It was observed that higher oil recovery could be obtained when low-salinity (LS) water flooded a core of high-salinity initial water about 15 years ago. Such low-salinity waterflooding benefit or effect has drawn the oil industry attention since then. In the recent years, many researchers conducted laboratory corefloods, and several companies carried field tests. The objectives of these efforts were (1) to conform the benefits and (2) find the mechanisms of such benefit. Although most of the results confirmed the positive effect, some results showed no benefit. Many mechanisms have been proposed, but there is no consensus of the dominant mechanism(s). The oil industry is continuing the effort to discover the effect. This paper is to provide a critical review of the results and to summarize the achievements of the industry׳s effort. This paper aims to provide the status of the art. The information provided in this paper hopefully will help to speed up our further efforts to explore this effect. The following contents are reviewed: (1) history of low-salinity waterflooding; (2) laboratory observations; (3) field observations; (4) working conditions of low-salinity effect; (5) mechanisms of low-salinity waterflooding; and (6) simulation of low-salinity waterflooding. In this paper, the mechanisms proposed in the literature and their validity are discussed.
Shale gas has become a significant resource play in the USA over the past few years and companies are now evaluating the shale gas potential of many sedimentary basins, including several onshore basins within Australia. The renewed focus on rock sequences that have hitherto largely been ignored has necessitated the development of workflows and methods for characterising shales. Along with the deployment of new methods comes the need for interpretation frameworks in order to understand properties such as rock source quality, mechanical properties and production performance from a diverse range of measurements. Laboratory characterisation of rock properties is an important part of any resource evaluation and for shale gas, specific properties of importance include silt content, organic matter abundance and type, static and dynamic mechanical properties (brittleness), micro/macro-fabrics, porosity, permeability, petrophysical properties and anisotropy. Here we introduce a workflow for systematic shale characterisation in the laboratory with a number of examples to illustrate and discuss the application to reservoir evaluation in shale gas plays. A suite of shales from a number of sedimentary basins around the world was collected and characterised with a full suite of non-destructive petrophysical methods before destructive geomechanical testing was performed. For each sample, a representative portion was analysed for quantitative mineralogy using XRD and XRF, and clay chemical reactivity via cation exchange capacity (CEC) and grain size by centrifugation. For many samples, surface area and Mercury Injection Capillary Pressure (MICP) for porosity and pore throat distribution were also performed and used to predict permeability from models available in the literature. Several imaging techniques including Scanning Electron Microscopy (SEM) and X-ray Computed (micro-)Tomography (X-ray CT) at low and high resolution were performed. Shale strength has previously been shown to be related to CEC, which is inversely proportional to silt content. Anisotropy of shale properties is both intrinsic and stress-induced. Dielectric properties are related to water content at high frequency and dispersion in the dielectric constant is directly related to CEC of clays in particular and hence rock strength. Stress-induced anisotropy of elastic properties was found to be dependent on the orientation of microfabrics with respect to the maximum principal stress direction. Low and high field nuclear magnetic resonance can be used to distinguish clay-bound and free water as well as adsorption of organic components and to screen for wettability. High and low field NMR techniques are combined to show that illitic shales tend to be strongly water wet while the presence of kaolinitic clays imparts a tendency for shales to become oil wet with likely consequences for oil/gas recovery strategy, production flow efficiency and drilling design. ► We introduce an improved workflow for systematic gas shale characterization. ► A suite of shales from a number of sedimentary basins around the world. ► Petrophysics using XRD, XRF, CEC, SSA often correlate with geomechanical properties. ► Permeability can be determined using Mercury Injection Capillary Pressure (MICP). ► SEM and X-ray CT imaging provide additional correlating parameters.
This article provides an overview of conventional and developing gas processing technologies for CO2 and N-2 removal from natural gas. We consider process technologies based on absorption, distillation, adsorption, membrane separation and hydrates. For each technology, we describe the fundamental separation mechanisms involved and the commonly applied process flow schemes designed to produce pipeline quality gas (typically 2% CO2, <3% N-2) and gas to feed a cryogenic gas plant (typically 50 ppmv CO2, 1% N-2). Amine absorption technologies for CO2 and H2S removal (acid gas treating) are well-established in the natural gas industry. The advantages and disadvantages of the conventional amineand physical-solvent-based processes for acid gas treating are discussed. The use of CO2 selective membrane technologies for bulk separation of CO2 is increasing in the natural gas industry. Novel low-temperature CO2 removal technologies such as ExxonMobil's Controlled Freeze Zone (TM) process and rapid cycle pressure swing adsorption processes are also emerging as alternatives to amine scrubbers in certain applications such as for processing high CO2 concentration gases and for developing remote gas fields. Cryogenic distillation remains the leading N-2 rejection technology for large scale (feed rates greater than 15 MMscfd) natural gas and liquefied natural gas plants. However, technologies based on CH4 selective absorption and adsorption, as well as N-2 selective pressure swing adsorption technologies, are commercially available for smaller scale gas processing facilities. The review discusses the scope for the development of better performing CO2 selective membranes, N-2 selective solvents and N-2 selective adsorbents to both improve separation power and the durability of the materials used in novel gas processing technologies. (C) 2012 Elsevier B.V. All rights reserved.
