Carbonate Core Samples Research Articles

Experimental study of the dissolution of carbonate samples with acid solutions

In this paper, we study the interaction of eight carbonate core samples (the same size, almost entirely composed of calcite) with hydrochloric acid solutions with concentrations of 12% and 18% at solution flow rates of 1, 2, 4, and 8 ml/min, respectively. During flooding experiments, the flow rate of acid solutions unevenly affected the final permeability and breakthrough pore volumes. In the case of injection of a 12% HCl solution, an average of almost 20% more acid solution was required for a breakthrough comparing to the injection of a 18% HCl solution, although in both cases the injection was carried out at the same rates. It was found that the largest increases in permeability are achieved mainly at high flow rates of the solution. Speaking of the 18% HCl solution during flooding experiments, almost identical pore volumes of solution were required to breakthrough for all flow rates; also, with an increase in the injection rate, a progressive increase in permeability was observed. The results of laboratory studies can be useful in the treatment of near wellbore zones and CO2 sequestration on a large scale for an approximate assessment of the final permeability of the treated zone and the required volumes of acid solutions.

Microbial induced mechano-petrophysical modified properties to improve hydrocarbon recovery in carbonate reservoirs

This study focuses on the impact of a microbial-induced process on mechanical and petrophysical properties of tight carbonate hydrocarbon reservoirs and its implication for hydrocarbon recovery from carbonate reservoirs. Tight carbonate core samples were treated with cultured microbial media of Clostridium acetobutylicum at 42 °C for 14 days. The before- and after-treatment mechanical (unconfined compressive strength, UCS; fracture toughness, Ks) and petrophysical (porosity and permeability) properties of the core samples were investigated and analyzed. The scratch test method was used for assessing the geomechanical properties. The results indicate that in tight carbonate reservoirs, post-treatment microbial-induced alterations could degrade its mechanical integrity with −30% UCS and −28% Ks. The post-treatment improvement in petrophysical properties of the tight carbonate rocks yielded a 355% increase the porosity and ＋734% in permeability. The application of the technology presented in this study can potentially enhance the susceptibility for induced fractures to nucleate and propagate during reservoir stimulation in tight carbonate reservoirs, and enhance flow pathways to improve hydrocarbon recovery. This study provides insight into microbial-induced alteration technology that can be incorporated with other reservoir-stimulation techniques to further enhance hydrocarbon recovery from carbonate reservoirs.

Minimizing the Barite Scale in Carbonate Formations during the Filter Cake Removal Process.

The barite scale is one of the most common scales in the oil and gas industry. It can form in the reservoir or precipitate in different production equipment. The formation of such a scale will significantly minimize the capillary diameter of the flow channels and consequently shrink the well productivity. On the other hand, the production of movable barite particles causes severe erosion for the installed equipment. There are several sources of the barite scale such as mixing of incompatible brines and solid invasion of the barite weighted during drilling. In addition, the barite scale could be produced during the interaction of the chelating agent solutions with the reservoir formation during the filter cake removal process (secondary damage). The main focus of this study is to prevent the barite scale inside the carbonate formations during filter cake removal. The capability of a solution consisting of both diethylenetriamine pentaacetic acid (DTPA) and ethylenediamine tetraacetic acid (EDTA) as a novel solution to prevent barite scale formation in carbonate formations after the removal of the barite filter cake was evaluated. A series of laboratory experiments were accomplished to characterize the barite scale and evaluate the performance of the proposed solution. In particular, particle size distribution, scanning electron microscopy, X-ray diffraction, core flooding, NMR spectroscopy, solubility test, and inductively coupled plasma (ICP) spectroscopy tests were conducted for this aim. The experiments were performed using carbonate core samples. The results showed that the proposed solution was able to load 35 000 ppm barium in the presence of calcite ions. The addition of EDTA tended to inhibit the barite deposition and improve the rate of the calcite reaction. NMR results showed that a mixture of DTPA and EDTA (20%) can stimulate the macropores, resulting in an increase in the return permeability by 1.4–1.8 times of the initial value, while the precipitation that occurred in the micropores could be ignored with respect to the overall porosity improvements.

