scholarly journals Rock physics and geomechanical application in the interpretation of rock property trends for overpressure detection

2020 ◽  
Author(s):  
Dorcas S. Eyinla ◽  
Michael A. Oladunjoye ◽  
Abel I. Olayinka ◽  
Boris B. Bate
Keyword(s):  
Pore Pressure ◽  
Acoustic Impedance ◽  
Linear Trend ◽  
Rock Physics ◽  
Cost Effective ◽  
Compressional Wave ◽  
Order Effect ◽  
Lithology Identification ◽  
Exploration Risk ◽  
Niger Delta Basin

AbstractOne of the complexities of geomechanical study is in the classification of rock’s properties and overpressured intervals—a knowledge which is not only essential for well safety and cost-effective drilling, but crucial in evaluating exploration risk factors and ensuring a successful hydraulic fracturing program. In this study, a more robust prediction of reservoir pressure regime is presented, where the geomechanical distributions of the rock give a distinct correlation. Three wells from the Niger Delta Basin were studied using empirical equations to estimate the elastic properties, wave velocities and the rock physics parameters for each well. From the results obtained, the velocities of compressional wave (Vp) and shear wave (Vs) decrease as porosity increases. Also, a linear correlation exists between Poisson’s ratio and Vp/Vs, where both variables showed distinct behavior and similar trend serving as useful tools for lithology identification. Another significant observation is the acoustic impedance of the materials which decreases with increasing porosity. Meanwhile, the depth plot of the impedance showed divergence and scattering away from the supposed linear trend. While inhomogeneity of the rock materials and disequilibrium compaction of sediments may account for this scattering, the variation of geomechanical distributions in this study revealed that pore pressure has a first order effect on the elastic strength of formations, also, under normal pore pressure conditions, acoustic impedance increases linearly with depth.

scholarly journals Cross plot Analysis of Rock Properties from Well Log Data for gas detection in Soku Field, Coastal Swamp Depobelt, Niger Delta Basin

2018 ◽  
Vol 3 (4) ◽  
pp. 180
Author(s):  
Okoli Emeka Austin ◽  
Okechukwu Ebuka Agbasi ◽  
Onyekuru Samuel ◽  
Sunday Edet Etuk
Keyword(s):  
Acoustic Impedance ◽  
Niger Delta ◽  
Gamma Ray ◽  
Rock Physics ◽  
Oil Field ◽  
Rock Properties ◽  
High Resistivity ◽  
S Wave ◽  
Lithology Identification ◽  
Well Data

The cross plotting of rock properties for fluid and lithology discrimination was carried out in a Niger Delta oil field using well data X-26 from a given oil field in the coastal swamp depobelt. The data used for the analysis consisted of suites of logs, including gamma ray, resistivity, sonic and density logs only. The reservoir of interest Horizon 1, was identified using the available suite of logs on the interval where we have low gamma ray, high resistivity and low acoustic impedance specifically at depths 10,424ft (3177.24m) to 10 724ft (3268m). We first obtained other rock attributes from the available logs before cross plotting. The inverse of the interval transit times of the sonic logs were used to generate the compressional velocities and the S-wave data was generated from Castagna´s relation. Employing rock physics algorithm on Hampson Russell software (HRS), rock attributes including Vp/Vs ratio, Lambda-Rho and Mu-Rho were also extracted from the well data. Cross plotting was carried out and Lambda Rho (λρ) versus MuRho (μρ) crossplots proved to be more robust for lithology identification than Vp versus Vs crossplots, while λρ Versus Poisson impedance was more robust than Vp/Vs versus Acoustic impedance for fluid discrimination, as well as identification of gas sands. The crossplots were consistent with Rock Physics Templates (RPTs). This implies the possibility of further using the technique on data points of inverted sections of various AVO attributes within the field in areas not penetrated by wells within the area covered by the seismic.

scholarly journals Lithology and fluid discrimination using rock physics-based modified upper Hashin–Shtrikman bound: an example from onshore Niger Delta Basin

2021 ◽  
Vol 11 (2) ◽  
pp. 569-578
Author(s):  
C. G. Okeugo ◽  
K. M. Onuoha ◽  
A. C. Ekwe
Keyword(s):  
Upper Bound ◽  
Acoustic Impedance ◽  
Niger Delta ◽  
Rock Physics ◽  
Time Lapse ◽  
Successful Prediction ◽  
Niger Delta Basin ◽  
Reservoir Connectivity ◽  
4D Seismic ◽  
Gas Bearing

