Prestack simultaneous inversion for delineation of the Lower Wilcox erosional remnant sandstone beneath the Texas Gulf Coastal Plain: A case study

2020 ◽  
Vol 8 (4) ◽  
pp. T991-T1005
Author(s):  
Tianze Zhang ◽  
Yani Lin ◽  
Kelly H. Liu ◽  
Stephen S. Gao
Keyword(s):  
Coastal Plain ◽  
Rock Physics ◽  
Velocity Estimation ◽  
Estimation Methods ◽  
Gulf Coastal Plain ◽  
Elastic Parameters ◽  
Simultaneous Inversion ◽  
Sequence Boundaries ◽  
Lower Wilcox ◽  
Gas Bearing

The Lower Wilcox lowstand sand deposits encased between two sequence boundaries along the Texas Gulf Coastal Plain are of good reservoir quality and usually gas productive. However, the sedimentation is sparsely scattered within such a depositional environment and it is hard to predict by qualitative interpretation methods. Simultaneous inversion of elastic parameters such as P-impedance, S-impedance, and density by the integration of prestack data and well logs allows us to quantitatively characterize the reservoirs and to distinguish them from the surrounding rocks. We have used prestack simultaneous inversion of the elastic parameters for delineation of the gas reservoir in an active field with limited log availabilities. For wells that are missing sonic and density logs, we estimate the parameters using the time-average equation (TAE) and Gardner’s equation, respectively. The shear wave velocity estimation methods are tested and compared using the measured log value. The estimation results are verified using well-log correlations in adjacent wells. Rock-physics analyses on wells are conducted to find the optimal elastic parameters for characterizing the gas-bearing sand. We successfully delineate the reservoir using the crossplot of VP/ VS versus S-impedance values. The inversion results are quality controlled by a producing well in the reservoir zone, and probability maps of each lithology are calculated by the probability density function. Our results from the Lower Wilcox Formation indicate that simultaneous inversion based on the estimated parameters using TAE is feasible, and the gas-bearing reservoirs can be recommended with high confidence.

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

Geophysics ◽  
2018 ◽  
Vol 83 (4) ◽  
pp. M41-M48 ◽  
Author(s):  
Hongwei Liu ◽  
Mustafa Naser Al-Ali
Keyword(s):  
Seismic Data ◽  
Rock Physics ◽  
Time Lapse ◽  
Velocity Estimation ◽  
Estimation Methods ◽  
Data Sets ◽  
Data Set ◽  
Velocity Models ◽  
Reservoir Monitoring ◽  
Focus Point

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.

Analysis of the Hidrocarbon Sandstone Distribution Using Rock Physics and Petrophysic Calculations, Simultaneous Inversion, Extended Elastic Impedance (EEI) and Curved Pseudo-Elastic Impedance (CPEI) in X Field Bonaparte Basin

2020 ◽  
Author(s):  
A., H. Kusuma
Keyword(s):  
Gamma Ray ◽  
Water Saturation ◽  
Rock Physics ◽  
Fluid Distribution ◽  
Elastic Parameters ◽  
Angular Rotation ◽  
Simultaneous Inversion ◽  
A Value ◽  
Seismic Volumes ◽  
Elastic Impedance

To analyze the distribution of hydrocarbon reservoirs in an area, appropriate methods and parameters can be used to map sediments in the area. In this study, the research was conducted on the X Field located in the Bonaparte Basin. The EEI and CPEI methods are used. The Extended Elastic Impedance (EEI) method is a method that can be used to connect seismic data with elastic parameters by applying the principle of angular rotation. From this method, seismic volumes of various elastic parameters and reservoir parameters will be obtained. The Curved Pseudo-elastic Impedance (CPEI which is able to answer the problem in describing the distribution of fluid in the study area) is also carried out. Gamma Ray (GR) is used to detect lithology and fluid distribution, while from the results of CPEI inversion, the water saturation volume is obtained to see the hydrocarbon distribution in the study area. The results show that the two inversions are able to differentiate the distribution of tight sand lithology, shale, wet sand, gas sand and porous sand. The presence of gas sand distribution can be identified by the value of GR = 20-40 API, λρ = 0-50 GPA*gr/cc, μρ > 80 GPA*g/cc, σ = 0.05-0.24 unitless and the value of Sw = 0-40%, lithology tight sand has a value of GR = 40-70 API, λρ = 70-80 GPA*gr/cc, σ>0.4 unitless, shale lithology has a value of GR > 90 API , μρ <30 GPA*gr/cc, and wet sand is shown with the value GR = 20-40 API, λρ = 50-80 GPA*gr/cc, σ = 0.25-0.35 unitless and Sw> 70%. Based on the results of these interpretations, a sandstone distribution map in X Field was generated and it consists of 2 reservoir layers in the research target zone.

Bayesian lithology and fluid prediction from seismic prestack data

Geophysics ◽  
2008 ◽  
Vol 73 (3) ◽  
pp. C13-C21 ◽  
Author(s):  
Arild Buland ◽  
Odd Kolbjørnsen ◽  
Ragnar Hauge ◽  
Øyvind Skjæveland ◽  
Kenneth Duffaut
Keyword(s):  
Seismic Data ◽  
Rock Physics ◽  
Real Data ◽  
Feasibility Analysis ◽  
Bayesian Inversion ◽  
Inversion Method ◽  
Elastic Parameters ◽  
Data Set ◽  
Prior Probabilities ◽  
Simultaneous Inversion

A fast Bayesian inversion method for 3D lithology and fluid prediction from prestack seismic data, and a corresponding feasibility analysis were developed and tested on a real data set. The objective of the inversion is to find the probabilities for different lithology-fluid classes from seismic data and geologic knowledge. The method combines stochastic rock physics relations between the elastic parameters and the different lithology-fluid classes with the results from a fast Bayesian seismic simultaneous inversion from seismic data to elastic parameters. A method for feasibility analysis predicts the expected modification of the prior probabilities to posterior probabilities for the different lithology-fluid classes. The feasibility analysis can be carried out before the seismic data are analyzed. Both the feasibility method and the seismic lithology-fluid probability inversion were applied to a prospect offshore Norway. The analysis improves the probability for gas sand from 0.1 to about 0.2–0.4 with seismic data.

Sign in / Sign up

Export Citation Format

Share Document