CN110646332B

CN110646332B - Method for determining movable water saturation of gas-water interbed gas reservoir under high-temperature and high-pressure conditions

Info

Publication number: CN110646332B
Application number: CN201911007216.XA
Authority: CN
Inventors: 汪周华; 杨博文; 何胜林; 郭平; 王雯娟; 杜建芬; 朱绍鹏; 刘煌; 杨柳; 胡义升
Original assignee: Southwest Petroleum University
Current assignee: Southwest Petroleum University
Priority date: 2019-10-22
Filing date: 2019-10-22
Publication date: 2022-03-11
Anticipated expiration: 2039-10-22
Also published as: CN110646332A

Abstract

The invention relates to a method for determining movable water saturation of a gas-water interbed gas reservoir under high-temperature and high-pressure conditions, which comprises the following steps: (1) obtaining different depths H of single well of certain gas reservoir_iCorresponding well-log interpretation permeability K_ciGas saturation S_gi(ii) a (2) Obtaining different depths H of the well_iCleaning and drying a reservoir plunger core, and testing the diameter D of the core_iLength L of_iDetermining the porosity phi by gas measurement_iPermeability K_i(ii) a (3) Determining the experimental displacement pressure difference, i.e. the maximum pressure gradient lambda_max(ii) a (4) Determining the movable fluid saturation of the rock core; (5) determining the saturation of the bound water and the saturation of the residual gas of the rock core under the conditions of high temperature and high pressure; (6) and determining the movable water saturation of each layer of the single well of the gas reservoir. The method utilizes the results of high-temperature high-pressure gas-water phase permeability test, nuclear magnetic resonance movable fluid saturation test and logging original water saturation, comprehensively considers the influences of reservoir temperature and pressure conditions and gas phase existence, and has the advantages of reliable principle, simplicity, practicability, high precision and wide market application prospect.

Description

Method for determining movable water saturation of gas-water interbed gas reservoir under high-temperature and high-pressure conditions

Technical Field

The invention relates to a method for determining movable water saturation of a gas-water interbed gas reservoir under high-temperature and high-pressure conditions in the field of petroleum and natural gas exploration and development.

Background

The gas-water interbed gas reservoir occupies a considerable proportion in the gas reservoir types in China, and the gas reservoir types are generally characterized by the following characteristics: firstly, the original water saturation of a reservoir with the gas layer having high water saturation and the permeability lower than 0.1mD can reach 60% (Taotai, summer yogo, Liu Innovation and the like; discussion of the high water-containing characteristics and the water production mechanism of a sunken compact sandstone gas reservoir in the east China sea and the west lake [ J ], natural gas exploration and development, 2018, 41 (3): 75-80); secondly, the gas-water relationship is complex, and the characteristics of gas layer and water layer interactive distribution are usually presented in the longitudinal direction; thirdly, water is generally produced by the gas well in the production process of the gas reservoir single well. Due to the restriction of the characteristics, the common understanding of the water outlet layer position, the water outlet condition, the single-layer water outlet quantity and the like of the gas reservoir single well is unclear, and the formulation of water treatment measures of the gas reservoir is severely restricted.

