R&D Studies - coordinated by Fadi Nader
Oil and Gas Shale : Can the Classical Basin Modelling be useful to Quantify Reserves ?
I. Moretti , F Lorant, D Jarvie, F Behar
Introduction
In the last few years the so called unconventional reserves have become more crucial for the evaluation of the total world hydrocarbon (HC) reserves. With the dramatic increase in production from the gas shale, mainly in the North America, the resources of the HC trapped within the source rocks have been published in numerous papers. This announced revolution became real for everybody when at the end of 2009, the USA surpassed Russia and occupied the first place in gas reserves worldwide. The estimated resources grew very quickly and the threat of the lack of energy supply has been post-dated for the next century. However, resources are far to be reserves, and still farther to be proven reserves.
One issue for explorationists in the HC industry has always been to predict the HC in place and the quantity that could be extracted from them. Petroleum system modelling is commonly used to predict occurrences of oil and gas accumulations. When this is completed, then trap sizes are assessed and reservoir modelling could be achieved, taking into account porosity and compartmentalization of the reservoir beds. The quantification of oil and gas in place within shaly source rocks required the development of a new methodology since the size of the plays are not simply related to geometrical characteristics (such as size of the traps, and thickness and porosity of the reservoirs). During the last decade, the lack of adequate methods was not fully appreciable since the gas shale industry has been driven by many rather small independent oil and gas companies focused on the economy of each individual well. The more recent involvement of the majors that now target such shale plays and the need of the decision makers to have more realistic numbers for reserves advocates for more accurate modelling of such reservoirs and the quantity of oil and gas that they hold.
IFP has fully understood the current situation and is actively working on the upgrade of its exploration workflow for oil and gas shale exploration. Exploration requires regional knowledge and, as such, IFP is part of the Gas Shales in Europe (GASH) consortium that started in 2009 (www.gasshales.org) . This consortium, coordinated by B. Horsfield and M. Schulz from GFZ in Potsdam, Germany aims to combine the effort of numerous research centres in Europe to estimate the European shale gas potential and speed up technological breakthrough in gas shale production, taking advantage of the experiences derived from North American basins (such as the Barnett and Marcellus shales). The consortium is funded by seven oil companies to date (Horsfield et al., 2010). The work program of GASH is shared among the construction of an European data base (under the responsibility of TNO), regional studies coordinated by IFP and reservoir scale study coordinated by C. Aplin from the Newcastle university.
In addition, IFP is working on an upgrade to its quantitative tools that encompass the various steps in an exploration workflow: restoration tools that allow up to 3D restoration with a link to a geomechanical model, sequence stratigraphy forward model, basin modelling and fracture network evaluation. Recent developments of the kinetics for a full compositional description of both primary and secondary craking enables computation of mass balances between expelled and retained hydrocarbons with increasing source rock maturity (Behar et al., 2008). Beyond the oil window, the retained compounds undergo secondary cracking and the mature kerogen generates a second pulse of dry gas.
Basin simulators were originally designed to account for the formation and the evolution in space and time of hydrocarbon systems. Some geologists may are contemplating the accuracy of these techniques to assess the occurrence of continuous, not structurally controlled, accumulations. Non-expelled HC – and so retained HC within the source rocks – have always been quantified by these tools, and as a result secondary cracking of retained HC and late primary cracking of the kerogen have already been successfully modelled. Basin simulations can be achieved to better delineate thermal maturity levels reached by the source rock in a gas and oil shale play. Total generated HC mass can also be easily derived from predicted maturity maps. At a straightforward level, the current basin modelling tools have indeed been used in unconventional plays: for instance TEMIS has been successfully used a long time ago for the Williston basin (Burrus et al., 1995 and 1996) and has allowed the authors to solve some of the paradoxes of this oil system. More recently, Lorant et al. (2010) used them for the Barnett shale gas system to compute the sensitivity response of the gas accumulation size to holistic petrophysical and geochemical factors.
