Water Shutoff Treatments Research Articles

Impact assessment of polymer, cross-linker, and nanoparticles on gelation kinetics and properties of silica nanocomposite hydrogel for water shut-off treatment in harsh reservoir conditions

The study presented the impacts of various parameters like compositional combinations of PHPA (partially hydrolyzed polyacrylamide), organic cross-linker (hydroquinone-HQ and hexamethylenetetramine-HX), and silica nanoparticles (SNP) in addition to the degree of hydrolysis and molecular weight of PHPA on the efficacy of hydrogel for water shut-off jobs. The investigation indicated that the gelation time, gel strength of the gel, tolerance against salinity, and temperature were tuned as required by the field conditions by changing the variables mentioned above. The gelation time was found to vary inversely with the concentration of polymer, cross-linkers, and silica nanoparticles, whereas the gel strength and temperature tolerance followed the reverse trend. SNP was observed to control the gel properties significantly, even at the lower polymer and cross-linker compositions, as evidenced by the stronger network in FESEM, rheological, and other related properties. The hydrogels prepared with the PHPA-LM (low molecular wt) and PHPA-HM (high molecular wt) polymers and HX-HQ cross-linkers showed improved temperature tolerance from 126.49 °C to 131.78 °C and 99.88 °C to 164.34 °C, respectively when improvised with SNP. The gel’s microstructure (FE-SEM image) exhibited significant silica nanoparticle aggregation and evenly distributed compact three-dimensional network structure. The prepared nanohydrogel with optimized composition maintained its stability even at a salinity of 60000 ppm and 120 °C for more than two years. Sand-pack flooding with the nanohydrogel proved very effective, with a permeability reduction of ∼ 90 %. Thus, the prepared nano-hydrogel could be effectively used for high temperature and high salinity conditions with preferred resistance to water flow.

APPLICATION OF HYDROGELS FOR WATER SHUTOFF TREATMENTS. Message No. 2

The article analyzes the use of hydrogels with nanoparticle additives for well water shutoff, as well as the development of a mathematical apparatus for hydrodynamic modeling of water shutoff operations. One of the most significant trends in the development of gel forming compounds for well water shutoff in the last 10 years has been the use of nanocomposites. The base polymers for nanocomposites used for water shutoff operations are either synthetic or biopolymer origin. The article highlights the novelty and prospects of using nanoparticles in sealing compositions. Various nanocomponent additives are used to increase the success of the use of hydrogel polymer systems in order to limit water inflow and expand the scope of their application in complicated reservoir conditions. These include carbon and mineral nanoparticles, which increase the stability and strength of crosslinked gels in formation conditions.In this paper, we consider the optimization of the repair and insulation operations design using gels for well water shutoff using mathematical modeling, which helps to justify the volume of hydrogel injection and calculate the necessary pressure gradients at which the sealing screen remains stable. The paramount importance of determining the source of well flooding is emphasized, depending on which the processing design is already being built, and appropriate materials are selected; trends in the development of repair and insulation operations at the present stage are traced. Based on the results of the implementation of the proposed model by numerical methods, the authors constructed diagrams of the stability of the waterproofing screen depending on the fracture width, screen size, gel injection rate and reservoir permeability. The technique proposed in the work allows to correctly select and optimize the technological parameters of the operation to maintain the stability of the screen in specific geological conditions.Mathematical modeling allows us to strictly justify the volume of injection of the gel screen, increase the technological and economic efficiency of the process, and in large fields — to rank wells according to the priority of processing. Oilfield practice in various regions of the country fully confirms the main conclusions made in this review article. Preliminary mathematical modeling and the introduction of microdispersions into gel formulations can significantly increase the efficiency of water shutoff operations. The next step in the development of water insulation technologies is the use of nanodispersions, which look very promising in laboratory modeling and are no longer exotic materials with unrealistic cost.

