Bad Reservoir Research Articles

Structural and Stratigraphic Reservoir Characterization of “MONI” Field¸ Niger Delta.

Reservoir characterization of “MONI” field of the Niger Delta has been carried out using well log and seismic data. The study is aimed at delineating structural and stratigraphic features associated with hydrocarbon entrapment of the field. Lithostratigraphic correlation reviewed two main lithologies which are reservoir sands and seal shales. Well log correlation and interpretation across the field indicates – main stratigraphic bounding surface which include two sequence boundaries and one maximum flooding surface. This indicates about three depositional sequences exists in the study area. Stacking patterns (progradation, retrogradation, and aggradation) were delineated and interpreted as lowstand system tract (LST), highst and system tract (HST), and transgressive system tract (TST). The alternation of LST, HST and TST offers good reservoir and seal for the hydrocarbon accumulation. The depositional environment of the reservoirs ranges from subaerial channel deposits, barrier bar, tidal channel sands to delta distributary channel fill. Subaerial channel deposits have a bad reservoir quality, tidal channel sands possess a fair reservoir quality while delta distributary channel fill have a good reservoir quality. Petrophysical analysis shows that three reservoirs delineated have a porosity ranging from 19.37% to 23.62%, permeability ranging from 1408.71 to 1855.36 mD, a Net-to-Gross ranging from 0.46 to 0.88, volume of shale ranging from 11.72% to 24.92%, Water saturation ranging from 37.24% to 47.96% and hydrocarbon saturation ranging from 52.04% to 62.76%. Structural interpretation reviewed four main faults that serves as traps to the accumulation of hydrocarbon. Three hydrocarbon bearing sands were interpreted in the seismic volume. Time and depth structure maps show that the hydrocarbon bearing structure is a fault assisted anticlinal structure. Seismic facies analysis reviewed five facies. The study concluded that structural and stratigraphic features can be used to characterize reservoirs.

Assessment of reservoir properties and Buckles model for Rumaila Formation in Ahdeb oil field, Central Iraq

The present study aims to evaluate the petrophysical properties of the middle Cretaceous Rumaila Formation and to discriminate the heterogeneity of reservoir properties between three wells (AD-1, AD-2 and AD-15) which were drilled at the center of three domes of Ahdeb oil field, Central Iraq. This study was carried out using various types of well log open hole, to determine the petrophysical parameters. These logs are: gamma ray, self-potential, neutron, density, sonic and resistivity. Using Interactive Petrophysics software, the reservoir properties such as porosity, water saturation, hydrocarbon saturation and volume of bulk water have been analyzed and interpreted. This formation’s lithological study was analyzed using cross plots such as the cross-plot neutron/density and cross-plot M–N. The cross plots of studied wells reveal that the Rumaila Formation’s primary lithology is limestone because calcite is the dominant mineral. Based on petrophysical properties, which are calculated using standard equations by Interactive Petrophysics software, Rumaila Formation was divided into four zones: Ru-1, Ru-2, Ru-3 and Ru-4. The zones Ru-1, Ru-3 and Ru-4 are the main oil-bearing units in well AD-1, but they are distinguished by bad reservoir properties on the other wells. Rumaila Formation displays the bulk volume of water and permeability using Buckles model that was accomplished to illustrate the variations in formation permeability and zones of irreducible water saturation.

Flow units and rock type for reservoir characterization in carbonate reservoir: case study, south of Iraq

