Multiattribute rotation scheme: A tool for reservoir property prediction from seismic inversion attributes

2015 ◽  
Vol 3 (4) ◽  
pp. SAE9-SAE18 ◽  
Author(s):  
Pedro Alvarez ◽  
Francisco Bolívar ◽  
Mario Di Luca ◽  
Trino Salinas
Keyword(s):  
Reservoir Characterization ◽  
Barents Sea ◽  
Water Saturation ◽  
Total Porosity ◽  
Seismic Inversion ◽  
Dimensional Euclidean Space ◽  
Petrophysical Properties ◽  
Reserve Estimation ◽  
Reservoir Property ◽  
Rotation Scheme

The multiattribute rotation scheme (MARS) is a methodology that uses a numerical solution to estimate a transform to predict petrophysical properties from elastic attributes. This is achieved by estimating a new attribute in the direction of maximum change of a target property in an [Formula: see text]-dimensional Euclidean space formed by an [Formula: see text] number of attributes and subsequent scaling of this attribute to the target unit properties. We have computed the transform from well-log-derived elastic attributes and petrophysical properties, and we have posteriorly applied it to seismically derived elastic attributes. Such transforms can be used to estimate reservoir property volumes for reservoir characterization and delineation in exploration and production settings and to estimate secondary variables in geostatistical workflows for static model generation and reserve estimation. To illustrate the methodology, we applied MARS to estimate a transform to predict the water saturation and total porosity from elastic attributes in a well located in the Barents Sea as well as to estimate a water-saturation volume in a mud-rich turbidite gas reservoir located onshore Colombia.

Modeling dolomitized carbonate‐ramp reservoirs: A case study of the Seminole San Andres unit—Part I, Petrophysical and geologic characterizations

Geophysics ◽  
1998 ◽  
Vol 63 (6) ◽  
pp. 1866-1875 ◽  
Author(s):  
Fred P. Wang ◽  
F. Jerry Lucia ◽  
Charles Kerans
Keyword(s):  
Reservoir Simulation ◽  
High Frequency ◽  
Reservoir Characterization ◽  
Water Saturation ◽  
Total Porosity ◽  
Carbonate Ramp ◽  
Petrophysical Properties ◽  
Rock Fabric ◽  
Wireline Logs ◽  
San Andres

Major issues in characterizing carbonate‐ramp reservoirs include geologic framework, seismic stratigraphy, interwell heterogeneity including rock fabric facies and permeability structure, and factors affecting petrophysical properties and reservoir simulation. The Seminole San Andres unit, Gaines County, West Texas, and the San Andres outcrop of Permian age in the Guadalupe Mountains, New Mexico, were selected for an integrated reservoir characterization to address these issues. The paper is divided into two parts. Part I covers petrophysical and geologic characterization, and part II describes seismic modeling, reservoir geostatistics, stochastic modeling, and reservoir simulation. In dolomitic carbonates, two major pore types are interparticle (includes intergranular and intercrystalline) and vuggy. For nonvuggy carbonates the three important petrophysical/rock fabric classes are (I) grainstone, (II) grain‐dominated packstone and medium crystalline dolostone, and (III) mud‐dominated packstone, wackestone, mudstone, and fine crystalline dolostone. Core data from Seminole showed that rock fabric and pore type have strong positive correlations with absolute and relative permeabilities, residual oil saturation, waterflood recovery, acoustic velocity, and Archie cementation exponent. Petrophysical models were developed to estimate total porosity, separate‐vug porosity, permeability, and Archie cementation exponent from wireline logs to account for effects of rock fabric and separate‐vug porosity. The detailed and regional stratigraphic models were established from outcrop analogs and applied to seismic interpretation and wireline logs and cores. The aggradational seismic character of the San Andres Formation at Seminole is consistent with the cycle stacking pattern within the reservoir. In particular, the frequent preservation of cycle‐based mudstone units in the Seminole San Andres unit is taken to indicate high accommodation associated with greater subsidence rates in this region. A model for the style of high‐frequency cyclicity and the distribution of rock‐fabric facies within cycles was developed using continuous outcrop exposures at Lawyer Canyon. This outcrop model was applied during detailed core descriptions. These, together with detailed analysis of wireline log signatures, allowed construction of the reservoir framework based on genetically and petrophysically significant high‐frequency cycles. Petrophysical properties of total and separate‐vug porosities, permeability, water saturation, and rock fabrics were calculated from wireline log data. High‐frequency cycles and rock‐fabric units are the two critical scales for modeling carbonate‐ramp reservoirs. Descriptions of rock‐fabric facies stacked within high‐frequency cycles provide the most accurate framework for constructing geologic and reservoir models. This is because petrophysical properties can be better grouped by rock fabrics than depositional facies. The permeability‐thickness ratios among these rock fabric units can then be used to approximate fluid flow and recovery efficiency.

