It is well known that water molecules at room temperature tend to form ‘iceberg’ structures around the hydrocarbon chains of surfactant molecules dissolved in water. The entropy reduction (times the absolute temperature T) associated with the iceberg structure can be considered as the net driving force for self-assembly. More recently, many investigators measured long-range attractive forces between hydrophobic surfaces, which are likely to result from structuring of the water molecules in the vicinity of the hydrophobic surfaces. Similarly, the hydrophobic nature of most gas hydrate formers may induce ordering of water molecules in the vicinity of dissolved solutes. In the present work, the surface forces between thiolated gold surfaces have been measured using an atomic force microscope (AFM) to obtain information on the structure of the thin films of water between hydrophobic surfaces. The results have been used to develop a new concept for the formation of gas hydrates.

Pressure drawdown tests were conducted using Schlumberger’s Modular Formation Dynamics Tester™ (MDT) wireline tool in the Mallik methane hydrate (MH) reservoirs in February 2002 as well as in the Mount Elbert (Alaska) MH reservoirs in February 2007, while a production test was conducted applying a depressurization method in one of the Mallik MH reservoirs in April 2007. All of these tests aimed at measuring production and bottomhole pressure (BHP) responses by reducing BHP below the MH stability pressure to estimate reservoir properties such as permeability and MH dissociation radius. We attempted to analyze the results of these tests through history matching using the numerical simulator (MH21-HYDRES) coded especially for gas hydrate reservoirs. Although the magnitude of depressurization and the total duration spent for these tests were almost identical to each other, the simulation studies revealed that there existed significant differences in what could be inferred and could not be inferred from test results between a MDT test and a production test. The simulation studies mainly clarified that (1) the MDT tests were useful to estimate initial effective permeability in the presence of MH, (2) when BHP is reduced below the MH stability pressure at MDT tests, the pressure and temperature responses were significantly influenced by the wellbore storage erasing all the important data such as those indicating a radius of MH dissociation and effective permeability after partial MH dissociation, and (3) history matching of production tests tended to result in multiple solutions unless establishing steady flow conditions. This paper presents the results of history matching for the typical MDT and production tests conducted in Mallik and Alaska MH reservoirs. This paper also discusses the parameters reliably estimated through MDT and production tests, which should provide many suggestions on future designs and analyses of short-term tests for MH reservoirs.

A gas hydrate production test using the depressurization method was conducted in early April 2007 as part of the JOGMEC/NRCan/Aurora Mallik production research program. The results of the production test were analyzed using a numerical simulator (MH21-HYDRES) coded especially for gas hydrate reservoirs. This paper evaluates the test results based on analyses of production test data, numerical modeling and a series of history matching simulations. Methane gas and water was produced from a 12 m perforation interval within one of the major methane hydrate (MH) reservoirs at the Mallik MH field, by reducing the bottomhole pressure down to about 7 MPa. The measured gas production rate was far higher than that expected for a comparatively small pressure drawdown. However, irregular (on-off) pumping operations, probably related to excessive sand production, resulted in unstable fluid flow within the wellbore, which made the analysis of test performance extremely complicated. A numerical reservoir model was constructed as a series of grid blocks, including those mimicking the wellbore, to enable rigorous simulation of fluid flow patterns in the vicinity of the wellbore. The model was then tuned through history matching, not by simply adjusting reservoir parameters, but by introducing the concept that sand production might have dramatically increased the near-wellbore permeability. The good agreement between observed and simulated performances suggests the mechanism of MH dissociation/production during the test. The history matched reservoir model was employed to predict the second-year production test performance, in order to examine the gas production potential of the Mallik MH reservoir, and to provide insight into future exploration and development planning for MH reservoirs.

