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Flow assurance deliverability issues
C H A P T E R
7 Flow assurance deliverability issues O U T L I N E Flowline design process
205
Optimization of flowline sizes
206
Artificial lifting
206
Topsides equipment and arrival pressures
207
Cold flow and emulsion Heavy oil viscosity Emulsion rheology
207 208 208
References
209
Further reading
209
Flowline design process Flowline design is in the realm of pipeline engineers, but is done in collaboration with flow assurance specialists. The flow assurance analysis helps indicate whether the pipe is sufficiently large or too large for the life of the project and whether flow is likely to be stable or intermittent. Flow assurance also helps forecast the amount of liquids arriving into the process equipment at various stages of the project life. Pipeline sizing considerations are usually based on two boundary conditions: pressure and velocity. Pressure in a pipeline should not to exceed the pipe design pressure. Usually the MAOP is set with a safety margin of between few bar and up to 10% lower than the design pressure, to allow for pressure surges during transient flow events such as production startup or shutdown. Velocity in a pipeline should not exceed the erosional velocity. Maximum velocity is determined based on operator internal design considerations for erosion, fluid corrosivity, or on recommended guidelines provided by API, DNV or NORSOK. Regional regulatory requirements may prescribe which method to use for the flow velocity considerations. In some cases, velocity should not drop below a certain minimum threshold to ensure produced solids such as sand are transported by the flow. Typical minimum liquid v elocity
Handbook of Multiphase Flow Assurance https://doi.org/10.1016/B978-0-12-813062-9.00007-5
205
© 2019 Elsevier Inc. All rights reserved.
206
7. Flow assurance deliverability issues
expected to transport sand in a near-horizontal pipe is 1 m/s. This value may differ at various operator companies. In some production systems operating in stratified multiphase flow regime, the chemical inhibitors are injected and are carried in the liquid phase. Sufficient gas flow velocity is required to entrain liquid droplets and wet the perimeter of the flowline so that all parts of the production system are treated with the injected chemicals. The minimum gas flow velocity consideration is important when top of the line corrosion (TOLC) is expected to be an issue. In multiphase flow with stratified flow regime, as flowing produced fluid cools down, water may condense from the gas stream and accumulate as droplets on top of the flow line. Freshly condensed water has no inhibitor chemicals in it. This brings the concerns of corrosion and hydrate formation. Corrosion risk may be mitigated by maintaining gas velocity above the minimum value. Hydrate risk may be mitigated by injection of a volatile hydrate inhibitor such as methanol. It should be noted that methanol may absorb oxygen from air if kept in a storage tank without a gas blanketing system. Oxygen thus brought into the system with methanol may increase the rate of corrosion. Routing of flowlines should avoid significant elevation changes. It may be more profitable to increase the line length in order to keep the line mostly flat rather than build it straight over a mountain or through a canyon. Analysis of the relative cost of extending the flowline length should be performed together with the flowline size and flow rate optimization to find the relative impact of a hill or canyon crossing on the backpressure and delivery of wells over the life of field.
Optimization of flowline sizes Flowline sizes may be optimized to provide target flow rates over the life of field. Larger diameter pipelines result in lower pressure drop, but also cost more. In multiphase flow the liquids accumulation as holdup in low and uphill sections of oversized lines also acts as a hydraulic restriction and increases pressure drop. Flow assurance can develop a flow performance analysis, correlating both pressure drop and liquid holdup with the flow rate and flowline size. There is expected to be a flowline size when pressure drop and holdup are low. This size is optimal for the operation as it would reduce the back pressure and increase production from wells over the life of field, and reduce liquid surge into process equipment.
Artificial lifting Artificial lift design is in the realm of production engineers, but should be done in collaboration with flow assurance specialists (Table 7.1). When reservoir pressure is or becomes low, there are several methods which allow to add or to periodically accumulate the energy in order to lift heavier liquids from reservoir to surface. Some of the artificial lift methods are listed in the table below. Absence of moving parts should improve equipment reliability.
