scholarly journals Petrophysical Analysis of an Iraqi Gas Field (Mansuriya Gas Field)

2020 ◽  
Vol 26 (3) ◽  
pp. 100-116
Author(s):  
Hasan Saleh Azeez ◽  
Dr. Abdul Aali Al-Dabaj ◽  
Dr.Samaher Lazim
Keyword(s):  
Gamma Ray ◽  
Water Saturation ◽  
Total Porosity ◽  
Logarithmic Scale ◽  
Formation Factor ◽  
Gas Field ◽  
The Matrix ◽  
Rock Parameters ◽  
Potassium 40

Mansuriya Gas field is an elongated anticlinal structure aligned from NW to SE, about 25 km long and 5-6 km wide. Jeribe formation is considered the main reservoir where it contains condensate fluid and has a uniform thickness of about 60 m. The reservoir is significantly over-pressured, (TPOC, 2014). This research is about well logs analysis, which involves the determination of Archie petrophysical parameters, water saturation, porosity, permeability and lithology. The interpretations and cross plots are done using Interactive Petrophysics (IP) V3.5 software. The rock parameters (a, m and n) values are important in determining the water saturation where (m) can be calculated by plotting the porosity from core and the formation factor from core on logarithmic scale for both and the slope which represent (m) then Pickett plot method is used to determine the other parameters after calculating Rw from water analysis . The Matrix Identification (MID), M-N and Density-Neutron crossplots indicates that the lithology of Jeribe Formation consists of dolomite, limestone with some anhydrite also gas-trend is clear in the Jeribe Formation. The main reservoir, Jeribe Formation carbonate, is subdivided into 8 zones namely  J1 to J8, based mainly on porosity log (RHOB and NPHI) trend, DT trend and saturation trend.  Jeribe formation was considered to be clean in terms of shale content .The higher gamma ray because of the uranium component which is often associated with dolomitisationl and when it is removed and only comprises the thorium and potassium-40 contributions, showed the gamma response to be low compared to the total gamma ray response that also contains the uranium   contribution.While the Jeribe formation is considered to be clean in terms of shale content so the total porosity is equal to the effective porosity.No porosity cut off is found if cutoff permeability 0.01 md is applied while the porosity cut off approximately equal to 0.1 only for unit J6 & J8 if cutoff permeability 0.1 md is applied . It can be concluded that no saturation cutoff for the units of Jeribe formation is found after a cross plot between water saturation and log porosity for the reservoir units of Jeribe formation and applied the calculated cut off porosity. The permeability has been predicted using two methods: FZI and Classical, the two methods yield approximately the same results for all wells.

A Quadruple-Porosity Model for Consistent Petrophysical Evaluation of Naturally Fractured Vuggy Reservoirs

SPE Journal ◽  
2020 ◽  
Vol 25 (05) ◽  
pp. 2678-2693
Author(s):  
Mahaman Salifou Aboubacar ◽  
Zhongxian Cai
Keyword(s):  
Water Saturation ◽  
Accurate Determination ◽  
Total Porosity ◽  
Fluid Systems ◽  
Proposed Model ◽  
Naturally Fractured ◽  
The Matrix ◽  
Input Variables ◽  
Porosity Model

Summary Several dual- and triple-porosity models have been proposed for quantifying the porosity exponent (m) in multiporosity reservoirs. Total porosity (ϕ) is usually portioned into the matrix (ϕb) and vuggy porosity, which includes separate vugs (SVGs) and connected vugs (CVGs). As a result, in their majority, the existing petrophysical models were developed and applied mostly without any distinction between the various types of CVGs despite their specific pore geometries, which critically determine the properties of the rock/fluid systems. For instance, unlike otherwise CVGs, natural fractures (NFs) and microcracks that have low pore-aspect-ratio values are highly compressible; this can cause their closure and lead to increasing m values. In this paper, we proposed a quadruple-porosity model that accounts for NFs (ϕ2 or ϕf) and CVGs (ϕc), in addition to ϕb and SVGs (ϕnc) separately, as distinct input variables to ensure accurate determination of m in composite reservoirs. The approach was based on the volume-model method and rules of electric-resistance networks in porous media. Computed water-saturation values used to validate the model show significant improvement and close agreement with the laboratory measurements, demonstrating the applicability of the proposed model for accurate prediction of m in naturally fractured vuggy reservoirs. New correlations that consider the pore-type diversity were generated using a plot of ϕ vs. m, obtained with the proposed quadruple-porosity model. The procedure involved sorting the ϕ/m scattering points using pore-type mixing and relative abundance of specific porosity. It allowed defining consistent ϕ/m relationships, with determination coefficients of 0.7 to 0.9. This suggests that m varies with the pore-structure types; this was further demonstrated with a rock-frame flexibility factor (γ) used as a proxy to cluster the scattering points. The established correlations can alternatively be applied to reasonably predict m using detailed prior knowledge of pore-type description.

