Time-lapse Seismic Data Sets Research Articles

Time-lapse full-waveform permeability inversion: A feasibility study

Time-lapse seismic monitoring necessitates integrated workflows that combine seismic and reservoir modeling to enhance reservoir property estimation. We present a feasibility study of an end-to-end inversion framework that directly inverts for permeability from multiple prestack time-lapse seismic data sets. To assess the method's robustness, we design experiments focusing on its sensitivity to initial models, potential errors in modeling, and crosstalk during multiparameter inversion. Our study leverages the publicly available Compass model to simulate CO2 storage in saline aquifers. This model is derived from well and seismic data from the North Sea in an area that is currently considered for geologic carbon storage.

Constrained nonlinear amplitude-variation-with-offset inversion for reservoir dynamic changes estimation from time-lapse seismic data

We develop a novel elastic amplitude-variation-with-offset (AVO) inversion process to estimate the fluid saturation and effective pressure or variations in these properties from time-lapse seismic data sets. These changes occur in oil and gas reservoirs caused by fluid injection or hydrocarbon production that leads to changes in the elastic wave properties, reflectivity, and seismic response. Our method is based on a seismic forward model that consists of a linearized AVO equation and a rock-physics model. The AVO equation links the elastic wave properties to seismic reflection amplitudes, whereas the rock-physics model maps the saturation and pressure into seismic velocities and density. The inversion approach relies on the gradient descent technique to estimate the unknown variables by searching for the minimum of the least-squares misfit between the observed and modeled data. The first-order gradient equations of the least-squares data misfit function with respect to effective pressure and water saturation are derived by using the adjoint-state method and the chain rule. The optimization method used to minimize the misfit function and obtain the best optimal solution is a limited-memory quasi-Newton algorithm. This inversion process allows us to incorporate prior constraints by using the logistic function to map the model variables to a bounded range. To achieve a stable solution to ill-posed inversion problems, optimal regularization weights are applied. The application of the developed workflow on 1D synthetic and real well-log data from the Edvard Grieg oil field simulating various saturation-pressure conditions during production demonstrates the validity of the approach with different noise levels. The inversion is then applied to a 2D synthetic data set modeled from the reservoir model of the Smeaheia field, a potential site for a large-scale offshore CO2 storage field located in the North Sea. Our results illustrate that our inversion method efficiently and accurately estimates reservoir saturation and pressure variations.

Derisking geologic carbon storage from high-resolution time-lapse seismic to explainable leakage detection

Geologic carbon storage represents one of the few truly scalable technologies capable of reducing the CO2 concentration in the atmosphere. While this technology has the potential to scale, its success hinges on our ability to mitigate its risks. An important aspect of risk mitigation concerns assurances that the injected CO2 remains within the storage complex. Among the different monitoring modalities, seismic imaging stands out due to its ability to attain high-resolution and high-fidelity images. However, these superior features come at prohibitive costs and time-intensive efforts that potentially render extensive seismic monitoring undesirable. To overcome this shortcoming, we present a methodology in which time-lapse images are created by inverting nonreplicated time-lapse monitoring data jointly. By no longer insisting on replication of the surveys to obtain high-fidelity time-lapse images and differences, extreme costs and time-consuming labor are averted. To demonstrate our approach, hundreds of realistic synthetic noisy time-lapse seismic data sets are simulated that contain imprints of regular CO2 plumes and irregular plumes that leak. These time-lapse data sets are subsequently inverted to produce time-lapse difference images that are used to train a deep neural classifier. The testing results show that the classifier is capable of detecting CO2 leakage automatically on unseen data with reasonable accuracy. We consider the use of this classifier as a first step in the development of an automatic workflow designed to handle the large number of continuously monitored CO2 injection sites needed to help combat climate change.

