University of Aberdeen MSc Subsea Engineering
Design of a Subsea Pipeline System Flow Assurance –EG55F8
Contents 1.0
Introduction.................................................................................................................................................1
2.0
Base Data-...................................................................................................................................................1
3.0
Methodology...............................................................................................................................................3
4.0
Results.........................................................................................................................................................3
4.1 Task 1- Identifying Suitable Pipeline Diameter............................................................................................3 4.2 Task 2- Erosion..............................................................................................................................................5 4.3 Task 3- Hydrate Formation Conditions.........................................................................................................6 4.4 Task 4- Insulation Configuration...................................................................................................................6 4.5 Task 5 - Slugging...........................................................................................................................................7 4.6 Task 6- Pressure.............................................................................................................................................7 5.1 Task 1- Identifying Suitable Pipeline Diameter............................................................................................8 5.2 Task 2- Erosion..............................................................................................................................................8 5.3 Task 3- Hydrate Formation Conditions.........................................................................................................8 5.4 Task 4- Insulation Configuration...................................................................................................................8 5.5 Task 5- Slugging............................................................................................................................................9 5.6 Task 6- Pressure.............................................................................................................................................9 5.7 Task 7- Operational Modes...........................................................................................................................9 5.0
Conclusion................................................................................................................................................10
6.0
References.................................................................................................................................................11
Appendix A -Erosion..............................................................................................................................................12 Appendix A- Erosion............................................................................................................................................13 Appendix B- Hydrate Formation........................................................................................................................14 Appendix B- Hydrate Formation........................................................................................................................15 Appendix C- Insulation Configuration..............................................................................................................16 Appendix D- Slugging...........................................................................................................................................17 Appendix D- Slugging..........................................................................................................................................18 Appendix E- Pressure..........................................................................................................................................20
1.0 Introduction Flow assurance is simply another term for multiphase transport, which regards the transmission of gas, oil and water all within the same pipeline from reservoir to processing [1]. Flow assurance is pivotal to the success of a developed field, because this area specifically concentrates on the behaviour of the flow within the pipeline. Flow assurance problems can hinder production rates in turn reducing revenue, therefore it is an area of extreme interest to keep pipelines producing. The purpose of this document is to present the determined findings in the area of interest, flow assurance more specifically, for the design of a subsea pipeline system. Within this document will be the methodology used to complete the assignment, including the means of how it was completed. The assignment was comprised of various tasks including, determining suitable pipeline diameters, establishing hydrate formation conditions and providing the insulation configuration. Other tasks included checking the terrain induced and severe slugging, specifically for well 1 and 4 as well as establishing whether the need for gas lift is present, when produced fluids are 90% water. All the tasks involved will be presented appropriately where results will be provided in either tabular or graphical representation. The base data used to complete the tasks will be included to show where particular values were extracted from and used.
2.0 Base Data Basic boundary conditions, pure hydrocarbon components, petroleum fractions and other constraints such as ambient sea temperature and the aqueous component are provided. Ambient sea temperature and aqueous component were set at 4 C and 0 rising to 90% respectively. The before mentioned basic data values and constraints are supplied to complete the assigned tasks, where values are used in calculations and the model configuration through the use of PIPESIM.
Figure 1(Boundary Conditions)
Figure 1 provided the values needed for firstly configuring the model on PIPESIM, where the inlet pressure and temperature as well as ambient sea temperature were assigned to each flowline and riser. The minimum arrival pressure to the platform, is used in determining the suitable pipe diameter through the use of PIPESIM. The pure hydrocarbon components as shown in figure 3 are also supplied for use in PIPESIM, as too is the petroleum fractions shown in figure 2. Predominantly all of the base data of which is supplied, is for use in PIPESIM in order to create a working model. The hydrocarbon components and petroleum fractions as shown in figure 2 &3, are supplied to construct the model, as the components are the composition of elements present within the produced fluids. The petroleum fraction is in fact the produced fluid, where the two figures show what components are extracted from the
well. Figure 2(Petroleum Fraction)
Figure 3(Hydrocarbon Components)
Figure 4 (Pipe Diameters & Well Flow Rates)
Figure 4 shows the pipe diameters and well flow rates which were also supplied, each individual diameter had to be run individually as PIPESIM wouldn’t allow all 3 to be calculated simultaneous. The final piece of data which is provided is the basic layout expected of the model layout involving the pipelines and riser as shown in figure 5.
