Interpretation Of Time-lapse Seismic Data Research Articles

Joint impedance and facies inversion of time-lapse seismic data for improving monitoring of CO2 incidentally stored from CO2 EOR

Time-lapse seismic monitoring is an effective and proven technology for mapping the distribution of CO2 in a subsurface reservoir. When injected CO2 displaces other reservoir fluids, porous-medium properties are changed and thus the seismic impedance changes, causing time-lapse seismic amplitude differences in the injection zones. The analysis and interpretation of images created from these amplitude differences can provide information about reservoir architecture and the CO2 migration within the reservoir. Incorporating seismic inversion and rock physics into the interpretation of time-lapse seismic data can considerably improve the modeling and monitoring to detect and assess the location of CO2 over time. The joint inversion method presented in this paper has an integral representation of the geology in the inversion algorithm using elastic facies, which provides information about the spatial distribution of the geologic heterogeneities controlling the movement of fluids in the reservoir. The method was successfully applied to time-lapse seismic data from a mature oil field undergoing CO2 enhanced oil recovery. The estimated seismic acoustic impedances and facies reflect the characteristics of individual geologic facies and fluid conditions of the reservoir subject to CO2 injection. The probabilities estimated by the joint impedance and facies inversion for the reservoir's litho-fluid facies can be used for forecasting CO2 saturation and pressure changes within the target reservoir.

Processing and Interpretation of Time-Lapse Seismic Data at Gao 89 CO2-EOR Area

CO2-EOR greatly recovered oil production in Gao 89-1 block in Sinopec Shengli Oil Company. However, CO2-EOR efficiency was high in some wells but some production wells had little effect. In order to study CO2 sweep efficiency and CO2 distribution, 3D seismic monitoring acquisition was conducted in December, 2010. It is the unique time-lapse 3D seismic datasets to monitor CO2 distribution in China. But the geometry of baseline and monitor is different. Moreover, the depth of reservoir is about 3200 m and effective thickness of reservoir is only 10 m. In addition, the injection volume of CO2 was small and around 50,000 t. If time-lapse 3D seismic technique could discriminate CO2 distribution has been a controversial question. In this paper, we studied the problems during CO2 flooding and estimated the net CO2 storage volume. Then we proposed a time-lapse seismic processing method that improved the conventional geometry degradation and made a better seismic image from vantages of seismic monitoring. In order to calibrate monitoring seismic datasets by using the well log data measured before CO2 injection, P- and S- wave velocity logs versus pressure change method is proposed and verified by making synthetic seismograms. Our study proved that the time-lapse seismic difference mainly caused by the change of pore pressure during CO2 injection in this area. Finally, time-lapse seismic difference calibration method is proposed that assuming the caprock seismic attributes were consistent before and after CO2 injection. The time-lapse difference matched the oil production and CO2 injection well.

Correction of seismic time-lapse data with different geometries

ABSTRACTIn the interpretation of time-lapse seismic data, we first assume that basal and monitor seismic data have been gathered and processed under equal condition. Basically having two sets of seismic data (basal and monitor data) does not confirm the possibility of 4D seismic data analysis and repeatability term commands that data should have equal data gathering and process condition. This is due to the low vertical resolution of seismic data which makes the changes in amplitude of seismic in basal and monitoring operations to occur finitely. Therefore, differences in amplitudes in two seismic surveys that have a source other than variations in reserval fluid saturation cause errors in 4D interpretations. In this paper, we represent a procedure to unify different geometries and also study post-stack processing methods for seismic time-lapse data and execute them on existing data at the studied field. In the, first step geometrical conception of basal and monitoring data should be equalized. This section has been implemented using a new methodology, developed in this paper and is called “similarity table”. Then, data will be analyzed with spectra point of view and by executing shaping filters and by using cross equalization approach, basal and monitor seismic information will be closer as far as possible. Finally, analyzes were performed to validate the obtained results and evaluate the quality of time -lapse seismic analyzes.

