Experimental and Numerical Observations of Hydrate Reformation

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Experimental and Numerical Observations of Hydrate Reformation during Depressurization in a Core-Scale Reactor† Yongkoo Seol*,‡ and Evgeniy Myshakin‡,§ ‡

National Energy Technology Laboratory, 3610 Collins Ferry Road, Morgantown, West Virginia 26507, United States URS, 626 Cochrans Mill Road, Pittsburgh, Pennsylvania 15236, United States

§

ABSTRACT: Gas hydrate has been predicted to reform around a wellbore during depressurization-based gas production from gas hydrate-bearing reservoirs. This process has an adverse effect on gas production rates and it requires time and sometimes special measures to resume gas flow to producing wells. Due to lack of applicable field data, laboratory scale experiments remain a valuable source of information to study hydrate reformation. In this work, we report laboratory experiments and complementary numerical simulations executed to investigate the hydrate reformation phenomenon. Gas production from a pressure vessel filled with hydratebearing sand was induced by depressurization with and without heat flux through the boundaries. Hydrate decomposition was monitored with a medical X-ray CT scanner and pressure and temperature measurements. CT images of the hydrate-bearing sample were processed to provide 3-dimensional data of heterogeneous porosity and phase saturations suitable for numerical simulations. In the experiments, gas hydrate reformation was observed only in the case of no-heat supply from surroundings, a finding consistent with numerical simulation. By allowing gas production on either side of the core, numerical simulations showed that initial hydrate distribution patterns affect gas distribution and flow inside the sample. This is a direct consequence of the heterogeneous pore network resulting in varying hydraulic properties of the hydrate-bearing sediment.

1. INTRODUCTION Significant interest has been focused on gas hydrate, a naturally occurring ice-like solid substance mainly composed of water and methane, because of the ample volume of methane gas as a potential energy source.1-3 Estimates of the amount of methane housed in gas hydrate, based on current knowledge, continue to range over several orders of magnitude, with potentially recoverable resources existing on the scale of 3 1013 m3 (1016 ft3) at standard conditions.2 Gas hydrate deposits occur in the permafrost and in deep ocean sediments where favorable temperature and pressure conditions exist. The gas hydrate can be dissociated by lowering pressure to a level lower than the equilibrium pressure at the ambient temperature, by raising temperature to a level higher than the equilibrium temperature at the ambient pressure, or by adding chemical inhibitors to shift phase equilibrium boundary in the phase diagram of water -methane-hydrate system. Depending on the presence of mobile phase (gas or water) under the hydrate-bearing layer and low-permeability confining layers, natural hydrate deposits are categorized into four classes:4,5 Class 1 with mobile fluid (including gas) underlying layer, Class 2 with mobile underlying water layer, Class 3 with no mobile phase below (single zone), and Class 4 without confining layers (e.g., low concentration oceanic accumulations). Numerical simulation is an essential component of gas hydrate production research because of limited accessibility to direct field information from potential reservoirs, complexity of physical processes involved, and difficulties in predicting and preventing potential operational and environmental hazards. Recent numerical simulator developments can make it possible to model hydrate formation and dissociation reactions along with r 2011 American Chemical Society

multiphase flow under various complex geologic conditions. Numerical simulators have been mainly applied to identify technically and economically plausible hydrate resources, to determine feasible production scenarios on the selected reservoirs, and to assess controlling factors for optimal performance of gas producing reservoirs during gas production.6 Recent numerical simulation studies have predicted that secondary gas hydrate can form after the original gas hydrate dissociates, particularly near wellbores. The hydrate reformation occurs when dissociated gas enters a near-wellbore region of depressed temperatures resulting from endothermic cooling with hydrate dissociation and compounded by the Joule-Thompson effect. This gas hydrate reformation may be further promoted by the dilution of water salinity associated with ongoing dissociation of in situ gas hydrate.7 Numerical simulations predict that hydrate saturations can reach 0.9, resulting in significant reduction in gas production rates in both Class 1 and 2 reservoirs,7,8 as well as in Class 3 reservoirs employing depressurization at a constant bottomhole pressure.9 In an attempt to overcome the barrier effect on gas production rates, local electrical heating of the wellbore or warm water circulations near the production interval have been suggested.9 The simulation results, however, are based on assumptions including uniform hydrological and geological properties such as porosity, permeability, hydrate saturation, and other phase saturations. Recent studies10-12 compared production forecasts of gas hydrate reservoirs from the Alaska North Slope based on Received: October 25, 2010 Revised: January 7, 2011 Published: January 28, 2011 1099

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Table 1. Measured Properties of Cores parameter

a

Figure 1. Schematic of experimental system.

vertical variability of porosity and hydrate saturations derived from well-log data. These studies suggested enhanced gas production in comparison with prior studies using homogeneous data due to the presence of greater in situ permeability zones. Additionally, the impact of heterogeneity using random initialization or a geostatistical model based on well-log data for hydrate saturation or porosity has been investigated.12 The reservoir productivity shows complex response and displays overall poorer performance in comparison with a base homogeneous case. Secondary hydrate formation predicted in those studies obstructs gas flow and severely reduces in situ permeability. As the secondary hydrate formation can cause detrimental impacts on sustainable gas productions, it is critical to validate the potential formation of the secondary hydrate under conditions close to those that can occur at a reservoir scale. This study was intended to confirm the secondary hydrate formation during gas production through direct experimental observation and core-scale numerical simulations. Laboratory experiments of core-scale gas production have been performed using an X-ray computed tomography (CT) scanner and laboratory-synthesized hydrate bearing sediments.13,14 X-ray CT images were directly adopted into the numerical mesh which can provide initial conditions for numerical simulations. With this direct usage of CT-image based initial conditions, intrinsic heterogeneities in the sample core in terms of porosity and phase saturations were fully incorporated into the model domain grid with a 2-mm resolution. This study was also designed to experimentally simulate reservoir scale issues such as hydrate reformation by controlling boundary conditions. High-resolution X-ray CT images and numerical simulations utilizing the CT-image based sediment properties can provide better insights for the impacts of 3-dimensional (3-D) heterogeneity within laboratory-formed hydrate bearing sediments on potential occurrence of the secondary hydrate reformation.

