CN107045671B - Method for predicting liquid accumulation risk of water producing gas well - Google Patents
Method for predicting liquid accumulation risk of water producing gas well Download PDFInfo
- Publication number
- CN107045671B CN107045671B CN201710174341.4A CN201710174341A CN107045671B CN 107045671 B CN107045671 B CN 107045671B CN 201710174341 A CN201710174341 A CN 201710174341A CN 107045671 B CN107045671 B CN 107045671B
- Authority
- CN
- China
- Prior art keywords
- gas
- water
- well
- pressure
- liquid
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired - Fee Related
Links
Images
Classifications
-
- G—PHYSICS
- G06—COMPUTING; CALCULATING OR COUNTING
- G06Q—INFORMATION AND COMMUNICATION TECHNOLOGY [ICT] SPECIALLY ADAPTED FOR ADMINISTRATIVE, COMMERCIAL, FINANCIAL, MANAGERIAL OR SUPERVISORY PURPOSES; SYSTEMS OR METHODS SPECIALLY ADAPTED FOR ADMINISTRATIVE, COMMERCIAL, FINANCIAL, MANAGERIAL OR SUPERVISORY PURPOSES, NOT OTHERWISE PROVIDED FOR
- G06Q10/00—Administration; Management
- G06Q10/06—Resources, workflows, human or project management; Enterprise or organisation planning; Enterprise or organisation modelling
- G06Q10/063—Operations research, analysis or management
- G06Q10/0635—Risk analysis of enterprise or organisation activities
-
- G—PHYSICS
- G06—COMPUTING; CALCULATING OR COUNTING
- G06Q—INFORMATION AND COMMUNICATION TECHNOLOGY [ICT] SPECIALLY ADAPTED FOR ADMINISTRATIVE, COMMERCIAL, FINANCIAL, MANAGERIAL OR SUPERVISORY PURPOSES; SYSTEMS OR METHODS SPECIALLY ADAPTED FOR ADMINISTRATIVE, COMMERCIAL, FINANCIAL, MANAGERIAL OR SUPERVISORY PURPOSES, NOT OTHERWISE PROVIDED FOR
- G06Q10/00—Administration; Management
- G06Q10/04—Forecasting or optimisation specially adapted for administrative or management purposes, e.g. linear programming or "cutting stock problem"
-
- G—PHYSICS
- G06—COMPUTING; CALCULATING OR COUNTING
- G06Q—INFORMATION AND COMMUNICATION TECHNOLOGY [ICT] SPECIALLY ADAPTED FOR ADMINISTRATIVE, COMMERCIAL, FINANCIAL, MANAGERIAL OR SUPERVISORY PURPOSES; SYSTEMS OR METHODS SPECIALLY ADAPTED FOR ADMINISTRATIVE, COMMERCIAL, FINANCIAL, MANAGERIAL OR SUPERVISORY PURPOSES, NOT OTHERWISE PROVIDED FOR
- G06Q50/00—Systems or methods specially adapted for specific business sectors, e.g. utilities or tourism
- G06Q50/02—Agriculture; Fishing; Mining
Abstract
The invention discloses a method for predicting the liquid loading risk of a water producing gas well, which provides a basis for a water prevention and control strategy for a liquid loading risk well in advance and lays a foundation for reasonable and effective water and gas reservoirs. The method comprises the following steps: step 1, establishing a productivity model of a water producing gas well, obtaining a productivity equation of the water producing gas well, and predicting productivity; step 2, comprehensively considering the changes of the formation pressure and the water-gas ratio, and determining the rule that the gas production of the gas reservoir changes along with the water-gas ratio and the rule that the gas production of the gas reservoir changes along with the formation pressure; calculating the critical liquid carrying flow of the gas well as a judgment boundary line of the accumulated liquid of the gas well by adopting a gas well liquid carrying critical flow calculation model; and 3, combining the change relation between the formation pressure and the water-gas ratio predicted by the gas reservoir numerical simulation to obtain the yield change relation comprehensively considering the formation pressure and the water-gas ratio change, and then combining the gas well accumulated liquid judgment boundary line to perform accumulated liquid risk well prediction analysis.
Description
Technical Field
The invention relates to the technical field of gas well development, in particular to a method for predicting the liquid accumulation risk of a water producing gas well.
Background
In domestic and foreign air houses, formation water exists to varying degrees during development. If the produced water cannot be timely discharged from a gas well shaft, the produced water can be accumulated at the bottom of the gas well to generate accumulated liquid.
After the gas well has the accumulated liquid, on one hand, the flow resistance of the gas is increased, the productivity of the gas well is reduced, and the gas well can be stopped in severe cases; on the other hand, the stratum can be seriously polluted due to long-time effusion soaking. Therefore, in the production process of the gas well, the position of the liquid level in the gas shaft is detected timely to know the liquid accumulation condition, which is an important content of dynamic monitoring of the gas field and can provide a basis for taking effective liquid drainage measures.
In order to facilitate production management, the height difference of accumulated liquid in a gas well shaft must be determined, and two methods are generally adopted at present: one method is to throw a pressure gauge into the wellbore to measure the pressure gradient. In the production process of the gas well, because the gas production rate is less than the minimum unloading flow rate of continuous liquid drainage, the liquid is retained to gradually increase the density of natural gas in a shaft, the pressure gradient of a gas column is gradually increased until the gas column is close to the pressure gradient of a pure liquid column, the gas well is pressed to be dead by the liquid column, the time from liquid accumulation to 'pressing to death' is determined by the volume fraction of liquid in a gas mixing column in the gas well, the higher the volume fraction of liquid in the gas mixing column is, the short pressing period is realized, and otherwise, the long period is realized. In order to ensure that the gas well is stably produced, a reasonable working system of the gas well must be determined, the minimum unloading flow of the gas well is reduced by optimizing a process pipe column, the gas well yield is higher than the minimum unloading flow, or the accumulated liquid is reduced by adding chemical agents to drain water and produce gas, so that the gas well is prevented from being crushed.
And the other method is to utilize an echo meter to test the position of the wellbore liquid accumulation of the gas well according to the sound wave. And (4) measuring by using an echometer to obtain the liquid level depth, and obtaining the height of the liquid column in the well due to the measured liquid level depth.
