Modeling of Hydrate Blockage in Gas-Dominated Systems - American

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Modeling of hydrate blockage in gas-dominated systems Zhi-yuan Wang , Yang Zhao, Baojiang Sun, Litao Chen, Jianbo Zhang, and Xuerui Wang Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b00521 • Publication Date (Web): 09 May 2016 Downloaded from http://pubs.acs.org on May 17, 2016

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Modeling of hydrate blockage in gas-dominated systems Zhiyuan Wang*, Yang Zhao, Baojiang Sun*, Litao Chen, Jianbo Zhang, Xuerui Wang Offshore Petroleum Engineering Research Center, School of Petroleum Engineering, China University of Petroleum (East China), Qingdao, 266580, PR China

HIGHLIGHTS

A coupling model was proposed to predict hydrate blockage in gas-dominated systems.

For annular flow, hydrate blockage mainly ascribes to hydrates formed in liquid film.

This work can help locate the most vulnerable position of hydrate blockage.

Simulation study indicates that the under-inhibition method is recommendable.

ABSTRACT Field experience indicates that hydrates formed in pipelines/wellbore may result in severe conduit blockage and other safety problems in oil/gas development. For gas-dominated systems, one key step to address the hydrate problems is the coupling of multiphase flow and hydrate behavior (formation, deposition, etc.), which has not been well studied so far. In this paper, a hydro-thermo-hydrate coupling model for gas-dominated system is developed by considering the interactions between multiphase flow and hydrate occurrence which is described as layer growth from hydrate deposition on the wall. The accuracy and reliability of the proposed model have been verified with field and literature data. By using the new model, hydrate formation and deposition during deepwater gas well testing operations are simulated. For a typical deepwater gas well (water depth ~1500 m, gas production rate ~50×104 m3/d, liquid holdup ~3%, without inhibitors), it takes 30 or more hours for hydrates to block the testing tubing. The hydrate blockage can be significantly promoted by the presence of a free water phase and postponed by the injection of inhibitors. The proposed model makes it possible to predict when and where hydrate blockage will occur in the tubing during a deepwater gas well testing. This work adds further insights into characterizing the

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interactions of the complicated systems and provides guidance for hydrate management optimization.

1. INTRODUCTION Gas hydrates are crystalline compounds in which water molecules formed cage-like structures trap guest molecules at high pressures and low temperatures.1 Hydrates can play an important role in various applications, including CO2 capture, energy storage, gas separation, etc. Naturally occurring gas hydrates are supposed to be one of the most promising alternative energy sources.2,3 However, hydrates formed in oil and gas pipelines may cause conduit blockage and pose significant operational and safety hazards.4 Thus hydrate formation and blockage are one of the major issues in flow assurance as more offshore oil and gas fields are developed, especially in deepwater regions, where high pressure and low temperature conditions are highly in favor of hydrate formation. Conventional thermodynamics-based hydrate prevention strategies, including insulation of pipelines and injection of thermodynamic hydrate inhibitors (THIs), such as methanol (MeOH) and mono-ethylene glycol (MEG), are economically infeasible and/or environmentally unacceptable.4,5 The flow assurance community has gradually moved towards risk management strategy, in which gas hydrates are allowed to form under control–i.e. by injection of kinetic hydrate inhibitors (KHIs) or anti-agglomerants (AAs)–without plugging the flowlines.5 A crucial step for hydrate management is to predict when and where hydrate blockage will form in the pipelines/wellbore.5,6 For gas-dominated flow systems which is characterized by a continuous gas phase with minor volume fraction of liquid phase such as condensate hydrocarbon and water, hydrate deposition on the pipe wall is suggested to be the controlling mechanism for hydrate blockage.7 Linglem et al.8 proposed that water molecules and gas molecules would diffuse to the cold pipe wall, form subcritical nuclei, and then grow into crystals, which was the initial crystallization period. The hydrate crystals continued to grow as the water and gas molecules diffused to the crystal surface. These were key mechanisms of hydrate deposition in gas-dominated systems, analogous to a freezing water pipeline. They also proposed a four-stage conceptual mechanism to describe the formation of hydrate


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blockage. Dorstewitz and Mewes9 conducted the first gas-dominated flowloop investigation (horizontal pipeline, length ~2 m, inner diameter = 15 mm, liquid holdup = 26%). They suggested that hydrates would form and deposit on the wall, forming a hydrate layer. During a field test on gas systems in 2002, a steady pressure drop was observed, followed by a rapid pressure drop decrease, indicating hydrate deposit buildup and release in the pipeline.10 Hydrate deposition onto the pipe wall was further confirmed by Nicholas et al.11 in a single pass flowloop investigation for saturated condensate systems. Rao et al.12 experimentally investigated hydrate deposition in water saturated gas systems and proposed that hydrate deposition mainly went through three stages, that is, initial crystal growth, hydrate growth period and hydrate annealing. Several recent gas-dominated flowloop studies also provided evidence for the hydrate deposition mechanism, including annular flow investigations by Di Lorenzo et al.13,14,15 with liquid volume fraction 5 to 6%, and stratified flow investigations by Sinquin et al.16 in which the liquid volume fraction was about 22%. The hydrate behavior (formation, deposition, etc.), hydrodynamics and heat transfer in the flow systems are inter-coupled.5,6 First of all, the pressure and temperature distribution is the dominating factor for hydrate formation.1 The spatial distribution and contact of the gas and liquid phases also affect the hydrate formation15, and the presence of free water phase is critical for hydrate deposition.17,18 Moreover, velocities of different phases play an important role in the deposition of hydrate particles. Conversely, the hydrate behavior also significantly impacts multiphase flow and heat transfer characteristics. The addition of hydrates changes the system from gas-liquid flow to gas-liquid-solid flow.19 Hydrate deposition and growth on pipe walls narrows the effective conduit diameters and increase the surface roughness7,8,20, causing a pressure drop increase, as observed by many researchers11,13,14,15,16,20. Furthermore, hydrate crystallization is exothermic1. The latent heat increases the system temperature and impacts further hydrate formation if the heat cannot be effectively removed away to the ambience. The deposited crystals grow and form a hydrate layer on the pipe walls, resulting in a growing heat transfer restriction and slowing down


