The document presents a consistent method to build 3D Mechanical Earth Models (3D MEM). It is based on a rock physics study to derive field specific correlations between mechanical properties and interpreted petrophysical quantities. The 3D MEMs built using this methodology yield robustness and consistency when matching to the measured minimum stress. They also display good predictive capabilities making them valuable for operational design.
This method consists of conducting a preliminary rock physics study in order to obtain correlations between the mechanical properties (elastic moduli and strength), of the various formations that are considered, and basic interpreted quantities which are readily available in most 3D geological models (porosity or mineralogy). The correlations are used to build a 3D MEM which is consistent with both the 3D geological model and the 1D geomechanical interpretation. It is also possible to extend the correlations by linking raw log data to rock mechanical properties.
The model was tested against field case study to verify its predictiveness. Minimum stresses calculated by the 3D MEM matched well to the measured values obtained from mini-frac tests performed at various locations. Ultimately it permits to better forecast the material properties (in 3D) as well as the effective stress tensor (in 4D). The 3D MEMs were used to evaluate the risks for infill drilling, and for completion purposes. Performing this type of preliminary rock physics study has a number of benefits. Firstly, to help identify which logging suite should be run to characterize the geomechanical properties of a given formation, and secondly it can be used to derive correlations between raw log data and geomechanical properties. These correlations can be applied during operations for real time decision making purposes when there is not yet a petrophysical interpretation available.
The novelty of the method introduced lies in the systematic and coherent integration of data to build a consistent geomechanical model (3D or 1D), that exhibits a robust predictive capability and shows the value of 3D MEM for the design of drilling and completion operations.
Halliburton, United States The'A' formation in the Abu Gharadig basin, northern Western Desert of Egypt is a carbonate reservoir characterized as a low-permeability soft chalk with medium porosity and low-quality natural fractures. Owing to these characteristics, achieving economical gas production rates and efficiently developing the reservoir have become increasingly challenging. To increase production from the field, a full development plan was initiated employing drilling of horizontal wells with multistage fracturing stimulation. An integrated and detailed programme of laboratory core testing was conducted to gain an indepth understanding of this reservoir's rock mechanics behaviour and to help optimize the hydraulic fracturing and completion designs. Particularly, elastic properties and principal in-situ stresses were acquired to provide the following: -Static and dynamic mechanical property information for correlating well log data -Calibration to the mechanical earth models constructed from sonic-derived mechanical properties to help provide realistic deformation parameters for hydraulic fracturing design purposes.
ABSTRACT: Layering-induced anisotropy of shale formations increases uncertainty in determining in-situ mechanical properties and stresses, thus increasing the risk associated with implementing advanced drilling and hydraulic stimulation in shales. We conduct simultaneous triaxial stress tests and ultrasonic wave propagation monitoring to quantify static and dynamic stiffness anisotropy in Mancos Shale. Two case studies evidence the impacts of (1) confining stress and (2) presence of pre-existing fractures, on dynamic-static transforms of Young’s moduli and Poisson’s ratios with increasing deviatoric stress. The first case shows that confining stress more heavily impacts dynamic mechanical properties than static. The effect is most prominent at high deviatoric stresses, where stress-induced damage increases the difference between dynamic and static Young’s moduli. The second case shows that samples with pre-existing fractures exhibit even higher differences between dynamic and static Young’s moduli than non-fractured (intact) and damaged rocks. Fractured samples exhibit ratios of Edyn/Est between 5:1 and 7:1, whereas intact samples generally remain near the 3:1 ratio. Pre- and post-test X-ray microtomography imaging confirm that bedding planes and pre-existing fractures act as planes of weakness, while sample layering causes mechanical stratigraphy, where changes in lithology may cause fractures to reorient. Results highlight the limitations of tangent linear elasticity moduli to explain complex deformational behavior in shales and the need for better models that address the strain-magnitude dependence of rock properties.
