In this simulation study, we analyzed the geomechanical response during depressurization production from two known hydrate-bearing permafrost deposits: the Mallik (Northwest Territories, Canada) deposit and Mount Elbert (Alaska, USA) deposit. Gas was produced from these deposits at constant pressure using horizontal wells placed at the top of a hydrate layer (HL), located at a depth of about 900 m at the Mallik and 600 m at the Mount Elbert.The simulation results show that general thermodynamic and geomechanical responses are similar for the two sites, but with substantially higher production and more intensive geomechanical responses at the deeper Mallik deposit. The depressurization-induced dissociation begins at the well bore and then spreads laterally, mainly along the top of the HL.The depressurization results in an increased shear stress within the body of the receding hydrate and causes a vertical compaction of the reservoir. However, its effects are partially mitigated by the relatively stiff permafrost overburden, and compaction of the HL is limited to less than 0.4%. The increased shear stress may lead to shear failure in the hydrate-free zone bounded by the HL overburden and the downward-receding upper dissociation interface. This zone undergoes complete hydrate dissociation, and the cohesive strength of the sediment is low. We determined that the likelihood of shear failure depends on the initial stress state as well as on the geomechanical properties of the reservoir. The Poisson's ratio of the hydratebearing formation is a particularly important parameter that determines whether the evolution of the reservoir stresses will increase or decrease the likelihood of shear failure.

TitleCoupled multiphase fluid flow and wellbore stability analysis associated with gas production from oceanic hydrate-bearing sediments ABSTRACTWe conducted numerical modeling of coupled multiphase fluid-flow, thermal, and geomechanical processes during gas production from an oceanic hydrate deposit to study the geomechanical performance and wellbore stability. We investigated two alternative cases of depressurization-induced gas production: (1) production from horizontal wells in a Class 3 deposit (a hydrate layer sandwiched between two low-permeability layers), and (2) production from vertical wells in a Class 2 deposit (a hydrate layer with an underlying zone of mobile water). The analysis showed that geomechanical responses around the wellbore are driven by reservoir-wide pressure depletion, which in turn, depends on production rate and pressure decline at the wellbore. The calculated vertical compaction of the relatively soft sediments and increased shear stress caused local yielding of the formation around the well assembly for both the horizontal and vertical well cases. However, the analysis also showed that the extent of the yield zone can be reduced if using overbalanced drilling (at an internal well pressure above the formation fluid pressure) and well completion that minimizes any annular gap between the well assembly and the formation. Our further analysis indicated that the most extensive yield zone would occur around the perforated production interval of a vertical well, where the pressure gradient is the highest. In the field, such yielding and shearing of the sediments could lead to enhanced sand production if not prevented with appropriate sand control technology. Moreover, our analysis shows that the vertical compaction of the reservoir can be substantial, with subsidence on the order of several meters and vertical compaction strain locally exceeding 10%. In the field, such substantial compaction strain will require appropriate well design (such as slip joints or heavy wall casing) to avoid tensile or buckling failure of the well assembly.2 Keywords: hydrates, geomechanics, modeling, well stability, gas production, subsidence NOMENCLATURE

