Showing papers in "Journal of Petroleum Science and Engineering in 2017"

Abstract: Pore throat structure is a significant factor controlling the properties of reservoir. Evaluation of the pore throat structure is also important for the exploration and development of tight oil. In order to determine the micro-structure of pore throat, the high pressure mercury intrusion experiments (HPMI) were performed on the tight oil sandstone samples of Chang 7 member in Xin’anbian Block, Ordos Basin, China. HPMI were conducted to obtain the microscopic parameters of the pore throat structure, such as pore-size distribution, pore connectivity, and pore space topology. The pore throat network of the tight oil sandstone mainly consists of micropores, transitional pores, and mesopores. The mesopores of the Chang 7 tight reservoirs is the dominant factor affecting the pore throat structure. Mesopores development positively influences the maximum pore radius, median radius, sorting coefficient, skewness, maximum mercury saturation, and efficiency of mercury withdrawal, indicating that with the development of mesopores, the properties of percolation, storage, pore throat connectivity, and oil recovery would become better. Fractal theory was used to quantitatively characterize the complex and irregular pore throat structure of the reservoir. The fractal dimensions of mesopores, transitional pores and micropores (D 1 , D 2 , and D 3 ) were calculated through the slopes of the trendlines of each segment obtained from the curve of log (1-S H ) versus log (Pc). The total fractal dimension (D) was obtained, based on the weighted average of porosity of mesopores, transitional pores, and micropores. D ranging of 2.2520–2.7875 indicates that the pore throat structure of Chang 7 tight reservoir is complex and has a strong heterogeneity. D 1 , D 2 , and D 3 have obvious negative correlations with porosity of the corresponding pores and only D 1 has an obviously negative correlation with permeability. D has a downward trend, with the increasing porosity, but no correlation with permeability. D 1 has better correlations with the parameters of pore throat structure than D 2 and D 3 . The heterogeneity and surface roughness of mesopores mainly influence the property of pore throat structure, especially percolation and storage space of the reservoir. The development of mesopores is a main factor affecting the pore throat structure of the Chang 7 tight oil sandstone. The fractal characteristic of mesopores reflects how well the pore throat structure for the exploration and development of Chang 7 tight oil.

Abstract: Although hydraulic fracturing is a mature technology that has been used commercially since the late 1940s, the development of unconventional hydrocarbon fields with the combination of directional drilling and multistage hydraulic fracturing in the last two decades gave rise to a substantial progress in both operations and associated modeling Numerical simulators, based on those models, are key to the design and evaluation of hydraulic fracturing treatments Though hydraulic fracturing is a truly coupled phenomenon, the solid mechanics part of the problem has typically received more attention than the fluid mechanics part Yet, that fluid mechanics field is a very rich multidisciplinary domain, presenting a number of challenges posed by the contemporary technology advancement, most of which being still unresolved This paper aims to review the state of the art in multiphase fluid mechanics modeling of hydraulic fracturing, highlighting gaps in the body of knowledge and clarifying the questions that are still open This review sheds light on critical phenomena peculiar to hydraulic fracturing treatments, which are grouped into three categories (according to subsequent stages of the stimulation treatment): (i) proppant transport down the wellbore, (ii) proppant placement into the fracture, (iii) flowback from fractures into a well after the end of stimulation treatment (which is particularly important for preserving the integrity and conductivity of the fracture network) To support the modeling in these areas, constitutive relationships calibrated by experiments are of paramount importance The list of phenomena, still not fully covered by modeling, includes: slugs dispersion in the well during alternate-slug fracturing, impact of fibers and visco-elasto-plasticity of the fracturing fluid on proppant placement in fractures, effects of complex rock fabric and real fracture morphology (roughness, steps, ledges, turns, and junctions), transition from dense suspension to close packing, dynamic bridging and mobilization, particle sedimentation to form a packed bed and re-suspension, dune transport in fracture network, overflush, and flowback into the near-horizontal well from fractures, to name a few All these effects need to be properly accounted for in the hydraulic fracturing simulators in order for the contemporary technology of multistage fracturing to be designed, executed, evaluated, and optimized properly and safely to yield optimum production, especially in unconventional reservoirs

Abstract: The current routine practice to produce oil in shale and tight reservoirs is the primary depletion by combining horizontal well drilling and fracturing. The technology can only produce less than 10% of shale oil, and the oil recovery in tight reservoirs is also low. There is a big prize to be claimed in terms of enhanced oil recovery (EOR) in such reservoirs. To enhance the oil recovery in these reservoirs, a few ideas have been proposed and studied in laboratory (experimental and theoretical or modeling studies). Such ideas include gas injection, water injection, and surfactant injection, especially in huff-n-puff mode. This paper briefly summarizes the research results or conclusions from the laboratory studies first, then focuses on the practices and applications in fields. Field tests of different methods are reviewed and analyzed. It is shown that water injection has been applied in large scale field projects in tight formations and proved successful in China. CO2 injection has been tested many times in small scales in China. Several gas injection and water injection have been tested in US and Canadian shale reservoirs. Detailed results of those projects have not been reported, with test benefits mixed. Although surfactants are added in fracturing fluids to improve oil recovery performance, the mechanisms are not well understood.

