Electric Heating for Hydrate Prevention in an Arctic, Single-Line

Article pubs.acs.org/jced

Electric Heating for Hydrate Prevention in an Arctic, Single-Line Tieback Douglas Turner,* Jonathan Dubois,‡ Ronald Bass,‡ Tyler Hamilton,‡ John Howlett,‡ and David Greaves‡ ExxonMobil Development Company, 22777 Springwoods Village Parkway, Spring, Texas 77389, United States ABSTRACT: This paper proposes a mechanism for safe single-line tieback operation in arctic waters. Owing to arctic currents in this area, the seafloor can drop to subzero temperatures, leading to flow assurance challenges such as hydrate and wax deposition. Pipe-in-pipe insulation will prevent hydrate formation under normal production, and depressurization will maintain conditions close to hydrate formation. To prevent hydrate formation during restart, subsea electric heating will be applied to the production pipeline. Electric heating technology will significantly reduce displacement fluid and inhibitor requirements. Additionally, wax management in a single-line tieback will be enabled through the use of electric heating. Electric heating is a new technology to ExxonMobil for subsea application, with only one previous pilot to date. Melting a hydrate blockage with electric heating is a potential safety concern, and considerations for an intrinsically safe design for the heating technology are included in this work.

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INTRODUCTION When considering flow assurance challenges, gas hydrate and wax issues are among the most common. Although the temperature at the seafloor is fairly uniform around the globe, in some regions cold currents originating from arctic ice melting can cause these temperatures to be subzero. Under those conditions, managing hydrate and wax becomes increasingly difficult. Additionally, design of a single-line tieback (i.e., a single pipeline connecting a subsea well development to a production platform) represents a particular flow assurance challenge, since it does not readily allow for more traditional methods for wax removal (such as pigging, where a solid device, typically made of hard rubber, is propelled through a pipeline to scrape solids from the pipe walls) or hydrate management (such as pipeline displacement with a stabilized fluid that cannot form hydrate or dual-sided depressurization to melt a hydrate). This work details a design developed for a subarctic case example, where economics, remoteness, or other constraints have limited the development to a single-line tieback. Pipeline electric heating has been incorporated into the design to help manage the challenges associated with hydrate and wax. Because of the large amount of gas uptake by hydrates, electric heating presents some safety concerns,1 and an “intrinsically safe” hydrate melting analysis is included to demonstrate under what conditions a heated hydrate blockage is potentially hazardous.

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Table 1. Field Study Properties property ambient temperature hydrate formation temperature at shut-in pressure wax appearance temperature wax dissolution temperature distance from the host water depth gas lift rate/well gas to oil volume ratio at standard conditions

41 °C 52 °C 7.5 km 100 m 1.0 m3/s at 101.325 kPa and 15 °C 712 m3/m3 at 101.325 kPa and 15 °C

It can be seen that the design is not a deepwater development, but does experience subzero temperatures. The case field layout is shown in Figure 1. In particular, the facilities include a production platform with single 6-in. (152.4 mm) inner pipe in 10-in. (254 mm) outer pipe in a pipe-in-pipe arrangement (i.e., “6×10 PIP”) with electric heating capability, and an umbilical service line for supplying power/control, lift gas for assisting production flow, chemicals to prevent hydrates and other flow assurance problems, displacement fluids to the subsea equipment, and depressurization, if needed. Special Issue: In Honor of E. Dendy Sloan on the Occasion of His 70th Birthday

DESIGN CONDITIONS AND CONSIDERATIONS

Received: July 1, 2014 Accepted: October 16, 2014 Published: October 31, 2014

For the subarctic case design, the field conditions in Table 1 were assumed. © 2014 American Chemical Society

value unit −2 °C 21 °C

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dx.doi.org/10.1021/je500608y | J. Chem. Eng. Data 2015, 60, 356−361

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the gray operational curve in Figure 3, in which the fluid temperature TR and pressure PR at the riserbase is presented.

Figure 1. Field layout of a single-line tieback in the arctic

Figure 3. Start-up riserbase temperature TR and riserbase pressure PR curves for the (black line) heated and (gray line) nonheated systems, with arrowheads indicating the direction of the curves with time during start-up: (red dotted line) hydrate formation curve; (blue filled circle) initial shut-in condition.