Design and construction of long term gas hydrate production facilities will require assessment of the in situ formation response to production at a field scale. Key parameters such as temperature and pressure are critical for the determination of phase conditions, others such as formation resistivity, formation acoustic properties and fluid mobility support the inference of gas hydrate saturation, permeability and porosity. An ability to continuously monitor the response of these parameters during the course of a production test would facilitate tracking of the dissociation front and yield valuable information for engineering design and verification of numerical reservoir simulators. Such a monitoring system has been designed, developed and introduced as a part of the Japan Oil, Gas and Metals National Corporation and Natural Resources Canada gas hydrate production testing program carried out in the winter of 2007 in the Mackenzie Delta, Canada. While the deployment of some sensors and the acquisition of some data sets were limited due to operational problems encountered during the field program, considerable experience has been gained during all phases of the research program. In particular, the acquisition and interpretation of downhole temperature profiles and changes in formation electrical potentials during testing provide insight into the production response of the reservoir and may assist in the understanding of operational conditions and related decision-making processes.

The responsible management and reduction of carbon dioxide (CO2) emissions to the atmosphere requires consideration of alternative options for disposal and long-term sequestration of CO2 generated at hydrocarbon-fueled power plants and large industrial sources. A number of “conventional” options for geological sequestration of CO2 are currently being evaluated worldwide, including disposal of CO2 in depleted oil and gas reservoirs, in deep saline aquifers, and in unrecoverable coal beds, typically in gaseous or liquid form or as a supercritical fluid. Although these geological settings may constitute the most readily accessible sites for immediate utilization, it is unlikely that they represent sufficient cumulative storage capacity to keep pace with global CO2 production and future disposal requirements. In addition, the requirement for long-term maintenance of CO2 sequestered in fluid form, raises concerns regarding the possible mobility of disposed CO2 over the longer term. The Geological Survey of Canada (GSC) has investigated potential opportunities to sequester CO2 in solid form in Canadian geologic reservoirs having pressure and temperature conditions suitable for the formation and long-term stability of CO2 hydrate. Initial screening of candidate reservoirs has identified substantial potentials for CO2 sequestration as gas hydrate in extensive porous sandstone and limestone formations beneath portions of the Canadian Great Lakes, and in areas of the Mackenzie-Beaufort hydrocarbon development region in northern Canada. A significant but less robust capacity has been identified in the oil and gas production regions of northeastern Alberta.

In order to evaluate the productivity of methane hydrate (MH) by the depressurization method, Japan Oil, Gas and Metals National Corporation and Natural Resources Canada carried out a full scale production test in the Mallik field, Mackenzie Delta, Canada in April, 2007. An extensive wire-line logging program was conducted to evaluate reservoir properties, to determine production/water injection intervals, to evaluate cement bonding, and to interpret MH dissociation behavior throughout the production. New open hole wire-line logging tools such as MR Scanner, Rt Scanner and Sonic Scanner, and other advanced logging tools such as ECS (Elemental Capture Spectroscopy) were deployed to obtain precise data on the occurrence of MH, lithology, MH pore saturation, porosity and permeability. Perforation intervals of the production and water injection zones were selected using a multidisciplinary approach. Based on the results of geological interpretation and open hole logging analysis, we picked candidate test intervals considering lithology, MH pore saturation, initial effective permeability and absolute permeability. Reservoir layer models were constructed to allow for quick reservoir numerical simulations for several perforation scenarios. Using the results of well log analysis, reservoir numerical simulation, and consideration of operational constraints, a MH bearing formation from 1093 to 1105 mKB was selected for 2007 testing and three zones (1224-1230, 1238-1256, 1270-1274 mKB) were selected for injection of produced water. Three kinds of cased-hole logging, RST (Reservoir Saturation Tool), APS (Accelerator Porosity Sonde), and Sonic Scanner were carried out to evaluate physical property changes of MH bearing formation before/after the production test. Preliminary evaluation of RST-sigma suggested that MH bearing formation in the above perforation interval was almost selectively dissociated (sand produced) in lateral direction. Preliminary analysis using Sonic Scanner data, which has deeper depth of investigation than RST brought us additional information on MH dissociation front and dissociation behavior.

