Eagle Ford Shale Prospecting with 3D Seismic Data within a Tectonic and Depositional System Framework

20 January, 2012
Who Should Attend
This e-symposium is ideal for individuals and organizations involved in the Eagle Ford Shale Play.
Objectives

Course Content

The Eagle Ford Shale in South Texas is one of the more exciting shale plays in the United States at the current time. Recently published reports of well tests describe gas well rates exceeding 17 mmcf/d and oil well rates in excess of 1500 bopd and unconfirmed rates of 2000 bopd. Acreage lease rates continue to climb as more positive results come from drilling within the trend. A key issue for the exploration companies is finding where to focus acreage acquisition and optimize drilling plans for optimal gas and oil recovery. Our paper will first consider the geologic context of the Eagle Ford and then look at geophysical techniques, in particular, comparing and contrasting the value of 3D Processing seismic attributes in building a successful exploration plan.

Conventional subsurface data, such as wireline logs, cores and cuttings, are limited in availability to many companies currently exploring the play. Interpretation of these data is often ambiguous at best. As a result, thorough understanding of the regional aspects of the play remains elusive to many companies. It is our belief that modern seismic data and interpretation techniques can add significantly to the database and greatly enhance regional understanding of the play for many companies. Newly acquired 3D datasets provide a continuous characterization of the subsurface, which highlights drilling hazards (faults), and also offers the potential for identifying better reservoir quality intervals (higher TOC shale sections with greater porosity and fractures). Extracting rock properties from the seismic should be the goal of any processing and interpretation effort. Linking the results of well tests to the attributes derived from the seismic will provide operators with a far more reliable predictive capability in any shale play.

Ultimately, the pursuit of Eagle Ford acreage and the designing of an Eagle Ford drilling campaign is best accomplished through a comprehensive understanding of the geologic framework coupled with a focused interpretation of the seismic. This shale is one of the more exciting domestic shale plays, and presents ample opportunities to make and lose money. The smart operator will utilize all the tools available to study the target section while recognizing the limitations of the technology.

Key Topics will include:

  • Seismic data
  • Heterogeneities in the Eagle Ford
  • Isochron and Isopach maps
  • Coherence and curvature attributes
  • Lineaments associated with small-throw faults and possible fracture trends
  • Seismic data offer a number of opportunities to understand potential heterogeneities in the Eagle Ford
  • Amplitude variation implications
  • Full azimuth data
  • Long offsets
  • High frequency / High fold data

Structure of the E-Symposium

Each e-symposium consists of one-hour live e-symposium, along with material for one full day of independent study. The live portion will be followed by a full day of independent study (not a live event). The one-hour live e-symposium can be accessed from any computer anywhere in the world using a high-speed internet connection. After the event is over, you will receive via email information about accessing the asynchronous segment (not live) which consists of your independent study materials, to be accessed and studied at any time. You will be able to email responses to the readings, along with your study question answers for CEU credit (if you sign up for the extended package).

Price Includes: Recording of original webinar, packet of independent study reading materials, PDF of original PowerPoint presentation by FTP download. (Original presentation date: January 20, 2012.) Some materials will also sent by e-mail.

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Original Presentation Slide Deck Download
Understanding Production from Eagle Ford-Austin Chalk System
Ron Martin, SPE, Jason Baihly, SPE, Raj Malpani, SPE, Garrett Lindsay, SPE, and W. Keith Atwood, SPE, Schlumberger
Download
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
Download
Eagle Ford Shale Prospecting With 3D Seismic Data
Galen Treadgold, Bill McLain, Weinman GeoScience/ Global Geophysical; Steven Sinclair, Matador Resources Company
Download
Petrophysical Characterization of the Eagle Ford Shale in South Texas
J. Mullen, SPE, Halliburton
Download
Articles With Abstracts
Eagle Ford Shale Prospecting With 3D Seismic Data Within a Tectonic and Depositional System Framework (In Reservoir Characterization)
Galen Treadgold, Bruce Campbell, Bill McLain, Steven Sinclair, and David Nicklin
Download

Abstract:

Leading Edge (Tulsa, OK) (January 2011), 30(1):48-53

The south Texas Eagle Ford shale formation in is an important emerging shale play in the United States. More than 1510 wells have either been drilled or permitted in the play. What has emerged is a well-defined downdip gas play that transitions rapidly updip into less well-defined wet gas and oil fairways. With initial gas well rates exceeding 17 million cubic feet per day and initial oil well rates in excess of 1000 barrels of oil per day common in the expanding play, exploration companies are pursuing methods to optimize drilling plans. Limited well and core data describing the Eagle Ford require the use of 3D seismic to help characterize reservoir quality variations, avoid drilling hazards, and help predict sweet spots. Modern, long-offset, full-azimuth 3D is an essential tool for building a geophysical description of the shale between wells. Anisotropic time imaging, feeding both acoustic and elastic inversions, is helping operators gain better insight into the reservoir's variability. The following discussion highlights components of an ongoing effort to extract value from seismic data in shale prospecting. Unfortunately, limited well data for calibration, as in many immature shale plays, remains the primary constraint on confident linkage between the actual reservoir quality and seismic measurements.