During normal conditions, the warm fluids and 6×10 PIP insulation keep the production out of the hydrate formation condition without the need for active continuous heating or chemical injection. During shut-in, in which production flow in the pipeline stops, the ambient temperature will cool the pipeline system. In this work, the hydrate subcooling is defined as the hydrate formation temperature minus the system temperature, such that a positive hydrate subcooling represents a hydrate-stable condition. Figure 2 shows the simulated hydrate subcooling

The heating system can be used prior to restart to prewarm the pipeline system, thereby avoiding hydrate formation. This is illustrated in Figure 3 as the black operational curve, which first warms the line before increasing pressure. Following heating, upon restart, pressurization and cooling occur from cold wellfluids and some Joule-Thomson (JT) cooling due to depressuring a gas-loaded well, but conditions are maintained above hydrate stable conditions. Should a hydrate blockage occur, because of inadequate heating during start-up, a potentially hazardous condition occurs where the hydrate blockage could be heated. One practical method to prevent heating of the hydrate is to impose design interlocks which disengage electric heating if a particular minimal pressure drop through the pipeline cannot be maintained, indicating a complete blockage condition, and if the boarding valve to the platform is not opened to allow for gas expansion. A second method is to model a heating system with a conceptual hydrate blockage sufficiently to understand potential isolation scenarios, including potential effects from uneven heating, and the impacts on the system. This type of modeling can be very difficult to undertake, particularly on a field-by-field case. A subset of the modeling approach is to ensure an intrinsically safe design, where any hydrate melted in the system, if isolated, could not result in a rupture. Wax Mitigation. In addition to hydrate prevention, electric heating is an enabling technology for single-line tiebacks as it provides the ability to remove wax from the pipeline without requirement for a looped pipeline for pigging or other pigging facilities. In this case, wax deposition was observed only in the riser section of the pipeline, toward the production platform.

Figure 2. Hydrate subcooling, ΔT = hydrate formation temperature minus system temperature, at the (black line) wellhead and (gray line) riserbase locations with time, t, following a shut-in event.

trend (estimated by a proprietary model based on the van der Waals and Platteau method for determining hydrate equilibria of a gas mixture with density of 0.833 kg/m3 at 101.325 kPa and 15 °C) at the riser base (i.e., the point at the bottom of the production platform, just before the vertical pipeline ascent) and well head (i.e., the subsea location where the pipeline system is connected to the producing well) upon shut-in assuming a depressurized, gas-filled pipeline system. In this case, although the hydrate condition is approached, hydrate stability is never achieved. In the figure, a temperature safety margin has been applied, so that there is some confidence that actual hydrate conditions will not be breached. The result in this case is that no electric heating is required to prevent hydrates during shut-in. Hydrate Mitigation. Although hydrate conditions were not quite achieved in a depressurized, shut-in system, start-up would cause rapid pressurization of the fluids, pushing the operation into the hydrate stable region. This is illustrated in

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COMPUTATIONAL METHODS Three heating modes were determined for the heated system: Mode 1, heating prior to cold restart; Mode 2, heating during shut-in, to maintain safe restart temperature; Mode 3, heating for melting wax. 357



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based resistance through insulation and outer steel with ocean currents is shown below:

Each heating mode represents a different transient process. The power required for each mode was modeled with spreadsheet analysis. Additionally, a method was developed to determine design considerations for intrinsically safe heating. Mode 1: A common mode of heating in systems where hydrate conditions do not occur during normal production is to heat the pipeline prior to restarting the pipeline. This allows the pipeline to be shut-in for an indefinite time period prior to restart. In this case, shown in Figure 2, the pipeline remains outside of the hydrate condition during shut-in; however, other cases, where the hydrate condition is breached, may also be able to benefit from cooling and preheating. This is due to the fact that hydrate is an interfacial phenomenon,2 and during a shut-in hydrate formation is restricted because of the limited mass transfer across stagnant layers3 and also because of the limited amount of required hydrate components in a system where gas or water are not continuously supplied. For example, hydrate formation requires sufficient gas that it would fill approximately 180 volumes at standard conditions to one volume of water;1 therefore, a complete hydrate blockage would require near complete water filling in a pipeline, which would severely limit the quantity of gas required for hydrate formation in these areas. Likewise, a gas-rich section may form hydrate, but not be sufficient to form a blockage during shut-in since gas would still have the ability to channel above the liquid to other parts of the pipeline. In this mode, the heat power requirement, Q̇ , is a function of heating time, t, and can be approximated by the following expression: Q̇ =

UI − o =

Q̇ =

2πLrI − o UI − o(Th − Ta) ε

( ) + LN( ) ⎤⎥

LN

ksteel

rO − i r I−o

k insulation

⎥⎦

(3)

