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Flow assurance stability issues
C H A P T E R
8 Flow assurance stability issues O U T L I N E Severe slugging Phenomena description Prediction methods Suppression techniques
211 211 212 213
Transient operation Shut-in and start-up Rate ramp-up and ramp-down
213 213 214
Slugging in gathering lines
214
Calculation of slug impact force on Tees and Elbows
214
Calculation of pressure surge on sudden flow shut-in 215 Vacuum condition in flow
216
References
216
Further reading
216
Severe slugging Phenomena description The issue of severe slugging has several impacts on production system. Periodic slugging causes mechanical integrity issues as slugs of liquid impact on bends of the flow lines. Slug of a large volume may cause a production facility shutdown if it overfills the separator capacity. Slug flow also causes periodic increase of backpressure on wells which reduces the overall production rate and may lead to lower ultimate recovery of hydrocarbons from the reservoir. A detailed description of severe slugging issues is provided by Hill and Wood (1994). The authors provide the correlations for slug frequency, average and maximum possible slug length and discuss the design of slugging systems. The authors report the “best fit” average slug frequency correlation as:
( Fs D / Vm ) ∗ (1 − 0.05 VSG ) D0.3 = −24.729 + 0.00766 exp ( 9.91209∗ Hle∗ (1 − 0.068 / VSL ) ) + 24.721 exp ( 0.20524∗ Hle∗ (1 − 0.068 / VSL ) ) ∗
Handbook of Multiphase Flow Assurance https://doi.org/10.1016/B978-0-12-813062-9.00008-7
211
© 2019 Elsevier Inc. All rights reserved.
212
8. Flow assurance stability issues
Fs = slug frequency per hour; D = pipe diameter, m; Vm = mixture velocity, m/s; VSG = superficial gas velocity, m/s; Hle = equilibrium stratified liquid holdup; VSL = superficial liquid velocity, m/s.
Prediction methods Flow regime map Flow regime map is plotted in coordinates of superficial liquid velocity vs. superficial gas velocity, on a log-log scale. A flow regime map would be expected to have the following form (Fig. 8.1). Stability limits Multiple additional works on severe slugging are available in the literature such as Montgomery (2002). The author indicates that severe slugging causes a 20% drop in production, and results in separator trips/shutdowns. The stability criterion proposed by the author: U GL S ≤ U GB S∗ ( 1 − g εLP L P sin θ ( ρL − ρG ) / ( PS + ρL g h R ) ) UGLS = inlet gas velocity. UGBS = gas velocity entering the riser base, m/s. g = gravity acceleration, m/s2. εLP = pipeline liquid holdup, calculated using Taitel (1986) method. LP = downhill pipe length upstream of the lowest point. θ = inclination from horizontal at riser base downstream of the riser lowest point. PS = separator pressure. ρL = liquid density. ρG = gas density. hR = riser height.
FIG. 8.1. Typical multiphase flow regime map.
Transient operation
213
The author indicates the stability criterion is that in order to prevent a bubble penetrating the riser base, the inlet gas velocity must be lower than some critical gas velocity, which depends on the ratio of the hydrostatic head in the pipeline and riser. The Boe criterion for the occurrence of severe slugging is commonly used in the industry. The Boe criterion provides an estimate of the minimum liquid velocity at which pressure increase due to liquid accumulation in vertical part of the multiphase flow system is higher than pressure increase due to gas compression in horizontal part of the system. U L S ≥ PP U G S / ( ρL g ( 1 − εL ) L sin α ) ULS = liquid superficial velocity. PP = pipe pressure. UGS = gas superficial velocity. ρL = liquid density. g = gravity acceleration. εL = pipeline or tubing liquid holdup. L = length of downhill pipe upstream of the lowest point. α = inclination of pipe upstream of the lowest point.
Boe estimated the holdup based on no-slip condition: ε L = U L S / ( U L S + U G S ) The Boe criterion is a straight line in ULS vs. UGS coordinates. Unstable flow is at values above the line. Additional work which provides stability criterion on horizontal-vertical flow systems includes Zakarian (2000). Author developed a stability criterion and validated it with laboratory analysis.
