Features and prevention of gas hydrate blockage in test strings of deep-water gas wells

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Available online at www.sciencedirect.com

ScienceDirect Natural Gas Industry B xx (2018) 1e7 www.elsevier.com/locate/ngib

Research Article

Features and prevention of gas hydrate blockage in test strings of deep-water gas wells*,** Wang Zhiyuan, Zhao Yang, Sun Baojiang* & Yu Jing College of Petroleum Engineering, China University of Petroleum e East China, Qingdao, Shandong 266555, China Received 15 November 2017; accepted 25 January 2018

Abstract Due to the uncertainties in formation mechanism of gas hydrate blockages in strings during the test of deep-water gas wells, inhibitors are either excessively consumed or inefficiently used when conventional prevention techniques are used. In this paper, a study was conducted on multi-phase flows, in terms of hydrate formation kinetics and hydrate particle migration and settlement kinetics. In this process, a model for quantitative prediction of hydrate blockage was built to predict when and where the blockage occurs in the strings and evaluate the severity of such blockage, in order to define the high-risk zones. Eventually, an innovative hydrate blockage prevention technique based on hydrate blockage free window (HBFW) was proposed to determine the optimal concentration and the flow rate of inhibitors. The study results are in the following four aspects. First, gas hydrates generated in the wellbore may deposit on the internal walls of strings. With the increase in thicknesses of such gas hydrate layers, the diameter of a pipe string decreases. Accumulation of gas hydrates generated around liquid film on pipe walls is the key contributor to the blockage in strings. Second, as the water depth increases or the gas production reduces, the HBFW turns to be narrower for production safety, and the time to initiate blockage is shorter. Third, application of hydrate inhibitors can effectively delay the occurrence of blockage and expand the window of safe production. Fourth, the innovative prevention technique can effectively reduce the volume and the flow rate of inhibitors (by 50% in the case study). The innovative technique effectively eliminates the problems related to the excessive consumption of inhibitors in the conventional methods and provides a valuable reference for the prevention of gas hydrates formation in deep-water gas well tests. © 2018 Sichuan Petroleum Administration. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Keywords: Deepwater; Gas well testing; Gas hydrate; Blockage; Prevention method; Hydrate blockage free window (HBFW); Annular mist flow; Volume of inhibitor; Flow rate

0. Introduction

*

Project supported by the National Program on Key Basic Research Project (973 Program) "Basic research on safe and efficient drilling and completion of marine deepwater oil and gas wells" (No.:2015CB251204) and the National Science Foundation for Distinguished Young Scholars “Theory and application of multiphase flow of oil and gas wells” (No.: 51622405). ** This is the English version of the originally published article in Natural Gas Industry (in Chinese), which can be found at https://doi.org/10.3787/j.issn. 1000-0976.2018.01.010. * Corresponding author. E-mail address: [email protected] (Sun B.). Peer review under responsibility of Sichuan Petroleum Administration.

In recent years, breakthroughs have been made in the exploration and development of deepwater oil and gas in China, and high-yield gas fields have been discovered in the blocks such as Liwan and Lingshui. As an important job in oil and gas reservoir identification and reservoir quality evaluation, gas well testing plays an indispensable role in the exploration and development of deepwater oil and gas. However, gas hydrates (hereinafter referred to as hydrates) generated in the test strings (hereinafter referred to as strings) during the deepwater test will block the strings, thereby threatening the operation [1e4]. At present, a commonly used

https://doi.org/10.1016/j.ngib.2018.01.008 2352-8540/© 2018 Sichuan Petroleum Administration. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Please cite this article in press as: Wang ZY, et al., Features and prevention of gas hydrate blockage in test strings of deep-water gas wells, Natural Gas Industry B (2018), https://doi.org/10.1016/j.ngib.2018.01.008

