Discrimination between pressure and fluid saturation changes from time‐lapse seismic data

Geophysics ◽  
2001 ◽  
Vol 66 (3) ◽  
pp. 836-844 ◽  
Author(s):  
Martin Landrø
Keyword(s):  
Seismic Data ◽  
Time Lapse ◽  
Seismic Survey ◽  
Baseline Survey ◽  
Water Contact ◽  
Data Set ◽  
Seismic Surveys ◽  
Fluid Saturation ◽  
Oil Water ◽  
Pressure Changes

Explicit expressions for computing saturation‐ and pressure‐related changes from time‐lapse seismic data have been derived and tested on a real time‐lapse seismic data set. Necessary input is near‐and far‐offset stacks for the baseline seismic survey and the repeat survey. The method has been tested successfully in a segment where pressure measurements in two wells verify a pore‐pressure increase of 5 to 6 MPa between the baseline survey and the monitor survey. Estimated pressure changes using the proposed relationships fit very well with observations. Between the baseline and monitor seismic surveys, 27% of the estimated recoverable hydrocarbon reserves were produced from this segment. The estimated saturation changes also agree well with observed changes, apart from some areas in the water zone that are mapped as being exposed to saturation changes (which is unlikely). Saturation changes in other segments close to the original oil‐water contact and the top reservoir interface are also estimated and confirmed by observations in various wells.

Discrimination between pressure and fluid saturation changes from marine multicomponent time‐lapse seismic data

Geophysics ◽  
2003 ◽  
Vol 68 (5) ◽  
pp. 1592-1599 ◽  
Author(s):  
Martin Landrø ◽  
Helene Hafslund Veire ◽  
Kenneth Duffaut ◽  
Nazih Najjar
Keyword(s):  
Pore Pressure ◽  
Seismic Data ◽  
Water Saturation ◽  
Synthetic Data ◽  
Time Lapse ◽  
Seismic Survey ◽  
Data Sets ◽  
Amplitude Variation With Offset ◽  
Fluid Saturation ◽  
Pressure Changes

Explicit expressions for computation of saturation and pressure‐related changes from marine multicomponent time‐lapse seismic data are presented. Necessary input is PP and PS stacked data for the baseline seismic survey and the repeat survey. Compared to earlier methods based on PP data only, this method is expected to be more robust since two independent measurements are used in the computation. Due to a lack of real marine multicomponent time‐lapse seismic data sets, the methodology is tested on synthetic data sets, illustrating strengths and weaknesses of the proposed technique. Testing ten scenarios for various changes in pore pressure and fluid saturation, we find that it is more robust for most cases to use the proposed 4D PP/PS technique instead of a 4D PP amplitude variation with offset (AVO) technique. The fit between estimated and “real” changes in water saturation and pore pressure were good for most cases. On the average, we find that the deviation in estimated saturation changes is 8% and 0.3 MPa for the estimated pore pressure changes. For PP AVO, we find that the corresponding average errors are 9% and 1.0 MPa. In the present method, only 4D PP and PS amplitude changes are used in the calculations. It is straightforward to include use of 4D traveltime shifts in the algorithm and, if reliable time shifts can be measured, this will most likely further stabilize the presented method.

Rock physics modelling and analysis of time-lapse seismic response in the Pyrenees Field, offshore Western Australia

2015 ◽  
Vol 55 (2) ◽  
pp. 470
Author(s):  
Stanislav Kuzmin ◽  
Mauricio Florez ◽  
Guy Duncan ◽  
Konstantinos Kostas
Keyword(s):  
Seismic Response ◽  
Coming Out ◽  
Significant Risk ◽  
Rock Physics ◽  
Time Lapse ◽  
Seismic Survey ◽  
Water Contact ◽  
Fluid Saturation ◽  
Oil Water ◽  
4D Seismic

Rock physics modelling of the time-lapse seismic response of the Pyrenees Field was carried out to evaluate the feasibility of monitoring reservoir drainage and performance. Initially, the purpose of 4D seismic was to monitor the upward displacement of the oil-water contact. It was recognised that the likelihood of gas breakout imposed a significant risk to the feasibility of monitoring the oil-water contact. Models for different scenarios were used to assess this uncertainty and demonstrated that, in either case, an observable change in seismic properties would occur, providing technical support for 4D seismic acquisition. The monitor seismic survey acquired in 2013, showed detectable changes in both interval velocity and reflectivity that was associated with gas coming out of solution in the reservoir, where depletion occurred below the bubble point. This agrees with pre-acquisition predictions based on rock physics modelling. Additional rock physics analysis was carried out to calibrate the observed 4D response to changes in both fluid saturation and effective stress.