Abstract: Brittleness is an important feature of rock and is related to many mechanical behavior of rock. An accurate evaluation of rock brittleness lays an analytical foundation of drilling and hydraulic fracturing. At present, there are several evaluation methods of rock brittleness, but none of them has taken the evolution of internal damage into consideration during the loading process, and thus will not effectively indicate the influence of damage on brittleness during loading. We have conducted a series of uni-axial compressive tests on coal rock, shale and tight sand, and have obtained the stress-strain curves of different types of rock. Then we have established the damage constitutive model of micro damage for each type of rock based on power function distribution, Weibull distribution and Gaussian distribution. We have proposed an evaluation method of brittleness index based on energy method, established the evaluation model of brittleness based on three types of damage constitutive relations, and have finally analyzed the effects of the damage variable of peak strain of different rocks on brittleness. The results of this paper have proved that the damage constitutive model of micro damage can effectively describe the stress strain curves of different rocks before the peak strength. On the other hand, it indicates that the increase of damage variable of peak strain will undermine rock brittleness, and the relation between brittleness and damage variable of peak strain obeys different rules of the three types of damage constitutive models damage constitutive model based on Gaussian distribution benefits evaluation of brittleness of different types of rock, and based on power function distribution makes for the same types of rock. This paper has proposed a fresh perspective of studying brittleness, the results of which will improve the present evaluation methods and enrich our understanding of rock brittleness.

Abstract: Surfactant adsorption and foaming characteristics are influenced by surfactant concentration and presence of inorganic electrolytes. Hence, it should be possible to optimize the performance of the surfactants in subsurface applications by understanding the influence of these parameters on surfactants. This study investigates the adsorption of sodium dodecyl sulfate (SDS) on kaolinite as a function of surfactant concentration and added electrolyte (NaCl, CaCl2 and AlCl3) concentration. Influence of temperature on the electrolyte and surfactant interactions was also examined. Adsorption isotherms were obtained using surfactant concentrations higher and lower than the critical micelle concentration (CMC). Surfactants adsorption on kaolinite was determined using a surface tension technique and two phase titration methods. Adsorption data were analyzed by fitting with Langmuir and Freundlich adsorption isotherms. The foam was generated by dispersing CO2 gas into the surfactant solution through a porous stone. Foam half-life and the rate of foam collapse as function of time was monitored. The adsorption of SDS by kaolinite increases with the increasing concentration of NaCl and CaCl2 and decreasing temperature. However, adsorption in presence of AlCl3 shows different behavior. The adsorption remains constant irrespective of the increasing AlCl3 concentration. Results show that the adsorption of SDS onto kaolinite in presence and absence of salts follows the Langmuir isotherm models. Salts containing trivalent ions and divalent ions (AlCl3 and CaCl2) were found to increase SDS adsorption on kaolinite and decrease bubbles stability compared to salts containing mono ions (NaCl). The order of increase in surfactant adsorption and bubble coalescence in presence of salts is as follows: AlCl3>CaCl2>NaCl. There was an optimum surfactant concentration corresponding to maximum foam stability beyond which there was either a reduction or no significant changes in foam stability. This concentration decreases in presence of salts, except for AlCl3 and high concentrations of NaCl (5 wt%) and CaCl2 (1 wt%). The presence of salt improved foam generation and bubble stability at SDS concentration below the CMC. Above CMC, the bubble coalescence inhibition and foam stability decreased in the presence of salt. Decrease in surfactant surface tension and CMC, the screening effect of electrostatic double layer (EDL) by salts and the ability of SDS to form a complex with divalent (Ca2+) and trivalent (Al3+) cations are critical factors affecting SDS adsorption and foaming behaviors in presence of AlCl3, CaCl2 and NaCl salts. The results of this study have wide applications in the design, implementation and optimization of chemical EOR in the field.

Abstract: This paper aims at making a thorough investigation on surfactant adsorption on rock under the influence of silica nanoparticles (SNP). The results showed that SNP can reduce surfactant adsorption effectively. With SNP concentration of 0.1, 0.2 and 0.3 wt%, static adsorption experiments showed that sodium dodecyl sulfate (SDS) adsorption can be significantly reduced to 2.57, 2.12, and 1.73 from 2.84 mg/g, and the dynamic adsorption of SDS decreased to 0.92, 0.77, and 0.66 from 1.16 mg/g, respectively. Our subsequent tests conformed a 4.68% growth of oil recovery by the injection of SNP - surfactant solution compared to the normal surfactant solution. The mechanism of the enhanced oil recovery is assumed to be the inhibition of surfactant adsorption and the profile control capability of silica nanoparticles. This study proves the SNP - surfactant flooding is a cost-effective way for enhanced oil recovery.

Abstract: Lost circulation is one of the most common and costly problems in drilling operations, but in many operational situations, wellbore strengthening is an effective and economic technique to prevent or mitigate lost circulation. While numerous experimental and modeling studies have been carried out in the last three decades, there remain differing views regarding fundamental mechanisms of lost circulation and wellbore strengthening. An extensive and critical review of achievements and limitations on these fundamental studies is needed to aid engineers and researchers in future developments in this area. This paper provides a state-of-the-art review of fundamental studies on lost circulation and wellbore strengthening. This review focuses mainly on experimental and theoretical studies, rather than field experiences, intended to illustrate limitations of current knowledge in this area and lead to new research endeavors.

