Search Results (32)

Lost circulation has become one of the important problems restricting the speed and efficiency of oil and gas drilling and production. To address severe drilling fluid losses in high-temperature fractured formations during deep/ultra-deep well drilling, this study developed a high-temperature and high-strength gelled resin gel plugging system through optimized resin matrix selection, latent curing agent, flow regulator, filling material, etc. Comparative analysis of five thermosetting resins revealed urea-formaldehyde resin as the optimal matrix, demonstrating complete curing at 100–140 °C with a compressive strength of 9.3 MPa. An organosilicon crosslsinker-enabled water-soluble urea-formaldehyde resin achieved controlled solubility and flow–cure balance under elevated temperatures. Orthogonal experiments identified that a 10% latent curing agent increased compressive strength to 6.26 MPa while precisely regulating curing time to 2–2.5 h. Incorporating 0.5% rheological modifier imparted shear-thinning and static-thickening behaviors, synergizing pumpability with formation retention. The optimal formula (25% urea-formaldehyde resin, 10% latent curing agent, 10% high-fluid-loss filler, 0.5% rheological modifier) exhibited superior thermal stability (initial decomposition temperature 241 °C) and mechanical integrity (bearing pressure 13.95 MPa in 7 mm wedge-shaped fractures at 140 °C). Microstructural characterization confirmed interlocking crystalline layers through ether-bond crosslinking, providing critical insights for high-temperature wellbore stabilization. Full article

In response to the special requirements for shale gas reservoir stimulation, a novel environmentally responsive fracturing fluid thickener was designed and developed in this paper. N,N-dimethylhexadecylallylammonium chloride (C16DMAAC), N-vinylpyrrolidone (NVP), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), and Acrylamide (AM) were used as functional monomers, and the synthesis of the target product was achieved successfully through free radical polymerization in an aqueous solution. The findings indicated that in the optimized situation, where the total monomer mass fraction was 25%, the ratio of AM:AMPS:C16DMAAC:NVP was 15:10:3:2, the initiator mass fraction was 0.3%, the pH was 6.5, and the temperature was 60 °C, the thickener achieved a number-average molecular weight of 1.13 × 10⁶. Furthermore, its remarkable thermal stability was manifested, as it only experienced a 15% mass loss in the temperature interval spanning from 40 °C to 260 °C. Performance evaluation results indicated that, at 120 °C, the viscosity of the thickener under study increased by over 49% compared to the control group. Simultaneously, in a 0.4 wt% CaCl₂ environment, it retained a high viscosity of 54.75 mPa·s. This value was 46.61 mPa·s greater than that of the control group. Furthermore, under the conditions of a temperature of 170 °C, the fracturing fluid viscosity remained above 68 mPa·s. Regarding the flow performance, within the flow rate range from 110 to 150 L/min, it showed a remarkable drag reduction effect, achieving a maximum drag reduction rate of 70%. At 150 °C, the fracturing fluid exhibited superior proppant-carrying efficacy, with a settlement rate that was 26.1% lower than that of the control group. The viscosity and residue content of the gel-broken fracturing fluid exceeded the requirements of industry standards. In particular, the residue content of this fracturing fluid was 21% lower than that of the control group. The research results provide an environmentally responsive fracturing fluid thickener with excellent performance for shale gas reservoir stimulation. Full article

