The Unconventional Frontier: Prospects for Global Unconventional Gas

This comprehensive project comprises a suite of interactive Multiclient Studies to provide a detailed geological, petroleum engineering, and economic analysis for each of these markets.

Why Now?

Until January 2007 it seemed that the North American natural gas market was headed toward increasing dependence on liquefied natural gas (LNG) exports. Yet by November 2010 production in the US Lower 48 had risen by 9.9 Bcf per day (102.3 Bcm per year). Today unconventional supply is the main pricing driver in North America and accounts for 160 Bcm in production. One of the most remarkable aspects of the unconventional gas revolution in North America is the speed with which technological innovations have spread, evolved, and continue to improve.

Analysts believe that the industry has the expertise, technical knowledge, and capacity to take this revolution global. Today's unconventional E&P technologies deliver lower costs and a smaller environmental footprint than ever before. Most importantly, E&P activity in North America has demonstrated the potential of this emerging industry to adapt to different regulatory regimes and geologies. Unconventional gas E&P is now a mature knowledge area and technology for export. This could be a game changer for key regions-and even on a global scale.

Key market players must understand the global potential of unconventional gas, make strategic choices, and create investment plans. These decisions must be made over the next one to two years and will reshape the supply picture over the next decade.

The Unconventional Frontier will help members answer these two key questions:

• Which regions will see the impact of increasing unconventional supply?
• When can we expect production to start, and what rate of increase can we expect?

IHS CERA Credentials

Over the past five years IHS CERA and its parent company, IHS, have steadily built proprietary data sets and gained significant experience in unconventional resources in order to apply the necessary rigor to this major global project. In particular IHS CERA has conducted several major studies in North America, gaining in-depth knowledge on how to develop methodologies to evaluate global opportunities.

Most recently IHS CERA completed Breaking with Convention: Prospects for Unconventional Gas in Europe. This major study, supported by more than 20 market experts, laid the groundwork for the IHS CERA project to explore 35 frontier shale and 19 coalbed methane (CBM) plays. In Breaking with Convention IHS CERA applied and refined the innovative methodology which we will apply to each of the Multiclient Studies that make up The Unconventional Frontier.

Proprietary IHS Data Resources:

IHS Global Exploration and Production Services (GEPS). This ongoing service provides a worldwide picture of E&P activity.

IHS Petroleum Economics and Policy Solutions (PEPS). This ongoing resource for the oil and gas industry reports on political, contractual, environmental, and legal policies around the globe.

IHS International Exploration and Production Database-IRIS21. This is the most comprehensive and reliable data set of E&P industry professionals available, featuring a fully integrated data area with over 13,000 E&P data attributes.

Global Coal Deposit Database. An authoritative reference on the location and composition of coal deposits worldwide.

IHS CERA Methodology

Summary 

Each of the studies that make up The Unconventional Frontier will be divided into three phases.

Phase 1 will provide members with a geological framework, evaluation of geological risk, and analysis of subsurface potential, including gas-in-place (GIP) estimates per play.

Phase 2 will provide members with the operational and production framework. In this critical phase, members will have access to an additional layer of the geological framework. IHS CERA's in-depth understanding of US analogs will be used to frame the potential key plays and generate scenarios for their development. An analysis of regulatory, environmental, and operational issues for each shale gas and CBM deposit identified in Phase 1 will frame the selection of plays.

Phase 3 addresses economics and marketing. The IHS CERA regional expert teams will apply the geological and operational frameworks to the market and policy conditions of each market. In this phase IHS CERA will provide outlooks for unconventional gas production in the region under study, as well as strategic recommendations.

A detailed description of each of these phases follows.

Detailed Methodology Description

Phase 1: Geological Framework

The geological framework phase assesses the subsurface risked resource potential for the range of unconventional gas plays in each market. This assessment is used as an input for Phase 2 to estimate potential production capacity and for Phase 3 for commercial and market analysis. By applying a consistent methodology across plays in divergent geological settings, our approach allows for broad comparisons and provides a consistent framework for the analysis of production capacity and commercial factors.

Play maps show the extent of the areas that are prospective for unconventional exploration based on the depth to the top of the specific shale or coal interval, the thickness (isopach) of the prospective horizon (net pay zone), and the maturity for hydrocarbon generation (iso-maturity). Geological information and well-top data are drawn from various sources, including scientific publications and in-house reports as well as the IHS IRIS21 Basin, Exploration, and Production databases.

Where available measured gas content in shales and coal is used, but often these measurements are not available. Gas content is estimated on the basis of maturity as well as kerogen quality in terms of total organic carbon (TOC) and Rock-Eval data parameters (for shale) or data from laboratory analysis (proximate analysis for coal). Algorithms are developed to calculate the amount of transformation of kerogen and coal into hydrocarbons, the sorption to the shale or coal matrix, and storage of "free" gas in the (micro)porosity of the shale matrix.