Abstract: Pores in coal and their connectivity are important properties of coal, providing network or channels for gas storage and migration within coal, e.g. during the coalbed methane (CBM) recovery. To investigate the growth characteristics and genetic types of pores in coal in terms of macropore and mesopore, the pores of a high-rank coal were measured by various techniques such as the mercury intrusion method, nitrogen adsorption, focused ion beam scanning electron microscopy (FIB-SEM), and X-ray micro-CT (Computed Tomography). Two high-rank coals formed from regional metamorphism collected from the southern Qinshui basin were selected. The FIB-SEM and X-ray micro-CT provides detailed experimental information for development of a three dimensional (3D) pore network model, which was further used to characterize the pore connectivity. Volume percent of pores of these high-rank coals are dominated by mesopores of approximately 10–50 nm in width, and then followed by micropores, along with the smallest volume percent of macropores. The connectivity within this high-rank coal was mesopore-dominated pore network. Electron microscopy observations further revealed there are coalification-related pores and mineral-related pores in the high-rank coal. The coalification-related pores can be classified as secondary gas pores in organic matter and shrinkage-induced pores around quartz and clay minerals; and the mineral-related pores are developed within minerals, and can be classified as dissolution-created pores and intercrystalline pores. The secondary gas pores are macropores and have poor connectivity. The mineral-related pores can be both macropores and mesopores, and have little influence on pore connectivity due to small content of carbonate minerals in these samples. Under electron microscopy, the shrinkage-induced pores are mainly mesopores. The regional metamorphism, with a high abnormal old thermal field in the research area, is the precondition of the formation of the shrinkage-induced pores. The quartz and clay minerals in the coal provide different formation conditions and hence form different shapes of the shrinkage-induced pores. The coal samples include a large number of shrinkage-induced pores that act as the interconnected pores in the coal and exhibit good connectivity. The quartz and clay minerals play a significant role in developing the interconnected pores in the high-rank coal formed from regional metamorphism.

Abstract: The purpose of hydraulic fracturing is to improve the gas permeability of a coal seam by the high-pressure injection of fracturing fluid into cracks. Some promising results of hydraulic fracturing in a coal seam using isotropic and intact model have been published in our previous study ( Wang et al., 2014 ), based on which further research is necessary for the reason that natural coal is anisotropic, inhomogeneous, inelastic, and characterized by multiple discontinuities, which can be one of the most important factors governing the deformability, strength and permeability. It is difficult to accurately identify and predict the manner in which hydraulic fractures initiate and propagate because of the pre-existing natural fractures. In this paper, five typical coal models—intact coal, layered jointed coal, vertical jointed coal, orthogonal jointed coal, and synthetic jointed coal—are established to simulate hydraulic fracturing in coal seam based on two-dimensional particle flow code (PFC2D). The effect of natural existing fractures on fluid-driven hydraulic fracture is investigated by analyzing the variation of fracture radius, cumulative crack number, and growth rate of porosity versus injection time. It is shown that the existence of natural fractures, which has a significant induced effect on the initiation and propagation of hydraulic fracture, contributes greatly to the increase of crack number and growth rate of porosity. The fracture network is greatly influenced by the interaction between hydraulic fracture and natural fractures. Natural fractures with different structural properties may result in different propagation types of hydraulic fracture, which can be categorized as capturing type, crossing type, and compound type.

Abstract: The primary objective of this study is to investigate the effects of SiO2 nanoparticles on improving the rheological behavior and inhibition of the thermal degradation of hydrolyzed polyacrylamide (HPAM) solutions. The SiO2-HPAM interactions were evaluated through i) Polymer adsorption onto nanoparticles, ii) rheological studies, and iii) evaluation of thermal stability in presence or absence of oxygen. SiO2 nanoparticles and HPAM were characterized through thermogravimetric analyses (TGA), Fourier transform infrared spectroscopy (FTIR) and dynamic light scattering (DLS). The nanofluids were prepared by adding a fixed concentration of nanoparticles to an HPAM-containing aqueous solution. The adsorption isotherms of HPAM over the SiO2 nanoparticles were obtained in batch-mode experiments. Results of adsorption experiments showed that isotherms followed a Type III behavior. The adsorption isotherms were modeled using Langmuir, Freundlich and Solid-Liquid Equilibrium (SLE) model. The best fitting was obtained using the SLE model based on the root-mean-square error (RMSE%), which was lower than 9.5. Also, polymer desorption from the surface of nanoparticles was found to be negligible, and thus the sorption process can be considered irreversible under conditions evaluated. Rheological tests in the range of 25 to 70 °C showed a pervasive non-Newtonian behavior for all the SiO2-HPAM combinations tested. The Herschel-Bulkley and Carreau models were used to describe the rheological behavior of the prepared nanofluids with RMSE% values better than 0.3. The thermal stability of polymeric solutions in the absence and presence of nanoparticles was evaluated under inert and oxidative atmospheres at 70 °C for 14 days. It was observed that a lower degree of degradation resulted for polymeric solutions in the presence of nanoparticles and the absence of oxygen, indicating that SiO2 nanoparticles can inhibit HPAM degradation through adsorption, and subsequently improve its thermal stability.

