Reservoir Lithology Research Articles

The Study on the Oil-water Distribution Rules of Putaohua Reservoirs in Z Block

The Putaohua formation in Z block plays an important role in Jilin oil field. It’s the lithologic reservoir,much composed of gray-green, magenta mudstone, argillaceous siltstone and fine sandstone. The Putaohua formation in Z block is mainly controlled by local structure. Reservoir is thin and drilling rate is low, so Putaohua formation in Z block has a good development prospect. By the analysis of typical reservoir profile of Putaohua formation in Z block we can know the reservoir types are mainly lithologic reservoirs and fault-lithology reservoirs, further we can comprehend that the oil-water distribution is controlled by structure and lithology.

Evaluation of dolomite reservoirs in the Longwangmiao Formation, Lower Cambrian in Northern Sichuan basin, China

Abstract With the extended petroleum exploration of the carbonate reservoir in the Longwangmiao Formation, Lower Cambrian in Sichuan basin, looking for a new favorable exploration area is the primary task in current exploration. This paper focusing on the dolomite reservoir in the Longwangmiao Formation in the Northern Sichuan basin, will evaluate the reservoir conditions, including reservoir lithology, reservoir spaces, physical properties and other basic characteristics. Combined with sedimentary environment study and diagenesis analysis, the genetic mechanism of Longwangmiao reservoir in study area will be discussed. It indicates that the reservoir rocks of Longwangmiao Formation in the study area are composed of dolarenite and crystalline dolomite, and the main reservoir spaces are intergranular dissolved pores, intragranular dissolved pores and intercrystalline dissolved pores. However, most of dissolved pores have been filled with bitumen, which lead to the reservoir properties very poor, both the porosity and permeability are worse than that of central Sichuan basin, so the reservoir in the Longwangmiao Formation in the Northern Sichuan basin is low-porosity and low-permeability reservoir. During the Early Cambrian Longwangmiao period, the study was near the old-land, and the energy of sea water was not enough to deposit many grain shoals, which cause the sediments are small with lots of quartz and muds. Moreover, because lacking of large scale karstification in the late diagenesis, there isn't much dissolved pores and vugs develop in the Longwangmiao Formation. Some Intergranular dissolved pores and intercrystalline dissolved pores formed by the early atmosphere water dissolved exist as some reservoir spaces, but most of them have been filled with bitumen, which was residual when the ancient oil reservoir transformed. Above factors cause the Longwangmiao Formation in the Northern Sichuan basin become not a very favorable reservoir in Sichuan basin.

CHARACTERIZATION AND DFN MODELLING OF THE FRACTURE NETWORK IN A MESOZOIC KARST RESERVOIR: GOMBA OILFIELD, PALEOGENE BASIN, CENTRAL HUNGARY

Reservoir rocks at Gomba oilfield, located in the Hungarian Paleogene Basin, include fractured and karstified Triassic carbonates with significant fluid storage potential. However little information is available about the fracture network in these carbonates which has led to production problems at Gomba. The purpose of this study is to investigate the relationship between the spatial distribution of high porosity zones in the carbonates and the microfracture system. For this evaluation, individual fractures were studied and used in a discrete fracture network (DFN) modelling exercise at two wells, Gomba‐1 and Gomba‐3. The investigation took place at two different scales. Fracture length and aperture distributions were derived at the micro‐scale (mm to cm), whereas fracture density and fracture orientation data were investigated at the reservoir scale. The results of both investigations were taken into consideration in the modelling. The results of the fracture network models were compared to reservoir lithologies which ranged from fractured carbonates to collapse breccias.Based on the results, it appears that the porosity associated with a significant proportion of the fractures was increased as a result of dissolution. Fracture distribution was not uniform along the studied well paths, and fracture orientation was chaotic at particular depth intervals. On the basis of the DFN models, three different fractured zones are predicted to occur in the reservoir, but only two of the zones have significant fracture porosity.Comparing these results with petrographic observations, an epigene karst phase is proposed which is older than (or the same age as) the time of hydrocarbon migration; karst‐related voids were therefore important pathways for fluid migration. The void system and karst caverns partly collapsed during subsequent burial, resulting in karst‐related traps. By analogy with modern cave systems, the karst cavern zones at Gomba probably extend horizontally rather than vertically, and are oriented NE‐SW parallel to major structural lineaments.