Suppression techniques Slug mitigation options (Montgomery, 2002) include: gas lift, choke control and separation. Choke control, separator pressure and gas lift are named as slug mitigation options in (Sancho, 2015). The author also provides a severe slug classification into four categories. A novel method for slug suppression by dividing large liquid slugs into smaller parts which would be more easily accommodated by the separator was proposed (Makogon et al., 2011) which was discussed in Chapter 4.
Transient operation Shut-in and start-up On production shut-in, liquids redistribute according to gravity in the production system. This affects the cooldown of the produced fluids. Water tends to retain more heat. As water drains to and accumulates in the low spots, this may provide additional time before hydrates begin to form. However, system insulation is usually designed to provide sufficient cooldown time in the gas-filled sections of the flowline. Gas has the least heat capacity of the produced fluids. Sections of flowline filled with gas cool down the fastest. Typical insulation
214
8. Flow assurance stability issues
thickness in subsea flowlines is 3 in., which provides sufficient time for the operator to take preventive action to manage the risk of flow assurance blockages in the system. Startup of production is a transient operation which can cause a surge of liquids settled in the low spots of the production system to arrive in the separator and stop the production if separator is not sufficiently large to hold the arrived liquids. Transient multiphase simulation tools are available to estimate the volume of liquid surge at different well ramp-up rates during a start-up.
Rate ramp-up and ramp-down Production operator may increase or decrease wells' production rate according to the field development plan. During a flow rate ramp-up an event similar to a liquid surge during start-up may be expected. Higher flow rate sweeps liquid holdup accumulated in the flow line; the liquid travels to the separator and temporarily increases the liquid rate. During a flow ramp-down, less liquid is expected to be produced to the process facilities. At lower flow rate more liquid will accumulate in the flow line.
Slugging in gathering lines Gathering lines carrying multiphase fluids may also experience slugging when slugs originate in a wellbore as the well starts to be loaded with liquids. Choke opening or artificial lift methods may be used to reduce the liquid loading in wells and slugging in the gathering lines. Lowering production tubing into the Boycott range may also help stabilize wells production and extend well life. If no method works to mitigate the slugging, then flowline restraints or bracing for the flowlines should be used as recommended by Hill and Wood (1994) to help with the loads on the pipework.
Calculation of slug impact force on Tees and Elbows Slugs traveling at high velocity through a production flow line carry a substantial momentum M and impact the pipe locations with change in direction with a significant force. Slugs are known to have knocked flow lines off their support stands and caused significant (greater than 1 pipe diameter) movement. Slugging has led to loss of integrity as in-field pipelines made of fiber epoxy got disconnected from the Tee at the location of slug impacts. Liquid slug is pushed through a flow line by gas. Liquid slug travels at nearly the velocity of gas which pushes the slug like a piston. A simplified correlation for slug length based on pipe diameter was proposed in Chapter 4. L [ ft ] = (D [ inch ])2
Calculation of pressure surge on sudden flow shut-in
215
The force of slug impact may be calculated if one knows slug density, gas velocity, pipe size and angle of the pipe bend. Force of slug impact on a bend may be estimated as: F = ∆Μ / ∆t = ρ V 2 A ( 2 − 2 cos θ )
0.5
ρ = liquid slug density, kg/m3. V = gas or slug velocity, m/s. A = pipe cross section area, m2. θ = bend angle. M = momentum, kg m/s. t = time, s. Time may be estimated based on slug velocity and slug length. The calculated force value should be multiplied with a suitable dynamic load factor (DLF). A DLF of 2.0 is commonly used. Experimental data on slug forces at pipe bends from several researchers was presented and summarized in the works of Hou et al. (2014) and Tay and Thorpe (2015).
