Production Grows – As Do Areas of Concern

Oil and natural gas production continued to grow in the United States in 2013 even as progress on new federal laws and regulations stalled – but local opposition to shale gas and oil development increased.

Canadian shale gas also ballooned – to 2.8 billion cubic feet per day in May 2013 – but still lagged behind its southern neighbor. Canadian shale gas represented only 15 percent of the country’s 2012 production, but jumped to 20 percent in 2013, as per the Canada National Energy Board and U.S. Energy Information Administration (EIA).

Outside North America, a dozen countries conducted exploratory shale gas drilling – but only China reported commercially viable production, according to EIA. China’s shale gas represented only one percent of the country’s total gas production.

U.S. Production Grew

U.S. oil and natural gas production grew substantially in 2013, but low gas prices continued to shift drilling activities away from natural gas. Below are just a few statistics (EIA data) to document these patterns:

  • In 2012 shale gas was 39 percent of U.S. dry gas production, and Marcellus production was 18 percent of U.S. production. By comparison, shale gas was 28 percent of production in 2011.
  • Natural gas marketed production is projected to have increased from 69.2 Bcf/d in 2012 to 70.4 Bcf/d in 2013.
  • The Henry Hub 2013 average price ($3.69 per thousand cubic feet, mcf, est.) was significantly above 2012 ($2.65/mcf), but nowhere close to the 2008 price of almost $8/mcf.
  • The Bakken Shale produced approximately one million barrels per day in December 2013, and increased oil production from the formation contributed to September 2013 domestic oil production being almost 20 percent over September 2012.
  • Oil well completions increased 18 percent while natural gas completions declined 30 percent, and total well completions increased 6 percent (American Petroleum Institute, third quarter 2013 compared to the third quarter 2012).
Federal Regulations

President Obama stated his intent to reduce greenhouse gas emissions, including reducing methane emissions from oil and gas operations, through executive branch actions because of congressional inaction, and many expected a rush of new regulations.

The early focus of this activity has been on coal-fired power plants, and almost no federal hydraulic fracturing regulations were finalized in 2013. The inaction may reflect longer times for the White House review process, plus the difficulty in dealing with the large number of comments received when draft rules and regulations were released.

The most recent White House regulatory agenda includes:

  • The Bureau of Land Management plans to release its new hydraulic fracturing rules in May 2014.
  • EPA’s draft guidance for hydraulic fracturing using diesel is not yet scheduled for release.
  • The U.S. Coast Guard has sent a draft regulatory proposal on barge transport of flow-back fluids from hydraulic fracturing to the Office of Management and Budget (OMB).

Preliminary ideas evidently include requiring barge operators to have certification of no hazardous materials in wastewater shipments – a potentially expensive and time-consuming requirement given that the fluid comes from multiple well sites.

State, Local Bans and Regulations

Local bans on hydraulic fracturing appeared around the country in 2013; the tally is about 400 state and local bans.

State bans or moratoria have been enacted in Maryland, New Jersey, New York and Vermont.

Most of the numerous local bans have not yet taken effect, and many are currently being fought in the courts. A few examples:

  • In Pennsylvania, the state Supreme Court ruled in December that the Marcellus Shale drilling law, Act 13, which allowed companies to drill anywhere in the state without regard to local zoning laws, is unconstitutional.
  • In Colorado, four municipalities have recently banned or suspended hydraulic fracturing. Governor (and past AAPG member) John Hickenlooper has expressed the position that the municipalities lack the authority to determine the use of the state’s natural resources.

Six states have strengthened their regulation of hydraulic fracturing: California, Colorado, Ohio, Pennsylvania, Utah and Wyoming; simultaneously, the governors of energy-producing states have reiterated their opposition to federal regulation of hydraulic fracturing. In late December the governors of 12 energy-producing states sent an open letter to Washington regulators and policy makers asking that regulation be left to the states.

Federal Legislation

Many Senate and House bills have been introduced on both sides of the safety debate, to either strengthen or weaken federal regulation of hydraulic fracturing – but no legislation that would affect hydraulic fracturing has passed either the House or the Senate, let alone both.

Both last year and this year the proposed bills focused on requiring disclosure of chemicals used in hydraulic fracturing fluid, or giving states the authority to regulate hydraulic fracturing on federal lands. 

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Policy Watch

Policy Watch - Edie Allison
Edie Allison began as the Director of the AAPG Geoscience and Energy Office in Washington D.C. in 2012.

