Direct reservoir parameter estimation using joint inversion of marine seismic AVA and CSEM data

Geophysics ◽  
2006 ◽  
Vol 71 (3) ◽  
pp. C1-C13 ◽  
Author(s):  
G. Michael Hoversten ◽  
Florence Cassassuce ◽  
Erika Gasperikova ◽  
Gregory A. Newman ◽  
Jinsong Chen ◽  
...  
Keyword(s):  
Water Saturation ◽  
Joint Inversion ◽  
Hydrocarbon Exploration ◽  
Rock Properties ◽  
Parameter Estimates ◽  
Angle Of Incidence ◽  
Model Errors ◽  
Inversion Algorithm ◽  
Fluid Saturation ◽  
Reservoir Parameter

Accurately estimating reservoir parameters from geophysical data is vitally important in hydrocarbon exploration and production. We have developed a new joint-inversion algorithm to estimate reservoir parameters directly, using both seismic amplitude variation with angle of incidence (AVA) data and marine controlled-source electromagnetic (CSEM) data. Reservoir parameters are linked to geophysical parameters through a rock-properties model. Errors in the parameters of the rock-properties model introduce errors of comparable size in the reservoir-parameter estimates produced by joint inversion. Tests of joint inversion on synthetic 1D models demonstrate improved fluid saturation and porosity estimates for joint AVA-CSEM data inversion (compared with estimates from AVA or CSEM inversion alone). A comparison of inversions of AVA data, CSEM data, and joint AVA-CSEM data over the North Sea Troll field, at a location for which we have well control, shows that the joint inversion produces estimates of gas saturation, oil saturation, and porosity that are closest (as measured by the rms difference, the [Formula: see text] norm of the difference, and net values over the interval) to the logged values. However, CSEM-only inversion provides the closest estimates of water saturation.

scholarly journals Pressure and fluid saturation prediction in a multicomponent reservoir using combined seismic and electromagnetic imaging

Geophysics ◽  
2003 ◽  
Vol 68 (5) ◽  
pp. 1580-1591 ◽  
Author(s):  
G. Michael Hoversten ◽  
Roland Gritto ◽  
John Washbourne ◽  
Tom Daley
Keyword(s):  
Electrical Conductivity ◽  
Water Saturation ◽  
Saturation Pressure ◽  
Shear Velocity ◽  
Velocity Shear ◽  
Rock Properties ◽  
Velocity Change ◽  
Archie’S Law ◽  
Fluid Saturation ◽  
Compressional Velocity

This paper presents a method for combining seismic and electromagnetic (EM) measurements to predict changes in water saturation, pressure, and CO2 gas/oil ratio in a reservoir undergoing CO2 flood. Crosswell seismic and EM data sets taken before and during CO2 flooding of an oil reservoir are inverted to produce crosswell images of the change in compressional velocity, shear velocity, and electrical conductivity during a CO2 injection pilot study. A rock‐properties model is developed using measured log porosity, fluid saturations, pressure, temperature, bulk density, sonic velocity, and electrical conductivity. The parameters of the rock‐properties model are found by an L1‐norm simplex minimization of predicted and observed differences in compressional velocity and density. A separate minimization, using Archie's law, provides parameters for modeling the relations between water saturation, porosity, and electrical conductivity. The rock‐properties model is used to generate relationships between changes in geophysical parameters and changes in reservoir parameters. Electrical conductivity changes are directly mapped to changes in water saturation; estimated changes in water saturation are used along with the observed changes in shear‐wave velocity to predict changes in reservoir pressure. The estimation of the spatial extent and amount of CO2 relies on first removing the effects of the water saturation and pressure changes from the observed compressional velocity changes, producing a residual compressional velocity change. This velocity change is then interpreted in terms of increases in the CO2/oil ratio. Resulting images of the CO2/oil ratio show CO2‐rich zones that are well correlated to the location of injection perforations, with the size of these zones also correlating to the amount of injected CO2. The images produced by this process are better correlated to the location and amount of injected CO2 than are any of the individual images of change in geophysical parameters.

