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This article analyzes the current situation of solid waste resource utilization in China's construction industry from a market-oriented perspective, and explores the promoting role of market mechanisms in the utilization of solid waste resources in construction. Through the analysis of the amount of solid waste generated, disposal methods, and the level of resource utilization in the construction industry in China, it is found that there are problems such as low resource recovery efficiency and imperfect market mechanisms in the current utilization of solid waste resources. Therefore, this article proposes a series of suggestions to promote the utilization of solid waste resources, including the formulation of sound policies and regulations, strengthening market supervision, and nurturing market entities. At the same time, this article also looks forward to the future development of the market for the utilization of solid waste resources in construction, believing that with the continuous improvement of policies and regulations and the soundness of market mechanisms, the market for the utilization of solid waste resources will usher in broader development space.

Gel treatment has been widely applied in mature oilfields to improve sweep efficiency and control water production. Correct numerical simulation is of major importance to the optimization design and prediction of a successful gel treatment. However, there exist many problems in current simulation studies in published literature. This paper first presents a comprehensive review on the major factors that have been considered at different gelation stages during gel treatment, the models used in the commercial/in-house simulators, and current numerical simulation studies on both laboratory and field scales. Then we classify the current in-situ gel numerical simulation problems as 1, deficient model problem that has published numerical model but has not been applied in simulator and application studies; 2, missing model problem that does not have published quantitative model; and 3, inaccurate application problem that does not consider the major factors of gel performance, based on the reasons from some questionable results of current simulation studies. Finally, we point out the major research efforts that should be made in the future to better simulate in-situ gel treatment process. The review indicates that numerous simulation studies using commercial software packages intend to predigest the gel treatment, many of which, however, ignore important mechanisms and mislead the operation of gel treatment. In fact, a full assessment of simulating in-situ gels cannot be achieved unless the quantitative models can be qualified in terms of transport and plugging mechanisms based on the experimental results.

Summary Gel treatment has been a cost-effective method to control the conformance of a reservoir with severe heterogeneity problems. The water channels in such reservoirs can be classified as open fractures or high permeability porous media with pore-throat network. Many simulation studies have been conducted to discuss gel treatment performance for conformance control. However, nobody considered the polymer rheology difference in open fractures and porous media in simulation. Previous simulation studies also ignored the residual resistance factor as a function of rock permeability rather than a constant parameter. In this study, a conceptual simulation model was established to simulate the linear flow system for the reservoir with horizontal wells considering the two factors mentioned above. The results demonstrate that the gel treatment always provides the better placement results in the open fracture type channel than pore-throat network type channel. Moreover, it is very necessary to consider residual resistance factor as a function of permeability, which is based on the experimental results and can provide much greater plugging efficiency in the higher permeable channels than constant residual resistance factor. Sensitivity analysis studies and multifactor analysis indicate that increasing oil viscosity and permeability ratio has a strong positive influence on conformance control results, which indicate in-situ gel treatment can be better applied in heavy or viscous oil reservoirs with fracture-like channels. Besides, the results also indicate that in reservoirs with severe channeling problem where channel velocity was high, the differences of gelant placement and profile improvement in models with two different types of channels could be enlarged greatly.

SummaryPolymer flooding has been widely used to improve oil recovery. However, its effectiveness would be diminished when channels (e.g., fractures, fracture-like channels, void-space conduits) are present in a reservoir. In this study, we designed a series of particular sandwich-like channel models and tested the effectiveness and applicable conditions of micrometer-sized preformed particle gels (PPGs, or microgels) in improving the polymer-flooding efficiency. We studied the selective penetration and placement of the microgel particles, and their abilities for fluid diversion and oil-recovery improvement. The results suggest that polymer flooding alone would be inefficient to achieve a satisfactory oil recovery as the heterogeneity of the reservoir becomes more serious (e.g., permeability contrast kc/km > 50). The polymer solution would vainly flow through the channels and leave the majority of oil in the matrices behind. Additional conformance-treatment efforts are required. We tried to inject microgels in an attempt to shut off the channels. After the microgel treatment, impressive improvement of the polymer-flooding performance was observed in some of our experiments. The water cut could be reduced significantly by as high as nearly 40%, and the sweep efficiency and overall oil recovery of the polymer flood were improved. The conditions under which the microgel-treatment strategy was effective were further explored. We observed that the microgels form an external impermeable cake at the very beginning of microgel injection and prevent the gel particles from entering the matrices. Instead, the microgel particles could selectively penetrate and shut off the superpermeable channels under proper conditions. Our results suggest that the 260-µm microgel particles tested in this study are effective to attack the excessive-water-production problem and improve the oil recovery when the channel has a high permeability (>50 darcies). The gels are unlikely to be effective for channels that are less than 30 darcies because of the penetration/transport difficulties. After the gels effectively penetrate and shut off the superpermeable channel, the subsequent polymer solution is diverted to the matrices (i.e., the unswept oil zones) to displace the bypassed oil. Overall, this study provides important insights to help achieve successful polymer-flooding applications in reservoirs with superpermeable channels.