Reprocessed time-lapse seismic data provides new reservoir information on the Njord field

Improvements in time-lapse (4D) seismic processing methods provide opportunities to extract additional information from older time-lapse seismic data sets. This new information can help to optimize reservoir production. Four marine streamer time-lapse seismic data sets on the Njord field, offshore mid-Norway, were previously processed in 2007. Reprocessing in 2020 concentrated on better noise and multiple attenuation, improved imaging, and a focused step-by-step workflow to estimate and correct timing variations within and between surveys. The results dramatically improved on the 2007 processing. Gas injection could be tracked in greater detail and previously unidentified 4D signal was interpreted. The new data sets are expected to enhance reservoir understanding and improve future field performance.

Influence of reservoir-scale heterogeneities on the growth, evolution and migration of a CO2 plume at the Sleipner Field, Norwegian North Sea

New analysis of the baseline (pre-injection) seismic data at Sleipner has revealed large-scale, roughly north-trending, channelled ‘fairways’ at a range of stratigraphical levels in the Utsira Sand. The baseline data also reveal localised stratigraphical ‘point discontinuities’ within the reservoir, some of which show evidence of having provided vertical conduits for earlier natural gas flow. The repeat time-lapse seismic datasets, where finer details of reservoir geology are illuminated by the reflective CO2, show smaller-scale, north-trending and sometimes sinuous channels within the larger channel fairways. They also show a number of vertical CO2 pathways within the CO2 plume, corresponding to the point discontinuities seen on the baseline data.Reservoir flow models were set up with flow properties constrained only by the observed levels of CO2 accumulation in the reservoir and the arrival time of CO2 at the reservoir top just prior to the first repeat seismic survey in 1999. The initial model with laterally homogeneous sand units separated by thin semi-permeable mudstones achieved only a moderate match to the observed time-lapse seismic data. Subsequent flow models, progressively incorporating higher permeability vertical CO2 pathways through the mudstones and large-scale channel fairways within the reservoir sands, yielded a progressive and marked improvement in the history-match of key CO2 layers within the plume. Crucially, no layer-specific model calibration was employed to achieve this improvement.New geophysical measurements from Utsira Sand core have recently become available. These measurements provide important constraints on rock physics models of CO2 and brine mixtures in the Utsira Sand. An empirical Brie fluid mixing law for intermediate fluid saturations provides a good fit to the new laboratory data, allowing measurements of CO2 saturation to be converted into seismic velocity. This rock physics model was used to convert CO2 saturation distributions predicted by the most realistic reservoir model into a seismic velocity model of the CO2 plume. Synthetic seismic reflectivity profiles generated using this velocity model show a striking resemblance to the observed time-lapse seismic data, both in terms of plume layer reflectivity and also of time-shifts within and beneath the CO2 plume. This provides confidence in the fidelity of the preferred reservoir model solution.These results represent a significant breakthrough in the understanding and modelling of CO2 plume development at Sleipner. We emphasise that the improvements were brought about not by fine tuning reservoir properties to fit the observed time-lapse data, but simply by incorporating geological permeability features that can reasonably be inferred from the baseline seismic data.

A Critical Comparison of Three Methods for Time-Lapse Time-Shift Calculation

Time-shift, one of the most popular time-lapse seismic attributes, has been widely used in dynamic reservoir characterization by linking it with pressure and geomechanical changes. Therefore, it is important to select appropriate calculation methods according to different time-lapse seismic data quality and time-shift magnitude. To date, there have been various published works comparing different time-shift calculation methods and discussing their advantages and disadvantages. However, most of these comparisons are based only on synthetic tests or single field applications. As the quality of time-lapse seismic data and time-shift magnitude can vary in different fields, one method may not work consistently well for each case. In this paper, a critical comparison of three different time-shift calculation techniques (Hale’s fast cross-correlation, Rickett’s non-linear inversion, and Whitcombe’s correlated leakage method) is provided. The three methods are applied to a set of synthetic data sets that are designed to account for various seismic noise and time-shift magnitudes. They are also applied to four real time-lapse seismic data sets from three North Sea fields. The calculated time-shift results are compared with the input (in synthetic tests) or the real observations from information such as seabed subsidence and compaction (in field applications). Both qualitative and quantitative comparisons are performed. At the end, each of the time-shift methods is evaluated based on different aspects, and the most appropriate method is suggested for each data scenario. All three time-shift methods are found to successfully measure time-shifts. However, Rickett’s non-linear inversion is the most outstanding method, as it gives smooth time-shifts with relatively good accuracy, and the derived time strains are more stable and interpretable.