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method is to inject excessive hydrate inhibitors (methanol/ ethylene glycol) into the string to prevent hydrate formation [2,5e9]. Some problems exist in the available hydrate blocking theory and prevention technique. 1) Based on the phase equilibrium theory of hydrate formation, only the formation position of hydrates can be initially judged [4,7], and it is unable to determine the rate of hydrate formation or predict when the string will be blocked. 2) It is generally believed that blockage occurs in the wellbore where hydrate formation conditions are satisfied, without taking into account the fact that the generated hydrates are carried and transported in the wellbore, so the dynamics of migration and settlement of the generated gas hydrates in the string cannot be described [10e12]. In this case, the predicted location of hydrate blockage does not match the actual situation. 3) Hydrate prevention measures based on conventional predictive theory have the disadvantage of overuse of hydrate inhibitors [13], and the use efficiency of inhibitors is low. In order to solve the above problems, we conducted a series of studies on the hydrate formation kinetics and the hydrate particle migration and settlement kinetics of multiphase flow [10e13]. Stress was laid on the formation characteristics of hydrate flow barriers of annular mist flow in the wellbore of deepwater gas wells. On this basis, the concept of hydrate blockage free window (hereinafter referred to as HBFW) was proposed, and an innovative hydrate blockage prevention technique based on expanding HBFW was established. This technique can help to significantly reduce the dosage and injection rate of hydrate inhibitors, and the requirement for the storage devices of hydrate inhibitors as well. 1. Hydrate deposition and blockage model In the test, when the temperature and pressure at a certain position in the string meet the conditions for the hydrate formation, hydrate will be generated. This position is the hydrate generation area. The generated hydrates will be carried by the high-velocity gas flow. A part of the hydrates will deposit on the pipe wall to form a hydrate deposit layer, resulting in a reduction of the effective flow area in the wellbore and an increase in the pressure drop. As the thickness of the hydrate layer continues to increase, the string is gradually plugged, which is why hydrates cause flow barriers. The annular mist flow often occurs in the string. A part of the liquid is carried by the gas flow in the form of small dispersed droplets and migrates along with the gas. The other part of the liquid flows along the pipe wall to form a liquid film [14,15]. Hydrates are formed both in droplets and in liquid film [10,12], as is shown in Fig. 1. There are significant differences between the liquid droplets entrained in the pipe wall fluid film and the gas, and their contact relationship with the gas, and the mass transfer and heat transfer characteristics.

Fig. 1. Formation and deposition of hydrates in string.

In this paper, based on the hydrate formation rate model established by Turner et al. [16], the coefficients showing the mass transfer and heat transfer intensity were introduced. The rate of hydrate formation in the string is expressed as follows:
 kt As k1 Mh k2 Rhf ¼ exp  ð1Þ ðDTsub Þ Mg Tf where Rhf represents the rate of hydrate formation in the string, kg/(s $ m); similarly, kt: the coefficient of mass transfer and heat transfer intensity [17,18], dimensionless; As: the gaseliquid contact area [12], m2; k1: the intrinsic kinetic parameter [16,19], being equal to 2.608  1016 kg m2$ K $ s1; Mh: the hydrate molar mass, kg/mol; Mg: the natural gas mixture molar mass, kg/mol; k2: the intrinsic kinetic parameter [16,19], being equal to 13600 K; Tf: the fluid temperature in the string, K; ▵Tsub: the degree of supercooling (i.e. the difference between the hydrate formation temperature and the fluid temperature) in K, which is the driving force for hydrate formation. A part of the hydrates formed in the string migrate with the gas, and another part of the hydrates deposit on the pipe wall [10,12]. Under the condition of annular mist flow, due to the strong adhesion of the inner wall of the string [20,21], the hydrates generated at the liquid film will directly adhere to the wall. Hydrates generated at the entrained droplets of gas will migrate a long distance due to the high-velocity carrying of gas [22] and have a small scope compared to hydrates generated in the string of subsea pipelines. In this case, the deposition of the hydrate particles generated at the droplets on the pipe wall can be ignored. Therefore, the deposition of hydrates formed at the liquid film on the pipe wall is the main cause of blockage of the string. Hydrate deposition rate is calculated by the following equation [11]:

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Rhd ¼


 2prf kt k1 Mh k2 exp  ðDTsub Þ Mg Tf

ð2Þ

where Rhd represents the hydrate deposition rate, kg/(s$m); and rf represents the diameter (effective diameter) in m, which continuously decreases with the hydrate deposition. Hydrates deposit on the pipe wall to form a hydrate layer with its thickness increasing continuously [10e12,23,24]. Neglecting the pores of the hydrate deposits, it is assumed that the hydrates are uniformly deposited in the radial direction within the same cross section of the string (i.e. the hydrate layer is evenly distributed in the radial direction); however, due to factors such as the degree of undercooling, the hydrate layer is non-uniformly distributed along the axis of the string. The thickness of the hydrate layer formed on the pipe wall is calculated by Eq. (3). Within one microelement section, it is assumed that the hydrate layer thickness is uniform, expressed as follows: Zt dh ¼ rti  rf ¼ 0