Policy Watch

Policy Watch is a monthly column of the EXPLORER written by the director of AAPG's  Geoscience and Energy Office in Washington, D.C. *The first article appeared in February 2006 under the name "Washington Watch" and the column name was changed to "Policy Watch" in January 2013 to broaden the subject matter to a more global view.

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D.C. Bound: Congressional Visits Days Slated for March 10-12

Want to participate in this year’s AAPG Congressional Visits Days (CVD)?

If so, the deadline to register is looming.

This year’s AAPG CVD event will be held March 10-12, but the registration deadline is Feb. 10.

AAPG Congressional Visits Days event annually provides an opportunity for AAPG members to discuss petroleum science and energy issues with decision makers in the legislative and executive branches of the federal government.

It also is an exciting introduction to the world of politics that will provide the tools to use at the local and state levels once you return home. AAPG staff will provide training and briefing materials, and schedule the meetings.

This year’s CVD:

  • Starts with an afternoon briefing on how Congress works; the legislative process; ways to make your visits successful; and issues that are of concern to Washington.
  • On the second day, gives participants the chance to visit the executive branch and congressional committee offices.
  • The third day is devoted to small-group visits to senators’ and representatives’ offices.

To register or get additional information contact Edith Allison, 
GEO-DC’s Energy and Geoscience policy director, at eallison@aapg.org
or (202) 643-6533.

To reserve lodging, contact the 
Army and Navy Club by Feb. 10, at (202) 628-8400; or email toFrontDeskPOS1@armynavyclub.org.

– Edith Allison

See Also: Book

See Also: Bulletin Article

Prolific hydrocarbon discoveries in the subsalt, commonly known as the “presalt,” section of Brazil and the conjugate African margin have created a business imperative to predict reservoir quality in lacustrine carbonates. Geothermal convection is a style of groundwater flow known to occur in rift settings, which is capable of diagenetic modification of reservoir quality. We simulated variable density groundwater flow coupled with chemical reactions to evaluate the potential for diagenesis driven by convection in subsalt carbonates.

Rates of calcite diagenesis are critically controlled by temperature gradient and fluid flux following the principles of retrograde solubility. Simulations predict that convection could operate in rift carbonates prior to salt deposition, but with rates of dissolution in the reservoir interval only on the order of 0.01 vol. %/m.y., which is too low to significantly modify reservoir quality. The exception is around permeable fault zones and/or unconformities where flow is focused and dissolution rates are amplified to 1 to 10 vol. %/m.y. and could locally modify reservoir quality. After salt deposition, simulations also predict convection with a critical function for salt rugosity. The greatest potential for dissolution at rates of 0.1 to 1 vol. %/m.y. occurs where salt welds, overlying permeable carbonates thin to 500 m (1640 ft) or less. With tens of million years residence times feasible, convection under these conditions could locally result in reservoir sweet spots with porosity modification of 1% to 10% and potentially an order of magnitude or more in reservoir permeability. Integrating quantitative model–derived predictive diagenetic concepts with traditional subsurface data sets refines exploration to production scale risking of carbonate reservoir presence and quality.

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See Also: CD DVD

A collection of fifteen papers originally published by the American Association of Petroleum Geologists, Gulf Coast Section-Society for Sedimentary Geology (GCS-SEPM), Marine and Petroleum Geology (Elsevier), Tectonophysics (Elsevier), Gulf Coast Association of Geological Societies (GCAGS), American Geophysical Union, and The Geological Society of London.

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See Also: DL Abstract

Reservoir characterization is an exercise in constraining uncertainty that arises from sparse sampling of the subsurface by widely spaced wells at lengthscales below seismic resolution. Outcrop analogs are an invaluable complement to well and seismic data in this context, because they provide qualitative concepts and quantitative spatial data to guide interpretations of lithology distribution in inter-well volumes. However, analog-driven interpretations of reservoir architecture are not straightforward to compare with dynamic data that describe fluid flow during production – the acid test of any interpretation of reservoir geology. The value of outcrop reservoir analogs is most fully realized when they are used to construct outcrop-based reservoir models that enable explicit predictions of flow patterns in a form that can be compared with routine reservoir-monitoring data.

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See Also: Field Seminar

This trip will focus on defining the Niobrara formation from the outcrop scale to the well bore, and discuss the key parameters that have made this play work, both from a geologic and a reservoir standpoint. Furthermore, we will describe how Noble Energy has helped to lead the industry in Northern Colorado to safely, responsibly and efficiently develop this huge resource. We will visit both Niobrara outcrops and Noble Energy production facilities to illustrate our current subsurface understanding and best practices.
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