2πLsrI − o UI − o(Tf − Ta) − ṁ f Cpf (Tf |IN − Tf |OUT ) ε (4)

In this expression, ṁ f is the mass flow rate of the fluid and the fluid temperature is assumed to be approximately the average temperature between the inlet and outlet fluid temperatures, Tf|IN and Tf|OUT, across the pipe section length, Ls. As Ls becomes small, the approximation for Tf is improved. Therefore, a discretized analysis of the pipeline is used. In a flowing system, this temperature should be above the wax dissolution temperature in the locations that contain wax. Intrinsically Safe Hydrate Melting. A condition was determined where hydrate melting is considered intrinsically safe. This is a condition where the design of the system is adequate to contain the pressure evolution of any amount of hydrate dissociation within the system. In this scenario, the heating rate is no longer a contributing factor, and therefore, a system is considered intrinsically safe because it can be melted at any rate. To perform the analysis, the worst case conditions were assumed, namely, (1) a totally nonporous plug which fills the entire volume of the container (2) full guest molecule occupancy of hydrate cages, with a Structure II hydrate for greater gas evolution. Structure II hydrate is more conservative than Structure I since there are more gas molecules per water molecule when cages are fully occupied (i.e., 1:5.67 vs 1:5.75 gas to water molecules, respectively);4 (3) total containment of the melting plug, with no gas migration out of the system (such as in localized heating). The analysis was derived by considering the gas law to model the pressure, P, that the gas from a hydrate would exert if contained in the available volume, Vgas after release from melting hydrate:

(1)

In this expression, ρf, ρp, Cpf, and Cpp are the densities and heat capacities of the fluid and pipewall, respectively. Additionally, rI−i and rI−o are the inner and outer radii of the inner pipe, L is the length of the pipe, and ε is the heating efficiency. Generally for this work, heating efficiency was assumed to be 100 %. This expression accounts for warming the fluid in the pipeline (the first term in the brackets) and warming the inner pipeline (the second term in the brackets). It also assumes that because of the efficient pipe-in-pipe insulation, heat loss to the environment during heating is negligible. Because either warm-up time or heat can be specified, a sensitivity of heat required to achieve various warm-up times was performed. Mode 2: One operational consideration is the option to maintain low level heating during a planned shut-in, either to prevent a hydrate condition during shut-in, or as in this case, to allow for more rapid restart. In this mode the heating power required to maintain the fluid temperature at the desired hold temperature, Th, is given by the following expression: Q̇ =

rI − o

rO − o rO − i

In the expression, ha is the heat transfer coefficient of the ambient seawater, ksteel is the thermal conductivity of the outer steel wall, while kinsulation is the effective thermal conductivity of all of the insulative layers between pipewalls (e.g., insulation and air gaps). Mode 3: To remove wax from the pipeline, the walls can be heated to above the wax melting temperature while flowing or stagnant. Heating while flowing is only effective at locations where the heated pipewall temperature exceeds the wax dissolution temperature, which may not be possible at inlet sections of a pipeline; in these cases, shut-in heating may be required. Heating times are expected to be shorter than required for full wax melting, since wax heating and melting at the walls should cause the remainder to separate from the wall and to slough. Heating analysis and results are presented here to illustrate the relative heating requirements for wax mitigation versus hydrate prevention; in particular, the operation for raising the temperature of the flowing system to the wax dissolution temperature is included. The respective expression follows:

π L (Tf |HOT − Tf |COLD ) ε·t × [ρf Cpf rI2− i + ρp Cpp (rI2− o − rI2− i)]

⎡ ⎢1 + ⎢⎣ ha

(2)

In this expression, UI‑o is the overall heat transfer coefficient of the PIP system, based on the outer radius of the inner pipe (i.e., rI‑o). To determine UI‑o, a heat resistance model of the outer layers is developed. An example of overall heat transfer coefficient358


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ZngasRT Vgas

melting for gas to migrate into, and represents the conservative scenario. Also note that there is an assumption to this result of constant Z-factor. Z is generally a function of pressure and temperature. To improve the result, multiple virial expressions exist to account for these dependencies. Also, since the composition of gas in a hydrate typically differs from the composition of the gas from which it formed,5 it is important to use the composition of gas that evolved from the hydrate when determining the Z-factor. For natural gases released from a hydrate, the Z-factor will be less than unity except at very high temperatures, on the order of 130 °C (derived using hydrated gas compositions from CSMGem and from Katz curves).6,7 Since the evolved gas pressure is directly proportional to the Z-factor, a constant Zfactor of 1 (i.e., an ideal gas) represents a conservative case except under extreme heating conditions.