207
Cold flow and emulsion
TABLE 7.1 Artificial lift methods categorized by energy introduction, application location and presence of moving parts Artificial lift method
Add or accumulate energy to flow Application
Moving parts
Gas lift
Add
Well
No
Plunger lift
Accumulate
Well
Yes
Velocity string
Accumulate
Well
No
ESP
Add
Well
Yes
Progressive Cavity Pump
Add
Well
Yes
Jet pump
Add
Well or flowline
No
Swabbing
Add
Well
Yes
Multiphase pump
Add
Flowline
Yes
Topsides equipment and arrival pressures Topside equipment should be rated to the pressures expected at the wellhead. In cases of high pressure high temperature (HPHT) reservoirs, the shut-in wellhead pressure may be significantly higher than the flowing wellhead pressure and the process equipment pressure rating. In such field development designs the high integrity pressure protection system (HIPPS) with fast-acting valves (can go from fully open to fully closed in approximately 3 s) may be installed to protect the equipment from pressure. A certain length of reinforced pipe rated to the maximum wellhead pressure, usually less than 1000 m long is installed downstream of HIPPS valves. The remainder of the pipe and process equipment may be rated to a lower pressure to reduce capital cost. Flow assurance can develop a fast transient flow performance analysis to estimate the maximum pressure observed downstream of the HIPPS valve while it closes. The fast transient HIPPS analysis can help ensure that the length of a reinforced pipe is sufficient to contain the produced fluid pressure during the time while the well stops and the HIPPS system actuates.
Cold flow and emulsion Cold flow is a technology concept which has been evaluated between 10 and 20 years ago. The premise of cold flow is to eliminate the use of the highest dosage and costly hydrate control chemicals by routing of the production fluids so as to induce precipitation of solids in a controlled way that said solids would not plug the production system. This may be accomplished by recycling some of the production fluids cooled to ambient temperature back to the vicinity of the wellhead. The cooled produced fluid would already contain small crystals of gas hydrate and paraffin wax. Injection of the recycle stream at the wellhead would serve to provide crystal seeds on which wax and hydrate would grow from the well stream fluid, instead of on the pipe wall. The method had been validated and demonstrated to work in a pilot scale equipment in Tiller, Norway (Argo et al., 2004).
208
7. Flow assurance deliverability issues
Another cold flow design is static mixer. The static mixer design has been validated in the field (Turner and Talley, 2008) to control the hydrate formation and to keep hydrates dispersed and flowing. None of the cold flow methods have been implemented for continuous field use due to novelty and lack of historic performance. Operators are not yet certain whether either cold flow technique can deliver 100% reliability over the life of field. Cold flow technology may be useful where the use of chemicals is restricted by local regulation.
Heavy oil viscosity Heavy oils provide increased resistance to flow not only by being heavy but also by having higher viscosity. Over 20 methods are available in literature for estimating oil viscosity. These methods have been summarized by Bergman and Sutton (2007) who correlated dead oil viscosity with temperature and density based on 9837 viscosity measurements from 3047 fluids which ranged in API gravity from 0.45° to 135.9°. The Bergman and Sutton correlation was discussed earlier in Chapter 3. A recent correlation for estimating the viscosity of heavy oil in mixtures with water has been presented by Wen et al. (2016). The method proposed by Wen may be used together with the correlation provided by Bergman and Sutton (2007).
Emulsion rheology Oil and water emulsion may be more viscous than just oil by a factor of 10 or more. Several correlations for emulsion viscosity had been developed including Smith & Arnold, Woelflin Loose, Woelflin Medium and Woelflin Tight. Emulsions may exhibit peak viscosity around 50–85% water cut. The inversion point from oil-external to water-external emulsion depends on the character of the crude, the character of the brine, and the degree of emulsification. The inversion points corresponds to maximum viscosity (Fig. 7.1). Emulsion Viscosity
Effective Emulsion Viscosity, cP
100,000
10,000
1000 Smith & Arnold Woelflin Loose Woelflin Medium Woelflin Tight
100 0.0
0.1
0.2
0.3
0.4 Water Cut
FIG. 7.1 Effective emulsion viscosity correlations comparison.
0.5
0.6
0.7
0.8
Further reading
209
References Argo, C.B., Bolavaram, P., Hjarbo, K.W., Makogon, T.Y., Oza, N., Wolden, M., Lund, A., Larsen, R., 2004. Method and System for Transporting Flows of Fluid Hydrocarbons Containing Wax, Asphaltenes, and/or Other Precipitating Solids. (WO2004059178). Bergman, D.F., Sutton, R.P., 2007. A consistent and accurate dead-oil-viscosity method, SPE110194. In: SPE Annual Technical Conference and Exhibition (Anaheim, 11–14 November). Turner, D.J., Talley, L.D., 2008. Hydrate inhibition via cold flow—no chemicals or insulation. In: 6th International Conference on Gas Hydrates, Vancouver, July 6–10. Wen, J., Zhang, J., Wei, M., 2016. Effective viscosity prediction of crude oil-water mixtures with high water fraction. J. Pet. Sci. Eng. 147, 760–770.
Further reading Bradley, H.B., 1987. Petroleum Engineering Handbook. Society of Petroleum Engineers, Richardson, TX (Chapter 19). Woelflin, W., 1942. The viscosity of crude-oil emulsions. In: Drill. and Prod. Prac., API, pp. 148–153.
