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The Jiyuan oil field is a tight sandstone reservoir, and water injection does not effectively enhance the oil recovery. The microscopic seepage characteristics of water flooding are studied...

During the development of oilfields, casings in long-term service tend to be damaged to different degrees, leading to poor development of the oilfields, ineffective water circulation, and wasted water resources. In this paper, we propose a data-based method for predicting casing failure risk at both well and well-layer granularity and illustrate the application of the method to GX Block in an eastern oilfield of China. We first quantify the main control factors of casing damage by adopting the F-test and mutual information, such as that of the completion days, oil rate, and wall thickness. We then select the top 30 factors to construct the probability prediction model separately using seven algorithms, namely the decision tree, random forest, AdaBoost, gradient boosting decision tree, XGBoost, LightGBM, and backpropagation neural network algorithms. In terms of five evaluation indicators, namely the accuracy, precision, recall, F1-score, and area under the curve, we find that the LightGBM algorithm yields the best results at both granularities. The accuracy of the prediction model based on the preferred algorithm reaches 87.29% and 92.45% at well and well-layer granularity, respectively.

Non-dominated sorting genetic algorithm, second version (NSGA-II) is used as a stochastic optimization technique successfully in different engineering applications. In this study, a data-driven optimization strategy based upon evolutionary neural network (EvoNN) algorithm is developed for providing input into NSGA-II optimization. Evolutionary neural network data-driven model is built and trained using initial solutions generated by NSGA-II optimization coupled with the reservoir simulation model. Evolutionary optimization incorporated in the EvoNN strategy is applied in the trained data-driven model to generate the Pareto optimal solution, which is then used as a guiding input into NSGA-II optimization. The described method is applied in two case studies (i.e., Brugge field model and water injection pattern model). The Pareto optimal solutions obtained with data-driven model guided NSGA-II in both models show improvement in convergence and diversity of the solution. The convergence to the Pareto optimal solution has improved by 9% for case-1 (i.e., Brugge field) and by 43% for case-2 (i.e., water injection pattern model). In addition, the Pareto optimal solution obtained by the proposed hybridization has shown improvement in the water–oil ratio (WOR) up to 6% in the Brugge field and up to 97% in the water injection pattern model. This improvement can lead to wide applications in using evolutionary optimizations in real-field simulation models at acceptable computation time.

For more than 60 years of primary production, the Fang oilfield has less oil recovery. The production can be upgraded more with the water flooding and enhanced oil recovery (EOR) methods. However, in this area, the suitable technologies have not been studied for commercial production yet. SiO2 nanoparticle is another pattern of chemical EOR (CEOR) to reduce the limitation of traditional CEOR techniques. The utilization of nanotechnology can provide the potential for producing more petroleum. Therefore, the aim of this study is to evaluate ability of nanosilica flooding in Fang oilfield and compare oil production with the conventional water flooding and natural flow by using simulation results with ECLIPSE. Also, the more parameters like injection rate and injection period have been studied. The results show that nanosilica can provide the highest recovery compared to both conventional techniques. Besides, the injection rates at 159 m3/day gives the highest oil production for 35.2%. For the injection period of nano-fluid, at low-injection rate, the result of different injection period is insignificant. But for higher injection rate, the difference in injection period can be observed with less than 1% difference. Therefore, the shorter injection period can be the better choice for field development for the future production. Moreover, this study can be used as a reference for the SiO2 nanoparticle application in this oilfield in future.

Chemical-induced oil recovery has the potential to recover trapped oil, which is not possible to obtain by primary pressure difference and secondary water flooding methods. However, the implementation of chemical-enhanced oil recovery schemes requires a deeper understanding of the process for its successful implementation. The comprehension of mechanisms such as interfacial tension, emulsification, displacement efficiency, mobility ratio and wettability alteration can severely reduce the complexities involved in the system. Therefore, the roles of different mechanisms involved and their impacts on crude oil recovery, screening criteria for chemicals like alkali, surfactant, polymer or their combination depending on crude oil and heterogeneous reservoir properties are developed. Alkali–surfactant–polymer (ASP) flooding due to their synergistic effect offers a huge potential to recover residual oil. The understanding of the system or process is essential for the formulation of an optimum ASP slug that can maximize oil recovery. In this chapter, the overall screening criteria necessary for ASP flooding are formulated and discussed. The recovery of residual oil by ASP flooding in laboratories, pilot or commercial field scale in different parts of the world is summarized.

