Previous petrographic work has shown that shale-petroleum reservoirs at discovery are characterized by a quad-porosity system. In this work, a petrophysical model is built that allows quantification of storage capabilities in shales through determination of adsorbed porosity (øads_c), organic porosity (øorg), inorganic porosity (øm), and fracture porosity ø2). All these porosities are important because they provide reasonable input to physics-based numerical simulators for shale-petroleum reservoirs and thus more-realistic projections of reservoir performance and recoveries.
Pattern recognition is used in a modified Pickett plot for distinguishing key shale components such as total organic carbon (TOC) and level of organic metamorphism (LOM) and to distinguish between viscous and diffusion-like flow. Results from the model compare well with laboratory data.
The petrophysical model is easy to use, yet it is robust because it can handle at the same time the four porosities mentioned previously, but it can also handle simultaneously three, two, or only one of those porosities depending on the characteristics of the reservoir at a given depth.
It is concluded that the petrophysical model presented in this paper constitutes a valuable tool for physics-based characterization of shale-petroleum reservoirs.
The objective of this paper is to present a methodology with drill cuttings for making estimates of porosity, permeability, and compressibility as a function of confining pressures in tight formations.
An easy-to-use stress-dependent permeability correlation is developed by comparing results from experimental work including hysteresis at various combinations of overburden and pore pressures in vertical and horizontal core plugs, and permeabilities determined in the laboratory from drill cuttings. On the other hand, stress-dependent porosity and compressibility correlations with respect to permeability as a function of net confining stress (NCS) are also introduced. The work is important because of the presence of stress-dependent slot and/or microfracture porosities and permeabilities in tight formations that can significantly affect reservoir performance and forecasting.
Recent work has shown that drill cuttings can be used quantitatively for complete petrophysical evaluation and rock-mechanical-properties estimation (Olusola and Aguilera 2013; Ortega and Aguilera 2014). The methods have been shown to be useful in those instances in which cores and specialized well logs are scarce. Porosity and permeability values obtained from the aforementioned works are extended in this paper to quantitative evaluation of stress-dependent properties.
It is concluded that drill cuttings are important direct sources of information that can be used for developing estimates of stress-dependent petrophysical properties particularly in those cases in which cores and specialized logs are scarce or not available. The methodology and stress-dependent-permeability, -porosity, and -compressibility correlations are presented in detail, as well as a practical application for the case of drill cuttings. Although the main and novel contribution is the development of easy-to-use correlations for stress-dependent tight reservoirs with drill cuttings, the correlations can obviously be used if only plug data are available.
This research presents a new method to analyze production- and well-test data: the superposition rate. The method was developed from the well-accepted superposition principle. It is presented in a generalized form and is applicable to data in transient flow (including radial, linear, and bilinear), as well as in boundary-dominated flow (BDF).
The superposition-rate method is validated by synthetic data generated from reservoir modeling. Moreover, a practical work flow of implementing the superposition rate in production-data and well-test analysis is presented. Finally, real-field examples are used to demonstrate the practicality of superposition rate.
A comparison between the superposition-rate and superposition-time methods is presented. The superposition rate shows advantages over the superposition time. A key improvement of the superposition rate in quality diagnostics and data analysis is that it does not modify time scale. Consequently, the superposition rate keeps all production data in the sequence of their occurrence.
Quantification of secondary mineralization or cementation within natural fractures has not been considered in previous petrophysical dual-porosity models. This is, however, of paramount importance because morphology of the fractures indicates that they can be open or partially or completely mineralized.
If cementation with secondary minerals is complete, the recovery of hydrocarbons will be generally very small because hydrocarbons will not have any way to move from matrix to natural fracture and then to the wellbore. However, if secondary mineralization is partial, production rates and recoveries could be quite significant because the secondary minerals would play the role of natural proppant agents helping to maintain the fractures open as the reservoir is depleted. If the fractures are initially open, production rates and recoveries could be large or small depending on the relative orientation of the natural fractures with respect to in-situ stresses.
These observations lead to the key objective of this paper: to develop an analytical dual-porosity model using resistance networks for quantifying petrophysical fracture parameters such as degree of cementation (ß), formation factor (F), dual-porosity exponent (m), and tortuosity (t) for different degrees of mineralization (cementation) within the fractures. The method further allows estimating matrix and fracture porosities and fracture compressibility on the basis of the amount of secondary mineralization.