kt k1 Mh DTsub k2 =Tf e dt rh M g

3

ð3Þ

where dh denotes the hydrate layer thickness, m; similarly, rti: the original diameter of the string, m; t: the time, s; and ph: the density of the hydrate, kg/m3. A dimensionless hydrate layer thickness (dD) is introduced and is expressed as: dh ð4Þ rti The formation of hydrates is a relatively slow process, and most of the generated hydrates are carried by the high-velocity gas flow. Therefore, even if the temperature and pressure in certain areas of the string satisfy the conditions for the formation of hydrates, blockage will not be formed immediately. By using the above formula, the distribution of the hydrate layer thickness can be predicted, and then appropriate control measures can be taken to ensure that no blockage will occur in the string.

dD ¼

2. Hydrate blockage free window (HBFW) As the hydrates deposit on the pipe wall, the roughness of the pipe wall increases, the pipe diameter decreases, and the pressure drop in the pipe string increases [24e26]. The relationship between the pressure drop and the hydrate layer thickness is shown in Fig. 2 [11], where ▵p represents the pressure drop (MPa) and ▵p0 represents the pressure drop (MPa) in the string when no hydrate is generated. When the dimensionless hydrate layer thickness increases and ranges from 0.45 to 0.55, the ▵p/▵p0 increases significantly, which is caused by the throttling effect resulted from the non-uniform deposition of hydrates on the pipe wall. This phenomenon will occur under different gas flow rates, temperatures, pressures, and void fraction (less than 10%). In this paper, 0.5 is used as the dimensionless critical hydrate layer thickness to

Fig. 2. Pressure drop vs. hydrate layer thickness.

determine the occurrence of hydrate blockage. This value can also be selected according to the actual situation on site. When the hydrate layer thickness increases to a critical value, the formation and deposition of hydrates will have a significant impact on the test operation. In this paper, the time required from the start of the test operation to the moment when the hydrate layer in the string reaches the critical thickness was defined to be the hydrate blockage free window (HBFW). The HBFW can be determined using a hydrate deposition and blockage model in the steps below. 1) The temperature and pressure fields of the wellbore are calculated, and then the hydrate generation area in the string is determined based on the phase balance conditions for the hydrate formation. The area where the wellbore temperature is lower than the phase equilibrium temperature of the hydrate formation is the hydrate generation area [7,9,and27]. Due to formation water and other factors, there is usually gaseliquid two-phase flow dominated by gas phase in the wellbore, generally in the form of annular mist flow [15]. In this paper, the gaseliquid twophase flow model was used to calculate the temperature and pressure fields in the wellbore [15]. 2) Hydrate generation rate and deposition rate are calculated using the hydrate formation rate formula (1) and the deposition rate formula (2). 3) Based on the hydrate layer thickness calculation formulas (3) and (4), the thickness increase of the hydrate layer on the pipe wall with the time at different depths is obtained, and the hydrate blocking state in the pipe string can be known to determine the HBFW. The following cases illustrate the application of HBFW in the prevention and control of hydrate blockage. In order to make the cases representative, the authors obtained the key parameter range of deepwater gas wells (Table 1) by consulting the deep-water oil and gas well data in the South China Sea [6,28,29], and then determined the basic parameters of the example wells (Table 2).

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Table 1 Ranges of key parameters of existing deepwater gas wells in the South China Sea. Water depth/m

Well depth/m

Bottom hole pressure/MPa

Subsea temperature/ C

Downhole temperature/ C

Gas production rate/(104 m3$d1)

Usually: 900e1600 Maximum: 2500

2300e4600

8e45

3e4

60e135

15e160 Initially higher than 100

Table 2 Basic parameters of the example wells. Parameter Testing horizon depth/m Water depth/m Subsea temperature/ C Downhole temperature/ C String diameter/m Bottomhole pressure/MPa Gas production/(104 m3$d1) Water production/(m3$d1)

