scholarly journals Evaluation of Chemical for Sand Consolidation in Laboratory Scale

2020 ◽  
Vol 43 (1) ◽  
pp. 17-29
Author(s):  
Sugihardjo Sugihardjo
Keyword(s):  
Pore Space ◽  
The Other ◽  
Reservoir Rock ◽  
Pore Geometry ◽  
Core Flooding ◽  
Pore Throat ◽  
Solid Materials ◽  
Particle Content ◽  
Plastic Resin ◽  
Anions And Cations

These paper contains a highlight of laboratory experiment to evaluate the work of chemical for sand consolidation to strengthen the bonding between grains of rock while do not cause permeability reduction significantly. This experiment used reservoir rock and fluids to understand the interaction between the chemical solution and the reservoir rock and fluid. Firstly, the reservoir rock and fluid were analyzed their properties. The rock has been analyzed using CT Scan to drill the best representative core plug for the experiments, using SEM to identify the pore throat and pore geometry of the rock, using XRD to determine the minerals composition which mostly quartz. While the fluids have been analyzed for the anions and cations content, viscosity and other important properties. The brine particle content and also particle size distribution of the rock have been also over lied in the graph in order to know the possibility of bridging particle in the pore throat, but the graph looks good that no problem may arise from the bridging particle. Chemical for Sand Consolidation has been used in this experiment. Sand consolidation chemical normally contain plastic resin that has a property of bonding between solid materials. It sticks on the surface of solid materials and bonding together.The core flooding experiments have been run for 4 times, 2 times using synthetic cores and the other two using native cores. The experiments used synthetic cores reduce the permeability significantly. However, after cutting both ends of the core the permeability has indicated improvement. The other 2 experiments using native cores have reduced the permeability approximately 4 times down. The last two experiments have no cutting the ends of core for further experiments, so they cannot be compared to the first two experiment. So, the experiment procedures must be improved for the next evaluation, such as during curing time the rate of injected oil may be increased to reduce the adsorption of chemical to the surface area of the pore and also to hinder the flocculation of chemical in the pore space.

Magnitude and Detailed Structure of Residual Oil Saturation

1983 ◽  
Vol 23 (02) ◽  
pp. 311-326 ◽  
Author(s):  
Ioannis Chatzis ◽  
Norman R. Morrow ◽  
Hau T. Lim
Keyword(s):  
Particle Size ◽  
Particle Size Distribution ◽  
Coordination Number ◽  
Pore Space ◽  
Pore Geometry ◽  
Size Distributions ◽  
Residual Oil ◽  
Pore Throat ◽  
Oil Saturation ◽  
Pore Body

Abstract Experimental results are presented that demonstrate the effect on residual oil, under water-wet conditions, of particle size, particle-size distribution, macroscopic particle size, particle-size distribution, macroscopic and microscopic heterogeneities, microscopic dimensions such as ratio of pore-body to pore-throat size, and pore-to-pore coordination number. Experiments were pore-to-pore coordination number. Experiments were performed in random packs of equal spheres, heterogeneous performed in random packs of equal spheres, heterogeneous packs of spheres with microscopic and macroscopic packs of spheres with microscopic and macroscopic heterogeneities, two-dimensional (2D) capillary networks having various pore geometries, and Berea sandstone. Detailed information on residual oil structure is presented, including blob-size distributions of residual presented, including blob-size distributions of residual oil. Major conclusions areresidual saturations are independent of absolute pore size, per se, in systems of similar pore geometry;well-mixed two-component aggregates of spheres gave virtually the same residual saturations as random packings of equal spheres;clusters of large pores accessible through small pores will retain oil;high aspect ratios tend to cause entrapment of oil as a large number of relatively small blobs, each held in single pores; andthe role of pore-to-pore coordination number is generally secondary; pore-to-pore coordination number is generally secondary; hence, correlations that have been proposed between residual oil and coordination number are unreliable. Introduction In recent years, there has been increased interest in the factors that determine the magnitude of residual oil and its microscopic distribution. Residual oil remaining in the swept zone of a waterflood is often taken as the target oil for enhanced recovery processes. Oil saturations remaining in these zones typically can occupy 15 to 35% of the pore space, but values outside this range are often measured. For the reservoir, it can be expected that the pore structure, the initial water content, and the superimposed effects of wettability determine recovery behavior and residual oil distribution under normal waterflood conditions. Salathiel has presented examples of the manner in which pore geometry, wettability, and volume throughput of floodwater can interact to affect oil recovery characteristics and final oil saturation. The likely complexity of trapping phenomena is indicated by the work of Wardlaw and Cassan, who investigated possible correlations between residual oil and 27 petrophysical parameters. Rocks with similar macroscopic properties often differed markedly in their residual oil saturations, and no significant correlation was observed between displacement efficiency and permeability. A tendency for residual nonwetting-phase permeability. A tendency for residual nonwetting-phase saturations to increase as porosity decreased was noted. This was related to a strong relationship between trapping and aspect ratio (ratio of pore-body to pore-throat size). A theory of residual oil trapping has been proposed by Larson et al. that provides an alternative explanation of the relationship between residual oil and porosity. It was reasoned that the trapped nonwetting-phase saturation will correspond reasonably well to the percolation threshold i.e., to the oil saturation at which oil continuity through the pore space is lost. SPEJ p. 311