Reservoir-parameter identification using minimum relative entropy-based Bayesian inversion of seismic AVA and marine CSEM data

Geophysics ◽  
2006 ◽  
Vol 71 (6) ◽  
pp. O77-O88 ◽  
Author(s):  
Zhangshuan Hou ◽  
Yoram Rubin ◽  
G. Michael Hoversten ◽  
Don Vasco ◽  
Jinsong Chen
Keyword(s):  
Relative Entropy ◽  
Joint Inversion ◽  
Parameter Estimates ◽  
Data Sets ◽  
Data Set ◽  
Mean Values ◽  
Prior Probabilities ◽  
Reservoir Fluid ◽  
Minimum Relative Entropy ◽  
Reservoir Parameter

A stochastic joint-inversion approach for estimating reservoir-fluid saturations and porosity is proposed. The approach couples seismic amplitude variation with angle (AVA) and marine controlled-source electromagnetic (CSEM) forward models into a Bayesian framework, which allows for integration of complementary information. To obtain minimally subjective prior probabilities required for the Bayesian approach, the principle of minimum relative entropy (MRE) is employed. Instead of single-value estimates provided by deterministic methods, the approach gives a probability distribution for any unknown parameter of interest, such as reservoir-fluid saturations or porosity at various locations. The distribution means, modes, and confidence intervals can be calculated, providing a more complete understanding of the uncertainty in the parameter estimates. The approach is demonstrated using synthetic and field data sets. Results show that joint inversion using seismic and EM data gives better estimates of reservoir parameters than estimates from either geophysical data set used in isolation. Moreover, a more informative prior leads to much narrower predictive intervals of the target parameters, with mean values of the posterior distributions closer to logged values.

Pressure-dependent cross-property relationships between elastic and electrical properties of partially saturated porous sandstones

Geophysics ◽  
2020 ◽  
Vol 85 (3) ◽  
pp. MR107-MR115
Author(s):  
Tongcheng Han ◽  
Shengbiao Liu ◽  
Denghui Xu ◽  
Li-Yun Fu
Keyword(s):  
Electrical Properties ◽  
Survey Data ◽  
Water Saturation ◽  
Joint Inversion ◽  
Confining Pressure ◽  
Porous Rocks ◽  
S Wave ◽  
Partially Saturated ◽  
Fluid Saturation ◽  
Two Samples

Successful joint inversion of seismic and electromagnetic survey data to estimate parameters and improve the characterization of the earth’s subsurface relies on the understanding of the cross-property relations between the elastic and electrical properties. Pressure-dependent cross-property relationships of rocks with varying degrees of fluid saturation remain poorly understood even though such conditions are encountered frequently. We investigate this problem by designing and undertaking dedicated laboratory experiments to simultaneously measure the elastic velocity and electrical resistivity in two Berea sandstone samples subject to varying confining pressure and water saturation, using a state-of-the-art joint elastic-electrical measurement system. P- and S-wave velocities are found to increase exponentially with increasing confining pressure at each water saturation, whereas electrical conductivity can either increase or decrease with confining pressure depending on the degree of water saturation. More interestingly, the elastic and electrical properties of the two samples are shown to be systematically correlated as functions of water saturation and the applied confining pressure. The correlations reveal the natural link between the elastic and electrical properties in the two porous sandstones with partial water saturation, and they help to better indicate the fluid flow within compliant pores in addition to the known flow between stiff and compliant pores. The results will form the theoretical basis for the successful joint interpretation of seismic and electromagnetic survey data acquired from partially saturated porous rocks in the subsurface of the earth.

scholarly journals DETERMINATION CONVENTIONAL ROCK PROPERTIES FROM LOG DATA & CORE DATA FOR UPPER NUBIAN SANDSTONE FORMATION OF ABU ATTIFEL FIELD

2019 ◽  
Vol 2 (1) ◽  
pp. 29-37
Author(s):  
Adel Alabeed ◽  
Zeyad Ibrahim ◽  
Emhemed Alfandi
Keyword(s):  
Water Saturation ◽  
Rock Properties ◽  
Well Log ◽  
Log Data ◽  
Nubian Sandstone ◽  
Core Data ◽  
Hydrocarbon Reservoir ◽  
Fluid Saturation ◽  
Volume Porosity ◽  
Sandstone Formation

A reservoir is a subsurface rock that has effective porosity and permeability which usually contains commercially exploitable quantity of hydrocarbon. Reservoir characterization is undertaken to determine its capability to both store and transmit fluid. Petrophysical well log and core data, in this paper, were integrated in an analysis of the reservoir characteristics by selecting of three productive wells. The selected wells are located at Abu Attifel field in Libya for Upper Nubian Sandstone formation at depth varied form 12921 to14330 ft. The main aim of this study is to compare the laboratory measurement of core data with that obtained from well log data in order to determine reservoir properties such as shale volume, porosity (Φ), permeability (K), fluid saturation, net pay thickness. The plots of porosity logs and core porosity versus depth for the three wells revealed significant similarity in the porosity values. The average volume of shale for the reservoir was determined to be 22.5%, and average permeability values of the three wells are above 150 md, while porosity values ranged from 9 to 11%. Low water saturation 13 to 22% in the three wells indicates the wettability of the reservoir is water-wet.

