Showing papers on "Effective porosity published in 2022"

Prediction of Cretaceous reservoir zone through petrophysical modeling: Insights from Kadanwari gas field, Middle Indus Basin

Abstract: This study involved an interpretation of wire-line logs in assessing the hydrocarbon capacity of the sandstone reservoir within the gas fields of Kadanwari, Sindh, Pakistan. Wire-line logs from four wells (KD-01, KD-03, KD-10 and KD-11) were used in our research and provided interpretation for thirteen reservoir zones. Reservoir analyses were done for effective porosity (ϕeff), shale content (Vsh), net pay thickness variations, water saturation, and hydrocarbon (Sw and Shc). Hydrocarbon-bearing zones consist of high values of resistivity, permeability, porosity, low water saturation content, and less shale content, indicating the presence of clean sand. The Thomas Stieber model findings show that in lower Goru sand, the laminated form of shale distribution persists. Sub-reservoirs’ petrophysical parameters were analyzed and ranked into a good sand reservoir quality (having ϕeff ∼0.11-0.44%), permeability (∼10.539-477.76 mD), hydrocarbon saturation (having Shc ∼0.59-0.86%), and water saturation (having Sw ∼0.18-0.45%). In the current research Indonesian model has been used to test for water saturation over a shaly-sand reservoir situated in a heterogeneous zone. It was observed that each well exhibited Sw at values lesser than 60%. This is indicative the selected zone has a hydrocarbon potential, and the hydrocarbons are of good quality. Isoparametric maps and crossplots of litho-saturation results reveal variations in the horizontal and vertical petrophysical parameters of the reservoir. The subsurface reservoir geographical distribution is visualized employing isoparametric maps. The fuel treasure in the southwestern section of the study area is enormous, as revealed by the petrophysical investigations, suggesting more well-drilling prospects in the gas fields of the lower Goru Formation situated in Kadanwari. Our research identified a quality hydrocarbon hotspot zone of immense economic value in Southern Kadanwari. In contrast, more research is needed regarding the northeastern section though our present findings suggest the northeastern section should be avoided because of excess shale and high-water concentrations.

Reservoir Quality Prediction of Gas-Bearing Carbonate Sediments in the Qadirpur Field: Insights from Advanced Machine Learning Approaches of SOM and Cluster Analysis

Abstract: The detailed reservoir characterization was examined for the Central Indus Basin (CIB), Pakistan, across Qadirpur Field Eocene rock units. Various petrophysical parameters were analyzed with the integration of various cross-plots, complex water saturation, shale volume, effective porosity, total porosity, hydrocarbon saturation, neutron porosity and sonic concepts, gas effects, and lithology. In total, 8–14% of high effective porosity and 45–62% of hydrocarbon saturation are superbly found in the reservoirs of the Eocene. The Sui Upper Limestone is one of the poorest reservoirs among all these reservoirs. However, this reservoir has few intervals of rich hydrocarbons with highly effective porosity values. The shale volume ranges from 30 to 43%. The reservoir is filled with effective and total porosities along with secondary porosities. Fracture–vuggy, chalky, and intracrystalline reservoirs are the main contributors of porosity. The reservoirs produce hydrocarbon without water and gas-emitting carbonates with an irreducible water saturation rate of 38–55%. In order to evaluate lithotypes, including axial changes in reservoir characterization, self-organizing maps, isoparametersetric maps of the petrophysical parameters, and litho-saturation cross-plots were constructed. Estimating the petrophysical parameters of gas wells and understanding reservoir prospects were both feasible with the methods employed in this study, and could be applied in the Central Indus Basin and anywhere else with comparable basins.

Estimating Effective Porosity in Bedrock Aquifers

Abstract: Flow in many bedrock aquifers is through fracture networks. Point to point tracer tests using applied tracers provide a direct measure of time of travel and are most useful for determining effective porosity. Calculated values from these tests are typically between 10−4 and 10−2 (0.01% to 1%), with these low values indicating preferential flow through fracture and channel networks. Tracer tests are not commonly used in site investigations, and specific yield is often used as a proxy for effective porosity. The most popular methods have used centrifuge measurements, water table fluctuations, pumping tests, and packer tests. Specific yield varies substantially with the testing method. No method is as reliable as tracer testing for providing estimates of effective porosity, but all methods provide complementary insights on aquifer structure. Temporal and spatial scaling effects suggest that bedrock aquifers have hierarchical structures, with a network of more permeable fractures and channels, which are connected to less permeable fractures and to the matrix. Consequences of the low effective porosities include groundwater velocities that often exceed 100 m/d and more frequent microbial contamination than in aquifers in unconsolidated sediments. The large uncertainty over the magnitude of effective porosity in bedrock aquifers makes it an important parameter to determine in studies where time of travel is of interest.