scholarly journals EVALUATION OF PORE SYSTEM PROPERTIES OF COQUINAS FROM MORRO DO CHAVES FORMATION BY MEANS OF X-RAY MICROTOMOGRAPHY

2018 ◽  
Vol 36 (4) ◽  
pp. 1 ◽  
Author(s):  
João Pedro Tauscheck Zielinski ◽  
Alexandre Campane Vidal ◽  
Guilherme Furlan Chinelatto ◽  
Leandro Coser ◽  
Celso Peres Fernandes
Keyword(s):  
Pore Space ◽  
Total Porosity ◽  
Reservoir Rock ◽  
Absolute Permeability ◽  
Pore System ◽  
Pore Throat ◽  
X Ray ◽  
Petrophysical Parameters ◽  
Potential Reservoir ◽  
Rock Characterization

ABSTRACT. The recent increase in the use of X-ray microtomography (μ-CT) for reservoir rock characterization can be explained by numerous factors, such as its non-destructive nature, higher spatial resolution and 3D pore space visualization, which were explored in this work to evaluate the pore system of coquinas, a potential reservoir rock mainly composed of shells and their fragments. However, most of the recent studies have not considered an association between petrophysical parameters extracted via μ -CT and coquina facies. For this reason, this work had the goal to characterize the pore types, quantify total porosity, obtain the porosity profile, analyze the pore and pore-throat size distribution, as well as to extract additional petrophysical parameters of different taphofacies from Morro do Chaves Formation coquinas, Sergipe-Alagoas basin. The results haven shown that taphofacies from shallow sub-environment under normal conditions (group T2) and deeper sub-environment under storm influence (group T5) are better in terms of reservoir quality. Nevertheless, rocks from storm influence, deeper sub-environments are more likely to represent a good reservoir, since its pore system is predominantly dominated by moldic pores, which are originated during eogenetic phase, while rocks from shallow normal conditions have pores dominantly generated during telogenesis. Additionally, μ-CT derived data such as coordination number and pore and pore-throat sizes could also be used to explain differences in absolute permeability in the studied rocks. Nevertheless, our data suggests that coquinas have a multiscale pore system and finer imaging scales are indispensable for more accurate petrophysical characterization.  Keywords: Coquinas, μ-CT, petrophysics. RESUMO. A crescente utilização da microtomografia de raios-X (μ-CT) visando a caracterização das rochas reservatório pode ser explicada por diversos fatores, como sua natureza não-destrutiva, alta resolução espacial e visualização 3D do espaço poroso, que são propriedades exploradas nesse trabalho para avaliar o sistema poroso de coquinas, uma potencial rocha reservatório composta principalmente por conchas e seus respectivos fragmentos. Entretanto, a maioria dos estudos recentes não tem associado os parâmetros petrofísicos com as fácies de coquinas. Por essa razão, esse trabalho buscou realizar a caracterização dos tipos de poros, quantificar a porosidade total, obter o perfil de porosidade, analisar a distribuição do tamanho de poros e gargantas, assim como extrair parâmetros adicionais de diferentes tafofácies das coquinas da Fm. Morro do Chaves, Bacia de Sergipe-Alagoas. Os resultados mostraram que as tafofácies dos subambientes rasos sob condições normais de deposição (grupo T2) e dos subambientes profundos sob influência de tempestades (grupo T5) são melhores em termos de qualidade de reservatório. No entanto, as rochas de subambientes profundos sob influência de tempestades são mais prováveis de representarem bons reservatórios, pois seu sistema poroso é predominantemente dominado por poros móldicos, que são originados durante a fase eogenética, enquanto que as rochas depositadas no subambiente raso em condições normais possuem poros gerados durante a telogênese. Adicionalmente, dados derivados da μ-CT, como número de coordenação e tamanho de poros e gargantas, também poderiam ser usados para explicar as diferenças em permeabilidade absoluta nas rochas estudadas. Entretanto, nossos dados sugerem que as coquinas possuem um sistema poroso multiescalar e o imageamento em escalas mais finas para uma caracterização petrofísica mais acurada é indispensável.Palavras-chave: Coquinas, μ-CT, petrofísica