2. METHODS AND MATERIALS 2.1. Laboratory Experiments. Initially moistened sand (F110 silica sand, US Silica, 0.35 porosity, and 20-40% water saturation) was packed into a rubber sleeve (5.08 cm diameter 19.8 cm length), which was placed in a triaxial confining pressure vessel. Multiple thermocouples at both ends were inserted into the sand pack for temperature monitoring. The entire pressure vessel including both end plugs was enclosed in a water jacket that provided constant temperature during experiments (Figure 1). Methane hydrate was formed by raising the pore pressure with methane gas to 8.3 MPa, while a confining pressure of

Test 1

Test 2

cylinder dimensions: diameter, d (mm)

51

length, L (mm)

188

188

porosity, φ

0.35

0.34

initial water saturation, Sw

0.21

0.37

permeability, k ( 10-12 m2), moistened

n.a.

0.693

permeability, k ( 10-12 m2), hydrate

n.a.

0.354

permeability, k ( 10-12 m2), saturated

n.a.

1.01

hydrate saturation, SH, estimated w/Sw hydrate saturation, SH, CT measured

0.26 0.26

0.46 0.40

water-to-hydrate conversion factor

1.0a

0.93

51

Assumed.

10.3 MPa and an initial temperature of 8 °C were applied on the sample. To mimic the occurrence of mobile brines within the reservoirs, the hydrate-bearing sand sample was subjected to water flooding followed by consecutive brine saturation (3.5 wt % KI) before dissociation. Instead of NaCl or KCl, KI was used because of high X-ray attenuation of KI. Similar experimental setup and procedures have been described in a previous study13 in greater detail. Dissociation induced by depressurization was executed in two different cases. In case 1, the pore pressure was reduced to 3.9 MPa to have the pressure difference of about 4.4 MPa (Test 1). In case 2, the depressurization occurred once the sample was surrounded by 3 °C coolant in order to mimic adiabatic condition (no heat flux through side boundary) around the sample (Test 2). Specifically, the temperature of coolant controlling temperature within the sample was lowered to 3 °C and once the temperature decline was detected by thermocouples located inside the sample closest to the rubber sleeve, the pore pressure was lowered to 3.9 MPa as done in the first case so that the temperatures both in and out of the sample were about the same (3 °C). During the entire course of the experiments, X-ray CT images were obtained regularly while pressure and temperature were continuously monitored. After the completion of hydrate dissociation (i.e., pore pressure was dropped to ambient pressure), the sample was air-dried to capture basic sand sample properties (porosity, initial water saturation). Permeability to gas or water was measured when the hydrate formation and water saturation were completed, respectively, by injecting constant flow of methane gas or water and measuring differential pressures at multiple steps of flow rates (Table 1). Based on the CT images of dry and watersaturated samples, hydrate saturation, initial and residual water saturation, and porosity were calculated (Table 1). Because the dry and saturated sand images were obtained after all the experiment procedures were completed, the hydrate saturation, initial and residual water saturation, and porosity were calculated later. To capture potential hydrate reformation, CT images were taken frequently during the dissociation and each image set was subtracted from the base image set taken before dissociation. 2.2. Image Processing for Input Generation. X-ray CT observations have been utilized to quantitatively examine fluid flow behavior upon depressurization and hydrate dissociation within the sediment. The X-ray attenuation is directly proportional to the combined mass of the materials in a voxel (a rectangular parallelepiped over which attenuation is computed). There are four sets of CT scan images taken during the test: (1) base scans of the initially packed core, (2) sample scans during hydrate dissociation, (3) dry scan on the air-dried core, and (4) saturated scan on the water-saturated core. The dry and saturated scans were obtained after the hydrate formation and water injection were completed. The two sets of images provide the possible range of X-ray attenuation with water in the sands, and images taken at other stages were compared to the attenuation ranges set by the two 1100

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Table 2. Reactor Properties, Initial Conditions, and Pertinent Model Parameters parameter

value

cylinder dimensions: diameter, d (mm)

50.8 þ 5.4 mm rubber sleeve

length, L (mm)

203.2

initial pressure, P0 (MPa)

6.9

initial temperature, T0 (°C)

8

water salinity (mass fraction of KI)

0.035

initial hydrate saturation, SH

heterogeneous

initial aqueous saturation, SH

heterogeneous

intrinsic permeability, k (D) pore compressibility, Rp (Pa-1)

1.01 5 10-9

porosity, φ

heterogeneous

dry thermal conductivity, kdry (W/m K)

0.5

wet thermal conductivity, kwet (W/m K)

3.1

composite thermal conductivity, kΘ (W/m K)21

kΘ = kdry þ ((SA)1/2 þ (SH)1/2)(kwet - kdry) þ φS1k1

capillary pressure model22

Pcap = -P[(S*)-1/λ - 1]1-λ S* = ((SA - SirA)/(SmxA - SirA))

SirA λ

0.11 0.45

SmaxA

1

relative permeability

n n krA = (S*) A ; krG = (S* G)

modified Stone 3-phase model23

S*A = ((SA - SirA)/(1 - SirA)); S*G = ((SG - SirG)/(1 - SirG))

n (aqueous/gas)

