State of the Science: Recent Advances and Current Challenges in Methane Hydrate Research
In recent years, a number of significant advances in methane hydrate research have been enabled by the Department of Energy (DOE) Program. A variety of ambitious field programs have advanced state-of-the-art core sampling, geophysical surveys, and experimental production testing. Substantial scientific knowledge has also been accrued through a number of diverse laboratory investigations and modeling studies. These and several international research initiatives have moved the field forward to the point where concentrated methane hydrate accumulations have been identified, and production concepts have been put forward based on existing oil and gas production methods, modified for the unique properties and reactions of methane hydrate. The state of knowledge of methane hydrate behavior in the environment has also been advanced through consideration of methane hydrate degassing induced by natural geologic processes.
This chapter reviews recent, critical, international, and domestic advances in methane hydrate research and identifies some of the remaining challenges to realizing the goal of commercial methane hydrate production. These challenges form a basis for Chapter 3, which discusses the research
projects currently supported by the Program, including their achievements and the remaining knowledge gaps.
METHANE HYDRATE RESOURCE ASSESSMENT
The “goal” in methane hydrate research and development is the identification and quantification of technically and economically recoverable natural gas from methane hydrate occurrences. Because of the paucity of reliable field data, past research focused on the basic documentation of the existence and regional locations of global methane hydrate occurrences. More recently, a number of new quantitative estimates of in-place methane hydrate volumes have been undertaken using petroleum systems concepts developed for conventional oil and natural gas exploration. When combined with field investigations to establish the physical properties of methane hydrate deposits in different geologic settings, a basis has also been established for considering production methods and recoverability.
Global Methane Hydrate Estimates
Over the past 30 years a number of researchers have compiled global inventories of the total potential volumes of natural gas occurring as methane hydrate (Kvenvolden, 1988, 1993; Milkov, 2004). These estimates have garnered much interest and served to stimulate consideration of methane hydrate as a possible global energy resource. However, the utility and application of these estimates are limited because they range over several orders of magnitude and the knowledge and data upon which the predictions have been made remain largely speculative and with correspondingly large uncertainties. For example, early methane hydrate resource determinations in the 1980s and 1990s relied mainly on indirect evidence such as bottom-simulating reflectors (BSRs) identified in marine seismic surveys, or on estimates of the portion of the methane hydrate stability field that might reasonably contain methane hydrate from microbial and thermogenic sources. In the past 15 years a number of dedicated methane hydrate drilling campaigns have been undertaken around the world (see
Figure 1.1), allowing researchers to refine their geologic models and improve their interpretations of geophysical data. Whereas some early global estimates of methane occurring as methane hydrate were as high as 1018 m3 (~35 million trillion cubic feet [TCF] methane at standard pressure and temperature [STP] conditions), estimates by Milkov (2004) decreased the range to 1-5 × 1015 m3 (~35,000-177,000 TCF). But later estimates by Klauda and Sandler (2005) are much larger (1.2 × 1017 m3 or 4,200,000 TCF), demonstrating that even recent estimates range over several orders of magnitude. However, even the lowest global resource estimates are 2 to 10 times greater than global estimates of the conventional natural gas endowment of 4.4 × 1014 m3 (~16,000 TCF) of reserves and technically recoverable undiscovered resources (Ahlbrandt, 2002; TEA, 2006). Recalling that the United States in 2008 consumed 6.5 × 1011 m3 (23 TCF; see Chapter 1) of natural gas, the global estimates of volumes of methane in methane hydrate are significant.
Although the global methane hydrate resource inventories illustrate the importance of methane hydrate as a component of the global carbon cycle, their utility to address the energy potential of methane hydrate is limited. The majority of the enormous global methane hydrate inventory occurs as dispersed concentrations over large areas and therefore recovery of the methane, for the most part, is unfavorable technically and economically. Conversely, areas with concentrated methane hydrate deposits that may be the appropriate candidates for economic development are more limited in size. Boswell and Collett (2006) reviewed the challenge of appraising the energy potential of the large but uncertain global inventories of methane hydrate and introduced the resource pyramid concept which qualitatively appraises the distribution of the global methane hydrate resource and evaluates which type of deposit holds the greatest economic potential for development (Figure 2.1). They conclude that the deposits that are most concentrated and hold greatest potential for exploitation occur in sandstone reservoirs in the Arctic and deepwater marine environments.
Recent Methane Hydrate Resource Assessments
Considerable effort has been devoted recently to carrying out more focused methane hydrate resource appraisals in specific regions by applying, with some modifications, quantitative methods commonly used for appraising conventional oil and natural gas deposits. This approach is consistent
The Methane Hydrate Resource as a “Petroleum System”
Recent field investigations conducted over the past decade in the offshore (i.e., Gulf of Mexico, Cascadia margin, Nankai Trough, India) as well as onshore (Mackenzie Delta of Canada and the Alaska North Slope) have shown that the occurrence of methane hydrate can be interpreted in the context of a “petroleum system,” in a manner similar to that used to evaluate conventional hydrocarbon occurrences. The methane hydrate system contains all the elements of a conventional petroleum system with consideration of the source of gas (thermogenic or microbial), possible migration pathways, and nature of the reservoir sediments, traps, and seals. The unique attributes of the methane hydrate petroleum system include the dominant controls of pressure and temperature on its stability and the differences in the manifestation of methane hydrate as a solid rather than gaseous form. This introduces unique considerations of trapping and/or sealing processes and consideration of temporal aspects because the pressure-temperature field may change with time. Typically, marine occurrences of methane hydrate are found at relatively shallow depths 500 meters below seafloor whereas methane hydrate in permafrost-dominated areas is found 1,200 meters below the surface (see also Box 1.1).
with the increasing knowledge of the geologic and reservoir controls over methane hydrate occurrences (see also Chapter 3) and the recognition of the applicability of petroleum system approaches that consider the source of gas, migration pathways, reservoir potential, and seals as the basis for establishing regional accumulation models (see Box 2.1).
Recent U.S. Methane Hydrate Resource Assessments
Gulf of Mexico
Using the extensive industry database of exploratory wells and two-dimensional (2D) and three-dimensional (3D) seismic surveys, the
Minerals Management Service (MMS) completed a preliminary methane hydrate resource assessment in the Gulf of Mexico1 (Frye, 2008). This MMS-funded and -directed work is part of the interagency collaboration on methane hydrate research, and has both contributed to and derived input from the Program’s Gulf of Mexico joint industry project (JIP)2 (see also Chapter 4). The assessment employs a spatial mass balance model and benefits from a long history of industry exploration and production activity in the Gulf of Mexico. Working in collaboration with industry and other research agencies, MMS has developed an extensive drilling database and more than 400,000 km2 of seismic information (of which about half is 3D data) for the assessment. Although these data were not collected with methane hydrate targets in mind, the data nonetheless provided a substantial basis for model inputs such as geologic setting with respect to the methane hydrate stability field, percentage of sand, as well as considerations of the gas sources, migration pathways, and trapping mechanisms. The assessment also considers possible seafloor indicators such as chemosynthetic communities and carbonates that may be associated with areas of higher probability for methane hydrate occurrences at depth. Using these attributes, the model first calculates gas generation through time, and then reallocates the distribution of gas based on a migration model.
