Sanding Onset and Volumetric Production in Gas Hydrate-Bearing Sediment

Abstract

ABSTRACT Sanding onset and sand production rate in non-isothermal conditions are of interest both for thermally related Enhanced Oi Recovery (EOR) and producing gas in gas hydrate bearing sediment processes for sand control and optimized production purposes. Thermal-hydraulic-mechanical coupling with hydrate decompostion (THMD) process once a supercritical condition is surpassed must be considered during wellbore depressurization, heating or a combined effort during drilling or production. Mechanical responses due to this THMD effect is calculated by a poro-elastplastic model in which a linear Mohr-Coulomb criterion is applied. The cohesion in the porous formation is assumed to be dominated by thhe hydrate saturation in addition to the pure mechanical loading. Sand production onset and sand rate is postulated to be defined by an effective plastic strain (EPS) and proportional to the sanding radius, respectively. Both sand rate inside conventional and GHBS are simulated and validated by the proposed model. We conclude that a temerpature increase at a wellbore may enhance the possibility of sanding risk and also the solid production rate. By reducing the wellbore temperature, sanding risk and sand rate may be reduced while a constant hydraulic drawdown is maintained. INTRODUCTION Wellbore depressurization and heating are strategies to decompose the solid hydrate into water and gas inside a gas-saturated formation. Combined together, it is considered as the most economic approach in producing gas in a gas-hydrate-bearing formation (GHBF). Sand detachment and solid flow associated with fluid (oil/gas/water) production are major concerns in such a porous formation that is typically poorly consolidated. Thermal-Hydraulic-Mechanical (THM) processes involving a dynamic solid hydrate decomposition (THMD) in terms of the solid rock skeleton and solid-hydrate phase change, which affect the hydraulic processes, must be considered. For economic consideration, other than a typical conventional reservoir evaluation, sand management and prediction are essential before determining whether a field exploitation is feasible and applicable in these unconventional reservoirs. This is particularly true once a critical pressure or temperature is surpassed during drilling and production when the solid hydrate is decomposed into water and gas in the GHBF. Heat exchange, solid hydrate phase change, multi-phase fluid flow interacting with formation erosion and severe deformation, and solid transport with fluid may induce a dynamic THMD local non-equilibrium condition. In conventional reservoirs, the driving forces for sand production and primary causes of wellbore integrity problems are mainly attributed to the far-field stress concentration near a borehole. Typically, a critical pressure is determined for a given stress concentration based on the formation strength. Linear poroelastic and poroelastoplastic models with a linear plastic yielding criterion are applied for the stress and critical wellbore pressure calculations, respectively. From geomechanical point of view, unlike in the conventional reservoir where the induced stress near wellbore is due to the in-situ stresses, the wellbore stability and critical sanding conditions may be impacted by combined effects of dynamic effective stress and formation strength changes due to a phase change once a solid hydrate dissociation occurs. This is also observed and reported in various field pilot tests (Kim et al., 1987; Masui et al., 2005, 2008; Yamamoto et al., 2017; Zhang et al., 2019) in a GHBS. The effective stress profiles inside the sanding zone may be affected by the dissociation process regardless of the changes in the non-hydration related THM conditions. Maintaining wellbore integrity and controlling the detached sand particle have been two of most important tasks to avoid the equipment damage due to the erosion from the flowing sand particles. The potential sand-free measures may increase costs and reduce the production at the same time. To produce gas economically in GHBS, it is essential to identify the onset of sand production and control or manage it by avoiding sanding from a sand control perspective. On the other hand, such a sand control measure may undermine the fluid production and compromise the objective of a maximized energy production. Thus, the procedures of controlling wellbore pressure, production rate, and temperature increase practiced in the conventional reservoir may be difficult, if not inapplicable, in GHBS. To minimize the solid production or completion cost and maximize the production, understanding the sanding mechanism in such a formation and estimating the sand rate during production are critical. Consequently, establishing comprehensive and quantified coupled THM model characteristics for the key processes in hydrate gas formations is highly desirable. It is our goal to develop a quantified approach to calculate the volumetric sand rate so that the impact of sand production can be evaluated, and the control on the fluid production can be designed.