scholarly journals Time-Lapse CSEM Monitoring: Correlating the Anomalous Transverse Resistance with SoPhiH Maps

Energies ◽  
2021 ◽  
Vol 14 (21) ◽  
pp. 7159
Author(s):  
Paulo T. L. Menezes ◽  
Jorlivan L. Correa ◽  
Leonardo M. Alvim ◽  
Adriano R. Viana ◽  
Rui C. Sansonowski
Keyword(s):  
Fluid Flow ◽  
Linear Relationship ◽  
Risk Reduction ◽  
Time Lapse ◽  
Hydrocarbon Exploration ◽  
Data Inversion ◽  
Transverse Resistance ◽  
New Frontier ◽  
Monitoring And Surveillance ◽  
Sweet Spots

The CSEM method, which is frequently used as a risk-reduction tool in hydrocarbon exploration, is finally moving to a new frontier: reservoir monitoring and surveillance. In the present work, we present a CSEM time-lapse interpretation workflow. One essential aspect of our workflow is the demonstration of the linear relationship between the anomalous transverse resistance, an attribute extracted from CSEM data inversion, and the SoPhiH attribute, which is estimated from fluid-flow simulators. Consequently, it is possible to reliably estimate SoPhiH maps from CSEM time-lapse surveys using such a relationship. We demonstrate our workflow’s effectiveness in the mature Marlim oilfield by simulating the CSEM time-lapse response after 30 and 40 years of seawater injection and detecting the remaining sweet spots in the reservoir. The Marlim reservoirs are analogous to several turbidite reservoirs worldwide, which can also be appraised with the proposed workflow. The prediction of SoPhiH maps by using CSEM data inversion can significantly improve reservoir time-lapse characterization.

Dual attenuation peaks revealing mesoscopic and microscopic fluid flow in partially oil-saturated Fontainebleau sandstones

2020 ◽  
Vol 224 (3) ◽  
pp. 1670-1683
Author(s):  
Liming Zhao ◽  
Genyang Tang ◽  
Chao Sun ◽  
Jianguo Zhao ◽  
Shangxu Wang
Keyword(s):  
Fluid Flow ◽  
Reservoir Characterization ◽  
Seismic Analysis ◽  
Confining Pressure ◽  
Time Lapse ◽  
Seismic Attenuation ◽  
Fluid Distribution ◽  
Oil Viscosity ◽  
Measurement Results ◽  
And Shifts

SUMMARY We conducted stress–strain oscillation experiments on dry and partially oil-saturated Fontainebleau sandstone samples over the 1–2000 Hz band at different confining pressures to investigate the wave-induced fluid flow (WIFF) at mesoscopic and microscopic scales and their interaction. Three tested rock samples have similar porosity between 6 and 7 per cent and were partially saturated to different degrees with different oils. The measurement results exhibit a single or two attenuation peaks that are affected by the saturation degree, oil viscosity and confining pressure. One peak, exhibited by all samples, shifts to lower frequencies with increasing pressure, and is mainly attributed to grain contact- or microcrack-related squirt flow based on modelling of its characteristics and comparison with other experiment results for sandstones. The other peak is present at smaller frequencies and shifts to higher frequencies as the confining pressure increases, showing an opposite pressure dependence. This contrast is interpreted as the result of fluid flow patterns at different scales. We developed a dual-scale fluid flow model by incorporating the squirt flow effect into the patchy saturation model, which accounts for the interaction of WIFFs at microscopic and mesoscopic scales. This model provides a reasonable interpretation of the measurement results. Our broad-frequency-band measurements give physical evidence of WIFFs co-existing at two different scales, and combining with modelling results, it suggests that the WIFF mechanisms, related to pore microstructure and fluid distribution, interplay with each other and jointly control seismic attenuation and dispersion at reservoir conditions. These observations and modelling results are useful for quantitative seismic interpretation and reservoir characterization, specifically they have potential applications in time-lapse seismic analysis, fluid prediction and reservoir monitoring.

scholarly journals Near-surface real-time seismic imaging using parsimonious interferometry

