GB2262117A - Conformance control in underground reservoirs - Google Patents

Conformance control in underground reservoirs Download PDF

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Publication number
GB2262117A
GB2262117A GB9225006A GB9225006A GB2262117A GB 2262117 A GB2262117 A GB 2262117A GB 9225006 A GB9225006 A GB 9225006A GB 9225006 A GB9225006 A GB 9225006A GB 2262117 A GB2262117 A GB 2262117A
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United Kingdom
Prior art keywords
particles
latex
flocculate
shrink
harden
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Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Granted
Application number
GB9225006A
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GB9225006D0 (en
GB2262117B (en
Inventor
Martin John Snowden
Brian Vincent
James Charles Morgan
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BP PLC
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BP PLC
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Publication date
Priority claimed from GB919125926A external-priority patent/GB9125926D0/en
Application filed by BP PLC filed Critical BP PLC
Priority to GB9225006A priority Critical patent/GB2262117B/en
Publication of GB9225006D0 publication Critical patent/GB9225006D0/en
Publication of GB2262117A publication Critical patent/GB2262117A/en
Application granted granted Critical
Publication of GB2262117B publication Critical patent/GB2262117B/en
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Expired - Lifetime legal-status Critical Current

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Classifications

    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00Sealing or packing boreholes or wells
    • E21B33/10Sealing or packing boreholes or wells in the borehole
    • E21B33/13Methods or devices for cementing, for plugging holes, crevices, or the like
    • E21B33/138Plastering the borehole wall; Injecting into the formation
    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/50Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/50Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/504Compositions based on water or polar solvents
    • C09K8/506Compositions based on water or polar solvents containing organic compounds
    • C09K8/508Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • C09K8/512Compositions based on water or polar solvents containing organic compounds macromolecular compounds containing cross-linking agents

Abstract

A method for conformance control of a reservoir where high formation temperatures are encountered comprises the steps of (a) injecting at ambient temperature into the formation a latex solution containing particles which flocculate, shrink and harden at higher temperatures, and a solution of an ionic compound as a promoter, (b) allowing the solution to flow through a zone or zones of relatively high permeability in the formation under increasing temperature conditions, and (c) allowing the latex particles to flocculate, shrink and harden at a location where the temperature is sufficiently high to promote this effect. When the particles flocculate, shrink and harden, they form a more effective blocking agent than the dispersed, expanded and softer particles.

