首页 | 本学科首页   官方微博 | 高级检索  
相似文献
 共查询到20条相似文献，搜索用时 483 毫秒
1.
In February 2007, the U.S. Department of Energy, BP Exploration (Alaska), and the U.S. Geological Survey, collected open-hole pressure-response data, as well as gas and water sample collection, in a gas hydrate reservoir (the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well) using Schlumberger's Modular Dynamics Formation Tester (MDT) wireline tool. Four such MDT tests, ranging from six to twelve hours duration, and including a series of flow, sampling, and shut-in periods of various durations, were conducted. Locations for the testing were selected based on NMR and other log data to assure sufficient isolation from reservoir boundaries and zones of excess free water. Test stages in which pressure was reduced sufficiently to mobilize free water in the formation (yet not cause gas hydrate dissociation) produced readily interpretable pressure build-up profiles. Build-ups following larger drawdowns consistently showed gas-hydrate dissociation and gas release (as confirmed by optical fluid analyzer data), as well as progressive dampening of reservoir pressure build-up during sequential tests at a given MDT test station.History matches of one multi-stage, 12-h test (the C2 test) were accomplished using five different reservoir simulators: CMG-STARS, HydrateResSim, MH21-HYDRES, STOMP-HYD, and TOUGH + HYDRATE. Simulations utilized detailed information collected across the reservoir either obtained or determined from geophysical well logs, including thickness (11.3 m, 37 ft.), porosity (35%), hydrate saturation (65%), both mobile and immobile water saturations, intrinsic permeability (1000 mD), pore water salinity (5 ppt), and formation temperature (3.3-3.9 °C). This paper will present the approach and preliminary results of the history-matching efforts, including estimates of initial formation permeability and analyses of the various unique features exhibited by the MDT results.  相似文献   

2.
In the first part of this paper, the pressure and temperature measurements obtained using Schlumberger's Modular Formation Dynamics Tester (MDT) conducted on the C2 interval in the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well (Mount Elbert Well) are history matched, with the following three objectives: (i) to obtain a better understanding of hydrate decomposition and its reformation as conditions cross the p/T stability, (ii) to obtain formation properties (e.g., permeability) that are consistent with the measurements, and (iii) to explore the non-uniqueness in the history match; i.e., to explore the ranges of parameters that allow a reasonable match of the measured quantities. In the second part of this paper, long-term production performance is predicted, and the effect of the uncertain parameters on the predictions is demonstrated. The results are used to demonstrate the range of long-term production that may be expected, when a model is calibrated using the MDT data. Usefulness of short-term tests for long-term forecast prediction is then discussed.  相似文献   

3.
The Mount Elbert Gas Hydrate Stratigraphic Test Well was drilled within the Alaska North Slope (ANS) Milne Point Unit (MPU) from February 3 to 19, 2007. The well was conducted as part of a Cooperative Research Agreement (CRA) project co-sponsored since 2001 by BP Exploration (Alaska), Inc. (BPXA) and the U.S. Department of Energy (DOE) in collaboration with the U.S. Geological Survey (USGS) to help determine whether ANS gas hydrate can become a technically and commercially viable gas resource. Early in the effort, regional reservoir characterization and reservoir simulation modeling studies indicated that up to 0.34 trillion cubic meters (tcm; 12 trillion cubic feet, tcf) gas may be technically recoverable from 0.92 tcm (33 tcf) gas-in-place within the Eileen gas hydrate accumulation near industry infrastructure within ANS MPU, Prudhoe Bay Unit (PBU), and Kuparuk River Unit (KRU) areas. To further constrain these estimates and to enable the selection of a test site for further data acquisition, the USGS reprocessed and interpreted MPU 3D seismic data provided by BPXA to delineate 14 prospects containing significant highly-saturated gas hydrate-bearing sand reservoirs. The “Mount Elbert” site was selected to drill a stratigraphic test well to acquire a full suite of wireline log, core, and formation pressure test data. Drilling results and data interpretation confirmed pre-drill predictions and thus increased confidence in both the prospect interpretation methods and in the wider ANS gas hydrate resource estimates. The interpreted data from the Mount Elbert well provide insight into and reduce uncertainty of key gas hydrate-bearing reservoir properties, enable further refinement and validation of the numerical simulation of the production potential of both MPU and broader ANS gas hydrate resources, and help determine viability of potential field sites for future extended term production testing. Drilling and data acquisition operations demonstrated that gas hydrate scientific research programs can be safely, effectively, and efficiently conducted within ANS infrastructure. The program success resulted in a technical team recommendation to project management to drill and complete a long-term production test within the area of existing ANS infrastructure. If approved by stakeholders, this long-term test would build on prior arctic research efforts to better constrain the potential gas rates and volumes that could be produced from gas hydrate-bearing sand reservoirs.  相似文献   