Joint petrophysical interpretation of multidetector nuclear measurements in the presence of invasion, shoulder-bed, and well-deviation effects

Geophysics ◽  
2017 ◽  
Vol 82 (1) ◽  
pp. D13-D30 ◽  
Author(s):  
Edwin Ortega ◽  
Mathilde Luycx ◽  
Carlos Torres-Verdín ◽  
William E. Preeg
Keyword(s):  
Gamma Ray ◽  
Water Saturation ◽  
Total Porosity ◽  
Neutron Density ◽  
Layer By Layer ◽  
Fluid Type ◽  
Fluid Properties ◽  
Radial Length ◽  
Neutron Porosity ◽  
Porosity Logs

Recent advances in logging-while-drilling sigma measurements include three-detector thermal-neutron and gamma-ray decay measurements with different radial sensitivities to assess the presence of invasion. We have developed an inversion-based work flow for the joint interpretation of multidetector neutron, density, and sigma logs to reduce invasion, shoulder-bed, and well-deviation effects in the estimation of porosity, water saturation, and hydrocarbon type, whenever the invasion is shallow. The procedure begins with a correction for matrix and fluid effects on neutron and density-porosity logs to estimate porosity. Multidetector time decays are then used to assess the radial length of the invasion and estimate the virgin-zone sigma while simultaneously reducing shoulder-bed and well-deviation effects. Density and neutron porosity logs are corrected for invasion and shoulder-bed effects using two-detector density and neutron measurements with the output from the time-decay (sigma) inversion. The final step invokes a nuclear solver in which corrected sigma, inverse of migration length, and density in the virgin zone are used to estimate water saturation and fluid type. The fluid type is assessed with a flash calculation and Schlumberger’s Nuclear Parameter calculation code to account for the nuclear properties of different types of hydrocarbon and water as a function of pressure, temperature, and salinity. Results indicate that accounting for invasion effects is necessary when using density and neutron logs for petrophysical interpretation beyond the calculation of total porosity. Synthetic and field examples indicate that the mitigation of invasion effects becomes important in the case of salty mud filtrate invading gas-bearing formations. The advantage of the developed inversion-based interpretation method is its ability to estimate layer-by-layer petrophysical, compositional, and fluid properties that honor multiple nuclear measurements, their tool physics, and their associated borehole geometrical and environmental effects.

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 Seismic Data Interpretation and Petrophysical Analysis of Kabirwala Area Tola (01) Well, Central Indus Basin, Pakistan

2021 ◽  
Vol 11 (7) ◽  
pp. 2911
Author(s):  
Naveed Ahmad ◽  
Sikandar Khan ◽  
Abdullatif Al-Shuhail
Keyword(s):  
Gamma Ray ◽  
Water Saturation ◽  
Research Work ◽  
Total Porosity ◽  
Effective Porosity ◽  
Indus Basin ◽  
Drilling Process ◽  
Reservoir Properties ◽  
Log Data ◽  
Petrophysical Analysis

Well logging is a significant procedure that assists geophysicists and geologists with making predictions regarding boreholes and efficiently utilizing and optimizing the drilling process. The current study area is positioned in the Punjab Territory of Pakistan, and the geographic coordinates are 30020′10 N and 70043′30 E. The objective of the current research work was to interpret the subsurface structure and reservoir characteristics of the Kabirwala area Tola (01) well, which is located in the Punjab platform, Central Indus Basin, utilizing 2D seismic and well log data. Formation evaluation for hydrocarbon potential using the reservoir properties is performed in this study. For the marked zone of interest, the study also focuses on evaluating the average water saturation, average total porosity, average effective porosity, and net pay thickness. The results of the study show a spotted horizon stone with respect to time and depth as follows: Dunghan formation, 0.9 s and 1080.46 m; Cretaceous Samana Suk formation, 0.96 s and 1174.05 m; Datta formation, 1.08 s and 1400 m; and Warcha formation, 1.24 s and 1810 m. Based on the interpretation of well logs, the purpose of petrophysical analysis was to identify hydrocarbon-bearing zones in the study area. Gamma ray, spontaneous potential, resistivity, neutron, and density log data were utilized. The high zone present in the east–west part of the contour maps may be a possible location of hydrocarbon entrapment, which is further confirmed by the presence of the Tola-01 well.

