Operational envelope for planning cold flow production

The paper presents a method to determine an operational envelope for the cold flow technology with respect to producing gas–oil ratio (GOR) and water cut (WC). The cold flow technology is a flow assurance method that enables cold production flow in thermal equilibrium with the seabed temperature. Cold flow converts hydrate and wax into dry, non-plugging microparticles inside a subsea cold flow unit downstream the wellhead. The small particles travel along with the liquid in the form of a slurry to the receiving host. The operational envelope shows that if the production flow reaches certain combinations of GOR and Wc, the hydrate volume fraction in liquid and consequently the slurry’s effective viscosity could be too high for pipe transportation. This paper also investigates the case when the slurry is transported with remaining water, where there might be some emulsion phenomena. Results show that this could reduce the operational region of the cold flow envelope, particularly for GOR–Wc values around the inversion point volume fraction. Therefore, water–slurry emulsification should also be taken into consideration when considering the operational envelope. If the hydrate–oil mixture is found to be too viscous to transport it can be resolved by, for example, removing water from the production flow upstream the cold flow unit. GOR–WC profiles from a real field case are over-imposed on the operational envelope to see the development during the field lifetime. Tieback costs for the cold flow technology are found to be 20–30% less than conventional methods for a 100 km tieback. The relative cost reduction increases with increasing tieback distance.


Introduction
This paper is about the flow assurance technology referred to as "cold flow."The technology has been in development since the 1990s mainly by SINTEF together with other industry partners [1][2][3][4].
The hydrate and wax cold flow technique under study is intended for subsea deployment in oil and gas fields.The technique consists of cooling down reservoir fluids to subsea temperature to purposefully induce the formation of hydrates and wax.Recirculation of hydrate particles (seeding) and localized pipe wall heating are used to ensure efficient formation and uninterrupted flow of a hydrate and wax slurry through the unit and the downstream system [5].
The cold flow technology will enable cold production flow along the seabed without the need of chemical injection or pipeline heating to avoid hydrate and wax problems.The technology has in recent years taken a major step from being in a research phase into a viable subsea solution that can be installed on both existing and new fields.EMPIG AS in Trondheim, Norway, has led this development together with SINTEF and several operator companies.
Lund et al. [1] described the initial cold flow method and system proposed by SINTEF.The proposed system is somewhat more complex than the EMPIG technology and includes several heat exchangers, a reactor and a separator.Lund et al. [2] described in more detail how the inert hydrate particles will form by the recirculation method.Dry hydrate particles from the recirculation line will grow outwards by absorbing free water from the incoming production flow.Remaining water will continue to be converted into hydrates by further cooling of the mixture.Argo et al. [3] described the SINTEF Saturn practical cold flow concept and how the 631 Page 2 of 12 concept can be applied on a producing subsea field.The paper also describes initial experimental tests conducted at SINTEF as well as cold flow process simulations applied on a North Sea field case.Wolden et al. [4] described smallscale laboratory experiments (1-inch flow loop) conducted at SINTEF.Three different oils were tested, and the results showed that the particle suspension was flowing easily at low temperatures (4 °C).The experiments included different values of water cut.Shut-in experiments were conducted to check the slurry stability in case of a shutdown situation.
The objective of this paper is to present a computational method to determine an operational envelope for cold flow production in terms of producing gas-oil ratio (GOR) and water cut (W C ).The resulting envelope can be used for cold flow field planning, for example to determine whether subsea processing is necessary and when the resulting cold flow slurry is transportable in the downstream pipe and the operating pressure of the cold flow unit.The method described focuses mainly on hydrates.
This work uses well-known procedures for modeling hydrate formation and a fluid PVT model that are currently implemented and integrated in commercial multiphase pipe simulators for simulating hydrate transport.The novelty of this work is the use and integration of these elements to estimate the hydrate volume fraction in liquid during the lifetime of the field and the presentation of the results in a graphical format.This makes it easy to understand and use the results and to determine the needs for additional technology and impact on the design of the subsea system.
This study is focused mostly on applications in early stages of development of offshore hydrocarbon fields.The feasibility assessment is therefore preliminary as it considers only the resulting hydrate volume fraction in liquid and slurry viscosity.Other issues such as solid transportability/accumulation and flow pattern in the cold flow unit and downstream pipeline should be also included for a more thorough feasibility studies in later stages of field planning.