4.
This study characterizes cored and logged sedimentary strata from the February 2007 BP Exploration Alaska, Department of Energy, U.S. Geological Survey (BPXA-DOE-USGS) Mount Elbert Gas Hydrate Stratigraphic Test Well on the Alaska North Slope (ANS). The physical-properties program analyzed core samples recovered from the well, and in conjunction with downhole geophysical logs, produced an extensive dataset including grain size, water content, porosity, grain density, bulk density, permeability, X-ray diffraction (XRD) mineralogy, nuclear magnetic resonance (NMR), and petrography.This study documents the physical property interrelationships in the well and demonstrates their correlation with the occurrence of gas hydrate. Gas hydrate (GH) occurs in three unconsolidated, coarse silt to fine sand intervals within the Paleocene and Eocene beds of the Sagavanirktok Formation: Unit D-GH (614.4 m-627.9 m); unit C-GH1 (649.8 m-660.8 m); and unit C-GH2 (663.2 m-666.3 m). These intervals are overlain by fine to coarse silt intervals with greater clay content. A deeper interval (unit B) is similar lithologically to the gas-hydrate-bearing strata; however, it is water-saturated and contains no hydrate.In this system it appears that high sediment permeability (k) is critical to the formation of concentrated hydrate deposits. Intervals D-GH and C-GH1 have average “plug” intrinsic permeability to nitrogen values of 1700 mD and 675 mD, respectively. These values are in strong contrast with those of the overlying, gas-hydrate-free sediments, which have k values of 5.7 mD and 49 mD, respectively, and thus would have provided effective seals to trap free gas. The relation between permeability and porosity critically influences the occurrence of GH. For example, an average increase of 4% in porosity increases permeability by an order of magnitude, but the presence of a second fluid (e.g., methane from dissociating gas hydrate) in the reservoir reduces permeability by more than an order of magnitude.  相似文献   

5.
A dielectric logging tool, electromagnetic propagation tool (EPT), was deployed in 2007 in the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well (Mount Elbert Well), North Slope, Alaska. The measured dielectric properties in the Mount Elbert well, combined with density log measurements, result in a vertical high-resolution (cm-scale) estimate of gas hydrate saturation. Two hydrate-bearing sand reservoirs about 20 m thick were identified using the EPT log and exhibited gas-hydrate saturation estimates ranging from 45% to 85%. In hydrate-bearing zones where variation of hole size and oil-based mud invasion are minimal, EPT-based gas hydrate saturation estimates on average agree well with lower vertical resolution estimates from the nuclear magnetic resonance logs; however, saturation and porosity estimates based on EPT logs are not reliable in intervals with substantial variations in borehole diameter and oil-based invasion.EPT log interpretation reveals many thin-bedded layers at various depths, both above and below the thick continuous hydrate occurrences, which range from 30-cm to about 1-m thick. Such thin layers are not indicated in other well logs, or from the visual observation of core, with the exception of the image log recorded by the oil-base microimager. We also observe that EPT dielectric measurements can be used to accurately detect fine-scale changes in lithology and pore fluid properties of hydrate-bearing sediments where variation of hole size is minimal. EPT measurements may thus provide high-resolution in-situ hydrate saturation estimates for comparison and calibration with laboratory analysis.  相似文献   

6.
As part of an effort to identify suitable targets for a planned long-term field test, we investigate by means of numerical simulation the gas production potential from unit D, a stratigraphically bounded (Class 3) permafrost-associated hydrate occurrence penetrated in the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well on North Slope, Alaska. This shallow, low-pressure deposit has high porosities (? = 0.4), high intrinsic permeabilities (k = 10−12 m2) and high hydrate saturations (SH = 0.65). It has a low temperature (T = 2.3-2.6 °C) because of its proximity to the overlying permafrost. The simulation results indicate that vertical wells operating at a constant bottomhole pressure would produce at very low rates for a very long period. Horizontal wells increase gas production by almost two orders of magnitude, but production remains low. Sensitivity analysis indicates that the initial deposit temperature is by the far the most important factor determining production performance (and the most effective criterion for target selection) because it controls the sensible heat available to fuel dissociation. Thus, a 1 °C increase in temperature is sufficient to increase the production rate by a factor of almost 8. Production also increases with a decreasing hydrate saturation (because of a larger effective permeability for a given k), and is favored (to a lesser extent) by anisotropy.  相似文献   