Water shutoff treatment of low permeable reservoirs by in situ polymerization: laboratory scale development and verification through core flow experiments

Excessive water generation in oil reservoirs poses economic challenges, diminishing hydrocarbon yield and incurring additional costs for water management. This study focuses on enhancing reservoir conformance control, particularly in low-permeability zones with high water production, where traditional gel-based methods face limitations. The goal is improved penetration into narrow fractures and effective sealing of water-inflow zones through in situ polymerization and sequential cross-linking. The study systematically optimized key polymerization parameters, including initiator/monomer ratios, initiator types, and environmental conditions. Core flooding tests demonstrated a significant 17% increase in original oil recovery, alongside a substantial reduction in permeability. Analytical techniques such as CT scans, thin section scans, SEM, and EDS were employed to assess gel distribution within pores and penetration rates. This in situ polymerization and gelation approach show promise in addressing water production challenges, offering enhanced recovery, and adapting well to diverse reservoir conditions. The comprehensive optimization of polymerization parameters and the use of advanced analytical methods contribute to the study’s potential impact on mitigating economic and operational issues associated with excessive water production in oilfields.

Simulation study of water shut-off treatment for heterogeneous layered oil reservoirs

The purpose of this paper is to develop a hydrodynamic model of two-phase, three-component fluid flow in a heterogeneous layered reservoir, taking into account cross-flow between layers, and to predict the process of oil displacement by water under conditions of water shut-off in the vicinity of injection or production wells. Numerical calculations at different water cuts (38%, 50%, 96%) showed that in the presence of cross-flow between layers, the current oil recovery coefficient of the reservoir at water shut-off in the vicinity of the producing well increases by 0.3254, 0.3067, and 0.0429 respectively, compared to water shut-off in the vicinity of the injection well. In the absence of cross-flow between layers, there is a decrease in oil recovery coefficient by 0.0082 and 0.0072 at 38 and 50% water cut, respectively. Additionally, there is an increase in recovery coefficient by 0.007 at 96% water cut. It was also obtained that in the presence of cross-flow between layers the gel washout period at water shut-off in the vicinity of the injection well is less at different water cut in 1.24–1.81 times than in the vicinity of the production well. In the absence of cross-flow between layers, the washout time at 38 and 50% water cut is almost the same, but increases by 1.084 times at 96% water cut. Comparison of results of water shut-off prediction using proposed hydrodynamic model and real data showed that calculations describe real data with an average error of about 7%.

A Review of Recent Developments in Nanomaterial Agents for Water Shutoff in Hydrocarbon Wells.

Reducing water production from hydrocarbon wells is one of the major requirements to prolong the life span of production wells. Gel treatment is commonly regarded as one of the traditional cost-effective methods for water shut-off applications. Different gel systems have been developed to overcome the challenges of performing a successful water shut-off treatment. Each gel system has its advantages and disadvantages. A new proposed technology is to enhance the gel performance by utilizing nanomaterials in its composition. Nanomaterials such as nanosilica, nanoclay, and graphene can significantly modify gel properties to improve plugging efficiency. This paper provides a brief review of the added value of using nanomaterials in the structure of polymer in situ gel, preformed particle-gel, and nanosilica-based fluid. Nanomaterials such as nanoclay, nanosilica, and nanographene are capable of adjusting the properties of in situ gel, such as control of gelation time (9-10) hours and enhancing gel strength up to 4.5 times. Nanomaterials also improved the swelling ratio of the preformed particle-gel by up to 400%, accompanied by increased gel strength. Notably, nanosilica-based gels exhibit an exceptional plugging efficiency (100%). Additionally, the paper discusses how modeling can be used to overcome operational challenges in terms of placement and plugging performance.

Migration characteristics and plugging rules of self-aggregating nanoparticles in the porous media

Nanoparticle profile control agents have been widely used for water shut-off treatment due to their excellent properties. However, the contradiction between the injectability and the plugging characteristics of profile control agents seriously affects their sealing effect. Self-aggregating nanoparticles can effectively alleviate this contradiction by forming particle clusters in the formation to block water channels. In this study, the injection and plugging properties of self-aggregating nanoparticle profile control agents in porous media were investigated using visual porous media etching model and core model. Injectivity experiments showed that the flow of nanoparticles in porous media was divided into three phases: flow dispersion phase, self-aggregation migration phase, and aggregation plugging state. They could aggregate to form clusters similar to the pore throat size after 60 min. Core displacement experiments showed that the plugging performance of nanoparticles was influenced by solution concentration, injection volume, injection rate, and core permeability. When injecting a 3000 mg/L nanoparticle solution into the core at 60 °C, the residual resistance coefficient was larger than 1.83. The retention rate in pore throats was superior to 60%.

