Permeability Carbonate Reservoirs Research Articles

Effects of Nanoparticles on Gas Production, Viscosity Reduction, and Foam Formation during Nanofluid Alternating Gas Injection in Low and High Permeable Carbonate Reservoirs

AbstractSome carbonate reservoirs are low‐permeable and mixed‐wet to oil‐wet. Application of enhanced recovery methods to decrease residual oil saturation is the main challenge in such reservoirs. Water‐flooding is not an appropriate method to improve the recovery due to the wettability of carbonate reservoirs. Water alternating gas (WAG) injection is used as another method but it faces some problems. To enhance the performance of the WAG method, the wettability of rock should be changed and mobility of the injected gas should be controlled.In our previous study (Moradi et al.[32]), to improve the WAG‐EOR process and overcome the problems, we developed the nanofluid‐alternating gas (NWAG) approach by adding nanoparticles to the aqueous phase. Our study indicated that the NWAG process could improve oil recovery in comparison to the conventional WAG method in different core samples with different lithology and permeability. In this study, core‐flooding experiments, dynamic foam generation, and viscosity measurement were performed to investigate the effect of nanoparticles on gas production, viscosity reduction, and possibility of foam formation in the NWAG process. The results indicated that the gas production was decreased in the NWAG process. In addition, viscosity of produced oil was lower in the NWAG process; CO2 dissolved in the oil and led to oil swelling and oil viscosity reduction. Oil recovery was higher in the samples with lower permeability due to the formation of foam in the porous media. Foam formation increased viscosity and controlled mobility, which led to better sweep efficiency.

Core/Shell Systems for Delayed Delivery of Concentrated Mineral Acid

Summary Acid stimulation, for both oil and gas wells, greatly supports the industry as a versatile means of enhancing production. Although acids enhance carbonate reservoir permeability to hydrocarbons, the reaction rates of the acid [e.g., hydrochloric acid (HCl)] with the rock often are too rapid at high temperatures, leading to a reduction in acid penetration. Several methods exist to improve the effectiveness of acidizing in high-temperature reservoirs (e.g., greater than 120°C), including the use of conventional emulsified-acid systems, mixtures of HCl and organic acids, and gelled acids. Many of the aforementioned techniques are effective forms of treatment; however, they hold significant limitations such as reduction in acid efficiency, poor control over penetration depth, and the requirement of corrosion inhibitors. Accordingly, encapsulated HCl holds potential as an attractive alternative to address these shortcomings because its prolonged release profile would permit transport of acid deep within the reservoir. In addition, when successfully encapsulated, this technology could eliminate, or at the very least minimize, the use of corrosion inhibitors. Herein, we demonstrate the design and preparation of highly modular core/shell particles comprising concentrated HCl encapsulated within an acrylate-based thermoset polymer shell. We show that the shell-generation mechanism (i.e., photopolymerization of acrylate monomers) is compatible with concentrated HCl and further detail the encapsulation process. Our results demonstrate that the acid-release profiles are dictated by the properties of the shell material, enabling a prolonged delivery of HCl in laboratory studies. This is a first step toward the design of particle-shell systems that can tolerate harsh reservoir conditions, including high temperatures, pressures, and salinity of mixing water. A tunable core/shell delivery system that encompasses a sufficient amount of strong mineral acid is well-poised to address the unmet need of deeper penetration of HCl into the reservoir, enabling greater stimulation efficiency.

Integrating seismic and log data for improved petroleum reservoir properties estimation using non-linear feature-selection based hybrid computational intelligence models

