Differential compaction is an inherent process in carbonate systems that is thought to produce early natural fractures prior to any significant burial. Such fractures can persist and can be major permeability pathways, including areas of minor tectonic overprint. We forward model differential compaction fracturing in a carbonate reservoir in effort to predict the location of fractures in the subsurface.
3D finite-element geomechanical models are created to simulate differential compaction fracturing at a carbonate platform scale (kilometers) and the smaller carbonate build-up scale (10s of meters) commonly present within carbonate platforms. Interpreted seismic surfaces of key reservoir horizons are used as an input for the platform-scale model. Geometry of carbonate build-up from an outcrop analog is used for the build-up scale models. In both type of models layers identified to be compaction prone are restored to their expected pre-compaction state. A simplified mechanical stratigraphy scheme is adopted to distribute mechanical properties within the models consistent with their expected pre-burial properties.
Geomechanical modeling in this study was applied to a field which includes two carbonate platforms at different stratigraphic levels. Modeling results predict increased fracture intensity at the windward margin of the carbonate platform. This coincides with increased windward-leeward asymmetry of an underlying older platform. Increased fracture intensity is predicted at the center of the platform where the underlying older platform displays significantly less asymmetry. Predicted fracture locations over the platform top also correspond with the location of carbonate build-ups identified from seismic data. Fracture observations from image logs and indirectly from mud loss data within the upper platform are consistent with our modeling results. Predicted areas of greatest fracture intensity correspond with the location of wells with the highest fracture intensity observed from image logs.
Build-up scale models suggest that the build-up shape exerts a major control on the resulting differential compaction fracture pattern. Elongate build-ups tend to produce fractures oriented parallel to their axes. Circular build-ups tends to produce radial fracture patterns. Fracture orientation from image logs along with build-up shape observed using the coherence seismic attribute are consistent with these findings.
This study offers a process-based fracture modeling approach that can enhance the predictability of the location and orientations of natural fractures in carbonate reservoirs.
Drilling deviated wells is a frequently used approach in the oil and gas industry to increase the productivity of wells in reservoirs with a small thickness. Drilling these wells has been a challenge due to the low rate of penetration (ROP) and severe wellbore instability issues. The objective of this research is to reach a better drilling performance by reducing drilling time and increasing wellbore stability.
In this work, the first step was to develop a model that predicts the ROP for deviated wells by applying Artificial Neural Networks (ANNs). In the modeling, azimuth (AZI) and inclination (INC) of the wellbore trajectory, controllable drilling parameters, unconfined compressive strength (UCS), formation pore pressure, and in-situ stresses of the studied area were included as inputs. The second step was by optimizing the process using a genetic algorithm (GA), as a class of optimizing methods for complex functions, to obtain the maximum ROP along with the related wellbore trajectory (AZI and INC). Finally, the suggested azimuth (AZI) and inclination (INC) are premeditated by considering the results of wellbore stability analysis using wireline logging measurements, core and drilling data from the offset wells.
The results showed that the optimized wellbore trajectory based on wellbore stability analysis was compatible with the results of the genetic algorithm (GA) that used to reach higher ROP. The recommended orientation that leads to maximum ROP and maintains the stability of drilling deviated wells (i.e., inclination ranged between 40°—50°) is parallel to (140°—150°) direction. The present study emphasizes that the proposed methodology can be applied as a cost-effective tool to optimize the wellbore trajectory and to calculate approximately the drilling time for future highly deviated wells.
Wu, Jing (China National Offshore Oil Corporation (CNOOC) Ltd., Tianjin Branch) | Wang, Mingchun (China National Offshore Oil Corporation (CNOOC) Ltd., Tianjin Branch) | Gao, Lei (China National Offshore Oil Corporation (CNOOC) Ltd., Tianjin Branch) | Gao, Wenbo (China National Offshore Oil Corporation (CNOOC) Ltd., Tianjin Branch) | Jiang, Tao (China National Offshore Oil Corporation (CNOOC) Ltd., Tianjin Branch)
Summary Shaleitian uplift is a typical conjugate area controlled by the NEtrending faults Huanghua-Dongming (H-D faults) and the NWtrending faults Zhang-Peng (Z-P faults).The two sets of faults not only control the formation and evolution of the uplift but also influence the key factors of hydrocarbon accumulation of it and surrounding. The land part of Z-P fault is studied relatively more, but few studies on the seat part as the main reason is lack of 3D seismic data.Research shows that oil and gas accumulation is closely related with Tan-Lu fault and Zhang-Peng fault in Bohai Bay Basin.Therefore, It's necessary to do further research about Z-P fault and the conjugate area of the H-D and Z-P fault. By means of the horizontal and vertical characters in plane and seismic profile, we can be certain of the geometry characteristics of the H-D and Z-P faults. Although the strike-slip property of the faults makes stress mechanisms complicated, the physical simulation experiment about the typical faults helps to do more in-depth analysis. According to the geometry characteristics and the stress field that the faults have been experienced, we built simplified evolution model of the faults.
Effective use of potential field and seismic methods to reduce exploration costs and ambiguity in multiple integrated imaging interpretations. Summary In underexplored frontier basins, the integrated interpretation of 2D'vintage' quality seismic data in conjunction with airborne gravity gradiometer (AGG) data and the value of 2.5D gravity modelling of geological cross sections along seismic lines has proven to be valuable for cost-effective exploration. The benefits of acquiring airborne potential field methods namely AGG, magnetic and EM data are time efficiency, ease of access and regularly spaced datasets. These datasets can be acquired over large areas in a small timeframe. Even in well explored basins, imaging in salt provinces continues to be challenging in spite of using improved seismic algorithms and technologies.
Beloborodov, Roman (CSIRO, Kensington, WA, Australia) | Pervukhina, Marina (CSIRO, Kensington, WA, Australia) | Shulakova, Valeriya (CSIRO, Kensington, WA, Australia) | Josh, Matthew (CSIRO, Kensington, WA, Australia) | Hauser, Juerg (CSIRO, Kensington, WA, Australia) | Clennell, Michael B. (CSIRO, Kensington, WA, Australia) | Chagalov, Dimitri (ExxonMobil, Melbourne, VIC, Australia)
Shales are omnipresent in sedimentary basins and generally need to be drilled through to reach conventional or to develop unconventional reservoir. Shales, especially smectite-rich, often cause significant drilling problems associated with overpressure, borehole instability, etc. Understanding of clay mineralogy before drilling is very important to reduce risks associated with drilling. In this study, we perform a simultaneous AVO inversion of a part of the Duyfken seismic survey, the Northern Carnarvon Basin of the North-West Shelf of Australia. Log data from a training well were used to establish correlations between smectite content and acoustic impedance (AI) and VP/VS ratio. It is worth noting that mechanically and chemically compacted shale exhibit two significantly different trends between smectite and a principal component of seismic attributes. The smectite content obtained from surface seismic is in a good agreement with that estimated in a blind test well from the XRD analysis of cuttings.
Presentation Date: Tuesday, October 16, 2018
Start Time: 1:50:00 PM
Location: 210A (Anaheim Convention Center)
Presentation Type: Oral
The GD band separation observed in the spectra for the experimentally matured Sample A is 30 cm -1 greater than measured for the immature sample.
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). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited.
Shale permeability measurements on plugs and crushed samples. Paper SPE-162235 presented at the Canadian Unconventional Resources Conference, Society of Petroleum Engineers, Calgary, Alberta, 30 October-1 November, doi:10.2118/162235-MS.
ABSTRACT: Carbonate strata are unique in that sediments can become lithified soon after deposition and prior to burial or loading (e.g., by marine or meteoric cementation). The rocks that develop have appreciable strength and cohesion that enable brittle failure under the influence of gravity. Conditions of increased effective tensile stress state can develop along steep-walled carbonate shelf margins and carbonate buildups. Marine and/or meteoric processes lead to the development of early mechanical property contrast between different facies. Some facies are mechanically competent (i.e. susceptible to brittle failure) while other facies experience ductile deformation via compaction. It is challenging to isolate features that are only related to early deformation in both outcrop and subsurface settings from those that occur from burial, uplift, and tectonism. To address this challenge, we present a forward numerical modeling approach using the finite-discrete element modeling code ELFEN to simulate these early deformation processes in carbonate systems. This modeling approach requires an initial geometry, initial rock properties, gravitational loading, and failure criteria. Bathymetry data of a modern example and a digital outcrop model of ancient rocks guides initial model geometry. Initial rock mechanical properties were measured by uniaxial compressive and Brazilian tests from collected modern and ancient rock samples. Failure criteria are assigned based on expected deformation behavior (i.e., brittle or ductile). Grain-rich carbonates and reef builders are prone to in situ early cementation and are expected to behave in a brittle manner and thus are assigned a Mohr-Coulomb with a rotating Rankine crack failure model. Soon after deposition mud-rich carbonate facies are expected to be prone to compaction and thus are assigned a modified CAM clay model that allows for compaction and porosity loss with increasing gravitational load. Modeling results are useful in determining most important variables to early fracturing and provide fundamental understanding of early deformation processes in strata that are known fractured carbonate reservoirs.
Syndepositional fracture and fault development has been documented in carbonate systems where lithification can commonly occur by meteoric and marine cementation prior to burial (e.g., Della Porta et al., 2004; Frost and Kerans, 2009; Kosa and Hunt, 2006; Verwer et al., 2009). These fracture and fault networks dictate early permeability anisotropy and influence subsequent diagenesis and deformation patterns (Budd et al., 2013; Frost et al., 2012). Syndepositional fractures can be a major contributor to permeability and hydrocarbon flow in giant carbonate reservoirs (e.g., Albertini, et al., 2013, Collins et al., 2013; Fernandez- Ibanez et al., 2016). Several challenges impede complete characterization of such fractures including insufficient sampling from the subsurface, outcrop quality, and overprinting by subsequent deformation or diagenesis. Here we address this challenge by a numerical modeling approach in which we simulate early fracture development in response to gravitational forces.
Ojha, Shiv Prakash (University of Oklahoma) | Misra, Siddharth (University of Oklahoma) | Tinni, Ali (University of Oklahoma) | Sondergeld, Carl H (University of Oklahoma) | Rai, Chandra (University of Oklahoma)
Pore-network characteristics, such as pore-size distribution (PSD), pore connectivity, and pore complexity, along with irreducible saturations in shales, are important petrophysical parameters for accurate estimation of absolute and relative permeability curves of various phases. We apply a method for estimation of these petrophysical parameters in shales by processing the low-pressure-nitrogen-adsorption/desorption (AD) measurements. The method uses effective-medium theory, percolation theory, and critical-path analysis (CPA) to quantify the transport properties of shales. The method has been applied to 35 samples of Eagle Ford and Wolfcamp Shales with different composition and from different maturity windows. Further, samples from the gas and oil windows of Eagle Ford Shale Formation were low-temperature plasma ashed to study the effect of the removal of organic matter on pore-network characteristics and irreducible saturations.
The estimated PSDs of condensate-window samples from Wolfcamp samples are significantly different from those of Eagle Ford samples. Our interpretation methodology indicates that the Eagle Ford samples exhibit better long-range pore connectivity and lower pore complexity compared with Wolfcamp samples. Consequently, Eagle Ford samples from oil and gas windows suggests better flow capacity compared with Wolfcamp samples from the condensate window. Moreover, the pore-network characteristics of kerogen from gas-window samples are significantly different from those of oil window samples. The estimated irreducible saturations for the samples collected from 100-ft interval in Eagle Ford gas window, 30-ft interval in Eagle Ford oil window, and the 60-ft interval in the Wolfcamp condensate window of shale formations exhibit minimal variation with depth. The samples exhibit large variations in organic content, pore connectivity, range of connected-pore network, and pore complexity that do not affect the irreducible-saturation estimates.