Stochastic inversion of pressure and saturation changes from time-lapse AVO data

Geophysics ◽  
2006 ◽  
Vol 71 (5) ◽  
pp. C81-C92 ◽  
Author(s):  
Helene Hafslund Veire ◽  
Hilde Grude Borgos ◽  
Martin Landrø
Keyword(s):  
Stochastic Model ◽  
Seismic Data ◽  
Synthetic Data ◽  
Time Lapse ◽  
Bayesian Framework ◽  
Reservoir Modeling ◽  
Data Set ◽  
The North ◽  
Fluid Saturation ◽  
Likelihood Model

Effects of pressure and fluid saturation can have the same degree of impact on seismic amplitudes and differential traveltimes in the reservoir interval; thus, they are often inseparable by analysis of a single stacked seismic data set. In such cases, time-lapse AVO analysis offers an opportunity to discriminate between the two effects. We quantify the uncertainty in estimations to utilize information about pressure- and saturation-related changes in reservoir modeling and simulation. One way of analyzing uncertainties is to formulate the problem in a Bayesian framework. Here, the solution of the problem will be represented by a probability density function (PDF), providing estimations of uncertainties as well as direct estimations of the properties. A stochastic model for estimation of pressure and saturation changes from time-lapse seismic AVO data is investigated within a Bayesian framework. Well-known rock physical relationships are used to set up a prior stochastic model. PP reflection coefficient differences are used to establish a likelihood model for linking reservoir variables and time-lapse seismic data. The methodology incorporates correlation between different variables of the model as well as spatial dependencies for each of the variables. In addition, information about possible bottlenecks causing large uncertainties in the estimations can be identified through sensitivity analysis of the system. The method has been tested on 1D synthetic data and on field time-lapse seismic AVO data from the Gullfaks Field in the North Sea.

scholarly journals Time-Lapse Seismic Monitoring of Onshore Reservoirs in Niger Delta, Field ‘K’ as a Case Study

2017 ◽  
Vol 1 (1) ◽  
pp. 23-27 ◽  
Author(s):  
A. Ogbamikhumi ◽  
T. Tralagba ◽  
E. E. Osagiede
Keyword(s):  
Seismic Data ◽  
Acoustic Impedance ◽  
Niger Delta ◽  
Rock Physics ◽  
Time Lapse ◽  
Seismic Survey ◽  
Impedance Change ◽  
Data Set ◽  
Reservoir Fluid ◽  
4D Seismic

Field ‘K’ is a mature field in the coastal swamp onshore Niger delta, which has been producing since 1960. As a huge producing field with some potential for further sustainable production, field monitoring is therefore important in the identification of areas of unproduced hydrocarbon. This can be achieved by comparing production data with the corresponding changes in acoustic impedance observed in the maps generated from base survey (initial 3D seismic) and monitor seismic survey (4D seismic) across the field. This will enable the 4D seismic data set to be used for mapping reservoir details such as advancing water front and un-swept zones. The availability of good quality onshore time-lapse seismic data for Field ‘K’ acquired in 1987 and 2002 provided the opportunity to evaluate the effect of changes in reservoir fluid saturations on time-lapse amplitudes. Rock physics modelling and fluid substitution studies on well logs were carried out, and acoustic impedance change in the reservoir was estimated to be in the range of 0.25% to about 8%. Changes in reservoir fluid saturations were confirmed with time-lapse amplitudes within the crest area of the reservoir structure where reservoir porosity is 0.25%. In this paper, we demonstrated the use of repeat Seismic to delineate swept zones and areas hit with water override in a producing onshore reservoir.

Time‐lapse imaging at Bullwinkle field, Green Canyon 65, offshore Gulf of Mexico

Geophysics ◽  
2003 ◽  
Vol 68 (5) ◽  
pp. 1470-1484 ◽  
Author(s):  
Alastair M. Swanston ◽  
Peter B. Flemings ◽  
Joseph T. Comisky ◽  
Kevin D. Best
Keyword(s):  
Gulf Of Mexico ◽  
Time Lapse ◽  
Seismic Survey ◽  
Data Sets ◽  
Water Contact ◽  
Seismic Surveys ◽  
Fluid Properties ◽  
Induced Changes ◽  
Time Lapse Imaging ◽  
Difference Images

Two orthogonal preproduction seismic surveys and a regional seismic survey acquired after eight years of production from the Bullwinkle field (Green Canyon 65, Gulf of Mexico) reveal extraordinary seismic differences attributed to production‐induced changes in rock and fluid properties. Amplitude reduction (of up to 71%) occurs where production and log data show that water has replaced hydrocarbons as the oil–water contact moved upward. Separate normalizations of these surveys demonstrate that time‐lapse results are improved by using seismic surveys acquired in similar orientations; also, clearer difference images are obtained from comparing lower‐frequency data sets. Superior stratigraphic illumination in the dip‐oriented survey relative to the strike‐oriented surveys results in nongeological amplitude differences. This documents the danger of using dissimilar baseline and monitor surveys for time‐lapse studies.

