Reserves estimation of shale gas

Shale gas is becoming increasingly important globally. The nature of these reservoirs pose special considerations in reserves estimation. What follows was written in 2001 and needs to be updated based on current experience. Nonetheless, some of the considerations mentioned remain appropriate.

Background

As reported in mid-2000, natural gas produced from shale in the US has grown to be approximately 1.6% (0.3 Tcf annually) of total gas production. The first commercial production of natural gas from shale was developed to supply gas to the town of Fredonia, New York, US, in the late 1820s, predating Col. Drake’s first oil well by almost 40 years.

By 1979, some 60 Bcf/year was being produced from wells in the Appalachian (Ohio) basin. Production from the Antrim shale (Michigan basin) began in the mid-1980s and by 1994 had surpassed production of the Appalachian basin. Three other US basins—San Juan (Colorado, New Mexico), Fort Worth (Texas), and Illinois (Illinois, Indiana, Kentucky) currently are producing from shale. Total US gas-bearing shale resources are shown in Table 1.

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  Table 1

In a 1992 report, the Gas Research Inst. (GRI) describes the Antrim shale as being organically rich and says that the majority of the in-place gas was sorbed into the organic constituent. Productivity is achieved by reducing reservoir pressure, and is maximized by hydraulic fracturing to access and connect the wellbore to the natural microfractures and other permeability pathways.

As in coalbed methane (CBM) reservoirs, the naturally occurring fracture system usually is water-filled, requiring artificial lift equipment to dewater the wells to reduce the bottomhole pressure to a level consistent with maximum gas desorption and production.

Calculation and considerations

Shale gas volumes initially in place (scf) can be calculated by:

......................(1)

where 1,359 is a conversion factor to convert volume (acre-ft), shale density (g/cm3), and gas content (scf/ton) to scf gas in place.

Shale density and gas content can be measured directly through core analysis or indirectly through well logs, using correlations established between gas content and shale bulk density. Core samples are taken and preserved to minimize the release of original gas in place. The free gas in the core sample canisters plus the gas that is released during core crushing is measured in the laboratory. This volume of gas may be adjusted to account for the volume estimated to have been lost during core retrieval. The analysis procedures are similar to those used for CBM.

Gas-content/shale-density correlations are an outgrowth of studies in which the laboratory-measured shale densities and total organic content (TOC) of the samples were compared and related in a linear correlation. Similarly, gas content was found to have a linear relationship with TOC.

This research thus leads to the ability to measure bulk density from well logs and use this information to directly estimate gas content and log-derived gas in place.

Fig. 1 is an example of the relationship between gas content and shale density for the Antrim shale in a defined area.

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  Fig. 1 – Calculation of gas content from bulk density measurements from log, Antrim shale (after Gas Research Inst.

Gas reserves estimation

Gas reserves estimates (REs) vary widely and are related to many factors, including:

• Completion efficiency
• Reservoir pressure
• Water removal efficiency
• Well spacing

The recoveries shown in Table 2 range from 5 to 60% gas-in-place (GIP), but probably average approximately 40% GIP in the Michigan basin (Antrim). A typical well production profile is shown in Fig. 2.

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  Table 2

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  Fig. 2 – Typical production graph for an Antrim shale well.

The initial dewatering period of approximately 1 year is characterized by diminishing water production and increasing gas production. Following perhaps a year of relatively constant production, a decline rate of approximately 6% per year is typical for a Michigan-basin Antrim well. Most wells exhibit exponential decline during their economic life.

The booking of proved reserves must be delayed until the production rate reaches a commercial level and/or there is ample evidence from nearby analog wells. Undeveloped locations may be classified as proved if these locations are directly adjacent to commercial wells (1978 U.S. SEC definitions). Additional locations may be classified as proved under the 1997 Society of Petroleum Engineers (SPE)/ World Petroleum Council (WPC) definitions if there is compelling evidence from nearby analogs and if the continuity of favorable reservoir conditions is reasonably certain.

Nomenclature

A	=	area of reservoir or accumulation, acre
Cgi	=	initial sorbed gas concentration, scf/ton, dry, ash-free coal or shale
Gi	=	gas-in-place at initial reservoir conditions, scf
hs	=	shale thickness, ft
ρ	=	density, general, g/cm3

Noteworthy papers in OnePetro

Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read

Online multimedia

Lee, W. John. 2014 Workflow for Applying Simple Models to Forecast Production from Hydraulically Fractured Shale Wells. SPE Webinars. Society of Petroleum Engineers, 9 January https://webevents.spe.org/products/workflow-for-applying-simple-models-to-forecast-production-from-hydraulically-fractured-shale-wells

External links

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See also

PEH:Estimation_of_Primary_Reserves_of_Crude_Oil,_Natural_Gas,_and_Condensate