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Collaborating Authors
Preparation and Mechanism of Stability for High-Temperature and High-Salinity Gels
Guo, Hongbin (China University of Petroleum (East China)) | Ge, Jijiang (China University of Petroleum (East China) (Corresponding author)) | Xu, Ya (China University of Petroleum (East China)) | Lv, Qi (China University of Petroleum (East China)) | Li, Ziwei (China University of Petroleum (East China)) | Zhou, Daiyu (Research Institute of Exploration and Development, Tarim Oilfield Company, PetroChina) | Tao, Zhengwu (Research Institute of Exploration and Development, Tarim Oilfield Company, PetroChina)
Summary By using an acrylamide (AM)-acrylamide propyl sulfonate (AMPS) copolymer crosslinked with hydroquinone (HQ) and hexamethylenetetramine (HMTA), a stable gel was prepared at 150℃ in simulated brine with a salinity of 25×10 mg/L. The gelation time, strength, and thermal stability of gel were investigated, and the results indicated that the dosage of the crosslinker was the key factor controlling the stability and gelation time of gel. When the polymer concentration was more than 0.7 wt% and the concentrations of HQ and HMTA were more than 0.2 wt%, respectively, a gel aged under high temperature and high salinity for 180 days could be obtained, but its gelation time was short and could be extended by adding lauramidopropyl hydroxy sulfobetaine (LHSB). When the crosslinker concentration was low, the gel would exhibit syneresis problems after aging at 150℃. Cryo-scanning electron microscopy (cryo-SEM), C nuclear magnetic resonance (C-NMR), X-ray photoelectron spectroscopy (XPS), and Fourier transform infrared spectroscopy (FT-IR) analyses showed that the presence of AMPS in the crosslinked polymer controlled the gel resistance to high temperature and high salinity. Using AM-AMPS copolymer with high AMPS content and regulating the crosslinker concentration can effectively inhibit the intramolecular catalytic hydrolysis of AMPS and enhance the stability of gel. The research results could guide the design and development of gels for conformance control in high-temperature and high-salinity reservoirs.
am-amp copolymer, asia government, chemical flooding methods, china government, concentration, crosslinked polymer, crosslinker concentration, data quality, drilling fluid chemistry, drilling fluid formulation, drilling fluid property, drilling fluid selection and formulation, drilling fluids and materials, enhanced recovery, fluid loss control, gel, gelant, hydrolysis, lhsb, polymer, polymer concentration, salinity, simulated brine, stability, storage modulus, Syneresis, thermal stability, united states government, Upstream Oil & Gas
Country:
- Asia > China (1.00)
- North America > United States > Texas (0.46)
Industry:
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
Oilfield Places:
- Asia > China > Xinjiang Uyghur Autonomous Region > Tarim Basin > Lunnan Field (0.98)
- South America > Venezuela (0.89)
- Europe > United Kingdom > North Sea (0.89)
- (3 more...)
SPE Disciplines:
An Extended Unified Viscoelastic Model for Predicting Polymer Apparent Viscosity at Different Shear Rates
Zeynalli, Mursal (Petroleum Engineering Department, Khalifa University of Science and Technology, SAN Campus (Corresponding author)) | Al-Shalabi, Emad Walid (Petroleum Engineering Department, Khalifa University of Science and Technology, SAN Campus) | AlAmeri, Waleed (Petroleum Engineering Department, Khalifa University of Science and Technology, SAN Campus)
Summary Polymer flooding is one of the most commonly used chemical enhanced oil recovery (EOR) methods. Conventionally, this technique was believed to improve macroscopic sweep efficiency by sweeping only bypassed oil. Nevertheless, recently it has been found that polymers exhibiting viscoelastic behavior in the porous medium can also improve microscopic displacement efficiency resulting in higher additional oil recovery. Therefore, an accurate prediction of the complex rheological response of polymers in porous media is crucial to obtain a proper estimation of incremental oil to polymer flooding. In this paper, a novel viscoelastic model is proposed to comprehensively analyze the polymer rheological behavior in porous media. This proposed model was developed and validated using 30 coreflooding tests obtained from the literature and further verified against a few existing viscoelastic models. The proposed viscoelastic model is considered an extension of the unified apparent viscosity model provided in the literature and is termed as extended unified viscoelastic model (E-UVM). The main advantage of the proposed model is its ability to capture the polymer mechanical degradation at ultimate shear rates primarily observed near wellbores. Moreover, the fitting parameters used in the model were correlated to rock and polymer properties using machine learning technique, significantly reducing the need for time-consuming coreflooding tests for future polymer screening works. Furthermore, the E-UVM was implemented in MATLAB Reservoir Simulation Toolbox (MRST) and verified against the original shear model existing in the simulator. It is worth mentioning that the irreversible viscosity drop for mechanical degradation regime was captured during implementing our model in the simulator. It was found that implementing the E-UVM in MRST for polymer non-Newtonian behavior might be more practical than the original method. In addition, the comparison between various viscosity models proposed earlier and E-UVM in the reservoir simulator showed that the latter model could yield more reliable oil recovery predictions as the apparent viscosity is modeled properly in the mechanical degradation regime, unlike UVM or Carreau models. This study presents a novel viscoelastic model that is more comprehensive and representative as opposed to other models in the literature. Furthermore, the need to conduct an extensive coreflooding experiment can be reduced by virtue of developed correlations that may be used to estimate model fitting parameters accounting for shear-thickening and mechanical degradation.