MICROPOROSITY CHANGES WITH ACIDIZING EFFECT IN SANDSTONES (KIZILDERE FORMATION-HATAY/S-TURKEY)

2021 ◽  
Vol 16 (1) ◽  
pp. 67-76
Author(s):  
Melda AVCU ◽  
◽  
Meryem YEŞİLOT KAPLAN
Keyword(s):  
The Other ◽  
Reservoir Rock ◽  
Micro Ct ◽  
Pore Throat ◽  
Fine Grained ◽  
Rock Fragments ◽  
Binding Material ◽  
Average Porosity ◽  
Matrix Rock ◽  
Quartz Grains

This study aims to determine the field and petrographic properties of sandstones observed in Arsuz-İskenderun (Hatay) region and micro-size porosity changes in acidizing stages. The fine-grained sandstones of the Aktepe formation have more quartz grains than the other components and the binding material is matrix. Rock fragments that consist of fossil shells, limestone and igneous fragments are observed relatively to quartz and feldspar grains in the Kızıldere formation sandstones. The first step of reservoir rock acidizing is HCl acidizing and the process is experimentally provided by capillarity experiment. HCl with dilution rates of 7.5% - 15% - 30% was absorbed into the samples at room temperature and after 100 minutes, effective distances were observed as 0.6-0.8-1.1 cm and dissolved rock amounts as 32.82-34.02-35.54 g, respectively. In acidizing process, the average porosity analysed with Micro-CT is 39.6% of acidified samples with 15% diluted acid and non-acidified samples, equivalent results were obtained with porosity values measured by well logs. There is an increase in the porosity of about 16% with acidizing. Pores were bonded together by acidizing and pore size increase about 20%. The change in the pore throat by acidizing is 105%. Calculation of porosity of rocks by Micro-CT and image processing methods can be performed faster compared to the other methods.

Enhanced Oil Recovery Application of Nanoparticles in Niger Delta Water-Wet Reservoir Rock

2021 ◽  
Author(s):  
Tinuola Udoh
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Niger Delta ◽  
Oil Production ◽  
Reservoir Rock ◽  
Core Flooding ◽  
Core Samples ◽  
Recovery Potential ◽  
Secondary Formation ◽  
Injection Modes

Abstract In this paper, the enhanced oil recovery potential of the application of nanoparticles in Niger Delta water-wet reservoir rock was investigated. Core flooding experiments were conducted on the sandstone core samples at 25 °C with the applications of nanoparticles in secondary and tertiary injection modes. The oil production during flooding was used to evaluate the enhanced oil recovery potential of the nanoparticles in the reservoir rock. The results of the study showed that the application of nanoparticles in tertiary mode after the secondary formation brine flooding increased oil production by 16.19% OIIP. Also, a comparison between the oil recoveries from secondary formation brine and nanoparticles flooding showed that higher oil recovery of 81% OIIP was made with secondary nanoparticles flooding against 57% OIIP made with formation brine flooding. Finally, better oil recovery of 7.67% OIIP was achieved with secondary application of nanoparticles relative to the tertiary application of formation brine and nanoparticles flooding. The results of this study are significant for the design of the application of nanoparticles in Niger Delta reservoirs.