Various petroleum reservoir properties have been estimated in literature using only one of log, seismic or production data. The recent trend in data mining is integrating multi-modal and multi-dimensional data for improved reservoir properties prediction. The objective of this paper is to employ hybrid machine learning and feature-selection based predictive models to estimate the permeability of carbonate reservoirs from integrated seismic and well log data. Hybrid models of Type-2 Fuzzy Logic System (T2FLS) and Support Vector Machine (SVM) with Functional Networks (FN) as the non-linear feature selection algorithm are proposed. Five seismic attributes were integrated with six commonly used Well logs. Data were collected from 33 oil Wells but only 17 of them had a complete matching seismic-log pair. The performance of the hybrid models were compared to those of the individual models without the non-linear but with the conventional feature selection algorithm. The comparative results showed improved prediction accuracies with the hybrid models and more excellently with the FN-SVM model. A blind test on the models revealed that the FN-SVM hybrid model gave an (R-Square) of 0.82, root mean square error of 0.46, and mean absolute error of 0.42 compared to the lowest performing T2FLS model with 0.40, 0.77 and 0.65 respectively. This demonstrates the significance of the hybrid machine learning paradigm in solving petroleum engineering problems with improved accuracies. The study presented some lessons learned from the data limitation challenges experienced in this work and proposed recommendations to chart further research directions.

Pore Network Modeling of Reactive Transport and Dissolution in Porous Media

Dissolution of solid grains in a porous medium is important in many applications, such as groundwater transport, carbon storage, mineral systems, formation of geologic features, and enhancement of near-wellbore permeability in carbonate reservoirs. Many models for dissolution in porous media are continuum-scale descriptions, but the flow, reactive transport, and subsequent increase in porosity and permeability occur at the pore scale. Thus, proper inclusion of parametric inputs is challenging. We present a single-phase, 3D, pore network model of dissolution for porous media in the mass-transfer-limited regime. A novel mass transfer coefficient correlation and pore-merging criterion are developed from finite element simulations that greatly improve the pore-scale physics and the quantitative accuracy of the network. The optimal Damkohler number determined from our network simulations closely matches the optimum of 0.29 reported experimentally for mass transfer dissolution in porous media.

A Novel Homogenous Hybridization Scheme for Performance Improvement of Support Vector Machines Regression in Reservoir Characterization

Hybrid computational intelligence is defined as a combination of multiple intelligent algorithms such that the resulting model has superior performance to the individual algorithms. Therefore, the importance of fusing two or more intelligent algorithms to achieve better performance cannot be overemphasized. In this work, a novel homogenous hybridization scheme is proposed for the improvement of the generalization and predictive ability of support vector machines regression (SVR). The proposed and developed hybrid SVR (HSVR) works by considering the initial SVR prediction as a feature extraction process and then employs the SVR output, which is the extracted feature, as its sole descriptor. The developed hybrid model is applied to the prediction of reservoir permeability and the predicted permeability is compared to core permeability which is regarded as standard in petroleum industry. The results show that the proposed hybrid scheme (HSVR) performed better than the existing SVR in both generalization and prediction ability. The outcome of this research will assist petroleum engineers to effectively predict permeability of carbonate reservoirs with higher degree of accuracy and will invariably lead to better reservoir. Furthermore, the encouraging performance of this hybrid will serve as impetus for further exploring homogenous hybrid system.

Distribution patterns of main structural-group parameters of crude oils from the Volga–Urals oil and gas basin according to NMR data

The character of the distribution of 16 main NMR-measurable parameters of the structural-group composition of Volga–Urals crude oils has been assessed. It has been shown that the distributions quite significantly differ from the normal distribution; they are in general asymmetrical and essentially different. Total aromaticity and the amount of n-alkyl structures in oils of the major stratigraphic plays are on average the same, although there are differences between the northern, central, and southern parts of the oil-and-gas basin. Regarding the concentration of unsaturated hydrocarbons, there are differences between both the plays and territories. Similarities and dissimilarities between the West Siberian and Volga–Urals basins in distributions have been revealed. Some features observed for Western Siberia oils have to be other in the Volga–Urals basin. Upper Carboniferous and Lower Permian carbonate reservoirs in the northeast of the basin have been found to contain oils with a uniquely high concentration of aromatics that evidently differ in composition from those normally present in crude oils. The advantages of interval plots of probability density over histograms for comparing the distributions have been demonstrated. Using the particular material, it has been shown that the Student t-test conventionally used to compare average values for oil groups leads to false conclusions. To determine systematic shifts between distributions, it is necessary to use the Mann–Whitney test and compare the medians of distributions.

