In recent years, in unconventional reservoirs, main fracture parameters including fracture permeability and fracture volume can be early evaluated using flowback data analysis. For analysis purposes, diagnostic plots, straight-line methods, and simulation model history-matching techniques are utilized. Usually, immediate gas and water production occur during flowback in shale gas wells. In this paper, solution of water diffusivity equation for different flow regimes during the early time of well life was used to analyze water performance. These flow regimes were determined based on the diagnostic plot of water rate vs. time. The analysis from Water RTA was used to calculate initial water in place (OWIP) and fracture parameters. The difference between the OWIP and the injected fracturing fluid was correlated against the formation water saturation. The main conclusions from this analysis are; 1) High quality shale if the OWIP equal to the total injected water volume, and water-production data usually do not show the transient period and in some cases, boundary dominated flow (BDF) is present.
Gupta, Ishank (University of Oklahoma) | Rai, Chandra (University of Oklahoma) | Sondergeld, Carl (University of Oklahoma) | Hofmann, Ronny (Shell International Exploration and Production Incorporated)
Hydraulic fracturing is the completion method of choice in unconventional resource plays. Common laboratory protocols for measuring rock strength, Young’s modulus, and Poisson’s ratio typically do not account for moisture content in rocks, yet these parameters are critical in fracture designs and are greatly affected by rock moisture content.
The process of water weakening is particularly complicated in shales because of the presence of both organic matter and inorganic minerals, such as clays, silica, and calcite. We study the effects of spontaneous fluid imbibition (brine and dodecane) on Young’s modulus and hardness in shales using nanoindentation. The shales studied include Marcellus, Woodford, Eagle Ford, and Wolfcamp.
A key objective was to compare the weakening effects of 2.5 and 7.5% KCl brine solutions vs. dodecane. Our measurements show that irrespective of the shale wettability, brine led to a greater reduction in Young’s modulus (45% reduction in Marcellus, 25% in Woodford, 12% in Eagle Ford, and 21% in Wolfcamp) than dodecane (25% reduction in Marcellus, 17% in Woodford, 4% in Eagle Ford, and 3% in Wolfcamp). Increasing the concentration of the clay stabilizers, such as KCl, led to lower weakening. On the basis of these measurements, it seems that wettability also plays a role in water weakening. Marcellus, being strongly water-wet, experienced the greatest reduction in Young’s modulus and hardness. On the other hand, the Eagle Ford samples, being predominantly oil-wet, experienced the least reduction in Young’s modulus and hardness. The Wolfcamp and Woodford samples, being mixed-wet, experienced moderate reductions in Young’s modulus and hardness.
Shale hydrocarbon production has become an increasingly important part of global oil and gas supply during the past decade. The life of projects in unconventional plays, such as shale oil and gas, tight oil and gas, coal bed methane etc., heavily depends on the Estimated Ultimate Recovery (EUR). However, the correlation to predict EUR in conventional plays becomes invalid for unconventional plays, which significantly affects the economics of relevant unconventional projects. The objective of this paper is to investigate the correlations between EUR and petrophysics/engineering/production parameters by data regression and interpolation analysis via big data mining from Eagle Ford. Furthermore, a 4-D interpolated EUR database and EUR prediction models are established based on the relevant regression and interpolation results. This study not only helps us understand the physics behind EUR prediction in unconventional plays, but also facilitates determining the viability of projects in unconventional formations from a big data perspective.
In this study, petrophysics/engineering/production data from 4067 wells in Eagle Ford is summarized for analysis. Firstly, a sensitivity analysis is carried out to determine the most sensitive petrophysics and engineering controlling factors. In particular, the physics behind the EUR predictions is discussed in details. Following it, the 2-D nonlinear regression and the multivariate linear regression are applied to evaluate the relationship between EUR and engineering/production data. In addition, a 4-D interpolated EUR database is established to predict EUR based on the petrophysics parameters. The applied nonlinear multivariate interpolation methodology is the Triangulated Irregular Network based Nearest Interpolation Method (3-D). Finally, the 4-D interpolated EUR database are applied to several wells in the Eagle Ford to test its accuracy, confidence and reliability.