Currently, there are several main methods for studying the mobility of water phase in a gas reservoir: the nuclear magnetic resonance testing method under different centrifugal force conditions (Juwenjuan, Lukefeng, Chengfeng, etc.. research on movable water saturation of depressed hypotonic sandstone gas reservoir in West lake [ J ], petroleum geology and engineering 2016,30(5): 67-70); secondly, core displacement testing methods with different pressure differences (Guo Ping, Huangwei Bao, Jiangwei and the like. compact gas reservoir constraint and movable water research [ J ], natural gas industry, 2006, 26 (10): 99-101); thirdly, a test method combining rock core displacement and nuclear magnetic resonance (Fuda, Zhuhuayin, Liuyi Cheng, etc., movable water experiment [ J ] in rock pores of a low permeability gas reservoir, Daqing institute of Petroleum, 2008, 32 (5): 23-26); and fourthly, a macroscopic well logging interpretation method (Wu Zu Yun, Zhang Yun, Ku Xiang. the movable water saturation of a compact reservoir stratum is evaluated by utilizing nuclear magnetic resonance well logging data [ J ], 2011,35 (6): 559-563). The method has the following problems in the overview: (1) the irreducible water saturation is determined based on a mercury intrusion experiment, influence of fluid property difference of a gas reservoir and reservoir temperature is ignored, and the determined irreducible water saturation value is low, so that the movable water saturation in the reservoir is overestimated; (2) determining the rock core fully saturated formation water when the irreducible water saturation is determined by the nuclear magnetic resonance method, neglecting the influence of gas phase in the formation, considering the movable fluid saturation of the nuclear magnetic resonance test as the movable water saturation, and exaggerating the movable water saturation in the reservoir; in addition, during nuclear magnetic resonance testing, the core displacement pressure gradient is generally large, the basis for determination is lacked, and the movable water saturation is also overestimated; (3) the well logging interpretation method relates to the determination of relaxation time threshold values of movable fluid and bound fluid, is influenced by reservoir heterogeneity, and adopts a uniform threshold value to determine that the mobility difference of a water phase is large, so that the determination accuracy of movable water saturation is influenced.

Disclosure of Invention

The invention aims to establish a method for determining movable water saturation of a gas-water interbed gas reservoir under the conditions of high temperature and high pressure.

In order to achieve the technical purpose, the invention adopts the following technical scheme.

The method for determining the movable water saturation of the gas-water interbed gas reservoir under the conditions of high temperature and high pressure sequentially comprises the following steps of:

(1) obtaining different depths H of a single well of a certain gas reservoir based on field logging interpretation data_i(m) corresponding well-logging interpretation permeability K_ci(mD), gas saturation S_gi(%) to give K respectively_ci—H_iRelation curve S_gi—H_iA relation curve;

(2) obtaining different depths H of the well_i(m) reservoir plunger core (not less than five cores), cleaning and drying, and testing core diameter D_i(cm) length L_i(cm) determining the porosity phi thereof by gas-measuring_i(%), permeability K_i(mD)；

(3) Determining an experimental displacement pressure difference:

based on the dynamic production data of the gas well, the gas and water yield corresponding to the maximum stable water-gas ratio is selected, and the corresponding bottom hole flowing pressure P is calculated_wf(MPa)；

Based on original formation pressure P of gas reservoir₀(MPa), well control radius R_e(m) radius of wellbore R_w(m) calculating the maximum pressure gradient lambda during the production of the well jet_max＝(P₀-P_wf)/ln(R_e/R_w) (MPa/m), namely the experimental displacement differential pressure;

(4) determining the movable fluid saturation of the core:

firstly, respectively saturating stratum water with rock cores, respectively testing the distribution characteristics of water phase in each rock core by adopting a nuclear magnetic resonance method, and determining the nuclear magnetic testing porosity phi_wi(％)；

② experimental displacement differential pressure (maximum pressure gradient) lambda_maxRespectively displacing each core by adopting nitrogen until no water is produced at the outlet end of the core under the condition of normal temperature; then the nuclear magnetic resonance method is adopted to test the water phase distribution characteristics to determine the residual water phase porosity phi_wri(%); cleaning and drying the rock core;

calculating movable fluid saturation value S of each rock core_di＝(Φ_wi-Φ_wri)/Φ_wi(%), plot S_di—K_iRelationship curve, regression analysis determines equation S_di＝f(K_i)；

(5) Determining the saturation of the rock core irreducible water and the saturation of residual gas under the conditions of high temperature and high pressure:

at the formation temperature T₀(° c), original formation pressure P₀(MPa), maximum pressure gradient lambda_maxUnder the condition, the actual natural gas sample is adopted to displace the rock core to the state of the bound water, and the bound water saturation S of each rock core is determined_wri(%); and drawing S_wri—K_iRelationship curve, regression analysis determines equation S_wri＝f(K_i)；