Artificial Intelligence, chemical flooding methods, concentration, correlation, degradation, drilling fluid chemistry, drilling fluid formulation, drilling fluid property, drilling fluid selection and formulation, drilling fluids and materials, e-uvm, enhanced recovery, flow in porous media, Fluid Dynamics, fluid loss control, machine learning, Modeling & Simulation, MRST, Oil Recovery, paper, permeability, polymer, polymer concentration, polymer flooding, reservoir simulation, salinity, scaling method, SPE Reservoir Evaluation, Upstream Oil & Gas, viscosity
Country:
- Europe (1.00)
- North America > United States > Texas (0.93)
- Asia > Middle East > UAE (0.68)
- South America (0.67)
Genre:
- Research Report > New Finding (0.68)
- Overview > Innovation (0.66)
Oilfield Places:
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- North America > United States > Washington > Sultan Basin (0.93)
SPE Disciplines:
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (2 more...)
Technology:
The Effect of Rheological Properties of Alkali-Surfactant-Polymer System on Residual Oil Recovery Rate After Water Flooding
Ma, Wen-guo (NorthEast Petroleum University, Petroleum Engineering Inst, Daqing, China) | Xia, Hui-fen (NorthEast Petroleum University, Petroleum Engineering Inst, Daqing, China) | Yu, Hong-yu (Fifth Oil Production Factory, Daqing Oilfield Co. Ltd, PetroChina)
Abstract Through rheological experiments and indoor core experiments, the rheological properties and oil displacement efficiency of Alkali-Surfactant-Polymer (ASP) system containing amphoteric surfactants is studied at ultralow interface tension (0.001mN/m). The effects of changing the concentration of polymer (0.5, 1.0 and 2.0g/L), alkali types (Sodium carbonate and sodium hydroxide) and concentration of Sodium carbonate (0.3-1.5%) on the rheological properties and oil displacement recovery is studied. The viscosity of ASP system increases with mass concentration of polymer increased, and the viscosity of ASP system decreased with mass concentration of Sodium carbonate increased. The viscosity of the system containing 0.6% Sodium hydroxide is higher than the system containing the same concentration of Sodium carbonate. Indoor man-made core displacement experiment results showed: With the mass concentration of polymer changing from 0.5g/L, 1.0g/L and 2.0g/L, the improving value of recovery rate is 25.26%, 21.05% and 22.1% respectively. After water flooding, with the changing of mass concentration of Sodium carbonate on ASP from 0.3%, 0.6%, 1.0% and 1.5%, the recovery rate of ASP systems is 25.26%, 21.42%, 23.81% and 35.35% respectively, the increment of recovery rate is all more than 20.0%, the Total recovery rate is 85.26%, 79.75%, 83.33% and 93.93% respectively. This research results in this paper has important guiding significance on production design.