7.
The BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well was drilled and cored from 606.5 to 760.1 m on the North Slope of Alaska, to evaluate the occurrence, distribution and formation of gas hydrate in sediments below the base of the ice-bearing permafrost. Both the dissolved chloride and the isotopic composition of the water co-vary in the gas hydrate-bearing zones, consistent with gas hydrate dissociation during core recovery, and they provide independent indicators to constrain the zone of gas hydrate occurrence. Analyses of chloride and water isotope data indicate that an observed increase in salinity towards the top of the cored section reflects the presence of residual fluids from ion exclusion during ice formation at the base of the permafrost layer. These salinity changes are the main factor controlling major and minor ion distributions in the Mount Elbert Well. The resulting background chloride can be simulated with a one-dimensional diffusion model, and the results suggest that the ion exclusion at the top of the cored section reflects deepening of the permafrost layer following the last glaciation (∼100 kyr), consistent with published thermal models. Gas hydrate saturation values estimated from dissolved chloride agree with estimates based on logging data when the gas hydrate occupies more than 20% of the pore space; the correlation is less robust at lower saturation values. The highest gas hydrate concentrations at the Mount Elbert Well are clearly associated with coarse-grained sedimentary sections, as expected from theoretical calculations and field observations in marine and other arctic sediment cores.  相似文献   

8.
Gases were analyzed from well cuttings, core, gas hydrate, and formation tests at the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well, drilled within the Milne Point Unit, Alaska North Slope. The well penetrated a portion of the Eileen gas hydrate deposit, which overlies the more deeply buried Prudhoe Bay, Milne Point, West Sak, and Kuparuk River oil fields. Gas sources in the upper 200 m are predominantly from microbial sources (C1 isotopic compositions ranging from −86.4 to −80.6‰). The C1 isotopic composition becomes progressively enriched from 200 m to the top of the gas hydrate-bearing sands at 600 m. The tested gas hydrates occur in two primary intervals, units D and C, between 614.0 m and 664.7 m, containing a total of 29.3 m of gas hydrate-bearing sands. The hydrocarbon gases in cuttings and core samples from 604 to 914 m are composed of methane with very little ethane. The isotopic composition of the methane carbon ranges from −50.1 to −43.9‰ with several outliers, generally decreasing with depth. Gas samples collected by the Modular Formation Dynamics Testing (MDT) tool in the hydrate-bearing units were similarly composed mainly of methane, with up to 284 ppm ethane. The methane isotopic composition ranged from −48.2 to −48.0‰ in the C sand and from −48.4 to −46.6‰ in the D sand. Methane hydrogen isotopic composition ranged from −238 to −230‰, with slightly more depleted values in the deeper C sand. These results are consistent with the concept that the Eileen gas hydrates contain a mixture of deep-sourced, microbially biodegraded thermogenic gas, with lesser amounts of thermogenic oil-associated gas, and coal gas. Thermal gases are likely sourced from existing oil and gas accumulations that have migrated up-dip and/or up-fault and formed gas hydrate in response to climate cooling with permafrost formation.  相似文献   

9.
The BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well was an integral part of an ongoing project to determine the future energy resource potential of gas hydrates on the Alaska North Slope. As part of this effort, the Mount Elbert well included an advanced downhole geophysical logging program. Because gas hydrate is unstable at ground surface pressure and temperature conditions, a major emphasis was placed on the downhole-logging program to determine the occurrence of gas hydrates and the in-situ physical properties of the sediments. In support of this effort, well-log and core data montages have been compiled which include downhole log and core-data obtained from the gas-hydrate-bearing sedimentary section in the Mount Elbert well. Also shown are numerous reservoir parameters, including gas-hydrate saturation and sediment porosity log traces calculated from available downhole well log and core data.  相似文献   