Experimental study on influencing factors of acid-fracturing effect for carbonate reservoirs

Abstract Acid fracturing treatment is the key technique for stimulation and stable production in carbonate reservoirs. In order to improve the carbonate reservoirs acid fracturing effect, in this paper, with a large number of experiments as the main research methods, study on influencing factors of acid-fracturing effect for carbonate reservoirs from increase the effective distance of living acid, increase acid corrosion eched fracture conductivity, reduce the acid fluid loss, etc. The effective distances of live acid calculated with reacted acid limitations measured in different acid systems are quite different from those calculated according to previous standard. Fracture conductivity is one of the key parameters that affects acid fracturing effects, but it's difficult to be predicted accurately due to the strong randomness of acid-rock reaction as well as various influence factors. Analyses of the impacts on fracture conductivity resulted from the rock embedment intensity, closure stress, acid dosage, rock-acid contact time, acid fluid loss, acid pumping rate through self-developed small-core fracture capacity test instrument. Fluid loss during acid fracture can be well controlled by thickened liquid as well as solid particles, but formation damage occurs inevitably. Foamed acid is a specific fluid with high viscosity, low fluid loss, small friction resistance, good retarding property, strong fracture making ability, easy flowback and low damage, which is an ideal acid system for low pressure and low permeability carbonate reservoirs. In this paper, the theoretical study on percolation mechanism and fluid-loss control mechanism of foam (acid) in porous medium are presented with the help of visual microscopic model fluid drive unit.

Porosity and permeability of tight carbonate reservoir rocks in the north of Iraq

Abstract The distribution of reservoir quality in tight carbonates depends primarily upon how diagenetic processes have modified the rock microstructure, leading to significant heterogeneity and anisotropy. The size and connectivity of the pore network may be enhanced by dissolution or reduced by cementation and compaction. In this paper we have examined the factors which affect the distribution of porosity, permeability and reservoir quality in the Turonian–Campanian Kometan Formation, which is a prospective low permeability carbonate reservoir rock in northern Iraq. Our data includes regional stratigraphy, outcrop sections, well logs and core material from 8 wells as well as a large suite of laboratory petrophysical measurements. These data have allowed us to classify the Kometan Formation into three lithological units, two microfacies and three petrofacies. Petrofacies A is characterized by dense and compacted and cemented wackstone/packstone with nanometer size intercrystalline pores and stylolites and presents a poor reservoir quality (porosity range 0.005±0.01 to 0.099±0.01, permeability range 65 nD–51 μD). Occasional open fractures in Petrofacies A improve reservoir quality resulting in a 2–3 order of magnitude increase in permeability (up to 9.75 mD). Petrofacies B is a dissolved wackstone/packstone that contains moldic and vuggy pores (porosity range 0.197±0.01 to 0.293±0.01; permeability range 0.087–4.1 mD), with both presenting good reservoir quality, while Petrofacies C is a carbonate mudstone that has undergone dissolution and possibly some dolomitization (porosity range 0.123±0.01 to 0.255±0.01; permeability range 0.065–5 mD). All three petrofacies can be distinguished from wireline log data using porosity and NMR measurements. A poroperm plot of all of the data is fitted by a power law of the form k ( mD ) = a ϕ b with a=28.044 and b=2.6504 with coefficient of determination, R2=0.703. When the permeability is predicted with the RGPZ model of the form k ( mD ) = d 2 ϕ 3 m / 4 a m 2 with mean grain diameter d=10 μm, and mean cementation exponent m=1.5 and a=8/3 a better fit is possible with R2=0.82.

Investigating the effect of correlation-based feature selection on the performance of support vector machines in reservoir characterization

Permeability is an important property of hydrocarbon reservoir as crude oil lies underneath rock formations with lower permeability and its accurate estimation is paramount to successful oil and gas exploration. In this work, we investigate the effect of feature selection on the generalization performance and predictive capability of support vector machine (SVM) in predicting the permeability of carbonate reservoirs. The feature selection was based on estimating the correlation between the target attribute and each of the available predictors. SVM has been improved through the feature selection approach employed. The uniqueness of this approach is the fact that it employs fewer dataset in improving the performance of the SVM model. The effect of the approach has been investigated using real-industrial datasets obtained during petroleum exploration from five distinct oil wells located in a Middle Eastern oil and gas field. The results from this approach are very promising and suggest a way to improve on the performance of this algorithm and many other computational intelligence methods through systematic selection of the best features thereby reducing the number of features employed.