The influence of grain shape and size on the relationship between porosity and permeability in sandstone: a digital approach

Abstract: An accurate and reliable description of the porosity-permeability relationship in geological materials is valuable in understanding subsurface fluid movement. This is important for reservoir characterisation, energy exploitation, geological carbon storage (GCS) and groundwater contamination and remediation. Whilst the relationship between pore characteristics and porosity and permeability are well examined, further investigation into the influence of grain characteristics on porosity and permeability would be beneficial due to the inherent relationship between grains and pores. This work aims to determine whether incorporation of grain characteristics into a porosity-permeability model is effective in constraining this relationship. Two fully digital approaches to individual 3D grain analysis based upon watershed segmentation are compared to determine the most effective, yet simple, workflow applicable to core plugs of significantly compacted grains. The identification of an effective segmentation workflow will facilitate future work on similarly complex materials, removing the need for traditional time-consuming and manual techniques. We use the most effective approach of measuring grain shape (sphericity) and size (Feret diameter) alongside an established fully digital workflow to measure porosity and permeability to investigate the impact of grain characteristics on porosity and permeability. We show that grain sphericity and porosity exhibit a positive relationship whereas no such relationship exists with grain size. Measurements of grain sphericity are applied to calculate a Kozeny-Carman (K-C) type porosity-permeability fit which was found to be unsatisfactory, compared to a simpler fit excluding any grain parameters. This is possibly due to the lower sphericity of the studied grains, deviating significantly from the K-C assumption that grains are entirely spherical. The simpler fit is most suitable for the studied materials, showing that inclusion of grain characteristics is not effective for better defining the porosity-permeability relationship in a K-C paradigm for these samples. This highlights the need for a model capable of considering a range of grain sphericities to further constrain the porosity-permeability relationship.

Analysis of Physical Properties and Influencing Factors of Longmaxi Shale in Sichuan Basin

Abstract: The physical properties of shale reservoirs directly affect the form of shale gas and its preservation conditions, and an evaluation of these properties has great significance on the storage and exploitation of shale gas. In this study, the Longmaxi Formation shale in the Sichuan Basin was considered as the research object. The parameters of porosity, permeability, mineral composition, total organic carbon content, density, in-situ stress, brittleness index, and fluid saturation of the samples were obtained through a series of tests. The influence of each parameter on the porosity and permeability was analyzed, and a weight analysis was conducted using an analytic hierarchy process (AHP). The results show that: clay mineral content in the mineral composition has a positive correlation with porosity, and the content of brittle minerals can affect the fracture development density and improve the permeability of samples; the total organic carbon content has a positive correlation with porosity and permeability; increases in density and in-situ stress will significantly reduce the porosity and permeability of samples; the brittleness index has a negative correlation with porosity and a positive correlation with permeability; water saturation has a positive correlation with porosity, gas saturation has a negative correlation with porosity, and the movable oil saturation has an obvious logarithmic relationship with porosity and a negative correlation with permeability. Furthermore, the AHP was used to analyze the specific effects of various parameters on porosity and permeability, with the weight of total organic carbon content > mineral composition > brittleness index > density > in-situ stress > fluid saturation. In this study, we evaluated the physical properties of shale reservoirs, which provides an important basis for shale reservoir evaluation and mining area selection.

Seismic Interpretation and Petrophysical Analysis for Evaluation of Ataga Field, Onshore Niger Delta, Nigeria