Abstract: In Colombia, the estimated reserves of crude oil are approximately 2.0 thousand million barrels, decreasing by approximately 13% in the last year according to the National Hydrocarbons Agency (ANH). In addition, the exponential growth of the world population as well as increasing motorization and industrialization has led to higher demand for fossil fuels to supply energy requirements. Colombia is aware of this issue and has become a key player of incorporating advances in nanotechnology to address this challenge by increasing the productivity/reserves of crude oil. Nanotechnology progress in Colombia has been supported by academy – state – industry synergy, which has aimed to mitigate formation damage and enhance oil recovery to facilitate increases in oil productivity and reserves based on the development of nanoparticles/nanofluids. In this sense, Colombia has been a worldwide pioneer in the application of nanotechnology under field-scale conditions, which has led to significant increases in oil rate production. This document presents a review of the recent applications of nanotechnology in Colombia, from laboratory approaches to field conditions. This review addresses the development of nanoparticles/nanofluids for application to the inhibition/remediation of formation damage (asphaltenes, alteration of reservoir wettability from liquid-wet to gas-wet, and inorganic scales, among other applications), productivity improvement (hydraulic fracturing, drilling fluids, and improvement mobility of heavy and extra-heavy oils), enhanced oil recovery (EOR) and heavy oil transport. Finally, three cases of field trials employing nanofluids are discussed for inhibiting the formation damage of asphaltene in tight-condensate reservoirs and light oil crude, fines migration in tight-condensate reservoirs and mobility improvement of heavy and extra-heavy oils. It is expected that this document will aid in the alignment of the academic and industrial sectors to pursue and incentivize the opening of a wider range of applications under field conditions through the extrapolation of laboratory studies.

Abstract: Traditional heavy oil recovery method of saturated steam injection faces many challenges. Present study on wellbore modeling of superheated steam (SHS) flow is still at the early stage. In order to fill this gap, a series of works were conducted to study the non-isothermal flow characteristics of SHS in ground pipelines and vertical wellbores. Firstly, a flow model inside the wellbores was proposed based on the energy and momentum balance equations. Then, coupled with heat transfer model in formation or atmosphere, a comprehensive model was developed. Then, type curves of SHS flow in ground pipelines and vertical wellbores were obtained by solving the model with finite difference method. Finally, model validation and sensitivity analysis were conducted. The results show that: (a). there exist a good agreement between predicted results and field data. (b). superheat degree increases with increasing of injection rate. (c). superheat degree increases with increasing of injection temperature. (d). superheat degree decreases with increasing of injection pressure. Consequently, practicing engineers are suggested to increase the injection rate and temperature and to decrease the injection pressure.

Abstract: This article provides an overview of the current state of digital rock technology, with emphasis on industrial applications. We show how imaging and image analysis can be applied for rock typing and modeling of end-point saturations. Different methods to obtain a digital model of the pore space from pore scale images are presented, and the strengths and weaknesses of the different methods are discussed. We also show how imaging bridges the different subjects of geology, petrophysics and reservoir simulations, by being a common denominator for results in all these subjects. Network modeling is compared to direct simulations on grid models, and their respective strengths are discussed. Finally we present an example of digital rock technology applied to a sandstone oil reservoir. Results from digital rock modeling are compared to results from traditional laboratory experiments. We highlight the mutual benefits from conducting both traditional experiments and digital rock modeling.

Abstract: Foams stabilized by a mixture of nanoparticles and surfactants are presently being considered for improving the poor macroscopic sweep efficiency of gas enhanced oil recovery (EOR) methods. The stability of these foams is influenced by the adsorption and foaming properties of the nanoparticles-surfactant mixtures. This study investigates the influence of silicon dioxide (SiO2) and aluminum oxide (Al2O3) nanoparticles on sodium dodecyl sulfate (SDS) adsorption on kaolinite and SDS-foam stability at static and dynamic conditions. The adsorption experiments were conducted by surface tension and two-phase titration methods. Adsorption data were analyzed by fitting with Langmuir, Freundlich and Temkin adsorption isotherms. Influence of salt on foam performance was investigated from bulk stability experiment conducted using KRUSS dynamic foam analyzer. The pore scale visualization experiments were carried out with etched glass micromodels to study foam stability in porous media. Results show that SDS adsorption on kaolinite reduced by 38% in presence of Al2O3 nanoparticles and 75% in presence of SiO2 nanoparticles. The Langmuir isotherm model suits the equilibrium adsorption of sole SDS and Al2O3-SDS onto kaolinite while the Freundlich isotherm model suits the adsorption of SiO2-SDS onto kaolinite. Foam stability decreased in presence of salts until the transition salt concentration. Beyond the transition salt concentration, foam stability generally increased with the increasing salt concentrations. The presence of Al2O3 and SiO2 nanoparticles increased the foam half-life and decreased the transition salt concentrations. The dominant mechanisms of foams flow process were identified as lamellae division and bubble-to-multiple bubble lamellae division. The dominant mechanisms of residual oil mobilization and displacement by foam were found to be direct displacement and emulsification of oil. The identified pore scale mechanisms were independent of the pore geometry of the etched glass micromodels. There was lamellae detaching and collapsing during the flow process of SDS-foam in presence of oil which resulted in poor microscopic displacement efficiency. The SiO2-SDS and Al2O3-SDS foams propagated successfully in porous media in presence of oil with almost 100% microscopic displacement efficiency due to the enhanced films interfacial elasticity. The findings of this research provide an insight into surfactant adsorption minimization and pore-scale mechanisms of foam stability improvement by nanoparticles.