Workflow for improvement of 3D anisotropic CSEM resistivity inversion and integration with seismic using cross-gradient constraint to reduce exploration risk in a complex fold-thrust belt in offshore northwest Borneo

2018 ◽  
Vol 6 (3) ◽  
pp. SG49-SG57 ◽  
Author(s):  
Max A. Meju ◽  
Ahmad Shahir Saleh ◽  
Randall L. Mackie ◽  
Federico Miorelli ◽  
Roger V. Miller ◽  
...  
Keyword(s):  
Reservoir Characterization ◽  
Three Dimensional ◽  
Structural Complexity ◽  
Hydrocarbon Exploration ◽  
Parameter Estimates ◽  
Thrust Belt ◽  
Exploration Risk ◽  
Resistivity Logs ◽  
Geologic Interpretation ◽  
Reservoir Parameter

The focus of hydrocarbon exploration has now moved into frontier regions where structural complexity, heterogeneous overburden, and hydrocarbon system fundamentals are significant challenges requiring an integrated exploration approach. Three-dimensional controlled-source electromagnetic (CSEM) anisotropic resistivity imaging is emerging as a technique to combine with seismic imaging in such regions. However, the typically reconstructed horizontal resistivity [Formula: see text] and vertical resistivity [Formula: see text] models often have conflicting depth structures that are difficult to explain in terms of subsurface geology. It is highly desirable to reduce ambiguity or subjectivity in depth interpretation of [Formula: see text] and [Formula: see text] models and also achieve comparability with other coincidentally located subsurface models. We have developed a workflow for integrating information from seismic well-based inversion, interpreted seismic horizons, and resistivity well logs in a cross-gradient-guided simultaneous 3D CSEM inversion for geologically realistic [Formula: see text] and [Formula: see text] models whose parameter estimates for a selected reservoir interval can then be better optimized to aid reservoir characterization. We developed our workflow using exploration data from a complex fold-thrust belt. We found that the integrated cross-gradient approach led to [Formula: see text] and [Formula: see text] models that have a common depth structure, are consistent with seismic and resistivity logs, and are hence less ambiguous for geologic interpretation and reservoir parameter estimation.

The effects of azimuthal anisotropy on 3D and 4D seismic amplitude variation with offset responses

Geophysics ◽  
2019 ◽  
Vol 84 (6) ◽  
pp. C251-C267
Author(s):  
Lisa J. Gavin ◽  
David Lumley
Keyword(s):  
Feasibility Studies ◽  
Azimuthal Anisotropy ◽  
Pore Fluid ◽  
Hydrocarbon Exploration ◽  
Rock Properties ◽  
Reservoir Properties ◽  
Amplitude Variation ◽  
North West ◽  
Fluid Saturation ◽  
4D Seismic

Seismic reflection amplitude variation with source-receiver offset (AVO) is an important tool in hydrocarbon exploration and reservoir monitoring, due to its sensitivity to elastic rock properties that are affected by changes in pore-fluid saturation and pressure. In most cases, 4D seismic feasibility studies and interpretation analyses assume that the earth is isotropic. This assumption can be problematic because it is becoming increasingly apparent that anisotropic rocks are quite common. Furthermore, the presence of even small amounts of anisotropy can have significant effects on AVO, and in the presence of azimuthal anisotropy the AVO will vary with azimuth. We determine that if 4D seismic surveys are acquired with different survey azimuths in the presence of azimuthal anisotropy, it is likely that 4D AVO interpretations will be significantly affected, leading to incorrect or nonphysical interpretations. This possibility is especially apparent in the context of the North West Shelf, Australia, where significant stress-induced azimuthal anisotropy is prevalent in sandstone formations that form the reservoir rocks. We model 4D AVO responses with and without azimuthal anisotropy effects for a variety of pore-fluid saturation and pressure change scenarios using average reservoir properties from the Stybarrow field, Australia. We found that azimuthal anisotropy does not affect the small reflection angles of the 4D AVO response, but it has a significant effect on larger reflection angles when comparing 4D surveys acquired at different acquisition azimuths. This azimuthal behavior leads to what we call an “apparent 4D effect” when reservoir properties do not change and a “contaminated 4D effect” when reservoir properties do change. We found real data examples in which we determine that the 4D AVO response must incorporate azimuthal anisotropy to be explained correctly. Our results further emphasize the importance of repeating survey acquisition azimuths whenever possible and/or accurately accounting for azimuthal anisotropy effects.