② recording the volume V of the natural gas remained in the rock core_g0i(ml); then at the maximum pressure gradient lambda_maxUnder the condition, stratum water is adopted to displace the rock core until no gas is discharged, and produced gas V is collected_g1i(ml), calculating the residual gas volume V of each core_gri＝V_g0i-V_g1i(ml), residual gas saturation S_gri＝100V_gri/(0.25πD_i ²L_iΦ_i) (%); drawing S_gri—K_iRelationship curve, regression analysis determines equation S_gri＝f(K_i)；

(6) Determining the movable water saturation of each layer of the single well of the gas reservoir:

(ii) for depth H_iGas layer according to K_ci—H_iRelation curve S_gi—H_iDetermining K of corresponding depth by using relation curve_ci、S_giIs a reaction of K_ciRespectively substitute into equation S_di＝f(K_i)、S_gri＝f(K_i) Determining the corresponding depth H of the well_iMovable fluid saturation S_cdi(%), residual gas saturation S_cgri(%) to obtain the well depth H_iMovable water saturation S_cdwi(％)＝S_cdi-(S_gi-S_cgri)；

② for depth H_iIn accordance with K_ci—H_iDetermining K of corresponding depth by using relation curve_ciIs a reaction of K_ciSubstitution equation S_di＝f(K_i) Determining the corresponding depth H of the well_iMovable fluid saturation S_cdi(%) to obtain the corresponding depth H of the well_iMovable water saturation S_cdwi(％)＝S_cdi。

Repetition (6)Step of determining movable water saturation S of each layer of the well_cdwi。

Drawings

FIG. 1 is a graph of mobile fluid saturation versus gas permeability.

FIG. 2 is a plot of irreducible water saturation versus gas permeability.

FIG. 3 is a plot of residual gas saturation versus gas permeability.

Detailed Description

The invention is further illustrated below with reference to the figures and examples.

The method for determining the movable water saturation of the gas-water interbed gas reservoir under the conditions of high temperature and high pressure comprises the following specific implementation steps:

(1) obtaining different depths H of a single well of a certain gas reservoir based on field logging interpretation data_i(1646.5 m-1656.6 m) corresponding well logging interpretation permeability K_ci(mD), gas saturation S_gi(%), see table 4.

(2) Obtaining 10 reservoir plunger cores of different depths Hi (1646.5 m-1656.6 m) of the well, cleaning and drying, and testing the diameter Di (cm) and the length Li (cm) of the cores; the porosity phi i (%) and the permeability Ki (mD) are determined by a gas measurement method, and the test results are shown in Table 1.

Physical property test result of core of 110 plunger blocks in table

NO.	H_i，m	D_i，cm	L_i，cm	ф_i，％	K_i，mD	NO.	H_i，m	D_i，cm	L_i，cm	ф_i，％	K_i，mD
												1	1646.5	2.54	4.19	10.23	0.45	6	1651.0	2.54	5.29	15.11	10.1
2	1647.0	2.54	5.31	12.8	2.72	7	1652.4	2.54	4.94	13.87	6.4
												3	1648.3	2.54	4.83	14.23	5.72	8	1653.2	2.54	4.06	15.41	11.1
4	1649.5	2.54	5.21	14.79	8.97	9	1654.1	2.54	5.23	15.23	13.21
												5	1650.1	2.54	5.04	14.72	7.71	10	1656.2	2.54	5.18	15.01	14.01

(3) Determining an experimental displacement pressure difference:

based on the dynamic production data of the gas well, the gas and water yield corresponding to the maximum stable water-gas ratio is selected to calculate the corresponding bottom hole flowing pressure P_wf＝11.5MPa；

Based on original formation pressure P of gas reservoir₀35.3MPa, well control radius R_e450m, wellbore radius R_wCalculating the maximum pressure gradient lambda in the gas well self-injection production process as 0.0625m_max＝(P₀-P_wf)/ln(R_e/R_w) Experimental displacement differential pressure, 2.68MPa/m, (35.3-11.5)/ln (450/0.0625).

