Hydrate Management in Deadlegs: Hydrate ... - ACS Publications

Nov 27, 2017 - Qualitative and quantitative information obtained from the present study contribute to our understandings of hydrate deposition and giv...
2 downloads 9 Views 3MB Size
Download PDF
Article Cite This: Energy Fuels 2017, 31, 13536−13544

pubs.acs.org/EF

Hydrate Management in Deadlegs: Hydrate Deposition Characterization in a 1‑in. Vertical Pipe System Jeong-Hoon Sa,† Bo Ram Lee,†,‡ Xianwei Zhang,† Keijo J. Kinnari,§ Xiaoyun Li,∥ Kjell M. Askvik,*,⊥ and Amadeu K. Sum*,† †

Hydrates Energy Innovation Laboratory, Chemical & Biological Engineering Department, Colorado School of Mines, Golden, Colorado 80401, United States ‡ Department of Chemical Engineering, Pohang University of Science & Technology, 77 Cheongam-Ro, Nam-Gu, Pohang, Gyeongbuk 37673, Korea § Statoil ASA, N-4035 Stavanger, Norway ∥ Statoil ASA, N-7005 Trondheim, Norway ⊥ Statoil ASA, N-5020 Bergen, Norway S Supporting Information *

ABSTRACT: Deadlegs are the pipe sections used for specific services in production and transportation of oil and gas, and they often encounter hydrate management challenges. Despite stagnant fluids in deadlegs, warm water vapor readily condenses on the cold pipe wall, resulting in a risk of hydrate blockages by deposition. Proper management of hydrates in deadlegs is therefore required for economic and safety reasons. Here, we discuss the development of an 1-in. vertical pipe system that is designed to study hydrate deposition from water saturated gas. From a series of hydrate formation and dissociation, the hydrate deposits are characterized to obtain gas/water consumption, thickness/volume hydrate deposit distribution, hydrate morphology, and hydrate porosity and wetness. These characteristic properties are correlated with the header temperature and the time duration for hydrate deposition. Qualitative and quantitative information obtained from the present study contribute to our understandings of hydrate deposition and give insight into establishing management strategies to avoid or minimize the risk of hydrate deposition in deadlegs in oil and gas production and transportation systems. While deadlegs filled with gas are prevalent in oil and gas pipelines, most relevant studies are limited to identifying the mixing region where the flow is significantly affected by main flowlines and to getting temperature/velocity fields in deadlegs filled with liquids.7−11 Several other studies only focused on hydrate deposition on the pipe wall with a dynamic flow in labscale experimental systems.12−16 While there have been a few preliminary attempts,17−19 systematic studies on gas-filled deadlegs have been recently initiated by our group. To properly assess the potential hydrate risk in deadlegs and to establish hydrate mitigation and -remediation strategies to manage economic and safety concerns, reported studies are essential. Our research group has previously developed a 2-, 3-, and 4in. vertical pipe systems to study hydrate deposition in deadlegs.6,20 Hydrate deposition from water saturated gas was successfully achieved, and the resulting hydrate deposits were characterized to obtain important data on hydrate morphology, hydrate plug location, hydrate deposit distribution, and water recovery. The effects of several experimental parameters on hydrate deposition were also investigated. However, hydrate deposition in such large systems is resource-intensive, requiring long time experiments ranging from a couple of days to months, which impedes systematic studies.

1. INTRODUCTION Gas hydrates are crystalline solid compounds that trap gas molecules inside water frameworks under low temperatures and high pressures.1 They hold a great promise as energy resources but also account for substantial flow assurance challenges within the oil and gas industry.2,3 Oil and gas pipelines often encounter conditions favorable for hydrate formation, so the continuous supply of water and gas may result in hydrate accumulation and eventual blockages. If not managed, hydrates can be a serious safety hazard and lead to significant economic losses. One area for hydrate formation in the production system that has not received much attention is the management of hydrates in deadlegs, which are the pipe sections connected to the main flowlines in the architecture of oil and gas production and transportation systems.4,5 Deadlegs are usually isolated from the main flowlines, thus having no through flow of liquid and gas. This stagnant environment causes deadlegs to be much colder than the main flowlines, and the water content in the gas can readily condense on the pipe wall and potentially result in hydrate deposition. It has been known that this frequently leads to hydrate plugging mainly by hydrate deposition.6 As the deadlegs are occasionally used for production, sampling, chemical injection, depressurization, and possible other services, hydrate blockages in deadlegs can restrict the proper management of main flowlines, thus leading to much more severe flow assurance problems. © 2017 American Chemical Society

Received: September 25, 2017 Revised: November 15, 2017 Published: November 27, 2017 13536

DOI: 10.1021/acs.energyfuels.7b02901 Energy Fuels 2017, 31, 13536−13544

Article

Energy & Fuels

Figure 1. Illustration of the 1-in. vertical pipe deadleg system for hydrate deposition studies.