Calculation of pressure surge on sudden flow shut-in Flowing mass of liquid carries a substantial momentum. When flow path becomes suddenly blocked, a pressure is expected to increase. Transient single phase flow simulators are commonly used to estimate the pressure change during such event. A simple albeit somewhat conservative method to calculate pressure surge is based on Joukowski. ∆P = ρ C ∆V ΔP = change in pressure, Pa. ρ = density of flowing fluid, kg/m3. c = speed of sound in fluid at operating pressure and temperature, m/s. ΔV = change in flow velocity, m/s. c = (K*/ρ)0.5. K* = K/(1 + D K/(e E)). D = pipe diameter, m. e = wall thickness, m. E = wall elasticity modulus, Pa = kg/(ms2). K = fluid bulk modulus, Pa = kg/(ms2). Some values for materials commonly used in production systems are shown below. ESTEEL = 200 * 109 Pa. EFIBERGLASS = 17 * 109 Pa. EHDPE = 0.8 * 109 Pa. KWATER = 2.15 * 109 Pa. KOIL = 1.7 * 109 Pa. KGLYCOL + WATER = 3.4 * 109 Pa.
216
8. Flow assurance stability issues
Vacuum condition in flow Vacuum condition and pressure surge may occur during stock oil flow. In oil export pipelines going through mountainous terrain, or in deepwater during displacement of the flowline live oil with stock oil there may be a vacuum condition at the highest point of the flow system. If pressure at a pipeline pumping station downstream of a mountain or at the bottom of the flowline riser is lower than hydrostatic head pressure for stock oil, vacuum may occur at the crest of the mountain or at the riser top. Vacuum condition has to be taken into account for design of flexible lines and flexible parts and materials on topsides system. Vacuum can also occur at top of chemical injection lines causing flashing off of solvent and deposition of active ingredient in the chemical tubing. Higher than normal flowing pressure or deadheading may occur during start-up of stock oil flow to move the stationary fluids in the pipeline or in the flowline such as during dead oil displacement.
References Hill, T.J., Wood, D.G., 1994. Slug flow: occurrence, consequences and prediction. In: SPE 27960, University of Tulsa Centennial Petroleum Engineering Symposium, Tulsa, 29–31 August. Hou, D.Q., Tijsseling, A.S., Bozkus, Z., 2014. Dynamic force on an elbow caused by a traveling liquid slug. J. Press. Vessel. Technol. 136. Makogon, T.Y., Estanga, D., Sarica, C., 2011. A new passive technique for severe slugging attenuation. In: 15th Multiphase Production Technology Conference, Cannes, France, 15–17 June. Montgomery, J.A., 2002. Severe Slugging and Unstable Flows in an S-Shaped Riser. PhD. Thesis, Cranfield University. Sancho, A.M., 2015. Severe Slugging in Pipelines. Master Sc. Thesis, Instituto Superior Tecnico, Lisboa. Taitel, Y., 1986. Stability of severe slugging. Int. J. Multiphase Flow 12 (2), 203–217. Tay, B.L., Thorpe, R.B., 2015. Statistical analysis of the hydrodynamic forces acting on pipe bends in gas–liquid slug flow and their relation to fatigue. Chem. Eng. Res. Des. 104, 457–471. Zakarian, E., 2000. Analysis of two-phase flow instabilities in pipe-riser system. In: Proceedings PVP2000, ASME Pressure Vessels and Piping Conference, July 23–27, Seattle.
Further reading Boe, A., 1981. Severe Slugging Characteristics, Part I, Flow Regime for Severe Slugging, Presented at Special Topics in Two-Phase Flow, Trondheim, Norway. Joukowsky, N., 1898. “Über den hydraulischen Stoss in Wasserleitungsröhren.” (“On the hydraulic hammer in water supply pipes.”). Mémoires de l'Académie Impériale des Sciences de St.-Pétersbourg (1900), Series 8 9 (5), 1–71. (in German); Sections presented to the Division of Physical Sciences of O.L.E., 26 September 1897, to the PhysicalMathematical Commission of the Society, 30 January 1898, to the Polytechnic Society of the Moscow Imperial Institute, 21 February 1898; complete paper to the Russian Technical Society, 24 April 1898, to the PhysicalMathematical Division of the Academy of Sciences, 13 May 1898. Also: Жуковский, Н.Е. (1899). “О гидравлическом ударе в водопроводных трубах.” (“On hydraulic hammer in water mains.”), Proc., 4th Russian Water Pipes Congress, pp. 78–173, printed in Moscow (1901), April 1899, Odessa, Russia.
