Permeability Of Reservoir Rocks Research Articles

Investigating the CO2 injection and the performance of nanoparticles in preventing formation damage at different pressures and concentrations

AbstractAsphaltene deposition is one of the main challenges during CO2 injection (miscible or immiscible) into reservoirs. Asphaltene deposition reduces the porosity and permeability of reservoir rock and changes its wettability to strongly oil‐wet. In this article, to control the asphaltene deposition during CO2 injection the use of direct asphaltene inhibitors (Al2O3 and Fe3O4) in reservoir conditions. In this research, nanoparticle screening (to investigate its significance in reducing asphaltene precipitation) has been done and it can be stated that Al2O3 nanoparticle will perform better effectivity than Fe3O4 nanoparticle. After that, by using effective nanoparticles (Al2O3) in different concentrations (1000 and 2000 ppm), the amount of asphaltene deposition during CO2 injection has been investigated. The obtained results show that increasing the injection pressure (from immiscible to miscible) causes an increase in asphaltene deposition and the use of nanoparticles will reduce the amount of asphaltene deposition.

Petroleum System Analysis and Burial History of Middle Permian Source Rock in Turpan–Hami Basin, NW China

The pre-Jurassic in the north depression of the Tuha depression is the most favorable replacement strata to obtain new reserves in the Turpan–Hami Basin. (Pre-Jurassic, in this paper, refers to the Permian and Triassic.) The main source rocks are the Taodonggou Group, of which the burial history and hydrocarbon generation potential remain unconfirmed. The investigation of the burial and thermal history is vital for the basin analysis and hydrocarbon exploration. Therefore, in this paper, by using the acoustic time difference method, vitrinite reflectance method, stratigraphic trend method and PetroMod-1D software, the differential characteristics of denudation thickness, burial history and thermal evolution history of different tectonic units in different periods of Taibei Sag in the Turpan–Hami basin are studied, and their influence on the petroleum system is analyzed, and then the zones with exploration potential are optimized. The results show that the Taibei Sag has experienced multiple tectonic uplift events. The Late Indosinian movement has profound effects on the Taodonggou Group source rocks. The rather large uplift amplitude postpones the maturation of source rocks. In addition, the Turpan–Hami Basin is a typical cold basin. Therefore, the thermal maturity of the source rocks is relatively low, with respect to the relatively deep burial. The thermal histories of the different sub-sags in the study area are slightly differentiated from each other. The Taodonggou Group source rocks in the Taibei Sag generally became mature during the Mid–Late Jurassic epoch, except for those in the Central–Southern Shanbei sub-sag, represented by Well LT-1, which reached the mature stage during the Late Triassic epoch. The study area has well-developed reservoir rocks, and effective reservoir bodies are formed in the slope zone and near the Tainan Sag, due to the higher porosity and permeability of reservoir rocks. The statistics related to the faults and an analysis of the structural styles of oil reservoirs indicate that the structural slope and anticline of the Huobei, Lianbei and Shanbei sub-sags are favorable for increasing reserves and production of hydrocarbons.

Competitive adsorption-diffusion coupling process of helium-nitrogen mixture in shale kerogen nano-slit

Helium, as a probe gas with low adsorption capacity, is widely used for measuring porosity, permeability, and specific surface area in reservoir rocks of unconventional gas such as shale and coal. The pretreatment duration of these rock samples determines the amount of residual nitrogen in their pores, and the competitive adsorption and diffusion of residual nitrogen with the probe gas has a significant impact on the measurement results of their physical properties. This work aims to reveal the mechanisms involved in the competitive adsorption-diffusion coupling process of nitrogen-helium mixtures. Brief experiments were conducted to demonstrate the competitive adsorption between nitrogen and helium in shale. Subsequently, molecular dynamics simulation was employed to investigate this process and provide necessary details. Meanwhile, a theoretical model was developed to describe the diffusion of gas molecules in this process. Our results indicate that helium rapidly permeates shale samples and reaches an equilibrium distribution. However, the competitive adsorption between nitrogen and helium can slow down the helium permeation process, which can be attributed to the main adsorption sites occupied by nitrogen. The agreement between FEM computations and MD simulations validates our model for various mechanisms. Furthermore, our model can be applied to a wider range of porous materials and gas mixtures in related fields.