Figure 2. Graphical representation to show the stepwise cooling and heating applied during stages A and B of the experiment. to a refrigerated circulator (−20 to 80 °C) containing an ethyl alcohol−water mixture to control the pipe wall temperature. The part of the pipe that is covered with copper cooling coil is divided into five sections with equivalent lengths. Each section is 5.5 cm long, so the characteristic length (Lsection/i.d.) is 2.3 and the distance from the header (x/i.d.) is used to specify the position, as indicated in the schematic of the experimental apparatus in Figure 1. On the top of the pipe, a webcam is placed above the glass window to monitor hydrate growth inside the pipe. The pipe is assembled with a stainless steel header (300 mL in volume), and the bottom of section 5 is 10 cm away from the top of the header. The heater unit is placed below the header to control the header temperature and the mixing rate of the magnetic stirrer placed inside the header. The stainless steel supply vessel has a volume of 2000 mL, which is connected to the header through gas flow lines, provides water saturated gas during the hydrate formation experiment. The temperature and pressure conditions are measured by resistance temperature detectors (OMEGA) and pressure transmitters (WIKA), respectively. These readings are recorded by LabView. 2.3. Experimental Procedure. Each experiment consists of a series of hydrate formation and dissociation stages: (A) hydrate formation, (B) hydrate dissociation under pressure, (C) hydrate reformation, and (D) hydrate dissociation after depressurization and characterization. For stage A, the supply vessel is charged with 1000 g of water and 100 bar of CH4/C2H6 gas mixture prior to the start of the experiment. The pipe interior is dried first, and the header is filled with 200 g of water. After assembling the pipe with header, the system is flushed and pressurized with gas up to 100 bar. The gas valve between the header and supply vessel is then opened to equalize the pressure in the system. The supply of gas from the vessel minimizes the pressure drop upon hydrate formation, maintaining the system at a relatively constant pressure (pressure decreases by no more than 3%). Once ready, the header is heated up and the pipe wall is cooled to the

To complement our studies with the large-sized deadlegs, herein we discuss the development of a new 1-in. vertical pipe system that enables simple and fast investigations of hydrate deposition from water saturated gas. This smaller deadleg system allows for easier hydrate deposit characterization. The gas and water consumption for hydrate formation are estimated by a unique developed quantification method of the 1-in. system, and the morphologies of hydrate deposits formed under different header temperatures are compared. In addition, the hydrate deposit thickness and volume distribution are obtained more precisely with a borescope system coupled with an XYZ manipulator, which enables precise control of the borescope position in 3D. The hydrate deposit porosity and wetness, which are typically difficult to measure, are quantified to better evaluate the risk in hydrate management.

2. EXPERIMENTAL SETUP AND PROCEDURE 2.1. Materials. All experiments used deionized water and a gas mixture of CH4 (74.2 mol %) and C2H6 (25.8 mol %), provided by General Air (±2% analytical accuracy). In some testing for temperature profile, industrial-grade N2 (99.0 mol %) was used, also supplied by General Air. 2.2. Experimental Apparatus. The 1-in. vertical pipe experimental system, shown in Figure 1, is designed to mimic the deadlegs in oil and gas pipelines. This experimental system was customdesigned for hydrate deposition studies and was manufactured by SejinYoungTech (Korea). The maximum operating pressure of the system is 150 bar. The 1-in. stainless steel pipe has the actual dimensions of 2.4 cm in inner diameter (i.d.) and 28 cm in total length (Lpipe), so the Lpipe/i.d. is 11.7. The pipe volume is 255 mL. This small system allows an easy interchange of pipes with different lengths and geometries. The pipe is wrapped with copper coils that are connected 13537

