scholarly journals Sandstone reservoir characteristics of Rio Del Rey basin, Cameroon, using well-logging analysis

2021 ◽  
Author(s):  
Janvier Domra Kana ◽  
Ahmad Diab Ahmad ◽  
Daniel Hervé Gouet ◽  
Xavier Djimhoudouel ◽  
Serge Parfait Koah Na Lebogo
Keyword(s):  
Oil And Gas ◽  
Gamma Ray ◽  
Water Saturation ◽  
Effective Porosity ◽  
High Resistivity ◽  
Neutron Density ◽  
Oil And Gas Exploration ◽  
Hydrocarbon Reservoir ◽  
Offshore Oil And Gas ◽  
Cloud Of Points

AbstractThe present work deals with an interpretation of well log data (gamma ray (GR), resistivity, density, and neutron) from four wells, namely P-1, P-2, P-3 and P-4 in the study area of the Rio Del Rey basin. The well logs analysis indicates five potential sandstone reservoirs at the P-1, two at the P-2, four at the P-3 and six at the P-4. The neutron–density-GR logs highlight the sandstone gas reservoir characterized by high resistivity and crossover between neutron density. The neutron–density-GR cross-plot confirms the presence of sandstone containing hydrocarbons by a displacement of the cloud of points, from low to medium GR values, from the sandstone line to the left. Petrophysical parameters exhibit the value 12–41% for a volume of shale, 15–34% for effective porosity, 29–278 mD for permeability and 3–63% for water saturation. The three potential hydrocarbon reservoir saturation ranges from 22 to 45%. The study will contribute to future offshore oil and gas exploration and development in the Rio Del Rey basin, based on the geological and geophysical characteristics of the reservoirs delineated.

scholarly journals Hydrocarbon Reservoir Characterization of ‘Khume’ Field, Offshore Niger Delta, Nigeria

2021 ◽  
pp. 47-60
Author(s):  
K. A. Obakhume ◽  
O. M. Ekeng ◽  
C. Atuanya
Keyword(s):  
Niger Delta ◽  
Reservoir Characterization ◽  
Gamma Ray ◽  
Water Saturation ◽  
Seismic Interpretation ◽  
Effective Porosity ◽  
Well Logs ◽  
Integrative Approach ◽  
Neutron Density ◽  
Hydrocarbon Reservoir

The integrative approach of well log correlation and seismic interpretation was adopted in this study to adequately characterize and evaluate the hydrocarbon potentials of Khume field, offshore Niger Delta, Nigeria. 3-D seismic data and well logs data from ten (10) wells were utilized to delineate the geometry of the reservoirs in Khume field, and as well as to estimate the hydrocarbon reserves. Three hydrocarbon-bearing reservoirs of interest (D-04, D-06, and E-09A) were delineated using an array of gamma-ray logs, resistivity log, and neutron/density log suites. Stratigraphic interpretation of the lithologies in Khume field showed considerable uniform gross thickness across all three sand bodies. Results of petrophysical evaluations conducted on the three reservoirs correlated across the field showed that; shale volume ranged from 7-14%, total and effective porosity ranged from 19-26% and 17-23% respectively, NTG from 42 to 100%, water saturation from 40%-100% and permeability from 1265-2102 mD. Seismic interpretation established the presence of both synthetic and antithetic faults. A total of six synthetic and four antithetic faults were interpreted from the study area. Horizons interpretation was done both in the strike and dip directions. Time and depth structure maps revealed reservoir closures to be anticlinal and fault supported in the field. Hydrocarbon volumes were calculated using the deterministic (map-based) approach. Stock tank oil initially in place (STOIIP) for the proven oil column estimated for the D-04 reservoir was 11.13 MMSTB, 0.54 MMSTB for D-06, and 2.16 MMSTB for E-09A reservoir. For the possible oil reserves, a STOIIP value of 7.28 MMSTB was estimated for D-06 and 6.30 MMSTB for E-09A reservoir, while a hydrocarbon initially in place (HIIP) of 4.13 MMSTB of oil equivalents was derived for the undefined fluid (oil/gas) in D-06 reservoir. A proven gas reserve of 1.07 MMSCF was derived for the D-06 reservoir. This study demonstrated the effectiveness of 3-D seismic and well logs data in delineating reservoir structural architecture and in estimating hydrocarbon volumes

scholarly journals Petrophysical Properties and Digenetic Evolution of Shuaiba Formation in Nasiriyah Oil Field, Southern Iraq

