GB2251445A - Method for the production of oil - Google Patents
Method for the production of oil Download PDFInfo
- Publication number
- GB2251445A GB2251445A GB9126786A GB9126786A GB2251445A GB 2251445 A GB2251445 A GB 2251445A GB 9126786 A GB9126786 A GB 9126786A GB 9126786 A GB9126786 A GB 9126786A GB 2251445 A GB2251445 A GB 2251445A
- Authority
- GB
- United Kingdom
- Prior art keywords
- oil
- emulsion
- volume
- reservoir
- peak
- Prior art date
- 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
Links
- 238000000034 method Methods 0.000 title claims abstract description 20
- 238000004519 manufacturing process Methods 0.000 title description 4
- 239000000839 emulsion Substances 0.000 claims abstract description 48
- 239000011148 porous material Substances 0.000 claims abstract description 21
- 230000035699 permeability Effects 0.000 claims abstract description 19
- 239000004094 surface-active agent Substances 0.000 claims abstract description 15
- 239000008346 aqueous phase Substances 0.000 claims abstract description 13
- 238000002156 mixing Methods 0.000 claims abstract description 13
- 238000002347 injection Methods 0.000 claims abstract description 7
- 239000007924 injection Substances 0.000 claims abstract description 7
- 239000002981 blocking agent Substances 0.000 claims abstract description 5
- 239000003208 petroleum Substances 0.000 claims abstract description 5
- 239000011435 rock Substances 0.000 claims abstract description 5
- 239000007864 aqueous solution Substances 0.000 claims abstract description 4
- 230000001804 emulsifying effect Effects 0.000 claims abstract description 4
- 238000007865 diluting Methods 0.000 claims abstract description 3
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 14
- 239000012071 phase Substances 0.000 claims description 10
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 claims description 8
- 239000011780 sodium chloride Substances 0.000 claims description 6
- 239000000203 mixture Substances 0.000 claims description 4
- 239000003513 alkali Substances 0.000 claims description 3
- 239000010409 thin film Substances 0.000 claims description 2
- 239000002699 waste material Substances 0.000 claims description 2
- 239000002894 chemical waste Substances 0.000 claims 1
- 239000003921 oil Substances 0.000 description 33
- 239000007764 o/w emulsion Substances 0.000 description 10
- 230000007246 mechanism Effects 0.000 description 8
- 239000012530 fluid Substances 0.000 description 7
- 238000009826 distribution Methods 0.000 description 6
- 230000000694 effects Effects 0.000 description 5
- 230000000903 blocking effect Effects 0.000 description 4
- 239000011159 matrix material Substances 0.000 description 4
- YXFVVABEGXRONW-UHFFFAOYSA-N Toluene Chemical compound CC1=CC=CC=C1 YXFVVABEGXRONW-UHFFFAOYSA-N 0.000 description 3
- 230000015572 biosynthetic process Effects 0.000 description 3
- 239000010779 crude oil Substances 0.000 description 3
- 239000010408 film Substances 0.000 description 3
- IEORSVTYLWZQJQ-UHFFFAOYSA-N 2-(2-nonylphenoxy)ethanol Chemical compound CCCCCCCCCC1=CC=CC=C1OCCO IEORSVTYLWZQJQ-UHFFFAOYSA-N 0.000 description 2
- 238000010790 dilution Methods 0.000 description 2
- 239000012895 dilution Substances 0.000 description 2
- 238000004945 emulsification Methods 0.000 description 2
- 229920000847 nonoxynol Polymers 0.000 description 2
- 230000035515 penetration Effects 0.000 description 2
- 239000008213 purified water Substances 0.000 description 2
- 230000009467 reduction Effects 0.000 description 2
- 229920006395 saturated elastomer Polymers 0.000 description 2
- 239000013535 sea water Substances 0.000 description 2
- 239000007762 w/o emulsion Substances 0.000 description 2
- 229920002449 FKM Polymers 0.000 description 1
- 238000006424 Flood reaction Methods 0.000 description 1
- 230000009286 beneficial effect Effects 0.000 description 1
- 239000012267 brine Substances 0.000 description 1
- 230000003247 decreasing effect Effects 0.000 description 1
- 230000001419 dependent effect Effects 0.000 description 1
- 238000006073 displacement reaction Methods 0.000 description 1
- 238000004090 dissolution Methods 0.000 description 1
- 229920001971 elastomer Polymers 0.000 description 1
- 238000010828 elution Methods 0.000 description 1
- 238000002474 experimental method Methods 0.000 description 1
- 230000002349 favourable effect Effects 0.000 description 1
- 239000006260 foam Substances 0.000 description 1
- 239000011346 highly viscous material Substances 0.000 description 1
- 238000011065 in-situ storage Methods 0.000 description 1
- 230000014759 maintenance of location Effects 0.000 description 1
- 239000000463 material Substances 0.000 description 1
- QSHDDOUJBYECFT-UHFFFAOYSA-N mercury Chemical compound [Hg] QSHDDOUJBYECFT-UHFFFAOYSA-N 0.000 description 1
- 229910052753 mercury Inorganic materials 0.000 description 1
- 229920000642 polymer Polymers 0.000 description 1
- 238000002459 porosimetry Methods 0.000 description 1
- 238000002360 preparation method Methods 0.000 description 1