Carbon capture and storage (CCS) technology has been widely investigated to decrease the greenhouse effect. Geological CO2 storage sites are targeted mainly on depleted petroleum reservoirs or deep...

The MnNiFeGe alloy is prepared by high-pressure annealing method. It is found that the martensitic transformation temperature after high-pressure annealing of this alloy decreases with the increasi...

SummaryTraditional polyacrylamide (PAM)-based superabsorbent polymer has been applied to control excess carbon dioxide (CO2) production in CO2-flooding fields. Nevertheless, the application results are mixed because the polyacrylamide-based superabsorbent polymer dehydrates significantly when exposed to supercritical CO2; therefore, we evaluated a novel CO2-resistant gel (CRG) with reliable stability and CO2-responsive properties. Particularly, the CRG swelling ratio (SR) and gel-volume increase after CO2 stimulation if additional water is available. Swollen CRG was placed in high-pressure vessels to examine the weight loss and the property changes before and after exposure to CO2. The breakthrough pressure and CRG-plugging efficiency to CO2 were measured using partially open fractured-sandstone cores. Two water/alternating/gas (WAG) cycles were conducted to test the CRG-plugging performance after CRG injection. The high-pressure vessel-test results show that the CRG is very stable under the supercritical-CO2 condition and no free water is released from the samples. The scanning-electron-microscope (SEM) images confirm that no structural damage was observed in CRG after exposure to CO2. The breakthrough pressure increases with the matrix permeability, which is mainly induced by the internal and external gel cake formed on the rock surface. CRG can reduce the water permeability more than CO2 permeability. CRG-plugging efficiency to CO2 decreases with the increase of WAG cycles. However, in the 0.5-mm fracture model and the 390-md model, CRG-plugging efficiency to water increases with WAG cycles. This phenomenon further indicates that CRG can be stimulated by CO2, which allows CRG to absorb additional water during post-waterflooding. In general, this study reports the concept of the novel CRG and a systematical evaluation of CRG stability under supercritical-CO2 conditions and CRG-plugging efficiency using a partially open fractured-sandstone model.

Steam flooding is a complex process that has been considered as an effective enhanced oil recovery technique in both heavy oil and light oil reservoirs. Many studies have been conducted on different sets of steam flooding projects using the conventional data analysis methods, while the implementation of machine learning algorithms to find the hidden patterns is rarely found. In this study, a hierarchical clustering algorithm (HCA) coupled with principal component analysis is used to analyze the steam flooding projects worldwide. The goal of this research is to group similar steam flooding projects into the same cluster so that valuable operational design experiences and production performance from the analogue cases can be referenced for decision-making. Besides, hidden patterns embedded in steam flooding applications can be revealed based on data characteristics of each cluster for different reservoir/fluid conditions. In this research, principal component analysis is applied to project original data to a new feature space, which finds two principal components to represent the eight reservoir/fluid parameters (8D) but still retain about 90% of the variance. HCA is implemented with the optimized design of five clusters, Euclidean distance, and Ward's linkage method. The results of the hierarchical clustering depict that each cluster detects a unique range of each property, and the analogue cases present that fields under similar reservoir/fluid conditions could share similar operational design and production performance.

The drive to mitigat water production continues to increase the interest in applying conformance-control gel treatments in mature oil fields. Practically, designs of new gel treatments are adopted from previous case histories conducted in analogous reservoirs. This design-by-analogy procedure requires reservoir engineers to have a thorough knowledge about how gel treatments should be designed and have been mostly applied for each reservoir type. This paper presents comprehensive design guidelines for sizes of injection-well gel treatments based on an integrated survey of worldwide field projects. It also provides the typical and most-applied treatment volumes per reservoir type to be used as a starting point in planning of new jobs. The survey includes 61 gel projects compiled from SPE papers and conducted in 11 different countries between 1985 and 2014. Summaries and distributions of five gel-volume parameters were evaluated using the univariate descriptive analysis and stacked histograms. Scatterplots were used to determine effects of the formation temperature and the treatment timing on treatment volumes. The unsuccessful pilots were compared with productive gel projects to indicate the causes of pilots’ failure. The survey showed that the typical treatment size is 10,700 barrels, 310 barrel per perforated foot, or 19% of the moveable-pore-volume (MPV) of problem zones. Overall, gel volumes are greatly affected by the formation type and larger treatment volumes are placed in sandstones than carbonates and in matrix-rock than other formation types. Frequently, matrix-rock formations are treated with gel volumes >100 bbl/ft while treatment sizes

Polymer rheology can have either a positive or a negative effect on polymer flooding performance under varied circumstances. Many researchers have studied the effect of polymer rheology in a vertical well, but no field scale studies have been conducted to investigate whether polymer rheology is beneficial to polymer flooding in heavy oil reservoirs developed by horizontal wells. In this paper, we conducted a numerical simulation study to examine the effect of HPAM polymer rheology on a polymer flooding pilot, which is the first-ever project conducted on a heavy oil reservoir from Alaska North Slope (ANS) developed by horizontal wells. Three rheology types were considered in the study including the apparent viscosity measured during coreflooding of using a HPAM polymer, the bulk viscosity measured with a viscometer, and a Newtonian flow model. The results suggest that using the bulk viscosity in simulation underestimates the conformance control and the water-oil-ratio reduction capability of the HPAM polymer solution. When the apparent viscosity is used, the incremental oil and sweep were largely increased, and the optimal recovery period of polymer flooding was extended greatly, especially for the heterogeneous formations. Therefore, the rheology type of polymer plays a significant role in the incremental oil recovery and injection profile of the horizontal well system given the pilot testconditions. This study has provided practical guidance to field operators for the ongoing polymer flooding pilot on ANS and will also provide valuable information for other polymer projects conducted in similar conditions.

