Abstract Improved understanding of hydraulic fractures is needed to optimize petroleum well drilling and completion strategies. Yet direct observations of hydraulic fractures are rarely made, and reliance is placed on indirect methods such as microseismic monitoring, interference tests, fibre optic detection of fracturing in adjacent wells and numerical modelling. While these techniques provide useful insights, verification of such studies is commonly lacking; core taken through stimulated intervals offers a robust option for verification. We make the case that core can provide complementary information at a different scale from other data types. Core from a slant well adjacent to two stimulated wells at the Hydraulic Fracture Test Site (HFTS1) in West Texas revealed 375 hydraulic fractures, striking 090°±20°, subparallel to present-day S Hmax . There are more hydraulic fractures than expected, and clustering across a range of scales from approximately 1 cm to 50 m. The largest cluster correlates with high microseismic event density. Diversion, bifurcation, and segmentation structures may account for the large number of fractures observed and the orientation spread. Reactivation of sealed natural fractures and bedding planes is relatively uncommon. Proppant sand packs and patches occur in a few locations, particularly where hydraulic fractures are complex.

Abstract: Overpressuring, tectonic stretching and thermoelastic contraction are all processes that can drive the formation of opening-mode fractures in the subsurface. Recent studies on crack-seal quartz deposits in opening-mode fractures have yielded fluid inclusion microthermometric data, which for the first time allow us to constrain the pressure–temperature conditions under which these fractures formed. Here, we utilize the results from studies in the Lower Cretaceous Travis Peak Formation in the East Texas Basin and the Upper Cretaceous Mesaverde Group in the Piceance Basin to construct stress history models based on mechanical properties, burial history and tectonic setting to evaluate the various driving mechanisms for opening-mode fracture formation. Our results show progress towards separating and independently evaluating these mechanisms. Although high fluid pressure and tectonic stretching can play a major part in the formation of opening-mode fractures, our results suggest that the persistence of fracture growth during uplift could have been strongly influenced by thermoelastic contraction associated with exhumation and cooling. For sandstone reservoirs, thermoelastic contraction will be more pronounced for stiffer, high Young’s modulus rocks with higher quartz contents. These models can therefore be used to provide additional insights into the distribution of opening-mode fractures in exhumed basins.

Abstract Fractures in tight gas sandstone remain challenging to characterize or predict accurately. Here we recapitulate recent work on continuity of fracture porosity and its important effect on fluid flow. Natural cement precipitation (diagenesis) in fractures can preserve fluid conduits by propping fractures open or otherwise reducing stress sensitivity of fracture permeability. It can also impede fluid flow by reducing effective fracture length, or occluding porosity. We report patterns of natural fracture growth and decay that are extensively influenced by diagenesis. These patterns typify many fractured siliciclastic and carbonate rocks. We show how appreciation of diagenetic effects can be used to improve accuracy of predictions of fracture attributes and illustrate implications for fluid-flow simulation. Our results also imply that fractures will not tend to close under subsurface loading conditions in many tectonic settings. Chemical alteration and the interactions of diagenetic reactions with rock properties and the in situ stress dictate the location of open fractured flow conduits.