A study on the mitigation of formation damage caused by excessive silica-based gel application in water shut-off treatments

This study investigated the mitigation of formation damage caused by silica-based gels. The historical development of water shut-off treatments in the oil and gas industry was also discussed in the paper. The authors highlighted the importance of silicate methods in reservoir conformance control and enhanced oil recovery. They also discussed the recent resurgence of interest in silicates due to their eco-friendly properties and potential for high-temperature applications. Weight loss experiments and sandpack flooding experiments were conducted to assess the removal efficiency of blocking under reservoir conditions. The results showed that a 1% NaOH-containing aqueous solution can completely dissolve the bulk gel within a relatively short timeframe. İt is noteworthy that 10-12 hours is typically sufficient to eliminate the gel responsible for formation damage in the bulk phase. In sandpack flooding experiments, it was found that NaOH injection can effectively remove gel blockages, but it may require multiple injections to achieve complete removal. Overall, this study provides a comprehensive overview of the mitigation of formation damage caused by silica-based gels. The results of this study can be used to improve the design and implementation of gel-based water shut-off treatments in the oil and gas industry. Keywords: silica gel; water shut-off; formation damage; sandpack; gel block.

Microfluidics investigation of the fracture/matrix interaction mechanisms during preformed particle gel (PPG) treatment in fractured porous media

Although water injection is one of the most common methods for enhancing the recovery from oil reservoirs, its effectiveness in severely heterogeneous porous media such as fractured rocks, is debatable. Preformed Particle Gel (PPG) treatment is one of the most promising methods which is considered for water shut-off in the near wellbore area or improving the sweep efficiency of the injected water deep in the reservoir. Recognizing the PPG transport mechanisms in fracture, fracture/matrix interactions during and after PPG treatment, and the contributing parameters on such mechanisms, is a prerequisite for designing an effective water shut-off process and possible enhanced oil recovery (EOR). With this aim, the dynamic behavior of PPG samples is studied in two different fractured porous media representing the near wellbore area (dual permeability model) and deep in the reservoir zones (single permeability model). During encroachment of the gel particles in fracture, the dehydration of gel produces a large volume of filtrate which sweeps the oil inside the matrix. PPG particles might go through deformation, shrinkage and/or breakage, before infiltrating into pores of matrix where they form an impermeable cake. The experimental results shows that formation of such cake, is one of the main affecting parameters in the performance of the conformance control and EOR. Additionally, the affecting parameters such as concentration of nano-silica (n-SiO2), width of fracture, particles size, ionic strength of brine and injection rate of gel were examined. The concentration of n-SiO2 affects the gel loss factor (ratio of loss modulus to storage modulus) and hence its encroachment behavior. The gel sample with 1 wt% n-SiO2 has the highest loss factor which makes it more favorable for water shut-off considering lower injection pressure and less volume required for treatment. The water shut-off treatment is more effective in the case of systems with wider fractures. Based on the size of the PPG particles, the plugging mechanisms of the fracture can be either direct plugging, bridge plugging or a combination of both mechanisms, however all the studied samples provided same degree of plugging efficiency in the performed experiments. Swelling the samples in brines with higher salinities reduces the required volume of gel, while the injection pressure remained unaffected. To reduce the required volume of gel, highest possible injection rate is recommended, since the shear thinning rheology of the gel damps increment of injection pressure. In the case of single permeability model, water shut-off treatment reduced the fracture conductivity effectively, so that in the subsequent flooding, the injected brine was diverted toward matrix and the displaced oil was recovered through the fracture. During water flooding stage after gel placement, the withstanding pressure of PPG must be taken into account to avoid gel rupture, movement and washout.

