Water Production Problems Research Articles

A Conceptual model of mixed-integer linear programming water distribution system

Water is a basic part of our daily lives, as such effective water supply is of paramount importance. Thus, as a result of the rise in population size and water shortage there is the need for proper, suitable and optimal utilization of water resources to efficiently be distributed among the populace. The proper allocation and distribution of water in the field of network planning need to be modelled through mathematical parameters for objective of water distribution system. This mathematical approach requires of solving an optimization problem based on multi-objective function subjected to certain constraints of mixed integer linear programming objective function which is proportional to the cost of the water distribution network. This study present a conceptual model of multi-objective optimization proposed for determination of design parameters of water distribution system by considering the significant number of constraints, decision variables, cost and reliability objective functions. The model was proposed to solve the reliability problem of water production and reduce the design and operational costs.

The Law of Liquid–Solid Carrying in the Wellbore of Natural Gas Hydrate Gas Well under the Condition of Foam Drainage Gas Recovery

During the trial production of marine gas hydrate in the former Soviet Union, Canada, North Slope of Alaska, South Sea Trough of Japan and Shenhu Sea of South China Sea, the problem of sand and water production cannot be avoided. The problems of sand production and water production in the process of natural gas hydrate depressurization exploitation have seriously restricted the exploitation efficiency and production of natural gas hydrate. The problems of sand production and water production are some of the main factors that prevent natural gas hydrate being commercially exploited. Therefore, it is urgent to carry out useful, relevant and cutting-edge research on the efficient drainage of sand and water from the wellbore in the process of natural gas hydrate mining. This paper innovatively proposes liquid-carrying and solid-carrying technology under foam circulation purging to address the existing problems of sand removal and drainage technology in hydrate mining. At present, no scholar has used this technology to solve the problem of sand removal and drainage in hydrate mining. Therefore, the research on efficient drainage is imperative. In this paper, We mainly studied the liquid-carrying and solid-carrying of vertical wellbore under the condition of foam cycle purging. We have revealed the relevant the liquid-carrying law and solid-carrying law through the above research.

Preparation of high-temperature gels for enhanced oil recovery using methyl etherized melamine-formaldehyde resin

Polymer gels are the most commonly used materials in the petroleum industry for reservoir conformance control and resolving excessive water production problems. In this study, high-temperature gels were prepared with HPAM or AM/AMPS as the gel-forming agent, methyl etherified melamineformaldehyde resin (MEMFR) as the crosslinker, and nano-silica as the stabilizer, and their properties were evaluated. The results showed that HPAM-MEMFR gels were unstable at 110°C in a brine of 20665 mg/L. AM/AMPS-MEMFR gels are stable at 110°C, with gelation time ranging from 15 h to 92 h and storage modulus ranging from 3.6 Pa to 50 Pa. AM/AMPS-MEMFR gel has less than 10% dehydration after aging at 110°C for 90 days, almost no shrinkage in volume, and a significant increase in strength, making it suitable as a gel material for enhanced oil recovery.

Evaluation of Ultrahigh-Temperature-Resistant Preformed Particle Gels for Conformance Control in North Sea Reservoirs

Summary Preformed particle gels (PPGs) are 3D, crosslinked, dried polymer particles that can swell to several hundred times on contact with formation water. PPGs have been used extensively to control water production problems in reservoirs with conformance problems. The current state-of-the-art PPGs are polyacrylamide-based hydrogel compositions which lack long-term thermal stability under high-temperature and -salinity conditions. There are many oil reservoirs across the globe exhibiting conditions of temperatures higher than 120°C with high salinity. A novel ultrahigh-temperature-resistant PPG composition (DMA-SSS PPG) was designed to fill up the technology gap between existing polyacrylamide-based PPG technology that degrades readily over 110°C temperatures. DMA-SSS PPG exhibited excellent thermal stability for greater than 18 months in North Sea formation and formation water environments at 130°C. DMA-SSS PPG described herein showed swelling capacities of up to 30 times in different salinity North Sea brines. DMA-SSS PPG’s physiochemical properties like swelling, swelling rate, and rheological behavior were studied as a function of temperature and salinity. DMA-SSS PPGs showed excellent elastic modulus (G’) of about 3200 Pa in formation water of 90% water content. Thermostability of DMA-SSS PPGs was assessed at 130 and 150°C in North Sea brines with different salinity conditions. DMA-SSS PPGs proved to be stable for more than 18 months without losing molecular integrity. Thermostability was further confirmed through different metrics such as cross-polarization magic angle spinning carbon-13 nuclear magnetic resonance (CPMAS 13C NMR), thermogravimetric analysis (TGA), and morphology. Laboratory coreflood experiments were performed to demonstrate the plugging efficiency of open fractures and effectiveness in reducing the permeability. DMA-SSS PPG comprehensive evaluation confirms its novelty for excellent hydrothermal stability, thus can be used to control water production problems for mature reservoirs exhibiting conditions of high salinity and high temperature.

