Simultaneous Seismic Inversion Research Articles

Application of Gassmann equation and simultaneous seismic inversion to estimate formation compressibility in unconsolidated sands reservoirs.

Application of Gassmann equation and simultaneous seismic inversion to estimate formation compressibility in unconsolidated sands reservoirs.

Estimating elastic properties of sediments by pseudo-wells generation utilizing simulated annealing optimization method

The hydrate concentration model considerably affects elastic properties, including bulk and shear modulus. Defining seismic properties of sediments, such as compressional and shear wave velocity and density, provides valuable information to identify rock facies and fluid types. This information commonly results from pre-stack seismic inversion, while post-stack seismic information provides acoustic impedance as a layer-based property. Traditionally, seismic inversion requires well logs to produce an initial guess of inversion routines and provide a low-frequency part of the amplitude spectrum. Eventually, seismic inversion methods could not be performed in the areas without well-log data, such as deep sea areas. In such cases, pseudo-well logs derived from pre-stack seismic data are a solution. Pseudo-well generation is a title used to estimate the elastic parameters of sediments in areas, such as deep marine environments, where drilled wells are absent or sparse. Metaheuristic optimization algorithms are suitable tools for minimizing the cost function as they best match real and synthetic seismic data. In this study, the SEAM earth model has been used as a reference to investigate the quality of pseudo-well generation utilizing a simulated annealing (SA) algorithm as an optimization method of property model change, which minimizes the cost function of seismic inversion. As a result, considering an initial model type of the SEAM model, simultaneous seismic inversion introduced the best compressional and shear wave velocities and density logs, which provide the best real and synthetic seismic data match when synthetic data is calculated from the simplified Zoeppritz equation.

Simultaneous seismic inversion study for channel sandstone identification, northern part of the Eastern Shelf, King County, North-Central Texas

This paper documents the results of a prestack simultaneous seismic inversion conducted to investigate the Wolfcampian lower Tannehill sandstone channels within a mixed carbonate siliciclastic system in the northern Eastern Shelf in King County, North Central Texas. Previous exploration methods for the Tannehill sandstone were based largely on well-log correlation which, because of their widely spaced sample points, are not optimal for channel delineation. We have generated crossplots of P- and S-wave velocity ratios ([Formula: see text]/[Formula: see text] ratios) versus P-impedance to determine lithologic types. We then used 3D seismic data and wireline logs to implement a prestack simultaneous seismic inversion procedure to generate P- and S-impedances, density, and [Formula: see text]/[Formula: see text] ratio volumes to identify the valley-fill Tannehill lowstand systems. Our results find that (1) based on impedance and density, the sandstone-rich channels can be easily separated from the carbonate-rich zones but are difficult to distinguish using [Formula: see text]/[Formula: see text]. (2) Although there appeared to be several channel systems in the area of investigation, two of these, hereby referred to as channel A and channel B, are recognized to be the key contributors of sandstone sediments to the shelf edge, slope, and basin areas. (3) Of these two channels, channel A is the larger and highly sinuous; it is associated with a meander loop, a point bar, and an abandoned channel. At the point-bar location, channel A has a width of 890 m (2920 ft) and a depth of 29 m (94 ft). The point bar is structurally anticlinal and thus constitutes a potential exploration target. In contrast, channel B is less sinuous, without any associated point bar. It has a maximum depth and width of 23 m (75 ft) and 270 m (886 ft), respectively. Finally, the inversion results suggest that other potential Tannehill sandstone reservoirs may still be present elsewhere within King County.

Prestack Seismic Velocity Ratio Evaluation of a Mixed Siliciclastic–Carbonate Formation: Case Study from the Strawn Group on the Eastern Shelf Texas