Trapping patterns during capillary displacements in disordered media

2022 ◽  
Vol 933 ◽  
Author(s):  
Fanli Liu ◽  
Moran Wang
Keyword(s):  
Numerical Simulations ◽  
Pore Size Distribution ◽  
Pore Size ◽  
Size Distribution ◽  
Disordered Media ◽  
Pore Geometry ◽  
Control Parameters ◽  
Pore Throat ◽  
The Impact ◽  
Theoretical Analyses

We investigate the impact of wettability distribution, pore size distribution and pore geometry on the statistical behaviour of trapping in pore-throat networks during capillary displacement. Through theoretical analyses and numerical simulations, we propose and prove that the trapping patterns, defined as the percentage and distribution of trapped elements, are determined by four dimensionless control parameters. The range of all possible trapping patterns and how the patterns are dependent on the four parameters are obtained. The results help us to understand the impact of wettability and structure on trapping behaviour in disordered media.

Miscible Flooding for Bitumen Recovery with a Novel Solvent

2021 ◽  
Author(s):  
Tanya Ann Mathews ◽  
Alex J.Cortes ◽  
Richard Bryant ◽  
Berna Hascakir
Keyword(s):  
Oil Recovery ◽  
Cold Water ◽  
Pore Space ◽  
Oil Quality ◽  
Environmental Concerns ◽  
Solvent Recovery ◽  
Core Flooding ◽  
Recovery Method ◽  
Steam Flooding ◽  
Oil Emulsions

Abstract Steam injection is an effective heavy oil recovery method, however, poses several environmental concerns. Solvent injection methods are introduced in an attempt to combat these environmental concerns. This paper evaluates the effectiveness of a new solvent (VisRed) in the recovery of a Canadian bitumen and compares its results with toluene. While VisRed is selected due to its high effectiveness as a viscosity reducer even at very low concentrations, toluene is selected due to its high solvent power. Five core flooding experiments were conducted; E1 (Steam flooding), E2 (VisRed flooding), E3 (Toluene flooding), E4 (Steam + Toluene flooding), and E5 (Steam + VisRed flooding). Core samples were prepared by saturating 60% of the pore space with oil samples and 40% with deionized water. The solvents were injected at a 2 ml/min rate, while steam was injected at a 18 ml/min cold water equivalent rate. Produced oil and water samples were collected every 20 min during every experiment. The oil recovery efficiencies of the core flood experiments were analyzed by the emulsion characterization in the produced fluids and the residual oil analysis on the spent rock samples. The best oil recovery of ~30 vol % was obtained for E2 (VisRed) in which VisRed was injected alone. Although similar cumulative recoveries were obtained both for E2 (VisRed) and E3 (Toluene), the amount of VisRed injected [~1 pore volumes (PV)] was half the volume required by toluene (~2 PV). The produced oil quality variations are mainly due to the formation of the water-in-oil emulsions during mainly steam processes (E1, E4, and E5). The increased amount of the polar fractions in the produced oil enhances the formation of the emulsions. These polar fractions are namely asphaltenes and resins. As the amount of the polar fractions in the produce oil increases, more water-in-oil emulsion formation is observed due to the polar-polar interaction between crude oil fractions and water. Consequently, E1 and E5 resulted in more water in oil emulsions. The cost analysis also shows the effectiveness of solvent recovery over steam-solvent recovery processes.

Two types of reservoir-induced seismicity

1988 ◽  
Vol 78 (6) ◽  
pp. 2025-2040
Author(s):  
D.W. Simpson ◽  
W.S. Leith ◽  
C.H. Scholz
Keyword(s):  
Normal Stress ◽  
Pore Pressure ◽  
Induced Seismicity ◽  
Elastic Stress ◽  
Pore Space ◽  
Temporal Distribution ◽  
The Other ◽  
Elastic Response ◽  
Reservoir Induced Seismicity ◽  
Effective Normal Stress

Abstract The temporal distribution of induced seismicity following the filling of large reservoirs shows two types of response. At some reservoirs, seismicity begins almost immediately following the first filling of the reservoir. At others, pronounced increases in seismicity are not observed until a number of seasonal filling cycles have passed. These differences in response may correspond to two fundamental mechanisms by which a reservoir can modify the strength of the crust—one related to rapid increases in elastic stress due to the load of the reservoir and the other to the more gradual diffusion of water from the reservoir to hypocentral depths. Decreased strength can arise from changes in either elastic stress (decreased normal stress or increased shear stress) or from decreased effective normal stress due to increased pore pressure. Pore pressure at hypocentral depths can rise rapidly, from a coupled elastic response due to compaction of pore space, or more slowly, with the diffusion of water from the surface.