Use of the new dual-porosity model is explained with two core data sets drawn from tight gas formations in the United States and Canada. A comparison is made with results of current dual-porosity models that do not take into account secondary mineralization within the natural fractures and tortuosity.
The conclusion is reached that the proposed dual-porosity model provides a valuable new quantitative tool for petrophysical and reservoir-engineering evaluations of naturally fractured reservoirs. This is illustrated with two numerical examples that show determination of original petroleum in place and recovery. One example is volumetric, and the other one is based on the material-balance calculations.
Tight formations are characterized by permeabilities equal to or less than 0.1 md. Due to these low permeability values, tight gas reservoirs have been economically produced through the implementation of multi-stage hydraulic fracturing. This operation requires a proper stimulation design, which depends on the knowledge of rock properties such as Biot's constants. Therefore, the purpose of this study is to determine vertical and horizontal Biot's constants through calibration of minimum horizontal stress (MHS) with the use of well logs and mini-frac data in the tight gas Monteith formation of the Western Canada Sedimentary Basin (W CSB).
The procedure utilized in this work consists of the determination of actual MHS values from mini-frac tests. It is assumed that MHS is equal to fracture closure pressure (FCP). Two non-linear regression equations are used to estimate MHS. Statistical analysis is performed to test the appropriateness of the non-linear regression expressions for MHS modeling. Next, MHS values are calculated from well log data using an existing correlation and by the application of Monte Carlo simulation. Uniform, triangular and beta-PERT distributions are considered in this study. Then, MHS values obtained from the above two methods are matched for calibration purposes. Finally, both vertical and horizontal Biot's constants are determined from the match previously obtained.
Statistical analysis of the two non-linear regression expressions for MHS modeling reveals that FCP ranges from 10.72 MPa to 17.78 MPa in the study area. From Monte Carlo simulations, it is found that horizontal Biot's constant values are most consistent among the different distributions considered in this study as compared with the case of the vertical Biot's constant. This large variation in vertical Biot's constants is a result of the uncertainty associated with the definition of the most suitable distribution for this variable. Horizontal Biot's constant values vary from 0.81 to 0.97 whereas vertical Biot's constant ranges from 0.66 to 0.95. It is concluded that beta-PERT distribution better represents Biot's constants, however, this finding has to be corroborated against experimental data.
The methodology presented in this work is robust and represents a practical method to determine Biot's constants instead of following the assumptions considered by current commercial 3D hydraulic fracture simulators. This is the first time that non-linear regression techniques, statistical analysis, and Monte Carlo simulation are coupled all together with both well log and mini-frac data to estimate Biot's constants. This methodology can be easily applied in other tight formations.
Identification of potential oil flow zones in shale reservoirs has been conducted in the past with the use of an oil saturation index (OSI) determined from Rock-Eval pyrolysis measurements on samples collected at pre-specified depths (partial sampling). This study introduces a new equation that allow continuous OSI determination with the use of the Nuclear Magnetic Resonance (NMR) log.
Geochemical analysis using measurements from Rock-Eval pyrolysis and LECO Carbon Analyzer laboratory techniques were carried out in a shale oil reservoir for estimating parameters such as total organic carbon (TOC) and OSI. This allowed identification of hydrocarbons zones. Next, Cross-over and OSI cut-off techniques were applied to distinguish intervals with producible and non-producible hydrocarbons. Subsequently, NMR total response relaxation time, T2, was divided into eight T2 cut-offs to calculate bin porosities. A sensitivity analysis for T2 cut-offs was run in order to establish a good match between the bin porosity and OSI values that indicate producible hydrocarbons.
A good agreement was reached among OSI greater than 100 mg HC/gTOC and the bin porosities estimated between T2 = 33ms and 80 ms. This match was corroborated by the visual "oil cross-over" from geochemical analysis. An OSI cut-off equal to 100 mg HC/g TOC has been recommended in the past by several authors to differentiate producible from non-producible oil intervals. That cutoff compares well with the NMR bin porosity developed in this paper. Thus, the porosity estimation between above T2 cut-offs is a good indicator of producible hydrocarbons in a shale oil reservoir. This observation has led to the development of a new equation in this paper to convert the NMR bin porosity to OSI (or vice versa) continuously throughout the NMR logged interval.