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the heat transfer process.9 A model coupling the hydrodynamics, the heat transfer, and the hydrate behavior of the flow systems can serve as a useful tool for the prediction of hydrate blockage. In the past decade, a hydrate kinetics model, CSMHyK, has been developed by the Center for Hydrate Research at Colorado School of Mines and incorporated in the commercial transient simulator OLGA.21 The CSMHyK mainly focuses on oil-dominated systems, where the oil is the continuous phase and particle agglomeration is the main cause for hydrate blockage.6,7,22,23 Zerpa et al.19 studied the interactions between hydrate formation and flow regime for gas-water-hydrate systems. However, they studied a high liquid volume fraction system (e.g. bubble, slug and stratified-wavy flow), in which hydrate blockage mechanism is substantially different from that for gas-dominated systems. Nicholas et al.20 and Rao et al.24 proposed a hydrate/ice deposition model for systems which were initially without free water phase based on the analogy between hydrate deposition and wax deposition. However, the hydrodynamics and hydrate formation and deposition are significantly different when free water phase is present. Several recently conducted flowloop investigations13-16 shed new light on hydrate behavior in gas-dominated systems and can help achieve a better understanding of the complicated systems. It has been observed that hydrate formation rate in gas-dominated systems is much higher (about 250 times) than that in oil-dominated systems, and not all the formed hydrates deposit on the pipe walls. In this work, a coupling model, combining hydrodynamics, heat transfer, and hydrate formation and deposition, is developed to predict hydrate blockage in gas-dominated systems. The model is verified with field and literature data and is applied to the prediction of hydrate blockage during deepwater gas well testing operations, in which the pressure and temperature conditions are favorable for hydrate formation. The current main strategy to deal with hydrates is injecting massive MeOH or MEG to keep the systems totally out of the hydrate stability region.25 It is indicated that for a typical deepwater gas well–water depth ~1500 m, gas production rate ~50×104 m3/d, without


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injection of THIs, it takes about 30 or more hours for hydrates to block the testing tubing. This can help achieve an alternative strategy to handle the hydrate associated flow assurance problems.

2. THE COUPLING MODEL For gas-dominated systems, the hydrate behavior, the hydrodynamics, and heat transfer are inter-coupled5,6, as shown in Figure 1. The temperature and pressure conditions are decisive factors for hydrate formation1, and for localization of hydrate stability region (HSR) in the systems. Moreover, the presence of free water phase, as well as the water content, significantly affect the hydrate formation rates11,15,20,26 and deposition behavior17,18. The spatial distribution of gas and liquid phases (i.e. flow pattern) also has an influence on hydrate formation and deposition, so different hydrate formation and deposition characteristics are observed in different flow patterns.13-16,26 The velocities of the gas and liquid phases also significantly affect the hydrate deposition. As velocities become higher, hydrates are more unlikely to deposit on pipe walls.27 Hydrodynamics and heat transfer

(1)

(2)

(1’)

(2’)

(3) Hydrate formation

Hydrate deposition (3’)

(1)-Pressure and temperature conditions, the presence of free water, and gas/liquid spatial distribution; (1’)-Gas and water consumption, the generation of the hydrate solids phase, and the latent heat; (2)-The presence of free water and fluid velocities; (2’)-The continuously growing hydrate layer formed from hydrate deposition (resulting in restriction to flow and heat transfer); (3)-Providing materials for deposition; (3’)-Indirect impact through pressure and temperature conditions.

Figure 1. The inter-coupling of hydrodynamics, heat transfer and hydrate behavior in gas-dominated systems

On the other hand, hydrate formation and deposition also prominently influence the multiphase flow behavior and heat transfer of the systems. In the process of hydrate formation, gas and water are consumed and a new phase– the solid hydrates–is generated. Parts of the formed hydrates are observed to be transported by the gas and liquid


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phases in flowloop investigation.15 Hydrate deposition on the pipe walls narrows the cross-sectional area of the pipelines7-9, thus the pressure drop is dramatically increased.11,13-16,20 Moreover, heat transfer process in the systems is significantly influenced by the exothermic effect of hydrate crystallization1 and the growing hydrate layer formed by hydrate deposits8,9,12,15,20. And in turn, the heat transfer affects the hydrate formation process.9 In addition, hydrate formation and deposition are time-dependent. In this paper, a time-dependent model is developed to describe hydrate formation, hydrate deposition, multiphase flow, and heat transfer in the inter-coupled gas-dominated flow systems. 2.1. Hydrodynamics and Energy Balance Modeling. The transient coupling model is composed of continuity equations, momentum conservation equation, and energy balance equation. The following assumptions are introduced in the development of the model. Multiphase flow and heat transfer in gas dominated systems are presented schematically in Figure 2. (a) It is one-dimensional transient flow in the pipes. (b) The compressibility of the gas is considered, while the densities of the liquid (water) and hydrates are assumed constant. (c) The model is developed mainly for gas-dominated systems, in which the liquid (droplets) and the transported hydrate particles can be assumed homogeneously distributed in the gas phase. And the interphase slippage is neglected. (d) The water is sufficient for consumption during the hydrate formation. (e) The volume of the dissolved gas in the liquid phase is neglected since it is small compared with the total volume of the gas phase.


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vm +

∂vm ds ∂s

p + dp q kh

rf

kt

rti rto

p vm

Figure 2. Multiphase flow and heat transfer in gas dominated systems

(1) Mass continuity equations If the system temperature is below hydrate formation temperature, the initial crystallization will occur, forming hydrate crystals.8 The water and gas molecules further diffuse to the crystal surface, converted into solid hydrates. In this process, water and gas are consumed and an additional phase (the solid hydrate phase) is generated.19 Parts of the formed hydrates will transport along with the gas and liquid phases.13,15 Thus the systems are shifted from gas-liquid two-phase flow to gas-liquid-solid three-phase flow.19 The pipeline is gradually narrowed by a continuously growing hydrate layer formed from hydrate deposits on the pipe walls.8,9 Hydrate formation and deposition are time-dependent, and the gas is highly compressible, making the systems in a transient state. For each segment, ds, the continuity equations for each phase can be expressed as:

In + Gen = Out + Consumed

Where In is the input mass, Gen is the generated mass, Out is the output mass, and Consumed denotes the consumed mass. Hence, continuity equations of the gas phase, the liquid phase, and the hydrate phase are as


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follows28: ∂ ∂t ∂ ∂t

( A ρl El ) +

∂ ∂t

∂

( ρ g AEg ) + ∂

∂s

( Aρ h Eh ) +

( ρ g Avg Eg ) = − xg rhf

(1a)

( Aρl vl El ) = −(1 − xg ) rhf

(1b)

∂s

∂ ∂s

( Aρ h Eh vh ) = rhf − rhd

(1c)

Where E is the volume fraction, the subscripts g, l, and h represent the gas, the liquid, and the transported hydrate phases, respectively, ρg, ρl, and ρh are the densities of the gas, the liquid, and the transported hydrates, respectively, rhf is the mass formation rate of hydrates in unit length of pipeline, kg/(s m), rhd is the mass deposition rate of hydrates in per unit length of pipeline, kg/(s m) (in this work, the SI unit system is used), and xg is the mass fraction of the gas in the hydrates and is defined as follows.

xg =

Mg Mg + N ⋅ MH O

(2)