Prospects and Challenges for the Spatial Quantification of the Diffusion of Fluids Containing 1H in the Pore System of Rock Cores

AbstractNuclear magnetic resonance (MR) (NMR) is commonly used for the determination of rock porosity, as well as pore size distribution (PSD) and tortuosity, required to handle hydrocarbon exploitation. Emerging technologies for NMR equipment now enable the visualization of porosity using magnetic resonance imaging (MRI). Currently, single‐point imaging is the most common MRI technique employed, but diffusion‐weighted imaging has been attracting the attention of geologists and geophysicists. In this study, a more advanced technique, diffusion tensor imaging (DTI), is proposed for the characterization of rock core samples. The main purpose of this paper is to demonstrate the usefulness of DTI in the petrophysical characterization of rocks and discuss its strengths. As an example, a carbonate core sample was examined using DTI. The diffusion tensor (DT) was obtained and DT parameters (mean diffusivity, MD; fractional anisotropy, FA; three eigenvalues; DT components; and proton density, PD) were visualized in 2D and 3D. Each parameter was described and its utility in terms of pore space characterization was analyzed. In addition, a new parameter, principal diffusion tracts, was introduced based on the DT tractography performed in the study. The analysis is summarized in a set of DT parameters and a resultant ellipsoid that delivers complementary information about the sample's pore network microgeometry, including referential measurements of anisotropic phantoms. The applications of DTI for the determination of pore size distribution, tortuosity and conductivity are also shown. The study ends with a consideration of the potential prospects and challenges for DTI‐based examination of rock core samples.

The impact of wormhole generation in carbonate reservoirs on CO2-WAG oil recovery

In this paper, the impact of CO2-carbonate interactions on hydrocarbon recovery from three initially oil-saturated heterogeneous carbonate core samples (with low and mid permeabilities) were investigated. Alternate injection of carbon dioxide (CO2) and synthetic formation brine was conducted after water flooding. X-ray computed tomography scanning of the core samples before and after core flooding was performed at ambient conditions. Extent of carbonate dissolutions and rock matrix modifications were observed from the change in porosities, permeabilities, and wormhole formations. Generally, the CO2-WAG injection resulted in more than 30% extra oil recovery from the three cores after water flooding scenario. As expected, the total recovery factor of the core with lowest initial permeability and porosity was the smallest, however the core permeability increased from 1.45 mD (pre-flood) to 1987.9 mD (post-flood). Considerable amount of oil was left behind in the core with initially low permeability and porosity due to preferentially flow of WAG fluid through the wormholes, bypassing the trapped oil in the pore spaces at the uninvaded region of the rock. The study suggests that low oil recovery from core with low initial permeability and porosity is principally due to formation of wormhole because of rapid rate of rock dissolution and faster rate of CO2-carbonate reactions. Compared to the mid permeability cores, the low permeable core slows down the WAG fluid flow and give more time for CO2-carbonate rock interactions and reactions because of the tightness of the pore spaces. Thus, facilitated more exposure time and effective contact between the carbonate rock fabrics and the CO2-saturated brine.

New Correlation for Calculating Water Saturation Based on Permeability, Porosity, and Resistivity Index in Carbonate Reservoirs.

Water saturation assessment is recognized as one of the most critical aspects of formation evaluation, reserve estimation, and prediction of the production performance of any hydrocarbon reservoir. Water saturation measurement in a core laboratory is a time-consuming and expensive task. Many scientists have attempted to estimate water saturation accurately using well-logging data, which provides a continuous record without information loss. As a result, numerous models have been developed to relate reservoir characteristics with water saturation. By expanding the use and advancement of soft computing approaches in engineering challenges, petroleum engineers applied them to estimate the petrophysical parameters of the reservoir. In this paper, two techniques are developed to estimate the water saturation in terms of porosity, permeability, and formation resistivity index through the use of 383 data sets obtained from carbonate core samples. These techniques are the nonlinear multiple regression (NLMR) technique and the artificial neural network (ANN) technique. The proposed ANN model achieved outstanding performance and better accuracy for calculating the water saturation than the empirical correlation using NLMR and Archie equation with a high coefficient of determination (R2) of 0.99, a low average relative error of 1.92, a low average absolute relative error of 13.62, and a low root mean square error of 0.066. To the best of our knowledge, the current research establishes a novel foundation using the ANN model in the estimation of water saturation.