Evaluation of Water Channeling Problems and Planning for Its Improvement Using the Remedial Cementing Method and Its Economics in Well AB-30 Field AB PT. Pertamina EP

The AB-30 well is an oil producing well located in the AB Field. Production performance data shows that AB-30 shows excessive water production behavior or is a high water cut production well. In addition, the interpretation of CBL data shows an amplitude value of <10 mV in the productive interval. This condition is an indicator that the primary cementing activity in this well is not good. Therefore, a comprehensive and integrated analytical method is needed to identify the problem of excess water production and to design and plan water shut-off activities through squeeze cementing as an effort to mitigate the problem of high water cut to economic analysis.The research begins by identifying the problem of excess water production, whether caused by water channeling, water coning, changes in water oil contact, or by the physical properties of the reservoir rock. Identification is done through production analysis and water diagnostic plots. The next stage is to evaluate the interpretation of CBL Logging results to strengthen the results of production data analysis. After confirming that the problem of excess water production is caused by poor cement bonding cement, the next step is to calculate the cement work program in order to repair the bad cement bonding. Subsequently, the productive zone interval re-perforation was carried out according to the results of the OH Loh Co Log evaluation. No less important is to conduct an economic analysis as a basis for whether or not this work is feasible.The result of this research is that the water shut-off activity went well and was able to reduce the level of excess water production in the AB-30 well and optimize oil production so as to provide a good economic indicator of oil recovery. Remedial cementing work for bonding repair was carried out at well AB-30. The first work is to close the existing layer, followed by Logging evaluation (CBL-USIT). The evaluation results showed that the cement bonding was good with the CBL amplitude parameter < 10 mV. After that, the productive zone reperforation was carried out. The economy by considering the values of economic indicators such as Pay Out Time and Rate Of Investment showed positive results so that the priority and strategy of well intervention could be continued. The results obtained before the well intervention were 148 BOPD oil production, 97% water cut after well intervention was 880 BOPD average oil production, 0% water cut for 1.5 months

MEASUREMENT OF PHYSICAL ROCK PROPERTIES AND SELECTION OF IDENTIFIED CORE PLUGS FOR INJECTIVITY AND BLOCKING TESS

An oil field on the island of Sumatra in Indonesia has excess water production problem. Its watercuts are greater than 90 %. Excess water production is not only linked to poor sweep efficiency, but also causes many problems in oil industry, such as scaling, corrosion, cost of oil water treatment and cost of water disposal, and in effective hydrocarbon mobility. Optimizing oil production often requires considerable time, effort and challenge. Chemical injection (e.g. BW Polymer) is a method proposed to solve the current problem in the oil field. Hopefully, the excess water production will be blocked effectively by using chemical injection method in order to obtain maximum productivity and recovery. This paper is especially focused on measurement of physical rock properties, identification and selection of core plugs for injectivity and blocking test study

Research on the Inflow Performance of the Plunger Lift in the Shale Gas Horizontal Well

Shale gas wells in the Changning block of Weiyuan, Sichuan, China, experience water production problems throughout their life cycles. In actual field production, plunger lift is typically used to discharge liquid from a shale gas well. However, it is difficult to test the formation inflow performance relationship curve (IPR) of a plunger lift well. Hence, data on the formulation and optimization of plunger lift well systems are lacking. Based on actual measured data related to casing pressure changes at the wellhead and the gas-liquid distribution characteristics in a wellbore during the shut-in phase, this paper establishes a method for calculating the formation IPR curve of a shale gas plunger lift well by calculating changes in wellbore gas volume continuously. This method has a fast calculation speed. The gas-water interface distribution can be obtained in 3–5 iterations, and the inflow dynamic curve can be calculated in less than 5 seconds. This method tested the IPR curves of gas wells in the Changning block. The IPR curves of plunger lift wells showed concave characteristics contrary to the conventional upward convex curves. This is because the bottom hole flowing pressure changes caused variations in the water saturation of the near-wellbore zone. Consequently, the productivity equation of the plunger lift well is established by introducing the variation coefficient of water saturation expressed by bottom hole flow pressure. This equation fits with the measured IPR curve with an average R2 of approximately 0.9989.

