Baden, Dawin (Aix-Marseille Université, CNRS, CEREGE, IRD) | Henry, Pierre (Aix-Marseille Université, CNRS, CEREGE, IRD) | Saracco, Ginette (Aix-Marseille Université, CNRS, CEREGE, IRD) | Marié, Lionel (Aix-Marseille Université, CNRS, CEREGE, IRD) | Tonetto, Alain (Aix-Marseille Université, CNRS, CEREGE, IRD) | Guglielmi, Yves (Lawrence Berkeley National Laboratory) | Nakagawa, Seiji (Lawrence Berkeley National Laboratory) | Massonnat, Gérard (Total Exploration & Production) | Rolando, Jean-Paul (Total Exploration & Production)
Physical properties of carbonate rocks cannot be fully captured from laboratory-sized samples. Indeed, heterogeneous facies distribution and/or diagenetic alterations may lead to significant variations in petrophysical properties within few meters. In carbonates, diagenetic transformations are tightly related to nature of fluids flowing through the formations, e.g. via fractures network. Consequently, reservoir properties may have patchy distribution, and may not be correlatable (e.g. using facies distribution or wells-logs correlations) within few meters. Our works aim at characterizing carbonates anisotropy at different scales, and are subject of two presentations at SEG's 87th Annual Meeting. This abstract deals with the second part of our approach, that's to say characterizing impact of diagenetic alteration on reservoir properties and seismic anisotropy, from centimeter to multi-meter scale. This part of the works integrate data from centimeter-scale (mini-cores), decimeter-scale (5″ cores), multi-meter (ultrasonic crosshole), and hectometer-scale (seismic), which have been measured at suitable frequency ranges (1MHz, 250kHz, 50kHz, and 1–100Hz, respectively). Although anisotropy is measureable at every scales, its origins vary according to scale. In this study, it is shown that matrix of porous samples are weakly anisotropic as a result of inter-crystalline pores. At centimeter-scale, anisotropy can also be related to: (1) patchy distribution of some physical properties, (2) local cracks distribution, and (3) thick single fractures. The lack of correlation between stiffness components from seismic-scale measurements, and laboratory to multi-meter scale ones emphasizes the fact that, when fracturing dominates, measured anisotropy is dominated by fracture/fault related anisotropy and matrix-related anisotropy may be lost. So that, scale effect must be handled carefully in anisotropy analyses, especially for carbonate formations.
This paper has been withdrawn from the Technical Program and will not be presented at the 87th SEG Annual Meeting.
Many studies involving the application of geophysical methods in the field of gas hydrates have focused on determining rock-physics relationships for hydrate-bearing sediments, with the goal being to delineate the boundaries of gas-hydrate accumulations and to estimate the quantities of gas hydrate that such accumulations contain using remote-sensing techniques. However, the potential for using time-lapse geophysical methods to monitor the evolution of hydrate accumulations during production and, thus, to manage production has not been investigated. In this work, we begin to examine the feasibility of using time-lapse seismic methods--specifically, the vertical-seismic-profiling (VSP) method--for monitoring changes in hydrate accumulations that are predicted to occur during production of natural gas. A feasibility study of this nature is made possible through the coupled simulation of large-scale production in hydrate accumulations and time-lapse geophysical (seismic) surveys. We consider a hydrate accumulation in the Gulf of Mexico that may represent a promising target for production. Although the current study focuses on one seismic method (VSP), this approach can be extended easily to other geophysical methods, including other seismic methods (e.g., surface seismic or crosshole measurements) and electromagnetic surveys. In addition to examining the sensitivity of seismic attributes and parameters to the changing conditions in hydrate accumulations, our long-term goals in this work are to determine optimal sampling strategies (e.g., source frequency, time interval for data acquisition) and measurement configurations (e.g., source and receiver spacing for VSP), while taking into account uncertainties in rock-physics relationships. The numerical-modeling strategy demonstrated in this study may be used in the future to help design cost-effective geophysical surveys to track the evolution of hydrate properties. Here, we describe the modeling procedure and present some preliminary results.
Schoenberg''s Linear-slip Interface (LSI) model for single, compliant, viscoelastic fractures has been extended to poroelastic fractures for predicting seismic wave scattering. However, this extended model results in no impact of the in-plane fracture permeability on the scattering. Recently, we proposed a variant of the LSI model considering the heterogeneity in the in-plane fracture properties. This modified model considers wave-induced, fracture-parallel fluid flow induced by passing seismic waves. The research discussed in this paper applies this new LSI model to heterogeneous fractures to examine when and how the permeability of a fracture is reflected in the scattering of seismic waves. From numerical simulations, we conclude that the heterogeneity in the fracture properties is essential for the scattering of seismic waves to be sensitive to the permeability of a fracture.
An on-going effort of conducting laboratory triaxial compression tests on synthetic methane hydrate-bearing sediment cores is presented. Methane hydrate is formed within a sand pack inside a test cell under a controlled temperature and confining stress, and triaxial compression tests are performed while monitoring seismic properties. A unique aspect of our experiment is that the formation and dissociation of hydrate in a sediment core, and the failure of the sample during loading tests, can be monitored in real time using both seismic waves and x-ray CT imaging. For this purpose, we built a specially designed triaxial (geomechanical) test cell. This cell allows us to conduct seismic wave measurements on a sediment core using compressional and shear (torsion) waves. Concurrently, CT images can be obtained through an x-ray-transparent cell wall, which are used to determine the porosity distribution within a sample owing to both original sand packing and formation of hydrate in the pore space. For interpreting the results from both seismic measurements and geomechanical tests, characterization of sample heterogeneity can be critically important. In this paper, we present the basic functions of our test cell, and the results of preliminary experiments using a sandpack without hydrate and a sandstone core. These measurements confirmed that (1) clear x-ray images of gas-fluid boundaries within a sediment/rock core can be obtained through a thick aluminum test cell wall, (2) the test cell funcions correctly during loading tests, and (3) both compressional and shear waves can be measured during a loading test. Further experiments using methane hydrate-bearing samples will be presented at the conference.