Using time-lapse VSP data to constrain velocity-saturation relations

Quantitative interpretation of time-lapse seismic data is an ongoing challenge. Understanding the velocity-saturation relations and changes caused by CO2 injection play an important role for the application of seismic monitoring techniques to carbon dioxide storage projects.High uncertainties associated with well log measurements affected by borehole conditions can affect our ability to constrain a rock physics model. Seismic measurements, such as Vertical Seismic Profile (VSP), that span both the near-well region and far beyond the borehole can provide good control for correcting these measurements and reducing the uncertainties thereafter.In this paper, we analyse the observed time delays in time-lapse VSP data from the Frio CO2 injection test site by employing an integrated approach of rock physics and seismic forward modelling to reduce uncertainties in the choice of the dry frame modulus and velocity-saturation relations. First, we confirmed the quality of pre-injection well logs velocities with VSP data. Afterwards, we use inverse Gassmann relations to calculate the dry frame properties of the reservoir with different input parameters for the grain moduli with fluid substitution applied for uniform saturation of brine and CO2. Finally, forward modelling of the results is implemented to compare the response with field VSP data.Our investigation shows that VSP data can help constrain the choice of dry frame modulus, and thus the velocity-saturation relation. The rock physics model best matches the VSP results using large grain moduli and uniform saturation for fluid substitution.

Processing and interpretation of time-lapse seismic data from a heavy oil field, Alberta, Canada

Summary Time-lapse seismic analysis of a heavy oil reservoir undergoing steam injection is a critical step in the evaluation of production efficiency and reserve potential after a period of steaming. Through the identification of changes in seismic characteristics, steam chamber development can be identified and investigated in an effort to delineate resources unaffected by steam. Unheated portions of the reservoir will play a role in future exploitation strategies, targeting resources currently being neglected by reservoir production. However, for time-lapse analysis to be most effective, a number of considerations must be addressed in the development of an accurate 4D monitoring survey. Acquisition and repeatability of source and receiver locations, identical data processing flows and interpretation techniques all play a role in the successful and accurate delineation of missed reserves and other reservoir properties of interest.

Velocity-saturation relation transition during rocks saturation: direct laboratory observation by computer tomography and ultrasonic technique

Maximising the recovery of known hydrocarbon reserves is one of the biggest challenges facing the petroleum industry today. Optimal production strategies require accurate monitoring of production-induced changes of reservoir saturation and pressure over the life of the field. Time-lapse seismic technology is increasingly used to map these changes in space and time. However until now, interpretation of time-lapse seismic data has been mostly qualitative. In order to allow accurate estimation of the saturation, it is necessary to know the quantitative relationship between fluid saturation and seismic characteristics (elastic moduli, velocity dispersion and attenuation). The problem of calculating acoustic properties of rocks saturated with a mixture of two fluids has attracted considerable interest (Gist, 1994; Mavko and Nolen-Hoeksema, 1994; Knight et al. 1998); for a comprehensive review of theoretical and experimental studies of the patchy saturation problem see Toms et al. (2006).

Direct laboratory observation of patchy saturation and its effects on ultrasonic velocities

Maximizing the recovery of known hydrocarbon reserves is one of the biggest challenges facing the petroleum industry today. Optimal production strategies require accurate monitoring of production-induced changes of reservoir saturation and pressure over the life of the field. Time-lapse seismic technology is increasingly used to map these changes in space and time. However, until now, interpretation of time-lapse seismic data has been mostly qualitative. In order to allow accurate estimation of the saturation, it is necessary to know the quantitative relationship between fluid saturation and seismic characteristics (elastic moduli, velocity dispersion, and attenuation). The problem of calculating acoustic properties of rocks saturated with a mixture of two fluids has attracted considerable interest (Gist, 1994; Mavko and Nolen-Hoeksema, 1994; Knight et al., 1998. For a comprehensive review of theoretical and experimental studies of the patchy saturation problem see Toms et al., 2006).

