scholarly journals Analisa Kesekatan Sesar dan Kompartemen Lapisan Berdasarkan Analisis Petrofisika dan Attribut Seismik pada Formasi Talang Akar, Sub Cekungan Jambi

2017 ◽  
Vol 1 (2) ◽  
pp. 10
Author(s):  
Eko Wibowo
Keyword(s):  
Water Saturation ◽  
Research Area ◽  
Effective Porosity ◽  
Ratio Method ◽  
Migration Route ◽  
Average Value ◽  
Average Water

<p>Daerah penelitian terletak pada Sub Cekungan Jambi. Fokus utama dalam penelitian ini adalah melakukan pendekatan mengenai stuktur yang berkembang di daerah penelitian yang dapat bersifat sebagai tempat akumulasi atau jalur migrasi dengan menggunakan metode SGR (<em>Shale Gauge Ratio</em>), rekonstrusi tektonik berdasarkan data seismik diharapkan dapat  menjawab kompartemenisasi lapisan reservoar pada Formasi Talang Akar dan migrasi fluida hidrokarbon pada reservoar. Berdasarkan analisis terhadap sumur Alpha-1 dan Betha-1 terdapat lapisan prospek hidrokarbon yang merupakan lapisan Formasi Talang Akar. Pada Alpha-1 zona prospek berada pada kedalaman 1436,6–1456,6 m (TVDSS) diberi nama TAF 1 memiliki porositas efektif rata-rata 0,1281; saturasi air rata-rata 0,34 dengan nilai <em>R</em><em>t </em>rata-rata 1794 ohm m dan <em>R</em><em>w </em>0,4 ohmm. Pada sumur Betha-1 zona prospek berada pada kedalaman 1448 m – 1456,5 m (TVDSS) dengan porositas efektif rata-rata  pada zona ini 0,129; saturasi air rata-rata 0,586 dengan nilai <em>R</em><em>t </em>rata-rata 32,2 ohm m dan nilai Rw 0,9 ohmm. Sifat kesekatan sesar pada sesar yang dianalisa adalah <em>leak </em>dengan ratio SGR 15 %, serta lapisan yang tersesarkan merupakan lapisan  reservoar dari Formasi Talang Akar yang sama. Pergerakan fluida hidrokarbon (migrasi) terjadi secara intraformasi (terjadi pada formasi yang sama).</p><p><em>The research area is located in the Jambi Sub-Basin. The focus of this study was the structure in this sub basin, fault which can be a trap or migration route, which can defined using SGR (Shale Gauge Ratio) method. This study also resulted in reconstruction of the tectonics history to know the compartements between reservoir (Talang Akar Formation) and  to know the migration of hydrocarbon. </em><em>Based on the analysis of the well Alpha-1 and Betha-1, there is a layer of hydrocarbon prospects in Talang Akar Formation. At ALPHA 1, prospect zone at depth of 1436.6 to 1456.6 m (TVDSS) named TAF 1 has an average effective porosity 0.1281, the average water saturation of 0.34 with an average permeability in this zone is 20, R<sub>t</sub> 62 mD with an average value of 1794 ohm m and R<sub>w</sub> 0.4 ohmm. The Betha-1 wells prospects zone at depth of 1448–1456,5 m (TVDSS) with an average effective porosity in this zone is 0,129 average water saturation of 0,586, permeability 19,6 mD with an average value of R<sub>t</sub> 32,2 ohm m and Rw value of 0.9 ohm m. The conclusion of fault seal in analysis that separated two layers is leaking with SGR ratio of 15%, as well as layers that faulted the reservoir layer of the same Talang Akar Formation. The movements of hydrocarbon as intraformation (in one formation migration).</em></p>

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.

scholarly journals Reservoir Potential Evaluation of the Middle Paleocene Lockhart Limestone of the Kohat Basin, Pakistan: Petrophysical Analyses

2020 ◽  
Vol 11 (1) ◽  
pp. 1-9
Author(s):  
Nasar Khan ◽  
Imran Ahmed ◽  
Muhammad Ishaq ◽  
Irfan U Jan ◽  
Wasim Khan ◽  
...  
Keyword(s):  
Water Saturation ◽  
Effective Porosity ◽  
Tight Reservoir ◽  
Average Water ◽  
Neutron Porosity ◽  
Wireline Logs ◽  
Hydrocarbon Saturation ◽  
Lockhart Limestone ◽  
Drilling Conditions ◽  
Reservoir Potential