Effect of polymer–graphene-quantum-dot solution on enhanced oil recovery performance

This study aimed to utilize graphene-quantum-dots in addition to a D118 superpusher polymer to increase oil recovery from mature oil fields. First, nanoparticles (NPs) were synthesized and fully characterized. These were then added to polymer solutions so the prepared fluids could alter the microscopic and macroscopic sweep efficiencies. To identify the best samples, concentrations of the NPs and polymer, as well as two types of salt, were carefully selected as influencing parameters using Design Expert as a time- and cost-saving technique. Interfacial tension (IFT) and contact angle—parameters affecting microscopic efficiency—as well as shear viscosity, which affects macroscopic efficiency, were considered as responses in this method. IFT reduction (of approximately 1.78 mN/m) and an extraordinary change in the wettability to hydrophilic were achieved, particularly in carbonate rocks as opposed to sandstone. In addition, the polymer resulted in improved mobility ratio. From the experiment and analysis of variance, two flooding fluids that increase the recovery factors for carbonate and sandstone core samples by up to 31% and 20%, respectively, are proposed. Furthermore, core flooding experiments confirmed the effectiveness of the proposed fluids for enhanced oil recovery.

Performance of sodium lignosulfonate as thickening additive in compositions for matrix acidizing of bottom hole zone

The work considers one of the promising directions for optimizing matrix acidizing using sodium lignosulfonate as a thickening agent. The mechanism of the interaction of acid solutions containing lignosulfonate with carbonate reservoirs is described. The use of sodium lignosulfonate in acid solutions solves several problems. Slowing the reaction rate allows the acid solution penetrate deeper into the formation, with maintaining the HCl concentration. The increased viscosity of the compositions increases the sweep efficiency of the bottomhole zone in the process of matrix acidizing. These two aspects increase the efficiency of matrix acidizing and the permeability of the bottomhole zone. In the course of this work, the chemical reaction rate of sodium lignosulfonate and hydrochloric acid solutions with carbonate core samples were evaluated. Sodium lignosulfonate in an acid solution reduces the dissolution rate of carbonate samples. It is assumed that slowing down the reaction rate allows the acid solution to form long high permeability channels which increases the efficiency of acidizing.

Development of a new chemical solvent package for increasing the asphaltene removal performance under static and dynamic conditions

In this work, a new solvent package (named TPMDS) for asphaltene removal under static and dynamic conditions was developed through a set of experiments. TPMDS consists of toluene, pyridine, methanol, surfactant dodecylbenzenesulfonic and sodium hydroxide. The optimum concentrations of TPMDS components were determined based on the efficiency evaluation of the chemical reagents to eliminate the asphaltene precipitation under static conditions. The highest effectiveness of the developed solvent package under static conditions was found to be 98%, which was observed at a soaking time of 6 h and a mass concentration of 1%. TPMDS had high performance (more than 97.5%) for asphaltene removal in four different oil samples containing various asphaltene concentrations. The results of the turbidity and dissolution rate experiments of asphaltene in the presence of TPMDS and toluene showed that the performance of TPMDS for asphaltene removal is significantly better than toluene. In addition, core flood tests were carried out with the use of TPMDS and toluene. Pressure drop due to asphaltene precipitation in the carbonate core samples was reduced eight times using the developed solvent package. The damaged permeability due to asphaltene deposition was 51% of the initial rock permeability before injection of any solvent. The results of core flood tests showed that the rock permeability has reached about 94% and 71% of the initial permeability after injection of TPMDS and toluene, respectively. Despite the increase in the amount of asphaltene precipitation in the core samples by increasing injection rate, the efficiency of the developed solvent was not decreased by changing the injection rate since the performance of the TPMDS was improved by the appearance of a synergistic effect for asphaltene dissolution. Furthermore, oil viscosity reduction with the use of TPMDS was more significant than with the use of toluene. The corrosion rate of the metal samples in the presence of the developed solvent package solution was less than 0.08 mm/year in a temperature range from 25 °C to 100 °C, which is less than an acceptable threshold corrosion rate of 0.1 mm/year. Moreover, the results of field analysis showed that the oil production rate could be enhanced by 3.3 times after treatment by TPMDS. Asphaltene removal effectiveness in the production wells using the industrial reagent and TPMDS has reached 84 and 96%, respectively. The rock permeability after treatment by TPMDS was increased by about 290%. TPMDS can be used for asphaltene removal in the near-wellbore region, production equipment, and tubing.