Water Shutoff With a Thixotropic Treatment in Offshore Well Increases Gas Production

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209889, “A Successful Water Shutoff Using a Thixotropic Treatment in a Subhydrostatic and Highly Aromatic Well Results in Increased Gas Production of 30% and Reduced Water Production of 63% in Vietnam,” by Tuanangkoon Daohmareeyor, Tran Thang Nguyen, and Reawat Wattanasuwankorn, Halliburton, et al. The paper has not been peer reviewed. _ An offshore operator in Vietnam faced high water production in a subhydrostatic and highly aromatic gas well. In addition to low productivity, the high water cut also strained the water-treatment facility. Previous treatment attempts to shut off the high-water-producing zones have been unsuccessful because of challenging well conditions. A customized solution using a thixotropic organically crosslinked polymer (TOCP) with extensive laboratory testing was found to be the most suitable treatment design for this well. The new placement technique provided prevention of losses to the depleted zones. The thixotropic treatment provided higher viscosity when pumping stopped, allowing the polymer to seal off at the target zone. Introduction Excessive water production in mature wells is a major challenge for oil and gas operators worldwide, causing numerous economic issues for hydrocarbon production. In this case, the operator faced concerns with handling the water at the production facility, which had almost reached its capacity limit and would soon result in well abandonment. Furthermore, the well discussed in the complete paper was one of the highest-producing gas wells on the platform. The trend of gas production in this well was decreasing year over year, however, and the previous chemical water-shutoff treatment was not successful because of reasons that included the following: - The highly depleted formation created difficulties for well-intervention activities and treatment placement. - A complex well-completion setup was not ideal for well intervention, especially for mechanical isolation applications. - High aromatic content from the reservoir created incompatibility with mechanical isolation packer elements, risking operational failure. To achieve a shutoff objective, prejob considerations should include proper candidate selection, root-cause investigation, placement selection, tailored treatment design, and risk-mitigation planning, all of which are important factors of a successful operation. The complete paper presents the design and operational execution to serve as a guideline for future wells with similar issues. The operation’s objective was to shut off the top interval (Interval A) of five intervals in the well to reduce water production and increase gas production.

Acrylic-grafted nanocellulose hybrid double-network hydrogel with super-high toughness for water shutoff treatments

Hydrogels with high strength are strongly needed to perform such operations as fluid plugging and water shutoff in the oil & gas industry. In this work, a new type of tough hydrogel consisting of the acrylic acid grafted nanocellulose network and the copolymer (AA-co-AM) network was synthesized via one-pot free-radical polymerization, and further cross-linked by using Al3+. The prepared dual-crosslinked double network hydrogel (DN-Poly-X-CNF-g-AA) showed the high compressive strength and toughness at low concentrations of nanocellulose (within 0.2 wt%), i.e., the maximum compressive strength was 2.5 MPa at strains of 90% and the recovery rates exceeded to 90% after 10 compressive cycles. Meanwhile, the grafted nanocellulose endowed the double-network hydrogels with the strong intermolecular forces and the well-ordered hierarchical structure, which exhibited a high thermal decomposition temperature, solid-like elastic behavior and a swelling suppression. Finally, the sand-pack plugging experiments showed that the double-network hydrogels could effectively plug the porous media with different permeability, in which the breakthrough pressure gradient was between 4.9 and 104.63 MPa/m. The results demonstrated that the obtained tough hydrogel has a great potential to be applied as soft materials for water shutoff and conformance control in reservoirs.

Laboratory evaluation of novel nano composite gel for water shut-off

When extracting oil and gas from underground reservoirs, fluids such as water, CO2, polymer solutions, and surfactant solutions are often injected to displace the hydrocarbon resources. However, the presence of high-permeable layers, channels, and fractures in the reservoirs can hinder the efficiency of the displacement processes. The displacing fluids tend to channel through these high-permeability features, leaving behind significant amounts of hydrocarbon in low-permeability zones, which remain unswept. Recent developments in nanocomposite hydrogels, such as PPGs, have shown promising results for water shutoff due to their thermal stability and deformability. In this study, a preformed particle gel with nano additive (NC-PPG) was developed through free radical polymerization of AM, AMPS, and nanoclay. Nanoclay nanoparticles were found to act as physical cross-linkers in the polymer network, leading to smaller pore sizes and slightly enhanced thermal stability. The addition of an appropriate amount of nanoclay nanoparticles significantly improved the swelling rate and mechanical properties of NC-PPG. The presented composition also showed good salt tolerance, as evidenced by its compatibility with highly saline formation water and the plugging rate and RRF of 0.25% NC-PPG solution, which were 94.3% and 17.6, respectively, in the sand-pack flowing experiment. These results suggest that NC-PPG has the potential to effectively plug the high permeability zones in mature reservoirs, making it a suitable candidate for water shutoff treatment and enhanced oil recovery (EOR) strategies. The ability of NC-PPG to improve sweep efficiency and control water flow in reservoirs can contribute to more efficient oil production and reservoir management practices. Keywords: enhanced oil recovery; water shut-off; plugging efficiency; preformed particle gel; nanoclay; sweep efficiency.