2

Where N is hydration number1, N = 6, Mg is the molecular weight of gas, kg/mole, and MH2O is the molecular weight of water, kg/mole. The terms at the right hand of eq 1a and eq 1b represent gas and water consumption rates, respectively. The terms at the right hand of eq 1c denote hydrate formation rate (mass source) and hydrate deposition rate (mass sink), respectively. Parts of the formed hydrates will deposit onto the pipe walls and form a growing hydrate layer, which narrows the effective cross-sectional area of the pipeline. And the effective sectional area is defined as A = π r f2

(3)

r f = rti − δ h

(4)

Where rf is the inner radius of the hydrate layer–i.e. the effective inner radius of the pipeline, m, rti is the initial inner radius of the pipeline, m, and δh is the thickness of the hydrate layer, which is assumed uniform within each ds


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increment. The thickness of the hydrate layer is controlled by hydrate deposition rate (see Section 2.3.). (2) Momentum conservation equation Pressure distribution along the pipelines is obtained from the momentum conservation equation. Nicholas et al.20 and Di Lorenzo et al.13-15 calculated the pressure profiles based on the assumption of steady-state flow with the effect of gravity neglected. However, the flow systems are in a transient state as described previously and the neglecting of gravity effect is unreasonable for inclined or vertical systems. Apart from horizontal systems, inclined and vertical systems are also common in oil/gas industry. Thus the transient momentum conservation equation is given as28: −

dp

=

ds

∂ ∂t

( A ρ m vm ) +

∂ ∂s

( A ρ m vm2 ) + A g ρ m cosα + f F

ρ m v m2 2d f

(5)

Where p is the bulk fluid pressure in the pipe, Pa, α is the pipeline inclination above a horizontal plane, and ρm is the density of the mixture, kg/m3, including the gas phase, the liquid phase and the transported hydrate phase. ρm is defined as ρ m = ρ g E g + ρ l El + ρ h E h

(6)

In eq 5, fF is the friction factor which is related to the roughness of the wall surface. Hydrate deposition on the pipe walls significantly changes the surface roughness. In this work, the explicit Colebrook and White correlation29 is applied to calculate the friction factor. In this correlation, the friction coefficient is correlated with the surface roughness and the Reynolds number of the bulk fluid, as presented below.  

 

f F =  −1.737 ln  0.269

ε D

−

2.185 Re

 

ln  0.269

ε D

+

14.5   

−2

  Re   

(7)

Where ε is the roughness of the surface20, m, and Re is the Reynolds number of the bulk fluid. (3) Energy balance equation The hydrate crystallization process is exothermic and is associated with heat exchange1. Meanwhile, the hydrate layer formed from hydrate deposits continuously grows on the pipe walls, resulting in an increasing thermal


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resistance to heat transfer, as confirmed experimentally by Dorstewitz and Mewes9. In turn, hydrate formation can be significantly hindered when the heat cannot be removed from the systems30-32. The heat transfer process is illustrated schematically in Figure 2. Considering the interaction between heat transfer and hydrate formation and deposition in the systems, the energy balance equation is established. For the energy balance equation, the following assumptions are made. (a) One-dimensional radial heat transfer is assumed and heat transfer in the axial direction is neglected. (b) The fluid temperature is the same within the same cross-section. (c) Heat accumulated in the pipe walls is neglected. (d) Heat generated from friction is ignored. (e) The hydrate layer thickness varies gradually in the axial direction and there is no sharp change in cross-sectional area, and the Joule-Thomson effects are neglected. The energy balance equation is: ∂ ∂t

( ρm ACmTf ) +

rhf ∆ h Mh

−

∂ ∂s

(wmCmTf ) = −q

(8)

Where ∆h is the specific hydrate formation enthalpy (J/mole), Mh is the molecular weight of gas hydrates (kg/mole), and Cm is the average specific heat capacity, J/(kg K), defined as C m = ρ g E g C g + ρ l El C l + ρ h E h C h

(9)

The negative sign on the right hand side of eq 8 represents that heat is lost from the system to the environment. The latent heat (the second term on the left hand side of eq 8) is considered as a heat source in the energy balance equation. The heat loss rate from unit length of pipe, q, (W/m), is determined from the following heat transfer equation, q=

1 B

(T f − Tto )


(10)

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Where Tto is the temperature at the outer surface of the pipe wall and is determined by combining the heat transfer with the environment, and B is an intermediate coefficient and is defined as B =

1

(11)

2π rtoU to

Where rto is the outer radius of the pipe. Substituting eqs 9–11 to eq 8 gives the energy balance equation. ∂ ∂t

( ρm ACmTf ) +

rhf ∆h

−

Mh

∂ ∂s

( wm CmTf ) = −2π rtoU to (Tf − Tto )

(12)

The combined heat transfer coefficient, Uto, W/(m2 K), is expressed as33:

−1

U to =

rto rti h f

+

rto ln ( rti rf kh

) + r ln ( r to

to

rti )

kt

(13)

The first term on the right hand side of eq 13 represents the convective resistance at the inner surface of the hydrate layer, and the inner heat transfer coefficient, hf, W/(m2 K), is calculated with the Chilton-Colburn analogy34.

hf =

kc ⋅ Nu f 2rf

= 0.023

kc 2rf

Re4/f 5 Pr1/3

(14)

Where Ref is the Reynolds number, Nuf is the Nusselt number, Pr is the Prandtl number, and kc is the thermal conductivity of the bulk fluid. The second term on the right hand side of eq 13 represents the conductive resistance of the hydrate layer. The heat conductivity of the hydrate layer, kh, is insensitive to the pressure and temperature conditions, and can be assumed to be constant. In this work, we assume the kh to be 0.5 W/(m·K).35 The third term on the right hand side of eq 13 represents the conductive resistance of the pipe wall, which has a high heat conductivity. Hence, this conductive resistance can be neglected. Combine eqs 1, 5, and 12 which represent the multiphase flow, the heat transfer, and the hydrate formation and deposition respectively, a hydro-thermo-hydrate coupling model was developed to characterize the complex process in gas-dominated systems.