Operating envelope
Since the cold flow unit generates inert hydrate particles (non-sticking), in this study it was considered that plugging and agglomeration are not a concern.However, if there are excessive amounts of solid particles in the outlet stream to the cold flow unit, then it will be difficult to transport.
The cold flow operating envelope is computed by calculating the resulting amount of hydrate particles and hydrate volume fraction in the slurry downstream the cold flow unit for several combinations of inlet GOR and W C .Regions where the hydrate volume fraction is above a predefined threshold are flagged as unfeasible.The expected field production GOR-W C profile is then over-imposed on this envelope.If at any time the GOR-W C combination falls on an unfeasible region, this indicates that probably the hydrate slurry will have too high effective viscosity.This indicates that subsea processing must be used (e.g., subsea water separation) to ensure transportability.

Model details
Figure 1 shows a diagram of the cold flow unit.The hydrate cold flow unit receives mass flow streams of gas, oil and water and outputs mass flow streams of gas, oil, water and inert hydrate particles.The hydrate particles at the outlet are dispersed in the liquid phase.
In this work, it is assumed the pressure change in the unit is minimum.The temperature is reduced to a value close to the temperature of the cooling media (seabed water in this case).
The unit could operate in two ways, depending on the inlet conditions: • Water-limited reaction: Most water will be converted to hydrates, and hydrate-forming light components will be leftover.In this case, the resulting slurry will consist of a dispersion of hydrate particles and some salty water in an oil continuous phase.• Hydrate former-limited reaction: Most hydrate-forming light components will be converted to hydrate, and some free water will be leftover.In this case, the resulting slurry will consist of oil-water multiphase flow with hydrate particles in oil, water or both.

Assumptions
• It is assumed that the cold flow unit dissipates the heat generated by the hydrate reaction to the surrounding ambient.• It is assumed there is a fixed (input) stoichiometric relationship between hydrate formers, water and hydrates.This stoichiometric relation is expressed in terms of mass fraction.In this work, it is assumed 0.86 kg of water join with 0.14 kg of hydrate-forming components to form 1 kg of hydrate.• The hydrate formation model does not include the reaction kinetics.• It is assumed that almost all components that end up in surface gas (standard conditions rate q g ) could poten- tially form hydrates.Therefore, the formation of hydrates effectively reduces the surface gas-oil ratio of the hydrocarbon mixture that enters the cold flow unit • It is assumed the salinity of the water is equal to zero • Water dissolved in reservoir gas entering the wellbore is neglected.

Calculations details
Calculations are performed based on 1 Sm3/d of oil.The standard condition volumetric rates of gas and water are calculated from the flowing gas-oil ratio (R p ) and the water cut (W c ).
1.The mass flow rate of surface water and surface gas are calculated using the standard conditions volumetric rates and standard conditions densities.2. The hydrate reaction is computed, assuming that a fraction "F" (in this work, equal to 0.94) of the surface gas converts to hydrates.This gives remaining mass flow rates of surface water, surface gas and hydrates.3. Remaining mass flow rates of surface gas and water are converted back to standard conditions volume rates.4. The standard conditions volumetric rates obtained in step 3 and black oil properties (Appendix 2) are used to calculate local volumetric rates of oil, gas and water (as indicated in Appendix 1) at two locations: a) the outlet of the cold flow unit and.b) at the receiving separator.
Since the temperature in the transportation pipeline downstream the cold flow unit is constant, these two locations give the lower and upper bound of operating pressure and thus the upper and lower bound of fluid volume fractions.5.The local volumetric rates are used to estimate volume fractions of hydrates in liquid.
The procedure described above was programmed into a function (called "cold flow unit" function) that receives as inputs the GOR and W C and outputs: • The hydrate volume fraction in liquid at separator conditions • The hydrate volume fraction in liquid at the outlet of the cold flow unit • An integer indicating whether the hydrate reaction is water-limited or hydrate former-limited • The gas volume fraction at separator conditions • The gas volume fraction at the outlet of the cold flow unit

Operational maps
There are two types of plots generated in this study, 1. Color maps and 2. Envelopes.A brief description of how these two are generated is provided next.