Shale layering causes bed-parallel differences in rock properties, a component of mechanical stratigraphy (Laubach et al. 2009). Stratigraphic variations in mechanical properties are known to influence the growth of engineered fractures (Bosziak et al. 2014). A further element of bed-perpendicular anisotropy can be introduced by pre-existing fractures, which can impact rock stress-strain response (Bergbauer and Pollard 2004). Over geologic time, subsurface stresses may vary, which can cause natural fracturing. Chemical alteration (diagenesis) might stiffen natural fractures, therefore their orientations might not be aligned with current stresses or layering (Laubach et al. 2004). Consequently, the attributes and orientation of layering and diagenetically altered open fractures can impact rock mechanical behavior, engineered fracture growth, and rock failure under a range of loading paths. Layering and pre-existing fractures are suspected to influence the behavior of shales undergoing hydraulic fracture treatment (Suarez-Rivera et al. 2013, Gale et al. 2014).
The Apollonia formation is a tight gas carbonate reservoir characterized as a low permeability soft chalk (Young’s modulus ~ 1 MM psi) with medium porosity and low quality natural fractures. The ability to achieve economical production rates and efficiently develop the Apollonia with those characteristics has become increasingly challenging. To further increase production from the field, a development plan was initiated employing drilling of horizontal wells with multistage fracturing stimulation. An integrated and detailed workflow of laboratory core testing was established to gain an in-depth understanding of this reservoir’s rock mechanics behavior and to help optimize the hydraulic fracturing and completion designs. Particularly, elastic properties and principal in-situ stresses were acquired to provide the following:
The evaluation program of mechanical properties testing was conducted on selected core samples and integrated logs from two offset vertical wells. The laboratory testing program consisted of the following:
All laboratory data, including procedures, tabulated results, stress-strain plots, computerized tomography scan images, and post-test sample images are provided for analysis and visualization of the failure mode. By understanding the reservoir geomechanics behavior and the mechanical parameters that have a critical impact on the hydraulic fracturing propagation, improved decision making in terms of fracturing design and optimization was made. Software was used to model the propagation of hydraulic fractures based on the integrated reservoir mechanical properties analysis. Different scenarios of perforation clusters were run to model propagation of multiple horizontal fractures and predict the changes in stress anisotropy in the neighborhood of the fractures. Results revealed that an increased number of perforation clusters attributed to increased stress interference from the outer fractures, causing reduced inner fracture half-length and resulting in longitudinal fracture propagation rather than transverse fractures, thus reducing the stimulated reservoir volume. The results of this study improve the understanding of the Apollonia reservoir mechanical properties and help provide valuable insight into optimization of multistage hydraulic fracturing design in horizontal wellbores, thus establishing the base for subsequent reservoir development.
Yu, Hongyan (State Key Laboratory of Continental Dynamics & Geology Department of Northwest University) | Wang, Zhenliang (State Key Laboratory of Continental Dynamics & Geology Department of Northwest University) | Rezaee, Reza (Curtin University) | Arif, Muhammad (Curtin University) | Xiao, Liang (China University of Geosciences)
Understanding the elastic properties of rocks is very important for unconventional reservoirs exploration. Unlike marine shale, the lacustrine shale is more complicated with complex mineral composition and frequent sand and shale interbeds. Typical analysis for lacustrine shale gas reservoir rock include: triaxial test, X-ray diffraction (XRD), total organic carbon (TOC) measurements. The mineral composition is different for argillaceous shale and silty laminae shale. The static elastic properties are controlled by clay content, organic matter and porosity. In this work we evaluate elastic properties of above mentioned rocks using experimeal core analysis and well log data. Based on triaxial test, Young's modulus and Poisson's ratio of rocks are obtained by means of the relationship between strain and stress. Argillaceous shale is low to medium strength rock, and silty laminae shale belongs to medium to high strength rock. We find that Young's modulus and Poison's ratio has a negative relationship with clay content, organic matter and porosity which is present by bulk density and neutron porosity logs. The dynamic elastic properties are obtained from cross diploe acoustic well logging data. The dynamic elastic properties have the same controlling factors as static properties. Argillaceous shale and silty laminae shale have significantly different response characteristics in well logging. The porosity is the main factor which leads to the differences between dynamic and static elastic properties. Moreover, it is also found that the ratio of static and dynamic elastic properties is a function of porosity. Hence, density porosity and neutron porosity from the logs are chosen to establish dynamic elastic properties correction model. The correction model is effective in predicting static properties in lacustrine shale gas reservoirs. We conclude that the static properties obtained from the correction model match with core derived static properties.