doi: 10.2118/134064-MS
SPE-134064-MS
alkali-surfactant-polymer system, asp flooding, ASP system, chemical flooding methods, concentration, drilling fluid chemistry, drilling fluid formulation, drilling fluid property, drilling fluid selection and formulation, drilling fluids and materials, enhanced recovery, flooding system, fluid loss control, mass concentration, polymer, polymer mass concentration, recovery rate, rheological property, sodium carbonate, Upstream Oil & Gas, viscosity, viscosity curve, viscosity mpa, water flooding
Oilfield Places:
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Application of Polymer-Gel Solutions in Remediating Leakage in CO2 Storage Reservoirs
Hadi Mosleh, Mojgan (Department of Earth Science and Engineering, Royal School of Mines, Imperial College London) | Govindan, Rajesh (Department of Earth Science and Engineering, Royal School of Mines, Imperial College London) | Shi, Ji-Quan (Department of Earth Science and Engineering, Royal School of Mines, Imperial College London) | Durucan, Sevket (Department of Earth Science and Engineering, Royal School of Mines, Imperial College London) | Korre, Anna (Department of Earth Science and Engineering, Royal School of Mines, Imperial College London)
Abstract The application of crosslinked gels has seen widespread use within the petroleum industry to divert fluid flow and remediate leakage at wells. The current study aimed at investigating the effectiveness of polymer-gel treatment in remediating a potential CO2 leakage site in the subsurface. This paper presents a brief summary of the results of laboratory characterisation work carried out on polymer gels, which involved characterisation of several polymer-gel systems with respect to their working and gelation times and conducting core flooding experiments on reservoir rocks to characterise their permeability reduction behaviour. The chemical flooding reservoir simulator, UTCHEM, was used to simulate polymer injection and its subsequent gelation process in the saline aquifer model. Parameters such as polymer concentration, polymer to crosslinker ratio and pH, and their influence on the gelation process and the area of influence have been investigated. The results have shown that lower polymer to crosslinker ratios lead to a relatively higher gel concentration. On the other hand, higher polymer to crosslinker ratios result in a relatively higher area of influence, which is mainly due to the decreased viscosity and slower gelation rate. It was also found that, as the concentration of H in the injection stream increases, the rate of crosslinking decreases and the lower viscosity polymer slug migrates to the far-field region of the reservoir formation.
chemical flooding methods, co 2, concentration, crosslinker, crosslinker concentration, crosslinker ratio, drilling fluid chemistry, drilling fluid formulation, drilling fluid property, drilling fluid selection and formulation, drilling fluids and materials, Effectiveness, enhanced recovery, flow in porous media, Fluid Dynamics, fluid loss control, gel concentration, gelation process, injection, leakage, permeability, Petroleum Engineer, polymer, polymer concentration, polymer-gel treatment, Reservoir Characterization, reservoir simulation, simulator, Upstream Oil & Gas
Country:
- Europe (1.00)
- North America > United States > Texas > Travis County > Austin (0.29)
SPE Disciplines:
Abstract In preparation of a gelant solution for making crosslinked polymer gels for water shutoff applications, unpublished experiments and chemical intuition suggest that, unless hydrolyzed polyacrylamide (HPAM) polymer is fully hydrated before addition of crosslinker, the final gel will have lower than optimum mechanical strength, presumably because polymer chains need to be fully unfolded before proper crosslinking can occur. When using dry polymer, which is usually the lowest cost form on a delivered basis, this may require more equipment and a large tankage footprint. However, if conditions exist where crosslinker can be added to wetted but not fully hydrated polymer, then dry polymer and crosslinker can be blended in a small continuous flow unit, with full hydration occurring as the gelant flows downhole prior to gelation. We have evaluated gel strengths of "flowing" gels for water shut off in natural fractures and other non-matrix features as a function of time of addition of crosslinker relative to time of hydration of polymer. Gels were prepared from moderately high molecular weight HPAM crosslinked with chromium(III) acetate (CrAc) or polyethyleneimine (PEI). Crosslinker was added after either (1) initial wetting of solid polymer particles or (2) complete dissolution of the polymer. Gel strengths were determined using a common qualitative coding system. Comparisons were made for gels prepared in an identical manner, except for the timing of crosslinker addition. Samples were prepared either in fresh water or 4% NaCl brine and then hydrated either at an ambient temperature or 122 °F. Gelant viscosity and crosslink time were also characterized with a viscometer. Results of this work demonstrate that for most field applications using CrAc as crosslinker, optimum quality gel can be obtained using dry polymer and a small continuous mixing system for initial wetting of the polymer, after which the crosslinker can be added to the polymer solution on-the-fly. This practice can decrease the footprint and cost of large volume flowing gel treatments.
chemical flooding methods, concentration, crosslinked gel, crosslinker, crosslinker addition, crosslinker concentration, drilling fluid chemistry, drilling fluid formulation, drilling fluid property, drilling fluid selection and formulation, drilling fluids and materials, enhanced recovery, fluid loss control, gel, gel strength, gelant solution, gelation time, hydrated polymer, hydration, hydration technique, hydraulic fracturing, makeup water, polymer, polymer crosslinker solution, polymer gel, polymer hydration, strength, Upstream Oil & Gas
Oilfield Places:
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
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