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2.2. Gas Hydrate Formation Rates. Gas hydrate formation rate is mainly controlled with three mechanisms: intrinsic kinetics, heat transfer, and mass transfer1. Various hydrate formation models have been proposed and can be divided into different categories according to the controlling mechanisms: kinetics model21,36,37,38, mass transfer limited model39, and heat transfer limited model30-32. For gas-dominated systems, Lingelem et al.8 proposed that hydrates were formed after the water and gas molecules diffused to the cold pipe walls, resulting in a continuously growing hydrate layer, similar to ice formation and plugging in water pipelines. Nicholas et al.11 and Rao et al.12 reported that hydrate formation and deposition in systems without free water were a process of heat and mass transfer, analogous to wax formation and deposition. The presence of a free water phase has a significant influence on hydrate formation in the systems. In a flowloop investigation (the liquid holdup was about 5% and it was annular flow according to Beggs and Brill40), Di Lorenzo et al.15 proposed that hydrates not only formed on the pipe walls (i.e. in the liquid film), but also formed within the entrained liquid droplets, and more strikingly, the major gas consumption was ascribed to hydrate formation within the entrained liquid droplets (about 80% of the total gas consumption). On the contrary, gas consumption in the liquid film only contributed a small fraction to the total gas consumption (about 20%). Based on the flowloop investigations, Di Lorenzo et al.15 suggested that, compared with the mass transfer limited model39, the kinetic model21 was more suitable for gas-dominated systems with the presence of a free water phase. The kinetics model21 is shown as eq 15:  k rhf = uAs k1 exp  − 2  T f 

  ( ∆ Tsub ) 

(15)

In this model, nucleation is assumed to occur immediately under a specified subcooling, ∆Tsub, ∆Tsub = Teq – Tf. Tf is the bulk fluid temperature and is determined with eq 12. Teq is the hydrate equilibrium temperature at the system pressure, calculated with hydrate thermodynamics.41 As is the gas-liquid interface area. In eq 15, the subcooling, ∆Tsub, is the driving force for hydrate formation. The intrinsic kinetic constants, k1 and


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k2, are regressed from the experiment data of Vysniauskas and Bishnoi36 and Englezos et al.37,38. For structure II hydrates21, k1 = 2.608 × 1016 kg m-2 K s-1 and k2 = 13600 K. It should be noted that the scaling factor, u, was not included when it was initially established. Through flowloop investigations, Boxall42 observed that the theoretical estimates of the kinetics model, eq 15, were much higher than the experimental values. The differences were attributed to the heat- and mass-transfer limitations to hydrate formation. Therefore, the scaling factor, u, was introduced to the kinetics model21 to account for the heatand mass-transfer limitations, and for oil- and water-dominated systems42, u has a value of 1/500. Di Lorenzo et al.13-15 observed that hydrates formed much faster in gas-dominated systems than in oil-dominated systems (about 250 times15) and proposed that the scaling factor, u, should be set to 0.5 in order to achieve a better agreement with experimental results. The gas-liquid interface area, As, is a key parameter of hydrate formation rates and is related to flow patterns. At present, the gas-liquid interface area has not been directly measured. For gas-dominated systems containing a free water phase, a liquid film would form on the pipe walls and a fraction of the liquid would be entrained and transported as small droplets by the gas phase. Therefore, the gas-liquid interface area is composed of: Af, the surface area of the liquid film, and Ad, the surface area of the water droplets. The gas-liquid interface area for gas-dominated systems in per unit length pipeline is expressed as As = Af + Ad

(16)

The effect of the continuously growing hydrate layer formed from hydrate deposition should be taken into account. The effective cross-sectional area of the pipelines will be narrowed dramatically as a result of hydrate deposition. Therefore, the Af and the Ad vary accordingly. The thickness of the liquid film is small compared with the pipe diameter, thus the surface area of the liquid film, Af, is assumed to be equal to the inner surface area of the hydrate layer. The Af for unit length of pipeline is:


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Af = 2π rf

(17)

The surface area of the water droplets, Ad, is related to the droplet number and droplet size. The droplet number is determined from the droplet entrainment, which is the portion of liquid transported by the gas phase as liquid droplets. In this work, the correlation proposed by Oliemans et al.43, which was based on the AERE Harwell data bank44, is used to estimate the entrainment, FE. FE =

M

(18)

1+ M 0.38

−0.92

−1.24

M = 0.03We SG FrSG Re SL Re SG 1.8

0.7

ρ  µ  ρ  µ      L

L

G

G

0.97

(19)

Where the Weber number, WeSG, the Froude number FrSG, the Reynolds number ReSL and ReSG are defined as 2ρg vSG rf 2

We SG =

σ

;

FrSG =

v SG

;

Re SL =

2 grf

2 ρl vSL rf

;

µl

Re SG =

2 ρ g v SG rf

µg

.

Where σ is the surface tension, µl and µg are the dynamic viscosities of the liquid and the gas, respectively, and vSL and vSG are the superficial velocities of liquid and gas, respectively. The surface area of the droplets in per unit length of the pipeline, Ad, can be obtained under the assumption that the liquid droplets are spherical.45

Ad =

3 2

2

π × 0.765

3

4 rf

dm

×

q LC 3 = π × 0.765 q g + ql 2

3

4 rf

2

dm

×

ql q g + ql

× FE

(20)

Where qLC is the droplet volumetric flow rate, m3/s, qg and ql are the gas and liquid volumetric flow rate, , m3/s, respectively. The Sauter mean droplet diameter, dm, m, is estimated with the following correlation45 

d m =  0.0091 



2σ r f 

0.5

 ρ g v g2 

(21)

The hydrate formation rates in gas-dominated systems with a free water phase can be obtained by substituting eqs 16–21 into eq 15. 2.3. Hydrate Deposition Rates and Hydrate Layer Growth. At present, hydrate deposition in


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gas-dominated systems has been far less sufficiently studied.7,14,15 It is believed that hydrate deposition is closely related to the adhesion forces between hydrates and the pipe wall surface, the presence of the free water phase, flow patterns and fluid velocities, etc. For systems without a free water phase, Nicholas et al.11,20 and Rao et al.24 suggested that the hydrate deposition mechanism was similar to that of wax deposition, in which the water molecules diffuse to the surface from the bulk phase, condensate into liquid, and then convert into hydrate crystals. As the water and gas molecules diffuse to the crystal surface, the hydrate crystals continuously grow, forming a hydrate layer on the pipe walls. The layer growth rates are largely controlled by the removal of the latent heat of hydrate crystallization from the systems to the environment. Moreover, the adhesion forces between the hydrates and surface of the pipe walls are small when a free water phase is absent, indicating that hydrates are more unlikely to deposit on the walls. Therefore, hydrate deposition rates are rather small (about 1 mm/day) with the heat- and mass-transfer limitations and the small adhesion forces. For systems with a free water phase, Di Lorenzo et al.13-15, conducted a series of flowloop tests (liquid holdup 5~6%), in which annular flow regime was observed. For annular flow, parts of the liquid flow along the pipe wall with a rather low velocity as a liquid film, and the other parts of the liquid are transported by the gas stream as small droplets and usually have a high velocity. Both the liquid film and the droplets are in contact with the gas phase and can form hydrates. Di Lorenzo et al.15 further observed that only a fraction of 30–50 vol % of the formed hydrates deposited onto the wall, contributing to the growing hydrate layer, and a large part of the formed hydrates were transported away by the gas and liquid phases. However, further explanation for these interesting phenomena was not given by Di Lorenzo et al.15. In this paper, we schematically give our explanation for the interesting phenomena in Figure 3, by combining micromechanical force (MMF) measurements, CFD studies, and annular flow characteristics.