Study on the Nonlinear Flow Percolation Law in Low Permeability Carbonate Reservoir of HF Oilfield

With the development of the global oil industry,the production of the normal or high permeability reservoirs decline rapidly. Therefore, more and more low permeability reservoirs are used to the production stimulation. The oilfields overseas make great contribution to CNPC. The HF oilfield is one oilfield that the CNPC have in overseas. The HF oilfield is mainly the low permeability carbonate reservoirs which make it not easy to economically exploit. Due to the reason that the low permeability carbonate reservoirs present small porosity and the fluid’s flow situation in the low permeability carbonate reservoirs, the flow doesn't obey the Darcy's law. Thus it is greatly necessary to study the non-Darcy percolation characteristics. In this paper, the HF ‘s low permeability is tested and the threshold pressure gradient test is finished ,according to the experiment results, the nonlinear percolation ‘s law ,which is suited to HF-oil field , is illustrated and the reservoir classification is achieved.

Study on Micro Pore Structure Characteristics of Carbonate Cores of Low Permeability

In order to understand the characteristics and flow characteristics of the low permeability carbonate reservoir of Middle East, in this paper, we take a Middle Eastern oil field as an example, using constant-rate mercury penetration technique, analyzing the micro pore structure characteristics of carbonate cores. The results show that, the pore radius distribution characteristics of different permeability is similar, mostly between 90-200μm, the peak occur at about 120μm. After that, we get the main factor affecting the reservoir physical quality of carbonate reservoir is throat rather than pore. And compared with the same permeability of sandstone cores, found that even if a poor sorting and strong heterogeneity of carbonate cores, but due to its throat contribution to permeability is very balanced, show the low permeability carbonate difficulty of development smaller than sandstone, only reducing the pore throat ratio, improve the ability of reservoir seepage, can have a good development effect.

Complex relationship between porosity and permeability of carbonate reservoirs and its controlling factors: A case study of platform facies in Pre-Caspian Basin

Abstract Based on a large amount of core analysis data in eastern Pre-Caspian Basin, the relationship between permeability and porosity and its influencing factors are studied. The sedimentary environments of the Carboniferous System in eastern Pre-Caspian Basin include open platform, restricted platform and evaporate platform. For dolomite reservoirs there are three main combination patterns of pores, namely, inter-crystalline and solution pores, inter-crystalline micro-pores, inter-crystalline and intra-crystalline pores, among which the first combination are highest in porosity and permeability. For limestone reservoirs, the main combination patterns of pores are inter-particle pores, inter-particle and intra-particle pores and moldic pores. Lacking connecting pore throats, moldic pores are poor in permeability. In the dolomite reservoirs, fractures and vugs are well-developed and increase the permeability significantly. Under similar porosity, the permeability is obviously determined by the size of pore throat and the percentage of middle to large size throats in different types of reservoirs. In limestone reservoirs, fractures are principally micro-fractures, the percentage of connecting pores to total pores is positively correlated with permeability; while in dolomite reservoirs, there is not such an obvious relationship between the percentage of connected pores to total pores and permeability. Sedimentary environment, controlling the distribution features of reservoir types, is the cause of the complex relationship between permeability and porosity.

