Sinha, Somnath (Exxon Mobil Upstream Research Company) | Braun, Edward M. (ExxonMobil Upstream Research Co.) | Passey, Quinn R. (ExxonMobil Upstream Research Co.) | Leonardi, Sergio Adrian (ExxonMobil Upstream Research Company) | Wood, Alexander C. (Exxon Mobil Corporation) | Zirkle, Timothy (Exxon Mobil Corporation) | Boros, Jeffrey Allan (ExxonMobil Upstream Research Co.) | Kudva, Ryan Ashok
Determination of permeability of unconventional reservoirs is critical for reservoir characterization, forecasting production, determination of well spacing, designing hydraulic fracture treatments, and a number of other applications. In many unconventional reservoirs, gas is produced from tight rocks such as shale. Currently the most commonly used industry method for measuring permeability is the Gas Research Institute (GRI) technique, or its variants, which involve the use of crushed samples. The accuracy of such techniques, however, is questionable because of a number of inadequacies such as the absence of reservoir overburden stress while conducting these measurements. In addition to questionable accuracy of crushed rock techniques, prior studies have indicated that there is significant variability in results reported by different laboratories that utilize crushed-rock technique to measure permeability on shale samples. Alternate methods are required to obtain accurate and consistent data for tight rocks such as shales. In this paper we discuss a robust steady-state technique for measuring permeability on intact tight rock samples under reservoir overburden stress. Permeability measurement standards for low permeability samples are critical for obtaining consistent results from different laboratories making such measurements, regardless of the method used for measuring permeability. In this paper we present permeability measurement standards developed based on first principles that serve as the "ground-truth?? for permeability in the 10 - 10,000 nanoDarcy range. These standards can be used to calibrate any permeability measurement apparatus used to measure permeability on intact tight rock samples such as shales, to enable delivery of consistent results across different laboratories conducting measurements on intact tight rock samples.
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.
A multidisciplinary approach to shale characterization in a variety of North American gas- and liquids-rich shale plays has lead to improved understanding of the bulk physical, chemical and mechanical properties of these deposits and their geologic history. This effort is leading to successful exploitation of these enigmatic resources. Microfacies analysis of mudrocks provides a platform for upscaling from the "nano?? to the regional scale, and results in comprehensive mudrock characterizations.
Microfacies analysis of mudrock types within a select stratigraphic interval in a basin leads to the recognition of mudrock lithofacies. Lithofacies identification allows for calibration of petrophysical models, documentation of basinspecific variations in mudrock composition and microfabrics, the distribution of organic-rich members of these intervals, definition of the mechanical stratigraphy for completion design, and provides the litho-stratigraphic building blocks for predictive sequence stratigraphic models.
Successful exploration and exploitation of mudrocks as resources can be advanced when the recognition of mudrock lithofacies provides a methodical means to tie together the geologic, chronostratigraphic, geochemical and petrophysical data from a diverse spectrum of physical scales and technical disciplines.
The Netherlands is a mature hydrocarbon province. EBN, the Dutch state participant for hydrocarbon exploitation and exploration, has identified shale plays as one of the contributors to add reserves and to maintain production at the current level. The main source rock for the limited amount of oil accumulations in The Netherlands are the Lower Jurassic (Toarcian) oil-prone shales. Lower Carboniferous (Namurian) hot shales have often been suggested as possible contributor to oil and gas Formation in The Netherlands as well, but this has not been proven to date. Recent discoveries of gas in the time-equivalent Bowland shales in the UK have encouraged interest in the production potential of these shales in North-western Europe. In this paper the geological and geomechanical properties of the Lower Jurassic and Lower Carboniferous are presented in a shale play context. The assessment methodology is subdivided in three sections: 1) the overall geology of the play, 2) the type and quantification of hydrocarbons present and 3) the production characteristics. New and specific measurements
on core and cutting material include pyrolysis, methane adsorption, mineralogy, texture, porosity, permeability, static and dynamic geomechanical properties, hardness and fracture conductivity.
The two identified plays show very distinctive properties. The Lower Jurassic samples indicate to be mostly thermally immature for dry gas implying that liquids can be expected. The Lower Carboniferous samples show areas that are overcooked. Mineralogical and geomechanical data suggest that different stimulation strategies may be necessary for these two plays to produce hydrocarbons effectively. The source rocks of Lower Jurassic age qualify as relatively soft while the Lower Carboniferous shales with high TOC content classify as very hard. Comparing the results of the assessment to known shale plays in the US, the plays position themselves in the opposite extremes of the productive shale play spectrum.
The resource base of the Netherlands is maturing rapidly. The current portfolio of producing gas fields shows that approximately 75% have produced more than half of their initial reserves volume (EBN, 2010). In order to maintain the current high production levels, enhanced recovery from existing fields is required as well as portfolio rejuvenation by increased exploration activities. In North America the gas production from organic rich shales have proven to be a game changing concept for the gas industry. This success sparked a worldwide interest in other shale basins with similar characteristics. In order to assess the
production potential of this type of unconventional resource, The Netherlands are currently investigating their prospective shale resources.