Many unconventional clay-rich oil and gas reservoirs are characterized by fine-scale heterogeneity that is challenging to characterize and predict at larger scales. This is particularly problematic in emerging shale plays with limited shared knowledge such as the Tuscaloosa Marine Shale (TMS). The TMS is located within the Central U.S. Gulf Coast region and contains an estimated 7 billion barrels of potentially recoverable oil. In this study we synthesized and interpreted newly available mineralogical and organic geochemical data from 11 wells located in the currently producing area of the TMS. The data are extremely heterogeneous within individual wells, but generally suggest that the basal region of the TMS within the producing region is characterized by higher concentrations of calcite and TOC relative to other areas of the TMS. Data from an ∼18 m section near the base of the TMS (including samples from all 11 wells) averaged 1.65 wt% TOC, 22.8 wt% quartz, 17.2 wt% calcite, 16.2 wt% kaolinite, 14.1 wt% illite, 11.8 wt% smecite, 5.7 wt% chlorite, 3.9 wt% plagioclase, and 4.4 wt% pyrite. Kerogen in this region is a mixture of Type II and Type III and Tmax and vitrinite reflectance data suggest that samples from most wells are within the oil and wet gas generation window. Comparisons to previous investigations of the TMS show that most studies are in reasonable agreement only at the largest scales of observation and break down at smaller scales such that the concentrations of minerals and organic matter reported depend largely on the scale and locations of the investigation and the sampling density. Hence, the best approach for quantifying, describing, and ultimately predicting the heterogeneous physical and chemical properties within TMS may be to rely upon statistically-based comparisons of groups of data such that probability distributions of these groups can be generated that vary with the changing stratigraphy and depositional environments.

Enhanced oil recovery with nanometer-sized particles is an attractive topic in the industry because of the various advantages brought about by the size. Since nanoparticles have not been applied wi...

Carbon dioxide (CO2) flooding has been demonstrated as an economically feasible technique for carbon capture and storage (CCS) via enhanced oil recovery (EOR). In the oil industry, most of the CO2-EOR projects were implemented in miscible phase (CO2 miscible flooding), and it has become the most productive EOR method in the United States since 2012. Successful implementation of CO2 miscible flooding requires comprehensive guidelines about where CO2 can be applied. With the development of new technology, the suitable conditions for CO2-EOR have changed. Therefore, updating the guidelines for CO2-EOR is necessary. In this study, we updated the guidelines for field CO2 miscible applications in the United States by collecting valuable information from about 100 publications. Significant parameters for CO2 miscible flooding such as minimum miscibility pressure (MMP) and pay zone net thickness were considered for the first time in comparison with existing research studies. After data processing/cleaning, 207 projects have remained in the dataset. Combination plots were created to explore the ranges, distributions, and cumulative frequencies of each property. Meanwhile, descriptive values were calculated based on statistical methods. The guidelines for CO2 miscible flooding were presented with important parameters, including porosity, permeability, depth, reservoir temperature, net thickness, oil saturation, oil gravity, oil viscosity, and MMP. The analyzed results show that the reservoir pressure should be greater than 1020 psi to achieve miscibility, and CO2 miscible flooding project could be successfully applied in a reservoir with an oil gravity greater than 25 °API, oil viscosity less than 4 cp, and a reservoir temperature less than 120 °F.

