Gas wells in the Marcellus shale are usually completed with a hydraulic fracture treatment in order to create a conductive proppant pack for fluid flow to the wellbore thus effectively increasing well productivity. A novel hydraulic fracture technique which creates a network of open channels within the created fracture has recently been introduced to the oil and gas industry with over 1400 successful treatment stages pumped in other ultra-low permeability, gas-bearing unconventional reservoirs. Channel fracturing boasts higher fracture conductivity and better fracture cleanup amongst its other claims. This paper reviews the applicability of the novel hydraulic fracturing technique in the Marcellus shale and details a case study investigating the possible production gains that may be obtained when channel fracturing is applied in this play.This feasibility study briefly describes the Channel Hydraulic Fracturing technique and investigates the geophysical properties of the Marcellus shale to see if Channel fracturing is applicable in the play. The methods employed involves analyzing over 160 well logs spread across the Marcellus shale in order to create a grid map of counties and regions within the Marcellus Shale area that meet the criteria required for the applicability of the new technology. The technique is then compared to conventional hydraulic fracturing by reviewing initial production results from a Marcellus well with a conventional hydraulic fracture and performing production analysis and history matching using a production analysis software package. The conventional hydraulic fracture parameters are then replaced with channel fracturing parameters to obtain incremental production estimates.The results of the study indicate that the Channel Fracturing technique is applicable without in most areas of the Marcellus shale play. The results of the simulation and case study show increased gas production from the new technique over conventional fracturing methods.

Horizontal wells drilled in unconventional gas reservoirs are often completed by combining multiple perforation clusters in a hydraulic fracture treatment stage. Each treatment stage is typically prevented from communicating by using an isolation plug. It is a challenge to design a limited entry completion that comprehensively ensures that all perforation clusters are equally stimulated within a treatment stage (Miller et al, 2011, Mcdaniel et al, 1999. Slippage or failure of isolation plugs have also been known to occur during treatment execution and in many cases, these failures are discovered only after the well stimulation has been completed. This paper presents three case studies in the Marcellus Shale where real-time microseismic Hydraulic Fracture Monitoring (HFM) was used to evaluate the behavior and development of the induced fracture and a need for the corrective intervention was observed. In one of the cases, an innovative corrective action was implemented and microseismic results show that the intervention was successful.This study shows how real-time microseismic monitoring can been used for not only evaluating fracture geometry and azimuth but can also be used as a diagnostic tool for observing operational failures in completion tools as well as making real-time changes to completion design in order to improve completion efficiency. Some of the potential failures that may be diagnosed using HFM analyzed in this study include loss of isolation between hydraulic fracture stages, breach in casing integrity, poor cement bond in annulus and confirmation of plug ball seating.The first case study describes a hydraulic fracture treatment where the real-time HFM interpretation was useful in identifying a failure in the isolation plug between completion stages. This observation during the treatment execution was later confirmed by tagging the depth of the plug during coiled tubing operations. A production log was also run in the well and showed limited production contribution from the stage with the plug failure. The other two case studies address the use of real-time HFM interpretation to identify undesired fracture growth into an already stimulated region. Subsequent intervention by using an isolation plug between perforation clusters as a means of diversion was implemented in one of the cases.These examples clearly show how real-time microseismic monitoring can be used to adapt conventional completion designs to the dynamic nature of completion operations in the field. The paper also highlights the innovative use of an isolation plug as a diversion mechanism during fracture treatment.

In multi-fractured horizontal wells, the wellbore is segmented into stages that are stimulated separately. This segmentation is traditionally geometrically based on a specific stage length ("geometric staging"); which is usually determined by trial and error including cost and production history considerations. However, this approach does not take geological and geomechanical properties into account. An alternative method for staging ("engineered staging") uses these properties to determine the wellbore segmentation by grouping intervals with similar rock properties together; theoretically promoting a higher percentage of stimulated clusters and subsequently better production. This alternative method is not commonly used as data acquisition can be costly for a large group of wells. In Pennsylvania, two pairs of wells were completed in order to understand the added value of engineered staging design. In one of them, a comprehensive suite of openhole logs was run in the horizontal leg of a dry gas well. The staging was then designed according to the measured rock properties and the well was stimulated using slickwater with plug and perf. Finally, a production log was run in the well after a year in order to determine the downhole contribution of each stage and cluster. After 400 days of production, the well cumulative production outperforms its offset with geometric staging by around 5 to 7%, potentially attributable to the engineered design but still within the expected statistical regional deviation between wells. Long term impact is yet to be determined. In the other pair, no openhole log other than MWD Gamma-ray was run. However properties were projected from a nearby vertical pilot hole with logs onto the horizontal section of a well which was then completed using the engineered staging method. Here again production figures after a year are showing a potential benefit; but this time without the cost of data acquisition in the lateral. This paper describes the process that was applied to achieve the engineered staging of these wells. It details the initial geological and geomechanical data acquisition or projection; then describes the design of the hydraulic fracturing engineered staging and finally discusses the performance of the wells.

The Medina is a group of Silurian-age sandstone formations that have been dependable gas producing zones in Western New York since the late 1800's. Most of the production from the Medina has come from a combination of the Whirlpool and Grimsby formations. The method of how to most effectively complete these two formations is an ongoing topic of debate. The formations are separated by the Cabot Head shale formation that ranges in thickness from less than 5 feet to more than 70 feet in some places. One of the main questions with regard to completion of these formations is whether to 1) stimulate the Whirlpool and the Grimsby with separate treatments to ensure effective stimulation of both layers; or 2) stimulate both formations with one hydraulic fracture treatment, at a lower cost, that grows from the Grimsby through the Cabot Head and into the Whirlpool.Microseismic monitoring of hydraulic fracture treatments is now a proven technique used to analyze hydraulic fracture geometry and azimuth. The New York State Energy Research and Development Authority funded a project in Chautauqua County, New York to use this technology to monitor a hydraulic fracture treatment in a Grimsby/Whirlpool well for the purpose of understanding hydraulic fracture development in these formations. This paper uses the microseismic results obtained from the study to validate a hydraulic fracture model of the Grimsby/Whirlpool formations. A sensitivity analysis was then performed using this hydraulic fracture model to give direction as to when the Grimsby and Whirlpool formations should be stimulated simultaneously and when a two-stage completion would be more beneficial to obtain an effective stimulation in both zones.