The main technology used to optimize field development is hydrodynamic modeling, which is very costly in terms of computing resources and expert time to configure the model. And in the case of brownfields, the complexity increases exponentially. The paper describes the stages of developing a hybrid geological-physical-mathematical proxy model using machine learning methods, which allows performing multivariate calculations and predicting production including various injection well operating regimes. Based on the calculations, we search for the optimal ratio of injection volume distribution to injection wells under given infrastructural constraints. The approach implemented in this work takes into account many factors (some features of the geological structure, history of field development, mutual influence of wells, etc.) and can offer optimal options for distribution of injection volumes of injection wells without performing full-scale or sector hydrodynamic simulation. To predict production, we use machine learning methods (based on decision trees and neural networks) and methods for optimizing the target functions. As a result of this research, a unified algorithm for data verification and preprocessing has been developed for feature extraction tasks and the use of deep machine learning models as input data. Various machine learning algorithms were tested and it was determined that the highest prediction accuracy is achieved by building machine learning models based on Temporal Convolutional Networks (TCN) and gradient boosting. Developed and tested an algorithm for finding the optimal allocation of injection volumes, taking into account the existing infrastructure constraints. Different optimization algorithms are tested. It is determined that the choice and setting of boundary conditions is critical for optimization algorithms in this problem. An integrated approach was tested on terrigenous formations of the West Siberian field, where the developed algorithm showed effectiveness.

As is known, fractured reservoirs compared to conventional reservoirs have such features as complex pore volume structure, high heterogeneity of the porosity and permeability properties etc. Apart from this, the productivity of a specific well is defined above all by the number of natural fractures penetrated by the wellbore and their properties. Development of fractured reservoirs is associated with a number of issues, one of which is related to uneven and accelerated water flooding due to water breakthrough through fractures to the wellbores, for this reason it becomes difficult to forecast the well performance. Under conditions of lack of information on the reservoir structure and aquifer activity, the 3D digital models of the field generated using the hydrodynamic simulators may feature insufficient predictive capability. However, forecasting of breakthroughs is important in terms of generating reliable HC and water production profiles and decision-making on reservoir management and field facilities for produced water treatment. Identification of possible sources of water flooding and planning of individual parameters of production well operation for the purpose of extending the water-free operation period play significant role in the development of these reservoirs. The purpose of this study is to describe the results of the hydrochemical monitoring to forecast the water flooding of the wells that penetrated a fractured reservoir on the example of a gas condensate field in Bolivia. The study contains data on the field development status and associated difficulties and uncertainties. The initial data were results of monthly analyses of the produced water and the water-gas ratio dynamics that were analyzed and compared to the data on the analogue fields. The data analysis demonstrated that first signs of water flooding for the wells of the field under study may be diagnosed through the monitoring of the produced water mineralization - the water-gas ratio (WGR) increase is preceded by the mineralization increase that may be observed approximately a month earlier. However, the data on the analogue fields shows that this period may be longer – from few months to two years. Thus, the hydrochemical method within integrated monitoring of development of a field with a fractured reservoir could be one of the efficient methods to timely adjust the well operation parameters and may extend the water-free period of its operation.

