Coupled multiphase fluid flow and wellbore stability analysis associated with gas production from oceanic hydrate-bearing sediments

• Published in: Journal of petroleum science & engineering 2012-08, Vol.92-93, p.65-81
• Main Authors: Rutqvist, J., Moridis, G.J., Grover, T., Silpngarmlert, S., Collett, T.S., Holdich, S.A.
• Format: Article
• Language: English
• Subjects: Applied sciences; Assembly; Completion equipments and methods. Casing. Cementing. Tests and measurements in wells; Crude oil, natural gas and petroleum products; Deposits; Drilling methods and equipments. Rocks mechanics. Directional and horizontal drilling; Drilling. Casing. Preparing wells for production; Energy; Exact sciences and technology; Fuels; Gas production; Geomechanics; Hydrates; Modeling; Natural gas; Prospecting and production of crude oil, natural gas, oil shales and tar sands; Sand; Sediments; Subsidence; Well drilling; Well stability
• ISSN: 0920-4105; 1873-4715
• DOI: 10.1016/j.petrol.2012.06.004

We 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. ► We modeled wellbore stability during gas production from an oceanic hydrate deposit. ► Vertical compaction and increased shear stress caused yielding around the well assembly. ► Such yielding and shearing of the sediments could lead to enhanced sand production. ► Yielding can be reduced by overbalanced drilling and appropriate well completion. ► Compaction strain of up to 10% could significantly impact the well assembly.