Formation mechanism of high-quality reservoirs of Lower Cretaceous volcaniclastic sedimentary rocks in Songliao Basin

High abundance gas reservoirs were discovered in the volcaniclastic sedimentary rocks of Wangfu faulted depression in Songliao Basin, but the distribution pattern and formation mechanism of this type of high-quality reservoirs were not clear. In the Shahezi Formation of Well Block CS6 in Wangfu faulted depression, the void space type, reservoir property, pore throat and pore diameters were studied by means of the casting thin section, helium intrusion porosimetry, mercury intrusion porosimetry (MIP) and nuclear magnetic resonance (NMR) methods, moreover, formation mechanism and main controlling factors of the high-quality reservoirs were discussed. Results showed that lithology of high-quality reservoirs consisted of the volcaniclastic sedimentary agglomerate and the volcaniclastic sedimentary breccia, and exhibited the coarsening-upward characteristics. Furthermore, three types (seven subtypes) of void spaces were identified, among which the intragranular vesicles with primary abundant pores were uniquely developed in the high-quality reservoirs of volcaniclastic sedimentary rocks, indicating this high-quality reservoir belonged to the large-pore and small-throat reservoir; porosity and permeability of volcaniclastic sedimentary agglomerate were slightly higher than those of volcaniclastic sedimentary breccia, and both were significantly higher than those of sedimentary rock in the Shahezi Formation, the porosity was closely related with the burial depth. Formation mechanisms of reservoirs in the volcaniclastic sedimentary rocks were release of volatile matters in parent rocks, grain support, dissolution and tectonic modification, among which the former two were the main controlling factors. The high-quality reservoirs over the study area were mainly distributed in the central part of the fan of volcaniclastic sedimentary rocks, among which the grain-supported, coarse-grained volcaniclastic sedimentary rocks with high content of intragranular vesicular detritus and burial depth less than 3000 m were the most favorable area for development of the high-quality reservoirs.

Bayesian discriminant analysis of lithofacies integrate the Fisher transformation and the kernel function estimation

The accurate identification of lithofacies is indispensable for reservoir parameter prediction. In recent years, the application of multivariate statistical methods has gained more and more attention in petroleum geology. In terms of the identification for lithofacies, the commonly used multivariate statistical methods include discriminant analysis and cluster analysis. Fisher and Bayesian discriminant analyses are two different discriminant analysis methods, which include intrinsic advantages and disadvantages. Given the discriminant efficiency of different methods, calculation cost, difficulty in the degree of determining the parameters, and the ability to analyze statistical characteristics of data, we put forward a new method combined with seismic information to classify reservoir lithologies and pore fluids. This method integrates the advantages of Fisher discrimination, the kernel function, and Bayesian discrimination. First, we analyze training data and search a projection direction. Then, data are transformed through Fisher transformation according to this direction and different kinds of facies can be distinguished more efficiently by exploiting transformed data than by using primitive data. Subsequently, using the kernel function estimates the conditional probability density function of the transformed variable. A classifier is constructed based on Bayesian theory. Then, the pending data are input to the classifier and the solution whose posteriori probability reaches the maximum is extracted as the predicted result at each grid node. An a posteriori probability distribution of predicted lithofacies can be acquired as well, from which interpreters can evaluate the uncertainty of the results. The ultimate goal of this study is to provide a novel and efficient lithofacies discriminant method. Tests on model and field data indicate that our method can obtain more accurate identification results with less uncertainty compared with conventional Fisher approaches and Bayesian methods.

