- Email: [email protected]
Experimental investigation of gas-water relative permeability for gas-hydrate-bearing sediments from the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope
Marine and Petroleum Geology 28 (2011) 419–426
Contents lists available at ScienceDirect
Marine and Petroleum Geology journal homepage: www.elsevier.com/locate/marpetgeo
Experimental investigation of gas-water relative permeability for gas-hydratebearing sediments from the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope Andrew Johnson, Shirish Patil, Abhijit Dandekar* Department of Petroleum Engineering, 425 Duckering Building, University of Alaska Fairbanks, Fairbanks, AK 99775, USA
a r t i c l e i n f o
a b s t r a c t
Article history: Received 1 April 2009 Received in revised form 27 October 2009 Accepted 27 October 2009 Available online 10 November 2009
Permeability of hydrate reservoirs found in nature is likely to be heavily influenced by the percent of the pore volume occupied by hydrates. The quantification of how hydrate saturation affects permeability is of key interest for reservoir engineering studies. In this study, an experimental setup was modified to test permeability characteristics of unconsolidated core samples containing various saturations of methane hydrates. Hydrates were formed in the unconsolidated samples using a refrigerated core holder connected to a brine and methane injection system. Studies of this type conducted to date have rarely been performed on core samples recovered from actual hydrate-bearing sedimentary sections from natural hydrate intervals. Samples from the Mount Elbert site on the Alaska North Slope (ANS) were used for this study. Relative permeability measurements using hydrate constituent components (e.g. water and methane) are not very desirable due to difficulties in preventing additional hydrate formation during displacement experiments. Relative permeability measurements performed with hydrate constituent components (e.g. water and nitrogen) can help to significantly mitigate issues with additional hydrate formation. However, unsteady state relative permeability experiments produce piston like displacement results suggesting that steady state experiments might be preferable. It was observed that as in previous work using consolidated core samples, permeability of both brine and gases was reduced in unconsolidated hydrate-bearing core samples. Experimental results show that low to moderate hydrate saturations (1.5 to 36%) can significantly reduce permeability of porous media. These saturations, in fact, are lower than hydrate saturations observed in the natural hydrate systems at Mount Elbert. Ó 2009 Elsevier Ltd. All rights reserved.
Keywords: Methane hydrate Alaska North Slope Mount Elbert Relative permeability Saturation
1. Introduction Natural gas hydrates have long been considered a nuisance by the petroleum industry. Gas hydrates are a significant hazard for drilling and production operations (Collett and Dallimore, 2002). In gas pipelines hydrates have formed plugs if gas was not properly dehydrated (Davies et al., 2008). Removing these plugs has been an expensive and time consuming process. Recently, however, due to the geologic evidence indicating in situ hydrates could potentially be a vast energy resource of the future, research efforts have been undertaken to explore how natural gas from hydrates might be produced.
* Corresponding author. Tel./fax: þ1 907 474 5912. E-mail address: [email protected] (A. Dandekar). 0264-8172/$ – see front matter Ó 2009 Elsevier Ltd. All rights reserved. doi:10.1016/j.marpetgeo.2009.10.013
There is still much uncertainty in determining hydrates’ natural gas quantities and distribution in nature. Despite these difficulties two key theories can be formulated: (1) hydrates likely exceed the total energy content of ‘conventional’ sources of natural gas (Kvenvolden, 1993) and (2) hydrates predominantly exist in offshore environments and onshore permafrost (Collett, 2002). Onshore deposits, commonly easier to produce than offshore if infrastructure is already in place; have been targeted for pilot programs and other studies in the Alaskan and Canadian Arctic. In 2002, the U.S. Department of Energy and BP Exploration (Alaska), Inc. (BPXA), initiated a cooperative research program in association with the U.S. Geological Survey to assess Alaska North Slope (ANS) gas hydrate resources. The primary goal of the program was to plan and conduct a production test to help determine the potential for environmentally-sound and economically viable production of methane from gas hydrates (Hunter et al., 2011). In 2005, the project team completed the delineated, described, and ranked
420
A. Johnson et al. / Marine and Petroleum Geology 28 (2011) 419–426
(including probabilistic volumetrics) 14 different gas hydrate prospects via integrated geological and geophysical analyses within the Milne Point area (Inks et al., 2009). The highest-ranked of the identified Milne Point prospects (named ‘‘Mount Elbert’’) was selected as the subject site for the planned field data acquisition program (Hunter et al., 2011). Between February 3, and February 21, 2007, the Mount Elbert-01 gas hydrate stratigraphic test well was drilled, cored, logged, tested and abandoned – meeting 100% of the U.S. Department of Energy technical goals for the project. The field program acquired significant gas hydrate-bearing reservoir data, including a full suite of open-hole well logs, over 500 feet of continuous core, and open-hole formation pressure response tests. Continuous wire-line coring operations (the first conducted on the ANS) achieved 85% recovery through 153 meters of section (base and top of the cored interval between 760.1 and 606.5 meters respectively), providing a total of 261 whole round sub-samples during the field program. Of these, 204 samples from both hydratebearing and non-hydrate bearing zones were processed for postfield analysis of physical properties, microbiology, and gas geochemistry. Forty-six (46) samples were cleaned and squeezed at the well site to extract pore water samples for interstitial water geochemical analyses. Eleven hydrate-bearing samples were stored in liquid nitrogen or methane-charged pressure vessels to halt further gas hydrate dissociation. All of these cores were later converted to liquid nitrogen, and then shipped first to Lawrence Berkeley National Lab for CT imaging, then forwarded to a variety of laboratories in the USA and Canada for further advanced study (Hunter et al., 2011). Five unconsolidated core samples from the Mount Elbert stratigraphic test well, ranging between the depths of 618 to 658 meters, were provided to the researchers by industry partners with the specific objective of conducting a variety of flow experiments in order to obtain data in support of reservoir simulation studies. With that objective in mind, this study specifically involves investigating permeability characteristics of core samples saturated with varying amounts of methane hydrates. Permeability in general is a measure of how easily fluids are able to move through porous media. When the term ‘absolute’ permeability is employed it refers to the flow of a given single phase fluid through a porous medium 100% saturated with that fluid phase. Absolute permeability is generally calculated from applying the Darcy equation. The concept of ‘relative’ permeability on the other hand provides a mechanism of quantifying the amount of flow for each phase in a multiphase situation and is fundamental to the study of the simultaneous flow of immiscible fluids through porous media. Relative permeability can also be considered as a dimensionless term devised to adapt the Darcy equation to multiphase flow conditions. If a single fluid is present in a rock, its relative permeability is 1.0. The determination of relative permeability allows comparison of the different abilities of fluids to flow in the presence of each other, since the presence of more than one fluid generally inhibits flow. Therefore, understanding the permeability characteristics of a reservoir is of key importance when determining a reservoirs production potential. In the case of two mobile and immiscible fluid phases flowing through a porous medium, the flow behavior is characterized by two-phase relative permeability; when three fluid phases are flowing, the flow process is described by three-phase relative permeability. Since relative permeability data basically signify the relative conductive capacity or flow behavior of a porous medium when it is saturated with more than one fluid phase, the most obvious laboratory measurement technique from which relative permeability data can be determined is the flow experiment. Laboratory measurement techniques for obtaining the two-phase relative permeability data based on the flow experiments are fairly well established. Essentially two different types of flow experiments can be conducted in reservoir
rock samples from which relative permeability data are determined. These methods are called steady state (SS) and unsteady state (USS) and are described in details in Dandekar (2006). A laboratory setup developed specifically for hydrate experiments at the University of Alaska Fairbanks was utilized in this study for conducting flow experiments. 2. Experimental setup An experimental setup designed for measuring permeabilities in hydrate core samples was used for this study, which is shown in Fig. 1. This setup was initially developed by Jaiswal (2004) and later modified by Singh (2008). The main functions of the setup are (1) to perform permeability experiments using numerous fluids and (2) to form hydrates and maintain their thermodynamic stability during subsequent permeability experiments. The setup allows for the injection of gases (either methane or nitrogen) as well as brine through a core with or without hydrates. Brine used was 5 ppt. The salinity of the brines used in this study were set at a constant of 5 ppt, which is representative of Mount Elbert core derived water salinities (Hunter et al., 2011; Anderson et al., 2011). The core holder was temperature controllable from room temperature down to the lowest operating temperature of 2 C. The fluid accumulators were also able to be temperature controlled over a similar range when desired. The Teledyne Isco Syringe Pumps, connected to accumulators which held the specific fluids, were used to inject fluids. Pumps could be set to maintain a constant pressure or a constant flow rate. These pumps could inject fluid on either side of the core holder with a collection system downstream of the core holder to monitor the rate of produced fluids. These components included a back pressure regulator, metal flask placed on an electronic weighing balance, and finally a gas flow meter. 3. Experimental procedure 3.1. Absolute permeability and porosity determination The first step was to saturate each core sample with brine and establish a base permeability measurement. Since the cores used were unconsolidated many of the traditional methods for determining porosity were difficult to implement. Core samples were originally provided in a frozen state, with native in situ hydrates dissociated but still with significant frozen water to maintain their strength. It was observed that once this ice melted cores would have little if any cementation and would crumble quite easily when handled. It was decided to remove the cores from the freezer, note initial dimension and weights, and allow the samples to warm up and dehydrate at room temperature and pressure. No ovens were used to dry the sample; samples were broken up and allowed to dehydrate and dry over a period of days at room temperature and pressure. While grain structure was irrevocably damaged it was necessary in order to make the experiments work within the confines of the experimental setup available. Core samples provided were approximately 36 mm in diameter with the core holder sleeve having an inner diameter of approximately 39 mm. Therefore to insure that the samples were properly supported by overburden pressure the broken samples were used to fill up the core holder sleeve and compacted. At this point dimensions of the core were noted. Following the installation of the core in the core holder brine would be injected at a constant flow rate (normally between 0.5 mL/ min and 1 mL/min). Pore volumes of the samples used ranged from 23 mL to 39.2 mL. The back pressure regulator was set to a relatively low value (commonly 200 psi). Once brine was more or less filled in
A. Johnson et al. / Marine and Petroleum Geology 28 (2011) 419–426
421
Fig. 1. Experimental setup for relative permeability measurement of hydrate systems.
the pore spaces the upstream and downstream pressures would slowly stabilize. When a relatively constant upstream pressure value was observed (when changes in the upstream pressure were found to be quite slow; on the order of 1 psi per minute) the brine pump would be set to constant pressure. Once a stabilized flow rate was observed at a constant differential pressure the values were noted and a base permeability calculated according to Darcy’s Law (see Equation (1)). Volumes injected varied but were commonly on the order of five pore volumes.