4.0/2.5

SirG

0.02

SirA

0.12

range-defining conditions. The image calculations have been executed with ImageJ.15 For the calculation of saturation and porosity, there were three assumptions made: (1) the conversion of hydrate into water occurs at the constant molecular ratio of 5.75, (2) the density of hydrate is 0.917 g/cm3,16 and (3) the density of the gas phase is much less than the densities of the other phases. The sample before the depressurization was flooded with KI solution, which causes difficulties in quantitative analysis of CT images. While the sample contains the KI, the CT images were compared only for attenuation contrasts. Direct incorporation of CT images into numerical simulations requires immense computation capacity, due to the fine resolution (512 512) of the CT images. Reduced resolution may be sufficient for looking into flow behavior through porous media of interest. An automated tool has been developed to convert X-ray CT image data suitable for a mesh used in numerical simulations. The tool reduces the total pixel numbers of original CT images by setting a larger grid dimension and averaged pixel values within the elements to assign the values into the larger corresponding grid elements. The extent of reducing total pixel numbers was adjusted so that in each grid element, properties were homogeneous, while the entire model domain preserved intrinsic heterogeneous nature of the original 3-D image. The conversion starts from cropping images into 280 280 pixels to eliminate marginal noninformative area. The cropped images are scaled down to 28 28 pixel images with a reducing ratio of 10, which was determined based on (1) multiple trials of reducing show the 1:10 reducing preserves the original heterogeneous pattern of hydrate distributions while keeping the total number of pixels at minimal, and (2) the final dimension of pixels (1.951 1.951 mm) is close to the thickness (2.0 mm) of each slice, i.e., the dimension of z-axis of grids. Seol and Kneafsey17 provided a detailed description of sequential reduction of pixels numbers and resulting images representing original heterogeneity retained, showing the changes of mean density and standard deviation of scanned area with reducing pixel numbers in a row (from 300 to 5) at the reduction steps. The initial density and standard deviation were kept nearly steady until

they are drastically dropped at the scale of 10 10 pixels, which confirms the minimum number (28 28) of pixels would retain the initial heterogeneity while keeping the total pixel numbers at minimum. The resulting model has a smaller number of elements that can be readily handled and still capture the heterogeneous nature of fluid flow and hydrate evolutions occurring in a model domain. 2.3. Numerical Simulations. The numerical simulation code TOUGHþHYDRATE18 was used to predict gas production from a laboratory core-scale, cylindrical pressure vessel containing a hydratebearing sand sample. The TOUGHþHYDRATE code includes the equilibrium model considering the hydrate formation and dissociation as proceeding at equilibrium state, as well as the kinetic model governed by the kinetic equation of Clarke and Bishnoi.19 The kinetic model describes the hydrate dissociation process at a reactor scale but requires an additional mass component and equation for every grid block. It was shown that kinetics plays an important role in prediction of gas production rates from a hydrate core.20 In this study, the kinetic model was used to perform simulations of gas production. The reactor model was designed as a 3-dimensional (3-D) model represented with a fine discretization of 82,561 grid blocks and 240,293 connections. This allows incorporating explicitly the effect of gravity into the model. The dimensions of the model represent those used in the laboratory experiment with explicit description of a rubber sleeve around the hydrate-bearing core. Detailed information on reactor properties, initial conditions, and pertinent model parameters are given in Table 2. Gas hydrate decomposition was induced by depressurization at a port located at the center of one of the ends of the cylindrical reactor. The pressure drop at the exit port was 3.9 MPa. In the numerical model, the port was simulated by adding one extra element and a corresponding connection to the central grid block of the mesh. This provides a 4 mm2 exposure area of the core to depressurization by assigning that extra element as a fixed pressure boundary, similar to the way reservoir scale simulations are conducted at a constant bottom-hole pressure.7 1101


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Figure 2. X-ray CT images of Test 1 Core hydrate-bearing, brine saturated, and under dissociation, and subtracted images of cores under dissociation from brine saturated core images. The white circular spots in the first and last image of each column are thermocouples. The simulations were performed with and without heat exchange with the surroundings. At the simulations without heat flux, the only heat supply into the modeled reactor was allowed through the port. Between the port and hydrate sample, a thin (2 mm) section of liquid-filled high porous (0.5) media was included to provide uniform exposure of hydrate to depressurization through the entire cross-sectional surface similar to the experiment setup. An intermediate layer between hydrate bearing sample and outside coolant, described with thermophysical properties of rubber, was also incorporated into the reactor model to mimic the rubber sleeve around the sample. The thickness (5 mm) of the modeled sleeve was similar to that of the experimental one. The numerical simulations used initial pressure and temperature (P/T) conditions corresponding to those in the experimental hydrate samples. The temperature depression induced by the presence of KI on the equilibrium P/T relationship was computed internally in the code through the equation of Dickens and Quinby-Hunt.24 The simulations utilized heterogeneous porosity and phase saturations (water, gas, and hydrate) derived from the X-ray CT observations. For numerical stability, the following restriction was imposed when adapting experimental porosity and saturation data into input for numerical simulations: if porosity fell below 0.1, it was internally reassigned to the value of 0.1; and if hydrate saturation exceeded 0.85, it was reassigned to that value of 0.85. The total number of elements requiring these restrictions was no more than 2% of the total elements of the model and it was assumed that impacts to the overall system responses to hydrate dissociation and flow dynamics would be negligible. We also performed additional simulation cases to study the effect of port locations since hydrate distribution displays a trend of a higher saturation pattern on that size of the experimental reactor that was first exposed to gas injection. The case where the production port was placed on the left side of the cylinder end was designated as “HetL”, and the case with the port was located on the right side was designated as “HetR”, which is reproducing the experimental setup. In the text, the terms “released” and “produced” gas are understood as the following: during methane hydrate decomposition in response to depressurization, methane and water are first released from hydrate, and then move to the production port in response to a pressure gradient. Upon exiting the port, the released gas is then considered as produced gas.