Abstract: In this research, combustion characterization and kinetics of four different origin crude oil samples were determined using thermogravimetry - differential thermal analysis (TGA-DTA) and thermogravimetry - Fourier transform infrared (TGA-FTIR) and thermogravimetry – mass spectrophotometry (TGA-MS) techniques. In the TGA-DTA analysis of crude oil samples, low temperature oxidation (LTO) and high temperature oxidation (HTO) reaction regions were observed in different temperature intervals. On the other hand, reaction regions, mass loss, and peak-burnout temperatures of the crude oil samples were also determined using TGA-DTA curves. In TGA-FTIR analysis, spectrums of crude oil samples were examined at different time intervals and composition of several hydrocarbon compounds was determined quantitatively. This research was also focused on the main volatile products (H 2 , H 2 O, CO, CO , C 6 H 6 , SO 2 etc…) of different origin crude oil samples on the basis of both their relative intensities and on their relevancy by using TGA-MS technique. Two different Arrhenius types of kinetic models were used in order to determine the kinetic triplets (activation energy, Arrhenius constant and reaction order) of crude oil samples studied. It was observed that in HTO region, higher activation energy values were observed depending on the °API gravities of the crude oils.

Abstract: Modeling the rate of penetration of the drill bit is essential for optimizing drilling operations. This paper evaluates two different approaches to ROP prediction: physics-based and data-driven modeling approach. Three physics-based models or traditional models have been compared to data-driven models. Data-driven models are built using machine learning algorithms, using surface measured input features - weight-on-bit, RPM, and flow rate – to predict ROP. Both models are used to predict ROP; models are compared with each other based on accuracy and goodness of fit (R 2 ). Based on the results from these simulations, it was concluded that data-driven models are more accurate and provide a better fit than traditional models. Data-driven models performed better with a mean error of 12% and improve the R 2 of ROP prediction from 0.12 to 0.84. The authors have formulated a method to calculate the uncertainty (confidence interval) of ROP predictions, which can be useful in engineering based drilling decisions.

Abstract: It has been a long dispute in the forming mechanism of coal and oil shale in coal-and oil shale-bearing succession because the depositional environments between coal and oil shale are distinctly different. In this study, the Huangxian Basin was chosen as a typical example to study the mechanism of sedimentation of the coal and oil shale. Eleven facies and four facies associations have been recognized from petrologic, sedimentological and paleogeographic characteristics. The four facies were formed in alluvial fan, fan delta, braided stream, braided stream delta, shore-shallow lake-lacustrine bog, shallow lacustrine and deep lacustrine environments. Two types of sequence boundaries (regional unconformities and regional exposed non-sedimentary surfaces) and double systems tract boundaries (maximum flooding and first flooding surfaces) are identified. Sequence stratigraphic frameworks with two sequences (each including three systems tracts) are established to analyze the depositional evolution. We find that the Huangxian Basin is a paralic continental faulted lacustrine basin with four different types of coal bed and oil shale combinations: oil shale/coal bed/oil shale (OS-CB-OS), coal bed/oil shale (CB-OS), coal bed/mudstone/oil shale (CB-M-OS) and oil shale/coal bed (OS-CB). The formation mechanisms of the coal bed and oil shale associations are interpreted to be: a) the basin first experienced transgression, giving rise to the CB-OS or CB-M-OS combinations where oil shale was overlain by coal beds, and b) continental, non-lacustrine deposition developed in the basin and was terminated by subsequent transgression, forming lacustrine deposits. Later, the basin was silted into a peat swamp that was subsequently interrupted by transgression or terrigenous clastic deposition, eventually forming OS-CB-OS or CB-OS combinations. Through analyzing depositional evolution of the basin we conclude that lowstand system tracts tend to develop CB-OS associations; expanding system tracts tend to develop CB-OS, CB-M-OS and OS-CB-OS combinations; and highstand system tracts tend to develop OS-CB combinations.

Abstract: In this paper, a novel mathematical model is proposed to analyze the flow behaviors of superheated multi-component thermal fluid (SMTF) in the perforated horizontal wellbores (PHWs). Firstly, a flow model comprised of mass, energy and momentum equations is established. Secondly, the proposed model is solved by finite difference method and iteration technique. Thirdly, the model is compared against previously published models and field data. Lastly, sensitivity analysis is conducted based upon the validated model. The results show that: (1). The predicted results from the novel model are in good agreement with field data. (2). The values of superheat degree along the PHWs decreases with increasing content of non-condensing gases. (3). Both the SMTF temperature and superheat degree increase with increasing of injection rate. (4). The SMTF temperature and superheat degree increase with increasing of injection temperature. This paper unravels some intrinsic flow characteristics of SMTF in PHWs, which has a significant impact on the optimization of SMTF injection parameters and analysis of heat transfer laws in PHWs.

Abstract: Injection of brines with carefully designed ionic compositions into oil-wet carbonate rocks at high temperatures has shown to alter their wettability towards a water-wet state and improve oil recovery. Various mechanisms have been postulated for this wettability alteration such as mineral dissolution and interaction of potential determining ions, such as Ca2+, Mg2+ and SO42−, with the carbonate surface. In this study, experimental and modeling work was performed to gain further insights into the geochemical interactions between carbonate rocks and modified brines. Single-phase static (equilibrium) and transport experiments were performed with various brines in limestone cores at 120 °C. The ionic compositions of the effluent samples were monitored using ion chromatography. A mechanistic model for the wettability alteration process was developed in UTCHEM-IPHREEQC based on key geochemical interactions. The calcite surface was assumed to consist of positive and negative sites and their interactions with potential determining ions were considered assuming local equilibrium. The model assumed the degree of oil-wetness to depend on the amount of organic acid attached on the surface, which in-turn was dependent on the geochemistry of the system. Results of static experiments performed with crushed limestones and brines showed an increase in calcium concentration and a decrease in magnesium concentration in the supernatant brines. The effluent concentrations from single-phase brine corefloods in limestone cores showed an increase in calcium concentration, a decrease in magnesium concentration and a delay in sulfate concentration. Three key geochemical interactions were identified based on these results: mineral dissolution, surface dolomitization and sulfate adsorption. A good qualitative agreement was observed between single-phase experiments and simulations, suggesting that the model was able to accurately capture the geochemistry. The simulation results showed good agreement with zeta potential and oil recovery results reported in the literature.