Summary As life-span extenders, bulk gels have been widely applied to rejuvenate oil production from uneconomic producers in mature oil fields by improving the sweep efficiency of improved-oil-recovery (IOR)/enhanced-oil-recovery (EOR) floods. This paper presents a comprehensive review of the responses of injection-well gel treatments implemented between 1985 and 2014. The survey includes 61 field projects compiled from SPE papers and US Department of Energy reports. Seven parameters related to the oil-production response were evaluated according to the reservoir lithology, formation type, and recovery process, using univariate analysis and stacked histograms. The interquartile-range (IQR) method was used to detect the underperforming and overperforming gel projects. Scatterplots were used to identify the effects of the injected-gel volume and the treatment timing on the treatment response. Pretreatment water cut, recovery factor, and flood life were used as indicators for the treatment timing. Results indicated that gel treatments have very wide ranges of response for injection and production wells and for oil and water rates and profiles. When successfully applied, they, on average, respond after 3.5 months, increase the oil-production rate by 32%, and additionally recover 116,000 STBO per treatment, 15 STBO per gel barrel, or 10 STBO per polymer pound. We identified that gel treatments perform more efficiently in carbonate (CB) than in sandstone (SS) reservoirs and in naturally fractured (NF) formations than in other formation types. In addition, the incremental oil production considerably increases with the channeling strength and the injected-gel volume for all formation types, not just for the matrix-rock (MR) reservoirs. Moreover, gel treatments applied in NF formations have lower productivities in SS than in CB reservoirs using normalized performance parameters. Declining trends were identified for all parameters of the oil-production response with the treatment-timing indicators. The sooner the gel treatment is applied, the faster the response, and the larger the incremental oil production and its rate. It is recommended to allow longer evaluation times for gel treatments applied in MR formations because their response times might extend to several months. Gel treatments will perform more efficiently if they are conducted at water cuts of less than 70%, flood lives of fewer than 20 years, or recovery factors of less than 35%. For different application environments, the present review provides reservoir engineers with updated ideas regarding the low, typical, and high performances of gel treatments when successfully applied, as well as how other treatment aspects affect performance.

Controlling excessive water production in mature oil fields has always been one major objective of the oil and gas industry. This objective calls for planning of more effective water-control treatments with optimized designs to obtain more attractive outcomes. Unfortunately, planning such treatments still represents a dilemma for conformance experts due to the lack of systematic design tools in the industry. This paper proposes and makes available a new design approach for bulk gel treatments by grouping designs of 62 worldwide field projects (1985-2018) according to gel volume-concentration ratio (VCR). After compiling them from SPE papers, the average gel volumes and polymer concentrations in the field projects were used to evaluate the gel VCR. Distributions of field projects were examined according to the gel VCR and the formation type using stacked histograms. A comprehensive investigation was performed to indicate the grouping criterion and design types of gel treatments. Based on mean-per-group strategy, the average VCR was estimated for each channeling and formation type to build a three-parameter design approach. Two approximations for the average polymer concentration and two correlations for minimum and maximum designs and were identified and included in the approach. The study shows that the gel VCR is a superior design criterion for in-situ bulk gel treatments. Field applications tend to aggregate in three project groups of clear separating VCR cut-offs (3 bbl/ppm). The channeling type is the dividing or distributing criterion of the gel projects among the three project groups. We identified that VCRs3 bbl/ppm are performed to address matrix-channeling often shown in matrix-rock formations and fracture networks (design type III). Results show that the VCR approach reasonably predicts the gel volume and the polymer concentration in training (R2 of 0.93 and 0.67) and validation (AAPE

The wettability of carbonate rocks is often oil-wet or mixed wet. A large fraction of oil is still remained in carbonate reservoirs, it is therefore of particular significance to implement effective methods to improve oil recovery from carbonate reservoirs. Altering wettability from oil-wet to more favorable water-wet has been proven successful to achieve this goal. Surfactants are widely investigated and served as wettability modifiers in this process. Yet a comprehensive review of altering wettability of carbonate reservoirs with surfactants is ignored in literature. This study begins with illustration of wettability evolution process in carbonate reservoirs. Techniques to evaluate wettability alteration extent or to reveal behind mechanisms are also presented. Several surfactant systems are analyzed in terms of their wettability alteration mechanisms, influential factors of performance, applicable conditions, and limitations. Mixture of different types of surfactants could obtain synergic effects, where applicable conditions are extended, and final performance is improved. Gemini surfactants have many desirable properties, which warrants further investigation for understanding their wettability alteration mechanisms and performance. At the end, this review discusses strategies related with surfactant cost, surfactant adsorption, and challenges at high temperature, high salinity reservoirs conditions. Also, some unclear issues are discussed.

Polymer bulk gels have been widely applied to mitigate excessive water production from mature oil fields by correcting the reservoir permeability heterogeneity. This paper reviews water responses, effective times, and economic assessments of injection-well gel treatments based on 61 field projects. Eight parameters were evaluated per the reservoir type using the descriptive analysis, stacked histograms, and scatterplots. Results show that water production generally continues to increase after the treatment for undeveloped conformance problems. Contrarily, it typically decreases after the reactive gel treatments target developed conformance issues. For the developed problems, gel treatments do not always mitigate the water production where the water cut may stabilize or increase by 17% in 22% of instances. In addition, they often do reduce water production but not dramatically to really low levels where the water cut stays above 70% and reduces by only 10% in most cases. Gel treatments are economically appraised based only on the oil production response, and both water responses (injection and production) are not considered in the evaluation. They have a typical payout time of 9.2 months, cost of incremental oil barrel of 2 $/barrel, and effective time of 1.9 years. In addition, they have better water responses and economics in carbonates than in sandstones and in unconsolidated and naturally fractured reservoirs than in matrix-rock formations. The current review strongly warns reservoir engineers that gel treatments are not superior in alleviating the water production and candidates should be nominated based on this fact to achieve favorable economics and avoid treatment failures.