THE YAMMADERRY, COWLE AND ROLLER DISCOVERIES IN THE BARROW SUB-BASIN, WESTERN AUSTRALIA

1991 ◽  
Vol 31 (1) ◽  
pp. 32
Author(s):  
M.K. McLerie ◽  
A.M. Tait ◽  
M.J. Sayers
Keyword(s):  
Early Cretaceous ◽  
Western Australia ◽  
Oil Fields ◽  
Seismic Survey ◽  
Seismic Profiles ◽  
Water Contact ◽  
Vertical Seismic Profiles ◽  
Fluid Saturation ◽  
Oil Water ◽  
Thickness Variable

The TP/3 Part I permit in the Barrow Sub-basin has been held by WAPET since 1952. Improvements in seismic quality and oilfield economics in the early 1980s resulted in the 1985 Saladin oil discovery, which subsequently led to the Yammaderry, Cowle and Roller discoveries.Yammaderry-1, drilled in 1988, encountered 16.5 m of gas capping a nine metre oil column. In 1989, Cowle-1 penetrated a 14 m oil column and tested at 1016 m3 (6390 BBL) of oil per day. Roller-1, drilled in 1990, encountered six metres of gas capping nine metres of oil and tested at 866 m3 (5450 BBL) of oil per day. Roller-2, deviated downdip to find the oil/water contact, proved an 18 m oil column, confirmed later by Roller-4.Early Cretaceous Barrow Group deltaic sandstones are the reservoirs for the Saladin, Yammaderry, Cowle and Roller oil fields. The Barrow Group is overlain by the Mar- die Greensand, the basal unit of the Muderong Shale which forms the regional seal. The transitional acoustic character of the Mardie Greensand and its thickness, variable fluid saturation and lithology, cause problems in picking a top Barrow Group event. Vertical Seismic Profiles acquired in the Yammaderry, Cowle and Roller wells have helped tie the wells to the seismic data.With Saladin on stream, and Yammaderry and Cowle under development, a major seismic survey was completed in late 1990 to delineate Roller and to detail prospects for future drilling in the revitalised TP / 3 Part 1 permit.

Streamline-based integration of time-lapse seismic and production data into petroleum reservoir models

Geophysics ◽  
2012 ◽  
Vol 77 (6) ◽  
pp. M73-M87 ◽  
Author(s):  
Alvaro Rey ◽  
Eric Bhark ◽  
Kai Gao ◽  
Akhil Datta-Gupta ◽  
Richard Gibson
Keyword(s):  
High Resolution ◽  
Finite Difference ◽  
Seismic Data ◽  
Time Lapse ◽  
Seismic Inversion ◽  
Absolute Permeability ◽  
Production Data ◽  
Petroleum Reservoir ◽  
Seismic Surveys ◽  
Fluid Saturation

We have developed an efficient approach of petroleum reservoir model calibration that integrates 4D seismic surveys together with well-production data. The approach is particularly well-suited for the calibration of high-resolution reservoir properties (permeability) because the field-scale seismic data are areally dense, whereas the production data are effectively averaged over interwell spacing. The joint calibration procedure is performed using streamline-based sensitivities derived from finite-difference flow simulation. The inverted seismic data (i.e., changes in elastic impedance or fluid saturations) are distributed as a 3D high-resolution grid cell property. The sensitivities of the seismic and production surveillance data to perturbations in absolute permeability at individual grid cells are efficiently computed via semianalytical streamline techniques. We generalize previous formulations of streamline-based seismic inversion to incorporate realistic field situations such as changing boundary conditions due to infill drilling, pattern conversion, etc. A commercial finite-difference flow simulator is used for reservoir simulation and to generate the time-dependent velocity fields through which streamlines are traced and the sensitivity coefficients are computed. The commercial simulator allows us to incorporate detailed physical processes including compressibility and nonconvective forces, e.g., capillary pressure effects, while the streamline trajectories provide a rapid evaluation of the sensitivities. The efficacy of our proposed approach was tested with synthetic and field applications. The synthetic example was the Society of Petroleum Engineers benchmark Brugge field case. The field example involves waterflooding of a North Sea reservoir with multiple seismic surveys. In both cases, the advantages of incorporating the time-lapse variations were clearly demonstrated through improved estimation of the permeability heterogeneity, fluid saturation evolution, and swept and drained volumes. The value of the seismic data integration was in particular proven through the identification of the continuity in reservoir sands and barriers, and by the preservation of geologic realism in the calibrated model.

