Summary Ultralow-permeability shale reservoirs require a large fracture network to maximize well performance. Microseismic fracture mapping has shown that large fracture networks can be generated in many shale reservoirs. In conventional reservoirs and tight gas sands, single-plane-fracture half-length and conductivity are the key drivers for stimulation performance. In shale reservoirs, where complex network structures in multiple planes are created, the concepts of single-fracture half-length and conductivity are insufficient to describe stimulation performance. This is the reason for the concept of using stimulated reservoir volume (SRV) as a correlation parameter for well performance. The size of the created fracture network can be approximated as the 3D volume (stimulated reservoir volume) of the microseismic-event cloud. This paper briefly illustrates how the SRV can be estimated from microseismic-mapping data and is then related to total injected-fluid volume and well performance. While the effectively producing network could be smaller by some proportion, it is assumed that the created and the effective network are directly related. However, SRV is not the only driver of well performance. Fracture spacing and conductivity within a given SRV are just as important, and this paper illustrates how both SRV and fracture spacing for a given conductivity can affect production acceleration and ultimate recovery. The effect of fracture conductivity is discussed separately in a series of companion papers. Simulated-production data are then compared with actual field results to demonstrate variability in well performance and how this concept can be used to improve completion design, well spacing, and placement strategies.

Ultra-low permeability shale reservoirs require a large fracture network to maximize well performance. Microseismic fracture mapping has shown that large fracture networks can be generated in many shale reservoirs. In conventional reservoirs and tight gas sands, single-plane fracture half-length and conductivity are the key drivers for stimulation performance. In shale reservoirs, where complex network structures in multiple planes are created, the concept of a single fracture half-length and conductivity are insufficient to describe stimulation performance. This is the reason for the concept of using stimulated reservoir volume as a correlation parameter for well performance. The size of the created fracture network can be approximated as the 3-D volume (Stimulated Reservoir Volume or SRV) of the microseismic event cloud. This paper briefly illustrates how the Stimulated Reservoir Volume (SRV) can be estimated from microseismic mapping data and is then related to total injected fluid volume and well performance. While the effectively producing network could be smaller by some proportion, it is assumed that created and effective network are directly related. However, SRV is not the only driver of well performance. Fracture spacing and conductivity within a given SRV are just as important and this paper illustrates how both SRV and fracture spacing for a given conductivity can affect production acceleration and ultimate recovery. The effect of fracture conductivity is discussed separately in a series of companion papers. Simulated production data is then compared with actual field results to demonstrate variability in well performance and how this concept can be used to improve completion design, and well spacing and placement strategies. Introduction Fisher et al. (2002), Maxwell et al. (2002), and Fischer et al. (2004) were the first papers to discuss the creation of large fracture networks in the Barnett shale and show initial relationships between treatment size, network size and shape, and production response. Microseismic fracture mapping results indicated that the fracture network size was related to the stimulation treatment volume. Figure 1 shows the relationship between treatment volume and fracture network size for five vertical Barnett wells, showing that large treatment sizes resulted in larger fracture networks. It was observed that as fracture network size and complexity increase, the volume of reservoir stimulated also increases. Fisher et al. (2004) detailed microseismic fracture mapping results for horizontal wells in the Barnett shale. This work illustrated that production is directly related to the reservoir volume stimulated during the fracture treatments. In vertical wells, larger treatments are the primary way to increase fracture network size and complexity. Horizontal well geometry provides other optimization opportunities. Longer laterals and more stimulation stages can also be used to increase fracture network size and stimulated reservoir volume. Mayerhofer et al. (2006) performed numerical reservoir simulations to understand the impact of fracture network properties such as SRV on well performance. The paper also showed that well performance can be related to very long effective fractures forming a network inside a very tight shale matrix of 100 nano-darcies or less.

Summary Rising commodity prices have resulted in an increase in secondary recovery projects that are associated with lower permeability reservoirs. These processes often inject fluids above the parting pressure for the duration of the life of the flood, and pressurization takes place as fluids leak off from the exposed surface area of the induced fracture into the surrounding moderate or low-permeability reservoir matrix. The primary difference between these situations and conventional flooding is that matrix fluid migration is initiating off an induced fracturing plane, as opposed to point-source initiation. During the early history of a flood, mass-balance issues are often ignored, as average reservoir pressures are typically low, and injection rates can dramatically exceed production. As pressures rise, some localized portions of the reservoir not only can exceed virgin static pressures, but volumes near existing induced fractures can approach or equal the pressure in those fractures. When this occurs, vertical fracturing initiates within the reservoir, and can migrate either above or below the reservoir, depending upon the location of the closest lower stress interval. A new method to detect the location of vertical "leakage" has been developed. This method uses existing surface tiltmeter (STM) technologies and a new surface deformation calculation regime to zero in on volumetric changes that occur above or below the limits of the given reservoir. This method uses measured surface deformation from observed tilt to extrapolate the volumetric change at different specified depths. With a number of constraints and using a linear geophysical model based on poroelastic equations, an inversion routine is used to find the reservoir compaction or expansion at different depths. When volumetric change best fits the measured deformation data (or tilt) at the surface, the depth and aerial location is then correlated to the area near a specific well or wells.