The MMS resource assessment model is based on the geologic characteristics of 200,000 cells that measure 2.32 km2 each, allowing for an assessed area of approximately 450,000 km2. The total volume of inplace methane in methane hydrate is calculated to range from about 11,000 TCF to 34,000 TCF with a mean estimate of 21,000 TCF (315 to 975 × 1012 m3; mean estimate of 607 × 1012 m3). Anticipating that the production potential may depend on the type of confining sediment in which the methane hydrate occurs, this estimate is further subdivided to a predicted mean of about 6,700 TCF (190 × 1012 m3) occurring in association with sandstone reservoirs (shown in Figure 2.2) and about 14,700 TCF (417 × 1012 m3) in association with shale and fractured reservoirs. Significant accumulations
are predicted near the margins of minibasins and at the front of the Sigsbee Escarpment at the southern margin of the salt in the Gulf of Mexico (Figure 2.2). Importantly, the estimates represent in-place resources and do not include either technically or economically recoverable resources.
The MMS anticipates using the methods and experiences from the Gulf of Mexico assessment as a framework to evaluate the entire U.S. Outer Continental Shelf including Alaska, Atlantic, and Pacific margins. A phased approach is anticipated. The first effort will assess the in-place methane hydrate resources; subsequently, the gas volumes that could be technically recovered will be evaluated; the last phase will consider economically recoverable resources.
Alaska North Slope
A methane hydrate resource assessment was released in November 2008 by the U.S. Geological Survey (USGS), covering the terrestrial methane hydrate beneath the Alaska North Slope (Collett et al., 2008; Figure 2.3). This work was supported primarily by the USGS with some contributions from DOE as part of the interagency cooperation on methane hydrate research (see Chapter 4 for further discussion). The assessment uses a petroleum systems approach (see Box 2.1). This USGS assessment is the first to estimate the amount of methane in the methane hydrate resource that can be technically recovered using conventional hydrocarbon production techniques. Research supported by the DOE program was central to this assessment as field research enabled through the BPXA-managed Alaska North Slope project3 provided a well-constrained case history of a North Slope accumulation, and reservoir simulation studies established a basis for predicting recoverability (Figure 2.3). The USGS assessment also carefully considered the results of the Mallik 2002 production research well program in the Mackenzie Delta (see Figure 1.1 for location) and preliminary results from a subsequent program in 2007 and 2008 (e.g., see Box 2.5). Among the various techniques for production, the USGS suggests that
http://www.netl.doe.gov/technologies/oil-gas/FutureSupply/MethaneHydrates/projects/DOEProjects/Alaska-41332.html; this cooperative agreement is managed by BP Exploration Alaska, Inc. (BPXA).
depressurization is the most promising (see also section Depressurization Technique).
The total undiscovered technically recoverable methane from the methane hydrate resource for the North Slope of Alaska (Figure 2.3) was estimated by the USGS to range between 25.2 and 157.8 TCF, representing 95 percent and 5 percent probability, respectively, with a mean of 85.4 TCF.4 This estimate allocates methane in methane hydrate resources to three widespread geologic formations on the North Slope. The assessment screens out occurrences less than 20 billion cubic feet (BCF) and does not consider methane hydrate deposits within ice- bonded permafrost.
The USGS estimate of the technically recoverable methane resource endowment remains uncertain because long-term production has not been demonstrated. However, estimating the recoverability of this resource has been undertaken with the reasonable expectation that conventional oil and gas recovery methods can be employed for sand-dominated methane hydrate reservoirs.
Eastern Nankai Trough, Japan
Japan has been pursuing an ambitious national methane hydrate research and development program to evaluate the energy potential of methane hydrate accumulations in the Nankai Trough (Ohno, 2009). Whereas many other resource assessments around the world have relied primarily on industry exploration data collected during the search for deeper hydrocarbon targets, the Japanese assessment is largely based on field research programs, including drilling and seismic surveys, conducted specifically for methane hydrate exploration (Fujii et al., 2008; Figure 2.4). The Japanese resource assessment applies conventional statistical methodologies using 2D and 3D seismic surveys designed specifically for shallow methane hydrate targets and drilling results from 16 dedicated stratigraphic test wells. This approach allowed researchers to establish a model that predicted high methane concentrations in methane hydrate accumulations within
turbidite sand sequences. Ten prospective methane hydrate zones were evaluated by considering sedimentary rock volumes that would most likely contain methane hydrate as well as other physical characteristics such as rock porosity and methane hydrate type (“cage occupancy”; see Box 1.1). Calculated resource estimates indicate a methane resource of 1.14 × 1012 m3 (40 TCF) at STP within the studied region within the Nankai Trough.
THE CHALLENGE OF MAPPING AND QUANTIFYING METHANE HYDRATE
Three unique characteristics control the application of remote-sensing exploration methods for methane hydrate: (1) methane hydrate can only be present under specific formation temperature and pressure regimes, (2) the occurrence of methane hydrate in sediments alters the physical properties of the host material significantly (e.g., porosity, electrical resistivity, seismic velocity, bulk and shear modulus; Santamarina and Ruppel, 2008), and (3) applying petroleum system concepts has been shown to be useful for finding concentrated deposits (e.g., consideration of source, migration, seals, reservoirs, and containment). Although progress has been made to improve methods to map and quantify methane hydrate occurrences, significant technical challenges remain.
Mapping the Methane Hydrate Stability Field (Pressure and Temperature)
Defining the pressure-temperature stability field of methane hydrate (Box 1.1) is an important consideration in undertaking a regional assessment of possible methane hydrate accumulations. Various remote-sensing techniques (see below) can be employed to measure and/or estimate in situ pressure or temperature characteristics of the sedimentary column. In marine environments, a first approximation of the temperature regime can be determined by considering the mean annual seabed temperature and regional estimates of the geothermal gradient. Physical measurements
can include drill-stem temperature measurements5 made by industry during drilling of exploration wells and scientific measurements made with probes attached to the drill string (Davis et al., 1997). However, these are only point measurements, and because they are made during the course of drilling, concerns exist that the measurements may be affected by drilling disturbance. More recently, fiber-optic distributed temperature sensors (DTS) have been used with some success to estimate equilibrium temperatures in terrestrial and marine methane hydrate settings (Henninges et al., 2005; Fujii et al., 2008). The substantial advantage of the DTS technique is that it can provide 1-meter vertical resolution to the accuracy of 0.1°C, and with repeat measurements, equilibrium temperatures can be estimated by applying corrections for drilling disturbance.
