Time-lapse Seismic Technology Research Articles

Numerical modeling of seismic responses from fractured reservoirs in 4D monitoring — Part 1: Seismic responses from fractured reservoirs in carbonate and shale formations

One of the most urgent problems of oil and gas reservoir monitoring is the assessment of fractured reservoir infill type — with fluid-filled, gas-filled, or closed (no-reservoir situation) fractures, which is of significant value for time-lapse seismic technology. We used the grid-characteristic method for numerical modeling of seismic responses from fractured periodic elastoacoustic structures. We consider every single fracture individually (without using the effective medium approach), and we set explicit boundary conditions on fracture surfaces. We assume realistic height-to-thickness ratios — fracture opening (aperture) — equaling three to five orders of magnitude. These techniques make our models as close to real fractured reservoirs as possible. Analyzing the simulated seismic responses, we solve the problem of assessing the fractured reservoir infill type. As a result, previously unknown properties of seismic responses from fractured reservoirs were revealed. We use amplitude variation with offset (AVO) as the main tool for the analysis of the fracture infill type effect on the seismic response in three frequency ranges. Three out of four models exhibit a stable positive AVO gradient regardless of the rock type and frequency range. The analysis of linearized Zoeppritz equations confirms such AVO behavior. We have developed quantitative criteria (indicators) for recognition of a fracture infill type. Amplitude-frequency analysis is shown to expand the capabilities of the infill type recognition. Thus, a method for determining the fractured reservoir infill type is established for carbonate and shale formations, which could become the basis for a new direction in time-lapse technology.

Prediction of residual oil saturation by using the ratio of amplitude attributes of time-lapse seismic data

Subtraction of baseline and monitoring seismic data is a common step in highlighting reservoir changes in time-lapse seismic interpretation. However, ambiguity exists in the interpretation of the amplitude difference, which is controlled by fluid change and reservoir thickness. To estimate the residual oil saturation quantitatively, we have developed a time-lapse seismic interpretation method that uses the ratio of amplitude attributes extracted from the baseline and monitoring seismic data. The relationship between impedance change and the ratio of the baseline and monitoring amplitude attributes is determined to avoid the influence of reservoir thickness. Subsequently, the fluid saturation is calculated from the impedance change by using a proper petrophysical relationship. We have tested our new method on a real time-lapse seismic data set from a water-flooded reservoir in the deepwater area of West Africa. The water-flooded area determined from the amplitude difference does not completely match the production logs because of the influence of variations in the reservoir thickness. However, the residual oil distribution calculated with the proposed method matches the production logs well. The connectivity of sandstone bodies is also evaluated based on an integrated interpretation of estimated oil saturation. With its simple principles and easy accessibility, our method improves the accuracy of time-lapse seismic data interpretation in water-flooded oil reservoirs. Furthermore, the quantitative interpretation of fluid change enables the time-lapse seismic technology to guide reservoir development directly.

Geometry Matching Technology of Non-Repeating Acquired Time-Lapse Seismic Data Processing

Different from the normal time-lapse seismic technology, time-lapse seismic technology with non-repeating acquired data utilize existing multi-period seismic data with different geometries at different exploration period of the same area. Not only the change of reservoir parameters cause the property differences of two-period data but also the difference of geometries, this uncertainty has become a fundamental problem in application of time-lapse seismic technology. In order to solve this problem, this paper takes advantage of the 3D Gaussian beam simulating method for illumination analysis of reservoir model, then we analyzes the impacts of various parameters of geometry on receiving energy of reservoir, finally we put forward the main factors affecting imaging of reservoir : the distribution of offset and azimuth. Basing on this conclusion this paper established the work flow of geometry matching for non-repeating acquired seismic data. By processing real data in S block, this technology could effectively reduce the affects of geometry difference and obtain an obvious result, and also provide an idea to increase value of multi-period seismic data in old oil field.