DOI: 10.1021/acs.energyfuels.7b02901 Energy Fuels 2017, 31, 13536−13544

Article

Energy & Fuels desired temperatures. The 60/4 °C condition is shown as an example (Figure 2). The liquid water loaded in the header is mixed with magnetic stirring set to 700 rpm. For stage B, a stepwise heating and cooling is applied (Figure 2) The gas valve between the header and supply vessel is first closed to prevent gas flow. The rate of mixing by the magnetic stirring is reduced to 100 rpm and the header temperature is decreased from 60 (for example) to 25 °C to halt hydrate growth. Once the temperatures and pressures are stabilized, the pipe wall temperature is increased to 25 °C to dissociate the hydrate deposits on the wall. After hydrate dissociation, the pipe wall temperature is decreased again to 4 °C. Then, the header temperature is heated up to the original temperature, which was applied to stage A. The 60 °C experiment is shown as an example here. For stage C, the system is stabilized at room temperature over a couple of hours. In this stage, the “memory effect”, which is caused by the previous history of hydrate formation, needs to be completely removed. All hydrate deposits are confirmed to fall off from the pipe wall and to dissociate by the mixing with hot liquid water in the header. To start hydrate formation, the header is heated up and the pipe wall is cooled down to the desired temperatures with a mixing of 700 rpm. Stage C is a repetition of stage A to reform hydrates for the characterization in stage D. For stage D, to isolate the pipe and the header from the supply vessel, the gas valve between those is first closed as in stage B and the rate of mixing is reduced to 100 rpm to halt hydrate growth. The temperatures of the header and pipe wall are then decreased to 25 and −10 °C, respectively. The low temperature in the pipe causes the hydrates and any free water to consequently freeze, minimizing any hydrate dissociation and preserving the solid deposited. Once the temperatures and pressures are stabilized, the system is depressurized to atmospheric pressure. Morphology and thickness of hydrate deposits are obtained by using a borescope coupled with custommade XYZ manipulator system. 2.4. Characterization of Hydrate Deposits. From a series of hydrate formation and dissociation experiments through stages A−D, the characteristics of the hydrate deposits are identified as detailed in Figure 3. During the hydrate formation stages A and C, the growth of

which is defined as the proportion of void space in the apparent volume of the hydrate deposit. The visual inspection using a borescope gives insight into the morphology of hydrate deposit and hydrate plug location (when formed). Information on the buildup of hydrate deposit can also be obtained by repeating the experiment for different time durations.

3. RESULTS AND DISCUSSION 3.1. Hydrate Formation and Dissociation. The formation of hydrates is initiated by heating up the header and cooling down the pipe wall. As deadlegs are usually much colder than the main flowlines, water vapor readily evaporates and condenses on the cold pipe wall, and if the conditions are right for hydrate formation, the condensed water can be readily converted to hydrates. In this study, header temperatures of 30, 60, and 80 °C are applied to vary the rate of water evaporation and condensation on the pipe wall. The pipe wall temperature is maintained at 4 °C to mimic a subsea environment typically encountered in oil and gas production. In stage A (Figure 4a), the pressure slightly decreases upon hydrate formation while the temperatures are relatively stable, indicating that the amount of gas consumed for hydrate formation is much less than that of gas in the entire system. The slight fluctuation in pressure readings has a negligible influence on hydrate deposition. From the webcam placed above the top window, the growth of hydrate deposition is monitored, although it is difficult to clearly see the morphology due to an unavoidable large gas-density gradient along the pipe. In stage B (Figure 4b), stepwise cooling and heating of the header and pipe wall are applied to estimate the moles of gas consumed for hydrate formation in stage A. The temperature and pressure at each step are used to calculate the moles of gas in the vapor phase. Because the hydrate phase equilibrium temperature for the gas mixture used at 100 bar is 18.9 °C (estimated by CSMGem), all the hydrate deposit starts to dissociate when the pipe wall temperature is increased to 25 °C. This is also confirmed by monitoring from the top window. In stage C (Figure 4c), the reformation of hydrates is resumed by setting the header and pipe wall temperatures as in stage A. The rate of hydrate growth and the pressure drop upon hydrate formation are quite repeatable at any given header and pipe wall temperature conditions. In stage D (Figure 4d), both header and pipe wall temperatures are cooled down to 25 and −10 °C, respectively, to prevent the further supply of water vapor from the header and to freeze the hydrate deposit and any free water trapped inside the hydrate deposits. Although the system is depressurized to atmospheric pressure, the hydrate deposit does not dissociate right away and is preserved due to the low temperatures, enabling visual inspection for characterization. 3.2. Estimation of Gas Consumption for Hydrate Formation. To translate the pressure drop upon hydrate formation into the moles of gas consumed, the average temperature of the entire system has to be identified, which is hardly known in our system due to the large temperature gradient along the pipe. As such, the estimated gas consumption is obtained by averaging the temperature by comparing the pressure difference between steps “c” and “e” in stage B, as shown in Figure 2, because such change in a closed system is only caused by temperature differences. The obtained average temperature is then applied into step “a” to estimate the gas consumption for hydrate formation. The estimation is