Common-focus point-based target-oriented imaging approach for continuous seismic reservoir monitoring

The ideal approach for continuous reservoir monitoring allows generation of fast and accurate images to cope with the massive data sets acquired for such a task. Conventionally, rigorous depth-oriented velocity-estimation methods are performed to produce sufficiently accurate velocity models. Unlike the traditional way, the target-oriented imaging technology based on the common-focus point (CFP) theory can be an alternative for continuous reservoir monitoring. The solution is based on a robust data-driven iterative operator updating strategy without deriving a detailed velocity model. The same focusing operator is applied on successive 3D seismic data sets for the first time to generate efficient and accurate 4D target-oriented seismic stacked images from time-lapse field seismic data sets acquired in a [Formula: see text] injection project in Saudi Arabia. Using the focusing operator, target-oriented prestack angle domain common-image gathers (ADCIGs) could be derived to perform amplitude-versus-angle analysis. To preserve the amplitude information in the ADCIGs, an amplitude-balancing factor is applied by embedding a synthetic data set using the real acquisition geometry to remove the geometry imprint artifact. Applying the CFP-based target-oriented imaging to time-lapse data sets revealed changes at the reservoir level in the poststack and prestack time-lapse signals, which is consistent with the [Formula: see text] injection history and rock physics.

Estimation of reservoir fluid saturation from 4D seismic data: effects of noise on seismic amplitude and impedance attributes

Time-lapse (4D) seismic data sets have proven to be extremely useful for reservoir monitoring. Seismic-derived impedance estimates are commonly used as a 4D attribute to constrain updates to reservoir fluid flow models. However, 4D seismic estimates of P-wave impedance can contain significant errors associated with the effects of seismic noise and the inherent instability of inverse methods. These errors may compromise the geological accuracy of the reservoir model leading to incorrect reservoir model property updates and incorrect reservoir fluid flow predictions. To evaluate such errors and uncertainties we study two time-lapse scenarios based on 1D and 3D reservoir model examples, thereby exploring a number of inverse theory concepts associated with the instability and error of coloured inversion operators and their dependence on seismic noise levels. In the 1D example, we show that inverted band-limited impedance changes have a smaller root-mean-square (RMS) error in comparison to their absolute broadband counterpart for signal-to-noise ratios 10 and 5 while for signal-to-noise ratio (S/N) = 3 both inversion methods present similarly high errors. In the 3D example we use an oilfield benchmark case based on the Namorado Field in Campos Basin, Brazil. We introduce a histogram similarity measure to quantify the impact of seismic noise on maps of 4D seismic amplitude and impedance changes as a function of S/N levels, which indicate that amplitudes are less sensitive to 4D seismic noise than impedances. The RMS errors in the estimates of water saturation changes derived from 4D seismic amplitudes are also smaller than for 4D seismic impedances, over a wide range of typical seismic noise levels. These results quantitatively demonstrate that seismic amplitudes can be more accurate and robust than seismic impedances for quantifying water saturation changes with 4D seismic data, and emphasize that seismic amplitudes may be more reliable to update fluid flow model properties in the presence of realistic 4D seismic noise.

Estimation of reservoir fluid saturation from 4D seismic data: effects of noise on seismic amplitude and impedance attributes

Time-lapse (4D) seismic data sets have proven to be extremely useful for reservoir monitoring. Seismic-derived impedance estimates are commonly used as a 4D attribute to constrain updates to reserv...