The Lockhart Limestone is evaluated for its reservoir potential by utilizing wireline logs of Shakardara-01 well from Kohat Basin, Pakistan. The analyses showed 28.03% average volume of shale (Vsh), 25.57% average neutron porosity (NPHI), 3.31% average effective porosity (PHIE), 76% average water saturation (Sw), and 24.10% average hydrocarbon saturation (Sh) of the Lockhart Limestone in Shakardara-01 well. Based on variation in petrophysical character, the reservoir units of the Lockhart Limestone are divided into three zones i.e., zone-1, zone-2 and zone-3. Out of these zones, zone-1 and zone-2 possess a poor reservoir potential for hydrocarbons as reflected by very low effective porosity (1.40 and 2.02% respectively) and hydrocarbon saturation (15 and 5.20%), while zone-3 has a moderate reservoir potential due to its moderate effective porosity (6.50%) and hydrocarbon saturation (52%) respectively. Overall, the average effective porosity of 3.31% and hydrocarbon saturation of 24.10% as well as 28.03% volume of shale indicated poor reservoir potential of the Lockhart Limestone. Lithologically, this formation is dominated by limestone and shale interbeds in the Shakardara-01 well. Cross-plots of the petrophysical parameters versus depth showed that the Lockhart Limestone is a poor to tight reservoir in Shakardara-01 well and can hardly produce hydrocarbons under conventional drilling conditions.

scholarly journals EVALUATION THE CALCULATION OF WATERSATURATION WITH SIMANDOUX AND INDONESIA METHOD IN THE P LAYER R FIELD

PETRO ◽  
2020 ◽  
Vol 8 (4) ◽  
pp. 142
Author(s):  
Puri Wijayanti ◽  
Ratnayu Sitaresmi ◽  
Guntur Herlambang Wijanarko
Keyword(s):  
Water Saturation ◽  
Effective Porosity ◽  
Log Analysis ◽  
Formation Water ◽  
Porosity Formation ◽  
Shale Volume ◽  
A Value ◽  
Average Water ◽  
Formation Water Resistivity ◽  
Water Resistivity

Logging Interpretation aims to determine petrophysical parameters such as volume shale, porosity, formation water resistivity used to calculate water saturation values. In this study the wells analyzed were four exploration wells. Log analysis carried out in this well is in the form of qualitative analysis and quantitative analysis. The average shale volume in KML-1, KML-2, KML-3 and KML-4 wells is respectively 0.172, 0.132, 0.167 and 0.115. The average effective porosity of KML-1, KML-2, KML-3 and KML-4  wells is 0.236, 0.268, 0.219 and 0.225 respectively. The values of a, m and n follow the lithology of the well, namely limestone (carbonate) with a value of 1, 2 and 2. The value of Rw is obtained from the Pickett Plot Method that is equal to 1.52 Ωm on KML-1, 1.52 Ωm on KML-2, 1 , 52 Ωm on KML-3 and 0.5 Ωm on KML-4. The average water saturation with the Simandoux Method in KML-1, KML-2, KML-3 and KML-4 wells is 0.336, 0.434, 0.670 and 0.397. While the average water saturation value with the Indonesian Method in KML-1, KML-2, KML-3 and KML-4 wells is 0.439, 0.488, 0.723 and 0.440 respectively. From the comparison with S<sub>w</sub> Core, the Simandoux method is better used in calculating water saturation because the result is closer to the value of Sw Core.

scholarly journals Reservoir Potential Evaluation of the Middle Paleocene Lockhart Limestone of the Kohat Basin, Pakistan: Petrophysical Analyses

2020 ◽  
Vol 11 (1) ◽  
pp. 1-9
Author(s):  
Nasar Khan ◽  
Imran Ahmed ◽  
Muhammad Ishaq ◽  
Irfan U Jan ◽  
Wasim Khan ◽  
...  
Keyword(s):  
Water Saturation ◽  
Effective Porosity ◽  
Tight Reservoir ◽  
Average Water ◽  
Neutron Porosity ◽  
Wireline Logs ◽  
Hydrocarbon Saturation ◽  
Lockhart Limestone ◽  
Drilling Conditions ◽  
Reservoir Potential