To enhance oil and gas recovery, a novel hydrophobic terpolymer was synthesized via free radical polymerization. The terpolymer consists of acrylamide, acrylic acid, and hydrophobic monomers, and is used as a hydraulic fracturing fluid thickener for freshwater environments. Hydrophobic groups were introduced into terpolymer to improve its tackiness and temperature resistance. The conformation and key parameters of hydrophobic monomers at different temperatures were investigated through a combination of experiments and molecular dynamics simulations. These methods were employed to elucidate the mechanism behind its high-temperature resistance. The experiment results show that, at concentrations between 0.2% and 0.4%, significant intermolecular aggregation occurs, leading to a substantial increase in solution viscosity. Configuring the base fluid of synthetic polymer fracturing fluid with 1% doping, the apparent viscosities of the base fluid were 129.23 mPa·s and 133.11 mPa·s, respectively. The viscosity increase rate was 97%. The base fluid was crosslinked with 1.5% organozirconium crosslinker to form a gel. The controlled loss coefficient and loss velocity of the filter cake were C₃ = 0.84 × 10⁻³ m/min^1/2 and v_c = 1.40 × 10⁻⁴ m/min at 90 °C, meeting the technical requirements for water-based fracturing fluid. Molecular dynamics simulations revealed that the radius of gyration of the hydrophobically linked polymer chain segments decreases as the temperature increases. This is due to the increased thermal motion of the polymer chain segments, resulting in less stretching and intertwining of the chains. As a result, the polymer chains move more freely, which decreases the viscosity of the solution. In conclusion, the proposed fracturing fluid thickener system demonstrates excellent overall performance and shows significant potential for application in oil and gas recovery. Full article

CO₂ fracturing technology has been widely used to develop unconventional oil and gas reservoirs such as shale oil and gas and tight sandstone reservoirs. To mitigate the issues of low viscosity and high friction associated with traditional CO₂ fracturing technology, this paper proposes CO₂ quasi-dry fracturing technology. Taking the low permeability tight sandstone reservoir in Block X of T oilfield as the research object, indoor experiments were conducted to optimize the ratio of CO₂ quasi-dry fracturing fluid. Numerical simulation was used to select the optimal construction displacement using FracproPT, and the temperature and pressure changes in the reservoir and the grid after CO₂ injection were analyzed using CMG to lay a foundation for the production practice. The results show that the fracturing fluid formulation system is 70% liquid CO₂ + 30% water with 1.2% water-based thickener APQD-6 and 1.2% CO₂ thickener APFR-2; the optimal construction displacement is 3 m³/min, and the fracture half-length is 206.2 m; the reservoir temperature responds to the CO₂ injection volume more rapidly than the pressure, which indicates that CO₂ has a more significant effect on the temperature. The field application results show that the reservoir temperature responds more rapidly to the CO₂ injection volume than the pressure, indicating that CO₂ has a more significant effect on temperature. The field application results are remarkable. This operation successfully achieved the key parameter indicators of the highest sand ratio of 10% and the average sand ratio of 6%. The daily liquid production of the well was stable at 1.6 t, the daily gas production jumped by 820 m³, and the daily oil production also increased by 0.7 t. The effect of single-well stimulation is very prominent, which strongly verifies the feasibility and effectiveness of CO₂ quasi-dry fracturing technology exploiting low-porosity and low-permeability reservoirs. This practical result provides valuable practical guidance for developing similar reservoirs. It is expected to promote the further development and application of low porosity and low permeability reservoir development technology. Full article

In order to solve the problems of long dissolution and preparation time, cumbersome preparation, and easy moisture absorption and deterioration during storage or transportation, acrylamide (AM), acrylic acid (AA), sodium p-styrene sulfonate (SSS), and cetyl dimethylallyl ammonium chloride (DMAAC-16) were selected as raw materials, and the emulsion thickener P(AM/AA/SSS), which can be instantly dissolved in water and rapidly thickened, was prepared by the reversed-phase emulsion polymerization method. DMAAC-16, the influence of emulsifier dosage, oil–water ratio, monomer molar ratio, monomer dosage, aqueous pH, initiator dosage, reaction temperature, reaction time, and other factors on the experiment was explored by a single-factor experiment, and the optimal process was determined as follows: the oil–water volume ratio was 0.4, the emulsifier dosage was 7% of the oil phase mass, the initiator dosage was 0.03% of the total mass of the reaction system, the reaction time was 4 h, the reaction temperature was 50 °C, the aqueous pH was 6.5, and the monomer dosage was 30% of the total mass of the reaction system (monomeric molar ratio n(AM):n(AA):n(SSS):n(DMAAC-16) = 79.2:20:0.5:0.3). X-ray diffraction analysis (XRD), infrared spectroscopy (FTIR), thermogravimetric analysis (TGA), and scanning electron microscopy analysis were carried out on the polymerization products. At the same time, a series of performance test experiments such as thickening performance, temperature and shear resistance, salt resistance, sand suspension performance, core damage performance, and fracturing fluid flowback fluid reuse were carried out to evaluate the comprehensive effect and efficiency of the synthetic products, and the results show that the P(AM/AA/SSS/DMAAC-16) polymer had excellent solubility and excellent properties such as temperature and shear resistance. Full article