7 Flow assurance deliverability issues O U T L I N E Flowline design process
205
Optimization of flowline sizes
206
Artificial lifting
206
Topsides equipment and arrival pressures
207
Cold flow and emulsion Heavy oil viscosity Emulsion rheology
207 208 208
References
209
Further reading
209
Flowline design process Flowline design is in the realm of pipeline engineers, but is done in collaboration with flow assurance specialists. The flow assurance analysis helps indicate whether the pipe is sufficiently large or too large for the life of the project and whether flow is likely to be stable or intermittent. Flow assurance also helps forecast the amount of liquids arriving into the process equipment at various stages of the project life. Pipeline sizing considerations are usually based on two boundary conditions: pressure and velocity. Pressure in a pipeline should not to exceed the pipe design pressure. Usually the MAOP is set with a safety margin of between few bar and up to 10% lower than the design pressure, to allow for pressure surges during transient flow events such as production startup or shutdown. Velocity in a pipeline should not exceed the erosional velocity. Maximum velocity is determined based on operator internal design considerations for erosion, fluid corrosivity, or on recommended guidelines provided by API, DNV or NORSOK. Regional regulatory requirements may prescribe which method to use for the flow velocity considerations. In some cases, velocity should not drop below a certain minimum threshold to ensure produced solids such as sand are transported by the flow. Typical minimum liquid v elocity
Handbook of Multiphase Flow Assurance https://doi.org/10.1016/B978-0-12-813062-9.00007-5
205
© 2019 Elsevier Inc. All rights reserved.
206
7. Flow assurance deliverability issues
expected to transport sand in a near-horizontal pipe is 1 m/s. This value may differ at various operator companies. In some production systems operating in stratified multiphase flow regime, the chemical inhibitors are injected and are carried in the liquid phase. Sufficient gas flow velocity is required to entrain liquid droplets and wet the perimeter of the flowline so that all parts of the production system are treated with the injected chemicals. The minimum gas flow velocity consideration is important when top of the line corrosion (TOLC) is expected to be an issue. In multiphase flow with stratified flow regime, as flowing produced fluid cools down, water may condense from the gas stream and accumulate as droplets on top of the flow line. Freshly condensed water has no inhibitor chemicals in it. This brings the concerns of corrosion and hydrate formation. Corrosion risk may be mitigated by maintaining gas velocity above the minimum value. Hydrate risk may be mitigated by injection of a volatile hydrate inhibitor such as methanol. It should be noted that methanol may absorb oxygen from air if kept in a storage tank without a gas blanketing system. Oxygen thus brought into the system with methanol may increase the rate of corrosion. Routing of flowlines should avoid significant elevation changes. It may be more profitable to increase the line length in order to keep the line mostly flat rather than build it straight over a mountain or through a canyon. Analysis of the relative cost of extending the flowline length should be performed together with the flowline size and flow rate optimization to find the relative impact of a hill or canyon crossing on the backpressure and delivery of wells over the life of field.
Optimization of flowline sizes Flowline sizes may be optimized to provide target flow rates over the life of field. Larger diameter pipelines result in lower pressure drop, but also cost more. In multiphase flow the liquids accumulation as holdup in low and uphill sections of oversized lines also acts as a hydraulic restriction and increases pressure drop. Flow assurance can develop a flow performance analysis, correlating both pressure drop and liquid holdup with the flow rate and flowline size. There is expected to be a flowline size when pressure drop and holdup are low. This size is optimal for the operation as it would reduce the back pressure and increase production from wells over the life of field, and reduce liquid surge into process equipment.
Artificial lifting Artificial lift design is in the realm of production engineers, but should be done in collaboration with flow assurance specialists (Table 7.1). When reservoir pressure is or becomes low, there are several methods which allow to add or to periodically accumulate the energy in order to lift heavier liquids from reservoir to surface. Some of the artificial lift methods are listed in the table below. Absence of moving parts should improve equipment reliability.