However, the implementation of the above two methods is expensive, which is not favorable for low-cost development of gas field. In order to preliminarily determine whether the gas well is accumulated with liquid and the liquid accumulation degree of the gas well, a new low-cost testing method needs to be developed.
Disclosure of Invention
The invention aims to overcome the defects of the prior art and provides a liquid accumulation risk prediction method for a water producing gas well.
The purpose of the invention is realized as follows:
a method for predicting liquid accumulation risk of a water producing gas well comprises the following steps:
and 3, combining the rule that the gas reservoir yield changes along with the water-gas ratio and the rule that the gas reservoir yield changes along with the formation pressure in the step 2 with the relationship between the formation pressure and the water-gas ratio, which is predicted by the gas reservoir numerical simulation, to obtain the yield change relationship which comprehensively considers the formation pressure and the water-gas ratio, and combining with a gas well accumulated liquid judgment boundary line to perform accumulated liquid risk well prediction analysis.
Further, in step 1, the following assumptions are made about the conditions of the gas reservoir:
horizontally homogenizing an infinite circular gas-water same-layer reservoir with equal thickness, and opening a well at the center;
secondly, gas and water are not mutually soluble, and the gas and water phases which do not play a chemical role flow simultaneously;
thirdly, the action of gravity and capillary force is not considered;
fourthly, the well is a perfect well, and fluid flows into the well in the radial direction;
rock and fluid are not compressible;
sixthly, considering the gas-water two-phase non-Darcy seepage and the starting pressure gradient, wherein the fluid viscosity is a constant;
the seepage process is isothermal.
Further, in step 1, the method for establishing the productivity model of the water producing gas well comprises the following steps:
the high-speed non-Darcy seepage of air water is described by a quadratic equation of Forcheimer
The velocity coefficients of the aqueous and gas phases were:
δ＝7.644×1010neglecting the influence of capillary forces, then pw＝pgP, the velocities of the aqueous phase and the gas phase are respectively
Considering the definition of the gas-water two-phase analog pressure function:
suppose the water-gas mass ratio a is mw/mgThen mass flow of gas mg＝qscρsc,mw＝aqscρscThe solution conditions are:
r＝rw，p＝pwf，r＝re，p＝pe
combining the formulae (1) to (4) to obtain
Combining the solution conditions, the above formula is calculated separately:
will be provided with
Substituting the formula to obtain:
because:
therefore, it is not only easy to use
The same principle is that:
thus:
considering the imperfection of the gas well, the skin coefficient is assumed to be S, mg＝qscρsc，mw＝aqscρscObtaining:
order:
thereby obtaining the capacity equation of the water producing gas well:
in the formula, A is a productivity equation Darcy coefficient; and B is the productivity equation non-Darcy coefficient.
Further, in step 1, the method for predicting the production performance is as follows:
capacity prediction solving step
1) Let p bewfValue, peIs the formation pressure;
2) calculating the average molecular weight according to the natural gas components;
Mg: relative molecular weight of natural gas;
yi: the mole fraction of natural gas component i; mi: the relative molecular mass of component i; n: number of components
3) Obtaining the density of the natural gas according to the natural gas state equation
Calculating rhog；
P: absolute pressure, MPa; r: molar gas constant, 0.008471; t: absolute temperature, K; m: gas mass, Kg; v: volume of gas, m3；
4) Calculating mu according to the composition data of natural gasgIs plotted against p, and p is obtainede、pwfμ at valueg；
5) Drawing the water yield according to the relative permeability curve
Curve (f) as a function of the water saturationw～sw)；
WGR production Water-to-gas ratio, m3/104m3；Rwgr: water-to-gas ratio of condensed water, m3/104m3；
6) According to
Calculating f under one gas-water ratiowFinding the f on the phase-permeation curvewCorresponding swValues, and thus s, on the relative permeability curvewCorresponding Krg、Krw；
7) Utilizing the steps 1) to 6) to calculate a Darcy yield coefficient A and Darcy yield coefficients B and psi (p)e)、Ψ(pwf)；
8) When p iswfAnd when the yield is 0, the yield of the gas well is the productivity of the gas well.
Further, in step 2, the method for determining the rule of the gas reservoir yield changing with the water-gas ratio and the rule of the gas reservoir yield changing with the formation pressure is as follows:
on the basis of the average physical property of the gas reservoir, calculating the capacity under different water-gas ratio production conditions by adopting the established capacity equation of the water-producing gas well, considering the influence of condensate water and bound water in production, setting the initial value of the water-gas ratio, selecting different water-gas ratios, obtaining the capacity under different lamination pressures and water-gas ratios, and obtaining a relation function between the unobstructed flow of the gas reservoir and the change of the water-gas ratio:
QAOF＝-A2lnWGR-B2
and the relation function of the gas reservoir unobstructed flow rate along with the change of the formation pressure:
QAOF＝A1lnP-B1。
further, in step 2, the method for establishing the gas well liquid-carrying critical flow calculation model comprises the following steps:
selecting a Liminn model to calculate the critical flow velocity and the critical flow, wherein in the critical flow state, the liquid drop is immobile relative to the shaft, the gravity of the liquid drop is equal to the buoyancy plus the resistance,
ρlgV＝ρggV+0.5ρgUc 2SCD
in the formula: v- -volume of ellipsoid, m3；
Vertical projected area of S-ellipsoid
m2；
CD-a drag coefficient, taking 1,
by combining the above formulas, the critical flow rate formula can be obtained:
Uc＝2.5[σ(ρl-ρg)/ρg 2]0.25
converting into a gas well flow formula under standard conditions:
Uc-gas well critical flow rate, m/s,
ρl、ρg-liquid and gas density, kg/m3, respectively;
qc-gas well critical flow, m 3/d;
σ - -gas-liquid surface tension, N/m;
a- -oil pipe cross-sectional area, m 2;
p- -pressure, MPa;
t- -temperature, K;
z- -gas compression factor, dimensionless.