The drilling fluid loss or lost circulation via near-wellbore fractures is one of the most critical problems in the drilling of deep oil and gas resources, which causes other problems such as difficulty in achieving wellbore pressure control and reservoir damage. The conventional treatment is to introduce granular lost circulation material (LCM) into the drilling fluid to plug the fractures. As the migration mechanism of the LCM in irregular fractures has not been completely figured out as of yet, the low success rate of fracture plugging and repeated drilling fluid loss still obstruct the exploitation of deep oil and gas resources. In this paper, the spatial data of actual rock fracture surfaces were obtained through structured light scanning, and an irregular surface identical to the rock was machined on a transparent polymethyl methacrylate plate. On this basis, a visualization experimental apparatus for fracture plugging was established, and the fracture flow space of this device was consistent with that of the actual rock fracture. Employing cylindrical nylon particles as LCM, a visualization experiment study was carried out to investigate the process of LCM bridging and fracture plugging and the influence of LCM injection methods. The experimental results show that the process of fracture plugging includes the sporadic bridging, plugging zone extension and merging, thickening of the plugging zone and complete plugging of the fracture. It was observed in the visualization experiment that a large number of small particles flow deep into the fracture in the traditional fracture plugging method, where all types and sizes of LCM are injected at one time. After changing the injection sequence, which injects the large particles first and the small particles subsequently, it is found that the large particles will form single-particle bridging at a specific depth of the fracture, intercepting subsequently injected particles and thickening the plugging zone, which finally increases the area of the plugging zone by 19%. The visualization experiment results demonstrate that modifying the LCM injection method significantly enhances both the LCM utilization rate and the fracture plugging effect, thereby reducing reservoir damage. This is conducive to reducing the drilling cost of fractured formation. Additionally, the visualized experimental approach introduced in this study can also benefit other research areas, including proppant placement and solute transport in rock fractures. Full article

To circumvent the numerous deficiencies inherent to water-based fracturing fluids and the associated greenhouse effect, CO₂ fracturing fluids are employed as a novel reservoir working fluid for reservoir reconstruction in unconventional oil fields. Herein, a mathematical model of CO₂ fracturing crack propagation based on seepage–stress–damage coupling was constructed for analysing the effects of different drilling fluid components and reservoir parameters on the crack propagation behaviour of low permeability reservoirs. Additionally, the fracture expansion mechanism of CO₂ fracturing fluid on low permeability reservoirs was elucidated through mechanical and chemical analysis. The findings demonstrated that CO₂ fracturing fluid can effectively facilitate the expansion of cracks in low-permeability reservoirs, and thickener content, reservoir pressure, and reservoir parameters were identified as influencing factors in the expansion of reservoir cracks and the evolution of rock damage. The 5% CO₂ thickener can increase the apparent viscosity and fracture length of CO₂ fracturing fluid to 5.12 mPa·s and 58 m, respectively, which are significantly higher than the fluid viscosity (0.04 mPa·s) and expansion capacity (13 m) of pure CO₂ fracturing fluid. Furthermore, various other factors significantly influence the fracture expansion capacity of CO₂ fracturing fluid, thereby offering technical support for fracture propagation in low-permeability reservoirs and enhancing oil recovery. Full article

Improving the chemical structure of the cross-linker is a potential method for reducing reservoir pollution and enhancing the fracturing efficiency of shale reservoirs. In this investigation, a three-dimensional (3-D) spherical cross-linker comprising branched chains was synthesized, and the 3-D structure of the cross-linker was analyzed through scanning electron microscopy (SEM). Furthermore, we constructed a multifunctional coupled collaborative evaluation device that can be used to evaluate numerous properties associated with water-based fracturing fluids, including fluid viscosity, adsorption capacity, and water pollution. Meanwhile, the influence of varying reservoir conditions and cross-linker content on the fluid viscosity of water-based fracturing fluids and the potential for reservoir contamination has been evaluated and elucidated. The results indicated that the synthesized cross-linker exhibited a superior environmental protection of the shale reservoir and an enhanced capacity for thickening fracturing fluids in comparison to commercial cross-linkers. Moreover, cross-linker content, reservoir temperature, reservoir pressure, and fracture width can affect fluid viscosity and reservoir residual in different trends. The addition of 0.3% nano-cross-linker (Synthetic products) to a water-based fracturing fluid resulted in an apparent viscosity of 160 mPa·s at 200 °C, and the adsorption capacity and water content of the shale reservoir were only 0.22 µg/m³ and 0.05 µg/L, respectively. Additionally, an elevation in reservoir temperature resulted in a reduction in the adsorption capacity. However, the cross-linker content in groundwater underwent a notable increase, and the cross-linker residue in water increased by 0.009 µg/L. The impact of reservoir pressure on fluid viscosity and groundwater pollution potential exhibited an inverse correlation compared to that of reservoir temperature, and the above two parameters changed by +18 mPa·s and −0.012 µg/L, respectively. This investigation provides basic data support for the efficient fracturing and reservoir protection of shale reservoirs. Full article

The utilization of CO₂ foam gel fracturing fluid offers several significant advantages, including minimal reservoir damage, reduced water consumption during application, enhanced cleaning efficiency, and additional beneficial properties. However, several current CO₂ foam gel fracturing fluid systems face challenges, such as complex preparation processes and insufficient viscosity, which limit their proppant transport capacity. To address these issues, this work develops a novel CO₂ foam gel fracturing fluid system characterized by simple preparation and robust foam stability. This system was optimized by incorporating a thickening agent CZJ-1 in conjunction with a foaming agent YFP-1. The results of static sand-carrying experiments indicate that under varying temperatures and sand–fluid ratio conditions, the proppant settling velocity is significantly low. Furthermore, the static sand-carrying capacity of the CO₂ foam gel fracturing fluid exceeds that of the base fluid. The stable and dense foam gel effectively encapsulates the proppant, thereby improving sand-carrying capacity. In high-temperature shear tests, conducted at a shear rate of 170 s⁻¹ and a temperature of 110 °C for 90 min, the apparent viscosity of the CO₂ foam gel fracturing fluid remained above 20 mPa·s after shear, demonstrating excellent high-temperature shear resistance. This work introduces a novel CO₂ foam gel fracturing fluid system that is specifically tailored for low-permeability reservoir fracturing and extraction. The system shows significant promise for the efficient development of low-pressure, low-permeability, and water-sensitive reservoirs, as well as for the effective utilization and sequestration of CO₂. Full article