Abstract: The majority of geophysical survey in hydrocarbon exploration and production sector is driven by the ability to describe reservoirs. This research is aimed at describing the interpretation and petrophysical analysis of the reservoirs in Ataga field Niger Delta using a combination of seismic and well-log data. The Ataga Field in the Niger Delta was subjected to 3-D seismic interpretation and petrophysical study to perform comprehensive structural interpretation, prospect evaluation, and volumetric calculation. Two reservoir windows “1” and “2” were identified and correlated from four wells ATA 10, ATA 11, ATA 5 and ATA 7. Detailed evaluation was done on well ATA 11 since it is the only well that has sufficient data for both qualitative and quantitative interpretation. Structural interpretation for inline 5731 revealed fifteen faults on the seismic vertical section through ATA 11, most of which are antithetic faults while the rest are synthetic faults. Top and base of each reservoir window was delineated from the well. Result of the petrophysical assessment of reservoir A, B and C for ATA 11 revealed that the porosity values range from (24 -29) % which are indicative of very good to excellent porosity value according to Rider (1996). While the permeability values range from (1887-2582) mD were obtained from the three reservioir A, B and C of ATA 11 which depict very good to excellent reservoir units. Since, .all of the wells were discovered to have hydrocarbon-bearing reservoir formations (sandstones), the integration of structural interpretation and well logs have successfully revealed that the reservoirs are mostly oil-bearing zones.

Assessment of the relationship of reservoir properties of hydrocarbon fields in the Lower Kura depression (Kursengi and Southern Kursengi areas)

Abstract: The article is devoted to the analysis of the geological-petrophysical properties of the Kursengi and Southern Kursengi fields of the Lower Kura depression with a view to clarify the changes in the physical properties (carbonate content, permeability, porosity) of rocks with depth. Promising sediments and horizons of deposits are also considered based on a detailed analysis of numerous rock samples. Oil and gas bearing objects are especially distinguished by area, as well as possible oil and gas bearing blocks. The main purpose of these studies is to unravel changes in carbonate, porosity and permeability of rocks with depth based on core samples taken from drilled wells in the study area and to identify the factors causing these changes. To do this, using the obtained well data, the dependences of changes in depth of porosity, permeability and carbonate were compiled. As known, with increasing depth, rocks experience compaction. With the depth of changes in porosity, the rocks do not show any regularity, i. e. at some depths, an increase in the porosity of rocks is observed, and at some depths, a decrease, and this occurs in an abrupt manner. In our sections, the critical depths of porosity decrease are observed from 500 m to 1600 m, and the critical depth of porosity increase from 1600 m to 2950 m. In other words, the porosity of reservoirs, with a general gradual decrease in depth, begins to sharply decrease from a depth of 3200 m. In the study of core materials, it was found that the rocks are characterized by good reservoir properties. However, in many of the studied samples, the porosity of the rocks varies within a wide range of 12.8–27.8 %, and the permeability ranges from 0.001x10–15m2 to 120x10–15m2. Changes in petrophysical values are observed in both study areas. The reason for the change in petrophysical values in a wide range at the objects of study is associated with the lithological heterogeneity of the complexes and the occurrence depth of the reservoir.

Machine Learning Based Prediction of Porosity and Water Saturation from Varg Field Reservoir Well Logs

Abstract: Abstract Accurate estimation of reservoir parameters such as fluid saturations and porosity is important for assessing petroleum volumes, economics and decisionmaking. Such parameters are derived from interpretation of petrophysical logs or time-consuming, expensive core analyses. Not all wells are cored in a field, and the number of fully cored wells is limited. In this study, a time-efficient and economical method to estimate porosity, water saturation and hydrocarbon saturation is employed. Two Least Squares Support Vector Machine (LSSVM) machine learning models, optimized with Particle Swarm Optimization (PSO), were developed to predict these reservoir parameters, respectively. The models were developed based on data from five wells in the Varg field, Central North Sea, Norway where the data were randomized and split into an unseen fraction (10%) and a fraction used to train the models (90%). In addition to the unseen fraction, a sixth well from the Varg field was used to assess the models. The samples are mainly sandstone with different contents of shale, while fluids water, oil and gas were present. The ‘seen’ data were randomized into calibration, validation and testing sets during the model development. The petrophysical logs in the study were Gamma-ray, Self-potential, Acoustic, Neutron porosity, bulk density, caliper, deep resistivity, and medium resistivity. The log based inputs were made more linear (via log operations) when relevant and normalized to be more comparable in the algorithms. Feature selection was conducted to identify the most relevant petrophysical logs and remove those that are considered less relevant. Three and four of the eight logs were sufficient, to reach optimum performance of porosity and saturation prediction, respectively. Porosity was predicted with R2 = 0.79 and 0.70 on the model development set and unseen set, for saturation it was 0.71 and 0.61, a similar performance as on the training and testing sets at the development stage. The R2 was close to zero on the new well, although the predicted values were physical and within the observed data scatter range as the model development set. Possible improvements were identified in dataset preparation and feature selection to get more robust models.