Analysis of Field Data Using Microsoft Excel and MATLAB Software to Evaluate Reservoir and Well Damage

Reservoir formation damage is a drop in a well's productivity caused by a decrease in reservoir rock permeability. To tackle this issue and maximize well production, obtained pressure build-up time data at a steady production rate from a vertical producing oil WELL 20A, was analysed to establish the wellbore and reservoir characteristics. A numerical well test simulator (Matlab) is used to simulate damage in the area close to the wellbore, a Microsoft Excel sheet and an analytical approach to calculate the impact of wellbore and reservoir factors such as skin, wellbore storage, and average reservoir permeability. In order to determine whether the numerical well test simulator was successful at performing pressure transient analysis on observed data, the findings from the analytical solutions using Microsoft Excel Sheet and numerical well test simulator Matlab were compared. Comparable outcomes for the permeability and skin values were obtained from the build-up test data analysis generated; hence, the negative skin values for wells 20A acquired after the analysis suggest that the formation is not damaged. This indicate that well 20A is not a candidate for workover operations.

An Innovative Experimental Methodology for Testing Anisotropic Permeabilities of Formation Rocks

Abstract The permeability of reservoir rocks is a typical anisotropic property. Accurate testing and characterization of reservoir in situ anisotropic permeability is crucial for geo-energy applications including geothermal energy extraction, hydrocarbon reservoir development, coalbed methane production, and carbon dioxide geological sequestration. In this work, a novel experimental apparatus was designed to more precisely determine the permeability tensor of reservoir rocks. The device can independently apply stresses in different directions to simulate in situ reservoir stress conditions and reservoir temperatures. The experiment can accurately measure the principal components of the permeability tensor in three directions for rock samples while effectively avoiding experimental errors caused by internal structure damage during disassembly. Using the self-developed apparatus, anisotropic permeability tests were conducted on sandstone, shale, and coal samples. The results show that the three-dimensional permeability of rock samples under in situ reservoir stress conditions is lower than under isotropic stress conditions. However, the variation magnitude of the three-dimensional permeability differs between the three rock types because of lithological differences. This confirms the difference in data between the proposed anisotropic permeability test method and other traditional methods. We also observed that for rocks without distinct oriented internal structures like sandstone, anisotropic permeability is more sensitive to (normal) stress changes. In contrast, for rocks with oriented pore structures such as shale and coal, the degree of anisotropic permeability is less sensitive to (normal) stress changes. The proposed novel anisotropic permeability test method obtains more accurate and realistic data under simulated in situ stress conditions compared with existing methods. It can evaluate rock properties and optimize geothermal or hydrocarbon production well designs to improve production efficiency.

Justification of the boundary values of open porosity and gas permeability using data from flow studies for porous carbonate reservoirs

This paper proposes a method for determining the boundary values of open porosity (KPO_GR) and gas permeability (KPR_GR) of porous-type carbonate reservoir rocks using the example of Tournaisian deposits of one of the oil fields of the Republic of Tatarstan. When justifying the boundary values, two databases on core studies are used: 1) on standard core studies (used mainly to calculate hydrocarbon (HC) reserves); 2) on special core studies (used for technological development projects). In the proposed method, the residual oil saturation factor is not a constant, but is taken from flow studies or calculated from core dependencies. When determining the lower limits of porosity and permeability from both databases, approximately the same boundary values were obtained: KPO_GR = 0.11 fr. un., KPR_GR = 2·10–3 μm2 and KPR_GR = 1.7·10–3 μm2, but they differ from the values, accepted by petrophysicists when calculating the reserves of considered deposit – KPO_GR = 0.09 fr. un., KPR_GR = 1·10–3 μm2. Such a difference in determining the boundary porosity can significantly affect the calculation of hydrocarbon reserves, technological calculations and field development planning.

An improved Klinkenberg permeability model for tight reservoir cores: Effects of non-linear gas slippage to real gases