Q ¼
kADP mL
(1)
with: Q (flowrate) in mL/sec; A (cross sectional area of the core plug calculated using the diameter) in cm2; DP (pressure drop across the core) in atm; m (viscosity) in cp and L (length of the core) in cm the calculated permeability, ‘k’ is in Darcy. The volume of brine produced at the downstream was also measured during this process. The difference in injected brine to accumulated brine gave an estimate for the porosity of the sample which was later important for determining hydrate saturations. Prior to injection all lines were filled with brine except those directly upstream and downstream of the core holder. The combined dead volume of these lines was approximately 2.5 mL. This dead volume amount was used to correct the measurements and determine the amount of water in the core sample. 3.2. Hydrate formation The second step in the procedure was to form hydrates. The pore pressure in the core was increased to approximately that which hydrates were desired to be formed at. Through trial and error it was found that pressures of about 1000 psi were found to be a good lower limit. Pore pressure was increased by closing the upper valve of the core holder and flowing the brine pump until the desired pressure was reached and stabilized. The brine on the opposite side of the
valve was evacuated and methane was pressurized to the same pressure. The valve was then opened and methane was injected into the core sample. This step was performed in one of two ways. Either the brine pump would be set to refill (withdraw fluid) or the bottom of the core was opened to the backpressure regulator. The back pressure set point was used to control how fast brine was removed from the core holder. The expansion of gas plus the withdrawal of brine allowed methane to be injected into the core. When a certain amount of brine was removed this process was terminated. The brine pump was set to constant pressure mode and the chilling unit was then set to cool the sample to between 2 and 4 C. Initially the core was cooled gradually per Jaiswal’s (2004) procedure. But it was also found that merely setting the chilling unit to the set point temperature, thus cooling the sample as fast as possible, was equally effective. No discernable difference was observed between these two methods. Since the objective was to form hydrate and study how the core performed after hydrate formation, specifics of hydrate formation were not stressed. This process usually lasted overnight with the pump data logged every 30 seconds. Pressure–temperature conditions were set so that hydrates formed more easily and the addition of free fluids (either brine or gas) would not affect the hydrate stability unduly in subsequent steps. Changing of fluid saturations likely affected the hydrate stability conditions but little to no gas was observed during water flooding, inferring that hydrates did not dissociate. Pressure and temperature conditions were constantly monitored during all of the steps when hydrates were present. Given the black box nature of the experiment it was difficult to precisely determine what percentages of brine and methane were being converted to hydrates. Therefore it was assumed that the volume formerly occupied by methane would be the maximum available volume for hydrate formation. One key reason for this was water was assumed to be the wetting phase which in a pressure constant system will be the phase most mobile. It must be noted that there were experimental limits to how saturated the cores could become with hydrates while still providing measurable permeability. This limit was observed to be
422
A. Johnson et al. / Marine and Petroleum Geology 28 (2011) 419–426
approximately 36% and correlates with previous experimental works using this setup (Jaiswal, 2004; Singh, 2008). The hydrate interval at Mount Elbert was shown to have hydrate saturations approximately double this amount. Hydrate saturations greater than 36% probably would have required orders of magnitude longer experimental times and would have further inhibited permeability experiments. In a closed system with no pressure support the consumption of methane gas to form hydrate would result in a drop in pressure. However, since the methane pump was set to maintain a set pressure, the formation of hydrates was observed by a noticeable jump in pump flow rate over a relatively short period of time. This sharp spike was often followed by a longer duration of much lower flow rate. This is consistent with the gas consumption rates described by Sloan and Koh (2008). The reduction of permeability in the following step is also a good indication of hydrate formation.
Following hydrate formation the remaining pore space of the core sample was flooded with brine. This served two functions. It allowed the researchers to analyze the effect that hydrate have on the overall permeably of core samples as well as to help estimate the hydrate saturation. This step provided the largest body of data for this work. A similar procedure to that in the first step was employed. Stabilized flow rate for a constant differential pressure allowed for the calculation of effective permeability of brine in hydrate samples. Since hydrates are a solid phase their movement through the core sample is severely limited. Analyzing the difference between injected brine and collected brine coupled with the amount of brine removed prior to hydrate formation gave an estimate for hydrate formation. A sample of this type of calculation is shown in Table 1. This assumption relies on water or gas not being trapped by surrounding hydrates during the hydrate formation process. This step, while theoretically simple in process was often quite difficult. It was observed that hydrates sometimes formed in such a way that to measure any permeability was impossible. The back pressure regulator, while mostly reliable was not able to act as a close valve when below its set point pressure. Therefore at extremely low flow rates a consistent back pressure was difficult to maintain. This made the analysis of low permeability samples quite difficult when hydrate saturation were high. It also increased the possibility of hydrate dissociation since one end of the core could be exposed to pressures which would not maintain hydrate stability at the set point temperature.
that the relative permeability of brine and methane in the hydrate core sample be determined. However, this was fraught with many difficulties. The Mount Elbert samples used for this experiment had low permeability when finally situated in the core holder with hydrates present. While porosities were often higher than that would be observed in sandstone samples permeabilities were often quite low. This could likely be attributed to poor grain size sorting as well as clay content. In the Mount Elbert samples, Elbert, with a few exceptions, median grain sizes (MGS) for the hydrate-bearing layers typically fall within the coarse silt to very fine sand (31 to 125 microns) ranges. The bounding clay-rich beds typically have MGS values in the very fine to fine silt (4 to 16 microns) ranges. Consistent with grain-size results, XRD analyses report higher quartz (82% by weight) in units C and D, compared to 55% in surrounding sediment. Clay minerals comprise an average of 10% of units C and D compared to an average of 31% in finer-grained sediment. Units C and D contain about equal amounts of chlorite and illite, and lesser amounts of kaolinite and only trace amounts of carbonate, Winters et al. (2011). While it was found that higher porosities made hydrate formation favorable, the lack of permeability was a significant drawback to these particular core samples. After many unsuccessful attempts of trying to displace water by methane it was decided to perform the same procedure with nitrogen instead. It had been theorized that either high capillary pressure or additional hydrate formation was the cause of choked flow during this step when using methane. Nitrogen, which would not form hydrates at the tested conditions, was thought to be able to help confirm if additional hydrate formation was cause for previous difficulties or capillary pressure. Calculations performed using a software developed by Hydrafact (www.hydrafact.com) for nitrogen and methane in pure water system indicates that at the tested temperature conditions the hydrate phase boundary pressures for Nitrogen are almost two times that of methane. Therefore, as the dilution of methane with nitrogen increases (i.e., trending from pure methane to various mixtures of methane and nitrogen and then to pure nitrogen), the phase boundary pressures will increase from that of pure methane to pure nitrogen. Additionally, nitrogen is routinely used for relative permeability experiments as it does not easily dissolve in other fluids. Its inert nature makes it well suited for experiments. Again, hydrate pressure and temperature conditions were selected so that addition of mobile fluids would not dissociate hydrates. Approximately 2 pore volumes of gas were injected during displacement experiments. While nitrogen was able to displace water, actual two phase flow was not suitably observed during the course of the experiment. Therefore only calculations of the end point gas permeability bear much weight.
3.4. Relative permeability/gas end point permeability
4. Results
The next step of the experiment was to determine what gas permeability was present in the sample. Originally it was desired
The results summarized in this paper help to illustrate the ways in which hydrates affect permeability characteristics in unconsolidated core samples. While the initial aim of the research was to determine relative permeability in unconsolidated hydrate samples, data on water and gas end point permeabilities still proved useful. Table 2 summarizes the bulk dimensions, porosities
3.3. Effective permeability and hydrate saturation determination
Table 1 Example calculations of hydrate saturation.
Step Hydrate Formation Effective Permeability
mL Brine collected 14.00 A Brine collected 100.04 B Brine injected 107.72 C Pore Volume
(A-(C-B))/D
Saturation
39.20 D Ratio 0.16
Table 2 Selected properties of core samples used. Core number
Depth (m)
Diameter (mm)
Length (mm)
Porosity, fraction
Pore volume (mL)
Hydrate saturations, fraction
UAF-2 UAF-3 UAF-5 UAF-6
618 619 653 658
39.1 39.1 39.1 39.1
76.9 85.6 66.5 90.3
0.38 0.38 0.29 0.36
35.0 39.0 23.0 39.2
0.15–0.36 0.10–0.18 0.26 0.015–0.16
A. Johnson et al. / Marine and Petroleum Geology 28 (2011) 419–426
10000.0
0.50
1000.0
0.45
Permeability, mD
Porosity (This work), fraction
423
0.40
0.35
UAF-Permeameter This Work Omni-Permeameter
100.0 10.0 1.0 0.1
0.30
0.25 0.25
0.0 600
610
620
630
640
650
660
670
Depth, m 0.30
0.35
0.40
0.45
0.50
Porosity (Log), fraction
Fig. 3. Comparison of Mount Elbert permeabilities from different tests as a function of depth.