Color map
To produce a color map, the "cold flow unit" function is triggered for several combinations of interest of producing gas-oil ratio and water cut, using a regular grid.The output is recorded for all combinations and plotted on a 2D plot of GOR versus WC.The value of the variable of interest (e.g., hydrate volume fraction in liquid at separator conditions) is shown using a color bar.

Operating envelope
The operating envelope depicts the following boundaries: • A line separating "feasible-unfeasible" operating regions (i.e., a threshold in volume fraction of hydrate in liquid is reached) • A line separating the regions of water-limited reaction versus hydrate former-limited reaction These two boundaries were found using the method of bisection on the "cold flow unit" function.The first boundary was found using as objective the hydrate volume fraction in liquid at separator conditions, while the second boundary was found using the integer indicating whether the hydrate reaction is water-limited or hydrate former-limited.

Software and computational tools employed
The main tool used to perform the calculations presented above and the emulsion viscosity model described later was the programming language python, v 3.8 (using the Webbased interactive programming platform Jupyter Notebook).The correlations for the black oil properties (shown in Appendix 2) were also programmed in python.
The chemical process simulator Hysys V10 (by Aspentech) was used to generate some of the black oil properties and to quality control the thermodynamic and PVT model.

Costs analysis
A cost comparison between alternative flow assurance methods is made to see how the cold flow technology compares with other technologies.Cost estimates for the different technologies are based on flowline cost models from [15] and experience from earlier field developments.

Methods applied on field case
The method is tested on a field case with transport distance to host of about 100 km.The API of the crude is 39.The specific gravity of surface gas is 0.86.Two reservoir recovery strategies are considered: gas injection and water injection.
It is considered that the pressure of the cold flow unit is 110 bara, separator pressure is 15 bara, and the ambient temperature is of 4 °C.These two points fall inside the hydrate equilibrium region.
Figure 2 shows a color map of the hydrate volume fraction in liquid (HVFL) at separator conditions for several combinations of GOR and W c .Regions of high GOR and high W C exhibit the highest values of HVFL.Regions of low GOR or low W c exhibit the lowest values of HVFL.
The cold flow operational envelope is provided in Fig. 3 when using a hydrate volume fraction in liquid (HVFL) threshold of 30%.The blue line separates the region of water-limited reaction (to the left of the line) and hydrate former-limited reaction (to the right of the line).The red line separates regions with HVFL greater than 0.3 (inside the "u") and regions with HVFL lower than 0.3 (outside the "u").
Figure 4 is similar to Fig. 3, but using three values of HVFL at separator conditions: 0.1, 0.2 and 0.3.Results show that if hydrate content tolerance is stricter (e.g., the slurry viscosity increases significantly with hydrate volume fraction) then the feasible area shrinks considerably.
GOR-W C profiles calculated from production data were over-imposed on the operational envelope.Figure 5 shows the results for the gas injection case and Fig. 6 for the water injection case.The results show the cold flow method is most suitable for the gas injection case, since the GOR-W c For the water injection case, several of the GOR-W C points during early field life fall into the region of high hydrate volume fraction in liquid.
Figure 7 shows the value of HVFL at separator conditions for both cases, gas injection and water injection, in time.For the water injection case, there is a period between 2 and 6 years where values are significantly higher than 0.3.
If a subsea water separator is installed upstream the cold flow unit to limit the water cut to 0.2, then it would be possible to operate in the feasible region.The new operational envelope is presented in Fig. 8.

