Najmah-Sargelu Formations of Kuwait show considerable potential as a new unconventional hydrocarbon play and produces mainly from fractures. The key uncertainties which affect the productivity are the nature and distribution of permeable fracture networks, and the limits of oil accumulation.
This paper presents the results from whole-rock elemental analysis of three cored wells in UG field. The main objectives of this study are to use high-resolution elemental chemostratigraphy to gain a better understanding of the detailed stratigraphy and correlation of the Najmah-Sargelu Formations, to assess the chemo-sedimentology for determining the intervals of high organic content, to estimate the mineralogy of the sequence using an algorithm developed for an analog formation in North America; and to determine the most likely intervals to contain fractures, using a brittleness algorithm.
A clear chemo stratigraphic zonation is recognized within the Najmah-Sargelu Formation. The larger divisions are driven mainly by inherent lithological variation. The finer divisions are delineated by more subtle chemo stratigraphic signals (K2O/Th and Rb/Al2O3 ratios) and preservation of organic matter (high V, Ni, Mo, and U abundances). Zones of alternating brittleness and ductility are clearly identified within the interbedded limestones and marlstones of Najmah-Sargelu Formation.
Two unexpected but important features of the Najmah-Sargelu limestones were elucidated by the elemental data. Brittle, high-silica spiculites, with virtually no clay or silt, are more common than previously recognized from petrophysical logs and core descriptions in the upper Najmah limestones. In addition, the limestones adjacent to the spiculites tend to contain bitumen as pore-filling are recognized by the trace metal proxies. Ternary plots of V, Ni, and Mo differentiate the combinations of kerogen and bitumen present in the Najmah-Sargelu Formations.
The clarity and sensitivity of the chemostratigraphic signals are sufficient to enhance formation evaluation, and can also assist borehole positioning using the RockWiseSM ED-XRF instrument at wellsite.
On the basis of micro- and mesoscale investigations, a new mathematical formulation is introduced in detail to investigate multiscale gas-transport phenomena in organic-rich-shale core samples. The formulation includes dual-porosity continua, where shale permeability is associated with inorganic matrix with relatively large irregularly shaped pores and fractures, whereas molecular phenomena (diffusive transport and nonlinear sorption) are associated with the kerogen pores. Kerogen is considered a nanoporous organic material finely dispersed within the inorganic matrix. The formulation is used to model and history match gas-permeation measurements in the laboratory using shale core plugs under confining stress. The results indicate significance of molecular transport and strong transient effects caused by gas/solid interactions within the kerogen. In the second part of the paper, we present a novel multiscale perturbation approach to quantify the overall impact of local porosity fluctuations associated with a spatially nonuniform kerogen distribution on the adsorption and transport in shale gas reservoirs. Adopting weak-noise and mean-field approximation, the approach applies a stochastic upscaling technique to the mathematical formulation developed in the first part for the laboratory. It allows us to investigate local kerogenheterogeneity effects in spectral (Fourier-Laplace) domain and to obtain an upscaled "macroscopic" model, which consists of the local heterogeneity effects in the real time-space domain. The new upscaled formulation is compared numerically with the previous homogeneous case using finite-difference approximations to initial/boundary value problems simulating the matrix gas release. We show that macrotransport and macrokinetics effects of kerogen heterogeneity are nontrivial and affect cumulative gas recovery. The work is important and timely for development of new-generation shale-gas reservoir-flow simulators, and it can be used in the laboratory for organic-rich gas-shale characterization.
