Abstract The Haynesville Shale in northwest Louisiana and east Texas is a geologically unique gas play in which many petrophysical, engineering, and mechanical properties are close to optimal. With high geopressure gradients ranging from 0.8 to >0.95 psi/ft and reservoir pressures ranging from 8000 to 17,000 psi, it is one of the most prolific shale-gas plays in North America. Through the use of horizontal wells and multiple-stage fracturing, gas production reached >7 Bcf/d in August 2011, and the play has surpassed the Barnett Shale in north Texas as one of the highest gas-producing plays in the United States. The objectives of this study are to investigate the effects of petrophysical, geochemical, geologic, mechanical, and engineering properties, as well as completion practices, on Haynesville Shale production. Core data show that connate water saturations range from 15 to 40% in the Haynesville. Low connate water saturation is attributed to water expulsion by oil and gas during hydrocarbon generation from organic matter within the shale. Nevertheless, slow fluid escape and gas generation at high temperatures resulted in an abnormally high reservoir pressure and pressure gradient, even in this relatively high porosity rock. The effects of the high geopressure gradient have been to increase reservoir pore pressure, to preserve porosity and permeability, and to enhance free gas content and the brittle nature of the gas shales. The average porosity of the Haynesville Shale is high, ~11%, and the free gas content is enhanced by high porosity and gas density. Because of the high formation pressures, effective stresses of the Haynesville are low, and laboratory compression tests show that the rocks are highly brittle at these low effective stresses. Production from the Haynesville is a complex function of geopressure gradient, effective stress, reservoir quality, and completion practices. A wide range of completion parameters, such as length of horizontal well, choke size, number of stages, and proppant volume, have been tested to find optimal production strategies. Large choke sizes, which increase initial potential, can have a detrimental effect on long-term production and smaller choke sizes lower the decline rates and increase long-term well productions. Initial potential and production are higher in the east and south regions with higher pressure, carbonate/silica content and total organic carbon than the northwest region in Texas with lower total organic carbon but higher clay content.

Abstract Successful production performances from shale resources in North America have generated broad interests in several intriguing properties, such as organic-matter pore network, wettability, connate-water saturation, geopressure gradient, and brittleness. Although poorly understood, unique characteristics of these properties can have profound impacts on storage capacity, fluid flow, and production. Objectives of this study were to investigate potential effects of organic-matter pore network, wettability, low connate-water saturation, geopressure gradient, and effective stress on properties of organic-rich shales as well as fluid flow through shale reservoirs.

Abstract Simulation studies and three-dimensional (3-D) reservoir modeling were conducted as part of an integrated geologie, petrophysical, and geophysical effort to better define the distribution of remaining oil and the opportunities for a more effective recovery of remaining hydrocarbons. Two 3-D reservoir models—a 2000-ac window model and a fieldwide model—were built using a cycle-based geologic framework and rock-fabric–dependent petrophysical properties. A comprehensive sensitivity study on volumetrics was conducted using the fieldwide model, and reservoir simulation was performed in a 1600-ac area in the window model. Original oil in place (OOIP) is a complex function of log-data quality, mapping parameters, vertical resolution of the 3-D grid, oil-water contact, and cutoff values in porosity, permeability, and water saturation. The high vertical-resolution 3-D model calculates higher OOIP than the 36-layer cycle-based model by 8 to 30%, depending on the cutoff criteria. Because permeability is a function of porosity and rock fabric, the permeability cutoff is equivalent to rock-fabric-dependent porosity or water saturation cutoffs and is less sensitive to grid vertical resolution than porosity and water saturation cutoffs. The simulation study was divided into two phases: sensitivity analysis and history matching. The sensitivity study was used to evaluate and rank the importance of reservoir parameters affecting production performance. During simulation, oil relative permeability for primary recovery has a strong effect on recovery from waterflooding. Because fractures and breccias are common in testing and core data, negative skin factors (or effective wellbore radii) were used to simulate near-wellbore fractures, and permeability values in the lower Wichita were modified to simulate karst-related breccias. Through history matching, optimal fluid and rock properties were determined.

ABSTRACT In carbonate-ramp reservoirs, stacking of rock-fabric facies within a high-frequency, sequence stratigraphic framework provides the most accurate framework for displaying the distribution of petrophysical rock properties of porosity, permeability, relative permeability, and capillarity. Rock-fabric facies are defined on the basis of grain and crystal size and sorting, interparticle porosity, separate-vug porosity, and the presence or absence of touching vugs. Outcrop geostatistical studies of the Algerita Escarpment suggest little spatial correlation of permeability within rock-fabric facies, and petrophysical properties can be averaged at rock-fabric-facies scale. An outcrop reservoir model has been constructed by mapping rock-fabric facies and using average petrophysical values for each rock-fabric facies. Experimental waterflood simulations show that performance depends upon the stacking of the rock-fabric facies, the dense layers, and the location of production and injection wells. In the subsurface, high-frequency cycles can be observed in cores and calibrated with wireline log response. Grain and crystal size and sorting and separate-vug porosity can be determined from gamma-ray, porosity, acoustic, and resistivity logs. Permeability profiles can be calculated using rock-fabric-specific transforms between interparticle porosity and permeability. A reservoir model of part of the Seminole San Andres Field was constructed using these methods. Three-dimensional waterflood simulations using this model result in a more realistic display of remaining oil saturation than the traditional layered model and show the importance of thin, dense mud layers in controlling vertical migration.