Investigation of core data reliability to support time-lapse interpretation in Campos Basin, Brazil

Quantitative interpretation of time-lapse seismic data requires knowledge of saturation and pressure effects on seismic velocities. Although the former can usually be modeled adequately using the Gassmann equation, the latter is obtained mainly by laboratory measurements, which can be affected by core damage. We investigate the magnitude of this effect on compressional-wave velocities by comparing laboratory experiments and log measurements. We use Gassmann fluid substitution to obtain low-frequency saturated velocities from dry core measurements (thus mitigating the dispersion effects) taken at reservoir pressure. The analysis is performed for an unusual densely cored well from which 43 cores were extracted over a [Formula: see text]-thick turbidite reservoir. These computed velocities show very good agreement with the sonic-log measurements. This confirms that, for this particular region, the effect of core damage on ultrasonic measurements is less than the measurement error. Consequently, stress sensitivity of elastic properties as obtained from ultrasonic measurements is adequate for quantitative interpretation of time-lapse seismic data.

Core Damage: can We Calibrate Pressure Response with Lab Data?

Time-lapse (4D) seismic quantitative interpretation is based mainly on measurements of how saturation and pressure changes affect seismic velocities. Effect of saturation can be modeled using Gassmann equations. Pressure effect is usually obtained by laboratory measurements, which can be affected by core damage. In order to assess the adequacy of the core measurements to the properties of the intact reservoir rocks, it is necessary to compare them to in situ measurements. We present a study to assess the adequacy of ultrasonic measurements on core samples by comparing measured ultrasonic velocities at reservoir pressures with sonic log data from two wells located in an oil field in Campos Basin, offshore Brazil. The analysis is performed for these densely cored wells: more than 50 samples were extracted from a turbidite reservoir. We use Gassmann fluid substitution to obtain low-frequency saturated velocities from dry core measurements (thus mitigating the dispersion effects) taken at reservoir pressure. Comparisons of these computed velocities with sonic logs measurements show very good agreement. This confirms that for those particular regions the effect of core damage on ultrasonic measurements is below the measurement error. Consequently stress sensitivity of elastic properties as obtained from ultrasonic measurements is adequate for quantitative interpretation of time-lapse seismic data.

Technical article: Mapping reservoir pressure and saturation changes using seismic methods - possibilities and limitations

In this paper, travel-time and amplitude information from time-lapse seismic data are combined to improve the mapping of an over-pressured reservoir segment. The increased pore pressure is caused by water injection into the segment. According to RFT measurements in the well, the pore pressure increase is of the order of 50-80 bars. The observed amplitude increase (between the base line and the monitor survey) associated with the top reservoir event is of the order of 100-200%. A rough estimate of the velocity changes needed (assuming that the density change is negligible) to explain this amplitude change is a 20% reduction in the P-wave velocity. The observed pull-down effect (time-lapse travel-time shift) measured over the whole reservoir thickness is of the order of only 4-6 ms, indicating a gradual change in velocity below the top reservoir event, decreasing with depth. Interpretation of time-lapse seismic data depends on knowledge of the relationship between the seismic parameters and the typical reservoir parameters we want to map, such as, for instance, pore pressure changes and fluid saturation changes. The established link for bridging the gap between the two types of parameter is rock physics. For saturation effects, the Gassmann equations form a reasonable working basis, enabling us to make quantitative estimates of how much each of the seismic parameters changes with, for instance, water saturation. However, for pore pressure changes, the theoretical basis is weaker, and we have to rely on ultrasonic core measurements in order to establish a link between pore pressure changes and the corresponding changes in seismic parameters. One major weakness of the core measurements is that the core sample is damaged during the coring process (Nes et al. 2000). Artificial cracks are probably formed during the anisotropic stress unloading process. Even if the core sample is reloaded to simulate in situ stress conditions for the ultrasonic core measurements, it is not very likely that the original crack state of the sample is re-established. Furthermore, we have to deal with the upscaling problem for our core measurements: Are the ultrasonic measurements made on the small core sample representative at a seismic scale?