The mechanism and verification analysis of permafrost-associated gas hydrate formation in the Qilian Mountain, Northwest China

Muri Basin in the Qilian Mountain is the only permafrost area in China where gas hydrate samples have been obtained through scientific drilling. Fracture-filling hydrate is the main type of gas hydrate found in the Qilian Mountain permafrost. Most of gas hydrate samples had been found in a thin-layer-like, flake and block group in a fracture of Jurassic mudstone and oil shale, although some pore-filling hydrate was found in porous sandstone. The mechanism for gas hydrate formation in the Qilian Mountain permafrost is as follows: gas generation from source rock was controlled by tectonic subsidence and uplift--gas migration and accumulation was controlled by fault and tight formation--gas hydrate formation and accumulation was controlled by permafrost. Some control factors for gas hydrate formation in the Qilian Mountain permafrost were analyzed and validated through numerical analysis and laboratory experiments. CSMGem was used to estimate the gas hydrate stability zone in the Qilian permafrost at a depth of 100–400 m. This method was used to analyze the gas composition of gas hydrate to determine the gas composition before gas hydrate formation. When the overlying formation of gas accumulation zone had a permeability of 0.05 × 10−15 m2 and water saturation of more than 0.8, gas from deep source rocks was sealed up to form the gas accumulation zone. Fracture-filling hydrate was formed in the overlap area of gas hydrate stability zone and gas accumulation zone. The experimental results showed that the lithology of reservoir played a key role in controlling the occurrence and distribution of gas hydrate in the Qilian Mountain permafrost.

Study on fracture identification of shale reservoir based on electrical imaging logging

In recent years, shale gas exploration has made important development, access to a major breakthrough, in which the study of mud shale fractures is extremely important. The development of fractures has an important role in the development of gas reservoirs. Based on the core observation and the analysis of laboratory flakes and laboratory materials, this paper divides the lithology of the shale reservoirs of the XX well in Zhanhua Depression. Based on the response of the mudstone fractures in the logging curve, the fracture development and logging Response to the relationship between the conventional logging and electrical imaging logging to identify the fractures in the work, the final completion of the type of fractures in the area to determine and quantify the calculation of fractures. It is concluded that the fracture type of the study area is high and the microstructures are developed from the analysis of the XX wells in Zhanhua Depression. The shape of the fractures can be clearly seen by imaging logging technology to determine its type.

Derived Rock Attributes Analysis for Enhanced Reservoir Fluid and Lithology Discrimination

Derived Rock Attributes Analysis for Enhanced Reservoir Fluid and Lithology Discrimination

USE OF WELL-LOGS FOR PETROPHYSICAL EVALUATION OF ABU MADI RESERVOIR IN ABU MADI - EL-QARA - NIDOCO AREA, NORTHERN NILE DELTA, EGYPT

The objective of the present study is to evaluate the reservoir characteristics of the Late Miocene Abu Madi Formation (Abu Madi Levels II and III) at Abu Madi-El-Qara-Nidoco area, northern Nile Delta, Egypt. The study area is located between Longitude 31° 13` 48`` -31° 24` 36``E and Latitude 31° 21` 36``- 31° 37` 12`` N. Open-hole wireline log data of seven wells are used in this study. The petrophysical characteristics of the studied formation are thoroughly investigated to elucidate its hydrocarbon potentialities. The vertical variation of the petrophysical characteristics is presented as Lithosaturation cross-plots. The parameters distribution maps (shale volume, porosity, fluid saturation, net pay thickness and hydrocarbon saturation) are constructed to represent the lateral variation of petrophysical characteristics. The shale model shows that the dominant shale is mainly of dispersed and laminated types. The constructed neutron-bulk density, neutron-sonic and M-N crossplots display that the main reservoir lithology is sandstone intercalated mainly with dispersed shale and minor laminated shale in Level III and dispersed to laminated shale in Level II. It is also shown that Abu Madi Formation has poor to very good porosities range from 0.03 to 0.22 for Level II and from 0.06 to 0.19 for Level III. The most favorable places for hydrocarbon reservoirs occupy southwestern part for Abu Madi Level II reservoir and in the middle, the middle-west, the middle-east and the southeastern parts for Abu Madi Level III reservoir.

