SPE 155356 Prediction of Liquid Loading in Gas wells Yashaswini Devi Nallaparaju, Pandit Deendayal Petroleum University, India
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, USA, 8-10 October 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Abstract It is a well known fact that the hydrocarbon demand increases by the day. Now, in order to meet this ever increasing demand it is essential for us to produce at the required rate over a specified period of time. The most prominent problem affecting production in gas wells is Liquid Loading. It is basically the inability of gas to remove liquids being produced in the wellbore. This occurs when the velocity of gas being produced falls down a particular value known as “critical velocity”. The produced liquid will accumulate in the well creating a static column of liquid, therefore creating a back pressure against formation pressure and reducing production until the well ceases production. This problem should be predicted early and dealt properly to prevent economic losses and produce efficiently. Some notable correlations that exist for predicting the critical rate required for liquid unloading in gas wells include Turner et al., (1969), Coleman et al., (1991), Nosseir et al. (1997) and Li et al. (2001). However, these correlations offer divergent views on the critical rates needed for liquid unloading and for some correlations in particular, at low wellhead pressures below 500 psia. In this paper, we compared the critical velocity graphs obtained from different models for four different wells and concluded that Turner model gives the most conservative value of critical velocity of all the methods for any value of pressure. The turner model is most widely used and accepted in oil and gas industries and moreover all the theories are based on the Turners model. Using Nodal Analysis we integrated IPR and TPR curves to find out the operating point of the wells. Then by intersecting turner model curve with the future IPR curves we predicted the year in which the problem of liquid loading may occur. This will help us in taking necessary precautions beforehand. After liquid loading has occurred, there are different deliquification techniques to deload the well. They have been presented in this paper, which help in reinitiating gas production. Liquid loading concept: The gas which is the dominant phase initially in the well will carry the produced liquid present in the reservoir to the surface as long as the gas velocity is high enough to let it do so. A high gas velocity will cause mist flow in the well in which liquid is dispersed in the gas. This also means the liquid in the well will be low relative to the gas and will be carried out without accumulating downhole. This will result in a low pressure gradient in the well since there is more gas than liquid. As the gas velocity drops with time, the liquid carried out along with gas will start to drop and accumulate in the well, causing the pressure gradient to increase. Since high pressure gradient means a high hydrostatic pressure in the well, the reservoir pressure will encounter a much larger pressure against itself downhole. This will cause a decline in the gas rate and cripple gas production. Lower the gas rate falls, more liquid will be accumulated and this holdup will become a cycle, causing the well cease producing eventually. Source of liquids: Even if the produced amount of liquids is very small almost every gas well produces liquids along with gas. These liquids may be free water, water condensate and/or hydrocarbon condensate. Condensate may be produced as liquid, or vapour depending on the reservoir and wellbore pressure. Produced liquids along with gas may have several sources depending on the conditions and type of the reservoir from which gas is produced:
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SPE 155356
•
Water Coning
•
Aquifer Water
•
Condensed Water
•
Condensed Hydrocarbons
•
Water Production from another Zone
•
Free Formation Water
Problems caused by liquid loading: Liquid loading can lead to erratic, slugging flow and decreased production. If the gas rate is high enough to remove most or all of the liquids, the flowing tubing pressure at the formation face and production rate will reach a stable equilibrium. The well will produce at a rate that can be predicted by the reservoir INFLOW PRODUCTION RELATIONSHIP (IPR) curve. When liquids accumulate, the well simply produces at a lower rate than expected through IPR. The pressure gradient in the tubing becomes large due to the liquid accumulation, resulting in increased pressure on the formation. As the back-pressure on the formation increases, the rate of gas production from the reservoir decreases and may drop below the critical rate required to remove the liquid. More liquids will accumulate in the wellbore and the increased bottomhole pressure will further reduce