The main parameters of interest derived from a diagnostic fracture injection test (DFIT) are minimum in-situ stress, reservoir pressure, and permeability. The latter two can only be obtained uniquely from the transient reservoir responses, often requiring days to weeks of test time. The DFIT flowback analysis (DFIT-FBA) method, a sequence of pump-in/flowback (PIFB), is a fast alternative to the pump-in/falloff (conventional) DFIT for estimating minimum in-situ stress and reservoir pressure.

The problem of a plane strain hydraulic fracture propagating in a layered formation is considered. Fracture toughness, in-situ stress, and leak-off coefficient are assumed to vary by layer, while the elastic properties are kept constant throughout the domain for simplicity. The purpose of this study is to develop a numerical algorithm based on a fixed mesh approach, which is capable to solve the above problem accurately using elements which can even be larger than the layer size.

Well spacing and hydraulic fracture design optimization are among the most important challenges confronting companies operating in unconventional reservoirs. Field trials are time-consuming and expensive. Reservoir simulation and/or rate transient analysis can help guide development decisions, but these calculations can be affected by non-uniqueness. This work demonstrates that tracers can be used to reduce non-uniqueness.

This paper demonstrates how geochemical production allocations can be used to calibrate reservoir simulation models and improve the optimization of well spacing and hydraulic fracture design in unconventional assets. Geochemical analyses provide quantitative assessments of flow by layer over time. This allows numerical models to be fine-tuned to realistically capture the productive fracture height for wells landed in different stratigraphic layers.

This paper presents a calibration and optimization workflow using a fully coupled hydraulic fracturing, reservoir, and geomechanics simulator, as applied to the HFTS-2 dataset in the Delaware Basin, Texas, USA. Modeling began with building a geomechanical stress profile using the viscoelastic stress relaxation (VSR) method. The model was then calibrated to key observations from the field diagnostic data, which included: horizontal and vertical well DAS/DTS/DSS fiber, downhole microseismic arrays, pressure gauges, core-through data, image logs, DFITs, proppant-in-cuttings analysis, interference tests, and production data. Finally, the calibrated model was used to perform an economic optimization of design parameters by running hundreds of variations and comparing their performance.

The problem of a plane strain hydraulic fracture propagating in a layered formation is considered. Fracture toughness, in-situ stress, and leak-off coefficient are assumed to vary by layer, while the elastic properties are kept constant throughout the domain for simplicity. The purpose of this study is to develop a numerical algorithm based on a fixed mesh approach, which is able to solve the above problem accurately using elements that can even be larger than the layer size.

This study describes an automated history matching and optimization workflow using an integrated hydraulic fracturing reservoir simulator and applies the workflow in four cases. The automated workflow solves a formal mathematical optimization problem to minimize misfit with observations from any point in the lifecycle of a hydraulically fractured well, or to maximize a quantity of interest, such as net present value.