Occurrences of overpressured zones in association with methane hydrate–bearing sediments can be expected to significantly alter methane hydrate stability (e.g., Bhatnagar et al., 2008). Unfortunately measurements of the in situ pressure regime are not routinely undertaken in most methane hydrate field investigations. Typically for marine methane hydrate deposits a hydrostatic pressure gradient is assumed from the seabed. Although this may be reasonable for conditions with uniform geology, areas with complex geology may experience significant overpressure affecting methane hydrate stability.
Finally, the geochemistry of the pore fluids and natural gas species is also important in determining the in situ stability of methane hydrate occurrences (e.g., Ruppel et al., 2005). As reviewed in Sloan and Koh (2008) gas composition can affect the methane hydrate structure, and pore fluid salinity can affect methane hydrate stability. The most commonly used approach employed to date is to rely on core measurements where gas and pore fluid samples are collected and analyzed (see section Geophysical Tools to Detect and Quantify Methane Hydrate Accumulations). As with the challenge of measuring undisturbed formation temperatures, the challenge of characterizing the in situ gas and fluid composition is significant. One
approach that has been used with some success is the Modular Dynamic Formation Tester tool, which can extract in situ gas and fluid samples from isolated borehole intervals (Dallimore and Collett, 2005; Hunter et al., 2008).
Use of BSRs as an Estimate of the Base of the Methane Hydrate Stability Zone
Since the 1970s, methane hydrate in the marine environment has traditionally been inferred by mapping of BSRs in seismic reflection profiles (e.g., Shipley et al., 1979). As shown in Figure 2.5, a BSR is a regional seismic
response that typically follows the sea-bottom topography. The BSR has been interpreted to indicate a change in physical properties of the sediments across the base of the methane hydrate stability zone (BMHSZ) where primary-wave (P-wave) seismic velocities6 decrease from high values, due to the presence of methane hydrate above, to low values due to the presence of free gas below the BSR. Because the BSR is conformable with an assumed geothermal boundary rather than a geologic boundary, it has been generally assumed to indicate the BMHSZ.
However, the BSR alone does not provide sufficient information about the amount and exact location of methane hydrate above the BMHSZ, or free gas beneath the BMHSZ. The drilling expeditions on the Blake Ridge (Ocean Drilling Program Leg 164),7 offshore Cascadia (Integrated Ocean Drilling Program Expedition 311),8 and offshore India (National Gas Hydrate Program Expedition 01)9 have all shown an apparent disconnect between the occurrence of methane hydrate and the presence of a BSR. Nonetheless, the presence of a BSR can be an indicator for the presence of some free gas at the BMHSZ, and it can provide a start to focus exploration efforts.
Geophysical Exploration Tools to Detect and Quantify Methane Hydrate Accumulations
Methane hydrate occurs in nature within the host sediment in different macroscopic forms where it replaces pore water: (a) methane hydrate can be disseminated within the sediment pore space or (b) methane hydrate can occur as more massive forms in nodules, veins, or fractures (sizes can vary from millimeter-scale veins to fractures several tens of centimeters thick; see Box 1.1). Independent from the specific macroscopic form of occur-
rence, the bulk physical properties of methane hydrate–bearing sediments are different relative to the corresponding sediments without methane hydrate. The two most important physical properties for detecting and quantifying methane hydrate are electrical resistivity (Box 2.2) and P-wave velocity.
Because solid methane hydrate replaces pore water in sediment, the formation of methane hydrate reduces the porosity of the sediment, which in turn increases the elastic modulus of the sedimentary package. This physical change can lead to differences in the sediment’s P-wave velocity, which can be detected with remote-sensing methods. The most common of these methods is a seismic reflection survey (Box 2.2), which uses acoustic waves to image subsurface structures and measure velocity changes between different types of subsurface sediment.
Detection of methane hydrate using seismic reflection data is not free of ambiguity. Natural variation of the physical properties of sediment, for example, from changes in grain size or compaction, or the occurrence of pore-filling materials other than methane hydrate (e.g., carbonates) can also result in the formation of velocity differences. Furthermore, small concentrations of methane hydrate (of about 5 percent or less) can reduce seismic reflection strength. This phenomenon has been reported from marine settings such as the Blake Ridge (Lee and Dillon, 2001). Understanding the natural reflectivity and host sediment characteristics is critical for determining the presence, and estimating the amounts, of methane hydrate based on seismic reflection data. Several approaches use seismic data for methane hydrate saturation mapping including impedance inversion and analysis of prestack seismic data; shear-wave or multicomponent seismic data may also be employed to map methane hydrate occurrences (Box 2.2 provides more technical detail regarding these techniques).
Prior to 2002, no strategic geophysical exploration specifically for Arctic methane hydrate had been attempted using seismic techniques. Methane hydrate was encountered in wells as a by-product of conventional hydrocarbon exploration. Definition of the regional methane hydrate stability zone was achieved through the use of the base of permafrost and temperature data from well locations (Majorowicz and Osadetz, 2001).
Seismic Reflection Surveys in Exploration for Methane Hydrate
Seismic waves emitted from a controlled source (such as an airgun) reach subsurface discontinuities (geological structures or changes in sediment properties) and reflect the sound waves back to one or more receivers. Recordings of these returning waves allow the calculation of the elastic properties of the subsurface layers through which the seismic waves have passed. Propagation of seismic waves is a function of impedance of the sediments, measured as the product of density and velocity. if methane hydrate is present in sediments, the impedance is typically much higher than for non-methane hydrate–bearing sediments. impedance inversion can use calibration from well-log data to calculate bulk density, P-wave velocity, porosity, and methane hydrate saturation in sedimentary packages (e.g., Bellefleur et al., 2006). The other type of approach to determine methane hydrate saturation in the subsurface uses prestack seismic data to measure seismic velocity, followed by an inversion step to link methane hydrate concentration to reflection strength (e.g., Dai et al., 2008). This method works without well calibration, but depends heavily on high-quality prestack seismic data and the rock-physics model that links velocity with saturation.
S-wave or multicomponent seismic data may offer an additional approach to help identify methane hydrate occurrences and to distinguish among methane hydrate formation models. However, acquisition of S-wave data is typically more challenging than P-wave data (on land as well in the marine realm). Only a few examples exist in which S-waves were used to image methane hydrate occurrences (e.g., Backus et al., 2006; Hardage and Murray, 2006). Ocean-bottom cables (OBC) may offer a simpler remote-sensing approach over larger regional distances than the use of a higher-seismic-resolution single (or multiple) ocean-bottom seismometer (OBS) station. The high deployment and recovery costs of either OBSs or OBCs are prohibitive for most academic research groups and are thus limited to the conventional oil and gas industry, where these tools are routinely used in areas of active exploration and production.
Effects of Methane Hydrate on Electrical Conductivity of the Sediment
As methane hydrate forms, the conductive interstitial pore-water phase is replaced with solid methane hydrate with a significantly lower conductivity. Only pure water can be incorporated in the methane hydrate cage structure, and, if the original pore fluid is saline, methane hydrate formation can cause salt exclusion, referred to as the local salt-inhibition effect (which is only a short-term effect in geological timescales). The result of methane hydrate formation is that the conductive pore water is replaced by methane hydrate. Thus, the bulk resistivity of the methane hydrate–bearing sediment is increased. Also, as the interstitial pore-water volume is replaced with methane hydrate, the porosity is effectively reduced. This increase in electrical resistivity and porosity reduction are described by an empirical relationship referred to as Archie’s law (Archie, 1942).
Only recently have dedicated efforts been conducted using 3D seismic data for mapping and quantifying methane hydrate in permafrost settings (Bellefleur et al., 2006; Riedel et al., 2009; Inks et al., 2010).
Remote-sensing techniques such as electromagnetics (EM) or magnetotellurics (MT) can detect higher-resistivity rocks—or rocks that may more likely contain methane hydrate—because of the behavior of methane hydrate as an electrical insulator (see Box 2.3). EM and MT are currently employed mainly in marine environments (e.g., Yuan and Edwards, 2000; Weitemeyer et al., 2006) but are not commonly used in the Arctic because of operational challenges in permafrost regions. However, the typically broad-scale geophysical anomalies detected with these techniques are not optimal for the purpose of methane hydrate resource appraisals.
Methane Hydrate Core and Physical Property Studies
Although progress has been made with the various remote sensing and in situ measurement techniques described above, core investigations are essential (a) to determine primary sediment controls on stability and mechanical properties, (b) to validate pore physics models, and (c) to quantify the reaction of methane hydrate deposits to production. The challenges are significant: in addition to heat and fluid contamination that may occur during drilling, changes in the pressure and temperature regime experienced during core retrieval and extraction can cause substantial degradation of methane hydrate and disruption of the sediment properties. To date, two directions have been pursued: (1) improvement of coring techniques to minimize the disruption of the in situ pressure and temperature regime and (2) physical property investigations using methane hydrate samples grown under laboratory conditions which attempt to replicate those that might be found in nature.
The development of pressure coring systems, which strive to maintain the in situ pressure (and temperature) of a core sample during retrieval in the field, and pressure core testing systems, which allow laboratory tests to be performed on pressure cores (without depressurization) has been a long-standing goal of the methane hydrate research community. The first attempts to apply pressure coring methods for methane hydrate drilling investigations in the 1980s, including later modifications to these systems through the 1990s, identified various technical problems and the significant time required to extract a sample from the core barrel. Subsequent programs successfully developed and applied a coring system that could control both temperature and pressure in research wells in the Nankai Trough (pressure-temperature core sampler [PTCS]; Takahashi and Tsuji, 2005) and an integrated pressure coring and analysis system to allow precise x-ray imaging and gamma densitometry under pressure (Schultheiss et al., 2008). A pressure core testing system has also been developed to enable physical property measurements to be performed on recovered pressure cores of methane hydrate–bearing sediment without depressurization, and/or partial dissociation of the sample (Santamarina, 2008). For example, laboratory measurements of the mechanical properties of hydrate-bearing
sediment cores recovered from the Nankai Trough using a PTCS and then subjected to different pressure conditions showed that cores with high hydrate saturations (43 percent) were stronger than cores with either low hydrate saturations (2.7 percent) or dissociated (depressurized) core samples (Hato et al., 2008).
The high cost of field programs, the challenge of retrieving well-preserved core samples, and the need to obtain accurate and reproducible data from close analogs to natural hydrate have also encouraged research efforts to grow methane hydrate under laboratory conditions (Box 2.4). Some of the first researchers to investigate methane hydrate grown in natural sediments used an autoclave to grow methane hydrate in natural and artificial sediment samples by introducing free gas (Ershov and Yakushev, 1992). Modifications of this technique have been used for determining thermal and geophysical properties and salinity effects on methane hydrate stability conditions (Wright and Dallimore, 2010). Another approach described by Stern at al. (2005) has been to form methane hydrate–sediment aggregates by physically mixing sediment and polycrystalline methane hydrate granules together. During the past decade a number of laboratories around the world have strived to build devices styled upon apparatuses used commonly in soil mechanics. These devices hold the potential to apply 3D confining pressure and to introduce methane dissolved in pore water rather then as free gas.
THE CHALLENGE OF PRODUCING METHANE FROM METHANE HYDRATE
Gas recovery from methane hydrate presents significant technical challenges because the gas is in a solid form and deposits occur in remote and hostile Arctic and deep marine environments. As dedicated field studies have been conducted around the world, it has also become apparent that methane hydrate can occur in a variety of different reservoir settings; each may require somewhat different field development strategies. Primary reservoir controls are likely to include (a) concentration and form of the methane hydrate occurrence, (b) physical properties of host rock (e.g., thickness, porosity,
permeability, thermal properties, in situ stress, and strength), (c) physical properties of overlying and underlying sediments, (d) pressure and temperature environment, (e) nonuniform conditions such as geologic heterogeneity or possible communication with open faults or fractures, and (f ) presence of free gas and/or free water zones above, below, or within the methane hydrate occurrence. To ensure safe and efficient drilling, completion, and production, a sound knowledge of the geomechanical properties of methane hydrate–bearing sediments is also necessary, as is the ability to predict changes in these properties during and after methane hydrate dissociation. Finally, environmental concerns associated with production are also keys to consider, including strategies for disposal of produced water, potential effects on the seafloor or subsurface in the case of marine deposits, and interactions with permafrost in the case of Arctic deposits.
Based mainly on conventional hydrocarbon completion and production methods, three primary methane hydrate production concepts have been proposed: (1) depressurization, (2) thermal stimulation, and (3) chemical stimulation. The goal with each is to manipulate the in situ stability conditions of the methane hydrate and induce in-place dissociation to release free gas and associated hydrate-bound pore water. Each of these methods is discussed in more detail below.