Fig. 2. Comparison between downhole log calculated porosities and experimentally determined porosities.
and tested hydrate saturations of each sample used for this experiment. Fig. 2, also summarized in Table 3 shows comparison of porosities measured in this work and those determined from logs. While conditions were intended not to be unduly altered, it seemed important to show that conditions of the core samples had been altered from what existed in the reservoir. 4.1. Comparison between measured values versus log data and other experimental works Due to physical constraints core samples used were not in their native state. High pressures, extensive amounts of fluid flow, and relative consolidation requirements were the reasons why core samples needed to be modified. Porosities were reduced preceding laboratory experiments since they were further consolidated to operate well within the core holder. As a result permeability was also likely reduced. Fig. 3, also summarized in Table 4 compares permeabilities determined in this experiment with those taken using pore permeameters by researchers from UAF and OMNI labs. As with porosity these values deviate from those observed in more native state conditions. 4.2. Hydrate formation Hydrates were confirmed to have formed in the core sample based on two primary data sets. The first was by analyzing pump data logged as the sample was cooled from room temperature down to a lower temperature where hydrate formation would occur. As mentioned earlier, hydrate gas consumption described by Sloan and Koh (2008) slowly increases as formation occurs and reaches its maximum rate and then decreases to a very low amount over time. This is equivalent to the pump flow rate when the pump is set to constant pressure. Fig. 4 is an excellent example of good hydrate formation. Peak pump flowrate corresponding to hydrate formation in this example is approximately 2 mL/min (0.05 pore
Table 3 Comparison between logged porosity and experimentally determined porosity in the laboratory. Core number
Lab porosity, fraction
Density porosity (ECS), fraction
UAF-2 UAF-3 UAF-5 UAF-6
0.38 0.38 0.29 0.36
0.45 0.41 0.34 0.38
volumes per min). The other method was to analyze the effective permeability to water. Hydrates act as a solid and therefore reduce the permeability of the sample. 4.3. Water relative permeability reduction as a function of hydrate saturation Hydrates were formed in core samples ranging from 1.5 to 36% hydrate saturation. Absolute and effective permeabilities before and after hydrate formation with water were determined by Darcy’s law (Equation (1)). All effective water permeabilities were divided by absolute permeabilities to determine the water relative permeability fraction at respective hydrate saturations. Ideally, if permeability, porosity, and hydrate saturation were uniformly distributed throughout each core sample, reduction in effective (relative) permeability would follow a more normal trend. However due to the probability that local variations in both effective (relative) permeability and hydrate saturation existed this trend at times is irregular. When observing the trend for each individual core sample it can be seen for core UAF-2 and UAF-3 that discrete increases in hydrate saturation did not always yield a greater reduction in effective (relative) permeability. The overall trend, however, clearly indicates a significant decrease in effective (relative) permeability with increased hydrate saturation. Fig. 5 shows how different hydrate saturations affected effective (relative) permeability for individual core samples. For the purposes of this work water effective permeability in the presence of hydrates is represented by a fraction, thereby comparing the permeability with and without a given saturation of hydrates. Also shown in Fig. 5 is an obvious relationship, i.e., water relative permeability of 1 when hydrate saturation is 0. 4.4. Relative permeability/gas end point permeability Gas-brine relative permeability as affected by hydrates in Mount Elbert samples was one of the original aims of this study. However this process presented many physical and technical challenges. At no time was methane able to flow through core samples containing hydrate with the remainder free and irreducible water. This was likely due to the fact that the samples’ low permeability lowered fluid velocity therefore forming additional hydrate from mobile brine and methane. After many unsuccessful attempts nitrogen was used in order to displace mobile water from the core. Data shown in Fig. 6 suggests that displacement of brine by gas is ‘‘piston like.’’ For the JBN method (Johnson et al., 1959) to calculate relative permeabilities it is necessary for significant two phase flow to be observed at the outlet of the sample for an extended period of
424
A. Johnson et al. / Marine and Petroleum Geology 28 (2011) 419–426
Table 4 Comparison of Mount Elbert permeabilities from different tests as a function of depth.
Depth (m) 608.8 614.8 618.0 (UAF-2) 619.2 (UAF-3) 653.0 (UAF-5) 623.6 625.3 658.2 (UAF-6) 641.9 647.6 659.4
Omni permeability (mD) 0.2 12.2
UAF-Permeameter (mD) 26.4 62.0
3.1 15.8 1.5 1370.0 1630.0
723.0 567.0 0.5
0.1 145.0 675.0
53.5 15.2 2.7
time. However, during these experiments it was observed that nearly all of the mobile brine was displaced before any gas breakthrough. Once gas breakthrough occurred, little to no brine production was observed. The JBN method was still used since it is meant for analysis of unsteady state displacement experiments and short periods of two phase flow that were observed in few runs. During two runs nitrogen was used to displace water and the effective permeability of gas at irreducible water saturation was determined as a function of hydrate saturation. While data for this is limited, it suggests that gas permeability is also decreased by increased percentages of hydrate saturation (Fig. 7). 5. Discussion As has been observed in nature, hydrates often exist in unconsolidated samples. Therefore hydrate experiments utilizing these samples are of interest. This experimental study confirms that previous techniques used to form hydrates is porous media can be applied to unconsolidated cores samples with additional modifications sometimes required. Brine effective permeability, the wetting phase, is most easily determined using the techniques outlined in this paper. One
2.5
observation immediately following the completion of hydrate formation gives some insight into how uniformly hydrates are distributed throughout the core sample. As gas was supplied to the top of the core holder hydrate formation was supported at that end of the core holder only. That is to say: a hydrate formation front was not also forming from the other end of the core sample. Instead the bottom of the core was analyzed with a pressure gauge. At certain times the two pressures observed on either side of the core prior to subsequent brine flooding were not equal and sometimes hundreds of psi apart. When this occurred subsequent brine flooding was often unsuccessful. The imbalance in pressures during hydrate formation suggests hydrates prevented the communication of pressure across the core sample. Other times, during the successful runs, pressure differences were much lower and over time stabilized brine flow was observed. During the determination of effective permeability initial high differential pressures were applied to the core in order to achieve significant brine flow (w0.1 mL/min). It is possible that this initial shock to the core with an incompressible fluid had the potential to dissociate some hydrates. However, once flow rates were observed to have increased to easily manageable amounts (>0.1 mL/min) differential pressures were reduced in an attempt to minimize the likelihood of excessive hydrate dissociation. The determination of
500 Flow Rate Pump Volume
2.0
1.0
480
UAF-2 UAF-3 UAF-5 UAF-6 Series5
460
1.5
420 400
1.0
380 360
0.5
0.8
Krw, fraction
440
Pump volume, mL
Flow rate, mL/min
This Work (mD)
0.6
0.4
0.2
320 0.0 0
500
1000
1500
300 2000
Time Steps (1 step = 30 seconds) Fig. 4. Example of hydrate formation step. Pumps set at constant pressure support the consumption of gas during hydrate formation.
0.0 0.00
0.10
0.20
0.30
0.40
Sh, fraction Fig. 5. Reduction in water relative permeability versus hydrate saturation for tested core samples.
A. Johnson et al. / Marine and Petroleum Geology 28 (2011) 419–426
0.60
0.06
K rw, fraction
0.50 0.40
0.05 0.04
0.30
0.03
0.20
0.02
0.10
0.01
0.00 8.0
13.0
18.0
Krg, fraction
Krw Krg Linear (Krg) Linear (Krw)
0 28.0
23.0
Sg, percent Fig. 6. Piston like displacement during unsteady state relative permeability experiment with hydrate saturation of 12.5%. This behavior prevents the collection of data which is able to help generate full relative permeability charts. Gas breakthrough occurred around 25 percent gas saturation with minimal water production following.
hydrate saturation was also determined at the end of brine flooding (not initial formed amounts). After the initial displacement of free gas from the sample, little if any gas was observed to be extracted from the core sample suggesting that hydrate dissociate was minimal. Intentionally dissociating hydrates following experimental runs also allowed produced gas to be analyzed and compared with injected gas. This allowed the researchers to determine if any significant hydrate dissociation during permeability experiments had occurred. One of the key difficulties observed during experimentation was hydrates reducing permeability to such an extent that fluid flow using the experimental setup was no longer possible. During hydrate formation gas is available in abundance due to the volume of the gas accumulator being an order of magnitude larger than the pore volume of the core sample. No additional brine was provided during hydrate formation. If hydrate stable conditions exist hydrates will continue to form provided excess amounts the constituent components are present. Since no additional brine is injected water will be the limiting component for hydrate formation. Assuming that there still exists permeability for fluid flow, gas still has the potential to seek out mobile water for additional hydrate formation. However, as water from lower capillary zones is depleted or hydrate formation restricts gas’s access to these low capillary pressure zones hydrate formation slows and eventually ceases. The resaturation of the remaining pore volume with brine following hydrate formation creates an environment where any additional free gas which is injected (presumably to perform
1.0
0.010
0.9 0.008
0.7 0.6
0.006
0.5 0.4
0.004
krg, fraction
krw, fraction
0.8
0.3 0.2
Krw Krg
0.1 0.0 0.00
0.05
0.10
0.002 0.000 0.15
Sh, fraction Fig. 7. Gas end point relative permeability as a function of hydrate saturation. Included are the corresponding brine end points for comparison.