Abstract: Nanoparticles have gained considerable interest in recent times for oil recovery purposes owing to significant capabilities in wettability alteration of reservoir rocks. Wettability is a key factor controlling displacement efficiency and ultimate recovery of oil. The present study investigates the influence of zirconium (IV) oxide (ZrO2) and nickel (II) oxide (NiO) nanoparticles on the wetting preference of fractured (oil-wet) limestone formations. Wettability was assessed through SEM, AFM and contact angle. The potentials of the nanoparticles to alter oil-wet calcite substrates water wet, was experimentally tested at low nanoparticle concentrations (0.004–0.05 wt%). Quite similar behaviour was observed for both nanoparticles at the same particle concentration; while ZrO2 demonstrated a better efficiency by altering strongly oil-wet (water contact angle θ=152°) calcite substrates into a strongly water-wet (θ=44°) state, NiO changed wettability to an intermediate-wet condition (θ=86°) at 0.05 wt% nanoparticle concentration. We conclude that ZrO2 is very efficient in terms of inducing strong water-wettability; and ZrO2 based nanofluids have a high potential as EOR agents.

Abstract: Interfacial tension between hydrocarbon liquids and salt water is a very important property for many industrial applications, especially in petroleum industry. Interfacial tension, in addition to other factors, has direct impact on displacement process in porous media so thus on oil recovery. Very recently, the salinity of injection brine has been regarded as a key factor in oil recovery using low salinity water flooding process. Decrease in the interfacial tension between crude oil and injection brine at low salinity condition might be a reason behind recovery improvement as suspected by some researchers; but there are also other effects associated with low salinity water flooding like wettability alteration, fine migration, mineral dissolution etc. It is suspected that the interaction of polar components at oil-water interface lead to the reduction of interfacial tension. However, the actual mechanism is not known and still under research. The main objective of this work is to determine the effect of salt concentration and type of ions present in an aqueous phase on the interfacial tension between pure hydrocarbon liquids and water. Different hydrocarbon liquids, such as aliphatic and aromatics, have been tested to understand the interaction of monovalent and divalent salts on the interfacial tension. The study reports the interfacial tension of five pure hydrocarbon liquids against solutions of three different salts (NaCl, MgCl2 and CaCl2) over a wide range of salinities. The interfacial tension measurements were done using Wilhelmy plate method by a dynamic contact angle tensiometer. All the experiments were conducted at room temperature and atmospheric pressure. The results lead us to the view that there is low a salinity concentration where the hydrocarbon/brine interfacial tension shows a minimum value. The type of salt also has a significant effect on interfacial tension of aliphatic and aromatic hydrocarbons. Monovalent salt found to be effective in reducing interfacial tension of aliphatic hydrocarbons while divalent salts were found to be effective for aromatic hydrocarbons. The possible mechanism for the reduction in IFT at low salt concentration has also been explained using Gibb's adsorption isotherm. In addition, the trend in IFT has been explained in the light of well-known Jones-Ray effect.

Abstract: The permeability of a coal seam is an important index of gas drainage. To improve the gas drainage effect of a coal seam with high gas content and low permeability, hydraulic-controlled blasting of a deep hole was carried out to provide pressure relief and to increase the permeability of a coal seam. The mechanism for pressure relief and permeability improvement caused by the hydraulic-controlled blasting was then analyzed. It was found that the outcomes were the result of joint action by the blasting force and the hydraulic pressure. The mechanism availably combines and exerts the advantages of both the blast force and hydraulic pressure. Based on the geological conditions, the 205 coal mining face of the 2nd coal seam in Yian coal mine was selected for this research. A numerical model of hydraulic-controlled blasting was established, and the spacing distance of the blasting holes and the effective radius of the blasting were numerically simulated using ANSYS/LS-DYNA software. The results of the simulation showed that the spacing distance between the control holes should be approximately 2.5 m, the effective blasting radius should be approximately 4.5 m. Therefore, the spacing distance between blasting holes should be less than 9 m. Hydraulic-controlled blasting technology of a deep hole was performed in the 205 coal mining face. The gas drainage flow, change in gas pressure, permeability coefficient and gas drainage time were measured at the blasting borehole and control boreholes. The results of engineering practice show that the technology can connect boreholes with each other through fractures, effectively discharge coal seam gas, effectively release gas pressure, greatly improve the permeability of the coal seam and reduce gas drainage time. The technology can effectively achieve the goals of relieving gas pressure, increasing the permeability of the coal seam, improving the gas drainage effect and providing economic benefits. The results provide a new technical method for relieving gas pressure and increasing the permeability of a coal seam with high gas content and low permeability.