Time-lapse seismic monitoring of hydraulic fracture stimulations within the Niobrara-Codell Reservoir Wattenberg Field, Colorado

Time-lapse seismic interpretation is demonstrated as a viable method for observing physical modification of a tight reservoir resulting from the hydraulic fracturing process. Compressional seismic data sets were acquired before and after completions of 11 horizontal wells within a section (one-square mile) of Wattenberg Field, Colorado. The time-lapse seismic data sets, after crossequalization, showed an acoustic impedance anomaly within the reservoir interval consistent with pressurization of the reservoir from surface operations. The spatial location of the anomaly is interpreted such that pressure compartmentalization exists due to faulting within the reservoir. A decrease in the acoustic P-impedance of up to 7% was observed from the baseline to the monitor survey in the reservoir interval. An increase in pore pressure owing to hydraulic fracturing was interpreted as the physical mechanism causing the greatest change in P-impedance. Hydraulic fracturing is highly dependent on local geology, and the integration of geoscience with parameter design is necessary for optimization. Time-lapse seismic reservoir monitoring can assist in documenting fault-related reservoir compartmentalization. The Colorado School of Mines Reservoir Characterization Project (RCP) undertook a monitoring project with Anadarko Petroleum Corporation (APC) in Wattenberg Field, Colorado. The Wishbone section is a one-square mile area containing 11 horizontal wells. Each well was fractured with multiple stages and completion design was varied from stage-to-stage. The completions parameters that varied were: well spacing, targeted formation, hydraulic fracturing volumes, pressure, rates, completion type, and number of stages.

Rock-physics-based double-difference inversion for CO2 saturation and porosity at the Cranfield CO2 injection site

Large-scale subsurface injection of [Formula: see text] has the potential to reduce emissions of atmospheric [Formula: see text] and improve oil recovery. Studying the effects of injected [Formula: see text] on the elastic properties of the saturated reservoir rock can help to improve long-term monitoring effectiveness and accuracy at locations undergoing [Formula: see text] injection. We used two vintages of existing 3D surface seismic data and well logs to probabilistically invert for the [Formula: see text] saturation and porosity at the Cranfield reservoir using a double-difference approach. The first step of this work was to calibrate the rock-physics model to the well-log data. Next, the baseline and time-lapse seismic data sets were inverted for acoustic impedance [Formula: see text] using a high-resolution basis pursuit inversion technique. The reservoir porosity was derived statistically from the rock-physics model based on the [Formula: see text] estimates inverted from the baseline survey. The porosity estimates were used in the double-difference routine as the fixed initial model from which [Formula: see text] saturation was then estimated from the time-lapse [Formula: see text] data. Porosity was assumed to remain constant between survey vintages; therefore, the changes between the baseline and time-lapse [Formula: see text] data may be inverted for [Formula: see text] saturation from the injection activities using the calibrated rock-physics model. Comparisons of inverted and measured porosity from well logs indicated quite accurate results. Estimates of [Formula: see text] saturation found less accuracy than the porosity estimates.

Estimation of pressure-saturation changes for unconsolidated reservoir rocks with highVP/VSratio

We find that conventional time-lapse seismic pressure-saturation discrimination methods become unstable for high [Formula: see text] ratios. Using first-order approximations in the amplitude variation with offset (AVO) gradient and intercept changes and in the rock-physics models increase the inaccuracy in pressure-saturation changes estimates. We propose a new method, based on a stepwise linear approximation to the intercept and gradient reflectivity changes, to estimate pressure and saturation changes. The applicability of the new method is tested on synthetic data over a range of 0%–50% gas saturation and 0–3.5 MPa pore-pressure changes. The new method is more consistent and provides better estimates compared with conventional methods. In the presence of random noise (up to 15%), the estimates are reasonably better for the new method. We use this new method to investigate the feasibility of pressure-saturation discrimination for a shallow unconsolidated sand reservoir in which an underground blowout occurred in 1989. We analyze a sand layer at 490-m depth that was charged by gas due to the blowout. Because of the shallow depth, the [Formula: see text] is expected to be higher than 2 before the blowout. Near- and far-offset time-lapse seismic data sets from 1988 and 1990 are used as input to estimate changes in AVO intercept and gradient and then changes in pressure and saturation. We find that the new method estimates more realistic pressure-saturation changes compared to the conventional one.