Optimal Productivity Index from Gas Pay Zones with FAF Test

Gas Condensate reservoirs are hydrocarbon liquid dissolved in saturated natural gas that comes out of solution when the pressure drops below the dew point. Condensate liquid saturation can build up near a well because of draw down below the dew point pressure, ultimately restricting the flow of gas. This phenomenon is called as “condensate blockage or banking”. This improves the mobility of the gas with respect to the oil. If the gas does not have sufficient energy to carry the liquid to surface, then “liquid loading” in the wellbore occurs. If liquid falls back down the wellbore, the liquid percentage will increase and may eventually restrict the production that at this time. Besides, water-shutoff treatments in gas wells suffering from water influx are to reduce water production. In this paper it has been concluded that Artificial Lift technologies as the best selection in gas condensate reservoirs for more CGR recovery method can be used to solve this problem. To help this matter, as well, the Flow After Flow (FAF) well testing has been done for a gas condensate reservoir data to obtain some important outputs.

Experimental Investigation on the Performance of Polymer-Coated Clay/Polyacrylamide Hydrogel for Water Shutoff Treatment

SummaryPolymer gel system has been identified as having the potential for blocking and diverting water flow. However, the current polymer reported an inability to maintain its mechanical strength, limited penetration depth, and instability in reservoir conditions of high temperature and high pressure. A distinctive bentonite nanomer clay (PGV)/acrylamide (AM)-co-2-acrylamido-2-methyl-1-propanesulfonic acid (AMPS) preformed particle gel with poly(ethylene glycol-b-tetramethylene oxide) (PEGTMO) coating to control the swelling kinetics is formulated. The in-house formulated gel’s ability to block and divert water flow in a porous medium is studied. The formation recipe of the gel was achieved by numerous swelling tests as induced by brine solution under reservoir conditions. Through the swelling tests, the long-term thermal stability of the gel solution was demonstrated. The incorporation of PGV clay particles improves the swelling and mechanical properties of the gel. Premature swelling can be avoided with PEGTMO coating as it slows the swelling rate over a 10-minute period, which gives the advantage of controlling the swelling before reaching the intended site of action during coreflood experiments. The rheological behavior of the hydrogel features rubber-like mechanical behavior with a viscosity value of 1.17 cp, which displayed water-like characteristics. Further, significant permeability reduction of large fractures is demonstrated by the coreflooding experiment with a calculated result of 96.2%. This formulated gel could offer the solution as a blocking agent in void space channels containing reservoirs that leads to a reduction of water cut due to thief zones.

Recent advances in enhanced polymer gels for profile control and water shutoff: A review.

Polymer gels have been effectively employed as a water management material for profile control and water shutoff treatments in low-middle temperature and low-middle salinity reservoirs. However, most polymer gel systems have limitations under high temperature and salinity reservoir conditions, such as short gelation time, poor strength, and long-term instability. Therefore, several researchers have developed enhanced polymer gels to satisfy the water control requirements in high temperature and salinity reservoirs. This work reviews the five main types of enhanced polymer gels that have been developed so far: nano silica-enhanced gel systems, cellulose-enhanced gel systems, graphite-enhanced gel systems, oily sludge-enhanced gel systems, and foam-enhanced polymer gel systems. Further, this article investigates the fundamental properties, strengthening and crosslinking mechanisms, reservoir application conditions, and field applications of several enhanced polymer systems. In this paper, it is found that the addition of strengthening materials can increase the bound water content in the gel network and significantly improve the temperature and salt resistance of polymer gel, so as to cope with the application of profile control and water plugging in high temperature and high salt reservoirs. Moreover, it also offers references and future research directions for enhanced polymer gel systems.