Effective viscosity of the liquid phase
So far, the value of hydrate volume fraction in liquid at separation conditions has been used as a proxy of the transportability of the liquid (oil-hydrate-water mixture).However, it would be more appropriate to estimate its viscosity and rheology.
Unfortunately, untuned hydrate slurry rheology models are usually highly uncertain and have poor predictability [6].Moreover, for conditions where there is water leftover, the hydrate wettability and the dynamics of liquid-liquid flow significantly affect the rheology of the hydrate-oil-water mixture.Usually, extensive laboratory experiments are required to customize models and ensure they have an acceptable accuracy.
In this section, an estimation of the viscosity of the liquid phase is performed using the following procedure and assumptions: • It is assumed hydrate particles remain in the oil and form an oil-hydrate slurry.The viscosity of this slurry is calculated with the equation by Thomas [13] (shown graphically in Fig. 9) • It is assumed the oil-hydrate slurry and the remaining water exhibit an emulsion viscosity behavior as shown in Fig. 10 (Richardson [14]).The inversion point occurs at 0.4 volume fraction of oil-hydrate slurry.The exponent for the slurry continuous region is equal to 2, and for the water continuous region, it is equal to 1.5.It is assumed these values do not change with the oil-hydrate slurry viscosity.
Figures 11 and 12 show color maps depicting the volume fraction of water in liquid at the outlet of the cold flow unit and at separator conditions, respectively.
Figures 13 and 14 show color maps depicting the effective viscosity of the liquid at the outlet of the cold flow unit and at separator conditions for several combinations of GOR and W c .Similar to Fig. 2, the regions with high viscosity occur at combinations of high GOR and high W c .The color map at separator conditions has higher viscosities than the map at the outlet of the cold flow unit and is therefore more restrictive.
Both color maps exhibit a low viscosity region to the right that corresponds to regions where the liquid mixture changes to water continuous (ref.Figures 11 and 12).
Figure 15 shows Fig. 3 over-imposed on Fig. 14.The figure shows if the field planner uses a criterion based on HVFL only, and neglects the formation of water-slurry emulsions, it would not necessarily ensure fluid transportability, especially for regions with W c around 0.5 and GORs around 100, which exhibit a high liquid viscosity.

Presence of gas and transportability of the liquid phase
The amount of gas in the pipe is also an aspect that affects the "transportability" of the hydrate slurry in the pipeline.Usually, high amounts of gas (high gas volume fraction, GVF) at high speed allow to transport viscous liquids efficiently.Figure 16 shows a color map depicting the GVF at the outlet of the cold flow unit for several combinations of GOR and W c . Figure 17 shows a color map depicting the GVF at separator conditions for several combinations of GOR and W C .Locations where the GVF is high could probably transport viscous liquid better.Please note that the presence of gas would not help for regions where there is water leftover and emulsion behavior between water and hydrate-oil slurry since there is no or little gas leftover.

Limitations and further work
The feasibility assessment performed only considers the resulting hydrate volume fraction in liquid and slurry viscosity and therefore should be considered preliminary.This could be sufficient for early phases of field planning of offshore hydrocarbon reservoirs.However, for later stages, it is important to perform a more thorough evaluation and consider other factors such as solid accumulation/transportability and flow pattern in the cold flow unit and downstream pipeline.
The fluid velocity could also affect the feasibility region for the cold flow unit.For example, it will play a role when other aspects are considered in feasibility of cold flow operation, e.g., flow pattern and accumulation/ transport of solids.
The fluid velocities could also play a role in transient operations such as start-up/shutdown and affect the slurry viscosity, e.g., if there is non-Newtonian behavior.
In this work, it has been assumed that the input hydrate stoichiometric relationship always applies.However, research (e.g., [16]) has suggested that there might be some unconverted water inside the hydrate particle.This will probably not affect much the resulting volume fraction of hydrate in liquid for oil continuous systems, but it could have a significant effect for water continuous systems.