Description

METHOD FOR THE PRODUCTION OF OIL This invention relates to an improved method for the recovery of crude oil from a petroleum reservoir.
Water flooding is one of the most successful and extensively used secondary recovery methods. Water is injected under pressure into the reservoir via injection wells and drives the oil through the rock into nearby producing wells. The oil in the reservoir is frequently associated with connate water which contains various salts. Many oil fields are situated in offshore locations and for them the only source of injection water is the sea which again contains various salts, particularly sodium chloride.
It is rare to obtain in practice a waterflood sweep efficiency approaching theoretical perfection. Usually significant mobile oil still remains in the reservoir when the producing watercut exceeds the economic limit (usually at a WOR of about 50:1 for individual wells). There are several reasons for this. Geological layering leads to poor vertical sweep conformance. Depositional history can also lead to non-uniform areal sweep, which can be a problem unless counteracted by offset injector/producer alignment. Vertical and areal sweep efficiencies can both be adversely affected by natural or induced fractures. Other factors include water underrunning because of gravity segregation and coning, particularly of bottom aquifers.
During water flooding of petroleum reservoirs, the injection fluid tends to find the easiest (ie, the most permeable) route from an injection well to a production well. These high permeability routes can be the result of reservoir fracturing, prolonged waterflooding or reservoir geology (eg, faults, or the nature of the rock matrix).
In the case of deep wells, where the producing formation is at a relatively high temperature, eg 50 to 2000 C, cold water injection produces a temperature gradient across the formation.
The injection of cold water has a cooling effect in the vicinity of the injection well and for some distance beyond it.
To enhance reservoir conformance control, ie, to mobilise oil which may be present in less permeable areas, some form of blocking agent can be injected. This creates an obstruction in the high permeability channels which causes the lower permeability paths to appear more favourable to a subsequent flood.
Conventional blocking agents fall into three main categories: polymers and polymer gels, foams and emulsions (water-in-oil (w/o) and oil-in-water (o/w)).
We have now discovered that certain latex particles are temperature sensitive and reversibly flocculate, shrink and harden at higher temperatures, and disperse, expand and soften at lower temperatures and that these can form effective blocking agents in the presence of an ionic compound, in a petroleum reservoir.
According to the present invention there is provided a method for conformance control of a reservoir where high formation temperatures are encountered which method comprises the steps of (a) injecting at ambient temperature into the formation a latex solution containing particles which flocculate, shrink and harden at higher temperatures, and a solution of an ionic compound as a promoter, (b) allowing the solution to flow through a zone or zones of relatively high permeability in the formation under increasing temperature conditions, and (c) allowing the latex particles to flocculate, shrink and harden at a location where the temperature is sufficiently high to promote this effect.
Preferably the latex particles reversibly flocculate, shrink and harden.
When the particles flocculate, shrink and harden, they form a more effective blocking agent than the dispersed, expanded and softer particles.
Suitable latex particles may be prepared by polymerising or copolymeerising an acrylamide of formula
where R1 and R2 are hydrogen atoms or alkyl groups containing 1 to 4 carbon atoms, preferably 2 or 3 carbon atoms, in the presence of a free radical initiator and a cross-linking agent.
The preferred latex is prepared by polymerising N-isopropyl acrylamide but other suitable latices may be prepared by copolymerising N-isopropyl acrylamide with acrylamide in various ratios.
A suitable free radical initiator is ammonium persulphate, but other free radical initiators can be used, particularly if it is desired to modify the surface of the latex particles. For example, a free radical initiator containing a carboxyl group, such as azo-bis-4-cyanopentanoic acid, can be used to provide carboxyl groups on the surface of the latex particles.
Carboxylated latex particles may be modified by treatment with a methylating agent, eg dimethyl sulphate. The surface of the modified polymer particles is rendered less hydrophilic and so permits earlier and stronger adhesion between the particles.
The ionic promoter compound may be inorganic, eg sodium chloride, or organic, eg a polyelectrolyte such as poly(styrene sulphonate) or carboxy methyl cellulose. It should be added in solution form to the latex.
Variation in the combination of solvent and promoter allows control over the temperature at which flocculation occurs.
The preferred cross-linking agent is N',N-methylene-bis acrylamide.
The molecular weight of the cross-linked polymer should be at least 10,000 to be effective, and is preferably in excess of one million.
The polymer latex concentration of fluid injected into the reservoir is preferably in the range 500 to 20,000 ppm.
The injected composition gives little viscosity increase before flocculation and moves freely into the more permeable zones of the formation, known as thief zones.
The present invention takes advantage of the temperature gradient in a reservoir in the following way. First a latex is selected which essentially does not block the porous matrix in the cold, but does block if heated. This is injected into the waterflood for a short period only. Most of the latex solution enters the thief zones. This has to follow the major established water paths wherever they go. Injectivity is not significantly changed because viscosity is not significantly affected. The latex solution, however, quickly catches up with the cold front and begins to block the thief zones by consolidation of the particles. The follow-up water begins to be diverted out of the thief zones and into the neighbouring zones upstream of the blockages. The net result is that more water passes through the lower permeability zones, and more oil and less water are delivered to the producers.
The invention is illustrated with reference to the following examples and Figures 1-6 of the accompanying drawings which are graphical representations of experimental results.