Experiments and modeling of variably permeable carbonate reservoir samples in contact with CO2-acidified brines

Reactive experiments were performed to expose sample cores from the Arbuckle carbonate reservoir to CO2-acidified brine under reservoir temperature and pressure conditions. The samples consisted of dolomite with varying quantities of calcite and silica/chert. The timescales of monitored pressure decline across each sample (and concurrent increases in permeability) in response to CO2 exposure, as well as the amount of and nature of dissolution features, varied widely among these three experiments. For all samples cores, the experimentally measured initial permeability was at least one order of magnitude or more lower than the values estimated from downhole methods. Nondestructive X-ray computed tomography (XRCT) imaging revealed dissolution features including “wormholes,” removal of fracture-filling crystals, and widening of pre-existing pore spaces. In the injection zone sample, multiple fractures may have contributed to the high initial permeability of this core and restricted the distribution of CO2-induced mineral dissolution. In contrast, the pre-existing porosity of the baffle zone sample was much lower and less connected, leading to a lower initial permeability and contributing to the development of a single dissolution channel. While calcite may make up only a small percentage of the overall sample composition, its location and the effects of its dissolution have an outsized effect on permeability responses to CO2 exposure. The XRCT data presented here are informative for building the model domain for numerical simulations of these experiments but require calibration by higher resolution means to confidently evaluate different porosity-permeability relationships.

Cap rock efficiency and fluid circulation of natural hydrothermal systems by means of XRD on clay minerals (Sutri, Northern Latium, Italy)

We performed XRD investigations on the sedimentary cap rock of the geothermal system developed in the area of Vico volcano (Northern Latium) to assess its effectiveness and degree of interaction with fluids. The system consists of a positive thermal anomaly, a permeable carbonate reservoir at shallow depths and a low permeability siliciclastic cap rock. Unfractured cap rock shows maximum paleo-temperatures <50–60°C, interpreted as the thermal signature of the original sedimentary basin. Fractured cap rock is characterized by kaolinite, calcite, short-range ordered mixed layers illite-smectite with paleo-temperatures between 85 and 110°C indicating strong interaction with hot fluids from a carbonate reservoir.

A comparison of water chemistry from a CO2‐enhanced oil recovery project with reactive transport modeling of CO2 injection into a carbonate reservoir

AbstractA long‐term geochemical monitoring program was conducted at a CO2‐enhanced oil recovery site in central Alberta (Canada) to examine geological storage of CO2. The program included geochemical monitoring of reservoir brines, a mineralogical study, and using TOUGHREACT to compare model and field observations. CO2 was injected into a highly permeable carbonate reservoir at 78 tonnes/day for 2.5 years. Fluid and gas samples were obtained for geochemical characterization before, during, and 1.4 years after injection from a production well ∼915 m from the injection well at a depth of ∼936 m. Downhole water compositions were calculated using SOLMINEQ88 and compared to predictions from TOUGHREACT. Following CO2 breakthrough after ∼23 months, downhole pH decreased, HCO3−; and calcium concentrations increased, while magnesium concentrations changed marginally, indicating solubility and ionic trapping were occurring simultaneously. Trends in analyzed and modeled species were similar, but concentration levels were different. Calibrating the model to achieve better correlation between results was attempted but proved unsuccessful. The variances were likely caused by differences between ideal and reservoir mineral's kinetic parameters, surface area, thermodynamic parameters and sampling technique. Five‐hundred‐year simulations showed the CO2 plume migrating vertically due to capillary forces with no significant change in gas saturation below the caprock over the post‐injection period. The majority of CO2 remained trapped as a supercritical phase as the reservoir is composed of only carbonate minerals. The low reactivity of the reservoir is positive, in that the reservoir is not negatively impacted by dissolution and negative in that no mineral trapping occurs. © 2013 Society of Chemical Industry and John Wiley &amp; Sons, Ltd

Experimental investigations of variations in petrophysical rock properties due to carbon dioxide flooding in oil heterogeneous low permeability carbonate reservoirs