(5)

In the equation, Z is the gas compressibility, ngas is the moles of gas contained in the volume, R is the gas constant, equal to 8.314 J/(K mol), and T is the system temperature. In a perfectly contained system, with no initial void space, the volume that the gas can occupy after some of the hydrate has melted is the difference between the initial volume of melted hydrate, Vhyd, and the respective volume of melted water, Vwater, so that the following holds: P=

ZngasRT (Vhyd − Vwater)

(6)

This concept is illustrated in Figure 4, where an initial volume of complete hydrate, is stoichiometrically dissociated

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RESULTS AND DISCUSSION Heating Rate. The required heating powers for the three modes of heating operation are presented for the case design. The sensitivity for reheating a cooled pipeline is shown in Figure 5. Figure 4. Illustration of a pipeline cross-section during the dissociation of a nonporous and completely contained hydrate.

into water and gas. With incompressible water, the gas must be compressed in the remaining space. In the illustration, the volume of the gas is exaggerated, since actual respective volume would be difficult to discern. Recognizing the relationship between volume, density, and molecular weight, the following relation can be arranged: ⎛ ngas ⎞ ρhyd ZRT ⎟⎟ P = ⎜⎜ ⎝ nhyd ⎠ MW ⎛⎜1 − Vwater ⎞⎟ hyd ⎝ Vhyd ⎠

(7)

Figure 5. Total heating power for the case study pipeline, Q̇ , and heating power per unit length, Q̇ /L, required as a function of warm-up time, t, from a shut-in pipeline condition at the minimum cooldown temperature.

Also, a relationship between the volume of water and volume of hydrate can be developed in terms of hydrate and water densities, molecular weights, and numbers of moles. These are identified as ρhyd, ρwater, MWhyd, MWwater, nhyd, and nwater, respectively: ρhyd m water ρhyd MWwatern water Vwater = = Vhyd ρwater mhyd ρwater MWhyd ·nhyd (8)

Heating power required for operating Modes 2 and 3 are shown in Table 2. It can be seen that levels of heating required for maintaining temperature during a shut-in are much lower than those required for heating a cold line or for melting wax.

Simple substitution leads to the following final expression: ⎛ ngas ⎞ ρhyd ZRT ⎟⎟ P = ⎜⎜ ⎝ nhyd ⎠ MW ⎛⎜1 − ⎜⎛ n water ⎟⎞ ρhyd ⎜⎛ MWwater ⎟⎞⎞⎟ hyd ⎝ nhyd ⎠ ρwater ⎝ MWhyd ⎠⎠ ⎝

( )

Table 2. Heating Power, Q̇ , and Power per Unit Length, Q̇ / L, Required for Heating Modes 2 and 3

(9)

The most striking feature of this outcome is that every parameter on the right-hand side of the equation is approximately constant with heating, except for temperature, indicating that pressure increase is not a function of how much hydrate is melted. Although this may seem counter-intuitive, this is due to the stoichiometric ratio of the original system volume (hydrate volume) to the water volume released, which is independent of the quantity of hydrate melted. Note that this is only true for a system with no void space prior to hydrate

heating mode

Q̇ /kW

(Q̇ /L)/(W/m)

Mode 2 Mode 3

57 235

8 32

In this case, the power required was dictated by the wax melting operation. However, lower levels of heating are typically required for shut-in wax melting, which was not performed in this study. With the available power for wax melting of 235 kW, a respective shut-in warm-up time would be 19 h. Intrinsically Safe Melting. Figure 6 and Figure 7 show how a hydrate would melt in the worst case plug system, where 359



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and hydrate equilibrium curves cross); at this condition, hydrate will melt at a rate proportional to the heat input, which provides the latent heat of hydrate melting. Eventually, all of the hydrate will be melted, and the gas will respond to temperature as a freed gas. Figure 7 is an illustration of how the temperature and pressure both plateau during constrained hydrate melting. The intrinsically safe design consideration was a system that could contain the pressure of the released hydrate. Additionally, a margin could be added for the further heating of a constrained free gas system. In the case shown in Figure 6, for a heating system that was limited to below a 40 °C temperature, the intrinsically safe design would be a system pressure rating of greater than ∼80 MPa.