In this work we have formulated the set criteria for cost-effective selection of technologies for industrial production of gas from a hydrate deposit, which rely on the properties of hydrate-bearing rock and the geologic properties of the gas hydrate deposit. For over forty years the world’s energy industry has been trying to effectively master vast unconventional resources of natural gas – the natural gas hydrates [1;3;4]. Specialists have accumulated during this period of time a great deal of knowledge about gas hydrates [8;10]. They established the conditions of hydrate formation in sedimentary rock and the conditions of formation and disappearance of gas hydrate deposits, and offered several classification methods for gas hydrate deposits. Specialists have proposed several methods to locate the gas hydrate accumulations on land and offshore and determined the probable areas where gas hydrate deposits may exist. More than 220 gas hydrate deposits were found to-date, and methods to calculate the amount of gas in a hydrate deposit were developed [1;12]. The principles of gas production from a hydrate deposit were formulated and real experience of commercial natural gas production from a hydrate deposit was gained. However, until now there were no set economic criteria for selection of effective technologies for industrial development of gas hydrate deposits. This results in periodic development of various models not applicable to specific geologic conditions.

A high-resolution seismic reflection survey was conducted during the NT07-05 cruise over the Formosa Ridge offshore southwestern Taiwan where strong and continuous bottom simulating reflections (BSR) have been observed. Previous seafloor pictures taken from a deep-towed camera indicate that there are some chemosynthetic colonies. During the NT07-05 cruise, not only large and dense chemosynthetic communities were confirmed at the plume site, ROV Hyper-Dolphin has also discovered that both deep-sea mussel Bathymodiolus platifrons, and galatheid crab Shinkaia crosnieri are vigorously populated at this site. By integrating swatch bathymetry, multichannel seismic and high-resolution seismic reflection data, we now have a better understanding on the structural characters of the cold seep site. The cold seep is situated at the summit of the Formosa Ridge southern peak. Submarine canyons that incised continental slope on both sides of the ridge are the controlling factors of the ridge formation. The sedimentary strata are generally flat lying but have been deformed by mass wasting processes. Strong BSR is observed 400 to 500 ms below the seafloor of the ridge, with many bright reflections beneath it. There is a narrow vertical blanking zone raising from BSR to the crest of the ridge. This narrow zone is interpreted to be the fluid conduit of the seep site. BSR may form a good cap to trap gas below, and this “gas reservoir” is shallower than the canyon floors on either side of the ridge. We suggest that this “ridge type” gas reservoir configuration enables the cold sea water to get into the fluid system, and forms a special kind of “hydrothermal” circulation that feeds the unusual chemosynthetic communities observed at the Formosa Ridge cold seep site.

The global estimates of methane stored in gas hydrates varied from 1018 to 1015 m3 over the last 4 decades. Each geoscientific discipline has its own quantification methods. The aim of the presented project is the combination of a well proven geochemical approach with a geophysical approach. A transfer function is presented which allows estimations based on geochemical and geophysical parameters. A first application of this combined approach has been performed along seismic line BGR99-44 off Costa Rica. The resulting concentration profile shows a differentiated distribution of the gas hydrate concentration along the slope of the margin with variations of 0 to 3 vol.% of pore space.

The purpose of this study is to develop the production method of CO2 hydrate-slurry. In this paper, the production process of CO2 hydrates with pure water dissolved antifreeze proteins (AFPs) is discussed. CO2 hydrate-slurry can be transported from a production place to storage one with a small pressure loss. The AFPs have made the hydrate particles be small and well disperse. It is revealed that the Type III AFPs are effective for the inhibition of structure I hydrate production. By the present experiments, the induction time for the hydrate production increases, and moreover the formation rate of the hydrate and the increasing rate of an agitator torque decrease.