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Sherif M. Hanafy ◽  
Hussein Hoteit ◽  
Jing Li ◽  
Gerard T. Schuster
Keyword(s):  
Fluid Flow ◽  
Real Time ◽  
Temporal Resolution ◽  
Seismic Imaging ◽  
Time Lapse ◽  
Rock Properties ◽  
Recording Time ◽  
Near Surface ◽  
Arrival Times ◽  
Order Of Magnitude

AbstractResults are presented for real-time seismic imaging of subsurface fluid flow by parsimonious refraction and surface-wave interferometry. Each subsurface velocity image inverted from time-lapse seismic data only requires several minutes of recording time, which is less than the time-scale of the fluid-induced changes in the rock properties. In this sense this is real-time imaging. The images are P-velocity tomograms inverted from the first-arrival times and the S-velocity tomograms inverted from dispersion curves. Compared to conventional seismic imaging, parsimonious interferometry reduces the recording time and increases the temporal resolution of time-lapse seismic images by more than an order-of-magnitude. In our seismic experiment, we recorded 90 sparse data sets over 4.5 h while injecting 12-tons of water into a sand dune. Results show that the percolation of water is mostly along layered boundaries down to a depth of a few meters, which is consistent with our 3D computational fluid flow simulations and laboratory experiments. The significance of parsimonious interferometry is that it provides more than an order-of-magnitude increase of temporal resolution in time-lapse seismic imaging. We believe that real-time seismic imaging will have important applications for non-destructive characterization in environmental, biomedical, and subsurface imaging.

Acquire Ocean Bottom Seismic Data and Time-Lapse Geochemistry Data Simultaneously to Identify Compartmentalization and Map Hydrocarbon Movement

2021 ◽  
Author(s):  
Rick Schrynemeeckers
Keyword(s):  
High Resolution ◽  
Seismic Data ◽  
Time Lapse ◽  
Field Trials ◽  
Detection Methods ◽  
Ocean Bottom ◽  
Field Development ◽  
Dense Grid ◽  
Hydrocarbon Charge ◽  
Sweet Spots

Abstract Current offshore hydrocarbon detection methods employ vessels to collect cores along transects over structures defined by seismic imaging which are then analyzed by standard geochemical methods. Due to the cost of core collection, the sample density over these structures is often insufficient to map hydrocarbon accumulation boundaries. Traditional offshore geochemical methods cannot define reservoir sweet spots (i.e. areas of enhanced porosity, pressure, or net pay thickness) or measure light oil or gas condensate in the C7 – C15 carbon range. Thus, conventional geochemical methods are limited in their ability to help optimize offshore field development production. The capability to attach ultrasensitive geochemical modules to Ocean Bottom Seismic (OBS) nodes provides a new capability to the industry which allows these modules to be deployed in very dense grid patterns that provide extensive coverage both on structure and off structure. Thus, both high resolution seismic data and high-resolution hydrocarbon data can be captured simultaneously. Field trials were performed in offshore Ghana. The trial was not intended to duplicate normal field operations, but rather provide a pilot study to assess the viability of passive hydrocarbon modules to function properly in real world conditions in deep waters at elevated pressures. Water depth for the pilot survey ranged from 1500 – 1700 meters. Positive thermogenic signatures were detected in the Gabon samples. A baseline (i.e. non-thermogenic) signature was also detected. The results indicated the positive signatures were thermogenic and could easily be differentiated from baseline or non-thermogenic signatures. The ability to deploy geochemical modules with OBS nodes for reoccurring surveys in repetitive locations provides the ability to map the movement of hydrocarbons over time as well as discern depletion affects (i.e. time lapse geochemistry). The combined technologies will also be able to: Identify compartmentalization, maximize production and profitability by mapping reservoir sweet spots (i.e. areas of higher porosity, pressure, & hydrocarbon richness), rank prospects, reduce risk by identifying poor prospectivity areas, accurately map hydrocarbon charge in pre-salt sequences, augment seismic data in highly thrusted and faulted areas.