Because of geomechanical stability concerns, the placement of wells and seafloor platforms associated with oil production is strongly influenced by the presence of gas hydrates on the sea floor or within the sediment lithology. These concerns will be far more pronounced if gas production from oceanic gas hydrate accumulation is to become an economically viable option in the future. Thermal loading and dissociation caused by warm reservoir fluids (originating from a deeper conventional reservoir under production) ascending through wellbores that intersect hydrate-bearing sediments (HBS) can also have adverse consequences for the HBS stability. The current state of knowledge on the properties of HBS that have a direct impact on the seafloor stability is still in its infancy. Additionally, for remote detection, resource evaluation and monitoring of in-situ HBS during exploration and production of oil and gas (including gas production from the hydrates), it is essential to establish concurrently the quantitative relationships among index properties (sediment porosity, hydrate saturation, gas saturation, etc.), geophysical properties (seismic velocities and attenuation, in particular), and geomechanical properties (mechanical stiffness, strength, time-dependent behavior) of HBS.
Detailed strength measurements that were conducted on laboratory-made, pure methane (CH4)-hydrate samples (Durham et al., 2003; Stern et al., 1996). Stern et al (1996) indicated that the mechanical, plastic flow properties of CH4 hydrates are very different from those of water ice. Thus, unlike ice (which exhibits yielding and softening), CH4-hydrates exhibit continuous hardening, and solid-state disproportionation and exsolution. These results suggest that geomechanical tests using water ice as an analogue may result (e.g., Nagaeki et al., 2004) in erroneous conclusions for the mechanical properties of oceanic HBR.
Many studies involving the application of geophysical methods in the field of gas hydrates have focused on determining rock physics relationships for hydrate-bearing sediment with the goal being to delineate the boundaries of gas hydrate accumulations and to estimate the quantities of gas hydrate such accumulations contain using remote sensing techniques. However, the potential for using time-lapse geophysical methods to monitor the evolution of hydrate accumulations during production and thus to manage production has not been investigated. In this work we begin to examine the feasibility of using time-lapse geophysical methods for monitoring changes in hydrate accumulations that are predicted to occur during production of natural gas. This is made possible through the coupled simulation of (1) large-scale production in hydrate accumulations and (2) time-lapse geophysical surveys. We consider a geological system, based on a hydrate accumulation in the Gulf of Mexico, which represents a promising target for production. While the current study focuses on seismic measurements, the approach can easily be extended to consider additional geophysical methods, such as electromagnetic methods. In addition to examining the sensitivity of geophysical attributes and parameters to the changing conditions in hydrate accumulations, we aim to determine optimal sampling strategies (e.g., source frequency, time interval for data acquisition) and measurement configurations (e.g., surface seismic reflection, and vertical seismic profiling), while taking into account uncertainties in rock physics relationships. The numerical simulation tool being developed in this work provides a means for designing cost effective geophysical surveys to track the evolution of hydrate properties. This work also serves as a basis for developing a comprehensive method for monitoring production that integrates multiple types of geophysical and hydrological data. Here we describe the modeling procedure and present some preliminary results.
Background. Identifying the extent of gas hydrate accumulations, predicting their behavior, and monitoring their properties is of great importance. Gas hydrates-solid crystalline structures consisting of water and gas molecules (usually methane)-are distributed widely across the earth in permafrost and under the ocean (Sloan, 1998). When conditions in hydrate-bearing sediment (HBS) become thermodynamically unfavorable for gas hydrates (e.g., when the pressure decreases or the temperature increases and moves the system away from the hydrate stability zone), dissociation can occur releasing large amounts of gas and water. Thus gas hydrates are viewed as a promising source of alternative energy (Kvenvolden, 1994; 2002), in hopes that dissociation can be induced in hydrate accumulations in a controlled manner while natural gas is harvested (Makogen, 1997). The presence of HBS also serves as a hazard to hydrocarbon production platforms or infrastructure, the integrity of which is at risk due to ocean floor instabilities arising from dissociation-induced sub-marine landslides or subsidence (Moridis and Kowalsky, 2007).
The use of geophysical methods for identifying hydrate accumulations and quantifying the amount of gas hydrates present in the subsurface has been investigated for many years and appears promising (e.g., Hyndman and Spence, 1992; Yuan et al., 1996; Andreassen et al, 1997; Ecker et al., 1998; Ecker et al., 2000; Gueren et al. 1999). There still remains much uncertainty in seismic (Helgerud et al., 1999; Gueren and Goldberg, 2005) and electrical (Spangenberg, 2001; Sun and Goldberg, 2005) rock physics relationships for HBS. The use of geophysical methods to remotely monitor the state of hydrate accumulations undergoing production (at distant locations where well-logging techniques can not be applied) is only beginning to be examined, which is made possible by recent advances in the ability to model the complex processes that occur in such systems which inevitably involve the nonisothermal, multiphase transport of fluids and gas.
Watanabe, Toshiki (Kyoto University) | Nihei, Kurt T. (Lawrence Berkeley National Laboratory) | Myer, Larry R. (Lawrence Berkeley National Laboratory) | Nakagawa, Seiji (Lawrence Berkeley National Laboratory)