Geochemical simulation of Single-Phase Ion-Engineered water interactions with carbonate Rocks: Implications for enhanced oil recovery

Ion-engineered water flooding (EWI) has attained considerable attention as an efficient and low-cost enhanced oil recovery (EOR) technique with multiple privileges in recent years. Different mechanisms have been proposed for water displacement improvement when seawater with modified composition is injected into carbonate formations. Due to the complexity of rock/fluid interaction, prediction of the EWI process poses a big challenge, and it is vital to identify the main mechanisms governing the EWI process. Thus, the focus of this study is to develop a novel single-phase geochemical model using CMG-GEM simulator and to explore important rock/fluid interactions. The compositional model was developed efficiently; accordingly, a combination of ion-exchange and adsorption reactions have been used to represent surface complexation reactions and reduce the time of simulations without compromising the accuracy of the results. Also, mineral dissolution/precipitation was considered in the model to match simulation results and experimental data. For having a better interpretation of rock/fluid interactions, the effluent ions concentration, ion-exchange equivalent fractions, and the amount of dissolved and precipitated minerals were evaluated. According to the results, the amount of dissolved calcite and precipitated dolomite was found to be insignificant in the carbonate core samples; however, the calcite dissolution and dolomite precipitation, and sulfate adsorption are the main factors affecting the single-phase water displacement process.

Investigations on the relationship among the porosity, permeability and pore throat size of transition zone samples in carbonate reservoirs using multiple regression analysis, artificial neural network and adaptive neuro-fuzzy interface system

Finding an accurate method for estimating permeability aside from well logs has been a difficult task for many years. The most commonly used methods targeted towards regression technique to understand the correlation between pore throat radii, porosity and permeability are Winland and Pittman equation approaches. While these methods are very common among petrophysicists, they do not give a good prediction in certain cases. Consequently, this paper investigates the relationship among porosity, permeability, and pore throat radii using three methods such as multiple regression analysis, artificial neural network (ANN), and adaptive neuro-fuzzy inference system (ANFIS) for application in transition zone permeability modeling. Firstly, a comprehensive mercury injection capillary pressure (MICP) test was conducted using 228 transition zone carbonate core samples from a field located in the Middle-East region. Multiple regression analysis was later performed to estimate the permeability using pore throat and porosity measurement. For the ANN, a two-layer feed-forward neural network with sigmoid hidden neurons and a linear output neuron was used. The technique involves training, validation, and testing of input/output data. However, for the ANFIS method, a hybrid optimization consisting of least-square and backpropagation gradient descent methods with a subtractive clustering technique was used. The ANFIS combines both the artificial neural network and fuzzy logic inference system (FIS) for the training, validation, and testing of input/output data. The results show that the best correlation for the multiple regression technique is achieved for pore throat radii with 35% mercury saturation (R35). However, for both the ANN and ANFIS techniques, pore throat radii with 55% mercury saturation (R55) gives the best result. Both the ANN and ANFIS are later found to be more effective and efficient and thus recommended as compared with the multiple regression technique commonly used in the industry.

Effects of initial wettability and different surfactant-silica nanoparticles flooding scenarios on oil-recovery from carbonate rocks