The current work is focused on the rock typing and flow unit classification for reservoir characterization in carbonate reservoir, a Yamama Reservoir in south of Iraq (Ratawi Field) has been selected, and the study is depending on the logs and cores data from five wells which penetrate Yamama formation. Yamama Reservoir was divided into twenty flow units and rock types, depending on the Microfacies and Electrofacies Character, the well logs pattern, Porosity–Water saturation relationship, flow zone indicator (FZI) method, capillary pressure analysis, and Porosity–Permeability relationship (R35) and cluster analysis method. Four rock types and groups have been identified in the Yamama formation depending on the FZI method, where the first group represents the bad reservoir quality (FZI-1) (Mudstone Microfacies and Foraminiferal wackestone Microfacies), the second group reflects a moderate quality of reservoir (FZI-2) (Algal wackestone–Packstone Microfacies and Bioclastic wackestone–Packstone Microfacies), the third group represents good reservoir quality (FZI-3) (Peloidal Packstone–Grainstone Microfacies), and the fourth group represents a very good reservoir quality (FZI-4) (Peloidal–oolitic Grainstone Microfacies). Capillary pressure curves and cluster analysis methods show four different rock types: a very good quality of reservoir and porous (Mega port type) (FZI-4) (Peloidal–oolitic Grainstone Microfacies) with a low irreducible Water saturation (Swi), good quality of reservoir and porous (Macro port type) (FZI-3) (Peloidal Packstone–Grainstone Microfacies), moderate quality of reservoir (Meso port type) (FZI-2) (Algal wackestone–Packstone Microfacies and Bioclastic wackestone–Packstone Microfacies), and a very fine-grained with bad reservoir quality (Micro port type) (FZI-1) (Mudstone Microfacies and Foraminiferal wackestone Microfacies) and with the higher displacement of pressure). These capillary pressure curves support the subdivision of the main reservoir unit to flow units.

Seismic analysis of the igneous intrusions in the Ash Shaer Area in the Northern Palmyrides, Syria and their impacts on petroleum system

The increasing availability of 3D seismic data and well logs from Ash Shaer Area has provided fundamental new insights into the Miocene igneous activity and its impacts on the petroleum system. The well logs, time slices, seismic attributes, and the seismic sections formed effective tools in delineating the igneous intrusions in the study area. Due to distinct geophysical property contrasts with host rocks (e.g., higher Vp, density, and resistivity than host rocks), intrusions were easily delineated on the well logs and then on the seismic data. The detailed analyses of 3D seismic data have provided valuable insights into the (1) interaction between strike-slip faults and igneous intrusion, (2) reservoir compartmentalization, and (3) geological risk in hydrocarbon exploration. Our analysis explained the bad reservoir properties (porosity and permeability) in some parts of the study area, which in turn explained why one of the drilled wells was a dry well. As a result of this study, a map of geological risk in hydrocarbon exploration and a schematic model of the reservoir formation in the Miocene have been generated.

Petrographic and petrophysical characterization of some Paleozoic rocks, Um Bogma area, Southwest Sinai, Egypt

Sixty-two samples were collected from the five formations at Um Bogma area, (Southwest Sinai, Egypt). Nine samples were collected from Sarabit El Khedim Formation, ten samples were collected from Abu Hamata Formation, eighteen samples were collected from Adedia Formation, eight samples were collected from Um Bogma Formation and eighteen samples were collected from Abu Thora Formation.The Paleozoic rocks at Um Bogma area, consist mainly of sandstones, siltstones, shales, limestone and dolostones, which are unconformably overlie igneous and metamorphic rocks (granite, diorite and gneiss) of Precambrian age.The petrographic studies were applied to identify different rock units, different facies and its diagenetic history and to reveal its effect on the storage capacity properties. Different types of porosity (oversized, intergranular, fracture and vuggy porosities) have been identified based on the petrographic investigation of the studied thin sections.The Paleozoic sandstone rock samples are characterized by porosity average about 19% for Facies 1 (quartz wack) and about 18%for Facies 2 (quartz arenite) and permeability average 420 mD for Facies 1 (quartz wack) and 690 mD for Facies 2 (quartz arenite), so these rocks can be considered as good reservoir rocks. The Paleozoic carbonate rock samples (Facies 3) are characterized by poor porosity (less than 7%) and very low permeability (less than 0.5 mD), which caused by matrix and diagenetic processes and refer to bad reservoir rocks.Porosity can be linked to the two derived electrical properties (formation resistivity factor and electrical tortuosity) of the studied Paleozoic rocks at Um Bogma area. The electrical tortuosity has significant effects on both permeability and formation resistivity factor. The permeability decreases with increasing electrical tortuosity and the relation between both of them is inverse relationship with good coefficient of correlation. The permeability decreases with increasing electrical tortuosity and the relations between both of them are inverse relationships with high coefficient of correlation. The formation resistivity factor increases with increasing electrical tortuosity and the relations between both of them are positive relationships with a fair to very high coefficient of correlation.