Worldwide experience in production testing of methane hydrate is very limited. Makogon (1981) has proposed that the Messoyakha natural gas field in northern Siberia may have been capped by methane hydrate and that the production response of this field can be explained in part by dissociation of methane hydrate as the pressure of the free-gas reservoir declined with time. However, this interpretation has been questioned (Collett and Ginsburg, 1998), and the scarcity of field data to confirm the initial in situ conditions or the detailed production response greatly limits any modern engineering evaluation. The only other full-scale methane hydrate production study to be undertaken has been at the Mallik field in the Mackenzie Delta (Box 2.5). At Mallik, a thermal stimulation test was undertaken in 2002 by a five-country consortium, including participation by DOE (Dallimore and Collett, 2005). Full-scale depressurization testing at the site was also undertaken by a Canadian-Japanese research program in 2007
Challenges to Laboratory Synthesis of Methane Hydrate-Bearing Sediment Samples
A key challenge in synthesizing repeatable samples that closely represent natural methane hydrate–bearing sediment formations is that natural cores that form within the hydrate stability zone most likely exhibit a methane hydrate pore-filling morphology (formed from an aqueous solution containing dissolved gas), whereas laboratory-synthesized hydrate samples which are typically formed from free gas generally result in methane hydrate cementing the sediment grains (Sloan and Koh, 2008; Waite et al., 2009). Therefore, the synthesis method strongly influences the pore-scale habit (see figure below), thereby potentially affecting the structural and physical properties of the hydrated sample. Methane hydrate–bearing sediment samples synthesized with dissolved gas can exhibit a formation mechanism and morphology more closely replicating nature (particularly hydrate formed within the hydrate stability zone and in coarse-grained sediment; Dallimore et al., 1999; Winters et al., 1999; Waite et al., 2009), but these syntheses involve extremely challenging and time-consuming procedures (Spangenberg et al., 2008; Waite et al., 2009). The use of laboratory-synthesized methane hydrate–bearing sediment samples (prepared using different methods, such as free gas plus partially water-saturated sediment, free gas plus ice grains plus sediment, premixed hydrate grains with sediment, and/or dissolved gas in water plus sediment) can be evaluated by comparing the physical property measurement data obtained using these samples with pressure coring and in situ hydrate field measurements. Further studies performed on the pore-scale habit of hydrate-bearing sediment systems could add needed detail to these types of laboratory syntheses.
The need to synthesize methane hydrate–bearing sediment samples that closely resemble natural samples has been recognized by most researchers and has also resulted in the ongoing laboratory synthesis efforts, and a shift away from using the model tetrahydrofuran (THF) hydrate system, which is stable at atmospheric pressure below 4.4°C (and hence is more convenient to prepare and handle in the laboratory than is methane hydrate). Important
Response of a Methane Hydrate Reservoir to Pressure Drawdown: The Mallik Well Example
The Mallik site, in Canada’s Mackenzie Delta, has had a long history of methane hydrate investigation with international research and development programs undertaken in 1998 (Dallimore et al., 1999) and 2002 (Dallimore and Collett, 2005). Core and well-log studies have confirmed high concentrations of methane hydrate within clastic sands, and the occurrence of methane hydrate as a matrix pore-filling material with an interconnected liquid-water interface with measurable permeability in the 0.001 to 0.01 milliDarcy range. The Japan Oil, Gas and Metals National Corporation, Natural Resources Canada, and Aurora College returned to the site in the winters of 2007 and 2008 to complete the first full-scale pressure drawdown production tests (Dallimore et al., 2008; Yamamoto and Dallimore, 2008). Field activities in the first year included drilling, borehole geophysics, and installation of production and monitoring infrastructure. A 13-meter test interval with high methane hydrate concentrations was selected for pressure drawdown testing. A short production test was undertaken by lowering the formation pressure below the methane hydrate phase equilibrium. The 2007 test results revealed the substantial mobility of methane hydrate—bearing sediments at Mallik when the methane hydrate, which bonds the sandy reservoir sediments, was dissociated. Because of the loss of sediment strength, sand flowed into the well causing operational problems (Dallimore et al., 2008; Kurihara et al., 2008; Numasawa et al., 2008). Although the duration and operation of the test were limited, several flow-rate responses were observed during the latter part of the test to exceed 5,000 m3/day (see figure on opposite page).
Operational problems encountered with sand inflow in 2007 were overcome in 2008 with the use of sand screens (Yamamoto and Dallimore, 2008), and a simpler operational sequence. A downhole heater was also used to prevent methane hydrate formation within the production tubing. Although detailed production results remain confidential at this time, Yamamoto and Dallimore (2008) and Dallimore et al. (2008) reported continuous
(Dallimore et al., 2008; Numasawa et al., 2008) and 2008 (Yamamoto and Dallimore, 2008). Although more limited, additional data are also available from short-term drilling tests conducted by industry in the 1970s (Bily and Dick, 1974) and from small-scale, in situ tests of the methane hydrate formations conducted as part of the 2002 Mallik program (Dallimore and Collett, 2005), the 2001 Nankai drilling program (Tsuji et al., 2007), and the 2007 drilling program in northern Alaska as part of the BPXA-managed Alaska North Slope project (Hunter et al., 2008; see also Chapter 3).
The depressurization technique is considered by many researchers to be the most cost-efficient and practical production method (Max et al., 2006). The primary concept is to reduce the in situ pressure of the fluids in the porous rocks in contact with the methane hydrate reservoir. This technique can be applied by changing the pressure regime of the methane hydrate reservoir itself, or by reducing the pressure of the overlying or underlying sedimentary rocks in contact with the methane hydrate reservoir and transferring this pressure change to the reservoir. The efficiency of this technique is significantly influenced by the manner in which the methane hydrate occurs (i.e., disseminated within sediment or in massive form) and the abundance and interconnectivity of the liquid pore water which helps to transmit the pressure decrease.
The primary concept in the thermal stimulation technique is to increase the in situ temperature of the methane hydrate reservoir above the pressure-temperature stability threshold. The only full-scale thermal stimulation test was conducted at the Mallik site in 2002. During this test, hot brine was circulated across a 13-meter perforated test interval, relying mainly on heat conduction into the formation to dissociate methane hydrate (see Dallimore and Collett, 2005). Approximately 500 m3 of gas were recovered during the course of the 124-hour thermal test. This low volume of gas
recovery suggests rather limited potential of this technique as a primary production method for methane hydrate. However, the combination of depressurization with modest thermal stimulation may offer the opportunity to both enhance reservoir production and overcome flow assurance issues within the production tubing. A critical challenge in this regard is to understand the endothermic change of the methane hydrate dissociation and the impact this change has on reformation temperatures and the produced water and gas. One category of technique often used to characterize conventional (and even unconventional) hydrocarbon reservoirs is based on pressure testing (or pressure transient testing and analysis). These kinds of techniques are complementary to other characterization techniques because (1) they fill a gap between the small-scale characterization based on cores and logs and large-scale characterization based on geophysical measurement and (2) they provide a measure of flow capacity (e.g., Hancock et al., 2005). Refinement of such techniques for methane hydrate reservoirs could prove advantageous.
The original production concept for the chemical stimulation of methane hydrate was to modify the in situ methane hydrate equilibrium conditions by injecting hydrate inhibitors such as salts and alcohols; these inhibitors act to decrease methane hydrate stability and induce dissociation. This technique has been used for decades to deal with methane hydrate blockages in pipelines, but it has not been seriously considered as an option for long-term production. Prohibitive issues include potential operational challenges to the introduction of the inhibitor into the formation, the significant expense of the method, and environmental issues related to disposing of the used chemicals after production.
