Effects of Carbonate Minerals on Shale-Hydraulic Fracturing Fluid Interactions in the Marcellus Shale

Natural gas extracted from tight shale formations, such as the Marcellus Shale, represents a significant and developing front in energy exploration. By fracturing these formations using pressurized fracturing fluid, previously unobtainable hydrocarbon reserves may be tapped. While pursuing this resource, hydraulic fracturing operations leave chemically complex fluids in the shale formation for at least two weeks. This provides a substantial opportunity for the hydraulic fracturing fluid (HFF) to react with the shale formation at reservoir temperature and pressure. In this study, we investigated the effects of the carbonates on shale-HFF reactions with a focus on the Marcellus Shale. We performed autoclave experiments at high temperature and pressure reservoir conditions using a carbonate-rich and a decarbonated or carbonate-free version of the same shale sample. We observed that carbonate minerals buffer the pH of the solution, which in turn prevents clay dissolution. Carbonate and bicarbonate ions also scavenge reactive oxidizing species (ROS), which prevents oxidation of shale organic matter and volatile organic compounds (VOCs). Carbonate-free samples also show higher pyrite dissolution compared to the carbonate-rich sample due to chelation reactions. This study demonstrates how carbonate minerals (keeping all other variables constant) affect shale-HFF reactions that can potentially impact porosity, microfracture integrity, and the release of heavy metals and volatile organic contaminants in the produced water.

Hydraulic Fracturing on Water from Alternative Sources: An Integrated Approach, Ways, and Solutions

In the context of a comprehensive search for ways to optimize and reduce operating costs for hydraulic fracturing operations, one of the areas to consider is the use of alternative water sources for making-up hydraulic fracturing fluids such as Cenomanian, mixed or produced water. This solution allows to optimize the speed and quality of work without wasting time and financial resources due to no need for heating and remote transportation. The main goal of the study was to create a stable guar-based hydraulic fracturing fluid system with a borate crosslinker, which allows high-quality treatment using high-salinity water. Much attention is paid to the composition of real saline sources, i.e. produced, mixed and Cenomanian water, which were sampled from the Gazpromneft-Khantos fields. Based on the data ranking by composition, the main groups of mineral components, as well as the cut-off criteria that determine the behavior of a hydraulic fracturing fluid in linear and cross-linked forms, were identified. The main stage of working on the fluid system quality included two areas: screening stabilizing components that meet the criteria for performing hydraulic fracturing operations, and assessing the fluid clogging properties based on flow tests. To study and select the composition of a hydraulic fracturing fluid, both standard and extended rheological tests were performed, which included core tests on real samples from target reservoirs and tests of residual conductivity and permeability of a proppant pack. The sand-transport properties of the fluid were measured both in static and dynamic conditions. The study resulted in the development of a fluid system complex including stabilizing additives and criteria for their applicability at real field conditions, taking into account the features of the existing equipment of hydraulic fracturing fleets. Experiments have shown that standard guar fluids based on water from alternative sources, when using a complex of stabilizing components, successfully replace the basic set of additives for fresh water, and are quite competitive not only in rheological properties and the ability to transport proppants, but also in restoring the permeability of a proppant pack and core samples. Each stabilizing component of such fluid makes its own unique contribution to achieving the required parameters of the fluid without losing its quality. An important achievement is the development of methods and criteria for the applicability of stabilizing components that make it possible to work with any source, whether it is produced, mixed, or Cenomanian water. The solution allows in a short time to adjust the fluid system depending on the actual mineral composition in a stationary field laboratory without the involvement of specialized equipment and expensive research.

Evaluation of anionic and non-ionic surfactant performance for Montney shale gas hydraulic fracturing fluids

Hydraulic fracturing is often used in unconventional shale reservoirs, and 50%–95% of the injected hydraulic fracturing fluid remains in the formation due to the capillary effect. This phenomenon has been observed in the Montney shale formation, Canada, where the flowback water recovery is generally less than 25%. Surfactant is one of the hydraulic fracturing fluid additives for reducing surface tension and capillary forces to facilitate water flowback recovery. Surfactant loss due to adsorption by the reservoir rocks reduces the chemical’s efficiency, and this causes water retention in the formation and reduces water flowback recovery. The compatibility of surfactant with reservoir rock is critical to minimize surfactant adsorption on the rock surface because this diminishes the primary function of the surfactant hydraulic fracturing fluid additive and to ensure cost-effectiveness. This study evaluates surfactant efficiency to improve flowback recovery for the Montney shale formation based on IFT, surface tension, and adsorption. This study evaluates surfactant performance and performs a fluid–fluid interaction experiment and fluid-rock compatibility investigation. Several commercial surfactants are screened for low interfacial tension and surface tension. Further analysis is carried out by evaluating the fluid-rock compatibility using the static soaking test at reservoir pressure and temperature. The pre-soaking and post-soaking test fluids were analyzed for water composition, liquid–liquid interfacial tension, surface tension, and pH. Results showed that the selected surfactant is a critical determiner of the hydraulic fracturing fluid performance. SOLOTERRA 938 is an anionic surfactant that has good compatibility with Montney shale formation. Unlike other non-ionic surfactants, SOLOTERRA 938 retains the interfacial tension and surface tension after seven days of interaction with reservoir rock. The interfacial tension remained unchanged at 0.1 mN/m. The surface tension decreased from 28.4 to 27.5 mN/m with air and from 21.7 to 20.8 mN/m with hydrocarbon because surfactant behavior changes with pH change. The surfactant concentration was measured using high-pressure liquid chromatography, and the loss was 12% after seven days of interaction with the reservoir rock (from 0.1 to 0.088wt%). The adsorption calculated based on the concentration volume showed a low value of between 0.43 and 0.97 mg/g rock.