The anti-agglomerating hydrate behavior observed for some crude oils has previously been related to crude oil composition and to surface adsorption mechanisms. Petroleum acids derived from some crude oils have been found able to convert systems with initially high risk of plugging into easily flowable dispersions. In this work, acid fractions are isolated from three oils with low tendency to form hydrate plugs and from two oils associated with high risk of hydrate plugging by using an ion-exchange resin. The extracts are further separated into four sub-fractions by solid phase extraction (SPE). The chemical composition of the fractions is studied by means of HPLC, GPC, FTIR- and UV/VIS spectroscopy and elemental analysis. The distribution of chemical compound classes in the fractions differs between the non-plugging and plugging oils, and the differences are most distinctive in one of the sub-fractions. The results imply that acid sub-fractions holding a significant proportion of more weakly polar compounds, like ester functionalities, are important for how the hydrate surfaces and the oil phase interact.

An underinhibited system is defined as a system where an insufficient amount of thermodynamic inhibitor is present to prevent hydrate formation. Underinhibition might occur due to malfunctioning of equipment, temporary limitations in the inhibitor supplies or operational limitations or errors. Understanding the plugging risk of such systems is important in order to take the correct precautions to avoid blocked flowlines. In this paper we summarize the experimental efforts for the last decade within StatoilHydro on the hydrate plugging risk in underinhibited systems. The flow simulator has been used as the main experimental equipment. The overall results for systems underinhibited with ethylene glycol or methanol show that the plugging potential increases up to a maximum at concentrations around 10-15 wt%. At higher concentrations the plugging potential reduces compared to the uninhibited system. The results can be explained as follows: As water is converted to hydrates in a system containing a thermodynamic inhibitor, the inhibitor concentration will increase until the remaining aqueous phase is inhibited. This self-inhibited aqueous phase will wet the hydrate particles, giving raise to the characteristic term of “sticky” hydrate particles. The aqueous layer surrounding the hydrate particles will form liquid bridges, by capillary attractive forces, upon contact with other hydrate particles or the pipe wall. During the hydrate formation period, there is also a possibility that some of the liquid bridges are converted to solid ones, strengthening the agglomerates. Depending on the oil-water interfacial tension, the phase ratio between the aqueous phase and the solid hydrates and the conversion of liquid bridges to solid ones, this leads to increased plugging risk at lower concentrations of inhibitor (< 20 wt%) and reduced risk at higher concentrations as compared to the uninhibited system.

As part of an international cooperative research program, the U.S. Geological Survey (USGS) and researchers from the National Gas Hydrate Program (NGHP) of India are studying the physical properties of sediment recovered during the NGHP-01 cruise conducted offshore India during 2006. Here we report on index property, acoustic velocity, and triaxial shear test results for samples recovered from the Krishna-Godavari Basin. In addition, we discuss the effects of sample storage temperature, handling, and change in structure of fine-grained sediment. Although complex, sub-vertical planar gas-hydrate structures were observed in the silty clay to clayey silt samples prior to entering the Gas Hydrate And Sediment Test Laboratory Instrument (GHASTLI), the samples yielded little gas post test. This suggests most, if not all, gas hydrate dissociated during sample transfer. Mechanical properties of hydrate-bearing marine sediment are best measured by avoiding sample depressurization. By contrast, mechanical properties of hydrate-free sediments, that are shipped and stored at atmospheric pressure can be approximated by consolidating core material to the original in situ effective stress.

The Scotian margin of the east coast of Canada has a large theoretical gas hydrate stability zone (GHSZ) yet review of extensive industry seismic data reveals a prominent BSR at only one location. 3D seismic reflection and long offset (9 km) pre-stack 2D multichannel seismic data were used to study the velocity structure and geophysical characteristics of the hydrate zone and surrounding regions. The Mohican Channel study area shows a unique double BSR at 300 to 450 m below the seafloor in the western section of the study area immediately adjacent to the Mohican Channel in a water depth range of 1500- 1930m. The topmost BSR (BSR 1) is the more extensive of the two covering an area of 150 km2 in the 3D volume and a calculated area of 280 km2 using 2D industry and single-channel seismic profiles outside of the study area. BSR 2 covers an area of ~50 km2 and occurs approximately 80m below BSR 1. A system of polygonal faults is prominent in the area and some faults appear as conduits for gas leakage into the GHSZ. Fluid escape features are common on the surface of BSR 1 but rare on the seafloor suggesting that fluid flux is at lower levels than in the past.