In traditional production environments, clay expansion in the near wellbore area may hinder drilling and completion operations. However, most of the above stabilizers cannot meet the actual requirement because the general clay stabilizer cannot migrate through small voids, and can also cause damage to the environment and be very expensive. Herein the behavior of nanoparticles in stabilizing clay particles and the condition for reducing the clay swelling and reservoir damage are investigated. The adsorption characteristics of nanoparticles on the core surface were studied by adsorption experiments and SEM. Displacement experiments of cores was conducted to discuss the migration behavior of nanoparticle inhibitors. In addition, the Malvern Zetasizer light reflectometer was employed to measure the electrokinetic potential of nanoparticles. To obtain a nanoparticle dispersion system, the dynamic dispersion measurement information of nanoparticle size distribution was collected. In the stability, by controlling the temperature, pH, pressure and other factors, the effects of these factors on the stability of the clay are investigated to obtain the mechanism of action of the nanoparticles. The core piece was immersed in 1g/L nano-liquid. After adsorption for a period of time, it was observed by SEM that the hydrophobic nanoparticles could form an adsorption layer on the core surface and show a strong hydrophobicity. The nano-electromotive potential is stable at +38.2mV and −36.0mV, indicating that the dispersion is very stable. The dynamic dispersion measurement surface size of nanoparticle dispersion is much smaller than the typical pore and pore channel size in most reservoirs. The microparticles are dispersed and injected through a filter device with a pore size of 200 nm and all of them are dispersed through the core. There is no residue in the filter device, thereby achieving effective migration in the core. It can be concluded that the adsorption effect is stronger under alkaline conditions when the adsorption amount is only reduced by 10% at 950 °C. This is not affected by the pressure factor and also the adsorption effect is stable. The action of mechanism between nano-silicone material and clay is obtained, and different factors are investigated to find out the prospect of nanoparticles in improving clay stability and reducing the reservoir damage.

Understanding the performance of the reservoir productivity in the post-stimulation conditions has recently gained an extensive emphasis from the specialist researchers and operators. Although there have been different tools used to evaluate the fracturing process and to predict the well performance, using production data as an indirect tool to calibrate the fracturing design and to forecast the reservoir performance has been considered the most potential technique. However, different methods with a high ambiguity have been used in this area of research over the last decade. Therefore; developing, screening, and specializing different methods and techniques to diagnose and evaluate the post-fracture reservoir performance by using flowback data has a significant priority. Determining the performance of hydraulic fractures from flowback data is considered the actual calibration to estimate the effective volume, length, height, conductivity, and width of hydraulic fractures. This paper presents a comprehensive review on most of the approaches, which have been recently introduced in this area of research, including their applicability, pros and cons. Furthermore, this study explains how each method can be valid at a specific time range. The potential tools, which could be more successful to be used in this direction of research, have been extensively discussed and recommended.

Surfactants have been the widely used agents to alter the wettability of carbonate rocks to more water-wet and enhanced oil recovery (EOR). As one of major EOR methods, an effective surfactant huff-puff application design requires comprehensive guidelines about where, how, and when this method could be applied. In order to construct such guidelines, a dataset including 338 effective surfactant imbibition tests is established by collecting information from nearly 50 publications. Based on this dataset, descriptive statistical analysis methods are used to conduct data analysis, including three main parts. The first part establishes the application guidelines for surfactant huff-puff treatments which displays suitable application ranges of critical parameters regarding rock, oil, and water. Results show that surfactants can be effectively applied in wide ranges: porosity from 3.1 to 51.7%, permeability from 0.04 to 1458 mD, starting oil saturation from 37.7 to 100%, temperature from 20 to 100 °C, average contact angle from 55 to 180°, oil gravity from 22 to 75.2 °API, oil viscosity from 0.3 to 23 cp, acid number from 0 to 4.5 mg KOH/g oil, base number from 0 to 1.83 mg KOH/g oil, asphaltene concentration from 0 to 10.7 wt%, salinity of connate water and imbibition water from 0 to 263.7 g/l, divalent cations concentration of connate water and imbibition water from 0 to 24.6 g/l. The second part discusses several aspects about design of surfactant huff-puff treatments. Results show that anionic, cationic, and nonionic surfactants have been applied in 83% of tests. Among them is cationic surfactants which have the most frequency. Surfactant concentration is suggested to be remained close or above a critical concentration to obtain the best performance. It is shown that 97% of tests are conducted with surfactant concentration less than 2.0 wt%. In addition, blends of different surfactants and usage of additives could enhance the effectiveness of surfactants. The last part evaluates the performance of surfactant imbibition tests. Results show that surfactants are capable to improve oil recovery either from secondary phase or tertiary phase. In general, the range of oil recovery from secondary phase and tertiary phase are similar, which covers from 1.0 to 93%. However, the average oil recovery from secondary phase is 39.1% which is higher than 32.2% from tertiary phase. Based on this, it is recommended that the treatment timing should be considered in the design of treatments.

Bakken is the most productive formation among unconventional plays in North America. This formation has about 7.4 billion barrels of recoverable oil. However, the primary oil recovery is still low as 5–10%. Miscible natural gas and carbon dioxide (CO2) might be the most two potential strategies to improve oil recovery in such a complex play. In this study, some of the IOR pilots which have been conducted in Montana, North Dakota, and South Saskatchewan have been presented. The performance results of these pilots in US-Bakken versus Canadian-Bakken have been compared. Moreover, the reasons behind the successful IOR pilots in Canadian-Bakken versus US-Bakken have been discussed. Then, numerical simulation models have been constructed to mimic the results of some pilots. Two different compositional models have been built for oils of two different formations. Furthermore, two different models, single porosity model and dual permeability model have been created to match the performance of some pilots. Implementation of molecular diffusion mechanism has been conducted in both of single porosity and dual permeability model. Finally, the continuous miscible gases injection versus huff-n-puff protocols have been compared and investigated. The results showed that the performance of natural gases generally over-performed the CO2 injection technique's in Bakken formation. Although the diffusion flow is dominant in these types of reservoirs, the diffusivity of the injected CO2 into formation oil is slow due to the fact that CO2 has large molecules as compared with the small pore throats of these porous media. Accordingly, miscible CO2-EOR might not be beneficial in huff-n-puff operations as in continuous flooding process. However, the success of natural gases based EOR does not have that strong functionality of molar diffusivity. Therefore, their performance was much better than CO2 performance in the field scale of these tight formations. Furthermore, the numerical simulation of this study concluded that the spacing between the production wells and injection wells should be minimized, for the continuous flooding process of miscible-gases EOR, to enhance their performance. Although the permeability of Canadian-Bakken has a permeability of 1–2 order higher than the permeability of US-Bakken, the pilots' spacing between injectors and producers in Canadian Bakken is interestingly much shorter than that for US-Bakken, which might be the reason behind the EOR success in Canadian Bakken. Finally, the activatiown process of the highly intensive natural fractures might be the key to enhance the diffusivity of CO2-EOR. Otherwise, natural gases are highly recommended to be the most potential EOR in these types of reservoirs. This study explains how the diffusion mechanism affects the performance of different miscible gases to improve oil recovery in these plays since they are more complex and very different from conventional formations. Also, it suggests that CO2 flooding process would be a good practice to overcome the limitations of CO2-diffusion rate in these reservoirs if the conformance problems are wisely controlled.

Summary Fractures and oil-wet conditions significantly limit oil recovery in carbonate reservoirs. Gel treatment has been applied in injector wells to modify the prevailing reservoir streamlines and significantly reduce fracture permeability, whereas low-salinity waterflooding has been applied experimentally to modify rock wettability toward water-wet for improved oil recovery. However, both processes have limitations that cannot be resolved using a single method. The objective of this study was to test whether low-salinity water could enable gel particles to move deeply into fractures to efficiently increase oil recovery and control water production. A semitransparent fracture model of carbonate cores and acrylic plates was built to study the effect of low-salinity waterflooding, fracture width, gel-injection volume, and fracture uniformity on oil recovery and to redirect the flow path to unswept zones. Preformed partial gel (PPG) and brine movements were visible through the model's transparent acrylic plate. Seawater was used for brine flooding and to prepare swollen particles; the seawater was diluted 100 times to create low-salinity water. A light crude oil was used, with 10-cp viscosity. Low-salinity water was injected after gel placement to test the gel-plugging efficiency. The results showed that the low-salinity water could improve gel propagation into the fracture and increase oil recovery because the gel strength (apparent viscosity) decreased as the brine concentration decreased. The gel-injection volume had a significant effect on the oil-recovery factor when seawater flooding followed the gel-injection process, although there was less of an effect when the gel was followed by low-salinity waterflooding. Moreover, the effect of low-salinity waterflooding on gel propagation decreased as the fracture width decreased. In addition, the resulting fracture uniformity illustrates a viable effect of the in-depth water-diversion treatment.

Improved Oil Recovery (IOR) techniques in Unconventional Liquids Rich Reservoirs (ULR) are still a new concept because there is no commercial project for any IOR technique so far. Carbon dioxide (CO2) based EOR technique has been effectively applied to improve oil recovery in the tight formations of conventional reservoirs. Extending this approach to unconventional formations has been extensively investigated over the last decade because CO2 has unique properties which make it the first option of EOR methods to be tried. However, the applications and mechanisms for CO2-EOR in unconventional reservoirs would not necessarily be the same as in conventional reservoirs due to the complex and poor-quality properties of these plays. Since the first CO2-EOR huff-n-puff project was conducted in conventional reservoirs in Trinidad and Tobago in 1984, more than 130 additional projects have been put in operation around the world, mainly located in USA, Turkey, and Trinidad and Tobago. In this study, we combined Production Data Analysis (PDA) for the production data of these projects with numerical simulation methods to produce one typical graph accounts for the main mechanisms controlling CO2-EOR performance in conventional reservoirs. On the other hand, we have couple of CO2-EOR huff-n-puff pilot tests conducted in Bakken formation between 2008 and 2016. Two engineering-reversed approaches have been integrated to produce a unique type curve for the performance of CO2-EOR huff-n-puff process in shale oil reservoirs. Firstly, a numerical simulation study was conducted to upscale the reported experimental-studies outcomes to the field conditions. As a result, different forward diagnostic plots have been generated from different combinations for CO2 physical mechanisms with different shale-reservoirs conditions. Secondly, different backward diagnostic plots have been produced from the history match with CO2 performances in fields’ pilots performed in some portions of Bakken formation located in North Dakota and Montana. Finally, fitting the backward with the forward diagnostic plots was used to produce another unique type curve to represent CO2-EOR performance in shale oil reservoirs. This study found that the delayed response in the incremental oil production resulted from CO2 injection in shale reservoirs is mainly function of CO2 molecular diffusion mechanism. On the other hand, the CO2 diffusion mechanism has approximately no effect on CO2-EOR performance in conventional reservoirs which have a quick response to CO2 injection. This finding is very well consistent with the experimental reports regarding the role of diffusion in conventional cores versus shale cores. In addition, this study found that kinetics of oil recovery process in productive areas and CO2-diffusivity level are the keys to perform a successful CO2-EOR project in shale formations. This paper provides a thorough idea about how CO2-EOR performance is different in the field scale of conventional reservoirs versus shale formations.

The recovery from fractured reservoirs is usually low. The areal heterogeneity is one result of the fractured reservoir. Low salinity waterflooding (LSWF) and preformed particle gel (PPG) have recently drawn great interest from the oil industry. LSWF can only increase displacement efficiency, and it has little or no effect on sweep efficiency whereas PPG can plug fractures and improve sweep efficiency, but they have little effect on displacement efficiency. The coupled method bypasses the limitations of each method when used individually and improves both displacement and sweep efficiency. The main objective of this study was to determine whether the combining technologies can improve conformance control in fractured sandstone reservoirs. Before the study was conducted, the effects of low salinity waterflooding, number of fractures, and PPG strength were studied. The PPG was injected into the fracture at a flow rate 2.0 ml/min. Brine was injected at a different flow rate after PPG placement to test the effect of flow rate on the PPG’s plugging efficiency. Laboratory experiments showed that the oil recovery factor and the Frrw increased when the concentration of injected brine changed from conventional salinity to low salinity and the areal sweep efficiency was improved. However, the PPG extruded pressure decreased when the PPG swelled in a low-brine concentration. At a high-flow rate, there was no significant effect on the Frrw. Combining two different EOR technologies can improve displacement and sweep efficiency and, in turn, enhance conformance control.

The oil recovery from fractured reservoirs is usually low, which is usually caused by the existence of areal formation heterogeneity. Two existing enhanced oil recovery (EOR) technologies, low salinity water flooding (LSWF) and preformed particle gel treatment (PPG), have recently drawn great interest from the oil industry. We integrated both of these technologies into one process to improve both oil displacement and areal sweep efficiency. The objective of this study was to test how the integrated method could be used effectively to increase oil recovery and control water production. The semi-transparent five-spot models, which were made of sandstone cores and acrylic plates, were built. We investigated the effect of four parameters on the improvement of oil recovery and areal sweep efficiency of oil, including gel strength, water salinity, injection rate, and number of fractures. Two approaches were followed during core flooding, sequential mode and mixed mode. The result shows that PPG and LSW injected together as one mixture improved oil recovery factor more than the first approach. PPGs plugged the fractures and successfully improved areal sweep efficiency; however, they have little effect on displacement efficiency. LWSF increased displacement efficiency but had little or no effect on sweep efficiency. The integrated methods bypassed the limitations of each method when used individually and improved both displacement and sweep efficiency.

Due to shortage of conventional resources, tight/shale oil/gas reservoirs have become increasingly important in balancing the energy consumption in China. As the most important shale reservoirs in China, marine Silurian shales in the Sichuan Basin have received intensive investigation during recent years in the area of pore structure characterization and reserve assessment. However, no work has been conducted to compare the China shale plays with other mature shale plays in the North America using multiple experimental methods based on the mineralogy analysis and organic geochemistry. In this paper, pore structure, formation porosity, total organic carbon (TOC), thermal maturity, and mineralogy of 36 samples in Longmaxi shale and 7 samples in Qiongzhusi shale have been investigated using multiple experimental methods. FIB-SEM imaging results show that Longmaxi shale gas reservoir include primary pores, residual intergranular pores, dissolution pores, and intergranular pores. The majority of the pores are distributed in residual intergranular pores, secondary dissolution pores, and intercrystalline pores, but less in primary intergranular pores. X-ray diffraction analysis shows that the clay minerals of Longmaxi shale reservoir mainly consist of illite and kaolinite, then followed by chlorite. The content of kaolinite is from 7.2% to 16.87%, and the average is 12.21%. The content of illite is from 8.03% to 26.8%, with the average of 16.1%. TOC tests show that most of the samples have their TOC more than 0.5%, which means Longmaxi formation has a potential to produce shale gas. Clay minerals mainly include quartz, K-feldspar, calcite, dolomite, anorthose, and pyrite. The quartz has the highest content value, followed by calcite, which are 29% and 22% average respectively. The content of pyrite and anorthose are less than 10%. The average content of brittle minerals of Longmaxi formation samples is 66% (>50%), which is suitable for hydraulic fracturing. Thermal maturity tests show that Vitrinite reflectance of each sample is more than 2.0%, which indicates that it is high enough to generate shale gas in the formation. Comparing with other mature shale plays, the Longmaxi and Qiongzhusi shale plays have lower porosity and lower TOC than that of the U.S. shale plays, and the quartz content and thermal maturity are similar. The Qiongzhusi shale and Longmaxi shale are over-mature (Ro>2.5%) compared with U.S. shale plays. The results of this study will contribute to the formation characteristics understanding and reserve assessment of China shale plays. Also, it will facilitate the development of suitable and efficient production plan for China shale plays.