Porosity and Permeability Model of a Regionally Extending Unit (Upper Miocene Sandstones of the Western Part of Sava Depression, Croatia) Based on Vintage Well Data

Abstract: The deep saline aquifer (DSA) Poljana in the Upper Pannonian Poljana Sandstones of Sava depression, the SW part of the Pannonian basin system, was identified as a potential CO2 storage object in previous works. Its boundaries have been redefined and its general model further developed, including the areal distribution of porosity based on analyses of 23 well logs. The sandstones were deposited in turbiditic and deltaic facies that caused considerable variations of porosity, which was further influenced by diagenetic processes. A comparison of altogether 355 pairs of porosity and permeability measurements on core plugs from 16 wells indicated 2 different sets of samples: impermeable samples with effective porosities reaching 18% and permeable samples which showed correlation between porosity and permeability. Accordingly, the permeability model was developed as semi-categorical with two categories: the first category comprising parts of DSA Poljana with porosity values exceeding 18%, where permeability was correlated with porosity, although with limited reliability, and the second category comprising model cells with porosity values below the threshold of 18%, where permeability should not be correlated with porosity due to the appearance of impermeable values. This approach enabled delineation of areas where permeability can be estimated with greater certainty, which is of utmost importance for the planning and development of CO2 storage projects and/or energy storage projects with respect to fluid injectivity. This approach can be used in areas with similar geological settings and limited datasets as an important step from regional capacity estimations towards the detailed, local-scale investigations.

Petrophysical Characterization of Shaly Sand Reservoirs in Well UK-05 Eastern Niger Delta Basin, Nigeria

Abstract: A petrophysical evaluation of Well UK-05 in the eastern Niger Delta Basin was carried out in order to determine reservoir zones, their porosity, permeability, fluid saturation and the effect of shaliness on the petrophysical parameters. Using interactive petrophysics software version 3.5, twenty five (25) reservoir zones were identified. The porosity values range from 15.77- 4.66% and permeability from 2.76-546.54 mD. The Archie’s, Simandoux, Dual-porosity, Waxman and Smith, and the Indonesian models were used to determine the fluid saturation. The water and hydrocarbon saturation values using the Indonesian model are 21.67-50.49% and 49.51-78.33% respectively. They slightly differ from the ones obtained using Simandoux, Dual Water and Waxman and Smith model (20.72-49.88% and 50.12- 9.22%, 18.26-50.49% and 49.51-81.74%, 14.67-48.26% and 51.74-5.33% for water and hydrocarbon saturation respectively). The interpreted lithology shows that the formation penetrated by the Well UK-05 is dominated by alternating sands and shales with the sand being the dominant lithology. These lithostratigraphic characteristics correspond to those of the parallic Agbada Formation. The effective porosity values obtained range from 14.93 to 34.66%, which are lower than 0.013% to 94.08% obtained by other authors since they did not take into consideration the effect of shaliness. This shows that the more the shale volume, the higher the uncertainty of actual porosity of the reservoir.

Prediction of porosity of reservoir sands using seismic attributes in “arike” field niger delta, nigeria

Abstract: The study aimed at predicting the porosity of reservoir sands in ‘Arike field’ Niger Delta, Nigeria by converting seismic trace of the interval of interest in the seismic survey into a porosity log to generate a porosity volume. Optimal number of relevant attributes were selected using multi-attribute analysis. The study discovered that three attributes (energy, velocity fan, and Q factor) were efficient. These attributes were then utilized to train a supervised neural network to establish the relationship between seismic response and porosity. The Opendtect software used, extracted all specified input attributes and target values over the specified range along the well tracks and randomly divided the data into a training and test set attribute. The study established the integration and correlation of energy attribute, velocity fan attribute, and Q factor as relevant seismic attributes for porosity estimation when little or no well log is available, hence giving a means of spatially extending well data.