scholarly journals An Integrated Microfacies and Well Logs-Based Reservoir Characterization of Yamama Formation, Southern Iraq

2021 ◽  
pp. 3570-3586
Author(s):  
Mohanad M. Al-Ghuribawi ◽  
Rasha F. Faisal
Keyword(s):  
Reservoir Characterization ◽  
Water Saturation ◽  
Effective Porosity ◽  
Well Logs ◽  
Petrophysical Properties ◽  
Reservoir Properties ◽  
Thin Sections ◽  
Porosity And Permeability ◽  
South Of Iraq ◽  
Southern Iraq

     The Yamama Formation includes important carbonates reservoir that belongs to the Lower Cretaceous sequence in Southern Iraq. This study covers two oil fields (Sindbad and Siba) that are distributed Southeastern Basrah Governorate, South of Iraq. Yamama reservoir units were determined based on the study of cores, well logs, and petrographic examination of thin sections that required a detailed integration of geological data and petrophysical properties. These parameters were integrated in order to divide the Yamama Formation into six reservoir units (YA0, YA1, YA2, YB1, YB2 and YC), located between five cap rock units. The best facies association and petrophysical properties were found in the shoal environment, where the most common porosity types were the primary (interparticle) and secondary (moldic and vugs) . The main diagenetic process that occurred in YA0, YA2, and YB1 is cementation, which led to the filling of pore spaces by cement and subsequently decreased the reservoir quality (porosity and permeability). Based on the results of the final digital  computer interpretation and processing (CPI) performed by using the Techlog software, the units YA1 and YB2 have the best reservoir properties. The unit YB2 is characterized by a good effective porosity average, low water saturation, good permeability, and large thickness that distinguish it from other reservoir units.

scholarly journals Characterization of Mishrif Formation Reservoir in Amara Oil Field, Southeast Iraq, Using Geophysical Well-logging

2021 ◽  
pp. 4702-4711
Author(s):  
Asmaa Talal Fadel ◽  
Madhat E. Nasser
Keyword(s):  
Reservoir Characterization ◽  
Gamma Ray ◽  
Water Saturation ◽  
Total Porosity ◽  
Effective Porosity ◽  
Oil Field ◽  
Neutron Density ◽  
Reservoir Water ◽  
Resistivity Logs ◽  
Reliable Knowledge

     Reservoir characterization requires reliable knowledge of certain fundamental properties of the reservoir. These properties can be defined or at least inferred by log measurements, including porosity, resistivity, volume of shale, lithology, water saturation, and permeability of oil or gas. The current research is an estimate of the reservoir characteristics of Mishrif Formation in Amara Oil Field, particularly well AM-1, in south eastern Iraq. Mishrif Formation (Cenomanin-Early Touronin) is considered as the prime reservoir in Amara Oil Field. The Formation is divided into three reservoir units (MA, MB, MC). The unit MB is divided into two secondary units (MB1, MB2) while the unit MC is also divided into two secondary units (MC1, MC2). Using Geoframe software, the available well log images (sonic, density, neutron, gamma ray, spontaneous potential, and resistivity logs) were digitized and updated. Petrophysical properties, such as porosity, saturation of water, saturation of hydrocarbon, etc. were calculated and explained. The total porosity was measured using the density and neutron log, and then corrected to measure the effective porosity by the volume content of clay. Neutron -density cross-plot showed that Mishrif Formation lithology consists predominantly of limestone. The reservoir water resistivity (Rw) values of the Formation were calculated using Pickett-Plot method.   