AbstractThe Ozifa reservoir is proven reservoir that cuts across the Northern and Greater Ughelli depo-belts of the Niger Delta Basin. This reservoir possesses heterogenous character southward of the field, making elastic properties, lithologies and fluid types difficult to describe accurately. In this study, rock physics template was applied to porosity and acoustic impedance (AI) crossplot clusters to illustrate rock–fluid relationships using modified Hashin–Shtrikman upper bound, Voigt upper bound and Reuss lower bound, as an input in the template. Values of acoustic impedance and porosity were used as lithofacies classification parameters for discrimination of lithofacies and fluid types. Our result showed that modified Hashin–Shtrikman upper bound line when applied in acoustic impedance (AI) and porosities (φ) crossplot domain discriminated gas-filled reservoirs from brine filled reservoirs and shale effectively. Similarly, results from crossplot showed clear separation of shale, heteroliths filled with brine and gas bearing sand, which was not plausible using conventional petrophysical analysis. This approach was successfully applied in analysing lithofacies and fluid relationship in different well locations and serves as a model for successful prediction of different lithology and fluid types, a major requirement for determining effects of geological variables such as sorting, clay distributions on the reservoir connectivity and optimum production using time-lapse (4D) seismic interpretation.

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.

Rock-physics templates based on seismic Q

Geophysics ◽  
2019 ◽  
Vol 84 (1) ◽  
pp. MR13-MR23 ◽  
Author(s):  
Stefano Picotti ◽  
José M. Carcione ◽  
Jing Ba
Keyword(s):  
Quality Factor ◽  
Acoustic Impedance ◽  
Rock Physics ◽  
P Wave ◽  
Gas Oil ◽  
Seismic Properties ◽  
Gas Saturation ◽  
Seismic Quality Factor ◽  
Porosity And Permeability ◽  
Higher Sensitivity

We build rock-physics templates (RPTs) for reservoir rocks based on seismic quality factors. In these templates, the effects of partial saturation, porosity, and permeability on the seismic properties are described by generalizing the Johnson mesoscopic-loss model to a distribution of gas-patch sizes in brine- and oil-saturated rocks. This model addresses the wave-induced fluid flow attenuation mechanism, by which part of the energy of the fast P-wave is converted into the slow P (Biot) diffusive mode. We consider patch sizes, whose probability density function is defined by a normal (Gaussian) distribution. The complex bulk modulus of the composite medium is obtained with the Voigt-Reuss-Hill average, and we show that the results are close to those obtained with the Hashin-Shtrikman average. The templates represent the seismic dissipation factor (reciprocal of seismic quality factor) as a function of the P-wave velocity, acoustic impedance, and [Formula: see text] (P to S velocity ratio), for isolines of saturation, porosity, and permeability. They differentiate between oil and brine on the basis of the quality factor, with the gas-brine case showing more dissipation than the gas-oil case. We obtain sensitivity maps of the seismic properties to gas saturation and porosity for brine and oil. Unlike the gas-brine case, which shows higher sensitivity of attenuation to gas saturation, the gas-oil case shows higher sensitivity to porosity, and higher acoustic impedance and [Formula: see text] sensitivity values versus saturation. The RPTs can be used for a robust sensitivity analysis, which provides insights on seismic attributes for hydrocarbon detection and reservoir delineation. The templates are also relevant for studies related to [Formula: see text]-storage monitoring.

scholarly journals Elastic characteristics of overpressure due to smectite-to-illite transition based on micromechanism analysis

Geophysics ◽  
2019 ◽  
Vol 84 (4) ◽  
pp. WA23-WA42
Author(s):  
Xuan Qin ◽  
De-Hua Han ◽  
Luanxiao Zhao
Keyword(s):  
Pore Pressure ◽  
Rock Physics ◽  
Fluid Loss ◽  
Sonic Velocity ◽  
Modeling Framework ◽  
Evolution Characteristics ◽  
Rock Physics Modeling ◽  
Pore Pressure Prediction ◽  
Bulk Volume ◽  
Physics Modeling

