Abstract Out of the 101 wells in the Changning and Weiyuan shale gas blocks in Southwest China's Sichuan basin drilled before March 2016, casing deformation occurred in 32. Analysis of one of these wells shows a fault at a sheared casing location, which suggests that hydraulic fracturing-induced fault shear is likely the cause of casing deformation. Here, we present a probabilistic geomechanical model evaluating imaged faults. The fact that the deformed casing is found close to a fault zone indicates that casing deformation was caused by hydraulic fracturing-induced fault slip. From the microseismic monitoring data, we can determine the strike and dip of the fault: N57°E and 70°. Image and wireline log data, as well as mini-frac test data from the subject well and other nearby wells, can be used to constrain geomechanical parameter distributions. Using these parameters, Mohr-Coulomb fault activation was evaluated. A Quantitative Risk Analysis (QRA) was undertaken to analyze both the probability of induced fault slip and the sensitivity of the slip to model parameters. Finally, we repeat this analysis for each fault interpreted from an ant tracked image, where each fault is colored by its potential for induced slip under the same pressure. The results show that, under current in-situ stress conditions, faults in the block are critically stressed and easily activated. After propagating uniformly distributed uncertainties in the geomechanical model using Monte Carlo simulation, we can observe that the fault that sheared had a 70% probability of doing so under a pressure increase of I 2,500 PSI. Applying this analysis to mapped faults allows us to separate fault segments into_those which should ideally be avoided by future production wells (red), and those which appear stable (green). The uncertainty analysis can also be used to prioritize further data collection by focusing on the parameters that the answer is most sensitive to (in this case S hmin and the natural pore pressure). The procedure highlighted herein provides a method for understanding the causes of casing deformation as well as measures for mitigating fault activation. It also shows the importance of seismic data - the same well appears to cross a second critically stressed fault which did not respond seismically as would be indicated by microseismicity or a sheared casing. Introduction In the Changning-Weiyuan national shale gas demonstration area of the Sichuan Basin, China, commercial shale gas production has been realized by using hydraulic fracturing to improve reservoir interconnectivity and permeability. Casing deformation is a significant challenge encountered in shale gas production in this play.

Abstract The Marcellus gas shale and Duvernay liquid rich shale are attractive targets because of their relatively high gas (S g-MARC ~0.8 - 0.9) and hydrocarbon saturations (S HC-DVRN ~0.7 - 0.8), respectively. The implied very low water saturations (S w ~0.1–0.3) confirm that these shales are dehydrated and contain no mobile water. When exposed to dilute meteoric water during hydraulic fracture stimulation the shale undergoes spontaneous imbibition, resulting in a coupled osmosis and diffusion process that imbibes most of the injected water. Only ~10–20 vol. % of the residual treatment water (RTW) is recovered from Marcellus wells, and ~20–50 vol. % of the residual treatment water (RTW) is recovered from Duvernay wells. Waters tends to be highly saline, increasing over production time, and often with TDS contents exceeding 250–300 kppm. Recently published data for Marcellus flow back brines by Rowan et al. (2015) shows that the RTW are isotopically enriched relative to injected local meteoric water (LMW) used in hydraulic fracture (HF) stimulation with δ 18 O ~ −1 to −3 ‰ vs. −9.5 ‰ for LMW (SMOW). The cause of the heavy oxygen isotopic signature has been attributed by some as being due to dissolution of salts in the Marcellus shale matrix. However, the RTW that has equilibrated with the Marcellus shale matrix is under-saturated with respect to halite. Based on geochemical analysis of hundreds of proprietary brine samples, an alternative interpretation is proposed for the origin of high salinities in RTWs associated with gas production in the Marcellus Fm. in the Appalachian Basin, PA. When plotted in the ternary NaCl-MCl 2 -H 2 O system (where M=Ca 2+ + Mg 2+ +Ba 2+ +Sr 2+ ), compositions of flow back brines from 55 Marcellus wells show a remarkably uniform composition with NaCl:MCl 2 of 57.8:42.2, indicating that their compositions are controlled by equilibration with the shale matrix. The Duvernay shale in the Deep Basin of Alberta Canada also has hundreds of proprietary brine samples that indicate very uniform NaCl:MCl 2 of ~70:30 also suggesting that RTW compositions are also controlled by equilibration with the shale matrix. Published oxygen isotope and TDS data from Marcellus RTW have been used to model the Water:Rock ratio (W:R) based on exchange between LMW and the shale matrix. An "open system" model has been used to estimate the W:R as this best approximates a single batch of fluid passing through the hydraulically fractured subsurface, consistent with the process of injection and flow back. Application of the oxygen isotope model to RTW associated with the Duverany Fm., from Deep Basin in Alberta Canada, shows similar oxygen isotope enrichment for the highest TDS and lowest inferred W:R ratios. The oxygen isotope-TDS signatures observed in some of the Deep Basin RTW allows for the fingerprinting of formation waters from stratigraphically deeper formations. These have enriched oxygen isotopic signatures (~+5 ‰; SMOW) and very high TDS contents of ~250 kppm. Their presence in Duvernay produced waters is an indication of breakthrough from these deeper and more saline formations.

Abstract The Kidson Sub-basin lies within latitudes 20°S and 24°S and longitude 123°E and 128°E and is one of the depocentres formed during the development of the Canning Superbasin in the Early Paleozoic in Western Australia. Hydrocarbon discoveries have been made over the years in some parts of the Canning Superbasin but none in the Kidson Sub-basin. This report evaluates the prospectivity of Kidson Sub-basin for unconventional hydrocarbon resources. The Kidson Sub-basin has a sedimentary section thickness reaching up to over 7000m, mainly of Paleozoic age. Using the available well data three unconventional shale gas plays within the Goldwyer, Bongabinni and Noonkanbah shales are interpreted to meet all the necessary requirements for hosting shale gas accumulations. A pseudo-well modelled near the centre of the Kidson Sub-basin shows that the organically-rich Noonkanbah Formation is mature enough to generate gas and 1-D modelling of the Kidson-1 well indicates that both the Bongabinni and Goldwyer Formations are also presently in the gas window. The prospective resources of the unconventional shale plays are estimated using geochemical approach. The Goldwyer Shale is estimated to contain potential gas in-place (GIIP) of about 13.4TCF over the most prospective area of Kidson Sub-basin estimated to be around 567 km2. The Bongabinni Shale is organically-rich and about 324 km2 is estimated to be prospective in the Kidson Sub-basin. About 205 km2 is estimated to be prospective in the centre of Kidson Sub-basin where Noonkanbah Shale is deeply buried to a depth up to 1600m. The three shale plays have mid range gross prospective resources of 31.0 TCF of gas. The current skilled labour shortage in Australia may pose a big challenge in shale gas production as this will lead to higher drilling costs compared to those of United States. In addition, Kidson Sub-basin is a desert and water scarcity will be another challenge for shale gas production since water is required for fraccing.