Absolute permeability is one of the most fundamental reservoir-rock properties required for reservoir simulation models. Most research studies are focused on the Klinkenberg gas slippage, considering the ideal behavior of the flowing gas under first- and second-order slippage conditions. This paper assesses the non-linear slippage of real gas through the low permeability reservoir rock samples. The cubic equation of state (van der Waals/Soave-Redlich-Kwong/Peng-Robinson), coupled with Taylor series-based non-linear slippage, predicts the apparent permeability for the non-Darcy gas flow in tight reservoir rock. The novelty of the present contribution is to develop a comprehensive mathematical model to describe the temperature- and pressure-dependent non-linear slippage effect accounting for the real gas behavior, which is based on the fundamental principle of momentum balance. The thirty-nine sets of experimental results of different authors using different core samples (e.g., coal seams, tight sandstones, tight carbonates, gas-shale reservoirs) and gases (Air, H2, He, N2, CH4, C2H6, and CO2) are used to authenticate the proposed non-linear slip model for real gases. Results show that (a) the proposed model correctly predicts infinite permeability and non-linear slippage coefficients of eight-tests non-ideal gases with an average absolute deviation of ≤9.69%, (b) non-linear slippage dominates for the core samples having permeability <1.5 mD, and (c) the first- and second-order slippage coefficients vary from 0.76 to 6.22 atm and 0.15–9.30 atm2, respectively. The proposed model is simple and may readily be applied for the reservoir simulation of coal seams, tight sandstones, tight carbonates, gas-shale reservoirs, etc., for reservoir characterization, forecasting future natural gas production, decision-making, and efficient reservoir management practices for enhanced production efficiency and sustainability.

A fresh look at the Lucia classification using mud- and grain-dominated reservoirs of the Persian Gulf

Carbonate reservoir heterogeneity, a multifaceted phenomenon in the domain of subsurface exploration, plays a pivotal role in the assessment of hydrocarbon resources. The upper Dalan and Dariyan formations are significant gas and oil reservoirs in the Persian Gulf. Both of these formations are strongly heterogenous. Different methods are used to evaluate reservoir heterogeneities and determine rock types. In this research, Lucia's standard petrophysical method was used to manage and compare the heterogeneity of the upper Dalan and Dariyan formations. To investigate the factors influencing the distribution of samples within Lucia's petrophysical classes, microfacies and diagenetic processes were studied in both formations using 1483 thin sections. To determine reservoir rock types, 2080 porosity and permeability data were plotted on Lucia's petrophysical chart. The charts were plotted at multiple scales, including the whole well, reservoir units, and microfacies levels. All Lucia's classes were observed in the upper Dalan Formation. Dissolution and dolomitization in the mud-dominated microfacies have led to the increase in both porosity and permeability, resulting in the distribution of samples primarily within Lucia classes 1 and 2. On the other hand, calcite and anhydrite cements in the grain-dominated microfacies have reduced the reservoir quality and increased the number of samples in the lower parts of the Lucia's chart. In contrast to the upper Dalan, the samples from the Dariyan Formation were concentrated within class 3 and the lower part of the Lucia's chart. This is due to the high abundance of mud-dominated microfacies and the presence of high microporosity and low permeability. Finally, by comparing the results obtained from the two formations, it can be concluded that the Lucia's method is more suitable for grain-dominated formations compared to mud-dominated reservoirs. The findings of this study can help for better understanding of the relationships between carbonate textures and porosity-permeability. Results also shed light on evaluating the heterogeneity of different carbonate reservoirs.

Analysis of structural-tectonic and petrophysical features of productive horizons of Mishovdag fold

&#x0D; &#x0D; &#x0D; The article analyzes the geological structure, lithofascial, tectonic, and morpho- logical features of the Mishovdag oil field, which is a productive area in terms of oil content. Morphologically, it represents a brachianticlinal fold located in the north-west and south-east directions. The Mishovdag fold is located on the Kalamaddin-Bandovan anticline zone between the Kichik Harami (in the northeast) and Galmaz (in the northwest) structures. The Mishovdag-Galmaz part of the anticlinal zone extends in the sub-southern direction. The structures included in the zone are represented on the surface mainly by Aghjagil, Absheron, and ancient Khazar sediments. Productive layer sediments come to the surface in few areas. The tectonic movements and activity of mud volcanoes (active or buried) have left characteristic traces in the geological structure of the research area. Brachianticlinal and other types of structures were formed here. Under the strong influence of tectonic movements, the layers forming them were deformed and broken into blocks by regional tectonic faults. The anticlinal structures of the zone are complicated by longitudinal and latitudinal faults. The Mishovdag fold is represented by a brachianticline, 20-25 km long and 4-6 km wide. Brachianticline has a sharply asymmet- rical structure. The southwestern limb is steep, and inclined at an angle of 25-450, while the northeastern limb is flat and characterized by an inclination angle of 7-250. As a result of the analysis of the cross-sections of deep wells drilled in the field, it was determined that Mesozoic, Paleogene-Miocene, and Pliocene-Anthropogenic sediments are developed in the section of the fold. Sediments repre- senting the cross-section are characterized by high reservoir properties. Geological-geophysical works are carried out in the field. Core materials were taken from wells. The lithological-petrophysical characteristics – carbonate, porosity, and permeability of reservoir rocks have been determined according to core samples taken from exploration wells drilled in the field. The lithological-petrophysical characteristic regularities of change were investigated depending on depth.&#x0D; &#x0D; &#x0D;