Value

Parameter

3730e3750 800e2500 3e4 37e62 0.1143 27e31 15e150 2e15

The HBFWs under different water depths and gas production conditions are shown in Fig. 3 and Table 3. As the water depth increases, the subsea temperature decreases, causing the decrease of the fluid temperature in the wellbore. In this case, the hydrate generation area increases and the degree of subcooling DTsub increases. From Eqs. (1)e(3), it can be seen that as the hydrate formation rate and deposition rate increase, the hydrate layer growth is accelerated, thereby aggravating the blockage and narrowing the HBFW. From Fig. 3-a and Table 3, it can be seen that when the gas production rate of gas well is 40  104 m3/d, as the water depth increases, hydrate blockage can form more rapidly, the HBFW narrows, and the risk of hydrate blockage is high. For example, when the water depth is 1455 m, the HBFW is 31.2 h; when the water depth increases to 2000 m, the HBFW is reduced to 26.4 h; and when the water depth further increases to 2500 m, the HBFW is further reduced to 22.3 h. When the gas production increases, the wellbore temperature increases and the hydrate generation area in the wellbore decreases. At the same time, the degree of subcooling DTsub decreases and the hydrate formation rate and the deposition

Value 1

Formation thermal conductivity/[W$(m$K) ] Formation rock specific heat/J$(kg$K)1] Formation rock density/(kg$m3) Seawater thermal conductivity/[W$(m$K)1] Specific heat of seawater/[J$(kg$K)1] Steel thermal conductivity/[W$(m$K)1] Cement sheath thermal conductivity/[W$(m$K)1] Annulus fluid thermal conductivity/[W$(m$K)1]

2.2 830 640 1.73 890 43.2 0.35 0.6

rate decrease. As a result, the time required for the formation of blockage increases and the HBFW widens. From Fig. 3-b and Table 3, it can be seen that when the water depth is 1455 m, as the gas production increases, the HBFW widens and the time required to form a blockage increases. When the gas production increases to a certain value, no hydrate will be generated in the pipe string. This value is the critical flow for no hydrate formation, and it is of great significance to the subsequent determination of the reasonable production parameters of the gas well [30]. Under the conditions of low gas production, the HBFW is narrow, and the risk of hydrate blockage is high. For example, when gas production is 50  104 m3/d, the HBFW is 34.4 h; and when gas production is 15  104 m3/d, the HBFW reduces to 25.6 h. Water depth and gas production also affect the distribution of high-risk areas that are prone to hydrate blockage. From Table 3, it can be seen that with the increase of water depth, the high-risk areas prone to hydrate blockage increase in depth; and when the gas production is low, the high-risk areas are located at a deep location. This feature serves as a reference for optimizing the injection position of hydrate inhibitors.

Fig. 3. Calculation results of HBFW. Please cite this article in press as: Wang ZY, et al., Features and prevention of gas hydrate blockage in test strings of deep-water gas wells, Natural Gas Industry B (2018), https://doi.org/10.1016/j.ngib.2018.01.008

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Table 3 Data of HBFW and high-risk area prone to hydrate blockage under different water depths and gas production rates. Case Case Case Case Case Case Case Case Case Case Case Case Case

1 2 3 4 5 6 7 8 9 10 11 12

Gas production rate/(104 m3$d-1)

Water depth/m

Hydrate generation area depth/m

40 40 40 40 40 40 15 30 50 60 100 150

800 900 1000 1455 2000 2500 1455 1455 1455 1455 1455 1455

No hydrate is generated in the string, so hydrate generation area does not exist 0e50 >200 No 0e440 >100 0e50 0e1045 31.2 180e220 0e2040 26.4 1050e1100 0e3100 22.3 1500e1600 0e1760 25.6 600e650 0e1400 26.8 300e350 0e960 34.4 200e240 0e820 64 180e220

HBFW/h

Depth of the high-risk area prone to hydrate blockage/m

No hydrate is generated in the string, so hydrate generation area does not exist

3. An innovative hydrate blockage prevention technique based on expanding HBFW The simulation results of the above cases show that the HBFW is generally tens of hours, which means that the formation of hydrate blockage requires tens of hours. On the other hand, the test operation is a relatively short process compared with the production operation. At present, the phenomenon of excessive use of hydrate inhibitors is widespread in hydrate prevention and control in deepwater gas wells [5,13]. Based on the above cases, this paper used methanol as an example to calculate the HBFW under different inhibitor concentrations by using the established hydrate deposition and blockage model. The gas production of the gas well is 40  104 m3/d and the water depth is 1455 m. First, the hydrate generation area under different inhibitor concentrations was calculated (Fig. 4). When no hydrate inhibitor was added (Case 4), the hydrate generation area was located at the depth of 0e1045 m in the well. After the hydrate inhibitor was added, the hydrate formation temperature