Example 1 Poly(N-isopropyl acrylamide (NIPAM) particles were prepared by the free radical polymerisation of NIPAM in water at 70"C using ammonium persulphate as the initiator in the presence of N'Nmethylene- bis acrylamide as the cross-linking agent, following the procedure of Pelton et al, Colloids and Surfaces, 1986, 20, 247. Following dialysis against distilled water transmission electron micrographs showed the particles to be monodisperse spheres having a mean diameter of 450nm. The molecular weight was in excess of one million. Poly(styrene sulphonate) Mw 46000 was purchased from Polymer Laboratories Ltd, Shropshire.The temperature dependency of the particle diameter of poly(NIPAM) latex was determined by photon correlation spectroscopy using a Malvern instrument type 7027 dual LOGLIN digital correlator equipped with a graphite laser (A = 530.9 nm). The intensity of scattered light was measured at 90". Particle size was measured from 25"C to 500C both on heating and cooling.
Flocculation experiments were carried out using dispersions containing 0.1% microgel particles and various amounts of sodium chloride made up to a total volume of 5 cm3. A first series of samples with increasing amounts of sodium chloride were placed in a water bath at 25"C and allowed to stand overnight. The extent of any aggregation in the dispersion was estimated from the wavelength dependence of the turbidity of the dispersions. The same experiment was repeated by placing the samples in a water bath at 40"C, and also at both temperatures using poly(styrene sulphonate) in place of sodium chloride.
Figure 1 illustrates the decrease in particle diameter of the poly (NIPAM) latex particles on heating. The initial diameter of 450nm at 25"C decreased to 240nm at 50"C. On cooling, however, the particles expanded and adopted their original particle size.
This procedure was found to be fully reversible over a number of heating and cooling cycles with no hysteresis taking place between the heating and cooling curves. Figure 2 illustrates that without sodium chloride or poly(styrene sulphonate) present, the particles remained dispersed over the temperature range studied (25-50 C).
Figure 3 shows that at 25"C the dispersion remains stable at all sodium chloride concentrations up to 0.10mol dim~3. However, on repeating the experiment at 400 C, aggregation of the poly(NIPAM) latex took place for samples with sodium chloride concentrations in excess of 0.06 mol dim~3. The samples which flocculated at 400C at NaCl concentrations in excess of 0.06 mol dim~3, redispersed on cooling to 250 C, having a value of n (d log absorbance/d log wavelength) of -2.6 indicating that the dispersion had become fully redispersed.This process of heating the samples, inducing flocculation, then cooling and allowing the particles to redisperse could be repeated many times with the process remaining fully reversible on each occasion.
Figure 4 shows the stability of the poly(NIPAM) particles in the presence of poly(styrene sulphonate). At 25"C the particles remained dispersed up to the highest polymer concentration studied at 0.8X. On repeating the same experiment with the dispersions at 40 C, flocculation was found to take place at a polymer concentration of 0.6% and above. The samples remained flocculated while the temperature was maintained at 40"C. On cooling the flocculated dispersions to 250C and gently inverting the container several times, the flocculated samples redispersed fully with their n values simultaneously decreasing from -1.3 to -2.7. This process was also found to be reversible over a number of heating and cooling cycles.
The decrease in diameter of the poly(NIPAM) latices on heating from 25 C to 400C is a consequence of the increase in the z parameter of the monomeric NIPAM. This facilitates more polymer-polymer contacts, hence the particles contact and shrink substantially. At 25"C the particles can be envisaged as spongy microgels, swollen with solvent and having very low Hamaker constants. At 40"C the particles shrink forcing out any solvent from the interstitial spaces and become very similar to hard spheres in their nature. Aggregation of the particles now takes place as the Hamaker constant increase plus screening of the charges at the particle surface allows close enough approach for coagulation to occur.In the presence of poly(styrene sulphonate) at 40"C the particles flocculate as a consequence of depletion forces operative in the system. It is believed that the polymer does not adsorb into the particles from water as both species have negative charges. The flocculated latex on cooling down to 25"C redisperses, presumably as a consequence of the particles swelling with solvent and then undergoing conformational rearrangements thus forcing each other apart.
With polystyrene sulphonate present, therefore, a dispersion of poly(NIPAM) latex in low salinity water can be made to flocculate as it heats up from 25"C to 40 C.
Examnle 2 In a test of the effect of flocculation with a porous medium, a 3 metre long "slim-tube" (which is a 6mm inner diameter tube) packed with crushed outcrop sandstone was flooded with sea water at 25"C, and then a dispersion of poly(NIPAM) latex particles (l0O0ppm in sea water) was passed through it. The particles were seen to reach the end of the tube, and the permeability of the slim-tube remained unchanged. On heating the downstream 2 metres of the tube to 70"C, the particles ceased to reach the outlet end of the slim-tube. After a period in which particles continued to flocculate and accumulate in the slim-tube, the permeability of the slim-tube became reduced from its original 2 Darcies to less than 0.5 Darcies.
Example 3 Stability experiments under capillary flow conditions were carried out by passing a 0.1% dispersion of a carboxylated poly NIPAM latex containing 0.5 mol dim~3 NaCl at a flow rate of lOcm3/hr through a Nucleopore membrane having a pore diameter of 3 . The latex was prepared in a similar manner to that prepared in Example 1, with the difference that azo-bis-4-cyanopentanoic acid was used as the initiator instead of ammonium persulphate.
After a small amount of eluent had passed through the membrane an attached pressure transducer was arbitrarily set to zero.
The membrane was then immersed in a water bath at OOC to increase the temperature. The pressure reading given by the transducer then rose due to blocking of the capillaries by the flocculate which formed.
Almost immediately the water bath was removed to decrease the temperature and the pressure fell as a result of deflocculation of the latex at the lower temperature.
The experiment was repeated using a methylated latex.
Methylation of the surface carboxyl groups was achieved by placing 250 cm3 of the carboxylated latex in a beaker with 25 cm3 of dimethyl sulphate (a large molar excess) and stirring at 300C overnight. Methylation occurs via a nucleophilic substitution mechanism.
The above experiments were then repeated using a membrane having a pore diameter of 5 instead of 31L.
Results from the 3p experiments are illustrated in Fig 5 and from the 5 experiments in Fig 6.
These show that the onset of flocculation is earlier for the methylated latex than for the unmethylated. The effect is more marked at 5z, where a greater amount of flocculation is necessary to block the pores.
They also show that the effect is reversible and that the flocculated particles deflocculate on cooling.