Figure 3. Diagram showing the stages, data collected, and data analysis for the characterization of hydrate deposition in the 1-in. deadleg system. hydrates and the time required to form a plug are monitored through the top window. In stage B, the gas consumption of hydrate formation in stage A is estimated (to be described later), and this is then converted into the moles of water consumed and the volume of hydrates (assuming hydration number and density). In stage D, in comparison with the water consumption from stage B, the amount of water collected from deposits is used to estimate the wetness of the hydrate deposits, which is defined as the amount of free water in the hydrate deposits. Hydrate deposit thickness is measured and converted to the apparent volume of hydrate deposits and their distribution along the pipe. These are then used to estimate the hydrate deposit porosity, 13538

DOI: 10.1021/acs.energyfuels.7b02901 Energy Fuels 2017, 31, 13536−13544

Article

Energy & Fuels

Figure 4. Sample temperature and pressure profiles during the different stages of an experiment in the 1-in. deadleg system: (a) formation in stage A, (b) dissociation under pressure in stage B, (c) reformation in stage C, and (d) dissociation after depressurization in stage D.

double-checked by repeating this calculation with steps “b”, “c”, and “d”. The obtained amount of gas consumed for hydrate formation increases over time as expected (shown in Figure 5), and the

into hydrates, all governed by the changing temperature profiles inside the pipe. Hydrate deposit morphologies obtained from all experiments are shown in the Supporting Information (Figures S1−S3). As the hot water vapor from the header moves toward the top of the pipe, by natural convection induced by the temperature gradient along both the axial and radial directions in the pipe, it is readily cooled due to the cold pipe wall temperature. The rate of water condensation and the following rate of hydrate formation are determined by the concentration of water and gas in the vapor phase, the heat transfer driven by the temperature gradient, and the subcooling temperature to form hydrates. All these variables are closely related, and they all affect both the morphology of hydrate deposits and the time required to form a hydrate plug. For the conditions with header/wall temperature of 60/4 °C, the hydrate deposit had a rough morphology in section 1 and became thicker toward the bottom, maintaining the roughness, as shown in Figure 6b. Below the position that had the most hydrates (x/i.d. = 6.7), the hydrate deposit morphology became much smoother, as shown in sections 3 (x/i.d. = 4.6−6.9) and 4 (x/i.d. = 2.3−4.6), indicating that the hydrates contained more free water trapped inside. At the very bottom, in section 5 (x/i.d. = 0.0−2.3), the liquid water condensed on the pipe wall was frozen upon cooling before depressurizing the system at −10 °C, leading to the relatively rough morphology. As the hydrate deposit formed, the center pathway became narrow toward the position with the most hydrates, restricting gas and water flow. The water vapor from the header was then accumulated below the position with the most hydrate deposit, and this resulted in the smooth morphology of the wet hydrates below. For the experiment with 30/4 °C conditions, hydrate deposits formed in sections 1−3 have rough morphologies, whereas those formed in sections 4 and 5 are slightly wetter, as shown in Figure 6c, but not as wet as those observed with 60/4 °C. At a lower header temperature, most of the water vapor from the header can be consumed to form hydrates, leading to less free water trapped in the hydrate deposit. The hydrate morphology formed at 80/4 °C is much wetter, especially in sections 2−4, as shown in Figure 6d. For this condition, some frozen icelike particles were observed on the hydrate deposit in section 2, as a consequence of freezing of condensed liquid water, which was not yet converted into hydrates. In section 3, right below the position with the most hydrates (x/i.d. = 8.5),

Figure 5. Estimated moles of gas consumed for hydrate formation. The symbols and lines are colored in blue (30/4 °C), black (60/4 °C), and red (80/4 °C). Dashed lines are drawn as a guide.

rate of consumption gradually decreases. As hydrate deposits on the pipe, the available surface to form hydrates is reduced and, because hydrates act somewhat as an insulator, the heat transfer between the pipe center and the wall is also reduced, leading to a decrease in the hydrate growth rate. As shown in Figure 5, increasing header temperatures increases the gas consumption for hydrate formation at a given time duration. As the header temperature increases, the increased amount and the rate of water evaporation from the header result in an enhanced rate of hydrate growth, although the gas amount in the vapor phase is unchanged. 3.3. Visual Inspection of Hydrate Deposits. After depressurizing the system in stage D, the hydrate deposit morphology is inspected via a borescope, which is inserted into the pipe. The borescope has a light source at its end, and its tip is precisely controlled by the custom-made XYZ manipulator. Figure 6 shows sample images obtained from the borescope, detailing the differences in hydrate deposit morphology along the pipe. The morphology observed varies from smooth to granular depending on the position along the pipe and the formation conditions, which mainly come from the balance between water evaporation from the header, water condensation on the pipe wall and hydrate deposit, and its conversion 13539

DOI: 10.1021/acs.energyfuels.7b02901 Energy Fuels 2017, 31, 13536−13544

Article

Energy & Fuels

Figure 6. (a) Graphical representation to show borescope inspection of hydrate deposits. Images obtained via borescope inspection of the hydrate deposit formed along the pipe. The changing hydrate deposit morphology is a consequence of the varying conditions in the pipe. The set of images are for experiments at the following header/wall temperatures: (b) 60/4 °C, (c) 30/4 °C, and (d) 80/4 °C.

