Committee Overview

The EMD Tight Oil and Gas Committee (formerly the Shale Gas & Liquids and Tight Gas Sands Committees) provides AAPG members with an outlet for technical information related to shale oil and gas as well as associated condensate resources and produces annual reports summarizing current information on the largest developed and developing plays in U.S. and international basins. Tight oil and gas or “shale” resources have been the focus of extensive development over the past 15+ years due to improvements in engineering, stimulation technology, recovery, and the abundance of reservoirs. International interests in developing unconventional hydrocarbon reservoirs continue to grow, with active exploration projects on most continents, but most of the successful development of and production from shales continues to be in North America. The success of shale liquid plays in the Permian Basin and the Bakken and Eagle Ford Shales have led to a reversal in U.S. oil production after 20 years of decline.

- Lucy Ko and Justin Birdwell

Shale Oil and Gas Resources – An Introduction

By Neil Fishman

Hydrocarbon production from deep, hydrocarbon-rich shale formations, known as “shale oil and/or gas,” is one of the most quickly expanding trends in onshore domestic oil and gas exploration. Recent activities in North America have demonstrated a wide distribution of these shales containing vast resources of natural oil and gas. Shale traditionally has been regarded as a hydrocarbon source rock or seal. Following applied research and experimentation by government, academia and industry over the past few decades, shales currently are recognized as complex oil and gas reservoirs that require unconventional thinking to produce hydrocarbons. It has taken many decades to reach the current understanding of how gas is stored in coal beds and how to produce the gas (coalbed methane). In many ways, shales are even more complex than coals, and our knowledge of shale-oil and gas production is still at the beginning of the learning curve.

Definition of Shale Gas and Liquids

Petroleum resource shales are thought of dually as hydrocarbon source rocks and fine-grained tight oil and gas reservoirs. Economic shale plays include both a hydrocarbon source rock for the source of methane (thermogenic and/or biogenic) and hydrocarbon gases and oils and a brittle lithology that contains natural and induced fractures that provide permeability to access the oil and gas-storage sites. Lacking either a source of hydrocarbon or permeability will result in an uneconomic play.

Even though shale makes up much of the rock record, not all shales will be economic. The best oil and gas shales are organic-rich black shales commonly in the oil and gas window, but with some important exceptions. Most gas shales contain oil-generative organic matter (e.g., Type II kerogen) in quantities (measured as Total Organic Carbon content) high enough to generate commercial quantities of hydrocarbons. In addition to free oil and gas stored in pores and fractures, shales also contain dissolved and sorbed (adsorbed and absorbed) phases associated with the organics and in solution.

History of Oil and Gas Shales

According to Curtis (2002), the first commercial gas well in the U.S. was completed in the organic-rich Dunkirk Shale (Devonian) in New York in 1821. Hill and Nelson (2000) estimated more than 28,000 shale-gas wells have been drilled in the U.S. since the early 1800s.

The first gas production from the Barnett Shale in the Fort Worth Basin was in 1981 by Mitchell Energy and Development Corporation (Curtis, 2002). Until the success of the Barnett Shale, it was thought that natural fractures needed to be present in gas shales. Low-permeability gas-shale plays are currently viewed as technological plays where advances in horizontal drilling, fracture stimulation and multiple frac stages, micro-seismic fracture mapping, simul-fracs, and the application of 3-D seismic have contributed to the success of shale wells.

Oil- and Gas-Shale Reservoirs and Technology

It cannot be emphasized enough that tight oil and gas shales are complex petroleum systems and generalizations have limited application. Having said that, some of the generalized lessons learned about tight oil and gas shales from recent presentations and articles are as follows:

• Tight oil and gas shales require fractures as permeability pathways for fluid flow. Fractures can be either natural or induced. Orientation, extent, type, and frequency of fractures need to be studied and understood.
• Mineralogy and texture of shales are important for fracture generation. Fractures are more prevalent and created more easily in silica-rich and carbonate-rich shales than in clay-rich shales. Mineralogy alone may make or break a shale play lacking innovative completion technology with particular attention to frac fluid types.
• Tight oil and gas shales drainage area depends on the extent of fracture development (permeability) and whether the well is vertical or horizontal. In general, drainage area for a vertical well is considered to be on the order of tens of acres with well spacing of 10-27 acres. Horizontal wells push this drainage area along the length of the lateral. Drainage area is an ongoing concern and area of research.
• Type II kerogen (oil-generative organic matter) is the predominant type of organic matter in current shale plays.
• Liquid hydrocarbons and water are detrimental to a gas-shale play.

Concerning minimum requirements, some parameters may be interchangeable or are too variable to specify:

• Thickness (although 50 ft has been suggested as a minimum thickness, it depends on many variables, including economics).
• Depth (what are the minimum and maximum economic depth limits?).
• Pressure (what is the importance of pressure, from hydrostatic to overpressured, to drive gas production?).
• Organic matter type (kerogen type) and quantity (total organic carbon) limits.
• Thermal maturity (minimum and maximum limits; optimum range?).
• Phase diagram and enveloped (miscible one phase or immiscible two phase?)
• Gas type (biogenic, thermogenic, or mixed).
• Gas content (measurement methods; acceptable range?) and gas composition