시간경과 탄성파 자료의 교차균등화를 위한 제약적 최적 맞춤필터링 방법

저류층 감시(reservoir monitoring)를 위해서는 시간경과(time-lapse) 탄성파 자료들을 비교하는 방법이 주로 사용되며, 시간경과 탄성파자료로부터 저류층에서의 변화에 의한 차이만을 추출해 내는 기술이 핵심이라 할 수 있다. 본 논문에서는 시간경과 탄성파자료로부터 저류층에서의 변화만을 추출하기 위한 방법으로 기존의 교차균등화(crossequalization) 방법과 개선된 최적화 방법을 실험 및 비교해 보았다. 기존의 방법론으로는 주파수 띠폭 균등화(bandwidth equalization)와 위상보정(phase rotation)을 주파수 영역과 시간 영역 그리고 혼합영역에서 각각 구현하여 그 성능을 비교해 보았으며, 이러한 방법들이 갖고 있는 고주파수가 손실되는 한계를 극복할 수 있는 제약적 최적화 필터링(constrained optimum filtering) 방법론을 제안 및 실험해 보았다. 새로이 제안된 제약적 최적화 필터링 방법은 최적화된 맞춤필터를 구함으로써 저류층 변화성분의 주파수띠폭을 넓히는데 개선된 결과를 보여주었다. The comparison between time-lapse seismic datasets is the most popular method in the reservoir monitoring. The method of extracting the changes only due to the change in the reservoir is the essential technique in the comparison of time-lapse seismic datasets. In the paper, the conventional cross-equalization approaches and an enhanced optimized approach have been tested and compared each other. As conventional approaches, the bandwidth equalization and phase rotation methods have been tested in frequency, time and mixed domains, respectively and their results were compared each other. In order to overcome the limit of the conventional approaches, which loses high frequency components, a new constrained optimum filtering method was proposed and experimented. The new constrained filtering method has shown the improvement in broadening the bandwidth of the components of reservoir changes by acquiring optimized match filter.

Target-oriented joint least-squares migration/inversion of time-lapse seismic data sets

Two related formulations are proposed for target-oriented joint least-squares migration/inversion of time-lapse seismic data sets. Time-lapse seismic images can be degraded when reservoir overburden is complex or when acquisition geometries significantly differ, because the migration operator does not compensate for the resulting amplitude and phase distortions. Under these circumstances, time-lapse amplitudes are poor indicators of production-related changes in reservoir properties. To correct for such image degradation, time-lapse imaging is posed as joint inverse problems that utilize concatenations of target-oriented approximations to the linear least-squares imaging Hessian. In both formulations, spatial and temporal constraints ensure inversion stability and geologically consistent time-lapse images. Using two numerical time-lapse data sets, we confirmed that these formulations can attenuate illumination artifacts caused by complex overburden or geometry differences, and that they yield better-quality images than obtainable with migration.

Geophysical Monitoring of Hydrological and Biogeochemical Transformations Associated with Cr(VI) Bioremediation

Understanding how hydrological and biogeochemical properties change over space and time in response to remedial treatments is hindered by our ability to monitor these processes with sufficient resolution and over field relevant scales. Here, we explored the use of geophysical approaches for monitoring the spatiotemporal distribution of hydrological and biogeochemical transformations associated with a Cr(VI) bioremediation experiment performed at Hanford, WA. We first integrated hydrological wellbore and geophysical tomographic data sets to estimate hydrological zonation at the study site. Using results from laboratory biogeophysical experiments and constraints provided by field geochemical data sets, we then interpreted time-lapse seismic and radar tomographic data sets, collected during thirteen acquisition campaigns over a three year experimental period, in terms of hydrological and biogeochemical transformations. The geophysical monitoring data sets were used to infer: the spatial distribution of injected electron donor; the evolution of gas bubbles; variations in total dissolved solids (nitrate and sulfate) as a function of pumping activity; the formation of precipitates and dissolution of calcites; and concomitant changes in porosity. Although qualitative in nature, the integrated interpretation illustrates how geophysical techniques have the potential to provide a wealth of information about coupled hydrobiogeochemical responses to remedial treatments in high spatial resolution and in a minimally invasive manner. Particularly novel aspects of our study include the use of multiple lines of evidence to constrain the interpretation of a long-term, field-scale geophysical monitoring data set and the interpretation of the transformations as a function of hydrological heterogeneity and pumping activity.