The Messoyakha Gas Field is located in Siberian permafrost. The field has been described as a free gas zone, overlaid by hydrate layer and underlain by an aquifer of unknown strength. The field was put on production in 1970 and has produced intermittently since then. Some characteristic observations were increase in average reservoir pressure during shut-in, perforation blocking due hydrate formation and no change in gas-water contact. It is believed the increase in reservoir pressure was caused by the hydrate layer dissociation, rather than aquifer influx. The objective of this study is to use numerical model to analyze the observed production data from the Messoyakha field. In this study, a range of single-well 2D cross-sectional models representative of Messoyakha have been developed using Tough + Hydrate reservoir simulator. The simulation results were analyzed and compared with various field observations. Further, we have done a parametric study of reservoir properties of hydrate capped gas reservoir. We have used Tough + Hydrate to simulate the observed gas production and reservoir pressure data at Messoyakha. We simulated various scenarios that help to explain the field behavior. We have evaluated the effect of various reservoir parameters on gas recovery from hydrates. Our work should be beneficial to others who are investigating how to produce gas from hydrate capped gas reservoir. We were able to generate results that are very similar to the reported flow rates and pressure behavior in Messoyakha Field. The value of absolute permeability in the hydrate layer and the lower free gas layer substantially affects the continued dissociation of hydrates during shut-down. We also modeled the formation of secondary hydrates near the wellbore that can cause the reduced gas flow rates. The important parameters affecting the gas production are the formation permeability in the gas layer, the effective gas vertical permeability in hydrate layer, the location of perforations, and gas hydrate saturation. We have described various scenarios which are beneficial as well as detrimental in producing gas from hydrate capped gas reservoirs. We have also listed various parameters that should be carefully measured for accurate modeling work. Introduction Natural gas hydrates have been the subject of active research in the oil and gas industry since their role in blocking fluid flow in oil and gas pipelines was demonstrated by Hammerschmidt (1934). Later, Makogon (1965) proposed that naturally occurring gas hydrates could exist in the earth's subsurface. Since 1965, a number of research projects have been performed to estimate and quantify the volume of naturally occurring gas hydrates. Although there is uncertainty over the quantity and distribution of naturally occurring hydrates in the earth, there is general agreement that substantial volumes of gas hydrates do exist in nature (Sloan and Koh, 2008). According to the latest data gathered by various expeditions for hydrates, the gas resource in hydrate ranges from 105 to 106 Tcf (US Department of Energy, 2007). Natural gas hydrates (NGH) are crystalline compounds formed by the association of molecules of water with natural gas. NGHs are a subset of substances known as clathrates, which means "cage like structures". The formation of natural gas hydrates depends upon pressure, temperature, gas composition, and the presence of inhibitors such as salts. NGHs are found in the subsurface in two distinct types of settings. One is the permafrost in arctic regions and the second is in deepwater marine environments.

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Microfracturing and induced elastic anisotropy impart changes on body wave velocities with implications to seismic and wellbore testing methods and interpretation. We have conducted simultaneous triaxial stress tests and ultrasonic wave propagation monitoring to quantify S-wave anisotropy and microfracture development in Berea Sandstone and Silurian Dolomite. The onset of stress-induced microfracturing is detected at the beginning of appreciable S-wave anisotropy called the “S-wave crossover” (SWX). The SWX and subsequent increases in S-wave anisotropy evidence microstructural damage development well before quasistatic indicators such as the volumetric strain point of positive dilatancy (PPD) and yield/failure in all samples. X-ray microtomography confirmed fracture development and allowed for geometric assessment of fracture orientation. Stresses at the SWX and PPD are compared with peak axial stress to understand linkages between damage and ultimate rock strength. In Berea Sandstone, the SWX occurs at 40%–60% of the peak axial stress, whereas in Silurian Dolomite, SWX occurs at approximately 60%–80% of the peak axial stress. Results indicate that rock samples undergo irreversible microstructural changes before dilatancy manifests, and earlier than previously thought. Analysis of tangent elastic coefficients indicates that the ratio between the dynamic and static Young’s moduli can change significantly prior to SWX due to elastic and inelastic processes induced by deviatoric loading and ranges from approximately 2:1 to 4:1 for Berea and 2:1 to 7:1 for Silurian. Understanding damage development and the relationship between the dynamic and static responses of rocks provides opportunities to upscale stress-strain behavior to the wellbore environment and for improved geomechanical interpretation from dipole sonic and time-lapse well-log analyses.

Nano-fluids are playing a very important role in thermal stream due to its physical and thermal properties. Now a day it was observed that there are lots of papers which have explained the deep study on nanofluids. There are so many areas in which nanofluids are used to increase the thermal efficiency and coefficient of heat transfer. In this review comprehension, many research works which are related to nanofluids used as a working fluid in shell and tube heat exchanger will be summarized in efficient way. And theoretical as well as experimental study is to be performed for shell and tube heat exchanger to determine what the effects on various parameters of graphene nanofluid, silver nanofluid, Al2O3 nanofluid and copper nanofluid. Graphite is the cheapest form of producing flanks of graphene and these samples of produced graphene were optimized with help of different type of methods. To increase the performance of heat transfer of shell & tube heat exchanger, the graphene nanofluid is used as a working fluid rather than any different type of ordinary fluid. The thermal efficiency and the coefficient of heat transfer depend upon the inlet temperature, flow rate, concentration of working fluid. The general outcomes show that by increasing in concentration of nanoparticle and flow rate of working fluids, there will be the increment in heat transfer rate, thermal conductivity and efficiency of heat exchanger.