Clarkson, Christopher R. (University of Calgary) | Wood, James (Encana Corporation) | Burgis, Sinclair (Encana Corporation) | Aquino, Samuel (University of Calgary) | Freeman, Melissa (University of Calgary)
The pore structure of unconventional gas reservoirs, despite having a significant impact on hydrocarbon storage and transport, has historically been difficult to characterize because of a wide poresize distribution (PSD), with a significant pore volume (PV) in the nanopore range. A variety of methods is typically required to characterize the full pore spectrum, with each individual technique limited to a certain pore size range. In this work, we investigate the use of nondestructive, low-pressure adsorption methods, in particular low-pressure N2 adsorption analysis, to infer pore shape and to determine PSDs of a tight gas siltstone reservoir in western Canada. Unlike previous studies, core-plug samples, not crushed samples, are used for isotherm analysis, allowing an undisturbed pore structure (i.e., uncrushed) to be analyzed. Furthermore, the core plugs used for isotherm analysis are subsamples (end pieces) of cores for which mercury-injection capillary pressure (MICP) and permeability measurements were previously performed, allowing a more direct comparison with these techniques. PSDs, determined from two isotherm interpretation methods [Barrett-Joyner-Halenda (BJH) theory and density functional theory (DFT)], are in reasonable agreement with MICP data for the portion of the PSD sampled by both. The pore geometry is interpreted as slot-shaped, as inferred from isotherm hysteresis loop shape, the agreement between adsorption- and MICP-derived dominant pore sizes, scanning-electron-microscope (SEM) imaging, and the character of measured permeability stress dependence. Although correlations between inorganic composition and total organic carbon (TOC) and between dominant pore-throat size and permeability are weak, the sample with the lowest illite clay and TOC content has the largest dominant pore-throat size and highest permeability, as estimated from MICP. The presence of stress relief-induced microfractures, however, appears to affect laboratory-derived (pressure-decay and pulse-decay) estimates of permeability for some samples, even after application of confining pressure. On the basis of the premise of slot-shaped pore geometry, fractured rock models (matchstick and cube) were used to predict absolute permeability, by use of dominant pore-throat size from MICP/adsorption analysis and porosity measured under confining pressure. The predictions are reasonable, although permeability is mostly overpredicted for samples that are unaffected by stressrelease fractures. The conceptual model used to justify the application of these models is slot pores at grain boundaries or between organic matter and framework grains.
Despite the extensive use of new technologies for the exploration of unconventional organic rich shale resources and vast work on the prediction of the quantities of light hydrocarbons (Gas in Place, GIP), many questions remaining concerning the storage, migration and production of natural gas in unconventional gas shales. There is a need for a deeper understanding of the physics and chemistry of light hydrocarbon molecules within the micro- and nanopores in the kerogen. A number of research results have been published that emphasize the importance of nanopores in kerogen for the unconventional shale resource plays, and our previously published laboratory results have shown that it is possible for gas to condense into liquid in the nanopores of kerogen once the Kelvin equation is satisfied.
Petrographic features of several Woodford shale core samples were studied using Scanning Electron Microscopy (SEM) on splintered and Focused Ion Beam (FIB) milled surfaces. The morphologic features and the connectivity of the pores in kerogen were recorded. We performed gas condensation experiments on these samples using hexane and found that there is a close relationship between the amount of condensed gas and the porosity within the kerogen. Based on the nanopore physics the flow of gas within the organic matter will be significantly impacted by capillary condensation. Nuclear Magnetic Resonance (NMR) measurement on the samples with condensed gas components show that the relaxation is also significantly affected by the properties of the nanopores within the kerogen of the unconventional shale samples and must be properly accounted for in the formation evaluation.
Background - Motivation
Organic rich gas and light-oil shale wells have become an important resource for North America and likely will become more important globally in the coming years. In North America there is a plethora of existing well data obtained during 100+ years of drilling for conventional hydrocarbon wells. Thus, the location of the unconventional, organic-rich shale-source-rock resource plays is well known. Nevertheless, two substantial problems with significant economic importance remain for the unconventional shale plays:
Carbonate reservoirs are commonly heterogeneous and their reservoir quality results from complex interactions between depositional facies and diagenetic processes. The Diagenetic Diagram is a powerful tool that helps in the characterization of the diagenetic processes that have affected the reservoir. From this knowledge, it is possible to significantly improve the understanding of the reservoir's pore system and permeability distributions, which are key factors for development optimization and production sustainability.
