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Petroleum Engineering paper

Text of li_Fan_2011

  • CSUG/SPE 148751

    An Integrated Approach for Understanding Oil and Gas Reserves Potential in Eagle Ford Shale Formation Li Fan, SPE, Ron Martin, SPE, John Thompson, SPE, Keith Atwood, SPE, John Robinson, SPE, and Garrett Lindsay, SPE, Schlumberger

    Copyright 2011, Society of Petroleum Engineers This paper was prepared for presentation at the Canadian Unconventional Resources Conference held in Calgary, Alberta, Canada, 1517 November 2011. This paper was selected for presentation by a CSUG/SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

    Abstract Examples of an integrated approach for quantifying oil and gas production potential in different hydrocarbon windows of the Eagle Ford Shale are presented. The Eagle Ford basin is unique in that reservoir fluids range from black oil to dry gas depending on the geology, burial depth, and temperature. The main goal of this paper is to guide operators to an understanding of potential reserves and their distribution in the Eagle Ford through the use of our specialized analysis and methodology to estimate ultimate recoveries.

    Data from the Eagle Ford Shale was compiled and analyzed to gain knowledge about the basin. The geology aided in indentifying sweet spots based on the various thermal maturation windows. Also, recent drilling and completion activities were examined in addition to the observed production from public databases. The intent was to determine curent completion practices in different parts of the Eagle Ford and also provide insight on the relationship between geologic features and production trends. A rapid asset evaluation case study is presented to demonstrate technique and workflow that uses vintage vertical well data to provide an estimate of asset value and reserves for a typical horizontal well in the Eagle Ford.

    The results of the study identifies sweet spots of oil and gas production and indicates that 1) Eagle Ford production is related to the maturation windows, as well as structure; 2) the best wells in the Eagle Ford are in the thicker areas; 3) Austin Chalk production relates to the underlying Eagle Ford production; 4) different completions for different areas and types of hydrocarbons should be considered, and 5) data and knowledge integration is the key for rapid evaluation of asset value in the Eagle Ford Shale.

    Operators can use this information and technique to help 1) better understand the uniqueness of the Eagle Ford Shale, 2) optimize their completion design and field development plan, and 3) calibrate expectations on oil and gas reserves potential under their acreage. Introduction The Eagle Ford Shale play began in 2008 with the drilling of STS First Rock #1 located in La Salle County, Texas. The play extends over an area of approximately 11 million acresfrom the Texas border with Mexico to the eastern borders of Gonzales and Lavaca Counties as shown in Fig. 1. The southern border of the trend is subparallel the Sligo shelf edge.

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    Fig. 1Area of industry activity in the Eagle Ford Shale and associated geologic features.

    Stratigraphically (Fig. 2), the Late Cretaceous Eagle Ford formation (Lock and Peschier, 2006), lies un-conformably above

    the Buda Limestone and is overlain by the Austin Chalk.






    Fig. 2Stratigraphic column showing the Eagle Ford Shale (Dawson 2000). The Eagle Ford varies stratigraphically through Texas as a result of several changes in both structure and depositional setting. The Eagle Ford dips from the outcrop located north of the Maverick basin to the Gulf of Mexico. Along its northeast/southwest depositional trend, the formation varies in thickness from 50 ft in the northeast to more than 300 ft in the southwest. Sedimentation was influenced by the Laramide Orogeny which shed sediments into the Maverick and Hawkville basins located between the Edwards and Sligo shelf edge (Fig. 3) (Scott 2004). The formation thins to approximately 50 ft over the San Marcos arch, which is located to the northeast and is considered the eastern limit of the play in South Texas.

    The Eagle Ford Shale is one of many major source rocks that were deposited during one of two anoxic extinction events that occurred at the Cenomanian/Turonian boundary. During this event, warm seas existed throughout the world. A runaway greenhouse effect existed, which resulted in an increased carbon dioxide level and consequently increased organic productivity. Consumption by aerobic bacteria created an anoxic or oxygen-poor environment that preserved the organic material. This increase in the level of carbon accounts for the accumulation of the thick black shale deposition observed around the world.

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    Sligo shelfedge


    Black Hawk field

    Hawkville field

    Fig. 3Map of Eagle Ford Shale formation tops with key geologic features.

    Identification of Sweet Spots The Eagle Ford Shale sourced the famous East Texas field (Woodbine sands) located in the East Texas Salt basin. To the south, the prolific Austin Chalk fields were also sourced by the Eagle Ford Shale. Analysis of the outcrop and samples from well control identified kerogen types II, II/III, and III. As the Eagle Ford dips south it went through the three maturation windows (Fig. 4). Pyrolysis data confirms, for example, that the Maverick Basin is in the oil window and the Hawkville basin is at the transition point between dry gas and wet gas as the San Marcos arch is approached (Tuttle 2010; Edman et al. 2010).

    Analysis of dozens of geochemical logs and associated production in the three production windows revealed a measurement pattern that was indicative of the relative liquid yield of each well (Fig. 5). A fluid-substitution technique was used to generate a synthetic neutron response (black) in oil, gas condensate, and dry gas windows on the basis of each wells individual mineralogic composition. When compared to the recorded neutron porosity (blue) and bulk density (red) (at the point indicated by the arrows), as can be seen in examples A, B, and C in Fig. 5, likely produced fluids are readily identifiable and indexable. Magnified inserts of the log response have been included in Fig. 5 for clarity.

    The neutron density measurement is generally responsive to the type of fluid contained in the pore space. In the presence of dry gas for instance, the neutron measurement will respond to the hydrogen deficit and will provide the classical crossover signature. Theoretically, as the density of the hydrocarbon in the pore space increases, the excavation effect on the neutron will diminish. The actual response we see in the Eagle Ford is varied as a result of the variations in mineral and hydrocarbon composition. Spectroscopy data allows us to synthesize neutron responses that are calibrated to the produced fluid via fluid substitution. This provides us with a reasonable indication of what type of fluid will be produced based upon log responses.

    A study of the Eagle Ford and Austin Chalk production data related to Eagle Ford thickness and geologic features identified the best producing areas and geologic controls. A public database provided the production data for this study. Gas production data from the Austin Chalk and Eagle Ford Shale were posted on an isopach map of the Eagle Ford formation(Fig. 6). The map shows geologic features and production bubbles representing an average daily rate for the maximum-production month.

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    Fig. 4Map showing the maturation windows of the Eagle Ford.

    The best Eagle Ford gas production occurs in the Hawkville basin between the Edwards and Sligo reef trends where the

    Eagle Ford is relatively thick. Austin Chalk gas production is from the Pearsall and Gonzalez fields. We observed that Eagle Ford production beneath these fields is not as good as the production in the Hawkville area. Our conclusion is that Eagle Ford gas formed in the gas window and migrated northward to source the two fields. Continued gas generation combined with the trapping of gas in the Hawkville area created the current area of best gas production in the Eagle Ford.

    A Oil B Heavy Liquids C Dry Gas

    Fig. 5Examples of neutron log response in the three fluid windows

    Oil production for the maximum-production month (Fig. 7) was posted on the same basemap used for the gas production. Oil in the Maverick basin is found throughout the basin, with the best oil production located in the southern sector of the basin. Oil produced in the Hawkville area is from condensate-rich gas located along the northern edge of the Hawkville basin. The best oil production occurs to the northeast and is closely associated with the faulting and structuring associated with the Karnes Trough. Because of the close proximity of the Gonzalez field to the Karnes Trough, Eagle Ford oil did not migrate far from the point of generation. In the Karnes Trough, the Eagle Ford section is over 200 ft thick. Oil from co