3. RESULT AND DISCUSSION 3.1. Hydrate Distributions. Initial water saturations in the moistened sand were 0.21 and 0.37 in the two separate experiments, which will result in hydrate saturations of 0.26 and 0.46, respectively (Table 1), based on the assumption of 100% conversion of water into hydrate. Although the hydrate saturation used in Test 1 is somewhat lower than an average saturation encountered in hydrate-bearing reservoirs, the saturation achieved for Test 2 is close to average reservoir hydrate saturations. For example, the mean of hydrate saturation computed from the Mount Elbert well-log data is around 0.61.25 Figures 2 and 3 in the first column show hydrate distribution patterns in the two tests. Note that the hydrate distributions resulted from the final hydrate formation events of multiple sequential trials (4 times on Test 1 and 3 times on Test 2), which had been designed to increase uniformity in gas hydrate distributions in the sample. On the CT images, hydrate is shown as brighter because hydrate is denser than gas. Although both tests were performed at the same pressure and temperature condition and with similar initial water saturations, the hydrate distributions show completely different patterns as shown as numerous spotty sphere patterns on Test 1 and a largely centered continuous-tube pattern on Test 2. 3.2. Dissociation and Hydrate Reformation Tests. After hydrate formation, the hydrate-bearing samples were flooded with the brine solution (3.5 wt % KI), which had been purged with methane gas for several days, to mimic the natural conditions in which hydrate bearing sediments are saturated with saline water. This experimental sequence of hydrate formation before brine saturation was adopted to form hydrate faster and to avoid variable salinity in the sample due to nonuniform hydrate formation. The main objective of the current study was to examine the impacts of secondary hydrate formation during gas production from hydrate dissociation, so it was important to identify the conditions that can promote secondary hydrate reformation. 1102


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Figure 3. X-ray CT images of Test 2 Core hydrate-bearing, brine saturated, and under dissociation, and subtracted images of cores under dissociation from brine saturated core images. The white circular spots in the first and last image of each column are thermocouples.

Figure 4. Pressure-temperature profiles during dissociation tests: (a) Test 1, and (b) Test 2.

Based on the previous numerical simulations, hydrate reformation was predicted to occur near production wells, and the dissociation interface is evolved not only in response to depressurization, but due to heat flux through the boundary with surrounding over- and under-burden formation.

The two experiments were designed to represent two distinct natural reservoir conditions: (1) production from a relatively thin reservoir or marginal area of thick reservoir with nearby lowpermeability bounding units that provide a source of heat, and (2) a thicker reservoir in which production was not readily impacted by reservoir boundaries with minimal heat influx. Figure 4 shows the profiles of pressure and temperature during dissociations of the two tests. In the first test, the temperature of coolant circulating the sample kept sample temperature constant at the hydrate formation temperature of 8 °C. As a result, during the dissociation with depressurization, heat can be transferred into the sample through the rubber sleeve, so that the temperature initially lowered to about 3 °C (as monitored with thermocouples) due to endothermic hydrate dissociation and an additional Joule-Thompson effect of exiting gas, rebounded to the initial temperature (8 °C) with the heat transferring from surrounding temperature control coolant (Figure 4a). In the second test with adiabatic (no heat transfer) boundary condition, there would be minimal heat flux from the confining fluid into the sample. Possible sensible heat dissipation from the sample was assumed negligible because of the low thermal conductivity of the rubber sleeve and quick temperature drop inside the reactor after dissociation was induced. Since there were no thermocouples monitoring temperature in the confining fluid and at the contact between the rubber sleeve and the core, the time to start depressurization was determined by declining temperature at the thermocouple located nearest to the contact in the sample. As soon as the internal temperature of the sample started declining, the pore pressure was lowered to initiate hydrate dissociation. When the pressure was dropped and dissociation began, the temperature inside the sample became about 3 °C as shown in the first test. Heat transfer was minimized as the temperatures in and out of the sample were nearly the same (Figure 4b). 1103


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Figure 5. Evolution of pressure and temperature during dissociation tests in relation to the phase stability curve of methane hydrate.

Dissociation tests were completed by lowering the pore pressure further after 3.3 h for Test 1 and 25 h for Test 2. Figure 5 presents pressure-temperature evolution profiles compared with the methane hydrate stability curve. The numbers in the figure represent the tests, and characters (A-D) represent steps during the tests such as initial condition (A), first depressurization (B), temperature drop (C), and second depressurization (D). Dissociation started by lowering pressure (1A f 1B, 2A f 2B) and temperature dropped rapidly (1B f 1C, 2B f 2C). Dissociation continued as the reaction pathway moved from 1B to 1D and 2B to 2D. In Test 2, the reaction pathway stayed near the equilibrium condition during 2C and 2D; hydrate formation and dissociation would occur simultaneously because endothermic cooling and salinity change cause a shift of P/T conditions in the hydrate stability zone. During the dissociation periods, the samples were monitored using periodic X-ray CT scanning. Columns in Figures 2 and 3 present the selected CT images of the samples after gas hydrate formation and brine saturation and during dissociations sequentially. Rows in the figures are images at the specific locations of the samples at the specified distance from the fluid injection port side of the sample. The first columns are the images of the hydrate bearing samples after the completion of hydrate formation, as discussed in the section above. The second columns on Figures 2 and 3 are the CT images of brinesaturated samples as a base state (Brine Flooded, BF) before dissociation. The rest of the columns after the second column are composed of multiple pairs (3 pairs for Test 1 and 4 pairs for Test 2) that consist of raw observation images at different times and their difference images from the images of BF. The difference images show the differences in density due to hydrate dissociation between the observations at the specific time and BF. For example, the third columns of the figures show the images of the samples after 0.7 h of dissociation. To show the difference in density after the 0.7 h of dissociation, the images on the third column (Diss. 1, t = 0.7 h, Dt0.7) were subtracted from BF, and the next columns are the results of the subtraction between BF and the first observation at t = 0.7 h (Dt0.7). The next pairs of columns are the observations at different times (t = 3.0 and 24 h) and the subtractions from BF. The last pair of columns in each figure are the CT images of the samples after the completion of dissociation (4.0 or 26 h on Test 1 and 2, respectively) with additional pressure drops and the subtractions between the final observations (Dt4.0 or Dt26) and the last observations from the first depressurization period (Dt3.0 or Dt24) accordingly.