A sensitivity study based on 2D synthetic data from the Gullfaks Field, using PP and PS time-lapse stacks for fluid-pressure discrimination

We investigate how combined use of time-lapse PP and PS seismic stacks can be utilized for discrimination between pressure and saturation changes. The theory is based on a combination of the well-known Gassmann and Hertz–Mindlin models. To simulate the amplitudes on PP and PS sections we compute the stacked reflection coefficients within a given angular span. Cross-plotting the PP and PS amplitude changes against the pressure and saturation changes, enables simultaneous estimation of pressure and saturation changes. The method is tested on a realistic 2D finite-difference time-lapse seismic dataset from the Gullfaks Field. The uncertainties in the estimated saturation and pressure changes are expressed by the uncertainties in PP and PS stack amplitudes. We find that this method is strongly dependent on the in situ stress conditions, and especially that low values for the initial effective pressure mean low discrimination sensitivity.

Discrimination between phase and amplitude attributes in time-lapse seismic streamer data

Time-lapse seismic experiments aim to obtain information about production-related effects in hydrocarbon reservoirs to increase the recovery percentage. However, nonrepeatability problems such as acquisition differences, overburden effects, and noise are often significantly stronger than the imprint of production changes in time-lapse seismic data sets. Consequently, it is very difficult to appraise the changes in petrophysical reservoir parameters over time. We introduce a 4D monitoring approach based on the spectral ratio method. This method produces two time-lapse attributes: the relative change in reflection coefficient and the traveltime shift at reflecting interfaces. These attributes can be used for appraising production-related changes in the subsurface. The approach corrects for time-invariant nonrepeatability effects in the overburden and source-receiver coupling problems in time-lapse surveys. The validity of the method is limited to structurally simple overburden and reservoirs with weak lateral variations. First, we validate the methodology using a synthetic time-lapse seismic experiment. Next, we apply the method to a real time-lapse data set from the Troll West gas province in the North Sea. In the real example, we could not detect movement in the fluid contact of [Formula: see text]. The expected change in amplitude is less than 10%, which is probably below the background noise level for this data set.

Successful application of time-lapse seismic data in Shell Expro's Gannet Fields, Central North Sea, UKCS

The Central North Sea contains a large variety of oil and gas fields at different stages of maturity within the life cycle of an asset, at varying depths, in varied geology and at widely differing pressure and temperature conditions. Over the last three years Shell UK Exploration and Production (Shell Expro) has acquired new 3D surveys over many of these fields which, following careful attention to detail in acquisition and processing, have been quantitatively compared to pre-production surveys. Differences between these time-lapse seismic datasets have then been interpreted in terms of changes in reservoir fluid movement and changed pressure/temperature conditions. These interpretations have proven useful for reservoir management by identifying swept versus unswept zones, sealing versus non-sealing faults, efficiency of drive mechanisms and connected volumes to specific wells Four case studies from the Gannet Development illustrate how these observations have impacted reservoir management and show how application of this relatively new, yet rapidly maturing technology has had a positive impact on the remaining value of these fields. Importantly, the detectability of changes in the reservoir has been seen to be greater than predicted prior to data acquisition. Indeed, 4D seismic data have become an established part of the long-term plans for all of Shell Expro's subsurface assets. With these successes have come fresh challenges and future efforts will focus on reducing costs in proven 4D technology whilst pushing to introduce new techniques for data gathering and for interpretation of large volumes of new information.