In this research, we study high resistivity fractures found in unconsolidated clay sediments on logging-while-drilling borehole resistivity images from Indian continental margin collected during the National Gas Hydrate Program Expedition 01. These fractures, found at Sites 5, 6, 7, and 10 are likely filled with natural gas hydrate. Gas hydrate is identified on borehole logs and images as high resistivity responses without associated density increases or indications of free gas. The local state of stress at the time of fracturing can be determined by fracture orientations. In Holes 5A, 5B, 6A an 7A the gas hydrate-filled fractures have an aligned, preferred orientation likely associated with a local stress regime. At Site 10, where 130 m of gas hydrate-filled fractures were observed, fracturing is chaotic, likely due to high gas flux.

The presence of gas hydrate and free gas within marine sediments, deposited along the South Shetland margin, offshore the Antarctic Peninsula, was confirmed by low and high resolution geophysical data, acquired during three research cruises. Seismic data analysis has revealed the presence of a bottom simulating reflector that is very strong and continuous in the eastern part of the margin. This area can be considered as a useful site to study the seismic characteristics of sediments containing gas hydrate, with a particular focus on the estimation of gas hydrate and free gas amounts in the pore space. Pre-stack depth migration and tomographic inversion were performed to produce a regional velocity field of gas-phase bearing sediments and to obtain information about the average thickness of gas hydrate and free gas layers. Using these data and theoretical models, the gas hydrate and free gas concentrations can be estimated. Moreover, the common image gather semblance analysis revealed the presence of detailed features, such as layers with small thickness characterised by low velocity alternating with high velocity layers, below and above the bottom simulating reflector. These layers are associated with free gas trapped within the hydrate stability zone and deeper sediments. Thus, the use of the detailed and the regional velocity field analysis is important to give a more reliable estimate of gas content in the marine sediments.

Results of seismic surveys are routinely used to assess the presence of methane hydrate in deep ocean sediments. Accurate estimates of hydrate distribution and volume within the sediment are required to assess the potential of gas hydrate as an energy resource, driver for climate change or as a geotechnical hazard. However, seismic velocity may be affected not only by the quantity and morphology of the hydrate, but also by the properties of the host sediment, for example its particle size distribution and grain shape. This paper reports the results of experiments conducted to determine dynamic geophysical properties such as compressional wave velocity (Vp), shear wave velocity (Vs) and their respective attenuation measurements (Qp -1 and Qs -1) of specimens with varying amounts of disseminated methane hydrate within materials with different particle shapes and sizes. The results show that the impact of disseminated hydrate is affected both by mean particle size and by particle sphericity, with the surface area of the sediment grains influencing the spread of hydrate throughout a material and therefore it’s bonding capabilities. The sediments with 10% hydrate content show the highest surface areas correspond to the least increase in seismic velocity while sediments with low surface areas gives the most.

The effects of porous medium heterogeneity on methane hydrate formation, water flow through the heterogeneous hydrate-bearing sand, and hydrate dissociation were observed in an experiment using a heterogeneous sand column with prescribed heterogeneities. X-ray computed tomography (CT) was used to monitor saturation changes in water, gas, and hydrate during hydrate formation, water flow, and hydrate dissociation. The sand column was packed in several segments having vertical and horizontal layers with two distinct grain-size sands. The CT images showed that as hydrate formed, the water and hydrate saturations were dynamically redistributed by variations in capillary strength of the medium (the tendency for a material to imbibe water), which changed with the presence and saturation of hydrate. Water preferentially flowed through fine sand near higher hydrate-saturation regions where the capillary strength was elevated relative to the lower hydrate saturation regions. Hydrate dissociation initiated by depressurization varied with different grain sizes and hydrate saturations.

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.