Horizontal cased hole completions have become the accepted practice for completing wells in many shale gas plays. There has been a great deal of focus on how to optimize these completions. One of the most important, yet least discussed, concepts in horizontal shale completion optimization strategies is how to perforate to optimize for both placement efficiency of the hydraulic fracture treatment as well as production. Some of the perforation scheme characteristics that typically need consideration are as follows: The number of perforation clusters for each fracture stage The optimum number of perforations per cluster The distance between perforation clusters The length of each perforated interval Shot density, phasing and perforation charge type Optimal location to place the clusters Taking into account all of these considerations and using an optimized perforation strategy can be the difference between placing a fracture as per design or experiencing high treatment pressures throughout the stimulation treatment and prematurely aborting the job part way through. Even more importantly, properly engineered perforations can improve overall production by ensuring an equal fracture treatment through each perforation cluster as well as improving wellbore connectivity to the fracture. This paper looks at all these outlined aspects through a number of different means including a literature review, the use of simulation tools, and case studies from the Marcellus shale. Ultimately, a strategy for optimized perforations is presented with specific focus on shale gas horizontal wells in the Marcellus with further application to other shale gas plays.

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.

To complete the Marcellus shale's horizontal wells simply and cost-effectively, operators typically use geometric perforation designs in order to prepare for hydraulic fracturing. With this technique, perforation clusters are placed at equidistant points along the lateral. However, microseismic monitoring shows that this type of stage selection often distributes hydraulic fracturing treatments unevenly. The fracture treatments propagate to the lowest-stress intervals, leaving a large number of perforations under stimulated or simply unstimulated. In an attempt to improve on this technique, a study was performed in which wells using an engineered perforation design were compared against offset wells that had a geometric perforation design. For the wells employing an engineered design, an acoustic scanning tool was deployed on wireline and mechanical rock properties were obtained along the length of the productive lateral. The critical well information, including in situ stress, lithology, Young's modulus, and Poissons Ratio enabled engineers to create custom staging and perforating designs. These designs were optimized to provide more consistent stimulation along the entire lateral, and lower breakdown and treating pressures. The final result of using the engineered perforation design was a significant increase in production when compared to conventionally completed wells. During the stimulation treatment of the engineered perforation design, there was a significant drop in the average treating pressures during fracturing when compared to geometric offsets. This was due to several factors including the fact that perforations targeted lower stress intervals. In addition to lower pressures, an elimination of premature job terminations or "screen-outs" was seen. This occurs when pressures increase to such a degree that the stimulation treatment cannot continue within acceptable pressure ranges. Previous treatments in offset wells yielded a 35% screen out rate which resulted in significant lost time and additional costs. The process and production results of wells completed with geometric perforations to wells with engineered perforations.

Integrating logging-while-drilling (LWD) measurements with pilot well log data and 3D seismic data provides a more accurate predictive mapping of unconventional reservoir properties than evaluations from the individual measurements alone. In this project, the final probability of drilling in a zone of good reservoir quality, as defined by the seismic attributes, had the highest correlation with production of any spatially mappable variable and provided the operator with a ranking of potential drilling locations. This link between production drivers and causal mechanisms allows optimal decision making, partly by distinguishing reservoir quality variation, which cannot be controlled, from operational behavior, which can be modified; untangling these two can mean optimal use of capital resources to exploit these challenging reservoirs. Fast shearHoriz shear slowness perpendicular to borehole Matrix, J 1 , and J 2 fractures 0.51 DTSH--FAST DTCO Well PathNuclear J 2 J 1

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.