Hybrid analysis for excessive water production problem

The production performance of wells should be studied in order to extend the production plateau period which can lead to an increase in revenue. The pool performance plot of a reservoir is a pictorial representation of the pressure-production history of a reservoir. Water-coning, near wellbore problem and multilayer channeling are the three basic mechanisms associated with high water-cut wells. Identification of the water sources is quite important to perform any remedial operation to extend oil production. This paper is a case study on the application of two methods to determine the accurate mechanism for high water-cut in an oil field ‘A’ of the upper Assam basin. Based on the study of conventional plotting of water-cut vs. time with well card data (History of all the jobs performed on the well) and log-log plots of WOR and WORꞌ vs. time, it was observed that the problems were due to multilayer channeling and coning. These plots show the problems associated with high water cut wells and they serve as an effective tool for the selection of water control treatment processes to enhance treatment. However, a failed treatment job will alter the conditions for the next job whereby the expenditure increases significantly.

Identification of Water Production Mechanism in One of Iran’s Oil Fields and Treat it With Gel Injection

In this study, the problem of water production in one of Iran's oil reservoirs will be examined. First, using the flow rate diagram of oil and water production, the problem of water production will be examined according to time. Then, after confirming the occurrence of water production problem, the mechanism of water production will be investigated using Chan diagnostic diagrams and the created sector model. The results of this study indicate that firstly, the problem of water production in the well under study is observed, and secondly, according to the Decline-curve analysis diagrams, Recovery plot, Chan derivative diagram and schematic shape of the fluid flow movement, it shows the mechanism. Water production is a channel flow process under water injection. A gel treatment at early time with 25% of water cut was studied, for that it was modelled a gel treatment after 500 days of production.The main observation is that by increasing the concentration of injected gel, the rate of oil production increases and the rate of water production decreases. The concentration evaluated concentration was from 0 to 100 (lb/bbl) of solution, a stabilization concentration was not observed. Finally, first by identifying the type of water production mechanism for this reservoir in Iran, it has been determined that it has water production through the canal and then by using a simulation of gel injection, the water production rate has decreased and the oil production rate has increased.

Water leak control for the oil-producing wells using Downhole Water Sink Technology

Casing or tubing leaks cause unwanted water production from oil-producing wells. Many chemical and mechanic water control technologies can be used to solve this problem, including squeezing chemical shutoff fluids into the targeted zone or using plugs, cement, packers, patches to block the leakage. Although those methods are field-proven to be effective, the mechanical solutions may require well logs to detect the water entry point in the well. Chemical methods may present environment risks. In this study, an alternative method, Downhole Water Sink, is proposed to solve the problem of unwanted water production from a casing or tubing leak. The effectiveness of this method to control water production in a well with casing or tubing leaks is tested using the Hele-Shaw experimental model. The results show that this method can control unwanted water production via dynamic control of the pressure drawdown in the reservoir. From a technical standpoint, the advantage of this technology is that it eliminates the need to run logs to locate the water entry point and does not require chemical injection into the formation. From an environmental standpoint, this technology has the circular economy elements. Because the produced water in this technology contains little or no oil, it can be reused for reinjection into the reservoir for water flooding or pressure maintenance purposes. Therefore, a production-reinjection process to recycle the produced water is established to reduce the pollution caused by discharging the wastewater into the environment.

Water Production Problem in Gas Reservoirs: Concepts, Challenges, and Practical Solutions

Gas resources play a key role in nowadays energy supply and provide 24% of the diverse energy portfolio. Water encroachment is one of the main trapping mechanisms in gas reservoirs. It decreases recovery by reduction of reservoir life, limits productivity and efficiency of wells, and elevates safety risks in gas production. The lack of a comprehensive study about water production problems is the primary motivation for this study. Contrary to the serious concern over the standalone investigation of an actual water production case study, less concern is put to deal with the problem comprehensively through an investigation of all potential sources and mechanisms, required methods, and available techniques. This study presents the potential sources of the problem, methods to identify it, and approaches to address it. Firstly, possible sources are described. Secondly, the diagnostic techniques are expressed. Then, practical solutions used in actual cases to overcome problems are elaborated. The solutions include both well- and reservoir-oriented approaches. Finally, all proper strategies are summarized to tackle the water problems in gas fields. The current study comprehensively presents the available methods for water control problems in parallel with conceptual and qualitative comparison. The finding of this study can be very constructive for better understanding of water sources, available diagnostic tools, and solutions for controlling water production in gas reservoirs and, consequently, taking the best decision in real case studies before attempting many water shut-off approaches.