Fractured-vuggy reservoir is significantly different from porous reservoirs. Ordovician reservoir in T Oilfield in China is the largest FVCR around the world. Water flooding has been applied as a prospective method in more than 140 units, but water channeling is especially serious and the recovery is only about 15%. In such reservoir, cavities and fractures are the main storage spaces and flow channels, respectively. Because the fractures and cavities are spatially non-stratified and discretized, the waterflood pattern differs significantly from that in sandstone or porous carbonate reservoirs. It is very essential to construct a spatial well pattern to match the distribution and connectivity of fractures and cavities, which is a very popular topic in recent years. In this work, we presented a multistage construction method of spatial well pattern combining reservoir engineering with numerical simulation methods. Firstly, the economic concepts of Lorenz curve and Gini coefficient were introduced to choose the injector from all wells to achieve equilibrium displacement of injected water in the plane. Secondly, displacement and drainage equilibrium index (DDEI) was presented to determine the vertical location of the injector to achieve equilibrium displacement and drainage in vertical direction. Thirdly, the vertical locations of the producers were determined based on the distribution of reserves in vertical direction. Fourthly, the local producers were further optimized based on the cavities along the wellbore by numerical simulation. Finally, this method was successfully used to construct the spatial well patterns of fractured-vuggy units with different karst features in A unit of T Oilfield. The results show that the oil recovery factor is inversely proportional to the Gini coefficient calculated with the combined variable of flow resistance and crude reserve rather than that calculated with flow resistance in pore reservoirs. The ratio of the reserve to formation factor, V/(kh), can be used to determine the vertical location of the injector. And the optimal DDEI which is the ratio of V/(kh) in upper reservoir of the wellbore to that in lower reservoir of the wellbore is equal to 1. The vertical locations of producers are related to the vertical distributions of reserve and cavities in different karst units. At last, the principles of constructing spatial well pattern in fractured-vuggy carbonate reservoirs were proposed. This work provides an innovative and effective method to establish a spatial well pattern for FVCRs, which will break new ground for efficient development of FVCRs by water flooding.

Preformed particle gels (PPGs), a type of hydrogel, have been widely applied to control the conformance of reservoirs owing to their robust gel chemistries. Traditional PPGs are polyacrylamide-based hydrogel compositions which can withstand neither higher temperatures nor high salinity conditions. There are many deep oilfield reservoirs worldwide which demand PPG products with a long term hydrolytic and thermal stability at the temperatures of higher than 120 °C. Current PPGs neither remain hydrated nor retain polymer integrity at these temperatures. A unique high temperature-resistant hydrogel composition (HT-PPG) was developed with exceptional thermal stability for greater than 18 months in North Sea formation temperature (~130 °C) and formation water environments. HT-PPG described herein can swell up to 30 times its initial volume in brines of different salinity for North Sea. The effects of salinity and temperature on swelling, swelling rate, and rheological behavior was studied. These HT-PPGs exhibit excellent strength with storage modulus (G’) of over 3,000 Pa at the swelling ratio of 10. Thermostability evaluations were performed in North Sea brines with variable salinity at temperatures of 130 °C and 150 °C and found to be stable for 18 months with no loss of molecular integrity at the higher temperature. Laboratory core flooding tests were conducted to test its plugging efficiency to fracture. HT-PPGs showed good plugging efficiency by reducing the permeability of open fracture and did not wash out during waterflooding. Overall, HT-PPG is a novel product with excellent hydrothermal stability that make it an ideal candidate for conformance problems associated with reservoirs of high temperature and salinity conditions.

The classification of water flooding severity is crucial for planning reservoir production and improving the recovery ratio. In this paper, we study a siliciclastic heavy oil reservoir in Bohai Bay, with resistivity reading close to, or even lower than the wet zone (3~5Ω.m). In this environment, computing original reservoir Sw using Traditional hydrocarbon saturation equation is challenging. As a result, the displacement efficiency of a water drive cannot be accurately determined. In order to properly evaluate displacement efficiency, we must estimate initial reservoir Sw (Swirr) and the modern day Sw. Sw can typically be estimated from NMR data with a proper T2 time cutoff. However, in heavy oil reservoirs, the relaxation times of oil and capillary bound water overlap, leading to an over-estimation of Sw. We propose to compensate for the heavy oil effect by adjusting the cutoff until NMR Sw matches the Sw from core Mercury Injection for Capillary Pressure (MICP). As oilfield development proceeds, water displaces some oil in the pore space. Since the injected water has higher salinity than reservoir water, formation resistivity (Rw) becomes lower. Based on the material balance theory, the variable multiple water injection material balance equation is established, and the equation set is established by combining the material balance equation with the Simandoux equation and the calculation formula of mixed water resistivity (Rwz). According to the rock electricity experiment under different salinity, the dynamic rock electricity parameters are used in the Simandoux equation, and the mixed water resistivity and modern day Sw after water flooding are solved iteratively under the original SW constraint. The displacement efficiency is calculated as the difference between Sw and modern day Sw. The proposed method was applied to 10 wells and improved the Sw accuracy by 5%-15%. The continuous solution Rw from our method matches Rw measured in the lab. The calculated displacement efficiency is compared with actual production history and the accuracy improved from 68% to 80%.