Reservoir property mapping and monitoring from joint inversion of time-lapse seismic, electromagnetic, and production data

Geophysics ◽  
2016 ◽  
Vol 81 (5) ◽  
pp. ID73-ID84 ◽  
Author(s):  
Lin Liang ◽  
Aria Abubakar ◽  
Tarek M. Habashy
Keyword(s):  
Prior Information ◽  
Joint Inversion ◽  
Synthetic Data ◽  
Rock Physics ◽  
Rock Properties ◽  
Production Data ◽  
Inversion Algorithm ◽  
Reservoir Properties ◽  
Temporal And Spatial Distribution ◽  
Archie’S Law

We have developed a deterministic multiphysics joint inversion approach integrating seismic, electromagnetic (EM), and production data to map relevant reservoir properties, such as permeability and porosity, and the time evolution of the flooding front movement, i.e., saturation changes with time. These measurements are complementary in terms of their sensitivity to individual reservoir properties and their coverage of reservoir volumes. As a consequence, integration reduces ambiguities in the interpretation. In the workflow, a reservoir model is first built based on prior information. The production data are simulated by evolving the model in time based on the known well-control strategy. Simultaneously, the temporal and spatial distribution of fluid properties, such as saturation, salt concentration, density, and pressure are also obtained from the forward modeling. These properties, together with in situ rock properties, are transformed to formation resistivity and elastic properties using prescribed petrophysical relationships, such as Archie’s law and effective medium rock-physics models. From the transformation results, synthetic EM and full-waveform seismic data can be subsequently simulated. A Gauss-Newton optimization scheme is used to iteratively update the reservoir permeability and porosity fields until the mismatch between the synthetic data and the observed data becomes less than a predefined threshold. This inverse problem is usually highly underdetermined; hence, it is necessary to bring in prior information to further constrain the inversion. Different regularization approaches are investigated to facilitate incorporation of prior information into the joint inversion algorithm.

scholarly journals Comparative Characterization of Petrophysical and Mechanical Properties of Siliciclastic Reservoir Rocks within a compressional structure of the Teapot Dome Oilfield, Wyoming, USA

2020 ◽  
Vol 5 (2) ◽  
pp. 1-12
Author(s):  
Rotimi Oluwatosin John ◽  
Ogunkunle Fred Temitope ◽  
Onuh Charles Yunusa ◽  
Ameloko Aduojo Anthony ◽  
Enaworu Efeoghene ◽  
...  
Keyword(s):  
Mechanical Properties ◽  
Seismic Data ◽  
Water Saturation ◽  
Accurate Determination ◽  
Hydrocarbon Exploration ◽  
Rock Properties ◽  
Petrophysical Properties ◽  
Fluid Movement ◽  
Property Variation ◽  
Reservoir Rocks

AbstractWorking with subsurface engineering problems in Hydrocarbon exploration as regard rock elastic and petrophysical properties necessitate accurate determination of in-situ physical properties. Several techniques have been adopted in correlating log-derived parameters with petrophysical and mechanical behavior of the rocks. However, limited field applications show there are no particular parameters and correlations that are generally acceptable due to the regional variation in geologic features (i.e., degree of mineralogy, texture, etc.). This study presents a method that assesses the disparity in petrophysical properties of oil and gas reservoir rocks in relation to their elastic/mechanical properties from 10 well-logs and 3D migrated seismic data. Two distinct facies were identified from seismic data after computing attributes. Reflection strength attribute of 2.5 and above depicts Bright spots within the central section of the field as clearly revealed by Variance and Chaos attributes. Formation properties calculated from logs were conformally gridded in consonance with the reflection patterns from the seismic data. The average Brittleness index (BI) of 0.52 corresponds to Young’s modulus (E) values of between 8 and 16 for the dense portion. This portion is the laminated, reasonably parallel, and undeformed part, flanked by the unlaminated and chaotic zones. From cross plots, the distinguished lower portion on the plot is the segment with higher sand of more than 50 %. This segment corresponds to the reservoir in this study as confirmed from the genetic algorithm neural network Acoustic impedance inversion process result. Similarly, the plot of Compressional velocity (Vp) and Poisson’s ratio (ν), reveals the laminated sand value of not less than 0.32 of ν, and Vp of about 4.2 km/s. The average porosity is about 16 %, average water saturation is about 16 %, and average permeability is approximately 25 md. Rock properties trends in a unique pattern and showing fluctuation that confirms the compressive nature of the structure with corresponding petrophysical properties. This trend is sustained in permeability computed and suggests a significant gravity-assisted compaction trend and fluid movement. It gives a reasonable idea of the fluid movement interplay and mechanical property variation within the sequence and across the dome. This part probably has been subjected to fair compressional deformational forces initiated from outside the survey.