8 Flow assurance stability issues O U T L I N E Severe slugging Phenomena description Prediction methods Suppression techniques
211 211 212 213
Transient operation Shut-in and start-up Rate ramp-up and ramp-down
213 213 214
Slugging in gathering lines
214
Calculation of slug impact force on Tees and Elbows
214
Calculation of pressure surge on sudden flow shut-in 215 Vacuum condition in flow
216
References
216
Further reading
216
Severe slugging Phenomena description The issue of severe slugging has several impacts on production system. Periodic slugging causes mechanical integrity issues as slugs of liquid impact on bends of the flow lines. Slug of a large volume may cause a production facility shutdown if it overfills the separator capacity. Slug flow also causes periodic increase of backpressure on wells which reduces the overall production rate and may lead to lower ultimate recovery of hydrocarbons from the reservoir. A detailed description of severe slugging issues is provided by Hill and Wood (1994). The authors provide the correlations for slug frequency, average and maximum possible slug length and discuss the design of slugging systems. The authors report the “best fit” average slug frequency correlation as:
( Fs D / Vm ) ∗ (1 − 0.05 VSG ) D0.3 = −24.729 + 0.00766 exp ( 9.91209∗ Hle∗ (1 − 0.068 / VSL ) ) + 24.721 exp ( 0.20524∗ Hle∗ (1 − 0.068 / VSL ) ) ∗
Handbook of Multiphase Flow Assurance https://doi.org/10.1016/B978-0-12-813062-9.00008-7
211
© 2019 Elsevier Inc. All rights reserved.
212
8. Flow assurance stability issues
Fs = slug frequency per hour; D = pipe diameter, m; Vm = mixture velocity, m/s; VSG = superficial gas velocity, m/s; Hle = equilibrium stratified liquid holdup; VSL = superficial liquid velocity, m/s.
Prediction methods Flow regime map Flow regime map is plotted in coordinates of superficial liquid velocity vs. superficial gas velocity, on a log-log scale. A flow regime map would be expected to have the following form (Fig. 8.1). Stability limits Multiple additional works on severe slugging are available in the literature such as Montgomery (2002). The author indicates that severe slugging causes a 20% drop in production, and results in separator trips/shutdowns. The stability criterion proposed by the author: U GL S ≤ U GB S∗ ( 1 − g εLP L P sin θ ( ρL − ρG ) / ( PS + ρL g h R ) ) UGLS = inlet gas velocity. UGBS = gas velocity entering the riser base, m/s. g = gravity acceleration, m/s2. εLP = pipeline liquid holdup, calculated using Taitel (1986) method. LP = downhill pipe length upstream of the lowest point. θ = inclination from horizontal at riser base downstream of the riser lowest point. PS = separator pressure. ρL = liquid density. ρG = gas density. hR = riser height.
FIG. 8.1. Typical multiphase flow regime map.
Transient operation
213
The author indicates the stability criterion is that in order to prevent a bubble penetrating the riser base, the inlet gas velocity must be lower than some critical gas velocity, which depends on the ratio of the hydrostatic head in the pipeline and riser. The Boe criterion for the occurrence of severe slugging is commonly used in the industry. The Boe criterion provides an estimate of the minimum liquid velocity at which pressure increase due to liquid accumulation in vertical part of the multiphase flow system is higher than pressure increase due to gas compression in horizontal part of the system. U L S ≥ PP U G S / ( ρL g ( 1 − εL ) L sin α ) ULS = liquid superficial velocity. PP = pipe pressure. UGS = gas superficial velocity. ρL = liquid density. g = gravity acceleration. εL = pipeline or tubing liquid holdup. L = length of downhill pipe upstream of the lowest point. α = inclination of pipe upstream of the lowest point.
Boe estimated the holdup based on no-slip condition: ε L = U L S / ( U L S + U G S ) The Boe criterion is a straight line in ULS vs. UGS coordinates. Unstable flow is at values above the line. Additional work which provides stability criterion on horizontal-vertical flow systems includes Zakarian (2000). Author developed a stability criterion and validated it with laboratory analysis.
