Basin-wide rock-physics analysis in Campeche Basin, Gulf of Mexico — Phase II: Reservoir rock and fluid properties

2021 ◽  
Vol 40 (10) ◽  
pp. 716-722
Author(s):  
Yangjun (Kevin) Liu ◽  
Michelle Ellis ◽  
Mohamed El-Toukhy ◽  
Jonathan Hernandez
Keyword(s):  
Oil And Gas ◽  
Rock Physics ◽  
Clay Content ◽  
American Petroleum Institute ◽  
P Wave ◽  
Reservoir Rock ◽  
Gas Oil ◽  
Amplitude Variation With Offset ◽  
Fluid Properties ◽  
The Impact

We present a basin-wide rock-physics analysis of reservoir rocks and fluid properties in Campeche Basin. Reservoir data from discovery wells are analyzed in terms of their relationship between P-wave velocity, density, porosity, clay content, Poisson's ratio (PR), and P-impedance (IP). The fluid properties are computed by using in-situ pressure, temperature, American Petroleum Institute gravity, gas-oil ratio, and volume of gas, oil, and water. Oil- and gas-saturated reservoir sands show strong PR anomalies compared to modeled water sand at equivalent depth. This suggests that PR anomalies can be used as a direct hydrocarbon indicator in the Tertiary sands in Campeche Basin. However, false PR anomalies due to residual gas or oil exist and compose about 30% of the total anomalies. The impact of fluid properties on IP and PR is calibrated using more than 30 discovery wells. These calibrated relationships between fluid properties and PR can be used to guide or constrain amplitude variation with offset inversion for better pore fluid discrimination.

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.

Bayesian linearized rock-physics inversion

Geophysics ◽  
2016 ◽  
Vol 81 (6) ◽  
pp. D625-D641 ◽  
Author(s):  
Dario Grana
Keyword(s):  
Granular Media ◽  
Computational Cost ◽  
Rock Physics ◽  
Real Data ◽  
Data Sets ◽  
New Approach ◽  
Amplitude Variation With Offset ◽  
Fluid Properties ◽  
Rock Physics Modeling ◽  
Physics Modeling

The estimation of rock and fluid properties from seismic attributes is an inverse problem. Rock-physics modeling provides physical relations to link elastic and petrophysical variables. Most of these models are nonlinear; therefore, the inversion generally requires complex iterative optimization algorithms to estimate the reservoir model of petrophysical properties. We have developed a new approach based on the linearization of the rock-physics forward model using first-order Taylor series approximations. The mathematical method adopted for the inversion is the Bayesian approach previously applied successfully to amplitude variation with offset linearized inversion. We developed the analytical formulation of the linearized rock-physics relations for three different models: empirical, granular media, and inclusion models, and we derived the formulation of the Bayesian rock-physics inversion under Gaussian assumptions for the prior distribution of the model. The application of the inversion to real data sets delivers accurate results. The main advantage of this method is the small computational cost due to the analytical solution given by the linearization and the Bayesian Gaussian approach.

An Alternate Method to API RP 14E for Predicting Solids Erosion in Multiphase Flow

2000 ◽  
Vol 122 (3) ◽  
pp. 115-122 ◽  
Author(s):  
Brenton S. McLaury ◽  
Siamack A. Shirazi
Keyword(s):  
Multiphase Flow ◽  
Production Rate ◽  
Oil And Gas ◽  
Gas Production ◽  
American Petroleum Institute ◽  
Sand Production ◽  
Threshold Velocity ◽  
Oil And Gas Production ◽  
Sand Erosion ◽  
Fluid Properties

One commonly used method for determining oil and gas production velocities is to limit production rates based on the American Petroleum Institute Recommended Practice 14E (API RP 14E). This guideline contains an equation to calculate an “erosional” or a threshold velocity, presumably a flow velocity that is safe to operate. The equation only considers one factor, the density of the medium, and does not consider many other factors that can contribute to erosion in multiphase flow pipelines. Thus, factors such as fluid properties, flow geometry, type of metal, sand production rate and size distribution, and flow composition are not accounted for. In the present paper, a method is presented that has been developed with the goal of improving the procedure by accounting for many of the physical variables including fluid properties, sand production rate and size, and flowstream composition that affect sand erosion. The results from the model are compared with several experimental results provided in the literature. Additionally, the method is applied to calculate threshold flowstream velocities for sand erosion and the results are compared with API RP 14E. The results indicate that the form of the equation that is provided by the API RP 14E is not suitable for predicting a production flowstream velocity when sand is present. [S0195-0738(00)00203-X]

scholarly journals Characterization of a Reservoir Fluid Based on an Analysis of Intrinsic Properties Using the Adaptive Batzle-Wang Method in Field “M”