This paper proposes a novel understanding of the mechanisms of coal and gas outbursts based on static-dynamic coupling loading and effective stress theory. Previous mechanisms of coal and gas outburst have a problem in describing the failure process of coal. Static-dynamic coupling loading is required to fully understand the development process of coal and gas outburst. The effective stress theory is also introduced to analyze the coal and gas outburst due to its similarity with that of sand vibrating liquefaction. Our results show that coal experiences deformation of shear compression instead of dilatancy in the development process of coal and gas outburst. Furthermore, coal not only absorbs in-situ stress, but also endures dynamic loading. In particular, the measured data suggests that when approaching the dangerous region of coal and gas outburst, coal seam gas pressure significantly rises with increasing compressive deformation of coal seam. These results validate our proposal. Additionally, a physical-mechanics model is established to realize quantitative analysis of the mechanism of coal and gas outburst.
Nowadays, a comprehensive action hypothesis (Xo?ot, 1966, and Bufan, 1985) has been widely used in the study of mechanisms of coal and gas outbursts, which is regarded as comprehensive action results of in-situ stress, physical and mechanics properties of coal, and coal seam gas pressure. Under the guidance of comprehensive action hypothesis, great attention has been paid to describe the mechanics failure mechanisms of coal and gas outbursts from different aspects (Zhemin, 1982. Zhongcheng, 1987. Shinin, 1990. Mengtao, 1991. Chenglin and Bin, 1995. Shaolin, 1999. Deyong, 2003. Qianting, 2008). Mechanics basis of these mechanisms is mainly derived from traditional rock mechanics. These mechanisms have provided a powerful theoretical guideline for the prediction and prevention in coal and gas outbursts. However, based on traditional rock mechanics, dilatancy cannot explain the rise of coal seam gas pressure during coal and gas outburst which has been observed at site. Actually, coal not only absorbs in-situ stress, but also endures dynamic loading which is not taken into consideration in the traditional rock mechanics. Coal and gas outburst always occurs in the region which contains tectonic coal. However, mechanics properties of tectonic coal under static-dynamic coupling loading have not been investigated yet. Additionally, we find that coal and gas outburst has a similarity with sand vibrating liquefaction, as they are both about granular element under staticdynamic coupling loading. Therefore, this paper proposes a novel mechanism of coal and gas outbursts based on effective stress theory and static-dynamic coupling loading theory. Our work includes theoretical analysis, site validation, and model establishment.
Rocks that exhibit multi-modal throat-size distributions cannot be reliably appraised and classified using conventional methods such as Winland R35 (Pittman, 1992) or Amaefule's flow zone indicator (Amaefule et al., 1993). Such popular classification procedures/protocols are tacitly based on the concept that rocks exhibit a single dominant throat-size, and they do not consider neither the multi-modality nature of throats, nor the variation in the amplitude of throat or grain-size distributions. Carbonates and tight-gas sandstones are notorious for their non-unimodal variability of throat sizes. Wide variations of throat sizes are also often observed in rocks which have been subject to extreme diagenesis and recrystallization.
This paper introduces new rock classification methods based on mercury-intrusion capillary pressure (MICP) and grain-size distribution measurements. We use three types of parametric basis functions to reproduce logarithmic throat-size and grain-size distributions derived from MICP data and grain-size distribution measurements. Magnetic resonance data are also invoked to quantify irreducible water saturation. First, a multi-modal Lorentzian distribution function is introduced where the function's free parameters are used to establish correlations between permeability and irreducible water saturation. In cases where grain-size data are available, we show how to estimate irreducible water saturation based on the surface-to-volume ratio of the rock. Results are then compared to a bimodal Gaussian distribution (Xu et al., 2013), and Thomeer hyperbolas (Thomeer, 1960), to assess when each method may or may not be more accurate to model the distribution of throat sizes and the corresponding flow properties. Finally, we introduce a new rock classification method that accounts for all pore and throat-geometry parameters to quantify storage and flow properties of rocks.
In the case of Cotton-Valley group tight-gas sandstones, the new rock classification method reliably identifies outlier permeability measurements and groups rocks with common pore textural properties. We emphasize the importance of assimilating the multi-modality of throat sizes with a Panoma carbonate field example, where a more accurate rock classification is obtained when compared to the flow-zone indicator method. Finally, we examine the case of a clastic offshore field in Trinidad, where additional petrophysical data confirm that the bimodal nature of the grain-size distribution renders a reliable estimation of irreducible water saturation.