However, improvements are still needed. For example, when working a conventional play, averaging the quality of the source rock and simplifying the expulsion to a threshold of water versus HC saturation within the porosity, have a low impact on the result of the modelling. Except in very mature exploration areas where the knowledge of the source rocks is sufficient to allow quantitative description of the HC using compositional kinetic parameters, simplification of the expulsion process is not an issue. Nor is the final decision of the exploration manager to drill neither the P50 of individual plays affected by the weakness of the expulsion model. Similarly, averaging the organic matter within the source rock does not influence the results considerably.
To help explorationists and economists to locate wells in a gas shale area and, subsequently, to have an accurate evaluation of the reserves, technological improvements are also needed. Since gas shale results from a balance between retention and expulsion processes, advanced fluid flow modelling is required, coupling both charging and discharging mechanisms within the source rock. To account precisely for the physics of gas displacement, storage and sorption within tight shales, improvement of the current tools are required and also the workflow itself has to be revised: fracture porosity has to be incorporated within the source rock description as well as the spatial variability. The current tools for restoration and fracture analyses and sequence stratigraphy allow such use but on high porosity beds of conventional reservoirs. New workflow and additional calibration will be done using a natural case study. In addition IFP is acquiring datasets characterizing gas sources by measurement of compositional kinetic parameters of the source rocks present within the gas shale provinces. Following, the recent kinetic scheme proposed by Behar et al., (2008, 2010), kerogen decomposes first into NSO compounds, which are the main source of gas and oil. Thus, expelled oil composition is controlled by the secondary cracking and the mobility of this polar fraction. In a second step, mature kerogen generates dry gas. Ongoing IFP research work (Jarvie et al., 2010) is to couple this integrated kinetic scheme for gas generation with an isotopic modelling of both methane and ethane generation in order to predict the isotopic composition of these two gas in geological conditions. We are also enhancing the numerical models by taking into account additional physical processes such as the friction effects during gas migration in shale. Sensitivity analysis will be also done that will provide guidelines to the explorationist on key parameters that will lead to prediction of gas-in-place in the shale (source rock characteristics, shale characteristics, initial porosity, permeability, expulsion threshold, adsorption parameters, pressure regime...). Case studies area scheduled by the IFP team on the Paris and South-east French basins where continuous reservoirs could be looked for; we are taking advantage of our proper geochemical data base containing more than 45000 Rock Eval analysis only for the national territories, from wells or outcrops.
References
Behar, F., Lorant, F., Lewan, M.D., 2008. Elaboration of a new compositional kinetic schema for oil cracking. Organic Geochemistry 39, 764-782.
Behar, F., Lorant, F., Mazeas, L., 2008. Role of NSO compounds during primary cracking of a Type II kerogen and a Type III lignite. Organic Geochemistry 39, 1-22.
Behar, F., Jarvie, D., Roy, S., 2010. Artificial maturation of a Type I kerogen in closed system: mass balances and kinetic modeling. Organic Geochemistry, submitted.
Burrus J. Osadetz K., Wolf S., Doligez, B., Visser K. and D Dearborn, 1995. Resolution of Williston Basin Oil system paradoxes Through Basin Modeling. Seventh International Williston Basin Symposium. Montana July 1995.
Burrus J. Osadetz K., Wolf S., Doligez, B., Visser K. and D Dearborn, 1996. A Two-dimensional Regional Basin Model of Williston Basin Hydrocarbon Systems. AAPG Bulletin, V 80, N°2, 265-291.
Jarvie D., Behar F., Roy S. (2010), Decomposition of Organic Matter and Impact on Shale Resource Play Assessments , AAPG Annual Convention and Exhibition, 11-14 April 2010, New Orleans, LA (oral presentation);
Horsfield et coauthors, (2010) Shale gas research: the way forward for Europe. Oilfeild technology. March.
Lorant F., Jarvie D., Moretti I. (2010) Can conventional basin modelling predict gas shale occurrence? A case study from the Fort Worth Basin, TX (USA), EAGE, Shale workshop.