Formation of slot-shaped borehole breakout within weakly cementedsandstones

Breakout (wall failure) of boreholes within the earth can take several forms depending upon physical properties of the surrounding rock and the stress and flow conditions. Three distinctive modes of breakout are (I) extensile breakout observed in brittle rocks (e.g., Haimson and Herrick, 1986), (II) shear breakout in soft and clastic rocks (Zoback et al., 1985), and (III) fracture-like, slot-shaped breakout within highly porous granular rocks (Bessinger et al., 1997; Haimson and Song, 1998). During fluid production and injection within weakly cemented high-porosity rocks, the third type of failure could result in sustained and excessive sand production (disintegration of the rock's granular matrix and debris production). An objective of this research is to investigate the physical conditions that result in the formation of slot-shaped borehole breakout, via laboratory experiments. Our laboratory borehole breakout experiment was conducted using synthetic high-porosity sandstone with controlled porosity and strength. Block samples containing a single through-goring borehole were subjected to anisotropic stresses within a specially designed tri-axial loading cell. A series of studies was conducted to examine the impact of (1) stress anisotropy around the borehole, (2) rock strength, and (3) fluid flow rate within the borehole on the formation of slot-shaped borehole breakout. The geometry of the breakout was determined after the experiment using X-ray CT. As observed in other studies (Hamison and Song, 1998; Nakagawa and Myer, 2001), flow within a borehole plays a critical role in extending the slot-shaped breakout. The results of our experiments indicated that the width of the breakout was narrower for stronger rock, possibly due to higher resistance to erosion, and the orientation of the breakout plane was better defined for a borehole subjected to stronger stress anisotropy. In most cases, the breakout grew rapidly once the borehole wall started to fail. This 'run-away' failure growth is induced by monotonically increasing stress concentration at the breakout tips, although this effect may be augmented by the finite size of the sample

Elastic wave propagation along a set of parallel fractures

Abstract. Previous studies on elastic wave propagation in fractured media have demonstrated that a single planar fracture supports fracture interface waves and that two plane parallel fractures support fracture channel waves. Here, the results are presented for plane wave propagation through an infinite number of plane parallel fractures with equal fracture spacing and fracture stiffnesses. Analysis of the dispersion equations for this fractured system demonstrates that these waves exhibit symmetric and antisymmetric particle motions, degenerate to classical Rayleigh-Lamb plate waves when the fractures are completely open, and possess dispersive velocities that are functions of both the fracture stiffness and spacing. Time-frequency analysis performed on a series of laboratory ultrasonic transmission measurements on a fractured rock analog shows good agreement with the theoretical predictions

Predictions of long-term behavior of a large-volume pilot test for CO2 geological storage in a saline formation in the Central Valley, California

The long-term behavior of a CO{sub 2} plume injected into a deep saline formation is investigated, focusing on mechanisms that lead to plume stabilization. Key measures are plume migration distance and the time evolution of CO{sub 2} phase-partitioning, which are examined by developing a numerical model of the subsurface at a proposed power plant with CO{sub 2} capture in the San Joaquin Valley, California, where a large-volume pilot test of CO{sub 2} injection will be conducted. The numerical model simulates a four-year CO{sub 2} injection period and the subsequent evolution of the CO{sub 2} plume until it stabilizes. Sensitivity studies are carried out to investigate the effect of poorly constrained model parameters permeability, permeability anisotropy, and residual gas saturation

A Strategy for Monitoring of Geologic Sequestration of CO2

Monitoring of geologic sequestration projects will require the measurement of many different parameters and processes at many different locations at the surface and in the subsurface. The greatest need for technology development is for monitoring of processes in the subsurface in the region between wells. The approach to fitting this need is to build upon decades of experience in use of geophysics in the oil and gas industry. These methods can be optimized for CO2 monitoring, and customized and extended in order to meet the need for cost-effective methods applicable to saline disposal sites, coal bed methane sites, as well as oil and gas reservoir sequestration sites. The strategy for development of cost-effective methods follows a three step iterative process of sensitivity analysis using numerical and experimental techniques, field testing at a range of scale in different formations, and analysis and integration of complimentary types of data

Scoping Calculations on Leakage of CO2 in Geologic Storage

Numerical simulations have been carried out to evaluate the rate at which a plume of CO2 moves upward through the subsurface, and the amounts of dissolution and phase trapping that occur along the way. A quantity of CO2 is injected into a 1000-m deep, 100-m thick layer saturated with saline water, where it forms an immiscible supercritical fluid phase and partially dissolves in the aqueous phase. As the supercritical CO2 moves upward, it smoothly transitions into a gas. Between the injection interval and the ground surface the medium (the overburden ) is assumed to be homogeneous, but anisotropic, with a ratio of vertical to horizontal permeability of 1:2. 1000-year simulations are conducted for overburden vertical permeabilities of 100 md, 10 md, and 1 md, using a version of the TOUGH2 numerical simulator that incorporates hysteretic relative permeability and capillary pressure functions. For each permeability, simulations are carried out for a range of maximum residual gas saturations (Sgrmax), because this parameter plays a key role in phase trapping and is poorly known for aqueous/CO2 systems. The time required for the CO2 plume to reach the surface increases with decreasing overburden permeability and increasing Sgrmax. CO2 reaches the surface within 1000 years only for the highest overburden permeability (100 md), with times ranging from 775 years for the large values of Sgrmax commonly used in the petroleum industry to 2.2 years for small values of Sgrmax. Additional simulations including a high-permeability conduit in an otherwise low-permeability overburden provide insights into the effects of geologic heterogeneity

A Strategy for Monitoring of Geologic Sequestration of CO2

Monitoring of geologic sequestration projects will require the measurement of many different parameters and processes at many different locations at the surface and in the subsurface. The greatest need for technology development is for monitoring of processes in the subsurface in the region between wells. The approach to fitting this need is to build upon decades of experience in use of geophysics in the oil and gas industry. These methods can be optimized for CO2 monitoring, and customized and extended in order to meet the need for cost-effective methods applicable to saline disposal sites, coal bed methane sites, as well as oil and gas reservoir sequestration sites. The strategy for development of cost-effective methods follows a three step iterative process of sensitivity analysis using numerical and experimental techniques, field testing at a range of scale in different formations, and analysis and integration of complimentary types of data

Geomechanical risks in coal bed carbon dioxide sequestration

The purpose of this report is to summarize and evaluate geomechanical factors which should be taken into account in assessing the risk of leakage of CO{sub 2} from coal bed sequestration projects. The various steps in developing such a project will generate stresses and displacements in the coal seam and the adjacent overburden. The question is whether these stresses and displacements will generate new leakage pathways by failure of the rock or slip on pre-existing discontinuities such as fractures and faults. In order to evaluate the geomechanical issues in CO{sub 2} sequestration in coal beds, it is necessary to review each step in the process of development of such a project and evaluate its geomechanical impact. A coal bed methane production/CO{sub 2} sequestration project will be developed in four steps: (1) Formation dewatering and methane production; (2) CO{sub 2} injection with accompanying methane production; (3) Possible CO{sub 2} injection for sequestration only; and The approach taken in this study was to review each step: Identify the geomechanical processes associated with it, and assess the risks that leakage would result from these processes