Ernesto Fonseca

Estimation of Rock Compressive Strength Using Downhole Weight-on-Bit and Drilling Models

In unconventional gas and tight oil plays, knowledge of the in situ rock mechanical profiles of the reservoir interval is critical in planning horizontal well trajectories and landing zones, placement of perforation clusters along the lateral, and optimal hydraulic fracture stimulation design. In current practice, vertical pilot holes and/or the laterals are logged after drilling, and the sonic and neutron log results are interpreted along with mechanical rock properties measured in the laboratory on core material. However, coring, logging, and core analyses are expensive and time consuming. In addition, as they are typically only performed in a few wells that are assumed to be representative, there is considerable uncertainty in extrapolating results across wide areas with known variability in stratigraphy, faults, thicknesses, hydrocarbon saturations, etc. This paper reports a method for estimating mechanical rock properties and in situ rock mechanical profiles in every well in a development, based on calibration from initial rock core analyses plus drilling data that is routinely acquired. Wellbore friction analysis was coupled with a torque and drag model to estimate in situ unconfined compressive strength (UCS) and Young’s modulus (YM) profiles. The key process steps include: a) Calculate the weight and wellbore friction force of each element of the drill string from bottom to the surface; b) Adjust the hook load (HL) by subtracting the weight of the hook and entire drill string; c) Iteratively compute the friction coefficient to match calculated and observed HL; d) Estimate downhole weight-on-bit (DWOB) by applying a stand pipe pressure correction to the calculated HL and considering potential sliding and abrasiveness; e) Use a rate of penetration (ROP) model developed for polycrystalline diamond compact (PDC) drill bits considering a force balance between a drill bit geometry and formation and a wear function depending upon the formation abrasiveness and bit hydraulics to compute confined compressive strength (CCS). The resulting CCS was correlated to UCS and YM using regression constants obtained from laboratory triaxial test data on whole core. Using examples from horizontal wells in a siltstone play in Alberta, Canada, this manuscript demonstrates a workflow to estimate rock strength from drilling data. The predicted UCS and YM values were compared with log data and potential uncertainties arising out of drilling data are discussed.

Emerging Technologies and the Future of Hydraulic Fracturing Design in Unconventional Gas and Tight Oil

As industry leaders seek solutions to the myriad of challenges facing unconventional projects, research and development efforts continue in the area of multistage fracturing design. These research activities are focused on the identification of novel approaches to hydraulic fracturing (HF) design that can lead to more effective design practices in the future. This paper describes emerging technologies within the building blocks of HF design for multi-stage horizontal wells, and proposes how application of these technologies can lay a foundation for the development and evolution of future industry practices. The industry debate on HF design commonly revolves around a perceived need for more powerful software tools that can capture complex fracture geometries. This perspective or position within the broader industry is due in large part to the cloud of microseismic induced events that is oftentimes observed to envelop a treatment area. Some interpret that these events arise from very complex fracture geometry, and therefore modeling tools with increased specialization are needed. Rather than focusing only on the ability of the software to replicate complex fracture geometries, a higher-level and integrated view of HF design is recommended. As shown in Fig. 1, this integrated approach considers the progressive analysis and application of subsurface diagnostics and modeling capabilities, and how they can influence meaningful decisions in the area of HF design. In reality, the capability for HF design is as strong as the weakest of these three components and need not rely solely on modeling capability. For example, consider the scenario where an advanced set of subsurface diagnostics are found to be limited by software capabilities due to the inability of the software to replicate the diagnosed phenomena with credible physics. This situation limits the use of subsurface diagnostics because the field observations are not mapped to the modeling capabilities and a relevant decision. In a similar scenario, modeling capabilities may be underpinned by credible data and diagnostics, but also lack the ability to influence a critical design parameter such as pump rate, well landing depth or fluid choice. This paper explores how emerging technologies within these building blocks are evolving and how this progress is resulting in new and relevant engineering choices in the design of hydraulic fractures. These choices include design for lateral sweet-spotting, better approaches in sequence and spacing of wells and fractures, and re-fracturing decisions for horizontal wells.