scholarly journals Petrophysical interpretation and fluid substitution modelling of the upper shallow marine sandstone reservoirs in the Bredasdorp Basin, offshore South Africa

2019 ◽  
Vol 10 (2) ◽  
pp. 783-803
Author(s):  
Moses Magoba ◽  
Mimonitu Opuwari
Keyword(s):  
South Africa ◽  
Water Saturation ◽  
Shear Velocity ◽  
Acoustic Properties ◽  
Rock Properties ◽  
Fluid Substitution ◽  
Shallow Marine ◽  
Fluid Saturation ◽  
Sandstone Reservoirs ◽  
Gassmann Fluid Substitution

Abstract The fluid substitution method is used for predicting elastic properties of reservoir rocks and their dependence on pore fluid and porosity. This method makes it possible to predict changes in elastic response of a rock saturation with different fluids. This study focused on the Upper Shallow Marine sandstone reservoirs of five selected wells (MM1, MM2, MM3, MM4, and MM5) in the Bredasdorp Basin, offshore South Africa. The integration of petrophysics and rock physics (Gassmann fluid substitution) was applied to the upper shallow marine sandstone reservoirs for reservoir characterisation. The objective of the study was to calculate the volume of clay, porosity, water saturation, permeability, and hydrocarbon saturation, and the application of the Gassmann fluid substitution modelling to determine the effect of different pore fluids (brine, oil, and gas) on acoustic properties (compressional velocity, shear velocity, and density) using rock frame properties. The results showed average effective porosity ranging from 8.7% to 16.6%, indicating a fair to good reservoir quality. The average volume of clay, water saturation, and permeability values ranged from 8.6% to 22.3%, 18.9% to 41.6%, and 0.096–151.8 mD, respectively. The distribution of the petrophysical properties across the field was clearly defined with MM2 and MM3 revealing good porosity and MM1, MM4, and MM5 revealing fair porosity. Well MM4 revealed poor permeability, while MM3 revealed good permeability. The fluid substitution affected rock property significantly. The primary velocity, Vp, slightly decreased when brine was substituted with gas in wells MM1, MM2, MM3, and MM4. The shear velocity, Vs, remained unaffected in all the wells. This study demonstrated how integration of petrophysics and fluid substitution can help to understand the behaviour of rock properties in response to fluid saturation changes in the Bredasdorp Basin. The integration of these two disciplines increases the obtained results’ quality and reliability.

Mineral exploration with 3-D controlled-source electromagnetic method: a synthetic study of Sukhoi Log gold deposit

2019 ◽  
Vol 219 (3) ◽  
pp. 1698-1716 ◽  
Author(s):  
M Malovichko ◽  
A V Tarasov ◽  
N Yavich ◽  
M S Zhdanov
Keyword(s):  
Finite Difference ◽  
Gold Deposit ◽  
Large Scale ◽  
Mineral Exploration ◽  
Mineral Deposit ◽  
Hydrocarbon Exploration ◽  
Contraction Operator ◽  
Inversion Algorithm ◽  
Controlled Source ◽  
Regularized Inversion

SUMMARY This paper presents a feasibility study of using the controlled-source frequency-domain electromagnetic (CSEM) method in mineral exploration. The method has been widely applied for offshore hydrocarbon exploration; however, nowadays this method is rarely used on land. In order to conduct this study, we have developed a fully parallelized forward modelling finite-difference (FD) code based on the iterative solver with contraction-operator preconditioner. The regularized inversion algorithm uses the Gauss–Newton method to minimize the Tikhonov parametric functional with the Laplacian-type stabilizer. A 3-D parallel inversion code, based on the iterative finite-difference solver with the contraction-operator preconditioner, has been evaluated for the solution of the large-scale inverse problems. Using the computer simulation for a synthetic model of Sukhoi Log gold deposit, we have compared the CSEM method with the conventional direct current sounding and the CSEM survey with a single remote transmitter. Our results suggest that, a properly designed electromagnetic survey together with modern 3-D inversion could provide detailed information about the geoelectrical structure of the mineral deposit.

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