gas production and may even kill the well. Late in the life of a well, liquid may stand over the sand face with the gas bubbling through the liquid to the surface. During this phase the gas is producing at a low but steady rate with little or no liquids coming to the surface. If this behaviour is observed with no knowledge of past well history, one might assume that the well is not liquid loaded but only a low producer. Critical velocity: The critical velocity is defined as the maximum terminal velocity of a freely falling body (liquid drop) in a fluid medium (gas) under the influence of gravity alone. The critical velocity is based on a stagnation terminal velocity, which must be exceeded by some finite quantity to guarantee removal or upward movement of the largest liquid droplet. This terminal velocity is therefore a function of the size, shape and density of the particle and of the density and viscosity of the fluid medium. Prediction models for critical velocity: Turner model: Turner, Hubbard, and Dukler, after studying the earlier observations, proposed two physical models for the removal of gas well liquids. The models are based on: (1) the liquid film movement along the walls of the pipe and (2) the liquid droplets entrained in the high velocity gas core. They used field data to validate each of the models and concluded that the entrained droplet model could better predict the minimum rate required to lift liquids from gas wells. This is because the film model does not provide a clear definition between adequate and inadequate rates as satisfied by the entrained droplet model when it is compared with field data. A flow rate is determined adequate if the observed rate is higher than what the model predicts and inadequate if otherwise. Again, the film model indicates that the minimum lift velocity depends upon the gas-liquid ratio while no such dependence exists in the range of liquid production associated with field data from most of the gas wells (1 - 130 bbl/MMSCF) The theoretical equation for critical velocity to lift a liquid drop, .
/
/
/
Turner’s expressions (with 20% upward adjustment to fit data) in field units are 5.304
, ,
/
. √ .
4.03
. √ .
And /
SPE 155356
3
Pwf (bar)
Turner Model 250 200 150 100 50 0 0
5 Critical Velocity (ft/s)
10
Coleman model: Using the Turner model but validating with field data of lower reservoir and wellhead flowing pressures all below approximately 500 psia, Coleman et al. were convinced that a better prediction could be achieved without a 20% upward adjustment to fit field data with the following expressions: Field units) Field units)
Coleman Model
2500
Pwf (psi)
2000 1500 1000 500 0 0
5
10
15
Critical Velocity (ft/s)
Critical Velocity Model Based on Flat-Shaped Droplet LI’s Model : Li, Li, Sun in there research posited that turner and Coleman’s models did not consider deformation of the free falling liquid droplet in a gas medium. They contended that as a liquid droplet is entrained in a high-velocity gas stream, a pressure difference exists between the fore and aft portions of the droplet. The droplet is deformed under the applied force and its shape changes from spherical to a convex bean with unequal sides (flat) as shown in Figure. Spherical liquid droplets have a smaller efficient area and need a higher terminal velocity and critical rate to lift them to the surface. However, flat-shaped droplets have a more efficient area and are
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SPE 155356
easier to be carried to the wellhead. The full derivation of Li’s critical rate model is summarized below: V
2.5
ρ
σ
ρ
SI Units
ρ 2.5
Q
10
PV A
SI Units
T Z
LI'S Model
250 Pwf (bar)
200 150 100 50 0 0
1
2
3
4
Critical Velocity (ft/s)
Critical Velocity Model Based on Flow Conditions Nossier Model: Nosseir et al. focused their studies on the impact of flow regimes and changes in flow conditions on gas well loading. They followed the path of turner droplet model but they made a difference from turner model by considering the impact of flow regimes on the drag coefficient (C). Turner model takes the value of C to be .44 under laminar, transition and turbulent flow d
regimes, which in turn determine the expression of the drag force and hence critical velocity equations. On comparing nossier observed that Turner model values were not matching with the real data for highly turbulent flow regime. Dealing with this deviation nossier found out the reason to be the change in value of C for this regime from .44 to 0.2. d
5
6
Nossier derived the critical flow equations by assuming C value of 0.44 for Reynolds number (Re) 2×10 to 10 and for Re d
6
value greater than 10 he took the C value to be 0.2. Representation of the critical velocity equations by Nosseir’s model is summarized as:
d
V
. σ .
ρ
μ .
ρ .
ρ .
(Field units)
Again, the critical velocity equation for highly turbulent flow regime is given as: V
. σ .
ρ ρ .
ρ .