2019 ◽  
Vol 17 (2) ◽  
Author(s):  
M. Syamsu Rosid ◽  
Muhammad` Iksan ◽  
Reza Wardhana ◽  
M. Wahdanadi Haidar
Keyword(s):  
Physical Properties ◽  
Laboratory Experiments ◽  
Fluid Model ◽  
Rock Physics ◽  
P Wave ◽  
Fluid Replacement ◽  
Intrinsic Properties ◽  
Temperature Conditions ◽  
Reservoir Conditions ◽  
Fluid Properties

The physical properties and phases of a fluid under reservoir conditions are different from those under surface conditions. The value of a fluid property may change as a result of changes in pressure and temperature. An analysis of the intrinsic properties of fluids is carried out to obtain a fluid model that corresponds to fluid conditions in a reservoir. This study uses the Adaptive Batzle-Wang model, which combines thermodynamic relationships, empirical data trends, and experimental fluid data from the laboratory to estimate the effects of pressure and temperature on fluid properties. The Adaptive Batzle-Wang method is used because the usual Batzle-Wang method is less suitable for describing the physical properties of a fluid under the conditions in the field studied here. The Batzle-Wang fluid model therefore needs to be modified to obtain a fluid model that adjusts to the fluid conditions in each study area. In this paper, the Adaptive Batzle-Wang model is used to model three types of fluid i.e. oil, gas, and water. By making use of data on the intrinsic fluid properties such as the specific gravity of the gases (G), the Gas-Oil Ratio (GOR), the Oil FVF (Bo), the API values, the Salinity, and the Fluid Density obtained from laboratory experiments, the Batzle-Wang fluid model is converted into the Adaptive Batzle-Wang model by adding equations for the intrinsic fluid properties under the pressure and temperature conditions in the field reservoir. The results obtained are the values of the bulk modulus (K), the density (ρ), and the P-wave velocity (Vp) of the fluid under reservoir conditions. The correlation coefficient of the Adaptive Batzle-Wang model with the fluid data from the laboratory experiments is 0.95. The model is well able to calculate the fluid properties corresponding to the conditions in this field reservoir. The model also generates a unique value for the fluid properties in each study area. So, it can adjust to the pressure and temperature conditions of the field reservoir under study. The Adaptive Batzle-Wang method can therefore be applied to fields for which laboratory fluid data is available, especially fields with a high reservoir pressure and temperature. The results of the fluid modeling can then be used for rock physics and Fluid Replacement Model analysis.

scholarly journals Microcrack Porosity Estimation Based on Rock Physics Templates: A Case Study in Sichuan Basin, China

Energies ◽  
2021 ◽  
Vol 14 (21) ◽  
pp. 7225
Author(s):  
Chuantong Ruan ◽  
Jing Ba ◽  
José M. Carcione ◽  
Tiansheng Chen ◽  
Runfa He
Keyword(s):  
Sichuan Basin ◽  
Rock Physics ◽  
Wave Impedance ◽  
Gas Production ◽  
P Wave ◽  
Gas Reservoirs ◽  
Tight Sandstone ◽  
Amplitude Variation With Offset ◽  
Xujiahe Formation ◽  
Seismic Properties

Low porosity-permeability structures and microcracks, where gas is produced, are the main characteristics of tight sandstone gas reservoirs in the Sichuan Basin, China. In this work, an analysis of amplitude variation with offset (AVO) is performed. Based on the experimental and log data, sensitivity analysis is performed to sort out the rock physics attributes sensitive to microcrack and total porosities. The Biot–Rayleigh poroelasticity theory describes the complexity of the rock and yields the seismic properties, such as Poisson’s ratio and P-wave impedance, which are used to build rock-physics templates calibrated with ultrasonic data at varying effective pressures. The templates are then applied to seismic data of the Xujiahe formation to estimate the total and microcrack porosities, indicating that the results are consistent with actual gas production reports.

scholarly journals TIME-LAPSE POROSITY AND VELOCITY ANALYSIS USING ROCK PHYSICS MODELS IN NIGER DELTA, NIGERIA

2021 ◽  
Vol 5 (2) ◽  
pp. 47-52
Author(s):  
Emmanuel Aniwetalu ◽  
Akudo Ernest ◽  
Juliet Ilechukwu ◽  
Okechukwu Ikegwuonu ◽  
Uzochukwu Omoja
Keyword(s):  
Oil And Gas ◽  
Seismic Velocity ◽  
Water Saturation ◽  
Rock Physics ◽  
Time Lapse ◽  
Fluid Substitution ◽  
Average Value ◽  
Velocity Models ◽  
Fluid Properties ◽  
Average Water