The effect of composition of welding wires on the interfacial microstructure and the bonding strength of Babbitt alloys and steel substrate has been studied. A cladding of Sn-based Babbitt alloys w...

Modified waterflooding is a process in which the ionic composition of injected water is altered to improve oil recovery. Recently, extensive studies on crude oil, brine, and rock systems reported that the composition of injected water can change rock wettability during waterflooding. Carbonate reservoirs are mixed or oil wet reservoirs and most of these reservoirs are fractured, resulting in low oil recovery. In the last decade, many researchers conducted laboratory experiments to evaluate gel treatment in fractured models. The objective of this study is to examine the effects of sulfate ion concentration and low salinity water (diluted seawater) on improving oil recovery in fractured and nonfractured reservoirs when combined with microgel treatment. Four key parameters were examined: increased sulfate ion concentration, a degree of seawater dilution, fracture width, and matrix permeability. Three models were designed and tested in this work: nonfracture, fully-open fracture, and partially-open fracture model. Three different sulfate ion concentrations (typical seawater and that which was doubled and then tripled in sulfate ion concentration) and low salinity water that had been diluted 10 and 100 times were applied as waterflooding processes in two fracture widths (0.5 mm and 1 mm) with two different matrix permeabilities (20 md and 2.44 md). Microgel (425 μm in size) was swollen in typical seawater and injected in the fractured model to block the fractures and divert the brine into the matrix. The results show that increased sulfate ion concentration and diluted seawater can improve oil recovery by changing core wettability towards water-wet conditions. We also found that diluted seawater can improve both displacement and sweep efficiency while increased sulfate ion concentration only improves displacement efficiency when applied after gel treatment in both fully open fractures and partially open fractures. Therefore, diluted seawater can improve plugging efficiency but sulfate ions cannot. Increased sulfate ion concentration followed by diluted sea water with microgel-filled fractures might be a viable technique to improve oil recovery in fractured carbonate reservoir. The sulfate ion concentration effects decrease as fracture width increases and matrix permeability decreases. Also, the diluted seawater effects decrease as matrix permeability decreases. Combining microgel with sulfate ion concentration results in higher oil recovery than combining microgel with low salinity water in fully open fracture. However, combining microgel with low salinity water showed highest oil recovery in partially open fracture.

Unconventional resources have played a significant role in changing oil industry plans recently. Shale formations in North America such as Bakken, Niobrara, and Eagle Ford have huge oil in place, 100–900 Billion barrels of recoverable oil in Bakken only. However, the primary oil recovery is still low as 5–10%. EOR methods are currently considered as a new concept in unconventional reservoirs due to the immature information about these plays. Injecting carbon dioxide (CO2) might be the most potential strategy to improve oil recovery in such complex plays (Alfarge et al., 2017a,b). Jin et al. (2016) conducted an experimental study to investigate improving oil recovery by CO2 injection in 21 natural preserved core samples from Bakken Petroleum System (BPS). Their experimental results indicated that CO2 injection has a significant potential to improve oil transportability in these Nano-pores formations. In this study, data analysis for feasibility of CO2-EOR has been conducted on 95 cases of natural preserved cores collected from different formations including 44 cases from Middle Bakken, 26 cases from Lower Bakken, 17 from Upper Bakken, 4 cases from Three Forks, and 4 cases from unknown formation/formations. The relationship between the improved oil recovery by the injected CO2 and 6 rock properties including porosity, permeability, mean pore throat radius, total organic carbon content (TOC), water saturation, and oil saturation has been separately determined and physically discussed. Furthermore, the relationships between the improved oil recovery obtained by the injected CO2 and 4 operating parameters including CO2 bath pressure, CO2 bath temperature, and core sample bulk size, and exposing time have been also separately investigated. A Proxy model to associate the functionality of the improved oil recovery by CO2 injection and these 10 parameters have been constructed. Moreover, statistical methods for Design of Experiments (DOE) have been used to rank the most important parameters affecting CO2-EOR performance in the microscale level (lab scale) of these unconventional reservoirs. This study provides an important set of lab-based data obtained from natural preserved cores to find out the applicability of CO2-EOR in these unconventional reservoirs. Also, this research demonstrates some key points which could help in understanding CO2-EOR mechanisms in shale plays since they are much complex and very different from conventional formations.