scholarly journals Petrophysical Properties and Well Log Interpretations of Tertiary Reservoir in Khabaz Oil Field / Northern Iraq

2020 ◽  
Vol 26 (6) ◽  
pp. 18-34
Author(s):  
Yousif Najeeb Abdul-majeed ◽  
Ahmad Abdullah Ramadhan ◽  
Ahmed Jubiar Mahmood
Keyword(s):  
Water Saturation ◽  
Total Porosity ◽  
Effective Porosity ◽  
Oil Field ◽  
Neutron Density ◽  
Petrophysical Properties ◽  
Secondary Porosity ◽  
Northern Iraq ◽  
Sonic Log ◽  
Oil Concentration

The aim of this study is interpretation well logs to determine Petrophysical properties of tertiary reservoir in Khabaz oil field using IP software (V.3.5). The study consisted of seven wells which distributed in Khabaz oilfield. Tertiary reservoir composed from mainly several reservoir units. These units are : Jeribe, Unit (A), Unit (A'), Unit (B), Unit (BE), Unit (E),the Unit (B) considers best reservoir unit because it has good Petrophysical properties (low water saturation and high porous media ) with high existence of hydrocarbon in this unit. Several well logging tools such as Neutron, Density, and Sonic log were used to identify total porosity, secondary porosity, and effective porosity in tertiary reservoir. For Lithological identification for tertiary reservoir units using (NPHI-RHOB) cross plot composed of dolomitic-limestone and mineralogical identification using (M/N) cross plot consist of calcite and dolomite. Shale content was estimated less than (8%) for all wells in Khabaz field. CPI results were applied for all wells in Khabaz field which be clarified movable oil concentration in specific units are: Unit (B), Unit (A') , small interval of Jeribe formation , and upper part of Unit (EB).

Integrated reservoir characterization of a Utica Shale field

2018 ◽  
Vol 37 (9) ◽  
pp. 656-661
Author(s):  
Jinming Zhu
Keyword(s):  
Seismic Data ◽  
Reservoir Characterization ◽  
Water Saturation ◽  
Clay Content ◽  
Seismic Inversion ◽  
Data Set ◽  
Utica Shale ◽  
Multidisciplinary Study ◽  
3D Seismic Data

We performed an integrated multidisciplinary study for reservoir characterization of a Utica Shale field in eastern Ohio covered by a multiclient 3D seismic data set acquired in 2015. Elastic seismic inversion was performed in-house for effective reservoir characterization of the Utica Shale, which covers the interval from the top of Upper Utica (UUTIC) to the top of Trenton Limestone. Accurate, high-fidelity inversion results were obtained, including acoustic impedance, shear impedance, density, and VP/VS. These consistent inversion results allow for the reliable calculation of geomechanical and petrophysical properties of the reservoir. The inverted density clearly divides the Point Pleasant (PPLS) interval as low density from the overlying UUTIC Shale interval. Both Poisson's ratio (PR) and brittleness unmistakably separate the underlying PPLS from the overlying Utica interval. The PPLS Formation is easier to hydraulically fracture due to its much lower PR. Sequence S4 is the best due to its higher Young's modulus to sustain the open fractures. The calculated petrophysical volumes indisputably delineate the traditional Utica Shale into two distinctive sections. The upper section, the UUTIC, can be described as having 1%–2% total organic carbon (TOC), 3.5%–4.8% porosity, 10%–24% water saturation, and 40%–58% clay content. The lower section, PPLS, can be described as having 3%–4.5% TOC, 5%–9% porosity, 2%–10% water saturation, and about 15%–35% clay content. Both sections exhibit spatial variation of the properties. Nevertheless, the underlying PPLS is obviously a significantly better reservoir and operationally easier to produce.