The Lockhart Limestone is evaluated for its reservoir potential by utilizing wireline logs of Shakardara-01 well from Kohat Basin, Pakistan. The analyses showed 28.03% average volume of shale (Vsh), 25.57% average neutron porosity (NPHI), 3.31% average effective porosity (PHIE), 76% average water saturation (Sw), and 24.10% average hydrocarbon saturation (Sh) of the Lockhart Limestone in Shakardara-01 well. Based on variation in petrophysical character, the reservoir units of the Lockhart Limestone are divided into three zones i.e., zone-1, zone-2 and zone-3. Out of these zones, zone-1 and zone-2 possess a poor reservoir potential for hydrocarbons as reflected by very low effective porosity (1.40 and 2.02% respectively) and hydrocarbon saturation (15 and 5.20%), while zone-3 has a moderate reservoir potential due to its moderate effective porosity (6.50%) and hydrocarbon saturation (52%) respectively. Overall, the average effective porosity of 3.31% and hydrocarbon saturation of 24.10% as well as 28.03% volume of shale indicated poor reservoir potential of the Lockhart Limestone. Lithologically, this formation is dominated by limestone and shale interbeds in the Shakardara-01 well. Cross-plots of the petrophysical parameters versus depth showed that the Lockhart Limestone is a poor to tight reservoir in Shakardara-01 well and can hardly produce hydrocarbons under conventional drilling conditions.

scholarly journals DETERMINING OF FORMATION WATER SATURATION TO ESTIMATE REMINING HYDROCARBON SATURATION IN THE X LAYER Y FIELD

PETRO ◽  
2019 ◽  
Vol 8 (3) ◽  
pp. 119
Author(s):  
Ratnayu Sitaresmi ◽  
Guntur Herlambang Wijanarko ◽  
Puri Wijayanti ◽  
Danaparamita Kusumawardhani
Keyword(s):  
Gamma Ray ◽  
Water Saturation ◽  
Effective Porosity ◽  
Reservoir Rock ◽  
Formation Water ◽  
Core Data ◽  
Shale Volume ◽  
Average Water ◽  
Hydrocarbon Saturation ◽  
Exploratory Wells

<p>Efforts are made to find the remaining hydrocarbons in the reservoir, requiring several methods to calculate the parameters of reservoir rock characteristics. For this reason, logging and core data are required. The purpose of this research is to estimate the Remaining Hydrocarbon Saturation that can be obtained from log data and core data. With several methods used, can determine petrophysical parameters such as rock resistivity, shale volume, effective porosity, formation water resistivity, mudfiltrate resistivity and rock resistivity in the flushed zone (Rxo) and rock resistivity in the Uninvaded Zone which will then be used to calculate the Water Saturation value Formation (Sw) and Mudfiltrat Saturation. (Sxo) In this study four exploratory wells were analyzed. Shale volume is calculated using data from Gamma Ray Log while effective Porosity is corrected for shale volume. Rw value obtained from the Pickett Plot Method is 0.5 μm. The average water saturation by Simandoux Method were 33.6%, 43.4%, 67.0% and 39.7% respectively in GW-1, GW-2, GW-3 and GW-4 wells. While the average water saturation value by the Indonesian Method were 43.9%, 48.8%, 72.3% and 44% respectively in GW-1, GW-2, GW-3 and GW-4 wells. From comparison with Sw Core, the Simandoux Method looks more appropriate. Average mudfiltrate (Sxo) saturation by Simandoux Method were 65.5%, 68.2%, 77.0% and 64.6% respectively in GW-1, GW-2, GW-3 and GW wells -4. Remaining Hydrocarbon Saturation (Shr) was obtained by 34.5%, 31.8, 23%, 35.4% of the results of parameters measured in the flushed zone namely Rxo, Rmf and Sxo data. For the price of Moving Hydrocarbons Saturation or production (Shm) is 31.9%, 24.8%, 10%, 24.9% in wells GW-1, GW-2, GW-3 and GW-4.</p>

scholarly journals ESTIMASI KANDUNGAN SERPIH (Vsh), POROSITAS EFEKTIF (∅e) DAN SATURASI AIR (Sw) UNTUK MENGHITUNG CADANGAN HIDROKARBON PADA RESERVOAR LIMESTONE LAPANGAN “PRB” DI SUMATERA SELATAN MENGGUNAKAN DATA LOG DAN PETROFISIKA