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Column 1 and 2 in Figures 2 and 3 are raw images showing density variations of the samples due to nonuniform phase distributions. The lighter color shown as bright yellow suggests higher density area while the darker red color means lower density region. The higher density region suggests that the area is filled with higher density material such as hydrate and KI brine. In the first column, because hydrate is denser than gas, hydrate distribution is clearly noticed. The KI has distinctly higher X-ray attenuation than water and hydrate so that the region filled with the brine appears as higher density area, shown as the brighter area in the second column. Note that the brightness of the first two columns was adjusted to emphasize the patterns of hydrate distribution and brine-flooded area. The raw images of Test 1 show a slightly noticeable trend of darkening as dissociation proceeds. Test 2 shows even more subtle changes in X-ray attenuation in the raw images. Because of the subtle changes in raw images, the subtraction images are compared and discussed below. Subtraction images were presented with a blue-white-red color scheme. Blue colors denote negative changes in attenuation reflecting decreases in density, and are interpreted to result from gas hydrate dissociation, dilution of the brine, and gas generation or intrusion. Red colors indicate positive changes in density attributed to gas hydrate formation and water or brine infiltration. White color indicates no changes in attenuation (Figures 2 and 3). In Figure 2, the subtraction images at different times become deeper blue throughout the imaged locations, and the last subtraction images on the column show mostly white with some blue, which indicates the additional dissociation resulted from the second pressure drop was not significant as most gas hydrate had already dissociated. The subtraction images for Test 2 (Figure 3) show negative changes (blue) in attenuation, in other words, potential hydrate dissociation (gas generation and brine dilution), occurs mostly in the area outside of the high hydrate saturation region located at the center of the core. Hydrate dissociation (or gas accumulation) appears to be more intense at the outer region where hydrate saturation was relatively low and heat transfer and pressure propagation would be faster. With time, the outer dissociation zone becomes darker (gas accumulation, water dissipation), and at the same time, the whiter region in the center becomes larger. During the period (24 h), while some released gas and water exits the core rapidly, some methane gas can be trapped into hydrate again or accumulation or imbibition of the released water happens, not only in the outer area but also inside the area of the high hydrate saturation zone. Because the P/T condition inside the sample was maintained near hydrate phase boundary condition, water can be formed into hydrates as salinity reduction can shift, thus, the density increase (i.e., blue turns into white) within or near the white region can result from hydrate reformation. With current resolution of the CT images, however, the definite determination of the phase causing the density increase in the area cannot be made. Numerical simulations, which will be discussed later, were performed to confirm the interpretation of gas hydrate reformation. With the second pressure drop, the white region in Column 8 showed density decrease as shown in the blue region in Column 10. This observation indicates the remaining hydrate in the white region was dissociated or water (or brine) imbibed into the high hydrate saturation region was expelled with released gas from the hydrate. The pattern of the blue region shows exact matching with the white region on the last subtraction images of the first 1104


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Figure 6. Production rates and cumulative gas volumes recorded during dissociations.

depressurization (Column 8), instead of the region on the first subtraction images (Column 4), and the density decrease is quite uniform within the blue region (slices at 50, 90, and 130 in Column 10). If the expansion of the white region were caused by water accumulation in the marginal area, the outer area of the initial white region would show less density change because the water-filled region would be less impacted by depressurization. This observation supports the density increase (the white region in Column 8) may be due to hydrate reformation during the dissociation period and the uniform density drop may be associated with hydrate dissociation with the second pressure drop. The interpretation of gas hydrate reformation will be further confirmed by the numerical simulations. Figure 6 shows the production rates and cumulative fluid volume collected at the outlet pump during the dissociation. The production rates spiked as soon as the pore pressure was released at both tests, and the cumulative volume steadily increased in Test 1 due to the continuous hydrate dissociation with heat influx, while it swiftly plateaued in Test 2 with balanced hydrate dissociation and reformation. Figure 7 illustrates the subtraction images at the dissociation time of 0.7 h, which were sampled more frequently (every 14 mm) and adjusted for brightness and color schemes to emphasize density decreases during dissociation. The images show localized density drops, marked with dotted circles and arrows, suggesting preferential flow pathways of released gas from hydrate dissociation. Due to the intrinsic heterogeneity in porosity and hydrate saturation, released gas and water from hydrate dissociation can find permeable flow pathways, and result in forming localized preferential flow channels, rather than a flow with a uniform moving front. In a perfectly homogeneous medium, such pathways might not be able to form. Some of those pathways (dark spots in the images) show noticeable continuity in locations and