Model Parameterization and P-wave AVA Direct Inversion for Young’s Impedance

AVA inversion is an important tool for elastic parameters estimation to guide the lithology prediction and “sweet spot” identification of hydrocarbon reservoirs. The product of the Young’s modulus and density (named as Young’s impedance in this study) is known as an effective lithology and brittleness indicator of unconventional hydrocarbon reservoirs. Density is difficult to predict from seismic data, which renders the estimation of the Young’s impedance inaccurate in conventional approaches. In this study, a pragmatic seismic AVA inversion approach with only P-wave pre-stack seismic data is proposed to estimate the Young’s impedance to avoid the uncertainty brought by density. First, based on the linearized P-wave approximate reflectivity equation in terms of P-wave and S-wave moduli, the P-wave approximate reflectivity equation in terms of the Young’s impedance is derived according to the relationship between P-wave modulus, S-wave modulus, Young’s modulus and Poisson ratio. This equation is further compared to the exact Zoeppritz equation and the linearized P-wave approximate reflectivity equation in terms of P- and S-wave velocities and density, which illustrates that this equation is accurate enough to be used for AVA inversion when the incident angle is within the critical angle. Parameter sensitivity analysis illustrates that the high correlation between the Young’s impedance and density render the estimation of the Young’s impedance difficult. Therefore, a de-correlation scheme is used in the pragmatic AVA inversion with Bayesian inference to estimate Young’s impedance only with pre-stack P-wave seismic data. Synthetic examples demonstrate that the proposed approach is able to predict the Young’s impedance stably even with moderate noise and the field data examples verify the effectiveness of the proposed approach in Young’s impedance estimation and “sweet spots” evaluation.

Lithology and oil-bearing properties of tight sandstone reservoirs: Chang 7 member of Upper Triassic Yanchang Formation, southwestern Ordos Basin, China

Using core, well logging, geological analysis, production, and test data, this study characterizes a method of well logging for identifying lithology, oil or water layers, and thickness of oil layers of tight sandstone reservoir in the Chang 7 member of the Upper Triassic Yanchang Formation, southwestern Ordos Basin, China. This reservoir consists of two rock types: fine sandstone and siltstone. The fine sandstone has distinct oil traces and flecks, which strongly indicate the presence of oil, and this rock is therefore the superior reservoir. The siltstone exhibits essentially no oil shows and thus is an unproductive layer. A method of density and neutron curve normalization and overlay was used to identify the tight fine sandstone, tight siltstone, mudstone, and shale. The criteria for identifying the tight fine sandstone are a natural gamma value of less than 93 API (American Petroleum Institute units) and a difference between the normalized curves exceeding 0.05. A resistivity-porosity plot was used to identify oil or water layers relatively effectively. The criteria for identifying the tight oil layers are (1) a resistivity exceeding 28 Ω·m and a porosity exceeding 9.5% or (2) a resistivity between 20 and 28 Ω·m, a porosity exceeding 9.5%, and an oil saturation exceeding 65%. Based on the lithologic identification via normalization and overlay of the density and neutron curves and the criteria for distinguishing the tight oil layers, the thickness of the tight fine sandstone oil reservoir was accurately determined by overlaying the normalized difference curve on the resistivity curve.