The methodology examined for this study was based on statistical analyses and GIS computations of frequent inland water flooding areas in Tangerang city, Indonesia during 2008–2015. Primary data used for this study were inland water flooding records from Tangerang city government and an approximately 90 m Merit DEM. We extracted the topographical characteristics of frequent inland water flooding areas and used principal component analysis to find its main characteristics. Results show that frequent inland water flooding areas in Tangerang emerged because of a slope in the upstream condition, the correlation between concave and flow length conditions, correlation of the slope condition and distance to a river, and relations among flow length in upstream characteristics and distance to a pond. Furthermore, a principal component score of frequent inland water flooding areas and other areas in the city was compared with measure similarity. This method correctly identified 71% of frequent inland water flooding areas. Also, 74% of one-time inland water flooding areas were classified as locations with high topographical similarity. Furthermore, field surveys indicated that the remaining 29% of frequent inland water flooding areas had low topographical similarity because of anthropogenic factors.

Characterization of the rock and fluids is an essential step in screening a reservoir for Low-Salinity Water Flooding (LSWF). A detailed characterization of rock and fluid properties using appropriate methods is being presented for LSWF in a low-permeability deep carbonate reservoir together with a critical analysis of findings. The techniques used are assessed against other possible alternative methods, with inferences drawn on advantages and disadvantages of each to better interpret and apply data so gathered. In so doing, discussions on their key features as to how they can be used effectively and efficiently to screen a reservoir for LSWF are also provided. Such integration of results with other available reservoir and production data should result in a comprehensive description of the target reservoir, and it will help interpret the mechanisms and process dynamics more reliably during a low-salinity waterflood. This integration should allow us not only to gain confidence on the experimental studies but could also help optimize the key parameters responsible for formulating a more robust, reliable and representative regime for tests relevant to the LSWF prior to its eventual implementation in the field. To authors’ knowledge, such integration of experimental studies has not yet been reported in the literature, particularly for the tight carbonate reservoirs with highly paraffinic oil.

The need for energy, especially the petroleum-based one, is steadily increasing along with population growth and technological advancement. Meanwhile, oil exploitation from oil reservoirs using primary and secondary techniques can only obtain about 30%-50 % out of the original oil in place. Enhanced Oil Recovery (EOR) is a method for increasing oil recovery from a reservoir by injecting materials that are not found in the reservoir, such as surfactant, polymer, etc. This research aims to develop a mathematical model representing two-phase flow through porous media in the EOR process. This model was extended from mass balance and fluid flow in porous media equations. The reliability of the model was then validated by water flooding and polymer flooding experiment. A porous media, constituted by a silica sand pack, was saturated with 2 % brine and sequentially flooded with HPAM polymer solution at various concentrations (5,000-15,000 ppm). The volume of the oil coming out from the media at any time intervals was measured. Validation of the model was carried out by optimizing the model parameters to obtain the best curve-fitting on the plot of the percentage of cumulative recovered oil against time. The results showed that the proposed mathematical model was reliable enough to express both water and polymer-flooding processes.

Due to long-term water-flooding, thief zones have been formed in the Donghe sandstone reservoir in the Hade Oilfield, resulting in an inefficient water flooding cycle. The genetic mechanism and level of thief zones are defined based on the fine reservoir description using core data and dynamic data. For original reservoirs with large pore throats (generally larger than 5 μm), as the porosity and permeability rapidly increase with water injection, it is likely to form thief zones. And thief zones prone to form in the area where the interlayer flow barrier formed with horizontal occurrence. Based on the analysis of sedimentary facies, pore structure, flow barrier, production injection ratio, and water content, classification criteria for the thief zones are carried out. The location and characteristics of the severe, potential, and rudimentary thief zones were determined. The results indicate that the thief zones are primarily distributed in layers 1 and 2 and are mainly distributed in the central region. Verification using tracer data indicates that the coincidence rate is 95%, which proves the accuracy of thief zone identification and prediction. This work adds value aiding in the characterization and evaluation of the hydrocarbon reservoir. It provides a basis for oil production in the Hade Oilfield and may be potentially applicable to other regions to increase the hydrocarbon production.