425
a relative permeability experiment) has the potential to form hydrates. It is suggested that hydrate formation occurring during the gas flood procedure has the propensity to happen since brine had then been injected back into pore spaces of lower capillary pressure. It was later observed that high capillary pressure outright did not prevent the injection gas but rather could have retarded flow of gases (in our case methane) which also could form hydrates. Hydrate formation appeared to happen more easily during this step than during the end of the hydrate formation step since the gas was limited by the capillary pressure of immobile water in the latter. In general published material on experimentally determined reservoir properties of gas hydrate systems is scarce; in particular the relative permeability characteristics. However, in this section we have discussed data available in the literature especially in regards to the relationship between hydrate saturations and gas and water relative permeabilities and compared the results obtained in this study. Murray et al. (2006) recognized that estimating permeability in hydrate saturated rocks from core is difficult. To make accurate laboratory measurements on permeability hydrate stability must be closely monitored. They reviewed water effective permeability measurements for hydrate saturated cores from Mallik, which were reported by Uchida et al. (2005), and stated that in stable conditions water permeabilities range from 1 to 6 mD at estimated hydrate saturations ranging from 10–20%. In one of the rare studies, Ahn et al. (2005) presented a complete gas-water relative permeability curve for a synthetic hydrate bearing sediment at a maximum hydrate saturation of 15% using the unsteady state displacement technique, which was also used in this study. Gas and water relative permeabilities were reported for gas saturations ranging from about 12 to 28%. Their gas relative permeabilities were significantly low from close to zero to a maximum of less that 0.1, whereas our values were much less (Fig. 6) for a hydrate saturation of 12.5%. However, Ahn et al. (2005) water relative permeabilities ranged from 0.05 to a maximum of 0.6, which is in fairly close agreement with our results for comparable gas saturation range (Fig. 6). Kleinberg et al. (2005) presented the water relative permeability as a function of hydrate saturations ranging from 10 to 70% as part of the Mallik 5L-38 gas hydrate production research well program. The water relative permeability values were determined using Schlumberger CMRÔ (Combinable Magnetic Resonance) tool. They also compared the CMR determined values with a variety of models that have been proposed to predict the effect of gas hydrate on relative permeability. Experimental results presented in this study on effect of gas hydrate saturation on water relative permeability (Fig. 5) indicates a trend and general agreement analogous to the one reported by Kleinberg et al. (2005). However, as far as models are concerned, clearly, the data and their comparison to models raise as many questions as they answer given the fact that many of these model predictions indicate a deviation from the reported CMR permeabilities, based on which Kleinberg et al. (2005) stated that there is a clear need for direct relative permeability measurements on gas hydrate affected sediments. Jaiswal (2004) presented two data sets on effective permeability and relative permeability (from unsteady state displacement tests) data of gas and water phases for gas-hydrate-saturated Oklahoma 100 mesh sand and Alaska North Slope (ANS) subsurface sediment samples from the Anadarko Hot Ice 1 well. However, the core samples from the Anadarko well were determined to be void of gas hydrate. It was determined that the artificially grown hydrate saturations in the Anadarko core samples ranged from 7 to 31% compared to as low as 1.5 to 36% in this study. The Anadarko sample results indicate significantly low gas as well as water relative permeabilities for the tested hydrate saturations, which are somewhat in agreement with the gas relative permeabilities;
426
A. Johnson et al. / Marine and Petroleum Geology 28 (2011) 419–426
however, water relative permeabilities were found to be much higher in the case of Mount Elbert samples tested in this study. Overall, Jaiswal’s two data sets indicate that initial permeability prior to hydrate formation was higher than what was observed in our study, but still of a similar order of magnitude, yet had lower permeability following hydrate formation. Considering the various relative permeability studies, it may be speculated though that in general, the significantly low gas relative permeabilities observed (compared to water relative permeability) could perhaps be due to the fact that gas is the non-wetting phase, whereas water is the wetting phase thereby existing as a relatively continuous phase thus having a higher permeability. Additionally, differences between the reduction in permeabilities is possibly influenced by how hydrates are distributed in the pore spaces; hydrate saturated rock permeability depends on where the hydrate resides in the pore space (Kleinberg et al., 2003). 6. Conclusions and recommendations The following conclusions can be made as a result of this study: (1) The ability to form hydrates in unconsolidated samples while still providing meaningful permeability was confirmed. Injection of one or more fluids which can form hydrates through low permeability hydrate samples will likely lead to additional hydrate formation. Injection of non hydrate forming gases at the prevailing test conditions likely maintains the original hydrate saturation to a greater extent than hydrate forming gases. (2) Hydrates, as formed in the laboratory over short time scales, significantly affect the subsequent available permeability for all fluid types. Based on the work described herein the authors wish to make the following recommendations related to possible future work in this area: (1) Evaluate the extent to which consolidated core samples can be substituted for unconsolidated core samples for hydrate studies. Additionally, evaluate the extent to which nitrogen can be substituted for methane when trying to evaluate gas-brine relative permeability or gas effective permeability in unconsolidated hydrate samples. (2) Modify the procedure herein in order to perform steady state relative permeability experiments. Acknowledgements The authors would like to thank BP Exploration (Alaska) Inc for providing core samples for this experimental work. We would like to acknowledge the financial support provided by the U.S. Department of Energy and the University of Alaska Fairbanks’ Institute of Northern Engineering over the course of this research program. Disclaimer: This article is prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor an agency thereof, nor any of their employees, makes any warranty, expressed or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. References herein to any specific
commercial product, process, or service by trade name, trademark, manufacturer, or otherwise do not necessary constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of the authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. The views and opinions of the authors expressed herein do not necessarily state or reflect those of BP Exploration (Alaska), Inc. References Ahn, T., Lee, J., Huh, D.-G., Kang, J.M., 2005. Experimental study on two-phase flow in artificial hydrate-bearing sediments. Geosystems Engineering 84 (4), 101– 104. Anderson, B.J., Kurihara, M., White, M.D., Moridis, G.J., Wilson, S.J., PooladiDarvish, M.x., Gaddipati, M.x., Masuda, Y., Collett, T.S., Hunter, R.B., Narita, H., Rose, K.K., Boswell, R.M., 2011. Regional long-term production modeling from a single well test, Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope. Journal of Marine and Petroleum Geology 28 (2), 493–501. Collett, T.S., November 2002. Energy resource potential of natural gas hydrates. AAPG Bulletin 86 (11), 1971–1992. Collett. T.S., Dallimore, S.R., 2002. Detailed analysis of gas hydrate induced drilling and production hazards. In: Proceedings of the Fourth International Conference on Gas Hydrates, Yokohama, Japan, April 19–23, 2002. Dandekar, A.Y., 2006. Petroleum Reservoir Rock and Fluid Properties. CRC Press, Taylor and Francis, Boca Raton, FL. Davies, S.R., Boxall, J.A., Koh, C.A., Sloan, E.D., Hemmingsen, P.V., Kinnari, K.J., ZhengGang, X., Predicting Hydrate Plug Formation in a Subsea Tieback, 2008 SPE Annual Technical Conference and Exhibition, Denver, Colorado, USA, September 21–24, 2008. Hunter, R.B., Collett, T.S., Boswell, R.M., Anderson, B.J., Digert, S.A., Pospisil, G.x., Baker, R.A., Weeks, M.x., 2011. Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope: Overview of scientific and technical program. Journal of Marine and Petroleum Geology 28 (2), 295–310. Inks, T., Lee, M., Agena, W., Taylor, D., Collett, T.S., Hunter, R., Zyrianova, M., 2009. Seismic prospecting for gas hydrate and associated free-gas prospects in the Milne Point Area of Northern Alaska. In: Collett, T., et al. (Eds.), Natural Gas Hydrates: Energy Resource and Associated Geologic Hazards. American Association of Petroleum Geologists Hedberg Memoir, 89. Jaiswal, N.J., 2004, Measurement of gas–water relative permeability for gas hydrate systems: Master’s thesis, University of Alaska Fairbanks Note: Electronic copies of thesis can be made available on request. Johnson, E.F., Bossler, D.P., Naumann, V.O., 1959. Calculation of relative permeability from displacement experiments. Transactions of AIME 216, 370–372. Kleinberg, R.L., Flaum, C.,, Collett, T.S., 2005. Magnetic resonance log of JAPEX/JNOC/ GSC et al. Mallik 5L-38 gas hydrate production research well: gas hydrate saturation, growth habit, and relative permeability. In: Dallimore, S.R., Collett, T.S. (Eds.), Scientific Results from the Mallik 2002 Gas Hydrate Production Research Well, Mackenzie Delta, Northwest Territories, Canada, Bulletin 585. Geological Survey of Canada, Ottawa. Kleinberg, R.L., Flaum, C., Griffin, D.D., Brewer, P.G., Malby, G.E., Peltzer, E.T., Yesinowski, J.P., 2003. Deep sea NMR: Methane hydrate growth habit in porous media and its relationship to hydraulic permeability, deposit accumulation, and submarine slope stability. Journal of Geophysical Research 108 (B10), 2508. Kvenvolden, K.A., 1993. Gas hydrates as potential energy resource – a review of their methane content. In: The Future of Energy Gases. U.S. Geological Survey Professional Paper, vol. 1570, pp. 555–561. Murray, D., Fukuhara, M., Khong, C.K., Namikawa, T., Yamamoto, K., 2006. Permeability estimates in gas hydrate reservoirs of the Nankai trough, SPWLA 47th Annual Logging Symposium, June 4–7, 2006. Singh, P.K., 2008. An engineering study to investigate the methane hydrate resource potential associated with the Barrow gas fields in Alaska: Master’s thesis, University of Alaska Fairbanks Note: Electronic copies of thesis can be made available on request. Sloan, E.D.,, Koh, C.A., 2008. Clathrate Hydrates of Natural Gases, third ed. CRC Press, New York, NY. Uchida, T., Tsuji, T., Takahashi, T., Okui, T., Minagawa, H., 2005. Petrophysical properties and sedimentology of gas-hydrate-bearing sediments in the JAPEX/ JNOC/GSC et al. Mallik 5L-38 gas hydrate production research well. In: Dallimore, S.R., Collett, T.S. (Eds.), Scientific Results from the Mallik 2002 Gas Hydrate Production Research Well, Mackenzie Delta, Northwest Territories, Canada, Bulletin 585. Geological Survey of Canada, Ottawa. Winters, W.J., Walker, M.M., Hunter, R.B., Collett, T.S., Boswell, R.M., Rose, K.K., Waite, W.F., Torres, M.E., Patil, S.L., Dandekar, A.Y., 2011. Physical properties of sediment from the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope. Journal of Marine and Petroleum Geology 28 (2), 361–380.