A study of non-equilibrium wave groups in two-phase flow in high-contrast porous media with relative permeability hysteresis

Non-equilibrium models are applicable in various physical situations, including phase transitions, hysteresis, and chemical reactions, among others. To model the dynamics of such phenomena, partial differential equations are employed with source terms, as seen in Eq. (1.1). This work focuses on situations where we connect states in equilibrium while allowing for non-equilibrium times. In our model, we model non-equilibrium through relaxation. The source term, in this case, acts as an attractor, and the model’s dynamics allow only a small-time far from equilibrium. We use this theory to model a two-equation system in a two-phase fluid in porous media, where different permeabilities of the flow lead to hysteresis phenomena. We show several examples and study the Riemann solution to gain a better understanding of the solution. We investigate the interplay between nonlinear wave groups of water–oil saturation with different permeabilities in the non-wetting phase and the high-contrast heterogeneity of the porous medium in two-space dimensions. This phenomenon is described by a coupled set of time-dependent partial differential equations of hyperbolic–parabolic–elliptic mixed type. We present and discuss a new projection method with relaxation to obtain 1D-analytical Riemann solutions in an idealized homogenized medium, and we use this solution to validate our numerical method. The primary components of obtaining these solutions are shocks, rarefactions, and bifurcations. We obtain 2D-numerical solutions using an operator splitting approach based on physics, highlighting the discretization methods used. We provide robust analytical–numerical examples to verify the theory and illustrate the approach’s capabilities. In particular, we discuss the 1D-2D behavior of wave groups in situations driven by water–oil infiltration problems of permeable reservoir rocks.

Badania biomonitoringowe oraz kontrolne prace badawcze dla potrzeb podziemnego magazynowania gazu i obecnie eksploatowanych złóż gazu ziemnego

This paper refers to several aspects of research studies supporting the oil and gas industry – in particular underground gas storage (UGS) in depleted deposits and salt caverns – and focuses on questions related to the formation of hydrogen sulphide contamination in reservoir conditions as well as on methods for limiting unfavourable biogenic phenomena. The main problem found at gas storage facilities is the activity of sulphate reducing bacteria (SRB). The elimination or limitation of H2S generation in microbiologically contaminated environments have been the subject of many extensive studies. Biocides, biocorrosion inhibitors and H2S scavengers are widely applied to protect reservoir structure, gas storage infrastructure as well as water-based drilling fluids from the negative effects of bacterial activity. One of the most popular biocidal products, recommended for oil and gas industry are triazine derivatives, laboratory tested in the presented biomonitoring studies. Triazine products prove very effective in biomass reduction and elimination of anaerobic bacteria, especially SRB. Before any industrial operation (based on technology of using biocides), it was necessary to analyse the sulphur compounds in the stored natural gas in different exploitation gas wells of UGS. It was also necessary to investigate the selection of a specific biocidal product and its proper concentration. A concentration that is too low may even stimulate the microbial growth; since the substance is not toxic for microorganisms, they may start to metabolise it. Moreover, the wrong choice of biocides may even generate an economic loss or environmental hazard. Generally, the application of biocides, H2S scavengers and nitrate-based treatment are one of the most effective world strategies to decrease microbiological contamination, which affects various areas of the oil and gas industry. These products have also been successfully applied to control bacterial growth in Polish natural gas wells. The issue of the influence of microorganisms and biomass on the permeability of reservoir rocks was also presented. In addition, the paper refers to biodegradation processes, that take place in the environment of drilling fluids. Also, the issue of choice of biocide/H2S scavenger preparations for industrial applications is presented. The choice of chemicals includes efficiency tests of nanoparticles in contaminated media.