Integrated reservoir characterization of a Utica Shale with focus on sweet spot discrimination

2020 ◽  
Vol 8 (3) ◽  
pp. SM1-SM14
Author(s):  
Jinming Zhu
Keyword(s):  
Reservoir Characterization ◽  
Water Saturation ◽  
Clay Content ◽  
Seismic Inversion ◽  
Reservoir Properties ◽  
Geomechanical Properties ◽  
Utica Shale ◽  
Characterization Study ◽  
Separate Point

Multiclient 3D seismic data were acquired in 2015 in eastern Ohio for reservoir characterization of the Utica Shale consisting of the Utica and Point Pleasant Formations. I attained accurate, high-fidelity acoustic impedance, shear impedance, density, and [Formula: see text], from elastic inversion. These accurate inversion results allow consistent calculation of reservoir and geomechanical properties of the Utica Shale. I found density critically important affecting the accuracy of other reservoir and geomechanical properties. More than a dozen properties in geologic, geomechanical, and reservoir categories were acquired from logs, cores, and seismic inversion, for this integrated reservoir characterization study. These properties include buried depth, formation thickness, mineralogy, density, Young’s modulus, Poisson’s ratio (PR), brittleness, total organic carbon (TOC), porosity, water saturation, permeability, clay content, and natural fractures. A ternary diagram of core samples from 18 wells demonstrates that the Point Pleasant is dominant with calcite, whereas the Utica mainly contains clay. Inverted density clearly divides Point Pleasant as low density from the overlying Utica. Calculated reservoir properties undoubtedly delineate the traditional Utica Shale as two distinctive formations. I calculated that the Utica Formation contains 1%–2% TOC, 3.5%–4.8% porosity, 10%–24% water saturation, and 40%–58% clay content, whereas Point Pleasant contains 3%–4.5% TOC, 5%–9% porosity, 2%–10% water saturation, and 15%–35% clay content. The PR and brittleness clearly separate Point Pleasant from the overlying Utica, with a lower PR and a higher brittleness index in Point Pleasant than in Utica. The higher brittleness in Point Pleasant makes it easier to frac, leading to enhanced permeability. Both formations exhibit spatial variations of reservoir and geomechanical properties. Nevertheless, the underlying Point Pleasant is obviously better than the Utica Shale with favorable reservoir and geomechanical properties for optimal development and production, although Utica is thicker and shallower. The central and southeastern portions of Point Pleasant have the sweetest reservoirs.

scholarly journals A Comparison of Mishrif Formation Characteristics in Kumait and Dujaila Oil Fields, Southern Iraq, Using Seismic Inversion Method and Petrophysical Properties Analysis

2020 ◽  
pp. 3294-3307
Author(s):  
Ahmed S. Al-Banna ◽  
Nowfal A. Nassir ◽  
Ghazi H. Al-Sharaa
Keyword(s):  
Acoustic Impedance ◽  
Water Saturation ◽  
Water Reservoir ◽  
Seismic Inversion ◽  
Effective Porosity ◽  
Oil Fields ◽  
Inversion Method ◽  
Oil Reservoir ◽  
Petrophysical Properties ◽  
Southern Iraq

A comparison was conducted between two wells, Kt-1and Kt-2, in Kumait and two wells, Du-1and Du-2, in Dujaila oil fields that belong to Mishrif formation, southern Iraq.  Seismic inversion method was employed to detect oil and water reservoirs. The comparison included the behavior of acoustic impedance (AI) of fluids and the lithology with related petrophysical properties. The values of water saturation, Shale volume (Vsh), and effective porosity were compared between the AI,  two fluid reservoirs. It was found that the AI value for the oil reservoir unit is relatively low to medium, whereas it was relatively medium for the water reservoir. Effective porosity value showed, in general, an increase in the oil reservoir and a slightly decrease in the water reservoir. The Vsh and water saturation (Sw) values of the oil reservoir unit were in general lower than those in the water reservoir, which indicates the presence of hydrocarbons accumulation. The lithology and porosity are the main factors affecting the acoustic impedance values. Despite the small difference in density between oil and water, these two fluids still show perceptible variation in their properties.  