(4) Determining the movable fluid saturation of the core:

firstly, 10 rock cores are respectively and completely saturated with formation water, the distribution characteristics of the water phase in each rock core are respectively tested by adopting a nuclear magnetic resonance method, and the nuclear magnetic test porosity value phi is determined_wi(%), see table 2.

Nuclear magnetic porosity test results for 210 plunger cores in table

NO.	H_i，m	Φ_wi，％	Φwri，％	NO.	H_i，m	Φ_wi，％	Φ_wri，％
								1	1646.5	9.72	6.58	6	1651.0	14.35	4.38
2	1647.0	12.16	6.65	7	1652.4	13.18	6.21
								3	1648.3	13.52	5.87	8	1653.2	14.64	5.02
4	1649.5	14.05	5.68	9	1654.1	14.47	3.31
								5	1650.1	13.98	5.89	10	1656.2	14.26	3.24

Is at lambda_maxRespectively displacing each core by adopting nitrogen until water is not produced at the outlet end of the core under the conditions of 2.68MPa/m and normal temperature (20 ℃); then, the nuclear magnetic resonance method is adopted to test the water phase distribution characteristics to determine the residual water phase porosity phi_wri(%), see table 2; and cleaning and drying the core.

Calculating movable fluid saturation value S of each rock core_di＝(Φ_wi-Φ_wri)/Φ_wi(%), plot S_di—K_iRelationship curve (see FIG. 1), regression analysis determines equation S_di＝f(K_i) As follows:

sdi 3.1418Ki +34.154 (equation 1)

at the formation temperature T₀Original formation pressure P at 75 ℃₀35.3MPa, maximum pressure gradient lambda_maxUnder the condition of 2.68MPa/m, the actual natural gas sample is obtained to displace the rock core to a bound water state, and each block is determinedIrreducible water saturation S of core_wri(%), detailed experimental results are shown in table 3; and drawing S_wri—K_iRelationship curve (see FIG. 2), regression analysis determines equation S_wri＝f(K_i) As follows:

S_wri＝-1.1609K_i+41.003 (equation 2)

TABLE 3 core testing of irreducible water and residual gas saturation

② recording the volume V of the natural gas remained in the rock core_g0i(ml); then at the maximum pressure gradient lambda_maxUnder the condition of 2.68MPa/m, stratum water is adopted to displace the rock core until no gas is discharged, and produced gas volume V is collected_g1i(ml), calculating the residual gas volume V of each core_gri＝V_g0i-V_g1i(ml), residual gas saturation S_gri＝100V_gri/(0.25πD_i ²L_iΦ_i) (%), detailed experimental data are shown in table 3; drawing S_gri—K_iRelationship curve (see FIG. 3), regression analysis determines equation S_gri＝f(K_i)。

S_gri＝-0.557K_i+27.258 (Eq.3)

(ii) for depth H_i(1646.5 m-1650.6 m, 1653.4 m-1656.6 m) gas layer, first according to K_ci—H_iRelation curve S_gi—H_iDetermining K of corresponding depth by using relation curve_ci、S_gi(ii) a Then, respectively adding K_ciSubstituting into equation (1) and equation (3), respectively determining the corresponding depth H of the well_iMovable fluid saturation S_cdi(%), residual gas saturation S_cgri(%) to obtain the compoundWell depth H_iMovable water saturation S_cdwi(％)＝S_cdi-(S_gi-S_cgri). The detailed calculation results are shown in Table 4.

② for depth H_iAqueous layer (1650.6 m-1652.7 m), first according to K_ci—H_iDetermining K of corresponding depth by using relation curve_ci(ii) a Then, respectively adding K_ciSubstitution equation S_di＝f(K_i) Determining the corresponding depth H_iMovable fluid saturation S_cdi(%) to obtain the corresponding depth H of the well_iMovable water saturation S_cdwi(％)＝S_cdi。

Repeating the step (6), thereby determining the movable water saturation S of each layer of the well_cdwiThe detailed calculation results are shown in Table 4.