Initial wettability of rock surfaces plays a crucial role in displacement efficiency during core flooding experiments. In this study, linear alkylbenzene sulfonic acid (LABSA) and silica nanoparticles (NPs) were utilized as enhanced oil recovery (EOR) agents to improve oil recovery from carbonate rock samples. Prior to the core flooding experiments, effects of the presence of LABSA and SiO 2 NPs on oil-water interfacial tension (IFT), wettability alteration, and surfactant adsorption on the rock surfaces were evaluated. The results of IFT/contact angle measurements showed that by adding 0.03 wt% LABSA, the IFT, and contact angle reduced from the initial values of 36.9 mN/m and 115.6° ± 0.2° to 8.3 mN/m and 100.3° ± 0.4°, respectively. Furthermore, incorporating SiO 2 NPs (0.1 wt %) into the system causes a further decrease in IFT value (dropped to 2.2 mN/m), along with a substantial reduction in contact angle (final contact angle after 6 h soaking into the solution was measured as 64.8° ± 0.3°). In addition, surfactant loss due to the adsorption on the rock surfaces decreased up to 35% in the presence of SiO 2 NPs (0.1 wt %). Moreover, various core flooding scenarios in carbonate plugs with different initial wettability conditions were conducted, and the performance of the EOR agents in enhancing oil recovery from oil-wet and water-wet core samples in the secondary and tertiary mode of flooding was evaluated. The outcomes revealed that the injection of a combination of chemicals, containing LABSA (0.03 wt %) and SiO 2 (0.1 wt %) in the secondary mode leads to the highest ultimate oil recovery from sister carbonate core samples.

Precipitation/dissolution and precipitants movement mechanisms effects on injectivity variations during diluted produced water re-injection into a layered reservoir - experimental investigation

ABSTRACT Permeability reduction is one of the significant problems in the water injection process. Several mechanisms may be involved in permeability reduction including scale formation, suspended particle invasion and fines migration. On the other hand, rock dissolution may also lead to permeability improvement of carbonate rocks. In this research, effect of rock lithology along with incompatibility of injection and formation brines, scale formation and plugging of pores by particles in the injection water for a layered reservoir were examined. Diluted formation brine (produced from desalination unit) was considered as injection water. Simulation of scale formation due to thermodynamic conditions and mixing of formation and injection brines were performed to investigate amount and types of scales. Simulation and jar tests showed that Scale precipitation decreased with increasing the mixing ratio of injection water to 75%. For core flooding tests, both carbonate and sandstone core samples from a layered candidate reservoir were selected for monitoring of formation damage and permeability variation due to incompatibility of fluids. SEM and EDX analysis were used for static and dynamic tests. Carbonate core sample showed sever damage and competition between scale precipitation and rock dissolution. Higher flow rates contribute to permeability enhancement of carbonate rocks by prevention of scale sedimentation (less scale formation) and acceleration of carbonate rock dissolution. As a pressure difference increasing of 60% was shown in the first stage of water injection process into the carbonate rock. Eventually, after increasing and decreasing the injection rate, the pressure difference decreased to 30 presences. Scale formation mechanism is dominant in sandstone rock samples and can be removed by backflow. As pressure difference decreased 27% in sandstone rock sample, which resulted in permeability decrease from 365 to 265 mD.

Effects of salinity and ionic composition of smart water on mineral scaling in carbonate reservoirs during water flooding

This work was conducted to study the risk of formation damage as the result of mineral scales deposition during smart waterflooding into carbonate core sample, as well as the influence of injected water salinity and ionic composition on mineral scaling and precipitation. The reservoir flowing conditions were simulated by a new laboratory core-flooding procedure, which took into count of the effect of in-situ contact time (CT) of injected water and formation water on scaling. After the optimum CT was determined, extent of permeability decline was studied by the change in the salinity and ionic composition of injection seawater. The scaled core sample was analyzed visually by scanning electron microscopy (SEM) to study the crystal morphology of the scale. Under the experimental conditions, extent of permeability decline caused by CaSO 4 and CaSO 3 composite scales ranged from 61% to 79.1% of the initial permeability. The salinity and the ionic composition of injected smart water, and CT of the mixing waters had significant effects on the co-precipitation of CaSO 4 and CaSO 3 scales. The SEM images reveal that the loss of permeability is mainly caused by the accumulation and growth perpendicular to the pore wall of scale crystals.