207
Cold flow and emulsion
TABLE 7.1 Artificial lift methods categorized by energy introduction, application location and presence of moving parts Artificial lift method
Add or accumulate energy to flow Application
Moving parts
Gas lift
Add
Well
No
Plunger lift
Accumulate
Well
Yes
Velocity string
Accumulate
Well
No
ESP
Add
Well
Yes
Progressive Cavity Pump
Add
Well
Yes
Jet pump
Add
Well or flowline
No
Swabbing
Add
Well
Yes
Multiphase pump
Add
Flowline
Yes
Topsides equipment and arrival pressures Topside equipment should be rated to the pressures expected at the wellhead. In cases of high pressure high temperature (HPHT) reservoirs, the shut-in wellhead pressure may be significantly higher than the flowing wellhead pressure and the process equipment pressure rating. In such field development designs the high integrity pressure protection system (HIPPS) with fast-acting valves (can go from fully open to fully closed in approximately 3 s) may be installed to protect the equipment from pressure. A certain length of reinforced pipe rated to the maximum wellhead pressure, usually less than 1000 m long is installed downstream of HIPPS valves. The remainder of the pipe and process equipment may be rated to a lower pressure to reduce capital cost. Flow assurance can develop a fast transient flow performance analysis to estimate the maximum pressure observed downstream of the HIPPS valve while it closes. The fast transient HIPPS analysis can help ensure that the length of a reinforced pipe is sufficient to contain the produced fluid pressure during the time while the well stops and the HIPPS system actuates.
Cold flow and emulsion Cold flow is a technology concept which has been evaluated between 10 and 20 years ago. The premise of cold flow is to eliminate the use of the highest dosage and costly hydrate control chemicals by routing of the production fluids so as to induce precipitation of solids in a controlled way that said solids would not plug the production system. This may be accomplished by recycling some of the production fluids cooled to ambient temperature back to the vicinity of the wellhead. The cooled produced fluid would already contain small crystals of gas hydrate and paraffin wax. Injection of the recycle stream at the wellhead would serve to provide crystal seeds on which wax and hydrate would grow from the well stream fluid, instead of on the pipe wall. The method had been validated and demonstrated to work in a pilot scale equipment in Tiller, Norway (Argo et al., 2004).
208
7. Flow assurance deliverability issues
Another cold flow design is static mixer. The static mixer design has been validated in the field (Turner and Talley, 2008) to control the hydrate formation and to keep hydrates dispersed and flowing. None of the cold flow methods have been implemented for continuous field use due to novelty and lack of historic performance. Operators are not yet certain whether either cold flow technique can deliver 100% reliability over the life of field. Cold flow technology may be useful where the use of chemicals is restricted by local regulation.
Heavy oil viscosity Heavy oils provide increased resistance to flow not only by being heavy but also by having higher viscosity. Over 20 methods are available in literature for estimating oil viscosity. These methods have been summarized by Bergman and Sutton (2007) who correlated dead oil viscosity with temperature and density based on 9837 viscosity measurements from 3047 fluids which ranged in API gravity from 0.45° to 135.9°. The Bergman and Sutton correlation was discussed earlier in Chapter 3. A recent correlation for estimating the viscosity of heavy oil in mixtures with water has been presented by Wen et al. (2016). The method proposed by Wen may be used together with the correlation provided by Bergman and Sutton (2007).
Emulsion rheology Oil and water emulsion may be more viscous than just oil by a factor of 10 or more. Several correlations for emulsion viscosity had been developed including Smith & Arnold, Woelflin Loose, Woelflin Medium and Woelflin Tight. Emulsions may exhibit peak viscosity around 50–85% water cut. The inversion point from oil-external to water-external emulsion depends on the character of the crude, the character of the brine, and the degree of emulsification. The inversion points corresponds to maximum viscosity (Fig. 7.1). Emulsion Viscosity
Effective Emulsion Viscosity, cP
100,000
10,000
1000 Smith & Arnold Woelflin Loose Woelflin Medium Woelflin Tight
100 0.0
0.1
0.2
0.3
0.4 Water Cut
FIG. 7.1 Effective emulsion viscosity correlations comparison.
0.5
0.6
0.7
0.8
Further reading
209
References Argo, C.B., Bolavaram, P., Hjarbo, K.W., Makogon, T.Y., Oza, N., Wolden, M., Lund, A., Larsen, R., 2004. Method and System for Transporting Flows of Fluid Hydrocarbons Containing Wax, Asphaltenes, and/or Other Precipitating Solids. (WO2004059178). Bergman, D.F., Sutton, R.P., 2007. A consistent and accurate dead-oil-viscosity method, SPE110194. In: SPE Annual Technical Conference and Exhibition (Anaheim, 11–14 November). Turner, D.J., Talley, L.D., 2008. Hydrate inhibition via cold flow—no chemicals or insulation. In: 6th International Conference on Gas Hydrates, Vancouver, July 6–10. Wen, J., Zhang, J., Wei, M., 2016. Effective viscosity prediction of crude oil-water mixtures with high water fraction. J. Pet. Sci. Eng. 147, 760–770.
Further reading Bradley, H.B., 1987. Petroleum Engineering Handbook. Society of Petroleum Engineers, Richardson, TX (Chapter 19). Woelflin, W., 1942. The viscosity of crude-oil emulsions. In: Drill. and Prod. Prac., API, pp. 148–153.