GIP resources are calculated for each play, taking into account the prospective area based on minimum criteria for pay zone thickness and maturity and the gas content in the prospective shale and coal sections.

Shale and coal gas plays are risked on a relative scale on the basis of subsurface parameters in order to group them into categories from high to low potential. Subsurface risk includes depth to top of the prospective horizons, pay zone thickness, burial history and maturity, shale kerogen quality or coal rank, and gas content.

GIP, subsurface risk parameters, and ranking on potential are used as input for Phase 2 to estimate potential production capacity and for Phase 3 to analyze commerciality and potential market impact.

Phase 1 will produce the critical deliverables shown below.

Phase 2: Operational and Production Framework

Using three different scenarios, the operational and production framework phase assesses and risks the potential of plays identified in Phase 1.

Phase 2 relies on a top-down approach to identify, quantify, and assess the production potential of unconventional gas. This analysis involves assessing risk at the macro/industry levels and then drilling down into play-level risks. The breakeven cost of supply, productive capacity, and activity are then projected, using assumptions for each play about discount rates, royalties, corporate tax, operating expenses, (opex), and capital expenditures (capex) for development wells.

The Macro Context. The broader political and economic context-along with the business environment in the energy industry-has a considerable impact in determining the trajectory of unconventional gas development. For this reason an important step in our analysis of production potential is to understand how these macro issues might interact with emerging developments in each of the markets.

Play-specific Factors. A wide range of factors is considered in assessing the likely production profiles of specific unconventional gas plays under various macro scenarios. These factors are judged to have varying importance and are weighted accordingly. The two first-order factors considered for each play are the plateau probable production and the time to first production. Both are elaborated in some detail for each play.

• The plateau probable production figures reflect resource risk (itself a function of the geological characteristics of the play), access constraints, reservoir recovery, geological potential, and the results from analogs in the United States.
• Time to first production reflects development pace and development risks, the breakeven cost of gas supply, production potential, and an assessment of aboveground risks.

The key risks for each play are identified and a range of outcomes for each risk is calculated to form a strategy whereby scenarios for development of each play are identified by threading through the key risks.

Another aspect of development pace-the speed of ramp-up after first production-is considered as a second-order factor and analyzed based on North American analogs. The rate of decline, reflecting the operator's ability to "milk the barrel" by adding reserves and production after the play has plateaued, is incorporated as a third-order factor. This analysis also involves detailed comparisons with analogs from the United States.

Plateau Probable Production—The Key Parameter. Traditional guidelines for risking resource estimates are uncertain, subject to interpretation, and not applicable to this case, for which there are so many unknowns. In this study risked production profiles for each play are built around an estimate for plateau probable production. Starting with a gross GIP estimate from Phase 1, a net GIP figure is calculated by removing any resources located on protected areas and towns. The resulting figure for each play is then transformed into a net recoverable resource by assuming that the recoverable share of the net GIP number is 20 percent for shale gas and 50 percent for CBM. The range of recovery factors for unconventional plays is assumed typically to fall between 10 and 30 percent for shale gas and 40 and 60 percent for CBM. Probable net recoverable gas resources are determined by applying a geological potential to each play—high, medium, or low—each with its own distribution of six potential outcomes. Estimates of plateau probable production for each point in the probable net recoverable distribution for each play are calculated using benchmarks from North America as appropriate.

Productivity Potential. Productivity potential is highly uncertain. However, to determine costs an assessment is made of the potential at the play level. This assessment is used to inform the time to first production view in combination with the US dollars per Mcf analysis. From a review of brittleness, pay thickness, gas content, and overpressure a productivity potential is assigned to each play. Overpressure is calculated by looking at the difference in the absolute pressure and the hydrostatic pressure of water at the reservoir depth; in this respect depth and pressure drive the result.

Time to First Production. Time to first production is calculated by assigning a time for first production-defined as early, on time, or late-for each play based on the geological characteristics of the play, access constraints, reservoir recovery, geological potential, and the results from analogs in the United States.

As a final output from Phase 2, IHS CERA develops several scenarios for production, matching three of these scenarios to our global scenarios by market.

Phase 3: Economics and Marketing

Phase 3 frames the results of the two previous phases against local market contexts and outlooks. This phase relies on IHS CERA regional research teams that leverage their market understanding to address key strategic questions for each market.

Major gas markets

• Europe (Breaking with Convention-completed November 2010)
• Eastern Europe (Ukraine, Romania)

Emerging gas markets

• China
• India
• South America

Potential export markets

• Indonesia
• Australia

Final Report

Each Multiclient Study will conclude with the completion of a Final Report to be delivered online. This report will complement the datasets and spreadsheets, which will also be made available. The Final Report outline is expected to have the following format: