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Field trials have demonstrated that foamed gel is a very cost-effective technology for profile modification and water shut-off. However, the mechanisms of profile modification and flow behavior of foamed gel in non-homogeneous porous media are not yet well understood. In order to investigate these mechanisms and the interactions between foamed gel and oil in porous media, coreflooding and pore-scale visualization waterflooding experiments were performed in the laboratory. The results of the coreflooding experiment in non-homogeneous porous media showed that the displacement efficiency improved by approximately 30% after injecting a 0.3 pore volume of foamed gel, and was proportional to the pore volumes of the injected foamed gel. Additionally, the mid-high permeability zone can be selectively plugged by foamed gel, and then oil located in the low permeability zone will be displaced. The visualization images demonstrated that the amoeba effect and Jamin effect are the main mechanisms for enhancing oil recovery by foamed gel. Compared with conventional gel, a unique benefit of foamed gel is that it can pass through micropores by transforming into arbitrary shapes without rupturing, this phenomenon has been named the amoeba effect. Additionally, the stability of foam in the presence of crude oil also was investigated. Image and statistical analysis showed that these foams boast excellent oil resistance and elasticity, which allows them to work deep within formations.

The primary objective of particle gel treatment is to significantly reduce water flow through high-permeability channels without damaging oil production zones. The ability of gels to reduce permeability to water much more than permeability to oil is a critical aspect of the success of water control in both production wells and in-depth fluid diversion conformance control. This work investigates factors affecting particle gel placement through fractures and determines the extent to which particle gels can reduce water permeability more than oil permeability within a fracture. Experimental models were designed to study the effect of the particle gel size, particle gel strength, fracture width, and oil viscosity on the disproportionate permeability reduction (DPR). Five-foot tubes with two internal diameters were used to represent a fracture with two different widths. PPGs were injected first into the fractures, followed by alternating floods of water and oil. During the gel injection, the resistance factors (Fr) increased as the gel particle size, gel strength, and fracture width increased. Results obtained from the alternating floods show that the DPR increased as the oil viscosity, particle size, gel strength, and fracture width increased. Gel shrinkage, gel strength, and gel dehydration were found to contribute significantly to this phenomenon. The permeability reduction factor to water increased, becoming 100 to 1700 times greater than the permeability reduction factor to oil. The injection pressure for different water cycles increased as more cycles were performed. These increases, however, were not significant when observed for different oil cycles. The experimental results show that when a second water cycle was injected to displace oil, the residual resistance factor for water (Frrw) in the second cycle was significantly less than the preceding Frrw values. This finding indicates that the gel experienced a significant breakdown during the first oil cycles. Additional oil cycles were performed, and the Frrw decreased during each new brine cycle, indicating further gel breakdown.

Screening is considered the first step in evaluating potential enhanced oil recovery (EOR) techniques for candidate reservoirs; therefore, it is important to update the screening criteria as new technologies are developed. However, most recently published screening criteria regarding polymer flooding were based on data collected from the bi-annual EOR surveys published by the Oil & Gas Journal. These data recorded valuable information for finished and ongoing polymer flooding worldwide, but they are constrained in two ways. Firstly, they do not include some important information, such as the formation water salinity, divalent concentration, and polymer type and concentration. Secondly, the field data do not reflect recent polymer technology developments that are still in the laboratory evaluation and pilot testing stages. To overcome these limitations, a comprehensive dataset that provides the overall picture of polymer flooding research and application is presented in this paper. A total of 865 polymer flooding projects were considered to construct the dataset, including 481 field projects from the Oil & Gas Journal (1974-2012), 329 laboratory experiments (1964-2013), and 55 pilot test projects (1966-2011) recorded in the literature. After enhancing the data quality, graphical and statistical methods were used to analyze and describe the dataset. The distribution of major parameters important to polymer flooding design is presented using histograms, and the range of all parameters and their statistical values are presented using box plots. New screening criteria are presented based on these statistics of the defined parameters. Compared to published screening analyses, the new dataset and criteria provide more information critical to the design of a successful polymer flooding project, such as data pertaining to the formation water salinity, polymer molecular weight and concentration, polymer viscosity, and slug size.

As an effective conformance control method, gel treatments have been applied widely in mature oilfields to reduce excess water production by preferentially plugging the water thief zones after long-term water flooding. Performed particle gels (PPGs) are becoming more and more popular in China for this purpose because they overcome some of the inherent drawbacks of in-situ gel systems, including the lack of control over the gelation time, gelling uncertainty due to shear degradation, chromatographic fractionation or change of gelant composition, and dilution by formation water. However, the literature in this area remains limited, providing few case studies or data analyses regarding the use of PPG in oilfields.This paper reports field applications of particle gels in water flooding, polymer flooding and ASP flooding. In Chinese oilfields from 2001 to 2012, we treated 655 wells with 12,765.62 tons of particles; the injected dry particles typically weighed between 11.5 to 20.6 tons per well. The applications covered both sandstone reservoirs and naturally fractured reservoirs with different temperatures and formation salinities. Properties of the particles applied in oilfields, such as the particle size, swelling ratio, and thermal stability, were tested. Eight cases are reported in this paper as examples of how to design and evaluate gel treatment projects. The results showed that the oil production rate increased from 14.3% to 50% and that water production decreased to the range of 0.4% to 4.7% after treatment.Based on the case study, highlights of illustrative PPG field applications and results are presented. Criteria for well selection and PPG treatment design are provided to serve as a guide for the kinds of conditions under which PPG conformance control can be applied successfully.

The application of nanoparticles in enhanced oil recovery (EOR) continues to gain attention in the oil industry due to its apparent potential. However, previous studies have focused on the evaluation of stiff particles, such as silica and aluminum oxide. In this paper, we present our experimental results of deformable nanoparticle transport behavior through porous media. Nanogel particles with sizes ranging from 100–285 nm were used to represent deformable nanoparticles. Core flooding tests were run using sandstone cores with water permeabilities ranging from 42 to 1,038 mD. We investigated the effects of the permeability, particle concentration, particle deformability, and flow rate on the particle propagation, resistance factor, and residual resistance factor (permeability reduction factor). The results show that the resistance factor ranged from 5 to 14 for rocks with permeabilities higher than 311 mD, indicating that the nanoparticles were able to transport easily through these rocks. However, the resistance increased to 383 when the permeability was as low as 41.2 mD, indicating that the nanogel could not penetrate the rock easily. After placing the particles, brine was injected at different flow rates. The results indicate that the nanoparticles effectively reduced the permeability of the rocks with the original permeabilities of 143 to 555.4 mD, but the residual resistance factor of the high-permeability rock (1,038 mD) was relatively small, ranging from 2.67 to 4.39. The resistance factor and residual resistance factor increased with the particle concentration and decreased with the flow rate, and both factors can be well fitted using power law equations as a function of velocity. The nanogel adsorption layer thickness decreased with the shear rate.

Unconventional oil reservoir has presented the potential to become a significant source of hydrocarbon in the future productions. Many shale oil systems consist of nano-scale pores and micro-scale fractures that are significantly smaller than those from conventional reservoirs. Such small size of the pore throats in shale may differ from the size of the saturating fluid molecules by only slightly more than one order of magnitude. This difference will result in different wettability, fluid flow mechanisms and storage capabilities in unconventional shale oil systems. However, the fluid flow behavior in the micro-scale or even nano-scale pores and channels is poorly investigated and understood. Therefore, it is increasingly important to investigate fluid flow behaviors and the fluids residue saturation in the nano-scale channels. In this work, a lab-on-chip approach for direct visualization of the water/oil flow in nano-scale channels is developed by using advanced confocal microscopy system combined with nano-fluidic chip. A comprehensive study of water/oil flow behaviors is presented. During drainage process, liquids tend to be piston like flow under micro; both residual phase saturation and configuration affect the flow behavior under smaller scale. During imbibition process, a fading out phenomenon was observed which. For residual phase saturation, confocal system can give a precise description within 3-dimensional scale.