Shale-gas plays and other unconventional resources have gained significant importance worldwide. Historically, synthetic based drilling fluids (SBM) are used in these plays when no environmental concerns are in place and are preferred when wellbore stability is necessary. In this paper, we study the use of an improved water based drilling fluid (WBM) that is simple in formulation and maintenance that shows excellent rheological properties, maintains wellbore stability, and a good environmental profile. A combination of well-known and economically affordable materials is combined with new technology to achieve desired rheological properties and wellbore stability.
The use of nanoparticles to decrease shale permeability by physically plugging nanoscale pores holds the potential to remove a major hurdle in confidently applying water-based drilling fluids in shale formations, adding a new advantage to the studied fluid. Silica nanomaterials were investigated for this purpose. Due to their commercial availability, these materials can be engineered to meet the specifications of the formation. Characterization of the nanoparticles was completed with Transmission Electron Microscopy (TEM), dynamic light scattering, and X-ray-photoelectron spectroscopy. Rheological properties and fluid
loss are studied together with other important properties such as shale stability and anti-accretion properties. The authors will describe new laboratory methods used to investigate these properties, from a modified API fluid loss test to the Shale Membrane Test that measures both fluid loss and plugging effects and illustrate additional future research that includes adding reactive species, and anchoring them to the pores, thus stabilizing the shale further.
A majority of the whole core samples recovered in the US today come from shale reservoirs. A primary reason for so much shale coring is that shale well log analysis requires rigorous core calibration to provide reliable data for reservoir quality, hydrocarbon-in-place, and hydraulic fracturing potential. However, the uncertainty in interpreting shale well log data is sometimes matched or exceeded by the uncertainty observed in traditional methods of analyzing core samples. Most commercial core analysis methods in use today were developed originally for sandstones and carbonates exceeding 1 millidarcy in permeability. High quality, organic-rich shale on the other hand is usually lower than 0.001 millidarcy. This extremely low permeability creates substantial challenges for existing methods and has contributed to the rapid rise of a new approach to reservoir evaluation called Digital Rock Physics (DRP).
DRP merges three key technologies that have evolved rapidly over the last decade. One is high resolution diagnostic imaging methods that permit detailed examination of the internal structure of rock samples over a wide range of scales. The second is advanced numerical methods for simulating complex physical phenomenon and the third is high speed, massively parallel computation using powerful graphical processing units (GPUs) that were originally developed for computer gaming and animation.
Based on pore-scale images from a wide range of organic shales, it can be seen that organic material is present in a variety of forms. Three primary forms of organic matter are commonly observed; non-porous, spongy, and pendular. Non-porous organic components fill all of the available non-mineral space leaving virtually no porosity or fluid flow path. Porous or "spongy?? organic material is commonly encountered in thermally mature gas shales. Pendular organic material appears to fill the small inter-granular and grain contact regions, leaving open pore space in the larger voids. These pore types are largely controlled by kerogen type and thermal maturity, and they exert large influence on the porosity, permeability, and overall shale reservoir quality.
Methodology for Digital Rock Physics
Digital rock physics analysis of shales is usually performed in three stages. Each stage provides visual and quantitative information that can be used to select a smaller but representative volume for the next stage of analysis. Stage 1 is performed on whole cores, stage 2 uses plug-size samples, and stage 3 is an ultra high resolution, 3D pore-scale analysis.
Pool, Wilfred (NAM) | Geluk, Mark (Shell Int. E&P) | Abels, Janneke (Shell International E&P) | Tiley, Graham John (Shell International E&P) | Idiz, Erdem (Shell Global Solutions International) | Leenaarts, Elise
In 2008 Shell obtained two licenses for unconventional gas exploration in the Skåne region of southern Sweden, with a total size of 2500 km2 (600,000 ac). The objective was the Cambro-Ordovician Alum Shale, one of the thickest and richest marine source rocks in onshore northern Europe.
The licenses covered the Höllviken Graben and the Colonus Shale Trough. In both areas the Alum Shale had been encountered in older wells, with a thickness of up to 90 m and TOC values up to 15%. Maturities of up to 2% Vre were considered encouraging for a shale gas play. Relative high quartz contents suggested good fraccability of the shales. All data was obtained through public sources. Identified risks were the uncertain timing of hydrocarbon generation and the position of the licenses adjacent to the Trans-European Suture Zone where several phases of fault movement have a risk for actually retaining the hydrocarbons.
The derisking strategy for this opportunity was based on both technical and non-technical aspects. Aim was to collect geological and geophysical data to constrain depth and thickness of the shale and to identify potential dolerite dykes. In addition, well data were needed to establish rock properties and gas content. The external environment, especially concerns from the people in Skåne regarding the visual impact of activities and potential impact of drilling activities on the aquifers and on the tourism industry have resulted in extensive engagements with stakeholders and specific requirements around seismic acquisition (low impact), site preparation and operations (e.g. small rig, different lighting).