Also, if TOC is already known from a given method (for example, Passey, Smocker, GR spectral, Uranium), the S1 parameter can be estimated from only well logs resulting in continuous S1 and OSI curves. This is a very significant advantage since Rock-Eval pyrolysis and LECO analyzer are run on samples which are taken at predefined depths (partial sampling); therefore, possible producible oil zones could be bypassed if only core results are taking into account.
Yousefzadeh, Abdolnaser (Schulich School of Engineering, University of Calgary) | Li, Qi (Schulich School of Engineering, University of Calgary) | Virues, Claudio (Nexen Energy ULC) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
We present a comparison of three different hydraulic fracture models as well as an anisotropic diffusivity model with the observed microseismic data from shale gas reservoirs in the Horn River Basin of Canada. We investigated the validity of these models in the prediction of hydraulic fracture geometries using tempo-spatial extension of microseismic data. In the study area, ten horizontal wells were drilled and hydraulically fractured in multiple stages in the Muskwa, Otter Park, and Evie shale gas formations in 2013. The treatments were monitored by downhole microseismic measurements.
We integrated microseismic analyses, geomechanical information extracted from well logs, and fracturing treatment parameters performed in the area. We compared fracture geometry predicted by Perkins-Kern-Nordgren (PKN), Khristianovic-Geertsma-de Klerk (KGD), and a Pseudo-3D (P3D) fracturing models as well as an anisotropic diffusivity model with actual fracture geometries derived from microseismic records in more than one hundred fracturing stages.
For the study area, we find that there are no barriers to hydraulic fracture vertical growth between the Muskwa, Otter Park and Evie shales. Therefore, the fracture height to length ratio is higher than unity in many stages. Large fracturing heights suggest that the PKN model might be more suitable for fracture modeling than the KGD model. However, our analyses show that the fracture length predicted by the KGD model is closer to, but still far less than the fracture length illustrated by microseismic events. Pseudo 3D model also predicts fracture lengths which are slightly larger than the modeled fracture lengths by the KGD and PKN equations and still significantly smaller than the microseismic fracture lengths.
These differences are observed throughout all stages suggesting that these methods are not able to perfectly predict the hydraulic fracturing behavior in the study wellpad. Vertical extension of microseismic data with linear patterns into the Keg River formation below the shale formations suggests the presence of natural fractures in the study area.
This study presents a distinctive insight into the complex hydraulic fracture modeling of shales in the Horn River basin and suggests that diffusivity mapping is a simple, but powerful tool for hydraulic fracture modeling in these formations. Observed microseismic fracture lengths are significantly higher than lengths predicted by the geomechanical models and closer to diffusivity models, which suggests the possibility of increasing well-spacing in future development using diffusivity equation for improving treatment design.
Fragoso, Alfonso (Schulich School of Engineering, University of Calgary) | Trick, Mona (Schlumberger Canada Limited) | Harding, Thomas (Nexen Energy ULC) | Selvan, Karthik (Nexen Energy ULC) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
The objective of this paper is to couple wellbore and surface production facilities models with reservoir simulation for a shale reservoir that contains dry gas, condensate and oil in separate containers. The goal of this integration is to improve liquid recoveries by dry gas injection and gas recycling.
Methods published up to now to investigate possible means of improving recovery from shales have concentrated on laboratory work and the reservoir itself, but have ignored the surface and wellbore production facilities. The coupling of these facilities in the simulation work is critical, particularly in cases involving condensate and oil reservoirs, gas injection and recycling operations. This is so because a change in pressure in the reservoir is reflected almost immediately in a change in pressure in the wellbore and in the surface installations.
The development presented in this paper considers multi-stage hydraulically fractured horizontal wells. Dry gas is injected into zones that contain condensate and oil. Gas stripped from the condensate production is re-injected in the condensate zone in a recycling operation.
The study leads to the conclusion that liquid recoveries can be maximized by utilizing continuous and huff and puff gas injection schemes. In general, huff and puff injection provides better results in terms of production and economics. Molecular diffusion is found to play a crucial role in continuous gas injection operations. Conversely, the effect of this phenomenon is negligible in huff and puff gas injection. This research demonstrates that proper design of wellbore and surface installations, including for example downhole pumps and compressors, is important as they play a critical role in the performance of production and injection operations, and in maximizing recovery of liquids from shale reservoirs.
The novelty of the methodology developed in this paper is the coupling of models that handle surface facilities, wellbores, numerical simulation including oil, condensate and dry gas reservoirs, gas injection and gas-condensate recycling operations. Essentially the shale containers, wellbore and surface facilities are ‘talking’ to each other continuously. To the best of our knowledge this integration for shales has not been published previously in the literature.