Figure 7. (a) Graphical representation of the hydrate deposit thickness profiles along the pipe. (b) Maximum deposit thickness divided by the pipe radius. (c) Apparent volume of hydrate deposit. The symbols and lines are colored in blue (30/4 °C), black (60/4 °C), and red (80/4 °C). Dashed lines are drawn as a guide. (d) Distribution of hydrate deposition in each section.

3.4. Thickness and Distribution of Hydrate Deposits. The thickness profiles of the hydrate deposit along the pipe are also obtained from the borescope inspection coupled with the XYZ manipulator system after depressurization. The travel length between the hydrate deposits is measured by the

pores on the hydrate deposit were observed, indicating that the water vapor filled the pores. Due to the rapid water evaporation from the header, the excess liquid water, which was not consumed to form hydrates, could result in such unusual morphology. 13540

DOI: 10.1021/acs.energyfuels.7b02901 Energy Fuels 2017, 31, 13536−13544

Article

Energy & Fuels

Figure 8. (a) Build-up of hydrate deposit for 60/4 °C experiment based on formation duration time. (b) Moles of water collected from hydrate deposits. Characterization of (c) porosity and (d) wetness of hydrate deposits. The symbols and lines are colored in blue (30/4 °C), black (60/4 °C), and red (80/4 °C). Dashed lines are drawn as a guide.

manipulator at a given vertical position and is then translated into the deposit thickness to get a profile along the pipe, as shown in Figure 7a. The measurement error for hydrate deposit thickness is 0.1 mm. Figure 7b shows the maximum thickness measured of the hydrate deposit divided by the pipe radius as a function of the total experimental time. This value is normalized for comparison with different sized pipe systems, and it reaches unity when the pipe is plugged with hydrates. As the header temperature increases, an enhanced rate of hydrate growth results in an increase in the hydrate deposit thickness at a given time duration of hydrate formation, as observed from the gas consumption. When converting the thickness profiles into the apparent volume of hydrate deposit formed along the pipe, this follows a similar trend, that is, the apparent volume increases with the time duration and header temperature, as shown in Figure 7c. The distribution of hydrate deposits, however, is very different under different header temperatures, as shown in Figure 7d with the apparent hydrate volume based on sections of the pipe. For the 30/4 °C conditions, the main amount of hydrates forms in section 4 and decreases toward the top, whereas sections 2 and 3 have the most hydrates at 60/4 °C. For the 80/4 °C conditions, section 2 clearly has the most amount of hydrates and the amount in section 1 substantially increases in the 30/4 °C and 60/4 °C tests. According to the hydrate distributions, the location where the most hydrates are formed moves upward with increasing header temperature. To interpret the results, the differences in temperatures and the amount of water and gas need to be addressed. As explained above, the hot header and the cold pipe wall establish a temperature profile along the pipe. The temperature in the system decreases from the bottom (header) to the top of the

pipe and close to the pipe wall. The temperature gradient in the axial direction, which is much larger than that in the radial direction, determines the rate of water transfer upward the pipe, mainly by natural convection. At a given location, the rate of hydrate formation is affected by the actual temperature as well as the concentration of water and gas. If the hot water vapor is not cooled down enough, as in the bottom section of the pipe, hydrate formation would be limited. This would only result in a thin layer of hydrate deposits on the wall. Moving upward along the pipe, once the temperature becomes low enough to form a significant amount of hydrates, hydrate deposit can steadily grow to form a plug. Further up the pipe, hydrate deposits can still form due to the low temperature, but the growth rate would be slower as most of the water vapor would have already been consumed in the lower parts of the pipe and the water content at low temperature is significantly reduced. Changes in the header temperature thus significantly affect the distribution of hydrate deposit along the pipe. 3.5. Characterization of Porosity and Wetness of Hydrate Deposits. Under pressure, visual observation of hydrate deposition is difficult due to the large gas-density gradient along the pipe, making the view through the top window very blurry. Hydrate formation is therefore repeated with different time durations, from 13 to 235 h, so that a visual inspection can be performed to physically measure the hydrate deposits and determine the hydrate-distribution profile, as shown in Figure 8a. Initially, only a thin layer of hydrate deposit forms along the pipe, and over time, the hydrate deposit was distributed along the pipe. For the 60/4 °C experiments, the most amount of hydrates forms in sections 2 and 3, and within 200 h, enough hydrates form in these sections to plug the pipe. In the bottom sections, however, hydrate deposition seems to reach a limit after a certain period of time due to the high 13541