Heterogeneity of reservoirs of the Qala suite (on the example of the Neft Dashlary field)

In order to study the heterogeneity of reservoir rocks based on core materials and well logging data, an analysis of the lithological-petrographic and reservoir properties of the rocks of the Qala suite of the PS of the Neft Dashlary field was carried out. For a more detailed study, an analysis of laboratory data on subformations (QaS1, QaS2, QaS3 and QaS4) has been carried out, the grainsize composition and reservoir properties (porosity, clay content, permeability and carbonate content) of reservoir rocks were studied. Based on the results of logging data interpretation and analysis of the constructed correlation schemes, heterogeneity, including the study of reservoirs thickness and the variability of their reservoir properties over the area have been studied. Keywords: Kalinskaya suite; Core; Logging; Heterogeneity.

Sensitivity analysis for enhancing crude oil recovery with continuous flow gas lift: A study in reference to the porous media of the upper Assam basin, India

Despite minimal formation damage or water-cut, the majority of oil wells in brown oil fields cease to flow naturally. The current study looks into and analyses what caused a self-flowing well in the upper Assam basin to become non-flowing. The non-flow condition of the well was investigated in the current work as a function of water cut, reservoir pressure, reservoir rock permeability, and GOR. The effect of WHP and WHT on these functions was investigated. This work incorporates innovative methodology that uses the PROSPER simulation model for assessing the possibility of establishing flowability in a dead well based on inflow (IPR) and vertical lift performance (VLP). Subsequent analysis was carried out to examine the scope of producing this dead well under continuous flow gas lift. For this, the current work first examined the tubing diameter and reservoir temperature as standalone parameters to find out if they have any role to play in the flowability of the dead well. Following this, sensitivity analysis was done taking four parameters into account, i.e., reservoir pressure, reservoir rock permeability, water cut, and total GOR. In the current work, surface equipment correlation was established using Beggs and Brill correlation, while vertical lift performance was established using correlation from Petroleum Expert. The results of the current work highlight that a well's production rate under continuous flow gas lift can be enhanced by employing an optimised gas injection rate. The findings of this work conclude that higher reservoir pressure enables an oil well to produce with a high water cut under a continuous flow gas lift system, provided there are no formation damage issues on the well.

Modeling Permeability Using Advanced White-Box Machine Learning Technique: Application to a Heterogeneous Carbonate Reservoir.

From exploration to production, the permeability of reservoir rocks is essential for various stages of all types of hydrocarbon field development. In the absence of costly reservoir rock samples, having a reliable correlation to predict rock permeability in the zone(s) of interest is crucial. To predict permeability conventionally, petrophysical rock typing is done. This method divides the reservoir into zones of similar petrophysical properties, and the permeability correlation for each zone is independently developed. The challenge of this approach is that the success depends upon the reservoir's complexity and heterogeneity and the methods and parameters used for rock typing. As a result, in the case of heterogeneous reservoirs, conventional rock typing methods and indices fail to predict the permeability accurately. The target area is a heterogeneous carbonate reservoir in southwestern Iran with a permeability range of 0.1-127.0 md. In this work, two approaches were used. First, based on permeability, porosity, the radius of pore throats at mercury saturation of 35% (r35), and connate water saturation (Swc) as inputs of K-nearest neighbors, the reservoir was classified into two petrophysical zones, and then, permeability for each zone was estimated. Due to the heterogeneous nature of the formation, the predicted permeability results needed to be more accurate. In the second part, we applied novel machine learning algorithms, modified group modeling data handling (GMDH), and genetic programming (GP) to develop one universal permeability equation for the whole reservoir of interest as a function of porosity, the radius of pore throats at mercury saturation of 35% (r35), and connate water saturation (Swc). The novelty of the current approach is that despite being universal, the models developed using GP and GMDH performed substantially better than zone-specific permeability, index-based empirical, or data-driven models used in the literature, such as FZI and Winland. The predicted permeability using GMDH and GP resulted in accurate prediction with R2 of 0.99 and 0.95, respectively, in the heterogeneous reservoir of interest. Moreover, as this study aimed to develop an explainable model, different parameter importance analyses were also applied to the developed permeability models, and r35 was found to be the most impactful feature.

Full scale, microscopically resolved tomographies of sandstone and carbonate rocks augmented by experimental porosity and permeability values

We report a dataset containing full-scale, 3D images of rock plugs augmented by petrophysical lab characterization data for application in digital rock and capillary network analysis. Specifically, we have acquired microscopically resolved tomography datasets of 18 cylindrical sandstone and carbonate rock samples having lengths of 25.4 mm and diameters of 9.5 mm. Based on the micro-tomography data, we have computed porosity-values for each imaged rock sample. For validating the computed porosity values with a complementary lab method, we have measured porosity for each rock sample by using standard petrophysical characterization techniques. Overall, the tomography-based porosity values agree with the measurement results obtained from the lab, with values ranging from 8% to 30%. In addition, we provide for each rock sample the experimental permeabilities, with values ranging from 0.4 mD to above 5D. This dataset will be essential for establishing, benchmarking, and referencing the relation between porosity and permeability of reservoir rock at pore scale.