Rewards and Challenges of Seismic Monitoring for CO2 Storage: A Fluid Substitution Study in the Gippsland Basin, Victoria, Australia

Seismic observation has key advantages that, in the right geological conditions, make it extremely valuable for CO2 storage monitoring. Among surface techniques allowing the observation of the entire storage complex, it has by far the greatest vertical and lateral resolution and it can provide a full 3D view of the reservoir and overburden. However, in our experience, theoretical applicability of seismic acquisition for CO2 plume tracking has often been challenged by the geology: high rock stiffness, heterogeneity, large depths, or low porosity in a storage site are not favorable factors. Moreover, there is uncertainty on the minimum levels of detectability. CO2 might mix either homogeneously or create patches of variable saturation, and this can result in a large variability on the expected seismic signal, especially for saturations lower than 50%. We investigate the seismic signal expected for a location in the Gippsland Basin, Victoria, Australia. Using classical rock physics equations, CO2 detectability at the reservoir level will present some challenges, but the possibility for detection above the reservoir is quite favorable. An understanding of the relative heterogeneity of storage formations is critical to establishing uncertainty and detection limits of time-lapse seismic technology.

Linking reservoir geomechanics and time-lapse seismics: Predicting anisotropic velocity changes and seismic attributes

Seismic technology has been used successfully to detect geomechanically induced signals in repeated seismic experiments from more than a dozen fields. To explain geomechanically induced time-lapse (4D) seismic signals, we use results from coupled reservoir and geomechanical modeling. The coupled simulation yields the 3D distribution, over time, of subsurface deformation and triaxial stress state in the reservoir and the surrounding rock. Predicted changes in triaxial stress state are then used to compute changes in anisotropic P- and S-wave velocities employing a stress sensitive rock-physics transform. We predict increasing vertical P-wave velocities inside the reservoir, accompanied by a negative change in P-wave anisotropy [Formula: see text]. Conversely, in the overburden and underburden, we have predicted a slowdown in vertical P-wave velocity and an increase in horizontal velocities. This corresponds to positive change in P-wave anisotropy [Formula: see text]. A stress sensitive rock-physics transform that predicts anisotropic velocity change from triaxial stress change offers an explanation for the apparent difference in stress sensitivity of P-wave velocity between the overburden and the reservoir. In a modeled example, the vertical velocity speedup per unit increase in vertical stress [Formula: see text] is more than twice as large in the overburden as in the reservoir. The difference is caused by the influence of the stress path [Formula: see text] (i.e., the ratio [Formula: see text] between change in minimum horizontal effective stress [Formula: see text] and change in vertical effective stress [Formula: see text]) on vertical velocity. The modeling suggests that time-lapse seismic technology has the potential to become a monitoring tool for stress path, a critical parameter in failure geomechanics.

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).

Time-lapse inversion and geomechanical modelling of the South Arne field

Time-lapse seismic technology is routinely used to monitor production-related reservoir changes. Indeed, the analysis of observed seismic 4D effects and estimation of the corresponding elastic attributes provide valuable information about the dynamics of the reservoir (saturation, pore pressure), particularly away from existing wells, into areas where production data is ‘blind.’ However, the interpretation of time-lapse response can be complex as different reservoir property changes can lead to the same variation in a given elastic parameter. This is particularly true for chalk fields undergoing porosity reduction in addition to change in fluid and pore pressure depletion.

Innovations in time

Victor Aarre, Henrik Juhl Hansen, Jörg Herwanger, Julie Marshall, Jens Olav Paulsen, Stephen Pickering, and Michael Tang of WesternGeco describe the company’s experience with time-lapse (4D) seismic using its proprietary Q-Marine technology. Time-lapse or 4D seismic technology has existed for quite some time; the first 4D seismic survey was acquired in 1981 onshore Canada. Today, 16% of Q-Marine single-sensor seismic surveys are related to the monitoring of reservoir production. One reason for the growth of seismic reservoir monitoring programmes is that, in the last five years, the industry has responded to 4D seismic imaging challenges through a number of significant enhancements in repeatability. This, combined with innovations in 4D analysis and interpretation, has caused time-lapse seismic technology to become an integral part of the business process of many oil companies.