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tend to appear more in the marginal area where hydrate dissociation and gas accumulation actively occurred. It is important to note that a development of preferential flow pathways is influenced by a degree of heterogeneity in a sample. In nature the hydrate distribution tends to be more uniform in comparison with the case considered in this study. In this regard, the processes of gas flow through highly permeable channels can be exaggerated due to highly heterogeneous media. Overall, depressurization initiates gas hydrate dissociation, mostly near the outer marginal area with low hydrate saturation, which results in a gas-filled region that enables the development of focused flow conduits. Simultaneously, some of the released gas can form secondary hydrate with released and initially present water available. Over the period that the system was at the phase boundary condition with a very low pressure gradient to mobile phase flow, hydrate not only dissociated but also redistributed as it reformed. This is possible because after sensible heat is nearly exhausted and virtually no heat flux is coming from the surroundings to maintain the decomposition reaction, the system remained at equilibrium and even a slightest change in P/T conditions could cause reformation. Salinity change and endothermic hydrate decomposition reactions are considered as factors promoting the reformation. Methane left in the system with water retaining residual partial clathrate structures can form hydrate with zero induction time.26 Heterogeneous hydrate saturation and complex pore networks lead to nonuniform dissociation depending on initial hydrate saturation and porosity with gas distributed differently in a system according to preferential flow pathways. As a result, it is unlikely that hydrate reformation could create complete blockage of flow pathways, particularly in the system with about 40% (on average) initial hydrate saturation. However, at a reservoir scale hydrate saturation can vary within a broad range depending on the sediment type and sand quality. At high hydrate saturation values even small changes could drastically reduce permeability and seal media for fluid transport. 3.3. Numerical Simulations of Hydrate Reformation. Figure 8 depicts initial gas hydrate saturation and porosity distribution existing inside the sample of Test 2 prior to depressurization. The hydrate saturation is highly heterogeneous so that some areas are free of hydrate while some display high saturation values. Porosity demonstrates a layered distribution which can be attributed to the way the sand was packed. In the numerical simulations, the sample was exposed to depressurization through a port located either on the right side, the HetR case as in the experiment, or on the left side, the HetL case. Figure 9 shows production rates and total volumes of mobile phases (gas and water) for the HetR (the rate and total cumulative volume obtained at the HetL case are close to those at HetR and are not shown in the figure) in comparison with experimental values (Test 2). The rate and volume of gas were adjusted to the experimental conditions with accounting for gas compressibility. Figure 9 displays that upon initial depressurization the rate curves demonstrate a peak reflecting intense gas hydrate decomposition similar to that recorded in the experiment. After several minutes, the dissociation process rapidly slowed because of exhaustion of sensible heat available in the system and adjusted pore pressure inside the sample to that at the exit port. The stabilization in pressure and temperature around 3 °C is confirmed by analyzing evolution of P/T conditions inside the modeled sample. Comparison of the experimental and predicted production rates (Figure 9) reveals that the peak of the 1105


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Figure 7. Subtracted CT images at first observation during dissociation. Arrows and dotted circles indicate potential preferential pathways (dark spots) of gas released during hydrate dissociation. The numbers on the top right corner of each slice show the location (mm) of the slice from the injection point.

Figure 8. Initial hydrate saturation (a) and porosity distribution (b) shown in a cross-section of the reactor taken along its length and a diameter.

experimental production rate was somewhat lower than the predicted curve during the first minutes after depressurization.

Figure 9. Production rate (a) and cumulative volume (b) of mobile phases produced at the HetR case in comparison with experimental values (Test 2).

As a result, the cumulative volumes of collected and predicted fluid show about 30% difference at the end of the first production hour. While such deviations can result from experimental factors such as sensitivity of the receiving pump at pressure gradient and 1106


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Figure 10. Change of hydrate saturation (a), pressure, Pa (b), and salinity (d) occurring between first and second minute of production together with gas saturation distribution (c) after 2 min at the HetL case in the left column and HetL cases in the right column.

data collection frequency, they can also be attributed to numerical parameters including default parameters in the relative permeability and capillary pressure functions, resolution of grids in the model domain, heterogeneity of flow paths captured in the model, and kinetic parameters for hydrate dissociation. Additional experiments are needed in conjunction with inverse history matching to estimate those parameters relevant to synthesized hydrate samples. The production rates shown in Figure 9 suggest that the process of gas hydrate dissociation at the core scale can be divided into two main stages. The first lasts about 10-15 min and is characterized by high gas rates under fast flow regime, steady declining temperature due to intense hydrate decomposition, a large initial driving force (the temperature difference) for kinetics, and rapid dissociation supported by sensible heat available in the system. The second stage is described by low gas production rates resulting from pressure stabilization within the sample, hydrate dissociation at P/T conditions close to equilibrium, and nearly full consumption of sensible heat with the only heat source available at a port (slow conductive transport). Because of distinctly different conditions at those

stages we analyze them separately focusing on the hydrate reformation phenomenon. Because of a short time frame for the first stage and limited scanning periodicity, X-ray CT imaging could not capture the short-term process to characterize system evolution. The CT images (Figures 2 and 3) used to deduce gas hydrate reformation present combined pictures of multiple processes that occurred over the time periods. Figure 10 shows changes in gas hydrate saturation, pressure, and salinity computed as a difference between two data sets obtained after 1 and 2 min of production (positive values indicate accumulation of properties of interest while negative ones show their depletion) together with gas saturation distribution after 2 min at the HetL and HetR cases. It is clearly seen that hydrate is reforming behind the dissociation front (Figure 10a), suggesting that reformation can proceed concurrently with dissociation. The plausible explanation for the reformation is that hydrate is decomposing not only at a sharp interface with hydrate-free porous media, but also inside a hydrate sample in response to depressurization, which has been observed in the CT images of Test 2 (Figure 3). As a consequence of rapid decomposition inside a sample, the local gas pressure buildup can cause a temporary shift of the P/T 1107


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Figure 11. Hydrate saturation evolution in HetL case after 0.6 h (a), 5 h (b), and 27 h (c) of production together with corresponding changes in hydrate saturation during 0.3-0.6 (a), 3-5 (b), and 21-27 (c) hour time frames.

conditions into the hydrate stability zone. In this regard, the direction of gas flow is important in samples for developing local pressure gradient as heterogeneous hydrate saturation would interfere in exiting gas flow. Notice that the reformation develops more intensively at the HetL case where released gas has to flow through areas with higher hydrate saturations (lower permeabilities) than at the HetR case (Figure 8). As a result of the lower permeability with higher hydrate saturation, pressure increases more steeply at HetL and contributes to more pronounced hydrate reformation (Figure 10b). Moreover, gas saturation distribution depicted in Figure 10c displays its accumulation at the top of the pressure vessel at the HetL case while at HetR it reveals a relatively uniform distribution. Further system evolution shows that gas accumulation is changed with depletion as hydrate decomposition is causing a permeability increase in pore space. Gas delivery to a port is also facilitated by the heterogeneous porosity distribution creating a network of preferential flow pathways with varied hydrological properties. At a reservoir scale, a development of flow channeling using a geostatistical reservoir model has been predicted.12 The final two pictures depict salinity changes during the chosen time interval (Figure 10d). Salt exclusion appears in the hydrate reformation areas together with areas of diluted brine cased by hydrate dissociation and fresh water accumulation. It is important to understand that hydrate reformation during the first stage of production is transient in nature. It is mainly driven by temporal local pressure increase inside hydrate-filled pore space with salinity change and endothermic cooling as supporting factors. For the second stage, results of numerical simulations are presented in Figure 11 depicting hydrate saturation evolution