Novel Production Methods
Some novel concepts to extract methane from methane hydrate have also been suggested with numerous technical patents being issued around the
world. Perhaps the most promising of these is a variation of a chemical stimulation technique which involves injecting another gas species such as carbon dioxide into a methane hydrate reservoir, essentially sequestering carbon dioxide and liberating methane at the same time. This concept is based on laboratory observations and thermodynamic considerations (Graue et al., 2006; McGrail et al., 2007; Stevens et al., 2008), which suggest that when carbon dioxide is brought into contact with methane hydrate it will exchange with methane in the hydrate structure. Although the laboratory and modeling studies are encouraging, the challenge of scaling this technique from the laboratory to field testing has yet to be undertaken.
Other production concepts put forward or patented include techniques to induce in situ combustion of the methane hydrate; combustion would heat the formation and stimulate methane hydrate dissociation10 (Collett, 2002; Max et al., 2006). In situ combustion has been pursued to stimulate production from tar sands; however, this concept has not been seriously considered for methane hydrate production. The possibility of seafloor strip mining has also been discussed as a potential approach to recover methane from near-seafloor methane hydrate deposits.11 With all novel production methods, where practical experience is limited and new techniques are being evaluated, the environmental impacts of development will require careful consideration.
Reservoir Simulation Modeling
Reservoir simulation models are computer models routinely used by engineers to simulate production from a hydrocarbon field over long timescales. They are valuable tools in the petroleum industry to evaluate the effectiveness of various production techniques and methods to stimulate or enhance production, and to consider the environmental consequences of production. Although considerable experience exists worldwide in the use
TABLE 2.1 Reservoir Simulators Under Development
1. TOUGH + HYDRATE
DOE-LBNL (Moridis et al., 2002)
2. CMG Stars
Computer Modeling Group, STARS
DOE-NETLa (Earlier code of TOUGH + HYDRATE)
4. MH21 HYDRES
National Institute of Advanced Industrial Science and Technology, Japan Oil Engineering Co., Ltd., University of Tokyo (Kurihara et al., 2005)
Pacific Northwest National Laboratory, University of Alaska, Fairbanks (Phale et al., 2006)
of reservoir simulators for conventional oil and gas deposits, the use of these tools for methane hydrate applications has only been recently considered. Acceptance of a verified methane hydrate simulation model would enable prediction of methane production rates and formation responses from different production strategies (e.g., depressurization, thermal stimulation, chemical inhibitor injection) for either Arctic or marine hydrate reservoirs. The integration of modeling and field studies is essential to effectively evaluate different production strategies and responses. Reservoir models can aid in predictions of both the production rates and responses, as well as in interpreting the experimental observations from the field tests. Reservoir simulators under development in the world are listed in Table 2.1. These numerical models incorporate coupled equations accounting for heat transfer, fluid flow, and kinetic mechanisms that govern methane production from hydrate reservoirs.
Despite the progress made through history matching with the currently available short-term field production datasets (Moridis et al., 2009), long-term production field data are lacking for validation of the simulations. However, attempts have been made to compare each model by
undertaking a series of simulations using the same reservoir parameters and data from some short-term reservoir studies. As described by Wilder et al. (2008), this code comparison effort determined that all simulators were able to capture basic heat and mass transfer, as well as the overall hydrate dissociation process. They predicted different hydrate front locations when ice formation was expected in some parts of the reservoir. All simulators showed that methane and water production rates increase when free pore water is present. The reliability and accuracy of the reservoir simulation predictions depend upon (a) knowledge of the parameters and relationships that describe quantitatively the physical processes and thermophysical properties of all the components of the system under investigation (these physical properties need to be obtained from laboratory experiments and/or from field tests either by direct measurement or through history matching) and (b) availability of field data for the validation of the numerical models (Moridis et al., 2008). Reservoir simulation models need to be carefully validated and tested with long-term production field data. The geomechanical modeling is still in the early stages of development, and experimental and field data will also be critical to validate the geomechanical predictions.
A recent, additional application of these simulations has been to develop economic models to estimate the commercial viability of methane production from methane hydrate on simulated methane hydrate reservoirs. These models, although very preliminary, are the first economic studies to be performed that estimate the price of natural gas that could lead to economically viable gas production from methane hydrate (Hancock, 2008; Walsh et al., 2009). These economic models result in a range of gas prices for economic production of methane hydrate that is in the range of prices seen historically in North America.
GEOLOGIC PROCESSES AND FEATURES ASSOCIATED WITH METHANE HYDRATE OCCURRENCES
As described previously, methane hydrate in certain marine and permafrost environments is thought to constitute a significant storehouse of natural gas. In addition to the energy potential of methane hydrate, considerable
interest exists to understand naturally occurring geologic processes associated with methane hydrate formation and decomposition, as well as the possible role of methane hydrate in global climate change. This section focuses on geologic processes that may be related to methane hydrate degassing, including methane seepage in marine and terrestrial environments, biological processes, submarine landslides, inferred gas venting structures, and methane hydrate as an atmospheric greenhouse gas source.
Detailed field studies have demonstrated that methane seepage is ubiquitous in various marine settings where pressure and temperature conditions are appropriate for methane hydrate to be stable at or close to the seafloor. Active methane seepage has been observed to occur in deep waters along essentially all the continental margins of the world including off the U.S. Gulf Coast (e.g., MacDonald et al., 1994), Atlantic (e.g., Van Dover et al., 2003), and Pacific (e.g., Suess et al., 1999). Although these observations seem to confirm that methane can migrate as free gas within the methane hydrate stability field, the detailed processes involved with this migration remain uncertain and the explicit link to methane hydrate is tenuous.
A number of authors have also suggested that methane seepage may occur where natural processes have either warmed formation temperatures or reduced pressure, causing methane hydrate dissociation. Some of the most perturbed methane hydrate deposits in the world occur in the Arctic in terrestrial permafrost environments with very cold mean annual surface temperatures. Here, methane hydrate deposits have in some cases warmed more than 15°C during the past 10,000 years (Kvenvolden, 1988; Taylor, 1991). Paull et al. (2007) suggest that in the transgressed shelf of the southern Beaufort Sea, dissociation of methane hydrate may be responsible for methane seepage and heaving of the seafloor to form large conical hills called pingo-like features. Methane seepage that may be related to degassing of transgressed permafrost methane hydrate accumulations has also been observed in the shallow waters of the East Siberian
Shelf of the Laptev Sea (Semiletov and Gustafsson, 2009). Recent oceanbottom warming and inferred down-slope retreat of the landward limit of methane hydrate stability conditions is also implicated in the formation of numerous gas vents observed offshore Svalbard (Westbrook et al., 2009). In terrestrial Arctic settings, Holocene warming both from atmospheric temperature changes and the formation of lakes or river channels has also significantly perturbed the geothermal regime in the Arctic. Dissociating methane hydrate has been implicated as a possible source of methane release observed in lakes on the North Slope of Alaska and Siberia (Walter et al., 2006) and as a source for thermogenic gas seeps observed beneath lakes and channels of the Mackenzie Delta (Bowen et al., 2008).