Although a mixed carbonate–siliciclastic system of the Strawn Group on the Eastern Shelf in King County, Texas, USA provides excellent hydrocarbon reservoirs, facies variability and reservoir properties within such systems are not well understood. We conducted prestack, simultaneous seismic inversion, and high-level petrophysical analysis to derive elastic properties of rocks to facilitate lithology identification and determination and distribution of the different carbonate facies. Our results show that (1) the Strawn Group in King County is dominated mostly by carbonates and (2) given the ratio of P- and S-wave velocity (Vp/Vs ratio), the carbonates can be separated into three facies: (a) high-Vp/Vs-ratio shelf-edge reef carbonates, in which the Vp/Vs ratio decreases linearly as porosity increases and the Vp/Vs ratio varies from ~2.1 to ≤2.6; (b) moderately low-Vp/Vs-ratio shelf (platform) carbonates, in which the Vp/Vs ratio also decreases as porosity increases and in which the Vp/Vs ratio ranges from ~1.75 to ≤2.15; (c) extremely low-Vp/Vs-ratio slope and basin carbonates, in which the Vp/Vs ratio, although appearing to be almost constant for a wide range of porosity, increases as porosity increases, and in which most Vp/Vs-ratio values appear to range from ~1.5 to ≤2. Results of a through c can be summarized thusly: the Vp/Vs ratio of reef carbonates >the Vp/Vs ratio of platform carbonates and >the Vp/Vs ratio of slope and basin carbonates in the study area.

Implementation of the Poisson Impedance Inversion to Improve Hydrocarbon Reservoir Characterisation in the Poseidon Field, Browse Basin, Australia

The prediction process of lithology and fluid content is the most important part of reservoir characterization. One of the methods used in this process is simultaneous seismic inversion. In the Poseidon field, Browse Basin, Australia, the parameters generated through simultaneous seismic inversion cannot accurately characterize the reservoir because of the overlapping impedance values between hydrocarbon sand, water sand, and shale, which cause a high level of ambiguity in the interpretation. The Poisson impedance (PI) inversion provides a solution to this problem by rotating the impedance a few degrees through coefficient c. Coefficient c is obtained through the target correlation coefficient analysis by finding the optimum correlation coefficient between the PI and the target log, namely, gamma rays, effective porosity, and resistivity. The results show that the PI gives better outcomes in separating hydrocarbon-saturated reservoir zones. Based on the results of the lithology impedance–gamma rays, the ϕI-effective porosity cross-plot, and the fluid impedance-water saturation (Sw) cross-plot, with optimum correlations of 0.74, 0.91, and 0.82, respectively. The lithology of hydrocarbon-saturated porous sand is at values of LI ≤ 2800 (m/s)(g*cc), ϕI ≤ 5500 (m/s)(g*cc) and FI ≤ 4000 (m/s)(g*cc). The presence of low values for LI, ϕI and FI correlates accurately with the presence of hydrocarbons in the well. Each value of c is then applied to the seismic data. The results show that this method can determine the distribution of gas-saturated porous sand on the seismic inversion section in the northeast–southwest direction.

Characterization of complex fluvial-deltaic deposits in Northeast India using Poisson impedance inversion and non-parametric statistical technique

Characterizing complex fluvial-deltaic deposits is a challenging task for finding hydrocarbon discoveries. We described a methodology for predicting the hydrocarbon zones from complex well-log and prestack seismic data. In this current study, data analysis involves an integrated framework based on Simultaneous prestack seismic inversion (SPSI), target correlation coefficient analysis (TCCA), Poisson impedance inversion, and non-parametric statistical analysis, and Bayesian classification. First, seismic elastic attributes from prestack seismic data were estimated. They can provide the spatial distribution of petrophysical properties of seismic data. Then target correlation coefficient analysis (TCCA) was estimated roration factor “c” from well-log data. Using the seismic elastic attributes and rotation factor “c”, Poisson impedance inversion was performed to predict the Poisson impedance volume. Finally, Bayesian classification integrated the Poisson impedance volume with non-parametric probabilistic density functions (PDFs) to estimate the spatial distribution of lithofacies. Despite complex characteristics in the elastic properties, the current study successfully delineated the complex fluvial-details deposits. These results were verified with conventional findings through numerical analysis.