Based on the sensitivity analysis results, Vitrinite Reflectance Equivalent (VRE), Total Organic Carbon (TOC) and Resource Density (porosity, hydrocarbon saturation and gross formation thickness) are the most sensitive and important parameters in Eagle Ford shale formation. Based on the data-mining results, effective lateral length has a positive monotonic relation with EUR; EUR increases with more proppant weight and higher true vertical depth. Frac stage and perf per cluster do not have a strong correlation with EUR. In addition, azimuth has a vague relation with EUR while drilling along the North-South orientation is the safest approach in Eagle Ford Shale. The physics behind the correlations is analyzed and discussed in detail. Finally, several DCA EURs of wells from Eagle Ford are used to test the established 4-D interpolated EUR database, and the study results show that the relative errors in EUR predictions are within 30%, indicating that the methodology in this study has great potentials for unlocking more reserves economically in shale formations.
This study offers an insightful understanding of unconventional hydrocarbon production mechanism from a big data perspective, as well as a feasible and accurate method to predict EUR and evaluate projects economic feasibility in Eagle Ford. This methodology can be also applied to other unconventional fields such as Utica, Permian and Bakken Shale plays, if data is available.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s).
Forecasting future production and estimating ultimate recovery (EUR) in supertight reservoirs and shale plays has long been problematic. Developing a reliable and more accurate production forecast have always been a main goal of any petroleum operation. Effectively assessing the reservoir volume and well producing life is instrumental for creation of development scenarios and strategies to maximize the value to the company. Different models have been introduced and used for reserves estimation and production forecast of unconventional reservoirs. This work is intended to review and compare the methods and models currently used in the industry.
Reserves estimation is a process that is constantly updated during the life of a reservoir. Its accuracy depends on the amount of data available and the method of forecast. Analytical models or rate transient analysis (RTA) methods are widely used for history matching and production forecast of unconventional reservoirs. Numerical simulation is also used for estimating ultimate recovery. Different relations have been introduced to model the rate/time behavior in unconventional plays as an alternative to the Arps’ decline curve analysis to address shortcomings when matching production history. Modified hyperbolic decline, power-law exponential decline (PLED), stretched-exponential decline (SEPD), Duong's method, and logistic-growth model (LGM) are developed for forecasting the production in shale reservoirs, but all are based on empirical observations of a particular scenario.
In this study, different methods of history matching the production of hydraulically fractured unconventional reservoirs were investigated by forecasting future production and predicting EUR's to quantify the differences between them. The traditional Arps’ decline for low permeability reservoirs over-forecasts reserves. PLED, SEPD, LGM, and Duong's method were intended to represent the character of rate/time production data for the standard well completion in a multiple-fractured horizontal well in a shale play. These methods provide different forecasts as they have different equation forms. Unfortunately, all of them are not satisfactorily sufficient to forecast production for all unconventional reservoirs. The RTA analytical models required certain modifications of the reservoir and fracture parameters to provide optimistic EUR when compared to the numerical simulation.
Different methods for forecasting unconventional well data have been reviewed and compared in this work based on the production forecast and EUR prediction. Field case production data has been used to reveal the accuracy of the models, the similarity of reserves estimation, and the relationship to the reservoir theory.
In this study, experiments were done on samples from the Marcellus, Woodford, and Eagle Ford shales. The experiments showed that samples from these formations were grossly water-wet, mixed-wet and oil-wet, respectively. The correlation of average wettability index with total organic carbon (TOC) showed that 5 wt% is the critical TOC content required to achieve connectivity and generate oil-wet pathways. Similarly, correlation of average wettability index with clay content showed that <10 wt% clay, samples are oil-wet and >65 wt%, they are predominantly water-wet, and between 10 and 65 wt% clay content, samples exhibited mixed wettability. The threshold values of 5 wt% TOC and 10 wt% clays represent the same volumetric fraction (~10%) of the rock. The figure of 10% can be thought of as percolation threshold for connectivity in shale rocks.