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 Hydrocarbon Reservoir Evaluation: a case study of Tymot field at southwestern offshore Niger Delta Oil Province, Nigeria

2018 ◽  
Vol 2 (2) ◽  
Author(s):  
Victor Cypren Nwaezeapu ◽  
Izediunor U. Tom ◽  
Ede T. A. David ◽  
Oguadinma O. Vivian
Keyword(s):  
Niger Delta ◽  
Gamma Ray ◽  
Water Saturation ◽  
Reservoir Evaluation ◽  
Hydrocarbon Reservoir ◽  
Structural Style ◽  
Average Porosity ◽  
Net To Gross ◽  
Well Data

Abstract: Aim: This study presents the log analysis results of a log suite comprising gamma ray (GR), resistivity (LLD), neutron (PHIN), density (RHOB) logs and a 3D seismic interpretation of Tymot field located in the southwestern offshore of Niger delta. This study focuses essentially on reserves estimation of hydrocarbon bearing sands. Well data were used in the identification of reservoirs and determination of petrophysical parameters and hydrocarbon presence. Three horizons that corresponded to selected well tops were mapped after well-to-seismic tie. Structural depth maps were created from the mapped horizons. The structural style is dominated by widely spaced simple rollover anticline bounded by growth faults, and this includes down-to-basin faults, antithetic faults and synthetic faults. The petrophysical values – the porosity, net-to-gross, water saturation, hydrocarbon saturation that were calculated yielding  an average porosity value  of 0.23, water saturation of 0.32 and an average net-to-gross value of 0.62. Three horizons H1, H2 and H3 were mapped. The three horizons marked the tops of reservoir sands and provide the structures for hydrocarbon accumulation. Hydrocarbon in-place was estimated. The total hydrocarbon proven reserves for the mapped horizons H1, H2, and H3 were estimated to be 39.04MMBO of oil and 166.13BCF for sand E. 

scholarly journals Lithology and Fluid discrimination of Sody field of the Nigerian Delta

2020 ◽  
Vol 24 (8) ◽  
pp. 1321-1327
Author(s):  
S.C.P. Finecountry ◽  
S. Inichinbia
Keyword(s):  
Niger Delta ◽  
Gamma Ray ◽  
Water Saturation ◽  
Total Porosity ◽  
Reservoir Properties ◽  
High Hydrocarbon ◽  
Average Porosity ◽  
Reservoir Porosity ◽  
Shaly Sand ◽  
Net To Gross

The lithology and fluid discrimination of an onshore Sody field, of the Niger Delta was studied using gamma ray, resistivity and density logs from  three wells in the field in order to evaluate the field’s reservoir properties. Two reservoir sands (RES 1 and RES 2) were delineated and identified as hydrocarbon bearing reservoirs. The petrophysical parameters calculated include total porosity, water saturation and volume of shale. The results obtained revealed that the average porosity of the reservoir sands, range from 21% to 39%, which is excellent indicator of a good quality reservoir and probably reflecting well sorted coarse grain sandstone reservoirs with minimal cementation. Water saturation is low in all the reservoirs, ranging from 2% to 32%, indicating that the proportion of void spaces occupied by water is low, and implying high hydrocarbon saturation. The crossplot discriminated the reservoirs lithologies as sand, shaly sand and shale sequences, except well Sody 2 which differentiated its lithologies as sand and shale sequences and distinguished the reservoirs’ litho-fluids into three, namely; gas, oil and brine. These results suggest that the reservoirs sand units of Sody field contain significant accumulations of hydrocarbon. Keywords: Reservoir, porosity, net-to-gross, impedance, lithology

Theoretical and Experimental Bases for the Dual-Water Model for Interpretation of Shaly Sands

1984 ◽  
Vol 24 (02) ◽  
pp. 153-168 ◽  
Author(s):  
C. Clavier ◽  
G. Coates ◽  
J. Dumanoir
Keyword(s):  
Volume Fraction ◽  
Water Saturation ◽  
Free Water ◽  
Total Porosity ◽  
Water Model ◽  
Implicit Assumption ◽  
Formation Water ◽  
Formation Factor ◽  
Water Conductivity ◽  
Clayey Sand