together with hydrate saturation changes over the same production period of the experimental observations. Hydrate saturation distributions captured at three time points show that hydrate reformation clearly evolves in the right part of the vessel crosssection, while the rest continues to dissociate. The dissociation is maintained by slow heat leak through a port; otherwise, at truly adiabatic conditions hydrate decomposition would stop soon after the end of the first stage with some undissociated gas hydrate remaining in the system. The corresponding hydrate saturation changes (right column in Figure 11) indicate the areas where hydrate either dissociates (shown in blue) or reforms (shown in red). Figure 11a shows the reformation process that occurs during the first 0.6 h at marginal areas along hydrate-free regions and zones with dissociating hydrate. Later (after 5 h), hydrate reformation occurs entirely around a hydrate “island” on the right side of the pictures (Figure 11b) and persists until the late production time (Figure 11c). It is noticeable that the hydrate saturation change reveals that reformation is switched to decomposition in the same area after 21 h of production since reformation process causes temperature to increase, which in turn leads to an eventual shift of the P/T conditions back into the hydrate dissociation zone. At the second stage, dissociation continues at equilibrium and it is highly unlikely that pressure variations could be a main reason of reformation. Thus, endothermic cooling combined with salinity change are the only factors promoting a shift of the P/T conditions into the hydrate stability zone. To explore the effect of salinity a separate simulation of gas production from the same hydrate sample but without salt present (initial temperature was increased by 1.2 °C to compensate for the shift in hydrate 1108


Energy & Fuels equilibrium conditions induced by the absence of salt, and reinitialization of initial conditions inside the modeled sample was performed) was conducted while keeping other parameters the same. The results indicate that no hydrate reformation similar to that depicted in Figure 11 is confirmed during the second stage of production (whereas reformation inside the core during the first stage was detected providing more credit to pressure buildup as a main cause of reformation there). Thus, salinity change appears to be a leading factor triggering reformation process as predicted at numerical simulations.

4. CONCLUSION AND SUMMARY In this paper, laboratory experiments studying depressurizationinduced gas production from a hydrate sample were performed to confirm the hydrate reformation phenomenon predicted at a reservoir scale. The experiments were designed to simulate two distinct thermal boundary conditions that can be found in natural hydrate reservoirs. In conjunction with supportive numerical simulations, the experimental study confirms the hydrate reformation and the development of preferential flow pathways during the depressurization. This study shows that laboratory-scale tests can be utilized to examine phenomena that can occur at a reservoir scale, and while qualitative description of processes captured by X-ray CT image can help elucidate the dynamic processes occurring within the hydratebearing sediment, quantitative information from X-ray CT images can also be of significant assistance to more accurately simulate the complicated processes governed by intrinsic heterogeneities of hydrodynamic properties. Information on heterogeneity of porosity and hydrate distribution in a sample is particularly important when interactions between flowing fluid and sediment matrix including hydrate are the subject of interest. X-ray CT observations of lab-formed hydrate bearing sediments provide direct insight into how hydrate dissociation, gas coalescence, fluid migration, and hydrate reformation can occur at that scale. This study was performed to confirm hydrate reformation during gas production as the hydrate reformation has been predicted with reservoir simulations to impose negative impacts on sustained gas production. X-ray CT observations captured a potential feature of hydrate reformation during the core-scale production tests. The feature includes increased density in the marginal area of high hydrate saturation region as well as inside the high hydrate saturation region while the rest of sample continues to lose density. With additional pressure drop, the region of the potential hydrate reformation showed density decrease, suggesting the region might have been filled with a phase denser than gas, i.e., hydrate or water. Numerical simulation supports that the density increase can be hydrate reformation. The feature suggesting hydrate reformation develops only when the system is isolated from external heat supply (i.e., adiabatic condition) that is required to continue the dissociation process. In the perspective of natural hydrate reservoir, the conditions close to adiabatic mimic the situations that can occur in the middle of the hydrate reservoir where heat exchange with surrounding formation was limited and reformed hydrate would persist. The CT observation also captured that dissociation occurs variably depending on initial hydrate saturation and boundary conditions, and released gas exits the system rapidly through preferential flow pathways, which make it difficult to develop uniform hydrate reformation pattern that can create complete blockage of flow pathways.

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Numerical simulations have utilized a core-scale hydrate bearing sediment model similar to that used in the experiment. A technique was developed to convert X-ray CT image data into input for numerical simulations. Subsequently, a model of the hydrate sample employing 3-D heterogeneous hydrate saturation and porosity was prepared based on experimental information. The simulations predict the hydrate reformation evolves during gas production. In the initial stage characterized with intense decomposition and large production rates, transient reformation occurs inside the dissociating sample in response to local pressure buildup. Heterogeneity in hydrate saturation pattern and porosity network can create an environment where gas can flow through high permeability channels to a port. At the second stage, hydrate continues to dissociate at conditions close to equilibrium under small pressure gradient. During that time hydrate reformation slowly develops as a consequence of endothermic cooling and salinity reduction. The reformation is predicted to start at the marginal areas and evolves to saturations detectable in CT data. This result supports the experimental interpretation of the hydrate reformation phenomenon reported above. The mechanism of hydrate reformation considered in this work is different from that predicted in previous work focused at a reservoir scale.7,9 There, the secondary hydrate barrier around a well was primarily driven by endothermic cooling and the Joule-Thomson effect. Here, by employing 3-D heterogeneous experiment and modeling we show that salinity reduction could be a major driving force of hydrate reformation together with the endothermic cooling. That reformation could occur on a large scale and far from a well under conditions of abundant fresh water drainage into low regions of a producing hydrate reservoir (especially in hydrate-bearing marine sediments). The extent of reformation and its preservation through time would be probably limited by local temperature raise due to gas hydrate formation and continuous depressurization that would shift P/T conditions back into the hydrate instability zone. To confirm that process in numerical simulations, a 3-D heterogeneous model providing complex pore network for water migration will be required.