Application of Artificial Intelligence to Predict Enhanced Oil Recovery Using Silica Nanofluids

The feasibility of approaches to enhanced oil recovery (EOR) in harsh conditions of reservoirs should be evaluated primarily in the laboratory environment to capture possible failures that threaten the performance of an operation, although such experiments are commonly expensive and time-consuming. This work investigated the application of artificial intelligence in allaying such concerns regarding the initial screening of EOR methods. Accordingly, three machine learning algorithms, namely adaptive neuro-fuzzy inference system (ANFIS), multilayer perceptron-artificial neural network (MLP–ANN), and radial basis function-artificial neural network (RBF–ANN), were employed to predict the efficiency of a set of silica nanofluid flooding experiments in carbonate and sandstone core samples. Initially, the optimum structures of the employed models were determined. Then, their performances were compared. The strongest performance was achieved by the ANFIS model, where the results in terms of coefficient of determination and root-mean-square error for training, testing, and entire data points were 0.9954 and 0.3395, 0.9877 and 0.4793, and 0.9939 and 0.3793, respectively. The ANFIS model also has the shortest execution time and the least over-fitting problems, and thus it can be utilized for screening the efficiency of silica-EOR projects.

Simulation and analysis of dynamic wettability alteration and correlation of wettability-related parameters during smart water injection in a carbonate core

Low salinity/Smart water injection (LSWI) is a promising enhanced oil recovery (EOR) method, where manipulating the injected water compositions helps in recovery from oil reservoirs via alteration of the rock wettability towards a more water-wet state. In this paper, the experimental data of LSWI in a carbonate core sample have been simulated and matched. The experimental results of oil recovery by injection of four different waters were examined, and the relative permeability curves were adjusted using a dynamic wettability alteration approach. Moreover, results of drainage and imbibition tests used to approximate the corresponding capillary pressures. True effective mobility (TEM) functions were also derived to evaluate the two-phase flow characteristics of the systems. Relative permeability and capillary pressure parameters showed strong correspondence with the injected salinity, and correlations were proposed for estimating the unknown parameters in other similar studies with different salinities. The trend of wettability alteration by LSWI was investigated, and it was concluded that the wettability does not linearly change with salinity, but rather it is non-linearly correlated with the logarithm of the total injected salinity. Injection of seawater (SW) did not significantly change the wettability and flow efficiency of the system compared to formation water (FW). However, dilution of SW to the salinity of 5000 ppm seemed to be the critical threshold below which the effect of LSWI had become substantially more pronounced. The results of this study can be helpful in optimizing and upscaling similar smart water applications, predicting the wettability-related parameters and two-phase flow characteristics at different injected salinities, and also block-to-block modelling in which the effect of the capillary pressure in the fracture network is also considered. Additionally, the non-linear relationship of the wettability-related parameters with salinity is particularly considerable for modifying the common modelling approaches of wettability alteration by LSWI in commercial simulators.

Nitrogen-doped graphene quantum dot nanofluids to improve oil recovery from carbonate and sandstone oil reservoirs

Nanofluids based on nitrogen-doped graphene quantum dots (N-GQDs) are an emerging nanotechnology with potential applications in enhanced oil recovery (EOR). Herein, we report the EOR performances of N-GQDs that have different GQD-sizes and nanofluid concentrations. Wettability and hydrocarbons/water interfacial tension (IFT) studies establish that N-GQDs nanofluids at concentrations of 0.5 mg/mL and with the lowest mean GQDs size range (about 3.5 nm) lead to more wettability alteration of carbonate rocks and decrease the oil/water IFT and n-heptane/water IFT from 16.88 mN/m to 0.975 mN/m, and from 50.24 mN/m to 27.87 mN/m, respectively. Moreover, core flooding experiments show that the aforementioned nanofluid provided greater than 18% and 14% enhancements in the oil recovery factors from carbonate and sandstone core samples, respectively, versus water flooding. In the carbonate core, the alterations of wettability and IFT reduction simultaneously promote oil recovery factors. By comparison, for the case of sandstone core, only the reduction in oil/water IFT leads to higher oil recovery factors.

Surfactant-silica nanoparticle stabilized N2-foam flooding: A mechanistic study on the effect of surfactant type and temperature