Evaluation of the Influence of Shale on the Petrophysical Properties of Hydrocarbon-Bearing Reservoir Sand in “CAC” Field in the Niger Delta, Nigeria

Abstract: This study aims at evaluating the influence of the presence of shale on the quality of reservoir sand in “CAC-Field”, Coastal swamp Niger Delta by integrating suites of well logs and 3D pre-stack seismic data. Shales in the reservoir pose interpretation challenges as they form baffles to fluid flow and reduce effective porosity. The data used included well logs (density, gamma ray, neutron, resistivity) and 3D seismic data. Petrel and Interactive Petrophysics software were adopted for the analyses. The Vclay/effective porosity cross-plots were used to determine the clay distribution patterns hence the influence of shale on the petrophysical properties of the hydrocarbon reservoir. Result of the well correlation yielded 12 reservoirs with 4 (RES 4 - RES 7) being hydrocarbon bearing and laterally continuous across the 4 wells, (CAC-1 - CAC-4) forming the focus of the study. Evidence of an NW-SE trending delta progradation in the CAC field is represented by the increasing sandiness downdip, at both intermediate and the shallow horizons. Thickening of the reservoir in some instances may be structurally controlled due to faulting. The results from the petrophysical evaluation show Vclay ranges of 13% - 21% and good to very good porosity values that vary from 15% - 25%. The permeability range from 240.49 - 2406.49 mD except for the sands in RES 7, CAC-3 well where the permeability was low (91 mD). Additionally, the Vclay/Effective Porosity cross-plots indicate essentially laminated and structural clay types with few dispersed clay in RES 7, CAC-3 well. The existence of these 3 clay types did not significantly influence the quality of the sands containing the hydrocarbon in the area, except in RES 7, CAC-3. The compartmentalizing effect of the laminated clay/shale could only possibly affect the vertical flow due to possible baffles to the vertical flow, but the horizontal flow may not have been impeded significantly. The study of the type and pattern of clay has helped to better evaluate the quality and mobility trend of the hydrocarbon in the CAC field.

Petrophysical analysis of well data for clastic reservoir evaluation and determination of the invaded zone effect: A case study of a field in the onshore Niger Delta, South-South, Nigeria

Abstract: Two reservoirs domiciled in a well have been analysed in this study in order to obtain the quantitative reservoir properties. These quantitative reservoir properties are essential not only for well development and optimization but also for accurate decision-making prior to reservoir exploitation and production. A suite of composite logs comprising the caliper log, gamma-ray (GR) log, density log, resistivity logs and sonic transit time logs obtained from a field in the onshore Niger Delta was used for the petrophysical analysis. From our quantitative results, Reservoir 1 has the potential to produce oil and gas with a total hydrocarbon saturation of 81%. However, due to the invaded zone effect on the reservoir potential, the total hydrocarbon fluid has been partitioned into moveable hydrocarbon of 65% saturation and immoveable hydrocarbon of 16% saturation. This resulted from the mud filtrate invasion of the radially shallow zone which displaced the original fluid while the undisplaced hydrocarbon fluid remained in the pore spaces of the reservoir. The porosity of the reservoir sand is 33% and its effective porosity is 32.5%. The high effective/interconnected porosity and clean nature of the sand which is due to the extremely small volume of shale present in the sand (just 1.0%) clearly shows that the reservoir is highly porous, permeable and producible.The net pay of the reservoir (represented by the thickness TH in Mesh 1) could not be quantitatively determined due to lack of depth information on the logs. The second reservoir (Reservoir 2) has a total hydrocarbon saturation of 94.8% and water saturation of just 5.2%. The total hydrocarbon saturation is partitioned into 82.8% moveable hydrocarbon saturation and 12% immoveable hydrocarbon saturation which resulted from the invaded zone effect. The porosity of the reservoir was determined at 33% and its effective porosity at 32.5%. Again, the high effective/interconnected porosity and clean nature of the sand arising from the extremely small volume of shale present in the sand (0.4%) is a clear indication that the second reservoir is also highly porous, permeable and producible. The net pay of Reservoir 2 (represented by the thickness TH in Mesh 2) is higher compared to Reservoir 1 but could not be evaluated due to absence of depth values on the logs. In the final analysis, the overall results show that the reservoirs are commercially favourable and have the potential to pay back.