The analysis of 3-D and time-lapse seismic data in Isomu Field has offered the dynamic characterization of the reservoir changes. The changes were analyzed using fluid substitution and seismic velocity models. The results of the initial porosity of the reservoirs was 29.50% with water saturation value of12%.The oil and gas maintained saturation values of 40% and 48% with average compressional and shear wave velocities of 2905m/s and 1634m/s respectfully. However, in fluid substitution modelling, the results reflect a change in fluid properties where average gas and oil saturation assume a new status of 34% and 24% which indicates a decrease by 14% and 16% respectively. The average water saturation increases by 30% with an average value of 42%. The decrease in hydrocarbon saturation and increase in formation water influence the porosity. Thus, porosity decreased by 4.16% which probably arose from the closure of the aspect ratio crack due to pressure increase.

A successful qualitative and quantitative integrated interpretation of Lower Miocene wells and seismic data in Salina del Istmo Basin, Mexico

2021 ◽  
Vol 40 (12) ◽  
pp. 897-904
Author(s):  
Manuel González-Quijano ◽  
Gregor Baechle ◽  
Miguel Yanez ◽  
Freddy Obregon ◽  
Carmen Vito ◽  
...  
Keyword(s):  
Seismic Data ◽  
Rock Physics ◽  
Reservoir Rock ◽  
Amplitude Variation With Offset ◽  
Volcanic Material ◽  
Qualitative And Quantitative ◽  
Rock Types ◽  
Deep Waters ◽  
Well Data ◽  
Gulf Of Mexico Basin

The study area is located in middepth to deep waters of the Salina del Istmo Basin where Repsol operates Block 29. The objective of this work is to integrate qualitative and quantitative interpretations of rock and seismic data to predict lithology and fluid of the Early Miocene prospects. The seismic expression of those prospects differs from age-equivalent well-studied analog fields in the U.S. Gulf of Mexico Basin due to the mineralogically complex composition of abundant extrusive volcanic material. Offset well data (i.e., core, logs, and cuttings) were used to discriminate lithology types and to quantify mineralogy. This analysis served as input for developing a new rock-physics framework and performing amplitude variation with offset (AVO) modeling. The results indicate that the combination of intercept and gradient makes it possible to discriminate hydrocarbon-filled (AVO class II and III) versus nonhydrocarbon-filled rocks (AVO class 0 and IV). Different lithologies within hydrocarbon-bearing reservoirs cannot be discriminated as the gradient remains negative for all rock types. However, AVO analysis allows discrimination of three different reservoir rock types in water-bearing cases (AVO class 0, I, and IV). These conclusions were obtained during studies conducted in 2018–2019 and were used in prospect evaluation to select drilling locations leading to two wildcat discoveries, the Polok and Chinwol prospects, drilled in Block 29 in 2020.

Sediments with gas hydrates: Internal structure from seismic AVO

Geophysics ◽  
1998 ◽  
Vol 63 (5) ◽  
pp. 1659-1669 ◽  
Author(s):  
Christine Ecker ◽  
Jack Dvorkin ◽  
Amos Nur
Keyword(s):  
Internal Structure ◽  
Wave Velocity ◽  
Seismic Data ◽  
Pore Space ◽  
Rock Physics ◽  
P Wave ◽  
S Wave ◽  
High Concentration ◽  
Amplitude Variation With Offset ◽  
Bottom Simulating Reflector

We interpret amplitude variation with offset (AVO) data from a bottom simulating reflector (BSR) offshore Florida by using rock‐physics‐based synthetic seismic models. A previously conducted velocity and AVO analysis of the in‐situ seismic data showed that the BSR separates hydrate‐bearing sediments from sediments containing free methane. The amplitude at the BSR are increasingly negative with increasing offset. This behavior was explained by P-wave velocity above the BSR being larger than that below the BSR, and S-wave velocity above the BSR being smaller than that below the BSR. We use these AVO and velocity results to infer the internal structure of the hydrated sediment. To do so, we examine two micromechanical models that correspond to the two extreme cases of hydrate deposition in the pore space: (1) the hydrate cements grain contacts and strongly reinforces the sediment, and (2) the hydrate is located away from grain contacts and does not affect the stiffness of the sediment frame. Only the second model can qualitatively reproduce the observed AVO response. Thus inferred internal structure of the hydrate‐bearing sediment means that (1) the sediment above the BSR is uncemented and, thereby, mechanically weak, and (2) its permeability is very low because the hydrate clogs large pore‐space conduits. The latter explains why free gas is trapped underneath the BSR. The seismic data also indicate the absence of strong reflections at the top of the hydrate layer. This fact suggests that the high concentration of hydrates in the sediment just above the BSR gradually decreases with decreasing depth. This effect is consistent with the fact that the low‐permeability hydrated sediments above the BSR prevent free methane from migrating upwards.