The application of nitrogen foam for enhanced oil recovery (EOR) purposes has grabbed the attention of many researchers. With this in view, the main objective of this paper is to design a promising foaming agent by evaluating the influence of silica (SiO2) nanoparticles in combination with three different surfactant-stabilized N2-foams at various salinities and temperatures. Therefore, precise experiments were conducted to investigate the stability of produced foam in the presence of cocamido propyl betaine (CAPB), linear alkylbenzene sulphonic acid (LABSA), and cetyltrimethylammonium bromide (CTAB) as amphoteric, anionic, and cationic surfactants, respectively, and N2 as the gaseous phase. Firstly, foam stability tests were performed, and the results revealed that using the CAPB solution as the aqueous phase for N2-foam generation leads to higher foam stability compared to the LABSA and CTAB surfactants. Secondly, the effects of SiO2 nanoparticles and NaCl on the stability of the generated foams were investigated through the foam half-life time measurements. The outcomes demonstrated that a combination of CAPB (0.05 wt%) + SiO2 (0.1 wt%) + NaCl (5.0 wt%) could form almost 2.28 and 3.15 times more stable foams, as compared to the similar conditions in the presence of CTAB and LABSA surfactants, respectively. Investigations on the effects of temperature on foam revealed that the superiority of the CAPB in generating more stable foams (compared to LABSA and CTAB) continues to 50 °C, and then, as the temperature increases to 70 °C, CTAB surfactant surpasses the CAPB and LABSA surfactants in stabilizing the N2-foams. Furthermore, bulk foam stability tests in the presence of oil was conducted and the results showed that the CAPB surfactant -with the lowest hydrophilic-lipophilic balance (HLB)- was more damaged, as compared to the other used surfactants. The results of foam flooding experiments into three sister carbonate core samples showed an increase of 28.6, 32.1, and 41.0% in ultimate oil recovery by using LABSA, CTAB, and CAPB in combination with SiO2 as the aqueous phase.

Sand failure: effect of biocide on the geomechanical properties of outcrop carbonate rock under static condition

The effects of chemical interaction of a biocide with formation rocks on the rock geomechanical properties are examined. A combination of analytical tests (scanning electron microscopy/energy-dispersive X-ray analysis, X-ray powder diffraction and particle size distribution) and uniaxial compression test was used in this study. The particle size distribution in the effluent showed an increase in D50 with poor sorting for the chemically treated outcrop carbonate core samples. The XRPD shows evidence of altered minerals in the chemically treated samples. It was observed that the interaction led to precipitation of new materials that clogged the pore space of the samples leading to up to 150% increase in compressive strength of the carbonate following treatment with the biocide. The results give more insight into the limitations of existing sand production prediction models with respect to the effect of oilfield chemicals on the strength of the reservoir rocks.

Создание концептуальной геологической модели, основанной на литолого-петрографических исследованиях, на примере пермокарбоновой залежи Усинского месторождения

The work intends to develop a conceptual model of the Permo-Carboniferous deposit of the Usinskoye field. In the furtherance of this goal, the authors have addressed the tasks of designing a specialised table format to describe thin sections of carbonate core samples and create a database based on the developed format for the subsequent analysis. The paper deals with studying the Permo-Carboniferous deposit of the Usinskoye field, located in the Komi Republic. A unique database of 1,710 described thin sections from 12 wells was created based on the developed format. The classification of carbonate rocks by R.J. Dunham supplemented by Embry and Kloven (based on the dominating fabric in limestone, type of cementing agent and their relationships in the rock) was used as a basis. According to rock material compositions and textural properties, the following nine rock lithotypes were identified: Mudstone, Wackestone, Packstone, Grainstone, Boundstone, Floatstone, Rudstone, Crystalline Carbonate (Dolomite), and Clayey Carbonate Silicite. By following the rock lithology type identification results and the seismic data, three main facies zones were determined in the section of the mid- Carboniferous and Lower Permian sediments: carbonate shoal (inner ramp zone), organogenic buildup (middle ramp zone) and shallow marine shelf plain (mid-ramp zone, partially outer ramp zone). A moderately deep marine shelf plain facies (outer ramp zone) was provisionally defined. Following the study results, two profiles of the Mid-Carboniferous and Lower Permian sediments of the Usinskoye field were plotted along two well lines. The presented sections support the conceptual model developed. Based on the core sample findings, the zone of organogenic build-ups stands out in the eastern part of the field, dating back predominantly to the Late Carboniferous and Early Permian periods. An inner ramp with the carbonate shoal facies supposedly exists in the field north-west. The conducted work has resulted in the development of a conceptual model of the Permo-Carboniferous deposit of the Usinskoye field, which can be used for further development of more reliable 3D facies models, commercial-scale estimations of reserves and field development designs.