decreased, the hydrate phase curve shifted to the left, and the hydrate generation area decreased. When the mass concentration of hydrate inhibitor reached more than 30%, no hydrate would be generated in the wellbore. When the conventional prevention technique is adopted, hydrate inhibitor concentration should be at least more than 30%. Further simulations were carried out to obtain the HBFW under different inhibitor concentrations based on Case 4, as is shown in Table 4. In Case 4, if the test operation time is less than 30 h, the test operation can be completed within the HBFW without adding hydrate inhibitors. Although there will be a small amount of hydrate generated in the string, the hydrate will not cause any blockage. However, if conventional prevention techniques are adopted, the concentration of the inhibitor should be more than 30% to completely inhibit the formation of hydrates in the string. From Table 4, it can be seen that as the concentration of the hydrate inhibitor increases, the time required for blockage formation in the string increases, that is, the inhibitor can delay the occurrence of blockage, thereby widening the HBFW. The reason for this phenomenon is that the hydrate inhibitor can significantly reduce the growth rate of the hydrate layer thickness, as is shown in Fig. 5. Fig. 5-a and b shows the distribution of the hydrate layer thickness in the string when the mass concentration of methanol is 5% (Case 13) and 15% (Case 14) respectively. A comparison between Fig. 5-a and b shows that as the hydrate inhibitor concentration increases, the hydrate layer thickness growth rate significantly decreases, thereby delaying the occurrence of plugging. From Table 4, it can be seen that when the hydrate inhibitor concentration increases from 5% to 15%, the HBFW increases

Table 4 HBFW under different inhibitor concentrations. Case

Fig. 4. Schematic diagram of hydrate generation areas under different hydrate inhibitor concentrations.

Case Case Case Case Case

4 13 14 15 16

Inhibitor concentration

HBFW/h

0 5% 15% 30% 45%

31.2 34.6 52 No hydrate is generated No hydrate is generated

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Fig. 5. Hydrate layer thickness growth and HBFW under different hydrate inhibitor concentrations.

from 34.6 h to 52 h. In this case, if the planned testing time is 40 h, it is certain that no blockage will occur during the test operation, which can be carried out smoothly by adding the hydrate inhibitor with a concentration of 15% instead of more than 30%. This can reduce the injection rate and dosage of hydrate inhibitors by up to 50%, thereby reducing the requirements for the injection equipment and reserves of hydrate inhibitors. It not only saves a large quantity of hydrate inhibitors, but also reduces the concentration of inhibitors (mainly methanol) in the formation water, reducing its harm to the environment and its processing difficulty. When the formation water production is relatively large, if conventional techniques are used, a very large inhibitor injection rate will be required to achieve a high concentration of inhibitor in the produced water. The new technique proposed herein can achieve hydrate blockage prevention at a low injection rate since it significantly reduces the required inhibitor concentration. Through the established hydrate deposition and blockage model, it is also possible to analyze the condition of hydrate blockage under different types of inhibitors such as other alcohols and salts, and to obtain the HBFW and the high-risk area of hydrate blockage. Then the injection position and injection rate of hydrate inhibitors can be optimized to provide reference for the formulation of hydrate prevention and control programs. 4. Conclusions 1) Hydrates generated in the wellbore deposit on the inner wall of the string and form a continuously thickening hydrate layer, resulting in a reduction in the diameter of the pipe string. Hydrates are formed on the surface of liquid droplets and the liquid film of the pipe wall. The deposition of hydrates formed at the liquid film on the pipe wall is the main cause for string blockage.

2) As water depth increases or gas production decreases, the HBFW becomes narrower and the time required for blockage formation becomes shorter. Injection of hydrate inhibitors can delay the occurrence of blockages and broaden the HBFW. 3) A new optimization technique for the hydrate prevention program was proposed, in which the inhibitor concentration and the inhibitor injection rate were optimized based on the HBFW. This technique can significantly reduce the dosage and the injection rate of hydrate inhibitors required. Under the cases described in this paper, the dosage and the injection rate can be reduced by 50%, which effectively overcomes the insufficiency of hydrate inhibitor overuse in conventional prevention techniques.

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