TABLE 4 typical well layer movable water saturation calculation results

Claims

1. The method for determining the movable water saturation of the gas-water interbed gas reservoir under the conditions of high temperature and high pressure sequentially comprises the following steps of:

(1) obtaining different depths H of a single well of a certain gas reservoir based on field logging interpretation data_iCorresponding well-log interpretation permeability K_ciGas saturation S_giRespectively obtain K_ci—H_iRelation curve S_gi—H_iA relation curve;

(2) obtaining different depths H of the single well of the gas reservoir_iCleaning and drying a reservoir plunger core, and testing the diameter D of the core_iLength L of_iDetermining the porosity phi by gas measurement_iPermeability K_i；

(3) Determining the experimental displacement pressure difference, i.e. the maximum pressure gradient lambda_max；

(4) Determining the movable fluid saturation of the core:

firstly, respectively saturating stratum water with rock cores, respectively testing the distribution characteristics of water phase in each rock core by adopting a nuclear magnetic resonance method, and determining the nuclear magnetic testing porosity phi_wi；

Lambda at maximum pressure gradient_maxRespectively displacing each core by adopting nitrogen until no water is produced at the outlet end of the core under the condition of normal temperature; then the nuclear magnetic resonance method is adopted to test the water phase distribution characteristics to determine the residual water phase porosity phi_wri；

Calculating movable fluid saturation value S of each rock core_di＝(Φ_wi-Φ_wri)/Φ_wiDrawing S_di—K_iRelationship curve, regression analysis determines equation S_di＝f(K_i)；

at the formation temperature T₀Original formation pressure P₀Maximum pressure gradient lambda_maxUnder the condition, the actual natural gas sample is adopted to displace the rock core to the state of the bound water, and the bound water saturation S of each rock core is determined_wri(ii) a And drawing S_wri—K_iRelationship curve, regression analysis determines equation S_wri＝f(K_i)；

② recording the volume V of the natural gas remained in the rock core_g0i(ii) a Then at the maximum pressure gradient lambda_maxUnder the condition, stratum water is adopted to displace the rock core until no gas is discharged, and produced gas V is collected_g1iCalculating the residual gas volume V of each core_gri＝V_g0i-V_g1iResidual gas saturation S_gri＝100V_gri/(0.25πD_i ²L_iΦ_i) (ii) a Drawing S_gri—K_iRelationship curve, regression analysis determines equation S_gri＝f(K_i)；

(ii) for depth H_iGas layer according to K_ci—H_iRelation curve S_gi—H_iDetermining K of corresponding depth by using relation curve_ci、S_giIs a reaction of K_ciRespectively substitute into equation S_di＝f(K_i)、S_gri＝f(K_i) Determining the corresponding depth H of the single well of the gas reservoir_iMovable fluid saturation S_cdiResidual gas saturation S_cgriObtaining the single well depth H of the gas reservoir_iMovable water saturation S_cdwi＝S_cdi-(S_gi-S_cgri)；

② for depth H_iIn accordance with K_ci—H_iDetermining K of corresponding depth by using relation curve_ciIs a reaction of K_ciSubstitution equation S_di＝f(K_i) Determining the corresponding depth H of the single well of the gas reservoir_iMovable fluid saturation S_cdiObtaining the corresponding depth H of the single well of the gas reservoir_iMovable water saturation S_cdwi＝S_cdi。

2. The method for determining the movable water saturation of the gas-water interbed gas reservoir under the high-temperature and high-pressure conditions, as claimed in claim 1, wherein the step (3) determines the experimental displacement pressure difference by the following process:

based on the dynamic production data of single well in gas reservoir, the gas and water yield corresponding to the maximum stable water-gas ratio is selected and the bottom hole flow pressure P is calculated_wf；

Based on original formation pressure P of gas reservoir₀Well control radius R_eWell bore radius R_wCalculating the maximum pressure gradient lambda of the gas reservoir during the single-well self-injection production_max＝(P₀-P_wf)/ln(R_e/R_w) I.e. the experimental displacement pressure difference.