Furthermore, in step 3, a judgment model of gas well accumulated liquid needs to be established, under a specific high-temperature high-pressure gas reservoir, the yield of the water-producing gas well is related to the water-gas ratio, the formation pressure, the wellhead pressure, the well bore diameter and the wellhead temperature of the gas well,
qsc＝f(wgr，PR，Pwh，rw，Twh)
the wellhead pressure, the well cylinder diameter and the wellhead temperature obtain the lowest pressure and the minimum wellhead temperature of a wellhead according to the actual condition of a gas reservoir, so that in the calculation model, the wellhead pressure, the well cylinder diameter and the wellhead temperature can be regarded as a specific value, and the model is simplified into:
qsc＝f(wgr，PR)
by establishing a water-producing gas well productivity equation, the single-factor decline change relations between the yield of the high-temperature and high-pressure gas reservoir and the water-gas ratio and between the yield and the pressure can be obtained, so that the relation relations between the yield of the gas well and the change relations between the water-gas ratio and the pressure can be obtained under the current yield condition, and the relations are respectively as follows:
qsc＝qsi×(1-(A2×ln(PR)+B2))
qsc＝qsi×(1-(A1×ln(wgr)+B1))
a method for predicting the relation between the water-gas ratio and the pressure by combining numerical simulation is adopted to obtain the dynamic relation between the pressure and the change of the water-gas ratio, and three conditions are mainly shown: (1) the bottom water does not reach the bottom of the well, only the condensate water is needed, so that the change of the yield along with the pressure is only needed to be considered; (2) after the gas well is exposed to water, the water-gas ratio slowly rises along with the pressure drop, and the common influence of the pressure and the water-gas ratio change needs to be considered for the yield change; (3) under the condition of low pressure, the water-gas ratio of the gas well quickly rises after water breakthrough, the influence of the water-gas ratio is greater than that of pressure, and the yield change needs to be considered, and the following relations are followed in three conditions:
PR＝f(wgr)
if the gas well is accumulated liquid, the critical liquid carrying flow of the gas well is combined, a Liminn model is selected as a reference,
if the critical liquid carrying flow is larger than or equal to the yield, accumulating liquid, otherwise, not accumulating liquid, and regarding the wellhead pressure, the wellbore diameter and the wellhead temperature as a specific value, as follows:
the accumulated liquid of the gas well is judged through the model, and the specific water breakthrough time of the gas well in a dynamic state can be obtained.
Due to the adoption of the technical scheme, the invention has the following beneficial effects:
at present, aiming at the problem of liquid accumulation of a water-producing gas well, the gas well is most concerned and is difficult to solve, and how to predict whether the liquid accumulation of the gas well with the water-producing gas well exists in advance is the key for effectively developing the gas well. The method starts with a productivity model of the water producing gas well, establishes a change relation between the yield of the water producing gas well and the pressure and the water-gas ratio, further combines a stratum pressure and water-gas relation which is predicted by numerical simulation of a gas reservoir, obtains a yield change relation which comprehensively considers the pressure and the water-gas ratio change, calculates the critical liquid carrying flow of the gas well as a connection limit by using a critical liquid carrying flow model which is widely applied to the gas well at present, and contrasts and predicts the time of gas well liquid accumulation risk. The method provides a basis for a water prevention and control strategy for the liquid accumulation risk well in advance, and lays a foundation for reasonably and effectively exploiting water and gas reservoirs.
Drawings
FIG. 1 is a graph of the gas reservoir phase-permeation in an example of the present invention;
FIG. 2 is a graph of the relationship between the unobstructed flow and the water-gas ratio of a gas reservoir at different formation pressures;
FIG. 3 is a graph showing the relationship between the unobstructed flow and the formation pressure for different gas-water ratios of a gas reservoir;
FIG. 4 is a schematic view of a flat ellipsoidal droplet;
FIG. 5 is a gas well liquid accumulation risk prediction idea diagram;
FIG. 6 is a graph showing the relationship between the gas pool yield and the water-gas ratio;
FIG. 7 is a graph of gas reservoir production as a function of pressure;
FIG. 8 is a predicted F1 well pressure versus water gas ratio variation;
Detailed Description
Examples
1. Establishment of water producing gas well productivity model
And establishing a productivity model of the water producing gas well on the basis of the seepage basic theory, and obtaining a productivity equation considering the water producing gas well through model derivation and solution. The following assumptions are made for establishing the capacity equation for the conditions of the gas reservoir:
horizontally homogenizing an infinite circular gas-water same-layer reservoir with equal thickness, and opening a well at the center;
secondly, gas and water are not mutually soluble, and the gas and water phases which do not play a chemical role flow simultaneously;
thirdly, the action of gravity and capillary force is not considered;
fourthly, the well is a perfect well, and fluid flows into the well in the radial direction;
rock and fluid are not compressible;
sixthly, considering the gas-water two-phase non-Darcy seepage and the starting pressure gradient, wherein the fluid viscosity is a constant;
the seepage process is isothermal.
Based on the above assumptions, the high-speed non-Darcy seepage of gas-water is described by the quadratic equation of Forcheimer
The velocity coefficients of the aqueous and gas phases were:
δ＝7.644×1010.
neglecting the influence of capillary forces, then pw＝pgP, the velocities of the aqueous phase and the gas phase are respectively
Considering the definition of the gas-water two-phase analog pressure function:
suppose the water-gas mass ratio alpha is mw/mgThen mass flow of gas mg＝qscρsc，mw＝aqscρscThe solution conditions are:
r＝rw，p＝pwf，r＝re，p＝pe
combining the formulae (1) to (4) to obtain
Combining the solution conditions, the above formula is calculated separately:
will be provided with
Substituting the formula to obtain:
because:
therefore, it is not only easy to use
The same principle is that:
thus:
if the imperfection of the gas well is considered, the skin coefficient is assumed to be S, mg＝qscρsc，mw＝aqscρscObtaining:
order:
thereby obtaining the capacity equation of the water producing gas well:
in the formula, A is a productivity equation Darcy coefficient; and B is the productivity equation non-Darcy coefficient.
Capacity prediction solving:
1) let p bewfValue, peIs the formation pressure;
2) calculating the average molecular weight according to the natural gas components;
Mg: relative molecular weight of natural gas;
yi: the mole fraction of natural gas component i; mi: the relative molecular mass of component i; n: number of components
3) Obtaining the density of the natural gas according to the natural gas state equation
Calculating rhog；
P: absolute pressure, MPa; r: molar gas constant, 0.008471; t: absolute temperature, K; m: gas mass, Kg; v: volume of gas, m3；
4) Calculating mu according to the composition data of natural gasgIs plotted against p, and p is obtainede、pwfμ at valueg；
5) Drawing the water yield according to the relative permeability curve
Curve (f) as a function of the water saturationw～sw)；
WGR: water-to-gas ratio of production, m3/104m3；Rwgr: water-to-gas ratio of condensed water, m3/104m3；
6) According to
Calculating f under one gas-water ratiowIn the phase of penetrationFinding f on the curvewCorresponding swValues, and thus s, on the relative permeability curvewCorresponding Krg、Krw；
7) Utilizing the steps 1) to 6) to calculate the Darcy coefficient A of the productivity and the non-Darcy coefficients B, psi (p)e)、ψ(pwf)；
8) When p iswfAnd when the yield is 0, the yield of the gas well is the productivity of the gas well.
2. Research on influence rule of gas reservoir water production on gas well productivity
The change of the gas well productivity is mainly influenced by two factors: first, a reduction in formation pressure; and secondly, the gas well productivity is reduced due to water production in the gas well production process. The result of these two factors together will have a large impact on the productivity of the gas well. Therefore, the research comprehensively considers the changes of the formation pressure and the water-gas ratio and determines the relation between the changes of the formation pressure and the water-gas ratio and the productivity.
Selecting a certain gas reservoir as an example, based on the average physical properties of the gas reservoir (the permeability is 1.9mD, the pressure of an original stratum is 52.5MPa, the gas phase relative density is 0.75, the control radius of the gas reservoir is 1500m, the thickness of a gas layer is 30m, the viscosity of gas is 0.02mpa.s, and the skin factor is 0), the phase permeability curve of the gas reservoir is shown in figure 1, the capacity under the production conditions of different water-gas ratios is calculated by adopting the established capacity equation of a water-producing gas well, meanwhile, the influence of condensate water and bound water in production is considered, and the initial value of the water-gas ratio is set as 0.5m3/104m3。
Therefore, different water to air ratios were chosen: 0.5, 2, 4, 6, 8, 10, 15m3/104m3The productivity equation coefficients of the gas reservoir are shown in table 1, and the productivity (no resistance flow) under different lamination pressures and water-gas ratios is shown in table 2 and fig. 2-3. And obtaining a relation function between the unobstructed flow of the gas reservoir and the change of the water-gas ratio:
QAOF＝-A2lnWGR-B2
and the relation function of the gas reservoir unobstructed flow rate along with the change of the formation pressure:
QAOF＝A1lnP-B1
from the above chart, it can be seen that:
(1) the change of the gas-water ratio has larger influence on the unobstructed flow of the gas reservoir, the unobstructed flow is reduced along with the increase of the gas-water ratio, and the gas-water ratio is from 0.5 to 15m3/104m3And the unimpeded flow rate is reduced by 72 percent.
(2) The unimpeded flow decreases logarithmically with decreasing formation pressure.
(3) And according to the established relationship between the formation pressure and the water-gas ratio and the productivity, a theoretical basis is provided for the calculation and prediction of the later productivity of the gas well.
TABLE 1 gas reservoir Productivity equation coefficient calculation Table
| Water-to-gas ratio | A | B | QAOF104m3/d | Magnitude of descent, decimal |
| 0.5 | 11.853 | 0.052 | 366.93 | 0 |
| 2 | 8.197 | 0.059 | 268.40 | 0.27 |
| 4 | 8.063 | 0.070 | 222.08 | 0.39 |
| 6 | 8.871 | 0.080 | 190.22 | 0.48 |
| 8 | 10.268 | 0.090 | 164.59 | 0.55 |
| 10 | 12.166 | 0.100 | 143.29 | 0.61 |
| 15 | 18.900 | 0.125 | 104.37 | 0.72 |
TABLE 2 gas reservoir non-resistance flow meter under different water-gas ratios and different formation pressures
3. Gas well liquid-carrying critical flow calculation model
When the liquid loading of the gas well starts, the lowest flow rate of gas in the shaft for enabling liquid drops to move upwards is called gas well liquid carrying critical flow rate, the corresponding flow rate is called gas well liquid carrying critical flow rate, when the actual flow rate of the gas in the shaft is smaller than the critical flow rate, the gas cannot completely discharge the liquid in the well from the well mouth, and the liquid loading can be generated at the well bottom. Therefore, in order to ensure that no liquid is accumulated in the gas well, the gas well production allocation must be larger than the liquid carrying critical flow, the liquid carrying critical flow of the gas well is accurately determined, and great guiding significance is provided for the gas well production allocation.
Plum blossom Min model
Li min considers that under the action of high-speed airflow, a pressure difference exists between the front and the back of the liquid drops carried by the high-speed airflow, and the liquid drops can become an ellipsoid under the action of the pressure difference, and the schematic diagram is shown in fig. 4.
The flat ellipsoid droplets have a larger effective area and are more easily carried into the wellhead, so that the required critical flow and critical flow rate are less than those calculated by the spherical model. The hoffman model calculated the critical flow rate and critical flow rate as 38% of the Turner model. In critical flow conditions, the droplets are immobile relative to the wellbore. The gravity of the droplets is equal to the buoyancy plus the resistance.
ρlgV＝ρggV+0.5ρgUc 2SCD
In the formula: v- -volume of ellipsoid, m3；
Vertical projected area of S-ellipsoid
m2；
CD-drag coefficient, taken as 1.
By combining the above formulas, the critical flow rate formula can be obtained:
Uc＝2.5[σ(ρl-ρg)/ρg 2]0.25
converting into a gas well flow formula under standard conditions:
Uc-gas well critical flow rate, m/s,
ρl、ρg-liquid and gas density, kg/m3, respectively;
qc-gas well critical flow, m3/d；
σ - -gas-liquid surface tension, N/m;
a- -oil pipe cross-sectional area, m2；
P- -pressure, MPa;
t- -temperature, K;
z- -gas compression factor, dimensionless.
4. Effusion risk well prediction analysis
According to the research of the influence rule of produced water on the gas well production energy, the change rule of the yield along with the formation pressure and the water-gas ratio can be obtained, and then whether the gas well accumulates liquid or not is judged by combining a judgment model of gas well accumulated liquid and the relation between the pressure and the water-gas ratio predicted by numerical simulation, and the specific idea is shown in figure 5.