A multi-scale and multi-method study (petrography, blue-dye impregnation, selective staining and porosity determination) of Middle Jurassic carbonates from the Lusitanian Basin (Portugal) has been undertaken, to find the best systematic approach to these reservoirs. It has involved thorough diagenetic characterization of each lithotype (lithofacies, texture, porosity, qualitative permeability assessment and diagenetic evolution). The study area was selected based on its excellent and varied exposures of carbonate facies and availability of core.
Methodological and terminological challenges were faced during the study, especially dealing with data coming from several scales (macro, meso, and micro). In order to overcome these challenges, a diagenetic diagram was developed and applied to the selected rocks. It is a tool that allows the integration of data coming from outcrops, hand samples, cores, cuttings, thin sections, and laboratory experiments.
This is carried out in a dynamic, guided, systematic, and rigorous way, enabling the evaluation of the relationship between facies, diagenetic evolution and pore systems. The latter are characterized regarding size, geometry, distribution, and connectivity. This enables the identification and characterization of permeability heterogeneities in the rocks. It was concluded that the main porosity class (i.e. secondary) was created by diagenetic processes.
The proposed method has strong application potential for: detailed characterization and understanding of porosity and permeability in carbonate reservoirs, from a diagenetic evolution and fluid flow perspective (e.g. SCAL and pore system description); definition of diagenetic trends for modeling petrophysical properties and rock types. In this regard, the method is being applied to a Valanginian carbonate reservoir in Kazakhstan, and some preliminary results are presented in this paper. Refining this technique may be helpful for similar carbonate studies, enhancing the results of typical diagenetic studies by improving the characterization of reservoir properties at various scales, thus contributing to a more sustainable exploitation of hydrocarbon reservoirs.
Technology Update - No abstract available.
Our studies of the underlying fundamental gas-recovery mechanisms from shale gas are motivated by expectations of the increasing role of shale gas in national energy portfolios worldwide. We use pore-scale analysis of reservoir shale samples to identify critical parameters to be employed in a gas-flow model used to evaluate well-production data. We exploit a number of 3D-imaging technologies to study the complexity of shale pore structure: from low-resolution X-ray computed tomography (CT) to focused ion beam and scanning electron microscopy (FIB/SEM). We observe that heterogeneity is present at all scales. The CT data show fractures, thin layers, and density heterogeneity. The nanometer-scale-resolution FIB/SEM images show that various mineral inclusions, clays, and organic matter are dispersed within a volume of few-hundred µm3. Samples from different regions differ sharply in the shape, size, and distribution of pores, solid grains, and the presence of organic matter. Although the samples have clearly distinguishable signatures related to the regions of origin, extremely low permeability is a common feature. This and other pore-scale observations suggest a bounded-stimulated-domain model of a horizontal well within fractured shale that accounts for both compression and adsorption gas storage. Using the method of integral relations, we obtain an analytical formula approximating the solution to the pseudopressure diffusion equation. This formula makes fast and simple evaluation of well production possible without resorting to complex computations. It ss a decline curve, which predicts two stages of production. During the early stage, the production rate declines with the reciprocal of the square root of time, whereas later, the rate declines exponentially. The model has been verified by successfully matching monthly production data from a number of shale-gas wells collected over several years of operation. With appropriate scaling, the data from multiple wells collapse on a single type curve. Pore-scale image analysis and the mesoscale model suggest a dimensionless adsorption-storage factor (ASF) to characterize the relative contributions of compression and adsorption gas storage.
For unconventional gas resources such as coal and organic-rich shale, sorbed-phase is an important component of storage and transport calculations. Routine measurements of sorption are, however, performed separately from the porosity and permeability measurements. In this work a new gas storage measurement technique is proposed combining the porosity and sorption measurements. Because the measurement is done using core plug under confining stress, it allows investigating the storage capacity for varying effective stress and incorporating the storage data into a subsequent permeability measurement under the same conditions.