Carbon dioxide has been successfully applied worldwide as an enhanced oil recovery process. Several important factors still have not been studied thoroughly. Therefore, this experimental study was carried out to investigate the variations in petrophysical reservoir rock properties of oil heterogeneous low permeability carbonate reservoirs. The main objectives of this experimental study are to investigate the effects of CO2 injection in tight limestone reservoir rocks on porosity, absolute and relative permeability, oil–water interfacial tension (IFT), reflective index, and reservoir water shielding phenomenon. Actual rock and fluid samples from an oil field in Abu Dhabi, UAE, are used to conduct this study at similar reservoir conditions of 4,000 psia and 250 °F. Oil recovery, permeability, porosity, and relative permeability were measured before and after the supercritical carbon dioxide (SC-CO2) flood to examine the effects of SC-CO2 flood on the variation in different oil and rock properties of tight composite limestone reservoir rocks. Detailed compositional analysis of initial and produced oil samples of core flood experiments were analyzed using gas chromatography to assess the mechanism of CO2 improved oil recovery. The results indicated that the application of SC-CO2 flooding under secondary and tertiary modes reduces porosity and permeability, alters relative permeability to a more water-wet condition, and reduces the oil/water IFT as a function of pore volume injected. Furthermore, the extracted components of the crude oil were also proven to be a function of injected CO2 pore volume. The applications of the attained results of this study provide much better understanding of different variation occurring in oil reservoirs under SC-CO2 injection and can be used effectively to validate and improve numerical simulation studies.

The Development Technology Policy of Secondary Oil Recovery in the Overpressure Carbonate Reservoir

Kenkiyak oilfield in kazakstan is a low porosity, extremely low permeability and overpressure carbonate reservoir. There are different reservoir and fracture characteristics in different region. The formation pressure decline seriously and water cannot be injected into the low permeability zone. Referring to the domestic and oversea research achievement, integrating regional geologic characteristics, numerical simulation results and reservoir engineering research results, we optimize a series of the development technology policy, including the reasonable gas and water injection modes and injection opportunity, the suitable well patterns and well spacing. Meanwhile, the development mode of energy supplement in the extremely low permeability and overpressure reservoir is explored.

A simple geometric model of sedimentary rock to connect transfer and acoustic properties

A simple rock model is presented which reproduces the measured hydraulic and electric transport properties of sedimentary rocks and connects these properties with each other, as well as with the acoustic propagation velocities and elastic moduli. The model has four geometric parameters (average coordination number Z of the pores, average pore radius r, average distance between nearest pores d, and average throat radius δ) which can be directly determined from the measured porosity Φ, hydraulic permeability k, and cementation exponent m of the rock via simple analytic expressions. Inversion examples are presented for published sandstone data, and for cores taken from Saudi Arabian, Upper Jurassic and Permian carbonate reservoirs. For sandstone, the inversion works perfectly; for carbonates, the derived rock model shows order-of-magnitude agreement with the structure seen in thin sections. Inverting the equations, we express the transfer properties Φ, k, and m as functions of r, d, δ, and Z. Formulae are derived for the bulk density Db, formation factor F, and P-wave velocity in terms of the proposed geometrical parameters.

Extreme Learning Machines Based Model for Predicting Permeability of Carbonate Reservoir

Extreme Learning Machines Based Model for Predicting Permeability of Carbonate Reservoir

Effectiveness of Calcium Sulfate Scale Inhibitors in Spent Hydrochloric Acid/Seawater System

Previous results have reported the precipitation of calcium sulfate during matrix acid treatments when seawater was used to prepare HCl-based acid. Precipitations of calcium sulfate causes severe damage on the permeability of carbonate reservoirs and negatively impacts the performance of acid treatments. Typically, scale inhibitors are applied in the field to prevent the formation of calcium sulfate scale, and the object of this study is to evaluate the effectiveness of different types of scale inhibitors to inhibit the formation of calcium sulfate scale during the acid stimulation process. Scale inhibition efficiency was determined in batch tests under different temperatures (77 to 210°F) and different degrees of spent acid conditions. Sulfate ions were analyzed in the samples of the batch tests to detect the precipitations of calcium sulfate. Results showed that application of scale inhibitors can successfully mitigate calcium sulfate scale formation up to 210°F. At higher temperatures, the rate of calcium sulfate precipitation increased and the effectiveness of all types of scale inhibitors decreased greatly. Most of the scale inhibitors were not effective in acidic conditions and some of the scale inhibitors even precipitated out of the solution in the presence of high concentration of calcium ions. Methylene phoshponic acid scale inhibitor was the most effective one under various experimental conditions. The findings in this study provided information for better calcium sulfate scale control under acid stimulation conditions.