Characterizing the elastic signatures of overpressure of shale caused by the smectite-to-illite transition relies on a good understanding of this mechanism and is also necessary for pore-pressure prediction. Methods of pore-pressure prediction in shales that have undergone smectite-to-illite transition are mostly based on empirical fitting without a quantitative interpretation based on a micromechanism analysis. With upscaled wireline-logging data, two trends of smectite-to-illite transition are categorized by using the crossplot of sonic traveltime and density. Trend I associated with a fluid-expansion scenario exhibits a decrease of sonic velocity with little change in the bulk density, whereas trend II induced by a fluid-loss scenario contains an increase of density with little change in the sonic velocity. The fluid expansion typically gives rise to high-magnitude overpressure and tends to happen when the overlying formations have more shaly contents and low permeability. The fluid loss case tends to have relatively deeper overpressure onsets, and its overlying formations tend to have more sandy contents with relatively high permeability. We develop a modeling framework to capture the elastic and pore-pressure evolution characteristics in shale during the smectite-to-illite transition. With proper bulk volume models, the velocity, density, and pore pressure increase of shale can be computed in the fluid expansion, fluid loss, and a mixture of these two scenarios. After calibration with logging data, rock-physics modeling can quantitatively interpret the rock-property evolution characteristics within the smectite-to-illite transition zone.

Using instantaneous frequency and colored inversion attributes to distinguish and determine the sandstones facies of the Late Ordovician Mamuniyat reservoir, R-field in Murzuq Basin, Libya

2016 ◽  
Vol 4 (4) ◽  
pp. T507-T519 ◽  
Author(s):  
Yousf Abushalah ◽  
Laura Serpa
Keyword(s):  
Instantaneous Frequency ◽  
Seismic Data ◽  
Acoustic Impedance ◽  
Rock Physics ◽  
Side Lobe ◽  
Petroleum Reservoir ◽  
Seismic Reflection Data ◽  
Frequency Bands ◽  
Reflection Data ◽  
Sandstone Facies

The Mamuniyat petroleum reservoir in southwestern Libya is comprised of clean sandstones and intercalated shale and sand facies that are characterized by spatial porosity variations. Seismic reflection data from the field exhibit relatively low vertical seismic resolution, side lobes of reflection wavelets, reflection interference, and low acoustic impedance contrast between the reservoir and the units underneath the reservoir, which make mapping those facies a difficult task. In the absence of broadband seismic data, optimizing frequency bands of bandlimited data can be used to suppress pseudoreflectors resulting from side-lobe effects and help to separate the clean sandstone facies of the reservoir. We have optimized the data based on our investigation of seismic frequency bands and used instantaneous frequency analysis to reveal the reflection discontinuity that is mainly associated with the reservoir boundary of the sandstone facies of the clean Mamuniyat reservoir. We also preformed rock-physics diagnostic modeling and inverted the seismic data using spectral-based colored inversion into relative acoustic impedance. The inverted impedance matches the up-scaled impedance from the well data and the inversion of relative acoustic impedance confirms the conclusion that was drawn from the instantaneous frequency results. The interpretation of facies distributions based on the instantaneous frequency was supported by the inversion results and the rock-physics models.

Seismic monitoring of a CO2 flood in a carbonate reservoir: A rock physics study

Geophysics ◽  
1998 ◽  
Vol 63 (5) ◽  
pp. 1604-1617 ◽  
Author(s):  
Zhijing Wang ◽  
Michael E. Cates ◽  
Robert T. Langan
Keyword(s):  
High Resolution ◽  
Pore Pressure ◽  
Rock Physics ◽  
Fluid Substitution ◽  
High Porosity ◽  
High Permeability ◽  
Pressure Buildup ◽  
Reservoir Rocks ◽  
Velocity Changes