Contents lists available at ScienceDirect
Marine and Petroleum Geology journal homepage: www.elsevier.com/locate/marpetgeo
Experimental investigation of gas-water relative permeability for gas-hydratebearing sediments from the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope Andrew Johnson, Shirish Patil, Abhijit Dandekar* Department of Petroleum Engineering, 425 Duckering Building, University of Alaska Fairbanks, Fairbanks, AK 99775, USA
a r t i c l e i n f o
a b s t r a c t
Article history: Received 1 April 2009 Received in revised form 27 October 2009 Accepted 27 October 2009 Available online 10 November 2009
Permeability of hydrate reservoirs found in nature is likely to be heavily influenced by the percent of the pore volume occupied by hydrates. The quantification of how hydrate saturation affects permeability is of key interest for reservoir engineering studies. In this study, an experimental setup was modified to test permeability characteristics of unconsolidated core samples containing various saturations of methane hydrates. Hydrates were formed in the unconsolidated samples using a refrigerated core holder connected to a brine and methane injection system. Studies of this type conducted to date have rarely been performed on core samples recovered from actual hydrate-bearing sedimentary sections from natural hydrate intervals. Samples from the Mount Elbert site on the Alaska North Slope (ANS) were used for this study. Relative permeability measurements using hydrate constituent components (e.g. water and methane) are not very desirable due to difficulties in preventing additional hydrate formation during displacement experiments. Relative permeability measurements performed with hydrate constituent components (e.g. water and nitrogen) can help to significantly mitigate issues with additional hydrate formation. However, unsteady state relative permeability experiments produce piston like displacement results suggesting that steady state experiments might be preferable. It was observed that as in previous work using consolidated core samples, permeability of both brine and gases was reduced in unconsolidated hydrate-bearing core samples. Experimental results show that low to moderate hydrate saturations (1.5 to 36%) can significantly reduce permeability of porous media. These saturations, in fact, are lower than hydrate saturations observed in the natural hydrate systems at Mount Elbert. Ó 2009 Elsevier Ltd. All rights reserved.
Keywords: Methane hydrate Alaska North Slope Mount Elbert Relative permeability Saturation
1. Introduction Natural gas hydrates have long been considered a nuisance by the petroleum industry. Gas hydrates are a significant hazard for drilling and production operations (Collett and Dallimore, 2002). In gas pipelines hydrates have formed plugs if gas was not properly dehydrated (Davies et al., 2008). Removing these plugs has been an expensive and time consuming process. Recently, however, due to the geologic evidence indicating in situ hydrates could potentially be a vast energy resource of the future, research efforts have been undertaken to explore how natural gas from hydrates might be produced.
* Corresponding author. Tel./fax: þ1 907 474 5912. E-mail address: [email protected] (A. Dandekar). 0264-8172/$ – see front matter Ó 2009 Elsevier Ltd. All rights reserved. doi:10.1016/j.marpetgeo.2009.10.013
There is still much uncertainty in determining hydrates’ natural gas quantities and distribution in nature. Despite these difficulties two key theories can be formulated: (1) hydrates likely exceed the total energy content of ‘conventional’ sources of natural gas (Kvenvolden, 1993) and (2) hydrates predominantly exist in offshore environments and onshore permafrost (Collett, 2002). Onshore deposits, commonly easier to produce than offshore if infrastructure is already in place; have been targeted for pilot programs and other studies in the Alaskan and Canadian Arctic. In 2002, the U.S. Department of Energy and BP Exploration (Alaska), Inc. (BPXA), initiated a cooperative research program in association with the U.S. Geological Survey to assess Alaska North Slope (ANS) gas hydrate resources. The primary goal of the program was to plan and conduct a production test to help determine the potential for environmentally-sound and economically viable production of methane from gas hydrates (Hunter et al., 2011). In 2005, the project team completed the delineated, described, and ranked
420
A. Johnson et al. / Marine and Petroleum Geology 28 (2011) 419–426
(including probabilistic volumetrics) 14 different gas hydrate prospects via integrated geological and geophysical analyses within the Milne Point area (Inks et al., 2009). The highest-ranked of the identified Milne Point prospects (named ‘‘Mount Elbert’’) was selected as the subject site for the planned field data acquisition program (Hunter et al., 2011). Between February 3, and February 21, 2007, the Mount Elbert-01 gas hydrate stratigraphic test well was drilled, cored, logged, tested and abandoned – meeting 100% of the U.S. Department of Energy technical goals for the project. The field program acquired significant gas hydrate-bearing reservoir data, including a full suite of open-hole well logs, over 500 feet of continuous core, and open-hole formation pressure response tests. Continuous wire-line coring operations (the first conducted on the ANS) achieved 85% recovery through 153 meters of section (base and top of the cored interval between 760.1 and 606.5 meters respectively), providing a total of 261 whole round sub-samples during the field program. Of these, 204 samples from both hydratebearing and non-hydrate bearing zones were processed for postfield analysis of physical properties, microbiology, and gas geochemistry. Forty-six (46) samples were cleaned and squeezed at the well site to extract pore water samples for interstitial water geochemical analyses. Eleven hydrate-bearing samples were stored in liquid nitrogen or methane-charged pressure vessels to halt further gas hydrate dissociation. All of these cores were later converted to liquid nitrogen, and then shipped first to Lawrence Berkeley National Lab for CT imaging, then forwarded to a variety of laboratories in the USA and Canada for further advanced study (Hunter et al., 2011). Five unconsolidated core samples from the Mount Elbert stratigraphic test well, ranging between the depths of 618 to 658 meters, were provided to the researchers by industry partners with the specific objective of conducting a variety of flow experiments in order to obtain data in support of reservoir simulation studies. With that objective in mind, this study specifically involves investigating permeability characteristics of core samples saturated with varying amounts of methane hydrates. Permeability in general is a measure of how easily fluids are able to move through porous media. When the term ‘absolute’ permeability is employed it refers to the flow of a given single phase fluid through a porous medium 100% saturated with that fluid phase. Absolute permeability is generally calculated from applying the Darcy equation. The concept of ‘relative’ permeability on the other hand provides a mechanism of quantifying the amount of flow for each phase in a multiphase situation and is fundamental to the study of the simultaneous flow of immiscible fluids through porous media. Relative permeability can also be considered as a dimensionless term devised to adapt the Darcy equation to multiphase flow conditions. If a single fluid is present in a rock, its relative permeability is 1.0. The determination of relative permeability allows comparison of the different abilities of fluids to flow in the presence of each other, since the presence of more than one fluid generally inhibits flow. Therefore, understanding the permeability characteristics of a reservoir is of key importance when determining a reservoirs production potential. In the case of two mobile and immiscible fluid phases flowing through a porous medium, the flow behavior is characterized by two-phase relative permeability; when three fluid phases are flowing, the flow process is described by three-phase relative permeability. Since relative permeability data basically signify the relative conductive capacity or flow behavior of a porous medium when it is saturated with more than one fluid phase, the most obvious laboratory measurement technique from which relative permeability data can be determined is the flow experiment. Laboratory measurement techniques for obtaining the two-phase relative permeability data based on the flow experiments are fairly well established. Essentially two different types of flow experiments can be conducted in reservoir
rock samples from which relative permeability data are determined. These methods are called steady state (SS) and unsteady state (USS) and are described in details in Dandekar (2006). A laboratory setup developed specifically for hydrate experiments at the University of Alaska Fairbanks was utilized in this study for conducting flow experiments. 2. Experimental setup An experimental setup designed for measuring permeabilities in hydrate core samples was used for this study, which is shown in Fig. 1. This setup was initially developed by Jaiswal (2004) and later modified by Singh (2008). The main functions of the setup are (1) to perform permeability experiments using numerous fluids and (2) to form hydrates and maintain their thermodynamic stability during subsequent permeability experiments. The setup allows for the injection of gases (either methane or nitrogen) as well as brine through a core with or without hydrates. Brine used was 5 ppt. The salinity of the brines used in this study were set at a constant of 5 ppt, which is representative of Mount Elbert core derived water salinities (Hunter et al., 2011; Anderson et al., 2011). The core holder was temperature controllable from room temperature down to the lowest operating temperature of 2 C. The fluid accumulators were also able to be temperature controlled over a similar range when desired. The Teledyne Isco Syringe Pumps, connected to accumulators which held the specific fluids, were used to inject fluids. Pumps could be set to maintain a constant pressure or a constant flow rate. These pumps could inject fluid on either side of the core holder with a collection system downstream of the core holder to monitor the rate of produced fluids. These components included a back pressure regulator, metal flask placed on an electronic weighing balance, and finally a gas flow meter. 3. Experimental procedure 3.1. Absolute permeability and porosity determination The first step was to saturate each core sample with brine and establish a base permeability measurement. Since the cores used were unconsolidated many of the traditional methods for determining porosity were difficult to implement. Core samples were originally provided in a frozen state, with native in situ hydrates dissociated but still with significant frozen water to maintain their strength. It was observed that once this ice melted cores would have little if any cementation and would crumble quite easily when handled. It was decided to remove the cores from the freezer, note initial dimension and weights, and allow the samples to warm up and dehydrate at room temperature and pressure. No ovens were used to dry the sample; samples were broken up and allowed to dehydrate and dry over a period of days at room temperature and pressure. While grain structure was irrevocably damaged it was necessary in order to make the experiments work within the confines of the experimental setup available. Core samples provided were approximately 36 mm in diameter with the core holder sleeve having an inner diameter of approximately 39 mm. Therefore to insure that the samples were properly supported by overburden pressure the broken samples were used to fill up the core holder sleeve and compacted. At this point dimensions of the core were noted. Following the installation of the core in the core holder brine would be injected at a constant flow rate (normally between 0.5 mL/ min and 1 mL/min). Pore volumes of the samples used ranged from 23 mL to 39.2 mL. The back pressure regulator was set to a relatively low value (commonly 200 psi). Once brine was more or less filled in
A. Johnson et al. / Marine and Petroleum Geology 28 (2011) 419–426
421
Fig. 1. Experimental setup for relative permeability measurement of hydrate systems.
the pore spaces the upstream and downstream pressures would slowly stabilize. When a relatively constant upstream pressure value was observed (when changes in the upstream pressure were found to be quite slow; on the order of 1 psi per minute) the brine pump would be set to constant pressure. Once a stabilized flow rate was observed at a constant differential pressure the values were noted and a base permeability calculated according to Darcy’s Law (see Equation (1)). Volumes injected varied but were commonly on the order of five pore volumes.
