Analysis of Water Based Fracture Fluid Flowback to Determine Fluid/Shale Chemical Interaction

Concerns about the substantial amounts of water and chemicals pumped into the subsurface during hydraulic fracturing are valid because long term effects of these stimulation actions are unknown at the present time. Although less than 1% of the hydraulic fracturing fluid composition is made up of the various chemicals, reactions are likely to occur when said chemicals are in contact with other elements from the rock.

To reduce the amount of water being used in these fracture treatments, flowback from stimulated reservoirs are considered as base fluid to prepare additional fracture fluid. However, in order re-use the fluid, it must be treated appropriately since the produced waters are chemically altered. Hence, the changes that ensue in both the rock and fluid have to be studied and quantified where possible.

Shale samples from the Barnett, Eagle Ford and Marcellus were exposed to a cross-linked gel composition for 1, 5, 10 and 30 days at simulated reservoir conditions (elevated temperature and pressure). Collected samples were sent to a commercial laboratory for analysis. Concentration of the cations, anions and dissolved metals in the fluid were measured before and after contact with the rock to establish any reactions that might have taken place.

To uncover the effects of hydraulic fracturing treatment on the different rock types, the mineralogy was determined using X-Ray fluorescence (XRF). Also, tests of total organic content (TOC) were performed to ascertain what kinds of changes may have affected the elements within the rock. Differences in measured quantities of cations, anions etc. confirm that chemical reactions occur. Furthermore, the variations observed between the base fluid and those exposed to the different shale types corroborate that the different composition of elements in the rocks can be correlated to the different concentrations of measured properties of the simulated flowback.