Gas-bearing sands appraisal for Zamzama Gas field in Pakistan through inverted elastic attributes assisted with PNN approximation of petrophysical properties

The Pab Formation of Zamzama block, lying in the Lower Indus Basin of Pakistan, is a prominent gas-producing sand reservoir. The optimized production is limited by water encroachment in producing wells, thus it is required to distinguish the gas-sand facies from the remainder of the wet sands and shales for additional drilling zones. An approach is adopted based on a relation between petrophysical and elastic properties to characterize the prospect locations. Petro-elastic models for the identified facies are generated to discriminate lithologies in their elastic ranges. Several elastic properties, including p-impedance (11,600-12,100 m/s*g/cc), s-impedance (7,000-7,330 m/s*g/cc), and Vp/Vs ratio (1.57-1.62), are calculated from the simultaneous prestack seismic inversion, allowing the identification of gas sands in the field. Furthermore, inverted elastic attributes and well-based lithologies are incorporated into the Bayesian framework to evaluate the probability of gas sands. To better determine reservoir quality, bulk volumes of PHIE and clay are estimated using elastic volumes trained on well logs employing Probabilistic Neural Networking (PNN), which effectively handles heterogeneity effects. The results showed that the channelized gas-sands passing through existing well locations exhibited reduced clay content and maximum effective porosities of 9%, confirming the reservoir's good quality. Such approaches can be widely implemented in producing fields to completely assess litho-facies and achieve maximum production with minimal risk.

Visualizing hydrocarbon migration pathways associated with the Ringhorne oil field, Norway: An integrated approach

Norway’s Ringhorne Field is a faulted anticline, which produces oil from Triassic (Statfjord) and Paleocene (Hermod) sands. It is located on the Utsira High. Geochemical studies of the produced oil indicate that the oil is generated from mature Upper Jurassic marine shales in the adjacent Viking Graben. However, it is not clear how oil migrated into the Triassic reservoirs and charged the overlying Paleocene reservoirs. Lateral hydrocarbon migration is not detectable on seismic data. However, vertical hydrocarbon migration can be observed as a vertically aligned, low-amplitude, chaotic signature on normally processed seismic data. Gas-chimney detection is a proven neural network technique to detect these vertical hydrocarbon migration pathways. The processing results are then validated using a set of criteria to determine if they represented true hydrocarbon migration rather than seismic artifacts. The chimney processing results using this traditional (shallow) neural network are compared with convolutional neural network (deep learning) results and geomechanical modeling on key lines. Key reservoirs are delineated using a deterministic simultaneous seismic inversion approach. Reliable chimneys are then visualized in the vicinity of the producing reservoirs. The results indicate pathways by which the Triassic fluvial sands received the charge and how these reservoirs have flank leakage to provide the charge to shallower Paleocene reservoirs. This approach is currently being used over hundreds of fields and dry holes in the Norwegian North Sea and worldwide as analogs to assess the hydrocarbon charge and top seal risk predrill.

Bayesian Theorem Application to Model Reservoir Facies Distribution on Deltaic Depositional Environment, Case Study of Browse Basin

Successful Hydrocarbon exploration and reservoir characterization always related with good understanding of geology and geophysics aspect. One of the fundamental issues is to get reliable parameter distribution and quantify the confidence level of the parameter model in 3D. The case study in this paper will be applied in Browse field that and the result will be a distribution model in 3D of facies and hydrocarbon fluid. The workflow that will be introduced in this paper is the combination between rock physics analysis, simultaneous seismic inversion and Bayesian estimation theorem. Rock physics analysis includes well log conditioning and correlation analysis between reservoir parameter (porosity, saturation, Vshale, etc) with seismic parameter (acoustic impedance, vp/vs, shear impedance, etc) to obtain facies classification in well log scale. The simultaneous seismic inversion method is used to obtain seismic parameter cube to be correlated with rock physics result to drive the facies distribution. Bayesian estimation theorem assembles initial knowledge about a model before observing the inversion attributes. The probability density function later will be used to drive the facies distribution combined with well log data and seismic data; and also estimate the confidence level distribution in 3D. The result can be used to identify new play in the Browse field.

Simultaneous Seismic Inversion for Reservoir Characterization at Poseidon Field, Browse Basin, Australia

Seismic inversion method has been widely used to obtain reservoir property in an oil and gas field. In this research, one of inversion methods known as simultaneous inversion is used to analyze reservoir characterization at Poseidon Field, Browse Basin. Simultaneous inversion is applied to partial angle stack data and result in volume of Acoustic Impedance (AI), Shear Impedance (SI) and Lame parameter (LMR). The objective of this study is to determine distribution of sandstone lithology with gas saturated in Plover reservoir formation. Sensitivity analysis is done by cross-plotting elastic and Lame parameter from five well log data and analyzing lithology type and fluid saturation. Based on those cross-plots, lithological type can be identified from AI, λρ, µρ and λ/µ parameters. Meanwhile, the presence of gas can be discriminated using SI, λρ, and λ/µ parameters. Gas-saturated sandstone presence is characterized by Lambda-Rho value less than 50 GPa g cc-1 and Lambda over Mu value less than 0.8 GPa g cc-1. Maps of each parameter are generated at reservoir interval. Based on those maps, it can be concluded that gas sand spread out in the eastern and western areas of research area.

