After a great deal of success with Bakken open-hole horizontal completions in Richland County, Montana, between 2002 and 2005, operators began to move to the more laterally extensive North Dakota side of the Bakken play in the Williston Basin. The early results in the North Dakota Bakken were, however, much more variable than the Richland County Bakken wells. With the huge resource at stake in North Dakota, it was realized that better understanding of the nature of the formation"s transmissibility and the completion and stimulation efficiency could shorten the learning curve on the economic exploitation of this important oil resource. A consortium was therefore formed with seven operators, a major service company, the state of North Dakota and the DOE to drill and complete three science wells. In these wells, we collected extensive vertical and horizontal log and core data. At this time, two wells were completed and one well was utilized as a monitoring well. During the stimulation, several seismic arrays were deployed to map out the microseismic events, including the largest seismic array ever deployed in a horizontal well. In addition multiple isotope RA tagging and fluid chemical tagging were employed. This paper presents some of the results of this project and of the completion analysis that was done with these data and other released data in the basin. In addition, we draw some conclusions on the nature of fracture initiation along the wellbore, and attempt to provide some insight to the completion optimization.

Since the widespread proliferation micro-seismic fracture mapping, it has been observed that some naturally fractured formations exhibit a non planar or complex set of micro seismic events. This fracture mapping technique has provided some valuable insight into the nature of this complex fracturing. However, this mapping is not necessarily a direct measurement of hydraulic fracturing. Instead the microseisms are small shear failures in the rock that can be caused by changes in pressure and temperature of the formation. Therefore we cannot know with certainty if these events are directly showing us where the proppant or even the frac fluid is going. None the less, this insight to complex fracturing, has been key to improving economic recovery of many unconventional plays over the past 8 years. However much of the improvements, have been through empirical trial and error and qualitative techniques. For example it had been observed that thin fracturing fluids tended to create more complex fracturing than viscous fluids. More recently it has been observed that smaller mesh proppant may be more successful at being transported out into the multiple fracture planes of the formation than larger mesh proppant. Although this trial and error technique has been useful, it is often very slow and can be expensive, it took many years to optimize the Barnett play in the Ft. Worth basin. But even more detrimental is when a success from one basin is applied in another basin without fully understanding the underlying mechanics. This can often lead to costly disappointment. This paper reviews the key parameters that need to exist to enable complex fracturing such as:○Nature and genesis of the natural fractures.○Orientation of the minimum and maximum horizontal stress.○The juxtaposition of the natural fractures to the stresses.○Magnitude of the difference between the minimum and maximum horizontal stress.○Poisson's ratio and Young's modulus of the rock being stimulated. From this information we attempt to quantify the dilation pressure of natural fracture systems which precede complex fracturing. But in particular we attempt to investigate the mechanics of the critical intersection of these transverse fractures and how they can interfere with each other and create pinch points that can inhibit non planar proppant transport. The ultimate goal of this paper is to demonstrate a methodology for quantifying the width relationship of these intersecting fracture systems, which can be used to determine if multi planar proppant placement is possible and help design the optimum mesh size and net pressure required to enable successful placement. Introduction: As conventional resources for natural gas become depleted, unconventional resources become more and more important for meeting our natural gas energy needs. It is estimated that currently more than 7 tcf of natural gas production per year come from unconventional tight gas, coalbed methane, and shale gas1. With extremely low matrix permeability formations, natural fracture enhancement of the formation permeability becomes important and many times essential for economic exploitation. The degree of influence natural fractures have upon reservoir formation permeability, storativity and completion effectiveness varies greatly and depends upon many parameters such as the origin of the fractures, fracture digenesis, the stress on the natural fractures, and stress orientation. Unfortunately many of these parameters are not always well understood when completion and stimulation decisions are made.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDrilling activity to access natural gas production from

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fax 01-972-952-9435. AbstractPropped hydraulic fracture stimulation has been one of the primary completion methods for coalbed methane wellbores for more than twenty years. However direct fracturing of coal seams has been notoriously inefficient. High fracture pressures in coal seams, coal cleating and natural fractures can lead to shear slippage and inefficient non-planar fracturing which significantly underperforms the stimulation potential compared to conventional clastic rock fracture stimulation. In 2003 the concept of indirect fracturing was introduced to significantly increase Coalbed methane (CBM) fracturing efficiency by initiating fractures in lower stress clastic rock adjacent to coal seams and allowing these induced fractures to connect and grow into the coal seams. This paper presents several examples of the application of indirect fracturing for the stimulation of coal seams in the Rockies. This paper evaluates production results, fracture pressure analysis, as well as micro seismic results and frac tracer analysis for quantifying the effectiveness of indirect fracturing for the stimulation of CBM reservoirs. From this data we present guidelines for when and where indirect fracturing is applicable and just as important, where indirect fracturing is not appropriate. Introduction: