gas plays in the barnett shale:
Barnett Shale: A Significant Gas Resource in the Fort Worth Basin: Craig Adams
The Mississippian Barnett Shale of the Fort Worth Basin is an organic-rich shale that is the reservoir trap and seal for a very large unconventional gas accumulation. The play has rapidly spread over a multi-county area.
The Barnett Shale is a spent oil-prone source rock. Porosity and permeability is developed upon thermal transformation from liquid to gas with resulting maturation-induced micro fractures. Gas is stored in these micro fractures, as well as being adsorbed in the solid organic matter (kerogen). The exploration fairway is defined by Barnett Shale isopachs, subcrop maps, source rock richness data (Total Organic Carbon), thermal maturity defined by vitrinite reflectance and the presence of reservoir quality Barnett Shale.
The Barnett Shale is one of the most active drilling targets of the past decade. Newark East Field is now the second largest gas-producing field in Texas. Drilling depths are less than 8,000 ft, and per well reserves in the expanding Newark East Field are 1-3 BCF. Gas-in-place is 145 BCF per square mile. The Barnett Play is estimated to have 10 TCF recoverable reserves (USGS, 1998).
Low proppant hydraulic fracturing technology ("water-fracs") has greatly improved play economics. This new technology has reduced total well cost by more than 20 percent and has resulted in much-improved rate and reserve profiles. Barnett Shale wells are typically re-fraced after several years resulting in producing rates superior to initial production rates.
The Barnett Shale Play, Fort Worth Basin: Kent A. Bowker
In terms of monthly production, the Newark East (Barnett Shale) field recently became the largest gas field in Texas. Production has grown from 80 MMCF/D in January 2000 to over 560 MMCF/D at present because of accelerated new-well drilling and old-well reworks/refracs. There are over 2.5 TCF of booked proven gas reserves in the field at present. Newark East field is located in the northern portion of the Fort Worth Basin, just north of the city of Fort Worth. The Mississippian Barnett rests on an extensive angular unconformity. The Barnett must be stimulated to achieve economic flow rates. Currently, wells are hydraulically fractured, but good frac barriers must be present directly above and below the Barnett for this stimulation technique to be successful. Hence, the stratigraphy above and below the Barnett is important to economic production. The thermal history of the basin is an important reason for the success of the Barnett. The thermal history of the Fort Worth basin is directly related to the emplacement of the Ouachita system. Sections of the Barnett bordering the Ouachita front (regardless of depth) have the highest thermal maturity and, hence, the lowest BTU content of produced gas. In the late 1990s, work by Mitchell Energy had demonstrated the viability of water fracs in the Barnett play; this development has contributed to a huge acceleration in Barnett leasing and drilling activity during the past three years. Also in the late 1990s, Mitchell determined that the previous gas-in-place values for the Barnett were low by over a factor of three. There is approximately 150 BCF/mi2 of in-place gas in Newark East field. The realization that the primary completion was only recovering 7% of the gas in place per well spurred the current (and very successful) rework/refrac program underway in the field.
The history of the evolving geologic and engineering concepts that guided development of the Barnett is a tribute to rare perseverance in the oil patch. And the success of the Barnett play may provide a model for prospecting for other large shale-reservoirs.
Barnett Shale Gas-in-Place Volume Including Sorbed and Free Gas Volume: Matt Mavor
Gas contained within unconventional shale gas reservoirs is stored by sorption within micro and mesoporosity of the rock matrix and by compression within the macroporosity and natural fracture porosity of the reservoir. Mitchell Energy cored the Kathy Keel #3 Barnett Shale well (Denton Co. Texas) with conventional and pressure coring equipment in the upper and lower Barnett to obtain core samples and data to obtain data required to estimate the gas-in-place volume stored by each mechanism. An extensive suite of data was measured that included desorption of samples to determine the sorbed gas content and gas composition as well as methane and ethane sorption isotherm data to estimate the sorbed gas storage capacity.These data were combined with other shale gas core analyses including TOC content, routine porosity, grain and bulk density, water saturation, capillary pressure, x-ray diffraction, and cation exchange capacity data to develop a log analysis model that combined log and core analysis data.
The estimates of the gas-in-place volume were significantly greater than past data measured and published in 1992 by Gas Research Institute (GRI) had indicated. The volume of gas stored by sorption within the pressure core interval was 120 scf/ton at an average TOC content of 5.2% compared to GRI's estimate of roughly 42 scf/ton. The sorbed gas volume accounted for 61% of the total gas-in-place volume that included both sorbed and free gas. Free gas volume in-place was determined by log analyses methods that were calibrated to core analyses to obtain in-situ estimates of porosity and water saturation.
While the gas-in-place volume is large, recovery of the gas volume is hindered by relatively low absolute permeability of the reservoirs. Recovery of the sorbed gas-in-place requires that operating pressures be kept low as possible to allow the gas to be released from the sorbed state. Recovery factor depends upon the decline in average reservoir pressure. Calculation methods for gas recovery factor will be discussed to illustrate that recovery factor may range from 10 to 25% of the total gas-in-place volume with conventional technology.
Microseismic Mapping During Frac Stimulation in the Barnett Shale: Nick Steinsberger
The Barnett Shale in North Texas is one of many tight shale plays across the country, however, over the last two years the Newark East (Barnett Shale) field has been the most active field in the United States. With an average of 35 drilling rigs running in the Fort Worth Basin, over 2000 wells have been drilled in Wise, Denton, and Tarrant counties for the ultra tight gas. The Barnett Shale is present in most of North Texas and has been tested in more than 12 counties by more than 50 operators.
Determining Petrophysical Properties and Gas Content in the Barnett Shale Using a log-based Neural Network Solution: Lee Utley
The Barnett Shale in the Fort Worth Basin of Texas is an organic-rich black shale capable of producing large amounts of natural gas and natural gas liquids. Traditional log analysis methods have not yielded acceptable results when attempting to determine standard petrophysical properties. Therefore, log analysis alone is an impractical method of predicting production in the Barnett Shale. Production in the Barnett Shale is affected by several factors, only some of which may be measured or calculated using log data, making gas content a poor predictor of well performance. However, a neural network technique has been developed to successfully estimate reservoir potential that relies on log derived qualitative and quantitative parameters.
Log analysis in the complex lithology of the Barnett Shale is very difficult. The existence of several exotic minerals in the matrix along with significant amounts of organic material makes a algorithm-based solution virtually impossible. Using extensive core data, a neural network solution was developed to calibrate the logs to the needed petrophysical properties, and thus enable the foot-by-foot calculation of gas content of the Barnett Shale. Since any evaluation technique requires proper verification, examples will be shown to demonstrate the effectiveness of the calibration.
The logs required to perform the analysis are readily available on most wells in the Fort Worth Basin, making the solution a practical exploration/exploitation tool. Outputs from the analysis include porosity, total organic content, water saturation, lithology, and gas content, both in the sorbed and free states.
Newark East, Barnett Shale Field, Wise and Denton Counties, Texas; Barnett Shale Frac Gradient Variances: David Martineau
The Newark East, Barnett Shale Field is one of the largest producing gas fields in Texas. The initial development of the field was centered in the southeast quarter of Wise County, and, over the past 20 years the field has expanded to the north, west, to the east into Denton County and the the South in Tarrant County. With the development of the field came the increased knowledge of the nature of the reservoir, the frac gradients and the porosity zones, all of which was important in the economic development of the Barnett Shale play.
In the early development it was recognized that the Upper Barnett (+100') had a higher frac gradient (.70+) than the Lower Barnett (.50 to .60+) (+300'). As the field developed and expanded in aerial extent, it became apparent that in the north part of the field the Lower Barnett (+600') could be subdivided into five (5) ("A" thru "E") correlatable porosity units with limestones and non-bituminous calcareous shale separating the productive porosity units.
With further investigation and evaluation of the Lower Barnett it became apparent that the upper "A" and "B" porosity units could have a different frac gradient than the lower "C", "D" and "E" units in certain areas.
Even though the majority of the water frac treatments consist of two phases, one for Lower Barnett and another for Upper Barnett, certain areas of the field will require multi-stage fracs to adequately recover the true reserve potential of the Barnett Shale.
Production logs and radioactive tracer surveys have been used to evaluate the effectiveness of frac jobs covering 300' to 600' intervals, where each zone could have variances in frac gradient, fractures and/or porosities.
As the field continues to expand beyond the Viola/Ellenberger subcrop, additional new data will possibly dictate a change in frac procedure.
Assessing Undiscovered Resources of the Barnett-Paleozoic Total Petroleum System, Bend Arch-Fort Worth Basin Province: Richard M. Pollastro
Organic-rich, Barnett Shale (Mississippian) is the primary source rock for oil and gas produced from Paleozoic reservoirs in the Bend Arch-Fort Worth Basin Province. Distribution and geochemical typing of hydrocarbons in this mature petroleum province indicates generation and expulsion from the Barnett at a depocenter coincident with a paleoaxis of the Fort Worth Basin. Barnett-sourced hydrocarbons migrated westward into reservoirs of the Bend Arch and Eastern shelf; however, some oil and gas was possibly sourced by a composite Woodford-Barnett petroleum system of the Midland Basin from the west.
Current U.S. Geological assessments of undiscovered oil and gas are performed on Total Petroleum Systems (TPS) that include mature source rock, known accumulations, and area(s) of undiscovered hydrocarbon potential. The TPS is subdivided into Assessment Units based on similar geologic conditions and accumulation type. Assessment of the Barnett-Paleozoic TPS focuses particularly on the continuous Barnett accumulation. Barnett shale gas will be assessed after mapping "sweet spots" and outlying areas of potential, and by defining distributions of drainage (cell) size and cell estimated ultimate recovery. An example of a Barnett "sweet spot" is the Greater Newark East area where thick, siliceous Barnett has reached the gas window, and overlain and underlain by impermeable limestones that serve as "frac" barriers. Assessment Units are also identified for mature conventional plays in Paleozoic carbonate and clastic reservoirs, such as the Chappel Limestone pinnacle reefs and Bend Group conglomerate, respectively. However, Barnett continuous gas is expected to add the greatest volume of undiscovered, technically recoverable resource.