Figure 5(Basic Pipeline Layout)
3.0 Methodology The methods used in the completion of the assigned tasks were done primarily through the use of the software, more specifically PIPESIM accompanied with various other calculations which were not completed using the software. Through the use of the before mentioned software and calculations, the desired outcomes to each task were achieved. The base data provided was used in variations of PIPESIM, configuring the working pipeline model. Firstly the parameters of each flowline and riser were completed, where the diameter, inlet pressure, wall thickness, roughness and temperature were assigned. The supplied petroleum fraction and hydrocarbon components are then inserted into the software too, so that the model could be tested, producing an output file. From the output file the necessary values for further hand calculations are provided. Calculations include using standards for determining the extent of erosion within the pipeline design. The Katz method was used to establish hydrate formation conditions within the pipeline as well as determining the insulation level and wax conditions. When reviewing the severe slugging terrain the Scott, Shoham and Brill method was used to determine the slug length and ultimately the volume to determine whether or not the separator could sustain the amount of slugging present. A detailed account of the equations and methods used is provided within the appendices, where each process is shown.
4.0 Results 4.1 Task 1- Identifying Suitable Pipeline Diameter To determine the best suited internal pipeline diameter from the three options as shown in figure 4, the following results were obtained using PIPESIM presenting the pressure within the pipeline over the distance of the pipeline development.
Figure 6(Diameter 241 mm Pressure vs Distance)
Figure 6 shows that there is a considerable difference in pressure between the different flow rates, where the pressure significantly drops for the 3280 sm3/day flow rate. It can be seen that pressure amongst the other flow rates drop to 12-19 bar where as the highest flow loses
all pressure by the end of the pipeline.
Figure 7(Diameter 292 mm Pressure vs Distance)
As presented in figure 7 a noticeable change in the pressure levels can be seen compared with figure 6. With the increased diameter a more consistent level of pressure is achieved, despite the very large drops at the end of the pipeline, the pressure levels still remain at 13 bar.
Figure 8(Diameter 343 mm Pressure vs Distance)
Figure 8 shows that similar to the previous diameter the pressure levels are increased with the diameter where each flow rate has a consistent pressure of over 20 bar, until evidently dropping to an adequate 12 -13 bar at the end of the pipeline. After consideration the diameter of 292 mm was selected, where reasons for selection are outlined in the discussion of task 1, section 5.1.
4.2 Task 2- Erosion Task 2 involved confirming the selected diameter is suitable with regards to erosion using API RP 14E, the specific detailed calculations used to complete this task will be included in appendix A. The API RP 14E is the American Petroleum Institute Recommended Practice, which defines a critical velocity above which erosion may occur. This standard recommends that the maximum velocity in the system to be limited to that of the critical velocity.
Figure 9(PIPESIM Output File Values)
Figure 9 presents values along with the appropriate headings which were extracted from the output file produced from the created model in PIPESIM. The above values were used in the equations outlined in appendix A using the API RP 14E.
Figure 10(Calculated Values using API RP 14E)
The results from using the before mentioned equations in appendix A are presented in figure 10, it should be noted that each table supplied are only the first 4 entries of the results, full results will be provided in the appendix A.
4.3 Task 3- Hydrate Formation Conditions To determine the results needed, the Katz method was used to determine the hydrate formation conditions of the pipeline. The equations used for this method will be provided in
appendix B along with the graphs used to obtain the hydrate K values needed for determination of the hydrate formation conditions.
Figure 11(Hydrate Formation Results Using Katz Method)
To determine the correct temperature involved, simple trial and error was implemented, where 10 °C was firstly used, however as shown in figure 11 this was not close to 1. With a slight increase in the temperature resulted in a more accurate value, resulting in hydrate formation occurring at 12 °C. Despite satisfying hydrate conditions, at an insulation level of 10 W∙m-2 °C-1 the wax conditions were not acceptable. The U-value was then changed to 0.5 W/(m2 ∙K), where the lowest temperature is recorded at 35°C, greater than the 25°C minimum requirement.
4.4 Task 4- Insulation Configuration Establishing the insulation configuration involved the before established U value, for which was the value 0.5 W/(m2 ∙K). This value was selected as it both satisfied the requirements set by the temperature which wax and hydrates formed. A K value of 0.007 W/m.K is used of which is that of the material izoflex and will resultantly produce a U value between 0.1 and 1 [2]. This material will be used as the insulation material, producing a thickness as shown, of 14.6 mm. The lowest temperature achieved with this U value is approximately 35 °C, a 10 °C gap as a precaution from the 25 °C, where wax begins to deposit. The equation used, again will be provided in appendix C, figure 12 shows the values which were obtained regarding the insulation configuration, including insulation thickness.