2021 ◽  
pp. 4810-4818
Author(s):  
Marwah H. Khudhair
Keyword(s):  
Gamma Ray ◽  
Water Saturation ◽  
Middle Part ◽  
Effective Porosity ◽  
Oil Field ◽  
Neutron Density ◽  
Petrophysical Properties ◽  
Secondary Porosity ◽  
Primary Porosity ◽  
Gamma Ray Log

     Shuaiba Formation is a carbonate succession deposited within Aptian Sequences. This research deals with the petrophysical and reservoir characterizations characteristics of the interval of interest in five wells of the Nasiriyah oil field. The petrophysical properties were determined by using different types of well logs, such as electric logs (LLS, LLD, MFSL), porosity logs (neutron, density, sonic), as well as gamma ray log. The studied sequence was mostly affected by dolomitization, which changed the lithology of the formation to dolostone and enhanced the secondary porosity that replaced the primary porosity. Depending on gamma ray log response and the shale volume, the formation is classified into three zones. These zones are A, B, and C, each can be split into three rock intervals in respect to the bulk porosity measurements. The resulted porosity intervals are: (I) High to medium effective porosity, (II) High to medium inactive porosity, and (III) Low or non-porosity intervals. In relevance to porosity, resistivity, and water saturation points of view, there are two main reservoir horizon intervals within Shuaiba Formation. Both horizons appear in the middle part of the formation, being located within the wells Ns-1, 2, and 3. These intervals are attributed to high to medium effective porosity, low shale content, and high values of the deep resistivity logs. The second horizon appears clearly in Ns-2 well only.

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 WELL LOGS ANALYSIS TO ESTIMATE THE PARAMETERS OF SAWAN-2 AND SAWAN-3 GAS FIELD

2020 ◽  
Vol 5 (2) ◽  
pp. 69-75
Author(s):  
Raja Asim Zeb ◽  
Muhammad Haziq Khan ◽  
Intikhab Alam ◽  
Ahtisham Khalid ◽  
Muhammad Faisal Younas
Keyword(s):  
Physical Properties ◽  
Oil And Gas ◽  
Water Saturation ◽  
Total Porosity ◽  
Effective Porosity ◽  
Indus Basin ◽  
Log Analysis ◽  
Neutron Density ◽  
Gas Field ◽  
Lower Goru Formation

The lower Indus basin is leading hydrocarbon carriage sedimentary basin in Pakistan. Evaluation of two sorts out wells namely Sawan-2 and Sawan-3 has been assumed in this work for estimation and dispensation of petro physical framework using well log data. The systematic formation assessment by using petro physical studies and neutron density cross plots reveal that lithofacies mainly composed of sandstone. The hydrocarbon capability of the formation zone have been mark through several isometric maps such as water saturation, picket plots, cross plots, log analysis Phie vs depth and composite log analysis. The estimated petro physical properties shows that reservoir have volume of shale 6.1% and 14.0%, total porosity is observed between 14.6% and 18.2%, effective porosity ranges 12.5-16.5%, water saturation exhibits between 14.05% and 31.58%, hydrocarbon saturation ranges 68.42% -86.9%, The lithology of lower goru formation is dominated by very fine to fine and silty sandstone. The study method can be use within the vicinity of central Indus basin and similar basin elsewhere in the globe to quantify petro physical properties of oil and gas wells and comprehend the reservoir potential.

scholarly journals Shale volume and porosity delineation of coast swamp depobelt in Niger delta region, Nigeria, using well log

2019 ◽  
Vol 7 (2) ◽  
pp. 142
Author(s):  
Ubong Essien
Keyword(s):  
Niger Delta ◽  
Gamma Ray ◽  
Water Saturation ◽  
Effective Porosity ◽  
Neutron Density ◽  
Well Log ◽  
Shale Formations ◽  
Log Data ◽  
Shale Volume ◽  
Niger Delta Region

