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This paper addresses the problems identified in current shale reservoir characterization practices. We also provide alternative approaches with relevant reflections on the determination of volumes in-place. Rock properties in unconventional reservoirs such as shales is of paramount importance. By comparison with conventional reservoirs, fluids are present not only in the intergranular porous media but also within the fine texture of the rock matrix (Clays, Kerogen and
Micro-Fractures) which usually are only recoverable with the aid of suitable stimulation and completion technologies. This paper questions current engineering practices related with the assumption of unrealistic cut-offs in the petrophysical
analyses which in turn may result in dangerously misleading estimates of in place volumes and thus inadequate development decisions being made.
The adsorption capacity of clays has been documented with observations on the correlations between the percentages of clay minerals in the rock and Langmuir volume (VL) determined in laboratory measurements of gas content from core
samples by means of Langmuir isotherms. Therefore it should be no surprise that clays in shale gas reservoirs are known to adsorb hydrocarbon gases and may contribute to the production when properly stimulated. We therefore recommend
that corrections for clay effects should not be arbitrarily applied in the petrophysical analysis of electric logs. The use of a total porosity-total water saturation model will help to avoid shortcomings in total gas in-place determination. Additional
reasons for the avoidance of clay porosity corrections; include the fact that there are no tools capable of differentiating between free gas and adsorbed gas.
Total porosity and water saturation methods give rise to total gas content determination with the appropiate model. Adsorbed gas content estimate, may be obtained by correlating geochemical data based on gas content from laboratory experiments and rock density measured on core and or logs.
Unconventional reservoirs have burst with considerable force in oil and gas production worldwide. Shale Gas is one of them, with intense activity taking place in regions like North America. To achieve commercial production, these reservoirs should be stimulated through massive hydraulic fracturing and, frequently, through horizontal wells as a mean to enhance productivity.
In sedimentary terms, shales are fine-grained clastics rocks formed by consolidation of silts and clays. In log interpretation of conventional reservoirs, it is very common to observe that the clay parameters used to correct porosity and resistivity logs for clay effects are in fact read in shaly intervals rather than in pure clay. Although no considerable deviation have been observed in shaly sandstones, anyway these concepts and procedures must be reviewed to run log analysis in shale gas. Organic matter deposited with shales containing kerogen that matured as a result of overburden pressure and temperature, giving rise to source rocks that have yielded and expulsed hydrocarbons. Shale gas reservoir type is a source rock that has retained a portion of the hydrocarbon yielded during its geological history so that to evaluate the current hydrocarbon storage and production potential it is necessary to know the kerogen type and the level of TOC - total organic carbon - in the rock. Produced gas comes from both adsorbed gas in the organic matter and "free" gas trapped in the pores of the organic matter and in the inorganic portions of the matrix, i.e. quartz, calcite, dolomite.
In these unconventional reservoirs, gas volumes are estimated through a combination of geochemical analysis and log interpretation techniques. TOC, desorbed total gas content, adsorption isotherms, and kerogen maturity among other things can be measured in cores, sidewall samples and cuttings, in the laboratory. These data are used to estimate total desorbed gas content and adsorbed gas content which is part of the total gas. Also in laboratory, porosity, grain density, water saturation, permeability, mineral composition and elastic modules of the rock are measured. Laboratory measurement uncertainty is high and consistency between different providers appears to be low, with serious suspicions that procedures followed by different laboratories are the source of such differences. The permeability is one of the most important parameters, but at the same time, one of the most difficult to measure reliably in a shale gas. Core calibrated porosity, mineral composition, water saturation and elastic modules can be obtained through electric and radioactive logs. All these information is used to estimate log derived total gas volume which results are also subject to a high degree of uncertainty that must be overcome.
Once this key information is obtained, it is possible to estimate different gas in-situ volumes. Indeed, an estimate of porosity-resistivity based total gas in-situ and, on the other hand, geochemical based adsorbed gas in-situ can be performed. Log total gas in-situ can be, and it is advisable to do, compared with adsorbed gas estimations and also with another gas measurement called direct method - total gas desorption performed on formation samples. The difference between log total gas in-situ and adsorbed gas in situ should be the "free" gas in situ. Free gas occupies the pores of kerogen and matrix; also it can be stored in open natural fractures if such fractures are present.
Currently, the deterministic methods for reserves estimation are the preferred method for both, companies and the U.S. Securities and Exchange Commission SEC. Last year, the SEC published the modernization rules for reporting oil and gas reserves where both, the deterministic and probabilistic methods, were accepted as valid methods for reserves estimation. In addition to the compulsory reporting of the oil and gas proved reserves, the probable and possible reserves were recognized to be disclosed in SEC filings for the first time, although it is optional for these two categories. In this paper the integrated deterministic-probabilistic approach is briefly reviewed, the cumulative probabilistic lognormal plots are used instead of a full Monte_Carlo simulation, and a procedure is proposed using these plots to follow up the reserves evolution in time. Plotting the deterministic reserves using probabilistic scale often reveals deviations with regards to the expected lognormal cumulative probability distribution behaviour, shown by real case examples. The corrections to obtain a better fit for the probabilistic distribution suggest to either changing the probable or the possible reserves or both. Furthermore, the slope of the probabilistic plots appears to be related to the uncertainty level of the probable and possible reserves. This property was used to follow up the reserves behaviour in time, finding consistency with the idea that as the fields are developed the level of uncertainty should be progressively reduced. Examples of the reserves follow up are also presented. The contribution of this paper is oriented to a practical use of an integrated deterministic-probabilistic approach as a complementary tool for reserves estimation for consistency with the probabilistic behaviour. The follow-up procedure of the reserves resulted to be quick and simple but powerful as indicator of the reserves evolution.
The Securities and Exchange Commission (SEC) of the United States of North America has modernized in December 2008 its regulations for the report of oil and gas reserves. From now on, the oil and gas companies will be able to report reserves of bituminous sands, the economic evaluation of reserves will be made with an yearly average price instead of the price of the last day of the year, the use of (reliable) technology will be allowed to demonstrate the producibility and the (lateral) continuity of production of the reservoirs as well as to determine the fluid contacts. Also, it will be authorized to publish, voluntarily, probable and possible reserves that previously were explicitly prohibited in the SEC reports. One of the important changes that concern to the petrophysicist is the qualification of Reliable Technology to support or demonstrate the producibility of the reservoirs without having a conclusive test. Using technology the petrophysicist will also be involved in fluid contacts determination and in the construction of analogy of the reservoir of interest with other reservoirs at a more advanced stage of development. The use of reliable technology is also enabled to support the estimate of proved undeveloped reserves at greater distances than the development spacing in the field provided that reasonable certainty of the production continuity is obtained by using such technology. The intrinsic technical uncertainty in reserves estimations often makes the estimators to adopt a probabilistic estimate instead of a deterministic one. The use of probabilistic estimates has become frequent in the industry and now the SEC has defined that estimates of proved reserves can be made either deterministically or probabilistically. When a probabilistic estimate is chosen,
or when in occasions the petrophysical parameters of an in essence deterministic estimate (net thickness, porosity and saturation of water) are chosen based on a probabilistic approach of the distribution of those parameters, the petrophysicist will have to observe some basic premises to avoid misinterpretations. Also, in the next years, operators and service providers will be embarked in an effort to find new tools and methodologies for reservoir evaluation and reserves estimation that allow them to value their properties with reasonable certainty still at the early stages of development. This will take place under a modernized regulatory framework that will enable the use of the most modern technologies provided that they can offer consistent, repetitive, and reasonably certain results on the expected answer of the reservoir.