Disproportionate Permeability Reduction When a Silicate Gel is Formed In-Situ to Control Water Production

2001 ◽  
Author(s):  
C.A. Grattoni ◽  
X.D. Jing ◽  
R.W. Zimmerman
Keyword(s):  
Permeability Reduction ◽  
Water Production ◽  
Control Water

Polymer in-Situ Rheology in Carbonate Reservoirs

2021 ◽  
Author(s):  
Tormod Skauge ◽  
Kenneth Sorbie ◽  
Ali Al-Sumaiti ◽  
Shehadeh Masalmeh ◽  
Arne Skauge
Keyword(s):  
Polymer Solution ◽  
Carbonate Rock ◽  
High Salinity ◽  
Polymer Flooding ◽  
Resistance Factor ◽  
Carbonate Reservoirs ◽  
Permeability Reduction ◽  
Polymer Flood ◽  
Core Flood

Abstract A large, untapped EOR potential may be extracted by extending polymer flooding to carbonate reservoirs. However, several challenges are encountered in carbonates due to generally more heterogeneous rock and lower permeability. In addition, high salinity may lead to high polymer retention. Here we show how in-situ viscosity varies with permeability and heterogeneity in carbonate rock from analysis of core flood results and combined with review of data available in literature. In-situ rheology experiments were performed on both carbonate outcrop and reservoir cores with a range in permeabilities. The polymer used was a high ATBS content polyacrylamide (SAV10) which tolerates high temperature and high salinity. Some cores were aged with crude oil to generate non-water-wet, reservoir representative wettability conditions. These results are compared to a compilation of literature data on in-situ rheology for predominantly synthetic polymers in various carbonate rock. A systematic approach was utilized to derive correlations for resistance factor, permeability reduction and in-situ viscosity as a function of rock and polymer properties. Polymer flooding is applied to improve sweep efficiency that may occur due to reservoir heterogeneities (large permeability contrasts, anisotropy, thief zones) or adverse mobility ratio (high mobility contrast oil-brine). In flooding design, the viscosity of the polymer solution in the reservoir, the in-situ viscosity, is an essential parameter as this is tuned to correct the mobility difference and to improve sweep. The viscosity is estimated from rheometer/viscometer measurements or, better, measured in laboratory core flood experiments. However, upscaling core flood experiments to field is challenging. Core flood experiments measure differential pressure, which is the basis for the resistance factor, RF, that describes the increased resistance to flow for polymer relative to brine. However, the pressure is also influenced by several other factors such as the permeability reduction caused by adsorption and retention of polymer in the rock, the tortuosity of the rock and the viscosity of the flowing polymer solution. Deduction of in-situ viscosity is straight forward using Darcy's law but the capillary bundle model that is the basis for applying this law fails for non-Newtonian fluids. This is particularly evident in carbonate rock. Interpretation of in-situ rheology experiments can therefore be misleading if the wrong assumptions are made. Polymer flooding in carbonate reservoirs has a large potential for increased utilization of petroleum reserves at a reduced CO2 footprint. In this paper we apply learnings from an extensive core flood program for a polymer flood project in the UAE and combine this with reported literature data to generate a basis for interpretation of in-situ rheology experiments in carbonates. Most importantly, we suggest a methodology to screen experiments and select data to be used as basis for modelling polymer flooding. This improves polymer flood design, optimize the polymer consumption, and thereby improve project economy and energy efficiency.

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

SPE Journal ◽  
2020 ◽  
pp. 1-15
Author(s):  
Gang Li ◽  
Lifeng Chen ◽  
Meilong Fu ◽  
Lei Wang ◽  
Yadong Chen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Gelation Time ◽  
Horizontal Wells ◽  
Uniform Grid ◽  
Drilling Fluids ◽  
Water Production ◽  
Water Control ◽  
Recovery Coefficient ◽  
Metastable Structure ◽  
Control Water

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.

scholarly journals Evaluating the accuracy of two in situ optical sensors to estimate DOC concentrations for drinking water production

