Multistage Hydrocarbon-Based Fracturing in Tight Gas Formation (Russian)

Summary Unconventional gas is stored in extensive areas known as basin-centered continuous-gas accumulations. Although the estimated worldwide figures differ significantly, the consensus among the studies relating to unconventional gas resources is that the volumes are gigantic. However, the low permeability in these types of reservoirs usually results in a very low recovery factor. To help unlock these resources, this paper presents a new and more accurate way of simulating multistage hydraulic fracturing in horizontal wells in three dimensions by use of single- and dual-porosity reservoir models. In this approach, the geometry (not necessarily symmetric) and orientation of the multiple hydraulic fractures are driven by the prevailing stress state in the drainage volume of the horizontal well. Once the hydraulic-fracturing job is accurately modeled in three dimensions, two-way geomechanical coupling is used to history match the produced gas from a horizontal well drilled in the Nikanassin naturally fractured tight gas formation of the Western Canada Sedimentary Basin (WCSB). Traditionally, the most widely used approaches have their roots in semianalytical calculations simplifying the fracturing system to a planar feature propagating symmetrically away from a line source of injection. In contrast, the computed results presented in this study show that the incorporation of geomechanical effects gives a more realistic representation of the orientation and geometry of hydraulic fractures. Reduction in permeability of the natural and hydraulic fractures because of pressure depletion results in more-realistic production predictions compared with the case in which geomechanical effects are ignored. The telling conclusion, in light of the computed results, is that the field of hydraulic fracturing provides an object lesson in the need for coupled 3D geomechanical approaches. The method presented in this paper will help to improve gas rates and recoveries from reservoirs with permeability values in the nanodarcy scale.

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Wettability of the Montney Tight Gas Formation

SPE Reservoir Evaluation & Engineering ◽

10.2118/171620-pa ◽

2015 ◽

Vol 18 (03) ◽

pp. 417-431 ◽

Cited By ~ 47

Author(s):

Qing Lan ◽

Hassan Dehghanpour ◽

James Wood ◽

Hamed Sanei

Keyword(s):

Water Uptake ◽

Clay Content ◽

Horizontal Wells ◽

Inorganic Materials ◽

Tight Gas ◽

Gas Formation ◽

Strong Adsorption ◽

Tight Formations ◽

Tight Gas Formation ◽

Tight Rocks

Summary The abundant hydrocarbon resources in low-permeability formations are now technically accessible because of advances in the drilling and completion of multilateral/multifractured horizontal wells. However, measurement and modeling of petrophysical properties, required for reserves estimation and reservoir-engineering calculations, are the remaining challenges for the development of tight formations. In particular, characterizing wettability (wetting affinity) of tight rocks is challenging because of their complex pore structure, which can be either in hydrophobic organic materials or in hydrophilic inorganic materials. We conduct comparative and systematic imbibition experiments on 10 twin core plugs from the Montney tight gas formation, which is an enormous tight gas fairway in the Western Canadian Sedimentary Basin. Both contact-angle and imbibition data indicate that the formation has a stronger affinity to oil than to water. However, the ratio between oil and water uptake of these samples is usually higher than what capillary-driven imbibition models predict. This discrepancy can be explained by the strong adsorption of oil on the surface of a well-connected organic-pore network that is partly composed of degraded bitumen. We also define a wettability index on the basis of the equilibrium oil and water uptake of the twin samples. Oil-wettability index is positively correlated with total organic carbon and clay content of the rocks, which generally increase from the upper Montney to the lower Montney.

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