Abstract A simple petrophysical model proposed by Waxman and Smits (WS)1 in 1968 and Waxman and Thomas (WT)2 in 1972 accounts for the results of an extensive experimental study on the effects of clays on the resistivity of shaly sands. This model has been well accepted by the industry despite a few inconsistencies with experimental results. It is proposed that these inconsistencies resulted from the unaccounted presence of salt-free water at the clay/water interface. Electrochemistry indicates that this water should exist, but is there enough to influence the results? Both a theoretical study and reinterpretation of Waxman-Smits-Thomas data show that there is. The corresponding new model starts from the Waxman and Smits concept of supplementing the water conductivity with a conductivity from the clay counterions. The crucial step, however, is equating each of these conductivity terms to a particular type of water, each occupying a representative volume of the total porosity. This approach has been named the "dual-water" (DW) model because of these two water types - the conductivity and volume fraction of each being predicted by the model. The DW model has been tested on most of the core data reported in Refs. 1 and 2. The DW concept is also supported by log data3 and has been successfully applied to the interpretation of thousands of wells. However, the scope of this paper remains limited to the theoretical and experimental bases of the DW model. The Petrophysical DW Model The purpose of this model is to account for the resistivity behavior of clayey sands. For petrophysical considerations, a clayey formation is characterized by its total porosity, ft; its formation factor, F0; its water saturation, SwT; its bulk conductivity, Ct; and its concentration per unit PV of clay counterions, Qv. The formation behaves like a clean formation with identical parameters ft, F0, and Swt but containing a water whose conductivity, Cwe, differs from the bulk formation water. Neither the type of clays nor their distribution influences the results. Since the formation obeys Archie's laws,Equation 1 The clayey sand equivalent water conductivity, Cwe, can be considered a mixture of two waters. 1. A clay water surrounds the clay particles but has a conductivity independent of the type and amount of clay. Its conductivity, Ccw, comes exclusively from the clay counterions. The volume fraction of clay water, Vcw, is directly proportional to the counterion concentration, QvEquation 2 where vQ is the amount of clay water associated with 1 unit (meq) of clay counterions. 2. The water further away from the clay is called far water. Its conductivity, Cw, and ionic concentration correspond to the salinity of bulk-formation water. The volume fraction of this water, Vfw, is the balance between the total water content and the clay water.Equation 3 The implicit assumption is that the far water is displaced preferentially by hydrocarbons.

Integration of Nuclear Spectroscopy Technology and Core Data Results for Through-Casing TOC Measurement and Saturation Analysis: A Case Study in Najmah-Sargelu Reservoir, South Kuwait

2020 ◽  
Vol 61 (6) ◽  
pp. 600-609
Author(s):  
Ramdane Bouchou ◽  
◽  
Ali Abughneej ◽  
Monica Ghioca ◽  
Nora P. Alarcon ◽  
...  
Keyword(s):  
Organic Carbon ◽  
Gamma Ray ◽  
Produced Water ◽  
Total Porosity ◽  
Total Carbon ◽  
Nuclear Spectroscopy ◽  
Oil Saturation ◽  
Excess Carbon ◽  
Core Data ◽  
The Matrix

The acquisition of openhole logging data is not always guaranteed because of difficult drilling environments. In such cases, formation evaluation, and thus the completion program, becomes a real challenge. The situation becomes more complex when dealing with unconventional reservoirs with very tight carbonates and organic carbon-rich formations. This paper presents a method to measure the total organic carbon (TOC), which, in this paper, represents the organic carbon in the matrix (kerogen and coal), and to estimate oil saturation in such a challenging environment. A suite of wireline tools (gamma ray (GR), Spectralog, density, neutron, nuclear spectroscopy) was run through 7.625-in. casing to evaluate the formation and to quantify TOC and the oil in the pores. The nuclear spectroscopy tool, which was the master tool, measures the total carbon in the formation. Part of this carbon is attributed to the inorganic matrix (carbonates). Another part is attributed to the organic matter in the matrix (kerogen). The remaining carbon, or excess carbon, is mainly the carbon inside the pores. The process consists of integrating the conventional logging data, spectroscopy data, core data, and some geological constraints to estimate corrected porosity, mineralogy, and TOC in the kerogen-rich intervals. The excess carbon, which is not attributed to the matrix and TOC, is used to estimate oil saturation. Finally, core data are used to validate the analysis results. The presented methodology has been applied to a casedhole well with no openhole data previously acquired due to drilling issues. The primary target of the well, in the deep section, produced water; then, the operator decided to revisit the second target and complete it for testing. It has to be pointed out that over the well-cemented intervals, the results showed a very good matching of the corrected total porosity and the core total porosity. Relying on TOC and saturation analysis results, the operator selected the most promising intervals to be tested. Testing results have shown excellent matching between production results and oil saturation analysis results. TOC and oil saturation quantification using nuclear spectroscopy technology and core data results showed its success in both tight carbonates and organic carbon-rich reservoirs. This method will be a solution to evaluate and complete any wells with no openhole data acquired, and also to evaluate and complete unconventional formations where the conventional methods have shown their limitations.

Determination of potassium-40 by gamma ray spectrometry for potassium-40/argon-40 geochronology

1969 ◽  
Vol 41 (10) ◽  
pp. 1319-1322 ◽  
Author(s):  
Lucia. Civetta ◽  
Paolo. Gasparini ◽  
John Allan Stewart. Adams
Keyword(s):  
Gamma Ray ◽  
Gamma Ray Spectrometry ◽  
Potassium 40
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