2020 ◽  
Vol 4 (3) ◽  
pp. 90-102
Author(s):  
Leo Rivandi Purba ◽  
Bagus Sapto Mulyatno
Keyword(s):  
Natural Gas ◽  
Water Saturation ◽  
Research Area ◽  
Effective Porosity ◽  
Research Field ◽  
Water Type ◽  
Average Thickness ◽  
Formation Factor ◽  
The Mean ◽  
Productive Zone

Log and petrophysics data of research area are that located in South Sumatera Basin, exactly at formation Baturaja will be used for counting the hydrocarbon stock in research field. There are 3 the well datas prosessed to determine the prospect layer of hydrocarbon and estimate the hydrocarbon stock in the productive zone by using 1 petrophysic data from well PRB-3. In order to determine the productive zone of hydrocarbon, the first thing to do is to determine the petrophysics parameters. Parameters used is shale content, effective porosity and water saturation. The value of shale content on “PRB” field shows that reservoir is clean from shale minerals. But, based on the saturation of water, type hydrocarbon in reservoir it is natural gas. Based value of three parameters last, the field “PRB” having 6 zone productive hydrocarbon in each ecploratory wells.  Then, determine zone net pay that had been determined by using the cut-off of shale content which is 8% it means hydrocarbon will be produced if the value of shale content under 8%, effective porosity is 5% it means hydrocarbon will be produced if the value of porosity of effective larger than 5% and water saturation is 70% it means that the value of water saturation on field “PRB” must be less than 70% that hydrocarbon can be produced. Average thickness of the net pay in well PRB-1 is 6.78 meter. In well PRB-2, the average thickness is 7.37 meter while in well PRB-3 it is 3,825 meter. The average thickness from those three wells is 3,005 meter. The mean effective porosity of those 3 wells is 8,1% and the mean water saturation is 27,2%. Gas volume formation factor (Bg) is 0,0226 bbl/SCF which the area width is 28 km2. Natural gas stock (OGIP) in this research area is 7,764 BSCF.

Geomorphic Indexes of Tectonic Activity Relative through The Analysis Quantitative in Cisanggarung Watershed, Kuningan District, West Java, Indonesia

2021 ◽  
pp. 367-375
Author(s):  
Ajeng Sekarkirana Pramesti Kameswara ◽  
Nana Sulaksana ◽  
Murni Sulastri ◽  
P. P. Raditya R.
Keyword(s):  
Activity Index ◽  
Shape Index ◽  
Research Area ◽  
Tectonic Activity ◽  
West Java ◽  
High Class ◽  
Watershed Area ◽  
Average Value ◽  
Active Tectonic ◽  
Class 1

The research area is very interesting to study to determine the characterization of the active tectonic influence of the Cisanggarung watershed, West Java. The research area is in Kuningan Regency, West Java. The purpose of this study was to determine the Relative Tectonic Activity Index (Iatr) in the Cisanggarung Watershed. Through the method approach used to identify the Relative Tectonic Activity Index (Iatr) using geomorphic indexes, watershed asymmetry factors (Af), watershed shape index (Bs), valley width, and height valley ratio (Vf), and mountainous face sinusitis (Smf). The Iatr research area is divided into 4 classes: Class 1 (very high), class 2 (high), class 3 (medium), and class 4 (low). Iatr distribution in 14 sub-watersheds covering an area of 286.24 km2 is Class 1 around 14.44% of the watershed area (41.35 km2) which is located in sub-watershed 1, with Smf values 1.157, Vf 0.3, Af 72.15, and Bs 4.3. Class 2 around 28.67% of the watershed area (82.09 km2) is located in sub-watershed 14, with Smf values 1.26, Vf 0.77, Af 15.69, Bs 1.01. Class 3 around 54.16% of the watershed area (155.03 km2) is located in sub-watersheds 2, 3, 6, 7, 8, 10, 11, 12, with an average value of Smf 2, Vf 1.54, Af 51.77, Bs 1.75, and Class 4 about 2.71% of the watershed area (7.76 km2) is located in sub- watersheds 4, 5, 9, 13, with an average value of Smf 2.25, Vf 8.18, Af 55.2, Bs 1.65. The results of the morphometric analysis indicated that the study area was mostly affected by tectonics and erosion.

scholarly journals HYDROCARBON POTENTIALITY OF FACHA RESERVOIR IN ASWAD OIL FIELD, SIRT BASIN, LIBYA