Figure 12(Insulation Configuration Values)
4.5 Task 5 - Slugging Similar to task 2, establishing the terrain slugging of the pipeline was completed using the same process.
Figure 13(Output File Values)
Figure 14(Max Slug Length & Volume)
Figure 13 shows only 2 entries obtained from the output file, the values shown are for 4 well and those for 1 well, which are then used in the determination of slug length. Once acquired the length is multiplied by the pipe area to establish the volume of slugging. The equation used in determine the terrain slugging will be provided in appendix D, accompanied with the other values from the output file.
4.6 Task 6- Pressure It is specified that as the field matures the same volume of liquid will be produced however of that, only 10% will be production fluid, with the remaining 90% being water. This shift in fluid composition has a direct impact on pressure within the pipeline. Figure 16 as shown in appendix E shows that pressure drops to as low as 8 bar, much lower than the minimum 10.3 bar required. It is recommended that gas lift is needed to return the pressure of the fluids to the minimum arrival pressure of 10.3 bar to allow the wells to flow.
5.0 Discussion 5.1 Task 1- Identifying Suitable Pipeline Diameter As previously presented in section 4.1 both diameters 292 mm and 343 mm both produced sufficient pressure levels when tested in the PIPESIM model, however the 292 diameter was chosen for further analysis. This diameter was selected solely down to financial motives with regard to practical application. The chosen diameter has a significantly lower diameter than that of the 343 mm option, the reduced diameter size therefore reduces material costs as the pipeline will have a lower overall area, hence forth the choice of the 292 mm option.
5.2 Task 2- Erosion The parameters in which surround the calculation of erosion are that to identify that the diameter selected is acceptable regarding erosion using API RP 14E. Using the API RP 14E determines the suitability of erosion through the use of equations, the detailed calculations
will be fully provided in appendix A, in determining this viewpoint a check is completed concluding calculation. This check is the equation Vm/Vm*< 1, where Vm is the mixture velocity and the maximum allowable mixture erosional velocity respectively. Using this check it establishes a consistent value of approximately 0.32 satisfying the criterion of being less than 1.
5.3 Task 3- Hydrate Formation Conditions The results as shown in section 4.3, show that through the use of the Katz method the temperature at which formation occurs was defined as 12 °C, however despite the model satisfying this restriction with temperatures above 12 °C, the temperatures achieved within the pipeline were unacceptable from a wax deposition viewpoint. The temperatures achieved were much lesser than the 25 °C at which wax deposition occurs, it is also a general efficiency consideration that temperatures must remain 10 °C above this minimal temperature. This consideration is applied to reduce the possibility of wax deposition as much as possible, within reason. To achieve the minimum 35 °C now needed, the U value assigned to the model in PIPESIM is changed to achieve this, where 0.5 W∙m2 °C- is selected, reduced 1
from the previous U value of 10 W∙m-2 °C-1.
5.4 Task 4- Insulation Configuration The insulation configuration can be determined following the establishment of a sufficient U value, completed in the previous task. A K value of 0.007 W/m.K was selected where the material which can achieve said value is that of izoflex. This material was selected as the assigned K value produces a U value range of which the previously selected U value is within. With a thermal conductivity ranging from 0.004 to 0.007 W/m.K producing U values between 0.1 to 1 W/m².K. Therefore, izoflex is the ideal insulation material given that the U value for the pipeline is 0.5 W∙m2 °C- , corresponding with the U value, and the thickness of 1
insulation calculated is too of reasonable dimensions. Through the calculations as shown in appendix C, the thickness of insulation is calculated to be 14. 6 mm.
5.5 Task 5- Slugging It is specified that the 1st stage separator only has an 8.5 m3 slug handling capacity. As shown in section 4.5 the max slug length for 4 well flow was determined to be 117.4 m, this calculated length was then multiplied by the area to produce a slug volume of 7.86 m 3, of which is lesser that specified in the criteria. The same procedure was completed for the determination of slug parameters for the flow of 1 well, where slug length and volume were
calculated to be 108.65 m and 7.28 m3 respectively also satisfying the 8.5 m3 restriction. The slugging lengths were initially determined using the Scott, Shoham and Brill method where the equations used will be provided in appendix D, it is established that slugging within the pipeline is acceptable due to both calculated volumes being below the aforementioned maximum capacity.