Petrophysical evaluation for development of a marginal oil field in the onshore Niger Delta, Nigeria

Abstract: Petrophysical evaluation was conducted on an onshore marginal field in Niger Delta with the aim of evaluating the rock and fluid properties to boost hydrocarbon production in the field. Five well logs suite from five wells and core log data for two wells were utilized for this study. Petrophysical properties evaluated included; porosity, net to gross, formation factor, irreducible water saturation, permeability, water saturation, hydrocarbon saturation and pay thickness. The well logs suite contained the following logs: Gamma ray log for lithology identification; Resistivity log for fluid type discrimination and determination of water saturation; Density log for porosity determination; and Neutron log in combination with density log for hydrocarbon types. A total of seven reservoir sands (, Sand A, B, C, D, E, F and G) were identified and correlated across all five wells on the basis of gamma ray and resistivity log motifs. The reservoir gross thicknesses ranged from 62.55 to 228.50 ft, shale volume from 7.0 to 24.60%, net to gross from 0.76 to 0.93%, effective porosity from 20.78 to 26.22%, water saturation from 35.80 to 62.30% and permeability ranged from 545.94 to 2821.97 mD. This shows that the reservoirs are of good quality for hydrocarbon productionacross the field.

Petrophysical properties assessment using wireline logs data at well#3 of Srikail gas field, Bangladesh

Abstract: This study focused on the quantitative analysis of the petrophysical parameters in characterizing the reservoir properties of the Srikail gas field using multi-scale wireline logs. Petrophysical parameters (shale volume, porosity, water saturation and hydrocarbon saturation) were estimated from the combination of gamma ray log, resistivity log, density log and neutron log for three hydrocarbon (gas)-bearing zones at well#3. At the first time, log records at 0.1 m and 0.2 m intervals were read for this study. Result showed the average shale volume is 21.07%, 53.67% and 51.71% for zone-1, zone-2 and zone-3, respectively. For these zones, the estimated average porosity was 35.89%, 29.83% and 28.76%, respectively. The average water saturation of 31.54%, 16.83% and 23.39% and average hydrocarbon saturation of 68.46%, 83.17% and 76.61% were calculated for zone-1, zone-2 and zone-3, respectively. Thus zone-2 is regarded the most productive zone of well#3. It was found that the values of some parameters (porosity, hydrocarbon saturation and permeability) are higher than the existing results. Therefore, this study confirmed that the log reading at minute/close interval provides better quantitive values of the reservoir’s petrophysical properties. It is expected that this result will contribute to the national gas field development program in future.

Evaluation of oil reservoir of Hartha Formation in Y and J field, North Iraq

Abstract: Afield development plan (FDP) of the Y and J oil fields for cretaceous reservoir (Harth Formation) evaluation and the production of hydrocarbons in the near future in two Y and J oil fields. Open hole logs namely (Gamma ray, Resistivity, Sonic, Caliper and Density) logs were used to determine petrophysical parameters. The parameters determined are; volume of shale, porosity, water saturation, irreducible water saturation and bulk volume of water. The thickness of the reservoir varies between (40 and 120) m. Determining the porosity depending on the porosity of the log (16-28)% and core Average porosity (18-37)% values vary between; generally decreasing with depth. Average porosity 33.3%.test is flow crude oil 1000 bll /d.in J field basically water saturation calculation5-16%. And oil saturation (90-80) % and the oil were carried out at a rate of 1000 barrels / day in the complete test of well Y. The amount of the original oil storage OOIP (1039 * 10^6) standard cubic meters. This study provides an insight into reservoir quality prediction in the study area and other carbonate reservoirs undergone different the development of Hartha reservoir in south Mosul north Iraq as a new reservoirs in the study as Tertiary reservoir producing as old degassing stations enabling facilities from the 1950s are being" surface facility", This study's aimed at making available petrophysical data the computer processed interpretation(CPI) for Hartha reservoir.

Experimental Investigating of Compaction Effect on Porosity Measurement for Carbonate Rocks

Abstract: Oil and natural gas may be found in commercial reservoirs, porous and easily permeable rocks. Porosity is an essential characteristic of reservoirs. This research focuses on comparing laboratory-measured porosity to log porosity. A comparison of the porosity values determined in the lab using the liquid saturation technique, density method, an ultrasonic method, and the porosity computed from wireline logs such as sonic, density, and neutron logs. Compaction is the decrease in volume caused by an external force. A discrepancy exists between the laboratory and log porosities because of the rock compaction. It is important to note that porosity may be broken down into two categories: total and effective. After calculating the bulk and grain volumes, the total porosity is determined by averaging the results of several techniques, such as gas density logs, density logs, and neutron logs. The porosity is estimated using ultrasonic equipment in the lab and compared to sonic logs. Sonic tests show a higher porosity in the lab than in the log due to the formation's rocks being compacted. An excellent correlation exists between density log porosity and density porosity from the lab, with a determination coefficient of 0.79.