Q ¼
kADP mL
(1)
with: Q (flowrate) in mL/sec; A (cross sectional area of the core plug calculated using the diameter) in cm2; DP (pressure drop across the core) in atm; m (viscosity) in cp and L (length of the core) in cm the calculated permeability, ‘k’ is in Darcy. The volume of brine produced at the downstream was also measured during this process. The difference in injected brine to accumulated brine gave an estimate for the porosity of the sample which was later important for determining hydrate saturations. Prior to injection all lines were filled with brine except those directly upstream and downstream of the core holder. The combined dead volume of these lines was approximately 2.5 mL. This dead volume amount was used to correct the measurements and determine the amount of water in the core sample. 3.2. Hydrate formation The second step in the procedure was to form hydrates. The pore pressure in the core was increased to approximately that which hydrates were desired to be formed at. Through trial and error it was found that pressures of about 1000 psi were found to be a good lower limit. Pore pressure was increased by closing the upper valve of the core holder and flowing the brine pump until the desired pressure was reached and stabilized. The brine on the opposite side of the
valve was evacuated and methane was pressurized to the same pressure. The valve was then opened and methane was injected into the core sample. This step was performed in one of two ways. Either the brine pump would be set to refill (withdraw fluid) or the bottom of the core was opened to the backpressure regulator. The back pressure set point was used to control how fast brine was removed from the core holder. The expansion of gas plus the withdrawal of brine allowed methane to be injected into the core. When a certain amount of brine was removed this process was terminated. The brine pump was set to constant pressure mode and the chilling unit was then set to cool the sample to between 2 and 4 C. Initially the core was cooled gradually per Jaiswal’s (2004) procedure. But it was also found that merely setting the chilling unit to the set point temperature, thus cooling the sample as fast as possible, was equally effective. No discernable difference was observed between these two methods. Since the objective was to form hydrate and study how the core performed after hydrate formation, specifics of hydrate formation were not stressed. This process usually lasted overnight with the pump data logged every 30 seconds. Pressure–temperature conditions were set so that hydrates formed more easily and the addition of free fluids (either brine or gas) would not affect the hydrate stability unduly in subsequent steps. Changing of fluid saturations likely affected the hydrate stability conditions but little to no gas was observed during water flooding, inferring that hydrates did not dissociate. Pressure and temperature conditions were constantly monitored during all of the steps when hydrates were present. Given the black box nature of the experiment it was difficult to precisely determine what percentages of brine and methane were being converted to hydrates. Therefore it was assumed that the volume formerly occupied by methane would be the maximum available volume for hydrate formation. One key reason for this was water was assumed to be the wetting phase which in a pressure constant system will be the phase most mobile. It must be noted that there were experimental limits to how saturated the cores could become with hydrates while still providing measurable permeability. This limit was observed to be
422
A. Johnson et al. / Marine and Petroleum Geology 28 (2011) 419–426
approximately 36% and correlates with previous experimental works using this setup (Jaiswal, 2004; Singh, 2008). The hydrate interval at Mount Elbert was shown to have hydrate saturations approximately double this amount. Hydrate saturations greater than 36% probably would have required orders of magnitude longer experimental times and would have further inhibited permeability experiments. In a closed system with no pressure support the consumption of methane gas to form hydrate would result in a drop in pressure. However, since the methane pump was set to maintain a set pressure, the formation of hydrates was observed by a noticeable jump in pump flow rate over a relatively short period of time. This sharp spike was often followed by a longer duration of much lower flow rate. This is consistent with the gas consumption rates described by Sloan and Koh (2008). The reduction of permeability in the following step is also a good indication of hydrate formation.
Following hydrate formation the remaining pore space of the core sample was flooded with brine. This served two functions. It allowed the researchers to analyze the effect that hydrate have on the overall permeably of core samples as well as to help estimate the hydrate saturation. This step provided the largest body of data for this work. A similar procedure to that in the first step was employed. Stabilized flow rate for a constant differential pressure allowed for the calculation of effective permeability of brine in hydrate samples. Since hydrates are a solid phase their movement through the core sample is severely limited. Analyzing the difference between injected brine and collected brine coupled with the amount of brine removed prior to hydrate formation gave an estimate for hydrate formation. A sample of this type of calculation is shown in Table 1. This assumption relies on water or gas not being trapped by surrounding hydrates during the hydrate formation process. This step, while theoretically simple in process was often quite difficult. It was observed that hydrates sometimes formed in such a way that to measure any permeability was impossible. The back pressure regulator, while mostly reliable was not able to act as a close valve when below its set point pressure. Therefore at extremely low flow rates a consistent back pressure was difficult to maintain. This made the analysis of low permeability samples quite difficult when hydrate saturation were high. It also increased the possibility of hydrate dissociation since one end of the core could be exposed to pressures which would not maintain hydrate stability at the set point temperature.
that the relative permeability of brine and methane in the hydrate core sample be determined. However, this was fraught with many difficulties. The Mount Elbert samples used for this experiment had low permeability when finally situated in the core holder with hydrates present. While porosities were often higher than that would be observed in sandstone samples permeabilities were often quite low. This could likely be attributed to poor grain size sorting as well as clay content. In the Mount Elbert samples, Elbert, with a few exceptions, median grain sizes (MGS) for the hydrate-bearing layers typically fall within the coarse silt to very fine sand (31 to 125 microns) ranges. The bounding clay-rich beds typically have MGS values in the very fine to fine silt (4 to 16 microns) ranges. Consistent with grain-size results, XRD analyses report higher quartz (82% by weight) in units C and D, compared to 55% in surrounding sediment. Clay minerals comprise an average of 10% of units C and D compared to an average of 31% in finer-grained sediment. Units C and D contain about equal amounts of chlorite and illite, and lesser amounts of kaolinite and only trace amounts of carbonate, Winters et al. (2011). While it was found that higher porosities made hydrate formation favorable, the lack of permeability was a significant drawback to these particular core samples. After many unsuccessful attempts of trying to displace water by methane it was decided to perform the same procedure with nitrogen instead. It had been theorized that either high capillary pressure or additional hydrate formation was the cause of choked flow during this step when using methane. Nitrogen, which would not form hydrates at the tested conditions, was thought to be able to help confirm if additional hydrate formation was cause for previous difficulties or capillary pressure. Calculations performed using a software developed by Hydrafact (www.hydrafact.com) for nitrogen and methane in pure water system indicates that at the tested temperature conditions the hydrate phase boundary pressures for Nitrogen are almost two times that of methane. Therefore, as the dilution of methane with nitrogen increases (i.e., trending from pure methane to various mixtures of methane and nitrogen and then to pure nitrogen), the phase boundary pressures will increase from that of pure methane to pure nitrogen. Additionally, nitrogen is routinely used for relative permeability experiments as it does not easily dissolve in other fluids. Its inert nature makes it well suited for experiments. Again, hydrate pressure and temperature conditions were selected so that addition of mobile fluids would not dissociate hydrates. Approximately 2 pore volumes of gas were injected during displacement experiments. While nitrogen was able to displace water, actual two phase flow was not suitably observed during the course of the experiment. Therefore only calculations of the end point gas permeability bear much weight.
3.4. Relative permeability/gas end point permeability
4. Results
The next step of the experiment was to determine what gas permeability was present in the sample. Originally it was desired
The results summarized in this paper help to illustrate the ways in which hydrates affect permeability characteristics in unconsolidated core samples. While the initial aim of the research was to determine relative permeability in unconsolidated hydrate samples, data on water and gas end point permeabilities still proved useful. Table 2 summarizes the bulk dimensions, porosities
3.3. Effective permeability and hydrate saturation determination
Table 1 Example calculations of hydrate saturation.
Step Hydrate Formation Effective Permeability
mL Brine collected 14.00 A Brine collected 100.04 B Brine injected 107.72 C Pore Volume
(A-(C-B))/D
Saturation
39.20 D Ratio 0.16
Table 2 Selected properties of core samples used. Core number
Depth (m)
Diameter (mm)
Length (mm)
Porosity, fraction
Pore volume (mL)
Hydrate saturations, fraction
UAF-2 UAF-3 UAF-5 UAF-6
618 619 653 658
39.1 39.1 39.1 39.1
76.9 85.6 66.5 90.3
0.38 0.38 0.29 0.36
35.0 39.0 23.0 39.2
0.15–0.36 0.10–0.18 0.26 0.015–0.16
A. Johnson et al. / Marine and Petroleum Geology 28 (2011) 419–426
10000.0
0.50
1000.0
0.45
Permeability, mD
Porosity (This work), fraction
423
0.40
0.35
UAF-Permeameter This Work Omni-Permeameter
100.0 10.0 1.0 0.1
0.30
0.25 0.25
0.0 600
610
620
630
640
650
660
670
Depth, m 0.30
0.35
0.40
0.45
0.50
Porosity (Log), fraction
Fig. 3. Comparison of Mount Elbert permeabilities from different tests as a function of depth.