scholarly journals A New Method for Predicting the Permeability of Sandstone in Deep Reservoirs

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-16
Author(s):  
Feisheng Feng ◽  
Pan Wang ◽  
Zhen Wei ◽  
Guanghui Jiang ◽  
Dongjing Xu ◽  
...  
Keyword(s):  
Support Vector Regression ◽  
Capillary Pressure ◽  
Prediction Models ◽  
Reservoir Rock ◽  
Support Vector ◽  
Pressure Curve ◽  
Pore Throat ◽  
Capillary Pressure Curve ◽  
Mercury Injection ◽  
Mercury Injection Capillary Pressure

Capillary pressure curve data measured through the mercury injection method can accurately reflect the pore throat characteristics of reservoir rock; in this study, a new methodology is proposed to solve the aforementioned problem by virtue of the support vector regression tool and two improved models according to Swanson and capillary parachor parameters. Based on previous research data on the mercury injection capillary pressure (MICP) for two groups of core plugs excised, several permeability prediction models, including Swanson, improved Swanson, capillary parachor, improved capillary parachor, and support vector regression (SVR) models, are established to estimate the permeability. The results show that the SVR models are applicable in both high and relatively low porosity-permeability sandstone reservoirs; it can provide a higher degree of precision, and it is recognized as a helpful tool aimed at estimating the permeability in sandstone formations, particularly in situations where it is crucial to obtain a precise estimation value.

scholarly journals Formation evaluation and reservoir characteristics of the Messinian Abu Madi sandstones in Faraskour Gas Field, onshore Nile Delta, Egypt

2020 ◽  
Author(s):  
Mahmoud Leila ◽  
Ali Eslam ◽  
Asmaa Abu El-Magd ◽  
Lobna Alwaan ◽  
Ahmed Elgendy
Keyword(s):  
Water Saturation ◽  
Nile Delta ◽  
Hydrocarbon Exploration ◽  
The Other ◽  
Reservoir Rock ◽  
Reservoir Quality ◽  
Pore System ◽  
Reservoir Properties ◽  
Gas Field ◽  
Irreducible Water Saturation

Abstract The Messinian Abu Madi Formation represents the most prospective reservoir target in the Nile Delta. Hydrocarbon exploration endeavors in Nile Delta over the last few decades highlighted some uncertainties related to the predictability and distribution of the Abu Madi best reservoir quality facies. Therefore, this study aims at delineating the factors controlling the petrophysical heterogeneity of the Abu Madi reservoir facies in Faraskour Field, northeastern onshore part of the Nile Delta. This work provides the very first investigation on the reservoir properties of Abu Madi succession outside the main canyon system. In the study area, Abu Madi reservoir is subdivided into two sandstone units (lower fluvial and upper estuarine). Compositionally, quartzose sandstones (quartz > 65%) are more common in the fluvial unit, whereas the estuarine sandstones are often argillaceous (clays > 15%) and glauconitic (glauconite > 10%). The sandstones were classified into four reservoir rock types (RRTI, RRTII, RRTIII, and RRTIV) having different petrophysical characteristics and fluid flow properties. RRTI hosts the quartzose sandstones characterized by mega pore spaces (R35 > 45 µm) and a very well-connected, isotropic pore system. On the other side, RRTIV constitutes the lowest reservoir quality argillaceous sandstones containing meso- and micro-sized pores (R35 > 5 µm) and a pore system dominated by dead ends. Irreducible water saturation increases steadily from RRTI (Swir ~ 5%) to RRTIV (Swir > 20%). Additionally, the gas–water two-phase co-flowing characteristics decrease significantly from RRTI to RRTIV facies. The gaseous hydrocarbons will be able to flow in RRTI facies even at water saturation values exceeding 90%. On the other side, the gas will not be able to displace water in RRTIV sandstones even at water saturation values as low as 40%. Similarly, the influence of confining pressure on porosity and permeability destruction significantly increases from RRTI to RRTIV. Accordingly, RRTI facies are the best reservoir targets and have high potentiality for primary porosity preservation.

Sign in / Sign up

Export Citation Format

Share Document