10.
  相似文献   

11.
Targeting the methane hydrate (MH) bearing units C and D at the Mount Elbert prospect on the Alaska North Slope, four MDT (Modular Dynamic Formation Tester) tests were conducted in February 2007. The C2 MDT test was selected for history matching simulation in the MH Simulator Code Comparison Study. Through history matching simulation, the physical and chemical properties of the unit C were adjusted, which suggested the most likely reservoir properties of this unit. Based on these properties thus tuned, the numerical models replicating “Mount Elbert C2 zone like reservoir”, “PBU L-Pad like reservoir” and “PBU L-Pad down dip like reservoir” were constructed. The long term production performances of wells in these reservoirs were then forecasted assuming the MH dissociation and production by the methods of depressurization, combination of depressurization and wellbore heating, and hot water huff and puff. The predicted cumulative gas production ranges from 2.16 × 106 m3/well to 8.22 × 108 m3/well depending mainly on the initial temperature of the reservoir and on the production method.This paper describes the details of modeling and history matching simulation. This paper also presents the results of the examinations on the effects of reservoir properties on MH dissociation and production performances under the application of the depressurization and thermal methods.  相似文献   

12.
In 2009, the Gulf of Mexico (GOM) Gas Hydrates Joint-Industry-Project (JIP) Leg II drilling program confirmed that gas hydrate occurs at high saturations within reservoir-quality sands in the GOM. A comprehensive logging-while-drilling dataset was collected from seven wells at three sites, including two wells at the Walker Ridge 313 site. By constraining the saturations and thicknesses of hydrate-bearing sands using logging-while-drilling data, two-dimensional (2D), cylindrical, r-z and three-dimensional (3D) reservoir models were simulated. The gas hydrate occurrences inferred from seismic analysis are used to delineate the areal extent of the 3D reservoir models. Numerical simulations of gas production from the Walker Ridge reservoirs were conducted using the depressurization method at a constant bottomhole pressure. Results of these simulations indicate that these hydrate deposits are readily produced, owing to high intrinsic reservoir-quality and their proximity to the base of hydrate stability. The elevated in situ reservoir temperatures contribute to high (5–40 MMscf/day) predicted production rates. The production rates obtained from the 2D and 3D models are in close agreement. To evaluate the effect of spatial dimensions, the 2D reservoir domains were simulated at two outer radii. The results showed increased potential for formation of secondary hydrate and appearance of lag time for production rates as reservoir size increases. Similar phenomena were observed in the 3D reservoir models. The results also suggest that interbedded gas hydrate accumulations might be preferable targets for gas production in comparison with massive deposits. Hydrate in such accumulations can be readily dissociated due to heat supply from surrounding hydrate-free zones. Special cases were considered to evaluate the effect of overburden and underburden permeability on production. The obtained data show that production can be significantly degraded in comparison with a case using impermeable boundaries. The main reason for the reduced productivity is water influx from the surrounding strata; a secondary cause is gas escape into the overburden. The results dictate that in order to reliably estimate production potential, permeability of the surroundings has to be included in a model.  相似文献   

13.
In 2006, the United States Geological Survey (USGS) completed a detailed analysis and interpretation of available 2-D and 3-D seismic data, along with seismic modeling and correlation with specially processed downhole well log data for identifying potential gas hydrate accumulations on the North Slope of Alaska. A methodology was developed for identifying sub-permafrost gas hydrate prospects within the gas hydrate stability zone in the Milne Point area. The study revealed a total of 14 gas hydrate prospects in this area.In order to validate the gas hydrate prospecting protocol of the USGS and to acquire critical reservoir data needed to develop a longer-term production testing program, a stratigraphic test well was drilled at the Mount Elbert prospect in the Milne Point area in early 2007. The drilling confirmed the presence of two prominent gas-hydrate-bearing units in the Mount Elbert prospect, and high quality well logs and core data were acquired. The post-drill results indicate pre-drill predictions of the reservoir thickness and the gas-hydrate saturations based on seismic and existing well data were 90% accurate for the upper unit (hydrate unit D) and 70% accurate for the lower unit (hydrate unit C), confirming the validity of the USGS approach to gas hydrate prospecting. The Mount Elbert prospect is the first gas hydrate accumulation on the North Slope of Alaska identified primarily on the basis of seismic attribute analysis and specially processed downhole log data. Post-drill well log data enabled a better constraint of the elastic model and the development of an improved approach to the gas hydrate prospecting using seismic attributes.  相似文献   