’ AUTHOR INFORMATION Corresponding Author

*Phone: þ1 (304)-285-2029. Fax: þ1 (304)-285-0903. E-mail: [email protected].

’ ACKNOWLEDGMENT We greatly benefited from the reviews by Ray Boswell and Timothy Kneafsey, and technical support from Karl Jarvis and Brian Tennant. E.M. performed this work under contract DE-FE0004000, Subtask 4000.4.605.261.001 in support of the National Energy Technology Laboratory’s Office of Research and Development.

’ DISCLOSURE † Disclaimer: Reference in this report to any specific product, process, or service is to facilitate understanding and does not imply its endorsement or favoring by the United States Department of Energy. ’ REFERENCES (1) Kvenvolden, K. A.; Lorenson, T. D. The Global Occurrence of Natural Gas Hydrate, Natural Gas Hydrate: Occurrence, Distribution, and Detection; Geophysical Monograph 124; American Geophysical Union: Washington, DC, 2001; pp 3-18. 1109


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(2) Boswell, R.; Collett, T. Energy Environ. Sci. 2011No. doi: 10.1039/c0ee00203h. (3) Makogon, Y. F.; Holditch, S. A.; Makogon, T.Y. J. Petrol. Sci. Eng. 2007, 56, 14–31. (4) Moridis, G. J.; Collett, T. S. Recent Advances in the Study of Gas Hydrate; American Institute of Chemical Engineers and Kluwer Academic/ Plenum Publishers: New York, 2004; pp 75-88. (5) Moridis, G. J.; Kowalsky, M. B.; Pruess, K. SPE 97266, SPE Annual Conference, Oct. 9-12, 2005, Dallas, TX. (6) Moridis, G. J.; Collett, T.; Boswell, R.; Kurihara, M.; Reagan, M. T.; Koh, C.; Sloan, E. D. SPE Res. Eng. Eval. 2009, 745–771. (7) Moridis, G. J.; Reagan, M. T. OTC 18866, Offshore Technology Conference, April 30-May 3, 2007, Houston, TX. (8) Moridis, G. J.; Seol, Y.; Kneafsey, T. J. Report LBNL-57295; Lawrence Berkeley National Laboratory: Berkeley, CA, 2005. (9) Moridis, G. J.; Reagan, M. T. OTC 18865, Offshore Technology Conference, April 30-May 3, 2007, Houston, TX. (10) Anderson, B. J.; Wilder, J. W.; Kurihara, M.; White, M. D.; Moridis, G. J.; Wilson, S. J.; Pooladi-Darvish, M.; Masuda, Y.; Collett, T. S.; Hunter, R. B.; Narita, H.; Rose, K.; Boswell, R. Proceedings of 6th International Conference on Gas Hydrates, July 6-10, 2008, Vancouver, British Columbia, Canada. (11) Anderson, B. J.; Kurihara, M.; White, M. D.; Moridis, G. J.; Wilson, S. J.; Pooladi-Darvish, M.; Gaddipati, M.; Masuda, Y.; Collett, T. S.; Hunter, R. B.; Narita, H.; Rose, K.; Boswell, R Mar. Pet. Geol. 2010In press. (12) Reagan, M. T.; Kowalsky, M. B.; Moridis, G. J. SPE 97266, SPE Western Regional Meeting, 27-29 May, 2010, Anaheim, CA. (13) Seol, Y.; Kneafsey, T. J. J. Petrol. Sci. Eng. 2009, 66, 121–132. (14) Kneafsey, T. J.; Seol, Y.; Gupta, A.; Tomutsa, L. SPE J. 2010In Press. (15) Abramoff, M. D.; Magelhaes, P. J.; Ram, S. J. Biophotonics Int. 2004, 11, 36–42. (16) Sloan, E. D. Clathrate Hydrates of Natural Gases, 2nd ed.; Marcel-Dekker: New York, 1998; 705 pp. (17) Seol, Y.; Kneafsey, T. J. J. Geophys. Res. 2011In review. (18) Moridis, G. J.; Kowalsky, M. B.; Pruess, K. TOUGHþHYDRATE v1.0 User’s Manual: A Code for the Simulation of System Behavior in Hydrate-Bearing Geologic Media; Report LBNL-149E; Lawrence Berkeley National Laboratory: Berkeley, CA, 2008. http://esd.lbl.gov/ toughþ/manuals/TplusH_Manual_v1.pdf. (19) Clarke, M. A.; Bishnoi, P. R. Can. J. Chem. Eng. 2001, 79, 143– 147. (20) Kowalsky, M. B.; Moridis, G. J. Energy Conv. Manage. 2007, 48, 1850–1863. (21) Makogon, Y. F. Hydrates of Hydrocarbons; PennWell: Tulsa, OK, 1997. (22) van Genuchten, M. Th. Soil Sci. Soc. Am. J. 1980, 44, 892–900. (23) Stone, H. L. Trans. SPE AIME 1970, 249, 214–220. (24) Dickens, G. R.; Quinby-Hunt, M. S. J. Geophys. Res. 1997, 102, 773–783. (25) Lee, M. W.; Collett, T. S. Mar. Pet. Geol. 201110.1016/j. marpetgeo.2009.06.007. (26) Myshakin, E. M.; Jiang, H.; Warzinski, R. P.; Jordan, K. D. J. Phys. Chem. A 2009, 113, 1913–1921.

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