Tight reservoirs with low and ultralow permeability must be successfully stimulated to produce at economic oil or gas rates. For this reason, costs of drilling and completing wells are very high in tight reservoirs. In order to reduce these costs, operators have often tried to replicate the same or similar hydraulic fracturing designs that have been successfully used in previous wells in the same geological area. This strategy sometimes results in unexpected surprises and operational challenges leading to unsuccessful stimulations and poor production performance. The major reason behind these challenges is that tight reservoirs exhibit a localized behavior with changes in reservoir quality such as mineralogy, hydrocarbon content, and thickness across the same reservoir.
In order to study the localized behavior of tight reservoirs; three wells that penetrated the Eaglebine formation in Texas were evaluated. The Eaglebine formation contains both the Eagle Ford and the Woodbine reservoirs. The combined Eagle Ford and Woodbine (Eaglebine) reservoir can sometimes exceed 1,000 feet in thickness. These reservoirs are present at depths between 6,500 and 15,000 feet in East Texas. In some areas, the Eaglebine contains a large percentage of silica-rich sands interbedded in organic rich shale and carbonate layers.
This paper investigates the reasons as to why same hydraulic fracturing techniques should not be applied necessarily for every well in the same geological area. Furthermore, it demonstrates how we can exploit the localized reservoir behavior to plan for future wells despite limited data availability. Data from mud logs, well logs, and cores, including mineralogy and geomechanical data are integrated to build the localized reservoir characterization model that can be used to plan how each individual well should be hydraulically fractured. The model provides information such as location of organic-rich zones, brittle zones, and ductile zones in a geological area. Lastly, it recommends the type of fracture fluid that can yield a successful stimulation operation in ductile or brittle zones.
During the last few years, production of liquid hydrocarbons has been reported from the gas-condensate window of the Eagle Ford, Barnett, Niobrara, and Marcellus shale plays in the US. This paper presents a new material-balance equation (MBE) for estimation of original gas in place (OGIP) and original condensate in place (OCIP) in shale-gas-condensate reservoirs. This material-balance methodology allows estimating the critical time for implementing gas injection in those cases in which condensate buildup represents a problem. In addition, the proposed MBE considers the effects of free, adsorbed, and dissolved gas-condensate production, and also takes into account the stress-dependency of porosity and permeability. An extension of the methodology is implemented for estimating the optimum time for hydraulically refracturing shale-condensate reservoirs.
The new MBE applies to shale-gas-condensate reservoirs by incorporating a two-phase gas-deviation factor (Z2) and total cumulative gas production (Gpt) that includes both gas and condensate. If a crossplot of P/Z2 (pressure/Z2) vs. Gpt is prepared for a conventional gas-condensate reservoir, a single straight line is obtained. However, when the single-phase gas-compressibility factor (Z) is used, a deviation from the linear behavior is observed after the reservoir pressure falls below the gas dewpoint. This methodology is applied in this study to unconventional shale-gas condensate. Because there are three characteristic stages of production in a shale-gas reservoir (production of free, adsorbed, and dissolved gas), the location of the aforementioned deviation will provide a hint of the production stage that will be affected by condensate buildup. For example, if the deviation point is in the region where production of free gas is predominant, then the production caused by desorption mechanisms will be negatively affected because condensation will have already occurred in the reservoir, resulting in reduction of effective permeability to gas. This methodology then allows estimating the critical time for implementing gas injection on the basis of the total cumulative gas production. The method also permits estimating the optimum time for refracturing. The refracturing can be of a normal size for a given shale (similar to the original fracturing job), or it can be a superfrac job.
Results are presented as crossplots of (1) P/Z2 vs. Gpt, (2) Gpt vs. time, and (3) gas rate vs. time. It is concluded that estimation of the critical time for implementing gas injection is useful for improving the performance of those shale-gas-condensate reservoirs in which condensate buildup represents a threat that can negatively affect the gas-production rate.
The novelty of this work resides on the fact that the combined effect of free, adsorbed, and dissolved gas-production mechanisms on stress-sensitive shale-gas-condensate reservoirs had not been considered previously in the literature for estimation of OGIP, OCIP, and reservoir performance with an analytical MBE. The inclusion of gas injection and refracturing had not been considered either.