2020 ◽  
Vol 6 (10) ◽  
pp. 2891-2901
Author(s):  
S. Hoffmeister ◽  
K. R. Murphy ◽  
C. Cascone ◽  
J. L. J. Ledesma ◽  
S. J. Köhler
Keyword(s):  
Drinking Water ◽  
Optical Sensors ◽  
Water Production ◽  
Production Processes ◽  
Doc Concentration ◽  
Drinking Water Production

Fluorescence and absorbance based sensors for DOC concentration estimations can help in optimizing drinking water production processes.

scholarly journals Anoxic-biocathode microbial desalination cell as a new approach for wastewater remediation and clean water production

2020 ◽  
Vol 81 (3) ◽  
pp. 550-563
Author(s):  
Simone Perazzoli ◽  
José Pedro de Santana Neto ◽  
Hugo M. Soares
Keyword(s):  
Bacterial Abundance ◽  
Microbiological Analysis ◽  
Anode Chamber ◽  
Water Production ◽  
Wastewater Remediation ◽  
New Approach ◽  
Carbon And Nitrogen ◽  
Microbial Desalination Cell ◽  
Conversion Efficiencies

Abstract Bioelectrochemical systems are emerging as a promising and friendly alternative to convert the energy stored in wastewater directly into electricity by microorganisms and utilize it in situ to drive desalination. To better understand such processes, we propose the development of an anoxic biocathode microbial desalination Cell for the conversion of carbon- and nitrogen-rich wastewaters into bioenergy and to perform salt removal. Our results demonstrate a power output of 0.425 W m−3 with desalination, organic matter removal and nitrate conversion efficiencies of 43.69, 99.85 and 92.11% respectively. Microbiological analysis revealed Proteobacteria as the dominant phylum in the anode (88.45%) and biocathode (97.13%). While a relatively higher bacterial abundance was developed in the anode chamber, the biocathode showed a greater variety of microorganisms, with a predominance of Paracoccus (73.2%), which are related to the denitrification process. These findings are promising and provide new opportunities for the development and application of this technology in the field of wastewater treatment to produce cleaner water and conserve natural resources.

Influence of Sol–Gel Conditions on the Growth of Thiol-Functionalized Silsesquioxanes Prepared by In Situ Water Production

2016 ◽  
Vol 16 (3) ◽  
pp. 3030-3038 ◽  
Author(s):  
Evgeny Borovin ◽  
Emanuela Callone ◽  
Benjamin Papendorf ◽  
Graziano Guella ◽  
Sandra Diré
Keyword(s):  
Sol Gel ◽  
Water Production

Gel Systems for Controlling CO2 Mobility in Carbon Dioxide Miscible Flooding

1999 ◽  
Vol 2 (02) ◽  
pp. 205-210 ◽  
Author(s):  
M. Raje ◽  
K. Asghari ◽  
S. Vossoughi ◽  
D.W. Green ◽  
G.P. Willhite
Keyword(s):  
Carbon Dioxide ◽  
Polymer Solution ◽  
Supercritical Co2 ◽  
Permeability Reduction ◽  
The Third ◽  
The Core ◽  
In Situ Gelation ◽  
Miscible Flooding ◽  
Carbon Dioxide Miscible Flooding