Cross-linked and responsive polymer: Gelation model and review

An urgency to do a reverse engineering of predicting required reagents from a given polymer gelation time is paramount to support an efficient and economical water conformance control in petroleum field. The gelation period should consider the duration of solution pumping, desired well shut-in, and well reopening. There are two major problems could occur in water shut-off treatment: a premature or a long-waited gelling. To address those challenges, we conduct a comprehensive data compilation, review on polymer gelation models, assessment of the state-of-the-art in responsive polymers, and gelation time predictions based on our own developed analytical models and selected machine learning algorithms. Physics-based and data-driven study for a polyacrylamide-hexamethylenetetramine-hydroquinone system reveal that higher temperatures, reagents concentrations, and pH induce quicker gelation processes. Hexamethylenetetramine is salient crosslinking agent compared to hydroquinone. Contrarily, the incremental of salinity prolong the gelation time. Predictions on polymer gelation time with Random Forest algorithm perform better among Artficial Neural Network, Convolutional Neural Network, and K-Nearest Neighbor.

Thermo-/pH-Dual-Sensitive PEG/PAMAM Nanogel: Reaction Dynamics and Plugging Application of CO2 Channeling.

Smart hydrogels, owing to their exceptional viscoelastic and deformable capacity in response to environmental stimulation involving temperature and pH, have been successfully applied in oilfields for purposes such as water and/or gas shutoff treatments. However, the CO2 breakthrough problem in low permeability reservoirs has not been well solved. In this work, a rheological method-based Avrami dynamics model and Dickinson dynamics model were employed to investigate the dynamic gelation process of thermo-/pH-dual-sensitive PEG/PAMAM nanogels to further our understanding of the microstructure of their gelation and pertinence plugging application. Plugging experiments were performed by alternating injections of CO2 and hydrogel solution in a slug type on three fractured low permeability cores with a backpressure of 13 MPa. The nanogels presented a secondary growth pattern from three to one dimension from micrometer to nanometer size with a morphological transformation from a sphere to an irregular ellipsoid or disk shape. The phase transition temperature was 50 °C, and the phase transition pH was 10. If both or either were below these values, the hydrogel swelled; otherwise, it shrank. Plugging results show that the plugging efficiency was higher than 99%. The maximum breakthrough pressure was 19.93 MPa, and the corresponding residual pressure remained 17.64 MPa for a 10 mD core, exhibiting great plugging performance and high residual resistance after being broken through by CO2.

Comprehensive Review of Polymer and Polymer Gel Treatments for Natural Gas-Related Conformance Control.

Conformance problems often exist in natural gas-related activities, resulting in excessive water production from natural gas production wells and/or excessive natural gas production from oil production wells. Several mechanical and chemical solutions were reported in the literature to mitigate the conformance problems. Among the chemical solutions, two classes of materials, namely polymer gels and water-soluble polymers, have been mostly reported. These systems have been mainly reviewed in several studies for their applications as water shutoff treatments for oil production wells. Natural gas production wells exhibit different characteristics and have different properties which could impact the performance of the chemical solutions. However, there has not been any work done on reviewing the applications of these systems for the challenging natural gas-related shutoff treatments. This study provides a comprehensive review of the laboratory evaluation and field applications of these systems used for water control in natural gas production wells and gas shutoff in oil production wells, respectively. The first part of the paper reviews the in-situ polymer gel systems, where both organically and inorganically crosslinked systems are discussed. The second part presents the water-soluble polymers with a focus on their disproportionate permeability reduction feature for controlling water in gas production wells. The review paper provides insights into the reservoir conditions, treatment design and intervention, and the success rate of the systems applied. Furthermore, the outcomes of the paper will provide knowledge regarding the limitations of the existing technologies, current challenges, and potential paths forwards.