A stepwise approach for identification of water production mechanisms in gas reservoirs

ABSTRACT Gas resources play a key role in nowadays energy supply, and it provides 24% of the diverse energy portfolio. Water encroachment is one of the main trapping mechanisms in gas reservoirs, and it causes subsequent recovery reduction. There are various reactive techniques that have been applied to cope with excess water production as long as many industry failures for treating water production consistently. The key to effective water control is the source and mechanism of water invasion identification. Reviewing the literature, there are 10 mechanisms for unwanted water production. Although there are a few general approaches to deal with undesirable water production, a stepwise approach to diagnose the source and mechanism of unwanted water production is missing. This paper presents a comprehensive approach employing all available data to identify the mechanism of water production. The proposed approach investigates all the possible water production mechanisms regardless of the severity of the problem. By applying some filters and screen out the irrelevant mechanisms, finding the main mechanism and consequently the necessary counter-reaction is more comfortable. As a case study, this approach was applied in a carbonate gas reservoir encountered a sever water production problem. The water rises 24 meter per year. By applying this approach, the main source and mechanism of water production in this field was recognized without any further diagnostic tests. As a consequence, the appropriate reservoir-based solutions were replaced with previous well-based treatment methods in the field with more than 20% recovery improvement.

Problem of unexpected water production with water saturation less than 40%: A case study from Alam El Bueib Formation, Safir Oil Field, Shushan Basin, Western Desert, Egypt

Safir Oil Field which locates within Shushan Basin is considered one of the well-known oil fields in northern Western Desert of Egypt. Alam El Bueib 3A Member is the main oil producer in this field. This member in Safir-N07 well has water saturation (Sw) values less than 40% with 17% porosity. However, the available data of Drill Stem Test (DST) indicate that 999 barrels water per day (BWPD) and only one barrel oil per day (BOPD) of total 1000 barrels fluid per day (BFPD) were produced. This represents a challenging problem facing any petrophysicist. The presented article treats this situation by comparing water saturation with other two extremely important petrophysical parameters. These are the critical water saturation (Scw) and minimum bulk volume water (BVWmin). The critical water saturation (Scw) of the tested interval is 34%, which is less than the calculated Sw (i.e., Sw > Scw) that reflects the existence of water rather than oil. In addition, BVWmin has been calculated to be 0.05. The calculated BVW for AEB-3A Member (Φ × Sw) is 0.07 which is higher than the BVWmin value confirming the water productivity and matching the DST data. The presented technique was also applied to the same member in Safir-03 well in the same field. The calculated Sw and BVW are 12% and 0.03, respectively, which are lower than Scw (31%) and BVWmin (0.05) indicating that the reservoir is at irreducible state (no water will produced). During DST, this member recovered 1350 (BOPD) and zero (BWPD) confirming the importance and validation for the applied techniques. The constructed structure contour map shows a distinctive three-way closure in the southern part of the study representing a suitable place for hydrocarbon accumulation in Safir-03 well. On the other side of this map displays Safir-N07 well located in downthrown which proves oil-free production as residual oil saturation.

A Novel Double-Group Crosslinked Hydrogel with High Thixotropy for Water Control in Horizontal Wells

Summary Horizontal wells that are completed with slotted liners often suffer from a severe water-production problem, which is detrimental to oil recovery. It is because the annulus between the slotted liners and wellbore cannot be fully filled with common hydrogels with poor thixotropy, which determines the ultimate hydrogel filling shape in the annulus. This paper presents a novel hydrogel with high thixotropy to effectively control water production in horizontal wells. This study is aimed at evaluating the thixotropic performance, gelation time, plugging performance, and degradation performance. The thixotropic performance of the new hydrogel was also investigated by measuring its rheological properties and examining its microstructures. It was found that the new hydrogel thickened rapidly after shearing. Its thixotropic recovery coefficient was 1.747, which was much higher than those of traditional hydrogels. The gelation time can be controlled in the range of 2 to 8 hours by properly adjusting the concentrations of the framework material, crosslinker, and initiator. The hydrogel could be customized for mature oil reservoirs, at which it was stable for more than 90 days. A series of laboratory physical modeling tests showed that the breakthrough pressure gradient and the plugging ratio of the hydrogel in sandpacks were higher than 9.5 MPa/m and 99%, respectively. At the same time, it was found that the hydrogel has good degradation properties; the viscosity of the hydrogel breaking solution was 4.22 mPa·s. Freeze-etching scanning-electron-microscopy examinations indicated that the hydrogel had a uniform grid structure, which can be broken easily by shear and restored quickly. This led to the remarkable thixotropic performance. The formation of a metastable structure caused by the electrostatic interaction and coordination effect was considered to be the primary reason for the high thixotropy. The successful development of the new thixotropic hydrogel not only helps to control water production from the horizontal wells, but also furthers the thixotropic theory of hydrogel. This study also provides technical guidelines for further increasing the thixotropies of drilling fluids, fracturing fluids, and other enhanced-oil-recovery polymers that are commonly used in the petroleum industry.