DOI: 10.1021/acs.energyfuels.7b02901 Energy Fuels 2017, 31, 13536−13544

Article

Energy & Fuels temperatures. The buildup of hydrate deposit looks very similar in the 30/4 °C (Figure S4) and 80/4 °C (Figure S5) experiments, while the hydrate deposit distributions (Figures S6−S8) and the hydrate plug locations are different. The water amount collected from melting the frozen solid, which may contain both hydrates and ice (from free water in the hydrate deposit), is used for characterization of the hydrate deposit (see Figure 8b). The amount of water increases with time and header temperature, similar to the gas consumption, but the changes between different header temperatures are much more significant than those observed for gas consumption (see Figure 5). For example, the amount of water recovered from the 80/4 °C experiment is more than twice that from the 30/4 °C experiment at ∼150 h. The hydrate deposit porosity is estimated by the ratio between the volume of hydrates calculated from the gas consumption to the apparent volume of deposits obtained from the thickness measurement, as shown in Figure 8c. Of particular interest in establishing some hydrate remediation strategy is the porosity of the hydrate deposit. As seen in the figure, a highly porous hydrate deposit initially forms, and the porosity decreases over time, resulting from continuing growth and annealing of the hydrate deposit. However, the header temperature has much less influence on the porosity. The asymptotic value of the hydrate porosity around 40−50% may not be surprising, as the reported porosity is an overall estimate for the hydrate formed along the entire pipe. On the basis of the visual observations and the morphology of the hydrate deposit, the porosity of the hydrate can substantially vary along the pipe. The hydrate deposit wetness is estimated by the ratio between the amount of water in the hydrates calculated from the gas consumption to the amount of water collected from melting the solid, as shown in Figure 8d. The wetness is physically related to the proportion of free water trapped in the hydrate deposit, because, depending on the conditions, water may condense on the hydrate deposit and remain unconverted (water-condensation rate greater than hydrate formation rate). As seen in the figure, the hydrate wetness decreases over time, similar to the porosity, but it increases with increasing header temperatures. A change in header temperature affects the water content in the vapor and, thus, the rate of water condensation and hydrate formation. At a low header temperature, most of the water in the vapor is converted to hydrates as soon as it condenses on the cold surface (initially the pipe wall and then the hydrate deposit), leading to a lower free water content in the hydrate deposit. As the header temperature increases, however, the rate of water evaporation and the resulting water amount in the vapor phase substantially increase. Excess water condensed on the hydrate deposit can then be trapped inside the hydrate deposit. Such porosity and wetness estimation essentially poses possible errors due to the assumptions like constant hydration number and density of hydrates, but the general trend of wetness change along with time and header temperature should be valid. 3.6. Hydrate Plug Characterization. If the conditions in the deadleg are suitable for hydrate formation and there is a constant supply of water and gas, enough hydrate can form to plug the deadleg. Figure 9 and Table 1 show the hydrate plugs formed under different header temperatures. As described above, an increase in the header temperature enhances the rate of hydrate formation, thus reducing the time required to form a plug. At the same time, the header temperature also affects the

Figure 9. Schematic illustration of hydrate plugs formed for (a) 30/4 °C, (b) 60/4 °C, and (c) 80/4 °C conditions. (d) Plug time (dark blue) and location (dark red) under different header temperatures and 4 °C wall temperature.

Table 1. Characterization of Hydrate Plug Time, Location, And Thickness in the 1-in. Deadleg System header temperature (°C) pipe wall temperature (°C) experimental duration (h) plug time (h) plug location section no. xplug/Lpipe xplug/i.d. plug thickness/i.d. porosity wetness