Distinctive Morphological Features Potentially Attributable to Gas Venting and Methane Hydrate Dynamics
Gas venting and methane hydrate occurrences are in some places linked with distinctive seafloor features or processes such as extrusion of sediment onto the seafloor (e.g., mud volcanoes; Kopf, 2002), deformation of the seafloor (e.g., mounds; Hovland and Svensen, 2006), excavation of the seafloor (e.g., pockmarks; Judd and Hovland, 2007), and collapse of the seafloor (e.g., large bathymetric depressions; Dillon et al., 2001). However, detailed physical explanations as to how gas venting and methane hydrate dynamics actually form these features have yet to be developed.
The presence of methane within and at the seafloor in these environments also generates biogeochemical impacts. In subseafloor environments where upward-migrating methane meets sulfate diffusing downward from the overlying seawater, populations of microorganisms anaerobically oxidize methane (Boetius et al., 2000). This process converts the methane carbon into bicarbonate, and the sulfate into hydrogen sulfide which then is used in iron sulfide mineral formation, and thus alters the local environment. The addition of bicarbonate to the pore waters can stimulate the precipitation of carbonate, which can cement the near-seafloor sediment (Ritger et al., 1987). This process can result in a
shift from an environment dominated by soft-sediment biological communities to hard-bottom, substrate-dominated communities. In some areas carbonate-cored mounds have been inferred to grow up from the seafloor, creating considerable local topography (Teichert et al., 2005). The availability of either methane or sulfide on the seafloor will stimulate the development of chemosynthetic biological communities. Some seep source estimates have been compiled to indicate the relative importance of various seeps and vents. However, the vast majority of the seeping methane dissolves into the surrounding waters and is consumed by bacteria. Thus, very little of the methane from seafloor seeps in deep water reaches the atmosphere (Reeburgh, 2007).
Many authors have tentatively associated major submarine landslides on continental margins with methane hydrate occurrences (e.g., Paull et al., 2003b). The potential causal link is the changes in mechanical properties and the geopressure regime when methane hydrate decomposes. When methane hydrate decomposes, the solid hydrate transforms into water and dissolved or gaseous methane, causing a consequent decrease in long-term sediment strength, thus making failure more likely. In circumstances in which high methane hydrate concentrations occur and the sediment permeability is restricted, the potential also exists for the buildup of fluid and/or gas pressure which can also substantially reduce the effective sediment strength.
The evidence linking methane hydrate to slope failures is consistently indirect; for example, seismic evidence in headwall sediments suggests that the landslide failure plane is coincident with or at least near a BSR seen in seismic profiles. The potential role of methane hydrate in natural slope stability and sediment dynamics remains largely an academic topic except in cases in which conventional oil and gas seafloor developments are being considered within potential slides and with corresponding tsunami potential (Solheim et al., 2005).
From a climate change perspective the natural dissociation of even a small part of the extremely large global methane hydrate occurrence that exists on Earth (see section Methane Hydrate Resource Assessment) could potentially release significant amounts of methane and water into the surrounding environment. However, the scientific evaluation of such releases is complex and involves considerations such as the response time of methane hydrate to change, and the geologic, biologic, and oceanographic processes that ultimately control connection between methane release (associated with methane hydrate decomposition) and methane release to the atmosphere from many other sources. Climate change researchers have generally approached these issues from the perspective of considering climate change in the geologic past, modeling studies, and, only very recently, field investigations.
Dickens (1999) suggests that large excursions in the carbon isotopic records of carbonates in oceanic sediments from the Paleocene-Eocene Thermal Maximum may have been attributed to massive dissociation of methane hydrate. Kennett et al. (2003) developed the clathrate gun hypothesis which proposes that episodic release of large amounts of methane from submarine landslides may have contributed significantly to the distinctive behavior of Late Quaternary climate on orbital and millennial timescales. Although stimulating much discussion in the literature, these theories remain unproven.
More recently, modeling studies have explored the possible past and future interactions between methane hydrate and the global carbon cycle (Archer et al., 2008) and the time lag of methane hydrate deposits to an imposed surface temperature change (Taylor et al., 2002). An example of imposed surface temperature change comes from the Arctic region, where the last major warming began at least 10,000 years ago. These studies indicate that most methane hydrate occurrences can take thousands of years to respond because of the attenuation of the temperature change versus depth, and the endothermic nature of the dissociation process itself.
GEOHAZARDS AND ENVIRONMENTAL ISSUES RELATED TO METHANE HYDRATE PRODUCTION AND FIELD DEVELOPMENT
The challenge to distinguish between methane seepage occurring from natural processes and seepage from active disturbance of methane hydrate during drilling and production is substantial, and many aspects of this field of investigation remain uncertain. In a traditional hydrocarbon context, all methane hydrate deposits occur at relatively shallow burial depths and therefore have the potential to induce either seafloor or surface displacements as long-term field development is undertaken.
Exploratory wells drilled in permafrost environments in the 1970s and 1980s encountered some uncontrolled gas releases from relatively shallow depths in which methane hydrate was also identified (Bily and Dick, 1974; Yakushev and Collett, 1992; Collett and Dallimore, 2002). The released gas was suggested as being generated either by (1) methane hydrate decomposition while drilling with warm drilling fluids or drilling fluids containing methane hydrate inhibitors such as glycol or (2) encountering preexisting overpressured gas pockets within the methane hydrate stability zone (see Box 1.1). Although drilling with chilled fluids and more carefully selected mud was shown to prevent decomposition of methane hydrate while drilling (Bily and Dick, 1974), the issue of whether overpressured gas pockets were encountered within the methane hydrate stability zone (Weaver and Stewart, 1982) has never been resolved.
In the 1970s, the Arctic was the only area where commercial drilling was conducted in association with potential methane hydrate–bearing sediments, both on- and offshore. Perceived, but unproven, safety issues related to methane hydrate–bearing sediments in commercial drilling projects in the Arctic resulted in a policy of categorically avoiding any drilling operations where methane hydrate was suspected to occur (Paull and Ussler, 2001). In practice this approach meant avoiding areas where BSRs were
present in the seismic reflection profiles at potential well locations, because BSRs were related to the potential of entering overpressured gas zones beneath the base of methane hydrate stability (Figure 2.6; see also section The Challenge of Mapping and Quantifying Methane Hydrate). Despite this practice, a number of unintentional encounters in marine environments
with methane hydrate–bearing sediments were made without adverse effects (Paull and Ussler, 2001).