Tight formations with extremely low matrix permeabilities, such as gas shale, can produce at economical rates is due to inborn fissures and fractures introduced during hydraulic stimulation. Hydraulic fracturing in gas shale can connect/generate these microfractures, causing them to become much more complex fracture networks. These microfractures have much more contact area with the matrix and therefore hold the majority of the productivity potential of gas shale. Slickwater fracturing has been proved to be an effective method by which to increase the recovery of shale gas reservoirs. Friction reducer is the primary component of this fluid. It can decrease the flowing friction in macro tubing. Lab tests and field applications have addressed this issue thoroughly. However, the flow characteristics of this solution in microfractures are not clear. The present study will show how this solution flows in microfractures by employing micro-sized fracture model. FR solution is a shear thinning fluid. Rather than reducing flow friction, with the FR fluid in a 1000 μm height, 50 width μm and 4.14 cm length microfracture, the injection pressure did not decrease but rather increased 36%. The impact of FR solution concentration was found to be more obvious at low velocities. At the same shear rate, the apparent viscosity is higher in large microfractures. At the same velocity, large microfractures have higher residual resistance factors. Through the analysis of fluid emulsion particle size and shale matrix pore size, this FR solution will not go into the matrix pores easily, but can block the pore entrance to prevent the fluid from leak off and to protect the formation from contamination during slickwater fracturing.

Gel treatment is a cost-effective method for oilfield conformance control. Traditionally, in-situ gels formed by the reaction of polymer and crosslinker at reservoirs have been used widely to control conformance. However, a newer trend is to apply preformed particle gels (PPGs) for this purpose because they are formed at surface facilities before injection and they overcome some distinct drawbacks inherent in in-situ gelation systems, such as lack of control over the gelation time, gelling uncertainty due to shear degradation, chromatographic fractionation or change of gelant compositions, and dilution by formation water. PPGs are characterized as having robust gel chemistries and as being highly insensitive to petroleum reservoir environments and interferences. They can resist temperatures up to 120 °C (250 °F) and are compatible with any kind of formation water. In this paper, we describe and discuss our extensive laboratory and field experiences with the widely applied and successful PPG technology. Highlights of illustrative PPG field applications and results are presented. An overview of what over a decade of experience in applying the PPG technology has taught us is discussed. This includes a discussion of classifying and distinguishing conformance problems and treatments, attributes of good candidate wells, requirements that must be met in candidate wells, gel treatment elements that must be implemented successfully to achieve success, and the guidelines as to where PPG conformance treatments are applied most successfully.

This paper proposes a domain decomposition method for the coupled stationary Navier-Stokes and Darcy equations with the Beavers-Joseph-Saffman interface condition in order to improve the efficiency of the finite element method. The physical interface conditions are directly utilized to construct the boundary conditions on the interface and then decouple the Navier-Stokes and Darcy equations. Newton iteration will be used to deal with the nonlinear systems. Numerical results are presented to illustrate the features of the proposed method.

Geospatial data sharing is an increasingly important subject as large amount of data is produced by a variety of sources, stored in incompatible formats, and accessible through different GIS applications. Past efforts to enable sharing have produced standardized data format such as GML and data access protocols such as Web Feature Service (WFS). While these standards help enabling client applications to gain access to heterogeneous data stored in different formats from diverse sources, the usability of the access is limited due to the lack of data semantics encoded in the WFS feature types. Past research has used ontology languages to describe the semantics of geospatial data but ontology-based queries cannot be applied directly to legacy data stored in databases or shapefiles, or to feature data in WFS services. This paper presents a method to enable ontology query on spatial data available from WFS services and on data stored in databases. We do not create ontology instances explicitly and thus avoid the problems of data replication. Instead, user queries are rewritten to WFS getFeature requests and SQL queries to database. The method also has the benefits of being able to utilize existing tools of databases, WFS, and GML while enabling query based on ontology semantics.

The information-hiding ratio is a well-known metric for evaluating steganalysis performance. In this paper, we introduce a new metric of image complexity to enhance the evaluation of steganalysis performance. In addition, we also present a scheme of steganalysis of least significant bit (LSB) matching steganography, based on feature mining and pattern recognition techniques. Compared to other well-known methods of steganalysis of LSB matching steganography, our method performs the best. Results also indicate that the significance of features and the detection performance depend not only on the information-hiding ratio, but also on the image complexity. http://www.sciencedirect.com/science/article/B6V0C-4PGGP7X-1/1/860a8a93799c6d245e4ee52bfdb4180d

Knowing the injection profile of each injector in a reservoir is of major importance for analyzing residual oil distribution underground. However, in practice, it is impossible to acquire real-time injection profiles for each well when they are needed. In this paper, a two-step learning fuzzy system was introduced to predict injection profiles for wells with outdated data or without data by analyzing those injectors whose injection profiles are well characterized. Five pivotal parameters were selected to be fed into the subtractive clustering algorithm and ANFIS (adaptive-network-based fuzzy inference system) to model their non-linear relationships with the injectivity of each producing layer. Experiments in comparing the two-step method and the backpropagate feed-forward (BPFF) neural network showed that the two-step method can automatically generate a more simply structured fuzzy inference system (FIS) and can simulate complicated numerical nonlinear relationships with higher accuracy. This method was used in injection profile prediction in one block of the Daqing oilfield. The average accuracy was shown to be above 80%.

In this information age, the problem of data quality deserves more attention than it is getting. Contaminated or corrupted data are data that were misunderstood or misrecorded in data sets. The success of the petroleum industry relies upon a combination of multi-dimensional reliable information and proper cross-disciplinary techniques. Contaminated data can mislead the strategic-level decision making and cause operational failures. This paper presents a methodology to identify contaminated data in large spatial data sets in the data quality control cycle. Graphical and quantitative spatial outlier detection methods are discussed. All these methods are different for identifying spatially abnormal data, both in mechanisms and results. This paper discusses these methods and compares their advantages and disadvantages. The effectiveness of these methods is evaluated by using a real spatial database, the Produced Water Chemistry Database (PWCD) in New Mexico.

The New Mexico Water and Infrastructure Data System (NM WAIDS) seeks to alleviate a number of produced water-related issues in southeast New Mexico. The project calls for the design and implementation of a Geographical Information System (GIS) and integral tools that will provide operators and regulators with necessary data and useful information to help them make management and regulatory decisions. The major components of this system are: (1) databases on produced water quality, cultural and groundwater data, oil pipeline and infrastructure data, and corrosion information, (2) a web site capable of displaying produced water and infrastructure data in a GIS or accessing some of the data by text-based queries, (3) a fuzzy logic-based, site risk assessment tool that can be used to assess the seriousness of a spill of produced water, and (4) a corrosion management toolkit that will provide operators with data and information on produced waters that will aid them in deciding how to address corrosion issues. The various parts of NM WAIDS will be integrated into a website with a user-friendly interface that will provide access to previously difficult-to-obtain data and information. Primary attention during the first six months of this project has been focused on creating the water quality databases for produced water and surface water, along with collection of corrosion information and building parts of the corrosion toolkit. Work on the project to date includes: (1) Creation of a water quality database for produced water analyses. The database was compiled from a variety of sources and currently has over 4000 entries for southeast New Mexico. (2) Creation of a web-based data entry system for the water quality database. This system allows a user to view, enter, or edit data from a web page rather than having to directly access the database. (3) Creation of a semi-automated data capturing system for use with standard water quality analysis forms. This system improves the accuracy and speed of water quality data entry. (4) Acquisition of ground water data from the New Mexico State Engineer's office, including chloride content and TDS (Total Dissolved Solids) for over 30,000 data points in southeast New Mexico. (5) Creation of a web-based scale prediction tool, again with a web-based interface, that uses two common scaling indices (Stiff-Davis and Oddo-Thomson) to predict the likelihood of scaling. This prediction tool can either run from user input data, or the user can select samples from the water analysis database. (6) Creation of depth-to-groundwater maps for the study area. (7) Analysis of water quality data by formation. (8) Continuation of efforts to collect produced water quality information from operators in the southeast New Mexico area. (9) Qualitative assessment of produced water from various formations regarding corrosivity. (10) Efforts at corrosion education in the region through operator visits. Future work on this project will include: (11) Development of an integrated web and GIS interface for all the information collected in this effort. (12) Continued development of a fuzzy logic spill risk assessment tool that was initially developed prior to this project. Improvements will include addition of parameters found to be significant in determining the impact of a brine spill at a specific site. (13) Cleanup and integration of water quality databases. (14) Compilation of both hard copy and online corrosion toolkit material.