80 km of 2D seismic was acquired in 2008 and three wells, with a final depth of around 1000 m, were drilled in 2009 to mid 2010. The Alum shale was fully cored and the well sites have been restored. Thickness, richness and maturity of the Alum were as predicted although the basin was shallower than previously anticipated. Canister desorption tests, however, indicated that the shales have only low gas saturation. This significantly increased the risk for a viable shale gas play and therefore the licenses were not renewed after the initial 3 year period.
Dehghan Khalili, Ahmad (U Of New South Wales) | Arns, Christoph Hermann (University of New South Wales) | Arns, Jiyoun (U. of New South Wales) | Hussain, Furqan (U. of New South Wales) | Cinar, Yildiray (U. of New South Wales) | Pinczewski, Wolf Val (Australian National University) | Latham, Shane (Saudi Aramco) | Funk, James Joseph
High-resolution Xray-CT images are increasingly used to numerically derive petrophysical properties of interest at the pore scale, in particular effective permeability. Current micro Xray-CT facilities typically offer a resolution of a few microns per voxel resulting in a field of view of about 5 mm3 for a 20482 CCD. At this scale the resolution is normally sufficient to resolve pore space connectivity and transport properties. For samples exhibiting heterogeneity above the field of view of such a single high resolution tomogram with resolved pore space, a second low resolution tomogram can provide a larger scale porosity
map. The problem then reduces to rock-typing the low resolution Xray-CT image, deriving viable porosity-permeability transforms from the high resolution Xray-CT image(s) for all rock types present, and upscaling of the permeability field to derive a plug-scale permeability.
In this study we characterize spatially heterogeneity using overlapping registered Xray-CT images derived at different resolutions spanning orders of magnitude in length scales. A 38mm diameter carbonate core is studied in detail and imaged at low resolution - and at high resolution by taking four 5mm diameter subsets, one of which is imaged using full length helical scanning. Fine-scale permeability transforms are derived using direct porosity-permeability relationships, random sampling of the porosity-permeability scatter-plot as function of porosity, and structural correlations combined with stochastic simulation. A range of these methods are applied at the coarse scale. We compare various upscaling methods including renormalization theory with direct solutions using a Laplace solver and report error bounds.
We find that for the heterogeneous samples permeability typically increases with scale. Conventional methods using basic averaging techniques fail to provide truthful vertical permeability due to large permeability contrasts. The most accurate upscaling technique is employing Darcy's law. A key part of the study is the establishment of porosity transforms between highresolution and low-resolution images to arrive at a calibrated porosity map to constraint permeability estimates for the whole core.
The new quest of unconventional resources is the achievement of well integrity which is highlighted by the inadequacy of conventional cementing procedures to provide zonal isolation. High temperatures and pressures or even post-cementing stresses imposed on the cement sheath as a result of casing pressure testing and formation integrity tests set in motion events which could compromise the long term integrity of the cement sheath due to fatigue. Knowledge of the mechanism of fatigue in cement and factors that affect it such as the magnitude of the load, strength and composition of the cement, mechanical properties of the cement and pattern of load cycles are important to achieve a realistic design of a cement system that will be subjected to fatigue loading. Such a design will go a long way to ensure the long term integrity of a well operating under downhole conditions. Finite element investigations help engineers to assess the stress magnitude and evolution for a given well configuration, but when structural calculations for casing-cement system are required, missing input parameters reduce the quality of the results.
In order to have reliable data we performed an extensive experimental work using Class G cement in order to measure the principal parameters for mechanical structural calculations: compressive and tensile strength, Young modulus, Poison Ratio. The data was measured under room conditions and elevated temperature and pressure. The results were also extrapolated for a time period for more than 300 days.
The paper will provide an excellent data inventory for class G cement that can be used when mechanical studies on cement, like finite element studies, are required.
Significant amounts of gas accumulations exist in unconventional gas plays. Current understanding held that in unconventional shale plays, natural gas was stored as "free?? gas in pore spaces and as an "adsorbed?? phase on clay minerals and surface of organic pores material. The adsorption of methane has been confirmed in lab experiments in high-pressured gas chambers. Our lab experiments indicated that hexane vapor could be adsorbed onto organic-rich shale core samples through capillary condensation and the signal could be detected by Nuclear Magnetic Resonance (NMR) instruments. This study further examines the capillary condensation of hexane vapor into clay minerals and the NMR response.
Smectite samples from the Clay Minerals Society were used in the experiments. Two types of capillary condensation experiments were conducted: one with water vapor and the other with hexane vapor, both at room conditions. Weight gains indicated that some of the vapor condensed in the loose powder of smectite clay. NMR experiments were performed on vaporsaturated samples using a Maran 2 MHz spectrometer with an inter-echo time of 300 µsec.
The T2 distributions of the water-vapor and hexane vapor-saturated smectite clay were both unimodal. The water vaporsaturated sample showed a T2 at 0.5 ms, while the hexane vapor-saturated sample showed a T2 between 1 and 6 ms. This was likely due to the fact that the smectite crystallites have a small charge that has a more pronounced effect on polarized molecules such as water, than on non-polarized molecules such as hexane.