30 4 300 260

60 4 235 200

80 4 160 145

4, 5 0.21 2.5 0.42 39.0% 27.5%

2, 3 0.64 7.5 1.25 48.6% 45.7%

2 0.74 8.5 1.25 50.1% 55.0%

hydrate plug location (Figure 9), which is reported by the section number, xplug/Lpipe, and xplug/i.d. (Table 1). While any amount of hydrate deposit is of concern, forming a hydrate plug is much more severe, and identifying the formation time and location of the hydrate plug is critical data for understanding the risk of hydrates in deadlegs. Once a hydrate plug forms, the transport of water above the plug is severely limited, and the hydrate can then only grow downward from the plug, increasing plug thickness over time. Any hydrate forming above the plug is limited by water that may permeate through the hydrate plug. The thicknesses of the hydrate plugs in the axial direction for the 60/4 °C and 80/4 °C conditions are about the same, while the rates of hydrate formation and increasing plug thickness are much faster in the 80/4 °C test. When considering the severity of a hydrate plug, the characteristic properties of hydrate plug such as porosity and 13542

DOI: 10.1021/acs.energyfuels.7b02901 Energy Fuels 2017, 31, 13536−13544

Article

Energy & Fuels wetness also need to be determined. Even though the hydrate plug for the 30/4 °C condition takes longer to form, the resulting dry (lower wetness) and dense (lower porosity) hydrate plug could require further efforts to recover. On the other hand, the hydrate plug formed for the 80/4 °C condition contains a significant amount of free water. If the deadleg is exposed to a cold environment, this could represent a severe risk of getting ice/hydrate plugs upon depressurization. As seen from these results, hydrate plugs formed under different conditions will have different characteristic properties and, as such, they must be remediated differently. For example, wet hydrate deposits can result in much more serious problems when they are frozen upon depressurization due to the Joule− Thompson effect and thus have to be properly managed, while it might be relatively easy to remove powder-like dry hydrate deposits.

■

AUTHOR INFORMATION

Corresponding Authors

*E-mail: [email protected] (K.M.A.). *E-mail: [email protected] (A.K.S.). ORCID

Jeong-Hoon Sa: 0000-0002-8579-1643 Amadeu K. Sum: 0000-0003-1903-4537 Notes

The authors declare no competing financial interest.

■

ACKNOWLEDGMENTS The authors wish to express their appreciation to Statoil for funding this project and granting permission to publish this paper.

4. CONCLUSION In this Article, we introduced a new 1-in. vertical pipe deadleg system and discussed how hydrates are characterized to understand the hydrate deposition from water saturated gas under natural convection conditions. The moles of gas and water consumed for hydrate formation are estimated to obtain the growth rate and the amount of hydrates formed. The increase in header temperature enhances the rate of water evaporation and, thus, hydrate formation. Thickness profiles of hydrate deposit are measured to identify their distribution along the pipe. The location with the most hydrates moves toward the top as it is determined by the temperature profiles, and this finally determines the plug location. Morphologies of the hydrate deposits under different header temperatures are explained by the balance between the rate of water condensation and hydrate formation on the cold surface. While the hydrate deposits formed at 30/4 °C have dry and rough morphology, those at 80/4 °C contain much more trapped free water, resulting in wet hydrate deposits. One of the major achievements of this study is the systematic quantification of the hydrate deposit characteristics in terms of porosity, wetness, distribution along the pipe, and plugging time and location. Such properties are essential for hydrate risk assessment. While it is still difficult to do real-time monitoring of hydrate deposition under pressure, the correlations of characteristic properties of hydrate deposits with time durations are useful to understand the hydrate deposition in gas-filled pipes. Hydrate deposition in the presence of inhibitors like methanol and ethylene glycol is another interesting subject of study, as these inhibitors are often used for hydrate management. Characterization of their vapor content and the effect on hydrate inhibition is also an important challenge. The qualitative and quantitative analyses reported in this study provide estimates for hydrate growth rate, deposit thickness, and plug time/location in oil and gas production and transportation systems. Such information will give an insightful understanding of when, where, and how fast hydrates form, and thus it is are useful in establishing the management strategies by providing specific guidelines for the design and operation of deadlegs.

■

Morphology, thickness profiles, and volume distribution of hydrate deposits (PDF)