ESTIMATION OF 3D CARBONATE RESERVOIR PERMEABILITY AND INTERPARTICLE POROSITY BASED ON ROCK TYPES DISTRIBUTION MODEL

Carbonate reservoir in “R” Oil Field is a reef limestone that has a very complex porosity and permeability characteristics caused by its diverse pore types (interparticle, stiff, and crack). This study aims to characterize the carbonate reservoir by estimating its interparticle porosity and permeability based on rock types distribution model. Modified Rock-Fabric Classification is used to determine the distribution of rock types in three reference wells (R2, R9, R20). Rock Types (RT) distribution model is generated by integrating Acoustic Impedance (AI) and Shear Impedance (SI) attributes from seismic simultaneous inversion with rock types distribution in reference wells using Naive-Bayes Classifier. Three-dimensional (3D) interparticle porosity and permeability are then estimated from the rock types distribution model. The result shows RT3 which is characterized by crack pores as the most dominant rock type in the reservoir followed by RT5, RT4, and RT6 which are characterized by interparticle pores. Relatively high interparticle porosity values ranges from 0.18 to 0.22 can be associated with RT6 of mud-dominated packstone or wackestone. Meanwhile, relatively high permeability values range from 70 to 80 millidarcy (mD) can be associated with RT4 of grainstone. Laterally, there are clusters of spots in the south of the three reference wells that showed relatively high permeability value.

A new approach to petroelastic modeling of carbonate rocks using an extended pore-space stiffness method, with application to a carbonate reservoir in Central Luconia, Sarawak, Malaysia

Pore geometry plays an important role in the elastic response of carbonate rocks. Diagenetic processes in carbonate sediments generate a range of pore-type distributions. Hence, the petroelastic modeling (PEM) of carbonate rocks is more complex than for clastics. Petrophysical properties connect to elastic properties through PEM or, in general terms, rock-physics modeling. Pore types cause variation in P-wave velocity — up to 40% for a given porosity. A variety of pore types with different aspect ratios such as vuggy, moldic, interparticle, intraparticle, fracture, and crack makes the porosity-velocity relationship complex, and empirical models fail to handle it properly. We propose a new, easy-to-implement approach for PEM of carbonate rocks that leads to more accurate elastic properties estimation. It offers a novel PEM method that reduces the number of defined parameters and equations. In it, the Xu-Payne rock-physics modeling equations are replaced with an extended pore-space stiffness equation. Instead of including a pore's aspect ratio as is done when using the Xu-Payne inclusion model formulation, in our proposed technique only the appropriate value of pore-space stiffness for each pore type is considered, together with the corresponding volume fraction of pore types. However, parameters are optimized by calibrating the estimated elastic properties with corresponding information from well-log measurements. This inclusion model yields acceptable predictions of elastic properties at wells that do not have measured elastic logs. The method was tested using well data from a carbonate reservoir in Central Luconia, offshore Sarawak, Malaysia. Here, one well has a complete suite of log data needed to calibrate the model. The calibrated model was then used to predict the missing shear velocity log in the other well. Next, simultaneous elastic seismic inversion was performed on 3D seismic data covering the area of the carbonate reservoir, and elastic property volumes (acoustic impedance and VP/VS ratio) were estimated. From these results, a posterior probability distribution of stiff pore types was determined, which validated the outcome of this approach using a blind test.