Experimental Investigation of Low-Concentrated Nanocomposite Polymer Gels for Water Shutoff Treatment Under Reservoir Conditions

Summary Excessive water production is one of the main challenges in mature oil fields. Applying polymer gels has proven to be an effective chemical treatment to this problem. Because of some limitations in application of polymer gels in oil reservoirs with harsh conditions, using nanoparticles (NPs) in gel structure has been proposed recently to improve the performance of such systems. However, while main body of the previous studies has only focused on improvement of bulk properties of polymer gels in presence of NPs, there is a serious lack of data on their performance in porous media. In this study, we have conducted a comprehensive investigation on application of two new nanocomposite polymer gels through bulk-gel static tests and dynamic core displacement tests. Fe2O3 and NiO NPs at low concentrations (<100 mg·L−1) in AN125VLM/chromium acetate polymer gel system were used. The results of bulk bottle tests at 82℃ demonstrated that the nanocomposite gel systems have the same gelation time and gel strength as the NPs-free gel. Swelling ratio measurements were also performed in a high-salinity formation water (268 949 mg·L−1), and accordingly, while NiO NPs deteriorated the swelling behavior of the gel system, Fe2O3 NPs showed a positive impact. The results of the strain-sweep test demonstrated relatively similar linear viscoelastic region and thus the same gel strength for all gel samples. In addition, the results of the thermogravimetric analysis (TGA) revealed that Fe2O3 NPs had a minor positive impact on thermal resistance of the polymer gel system. Finally, high pressure-high temperature coreflooding experiments were carried out on three sandstone reservoir core samples. Although the NPs-free gel showed a desirable level of disproportionate permeability reduction, the injection of Fe2O3 nanocomposite gel showed unsatisfactory results and caused rock permeability degradation. The pressure drop trend and deposition of polymer gel particles at the upstream injection side confirmed the aggregation and plugging effect of NPs during injection. Our findings demonstrate the critical aspect of dynamic core displacement testing of nanocomposite gels before their use for field applications.

Experimental Investigation of a Novel Nanocomposite Particle Gel for Water Shutoff Treatment in Mature Oilfields.

Conventional preformed particle gels suffer from insufficient salt tolerance and weak mechanical properties after water absorption, which reduce the water shutoff effect in mature oilfields. In this paper, a nanocomposite particle gel (NCPG) is synthesized by copolymerization of acrylamide (AM) and 2-acrylamido-2-methylpropane sulfonic acid (AMPS) using laponite RD (LPT) as a physical cross-linker and N,N-methylene-bisacrylamide (MBA) as a chemical cross-linker via in situ free radical polymerization. Compared with the NCPG without LPT, both the swelling rate and mechanical properties of NCPG added with LPT are found to be improved. In addition, the pore sizes of the network of the swollen NCPG are smaller than those of the sample without LPT, and the thermal stability is also slightly enhanced. The swelling rate of NCPG increases with increasing AMPS concentration. The water absorbency of NCPG first increases and then decreases with increasing MBA and APS concentrations. The NCPG is sensitive to alkaline medium due to the presence of sulfonic acid groups on the molecular chains of the NCPG. The synthesized NCPG exhibits good salt tolerance at 80 °C in formation water. The plugging rate of the NCPG to a sand-pack is above 90%, and the residual resistance factor reaches 19.2 under reservoir conditions. These results indicate that the NCPG may have potential application for water shutoff treatment in mature oilfields.

A New Strategy for Pre-Selecting Gas Wells for the Water Shut-Off Treatment Based on Geological Integrated Data

This article presents a new analytical procedure for pre-selecting gas wells for water shut-off treatments based on available at hand results of an analysis of integrated geological, reservoir and exploitation data. Attention was paid to assess the possibility of the appearance of cross flows between layers in the near wellbore zone. Their appearance always eliminated the well as a candidate for the treatment. The basis for assessing the possibility of the emergence of cross flows was based on the assessment of the presence or absence of impermeable barriers (e.g., shales or anhydrite) in intervals, completed by perforation. For this assessment, well logging data were used, which were carried out in different years with the use of various types of probes. Based on modified quantitative and qualitative interpretation techniques, permeable and impermeable layers were separated in the analysed borehole sections. In some cases, in the absence of other data, well logs are the only source of information from which a vertical profile of horizontal permeability can be made. The article describes the verification process carried out for the eight wells situated in the area of the Carpathian Foredeep, which have been preselected by the operator. As part of this procedure, the available geological, reservoir and exploitation data were used, and a preliminary assessment of the possibility of implementing the obtained results into other wells and gas fields in the area of the Carpathian Foredeep was carried out. On the basis of the well ranking, two out of the eight analysed wells were recommended as candidates for water shut-off treatment.