Geochemical Effects on Storage Gases and Reservoir Rock during Underground Hydrogen Storage: A Depleted North Sea Oil Reservoir Case Study

In this work, geochemical modelling using PhreeqC was carried out to evaluate the effects of geochemical reactions on the performance of underground hydrogen storage (UHS). Equilibrium, exchange, and mineral reactions were considered in the model. Moreover, reaction kinetics were considered to evaluate the geochemical effect on underground hydrogen storage over an extended period of 30 years. The developed model was first validated against experimental data adopted from the published literature by comparing the modelling and literature values of H2 and CO2 solubility in water at varying conditions. Furthermore, the effects of pressure, temperature, salinity, and CO2% on the H2 and CO2 inventory and rock properties in a typical sandstone reservoir were evaluated over 30 years. Results show that H2 loss over 30 years is negligible (maximum 2%) through the studied range of conditions. The relative loss of CO2 is much more pronounced compared to H2 gas, with losses of up to 72%. Therefore, the role of CO2 as a cushion gas will be affected by the CO2 gas losses as time passes. Hence, remedial CO2 gas injections should be considered to maintain the reservoir pressure throughout the injection and withdrawal processes. Moreover, the relative volume of CO2 increases with the increase in temperature and decrease in pressure. Furthermore, the reservoir rock properties, porosity, and permeability, are affected by the underground hydrogen storage process and, more specifically, by the presence of CO2 gas. CO2 dissolves carbonate minerals inside the reservoir rock, causing an increase in the rock’s porosity and permeability. Consequently, the rock’s gas storage capacity and flow properties are enhanced.

The effect of fracturing on permeability in carbonate reservoir rocks

Hydrocarbon flow rates from tight carbonate reservoirs often depend on the distribution and properties of fractures throughout the reservoir interval. Hence, quantification of fracture parameters can contribute to understanding of reservoir characteristics and reservoir potential. In this paper, natural fractures in tight carbonate reservoir rocks of the Upper Cretaceous Shiranish Formation in the Taq Taq field (Kurdistan Region of North Iraq) were examined primarily using core samples, XRMI micro-resistivity image logs and conventional wireline logs, with additional dynamic data from well tests and mud logs. The Shiranish Formation is composed of a variety of limestones and argillaceous limestones with arithmetic mean matrix porosity and geometric mean permeability values of 1.64 ± 0.37% and 0.0223 ± 0.59 mD, respectively. However, fracturing has enhanced the permeability by up to four orders of magnitude above the maximum matrix permeability (1.79 ± 0.59 mD). Hydrocarbons are produced entirely from the fracture network in these rock types in the Taq Taq reservoir. Observed open and partially-open fractures have NE-SW orientations; these are classified as macro-fractures with average aperture of 0.17 ± 0.18 mm, arithmetic mean height of 11.70 ± 45.40 mm and arithmetic mean length of 26.7 ± 32.32 cm, where the uncertainties are standard deviations. Fracture aperture size and fracture height control fracture permeability and fluid flow. However, while fracture frequency has no effect on permeability, fracture distance distribution influences flow rates and hydrocarbon production. The dominant NE-SW trending fractures are more likely to remain open within the NE-SW oriented present day stress field at Taq Taq. Furthermore, the effect of overburden stress on the permeability and production rate was examined in laboratory tests on core plugs by increasing the confining stress during permeability measurements using constant flow rates. It was found that the magnitude of fracture permeability was reduced by 70% by applying 4000 psi of confining stress. In the reservoir, this effect would be exacerbated by reduced reservoir fluid pressures as a function of production. However, fractures with apertures greater than 0.10 mm are preserved as productive fractures even at high confining pressures and implying that hydraulic fracturing could open existing fractures significantly, enhancing production. This last observation implies that the use of hydraulic fracturing in tight carbonate reservoirs with natural fracturing is likely to be commercially viable.