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MMF measurements17,18 showed that the presence of a free water phase could increase the adhesion forces between hydrate particles and the wall surface by more than 10 times, suggesting that hydrates directly formed in the liquid film are more likely to adhere to the pipe wall, rather than to be transported away by the gas and liquid phases (denoted as hydrates (1) and (2) in Figure 3). Due to the relatively high gas velocity in annular flow40, the hydrate particles generated from droplets (hydrates (3) in Figure 3(a)) are more likely to be transported in the gas core, similar to the entrained droplets. As the hydrate particles are transported close to the surface of the liquid film (hydrates (4) in Figure 3(b)), due to the barrier– hydrates formed on the surface of the liquid film, these hydrate particles are difficult to directly contact the liquid film, as illustrated in Figure 3(b). Therefore, these particles still have a strong tendency to be transported in the gas core, rather than to deposit onto the pipe wall. Another controlling factor for hydrate deposition is fluid velocities. Jassim et al.27 studied the effect of fluid velocities (especially the gas velocity) on hydrate deposition through CFD investigation of single hydrate particle deposition behavior. It is indicated that hydrate particles are more likely to be transported away by the gas and liquid phases, rather than to deposit onto the pipe walls when the gas velocity increases, as shown in Figure 3.


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pipe wall

hydrate layer

pipe wall hydrate layer

(1) (2)

(2)

(3)

(4)

rf

rf

rti

rti

rto

rto

(a) Deposition of hydrates formed on the liquid film.

(b) Deposition of hydrates formed from liquid droplets.

(1) Deposited hydrates–These hydrates are immersed in the liquid phase and are being covered by newly formed hydrates (denoted as (2)). Thus these hydrates have a high tendency to deposit and form a hydrate layer on the pipe wall. (2) Loose hydrates–These hydrates are being formed at the surface of the liquid film and are unlikely to be transported away due to the relatively large adhesion forces when a free water phase is present17,18. (3) Hydrate particles which are formed from liquid droplets and transported by the gas core. These particles usually have a high velocity, indicating the particle is unlikely to deposit onto the pipe walls27,40. (4) Hydrate particles which migrate close to the surface of the liquid film due to the turbulent flow in the pipes. Hydrates also form at the surface of the liquid film, as denoted by (2). Thus the liquid film is usually covered with hydrates, impeding the direct contact of the hydrate particles with the liquid film. Meanwhile, these particles commonly have a high velocity (approximately the same with the gas velocity). Therefore, these particles are unlikely to deposit onto the walls.

Figure 3. Schematic diagram of hydrate deposition on the pipe wall

The previous MMF measurements17,18, flowloop investigations13-15, and CFD studies27 suggest that most of the hydrates formed in the liquid film deposit onto the wall and contribute to the growing hydrate layer, and on the contrary, most of the hydrate particles formed from droplets are transported away by the gas and liquid phases. Based on these previous work, we deduce that hydrate blockage for annular flow is largely attributed to the deposition of the hydrate formed from the liquid film. Hence, the deposition rates are approximately equal to the hydrate formation rates in the liquid film. For per unit length of pipeline, the deposition rate is21:


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1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

 k2   T  ( ∆Tsub ) ⋅ 2π rf  f 

rhd = uk1 exp  −

Page 18 of 38

(22)

It should be noted that our deduction is a preliminary explanation for hydrate deposition and there is still a long way from a full understanding of hydrate deposition in gas-dominated systems and more work is required in the future. Rao et al.12,24 proposed that the systems would turn into an annealing period, in which hydrate formation would cease as the temperature of the hydrate layer surface reached the hydrate equilibrium temperature. At the same time, water would fill into the pore spaces, making the hydrate deposits less porous. The hydrate deposits are hardened during this period and are more difficult to be removed away, which is more harmful to the systems. In actual production operations, these situations should be avoided as completely as possible. The annealing period typically starts after a rather long time from the initial nucleation period (about 2 days).12,24 During the period before the hardening effect starts, the pipeline diameter continuously decreases due to hydrate deposition on the walls, and the decreasing rate of the effective pipeline radius is given as −

dr f dt

=

rhd 2π rf ρ h

(23)

The shear forces exerted on the deposits increase as the hydrate layer becomes thicker and the fluid velocities become higher. As a result, some of the deposits would be peeled off and transported downstream, which is the so-called sloughing effect.8,13,15 This phenomenon has been poorly understood at present.7 And the sloughing effect is neglected in eq 23. Thus, the estimated decreasing rate of the pipeline diameter might be larger than the actual value. The decrease of pipeline diameter is believed to be the main cause for the pressure drop increase in gas-dominated systems.7,11,15,16 Therefore, neglecting the sloughing effect may result in more conservative prediction results, which can help the operators timely detect the hydrate formation and blockage risk, and take measures to cope with the hydrates in order to avoid more serious situations (e.g. complete blockage of the pipelines). By introducing the initial condition, rf = rti at t = 0, the effective inner radius of the pipeline, rf, can be obtained


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by integrating eq 23, and rf is: t

uk1∆Tsub

0

ρh

rf = rti − ∫

e

− k2 / T f

(24)

dt

The subcooling and the fluid temperature are different at different locations of the pipelines and will change over time, thus the effective diameter of the pipeline will change temporally and spatially. The hydrate layer thickness, δh, can also be obtained: t

uk1∆Tsub

0

ρh

δ h = rti − rf = ∫

e

− k2 / T f

dt

(25)

The hydrate layer thickness is also related to the subcooling and the fluid temperature, and will change temporally and spatially. Eqs 23–25 indicate that the pipeline is expected to be narrowed by the continuously growing hydrate layer formed from hydrate deposition. Therefore, the pressure drop is increased and the transmission capacity of the pipeline is largely reduced, finally resulting in catastrophic pipeline blockage. The proposed coupling model can be used as a tool to predict the dynamic process of the systems and estimate when and where the hydrate blockage will occur. Thus, it can provide guidance for hydrate management. 2.4. Solution Procedure. As discussed above, the hydrodynamics, heat transfer, and hydrate formation and deposition are inter-coupled, which makes the present time-dependent model strongly nonlinear. In the numerical solution, finite difference method is adopted. The solution procedure is summarized below (also illustrated in Figure 4). (1) The pipeline is divided into equally spaced sections with a length of ∆s. The parameters, including the hydrate formation rate, the deposition rate, the thickness of the hydrate layer, and the roughness of the pipe wall are assumed uniform within each section. (2) The outlet pressure, pout, and temperature, Tout, of section i at time step n are guessed. (Meanwhile, the inlet parameters, including the pressure, temperature, and the fluid velocities, are already known.)