Targeted drilling activities through BSRs where methane hydrate is stable within the surface sediment have also been conducted in numerous global marine settings: drilling projects coordinated by national research programs in China, India, Korea, and Japan; at a research site off Norway; by Deep-Sea Drilling Project, Ocean Drilling Program, and Integrated Ocean Drilling Program expeditions;12 in the Gulf of Mexico JIP supported by the DOE Program (Ruppel et al., 2008); and through oil industry exploration and production activities. These projects have detected no adverse effects on the drilling operations. The committee is unaware of documented bore-hole problems that have been attributed to methane hydrate during drilling of exploratory or development holes in deepwater settings where the holes passed through the depths associated with BSRs observed in seismic reflection data over the well site. The combined experiences of these drilling activities have also shown that the amount of interstitial gas needed to generate BSRs and the probable overpressures in marine methane hydrate are modest (e.g., Hornbach et al., 2004).
Considerable experience now exists for drilling operations in non-Arctic marine settings and in the terrestrial Arctic with few operational issues attributed to drilling through methane hydrate (e.g., Yakushev and Collett, 1992; Collett and Dallimore, 2002). Conversely, some evidence suggests that overpressures may occur at shallow depths on the submerged parts of the Arctic shelf where methane hydrate may be undergoing decomposition associated with long-term warming stimulated by the last deglacial transgression (Paull et al., 2007). These overpressures may be significant enough to extrude sediments in the form of gas vents and structures on the Arctic shelf. The identification of these features has occurred in the same areas where Bily and Dick (1974) introduced the concept that methane hydrate may contribute to overpressured conditions in the subsurface. If the link between overpressures and these features is correct, methane hydrate decomposition may, in fact, contribute to the overpressure of sediments,
Legs 11, 143, 146, 164, 204, and 311; http://odp.georef.org/dbtw-wpd/qbeodp.htm.
at least in areas where they already have been undergoing decomposition for hundreds to thousands of years. Again, however, the available data are inadequate to confirm or refute these assertions.
Operational Issues Related to Long-Term Production
A number of issues may be associated with the presence of methane hydrate in the host sediments outside the well casing or the supporting well infrastructure (Figure 2.7). However, most of the scenarios that may suggest methane hydrate is a geohazard to traditional hydrocarbon infrastructure do not manifest themselves at the time the well is being drilled, but rather result as a consequence of the long-term warming of the sediment associated with hydrocarbon production (Figures 2.6C and 2.7; e.g., Borowski and Paull, 1997; Hovland and Tobias, 2001; Nimblett et al., 2005).
These concerns relate to the substantial changes in sediment strength and permeability experienced when methane hydrate deposits are dissociated during production when the production well passes through a hydrate-bearing zone and when the production is from the hydrate-bearing zone. During the life of a potential producing methane hydrate field the
dissociated zone may initially affect the near well-bore area, but with time, the affected area could move some distance away from the producing well. Strength and consolidation changes in the near well-bore area and production-induced regional subsidence could induce significant forces on the well casing with the possibility both of building pressure and developing significant casing strain, potentially resulting in casing failure (Figure 2.6C). Because most methane hydrate–bearing sediments are unconsolidated, potential also exists for sediment migration into the producing well, resulting in operational problems (Dallimore et al., 2008). These issues, when combined with permeability changes induced by dissociation, could cause poor sediment contact with the production casing, potentially resulting in failure of the casing cement bond and the creation of vertical migration pathways for gas migration. Although the petroleum industry has considerable experience worldwide in dealing with these types of problems, specific challenges may exist related to methane hydrate, especially if production schemes such as the use of horizontal wells are considered.
Some experience from settings where permafrost overlies deeper conventional hydrocarbon fields may be applicable to address physical property changes that may result when methane hydrate dissociates as a result of drilling and/or production. Permafrost also experiences significant changes in physical properties (strength, porosity, permeability) when the permafrost thaws in the near well-bore area in conventional oil and gas fields. Typical approaches to the predictions of permafrost response have been based on laboratory measurements of the consolidation effects on permafrost core samples and the development of a geomechanical model to predict both the near well-bore and field response to oil and gas extraction at depth. In the situation of a producing methane hydrate field, the case is more complex because the producing and responding interval are the same, and at present, no published laboratory measurements exist of the consolidation response of methane hydrate samples.
Another largely understudied topic is the amount and chemistry of the produced water that may be released when methane hydrate deposits dissociate. Some reservoir simulation models suggest that the pore water liberated when methane hydrate dissociates will be highly mobile and will
flow to the producing well. The volume of produced water associated with methane hydrate production will directly impact the design of the well completion (i.e. downhole pump selection) but also be a consideration in terms of ancillary environmental issues related to water disposal.
Secondary Gas Migration
An important environmental consideration in any gas field is the risk of gas migration away from the production well infrastructure interacting with other geologic strata at depth or reaching the surface. In both cases a critical consideration is the seal integrity or the overlying permeability barrier above the production interval in the near well bore and also away from the well bore. For most methane hydrate deposits, the nature of the seals may differ significantly from traditional hydrocarbon reservoirs. In some settings, methane hydrate itself or a permafrost layer may act as a seal and trap free gas below (Grauls, 2001). The relatively shallow depths of methane hydrate occurrences also may mean that secondary sealing by the overlying sediment may only be weakly developed. At present the mobility of the gas and water released from methane hydrate decomposition is unknown, including their potential to migrate to the surface (e.g., Xu and Ruppel, 1999; Judd and Hovland, 2007).
Migrating methane can also reform into methane hydrate within the cold ocean bottom waters and form on top of the bottom-hole well assembly, potentially compromising the blow-out prevention systems. Large pieces of methane hydrate have been observed to raft away from the seafloor because of their low density with respect to seawater (~0.91 g/cm3; Paull et al., 2003a). Erosion of the seafloor around wellheads could compromise these structures (Figure 2.7).
STATE OF THE RESEARCH FIELD
The level of progress and sophistication in methane hydrate research has been advancing at an exponential rate (Figure 2.8). As outlined in this chapter, observations, data, and analysis acquired from multidisciplinary
field activities on- and offshore and from laboratory experiments and modeling have advanced the understanding of the behavior and properties of methane hydrate and the potential to produce methane from methane hydrate accumulations. Although these advances in knowledge testify to the great interest in the potential of methane hydrate to serve as a future energy source, they belie the need for considerably more information on methane hydrate including its behavior in nature, during drilling, and in production settings, and the approaches needed to identify and reliably produce methane from this type of occurrence. Chapter 3 reviews the research projects that the Program has supported during the past 5 years in pursuit of some of these outstanding issues.
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