Recently nanoparticles have become an attractive agent for improved and enhanced oil recovery (IOR & EOR) at laboratory scale. Most researchers have observed promising results and increased ultimate oil recovery by injecting nanoparticle suspension (nanofluid) in laboratory experiments. The objective of this study is to reveal nanofluid possibility for EOR in low to high-permeability sandstone (ss) rocks and investigate suitable concentration. In this study, parameters involved in the structural disjoining pressure mechanism, such as lowering interfacial tensions (IFT) and altering wettability, were studied. Laboratory coreflood experiments were performed in water-wet Berea ss core plugs with permeability in range 9–400 mD using different concentrations of nanofluids. A crude oil from a field in the North Sea was employed and three nanofluid concentrations 0.01, 0.05 and 0.1 wt% were synthesized with synthetic brine. We observed that IFT decreased when hydrophilic nanoparticles were introduced to brine. The IFT decreases as nanofluid concentration increases and this indicates a potential for EOR. Increasing hydrophilic nanoparticles will also decrease contact angle of aqueous phase and increase water wetness. We have also observed that the higher the concentrations of nanofluids, the more the impairment of porosity and permeability in Berea core plugs. Despite that increasing nanofluid concentration shows decreasing IFT and altering wettability, our results indicate that additional recovery is not guaranteed. The processes and results are outlined and also further detailed in the paper to reveal the possible application of nanofluid EOR as a future or an alternative EOR method.
Gas shales have a complex pore structure. Mechanisms of gas storage in the gas shale pore system are in two ways, free gas and sorbed gas. The nanometer scaled pore systems of gas shale reservoirs have a prominent contribution for gas storage, especially for adsorbing gas onto their surfaces. In this study three different methods of low pressure nitrogen adsorption, mercury porosimetry and gas expansion were used for pore structure characterization of gas shales. Mercury porosimetry and gas expansion methods have been used for a long time in characterization of conventional reservoirs but low pressure nitrogen adsorption has been considered recently as a tool for gas shale evaluation. The studied gas shale samples are coming from the Perth and Canning Basins, Western Australia. Analyzing the results of case study shows that the Canning shale samples have the specific surface area and micro/mesopore volume around 13 m /g and 1.4 cc/100 g, respectively, which are relatively higher than the same values for the Perth shale samples. Quantitative analysis of the obtained results clarifies the shape, size and pore volume of the studied gas shale samples. However analyzing the results shows that there is not any consistency between similar parameters like effective porosity or pore size distribution (PSD) extracted from these techniques; several explanations have been proposed for justification of this inconsistency. As well as the results of this study make it clear that each of the usual techniques applied for characterization of gas shale pore systems has some deficiencies and cannot be used alone for this purpose. Whereas, by combining the results of these methodologies pore size spectrum of gas shales can be determined in a more accurate way.
The transportation of heavy and extra-heavy crude oils from the head-well to the refinery is becoming important since their production is currently rising all over the world. Such oils are characterized by a low API gravity ( 10 cP at 298.15 K) that render difficult oil flow through pipelines. Conventional technology pipelining is designed for light and medium oil crudes, but the pipelining of heavy and extra-heavy crude oils may be challenging because of their high viscosities, asphaltene and paraffin deposition, increasing content of formation water, salt content and corrosion issues. In this paper, the current and innovative technological solutions covering viscosity and friction reduction to move such crude oils from the production site to the processing facilities are thoroughly discussed. ► Extra-heavy crude oil pipelining might require hybrid technologies. ► Viscosity reduction requires lighter crude oils, condensates or water. ► Lubricated flow and drag reduction are not fully understood. ► Fundamental research is imperative to understand basic mechanisms. ► Future developments require pilot plant and semi-industrial assays.
