Abstract: A portion of an anisotropy formation through which a wellbore is formed can be identified. An estimate of an elastic anisotropy parameter for the portion can be adjusted based on a first quality control analysis using the elastic anisotropy parameter for the portion. The first signal representing the elastic anisotropy parameter for the portion. The estimate of the elastic anisotropy parameter for the portion can be adjusted based on a second quality control analysis using estimates for the elastic anisotropy parameters for two or more portions of the anisotropy formation.

Abstract: A portion of an anisotropy formation through which a wellbore is formed can be identified. An estimate of an elastic anisotropy parameter for the portion can be adjusted based on a first quality control analysis using the elastic anisotropy parameter for the portion. The first signal representing the elastic anisotropy parameter for the portion. The estimate of the elastic anisotropy parameter for the portion can be adjusted based on a second quality control analysis using estimates for the elastic anisotropy parameters for two or more portions of the anisotropy formation.

Abstract: According to a preferred aspect of the instant invention, there is provided herein a system and method for imaging complex subsurface geologic structures such as salt dome flanks using VSP data. In the preferred arrangement, a receiver wave field will be downward continued through a salt flood model and a source wave field will be upward continued through a sediment flood model until they “meet” at the subsurface locations of the VSP receivers. The source and receiver wave fields will be cross correlated as an imaging condition at each depth interval.

Abstract: According to a preferred aspect of the instant invention, there is provided herein a system and method for imaging complex subsurface geologic structures such as salt dome flanks using VSP data. In the preferred arrangement, a receiver wave field will be downward continued through a salt flood model and a source wave field will be upward continued through a sediment flood model until they “meet” at the subsurface locations of the VSP receivers. The source and receiver wave fields will be cross correlated as an imaging condition at each depth interval.

Abstract: The methods described herein are conceptually similar to classical migration/imaging for surface seismic data. However, instead of using computed (estimated) Green's functions in the imaging process, the instant invention utilizes measured (near-exact) Green's functions from VSP data to image the surface seismic data. Although the instant invention is best utilized where the velocity profile is approximately 1D (i.e., v(z)), the methods disclosed herein can also be extended to instances where there are some lateral velocity variations. Under these conditions, the instant invention allows for imaging surface seismic data and ‘self-imaging’ VSP data without first having to estimate a velocity model. The measurements obtained from the VSP data can also be used as a tool for calibrating computed Green's functions and migration operators.

Abstract: There is provided herein a system and method for the imaging and monitoring of hydrocarbon reservoirs and other subsurface features preferably using seabed or surface sensors in conjunction with one or more downhole sensors. In one preferred embodiment, recordings will be simultaneously made using both seabed and downhole receivers. The energy source might be either a controlled seismic source or ambient noise. In one embodiment, the data will be used to compute a virtual VSP, checkshot, or similar survey by cross correlating a trace recorded at the surface with a trace recorded at depth. In another embodiment, the surface and well sensors will be permanently emplaced and repeated recordings over time will be used to form a time-varying (4-D) image of the subsurface.

Abstract: The methods described herein are conceptually similar to classical migration/imaging for surface seismic data. However, instead of using computed (estimated) Green's functions in the imaging process, the instant invention utilizes measured (near-exact) Green's functions from VSP data to image the surface seismic data. Although the instant invention is best utilized where the velocity profile is approximately 1D (i.e., v(z)), the methods disclosed herein can also be extended to instances where there are some lateral velocity variations. Under these conditions, the instant invention allows for imaging surface seismic data and ‘self-imaging’ VSP data without first having to estimate a velocity model. The measurements obtained from the VSP data can also be used as a tool for calibrating computed Green's functions and migration operators.

Abstract: There is provided herein a system and method for the imaging and monitoring of hydrocarbon reservoirs and other subsurface features preferably using seabed or surface sensors in conjunction with one or more downhole sensors. In one preferred embodiment, recordings will be simultaneously made using both seabed and downhole receivers. The energy source might be either a controlled seismic source or ambient noise. In one embodiment, the data will be used to compute a virtual VSP, checkshot, or similar survey by cross correlating a trace recorded at the surface with a trace recorded at depth. In another embodiment , the surface and well sensors will be permanently emplaced and repeated recordings over time will be used to form a time-varying (4-D) image of the subsurface.

Abstract: A computer system (30) and method of operating the same to analyze well log data so as to distinguish fractures from drilling artifacts, such as caves, washouts, and breakouts, is disclosed. According to the disclosed system and method, a Stoneley wave well log obtained at a plurality of depths is analyzed at a low and a high frequency, to generate a low frequency reflection coefficient trace over depth and a high frequency reflection coefficient trace over depth. Comparison of these reflection coefficient traces with one another will indicate whether a reflecting feature includes a fracture (as indicated by good low frequency response) or a cave, washout, or other artifact (as indicated by good high frequency response), or both. The particular methods disclosed include the generation of the reflection coefficient traces through back-projection stacking of deconvolved impulse traces at both frequencies, and applying and evaluating an envelope function to the stacked traces.

Abstract: Methods are provided for determining the axial and radial slowness of a formation traversed by a borehole via utilization of sonic data obtained from a sonic borehole tool having a plurality of detectors. The methods utilize first arrival time information, ray tracing techniques, and backprojection techniques. The differences between the actually measured first arrival times and the theoretical first arrival times as calculated by ray tracing through an initial slowness model of the formation, are backprojected along the theoretical ray paths of first arrival in order to modify the initial slowness model of a formation. The methods utilized are preferably iterative, such that the modified slowness model is then utilized for additional ray tracing and backprojection. Secondary arrivals may also be utilized to refine slowness determinations made from first arrival information.

Abstract: In a method for locating fractures in subsurface earth formations traversed by a borehole a first signal is generated representative of low frequency Stoneley waves (that is tube waves) propagating along the borehole from a source mounted in a logging tool. A second signal is generated by an array of detectors on the tool, representative of low frequency Stoneley waves propagating along the borehole and arising from reflection from fractures of the waves propagating from the source. An indication of the presence of fractures is derived by deconvolving the second signal with the first signal and identifying the time and magnitude of the peak value of the envelope of the deconvolved signal. The variation that would be expected in the presence of fracture and the actual variation are compared and a fracture detected when the actual and expected variations match. Alternatively the first and second signals can be cross-correlated and the time of the peak negative value of the cross-covariance determined.

Abstract: Waveform data obtained in a borehole by a tool having a sonic source and an array of sonic detectors is analyzed to obtain an image of formation features within several tens of feet of the borehole, such as fractures, bed boundaries and other boreholes. A value of background sonic slowness is derived from the data and used to determine the sonic energy transit time from the source to each detector via each point in a grid of points extending into the formation and along the borehole. The time for a particular detector/point pair is used to extract the amplitude of the waveform from that detector at that time relative to operation of the source. Such amplitudes for the same point and for different detectors and tool positions are cumulated. The final values for all points are plotted as a variable density display which provides the desired image.

Abstract: A method for determining the fluid mobility or permeability of subsurface formations using borehole measurements of the tube wave. The slowness of an hypothetical tube wave travelling in an elastic, nonpermeable medium is computed based on various measured parameters such as the formation matrix density, fluid density and fluid acoustic slowness. This elastic model slowness is subtracted from the measured tube wave slowness of a selected formation traversed by the borehole, and the difference is used to determine the formation permeability.