Determining the effect of mineral scaling formation under different injection water sources on the performance of Mishrif carbonate reservoir in Halfaya oilfield, Southern Iraq

The chief source of the oilfield scale is the mixing of incompatible waters. This study demonstrated that mixing the reservoir of Mishrif formation (Halfaya oilfield) with six types of injection water sources, including Tigris River water, producing water formation, Gulf seawater, Marshes water, Middle Kirkuk formation water, and Main Outfall Drain water (AL-Masab AL-Aam Channel), leads to the formation of salt crusts that cause the reduction of reservoir rock permeability. According to the Piper diagram, the Mishrif formation water of all extant water samples was of the sodium chloride type (NaCl), except for HF-81, which was between (NaCl) and mix (CaMgCl) type. A geochemical simulation model of water alignment (PHREEQC) was used to simulate this problem, and it revealed the mineral scaling from mixing processes. These minerals precipitate in rock pores and clog them, which then cause damage to the petrophysical properties of the reservoir and prevent the passage of liquids. Results showed that the best water types used for injection are Middle Kirkuk formation water, followed by the general downstream, then Gulf seawater, but treatment before injection is needed. The study of geochemical modeling method can help to better understand scaling issues by efficiently identifying the best injection water from various selected types with the lowest possible cost, which in turn improves oil production.

CT-based 3D pore-fracture network analysis of volcanic reservoirs of Lower Cretaceous Yingcheng formation in southern Songliao Basin, China: Impact on natural gas migration

Volcanic rocks as an important part of basins are found in almost all basins in the world. Although volcanic rock reservoirs are denser and more heterogeneous than conventional reservoirs, they still have good storage capacity in the deeper hydrocarbon-bearing basins. Due to the presence of a large number of irregular and random pores, throats and fractures in volcanic reservoirs at micron-nano scale, its permeability and reservoir capacity are complex. A series of experiments show an abnormal negative correlation between porosity, permeability and natural gas diffusion coefficient in volcanic reservoir rocks of the Yingcheng Formation in the southern Songliao Basin. The dacite sample from CS105 well in Changling Fault Depression and the andesite sample from DS9 well in Dehui Fault Depression with this negative correlation phenomenon were selected, the micron-nano CT scanning technology and Avizo software are applied to quantitively evaluate the 3D pore-fracture network system of the volcanic reservoir samples at multiscale. By comparing the statistical results from CT scanning of the two samples, the dacite sample of CS105 well with higher diffusion coefficient has higher porosity, more connected pores, larger average pore volume and higher average coordination numbers, in addition, the micro-fractures in the CS105 sample promotes the development of secondary pore-throats through later dissolution and further improve the physical properties of volcanic rock reservoirs. In the meantime, the gas seepage simulation results also prove the positive correlation between porosity, permeability and diffusion coefficient of volcanic rock reservoir. The micron-nano CT scanning can more accurately evaluate the physical properties of volcanic rock reservoirs with a large number of pore-throats and fractures at the micron-nano scale, providing theoretical basis for the study of natural gas migration mechanism in highly heterogeneous tight volcanic rock reservoirs.

Improving carbonate reservoir characterization by applying rock typing methods: a case study from the Nam Con Son Basin, offshore Vietnam

Understanding the permeability-porosity relationships is the key to improving reservoir prediction and exploitation especially in carbonate reservoirs, which are known for their complex textural and diagenetic variation. Rock type classifications have long been proven to be an effective technique for establishing permeability- porosity relationships, enhance the capability to capture the various reservoir flow behavior and prediction for uncored reservoir zones. This study highlights some of those practical and theoretically-correct methods, such as Hydraulic Flow Unit (HFU); Global hydraulic element (GHE), Winland’s R35 method, Pittman method, Lucia method. They are proposed and tested for identification and characterization of the rock types using a database of 555 core plugs from the Miocene carbonate reservoir in the Nam Con Son basin. It is a large isolated carbonate build-up structure which were deposited within a shallow marine platform interior and are dominated by coral, red algal and foraminiferal packstones, wackestones and grainstones. Hydrocarbons in this reservoir have been found in the upper most part of the late Miocene formation. Conventional core data were first used to define and display the cross plot of permeability and porosity. Different charts and cutoff thresholds were used to classified, defined number of rock type and the linear and non-linear equations were established. The predicted core permeability was calculated using different methods and compared with the actual core permeability for each rock type. The predicted reservoir rock type and permeability predictions of HFU method was recognized to give better matching of measured core permeability with coefficient of more than 89%.