Scanning electron microscope (SEM) imaging done on representative samples (one per formation) was used to quantitatively assess the fraction of different pore types. The fractions of different pore types were in agreement with the observations from the macroscopic imbibition experiments. For instance, oil-wet Eagle Ford samples had a higher fraction of organic pores (22.5%) while water-wet Marcellus samples had a higher fraction of inorganic pores (40%). The samples from all the three shales had a high fraction of mixed-wet pores (Marcellus 57%, Eagle Ford 69%, and Woodford 68%). This knowledge of fractions of different pore types can be instrumental in modeling connectivity pathways.
Pore connectivity controls fluid flow in porous media. Well-established methods such as permeability measurements or mercury-injection porosimetry are used to evaluate pore connectivity. However, these methods have limits in unconventional shale formation mainly because of the presence of different-wettability pores with large capillary pressures associated with them. In the present study, we have used the sequential spontaneous imbibition of brine and dodecane to study pore connectivity in shales. The present study shows the presence of water-wet pores, hydrocarbon-wet pores, and mixed-wettability pores. The water-wet pores are the continuous phase, and are controlled by the amount and distribution of inorganic water-wet minerals. The hydrocarbon-wet pores are essentially contained within the organic matter and require a minimum amount of total organic carbon (TOC), ≈3 wt%, to form a connected network of hydrocarbon wet pores. The ≈3 wt% of TOC is a necessary, but not sufficient, condition for developing connectivity throughout organic bodies. The mixed-wettability pores appear to enhance the systems connectivity.
This study introduces a novel outlook on a shale-pore system and on the potential effect of pore compressibility on the production performance. We divide porosity of the system into accessible and inaccessible pores, and incorporate inaccessible pores with grains into the part of the rock that is not accessible. In general, accessible pores contribute to flow directly, whereas inaccessible pores do not.
We present a mathematical model that uses mercury-injection capillary pressure (MICP) data to determine the accessible-pore and inaccessible part of the rock (IRP) compressibility as a function of pressure. During MICP testing in a typical shale sample, the rock sample experiences conformance, compression, and intrusion as effective pressure increases. We characterize the compressibility value dependent on MICP data as a function of pressure. The calculated compressibility values for accessible pores generally appear to be much greater (two to three orders of magnitude) than those of IRP.
Next, we evaluate how calculated accessible-pore-compressibility values affect gas recovery in several shale-gas plays. Our results suggest that substitution of total pore compressibility with accessible-pore compressibility can significantly change the reservoir-behavior prediction. The fundamental rock property used in many reservoir-engineering calculations including reserves estimates, reservoir performance, and production forecasting is the total pore-volume (PV) compressibility, which has an approximate value typically within the range of 1×10-6 to 1×10-4 psi-1 (Mahomad 2014). By recognizing the part of the pore system that actually contributes to production and identifying its compressibility, we can substitute total pore compressibility with accessible-pore compressibility. The result changes the value by nearly two orders of magnitude.
The outcome of the paper changes the industry’s take on prediction of reservoir performance, especially the rock-compaction mechanism. This study finds that production caused by rock compaction is in fact much greater than what has often been regarded, which will change the performance evaluation on a great number of reservoirs in terms of economic feasibility.
Matskova, N. (Universite de Poitiers) | Pret, D. (Universite de Poitiers) | Gaboreau, S. (BRGM) | Cosenza, P. (Universite de Poitiers) | Brechon, R. (Universite de Poitiers) | Gener, I. (Universite de Poitiers) | Fialips, C. I. (Total E&P) | Dubes, G. (Total E&P) | Gelin, F. (Total E&P)
Non-conventional shale reservoirs are characterized by multi-scaled pore systems closely associated with a variable spatial distribution of mineral grains and organic matter. Therefore, only an integrated multi-technique approach can provide a quantitative balance in pore size distribution. Such a balance is not achievable when each of the different methods is applied on different samples that are randomly selected within the formation being studied. In this multi-technique study, the initial cores were first scanned by μ-tomography with an achieved resolution of 78.8 μm to visualize potential spatial heterogeneities at the core scale. This approach identified similar and homogenous areas of interest for localized bulk measurements. In particular, the sub-sample positions were selected, in the 3D views, in areas presenting (i) similar non-clay grain amounts, (ii) similar X-ray linear attenuation coefficients, and (iii) no cracks or macro-heterogeneities.