Abstract How to control water-cut of mature oilfields is always a challenging task for field operators. In order to control excess water production, a new selective water plugging agent was developed. It is made up of crude oil and emulsifier. Squeezed into water zones, it forms emulsion when contacting with water. The viscosity of emulsion is 20 times that of the crude oil used, leading to the plugging of the zone. In contrast, when entering oil zones it dissolves into oil without causing any damage. Due to its selectivity, it can be injected into high water-cut production wells by bullhead method. The purpose of this paper is first to introduce a new emulsifier, then to present the experimental study concerning crude oil emulsions and field operations performed using this technique. The morphological changes of the activated crude oil induced by the mixing with water, the viscous properties of several emulsions and the selection of crude oil are discussed. Coreflood experiments were also carried out to demonstrate the selective placement of the activated crude oil. A formula based on the critical pressure of the emulsions is given to optimize the volume of emulsions to be injected in oilfield experiments. From Jan.91 to Jun. 99, 238 water shutoff operations using this new technique were performed in Liaohe oil field of CNPC, resulting in 167,000 t of incremental oil and 295,000m3 of reduced water. Introduction Excess production water is a very serious problem during waterflooding of heterogeneous reservoir formations. To solve the problem, many kinds of plugging agents have been developed1–3. These plugging agents include: cements, gels, particulates, microorganisms and so on. All these agents were widely used in Chinese oilfields 4. A key factor influencing water plugging success rate is whether the plugging agent will only reduce water production without damaging less-permeable, oil-productive zones5–8. Four types of treatments have been studied to reduce the damage caused by the plugging agents on non-target zones9–12.Zone isolation: one entire isolated zone is being abandoned in order to allow production from other zones.Dual injection: the treatment is often used in a single, discrete, reservoir zone, when mechanical wellbore control of fluid placement is impossible.Injection of a relative permeability modifier: A relative permeability modifier is bullheaded into all perforated zones. This treatment is often used in these wells in which we cannot identify the specific water producing zone or there may be no barriers beyond the near wellbore region to provide fluid control.Injection of a selective entrance plugging agent: the agent perferentially enter high-permeability high watered-out zones, while it forms face plugging in low-permeability zones. After plugging agent injection, a small volume of dissolver is injected to dissolve face plugging material. Treatments with zone isolation cannot damage low-permeability zone. However, it has a limited range of applicability, due to the poor distinction between water-producing and oil-producing layers in great majority of the wells, especially in mature oilfields in China. Other types of treatments can damage low-permeability zones more or less.

Nanocrystalline nickel ferrite has been successfully synthesized through a simple hydrothermal process at 180 °C for 10 h. The as-synthesized powders were characterized by high-resolution transmission electron microscopy (HRTEM) and X-ray diffraction (XRD) techniques. TEM image and HRTEM image revealed that the as-prepared crystals were well crystallized with grain size distribution from 50 to 80 nm. The magnetic properties were studied by vibrating sample magnetometer (VSM), it exhibited lower coercivity and higher saturation magnetization which came from high crystallinity and uniform morphologies.

The adsorption of hydrogen molecules on titanium-decorated (Ti-decorated) single-layer and bilayer graphenes is studied using density functional theory (DFT) with the relativistic effect. Both the local density approximation (LDA) and the generalized gradient approximation (GGA) are used for obtaining the region of the adsorption energy of H2 molecules on Ti-decorated graphene. We find that a graphene layer with titanium (Ti) atoms adsorbed on both sides can store hydrogen up to 9.51 wt% with average adsorption energy in a range from −0.170 eV to −0.518 eV. Based on the adsorption energy criterion, we find that chemisorption is predominant for H2 molecules when the concentration of H2 molecules absorbed is low while physisorption is predominant when the concentration is high. The computation results for the bilayer graphene decorated with Ti atoms show that the lower carbon layer makes no contribution to hydrogen adsorption.

Producing gas from shale strata has become an increasingly important factor to secure energy over recent years for the considerable volume of natural gas stored. Unlike conventional gas reservoirs, gas transport in shale reservoirs is a complex process. In the organic nano pores, slippage effect, gas diffusion along the wall, viscous flow due to pressure gradient, and desorption from Kerogen coexist; while in the micro fractures, there exist viscous flow and slippage. Hydraulic fracturing is commonly used to enhance the recovery from these ultra-tight gas reservoirs. It is important to clearly understand the effect of known mechanisms on shale gas reservoir performance. This article presents the pressure transient analysis (PTA) and rate decline analysis (RDA) on the hydraulic fractured vertical wells with finite conductivity in shale gas reservoirs considering multiple flow mechanisms including desorption, diffusive flow, Darcy flow and stress sensitivity. The PTA and RDA models were established firstly. Then, the source function, Laplace transform, and the numerical discrete methods were employed to solve the mathematical model. At last the type curves were plotted and different flow regimes were identified. The sensitivity of adsorption coefficient, storage capacity ratio, inter-porosity flow coefficient, fracture conductivity, fracture skin factor, and stress sensitivity were analyzed. This work is important to understand the transient pressure and rate decline behaviors of hydraulic fractured vertical wells with finite conductivity in shale gas reservoirs.