Seismic surveys at an artificially created field-test cavern within a salt pillar

2020 ◽  
Author(s):  
Heike Richter ◽  
Rüdiger Giese ◽  
Axel Zirkler ◽  
Bettina Strauch
Keyword(s):  
Field Test ◽  
Seismic Data ◽  
Field Experiments ◽  
Experimental Simulation ◽  
Seismic Survey ◽  
Baseline Survey ◽  
Multiphase System ◽  
Rock Interaction ◽  
Seismic Surveys ◽  
Salt Rocks

<p>Salt rocks serve as host rock for technical caverns due to their impermeability but their can also be influenced by fluid migration due to geological fracture zones. Seismic methods can be used to monitor cavernous structures in the transition zone between cavity and undisturbed salt rocks. Around an artificially created cavity (field-test cavern) in a salt pillar with a volume of approximately 100 litre, travel time tomography was utilized to image structures related to caverns and fluid-storage. Seismic surveys were performed at different stages of an experimental simulation of gas-water-rock interaction in the field-test cavern aiming for a better understanding of the multiphase system in the cavern-near area. The baseline survey (1) was carried out using 8 three-component piezo-electrical sensor rods and a seismic vibrator source at the surface of the salt pillar, first without an installed field-test cavern. After drilling and installing the field-test cavern, seismic cross-hole measurements were performed after producing partial vacuum in the test cavern (2) and infill of gas (3) and water (4). To finalize the field experiments the last seismic survey (5) was again conducted at the surface of the salt pillar as a repeat measurement to the baseline survey. The seismic monitoring of the salt pillar was carried out in a frequency range of 100 Hz to 14000 Hz allowing a spatial resolution in the cm-range. This was followed by pre-processing of the seismic data sets to apply the picked travel times in a tomography program. On the basis of the tomography results and reflection seismic data we want to assess the potential enlargement of the field-test cavern due to water-infill and to image the differences between unaffected salt rocks, cavernous structures and developing transition zones.</p>

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

Geophysics ◽  
2017 ◽  
Vol 82 (1) ◽  
pp. IM1-IM12 ◽  
Author(s):  
Meng Li ◽  
Zhen Liu ◽  
Minzhu Liu ◽  
Huilai Zhang
Keyword(s):  
Seismic Data ◽  
Time Lapse ◽  
Seismic Interpretation ◽  
Impedance Change ◽  
Residual Oil ◽  
Data Set ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Amplitude Difference ◽  
Fluid Saturation

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.

Modeling velocity changes associated with a miscible flood in the Prudhoe Bay Field

Geophysics ◽  
1997 ◽  
Vol 62 (5) ◽  
pp. 1442-1455
Author(s):  
Robert J. Withers ◽  
Michael L. Batzle
Keyword(s):  
Seismic Data ◽  
Baseline Survey ◽  
Time Varying ◽  
Seismic Surveys ◽  
Recovery Processes ◽  
Fluid Saturation ◽  
Fluid Velocities ◽  
Gassmann’S Equation ◽  
Velocity Changes ◽  
Prudhoe Bay

The Prudhoe Bay Field, Alaska, is produced by a number of recovery processes. A miscible gas (MI) injection pilot was studied to see if repeated seismic surveys could detect the progress of the MI gas. Gassmann's equation was used on the injection, producing and monitor wells where a detailed reservoir simulation was available. Time‐varying saturations of the three fluid phases and the pressure were used to calculate the expected velocity of the reservoir at different stages of the injection. The differences between the modeled velocities at two extremes of gas saturation after the water‐after‐gas (WAG) range up to 500 ft/s (150 m/s). It was concluded that it have been possible to detect the fluid saturation had a baseline survey been collected early in the field's development. Unfortunately, initial production introduced 2% gas into the fluid, muting later attempts to map changes in saturation that varied from between 30% and 60%. Additionally, the use of a WAG process further complicated the gas mapping by both increasing and decreasing the reservoir fluid velocities. Collecting new seismic data over this pilot was not recommended. The modeling exercise highlighted a number of issues that are important in monitoring other reservoirs. Amongst these are the timing of data collection and the weakness of the petrophysical models caused by the numerous assumptions that are required in the absence of field observations. It was demostrated that modeling exercises can both save unnecessary field expenses and provide considerable insight in reservoir behavior.

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