14.
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.  相似文献   

15.
Using cryogenic scanning electron microscopy (CSEM), powder X-ray diffraction, and gas chromatography methods, we investigated the physical states, grain characteristics, gas composition, and methane isotopic composition of two gas-hydrate-bearing sections of core recovered from the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well situated on the Alaska North Slope. The well was continuously cored from 606.5 m to 760.1 m depth, and sections investigated here were retrieved from 619.9 m and 661.0 m depth. X-ray analysis and imaging of the sediment phase in both sections shows it consists of a predominantly fine-grained and well-sorted quartz sand with lesser amounts of feldspar, muscovite, and minor clays. Cryogenic SEM shows the gas-hydrate phase forming primarily as a pore-filling material between the sediment grains at approximately 70-75% saturation, and more sporadically as thin veins typically several tens of microns in diameter. Pore throat diameters vary, but commonly range 20-120 microns. Gas chromatography analyses of the hydrate-forming gas show that it is comprised of mainly methane (>99.9%), indicating that the gas hydrate is structure I. Here we report on the distribution and articulation of the gas-hydrate phase within the cores, the grain morphology of the hydrate, the composition of the sediment host, and the composition of the hydrate-forming gas.  相似文献   

16.
We studied the microbial communities collected from hydrate-bearing sediments on the North Slope of Alaska to determine how abiotic variables (e.g., grain size, hydrate presence, formation fluid gases) may correspond to the type and distribution of microbes in the sediments. The cores were acquired from sub-permafrost, Eocene (46-55 million year old) sediments in the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well within which hydrates are believed to have formed 1.5 mya. Forty samples, eight of which originally contained hydrates, were acquired from depths of ca. 606-666 m below land surface. Five drilling fluid samples acquired from the same depth range were included in the analysis as a control for possible contamination by drilling fluid microbes during the drilling and handling of cores. DNA was extracted from 15 samples (typically <1 ng DNA/g sediment was recovered) and then amplified using polymerase chain reaction with primers specific for bacterial and archaeal 16S rDNA genes, which indicates the likelihood that microbes were present in all analyzed samples. Only bacterial DNA amplicons were detected. Terminal-restriction fragment length polymorphism (T-RFLP) was used to measure bacterial diversity in the respective samples. Non-metric multidimensional scaling (NMS) was used to determine the abiotic variables that may have influenced bacterial diversity. NMS analysis revealed that the microbial taxa present in the sediment were distinct from the taxa present in the drilling fluids suggesting that the sediments were not contaminated by the drilling fluids. Multi-response permutation procedures (MRPP) found no significant difference between three sample groups identified a priori as being from within a hydrate zone, outside of hydrate zone, or on the edge of a hydrate/non-hydrate zone according to downhole nuclear magnetic resonance spectroscopy logs. However, among the several other abiotic parameters that were evaluated mud gas methane concentration and variables related to hydrate presence (e.g., chloride concentration, salinity, and resistivity) appeared to define the arrangement of microbial community signatures in plots resulting from NMS analysis. Communities from hydrate and non-hydrate layers each contained unique taxa as determined by the T-RFLP assay.  相似文献   

17.
Data acquired at the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well, drilled in the Milne Point area of the Alaska North Slope in February, 2007, indicates two zones of high gas hydrate saturation within the Eocene Sagavanirktok Formation. Gas hydrate is observed in two separate sand reservoirs (the D and C units), in the stratigraphically highest portions of those sands, and is not detected in non-sand lithologies. In the younger D unit, gas hydrate appears to fill much of the available reservoir space at the top of the unit. The degree of vertical fill with the D unit is closely related to the unit reservoir quality. A thick, low-permeability clay-dominated unit serves as an upper seal, whereas a subtle transition to more clay-rich, and interbedded sand, silt, and clay units is associated with the base of gas hydrate occurrence. In the underlying C unit, the reservoir is similarly capped by a clay-dominated section, with gas hydrate filling the relatively lower-quality sands at the top of the unit leaving an underlying thick section of high-reservoir quality sands devoid of gas hydrate. Evaluation of well log, core, and seismic data indicate that the gas hydrate occurs within complex combination stratigraphic/structural traps. Structural trapping is provided by a four-way fold closure augmented by a large western bounding fault. Lithologic variation is also a likely strong control on lateral extent of the reservoirs, particularly in the D unit accumulation, where gas hydrate appears to extend beyond the limits of the structural closure. Porous and permeable zones within the C unit sand are only partially charged due most likely to limited structural trapping in the reservoir lithofacies during the period of primary charging. The occurrence of the gas hydrate within the sands in the upper portions of both the C and D units and along the crest of the fold is consistent with an interpretation that these deposits are converted free gas accumulations formed prior to the imposition of gas hydrate stability conditions.  相似文献   