Claims (16)

Claims
1. A method for conformance control of a reservoir where high formation temperatures are encountered which method comprises the steps of (a) injecting at ambient temperature into the formation a latex solution containing particles which flocculate, shrink and harden at higher temperatures, and a solution of an ionic compound as a promoter, (b) allowing the solution to flow through a zone or zones of relatively high permeability in the formation under increasing temperature conditions, and (c) allowing the latex particles to flocculate, shrink and harden at a location where the temperature is sufficiently high to promote this effect.
2. A method according to claim 1 wherein the latex particles reversibly flocculate, shrink and harden.
3. A method according to either of claims 1 or 2 wherein the latex solution is prepared by polymerising or copolymerising an acrylamide of formula
where R1 and R2 are hydrogen atoms or alkyl groups containing 1 to 4 carbon atoms, in the presence of a free radical initiator and a cross-linking agent.
4. A method according to claim 3 wherein the acrylamide is N isopropyl acrylamide.
5. A method according to any of the preceding claims wherein the free radical initiator is ammonium persulphate.
6. A method according to any of claims 1 to 4 wherein the free radical initiator contains carboxyl groups to provide carboxylated latex particles.
7. A method according to claim 6 wherein the free radical initiator containing carboxyl groups is azobis-4-cyanopentanoic acid.
8. A method according to either claims 6 or 7 wherein the carboxylated latex particles are modified by treatment with a methylating agent.
9. A method according to claim 8 wherein the methylating agent is dimethyl sulphate.
10. A method according to any of the preceding claims wherein the cross-linking agent is N',N-methylene-bis acrylamide.
11. A method according to any of the preceding claims wherein the ionic promoter is sodium chloride.
12. A method accoarding to any of claims 1 to 10 wherein the ionic promoter compound is a polyelectrolyte.
13. A method according to claim 12 wherein the polyelectrolyte is poly (styrene sulphonate) or carboxymethyl cellulose.
14. A method according to any of the preceding claims wherein the molecular weight of the cross-linked polymer is in the range 10,000 to in excess of one million.
15. A method according to any of the preceding claims wherein the polymer latex concentration of fluid injected into the reservoir is in the range 500 to 20,000 ppm.
16. A method according to claim 1 as hereinbefore described with reference to the examples.
GB9225006A 1991-12-05 1992-11-30 Method for the production of oil Expired - Lifetime GB2262117B (en)

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GB9225006A GB2262117B (en) 1991-12-05 1992-11-30 Method for the production of oil

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
GB919125926A GB9125926D0 (en) 1991-12-05 1991-12-05 Profile control
GB9225006A GB2262117B (en) 1991-12-05 1992-11-30 Method for the production of oil

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GB2262117A true GB2262117A (en) 1993-06-09
GB2262117B GB2262117B (en) 1995-05-03

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Cited By (15)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP0651131A2 (en) * 1993-10-22 1995-05-03 Halliburton Company Control of water flow from subterranean formation
WO1995026455A1 (en) * 1994-03-28 1995-10-05 Allied Colloids Limited Downhole fluid control processes
FR2780752A1 (en) * 1998-07-03 2000-01-07 Inst Francais Du Petrole Method for controlling the permeability of a subterranean formation by the use of an aqueous colloidal dispersion
US7888296B2 (en) 2008-04-21 2011-02-15 Nalco Company Composition and method for recovering hydrocarbon fluids from a subterranean reservoir
US7897546B2 (en) 2008-04-21 2011-03-01 Nalco Company Composition and method for recovering hydrocarbon fluids from a subterranean reservoir
US7902127B2 (en) 2008-04-21 2011-03-08 Nalco Company Composition and method for recovering hydrocarbon fluids from a subterranean reservoir
US7928042B2 (en) 2008-04-21 2011-04-19 Nalco Company Composition and method for recovering hydrocarbon fluids from a subterranean reservoir
US7947630B2 (en) 2008-04-21 2011-05-24 Nalco Company Compositions comprising at least two different polymeric microparticles and methods for recovering hydrocarbon fluids from a subterranean reservoir
US7989401B2 (en) 2008-04-21 2011-08-02 Nalco Company Block copolymers for recovering hydrocarbon fluids from a subterranean reservoir
US9206346B2 (en) 2008-04-21 2015-12-08 Nalco Company Compositions and methods for diverting injected fluids to achieve improved hydrocarbon fluid recovery
WO2018197479A1 (en) 2017-04-27 2018-11-01 Bp Exploration Operating Company Limited Microparticles and method for modifying the permeability
WO2019025810A1 (en) * 2017-08-03 2019-02-07 Bp Exploration Operating Company Limited Crosslinked polymer microparticles for use in conformance control
WO2020131720A1 (en) * 2018-12-19 2020-06-25 Saudi Arabian Oil Company Gelation characterization in slim tubes
US11286232B2 (en) 2020-07-29 2022-03-29 Saudi Arabian Oil Company Preparation of cationic surfactants
US11820842B2 (en) 2020-09-09 2023-11-21 Saudi Arabian Oil Company Sulfonated polymer