5.6 Task 6- Pressure From the results of task 6 in section 4.6 it is established that due the change in composition of fluid properties the pressure within the pipeline cannot be maintained at the minimum 10.3 bar to allow the well to flow. The fact that the well will not flow is the main impact of the pressure drop, no flow results in no production therefore no revenue is generated. Ultimately producing and generating revenue are the main concerns of operators in the oil and gas industry, excluding safety. If a well cannot produce the necessary fluids, the costs to maintain said well will soon inflate larger than the profit generated. Therefore to keep the pipeline flowing gas lift is needed to keep the field development economically viable. Gas lift is a method where injected gas decreases the viscosity within the fluids by reducing the pressure on the bottom of the well, allowing the fluids to flow easily [3].
5.7 Task 7- Operational Modes Before finalising the overall architecture of the pipeline, consideration should be given to the other operational modes of the pipeline. Well start up is as the name states, the well is started up at a specified rate from which allows time to warm up. However at this stage there will be a minimum flow rate where the thermal losses throughout the system will put the fluids in the hydrate formation region [4]. Well shut in can also produce a high hydrate formation risk, however the formation of hydrates can be prevented in the flowline. This can be accomplished through the method of flowline blowdown, where the pressure is reduced below the hydrate formation pressure at ambient sea pressures [4]. This procedure is necessary to prevent the temperature within the flowline from forming hydrates due to the temperature of the fluids flowing in the flowline. The risk of hydrates with a well shut in is because the pressure remains high, however temperature significantly reduces due to the transfer of heat to the ambient environment. Due to the high risk of hydrate formation in the other operational modes, it is extremely important to review the architecture of the pipeline regarding these modes and risks to maintain the flow within the flowline. It should also be noted that the need for a blowdown is subject to several factors including the ability of heat
retention of the insulation, flowline pressure and the thermal energy available in pipeline system.
5.0 Conclusion In conclusion it was determined that the suitable diameter for the pipeline was 292 mm, despite 343 mm also satisfying the requirements, it was noted that the lesser diameter would reduce overall costs. Using the API RP 14E standards it was revealed that the pipeline would experience no erosion, meeting the requirements of task 2. The temperature hydrate formation would occur at was 12 °C, however the pipeline parameters were not acceptable regarding wax deposition, therefore the U value was adjusted to 0.5 5 W∙m2 °C- . Using the 1
adjusted U value, the thickness of insulation was calculated to be 14.6 mm. The Scott, Shoham and Brill method revealed that the calculated slug volume within the system was lesser than that of the 8.5 m3 requirements. Regarding the change in component volumes, the pressure within the system was reduced to below the minimum 10.3 bar, indicating the need for gas lift to allow the pipeline to continue flow. It was also established that with regard to the operational modes of well start up and shut in, consideration is needed over the finalisation of the pipeline system, specifically hydrate formation. It was also noted that this could possibly be prevented in the shut in mode using blowdown, however this method is subject to various factors which can also influence how vulnerable the pipeline will be to hydrate formation.
6.0 References [1] Statoil, 2007. About Flow Assurance. [online] Available at: [Accessed 5 April 2015] [2]Microtherm, 2015. Izoflex, Very Best Pipeline Insulation of 21st Century. [online] Available at:< http://www.microthermgroup.com/low/EXEN/site/adv_pipelines.aspx> [Accessed 7 April 2015] [3]Rigzone, 2015. How Does Artificial Lift Work?. [online] Available at:< http://www.rigzone.com/training/insight.asp?insight_id=315&c_id=4 > [Accessed 6 April 2015] [4] Bai, Q., Bai, Y., 2005. Subsea Pipelines and Risers. 1st ed. London. Elsevier.