Fig. 2. Comparison between downhole log calculated porosities and experimentally determined porosities.
and tested hydrate saturations of each sample used for this experiment. Fig. 2, also summarized in Table 3 shows comparison of porosities measured in this work and those determined from logs. While conditions were intended not to be unduly altered, it seemed important to show that conditions of the core samples had been altered from what existed in the reservoir. 4.1. Comparison between measured values versus log data and other experimental works Due to physical constraints core samples used were not in their native state. High pressures, extensive amounts of fluid flow, and relative consolidation requirements were the reasons why core samples needed to be modified. Porosities were reduced preceding laboratory experiments since they were further consolidated to operate well within the core holder. As a result permeability was also likely reduced. Fig. 3, also summarized in Table 4 compares permeabilities determined in this experiment with those taken using pore permeameters by researchers from UAF and OMNI labs. As with porosity these values deviate from those observed in more native state conditions. 4.2. Hydrate formation Hydrates were confirmed to have formed in the core sample based on two primary data sets. The first was by analyzing pump data logged as the sample was cooled from room temperature down to a lower temperature where hydrate formation would occur. As mentioned earlier, hydrate gas consumption described by Sloan and Koh (2008) slowly increases as formation occurs and reaches its maximum rate and then decreases to a very low amount over time. This is equivalent to the pump flow rate when the pump is set to constant pressure. Fig. 4 is an excellent example of good hydrate formation. Peak pump flowrate corresponding to hydrate formation in this example is approximately 2 mL/min (0.05 pore
Table 3 Comparison between logged porosity and experimentally determined porosity in the laboratory. Core number
Lab porosity, fraction
Density porosity (ECS), fraction
UAF-2 UAF-3 UAF-5 UAF-6
0.38 0.38 0.29 0.36
0.45 0.41 0.34 0.38
volumes per min). The other method was to analyze the effective permeability to water. Hydrates act as a solid and therefore reduce the permeability of the sample. 4.3. Water relative permeability reduction as a function of hydrate saturation Hydrates were formed in core samples ranging from 1.5 to 36% hydrate saturation. Absolute and effective permeabilities before and after hydrate formation with water were determined by Darcy’s law (Equation (1)). All effective water permeabilities were divided by absolute permeabilities to determine the water relative permeability fraction at respective hydrate saturations. Ideally, if permeability, porosity, and hydrate saturation were uniformly distributed throughout each core sample, reduction in effective (relative) permeability would follow a more normal trend. However due to the probability that local variations in both effective (relative) permeability and hydrate saturation existed this trend at times is irregular. When observing the trend for each individual core sample it can be seen for core UAF-2 and UAF-3 that discrete increases in hydrate saturation did not always yield a greater reduction in effective (relative) permeability. The overall trend, however, clearly indicates a significant decrease in effective (relative) permeability with increased hydrate saturation. Fig. 5 shows how different hydrate saturations affected effective (relative) permeability for individual core samples. For the purposes of this work water effective permeability in the presence of hydrates is represented by a fraction, thereby comparing the permeability with and without a given saturation of hydrates. Also shown in Fig. 5 is an obvious relationship, i.e., water relative permeability of 1 when hydrate saturation is 0. 4.4. Relative permeability/gas end point permeability Gas-brine relative permeability as affected by hydrates in Mount Elbert samples was one of the original aims of this study. However this process presented many physical and technical challenges. At no time was methane able to flow through core samples containing hydrate with the remainder free and irreducible water. This was likely due to the fact that the samples’ low permeability lowered fluid velocity therefore forming additional hydrate from mobile brine and methane. After many unsuccessful attempts nitrogen was used in order to displace mobile water from the core. Data shown in Fig. 6 suggests that displacement of brine by gas is ‘‘piston like.’’ For the JBN method (Johnson et al., 1959) to calculate relative permeabilities it is necessary for significant two phase flow to be observed at the outlet of the sample for an extended period of
424
A. Johnson et al. / Marine and Petroleum Geology 28 (2011) 419–426
Table 4 Comparison of Mount Elbert permeabilities from different tests as a function of depth.
Depth (m) 608.8 614.8 618.0 (UAF-2) 619.2 (UAF-3) 653.0 (UAF-5) 623.6 625.3 658.2 (UAF-6) 641.9 647.6 659.4
Omni permeability (mD) 0.2 12.2
UAF-Permeameter (mD) 26.4 62.0
3.1 15.8 1.5 1370.0 1630.0
723.0 567.0 0.5
0.1 145.0 675.0
53.5 15.2 2.7
time. However, during these experiments it was observed that nearly all of the mobile brine was displaced before any gas breakthrough. Once gas breakthrough occurred, little to no brine production was observed. The JBN method was still used since it is meant for analysis of unsteady state displacement experiments and short periods of two phase flow that were observed in few runs. During two runs nitrogen was used to displace water and the effective permeability of gas at irreducible water saturation was determined as a function of hydrate saturation. While data for this is limited, it suggests that gas permeability is also decreased by increased percentages of hydrate saturation (Fig. 7). 5. Discussion As has been observed in nature, hydrates often exist in unconsolidated samples. Therefore hydrate experiments utilizing these samples are of interest. This experimental study confirms that previous techniques used to form hydrates is porous media can be applied to unconsolidated cores samples with additional modifications sometimes required. Brine effective permeability, the wetting phase, is most easily determined using the techniques outlined in this paper. One
2.5
observation immediately following the completion of hydrate formation gives some insight into how uniformly hydrates are distributed throughout the core sample. As gas was supplied to the top of the core holder hydrate formation was supported at that end of the core holder only. That is to say: a hydrate formation front was not also forming from the other end of the core sample. Instead the bottom of the core was analyzed with a pressure gauge. At certain times the two pressures observed on either side of the core prior to subsequent brine flooding were not equal and sometimes hundreds of psi apart. When this occurred subsequent brine flooding was often unsuccessful. The imbalance in pressures during hydrate formation suggests hydrates prevented the communication of pressure across the core sample. Other times, during the successful runs, pressure differences were much lower and over time stabilized brine flow was observed. During the determination of effective permeability initial high differential pressures were applied to the core in order to achieve significant brine flow (w0.1 mL/min). It is possible that this initial shock to the core with an incompressible fluid had the potential to dissociate some hydrates. However, once flow rates were observed to have increased to easily manageable amounts (>0.1 mL/min) differential pressures were reduced in an attempt to minimize the likelihood of excessive hydrate dissociation. The determination of
500 Flow Rate Pump Volume
2.0
1.0
480
UAF-2 UAF-3 UAF-5 UAF-6 Series5
460
1.5
420 400
1.0
380 360
0.5
0.8
Krw, fraction
440
Pump volume, mL
Flow rate, mL/min
This Work (mD)
0.6
0.4
0.2
320 0.0 0
500
1000
1500
300 2000
Time Steps (1 step = 30 seconds) Fig. 4. Example of hydrate formation step. Pumps set at constant pressure support the consumption of gas during hydrate formation.
0.0 0.00
0.10
0.20
0.30
0.40
Sh, fraction Fig. 5. Reduction in water relative permeability versus hydrate saturation for tested core samples.
A. Johnson et al. / Marine and Petroleum Geology 28 (2011) 419–426
0.60
0.06
K rw, fraction
0.50 0.40
0.05 0.04
0.30
0.03
0.20
0.02
0.10
0.01
0.00 8.0
13.0
18.0
Krg, fraction
Krw Krg Linear (Krg) Linear (Krw)
0 28.0
23.0
Sg, percent Fig. 6. Piston like displacement during unsteady state relative permeability experiment with hydrate saturation of 12.5%. This behavior prevents the collection of data which is able to help generate full relative permeability charts. Gas breakthrough occurred around 25 percent gas saturation with minimal water production following.
hydrate saturation was also determined at the end of brine flooding (not initial formed amounts). After the initial displacement of free gas from the sample, little if any gas was observed to be extracted from the core sample suggesting that hydrate dissociate was minimal. Intentionally dissociating hydrates following experimental runs also allowed produced gas to be analyzed and compared with injected gas. This allowed the researchers to determine if any significant hydrate dissociation during permeability experiments had occurred. One of the key difficulties observed during experimentation was hydrates reducing permeability to such an extent that fluid flow using the experimental setup was no longer possible. During hydrate formation gas is available in abundance due to the volume of the gas accumulator being an order of magnitude larger than the pore volume of the core sample. No additional brine was provided during hydrate formation. If hydrate stable conditions exist hydrates will continue to form provided excess amounts the constituent components are present. Since no additional brine is injected water will be the limiting component for hydrate formation. Assuming that there still exists permeability for fluid flow, gas still has the potential to seek out mobile water for additional hydrate formation. However, as water from lower capillary zones is depleted or hydrate formation restricts gas’s access to these low capillary pressure zones hydrate formation slows and eventually ceases. The resaturation of the remaining pore volume with brine following hydrate formation creates an environment where any additional free gas which is injected (presumably to perform
1.0
0.010
0.9 0.008
0.7 0.6
0.006
0.5 0.4
0.004
krg, fraction
krw, fraction
0.8
0.3 0.2
Krw Krg
0.1 0.0 0.00
0.05
0.10
0.002 0.000 0.15
Sh, fraction Fig. 7. Gas end point relative permeability as a function of hydrate saturation. Included are the corresponding brine end points for comparison.