Gannet F field – Unexpected fluid flow between reservoirs identified from time-lapse seismic data

First Break ◽  
2014 ◽  
Vol 32 (2017) ◽  
Author(s):  
Gwilym Lynn ◽  
A. Christian Ellis ◽  
Jonathan Brain ◽  
Richard Parker ◽  
Gerd-jan Lörtzer ◽  
...  
Keyword(s):  
Fluid Flow ◽  
Seismic Data ◽  
Time Lapse

scholarly journals Post-Depositional Fluid Flow in Jurassic Sandstones of the Uncompahgre Uplift: Insights From Magnetic Fabrics

2020 ◽  
Vol 8 ◽  
Author(s):  
John I. Ejembi ◽  
Eric C. Ferré ◽  
Sara Satolli ◽  
Sarah A. Friedman
Keyword(s):  
Fluid Flow ◽  
Remanent Magnetization ◽  
Magnetic Hysteresis ◽  
Natural Remanent Magnetization ◽  
Upper Jurassic ◽  
Hydrocarbon Exploration ◽  
Reservoir Rock ◽  
Magnetic Fabrics ◽  
Deformation Processes ◽  
Carbonate Formations

The anisotropy of magnetic susceptibility (AMS) in sedimentary rocks results from depositional, diagenetic, syn- and post-sedimentary processes that affect magnetic grains. Some studies have also shown the potential role played by post-depositional fluid flow in detrital and carbonate formations. Here we present a new case study of Middle-Upper Jurassic sandstones where secondary iron oxides, precipitated from fluids that migrated through pores, give rise to the AMS. These sandstones are well exposed in the Uncompahgre Uplift region of the Central Colorado Trough, Colorado. The magnetic foliation of these undeformed, subhorizontal strata consistently strike NE-SW over a large distance with an average 45° dip to the SE. This steep AMS fabric is oblique with respect to the regional subhorizontal bedding and therefore does not reflect the primary sedimentary fabric. Also, outcrop-scale and microscopic observations show a lack of post-depositional plastic (undulose extinction) or pressure-solution (stylolites) deformation microstructures in these sandstones, hence precluding a tectonic origin. The combination of magnetic hysteresis, isothermal remanent magnetization, and thermal demagnetization of the natural remanent magnetization indicate that these rocks carry a chemical remanent magnetization born primarily by hematite and goethite. High-field magnetic hysteresis and electron microscopy indicate that detrital magnetite and authigenic hematite are the main contributors to the AMS. These results show that post-depositional iron remobilization through these porous sandstones took place due to the action of percolating fluids which may have started as early as Late Cretaceous along with the Uncompahgre Uplift. The AMS fabric of porous sandstones does not systematically represent depositional or deformation processes, and caution is urged in the interpretation of magnetic fabrics in these types of reservoir rock. Conversely, understanding these fabrics may advance our knowledge of fluid flow in porous sandstones and may have applications in hydrocarbon exploration.

scholarly journals Multitransient electromagnetic demonstration survey in France

Geophysics ◽  
2007 ◽  
Vol 72 (4) ◽  
pp. F197-F209 ◽  
Author(s):  
Anton Ziolkowski ◽  
Bruce A. Hobbs ◽  
David Wright
Keyword(s):  
Current Source ◽  
Hydrocarbon Exploration ◽  
Input Current ◽  
Impulse Responses ◽  
Full Waveform ◽  
Transverse Resistance ◽  
Survey Line ◽  
Exploration And Production ◽  
Hydrocarbon Exploration And Production ◽  
Step Responses

We describe the acquisition, processing, and inversion of a multitransient electromagnetic (MTEM) single-line survey, conducted in December 2004 over an underground gas storage reservoir in southwestern France. The objective was to find a resistor corresponding to known gas about [Formula: see text] below the survey line. In data acquisition, we deployed a [Formula: see text] inline bipole current source and twenty [Formula: see text] inline potential receivers in various configurations along the [Formula: see text] survey line; we measured the input current step and received voltages simultaneously. Then we deconvolved the received voltages for the measured input current to determine the earth impulse responses. We show how both amplitude and traveltime information contained in the recovered earth impulse responses reveal the lateral location and approximate depth of the resistive reservoir. Integrating the impulse responses yields step responses, from which the asymptotic DC values were estimated and used in rapid 2D dipole-dipole DC resistivity inversion to find the top of the reservoir. A series of collated 1D full-waveform inversions performed on individual common midpoint gathers of the step responses position the top and bottom of a resistor corresponding to known gas in the reservoir and also obtain the transverse resistance. The results imply that the MTEM method can be used as a tool for hydrocarbon exploration and production.

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