The Keshen reservoir in China is a deep, tight-gas-sandstone reservoir under high tectonic stress with reservoir pressure at more than 16,000 psi (110 MPa) and temperatures up to 165C. Development wells for this field are in excess of 6500 m in true vertical depth (TVD). Stimulation is required to provide sufficiently high production rates that compensate for the high cost of drilling and completing wells. Hydraulic-fracture design and execution must be optimal to ensure economic production. To effectively stimulate a more-than-200-m-thick sandstone reservoir with consistently high performance, it is necessary to understand the mechanical behavior of the reservoir, especially mechanical properties and in-situ stresses because the two control the creation and propagation of each hydraulic fracture. The mechanical behavior is complicated by high tectonic stresses, significant compaction, and high overpressure. To gain an in-depth understanding of the mechanical properties and in-situ stresses of the Keshen reservoir, an integrated geomechanical evaluation was conducted. The evaluation used the core from two wells, KS205 and KS207, and log data obtained from 15 wells including the wells with core evaluation in the field. A laboratory-testing program to investigate the mechanical behavior of the reservoir sandstone under realistic in-situ stresses, pore pressures, and temperature was performed. The description of mechanical behavior obtained from the laboratory testing was used to calibrate and augment mechanical Earth models (MEMs) constructed from well-log data. The reliability of the completed MEMs was validated through comparison between wellbore-stability predictions with observation of borehole failure from the borehole-microresistivity image. The geomechanics information was delivered to the stimulation- engineering team. Hydraulic-fracture design and execution was conducted on the basis of this information. The outcome of hydraulic fracturing was very encouraging. This study demonstrated that successful stimulation of a tight reservoir in high pressure/high temperature (HP/HT) relies on integrated geomechanical analysis.
khair, Elham Mohammed M. (Sudan University of Science & Technology) | Zhang, Shicheng (China University of Petroleum, Beijing) | Abdelrahman, Ibrahim Mustafa (Sudan University of Science & Technology)
The current study presents elastic properties model for Fulla Oilfield in northeast of Block 6 in south of Sudan. Due to the poor formation consolidation and relatively viscose fluid, reservoirs may predictably produce massive amounts of sand and numerous troubles were found in the field as a result of sanding. No documented researches were found to introduce good parameters for rock strength and rock failure conditions through the field. Therefore, an accurate technique for predicting rock failure conditions may yield good profits and improve the economic returns through preventing sand production from the formations. General correlations were presented to accurately describe rock strength parameters for the field; the work utilizes the application of the wireline porosities to be used as a strength indicator through the combination of rock mechanical theories with the characterization of Fulla oilfield. Log porosities (density, sonic and neutron) were calibrated with the core measured porosity, and the best matching porosity were correlated with the dynamic calibrated strength parameters by different correlations. The results support the evidence of the use of porosity as an index for mechanical properties; power functions were found more reliable than the exponential functions, and can be used with a high degree of confidence; also it is more accurate than the Shale Index model presented in previous work for same field; however, the result does not support the direct linear expression presented in the literature for other field due to the variations in the field conditions.
The Keshen tight sandstone reservoir is located in the Kuqa foreland thrust belt at the foothills of the Tianshan Mountain, western China. Recent exploration success shows that there is large reserve of natural gas in Keshen reservoir, similar to several other previously discovered gas reservoirs are located in the same thrust belt. The reservoir formation is the Cretaceous Bashijiqike fan delta sandstone overlaid by Kumugeliemu interbedded gypsum-salt rocks acting as excellent cap rock (Xie et al. 2013; Liu et al. 2013). The reservoir sandstone has been subject to high compaction, high tectonic stress, then high overpressure due to hydrocarbon migration and cementation, all of which result in low porosity and permeability (Li et al. 2011). Previous stimulation activities in this field yielded variable production performance from different wells, while encountering operational difficulties, e.g., often excessively high treating pressure (Zhang et al. 2012). The success of a stimulation job relies on placing a hydraulic fracture into reservoir at proper depth interval in proper geometry with operational feasibility, e.g. with reasonable treating pressure. To achieve this the following questions must be answered: 1. How can the fracture height be contained, e.g.