Reservoir characteristics of some Cretaceous sandstones, North Western Desert, Egypt

The present study aims to reveal diagenetic processes and reservoir characteristics of the subsurface Cretaceous (Upper and Lower) sandstones at the North Western Desert of Egypt at four wells namely Gibb Afia-1, Betty-1, Salam-1X and Mersa Matruh-1.Petrographic observations and statistical analysis of petrophysical data of forty-five subsurface Cretaceous sandstone samples reflect good reservoir characteristics in some intervals due to high porosity (varies up to more than 27%) and permeability (varies up to more than 826mD). In other intervals, they reflect fair to bad reservoir characteristics due to low porosity (reaches a value of 6.25%) and permeability (reaches a value of 0.01mD), caused by matrix and diagenesis processes.FZI (flow zone indicator) and R35 (pore aperture corresponding to the mercury saturation of 35% pore volume) were calculated from the measured porosity and permeability, by defining FZI and R35, four hydraulic flow units (HFU1, HFU2, HFU3 and HFU4) in a reservoir have been identified. HFU1 is distinguished by FZI values that lie between 3.71and 8.11μm, meanwhile, the values of R35 are greater than 10μm. HFU2 is marked where the FZI values are between 1.32 and 3.70μm, while the values of R35 are between 2 and 10μm. HFU3 is noticed where FZI shows values between 0.40 and 1.31μm, while the values of R35 are between 0.5 and 2μm. The HFU4 is evaluated where FZI values are between 0.06 and 0.39μm, and the R35 values are less than 0.5μm.

Numerical Simulation Study on the Technology of Different Nature Polymer Injection in Thin and Bad ReservoirNumerical Simulation Study on the Technology of Different Nature Polymer Injection in Thin and Bad Reservoir

The thin and poor reservoir , as an important replacement of production decline in the later stage of oilfield development, is gradually becoming the target of three oil recovery due to the large proportion of its reserves. For Class Ⅲ and Class Ⅳ of thin and poor reservoirs with large contradiction between the layers, if the same molecular weight polymer flooding is used to drive oil, it is easy to affect the development effect because of low producing degree of poorly matched reservoir. On the basis of the fine geological model, the water cut and cumulative oil production of the simulated area were fitted by the simulation software of eclipse, and the development effect of different production schemes is analyzed and forecasted. Research results show that the effect of different layer different nature polymer injection is better than that of general polymer injection, and the effect of different stage different nature polymer injection is better than that of the different layer different nature.

Petrographical and petrophysical integrated studies, Jurassic rock samples, North Sinai, Egypt

For the hydrocarbon production enhancement and development, many petrophysical parameters are needed while some of them are usually calculated using relevant equations or even assumed by geologist or geophysicist. In the present study, 112 core samples obtained from six formations at Gebel El-Maghara Jurassic rocks, Mashaba Formation, Rajabia Formation, Shusha Formation, Bir Maghara Formation, Safa Formation, and Masajid Formation. The studied samples were classified into two following main groups: sandstone rock samples (27 samples) and carbonate rock samples (85 samples). Based on the mineralogical composition, texture, structure, and faunal content, thin section examination and scanning electron microscope study of Jurassic rocks at Gebel El-Maghara revealed that the studied carbonate rock samples were classified into five carbonate microfacies, biomicrite, fossiliferous biomicrite, sandy biomicrite, oobiosparite, and foraminiferal biomicrite, while the studied sandstone rock samples are mainly quartz arenite. The porosity of the studied samples is mainly primary mixed with secondary porosity due to the effect of the diagenetic processes (cementation, dissolution, leaching, neomorphism, and compaction). The permeability of the most samples increases with increasing the porosity. The studied sandstone samples reflected good reservoir characteristics in some intervals due to high porosity and permeability, while fair to bad reservoir characteristics in some other intervals due to low porosity and permeability caused by matrix and diagenesis. The limestone reflected bad reservoir characteristics in the most intervals. The reservoir quality index depends mainly on permeability, where the high permeability offsets by the high reservoir quality and the low permeability offsets by the low reservoir quality, where the reservoir quality index with average values of 0.70 and 0.13 μm offsets by the permeability with average values 231.44 and 1.16 mD for sandstone and limestone rock samples, respectively.