Mineral carbonation technology (MCT) is a process whereby CO is chemically reacted with calcium- and/or magnesium-containing minerals to form stable carbonate materials which do not incur any long-term liability or monitoring commitments. Mineral carbonation is a potentially attractive sequestration technology for the permanent and safe storage of CO . Vast amounts of magnesium silicate minerals exist worldwide that may be carbonated, with magnesium carbonate as stable and environmentally harmless product. In this review, a number of processes under development, such as the Åbo Akademi University (ÅA) process routes, the CO Energy Reactor , and the chemical and biological catalytic enhancement as new carbon capture and sequestration (CCS) technology are discussed. The key factors of the mineral CO sequestration process are identified, their influence on the carbonation process and environmental impact of the reaction products with regard to their possible beneficial utilization are critically evaluated. Chemistry and comparative analysis of residues and ores carbonation processes, as well as cost and gap analyses of this technology are discussed.
The clear mechanism of hydraulic fracture propagation in glutenite reservoirs with high heterogeneity is still not obtained, thus it is difficult to carry out the design of fracturing plan effectively. Based on the characteristics of the glutenite reservoirs, a coupled flow-stress-damage (FSD) model of hydraulic fracture propagation with gravels is established. This model is experimentally verified and the research on the influence of rock physical parameters and gravel property on the hydraulic fracture propagation is conducted. It is shown that as the gravel tensile strength increases, the hydraulic fracture is prone to propagate around the gravel, where the fracture deflection always occurs; as the gravel Young's modulus increases, there is high probability that hydraulic fracture propagates around the gravel, with more obvious fracture deflection; the matrix permeability influences fracture propagating morphology when encountering gravel and total fracture length; the horizontal geostress difference seriously impacts the fracture deflection; as the fracturing fluids injection displacement increases, the fracture is prone to deflect when encountering gravel; the low viscosity fracturing fluids result in the shorter fracture; the larger gravel increases the possibility of fracture deflection; in case of smaller gravel sizes, the increasing gravel content has a big influence on fracture deflection, and the increasing content of large gravel complicates the fracture morphology, resulting in the fine branched fractures; for the well rounded gravel, the fracture propagation around the gravel is prone to occur, and the fracture is not prone to deflect. Compared with the conventional sandstone reservoir, the glutenite reservoirs have higher breakdown and extension pressures, which fluctuate due to the gravel; the larger gravel size results in higher extension pressure. In this paper, a simulation method of hydraulic fracture propagation in the glutenite reservoirs is introduced, and the result provides the theoretical support for prediction of fracture propagation morphology and plan design of hydraulic fracturing in the glutenite reservoirs.
The low salinity/engineered water injection techniques (LSWI/EWI) have become one of the most important research topics in the oil industry because of their possible advantages for improving oil recovery compared to conventional seawater injection. Researchers have proposed several mechanisms for the LSWI/EWI process in the literature; however, there is no consensus on a single main mechanism for the low salinity effect on oil recovery. Because of the latter, there are few models for LSWI/EWI and especially for carbonates due to their heterogeneity and complexity. In this paper, we present a comprehensive state-of-the-art review on low salinity/engineered water injection for both sandstones and carbonates. This review includes descriptions of underlying mechanisms, spontaneous imbibition and coreflood laboratory work, field-scale pilots, numerical and modeling work, implementation, comparison between sandstones and carbonates, other LSWI/EWI applications, and desalination methods. List of recommendations and conclusions are provided based on this vast literature review and our experiences. This paper can be used as a guide for starting or implementing laboratory- and field-scale projects on low salinity/engineered water injections.