The efficient development of carbonate rock reservoirs with rich oil and gas resources has become a hot topic and a focal point in the current oil and gas industry. The development of carbonate rock oil and gas reservoirs differs from that of sandstone reservoirs. Although gas flooding, water flooding, and chemical flooding have been carried out in recent years, the development is still unsatisfactory, and the on-site application of technologies such as nanoparticles is on the rise. For the future development of acid fracturing technology, accurate reservoir geological description, core printing based on additive manufacturing technology, the development of new acid fracturing techniques, and the research and development of acid fracturing equipment will have great research potential and economic value in the development of carbonate rock oil and gas reservoirs. Under the development background of high-temperature deep reservoirs, this paper comprehensively reviews unconventional acidizing fracturing fluids in carbonate rock oil and gas reservoirs. We introduce the main components, corresponding mechanisms of action, current research achievements, and advantages of promising acid fracturing fluids, including thickened acids. We focus on the application and limitations under harsh conditions of high temperature and high salinity while also focusing on the development of thickened acid fracturing technology. The thickening agent is the core of a thickened acid solution. Therefore, this article fully reviews the structure, sources, advantages and disadvantages, as well as the current development status of biological, cellulose, and synthetic polymer thickeners. Synthetic polymers, low-molecular-weight polymers, and small-molecular compound crosslinkers provide clues for temperature and salt-resistant thickeners and also promote the development of tight reservoirs. Full article

Water-based fracturing fluid has recently garnered increasing attention as an alternative oilfield working fluid for propagating reservoir fractures and transporting sand. However, the low temperature resistance and stability of water-based fracturing fluid is a significant limitation, restricting the fracture propagation and gravel transport. To effectively ameliorate the temperature resistance and sand-carrying capacity, a modified cross-linker with properties adaptable to varying reservoir conditions and functional groups was synthesized and chemically characterized. Meanwhile, a multifunctional collaborative progressive evaluation device was developed to investigate the rheology and sand-carrying capacity of fracturing fluid. Utilizing molecular dynamics simulations, the thickening mechanism of the modified cross-linker and the sand-carrying mechanism of the fracturing fluid were elucidated. Results indicate that the designed cross-linker provided a high viscosity stability of 130 mPa·s and an excellent sand-carrying capacity of 15 cm² at 0.3 wt% cross-linker content. Additionally, increasing reservoir pressure exhibited enhanced thickening and sand-carrying capacities. However, a significant inverse relationship was observed between reservoir temperature and sand-carrying capacity, attributed to changes in the drag coefficient and thickener adsorption. These results verified the effectiveness of the cross-linker in enhancing fluid viscosity and sand-carrying capacity as a modified cross-linker for water-based fracturing fluid. Full article

The following study presents the results of research in the field of the performance of geopolymers consisting of Class F fly ash with an alkaline activator solution consisting only of sodium metasilicate (Na₂SiO₃) and water. The performances of this geopolymer are compared to the those of American Petroleum Institute (API) Class G cement. This comparison is to evaluate the potential of the geopolymer as an alternative to cement in cementing hydrocarbon wells in the oil and gas industry. The gap in the research is determining the performance properties that restrict the use of fly ash in the oil and gas industry. Using only sodium metasilicate as an activator with water, the solution creates a strong binding gel for the geopolymer and activates the aluminosilicate properties of the fly ash. This geopolymer is compared with Class G cement without additives to determine their base performances in high pressure and high temperature conditions, as well as note any properties that are affected in the process. This commences by formulating recipes of these two materials from workable ratios and concentrations. The ratios are narrowed down to the best working models to proceed to comparative performance testing. The tests included exploring their vital performances in fluid loss and thickening time. The results produced suggest that Class G cement generally has less fluid loss at low temperature than the geopolymer but could not maintain its integrity and structure as temperatures increased. Class G cement exhibited stability, consistencies of 100 Bcs (Bearden Consistency Units), and a faster thickening time of 1 h and 48 min when placed under high temperature and high-pressure conditions, respectively. However, the geopolymer showed more consistency regarding fluid loss with respect to rising pressure and temperature, and smoother, less fractured samples emerging from both tests. Though the geopolymer showed stronger performances in thickening and water retention, the experiments showed that it is not a uniform and consistent material like Class G cement. Through the use of different additives and intricate design, the sample may show success, but may prove more difficult and complex to apply than the industry standard and uniform content of Class G cement. Full article