Families Citing this family (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
GB201612678D0 (en) * 2016-07-21 2016-09-07 Bp Exploration Operating Process

Citations (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
GB2062070A (en) * 1979-10-30 1981-05-20 Phillips Petroleum Co Treatment of subsurface gas-bearing formations to reduce water production therefrom
WO1992012325A1 (en) * 1990-12-28 1992-07-23 Institut Français Du Petrole Stable suspension and use thereof for recovering hydrocarbons

Patent Citations (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
GB2062070A (en) * 1979-10-30 1981-05-20 Phillips Petroleum Co Treatment of subsurface gas-bearing formations to reduce water production therefrom
WO1992012325A1 (en) * 1990-12-28 1992-07-23 Institut Français Du Petrole Stable suspension and use thereof for recovering hydrocarbons

Cited By (19)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP0651131A2 (en) * 1993-10-22 1995-05-03 Halliburton Company Control of water flow from subterranean formation
EP0651131A3 (en) * 1993-10-22 1996-01-03 Halliburton Co Control of water flow from subterranean formation.
WO1995026455A1 (en) * 1994-03-28 1995-10-05 Allied Colloids Limited Downhole fluid control processes
FR2780752A1 (en) * 1998-07-03 2000-01-07 Inst Francais Du Petrole Method for controlling the permeability of a subterranean formation by the use of an aqueous colloidal dispersion
US7947630B2 (en) 2008-04-21 2011-05-24 Nalco Company Compositions comprising at least two different polymeric microparticles and methods for recovering hydrocarbon fluids from a subterranean reservoir
US7897546B2 (en) 2008-04-21 2011-03-01 Nalco Company Composition and method for recovering hydrocarbon fluids from a subterranean reservoir
US7902127B2 (en) 2008-04-21 2011-03-08 Nalco Company Composition and method for recovering hydrocarbon fluids from a subterranean reservoir
US7928042B2 (en) 2008-04-21 2011-04-19 Nalco Company Composition and method for recovering hydrocarbon fluids from a subterranean reservoir
US7888296B2 (en) 2008-04-21 2011-02-15 Nalco Company Composition and method for recovering hydrocarbon fluids from a subterranean reservoir
US7989401B2 (en) 2008-04-21 2011-08-02 Nalco Company Block copolymers for recovering hydrocarbon fluids from a subterranean reservoir
US9206346B2 (en) 2008-04-21 2015-12-08 Nalco Company Compositions and methods for diverting injected fluids to achieve improved hydrocarbon fluid recovery
WO2018197479A1 (en) 2017-04-27 2018-11-01 Bp Exploration Operating Company Limited Microparticles and method for modifying the permeability
WO2019025810A1 (en) * 2017-08-03 2019-02-07 Bp Exploration Operating Company Limited Crosslinked polymer microparticles for use in conformance control
WO2020131720A1 (en) * 2018-12-19 2020-06-25 Saudi Arabian Oil Company Gelation characterization in slim tubes
US10788410B2 (en) 2018-12-19 2020-09-29 Saudi Arabian Oil Company Gelation characterization in slim tubes
US11286232B2 (en) 2020-07-29 2022-03-29 Saudi Arabian Oil Company Preparation of cationic surfactants
US11591291B2 (en) 2020-07-29 2023-02-28 Saudi Arabian Oil Company Preparation of cationic surfactants
US11591292B2 (en) 2020-07-29 2023-02-28 Saudi Arabian Oil Company Preparation of cationic surfactants
US11820842B2 (en) 2020-09-09 2023-11-21 Saudi Arabian Oil Company Sulfonated polymer

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