For many years, local industry consensus and various authors1,2,3 have concluded that with few exceptions4, fracture-stimulation of the Morrow sand series in southeastern New Mexico is best undertaken utilizing fluids containing [at least] CO2, KCl, and methanol. Unfortunately, this conclusion originates from hearsay and limited studies that looked at only a few treatments. Difficulties with past efforts to verify and compare post-fracture well performance were centered on the inability to database naturally-occurring parameters for the majority of wells, as well as problems stemming from inaccurate and erroneous public data. Localized successes with foams containing CO2, KCl, nitrogen, and methanol prompted a more comprehensive study of the area that attempted to address the problems associated with the evaluation of public production data. A Graphical Information System5 was coupled with publicly available production data and internal pumping service company records6 to attempt to determine if one completion methodology was really any better than another. Production from wells treated with Binary foams over a four-year period (1996 - 1999) was compared to production from up to 19 offsets per well of interest. A set of relatively rigid criteria was set up and followed to ensure that the study was as objective as possible, given the constraints of working with public data. Although it was not possible to "normalize" the wells of interest or their offsets to account for differences in natural parameters, the large number of wells examined provided some degree of confidence in the validity of the process. Conclusions are presented. The average first 90-day cumulative production from wells treated with Binary foam was higher than the average of wells that were stimulated with other systems. Evidence is also presented to suggest that it may be prudent to fracture-stimulate wells with high initial natural production. Introduction The Morrow formation in southeastern New Mexico is a Pennsylvanian gas sand that can be relatively prolific in certain areas of Chaves, Lea and Eddy Counties. Reserve estimates are in excess of 10 trillion cubic feet of gas and about 100 million barrels of oil and/or condensate1. Complex vertical sequences of sandstone reservoirs are present that can vary substantially, due to the lateral shifting of the various high-energy depositional environments over time. Siliciclastics originating from the Pedernal uplift in the northwest and Central Basin platform to the east were deposited in channels and along a rapidly shifting shoreline.7 Over time, trapping of mobile fluids was accomplished by lower-energy deposition of Atoka and Strawn sediments. Productive hydrocarbon traps are typically from permeability pinchouts within alluvial plains, transitional marine, channel, and shoreline facies. Variability of the Morrow can be illustrated in several ways. Formation depths range from 8,000 to 15,000 feet across the three-county area. Net zone thickness can be from just a few feet to as high as 50 feet or more, and can be present multiple times in a complex vertical series of facies.Individual wells can have several distinct zones in which each zone originated from a unique deposition. Productive resevoir porosities have ranged from 4 to 15%. Permeabilities of producing zones have been reported from hundreths of a millidarcy to several hundred millidarcies. Pressure gradients can range from underpressured reservoirs at 0.3 psi/ft to overpressured sands at 0.6 psi/ft8. Morrow sands can be described as well consolidated, white angular to sub-angular, coarse grains containing various quantities of calcareous and glauconitic material. X-Ray diffraction and SEM analysis on sidewall and full cores have revealed typical mineral content8 from the major mineral types as follows:Quartz content from 45% to 98%Carbonate content from 8 to 48%Feldspar content from 2 to 15%Clay content from 0.5 to 28%

fax 01-972-952-9435. AbstractFort Worth Basin Barnett Shale fiscal success and completion methodology have matured to the point that analog plays all over the North American continent are being actively sought and tested. It is probable that additional potential plays outside the current active areas exist, and that sufficient infrastructure may be present (or could be present) to develop them.Low permeability shale gas extraction has only become generally commercial over the last five to six years. Finding and developing this type of reservoir involves matching a number of naturally occurring parameters with an extraction process that is both detailed and capital intensive. This paper will address the natural parameters that must be present for a commercial play to be viable. It will cover the latest process and engineering improvements (stimulation and other completion issues) that have shown to improve the overall net present value of the various properties. Wildcatting strategies will be addressed, including minimizing "science" costs and reducing the time required to advance up a given learning curve.