The relation of the yield of a certain gas reservoir along with the change of the water-gas ratio and the pressure is obtained according to the influence rule of the water production on the gas well productivity as shown in figures 6 and 7, and the relation of the F1 well pressure and the change of the water-gas ratio predicted by numerical simulation is shown in figure 8.
And (3) establishing a model, wherein under a specific high-temperature high-pressure gas reservoir, the yield of the water-producing gas well is mainly related to the water-gas ratio, the formation pressure, the wellhead pressure, the well bore diameter and the wellhead temperature of the gas well.
qsc＝f(wgr，PR，Pwh，rw，Twh)
The wellhead pressure, the well cylinder diameter and the wellhead temperature obtain the lowest pressure and the minimum wellhead temperature of a wellhead according to the actual condition of a gas reservoir, so that in the calculation model, the wellhead pressure, the well cylinder diameter and the wellhead temperature can be regarded as a specific value, and the model is simplified into:
qsc＝f(wgr，PR)
by establishing a water-producing gas well productivity equation, the single-factor decline change relations between the yield of the high-temperature and high-pressure gas reservoir and the water-gas ratio and between the yield and the pressure can be obtained, so that the relation relations between the yield of the gas well and the change relations between the water-gas ratio and the pressure can be obtained under the current yield condition, and the relations are respectively as follows:
qsc＝qsi×(1-(A2×ln(PR)+B2))
qsc＝qsi×(1-(A1×ln(wgr)+B1))
because the change relation between the water-gas ratio and the pressure belongs to a dynamic relation, the influence factors are more, and the relation between the water-gas ratio and the pressure change is difficult to be really determined mainly by the factors of whether the formation water reaches the bottom of the well, the content of the condensed water and the like. Therefore, the method for predicting the relation between the water-gas ratio and the pressure by combining numerical simulation is adopted to obtain the dynamic relation between the pressure and the change of the water-gas ratio, and three conditions are mainly shown: (1) the bottom water does not reach the bottom of the well, only the condensate water is needed, so that the change of the yield along with the pressure is only needed to be considered; (2) after the gas well is exposed to water, the water-gas ratio slowly rises along with the pressure drop, and the common influence of the pressure and the water-gas ratio change needs to be considered for the yield change; (3) under the condition of low pressure, the water-gas ratio of the gas well after water breakthrough quickly rises, the influence of the water-gas ratio is greater than that of the pressure, and both yield changes need to be considered. In all three cases, a relationship can be obtained:
PR＝f(wgr)
and if the gas well is accumulated with liquid, the critical liquid carrying flow of the gas well is combined, a commonly used critical liquid carrying flow model in China is selected, and the Liminn model is used as a reference.
And accumulating liquid if the critical liquid carrying flow is larger than or equal to the yield, and not accumulating liquid if the critical liquid carrying flow is not larger than the yield. Therefore, in the modeling assumption model, the wellhead pressure, the wellbore diameter and the wellhead temperature can be regarded as a specific value, as follows:
the accumulated liquid of the gas well is judged through the model, the specific water breakthrough time of the gas well in a dynamic state can be obtained, theoretical data is provided for advanced water prevention and control of the gas well, formulation of water control and water prevention measures is guided, and a foundation is laid for finally improving development of a water-bearing gas reservoir.
Production is carried out according to the current yield of an F1 well (33.23 multiplied by 10) by carrying out predictive analysis on a certain gas reservoir liquid accumulation risk well F1 well4m3/d) predicted F1 well production as a function of pressure and water-gas ratio is shown in Table 3. Assuming that the minimum wellhead pressure of a gas well is 2MPa, the wellhead temperature is 20 ℃, the size of an oil pipe is 3-1/2 ″, and the critical liquid carrying flow is 2.42 multiplied by 104m3And d. From table 3, it can be seen that: when the F1 well liquid is accumulated, the formation pressure is reduced to 20-25MPa, and the water-gas ratio is 35m3/104m3。
TABLE 3 predicted well production as a function of pressure and water-gas ratio for F1 well
Finally, it is noted that the above-mentioned preferred embodiments illustrate rather than limit the invention, and that, although the invention has been described in detail with reference to the above-mentioned preferred embodiments, it will be understood by those skilled in the art that various changes in form and detail may be made therein without departing from the scope of the invention as defined by the appended claims.