High-resolution processing for time-lapse seismic

Time-lapse seismic technology is moving from measurement of qualitative variations to quantitative analysis of fluid saturation and pressure variations. Increasing the resolution of time-lapse seismic data relative to the reservoir body scale offers the possibility of even more accurate measurements. The resolution improvement is directly dependent on the capacity to recover the high frequency content of the seismic measurement. In this paper, we investigate a data processing methodology that provides a 4D seismic signature with an extended frequency bandwidth. We pay particular attention to the seismic data preconditioning in order to remove random noise and spatial correlated noise, such as the acquisition footprint, which can contaminate the seismic high frequency content. Using a geostatistical technique, we apply the concept of common seismic cube derived from two adjacent seismic angle stacks. The common seismic cube does not include the acquisition imprint and has an improved signal to noise ratio, especially for the high frequencies. The concept of common spectrum is used to design two symmetric matching operators in order to increase the repeatability of the high frequencies. Once the data have been preconditioned, we use an innovative technology exploiting the spatial coherence of the seismic information with predefined reflector constraints to solve a sparse reflectivity distribution. A North-Sea example shows the benefits of the new high-resolution time lapse processing workflow.

BP's increasing systematic use of time-lapse seismic technology

Following experimental success in the application of 4D technology in the Magnus and Foinaven fields and the delivery of commercial value from the application of time-lapse seismic (4D) studies in the Forties and West of Shetland fields and in the Pompano Field in the Gulf of Mexico, BP has embarked on the systematic use of 4D monitoring in its NW Europe operations to enhance value in the light of an increasing production challenge. Within the past two years, 12 datasets have been acquired over 19 fields of varied reservoir age, type and property. Although specific questions differ from field to field, in all cases a major objective is to influence the location and design of infill wells. Useful time-lapse information has been gained from post-stack matched ‘legacy’ surveys of varying data quality. However, it is clear that more value is added by custom-designed 4D surveys: seismic quality and repeatability are critical to the successful delivery of reliable time-lapse seismic monitoring. Integration of seismic data with dynamic data is still relatively ‘low-tech’ and further benefits will be gained by improvement in this area. The paradigm is shifting to a position where 4D monitoring in the North Sea is the rule rather than the exception. Now that there is clear evidence of added value in the most obvious target reservoirs, surveys are being carried out in areas that are technically more challenging – and the early results indicate that these too will be of real commercial benefit. Use of 4D data is also being progressed in other regions, including the Gulf of Mexico, and application in other basins around the world is being planned. On the technology development front, BP is seeking continuous improvements in acquisition and processing, both in quality and turnaround time, and richer integration with production and conventional well-based surveillance data. The ultimate goal is for effective reservoir management based on a range of surveillance methods.

F.A.R.M: (Foinaven Active Reservoir Monitoring): Planning and Progress Towards 4-D Seismic: ABSTRACT

Foinaven Field is a new deep water development, West of Shetland, on the United Kingdom Continental Shelf. During 1995, it has become the subject of an intensive 3 year trial into the benefits of time lapse seismic technology. This paper describes the progress made towards actively monitoring the reservoir fluids during production. The fast track appraisal and development of Foinaven has been facilitated by the use of direct hydrocarbon indicators from 3-D seismic. In theory, the same benign rock properties can be used to monitor the movement of the water flood or gas cap. It is expected that 4-D seismic could permit better prediction of field performance and pinpoint future infill drilling opportunities. Reservoir monitoring using the seismic method relies upon frequent acquisition of high quality and repeatable 3-D data. The F.A.R.M. project, to date, has been involved in the installation of a permanent array of hydrophones on the seabed for the first [open quotes]submarine[close quote] 3-D acquired across Foinaven. In addition, a high specification conventionally surface towed 3-D has been acquired for comparison. Both surveys will be repeated following several months of oil production. This paper will describe the planning and current status of F.A.R.M. together with the perceivedmore » benefits of the 4-D technique.« less