Abstract: Cleaning the wellbore from drilled material is important to continue drilling efficiently and to prevent high torque and drag, as well as reducing down time due to reaming operations. Drilling fluids used for this purpose are complex fluid systems, generally with water or oil as a base substance. Water-based and oil-based drilling fluids are performing differently in terms of hole cleaning, even when their density and viscosity are fairly similar. Comparative studies performed by several research groups have resulted in diverse outcomes, showing superior behavior of either water- or oil-based drilling fluids, or no significant differences between the fluids at all. In the present study, a water-based and an oil-based drilling fluid have been investigated regarding their viscoelastic properties, using the Anton Paar rheometers MCR 102 and MCR 302. Amplitude sweep tests, 3-intervall-thixotropy tests, temperature sweep tests, and low-shear rate flow curves with controlled shear stress and shear rate were performed and analyzed. Cuttings transport experiments in a flow loop with a 10 m long test section and a free-whirling inner-rotating drill string were conducted with the same fluids to study the hole-cleaning efficiency of different drilling fluids. The results from both experimental parts are presented. The rheometer results are used to interpret the cuttings transport behavior in the flow-loop experiments. The water-based drilling fluid was a KCl brine based fluid, and the oil-based fluid a water-in-oil emulsion. Both fluids are actual field fluids, used during drilling operations on the Norwegian Continental Shelf and have similar viscosities and densities. The oil-based drilling fluid showed better hole-cleaning abilities during the flow-loop experiments, leaving a lower sand bed in the test section. This fluid displayed viscoelastic properties, such as a yield stress and a linear viscoelastic range. The water-based drilling fluid showed no yield stress and a 50–100% higher elasticity than the oil-based drilling fluid.

Abstract: Low-field Nuclear Magnetic Resonance (NMR) has proved to be a valuable tool for the petrophysical characterization of conventional reservoirs, but its effective application to unconventional reservoirs is still under research. Pore structure characterization of shales is particularly challenging due to the complexity of the pore network and the small size of pores. Using low-field NMR, we performed transverse relaxation (T2) experiments on samples from the Perth Basin, Western Australia. The samples were initially saturated with KCl brine to obtain the total NMR porosity and T2 distribution, then centrifuged and finally oven-dried at increasing temperatures. T2 spectra were also acquired after centrifuging and heating the samples. Our results indicate that most of the transverse relaxation occurs below 3 ms in saturated samples and that a conventional centrifuge cannot remove water from the smaller pores, making the commonly accepted clay bound water cut-off unsuitable for shales. Furthermore, the results from NMR experiments performed on the oven-dried shale samples suggest that the water content remains relatively constant after heating them above 65 °C. The calculated T2 cut-off for clay bound water is between 0.22 and 0.26 ms for the samples studied. The methodology presented in this paper can be replicated in other formations to find a suitable T2 value for clay bound water, which can be a good indication of potentially producible porosity and can also be used for permeability estimation.

Abstract: On a world-wide basis there is an estimated 5.6 trillion barrels of bitumen and heavy-oil resources which occur in over 70 different countries, with most of the heavy-oil in Venezuela and most of the bitumen in Canada. The most common plate-tectonic settings in which the heavy-oil and bitumen are found are in continental multi-cyclic marginal basins and in continental rift basins. Heavy oil and bitumen resources are largely a result of natural degradation of formerly conventional oil accumulations. The natural degradation for most is biologic in origin, with the result that the majority of heavy-oil and bitumen deposits is characteristically in younger rocks (Cretaceous and younger) and at shallow depths (usually

Abstract: The reduction in interfacial tension (IFT) of paraffin crude oil is of key importance, particularly for oilfield applications such as enhanced oil recovery (EOR). Nanoparticle laden suspension such as nanofluid is gaining widespread interest and their use to achieve moderate IFT reduction in paraffin crude oil. In this work, stable nanofluids of an oilfield polymer (polyacrylamide, PAM) with and without surfactant (sodium dodecyl sulfate, SDS) have been formulated and examined for IFT reduction of paraffin oils such as n-decane, n-hexane, n-pentane, and n-heptane. Nanofluids were also investigated for various studies such as dispersion stability, viscosity, rate of sedimentation (ROS), and DLS based measurements (size and zeta-potential). Other studies involving investigations on surface tension (SFT), IFT reduction, effect of SDS and varying SiO2 concentration on IFT reduction, and their efficacy for IFT reduction under high temperature environment have also been reported. The performance of nanofluids for IFT reduction has been compared with IFT results of conventional polymer (P) and surfactant-polymer (SP) methods, which are typically used for chemical-EOR practices. As compared to P and SP methods, IFT value of nanoparticle-polymer (NP) and nanoparticle-surfactant-polymer (NSP) fluids were found to be significantly lower suitable for enhanced oil recovery. In addition, NSP nanofluids provided superior reduction in IFT values mainly due to the presence of SDS. Thus, we conclude that SiO2 nanofluid, as compared to P/SP EOR methods, can be a potential alternative to reduce the IFT of paraffin crude oil.