Claims (5)
1. The method for predicting the risk of liquid accumulation of the water producing gas well is characterized by comprising the following steps of:
step 1, establishing a productivity model of the water producing gas well on the basis of a seepage theory, obtaining a productivity equation of the water producing gas well through model derivation and solution, and then predicting the productivity according to the productivity equation;
step 2, comprehensively considering the changes of the formation pressure and the water-gas ratio, and determining the rule that the gas reservoir yield changes along with the water-gas ratio and the rule that the gas reservoir yield changes along with the formation pressure; calculating the critical liquid carrying flow of the gas well as a judgment boundary line of the accumulated liquid of the gas well by adopting a gas well liquid carrying critical flow calculation model;
in the step 2, the method for determining the rule that the gas reservoir yield changes with the water-gas ratio and the rule that the gas reservoir yield changes with the formation pressure comprises the following steps:
on the basis of the average physical property of the gas reservoir, calculating the capacity under different water-gas ratio production conditions by adopting the established capacity equation of the water-producing gas well, considering the influence of condensate water and bound water in production, setting the initial value of the water-gas ratio, selecting different water-gas ratios, obtaining the capacity under different lamination pressures and water-gas ratios, and obtaining a relation function between the unobstructed flow of the gas reservoir and the change of the water-gas ratio:
QAOF＝-A2lnwgr-B2，QAOFfor unimpeded flow, 104m3D; a2, B2: are all coefficients; wgr is water-gas ratio, m3/104m3，
And the relation function of the gas reservoir unobstructed flow rate along with the change of the formation pressure:
QAOF＝A1lnP-B1，QAOFfor unimpeded flow, 104m3D; a1, B1: are all coefficients;
step 3, combining the rule that the gas reservoir yield changes along with the water-gas ratio and the rule that the gas reservoir yield changes along with the formation pressure in the step 2 with the relationship between the formation pressure and the water-gas ratio, which is predicted by numerical simulation of the gas reservoir, to obtain the yield change relationship which comprehensively considers the formation pressure and the water-gas ratio, and combining with a gas well accumulated liquid judgment boundary line to perform accumulated liquid risk prediction analysis;
in the step 3, a judgment model of gas well accumulated liquid is also required to be established, under a specific high-temperature high-pressure gas reservoir, the yield of the water-producing gas well is related to the water-gas ratio, the formation pressure, the wellhead pressure, the well bore diameter and the wellhead temperature of the gas well,
qsc＝f(wgr，PR，Pwh，rw，Twh) Wgr is water-gas ratio, m3/104m3；pRIs the formation pressure, MPa; p is a radical ofwhThe wellhead pressure is MPa; r iswIs the wellbore radius, m; t iswhWell head temperature, deg.C;
the wellhead pressure, the well cylinder diameter and the wellhead temperature obtain the lowest pressure and the minimum wellhead temperature of a wellhead according to the actual condition of a gas reservoir, so that in the calculation model, the wellhead pressure, the well cylinder diameter and the wellhead temperature can be regarded as a specific value, and the model is simplified into:
qsc＝f(wgr，PR) Wgr is water-gas ratio, m3/104m3；pRIs the formation pressure;
by establishing a water-producing gas well productivity equation, the single-factor decline change relations between the yield of the high-temperature and high-pressure gas reservoir and the water-gas ratio and between the yield and the pressure can be obtained, so that the relation relations between the yield of the gas well and the change relations between the water-gas ratio and the pressure can be obtained under the current yield condition, and the relations are respectively as follows:
qsc＝qsi×(1-(A2×ln(PR)+B2))
qsc＝qsi×(1-(A1×ln(wgr)+B1))，qscis a flow rate at a certain time, m3D; a1, B1, A2 and B2 are all coefficients;
a method for predicting the relation between the water-gas ratio and the pressure by combining numerical simulation is adopted to obtain the dynamic relation between the pressure and the change of the water-gas ratio, and three conditions are mainly shown: (1) the bottom water does not reach the bottom of the well, only the condensate water is needed, so that the change of the yield along with the pressure is only needed to be considered; (2) after the gas well is exposed to water, the water-gas ratio slowly rises along with the pressure drop, and the common influence of the pressure and the water-gas ratio change needs to be considered for the yield change; (3) under the condition of low pressure, the water-gas ratio of the gas well quickly rises after water breakthrough, the influence of the water-gas ratio is greater than that of pressure, and the yield change needs to be considered, and the following relations are followed in three conditions:
PR(wgr) ═ f, wgr for water-gas ratio, m3/104m3；pRIs the formation pressure;
if the gas well is accumulated liquid, the critical liquid carrying flow of the gas well is combined, a Liminn model is selected as a reference,
if the critical liquid carrying flow is larger than or equal to the yield, accumulating liquid, otherwise, not accumulating liquid, and regarding the wellhead pressure, the wellbore diameter and the wellhead temperature as a specific value, as follows:
the accumulated liquid of the gas well is judged through the model, and the specific water breakthrough time of the gas well in a dynamic state can be obtained.
2. The method for predicting the liquid loading risk of the water producing gas well as the liquid:
horizontally homogenizing an infinite circular gas-water same-layer reservoir with equal thickness, and opening a well at the center;
secondly, gas and water are not mutually soluble, and the gas and water phases which do not play a chemical role flow simultaneously;
thirdly, the action of gravity and capillary force is not considered;
fourthly, the well is a perfect well, and fluid flows into the well in the radial direction;
rock and fluid are not compressible;
sixthly, considering the gas-water two-phase non-Darcy seepage and the starting pressure gradient, wherein the fluid viscosity is a constant;
the seepage process is isothermal.
3. The method for predicting the liquid accumulation risk of the water producing gas well as the method for establishing the productivity model of the water producing gas well in the step 1 are as follows:
the high-speed non-Darcy seepage of air water is described by a quadratic equation of Forcheimer
The velocity coefficients of the aqueous and gas phases were:
δ＝7.644×1010，
in the formula pwWater phase pressure, MPa; p is a radical ofgGas phase pressure, MPa; kwAs water phase permeability, KgIn order to be the gas-phase permeability,
neglecting the influence of capillary forces, then pw＝pgP, the velocities of the aqueous phase and the gas phase are respectively
Considering the definition of the gas-water two-phase analog pressure function:
p is pressure, assuming water-gas mass ratio α ═ mw/mgMass m of gasg＝qscρscMass of water mw＝aqscρsc，
And (3) determining the solution conditions:
r＝rw，p＝pwf，r＝re，p＝pe (4)
combining the formulae (1) to (4) to obtain
Combining the solution conditions, the above formula is calculated separately:
will be provided with
Substituting the formula to obtain:
because:
therefore, it is not only easy to use
The same principle is that:
thus:
considering the imperfection of the gas well, the skin coefficient is assumed to be S, mg＝qscρsc，mw＝aqscρscObtaining:
order:
thereby obtaining the capacity equation of the water producing gas well:
in the formula, pe: formation pressure in MPa; p is a radical ofwf: bottom hole flow pressure in MPa; psi (p)e): pressure peThe gas-water two-phase simulated pressure is in unit of MPa; psi (p)wf): pressure pwfThe gas-water two-phase simulated pressure is in unit of MPa; a: the productivity equation darcy coefficient; q. q.ssc: gas volume flow in a gas well at a temperature of 0 ℃ and a pressure of 1 standard atmosphere in m3S; b: the productivity equation is not Darcy's coefficient; r ise: gas reservoir control radius, unit m; r isw: wellbore radius, in m; krw、KrgRelative permeability of water phase and gas phase respectively without dimension; rhow、ρgDensity of water and gas, respectively, in kg/m3；μw、μgRespectively the viscosity of water phase and gas phase, the unit of mPa & s, alpha is the mass ratio of water to gas, and the unit of kg/kg; h is the oil layer thickness in m; delta is a constant of 7.644 x 1010(ii) a K is the gas reservoir permeability in 10 units-3μm2(ii) a r is the gas seepage radius in m, rw≤r≤re(ii) a Epidermal coefficient of S, dimensionless, qwIs the water flow rate, qgIs the gas flow rate.