Effect of salinity
In this work, it was assumed that the salinity of the water is equal to zero, meaning that all the water is available for conversion to hydrate.
If there is salt dissolved in the water, as water converts to hydrates in the cold flow unit, the remaining free water will become saltier, and the hydrate formation curve will move to the left.This process will continue along the unit until the hydrate formation curve passes through the current pressure and temperature of the fluid.At this point, the hydrate reaction will stop.Salt precipitation might occur, if the salt concentration increases above the maximum solubility of salt in water.
When the pressure is reduced downstream that location, the operating pressure-temperature conditions will exit the hydrate formation region, causing gradually hydrate melting and the movement of the hydrate formation curve to the right.
Therefore, the presence of salt reduces the total available amount of water available for hydrate conversion.The presence of salt will therefore increase the operational region in the cold flow envelope, specifically in the waterlimited region.
An example is shown in Fig. 18.The method described in Appendix 3 is used to compute the salt concentration required to change the hydrate formation temperature from 20 to 4 °C.The result is 34.3 wt%.The available water to convert to hydrates is then calculated using the following expression: where x in is the inlet water salinity and x out is 34.3 wt%.

Hydrate melting downstream the cold flow unit
In this study, it was the case that the pressure and temperature conditions in the transportation pipeline fall inside the hydrate formation region.However, it could occur that, as pressure is reduced in the pipeline, the pressure-temperature conditions fall outside the hydrate formation region, causing hydrate melting.These situations were not studied in this article.However, in these cases, the hydrate volume fraction in liquid will be reduced; thus, the procedure proposed can still be useful as a conservative estimate.This situation could also arise during shutdown if there is a reduction of pressure.
If there is some free water trapped in the hydrate particle, it could exit when pressure is reduced.Larsen et al. [19] discussed the robustness of the cold flow method based on experiments including shut-in and restart experiments.

Cost results
Total costs (CAPEX plus OPEX) for different flow assurance technologies are shown in Fig. 19.The figure shows that the EMPIG cold flow technology [5] has 20-30% less costs than direct electrical heating (DEH) at 100 km.For greater distances, cold flow is more beneficial.The cost difference is mainly driven by lower CAPEX due to the use of a bare pipeline instead of a heated and insulated pipeline.A lower OPEX due to considerably lower energy consumption is also an essential contributor.

Conclusion
Based on a specific input GOR and W C combination, the resulting volume fraction of hydrate solids suspended in the liquid flow downstream the cold flow unit is calculated.Depending on the inlet conditions, the cold flow unit will operate in water-limited mode (gas leftover) or hydrate former-limited mode (water leftover).By using a predefined threshold on the maximum allowed hydrate volume fraction in the flowing liquid (HVFL), an operational map with respect to GOR and W C can be determined.If a GOR and W C combination gives a hydrate volume fraction greater than this threshold, the resulting cold flow slurry is considered as too viscous to transport.The method applied gives a U-shaped feasible region in the GOR/ W C operational map.The feasible region increases with increasing hydrate volume fraction in liquid threshold.GOR and W C profiles belonging a field case are plotted on the map, and corresponding measures (e.g., water separation) can be determined from the method.
In case of water leftover, the oil-hydrate slurry and the remaining water could potentially form an emulsion and exhibit increased effective viscosity.By using an emulsion viscosity model, one can investigate the viscosity effects around the emulsion inversion point.Emulsification can reduce the cold flow operational region.
The use of cold flow technology introduces significant cost reductions compared to conventional flow assurance methods.

Fig. 1
Fig. 1 Block diagram of the hydrate cold flow unit

Fig. 2 Fig. 3 Fig. 4
Fig. 2 Color map depicting hydrate volume fraction in liquid at separator conditions, i.e., 15 bara, 4 °C, for different combinations of GOR and W C

Fig. 9 Fig. 10 Fig. 11 Fig. 12
Fig. 9 Plot depicting the ratio between effective viscosity of an oilhydrate slurry and oil viscosity versus the hydrate volume fraction in the slurry

Fig. 13 Fig. 14 Fig. 15 3 Fig. 16
Fig.13 Color map depicting effective liquid viscosity at the outlet of the cold flow unit for several combinations of GOR and W c .The upper limit of the viscosity color bar has been set to 200 cP

Fig. 17 Fig. 18
Fig. 17 Color map depicting gas volume fraction at separator conditions (15 bara, 4 °C) for several combinations of GOR and W C

Fig. 22
Fig. 22 Plot of solution gas-oil ratio (R s ) versus pressure for a temperature equal to 4 °C