Well log data from two wells were evaluated for shale volume, total and effective porosity. Well log data were obtained from gamma ray, neutron-density log, resistivity, sonic and caliper log respectively. This study aimed at evaluating the effect of shale volume, total and effective porosity form two well log data. The results of the analysis depict the presence of sand, sand-shale and shale formations. Hydrocarbon accumulation were found to be high in sand, fair in sand-shale and low in shale, since existence of shale reduces total and effective porosity and water saturation of the reservoir. The thickness of the reservoir ranged from 66 – 248.5ft. The average values of volume of shale, total and effective porosity values ranged from 0.004 – 0.299dec, 0.178 – 0.207dec and 0.154 – 0.194dec. Similarly, the water saturation and permeability ranged from 0.277 – 0.447dec and 36.637 - 7808.519md respectively. These values of total and effective porosity are high in sand, fair in sand-shale and low in shale formations. The results for this study demonstrate: accuracy, applicability of these approaches and enhance the proper evaluation of petrophysical parameters from well log data.    

scholarly journals ANALISIS PETROFISIKA UNTUK MENENTUKAN OIL-WATER CONTACT PADA FORMASI TALANGAKAR, LAPANGAN “FBT”, CEKUNGAN SUMATRA SELATAN

2020 ◽  
Vol 5 (1) ◽  
pp. 15-29
Author(s):  
Febrina Bunga Tarigan ◽  
Ordas Dewanto ◽  
Karyanto Karyanto ◽  
Rahmat Catur Wibowo ◽  
Andika Widyasari
Keyword(s):  
Gamma Ray ◽  
Water Saturation ◽  
Effective Porosity ◽  
Neutron Density ◽  
Water Contact ◽  
Core Data ◽  
Petrophysical Property ◽  
Reservoir Conditions ◽  
Oil Water ◽  
Well Data

In conducting petrophysics analysis, there are many methods on each property. Therefore, it is necessary to determine the exact method on each petrophysical property suitable for application in the field of research in order to avoid irregularities at the time of interpretation. The petrophysical property consists of volume shale, porosity, water saturation, etc. This research used six well data named FBT01, FBT02, FBT03, FBT04, FBT05, and FBT06 and also assisted with core data contained in FBT03. Core data used as a reference in petrophysical analysis because it was considered to have represented or closed to the actual reservoir conditions in the field. The area in this research was in Talangakar Formation, "FBT" Field, South Sumatra Basin. The most suited volume shale method for “FBT” field condition was gamma ray-neutron-density method by seeing its photo core and lithology. As for the effective porosity, the most suited method for the field was neutron-density-sonic method by its core. Oil-water contact was useful to determine the hydrocarbon reserves. Oil-water contact was obtained at a depth of 2277.5 feet on FBT01, 2226.5 feet on FBT02, 2312.5 feet on FBT03, 2331 feet on FBT04, 2296 feet on FBT05, and 2283.5 feet on FBT06. The oil-water contact depth differences at Talangakar formation in FBT field caused by structure in subsurface.

A Revised Gassmann Fluid Replacement Model Based on Neutron-Density Logs in Shaly Sandstone Reservoirs

2021 ◽  
pp. 1-13
Author(s):  
Shantanu Chakraborty ◽  
Samit Mondal ◽  
Rima Chatterjee
Keyword(s):  
Oil And Gas ◽  
Reservoir Characterization ◽  
Rock Physics ◽  
Oil And Gas Industry ◽  
Effective Porosity ◽  
Fluid Replacement ◽  
Neutron Density ◽  
Gas Industry ◽  
Sandstone Reservoirs ◽  
Shaly Sandstone

Summary Fluid-replacement modeling (FRM) is a fundamental step in rock physics scenario modeling. The results help to conduct forward modeling for prediction of seismic signatures. Further, the analysis of the results improves the accuracy of quantitative interpretation and leads to an updated reservoir characterization. While modeling for different possible reservoir pore fluid scenarios, the quality of the results largely depends on the accuracy of the FRM. Gassmann (1951)fluid-replacement modeling (GFRM) is one of the widely adopted methods across the oil and gas industry. However, the Gassmann method assumes the reservoir as clean sandstone with connected pores. This causes Gassmann fluid-replacement results to overestimate the fluid effect in shaly sandstones. This study uses neutron and density logs to correct the overestimated results in shaly sandstone reservoirs. Due to the nature of these recordings, both of these log readings have close dependencies on the presence of shale. When the logs are plotted in a justified scale, the differences between the logs provide an accurate measurement of shaliness within the reservoir. The study has formulated a weight factor using the logs, which has further been used to scale the overestimated Gassmann-modeled fluid effect. The results of the revised method are independent of type of clay presence and associated effective porosity. Moreover, the corrected FRM results from the revised Gassmann method shows good agreement with rock physical interpretation of shaly sandstone reservoirs.

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