Integration of fluid replacement modeling and seismic AVO analysis towards simultaneous seismic inversion to delineate the distribution of Globigerina limestone gas reservoir

Integration of fluid replacement modelling and seismic AVO analysis towards simultaneous seismic inversion had been done to delineate the distribution of Globigerina limestone gas reservoir in Madura Strait, East Java Basin. This study was using backward modelling or well known as inversion modelling to finish the quantitative analysis. The purpose of the study is to map the distribution of Globigerina limestone gas reservoir so that in the end the final result will be used as a guidance to drill the next exploration well. It started with an optimized low frequency model building by integrating fluid substitution modelling and seismic AVO analysis. By integrating these two methods, the distorted top and bottom reservoir can be compensated, and the low frequency model will be optimized. The availability of the data includes 3D seismic data with acquisition bin size 18.75 m × 12.5 m, with two well logs. The cross plot result showed that the reservoir and non-reservoir lithology can be distinguished by Vp and Vs log. By analysing the acoustic impedance together with Vp/Vs ratio, the character of gas reservoir at surrounding F and H structures can also be delineated. The main cut off for acoustic impedance and Vp/Vs ratio were 5,500 gr/cm3*m/s and 2.0. The final optimizing result of low frequency model showed that the target G structure, which will be the next exploration target, showed an analogue response with its neighbour F and H structures. It is concluded that by integrating both two methods, fluid replacement modelling and AVO seismic analysis, the optimizing of low frequency model can be achieved and the simultaneous seismic inversion can successfully map other gas reservoir.

Lithological Characterization by Simultaneous Seismic Inversion in Algerian South Eastern Field

Lithological Characterization by Simultaneous Seismic Inversion in Algerian South Eastern Field

Lithological Characterization by Simultaneous Seismic Inversion in Algerian South Eastern Field

The main goal of this paper is to characterize a reservoir situated in the southeast of Algeria based on AVO seismic inversion. The seismic inversion model has been built by the iterative method of Aki and Richards’s approximation and it has been correlated with four-existing wells in the studied zone. The correlation rate between the inversion model and logging data is good (varying from 72% to 85%). Reservoir characterization of this field has been given in detail. The lithological description is used to construct a Geomechanical model that is useful for new wells’ drilling decisions. The high correlated results allowed us to have a vision on the horizontal variation of Petrophysical parameters such as density and lithological variation of three facies clay, tight limestone, and porous limestone. Moreover, this classification is used in the best way to determine the interesting zone with higher porosity values, so that the exploration strategy becomes more efficient with minimized uncertainties. Therefore, it is highly recommended to use the constructed model to propose new wells as well-5 in this study.

Simultaneous seismic inversion to identify prospective areas in carbonate rocks of the southeastern part of the West Siberian Platform

This paper focuses on the description of a technology and results of identifying and mapping areas in Devonian carbonate rocks prospective for hydrocarbons and associated with increased fracture-cavern porosity in the southeastern part of the West Siberian Platform. The lack of wide-azimuthal seismic data and recording of only the vertical component in the study area did not allow the use of the direct indicators of fracture systems based either on azimuthal anisotropy of the amplitudes of pressure waves or on splitting converted waves into fast and slow. Instead, abnormally low values of the ratio of pressure-wave and shear-wave velocities derived by deterministic simultaneous pre-stack seismic inversion were used as an indirect indicator of increased fracturing. The choice of this seismic signature of fractures is substantiated by a brief review of publications on its successful use in the identification and delineation of highly fractured and cavernous zones in carbonate reservoirs. The behaviour of the indicator showed good agreement with well productivity in the study area and, therefore, made it possible to predict a number of perspective pay zones, presumably associated with in-creased fracturing. At the same time, however, well log estimates of the velocity ratio related to fractured reservoirs exhibited an opposite trend, which mismatched the facts observed in the study area and reported in the literature. This apparent discrepancy is explained by the impact of near-vertical natural macro-fracturing, which, due to different measurement scales, might substantially reduce seismic estimates while producing no impact on well log estimates. In order to describe this phenomenon quantitatively, the weak-anisotropy approximation of P-wave reflection coefficients at a horizontal boundary derived by Rüger for transversely isotropic media with a horizontal axis of symmetry was used. This equation was rewritten in terms of impedances and density and then was analyzed analytically. To express the impact of fractures in terms of fracture density, the simplest model of thin, isolated, penny-shaped fractures was used.