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(3) The p and Tf, p = (pin+pout)/2 and Tf = (Tfin+Tfout)/2, are used as the average pressure and temperature of section i at time step n. (4) Based on p and Tf, the parameters, ρg, rhf, rhd, δh, rf, A, and fF in this section, are calculated with the equations in Section 2.1.–Section 2.3. If the effective pipe diameter (2rf) is smaller than the critical diameter (discussed further in Section 4.), the pipe is supposed to be blocked by hydrates. (5) The parameters obtained in (4) are substituted into the proposed coupling model (eqs 1, 5, and 13). The model is solved with finite difference method, and an iterative process is conducted until the convergent outlet pressure and temperature (p and Tf) are reached. The parameters mentioned in (4) are updated and the hydrate deposition status (including hydrate blockage) is estimated in the iterative process. (6) The outlet pressure and temperature (p and Tf) of section i at time step n are used as the inlet pressure and temperature (p and Tf) of the section i+1 at time step n. Similar process, as (2)–(5), are carried out to obtain the convergent outlet pressure and temperature (p and Tf) of the section i+1 at time step n. The hydrate deposition status (including the occurrence of hydrate blockage) is also estimated. (7) Similar process can be carried out for estimation of pressure, temperature, and the hydrate deposition status at time step n+1.


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Figure 4. Flow chart for hydrate blockage prediction in gas-dominated systems

3. MODEL VERIFICATION Gas well testing is an important technique in acquiring reservoir information, estimating production potential, and providing basis for subsequent production project design, especially during deepwater gas development. The gas well testing system is schematically shown in Figure 5(a). During well testing operations, natural gas from the testing zone flows upward in the testing tubing to the surface (platform). A small amount of water may be present in the tubing and would be transported upward by the gas phase. Thus, it is a gas-dominated flow system in the testing tubing. Low ambient temperature (as low as 2-4 ºC) is encountered near the seafloor (mudline) due to the large water depth. Meanwhile, the pressure is usually very high in the tubing, depending on well depth, reservoir pressure, etc.25 Therefore, hydrates would form in the tubing during well testing operations, which may result in conduit blockage and severe safety hazards46. The current dominant hydrate management strategy is injecting massive inhibitors (mainly THIs, e.g. MeOH and MEG) to keep the systems totally operating outside the hydrate


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stability region (HSR).25 The present coupling model is verified with field data from well testing operations on a deepwater gas well, X-1, in the South China Sea. X-1 is a vertical deepwater gas well, with a water depth of 1350 m, and testing zone depth(s) of 3150-3190 m. The pore pressure in the testing zone is 32.97 MPa, and the geothermal gradient is 0.0345 K/m. The composition of the produced natural gas is given in Figure 5(b). This gas forms structure II (sII) hydrates according to CSMGem1 and the hydrate phase equilibrium curve is given in Figure 5(c). During the well testing operations, the water production rate is less than 3.5 m3/d (30 bwpd). The cumulative injection of methanol is 5.0 m3 (43.2 bbls), and the system is operated outside of the HSR. (b) Gas composition (mol %) CH4

C2 H 6

C3H8

i-C4H10

n-C4H10

i-C5H12

86.465

4.782

2.097

0.375

0.576

0.249

n-C5H12

C6

C7+

CO2

N2

0.192

0.26

1.434

3.125

0.445

28 24 Pressure (MPa)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 22 of 38

Hydrate phase equilibrium curve

20 16 12 8 4 0 0

(a) Schematic diagram of well testing systems

4

8 12 16 Temperature (ºC)

20

24

(c) Hydrate phase equilibrium curve

Figure 5. Gas composition and hydrate phase equilibrium in the well testing

The field data, including gas production rates, water production rates, wellhead pressures and temperatures, and the calculated wellhead pressures and temperatures (in the calculation, the wellbore heat transfer equations should be included, see reference 33) are given in Table 1. It is indicated that the proposed model can achieve reliable


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performance in predicting the pressure and temperature distributions, which are key factors for hydrate formation and deposition (as discussed in Section 2.2. and Section 2.3.). Table 1. Comparison of the calculated results with the field data

wellhead temperature (ºC)

wellhead pressure (MPa)

gas rate

water rate

(104 m3/d)

(m3/d)

measured

calculated

relative error

measured

calculated

relative error

70

2.31

32.78

34.36

4.82%

25.11

26.94

7.29%

44.5

3.35

42.78

43.39

1.43%

24.64

26.12

6.01%

148.7

0

55

55.21

0.38%

20.64

22.08

6.98%

In order to further confirm the reliability of the proposed model in describing the inter-coupled systems, we compared the predicted hydrate layer growth rates with the results of recently published flowloop investigations conducted by Di Lorenzo et al.14,15. It is indicated that a good agreement can be achieved, which will be further discussed in Section 4.1.

4. MODEL APPLICATION AND DISCUSSION A simulation study is performed to evaluate the applicability of the proposed model and to further confirm its reliability in describing the inter-coupled phenomena in gas-dominated systems. Interesting results are obtained, which can provide new insights and practical guidance for hydrate management during deepwater operations. The simulation study is conducted for hydrate blockage prediction during deepwater gas well testing operations of a case well, X-3, which is in the same block as X-1. The wellbore configuration of X-3 is similar to X-1, but the water depth is 1565 m, and the setting depths of the surface casing and the intermediate casing are 2300 m and 3600 m, respectively. The testing zone depth is 3850-3900 m. The gas composition and the phase equilibrium curve of hydrate formation of the X-1 are used in the simulation study, as shown in Figure 5. In the simulation study, the bottomhole pressure (BHP), the gas production rate, the water production rate are set at 28 MPa, 43.2×104 m3/d, and 15 m3/d (i.e. 130 bwpd or 0.35 m3/104 sm3), respectively. According to reference


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40, the liquid holdup in the testing tubing is about 3%, and it falls within the annular flow regime. The pressure in the testing tubing decreases from 28 MPa at bottomhole to 18 MPa at surface (platform). It should be noted that, in the simulation, the water content is high enough to ensure a relatively sufficient water supply for hydrate formation. Combining the present model with the wellbore heat transfer equations33, the temperature and pressure distribution is obtained. The fluid temperature, the ambient temperature (including the formation temperature along the wellbore and sea water temperature along the risers), and the hydrate formation temperature at in-situ pressure conditions (without inhibitors), are given in Figure 6. It can be seen that the ambient temperature is rather low (about 4 ºC) near the mudline, where yet the fluid temperature in the tubing is still above the hydrate formation temperature, Teq, thus hydrates cannot form. As the fluid continues to flow upward, more heat is lost to the ambience–i.e. sea water around the riser, and the fluid temperature becomes lower. At the depth of 910 m, the fluid temperature reduces to the in-situ hydrate formation temperature. From this point above to the platform, the fluid temperature is below the in-situ hydrate formation temperature. Hence, the driving force–the subcooling–is present in this section, and this section (0–910 m) is within the HSR. The formed hydrates in the HSR are expected to deposit onto the tubing walls, forming a continuously growing hydrate layer and narrowing the tubing. According to eq 5 and eq 7, the pressure drop is expected to increase, and Figure 7 shows the pressure drop behavior with respect to the effective diameter (denoted in terms of dimensionless diameter, Dr, defined as the ratio of Df to Dti, where Df is the effective inner diameter and Dti is the initial inner diameter). Figure 7 indicates that a significant pressure drop increase is present47 when the dimensionless diameter reduces to 0.55–0.45. In this work, the value of 0.5 is used as the critical diameter, which indicates that well testing operations are expected to be significantly interfered by hydrate deposition and cannot be run normally when the effective diameter reduces to or even below the critical value. We use the critical diameter to denote the hydrate blockage risk margin (HBRM).