In-depth gel treatment has become an attractive and optimum technology for remedying any problems that cause poor sweep efficiency, such as heterogeneity of the reservoir and unfavorable mobility ratio (due to high oil viscosity). The low recovery factor resulted from the difference in reservoir properties especially reservoir permeability, would lead eventually to use of the chemical materials such as polymer and gel to correct this condition. A comprehensive simulation study of deep placement of weak gel in thick heterogeneous reservoir is presented in this paper. A conceptual model with quarter of inverted nine spot pattern using CMG-STARS commercial simulator was built, to demonstrate the effectiveness of in-depth gel treatment in correcting the heterogeneity in this thick reservoir. The model consists of one injector and three producers with three layers of different permeabilities and thicknesses. These wells are perforated in all layers of the model (i.e., layers 1, 2, & 3). The results showed that injecting even a low PV of gel into high permeability layers could make a remarkable increase in oil recovery factor and incremental oil over the base case water flooding. Polymer and gel degradation rate have a significant impact on the reservoir performance after the treatment. Three different scenarios for both polymer and gel degradation are considered: no degradation, 2 years and 4 years degradation. The results were showed that always the runs without degradation yielded higher recovery factor regardless the injected PV. In addition, when gel is injected into only high permeability layers a higher incremental oil and higher oil recovery factor were obtained in comparison with runs when gel is injected into all three layers. Moreover, the more homogeneous the reservoir is, the higher recovery factor could be obtained. However, in this study, changing the crossflow (kv/kh) value has no effect on oil recovery values over the ranges selected (i.e., 0.001, 0.005, 0.01, and 0.02). The best time to start gel injection is also investigated, it was revealed that it is better to start gel treatment when water cut is about 80%, because before that time the high permeability layers may still contain a moveable oil that can be recovered. Another set of runs were carried out to show the importance of injecting polymer and gel together. The results showed that when gel is injected into all three layers with 4 years gel degradation and 2 years polymer degradation, polymer flooding then gel treatment yielded better results than gel treatment then polymer flooding. Finally, a sensitivity analyses, by CMG-CMOST, was carried out to show the importance of in-situ parameters (i.e., k1, k2, k3, kv/kh, RRFT, and thicknesses of the layers) and operating parameters (i.e., polymer properties, injection pressure, and injection time) on cumulative oil production and oil recovery factor. An optimum values have been obtained that yielded the highest cumulative oil production and highest oil recovery factor. All gel treatment runs had been compared with water and polymer flooding to evaluate the diversion potential of in-depth gel treatment.

Producing gas from shale gas reservoirs has played an increasingly important role in the volatile energy industry over recent years in North America for considerable volume of natural gas stored in the reservoirs. Unlike conventional gas reservoirs, the gas flow in shale reservoirs is a complex multi-scale flow process and has special flow mechanisms. Most importantly, the shale gas reservoir contains a large portion of nano pores. The study of flow in nano pores is essential for accurate shale gas numerical simulation. However, there is still not a comprehensive study in understanding how gas flows in nano pores. In this paper, based on the advection-diffusion model, we constructed a new mathematical model to characterize gas flow in nano pores. We derived a new apparent permeability expression based on advection and Knudsen diffusion. Acomprehensive coefficient in characterizing the flow process was proposed. Simulation results were verified against the experimental data for gas flow through nano membranes. By changing the comprehensive coefficient, we found the best candidate for the case of Argon with membrane pore diameter 235 nm. We verified the model using different gases (Oxygen, Argon) and different pore diameters (235 nm, 220 nm). The comparison shows that the new model matches the experimental data very closely. Additionally, we compared our results with experimental data, Knudsen/Hagen-Poiseuille analytical solution, and existing researcher’s work. The results show that this study yielded a more reliable solution. For shale gas simulation where gas flowing in nano pores plays a critical role, the results from this work will made the simulation more accurate and reliable.