(Field units)
SPE 155356
5
Nossier Model
250
Pwf (bar)
200 150 100 50 Critical velocity (ft/s) 0 0
2
4
6
8
10
CRITICAL VELOCITY VS Pwf
2500
Pwf (psi)
2000 1500
Turner Colmen
1000
Li's Nossier
500 0 0
5
10
15
Critical Velocity (ft/s)
Nodal Analysis INTRODUCTION: Since critical gas rate equations only give a simple idea for the minimum rates, Liquid loading can be determined by nodal analysis; nodal analysis will be more detailed since it considers the complete flow path of fluids from Reservoir to wellhead. Nodal analysis divides the system into two subsystems at a certain location called nodal point. One of these subsystems considers inflow from reservoir to the nodal point selected (IPR), IPR shows the relationship between flowing bottom hole pressure (Pwf) to flow from the well (Qg) while the other subsystem considers outflow from the nodal point to the surface (TPR), TPR shows the relationship between the pressure drop in the tubing string and surface pressure value. Each subsystem gives a different curve plotted on the same pressure‐rate graph. These curves are called the inflow curve and the outflow curve, respectively. The point where these two curves intersect denotes the optimum operating point where pressure and flow rate values are equal for both of the curves.
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IPR & TPR
3,500 3,000
Pwf (psi)
2,500 2,000 IPR @ 3281
1,500 1,000 500 0 0
50
100
150
Qg (MMSCFD)
When the critical flow rate by turner model curve is also plotted on the same graph it gives us a better understanding of when liquid loading will be occurring and it gives us an insight of whether we are operating in a safe condition or not. For example by looking into the figure we can justify that for a given initial static reservoir pressure of 3281 psi and Tubing head pressure of 1500 psi the optimum point is towards the right of the turner and IPR intersection point, that means the critical flow rate that should be maintained according to turner model is nearly 10MMSCFD where as the operating point is near 75MMSCFD so we are operating on safe side. For estimation of when liquid loading is going to occur for a particular well we need to look out for a point where the IPR and turner intersection point falls to the left of optimum point, this is done by plotting future IPR for the wells.
IPR & TPR OVERLAP WITH TURNER
3,500 3,000
Optimum point
Pwf (psi)
2,500 2,000
IPR @ 3281
1,500
TPR @ THP of 1500
1,000 500 0 0
20
40
60 Qg (MMSCFD)
Application and case study: Static Reservoir Pressure Wellhead depth
3281psi 727m MDRT
Well bottom depth
2170m MDRT
Well Depth (measured)
1443m
Pwf (psi) 3240 3187 3108
Qg (MMSCFD) 5.4 12.0 18.9
80
100
120
SPE 155356
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Nodal analysis: IPR construction: Initial IPR at Ps =3281 : IPR
3,500 3,000
Pwf (psi)
2,500 2,000 1,500 1,000 500 0 0
50
100
Qg (MMSCFD)
150
Future IPR at Ps =3000psi, 2700psi, 2400psi, 2100psi.
FUTURE IPR'S 3,500 3,000
IPR @ 3281 IPR @ 3000 IPR @ 2700 IPR @ 2400
Pwf (psi)
2,500 2,000 1,500 1,000 500 0
0
50Qg (MMSCFD)100
TPR Construction for THP of 1631psi and 1500psi:
150
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SPE 155356
IPR & TPR
3,500 3,000
IPR @ 3281
Pwf (psi)
2,500 2,000
IPR @ 3000
1,500 IPR @ 2700
1,000 500 0
0
50Qg (MMSCFD)100
150
Critical Flow rate Graph overlaps with IPR and TRP Based on TURNER MODEL: IPR & TPR OVERLAP WITH TURNER 3,500 3,000 IPR @ 3281
2,500 Pwf (psi)
2,000 1,500
IPR @ 3000
1,000 500 0
0
50
100
Qg (MMSCFD)
150
Conclusion: For the well the intersection of IPR for a static reservoir pressure of 2100 and TPR curve for a THP of 1631 psi falls to the left of the intersection of IPR and turner model curve. This is where this well will encounter the liquid loading problem as the optimum rate is less than the critical flow rate as predicted from the turner model.