scholarly journals Effect of Arenite, Calcareous, Argillaceous, and Ferruginous Sandstone Cuttings on Filter Cake and Drilling Fluid Properties in Horizontal Wells

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-10 ◽  
Author(s):  
Badr S. Bageri ◽  
Mohammed Benaafi ◽  
Mohamed Mahmoud ◽  
Shirish Patil ◽  
Abdelmjeed Mohamed ◽  
...  
Keyword(s):  
Filter Cake ◽  
Drilling Fluid ◽  
Clay Content ◽  
Point Of View ◽  
Fluid Loss ◽  
X Ray ◽  
Fluid Properties ◽  
Porosity And Permeability ◽  
Sandstone Formation ◽  
The Impact

Fine, small-size, drilled cuttings, if not properly separated using mud conditioning equipment at the surface, are circulated with the drilling fluid from the surface to the bottom hole. These drilled cuttings have a significant effect on the drilling fluid properties and filter cake structure. During drilling long lateral sandstone formations, different cuttings with varied properties will be generated due to sandstone formations being heterogeneous and having different mineralogical compositions. Thus, the impact of these cuttings on the drilling fluid and filter cake properties will be different based on their mineralogy. In this paper, the effect of different sandstone formation cuttings, including arenite (quartz rich), calcareous (calcite rich), argillaceous (clay rich), and ferruginous (iron rich) sandstones, on the filter cake and drilling fluid properties was investigated. Cuttings of the mentioned sandstone formations were mixed with the drilling fluid to address the effect of these minerals on the filter cake thickness, porosity, and permeability. In addition, the effect of different sandstone formation cuttings on drilling fluid density and rheology, apparent viscosity (AV), plastic viscosity PV), and yield point (YP) was investigated. High-pressure high-temperature (HPHT) fluid loss test was conducted to form the filter cake. The core sample’s petrophysical properties were determined using X-ray fluorescence (XRF) and X-ray diffraction (XRD) techniques and scanning electron microscopy (SEM). The results of this work indicated that all cutting types increased the rheological properties when added to the drilling fluid at the same loadings but the argillaceous sandstone (clay rich) has a dominant effect compared to the other types because the higher clay content enhanced the rheology. From the filter cake point of view, the ferruginous sandstone improved the filter cake sealing properties and reduced its thickness, while the argillaceous cuttings degraded the filter cake porosity and permeability and allowed the finer cuttings to penetrate deeply in the filter medium.

Estimation of microfracture porosity in deep carbonate reservoirs based on 3D rock-physics templates

2020 ◽  
Vol 8 (4) ◽  
pp. SP43-SP52
Author(s):  
Mengqiang Pang ◽  
Jing Ba ◽  
Li-Yun Fu ◽  
José M. Carcione ◽  
Uti I. Markus ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Velocity Ratio ◽  
Rock Physics ◽  
Total Porosity ◽  
Spectral Ratio ◽  
Wave Impedance ◽  
Seismic Attenuation ◽  
Carbonate Reservoirs ◽  
P Wave ◽  
Ratio Method

Carbonate reservoirs in the S area of the Tarim Basin (China) are ultradeep hydrocarbon resources, with low porosity, complex fracture systems, and dissolved pores. Microfracturing is a key factor of reservoir connectivity and storage space. We have performed measurements on limestone samples, under different confining pressures, and we used the self-consistent approximation model and the Biot-Rayleigh theory of double porosity to study the microfractures. We have computed the fluid properties (mainly oil) as a function of temperature and pressure. Using the dependence of seismic [Formula: see text] on the microfractures, a multiscale 3D rock-physics template (RPT) is built, based on the attenuation, P-wave impedance, and phase velocity ratio. We estimate the ultrasonic and seismic attenuation with the spectral-ratio method and the improved frequency-shift method, respectively. Then, calibration of the RPTs is performed at ultrasonic and seismic frequencies. We use the RPTs to estimate the total and microfracture porosities. The results indicate that the total porosity is low and the microfracture porosity is relatively high, which is consistent with the well log data and actual oil production reports. This work presents a method for identification of deep carbonate reservoirs by using the microfracture porosity estimated from the 3D RPT, which could be exploited in oil and gas exploration.

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