Summary Conformance control for carbon dioxide miscible flooding using gel has not been widely attempted. Laboratory research efforts at the University of Kansas have produced promising in-situ gelation techniques aimed at this application. Three in-situ gel systems were developed and tested in laboratory cores. Two systems are based on a new biopolymer, termed KUSP1, and the third gel system uses the reaction of sulfomethylated resorcinol and formaldehyde to form a gel. KUSP1 gel systems were studied using two different methods of inducing in-situ gelation. In the first method, gelation was accomplished by injecting CO2 at low pressure into the Berea sandstone core saturated by alkaline polymer solution. Permeability reduction to the brine and CO2 in the range of 80% was achieved. Stability of the gel was tested in the presence of supercritical CO2 When supercritical CO2 was used to induce in-situ gelation, the same degree of permeability reduction was achieved. The gel remained stable after the injection of many pore volumes of supercritical CO2The second method of initiating in-situ gelation involved the use of an ester. Hydrolysis of the ester, monoethylphthalate, in the alkaline polymer solution caused the pH to drop to levels where in-situ gelation occurred. The permeability of the treated core to supercritical carbon dioxide was about 1 md which was equivalent to a permeability reduction of 95%-97% of the initial brine permeability. The third gel system, based on the reaction of sulfomethylated resorcinol and formaldehyde (SMRF), was gelled in situ and contacted with both brine and supercritical CO2. Permeabilities to carbon dioxide on the order of 1 md or less were observed. This permeability is equivalent to a reduction of about 99% in the initial brine permeability. Reduced permeabilities were maintained after injecting many pore volumes of supercritical CO2 and brine. Introduction Carbon dioxide miscible flooding is one of the most important tertiary oil recovery techniques employed in the United States. However, the process experiences major difficulties in field application because of reservoir heterogeneity due to high permeability contrast. CO2 tends to finger through the high permeability zones and bypass the oil. Early CO2 production occurs with increased recycling and other operating costs. Different methods have been investigated for improving the overall efficiency of the CO2 flooding process. In almost all these methods, attempts have been made to achieve a favorable mobility ratio by affecting the CO2 relative permeability. Examples of these methods are:water alternating gas (WAG) process,1carbon dioxide-foam process,2 andviscosified carbon dioxide process.3 Another technology which is under study is permeability reduction by in-depth placement of polymer gels. The objective of this research is to reduce the permeability in permeable zones of the reservoir. Reduction of matrix permeability in the CO2 process has been studied by other investigators.4,5 No systems were found that gave satisfactory permeability reduction when exposed to prolonged injection of CO2. Three new in-situ gel systems developed and tested in our laboratory are described in this paper. Two of these systems are based on a biopolymer termed KUSP1.6,7 The third system is based on a modification of a previously reported organic crosslinking system. Experiment The experimental program consisted of gelling each polymer system in a 1 ft Berea core which was mounted in a core holder and determining the permeability of the treated rock to brine and carbon dioxide at supercritical conditions. Five separate tests were conducted. Dispersion tests were run in some tests to estimate the pore volume contacted by the injected fluids after treatment with a gelled polymer system. Equipment and Materials Experimental Apparatus. Fig. 1 is a schematic presentation of the experimental apparatus used in this work. An ISCO syringe pump was used for injecting CO2 brine, and gel solutions into the core. All the experiments were conducted at constant rate. The effluent of the core was collected by a fraction sample collector for further analysis. A TEMCO high-pressure core holder equipped with pressure ports was used. The rubber sleeve was filled with water and the injection pressure was kept at 500 psi below the sleeve pressure because higher sleeve pressures caused the rubber sleeve around the pressure taps to deform and seal off the pressure ports. One ft Berea cores, 2 in. in diameter, were used in all experiments. Pressure ports were located such that the core was divided into four sections. The first and fourth sections were 5 cm in length and sections two and three were 10 cm long. The pressure difference for each section and the overall pressure difference were measured by pressure transducers and recorded via a computer-based data gathering system. The apparatus was placed in an air bath in which the temperature of the core and the injected fluids was kept constant. The pressure of the core was maintained by a TEMCO back-pressure regulator connected to a cylinder containing nitrogen at high pressure. The back pressure was maintained at 1200 psi. Details of the experimental setup are presented elsewhere.8 Gels Produced from KUSP1. KUSP1 is an acronym for a biopolymer developed at the University of Kansas. The polymer is a ?-1,3-polyglucan and is produced by fermentation of a bacterium known as Alcaligenes faecalis and certain species of Agrobacterium.6 The polymer grows on the surface of the bacteria. During the fermentation process, the polymer laden bacteria aggregate and settle out from the growth medium. Polymer is extracted from the bacteria by suspension in dilute alkali. Neutralization of the alkaline polymer solution produces a hydrogel. The gelation process is reversible and the hydrogels are stable at high temperatures in neutral solutions. The polymer degrades in alkaline solution with time and at elevated temperatures.

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