Routine Core Analysis (RCAL) Untuk Menentukan Porositas, Permebilitas, dan Saturasi Pada Batupasir (Sandstone)

Abstract: The physical properties of basic reservoir rocks that are very important to know, especially in the oil and gas industry, include porosity, permeability and saturation. The three physical properties determine the economics of an oil and gas field, especially in the reservoir rock layer. Sandstone (sand) is a lithology that very common oil and gas reservoir rock. The research was conducted at a laboratory scale using three (3) core plug samples from conventional cores. The method used in the Porosity measurement is Boyle's law helium porosimeter, while for the measurement of saturation using the results of the Conventional Retort method. The results of his research are the porosity values of the three samples taken from an average value of 23.76%, which is in the very good (very good) category. Meanwhile, the permeability values of the three samples were taken from an average value of 211.67 mD which is also in the very good category. From the graph of porosity to permeability it shows a directly proportional relationship, then from the graph of porosity to depth of the three samples above it shows an inverse relationship, those are shown by the trendline but with a very low R2 value. This is possibly caused by two things, namely: lack of sample data, and too close sample interval so that it cannot be used as justification that porosity and depth are not reversed. Oil saturation values (So) and gas saturation (Sg) of the three samples were taken from the average values of 46% and 1.7%.

The analysis of Reservoar Porosity Calculation based on Well Log in Bintuni Basin Area

Abstract: The Bintuni Basin is one of several oil and gas producing basin in Eastern Indonesia. This basin has one of the hydrocarbon-producing reservoir in the Kais Formation. The carbonate reservoir in Kais Formation is Middle to Upper Miocene age. The understanding of reservoirs is important for further field development. Petrophysical analysis is a method for understanding reservoirs especially porosity parameter and estimation of hydrocarbon reserve. The data used in study is well data including, mudlog report, well report, Gamma Ray (GR), Sonic, Resistivity (ILD, ILS, MSFL), density (RHOB) and NPHI logs. The aim study is to analyze the reservoir using Gamma Ray log and porosity calculation using Sonic, RHOB and NPHI logs. The study method includes regional geological literature review, marker analysis, Gamma Ray picking, and reservoir porosity calculations. According to Gamma Ray picking analysis, the Kais Formation GR has values of GRsand = 25 API and values of GRshale = 80 API. The Low Gamma Ray below 60 API is interpretated as carbonate reservoir. For porosity validation, the porosity of routine core analysis (RCAL) data is plotted into porosity logs (porosity calculation using Sonic, RHOB and NPHI logs). Based on the porosity calculation using three porosity logs(Sonic, Density, NPHI Logs), the porosity estimated from density log is more match with the porosity of routine core analysis (RCAL) data. According to porosity calculation at WTU Well, the porosity from log density in the Kais Formation has value from 2% - 25%. The porosity in Carbonate has large value as a result of secondary porosity.©2022 JNSMR UIN Walisongo. All rights reserved.

Influence of pressure on porosity–permeability relationship in southern niger delta, nigeria

Abstract: Well logs data comprising of comprising of gamma ray, spontaneous potential, density and neutron logs from four oil wells were analysed for determining the influence of pressure on porosity–permeability relationship in the study area. Porosity values were deduced from well log whereas permeability and pressure values were computed using empirical equations. The average porosity, permeability and pressure values for the four wells range from 0.1% to 30.9%, 34.9mD to 306.4mD, 61926.9psi to 109928.1psi respectively. The lithostratigraphic correlation section of the wells revealed a sand – shale sequence which is a characteristic of a typical Niger Delta formation. The results of this work show that three reservoirs (sand A, sand B and sand C) were identified and correlated across the four wells, each reservoir sand unit spread across the wells and differs in thickness ranging from 8ft to 155ft, with some unit occurring at greater depth than their corresponding unit. The analysis of the wells show that wells OTIG9 and OTIG11 have better reservoirs indicating high potentiality and productivity due to their more porous and permeable nature, reflecting well sorted coarse grained sandstone and linearity in the relationship between porosity, permeability and pressure. The reservoir of well OTIG7 is the least porous but most permeable, thus is highly productive but less potential. The reservoir of OTIG2 has moderate potentiality and good productivity, hence is said to have average production capacity. The results of this work can be used as an evaluation tool for reservoir engineering activities, structural engineering, well stability analysis, blowout and lost circulation prevention