Carbon corrosion in catalysts is one of the main limitations of proton exchange membrane fuel cell (PEMFC) lifetime. Water flooding can accelerate the carbon corrosion rate in PEMFCs, especially at high current densities. Increasing the operation temperature can effectively mitigate water flooding and improve the water management performance of PEMFCs. However, elevated temperatures also increase the carbon corrosion reaction kinetics, accelerating the degradation of PEMFCs lifetime. To study the effects of temperature on carbon corrosion at high current densities, PEMFCs operating for 100 h at 65 °C and 90 °C under 1600 mA·cm−2 were investigated. The results showed that the electrochemical active surface area (ECSA) of the cathode catalyst layer decreased by 9.16% and 13.92% at 65 °C and 90 °C, respectively. The reduction rate of the catalyst layer in the nonflooding area increased as the operating temperature increased. However, the reduction rate decreased by 69.82% and 54.04% at 65 °C and 90 °C, respectively, at the outlet of the PEMFC. Therefore, water flooding is the key issue causing lifetime degradation, and water management is essential for PEMFCs that operate at high current densities, especially at the outlet of PEMFCs.

Low-salinity water flooding (LSWF) is environment-friendly and operates similarly to conventional waterflooding without the need for synthetic chemical materials. The application of LSWF makes sense in Vietnam as HC production has steadily declined since 2002, and the majority of main oil fields have become near mature and mature fields. In the next years, Enhanced Oil Recovery (EOR) should be a top priority for Petro Vietnam to boost its oil production, for which the key issue is how to select a suitable EOR technology. In this study, LSWF of the Lower Miocene sand using low salinity water from Lower Oligocene sand was investigated. Previously at the Ruby field in the Cuu Long Basin, an LSWF feasibility study was carried out based on a conventional core flooding experiment, which is time-consuming and costly. This study targets the Chim Sao field in the Nam Con Son Basin, for which a cheaper and faster assessing method is required. As a result, a numerical code written in Matlab was developed and successfully validated with the core flooding experiment results obtained at the Ruby field. The LSWF simulation was conducted using the multiple ion-exchange mechanisms (MIE), and the results obtained showed an increase in the oil recovery factor by 2.19% for the Lower Miocene Sand. Another important outcome of this study is the innovative proposal and successful simulation to use the abundant low salinity water from the underlying Lower Oligocene sand as a natural LSW source to inject into the Lower Miocene oil reservoir that can be a decisive factor to help apply LSWF in practice on a wide scale not only for Chim Sao but also other similar oil fields in southern offshore Vietnam.

Spontaneous imbibition and displacement are important mechanisms in water flooding. This paper is aimed to evaluate the performance of water imbibition and injection in tight sandstone oil reservoir. Imbibition tests were first done to assess potential contributions to displacement and oil recovery. Then, a subsequent water injection at constant pressure was conducted in cores with permeability less than 0.1 mD and larger than 0.1 mD to explore the extent to which oil can be displaced and to evaluate fluid flow behavior. Finally, water injection at constant velocity was implemented to simulate displacement under reservoir condition and to analyze flow characters during injection. Results showed that water imbibition enhanced recovery more significant in cores with permeability less than 0.1 mD than that in cores with permeability larger than 0.1 mD. The recovery obtained was 19.2–26.7% and 6.7–7.6%, respectively. The subsequent water injection at constant pressure enhanced recovery further from 6.7–7.6% to 35.2–37.7% in cores with permeability larger than 0.1 mD. However, it did not make sense in cores with permeability less than 0.1 mD. There were a narrow area for oil/water co-flow and a sharp decrease in oil permeability at the initial stage. Meanwhile, the recovery during water injection at constant velocity was 57.7% and 42.9%, respectively. It presented high injection pressure in the upstream, and the quasi-threshold pressure gradient reached 80–200 MPa/m, which was hard to implement in reservoir. The injection pressure increased with the decrease in permeability. It also reveals that dominant channels exist and may lead to early water breakthrough which is negative for recovery enhancement.