Dual networks formed by entangled polymer chains and wormlike surfactant micelles have attracted increasing interest in their application as thickeners in various fields since they combine the advantages of both polymer- and surfactant-based fluids. In particular, such polymer-surfactant mixtures are of great interest as novel hydraulic fracturing fluids with enhanced properties. In this study, we demonstrated the effect of the chemical composition of an uncharged polymer poly(vinyl alcohol) (PVA) and pH on the rheological properties and structure of its mixtures with a cationic surfactant erucyl bis(hydroxyethyl)methylammonium chloride already exploited in fracturing operations. Using a combination of several complementary techniques (rheometry, cryo-transmission electron microscopy, small-angle neutron scattering, and nuclear magnetic resonance spectroscopy), we showed that a small number of residual acetate groups (2–12.7 mol%) in PVA could significantly reduce the viscosity of the mixed system. This result was attributed to the incorporation of acetate groups in the corona of the micellar aggregates, decreasing the molecular packing parameter and thereby inducing the shortening of worm-like micelles. When these groups are removed by hydrolysis at a pH higher than 7, viscosity increases by five orders of magnitude due to the growth of worm-like micelles in length. The findings of this study create pathways for the development of dual semi-interpenetrating polymer-micellar networks, which are highly desired by the petroleum industry. Full article

Two acid thickeners, ADMC and ADOM, were prepared by aqueous solution polymerization using acrylamide (AM) and methacryloyloxyethyl trimethyl ammonium chloride (DMC) as raw materials, with or without the introduction of octadecyl polyoxyethylene ether methacrylate (OEMA). It was characterized by FTIR, ¹H NMR, and the fluorescence spectra of pyrene. The double-layer thickening mechanism of ADOM was proved by comparing the thickening and rheological properties of ADMC and ADOM tested by a six-speed rotary viscometer and a HAKKE MARSIV rheometer during the acidification process. The results showed that the synthetic product was the target product; the first stage of the self-thickening ADOM fresh acid solution during high-temperature acidification was mainly affected by Ca²⁺ concentration, and the second stage of self-thickening was mainly affected by temperature. The residual viscosity of the 0.8 wt% ADOM residual acid solution was 250, 201.5, and 61.3 mPa·s, respectively, after shearing at 90, 120, and 150 °C for 60 min at a shear rate of 170 s⁻¹. The thickening acid ADOM with a hydrophobic association structure has good temperature resistance and shear resistance, which can be used for high-temperature deep-well acid fracturing. In addition, no metal crosslinking agent was introduced in the system to avoid damage to its formation, and ADOM exhibited good resistance to Ca²⁺, which could provide ideas for the reinjection of the acidizing flowback fluid. It also has certain advantages for environmental protection. Full article

We report on the effect of a hydrocarbon (n-dodecane) on the rheological properties and shapes of the hybrid wormlike micelles (WLMs) of a surfactant potassium oleate with an embedded polymer poly(4-vinylpyridine). With and without hydrocarbon solutions, the hybrid micelles exhibit the same values of viscosity at shear rates typical for hydraulic fracturing (HF) tests, as solutions of polymer-free WLMs. Therefore, similar to WLMs of surfactants, they could be applied as thickeners in HF fluids without breakers. At the same time, in the presence of n-dodecane, the hybrid micelles have much higher drag-reducing efficiency compared to microemulsions formed in polymer-free systems since they form “beads-on-string” structures according to results obtained using cryo-transmission electron microscopy (cryo-TEM), dynamic-light scattering (DLS), and small-angle X-ray scattering (SAXS). Consequently, they could also act as drag-reducing agents in the pipeline transport of recovered oil. Such a unique multi-functional additive to a fracturing fluid, which permits its concurrent use in oil production and oil transportation, has not been proposed before. Full article