Full Wave and Down-Going Elastic Inversion of Deepwater OBN Seismic Data: Example from Niger Delta

We evaluate the performance of traveltime tomography and full-wave inversion (FWI) for near-surface modeling using the data from a shallow seismic field experiment. Eight boreholes up to 20-m depth have been drilled along the seismic line traverse to verify the accuracy of the P-wave velocity-depth model estimated by seismic inversion. The velocity-depth model of the soil column estimated by traveltime tomography is in good agreement with the borehole data. We used the traveltime tomography model as an initial model and performed FWI. Full-wave acoustic and elastic inversions, however, have failed to converge to a velocity-depth model that desirably should be a high-resolution version of the model estimated by traveltime tomography. Moreover, there are significant discrepancies between the estimated models and the borehole data. It is understandable why full-wave acoustic inversion would fail — land seismic data inherently are elastic wavefields. The question is: Why does full-wave elastic inversion also fail? The strategy to prevent full-wave elastic inversion of vertical-component geophone data trapped in a local minimum that results in a physically implausible near-surface model may be cascaded inversion. Specifically, we perform traveltime tomography to estimate a P-wave velocity-depth model for the near-surface and Rayleigh-wave inversion to estimate an S-wave velocity-depth model for the near-surface, then use the resulting pairs of models as the initial models for the subsequent full-wave elastic inversion. Nonetheless, as demonstrated by the field data example here, the elastic-wave inversion yields a near-surface solution that still is not in agreement with the borehole data. Here, we investigate the limitations of FWI applied to land seismic data for near-surface modeling.

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Full‐wave anisotropic elastic inversion of synthetic crosswell seismic data

10.1190/1.1851166 ◽

2004 ◽

Cited By ~ 1

Author(s):

Christophe Barnes ◽

Marwan Charara ◽

Terry Tsuchiya

Keyword(s):

Seismic Data ◽

Full Wave ◽

Anisotropic Elastic ◽

Elastic Inversion

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Multiples in Onshore Niger Delta from 3D prestack seismic data

International Journal of the Physical Sciences ◽

10.5897/ijps2016.4558 ◽

2017 ◽

Vol 12 (1) ◽

pp. 1-7

Author(s):

B. Azuoko G. ◽

N. Ehirim C. ◽

O. Ebeniro J. ◽

N. Uraechu D.

Keyword(s):

Seismic Data ◽

Niger Delta

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Pore pressure prediction using seismic data: Insight from Onshore Niger Delta, Nigeria

Journal of Geology and Mining Research ◽

10.5897/jgmr2015.0226 ◽

2015 ◽

Vol 7 (8) ◽

pp. 74-80

Author(s):

G Z Ugwu

Keyword(s):

Pore Pressure ◽

Seismic Data ◽

Niger Delta ◽

Pore Pressure Prediction

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

Nigerian Journal of Environmental Sciences and Technology - March 2018 ◽

10.36263/nijest.2017.01.0010 ◽

2017 ◽

Vol 1 (1) ◽

pp. 23-27 ◽

Cited By ~ 1

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.

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Facies Analysis and Depositoinal Environment of D-3 Reservoir Sands Vin Field, Eastern Niger Delta

Journal of Geography Environment and Earth Science International ◽

10.9734/jgeesi/2019/v19i230080 ◽

2019 ◽

pp. 1-19

Author(s):

Onyewuchi, Chinedu Vin ◽

Minapuye, I. Odigi

Keyword(s):

Seismic Data ◽

Niger Delta ◽

Depositional Environment ◽

Gamma Ray ◽

Facies Analysis ◽

Depositional Environments ◽

Width Ratio ◽

Neutron Density ◽

Wireline Logs ◽

Isopach Map

Facies analysis and depositional environment identification of the Vin field was evaluated through the integration and comparison of results from wireline logs, core analysis, seismic data, ditch cutting samples and petrophysical parameters. Well log suites from 22 wells comprising gamma ray, resistivity, neutron, density, seismic data, and ditch cutting samples were obtained and analyzed. Prediction of depositional environment was made through the usage of wireline log shapes of facies combined with result from cores and ditch cuttings sample description. The aims of this study were to identify the facies and depositional environments of the D-3 reservoir sand in the Vin field. Two sets of correlations were made on the E-W trend to validate the reservoir top and base while the isopach map was used to establish the reservoir continuity. Facies analysis was carried out to identify the various depositional environments. The result showed that the reservoir is an elongate , four way dip closed roll over anticline associated with an E-W trending growth fault and contains two structural high separated by a saddle. The offshore bar unit is an elongate sand body with length: width ratio of >3:1 and is aligned parallel to the coast-line. Analysis of the gamma ray logs indicated that four log facies were recognized in all the wells used for the study. These include: Funnel-shaped (coarsening upward sequences), bell-shaped or fining upward sequences, the bow shape and irregular shape. Based on these categories of facies, the depositional environments were interpreted as deltaic distributaries, regressive barrier bars, reworked offshore bars and shallow marine. Analysis of the wireline logs and their core/ditch cuttings description has led to the conclusion that the reservoir sandstones of the Agbada Formation in the Vin field of the eastern Niger Delta is predominantly marine deltaic sequence, strongly influenced by clastic output from the Niger Delta. Deposition occurred in a variety of littoral and neritic environment ranging from barrier sand complex to fully marine outer shelf mudstones.

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Characterization of reservoir sands using 3D seismic attributes in the coastal swamp area of Niger Delta Basin

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-021-01286-z ◽

2021 ◽

Author(s):

Oluwatoyin Khadijat Olaleye ◽

Pius Adekunle Enikanselu ◽

Michael Ayuk Ayuk

Keyword(s):

Seismic Data ◽

Niger Delta ◽

Seismic Attributes ◽

Effective Porosity ◽

High Porosity ◽

Hydrocarbon Accumulation ◽

3D Seismic ◽

Seismic Attribute ◽

Niger Delta Basin

AbstractHydrocarbon accumulation and production within the Niger Delta Basin are controlled by varieties of geologic features guided by the depositional environment and tectonic history across the basin. In this study, multiple seismic attribute transforms were applied to three-dimensional (3D) seismic data obtained from “Reigh” Field, Onshore Niger Delta to delineate and characterize geologic features capable of harboring hydrocarbon and identifying hydrocarbon productivity areas within the field. Two (2) sand units were delineated from borehole log data and their corresponding horizons were mapped on seismic data, using appropriate check-shot data of the boreholes. Petrophysical summary of the sand units revealed that the area is characterized by high sand/shale ratio, effective porosity ranged from 16 to 36% and hydrocarbon saturation between 72 and 92%. By extracting attribute maps of coherence, instantaneous frequency, instantaneous amplitude and RMS amplitude, characterization of the sand units in terms of reservoir geomorphological features, facies distribution and hydrocarbon potential was achieved. Seismic attribute results revealed (1) characteristic patterns of varying frequency and amplitude areas, (2) major control of hydrocarbon accumulation being structural, in terms of fault, (3) prospective stratigraphic pinch-out, lenticular thick hydrocarbon sand, mounded sand deposit and barrier bar deposit. Seismic Attributes analysis together with seismic structural interpretation revealed prospective structurally high zones with high sand percentage, moderate thickness and high porosity anomaly at the center of the field. The integration of different seismic attribute transforms and results from the study has improved our understanding of mapped sand units and enhanced the delineation of drillable locations which are not recognized on conventional seismic interpretations.

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