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Integration of time-lapse seismic data into dynamic reservoir model is an efficient process in calibrating reservoir parameters update. The choice of the metric which will measure the misfit between observed data and simulated model has a considerable effect on the history matching process, and then on the optimal ensemble model acquired. History matching using 4D seismic and production data simultaneously is still a challenge due to the nature of the two different type of data (time-series and maps or volumes based).
Conventionally, the formulation used for the misfit is least square, which is widely used for production data matching. Distance measurement based objective functions designed for 4D image comparison have been explored in recent years and has been proven to be reliable. This study explores history matching process by introducing a merged objective function, between the production and the 4D seismic data. The proposed approach in this paper is to make comparable this two type of data (well and seismic) in a unique objective function, which will be optimised, avoiding by then the question of weights. An adaptive evolutionary optimisation algorithm has been used for the history matching loop. Local and global reservoir parameters are perturbed in this process, which include porosity, permeability, net-to-gross, and fault transmissibility.
This production and seismic history matching has been applied on a UKCS field, it shows that a acceptalbe production data matching is achieved while honouring saturation information obtained from 4D seismic surveys.
In this paper we propose a proxy model based seismic history matching (SHM), and apply it to time-lapse (4D) seismic data from a Norwegian Sea field. A stable proxy model is developed for generating 4D seismic attributes by using only the original baseline seismic data and dynamic pressure and saturation predictions from reservoir flow simulation. This method (
In this study we firstly perform a check on the validity and accuracy of the proxy approach following the methodology of (
We propose a stable and accurate proxy for generating maps of 4D seismic attributes using only the original baseline seismic data and fluid-flow simulation predictions. The approach provides a fast track procedure for generating 4D seismic data from the simulator. It has particular use in quantitative 4D seismic analysis, and specifically for incorporating time-lapse seismic data into the history-matching loop where many seismic modeling iterations are required. The method circumvents the petro-elastic model with its associated uncertainties and also the need to choose a seismic full-wave or convolutional modeling solution. Despite the relative simplicity of the proxy, it is found not to bias the choice of optimal solution for the history match. Application to synthetic datasets based on a two North Sea fields indicates that the proxy can remain accurate to within a mean error of 5%.
Presentation Date: Monday, October 17, 2016
Start Time: 2:15:00 PM
Location: Lobby D/C
Presentation Type: POSTER
Yin, Zhen (The Edinburgh Time-Lapse Project, Heriot-Watt University) | MacBeth, Colin (The Edinburgh Time-Lapse Project, Heriot-Watt University) | Chassagne, Romain (The Edinburgh Time-Lapse Project, Heriot-Watt University)
A technique is proposed to quantitatively measure interwell connectivity by correlating multiple 4D seismic monitors to historical well production data. We make use of multiple 4D seismic surveys shot over the same reservoir to generate an array of 4D seismic differences. Then a causative relationship is defined between the 4D seismic signals and changes of reservoir fluid volumes caused by injection and production behavior. This allows us to correlate seismic data directly to well data to generate a "well2seis" volume. It is found that the distribution of the "well2seis" correlation attributes reveals key reservoir connectivity features, such as the seal of faults, inter-reservoir shale and fluid flow pathways between wells, and can therefore enhance our interpretation on interwell connectivity. Combining with conventional interwell methods that are based on injection and production rate variations, this multiple 4D seismic method is found to support the conventional interwell approaches and can provide more reliable and detailed interpretation.
Our methodology is tested on a synthetic model extracted from full-field data for a Norwegian Sea reservoir, the fluid flow of which is controlled by fault compartmentalization and inter-reservoir shale. The full structural details and reservoir properties are preserved but three scenarios with different degrees of reservoir connectivity are created. It is found that proposed technique successfully detects the flow paths of the injected fluids in all reservoir scenarios. A volumetric attribute is created that accurately identifies the distinctive types of key flow barriers and conduits for each scenario that are known to be major factors influencing the reservoir dynamics. This proves that the well2seis attribute agrees with geological interpretations better than conventional well connectivity factors based on engineering data only. Additionally, the combination of the two types of methods provides a more robust tool for characterization of the reservoir connectivity by providing both quantitative degree and physical pattern of interwell communication.