Play evaluation on lithologic reservoirs in hydrocarbon-rich sags in Sudan: a case study on Fula sag, Muglad Basin

Play evaluation on lithologic reservoirs in hydrocarbon-rich sags in Sudan: a case study on Fula sag, Muglad Basin

AN EXPERIMENTAL STUDY ON RESISTIVITY AND CONDUCTIVE MECHANISM IN LOW‐PERMEABILITY RESERVOIRS WITH COMPLEX WETTABILITY

AbstractAs the clay film developed in low‐permeability lithologic reservoirs absorbs oil, reservoirs become oil‐wet, which results in abnormally high resistivity oil‐water layers and water layers. Such layers bring great challenges to the identification of oil and water layers. In order to make clear the resistivity response characteristics and conductive mechanism in reservoirs with different wettability, cores were selected in Chang 8 formation, Yanchang group, Upper Triassic, the western Ordos basin of China. Experiments were conducted with these samples to simulate the process of oil displacing water, ageing and water displacing oil. In addition, the contact angles of thin slices after washing oil were also tested. The experimental results show that abnormally high resistivity cores are not completely water‐wet after washing oil. However, the formation factors of abnormally high resistivity cores and normal resistivity cores have little difference. In the process of oil displacing water, the relationship between normal resistivity core resistivity index and water saturation is linear in a log‐log plot, while that of abnormally high resistivity cores is convex. The resistivity of abnormally high resistivity cores remains unchanged during ageing process. Combining the analysis of nuclear magnetic resonance (NMR) T2 spectra under different conditions, it can be inferred that wettability of abnormally high resistivity cores has become less water‐wet after oil displacing water, whereas the ageing process has little effect on the wettability. In the process of water displacing oil, the relation between abnormally high resistivity core resistivity index and water saturation is almost linear, which shows that the conductive structure of rock is not changed. Based on the analyses and discussions of these experimental results, a hydrocarbon accumulation mode and the corresponding conductive mechanism are proposed for low‐permeability reservoirs with complex wettability. It shows that abnormally high resistivity water layers are caused by the destruction of continuous conductive paths under oil‐wet condition. The researches and experiments are of great importance for understanding the conductive mechanism, identifying oil and water layers and evaluating water flooded formations in low‐permeability reservoirs with complex wettability.

Technology Focus: Seismic Applications (March 2017)

Technology Focus My career in the oil and gas industry started in 1975. Shortly thereafter, a theme that became wildly popular in conferences, workshops, and internal boardrooms was better integration of seismic with other oilfield disciplines. Initial progress was slow, but, if we fast-forward to today, we see that significant strides indeed have been made. A good representation of integration papers appeared this past year, so that is the theme we will use. Advancement of the integration of seismic with other oilfield disciplines has been fueled by two factors. First, evolutionary advances in seismic technologies naturally led to more-powerful integration. A simple example is the progress made in bandwidth. In this regard, advances in seismic sources, field recording equipment, and data processing all benefited interpretation, inversion, and reservoir modeling. For example, in the 1980s, a commonly used vibrator sweep in land surveys was 12–48 Hz. Today, sweeps start as low as 2 Hz and often go up to more than 100 Hz. The benefits to resolution and derisking have been striking. Second, several developments in seismic were motivated in direct response to the needs of interpreters and engineers. For instance, the appearance of creative, new, high-channel-count survey designs provided full-azimuth, densely sampled data that led to striking advances in imaging complex structures (especially in subsalt settings) and provided the wherewithal for characterizing natural fractures and stress in both conventional and unconventional plays. Indeed, this tighter integration of seismic with geomechanics energized the rise of the microseismic technique. Six integration papers were selected. Three are presented here in summary format, and three are listed for additional reading. They come from all over the world, cover a range of reservoir lithologies, and deal with a suite of geologic settings. Let’s keep the progress moving. Recommended additional reading at OnePetro: www.onepetro.org. SPE 183289 Seismic Reservoir Characterization of Carbonate Reservoirs—Case Study of the Mishrif Formation, Zubair Field, Iraq by J.M. Rodrigues, Eni, et al. IPTC 18956 Seismic-Driven Lithofacies for Geological-Model Infilling in a Deep Offshore Turbiditic Field—Case Study by Victoriano Da Silva, Total E&P, et al. SPE 181872 Microseismic Mapping Improves Understanding of a Complex Reservoir: A Case Study in a Southern Sichuan Shale Gas Field by Yang Wang, Halliburton, et al.