A carbon dioxide (CO2) injection pilot project is underway in Section 205 of the McElroy field, West Texas. High‐resolution crosswell seismic imaging surveys were conducted before and after CO2 flooding to monitor the CO2 flood process and map the flooded zones. The velocity changes observed by these time‐lapse surveys are typically on the order of −6%, with maximum values on the order of −10% in the vicinity of the injection well. These values generally agree with laboratory measurements if the effects of changing pore pressure are included. The observed dramatic compressional ([Formula: see text]) and shear ([Formula: see text]) velocity changes are considerably greater than we had initially predicted using the Gassmann (1951) fluid substitution analysis (Nolen‐Hoeksema et al., 1995) because we had assumed reservoir pressure would not change from survey to survey. However, the post‐CO2 reservoir pore fluid pressure was substantially higher than the original pore pressure. In addition, our original petrophysical data for dry and brine‐saturated reservoir rocks did not cover the range of pressures actually seen in the field. Therefore, we undertook a rock physics study of CO2 flooding in the laboratory, under the simulated McElroy pressures and temperature. Our results show that the combined effects of pore pressure buildup and fluid substitution caused by CO2 flooding make it petrophysically feasible to monitor the CO2 flood process and to map the flooded zones seismically. The measured data show that [Formula: see text] decreases from a minimum 3.0% to as high as 10.9%, while [Formula: see text] decreases from 3.3% to 9.5% as the reservoir rocks are flooded with CO2 under in‐situ conditions. Such [Formula: see text] and [Formula: see text] decreases, even if averaged over all the samples measured, are probably detectable by either crosswell or high‐resolution surface seismic imaging technologies. Our results show [Formula: see text] is sensitive to both the CO2 saturation and the pore pressure increase, but [Formula: see text] is particularly sensitive to the pore pressure increase. As a result, the combined [Formula: see text] and [Formula: see text] changes caused by the CO2 injection may be used, at least semiquantitatively, to separate CO2‐flooded zones with pore pressure buildup from those regions without pore pressure buildup or to separate CO2 zones from pressured‐up, non‐CO2 zones. Our laboratory results show that the largest [Formula: see text] and [Formula: see text] changes caused by CO2 injection are associated with high‐porosity, high‐permeability rocks. In other words, CO2 flooding and pore pressure buildup decrease [Formula: see text] and [Formula: see text] more in high‐porosity, high‐permeability samples. Therefore, it may be possible to delineate such high‐porosity, high‐permeability streaks seismically in situ. If the streaks are thick enough compared to seismic resolution, they can be identified by the larger [Formula: see text] or [Formula: see text] changes.

Application of Probabilistic Neural Network and Rock physics Analysis for Carbonate Reservoir Characterization: A Case Study from Onshore Supergiant Oil Field

2020 ◽  
Author(s):  
Ali Alali ◽  
Karl Stephen
Keyword(s):  
Neural Network ◽  
Elastic Properties ◽  
Acoustic Impedance ◽  
Reservoir Characterization ◽  
Probabilistic Neural Network ◽  
Rock Physics ◽  
Carbonate Reservoir ◽  
High Porosity ◽  
Tidal Channels ◽  
Porosity Distribution

<p>Identification and modeling of the carbonate tidal channels is key for finding sweet spots or areas at higher risk to water breakthroughs which have a significant impact on the development and monitoring of reservoir dynamic performance. However, such these channels cannot be easily characterize by conventional seismic attributes. It is important to decipher the complexity of carbonate tidal channel architecture with integrated multisource data and different approaches.</p><p>A step wise approach has been taken in this work. First, rock physics model was carried out to ensure that elastic properties can be applied for reservoir characterization from the seismic data. Then, post-stack seismic inversion was carried out on the high resolution of 3D seismic dataset. The seismically derived porosity estimation is undertaken using geostatistical method and multiattributes combination was used. Probabilistic neural network training technique was then performed to improve the results for thick reservoir and the result has been used for seismic conditioning of geological models. Finally, the spatial distribution of porosity volume was cautiously assessed through the comparison between input and blind wells, also validated by core data.</p><p>The analysis of rock physics displayed a high correlation between elastic properties and the porosity distribution of the Mishrif channel, three facies were observed. The final interpretation of seismically derived characterization in Mishrif channel, observed a different lateral distribution of inverted elastic properties. These features of Mishrif carbonate tidal channels could be classified into these regions: north, southwest, and east. Related a high porosity with low acoustic impedance appeared mostly in these channels which reflect a good reservoir quality grainstone channels or sholas bodies. While, outside these channels is heavily mud filled by peritidal carbonates and characterized a high acoustic impedance anomaly with low quality of porosity distribution.</p><p>The results provided a new insight into the distribution of the petrophysical properties and reservoir architecture of facies with quantification of their influence on dynamic reservoir behavior in the Mishrif channelized systems and also for similar heterogeneous carbonate reservoirs</p>

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