425
a relative permeability experiment) has the potential to form hydrates. It is suggested that hydrate formation occurring during the gas flood procedure has the propensity to happen since brine had then been injected back into pore spaces of lower capillary pressure. It was later observed that high capillary pressure outright did not prevent the injection gas but rather could have retarded flow of gases (in our case methane) which also could form hydrates. Hydrate formation appeared to happen more easily during this step than during the end of the hydrate formation step since the gas was limited by the capillary pressure of immobile water in the latter. In general published material on experimentally determined reservoir properties of gas hydrate systems is scarce; in particular the relative permeability characteristics. However, in this section we have discussed data available in the literature especially in regards to the relationship between hydrate saturations and gas and water relative permeabilities and compared the results obtained in this study. Murray et al. (2006) recognized that estimating permeability in hydrate saturated rocks from core is difficult. To make accurate laboratory measurements on permeability hydrate stability must be closely monitored. They reviewed water effective permeability measurements for hydrate saturated cores from Mallik, which were reported by Uchida et al. (2005), and stated that in stable conditions water permeabilities range from 1 to 6 mD at estimated hydrate saturations ranging from 10–20%. In one of the rare studies, Ahn et al. (2005) presented a complete gas-water relative permeability curve for a synthetic hydrate bearing sediment at a maximum hydrate saturation of 15% using the unsteady state displacement technique, which was also used in this study. Gas and water relative permeabilities were reported for gas saturations ranging from about 12 to 28%. Their gas relative permeabilities were significantly low from close to zero to a maximum of less that 0.1, whereas our values were much less (Fig. 6) for a hydrate saturation of 12.5%. However, Ahn et al. (2005) water relative permeabilities ranged from 0.05 to a maximum of 0.6, which is in fairly close agreement with our results for comparable gas saturation range (Fig. 6). Kleinberg et al. (2005) presented the water relative permeability as a function of hydrate saturations ranging from 10 to 70% as part of the Mallik 5L-38 gas hydrate production research well program. The water relative permeability values were determined using Schlumberger CMRÔ (Combinable Magnetic Resonance) tool. They also compared the CMR determined values with a variety of models that have been proposed to predict the effect of gas hydrate on relative permeability. Experimental results presented in this study on effect of gas hydrate saturation on water relative permeability (Fig. 5) indicates a trend and general agreement analogous to the one reported by Kleinberg et al. (2005). However, as far as models are concerned, clearly, the data and their comparison to models raise as many questions as they answer given the fact that many of these model predictions indicate a deviation from the reported CMR permeabilities, based on which Kleinberg et al. (2005) stated that there is a clear need for direct relative permeability measurements on gas hydrate affected sediments. Jaiswal (2004) presented two data sets on effective permeability and relative permeability (from unsteady state displacement tests) data of gas and water phases for gas-hydrate-saturated Oklahoma 100 mesh sand and Alaska North Slope (ANS) subsurface sediment samples from the Anadarko Hot Ice 1 well. However, the core samples from the Anadarko well were determined to be void of gas hydrate. It was determined that the artificially grown hydrate saturations in the Anadarko core samples ranged from 7 to 31% compared to as low as 1.5 to 36% in this study. The Anadarko sample results indicate significantly low gas as well as water relative permeabilities for the tested hydrate saturations, which are somewhat in agreement with the gas relative permeabilities;
426
A. Johnson et al. / Marine and Petroleum Geology 28 (2011) 419–426
however, water relative permeabilities were found to be much higher in the case of Mount Elbert samples tested in this study. Overall, Jaiswal’s two data sets indicate that initial permeability prior to hydrate formation was higher than what was observed in our study, but still of a similar order of magnitude, yet had lower permeability following hydrate formation. Considering the various relative permeability studies, it may be speculated though that in general, the significantly low gas relative permeabilities observed (compared to water relative permeability) could perhaps be due to the fact that gas is the non-wetting phase, whereas water is the wetting phase thereby existing as a relatively continuous phase thus having a higher permeability. Additionally, differences between the reduction in permeabilities is possibly influenced by how hydrates are distributed in the pore spaces; hydrate saturated rock permeability depends on where the hydrate resides in the pore space (Kleinberg et al., 2003). 6. Conclusions and recommendations The following conclusions can be made as a result of this study: (1) The ability to form hydrates in unconsolidated samples while still providing meaningful permeability was confirmed. Injection of one or more fluids which can form hydrates through low permeability hydrate samples will likely lead to additional hydrate formation. Injection of non hydrate forming gases at the prevailing test conditions likely maintains the original hydrate saturation to a greater extent than hydrate forming gases. (2) Hydrates, as formed in the laboratory over short time scales, significantly affect the subsequent available permeability for all fluid types. Based on the work described herein the authors wish to make the following recommendations related to possible future work in this area: (1) Evaluate the extent to which consolidated core samples can be substituted for unconsolidated core samples for hydrate studies. Additionally, evaluate the extent to which nitrogen can be substituted for methane when trying to evaluate gas-brine relative permeability or gas effective permeability in unconsolidated hydrate samples. (2) Modify the procedure herein in order to perform steady state relative permeability experiments. Acknowledgements The authors would like to thank BP Exploration (Alaska) Inc for providing core samples for this experimental work. We would like to acknowledge the financial support provided by the U.S. Department of Energy and the University of Alaska Fairbanks’ Institute of Northern Engineering over the course of this research program. Disclaimer: This article is prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor an agency thereof, nor any of their employees, makes any warranty, expressed or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. References herein to any specific
commercial product, process, or service by trade name, trademark, manufacturer, or otherwise do not necessary constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of the authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. The views and opinions of the authors expressed herein do not necessarily state or reflect those of BP Exploration (Alaska), Inc. References Ahn, T., Lee, J., Huh, D.-G., Kang, J.M., 2005. Experimental study on two-phase flow in artificial hydrate-bearing sediments. Geosystems Engineering 84 (4), 101– 104. Anderson, B.J., Kurihara, M., White, M.D., Moridis, G.J., Wilson, S.J., PooladiDarvish, M.x., Gaddipati, M.x., Masuda, Y., Collett, T.S., Hunter, R.B., Narita, H., Rose, K.K., Boswell, R.M., 2011. Regional long-term production modeling from a single well test, Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope. Journal of Marine and Petroleum Geology 28 (2), 493–501. Collett, T.S., November 2002. Energy resource potential of natural gas hydrates. AAPG Bulletin 86 (11), 1971–1992. Collett. T.S., Dallimore, S.R., 2002. Detailed analysis of gas hydrate induced drilling and production hazards. In: Proceedings of the Fourth International Conference on Gas Hydrates, Yokohama, Japan, April 19–23, 2002. Dandekar, A.Y., 2006. Petroleum Reservoir Rock and Fluid Properties. CRC Press, Taylor and Francis, Boca Raton, FL. Davies, S.R., Boxall, J.A., Koh, C.A., Sloan, E.D., Hemmingsen, P.V., Kinnari, K.J., ZhengGang, X., Predicting Hydrate Plug Formation in a Subsea Tieback, 2008 SPE Annual Technical Conference and Exhibition, Denver, Colorado, USA, September 21–24, 2008. Hunter, R.B., Collett, T.S., Boswell, R.M., Anderson, B.J., Digert, S.A., Pospisil, G.x., Baker, R.A., Weeks, M.x., 2011. Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope: Overview of scientific and technical program. Journal of Marine and Petroleum Geology 28 (2), 295–310. Inks, T., Lee, M., Agena, W., Taylor, D., Collett, T.S., Hunter, R., Zyrianova, M., 2009. Seismic prospecting for gas hydrate and associated free-gas prospects in the Milne Point Area of Northern Alaska. In: Collett, T., et al. (Eds.), Natural Gas Hydrates: Energy Resource and Associated Geologic Hazards. American Association of Petroleum Geologists Hedberg Memoir, 89. Jaiswal, N.J., 2004, Measurement of gas–water relative permeability for gas hydrate systems: Master’s thesis, University of Alaska Fairbanks Note: Electronic copies of thesis can be made available on request. Johnson, E.F., Bossler, D.P., Naumann, V.O., 1959. Calculation of relative permeability from displacement experiments. Transactions of AIME 216, 370–372. Kleinberg, R.L., Flaum, C.,, Collett, T.S., 2005. Magnetic resonance log of JAPEX/JNOC/ GSC et al. Mallik 5L-38 gas hydrate production research well: gas hydrate saturation, growth habit, and relative permeability. In: Dallimore, S.R., Collett, T.S. (Eds.), Scientific Results from the Mallik 2002 Gas Hydrate Production Research Well, Mackenzie Delta, Northwest Territories, Canada, Bulletin 585. Geological Survey of Canada, Ottawa. Kleinberg, R.L., Flaum, C., Griffin, D.D., Brewer, P.G., Malby, G.E., Peltzer, E.T., Yesinowski, J.P., 2003. Deep sea NMR: Methane hydrate growth habit in porous media and its relationship to hydraulic permeability, deposit accumulation, and submarine slope stability. Journal of Geophysical Research 108 (B10), 2508. Kvenvolden, K.A., 1993. Gas hydrates as potential energy resource – a review of their methane content. In: The Future of Energy Gases. U.S. Geological Survey Professional Paper, vol. 1570, pp. 555–561. Murray, D., Fukuhara, M., Khong, C.K., Namikawa, T., Yamamoto, K., 2006. Permeability estimates in gas hydrate reservoirs of the Nankai trough, SPWLA 47th Annual Logging Symposium, June 4–7, 2006. Singh, P.K., 2008. An engineering study to investigate the methane hydrate resource potential associated with the Barrow gas fields in Alaska: Master’s thesis, University of Alaska Fairbanks Note: Electronic copies of thesis can be made available on request. Sloan, E.D.,, Koh, C.A., 2008. Clathrate Hydrates of Natural Gases, third ed. CRC Press, New York, NY. Uchida, T., Tsuji, T., Takahashi, T., Okui, T., Minagawa, H., 2005. Petrophysical properties and sedimentology of gas-hydrate-bearing sediments in the JAPEX/ JNOC/GSC et al. Mallik 5L-38 gas hydrate production research well. In: Dallimore, S.R., Collett, T.S. (Eds.), Scientific Results from the Mallik 2002 Gas Hydrate Production Research Well, Mackenzie Delta, Northwest Territories, Canada, Bulletin 585. Geological Survey of Canada, Ottawa. Winters, W.J., Walker, M.M., Hunter, R.B., Collett, T.S., Boswell, R.M., Rose, K.K., Waite, W.F., Torres, M.E., Patil, S.L., Dandekar, A.Y., 2011. Physical properties of sediment from the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope. Journal of Marine and Petroleum Geology 28 (2), 361–380.