Abstract: Shale formations often consist of multiple weak interfaces between layers, which is easily opened during hydraulic fracturing treatment and affect growth of fracture height. Fracture propagation in such formations usually induced complex fracture geometry with primary vertical fractures and horizontal fracture segments between layers. Although numerous numerical models have been developed to simulate fracture propagation in unconventional reservoirs, relatively few physical three-dimensional models exist to quantitatively simulate opening of fractures affected by weak interfaces. In this paper, we analyze width profile of fractures and interaction of vertical and horizontal fracture segments with predetermined fracture path under the assumption of neglecting the flow effect. A fully three-dimensional displacement discontinuity method (3D DDM) is introduced to model multiple fractures in a stage in three dimensions. The fracture geometry is prescribed, which combined with vertical and horizontal fractures. In each case, the horizontal fracture is regarded as opening of the bedding interface and vertical fracture would either be arrested or directly cross the interface. Interfacial sliding distance, defined as width jump of the vertical fracture at the interface, is regarded as a primary impact of fracture height containment. Analysis of fracture opening, shear displacements and interfacial sliding distance is given for both vertical and horizontal fracture segments. When multiple vertical fractures intersect with a horizontal interface, shear displacements are induced on the interface and vertical fractures have smaller width compared with the case without the horizontal interface, as a result of the interaction with the interface. We observed that both widths of fracture segments and interfacial sliding distance are positively correlated with the distance between the center of the vertical fracture and the horizontal interface, half-length of horizontal fracture segment, the net pressure within fracture segments. Conversely, Young's Modulus has a negative relationship with both width of fracture segments and interfacial sliding distance. This paper analyzes the effects of opening of weak interfaces and provides critical insights of fracture width distribution and its impacts on proppant transport.

Abstract: Nanotechnology is the design and application of engineered or naturally occurring nanoparticles with at least one dimension of the order of 1–100 nm to accomplish specific purposes. Nanoparticles possess three unique properties. First, their small size enables nanoparticles to be transported into formation pores not accessible to larger particles. Second, at nanoscale, material properties are size dependent. Therefore nanoparticles can be engineered to contain specific optical, magnetic, interfacial, electrical or chemical properties to perform specific functions. Third, they have a very large surface-to-area ratio. Combined together, these unique properties allow nanoparticles to be used for many purposes in the oilfield. The objective of this paper is to conduct a critical review of the recent literature to determine the status of research and development and field application of nanotechnology to the oilfield. Most of the proposed applications of nanotechnology in the oilfield can be classified into the following six areas: (1) sensing or imaging, (2) enhanced oil recovery (EOR), (3) gas mobility control, (4) drilling and completion, (5) produced fluid treatment, and (6) tight reservoir application. Our review shows that much of the current research is focused on the performance of nanoparticles in the reservoir. Some work is done of the propagation of nanoparticles and very little work is done on the delivery and recovery of nanoparticles. In addition, a lack of well-defined health, safety and environmental protocols for safe delivery and recovery of nanoparticles can be a showstopper and more focused research is needed in this area. Our work also shows that affordability of nanoparticles is another showstopper due to the large quantity needed for oilfield applications and the current lack of vendors. As a remedy, we propose focused research and development on the use of naturally-occurring and industrial waste nanoparticles for oilfield applications. Of the six application areas, we rank imaging, drilling through unstable zones, tight reservoir applications and EOR as ones having the biggest potential impact. Using nanoparticles to detect hydrocarbon saturation in a reservoir can significantly impact how we plan field development, such as well placement. Similarly, using nano-enhanced drilling fluid to stabilize and drill through unstable zones can increase rate of penetration, reduce drilling cost and minimize environmental impact. Furthermore, using specially-designed nanoparticles to image and prop up induced and naturally occurring fractures in tight reservoirs can lead to sweet spot identification and more prolific wells. With its ability to make reservoir rocks more water-wet, waterflooding by nanofluids also has the potential to augment or replace low-salinity waterflooding as an EOR method.

Abstract: Cuttings transport is a topic of great interest in the oil and gas drilling industry. Insufficient cuttings transport leads to several expensive problems. Knowledge and selection of the drilling fluids is one of the important factor for efficient hole cleaning. It has been observed, however, that the hole cleaning performance of drilling fluids can be different even if the fluid rheological properties are similar as measured in accordance with API specifications. The reasons for stated difference in the behavior of drilling fluids are not well understood. The main objective of present work is to evaluate hole cleaning efficiency of an oil-based drilling fluid (OBM) and a water-based drilling fluid (WBM) whose viscosity profiles are similar as per API specifications. Hole cleaning efficiency of an oil-based drilling fluid and a water-based drilling fluid whose viscosity profiles are similar was investigated. The fluids tested were industrial fluids used in the field and were sent to us after reconditioning. Experimental studies were performed on an advanced purpose-built flow-loop by varying flow velocities and drill string rotation rates. The flow loop had a 10 m long annulus section with 4″ inner diameter wellbore and 2″ outer diameter fully eccentric drill string. Pressure drop and sand holdup measurements were reported. Rheological investigations of the same fluids were used to understand the difference in the behavior of the drilling fluids tested. Higher pressure drop was observed for WBM compared to OBM, and for both fluids, the pressure drop increased with drill string rotation speed. In case of no drill string rotation, better hole cleaning performance was observed with the oil-based fluid compared to the water-based fluid. With the presence of drill string rotation, hole cleaning performance of both the fluids was nearly the same.

Abstract: The problems associated with asphaltene deposition generate significant production loss and involve expensive corrective measures. The deposition of asphaltenes greatly reduces the productivity of the affected wells, and in some cases stops the well from flowing after a complete plugging of production column, it may also obstruct surface production facilities. This article reviews the different factors influencing the deposition of asphaltenes. The main problems caused by asphaltene deposition are presented in this work. Our focus will be on the current methods to fight these problems through the removal and the prevention of asphaltene deposition. Among the objectives of this review study is to provide an overview of current asphaltene inhibitors and dispersants that have been used in the literature. Finally, this paper sheds light on the strategy to control and minimize asphaltene deposits by inhibitors or dispersants to avoid any harmful consequence that will be happened later because of asphaltene deposits.