Rock Property Cross-Plot Analysis and Post-Stack Acoustic Impedance Inversion for Optimal Reservoir Characterization in Aplha Field, Onshore Niger Delta Basin

2021 ◽  
Author(s):  
George-Best Azuoko ◽  
Amobi Ekwe ◽  
Amulu Emmanuel ◽  
Ayatu Usman ◽  
Eluwa Ndidiamaka ◽  
...  
Keyword(s):  
Acoustic Impedance ◽  
Reservoir Characterization ◽  
Water Saturation ◽  
Seismic Inversion ◽  
Hydrocarbon Reservoirs ◽  
Event Time ◽  
Plot Analysis ◽  
Impedance Inversion ◽  
Acoustic Impedance Inversion ◽  
Niger Delta Basin

Abstract In the quest to recover by-passed hydrocarbons, extend the life of mature fields, increase hydrocarbon reserves and satiate the increasing global demand for energy, the need for robust reservoir characterization using acoustic impedance inversion continues to grow. In this study, petrophysical parameters were evaluated for two sand intervals RX2 and RX5. Detailed cross-plot analysis of robust petrophysical properties, (density, water Saturation, Lambda-rho and Mu-rho and Porosity) facilitated fluid and lithology discrimination. Well to seismic correlations and acoustic-Impedance model-based, 3-D seismic inversion was done using Hampson Russell software, while petrophysical attribute slices and event-time structure maps were extracted at two horizons - H1 and H2. Results show that RX2 is 100ft thick in Well A, ranging from 5860ft to 5960ft, and 141ft thick in Well B, ranging from 5794ft to 5935ft. Interval RX5, 71ft thick, ranges from 6447ft to 6518ft in Well A, and 88ft thick in Well B, ranging from 6447ft to 6535ft. These intervals had average densities of 2.20g/cc for RX2 and 2.23g/cc for RX5 in Well A. In well B, density values are 1.95g/cc in RX2 and 2.06g/cc for RX5. Average porosities of 25.5% and 27.5% in RX2 and RX5 respectively for Well A; 29% and 19% in RX2 and RX5 respectively for Well B were observed. Respectively, average water and hydrocarbon saturation values of 0.31Swand 0.69Shfor Well A; 0.51Swand 0.49Shfor Well B, was recorded in both intervals. From the results, the thicknesses of RX2 and RX5 conform to the standard thickness of hydrocarbon reservoirs in the study area. Furthermore, the discrimination of the reservoir contents into fluid and lithology by the cross plots, and the observations in the attribute slices indicate that the selected intervals RX2 and RX5 are viable conventional hydrocarbon reservoirs.

scholarly journals Petrophysical interpretation in shaly sand formation of a gas field in Tanzania

2019 ◽  
Vol 10 (3) ◽  
pp. 1201-1213
Author(s):  
Oras Joseph Mkinga ◽  
Erik Skogen ◽  
Jon Kleppe
Keyword(s):  
Volume Fraction ◽  
Water Saturation ◽  
Total Porosity ◽  
Published Data ◽  
Petrophysical Properties ◽  
Production Forecast ◽  
Sand Fraction ◽  
Gas Field ◽  
Shale Volume ◽  
Shaly Sand

AbstractAn onshore gas field (hereafter called the R field—real name not revealed) is in the southeast coast of Tanzania which includes a Tertiary aged shaly sand formation (sand–shale sequences). The formation was penetrated by an exploration well R–X wherein no core was acquired, and there is no layer-wise published data of the petrophysical properties of the R field in the existing literature, which are essential to reserves estimation and production forecast. In this paper, the layer-wise interpretation of petrophysical properties was undertaken by using wireline logs to obtain parameters to build a reservoir simulation model. The properties extracted include shale volume, total and effective porosities, sand fractions and sand porosity, and water saturation. Shale volume was computed using Clavier equation from gamma ray. Density method was used to calculate total and effective porosities. Thomas–Stieber method was used to determine sand porosity and sand fraction, and water saturation was computed using Poupon–Leveaux model. The statistics of the parameters extracted are presented, where shale volume obtained that varies with zones is between 6 and 54% volume fraction, with both shale laminations and dispersed shale were identified. Total porosity obtained is in a range from 12 to 22%. Sand porosity varies between 15 and 25%, and sand fraction varies between 33 and 93% height fraction. Average water saturation obtained is between 32 and 49% volume fraction.

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