Onshore Wave-Equation Depth Imaging and Velocity Model Building (In Reverse Time Migration)
Joe Higginbotham, Morgan Brown, Cosmin Macesanu, and Oscar Ramirez
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Abstract:

Leading Edge (Tulsa, OK) (November 2010), 29(11):1386-1392

The most advanced prestack depth-migration (PSDM) technologies available today, such as wave-equation migration (WEM) and reverse time migration (RTM), are primarily used for offshore applications like subsalt imaging. However, E&P efforts in many onshore basins can also benefit from PSDM, and there is considerable momentum in many basins to adopt this technology as the default imaging tool (Young et al., 2009). This paper highlights the application of wave-equation depth-imaging technologies (WEM and RTM) with several onshore U.S. case studies. Below we list some benefits that users of PSDM technology might expect to enjoy.

Assessment of Undiscovered Conventional Oil and Gas Resources, Onshore Claiborne Group, United States Part of the Northern Gulf of Mexico Basin
Paul C. Hackley and Thomas E. Ewing
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Abstract:

AAPG Bulletin (October 2010), 94(10):1607-1636

The middle Eocene Claiborne Group was assessed for undiscovered conventional hydrocarbon resources using established U.S. Geological Survey assessment methodology. This work was conducted as part of a 2007 assessment of Paleogene-Neogene strata of the northern Gulf of Mexico Basin, including the United States onshore and state waters (Dubiel et al., 2007). The assessed area is within the Upper Jurassic-Cretaceous-Tertiary composite total petroleum system, which was defined for the assessment. Source rocks for Claiborne oil accumulations are interpreted to be organic-rich, downdip, shaley facies of the Wilcox Group and the Sparta Sand of the Claiborne Group; gas accumulations may have originated from multiple sources, including the Jurassic Smackover Formation and the Haynesville and Bossier shales, the Cretaceous Eagle Ford and Pearsall (?) formations, and the Paleogene Wilcox Group and Sparta Sand. Hydrocarbon generation in the basin started prior to deposition of Claiborne sediments and is currently ongoing. Primary reservoir sandstones in the Claiborne Group include, from oldest to youngest, the Queen City Sand, Cook Mountain Formation, Sparta Sand, Yegua Formation, and the laterally equivalent Cockfield Formation. A geologic model, supported by spatial analysis of petroleum geology data, including discovered reservoir depths, thicknesses, temperatures, porosities, permeabilities, and pressures, was used to divide the Claiborne Group into seven assessment units (AUs) with three distinctive structural and depositional settings. The three structural and depositional settings are (1) stable shelf, (2) expanded fault zone, and (3) slope and basin floor; the seven AUs are (1) lower Claiborne stable-shelf gas and oil, (2) lower Claiborne expanded fault-zone gas, (3) lower Claiborne slope and basin-floor gas, (4) lower Claiborne Cane River, (5) upper Claiborne stable-shelf gas and oil, (6) upper Claiborne expanded fault-zone gas, and (7) upper Claiborne slope and basin-floor gas. Based on Monte Carlo simulation of justified input parameters, the total estimated mean undiscovered conventional hydrocarbon resources in the seven AUs combined are 52 million bbl of oil, 19.145 tcf of natural gas, and 1.205 billion bbl of natural gas liquids. This article describes the conceptual geologic model used to define the seven Claiborne AUs, the characteristics of each AU, and the justification behind the input parameters used to estimate undiscovered resources for each AU. The great bulk of undiscovered hydrocarbon resources are predicted to be nonassociated gas and natural gas liquids contained in deep (mostly >12,000-ft [3658 m], present-day drilling depths), overpressured, structurally complex outer shelf or slope and basin-floor Claiborne reservoirs. The continuing development of these downdip objectives is expected to be the primary focus of exploration activity for the onshore middle Eocene Gulf Coast in the coming decades.

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$145
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Nonmember Tuition with CEU
$35
$35
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Student Tuition with CEU
$35
$35
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Displaced Professional Tuition with CEU
$30
$30
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200
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Expanded package for CEU credit is $100 for AAPG members, and $145 for non-members. Special Student Pricing: $25 for Webinar only; $35 for Expanded package.

 

Galen E. Treadgold Weinman GeoScience (a division of Global Geophysical)
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Director, Innovation and Emerging Science and Technology +1 918 560 2604
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