Suppression techniques Slug mitigation options (Montgomery, 2002) include: gas lift, choke control and separation. Choke control, separator pressure and gas lift are named as slug mitigation options in (Sancho, 2015). The author also provides a severe slug classification into four categories. A novel method for slug suppression by dividing large liquid slugs into smaller parts which would be more easily accommodated by the separator was proposed (Makogon et al., 2011) which was discussed in Chapter 4.
Transient operation Shut-in and start-up On production shut-in, liquids redistribute according to gravity in the production system. This affects the cooldown of the produced fluids. Water tends to retain more heat. As water drains to and accumulates in the low spots, this may provide additional time before hydrates begin to form. However, system insulation is usually designed to provide sufficient cooldown time in the gas-filled sections of the flowline. Gas has the least heat capacity of the produced fluids. Sections of flowline filled with gas cool down the fastest. Typical insulation
214
8. Flow assurance stability issues
thickness in subsea flowlines is 3 in., which provides sufficient time for the operator to take preventive action to manage the risk of flow assurance blockages in the system. Startup of production is a transient operation which can cause a surge of liquids settled in the low spots of the production system to arrive in the separator and stop the production if separator is not sufficiently large to hold the arrived liquids. Transient multiphase simulation tools are available to estimate the volume of liquid surge at different well ramp-up rates during a start-up.
Rate ramp-up and ramp-down Production operator may increase or decrease wells' production rate according to the field development plan. During a flow rate ramp-up an event similar to a liquid surge during start-up may be expected. Higher flow rate sweeps liquid holdup accumulated in the flow line; the liquid travels to the separator and temporarily increases the liquid rate. During a flow ramp-down, less liquid is expected to be produced to the process facilities. At lower flow rate more liquid will accumulate in the flow line.
Slugging in gathering lines Gathering lines carrying multiphase fluids may also experience slugging when slugs originate in a wellbore as the well starts to be loaded with liquids. Choke opening or artificial lift methods may be used to reduce the liquid loading in wells and slugging in the gathering lines. Lowering production tubing into the Boycott range may also help stabilize wells production and extend well life. If no method works to mitigate the slugging, then flowline restraints or bracing for the flowlines should be used as recommended by Hill and Wood (1994) to help with the loads on the pipework.
Calculation of slug impact force on Tees and Elbows Slugs traveling at high velocity through a production flow line carry a substantial momentum M and impact the pipe locations with change in direction with a significant force. Slugs are known to have knocked flow lines off their support stands and caused significant (greater than 1 pipe diameter) movement. Slugging has led to loss of integrity as in-field pipelines made of fiber epoxy got disconnected from the Tee at the location of slug impacts. Liquid slug is pushed through a flow line by gas. Liquid slug travels at nearly the velocity of gas which pushes the slug like a piston. A simplified correlation for slug length based on pipe diameter was proposed in Chapter 4. L [ ft ] = (D [ inch ])2
Calculation of pressure surge on sudden flow shut-in
215
The force of slug impact may be calculated if one knows slug density, gas velocity, pipe size and angle of the pipe bend. Force of slug impact on a bend may be estimated as: F = ∆Μ / ∆t = ρ V 2 A ( 2 − 2 cos θ )
0.5
ρ = liquid slug density, kg/m3. V = gas or slug velocity, m/s. A = pipe cross section area, m2. θ = bend angle. M = momentum, kg m/s. t = time, s. Time may be estimated based on slug velocity and slug length. The calculated force value should be multiplied with a suitable dynamic load factor (DLF). A DLF of 2.0 is commonly used. Experimental data on slug forces at pipe bends from several researchers was presented and summarized in the works of Hou et al. (2014) and Tay and Thorpe (2015).
