We present a fully 3D planar fracture model based on a finite element solution for fracture opening and a finite difference solution for slurry transport in the fracture. The new model can be used in cases with sufficient data gathered from logs, cores and micro-fracs. It can also be used in conjunction with fracture mapping to develop calibrated models that are based on the fundamental physics of fracturing.Using novel numerical methods for the elasticity solution, we obtain an accurate description of the stress near the fracture tip. Combined with the physics of the cohesive zone model, this provides an appropriate description of fracture propagation. Benchmarking the model against laboratory tests shows a favorable comparison between modeling and observations.

One of the most important challenges in the Jonah Field in Sublette County, Wyoming, is to obtain effective fracture-height coverage over the entire 2,800+ ft Lance formation. The Lance formation in Jonah Field is composed of a stacked sequence of 20 to 50 fluvial channel sands interbedded with associated overbank siltstone and floodplain shale deposits. Within this interval, the net-to-gross ratio varies from 25 to 40%. Sandstone bodies occur as individual 10- to 25-ft thick channels and stacked-channel sequences greater than 200 ft in some cases. Tiltmeter and microseismic fracture mapping was conducted on hundreds of propped-fracture treatments in the Jonah Field. These direct height-growth measurements helped to obtain an understanding about the effectiveness of shale barriers. It was found that a standard triple-combo log suite could be used to identify shale barriers for fracture growth. A calibrated fracture model was developed for the Jonah Field that ties the log analysis to the fracture-growth behavior that was mapped using direct fracture-mapping technologies and to the net-pressure response measured during propped fracture treatments. These improvements in predictive modeling capabilities have lead to better insight into fracture growth behavior in the Lance formation. A 3D fracture-growth model was modified to determine perforation strategy and fracture-treatment schedules to obtain effective coverage of the Lance formation in new Jonah wells in a semi-automated process. As a result, the entire process for fracture design can now be performed in an integrated software package.

With the growing popularity of multi-stage hydraulic fracturing treatments in horizontal wellbores, various completion systems have been utilized for mechanical isolation and staging of individual fracture treatments. One of the more popular fracture staging techniques is the plug-and-perf technique in cemented casing, which requires the lateral section of the wellbore to be free of debris and proppant so that the plug and perforation tool string can be pumped down to the desired setting depth. Proppant that has settled in the lateral can result in plugs getting stuck and prematurely setting at the wrong depth, requiring costly intervention work and delaying the progress of completing the well. The industry standard practice to prepare a clean wellbore has been to over-flush each fracture treatment by 50 to 100 barrels in excess of the volume to the perforations. This practice has raised concerns about disturbing near-wellbore proppant conductivity and potentially harming fracture continuity with the wellbore, and thus productivity. Since operators have achieved satisfactory economics in many shale plays, this practice continues despite its controversy. These concerns have led to experiments in minimizing excess flush volumes in wells located in the liquids-bearing window of the Eagle Ford Shale. This paper proposes a process involving the use of real-time treatment data displayed within a wellbore model simulation to adjust the flush volume of each stage based on the reduction in proppant concentration at the perforations. Over 200 stages were successfully placed with this method with no incidences of plugs sticking in the lateral. This paper contains a selection of treatment charts and wellbore diagrams from actual applications of this method. Simulated fracture profiles of different over-flush scenarios are also compared and discussed. This paper will be useful for engineers and managers involved in well completions and stimulation, and presents detailed methodology for successfully applying this strategy in their fields. By applying these procedures, continuity between the proppant pack in the fractures and the wellbore should be improved, and fresh water usage will be reduced.

Hydraulic fracturing stimulation in unconventional reservoirs has taken on a new emphasis in the search for oil and liquids from these low permeability reservoirs. Today, we are attempting to achieve economic production from reservoirs that were passed over just five years ago. The fracture stimulation goal: to provide a conductive path between the reservoir and the wellbore. However, these reservoirs are inherently difficult, at best, to evaluate and to fully understand the completion environment at a distance from the wellbore. Fortunately, there is a workflow that allows understanding of permeability sources as the fracture treatment is placed in real time and certainly in post-frac analysis. The toolbox uses a "planar" frac model to analyze data gathered from surface sources. This paper will discuss a workflow to differentiate between pressure trends due to fluid and/or proppant effects on friction, and actual net-pressure change due to permeability exposure by the frac fluid in the reservoir. By understanding that fracture stimulation is a highly invasive process, the authors will examine the data that can be used as a benchmarking tool for reservoir response. We will discuss examples from the Eagle Ford formation for naturally fractured permeability reservoirs and the Wolfberry trend for matrix-based reservoirs. The workflow will aid in fracture spacing in horizontal wells and well spacing in multi-layered vertical wells.

Advances in fracture mapping and full 3D modeling have yielded new insights into hydraulic fracture geometry, but it is still impossible to predict height growth. Fracture mapping data collected from a large number of treatments in different basins yield a rule-of-thumb for expected fracture height over fracture length (aspect ratio), but in specific cases fracture design optimization requires a more accurate forecast for height growth. Calibrated models with full 3D fracture geometry will give the best results, but in many projects the available data to calibrate such a model is severely limited. Knowing this, the question this paper attempts to answer is: "Will using a full 3D model give more reliable predictions of fracture geometry (maybe height growth) compared with pseudo-3D models?". Using data from an instrumented field test and routine fracture treatments, the results of the different fracture models are tested. Even when detailed knowledge of stress and geomechanical properties are available, it is impossible to match observed fracture geometry using only conventional hydraulic fracture physics. So, even a full 3D model does not provide a true prediction of fracture geometry. Both pseudo3D and full 3D fracture models can match observed fracture geometry, but only by introducing additional parameters beyond conventional fracture propagation physics, such as formation lamination or fracture tip pore pressure. A full 3D model with default input parameters and conventional fracture physics yields a prediction of strong containment, even for modest stress difference between pay and overburden. This agrees in general with average observed geometry, but in specific cases, fracture height growth still occurs, showing that in these cases the model was inadequate and needs to be calibrated. Pseudo-3D models tend to overestimate height growth for default inputs, but that can also be modified to match the stronger containment often seen in practice. Therefore, no benefit is obtained from fully gridded simulation models in routine cases where critical inputs and calibration data are unavailable.