2020 ◽  
Vol 3 (1) ◽  
pp. 62-77
Author(s):  
A. A. Kushlaf ◽  
A. E. El Mezweghy
Keyword(s):  
Water Saturation ◽  
Oil Field ◽  
Reservoir Rock ◽  
Physical Parameters ◽  
Structural Framework ◽  
Average Porosity ◽  
Average Water ◽  
Exploratory Wells ◽  
Hydrocarbon Potentiality ◽  
Sirt Basin

This paper is to study the structural framework, stratigraphy, and the petro-physical characteristics of Facha reservoir of Gir Formation in Aswad oil field, which is located in Block NC74B at the Zella Trough, south-west of Sirt basin, Libya. The data used have been got from well-logging records of nine exploratory wells distributed in Aswad oil field. These data have been analyzed and interpreted through using analytical cross-plots in order to calculate the petro-physical parameters. The results revealed that the lithological facies consists mainly of dolomite. Moreover, they revealed that the lateral distribution of the petro-physical parameters of Facha reservoir indicates that average porosity is 10-23%, average water saturation is 52- 93%, and net pay is of 62.44 ft. This shows that Facha member is a good reservoir rock. The variations in values between wells have been affected by the trend of faults; this indicates that the area is structurally controlled.

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 Stratigraphic variability of Mississippian Meramec chemofacies and petrophysical properties using Machine Learning and geostatistical modeling,STACK trend, Anadarko Basin, Oklahoma

2021 ◽  
pp. 1-59
Author(s):  
Laynie Hardisty ◽  
Matthew J. Pranter ◽  
Deepak Devegowda ◽  
Kurt J. Marfurt ◽  
Carl Sondergeld ◽  
...  
Keyword(s):  
Water Saturation ◽  
Development Planning ◽  
Effective Porosity ◽  
Well Logs ◽  
Blind Test ◽  
Cross Sectional ◽  
Anadarko Basin ◽  
Rock Types ◽  
Calcite Cement ◽  
Stacking Patterns

Mississippian Meramec deposits and reservoirs in the Sooner Trend in the Anadarko (Basin) in Canadian and Kingfisher counties (STACK) play of central Oklahoma are comprised of silty limestones, calcareous sandstones, argillaceous-calcareous siltstones, argillaceous siltstones, and mudstones. We have used core-derived X-ray fluorescence (XRF) data and established environmental proxies to evaluate the occurrence of specific elements (Al, K, Ti, Zr, Sr, Ca, and Si) and to illustrate their stratigraphic variability. For the Mississippian Meramec, six indicator elements or element ratios serve as proxies for clay (Al and K), detrital sediment (Ti and Zr), carbonate deposits (Sr and Ca), calcite cement (Sr/Ca), and biogenic and continentally derived quartz (Si/Ti and Si/Al). We used an unsupervised K-means classification to cluster elemental data from which we interpret three chemofacies: (1) calcareous sandstone, (2) argillaceous-calcareous siltstone, and (3) detrital mudstone. We used a random forest approach to relate core-derived chemofacies to well logs and classify chemofacies in noncored wells with an accuracy of up to 83% based on blind test results. We integrated core-derived XRF, conventional well logs, and chemofacies logs to produce a dip-oriented cross-sectional chemofacies model that trends from the northwest to the southeast across the southern STACK trend. Meramec chemofacies distributions reflect parasequence stacking patterns. The stratigraphic variability of chemofacies indicates an upward increase of argillaceous detrital mudstone from parasequences 1 to 3. Parasequence 3 is capped by a maximum flooding surface. From parasequences 4 to 5, an increase in argillaceous-calcareous siltstone and calcareous sandstone reflects the progradational stacking. Porosity is relatively low in calcareous sandstones primarily due to calcite cement. Water saturation is high in argillaceous-calcareous siltstone, moderate in calcareous sandstone, and low in detrital mudstone. Within the Meramec, biogenic quartz is associated with drilling issues, specifically frequent bit trips due to its hardness. Interpreted biogenic quartz from element profiles corresponds to the calcareous sandstone chemofacies, which can be estimated from triple-combo well logs and can be mapped. Effective porosity and water saturation models reflect the stratigraphic variability of chemofacies and rock types and can be predicted within the defined chemostratigraphic framework. Understanding the spatial variability of effective porosity and water saturation is important for reservoir development planning.

Sign in / Sign up

Export Citation Format

Share Document