Numerical simulation of water production process and spontaneous imbibition in a fractured gas reservoir – A case study on homa gas field

Water coning in gas production wells generally causes excess water production and many operational problems. This phenomenon is more crucial in fractured reservoirs. The purpose of this study is to investigate this phenomenon by numerical simulation of gas production in a three-dimensional single well model. In order to obtain accurate perception of actual flow behavior, the structure of fracture network consisting of horizontal and vertical fractures defined clearly in the model. The fluid and rock properties of one of the gas fields in south of Iran is used in the model. The performed simulations showed increase of water level around production well due to the high pressure-gradient in the fracture network of reservoir. In addition, evaluation of the impact of various parameters on flow behavior proved that the fracture network plays a significant role in water and gas production in carbonated reservoirs. The results also showed that short-term well closure can not have an important effect on water production problem; but flow rate reduction causes decrease in water production to an acceptable extent. Furthermore, designing suitable depth of completion can also be remarkable in management of water production of gas wells.

A Nanoparticle Adsorption‐Based Salt‐Resistant Foam for Gas Well Deliquification

AbstractWith the continuous development of gas fields, water production problems are seriously affecting production rates. Aiming at the problem of the high production rates of mineralized formation water in China's gas fields, we investigate the feasibility of a foam for gas well deliquification process using a combination of nanoparticles and surfactants. Through the combination of anionic and non‐ionic surfactants, a system with better foam stability is optimized by the hand‐shock method. Based on the formation of hydrogen bonds between the fatty alcohol polyoxyethylene ether and SiO2 nanoparticles, the fatty alcohol polyoxyethylene ether created hydrophobicity after silica was added. Adsorbed on the gas–liquid interface, the dilatational modulus of the gas–liquid interface increased, the shift time extended, and the diameter of the generated foam is smaller, that is, a unit volume of gas can carry more liquid. Foam stability can be adjusted by altering the pH value of the foam for gas well deliquification. Last, the oil resistance of the system was improved by adding fatty alcohols. Here, a foam for gas well deliquification was established by the combination of surfactant, nanoparticles, and fatty alcohols, which has good foaming performance, stability, and oil resistance.

Experimental and Theoretical Investigation of Gelation Time of Nanostructured Polymer Gels by Central Composite Approach

Currently available polymers as a component of in-situ gels are unsuitable for treating high-temperature/high-salinity reservoirs due to their chemical and thermal degradation. In this study, a new copolymer-based gel system including high molecular weight nanostructured polymers (NSPs) was developed to address the excessive water production problem in reservoirs under harsh conditions. The stability of conventional polymer systems and NSPs was investigated under conditions of 40 days aging at 87000 ppm salinity and 90 °C. Then, gelation time optimization of gel systems composed of NSPs and chromium (III) acetate was performed with regards to the effect of copolymer concentration and copolymer/cross-linker ratio and their interactions during the gelation time. The central composite approach was used to design experiments and build a mathematical model. The analysis of variance (ANOVA) was used to estimate the deviation of the model predictions from the data. The results of stability analysis demonstrated the advantages of NSPs over conventional polymers by a viscosity reduction of 69, 36, and 18% for Flopaam3310, AN105, and NSPs respectively. The model developed for the prediction of gelation time of NSPs gel was significant at a confidence level of 98.6% against the test data. Moreover, it was found that gelation time became longer with a decrease in copolymer concentrations and/or increase in copolymer/cross-linker ratio.