During construction of the sorption isotherm in the laboratory using Boyle's law setup and a volumetric method, at each pressure step, volume of the sorbed gas taken up by the sample reduces the pore volume of the sample. As a result, the initially determined pore volume at low pressure must be corrected at the beginning and at the end of the pressure step. Also known as Gibbs correction, this correction can be done relatively easily during the routine sorption measurements with the crushed samples; however, it is a challenging task with core plugs under confining stress because at each pressure step the pore volume could also change due pore compressibility. Our approach is based on a new analytical model of total gas storability developed to interpret multiple-step laboratory measured pressure data on a graphical domain where the parameter estimation can be done fast and accurately using a straight line. The approach considers both the compressibility and sorbed-phase effects on the pore volume and the sorption parameters.
Experimental storage data of various shale and coal samples with varying total organic content and maturity is used to demonstrate applicability of the analytical method to the measurements. Our results show that the sorption measurements can be done with increased accuracy and relatively fast. The work is important for organic-rich sample characterization in the laboratory, and for gas-in-place and transport calculations.
Traditional methods of determining wettability such as the Amott and the U.S. Bureau of Mines (USBM) test for an oil/brine/rock system are difficult to apply to shales due to their extremely low permeability, usually in the nanodarcy range. Earlier Nuclear Magnetic Resonance (NMR) studies on Berea sandstone showed consistency with standard wettablity measurements and served as a calibration standard. A total of 10 core plugs from an Ordovician organic rich shale were analyzed. The T2 NMR signature of the imbibed dodecane and brine occurred mostly at relaxation times faster than their measured bulk relaxation of 1 and 3 second, respectively, indicating that surface relaxation is dominant. The Ordovician organic rich shale display mixed wettability. Three of the samples had a high affinity for dodecane, as a result of the organic pores present in the samples. This result was consistent with the NMR spectra in both sequences as well as the gravimetric analysis. The main advantage NMR has over the traditional methods is that we are able to see where the fluids are being imbibed.
Mercury injection capillary pressure (MICP) characterizes the distribution of pore throats while NMR responds to the pore bodies. Assuming the throats and bodeies are equivalent, a scaling factor was used to match the NMR spectra and the MICP curves to estimate the effective surface relaxivity for the shale samples. The range of the effective surface relaxivities ranged between 0.5µm/sec to 3.1µm/sec with an average of 1.7 ± 1.0 µm/sec. Mineralogy variations were observed across the 10 shale samples but showed a correlation which suggests that the effective surface relaxivity is dependent on mineralogy.
Fracture fluid flow back has been identified as one of the major challenges of hydraulic fracturing operations conducted in shale reservoirs. Factors causing the very low fracture fluid recovery need to be well understood and properly addressed, in
order to get full benefits from costly hydraulic fracture jobs conducted in unconventional reservoirs. Despite the recent surge of investigations of the problem, one major question still remains: what happens to the fracture fluid that is not recovered?
Does it stay in the fracture or does it go into the matrix? In case of both mechanisms are responsible for fracture fluid retainment, what fraction of fracture fluid stays in the propped fracture and what fraction is transferred from fracture to
matrix. The focus of the current study is to understand if the transfer of fracture fluid from fracture to matrix through imbibition is of significant importance.
We systematically measure the imbibition rate of water, brine, and oil into the actual core samples from the three shale sections of Horn River basin (i.e., Fort Simpson, Muskwa and Otter Park). We characterize the shale samples by measuring,
porosity, wettability, mineral composition through XRD analysis, and interpreting the well log data. The results show that imbibition could be a viable mechanism for fluid transfer from fracture to matrix in Horn River shales. The comparative study shows the imbibition rate in the direction parallel to the bedding plane is higher than that in the direction perpendicular to the bedding. The study also suggests that the imbibition rate of the aqueous phases is significantly
higher than that of the oleic phases.