With the increasingly wide use of hydraulic fracturing in the petroleum industry, it is essential to accurately predict the behavior of fracture propagations based on the understanding of fundamental mechanisms governing the process. For unconventional resources exploration and development, hydraulic fracture pattern, geometry and associated dimensions are critical in determining well stimulation efficiency. In shale formations, non-planar, complex hydraulic fractures are often observed, due to the activation of pre-existing natural fractures. The propagating of turning non-planar fractures due to re-fracturing treatment and unfavorable perforation conditions have also been reported. Current numerical simulation of hydraulic fracturing generally assumes planar crack geometry and weak coupling behaviors, which severely limits the applicability of these methods in predicting fracture propagation under complex subsurface conditions. In addition, the prevailing approach for hydraulic fracture modeling also relies on Linear Elastic Fracture Mechanics (LEFM), which uses stress intensity factor at the fracture tip as fracture propagation criteria. Even though LEFM can predict hard rock hydraulic fracturing processes reasonably, but often fails to give accurate predictions of fracture geometry and propagation pressure in ductile rocks, such as poorly consolidated/unconsolidated sands and clay-rich ductile shales, even in the form of simple planar geometry. In this study, a fully coupled non-planar hydraulic fracture propagation model in permeable medium based on the Extended Finite Element Method (XFEM), Cohesive Zone Method (CZM) and Mohr-Coulomb theory of plasticity is developed for the first time, which is able to model fracture initiation and propagation in both brittle and ductile formations. To illustrate the capabilities of the presented model, example simulations are presented on both near wellbore and far field scale. The results indicate that the in-elastic deformations induced by propagating hydraulic fracture have significant impact on propagation pressure and fracture geometry, and the prediction of fracture propagation behaviors can be extremely erroneous if ductile formations are simply treated as soft rocks with lower Young's modulus. The method discussed in this article represents a useful step towards the prediction of non-planar, complex hydraulic fractures and can provide us a better guidance of completion design and optimizing hydraulic fracture treatment that will better drain reservoir volume in formations with complex stress conditions and heterogeneous properties.
Chemical enhanced oil recovery (EOR) is surely a topic of interest, as conventional oil resources become more scarce and the necessity of exploiting heavy and unconventional oils increases. EOR methods based on polymer flooding, surfactant-polymer flooding and alkali-surfactant-polymer flooding are well established, but new challenges always emerge, which give impulse to the search for new solutions. Polymeric surfactants represent a very attractive alternative to these techniques, because they can provide simultaneously increase in water viscosity and decrease in interfacial tension, both beneficial for the efficiency of the process. The analysis of the literature shows that the use of polymeric surfactants as displacing fluid has the potential to improve the performances of EOR in some cases. However, the synthesis are often challenging and costly and the available data about the real performances of such systems in oil recovery are still sparse. This holds back the possibility of a significant use of polymeric surfactants for EOR. This review collects the relevant work done in the last decades in developing and testing polymeric surfactants for EOR, with a particular emphasis on the chemical aspects, the patent literature and bio-based systems.
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.
The Chang 7 tight oil reservoirs are important oil exploration targets in the Ordos basin. The reservoirs are generally characterized by low porosity, low permeability and strong microscopic heterogeneity. Mineralogical, petrographic, and geochemical analyses have been used to investigate the type and degree of diagenesis and diagenetic history of Chang 7 tight oil reservoirs. The influences of composition, texture and diagenesis on reservoir quality were also discussed in this article. Diagenesis of the Chang 7 tight oil reservoirs was mainly composed of mechanical compaction, grain dissolution and cementation by quartz, carbonates and various clay minerals. Reduction of porosity by mechanical compaction was more significant than by cementation. Eodiagenesis mainly includes (1) mechanical compaction and mechanically infiltrated clays; (2) cementation by calcite, pyrite, and clay minerals; and (3) leaching of feldspars. Mesodiagenesis mainly includes (1) further mechanical compaction; (2) cementation by late stage carbonates; (2) formation of illite and mixed-layered illite-smectite; (3) quartz cements; (4) dissolution of feldspars. The porosity was decreased by compaction and cementation and then increased by dissolution of the framework grains. Primary porosity is higher in sandstones with abundant detrital quartz. Secondary dissolution pores are mainly associated with those feldspar-rich samples. Sandstones which have undergone the most feldspar dissolution are the cleaner (abundant in both detrital quartz and feldspar), better sorted, and coarser-grained samples. Reservoir quality of Chang 7 tight oil reservoirs is also largely controlled by pore occluding cements. The composition and texture have played an important role on intergranular volume and subsequent diagenetic modifications of the Chang 7 tight oil reservoirs. Good quality reservoir intervals are characterized by fine-grained, moderately-well sorted with high percentages of detrital quartz and feldspar but low content of detrital clay and cements.