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CONCLUSIONS Electric heating technology can enable a reduced subsea kit in arctic regions, including a move to single-line tiebacks and reduced inhibitor chemical usage. The heating power required to sustain a planned shut-in system is typically minimal compared to general requirements for thermal ramp-up or wax melting. An intrinsically safe design considers the maximum pressure that could be achieved by a confined, nonporous hydrate melting. In this scenario, the pressure evolution is not a function of how much hydrate is melted. Also, no hydrate would melt until the intrinsically safe pressure is obtained. The intrinsically safe pressure is a strong function of the hydrate formation curve and will vary for any particular gas composition, and as a result, will be project dependent. An actual hydrate blockage is generally expected to produce lower overall pressure than the intrinsically safe condition since there will typically be gas void spaces prior to hydrate melting that freed gas can populate. It should also be noted that although the intrinsically safe design in this work considers gas pressure containment from a melting plug, it does not address plug run-away. Plug run-away can occur if there is a significant pressure differential across a blockage and it dislodges from the pipewall, resulting in a highmomentum projectile.1

Figure 6. (Red dotted line) pressure, P, and temperature, T, evolution from an initially subcooled nonporous and completely contained hydrate to a dissociated state during heating: (black line) hydrate equilibrium curve; (gray line) liberated gas curve, volume-constrained by original hydrate volume minus liberated water volume.

Figure 7. Temperature, T, and pressure, P, trend during constant rate heating of a nonporous and completely contained hydrate to a dissociated state

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the hydrate is nonporous and remains contained during melting. Such a system is similar to hydrate particles which experience rapid depressurization at near the freezing temperature of ice, which is thought to rapidly create a pressurecontaining ice shell, and has been observed to undergo a selfpreservation effect, where hydrate cannot melt readily under this condition.8 In Figure 6, the operational path for hydrate melting with constant heat input is represented by the dashed path. As the system warms, the hydrate formation temperature is eventually obtained. At this point, the pressure begins to climb; however, no hydrate melts at this condition. This is because any gas released would be in a higher pressure state, represented by the gray line, than in the hydrate phase. This is a special condition where no void space exists prior to hydrate warming for the released gas to occupy. This is an operational period of considerable pressure increase with relatively little heat input. The same temperature−pressure trend during hydrate melting was experimentally reported in a related paper.9 Eventually, a condition will be reached where the gas phase pressure and hydrate pressure are equal (i.e., where the free gas

AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. Author Contributions ‡

J.D., R.B., T.H., J.H., and D.G. contributed equally to this work. Notes

The authors declare no competing financial interest.

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REFERENCES

(1) Sloan, E. D.; Koh, C.; Sum, A. Natural Gas Hydrates in Flow Assurance; Gulf Professional Publishing: Houston, TX, 2011. (2) Freer, Eric Methane Hydrate Formation Kinetics. Master’s Thesis, Colorado School of Mines, Golden, CO, 2000. (3) Davies, S. R.; Sloan, E. D.; Sum, A. K.; Koh, C. A. In-situ studies of the mass transfer mechanism across a methane hydrate film using high-resolution confocal Raman spectroscopy. J. Phys. Chem. C 2010, 114 (2), 1173−1180. (4) Sloan, E. D.; Koh, C. Clathrate Hydrates of Natural Gases, 3rd ed.; CRC Press: Boca Raton, FL, 2008. (5) Eslamimanes, A.; Mohammadi, A. H.; Richon, D.; Naidoo, P.; Ramjugernath, D. Application of gas hydrate formation in separation

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processes: A review of experimental studies. J. Chem. Thermodyn. 2012, 26, 62−71. (6) Ballard, A. L; Sloan, E. D. The next generation of hydrate prediction: Part III. Gibbs energy minimization formalism. Fluid Phase Eq. 2004, 218 (1), 15−31. (7) Katz, D. L.; Firoozabadi, A. Predicting phase behavior of condensate/crude oil systems using methane interaction coefficient. J. Pet. Technol. 1978, 1649−1655. (8) Stern, L. A.; Circone, S.; Kirby, S. H.; Durham, W. B. Anomalous preservation of pure methane hydrate at 1 atm. J. Phys. Chem. B 2001, 105 (9), 1756−1762. (9) Tzotzi, C.; Parenteau, T.; Gainville, M.; Sinquin, A.; Cassar, C.; Turner, D.; Greaves, D.; Bass, R.; Decrin, M. K.; Larrey, D.; Gerald, F.; Glenat, P.; Morgan, J.; Zakarian, E. Hydrate Plug Management: Electrically Trace Heating Pipe in Pipe Full Scale Test. Proceedings of the 8th International Conference on Gas Hydates, Beijing, China, 2014.

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Electric Heating for Hydrate Prevention in an Arctic, Single-Line

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