4. The method for predicting the liquid loading risk of the water producing gas well as the production capacity in the step 1 is characterized by comprising the following steps of:
capacity prediction solving step
1) Let p bewfA value;
2) calculating the average molecular weight according to the natural gas components;
Mg: relative molecular weight of natural gas;
yi: the mole fraction of natural gas component i; mi: the relative molecular mass of component i; n: number of components
3) Obtaining the density of the natural gas according to the natural gas state equation
Calculating rhog；
P: absolute pressure, MPa; r: molar gas constant, 0.008471; t: absolute temperature, K; m: gas mass, Kg; v: volume of gas, m3；
4) Calculating mu according to the composition data of natural gasgIs plotted against p, and p is obtainede、pwfμ at valueg；
μgViscosity in the gas phase, pgIs the gas phase pressure;
5) drawing the water yield according to the relative permeability curve
Curve f dependence of water saturationw～sw，fwIs the water content, swThe water saturation; wgr is water-gas ratio, m3/104m3；Rwgr: water-to-gas ratio of condensed water, m3/104m3；
6) According to
Calculating f under one gas-water ratiowFinding f on the relative permeability curvewCorresponding swValues, and thus s, on the relative permeability curvewCorresponding Krg、Krw；
7) Utilizing the steps 1) to 6) to calculate the Darcy coefficient A of the productivity and the non-Darcy coefficients B, psi (p)e)、ψ(pwf)；
8) When p iswfAnd when the yield is 0, the yield of the gas well is the productivity of the gas well.
5. The method for predicting the liquid accumulation risk of the water producing gas well as the liquid production well, as set forth in claim 1, is characterized in that in the step 2, the method for adopting the gas well liquid carrying critical flow calculation model is as follows:
selecting a Liminn model to calculate the critical flow velocity and the critical flow, wherein in the critical flow state, the liquid drop is immobile relative to the shaft, the gravity of the liquid drop is equal to the buoyancy plus the resistance,
ρlgV＝ρggV+0.5ρgUc 2SCD
in the formula: v- -volume of ellipsoid, m3；
Vertical projected area of S-ellipsoid
g- -coefficient of gravity;
CD-a drag coefficient, taking 1,
by combining the above formulas, the critical flow rate formula can be obtained:
Uc＝2.5[σ(ρl-ρg)/ρg 2]0.25
converting into a gas well flow formula under standard conditions:
Uc-gas well critical flow rate, m/s,
ρl、ρg- -are respectively the liquid and gas densities, kg/m3；
qc-gas well critical flow, m3/d；
σ - -gas-liquid surface tension, N/m;
Ag- -oil pipe cross-sectional area, m2；
P- -pressure, MPa;
t- -temperature, K;
z- -gas compression factor, dimensionless.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN201710174341.4A CN107045671B (en) | 2017-03-22 | 2017-03-22 | Method for predicting liquid accumulation risk of water producing gas well |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CN201710174341.4A CN107045671B (en) | 2017-03-22 | 2017-03-22 | Method for predicting liquid accumulation risk of water producing gas well |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CN107045671A CN107045671A (en) | 2017-08-15 |
| CN107045671B true CN107045671B (en) | 2021-01-12 |
Family
ID=59544708
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CN201710174341.4A Expired - Fee Related CN107045671B (en) | 2017-03-22 | 2017-03-22 | Method for predicting liquid accumulation risk of water producing gas well |
Country Status (1)
| Country | Link |
|---|---|
| CN (1) | CN107045671B (en) |
Families Citing this family (20)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN108595875A (en) * | 2018-05-08 | 2018-09-28 | 中国石油天然气集团有限公司 | A kind of method, apparatus and system of determining side water gas condensate reservoir water breakthrough time |
| CN108756817B (en) * | 2018-05-14 | 2020-07-07 | 中国石油大学(华东) | Method for judging scaling risk of shaft of water-producing gas well and determining injection time of antiscaling agent |
| CN108627417A (en) * | 2018-05-23 | 2018-10-09 | 中国海洋石油集团有限公司 | The test of condensation water content and computational methods under the conditions of a kind of high temperature and pressure gas reservoir |
| CN109033518A (en) * | 2018-06-22 | 2018-12-18 | 中国石油天然气集团有限公司 | The water breakthrough time prediction technique and device of bottom water gas condensate reservoir |
| CN109339775A (en) * | 2018-10-25 | 2019-02-15 | 西南石油大学 | A kind of method of determining water drive gas reservoir Living space |
| CN109356566B (en) * | 2018-12-18 | 2022-02-08 | 中海石油(中国)有限公司 | Method for predicting blowout stop time of self-blowing production well in high water-containing stage in deepwater volatile oil field |
| CN110005399B (en) * | 2019-04-16 | 2022-05-31 | 重庆科技学院 | Experimental method for measuring volume of retrograde condensate oil containing excessive water condensate gas |
| CN110163442A (en) * | 2019-05-27 | 2019-08-23 | 华北理工大学 | A kind of gas well plug-ging prediction technique based on integrated study |
| CN110735633B (en) * | 2019-09-11 | 2023-04-07 | 中国石油天然气股份有限公司 | Low-permeability carbonate gas reservoir gas well shaft effusion early-stage identification method |
| CN112627800B (en) * | 2019-09-24 | 2024-03-29 | 中国石油化工股份有限公司 | Method and system for detecting daily gas production measurement deviation of water gas well |
| CN111400978B (en) * | 2020-06-08 | 2020-09-29 | 西南石油大学 | Critical liquid carrying flow calculation method considering liquid drop deformation and multi-parameter influence |
| CN111832232A (en) * | 2020-07-20 | 2020-10-27 | 森诺科技有限公司 | Technical method for diagnosing and identifying accumulated liquid in pipeline |
| CN112065360B (en) * | 2020-09-10 | 2023-11-14 | 中国石油天然气股份有限公司 | Intermittent production system optimization method for low-permeability water-producing gas reservoir gas well |
| CN112036097B (en) * | 2020-09-11 | 2022-05-31 | 重庆科技学院 | Capacity calculation method for water-lock gas well |
| CN114764966A (en) * | 2021-01-14 | 2022-07-19 | 新智数字科技有限公司 | Oil-gas well trend early warning method and device based on joint learning |