Obtaining a high-resolution geological and petrophysical model from the results of reservoir-orientated elastic wave-equation-based seismic inversion

A previous geological and petrophysical model of the fluvio-deltaic Book Cliffs outcrops contained eight lithotypes, within each of which a number of lithologies were grouped. While this model was an adequate representation of the overall depositional architecture, for reservoir-geological purposes the potential reservoir and non-reservoir lithologies needed to be separated. Here, a new and more detailed geological model is presented in which more differentiation is put on the potential reservoir lithologies. This new model contains 12 lithologies with layers down to 1 m in thickness. Assuming a burial depth of 3 km and an average clay content, representative rock physical properties are assigned to lithologies based on published data. After the model thickness has been stretched by a factor of 4 in order to represent a more realistic reservoir, a full-waveform forward seismic response is modelled. These data are used as inputs into an iterative elastic wave-equation-based inversion scheme, with the goal to retrieve the rock properties and layer geometries. The results of this conceptual study show that sandstone units in the shoreface and distributary channels, which are potential reservoirs, are successfully identified. The recovery of medium parameters has a high resolution because the non-linear relationship between rock properties and the seismic data has been exploited.

Karst reservoirs seismic prediction of Lower Permian Maokou Formation in central Sichuan Basin, SW China

Abstract Based on the new well logging and seismic data of recent years in central Sichuan Basin, the comprehensive study of the karst reservoirs in the Lower Permian Maokou Formation was carried out using new geophysical technology. The quantitative rock physical modeling and analysis demonstrated that the velocity and density of the reservoir decrease with the increase of porosity, shale volume and gas saturation. Seismic forward modeling analysis based on rock physical modeling confirmed that the reflection characteristics of the karst reservoirs show ‘dim point’ at top of the Maokou Formation, which is weak amplitude and low frequency. Through seismic attributes and acoustic impedance inversion, four large areas of favorable karst reservoirs are predicted. Based on the comprehensive evaluation, it is thought that karst lithologic reservoirs in up-dip direction can be formed, and the west to Shehong and Yanting are the most favorable exploration areas in the central Sichuan Basin.

四川盆地威东–安岳地区须二段储层特征及有利区预测

应用岩心铸体薄片鉴定、压汞实验以及孔渗等分析化验资料，对安岳地区须家河组须二段砂岩储集特征进行综合分析。结果表明，须二段砂岩储层的岩性主要以岩屑长石砂岩及长石岩屑砂岩为主，其次有长石石英砂岩及岩屑石英砂岩；储集孔隙类型主要为残余粒间孔、粒内溶孔、其次为铸模孔、晶间微孔；储层的排驱压力高、饱和中值压力高，储集空间类型为细孔微喉型，总体上属于低孔低渗和特低孔特低渗储层。结合储层有效厚度、孔隙度平面分布、已钻井产气情况等，预测出3个须二段储层分布有利区。 The sandstone reservoir characteristics of the 2nd member of Xujiahe formation in Anyue area were comprehensively analyzed by core casting slice identification, mercury injection test and porosity and permeability analysis. The results show that the lithology of the 2nd member sand-stone reservoir mainly consists of debris feldspar sandstone and feldspar debris sandstone; fol-lowed by feldspar quartz sandstone and debris quartz sandstone. The pore types of the reservoir are mainly residual intergranular pore, intragranular dissolved pore, followed by mould pore and intercrystalline pore. The displacement pressure of reservoir is high, the median pressure of saturation is high, and the type of reservoir space is micropore type. Generally, it belongs to low porosity, low permeability reservoir and extremely low porosity, extremely low permeability reservoir. Combined with the effective thickness of reservoir, the plane distribution of porosity and the situation of gas production in drilling, it is predicted that there are 3 favorable reservoirs for the 2nd member of Xujiahe formation.