18.
In the 1960s Russian scientists made what was then a bold assertion that gas hydrates should occur in abundance in nature. Since this early start, the scientific foundation has been built for the realization that gas hydrates are a global phenomenon, occurring in permafrost regions of the arctic and in deep water portions of most continental margins worldwide. In 1995, the U.S. Geological Survey made the first systematic assessment of the in-place natural gas hydrate resources of the United States. That study suggested that the amount of gas in the gas hydrate accumulations of northern Alaska probably exceeds the volume of known conventional gas resources on the North Slope. Researchers have long speculated that gas hydrates could eventually become a producible energy resource, yet technical and economic hurdles have historically made gas hydrate development a distant goal. This view began to change in recent years with the realization that this unconventional resource could be developed with existing conventional oil and gas production technology. One of the most significant developments was the completion of the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well on the Alaska North Slope, which along with the Mallik project in Canada, have for the first time allowed the rational assessment of gas hydrate production technology and concepts. Almost 40 years of gas hydrate research in northern Alaska has confirmed the occurrence of at least two large gas hydrate accumulations on the North Slope. We have also seen in Alaska the first ever assessment of how much gas could be technically recovered from gas hydrates. However, significant technical concerns need to be further resolved in order to assess the ultimate impact of gas hydrate energy resource development in northern Alaska.  相似文献   

19.
Systematic analyses have been carried out on two gas hydrate-bearing sediment core samples, HYPV4, which was preserved by CH4 gas pressurization, and HYLN7, which was preserved in liquid-nitrogen, recovered from the BPXA-DOE-USGS Mount Elbert Stratigraphic Test Well. Gas hydrate in the studied core samples was found by observation to have developed in sediment pores, and the distribution of hydrate saturation in the cores imply that gas hydrate had experienced stepwise dissociation before it was stabilized by either liquid nitrogen or pressurizing gas. The gas hydrates were determined to be structure Type I hydrate with hydration numbers of approximately 6.1 by instrumentation methods such as powder X-ray diffraction, Raman spectroscopy and solid state 13C NMR. The hydrate gas composition was predominantly methane, and isotopic analysis showed that the methane was of thermogenic origin (mean δ13C = −48.6‰ and δD = −248‰ for sample HYLN7). Isotopic analysis of methane from sample HYPV4 revealed secondary hydrate formation from the pressurizing methane gas during storage.  相似文献   

20.
Collecting and preserving undamaged core samples containing gas hydrates from depth is difficult because of the pressure and temperature changes encountered upon retrieval. Hydrate-bearing core samples were collected at the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well in February 2007. Coring was performed while using a custom oil-based drilling mud, and the cores were retrieved by a wireline. The samples were characterized and subsampled at the surface under ambient winter arctic conditions. Samples thought to be hydrate bearing were preserved either by immersion in liquid nitrogen (LN), or by storage under methane pressure at ambient arctic conditions, and later depressurized and immersed in LN. Eleven core samples from hydrate-bearing zones were scanned using x-ray computed tomography to examine core structure and homogeneity. Features observed include radial fractures, spalling-type fractures, and reduced density near the periphery. These features were induced during sample collection, handling, and preservation. Isotopic analysis of the methane from hydrate in an initially LN-preserved core and a pressure-preserved core indicate that secondary hydrate formation occurred throughout the pressurized core, whereas none occurred in the LN-preserved core, however no hydrate was found near the periphery of the LN-preserved core. To replicate some aspects of the preservation methods, natural and laboratory-made saturated porous media samples were frozen in a variety of ways, with radial fractures observed in some LN-frozen sands, and needle-like ice crystals forming in slowly frozen clay-rich sediments. Suggestions for hydrate-bearing core preservation are presented.  相似文献   

设为首页 | 免责声明 | 关于勤云 | 加入收藏

Copyright©北京勤云科技发展有限公司  京ICP备09084417号