Preformed Particle Gel (PPG) have been used as conformance control in mature oil field. Reservoirs ith fractures and very high permeability are candidates for gel treatment. By injecting the PPG in the flooded area, the post waterflooding reached unswept area and improve oil recovery factor. Recently, Discrete Fracture Model (DFM) has been reached a great attention by some researchers in reservoir modeling area. Therefor, DFM was used to evaluation of gel treatment in fractured reservoirs using different senarios. Outcrop carbonate core with oil-wet wettability was used to establish the experiment part. Transparent acrylic plates was used to design the fracrure model with 1.5 mm fracture width. Sodium chloride was prepared for waterflooding and PPG swollen. The experimental results showed that the preformed particle gel improved the oil recovery improved by 12% after gel treatment with 20% water cut reduction as an experimental results. Morover, the experimental result showed a very good match with simulation results in lab scale. The main PPG design variables are PPG concentration and PPG treatment timing according to the field scale simulation resuls and when gel treatment applied early, the oil recovery improved. The integration of gel treatment and Embedded Discrete Fracture Modeling (EDFM) will help the field developers to select the best senario for gel treatment.

Millimeter-sized (10 um~mm) preformed particle gels (PPGs) have been used successfully as conformance control agents in more than 5,000 wells. They help to control both water and CO2 production through high-permeability streaks or conduits (large pore openings), which naturally exist or are aggravated either by mineral solutions or by a high injection pressure during the flooding process. This paper explores several factors that can have an important impact on the injectivity and plugging efficiency of PPGs in these conduits. Extensive experiments were conducted to examine the effect of the conduit's opening size and the PPG strength on the ratio of the particle size to the opening diameter, injectivity index, resistance factor, and plugging efficiency. Five-foot tubes with four internal diameters were designed to emulate the opening conduits. Three pressure taps were mounted along the tubes to monitor PPG transport and plugging performance. The results show that weak gel has less injection pressure at a large particle opening ratio compared to strong gel. PPG strength impacted injectivity more significantly than did particle opening ratio. Resistance factor increased as the brine concentration and conduit opening size increased. PPGs can significantly reduce the permeability of an open conduit and their plugging efficiency depends highly on the particle strength and the conduit's opening size. The particle size of PPG was reduced during their transport through conduits. Experimental results confirm that the size reduction was caused by both dehydration and breakdown. Based on the lab data, two mathematical models were developed to quantitatively calculate the resistance factor and the stable injection pressure as a function of the particle strength, particle opening ratio, and shear rate. This research provides significant insight into designing better millimeter-sized particle gel treatments intended for use in large openings, including open fractures, caves, worm holes, and conduits.

Producing gas from shale strata has become an increasingly important factor to secure energy over recent years for the considerable volume of natural gas stored. Unlike conventional gas reservoirs, gas transports in shale reservoir is a complex process. In the organic nano pores, slippage effect, gas diffusion along the wall, viscous flow due to pressure gradient, and desorption from Kerogen coexist. In the micro fractures, there exists viscous flow and slippage. Also, with pressure depletion, gas viscosity will decrease. The porosity will increase when the gas desorbs from the pore wall. However, factors such as viscosity decrease and porosity increase have not received enough attention in existing mathematical models. It is important to construct a unified model considering all known mechanisms. In this paper, based on dual porosity continuum media, mass balance equations in matrix and fracture were constructed using dusty gas model. In the matrix, Knudsen diffusion, Fick diffusion and viscous flow were considered. Gas desorption was characterized by Langmuir isothermal equation. In the fracture, Forchheimer flow was considered. Porosity increase was calculated by the equivalent volume increase due to gas desorption from the pore wall. Gas viscosity was characterized as a function of Knudsen number. Later, equivalent integral weak forms were derived based on constant pressure boundary. And model got solved using finite element method. Finally sensitive factors of shale gas production were analyzed. The results show that considering gas viscosity change increases cumulative gas production by nearly 12% under given reservoir conditions. Considering porosity increase will obtain higher production than without. The matrix and fracture permeability increase with time during production. Ignoring one of these factors such as Knudsen diffusion, slippage effect, desorption, viscosity decrease and porosity increase will obtain less cumulative production. For more accurate shale gas production prediction, it is crucial to incorporate these factors into the model.