Microbial contamination is well known in the oil and gas industry and it occurs in most processes where water processing systems are involved. Microorganisms are spread everywhere, even in the subsurface, where operations of oil exploration and production are developed. For this reason, different genera of microorganisms can affect the Oil & Gas Industry. One of the major problems in oil mature fields undergoing secondary recovery is the contamination with sulfate reducing bacteria (SRB), caused generally by the injection water system (fresh and/or production) and/or of the reservoir (natural or by drilling fluids, completion, stimulation, etc.). This problem causes formation damage and microbiological induced corrosion (MIC) in the injection-production system. In many producing wells, formation damage by microbiological contamination is initially masked by a decline in reservoir pressure; however, initial production of H2S does provide a possible microbial contamination of water production, water injection and eventually petroleum reservoir. In some producing wells, H2S concentrations have exceeded the lethal limits of 250 ppm and there are cases of producing wells with levels above 1000 ppm. In this work, both a conceptual study and an experimental protocol were developed for the evaluation of formation damage by microbial contamination in water flooding processes. It is focused on finding the best stimulation treatment with biocides to H2S and corrosion control in Producer Wells of Oil Fields Undergoing Secondary Recovery as part of the comprehensive strategy to implement in the injection-reservoir-production system of the Chichimene field in Colombia. This study included the following stages:1. State of the art to define main bactericides, matrix stimulation treatments to H2S and corrosion control, removal of biomass (biofilm) and iron sulfide, etc. in producers wells. 2. Conceptual study of the formation damage by growth of sulfate-reducing bacteria.3. Experimental protocol for the evaluation of formation damage due to microbial contamination in water flood processes.4. Experimental evaluation of formation damage due to microbial contamination in cores of the Chichimene field, in Colombia. Finally, the main findings, conclusions and recommendations obtained in this study are shown.Keywords: microbial contamination, microorganisms, secondary recovery, stimulation, formation damage, sulfate-reducing bacteria, water production, waterflooding.

The elucidation of the detailed mechanism used by F(0) to convert proton gradient to torque and rotational motion presents a major puzzle despite significant biophysical and structural progress. Although the conceptual model has advanced our understanding of the working principles of such systems, it is crucial to explore the actual mechanism using structure-based models that actually reproduce a unidirectional proton-driven rotation. Our previous work used a coarse-grained (CG) model to simulate the action of F(0). However, the simulations were based on a very tentative structural model of the interaction between subunit a and subunit c. Here, we again use a CG model but with a recent cryo-EM structure of cF(1)F(0) and also explore the proton path using our water flooding and protein dipole Langevin dipole semimacroscopic formalism with its linear response approximation version (PDLD/S-LRA) approaches. The simulations are done in the combined space defined by the rotational coordinate and the proton transport coordinate. The study reproduced the effect of the protomotive force on the rotation of the F(0) while establishing the electrostatic origin of this effect. Our landscape reproduces the correct unidirectionality of the synthetic direction of the F(0) rotation and shows that it reflects the combined electrostatic coupling between the proton transport path and the c-ring conformational change. This work provides guidance for further studies in other proton-driven mechanochemical systems and should lead (when combined with studies of F(1)) to a complete energy transduction picture of the F(0)F(1)-ATPase system.

Tight sands are abundant in nanopores leading to a high capillary pressure and normally a low fluid injectivity. As such, spontaneous imbibition might be an effective mechanism for improving oil recovery from tight sands after fracturing. The chemical agents added to the injected water can alter the interfacial properties, which could help further enhance the oil recovery by spontaneous imbibition. This study explores the possibility of using novel chemicals to enhance oil recovery from tight sands via spontaneous imbibition. We experimentally examine the effects of more than ten different chemical agents on spontaneous imbibition, including a cationic surfactant (C12TAB), two anionic surfactants (O242 and O342), an ionic liquid (BMMIM BF4), a high pH solution (NaBO2), and a series of house-made deep eutectic solvents (DES3–7, 9, 11, and 14). The interfacial tensions (IFT) between oil phase and some chemical solutions are also determined. Experimental results indicate that both the ionic liquid and cationic surfactant used in this study are detrimental to spontaneous imbibition and decrease the oil recovery from tight sands, even though cationic surfactant significantly decreases the oil–water IFT while ionic liquid does not. The high pH NaBO2 solution does not demonstrate significant effect on oil recovery improvement and IFT reduction. The anionic surfactants (O242 and O342) are effective in enhancing oil recovery from tight sands through oil–water IFT reduction and emulsification effects. The DESs drive the rock surface to be more water-wet, and a specific formulation (DES9) leads to much improvement on oil recovery under counter-current imbibition condition. This preliminary study would provide some knowledge about how to optimize the selection of chemicals for improving oil recovery from tight reservoirs.