This paper presents a history matching scheme that has been applied to production data and time lapse seismic data. The production data objective function is calculated using the conventional least squares method between the historical production data and simulation predictions, while the seismic objective function uses the Hamming distance between two binary images of the gas distribution (presence of gas (1) or absence of gas (0)) sequenced over the different acquisition times. The technique is applied to a UKCS (United Kingdom Continental Shelf) field that has deep-water tertiary turbidite sands and multiple stacked reservoirs defining some degree of compartmentalisation. Thirty five parameters are perturbed in this history match, they can be classified as volumetric parameters (net-to-gross, pore volume), transmissibility parameters (permeability, transmissibility), and end points of the relative permeability curves (critical saturation points). An initial ensemble of fluid flow simulation models is created where the full range of uncertain parameters are acknowledged using experimental design methods, and an evolutionary algorithm is used for optimization in the history matching process. It is found that permeability and critical gas saturation are key parameters for achieving a good history match, and that the volumetric parameters are not significant for this match in this particular reservoir. We also observe that matching only to production data marginally improves the seismic match, whilst matching to only seismic data improves the fit to production data. Combining both sets of data delivers an improvement for the production data and seismic data, as well as an overall reduction in the uncertainties. A unique feature of this technique is the use of the Hamming distance metric for seismic data history matching analysis, as this circumvents the use of the uncertain petroelastic model. This approach is easy to implement, and also helps achieve an effective global history match.
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the EAGE Annual Conference & Exhibition incorporating SPE Europec held in Copenhagen, Denmark, 4-7 June 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract We used a commercial reservoir simulator to study first the dissipation of aqueous drilling fluid filtrate invasion around a cased observation well in an oil-saturated formation under the action of capillary pressure, and then the interaction of a waterflood front with the cased well and remaining invaded zone. Hysteretic behavior of the capillary pressure and relative permeabilities is critically important to these processes and is taken into account using the Killough model, with the various bounding drainage and imbibition curves computed from a pore network model. Filtrate invasion into a hydrocarbon formation influences the readings of well logging tools.
Mitchell, Jonathan (Schlumberger) | Edwards, John Ernest (Schlumberger) | Fordham, Edmund (Schlumberger Cambridge Research) | Staniland, John (Schlumberger) | Chassagne, Romain (Petroleum Development Oman) | Cherukupalli, Pradeep Kumar (Petroleum Development Oman (PDO)) | Wilson, Ove B. (Shell Intl. E&P BV) | Faber, Marinus J. (Shell Global Solutions Int) | Bouwmeester, Ron
Laboratory and single well pilot nuclear magnetic resonance (NMR) logging results are obtained for an enhanced oil recovery (EOR) project using a common physics of measurement at both scales. Screening for chemical EOR efficacy usually begins in the laboratory before moving to single or multiple well field pilots. Laboratory experiments were conducted on a low-field bench-top NMR magnet with fluid injection protocols that matched the log-inject-log concept of the single-well in situ EOR evaluation (Arora et al. 2010). In situ measurements of the oil and brine saturations during the flood, by "diffusion-editing?? protocols and by relaxation measurements alone, are shown to be in quantitative agreement with gravimetric assays of recovered oil. Spatially resolved T2 analysis (the laboratory equivalent of a standard NMR well log) revealed non-uniform oil saturation during the EOR process in short core plugs. The final remaining oil distribution is confirmed by a reservoir simulation in a geometry identical to the NMR-compatible core holder. In a region of the core-plug not influenced by end effects, complete recovery of the oil was observed, consistent with the the single-well in situ EOR evaluation. The quantitative estimates of remaining oil, using a tool-equivalent NMR protocol, demonstrate the potential for NMR logging of remaining oil in monitoring wells completed with NMR-transparent casing.