■

REFERENCES

(1) Sloan, E. D.; Koh, C. A. Clathrate Hydrates of Natural Gases, 3rd ed.; CRC Press: Boca Raton, FL, 2008. (2) Sloan, E. D.; Koh, C. A.; Sum, A. K. Natural Gas Hydrates in Flow Assurance; Gulf Professional Publishing: 2010. (3) Kinnari, K.; Hundseid, J.; Li, X.; Askvik, K. M. Hydrate Management in Practice. J. Chem. Eng. Data 2015, 60, 437−446. (4) Habib, M. A.; Badr, H. M.; Said, S. A. M.; Hussaini, I.; Al-Bagawi, J. J. On the Development of Deadleg Criterion. J. Fluids Eng. 2005, 127, 124−135. (5) Lunde, K.; Kinnari, K.; Labes-Carrier, C. Deadleg. U.S. Patent, 9297237 B2, 2016. (6) Kinnari, K. J.; Askvik, K. M.; Li, X.; Austvik, T.; Zhang, X.; Sa, J.H.; Lee, B. R.; Sum, A. K. Hydrate Management of Deadlegs in Oil and Gas Production SystemsBackground and Development of Experimental Systems. Energy Fuels 2017, 31, 11783−11792. (7) Bloom, G. R. Turbulent Hydraulic Penetration from Turbulent Pipe Flow into Stagnant Columns; Ph.D. Thesis, Washington State University, Pullman, WA, U.S.A., 1978. (8) Habib, M. A.; Badr, H. M.; Said, S. A. M.; Mokheimer, E. M. A.; Hussaini, I.; Al-Sanaa, M. Characteristics of Flow Field and Water Concentration in a Horizontal Deadleg. Heat Mass Transfer 2005, 41, 315−326. (9) Habib, M. A.; Said, S. A. M.; Badr, H. M.; Hussaini, I.; Al-Bagawi, J. J. Effect of Geometry on Flow Field and Oil/water Separation in Vertical Deadlegs. Int. J. Numer. Methods Heat Fluid Flow 2005, 15, 348−362. (10) Asteriadou, K.; Hasting, A. P. M.; Bird, M. R.; Melrose, J. Exploring CFD Solutions for Coexisting Flow Regimes in a T-Piece. Chem. Eng. Technol. 2009, 32, 948−955. (11) Hagemann, O.; Jensen, A.; Grafsronningen, S. Cooldown of Subsea Deadleg With a Cold Spot: Experimental and Numerical HeatTransfer Analysis. Oil Gas Facil. 2016, 5, 1−8. (12) Nicholas, J. W.; Koh, C. A.; Sloan, E. D.; Nuebling, L.; He, H.; Horn, B. Measuring Hydrate/Ice Deposition in a Flow Loop from Dissolved Water in Live Liquid Condensate. AIChE J. 2009, 55, 1882− 1888. (13) Jassim, E.; Abdi, M. A.; Muzychka, Y. A New Approach to Investigate Hydrate Deposition in Gas-Dominated Flowlines. J. Nat. Gas Sci. Eng. 2010, 2, 163−177. (14) Rao, I.; Koh, C. A.; Sloan, E. D.; Sum, A. K. Gas Hydrate Deposition on a Cold Surface in Water-Saturated Gas Systems. Ind. Eng. Chem. Res. 2013, 52, 6262−6269. (15) Grasso, G. A.; Sloan, E. D.; Koh, C. A.; Sum, A. K.; Creek, J. L. Hydrate Deposition Mechanisms on Pipe Walls. Proceedings of the Offshore Technology Conference, Houston, TX, U.S.A., May 5−8, 2014. (16) Straume, E. O.; Kakitani, C.; Merino-Garcia, D.; Morales, R. E. M.; Sum, A. K. Experimental Study of the Formation and Deposition

ASSOCIATED CONTENT

S Supporting Information *

The Supporting Information is available free of charge on the ACS Publications website at DOI: 10.1021/acs.energyfuels.7b02901. 13543

DOI: 10.1021/acs.energyfuels.7b02901 Energy Fuels 2017, 31, 13536−13544

Article

Energy & Fuels of Gas Hydrates in Non-Emulsifying Oil and Condensate Systems. Chem. Eng. Sci. 2016, 155, 111−126. (17) Anderson, H. Computational Study of Heat Transfer in Subsea Deadlegs for Evaluation of Possible Hydrate Formation; M.S. Thesis, Telemark University College, Porsgrunn, Norway, 2007. (18) Nazeri, M.; Tohidi, B.; Chapoy, A. An Evaluation of Risk of Hydrate Formation at the Top of a Pipeline. Oil Gas Facil. 2014, 3, 67−72. (19) Wang, Z.; Zhang, J.; Sun, B.; Chen, L.; Zhao, Y.; Fu, W. A New Hydrate Deposition Prediction Model for Gas-Dominated Systems with Free Water. Chem. Eng. Sci. 2017, 163, 145−154. (20) Zhang, X.; Lee, B. R.; Sa, J.-H.; Kinnari, K. J.; Askvik, K. M.; Li, X.; Sum, A. K. Hydrate Management in Deadlegs: Effect of Header Temperature on Hydrate Deposition. Energy Fuels 2017, 31, 11802− 11810.

13544

DOI: 10.1021/acs.energyfuels.7b02901 Energy Fuels 2017, 31, 13536−13544