracturing section, and the formation lithology is related to the logging curve. The regional experience coefficient P0-P3 can be determined by combining the data of the fracturing well with the data fitting method, so as to calculate the formation fracture pressure coefficient.

5) Calculate the formation fracture pressure gradient FRAC of the shale gas reservoir section by the formula: FRAC=K*ρ;

In the formula, the fracture pressure gradient FPAC dimension of the shale reservoir is MPa/100m,

The dimension of formation average density ρ is g/cm ³ ,

6) Output calculation results.

The present invention is described in detail below with specific examples. (The embodiment is preferably written according to the previous steps)

Example 1: Well JY2-3 in a certain gas field

1) Collect the conventional logging curve data (including acoustic wave, density, and neutron curve) of the whole well section of the well, and use the weighted average method to calculate the average skeleton density ρma of the rock as 2.67g/cm ³ using the density logging curve data. The average porosity Φ of the formation is determined to be 0.05, and the fluid density ρw is 1.05g/cm ³ according to the conventional logging curve data of the section and the core porosity analysis data of the core well of the regional exploration well;

2) Determine the well section of the shale gas reservoir to be 2980.0-4490.0m and the vertical depth to be 2448.0-2521.0m, and collect the data of acoustic wave, density and neutron logging curves of the shale reservoir section;

3) By ρ=(1-Φ)*ρma+Φ*ρw; calculate the average formation density ρ to be 2.589g/cm ³ ;

4) Determine the fracture pressure coefficient k (area empirical coefficient related to regional strata) through the data of acoustic wave, density, and neutron logging curves in the fracturing section, and the formula for calculating the fracture pressure coefficient (AC is acoustic wave, DEN is density, CNL is neutron , P0-P3 are constants): K=P0+P1*AC+P2*DEN+P3*CNL. Through the fitting analysis of more than 4,000 fracturing data of more than 260 wells in the Fuling area, the fitting regression method was used to obtain p1=-0.004274867, p2=-0.046441009, p3=0.004972802, p0=2.019452937. The average K value of this fracturing section is calculated to be 0.977.

5) By the formula: FRAC=K*ρ, the formation fracture pressure gradient in the fracturing section is calculated to be 2.537, and the average fracture pressure is 63.06MPa;

6) Output the fracture pressure gradient and fracture pressure calculation results according to user requirements.

The fracturing pressure of the shale gas layer in the 2980.0-4490.0m well section of the JY2-3 well section calculated by the present invention is 63.06MPa. The average formation fracture pressure of the 20 sections of the well was measured to be 63.48MPa, with an error of less than 10%. The calculated results are very close. The initial unobstructed flow rate of natural gas production is about 116.39×10 ⁴ m ³ , and the fracturing effect is remarkable.

It can be seen from Example 1 that the formation fracture pressure gradient and formation fracture pressure calculated by the present invention are close to the actual measurement results, and the error is less than 10%, which meets the needs of on-site construction and has strong application value.

Example 2: Well JY13-2 in a shale gas field

Well JY13-2 is a horizontal well with a long horizontal section, the horizontal section of the gas reservoir is 2630-4078m, the vertical depth of the gas reservoir is 2330.0-2412.0m, and the horizontal section passes through the gas reservoir.

1) Collect the conventional logging curve data (including acoustic wave, density, and neutron curve) of the whole well section of the well, and use the weighted average method to calculate the average skeleton density ρma of the rock as 2.67g/cm ³ using the density logging curve data. The average porosity Φ of the formation is determined to be 0.05, and the fluid density ρw is 1.05g/cm ³ according to the conventional logging curve data of the section and the core porosity analysis data of the core well of the regional exploration well;

2) Determine the well section of the shale gas reservoir to be 2630-4078m, and the vertical depth to be 2332.0-2412.0m, and collect the acoustic wave, density and neutron logging curve data of the shale reservoir section;

3) By ρ=(1-Φ)*ρma+Φ*ρw; calculate the average formation density ρ to be 2.589g/cm ³ ;

4) Determine the fracture pressure coefficient k (area empirical coefficient related to regional strata) through the data of acoustic wave, density, and neutron logging curves in the fracturing section, and the formula for calculating the fracture pressure coefficient (AC is acoustic wave, DEN is density, CNL is neutron , P0-P3 is a constant): K=P0+P1*AC+P2*DEN+P3*CNL, through the fitting analysis of more than 4,000 fracturing data of more than 260 wells in Fuling area, using the fitting regression method to obtain p1=-0.004274867, p2=-0.046441009, p3=0.004972802, p0=2.019452937, the calculated average K value of this fracturing section is 1.036;

5) By the formula: FRAC=K*ρ, the formation fracture pressure gradient in the fracturing section is calculated as 2.137, and the average fracture pressure is 64.2MPa;

6) Output the fracture pressure gradient and fracture pressure calculation results according to user requirements.

The average fracture pressure of the shale gas formation in the 2630-4078m horizontal section of the JY13-2 well calculated by the present invention is 64.2MPa. The completion fracturing operation was carried out in 18 stages. The average fracture pressure of the formation measured during the construction was 60.0MPa, and the initial unobstructed flow rate of natural gas production was about 111.02×10 ⁴ m ³ per day. The fracturing effect was obvious.

It can be seen from Example 1 that the formation fracture pressure gradient and formation fracture pressure calculated by the present invention are close to the actual measurement results, with an error of less than 10%, and the effect of guiding fracturing operation is good.

Claims (3)

1. shale gas reservoir formation fracture pressure gradient computational methods, it is characterised in that：Concretely comprise the following steps：

1) the Logging Curves data of full well section are collected, Logging Curves data includes natural gamma, neutron, density, sound Ripple, Resistivity log；Matrix density ρ ma are calculated using Logging Curves data using weighted mean method, utilized The core porosity analysis of data of full well section Logging Curves data and region prospect pit core hole, determines formation average porosity Φ and fluid density ρ w；

Matrix density ρ ma dimensions are g/cm³,

Formation average porosity Φ dimensions are percentage,

Fluid density ρ w dimensions are g/cm³；

2) shale gas well Reservoir Section depth, vertical depth, sound wave AC, density DEN, neutron CNL borehole log datas are collected；

Density DEN dimensions are g/cm³,

Sound wave AC dimensions are μ s/m,

Neutron CNL dimensions are percentage,

3) formation rock skeletal density ρ ma, porosity Φ and fluid density ρ w calculate formation average denstiy ρ obtained by step 1)：

ρ=(1- Φ) * ρ ma+ Φ * ρ w,

Formation average denstiy ρ dimensions are g/cm³；

4) it is collected that shale reservoir section sound wave, density DEN, neutron well logging curve data combine area fractured well by step 2) Fracture pressure, fracture pressure COEFFICIENT K is determined by being fitted the method returned：K=P0+P1*AC+P2*DEN+P3*CNL,

P0 to P3 is regional experience coefficient in formula, and relevant with fracturing section formation lithology, formation lithology is relevant with log；

5) formula is passed through：FRAC=K* ρ calculate shale gas Reservoir Section formation fracture pressure gradient FRAC；

Shale reservoir formation fracture pressure gradient FPAC dimensions are MPa/100m in formula,

Formation average denstiy ρ dimensions are g/cm³；

6) result of calculation is exported.

2. shale gas reservoir formation fracture pressure gradient computational methods according to claim 1, it is characterised in that：Step 1) Middle Logging Curves data is exclusion bad well and corrupt data data.

3. shale gas reservoir formation fracture pressure gradient computational methods according to claim 1, it is characterised in that：Fluid is close Degree ρ w take 1.1 ± 0.1g/cm³。