Classification and Evaluation of Porous Bioclastic Limestone Reservoir Based on Fractal Theory

The conventional method of classifying and evaluating reservoir based on structural features of microscopic pore has limitation. In order to realize quantitative classification and evaluation of complicated reservoir by fractal theory, the paper used mercury penetration materials to calculate fractal dimension of reservoir’s pore structure, and gathered statistics to analyze the relation between fractal dimension and microscopic pore structure parameter, highlighted geological significance of fractal dimension, believing that fractal dimension of reservoir’s pore structure comprehensively and qualitatively characterizes complication degree of reservoir’ pore structure. The smaller the fractal dimension is, the weaker the reservoir’s microscopic heterogeneity is and the better the reservoir’s quality is. Based on this, fractal dimension is applied to classify and evaluate pore-type bioclastic limestone reservoir, and it shows that the reservoir is clearly partitioned. Besides, the reservoir is divided quantitatively into high quality reservoir, good reservoir, bad reservoir, worse reservoir and invalid reservoir according to size of fractal dimension, thereby realizing quantitative classification and evaluation of complicated reservoir.

Impact of laminations on physical properties of the Bahariya ormation, Egypt

The type locality of the Bahariya Formation in Egypt is the Bahariya Oasis, which lies about 280 km southwest of Cairo, Egypt. It is composed mainly of sandstones which deposited in fluvio-marine to shallow marine environment. The high grain density values recorded for some parts of the Bahariya Formation is due to the existence of iron oxides and pyrite presented as pore filling and/or cementing materials. The primary sedimentary structures like wavy and zigzag laminations severely affect the majority of rock petrophysical properties. The rock laminations are considered as the main source of reservoir rock anisotropy. The relation between pore specific surface (Spor) and permeability is positively improved in the laminated rock samples rather than in the non-laminated. There is a robust and close relationship between porosity and bulk density for non-laminated samples (R2 = 0.86), while for laminated samples, the relation is very weak due to the presence of iron oxides and pyrite laminas. Permeability anisotropy is highly scattered, but generally it increases with depth. Higher permeability anisotropy supports the horizontal migration of reservoir fluids. Permeability anisotropy is most likely due to the existence of microfractures and/or laminations which are mostly existed in the upper part of the Bahariya Formation. The low values of electrical resistivity are showing by laminated samples in depth more than 3516m. It most likely due to the presence of conductive solids like iron rich cement or matrix and rock pore space architectures. However, the mineral composition of some few laminas is free of iron oxides (depth=3515m). The electrical resistivity anisotropy has high values for laminated samples relative to the non-laminated ones. It increases, in general, with depth as a trend of highly scattering data points. This anisotropy is responding by the magnitude of the magnetic susceptibility anisotropy. The non-laminated samples have low magnetic susceptibility relative to the samples with laminations. The magnetic susceptibility of the Bahariya samples is apparently not related to irreducible water saturation (Swi). The main reason for irreducible water saturation variations is the amount and type of clay minerals inside the rock pore spaces. The clay mode of occurrence is usually pore filling, lining, bridging or grain coating. The displacement pressure (Pd) measured for the Bahariya samples are ranged from 10 up to 5000 Psi. The pore surface area of non-laminated samples shows a close and reliable relationship with displacement pressure (R2 = 0.97), while the pore surface area of the laminated samples has no relation with the displacement pressure (R2 = 0. 09). The samples expose mean hydraulic pore radius (R50 &R35) less than 0.04 µm are considered as bad reservoir or even sealing rocks or permeability barrier irrespective to laminations.