Predicting Reservoir Performance Using the Elastic Properties of Well Logs in Fabi Field, Niger Delta Basin in Nigeria

In recent times, characterization of reservoir using elastic properties of the well logs is limited to discrimination of reservoir fluids and lithologies which do not precisely reflect reservoir characteristics. In this study, we propose a robust approach that uses the well log derived attributes to predict the effects of the production related changes and performance levels of the reservoirs. First, the elastic attributes were generated from the well logs using the transform menu of the E-log program. The appropriate pairs of the attributes were cross-plotted and color overlay of the most robust attributes established. The cross-plot of Lambda-Rho versus Mu-Rho revealed the gas charged sand, brine charged sand and streak of shale in HD5000 reservoir. The color overlay of the lambda-Rho showed very high degree of brine saturation and very low gas saturation. The cross plot of velocity ratio versus P-impedance in HD8000 reservoir revealed hydrocarbon charged sand which was associated with very low velocity ratio, acoustic impedance values and brine saturation. The color overlay of acoustic impedance showed very high hydrocarbon saturation and low brine saturation. The cross plot of Mu-rho versus density at HD9000 reservoir also revealed the hydrocarbon charged sand (very low-density values) and brine charged sand. The color overlay of density revealed relatively high hydrocarbon and low brine saturation. The high brine saturation in the reservoirs probably resulted from increase in formation water due to production and steam injection program which is an indication of reservoir depletion. However, the results indicate that HD8000 and HD9000 reservoirs are still active for more hydrocarbon production while HD5000 reservoir is not.

伊拉克M油田Asmari组碎屑岩与碳酸盐岩混合沉积特征

结合薄片、岩心、测井等及相关生产资料，对伊拉克M油田Asmari组B段储层特征及成因进行了分析。Asmari组B段岩性复杂，碳酸盐岩与陆源碎屑岩呈现互层和成分的混积，储层非均质性强，研究认为沉积相以三角洲、混积台地和局限台地的交替变化为特点。构造运动和海平面频繁震荡共同控制碎屑岩和碳酸盐岩的分布，形成了两种不同岩性储层的混积现象。 Based on thin section, core, well logging and production data, the characteristics and genesis of B reservoir in Asmari formation in Iraq were studied. The lithology of B reservoir is complex: carbonate and terrigenous clastic rock present interbeding and mixed composition; reservoir heterogeneity is strong. The sedimentary facies alternate among delta, mixed platform facies and restricted platform facies. Tectonic movement and frequent change of sea level control the distribution of clastic rock and carbonate rock, which results in two different lithologic reservoir of mixed phenomenon.

Use of Well Logs for Petrophysical Evaluation of Abu Madi Reservoir in Abu Madi-ElQara-Nidoco Area, Northern Nile Delta, Egypt

The open-hole wire line log data of seven wells are used to study the petrophysical characteristics of the Late Miocene Abu Madi Formation (levels II and III) in Abu Madi-El-Qara-Nidoco area, northern Nile Delta, Egypt. The vertical variation of the petrophysical characteristics is presented as lithosaturation cross-plots. The parameters distribution maps (shale volume, effective porosity, fluid saturation, net pay thickness and hydrocarbon saturation) are used to represent the lateral variation of petrophysical characteristics. Cross plots show that the main reservoir lithology is shaly sandstone with laminated to dispersed shale in level II and dispersed shale and minor laminated shale in level III. The shale volume ranges from 0.19 to 0.71 for level II and from 0.19 to 0.47 for level III. The effective porosity ranges from 0.03 to 0.22 for level II and from 0.06 to 0.19 for level III. The hydrocarbon saturation reaches up to 0.88 for level II and up to 0.81 for level III. The net-reservoir thickness ranges from 50 to 101 m for level II and from 30 to 153 m for level III. The net-pay thickness ranges from 75 to 90 m for level II and from 22 to 110 m for level III. Maps show that the most favorable places for hydrocarbon reservoirs occupy southwestern part for Abu Madi level II reservoir and in the middle, the middle-west, the middle-east and the southeastern parts for Abu Madi level III reservoir.