Experimental Study on Water Shutoff Technology Using In-Situ Ion Precipitation for Gas Reservoirs

Once a gas well begins to produce water, gas production will be seriously affected. If no effective measures are taken, the gas well will be shut down. Although some methods can be adopted to limit the production of unwanted water in gas reservoirs, they do not radically solve the problem of excessive water production, which may cause gas shutoff and dramatically increase the cost of dealing with disposing of the unwanted water. In this study, water shutoff technology with in-situ ion precipitation was tested for a gas well in southwest China, with results demonstrated through experiments of ion precipitation distribution and core displacement. The results of the ion precipitation distribution experiments show that it can be artificially controlled to produce ion precipitation blocking the water layer. The distribution of ion precipitation depends on influencing factors including injection flow rate, injection height, and ion concentration, which is generally hill-shaped. Dynamic displacement experiments through two types of cores (matrix core and fracture core) show that during the process of injecting gas-field water into the core, the ion precipitation caused by the in-situ reaction constantly blocked the seepage channel, resulting in a significant decrease in the injection rate. After injection of the gas-field water, the permeability of the core decreased, the starting pressure gradient increased, and the effect of water shutoff was remarkable. Given the experimental results, the in-situ ion precipitation water-plugging technology for gas reservoirs can directly solve the problem of water production in gas wells in the water layer because it can block the water layer by using formation water itself. This technology has promise for use in southwest China and can provide technical guidance for other gas reservoirs.

Comparative Study between Smart Controls and Conventional Bottom Hole Completions

This research project made use of Schlumberger’s “ECLIPSE 100” reservoir simulator to predict the performance of a reservoir with an overlying gas cap and an underlying aquifer (i.e., a three- phase Water-Oil-Gas reservoir) under conventional BHC techniques. Additional work was done to ascertain the suitability of incorporating an Intelligent Well (IW) to deal with water production problem by placing Inflow Control Valves (ICV) at particular segments in the well to monitor and control fluid flow. Comparing BHCs, it was found out that open hole completion yielded the maximum performance whereas gravel pack completion yielded the least. The simulation yielded FOEs of 13.27, 13.04, 13.02 and 12.98% for open hole, cased hole, perforated liner and gravel pack completions, respectively. Application of the intelligent well (IW) as opposed to the conventional cased hole well yielded a 4.06% increment in FOE. The project yielded a 41% reduction in water cut by the intelligent well compared to the conventional well. These were all due to the open-close action of the valves employed in the intelligent well model. This justified the applicability and suitability of intelligent wells in improving oil production by solving unnecessary water production, thus providing better returns on investment. Keywords: Open-hole, Casing, Annular Cementation, Perforated Liner, Pre-slotted liner, Gravel Pack, Intelligent Well, Field Oil Efficiency

Experimental study of calcium-enhancing terpolymer hydrogel for improved oil recovery in ultrodeep carbonate reservoir

Along with the continuous water injection, water production problem is getting worse in ultrodeep carbonate reservoir (depth≥6000 m), but it is hard for common hydrogels to plug the water in this hostile reservoir condition (temperature≥130 °C, salinity≥220,000 mg/L). In this paper, acrylamide/acryl-acid/2-acrylamido-2-methyl-propanesulfonate (AM/AA/AMPS) hydrogel has been found to be a very effective plugging agent for this unconventional reservoir, and its thermal-resistance and salt-tolerance mechanism was studied detailedly. The results show that stable time of AM/AA/AMPS hydrogel can reach up to 60 days, and the syneresis rate is below 5% on the 120th day in the hostile condition (temperature = 130 °C, salinity = 223,000 mg/L, Ca2+ concentration = 11,000 mg/L). The viscosity and weight-average molecular weight of four polymers (PAM, AM/AA /AMPS, AM/DAC and AM/DMDAAC) decrease with the increasing aging time, but the descent speed of AM/AA/AMPS is the slowest. Besides, AM/AA/AMPS has strong hydrophilicity in the saline water since its Rh is the highest when the weight-average molecular weight of four polymers is nearly the same. FTIR, NMR and LS measurements show that the COO− of AM/AA/AMPS reacts with Ca2+, changing the hydrogel from the single-group crosslinking to double-groups crosslinking, which results in the microgrid structure of hydrogel becoming dense and strong. In contrast with the common hydrogel, the AM/AA/AMPS hydrogel shows better water plugging effect in the hostile condition. The enhancing hydrogel strength and outstanding absorption of polymer onto rock are considered as the important reasons to the better performance of AM/AA/AMPS hydrogel.