Page 24 of 38

Page 25 of 38

50

122

Teq

77

20

10

Mudline

Temperature (ºC)

92 30

HSR

62 47

0 0

Temperature(ºF)

107

40

1000

2000

3000

32 4000

Depth (m) Gas production rate: 43.2×104 m3/d; water production rate: 15 m3/d (liquid holdup: ~3%); pressure in the tubing: from 28 MPa at the testing zone to 18 MPa at surface (platform).

Figure 6. Temperature profiles of the bulk fluid and the hydrate formation region (HSR) in the testing tubing

9

∆p/∆p0

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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6

3

0 1.00

0.90

0.80

0.70 Dr

0.60

0.50

0.40

Figure 7. The relation of pressure drop and the effective tubing diameter

4.1. Hydrate Blockage Prediction during Well Testing Operations (1) The simulation results It is shown that a section longer than 900 m is operated within the HSR during well testing without any inhibitor injection. Hydrates are expected to form in this section and deposit onto the tubing walls, narrowing the conduit and finally resulting in blockage. Change of the effective diameter over time is shown in Figure 8(a) and development of the effective diameter along the tubing in the HSR is given in Figure 8(b).


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Figure 8(a) shows that within the 34 hours from the initial nucleation period, the effective tubing diameter is above the critical value, indicating that no significant pressure drop increase is caused by hydrate deposition. The fluid (mainly gas) still can flow upward in the tubing and the well testing operation can be run without significant interference. The simulation work conducted on deepwater gas production systems by Zerpa et al.23 and Rao et al.24 also indicated that the systems still could work normally with the presence of small amounts of hydrate deposits and a small change in pipeline diameter. After 34 hours from the initial nucleation period, the hydrate layer grows thicker and makes the effective tubing diameter at the depth of 150 m smaller than the critical diameter. That is, the HBRM is reached. The pressure drop in the tubing is expected to increase significantly (as indicated in Figure 7) and the hydrate blockage risk will increase dramatically. Thus, the well testing operations will be strongly interfered and cannot be carried out normally. Figure 8(b) indicates that hydrate layer is formed all along the tubing walls in the HSR, and as the well testing operation continues, the effective diameter decreases. The layer thickness also varies along the tubing. According to eqs 24–25, the increase rate of the hydrate layer thickness is closely related to the subcooling. As the subcooling becomes larger, the hydrate formation rates and the hydrate deposition rates increase (as indicated in eq 15 and eq 22, respectively). Therefore, the hydrate layer thickness increases more rapidly. The subcooling can be seen in Figure 6, and the largest subcooling (about 4.8 ºC) is present at the depth of 150 m. As the well testing operation continues, the effective diameter at the depth of 150 m will first reach the HBRM, and this interval has a higher risk for hydrate blockage.


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1.0 0.9 0m 100 m 150 m 300 m 500 m 700 m 900 m

0.8 Dr

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

0.7 0.6 0.5

Critical diameter

0.4 0

10 20

30 40 50 Time (hour)

60

70

80

(a) Change of the effective tubing diameter over time

The darkness of the color in the testing tubing represents the hydrate deposition rates, thus the darker region will be blocked sooner by hydrates.

(b) Development of the effective diameter along the tubing Figure 8. Hydrate deposition and blockage behavior in the testing tubing

(2) Comparisons with previous researches Our simulation results are compared with the results of previously published laboratory experiments and flowloop investigations on gas-dominated systems. These researches can be divided into two categories according to whether a free water phase was present in the systems.


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For gas-dominated systems without a free water phase, Rao et al.12,24 reported a maximum hydrate layer growth rate of about 1 mm/d for water saturated gas systems. Nicholas et al.11 obtained similar results for saturated condensate systems. The growth rate of the hydrate layer during well testing operations obtained in our simulation work is much higher (about 16 mm/d), compared with that in the systems without a free water phase.11,12,23,24 It takes about 34 hours for the hydrate to block the testing tubing, while it requires tens of days for the systems without a free water phase23,24. Several factors are responsible for the relatively high hydrate layer growth rate in the tubing during well testing operations. The pressure in the tubing during well testing operations is usually higher than that in gas production pipelines. In our simulation study, the pressure in the tubing is 18–28 MPa (2610–4060 psi), while it is about 6.9 MPa (1000 psi) in the simulation for gas production.24 The higher pressure results in higher hydrate formation temperature1 and larger subcooling. According to eq 15, higher hydrate formation rates are expected. It should also be noted that a relatively low gas production rate is used in our simulation. The HSR will be widened and the subcooling will increase when the gas production rate is lower25. Thus hydrates are expected to form more rapidly. Furthermore, in our simulation, a water volume fraction of 3% is introduced, which results in annular flow in the tubing.40 The liquid phase is transported as liquid film and small droplets, and there is intensive heat and mass transfer between the gas and liquid phases, which also results in higher hydrate formation rates.30-32,39 The tubing wall is wetted by the free water, making hydrates more likely to deposit. While for systems without a free water phase, hydrates are more likely to the transported downstream rather than to deposit onto the wall (as discussed in Section 2.3.). As a result, hydrate layer grows more rapidly when a free water is present in the systems. For gas-dominated systems with a free water phase, Di Lorenzo et al.14,15 obtained higher hydrate layer growth rates, ranging from about 90 to 110 mm/d, in their flowloop investigations. The extremely higher hydrate layer growth rates might be due to the higher liquid volume fraction (about 5–6%, annular flow) in their flowloop tests,


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while it is about 3% in our simulation. According to eqs 18–20, the thickness of the liquid film, as well as the droplet entrainment will be increased as the liquid volume fraction increases. Furthermore, the turbulence intensity at the liquid film interface, and the mass and heat transfer between gas and liquid phases will be significantly enhanced due to the increasing liquid fraction.48 Therefore, hydrates form more rapidly as the liquid fraction increases (other conditions being equal). A comparable hydrate layer growth rate of 82.1 mm/d is obtained at the most vulnerable position (150 m) with the present model when the liquid volume fraction is set at 6% (other conditions being equal). (3) Application of simulation results to field operations At present, the dominant hydrate management technique during well testing operations is injecting massive inhibitors to keep the systems totally out of HSR. This technique is economically infeasible and environmentally harmful as mentioned in Section 3. Deepwater gas well testing operations typically last 20 to 30 hours (including clean up period, sampling period, and flow period), which is much shorter compared to production operations. The simulation results indicate that the well testing could partially operate within the HSR and hydrates would form in the testing tubing without injecting inhibitors. The formed hydrates would deposit onto the tubing wall and narrow the tubing. Yet the effective diameter is still above the critical value during well testing operations. And as mentioned previously, we simulated a relatively dangerous situation and obtained relatively conservative results. It is shown that hydrate formation does not always lead to complete conduit blockage, which was also observed in oil/gas production.4 Therefore, the risk based hydrate management strategy5 may be applicable for well testing operations, in which no hydrate inhibitors are required when the well testing operations can be completed before the tubing being narrowed to the HBRM. It should be noted that flow restrictions, such as valves, orifices, bends, and other conditions like extremely low gas production rates, ultra-deep water, etc., may complicate the process and hydrate blockage may occur earlier, which requires further studies.