Integrated petrographical and petrophysical studies of some Eocene carbonate rocks, Southwest Sinai, Egypt

The present study deals with the effect of petrographical aspects on the petrophysical properties of the Eocene rocks, which are represented by Thebes, Samalut, Darat and Tanka formations in Southwest Sinai, Egypt.The studied diagenetic factors have an important role to enhance and/or reduce the pore volume and governing the petrophysical behavior. The cementation and neomorphism are the main porosity-reducing factors, whereas dissolution and leaching out as well as the fossil content are the main porosity-enhancing factors.The petrophysical behavior of the studied facies has been outlined by measuring rock porosity, density, permeability, and electrical resistivity. The reservoir quality index (RQI) reveals that, the petrophysical features of the studied facies are consistent with the petrographical characteristics indicating bad reservoir properties for Thebes, Samalut, Darat and Tanka formations in the nearby subsurface extensions. Studying the petrophysical behavior indicates that, both permeability and formation resistivity factor are mostly dependent on the effective porosity and to some extent on the electric tortuosity.

A hybrid approach for litho-facies characterization in the framework of sequence stratigraphy: A case study from the South Pars gas field, the Persian Gulf basin

The Upper Dalan and Kangan formations with dominant lithology of limestone and dolomite associated with anhydrite nodules and interbeds form the Permo-Triassic succession of South Pars gas field (SPGF) and host the largest none-associated gas reservoir in the world. The current study focuses on preparing a comprehensive litho-facies model in the framework of sequence stratigraphy. For this purpose, Self-Organizing Map Neural Network (SOM-ANN) and hierarchical cluster analysis (HCA) were utilized as effective tools to prepare the preliminary data for litho-facies mapping. Neural networks (self-organizing maps) and hierarchical clustering approaches were applied to characterize litho-facies in un-cored but logged wells. Particularly, the powerful visualization tools of the SOM-ANN which provide more information in comparison to HCA facilitate the task of establishing an order of priority between the distinguished electro-facies groups. The mentioned method of SOM-ANN clustering algorithm showed a good performance in petrophysical data clustering and litho-facies determination. Based on the porosity and permeability maps at different depth levels, the target reservoir is ranked and classified into four litho-facies and six electro-facies. They include litho-facies 3 with good reservoir quality (equivalent of electro-facies 4–6), litho-facies 4 with moderate reservoir quality (equivalent of electro-facies 2) and litho-facies 1 and 2 with poor to bad reservoir quality (equivalent of electro-facies 1 and 3). The main litho-facies assemblages are indicative of deposition within tidal flat, lagoon, shoal and off-shoal environments. The most shoal litho-facies with best reservoir quality occurs in the high energy sub-environment within upper transgression position (HST) of the 3rd-order cycle in K4 and K2 reservoir units. Distribution of the petrophysical characteristics was analyzed in detail in the framework of electro-facies and sequence stratigraphy. The methodology is illustrated by using a case study from SPGF, Iran.

Porosity-reducing and porosity-enhancing diagenetic factors for some carbonate microfacies: a guide for petrophysical facies discrimination

The present study deals with the petrographical and petrophysical properties of the Aptian–Albian Risan Aneiza Formation in north Sinai, Egypt. Cementation and aggrading neomorphism are the main porosity-reducing factors for Risan Aneiza Formation, whereas dissolution and leaching out are the main porosity-enhancing factors. Dolomitization, on the other hand, played a multistage role as a porosity-reducing factor in the initial invasion stage by Mg-bearing solutions and in the final pervasive stage, while it played an enhancing role in the selective dolomitization midway stage. Mostly, the mentioned pore types were later reduced by cementation with sparite and dolosparite as well as by aggrading neomorphism. Based on the governing effect of diagenetic factors on the petrophysical behavior and their enhancing or reducing effect on the pore volume, the Risan Aneiza Formation has to be classified into seven petrophysical facies; each one has its characteristic petrophysical features and behavior. The petrophysical behavior of the studied facies has been examined by measuring porosity, density, permeability, and electrical resistivity. The reservoir quality index reveals that the petrophysical features of the studied facies can be explained based on their petrographical features, indicating bad reservoir properties for the Risan Aneiza samples. Studying the petrophysical facies behavior indicates that the permeability and formation resistivity factors are mostly dependent on the effective porosity and, to some extent, on the electric tortuosity. Precautions must be taken into consideration in extrapolating the present conclusion to the subsurface extensions, e.g., similarity of the mineralogical composition, the diagenetic history stage, as well as the geopressure.