This approach was applied to seven core samples (dimensions of ~7x7 cm) from the Vaca Muerta formation (Argentina), taken from three different exploration wells in zones with various hydrocarbon types (condensate gas, dry gas, and oil). These samples were chosen on the basis of well log data and their petrophysical interpretations. Lithofacies with similar mineral distribution but contrasting physical properties (resistivity, porosity, and density) and organic matter content were selected.
Conventional bulk methods were used to characterize the pore network of the selected sub-samples: mercury intrusion porosimetry, gas adsorption, nuclear magnetic resonance spectroscopy and helium pycnometry. Some of these methods are generally applied to non-localized crushed powder samples, which is inappropriate for evaluating preserved microstructure from the micro- to the macro-porosity range. For this reason, most of the acquisitions were performed on preserved core blocks, including nitrogen gas adsorption experiments, which were performed with kinetic control of adsorption equilibrium. This innovative approach has provided, for the first time ever, a full set of truly comparable data, localized on 3D views, displaying quantitative balances of pore size distribution in shale reservoirs.
Development of source-rock resources relies on the rigorous knowledge of their petrophysical properties such as porosity, permeability, and hydrocarbon saturation. In parallel, a concise description of the wettability and pore structures is commended. This paper presents a detailed Nuclear Magnetic Resonance (NMR) T2 study of the wetting characteristics and pore structure in organic-rich source rocks from different locations including the Eagle Ford formation. Although these rocks are highly laminated and calcite dominated, our studies indicated that they have distinct different pore structure and connectivity, and differ in how TOC is dispersed within the rock fabric. We believe that the entailed findings could influence our thinking on how best to produce these shales, wellbore stability, drilling fluid selection and other asset development actions.
Source-rock samples with varied amount of total organic content (TOC) were drilled perpendicular or parallel to the laminations. The samples were cut into twin plugs which were sequentially saturated by spontaneous imbibition of 5% KCl brine and diesel (oil). The NMR T2 measurements were used to determine the fluid imbibition rate and amount, as well as the porosity associated with organic and inorganic components of the source rocks. The fracture apertures were obtained via an application of characteristic T2 cutoff times to the NMR T2 distributions. The mineral elements, phases and TOC of the rocks were measured using X-ray Fluorescence (XRF), X-ray Diffraction (XRD) and HAWK pyrolysis, respectively.
The prevalence of surface relaxation on the NMR dynamics was prominent as the transverse relaxation took place at time scales (T2 ≤ 100 ms) much shorter than their bulk values. The overall wettability of the samples showed a mixed character as the brine and the oil had been intimately imbibed. Nevertheless, the details of the wetting behavior of the Eagle ford samples and the other samples were different. For instance, Eagle Ford samples imbibed larger volumes of brine and faster than oil, on the contrary the other samples imbibed larger volumes of oil and faster than brine.
The apparent preference of oil on the other samples is attributed to their high TOC compared to the Eagle Ford samples. Upon imbibition in these samples, brine is observed to flow along the clay rich bedding planes. In fact, the interaction between brine and clay is identified to be the potential driver of the rock stability problems especially near the wellbore; however it is constrained by the type of residing clays. The discrepancies in the wetting traits are magnified by the presence of fractures which enhanced the network connectivity of both hydrophobic and hydrophilic pores or even across them. Furthermore, the fractures allowed the fluids to surpass the vertical bedding planes and thus accelerating the fluid distribution processes inside the pore space. The fracture apertures were found to range from 1 μm to 15 μm which are typical values for source rocks (