Reservoir development is increasingly moving towards the heavy oil resources due to the rapid decline in conventional oil reserves. With the production of conventional low gravity crude oil being surpassed by heavy oil production in Alberta, the vast fields of heavy oil have been considered an emerging source of energy to the growing demands for oil and gas. Although the applications of thermal methods have been successful in many enhanced oil recovery (EOR) projects, they are usually uneconomic or impractical in deep and thin pay zones reservoirs. Therefore, polymer flooding is a preferred EOR technique in such reservoirs. An application of polymer flooding in heavy oil reservoirs dates back to more than half a century ago. However, it has long been considered a suitable method for reservoirs with viscosities up to 100 cP only. Recently, this EOR technique has attracted great attentions and become a promising method for oil recovery from heavy oil reservoirs with viscosities ranging from several hundreds to several thousands of centipoises. The main reasons for such a widespread application of the technique in heavy oil reservoirs during the last two decades have been rises in oil prices, extensive use of horizontal wells and advances in the polymer manufacturing technology. This paper aims to review the advances and technological trends of polymer flooding in heavy oil reservoirs since the 1960s. Upon the review, complete data sets of the laboratory works, pilot tests and field applications are established. The database provides qualitative description and quantitative statistics regarding both scientific research and practical applications. Then suitable ranges of some crucial affecting reservoir properties and polymer characteristics for successful field applications are examined. Finally, new screening criteria are developed specifically for heavy oil reservoirs based on an analysis of the data. The criteria are compared with the previously established ones. The outcome of this paper can be used as guidelines for screening, planning, design and eventually implementation of future projects.
Brittleness is commonly used to characterize the possible failure features in rocks, quantified by the brittleness index ( (26) s, the applicability of each should be well understood to enable the selection of the most suitable for each application. This study reports on a detailed review of existing definitions in the rock mechanics field, the transition from brittle to ductile and the application of s to shale fracturing. The success of shale gas recovery using hydraulic fracking is greatly dependent on the shale's brittleness, since brittle shales have many pre-existing fractures and are easy to fracture in tensile and shear modes. A combination of laboratory and geophysical approaches are recommended for shale brittleness quantification. Precise quantification of brittleness is important, both in the laboratory and the field. Brittleness indices based on the elastic moduli (Young's modulus and Poisson's ratio) and mineral composition are common in field applications, and can be derived from both laboratory tests and field log data.
Successful stimulation of shale gas reservoirs by hydraulic fracturing operations requires prospective rocks characterized by high brittleness to prevent fast healing of natural and hydraulically induced fractures and to decrease the breakdown pressure required to (re-) initiate a fracture. We briefly reviewed existing brittleness indices ( ) and applied several, partly redefined, definitions relying on composition and deformation behavior on various, mainly European black shales with different mineralogical composition, porosity and maturity. Samples were experimentally deformed at ambient and elevated pressures ( ) and temperatures ( ), revealing a transition from brittle to semibrittle deformation behavior with increasing pressure and temperature. At given composition and deformation conditions, values obtained from different definitions vary considerably. The change of with applied deformation conditions are reasonably well captured by most definitions based on the stress–strain behavior, which do not correlate with the fraction of individual phases, e.g., clay content. However, at given deformation conditions, most composition-based indices show similar variations with bulk composition as those derived from stress–strain behavior. At low conditions ( 4 km depth), where samples showed pronounced post-failure weakening, values determined from composition correlate with those calculated from pre-failure stress–strain behavior and both correlate with the static Young's modulus. In this regime, the brittleness concept can help to constrain successful hydraulic fracturing campaigns and brittleness maybe estimated from core or sonic logs at shallow depth. However, long term creep experiments are required to estimate in-situ stress anisotropy and the healing behavior of hydraulically induced fractures.
Conventional heavy oil recovery method of saturated steam injection at heel-point of horizontal wellbores is facing comparatively more serious fingering phenomenon. With this, oil companies are now actively developing new recovery method of supercritical CO - superheated steam injection in horizontal wellbores with toe-point injection technique. Firstly, considering the heat exchange between the inner tubing (IT) and annuli, a pipe flow model comprised of energy and momentum conservation equations is developed for the mixture flow in both IT and annuli. Then, coupled with the S-R-K real gas model, variable mass flow model and transient heat transfer model in oil layer, a comprehensive mathematical model is established. Numerical solutions of the mixture flow in toe-point injection wellbores are obtained through straight forward numerical method. Finally, model validation and sensitivity analysis are conducted. The results show that: (1). there exists a good agreement between predicted results and field data. The predicted temperature is higher when the heat exchange between IT and annuli is neglected. The predicted temperature is lower when the friction loss item is considered in the energy balance equation. (2). the temperature of the mixture increases when the mixture flows from toe-point to heel-point in annuli due to heat flow from IT to annuli. (3). While the absorption rate of the mixture in formation increases with increasing of the content of supercritical CO , it can be offset by the decrease of temperature and enthalpy of the mixture. (4). Both of the mixture temperature and formation mixture absorption rate increase with increasing of injection pressure.
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.