Calculation of pressure surge on sudden flow shut-in Flowing mass of liquid carries a substantial momentum. When flow path becomes suddenly blocked, a pressure is expected to increase. Transient single phase flow simulators are commonly used to estimate the pressure change during such event. A simple albeit somewhat conservative method to calculate pressure surge is based on Joukowski. ∆P = ρ C ∆V ΔP = change in pressure, Pa. ρ = density of flowing fluid, kg/m3. c = speed of sound in fluid at operating pressure and temperature, m/s. ΔV = change in flow velocity, m/s. c = (K*/ρ)0.5. K* = K/(1 + D K/(e E)). D = pipe diameter, m. e = wall thickness, m. E = wall elasticity modulus, Pa = kg/(ms2). K = fluid bulk modulus, Pa = kg/(ms2). Some values for materials commonly used in production systems are shown below. ESTEEL = 200 * 109 Pa. EFIBERGLASS = 17 * 109 Pa. EHDPE = 0.8 * 109 Pa. KWATER = 2.15 * 109 Pa. KOIL = 1.7 * 109 Pa. KGLYCOL + WATER = 3.4 * 109 Pa.
216
8. Flow assurance stability issues
Vacuum condition in flow Vacuum condition and pressure surge may occur during stock oil flow. In oil export pipelines going through mountainous terrain, or in deepwater during displacement of the flowline live oil with stock oil there may be a vacuum condition at the highest point of the flow system. If pressure at a pipeline pumping station downstream of a mountain or at the bottom of the flowline riser is lower than hydrostatic head pressure for stock oil, vacuum may occur at the crest of the mountain or at the riser top. Vacuum condition has to be taken into account for design of flexible lines and flexible parts and materials on topsides system. Vacuum can also occur at top of chemical injection lines causing flashing off of solvent and deposition of active ingredient in the chemical tubing. Higher than normal flowing pressure or deadheading may occur during start-up of stock oil flow to move the stationary fluids in the pipeline or in the flowline such as during dead oil displacement.
References Hill, T.J., Wood, D.G., 1994. Slug flow: occurrence, consequences and prediction. In: SPE 27960, University of Tulsa Centennial Petroleum Engineering Symposium, Tulsa, 29–31 August. Hou, D.Q., Tijsseling, A.S., Bozkus, Z., 2014. Dynamic force on an elbow caused by a traveling liquid slug. J. Press. Vessel. Technol. 136. Makogon, T.Y., Estanga, D., Sarica, C., 2011. A new passive technique for severe slugging attenuation. In: 15th Multiphase Production Technology Conference, Cannes, France, 15–17 June. Montgomery, J.A., 2002. Severe Slugging and Unstable Flows in an S-Shaped Riser. PhD. Thesis, Cranfield University. Sancho, A.M., 2015. Severe Slugging in Pipelines. Master Sc. Thesis, Instituto Superior Tecnico, Lisboa. Taitel, Y., 1986. Stability of severe slugging. Int. J. Multiphase Flow 12 (2), 203–217. Tay, B.L., Thorpe, R.B., 2015. Statistical analysis of the hydrodynamic forces acting on pipe bends in gas–liquid slug flow and their relation to fatigue. Chem. Eng. Res. Des. 104, 457–471. Zakarian, E., 2000. Analysis of two-phase flow instabilities in pipe-riser system. In: Proceedings PVP2000, ASME Pressure Vessels and Piping Conference, July 23–27, Seattle.
Further reading Boe, A., 1981. Severe Slugging Characteristics, Part I, Flow Regime for Severe Slugging, Presented at Special Topics in Two-Phase Flow, Trondheim, Norway. Joukowsky, N., 1898. “Über den hydraulischen Stoss in Wasserleitungsröhren.” (“On the hydraulic hammer in water supply pipes.”). Mémoires de l'Académie Impériale des Sciences de St.-Pétersbourg (1900), Series 8 9 (5), 1–71. (in German); Sections presented to the Division of Physical Sciences of O.L.E., 26 September 1897, to the PhysicalMathematical Commission of the Society, 30 January 1898, to the Polytechnic Society of the Moscow Imperial Institute, 21 February 1898; complete paper to the Russian Technical Society, 24 April 1898, to the PhysicalMathematical Division of the Academy of Sciences, 13 May 1898. Also: Жуковский, Н.Е. (1899). “О гидравлическом ударе в водопроводных трубах.” (“On hydraulic hammer in water mains.”), Proc., 4th Russian Water Pipes Congress, pp. 78–173, printed in Moscow (1901), April 1899, Odessa, Russia.