Two-parameter prestack seismic inversion of porosity and pore-structure parameter of fractured carbonate reservoirs: Part 2 — Applications

Fractures and fracture-related dissolution pores, as well as cavities, molds, and vugs, provide the major conduit and/or storage space for hydrocarbons in the deeply buried carbonate hill of Hexiwu field, Bohai Bay Basin. The fractured reservoir generally has lower porosity but better permeability than moldic/vuggy reservoir, and it consists of the major part of the buried-hill slope and buried-hill internal reservoirs. The conventional method of characterizing carbonate reservoirs, however, often mixes these two types of reservoirs together because they both have low acoustic impedance and low bulk modulus. The rock-physics analysis of two field wells indicates that a pore-structure parameter defined in a rock-physics model, the so-called Sun model, can help to distinguish the fractured reservoir zones together with porosity. Fractured zones usually have porosity of less than 5% and a pore-structure parameter of greater than six, whereas moldic/vuggy reservoirs of higher porosity have a pore-structure parameter of less than six. Field-scale application demonstrates that simultaneous prestack seismic inversion for the porosity and pore-structure parameter enables 3D mapping of fractured reservoir zones in the buried carbonate hills. It also provides an analog of detecting fractures and/or fracture-related pores in deeply buried carbonates in similar geologic settings.

Two-parameter prestack seismic inversion of porosity and pore structure parameter of fractured carbonate reservoirs: Part 1 — Methods

Fractured zones in deeply buried carbonate hills are important because they often have better permeability resulting in prolific production than similar low-porosity rocks. Nevertheless, their detection poses great challenge to conventional seismic inversion methods because they are mostly low in acoustic impedance and bulk modulus, hardly distinguishable from high-porosity zones or mudstones. A proxy parameter of pore structure defined in a rock-physics model, the so-called Sun model, has been used for delineating fractured zones in which the pore structure parameter is relatively high, whereas the porosity is low in general. Simultaneous seismic inversion of the pore structure parameter and porosity proves to be difficult and nontrivial in practice. Although the pore structure parameter is well-defined at locations where density, P-, and S-velocity are known from logs, estimation of P- and S-velocity information, especially density information from prestack seismic data is rather challenging. A three-step iterative inversion method, which uses acoustic, gradient, and elastic impedance from angle-stacked seismic data as input to the rock-physics model for calculating porosity and bulk and shear pore structure parameters simultaneously, is proposed and implemented to solve this problem. The methodology is successfully tested with well logs and seismic data from a deeply buried carbonate hill in the Bohai Bay Basin, China.

Simultaneous prestack seismic inversion in a carbonate reservoir

Abstract We applied a method of Simultaneous Prestack Seismic Inversion (SPSI) in a hydrocarbon field located in the Campos Basin, Brazil. The goal was to study the application of this method to Albian carbonate rocks of the Quissama Formation. Based on what is found in nearby fields, this Formation potentially contains hydrocarbon accumulations that can be revealed with the inverted models. P-wave velocity (Vp), S-wave velocity (Vs) and density (ρ) curves along seven wells were used as inputs to construct 3-D initial models of acoustic impedance (Zp), shear impedance (Zs) and ρ. Wells without Vs and ρ curves had those values calculated from well-established equations. Final 3-D models were calculated from deviations in linear relationships between the logarithms of Zs and Zp, as well as between ρ and Zp, which were merged with the initial models. Interpretations of the inversion results were conducted based on patterns found along well logs such as resistivity (ILD), gamma ray (GR), density (RHOB), neutron porosity (NPHI) and sonic (DT). These analyses provided criteria to select the best inverted models. These models show low impedance anomalies that are consistent with previous studies performed with the well logs. One well in particular was interpreted as having high potential to contain hydrocarbons. This well shows an impedance pattern that allowed us to highlight other areas with the same pattern throughout the entire seismic volume.

Quantitative interpretation sensitivity to angle and frequency-dependent pre-stack time shift, amplitude and phase perturbations

As discussed by Long (2017), marine ‘broadband’ signal processing flows typically incorporate a combination of free-surface deghosting, spectral shaping, and attenuation compensation. Overall, there are many opportunities to corrupt the phase content in an angle-dependent and frequency-dependent manner during any signal processing flow, and such risks may increase during aggressive ‘broadband’ flows. We conducted a synthetic modelling study to quantify and understand how angle-dependent time shifts, angle-dependent frequency variations, or frequency-dependent phase errors can impact the recovery of elastic impedance attributes using pre-stack simultaneous seismic inversion. All modelling and inversion was 2D in nature, included no noise considerations, and assumed the velocity model was perfectly understood.