Most horizontal completion methods used for Resource Plays are very challenged to either effectively place or to keep proppant in the near wellbore area; in fact, this seems to rarely be a major goal of our completion plan and/or fracture treatment designs, but can we afford to continue this? Few Resource Plays have the high rock complexity found in the Barnett Shale; each play should be developed using completions and designs relative to its own formation properties, not simply clone the Barnett completions and stimulation designs. Too often operators have chosen to force-fit what they have seen to be successful in the Barnett to a much different set of formation conditions and properties.

The pre-Barnett successes using waterfracs in tight gas non-complex formations, where the poor formation responses often seen after using large gelled fluid frac treatments on tite gas zones are now believed to be due to the severe cleanup problems from gel. Tight formations may not have adequate energy to effectively clean a large mass of gel from the proppant bed porosity, especially if underpressured. With only partial cleanup of these costly treatments, operators looked for improvements in production or reduced cost (Mayerhofer et al. 1997). Although the WaterFrac treatments placed much less proppant, with only water in it, the proppant bed could easily be cleaned to provide near 100% benefit, while gelled treatments of that timeframe placed in tight gas formations may clean up only a small percentage of the proppant placed. With the Barnett Shale, it turned out to be much more than that, as it is quite different from any other major formation being significantly drilled in the mid- to late 1990’s. The key was the massive number of small fractures present, many of which were in a "healed" state prior to fracturing. Mitchell Energy finally found the secret to unlock this complexity: Large volume, high injection rate WaterFrac treatments! The nanodarcy range insitu perm of the rock must have a massive volume of enhancement to that permeability, and they could only be adequately activated using these large volume high rate Waterfracs. By not placing any gel into this complex system, even without propping them open they could perform as a massive "gathering system" to get more gas back to the propped fractures. Soon after the Barnett proved economic with vertical completions, by moving to long horizontal completions and using large volume, high rate multi-stage fracturing applications, the Barnett proved to suddenly be one of the highest returns on investment (RoI) opportunities of the time. It soon became the field with the most rigs operating in North America. This new completion concept, using long lateral completions combined with massive multi-stage fracture stimulations, we will christen as the Shale Completion Method for discussions in this paper.

However, although we now are successfully completing economic horizontal wells in many other ultra-low perm source rock formations, there seems too often be short cuts taken in many areas that can challenge continued success away from the sweet-spots of the field, and we even accept leaving much of the recoverable hydrocarbons still in place even when the well may achieve acceptable economics. The most obvious stimulation related shortcoming is that Waterfracs have often proved to be quite inadequate as the only stimulation fluid, as only a few of these later fields have formations where we can generate massive complexity when we fracture stimulate. Fortunately, we often can develop some limited degree of complexity, and even though most all of these new source rock plays have sub-microdarcy permeability, they typically will be 10- to 30-fold higher than most Barnett shale. Operators soon moved the Shale Completion Method to the oil bearing Bakken shale in North Dakota, and soon after many more rigs followed. Next, the Shale Completion Method to low/very low perm conventional plays, with the Granite Wash in the Anadarko basin in the Texas Panhandle and western Oklahoma being an early poster child, further showcasing how old fields could be returned to boom-time drilling prospects.

Now we found ourselves needing to place fractures with far more conductivity than we needed for the Barnett shale, and needed to use fracturing fluids that could effectively place traditional proppant sizes and at least moderate proppant concentrations. In 2008-09, a significant economic downturn suddenly caused gas prices to tumble, yet global economic factors kept oil prices from falling proportionally, and operators throughout North America were forced to reduce gas well drilling and turn to oil or liquids-rich gas plays. These are plays where we need effective fracture conductivity to produce commercial rates.

Today, whether producing from RoI challenged dry gas plays, moderate-RoI gas liquids plays, or (potentially) higher RoI oil plays, all facets of our operations will either be a contributor or detractor from achieving effective fracture conductivity. This starts with initial well location choice and continues through to our long term production methods. The oil and gas plays throughout North America each need to be drilled/completed/stimulated/produced using procedures best suited to each individual play, not copied from somewhere else it appears to be successful. Achieving effective conductivity in our fractures, and ensuring those fracs have adequate connection to our wellbores is a primary factor to maintaining attractive RoI’s and to keep drilling. In this paper we will mostly look at how we can best achieve this in addition to simply using the correct proppants and fluid systems.

We can create challenges to delivering effective conductive fractures before we even spud the well and then create added challenges during drilling and add even more before it is time to try to actually place our fractures into our formations.

You can access this article if you purchase or spend a download.