Appendix A -Erosion The equations used in task 2 for establishing the erosion of the pipeline are as follows. Conforming to API RP 1E standard: V m∗¿
1.22∗C ρm
[1.1]
However, ρm is not known and also must firstly be calculated along with λl before equation 1.1 can be solved. Firstly λl must be calculated which is done through the use of: λ L=
Vsliquid ( Vsliquid +Vsgas )
[1.2]
Vsl and Vsg are the superficial velocities of both the liquid and gas respectively, values which are produced from the PIPESIM model output file. The next step in the procedure is to determine ρm which is completed
through the equation: [1.3]
ρm=λl∗ρ liquid + ( 1− λl )∗ρgas Equation 1.1 can now be performed that all the input values are known, Vm* is the maximum allowable mixture erosional velocity, of which is used in the criterion for no erosion. However to use the equation for the criterion Vm must also be calculated, which is done through the simple equation of: [1.4] Vm=Vsliquid+ Vsgas The task is then completed by using the equation as follows to satisfy the criterion for no erosion within the pipeline: Vm∗¿<1 Vm ¿
[1.5]
The result of using such equations are presented in tables 1, 2 and 3, which reveal each calculated value throughout the 0.25 m intervals of the riser, flowline 1 and 2.
Table 1(Erosion Calculation Results- Riser)
Appendix A- Erosion
Table 2(Erosion Calculation Results- Flowline 1)
Table 3(Erosion Calculation Results- Flowline 2)
Appendix B- Hydrate Formation To complete task 3 the Katz method was used to determine at what temperature hydrate would form within the model. The equation used for the Katz method is as follows: i=n
∑ ¿ Ky i=1
=1
[2.1]
VS
The equation 2.1 is used to provide a value to equal one, once successfully completed this produces the temperature at which hydrate formation will occur within the pipeline. The values for y are that of the mole fractions which are obtained from the PIPESIM model, Kvs values are those extracted from the hydrate K value graphs. The process involves trial and error, a temperature is used to extract K values from the graph and then implemented into equation 2.1 until the final produced number is equal to 1. With regard to pipeline, 10 °C was first tried but was not successful, it was found that 12 °C was closely accurate to one, therefore hydrate formation would occur at this temperature. In table 4 the produced results from the calculation are revealed, accompanied with the mole fractions which are extracted from the output file of PIPESIM.
Table 4(Katz method, Calculation Results)
An example of the hydrate graphs used to attain the K values are also provided in tables 5 and 6, where temperature is along the x axis and pressure on the y axis respectively. It should be noted that individual graphs are used for each separate component such as methane ethane etc.
Appendix B- Hydrate Formation
Table 5(Methane K Value Hydrate Graph)
Table 6(Ethane K Value Hydrate Graph)
Appendix C- Insulation Configuration The equation used for the configuration has different derivations, however because the U value
is
below
1,
the
correct
derivation
can
be
selected
as
shown.
[3.1]
As it is the thickness of insulation which is desired, equation 3.1 is rearranged to solve for the parameter r1, which is shown in equation 3.2. r 1=rp∗e
(
k1 ) U ∗rp
[3.2]
To establish the thickness of insulation, r1 is then subtracted from rp, where rp is the inner radius of the pipe, and r1 is the outer radius respectively. Figure 15 below shoes what each value within equation 3.2 represents regarding the pipeline.
Figure 15(Equation 3.2 Representation)
Appendix D- Slugging It is specified that at the 1st stage separator the maximum capacity for slugging is 8.5 m 3, therefore the empirical formula of Brill et al. (1981) is used to determine the slug length within the pipeline. Equation 4.1 is the formula of Brill et al. (1981) as follows: [4.1] The slug length is represented by L m, which is the parameter desired. D is pipe diameter where um is mixture velocity. As all the values are known they are then inserted into equation 4.1, however both the diameter and mixture velocity were initially in metric units but were converted to imperial as specified by the formula. Once calculated in imperial units, the results were then again converted into metric units, where the produced slug length was multiplied by the pipe area to provide the total slug volume of the pipeline. Tables 7, 8, 9 and 10 show the calculated results both for the 4 well flow and 1 well flow, accompanied with the total slug volume of both.
Table 7(Flowline 1 Slug Length Results)
Appendix D- Slugging
Table 8(Flowline2 and Riser Slug Length Results)
Table 9(Flowline 1 & 2 Slug Calculation Results - 1 Well)
Table 10(Riser Slug Calculation & Max Slug Volume)
Appendix E- Pressure Firstly each individual component had to be changed from their original value to 10% of that value, table 11 shows each component and the new values assigned in accordance to the specification. As well as reducing the original components to 10%, water was added and made 90% of the fluid being extracted from the well. Figure 15 shows the pressure drop due to the change in fluids produced, which results in the need for gas lift to maintain the flow within the pipeline.
Table 11(Individual Component Assigned Values)
Figure 16(Pressure Drop)