| CN113468826A (en) * | 2021-06-17 | 2021-10-01 | 西南石油大学 | Shale gas horizontal well critical liquid carrying flow prediction method based on real liquid film distribution |
| CN113236203B (en) * | 2021-07-09 | 2021-09-21 | 西南石油大学 | Water invasion dynamic production allocation method for carbonate rock with water-gas reservoir |
| CN114893154B (en) * | 2022-05-24 | 2023-03-31 | 西安石油大学 | Dynamic optimization method for bottom-edge water gas reservoir horizontal well production allocation |
| CN114991724B (en) * | 2022-06-17 | 2024-01-02 | 中海石油(中国)有限公司 | Dense gas well productivity prediction method and system |
| CN116752948B (en) * | 2023-06-16 | 2023-12-29 | 重庆科技学院 | Water invasion dynamic analysis method for strong water flooding gas reservoir |
Citations (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN103590812A (en) * | 2013-10-21 | 2014-02-19 | 中国石油天然气股份有限公司 | Calculating method, calculating device and determining method of gas well effusion volume |
| CN104612659A (en) * | 2015-02-10 | 2015-05-13 | 中国地质大学（武汉） | Method for determining critical liquid carrying amount of gas well with low gas liquid ratio |
| RU2571321C1 (en) * | 2014-08-21 | 2015-12-20 | Федеральное государственное бюджетное образовательное учреждение высшего профессионального образования "Оренбургский государственный университет" | Method of determination of dynamic level in annulus of water cut gas well |
Family Cites Families (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| EP2599032A4 (en) * | 2010-07-29 | 2018-01-17 | Exxonmobil Upstream Research Company | Method and system for reservoir modeling |
| CN104504457B (en) * | 2014-12-04 | 2018-08-10 | 中国石油大港油田勘探开发研究院 | Water-producing gas well PRODUCTION FORECASTING METHODS |
-
2017
- 2017-03-22 CN CN201710174341.4A patent/CN107045671B/en not_active Expired - Fee Related
Patent Citations (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN103590812A (en) * | 2013-10-21 | 2014-02-19 | 中国石油天然气股份有限公司 | Calculating method, calculating device and determining method of gas well effusion volume |
| RU2571321C1 (en) * | 2014-08-21 | 2015-12-20 | Федеральное государственное бюджетное образовательное учреждение высшего профессионального образования "Оренбургский государственный университет" | Method of determination of dynamic level in annulus of water cut gas well |
| CN104612659A (en) * | 2015-02-10 | 2015-05-13 | 中国地质大学（武汉） | Method for determining critical liquid carrying amount of gas well with low gas liquid ratio |
Non-Patent Citations (1)
| Title |
|---|
| Density-Based Decline Performance Analysis of Natural Gas Reservoirs Using a Universal Type Curve;Ayala, LF;《JOURNAL OF ENERGY RESOURCES TECHNOLOGY-TRANSACTIONS OF THE ASME》;20131231;第135卷(第4期);全文 * |
Also Published As
| Publication number | Publication date |
|---|---|
| CN107045671A (en) | 2017-08-15 |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| CN107045671B (en) | Method for predicting liquid accumulation risk of water producing gas well | |
| CN107301306B (en) | Dynamic non-resistance flow prediction method for tight sandstone gas reservoir fractured horizontal well | |
| CN107563899B (en) | Oil-gas well productivity prediction method and device | |
| CN110598167B (en) | Processing method of oil-water relative permeability experimental data of low-permeability reservoir | |
| CN111353205B (en) | Method for calculating formation pressure and dynamic productivity of water-producing gas well of tight gas reservoir | |
| CN106761733A (en) | A kind of horizontal wells in heavy oil reservoir steam soak initial productivity Forecasting Methodology | |
| CN109184644B (en) | Early-stage polymer injection effect evaluation method considering non-Newtonian property and seepage additional resistance of polymer | |
| CN105160071B (en) | A kind of suitable gas-liquid is the same as the method for discrimination of production horizontal well underground working | |
| CN107526891B (en) | Polymer flooding large-pore oil reservoir well testing analysis method | |
| CN107462936B (en) | Utilize the method for pressure monitoring Data Inversion low permeability reservoir non-Darcy percolation law | |
| Wang et al. | Prediction of the critical gas velocity of liquid unloading in a horizontal gas well | |
| CN104213906A (en) | Drilling shaft pressure calibrating method | |
| CN102288732A (en) | Method for rapidly evaluating ultralow permeability gas reservoir water lock | |
| CN105672997A (en) | Monitoring method for formation leakage of drilling fluid | |
| CN105716998B (en) | A kind of computational methods of distress in concrete chemical grouting grout spreading range | |
| CN108133086A (en) | Water Fractured Gas Wells fracture half-length's inversion method is produced in a kind of stress sensitive reservoir | |
| Czarnota et al. | Semianalytical horizontal well length optimization under pseudosteady-state conditions | |
| CN106503284B (en) | Shale gas horizontal well horizontal segment gas-bearing formation produces gas evaluation method | |
| CN112257349B (en) | Method for judging whether tight sandstone movable water-gas reservoir gas well has development value | |
| CN108756873B (en) | Determination method for reducing fluid seepage resistance based on nanotechnology | |
| CN109931038B (en) | Design method for injecting nitrogen into fracture-cavity oil reservoir | |
| CN107356512A (en) | Temperature becomes Under Concrete hydrostatic osmotic pressure test device | |
| CN114169204A (en) | Sand prevention opportunity determination method for offshore oil and gas field development and production | |
| Moradi | Cost-effective and safe oil production from existing and near-future oil fields | |
| CN114510847A (en) | Low-permeability reservoir contaminated well productivity calculation method, electronic device and storage medium |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| PB01 | Publication | ||
| PB01 | Publication | ||
| SE01 | Entry into force of request for substantive examination | ||
| SE01 | Entry into force of request for substantive examination | ||
| GR01 | Patent grant | ||
| GR01 | Patent grant | ||
| CF01 | Termination of patent right due to non-payment of annual fee | ||
| CF01 | Termination of patent right due to non-payment of annual fee |
Granted publication date: 20210112 |