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4.2. Effect of Inhibitors on Hydrate Blockage. The well testing operations sometimes could not be completed before the tubing being narrowed to the HBRM. In this case, inhibitors (MeOH, for example) are applied to reduce hydrate formation temperatures. The hydrate phase equilibrium curve with different MeOH concentrations is shown in Figure 9(a). The HSR is obviously shrunk and the subcooling is significantly decreased as the MeOH concentration increases, as shown in Figure 9(b). 30

40 0% MeOH 5% MeOH 10% MeOH 15% MeOH 20% MeOH

25

81

20 15

0% MeOH 5% MeOH 10% MeOH 15% MeOH 20% MeOH

20 15 Teq 10

Environment temperature

HSZ

10

71

61

Temperature(ºF)

30

Fluid temperature 25

Temperature (ºC)

35

Pressure (MPa)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 30 of 38

51

5

5 0

0

0

4

8

12 16 20 Temperature (ºC)

24

28

0

300

600

900

1200

1500

41 1800

Depth (m)

(a) hydrate phase equilibrium curve

(b) p-T profiles and the HSR in the systems

with different inhibitor concentrations

with different inhibitor concentrations

Figure 9. Hydrate phase equilibrium curve and the HSR with MeOH injection

Figure 10 shows the change of the effective tubing diameter, at the depth where hydrate layer grows most rapidly and blockage is expected to occur the earliest, with different MeOH concentrations. It is indicated that increasing the MeOH concentration can significantly extend the time required for the tubing to be narrowed to the HBRM. In other words, the occurrence of hydrate blockage can be substantially delayed by increasing the MeOH concentration. For instance, the time is extended from 36 hours to 52 hours as the MeOH concentration increased from 5 wt % to 10 wt %. Figure 11 gives the development of the effective diameter along the tubing in the HSR with different MeOH concentrations. It is shown that the lower boundary of the HSR moves upward as the MeOH concentration increases (910 m with 0 wt %, 720 m with 5 wt %, and 530 m with 10 wt %). The HSR shrink is also


Page 31 of 38

illustrated in Figure 9(b). Figure 11 also shows that the occurrence of conduit blockage can be postponed by increasing the MeOH concentration. 1.1 1 0.9 0% MeOH 0.8

5% MeOH

Dr

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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10% MeOH

0.7

15% MeOH

0.6 0.5

Critical diameter

0.4 0

10

20

30 40 Time (hour)

50

60

70

Figure 10. Effect of MeOH on hydrate deposition and blockage in the testing tubing

These phenomena can be attributed to the following two factors. As the MeOH concentration increases, the hydrate formation temperature is reduced, which results in smaller subcooling. Hence, the hydrate formation rates decreases according to eq 15. Secondly, the liquid phase becomes more viscous and exerts higher shear stress against the hydrate deposits, which increases the sloughing tendency. As a result, the transportability of the hydrate particles is enhanced. Hydrates are more likely to be transported upward, rather than to deposit onto the wall. Therefore, a lower hydrate layer growth rate is expected, delaying the occurrence of hydrate blockage. The simulation results indicate that the current overinhibition strategy may be replaced by the more economical and less environmentally harmful hydrate management techniques–the non-inhibition strategy and/or the under-inhibition strategy. For instance, in order to ensure a 40-hour well testing operation run smoothly, the MeOH is recommended to be injected to a concentration of 10 wt % to avoid the hydrate blockage, rather than 15 wt % or higher, to completely suppress hydrate formation.


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The red, green, and blue lines are the dimensionless tubing diameters (defined at the beginning of Section 4) with 0, 5, and 10 wt % MeOH, respectively. The “critical diameter” is defined at the beginning of Section 4. (1), (2), (3) are the lower boundaries of the HSR in the testing tubing with 0, 5, and 10 wt % MeOH, respectively.

Figure 11. Decrease of effectve tubing diameter due to hydrate deposition with different MeOH concentrations


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5. CONCLUSIONS In this work, a coupling model is developed to characterize the interaction between multiphase flow, heat transfer, and hydrate behavior in gas-dominated systems. The proposed model can describe and predict the behavior of the systems within industrially acceptable accuracy. For annular flow, based on the previous micromechanical forces measurements and the flowloop investigations, we preliminarily deduce that the hydrate deposition is mainly ascribed to hydrates formed in liquid film, on which further research is required. The hydrate layer growth rate significantly increases when a free water phase is present, as well as when the water fraction increases. That is, hydrate blockage is more likely to occur. This may be resulted from the enlarged gas-liquid interface and the enhanced heat and mass transfer between the water and gas phases. This work makes it possible to predict when and where hydrate blockage will form in tubing during deepwater gas well testing. It is shown that during typical deepwater gas well testing operations (water depth ~1500 m, gas production rate ~50×104 m3/d, liquid holdup ~3%, without inhibitors), it takes 30 or more hours for hydrates to block the testing tubing, which means that hydrate formation does not always lead to complete conduit blockage during gas well testing. It is also shown that inhibitors can significantly postpone the hydrate blockage. We suggested a practical concept, namely hydrate blockage risk margin (HBRM), for the hydrate management optimization. The required inhibitor concentration can be optimized according to the HBRM, which can help reduce the consumption of hydrate inhibitors. For instance, a MeOH concentration of 10 wt % is recommended to delay the hydrate blockage by 18 hours rather than 15 wt % or higher to completely suppress the hydrate formation. The study suggests that the non-inhibition strategy and/or the under-inhibition strategy could be applied as an alternative method to the current total avoidance technique.


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AUTHOR INFORMATION

Corresponding Authors * Phone: +86 532 86981927. E-mail: [email protected] (Z. Wang); [email protected] (B. Sun)

Notes The authors declare no competing financial interest.

ACKNOWLEDGMENTS The authors acknowledge the support from the National Key Basic Research Program of China (973 Program, 2015CB251200), the National High Technology Research and Development Program of China (863 Program, 2013AA09A215), and the Program for Changjiang Scholars and Innovative Research Team in University (IRT_14R58).

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