- 230000008569 process Effects 0.000 description 1
- 230000002035 prolonged effect Effects 0.000 description 1
- 238000011084 recovery Methods 0.000 description 1
- 150000003839 salts Chemical class 0.000 description 1
- 238000010008 shearing Methods 0.000 description 1
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 1
- 238000002798 spectrophotometry method Methods 0.000 description 1
- 239000000126 substance Substances 0.000 description 1
- 238000005320 surfactant adsorption Methods 0.000 description 1
Classifications
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/502—Oil-based compositions
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
- E21B43/261—Separate steps of (1) cementing, plugging or consolidating and (2) fracturing or attacking the formation
Landscapes
- Life Sciences & Earth Sciences (AREA)
- Chemical & Material Sciences (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Mining & Mineral Resources (AREA)
- Geology (AREA)
- Organic Chemistry (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- Materials Engineering (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- Geochemistry & Mineralogy (AREA)
- Colloid Chemistry (AREA)
Abstract
A method for conformance control of a petroleum reservoir comprises the steps of: (a) mixing 70 to 98% by volume of a viscous oil with 30 to 2% by volume of an aqueous solution of an emulsifying surfactant under low shear conditions, in such manner that an emulsion is formed comprising distorted oil droplets having peak droplet diameters in the range 2 to 50 mu m and controlling the peak droplet diameter of the oil to a value which is equal to or less than the peak pore diameter of the rock of the reservoir, (b) diluting the emulsion with further quantities of an aqueous phase, and (c) injecting the diluted emulsion into an injection well in the reservoir to act as a blocking agent in zones of high permeability so that subsequent flooding medium contacts less permeable oil bearing zones more readily.
Description
METHOD FOR THE PRODUCTION OF OIL
This invention relates to an improved method for the recovery of crude oil from a petroleum reservoir.
During steam or 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).
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. Blocking agents fall into three main categories: polymers, foams and emulsions, (water-in-oil (w/o) and oil-in-water (o/w)).
The present application is concerned with the use of o/w emulsions in conformance control.
European Patent 0 156 486 B1 discloses and claims a method for the preparation of an HIPR (high internal phase ratio) emulsion of oil-in-water which method comprises directly mixing 70 to 98% by volume of a viscous oil with 30 to 2% by volume of an aqueous solution of an emulsifying surfactant or an alkali, percentages being expressed as percentages by volume of the total mixture; characterised by the fact that the oil has a viscosity in the range 200 to 250,000 mPa.s at the mixing temperature and mixing is effected under low shear conditions in the range 10 to 1,000 reciprocal seconds in such manner that an emulsion is formed comprising highly distorted oil droplets having mean droplet diameters in the range 2 to 50 pm separated by thin interfacial films.
It also discloses that the HIPR emulsions may be diluted and that the narrow size distribution and droplet size are maintained on dilution.
Several workers have studied the mechanism of conformance control by relatively stable o/w emulsions and it is believed that the controlling mechanism is dependent on the ratio of emulsion droplet size to matrix pore size. If the droplet size is greater than the pore size, then a straining mechanism dominates. Droplets will lodge in pore throats and permeability will be reduced. If the droplet size is less than the pore size, then an interception mechanism dominates. The small droplets are captured on the surfaces of the matrix grains.
It has been suggested that the optimum droplet size for this application is slightly greater than the average pore throat diameter.
We have now discovered that good results are obtained in conformance control when the peak oil droplet size is equal to or less than that of the pore size of the reservoir rock and that the droplet size should be matched with pore size by controlling the droplet size during manufacture of the emulsion.
Thus according to the present invention there is provided a method for conformance control of a petroleum reservoir which method comprises the steps of:
(a) mixing 70 to 98% by volume of a viscous oil with 30 to 2% by volume of an aqueous solution of an emulsifying surfactant or an alkali, percentages being expressed as percentages by volume of the total mixture, wherein the oil has a viscosity in the range 200 to 250,000 mPa.s at the mixing temperature and mixing is effected under low shear conditions, preferably in the range 10 to 1,000 reciprocal seconds, in such manner that an emulsion is formed comprising distorted oil droplets having peak droplet diameters in the range 2 to 50 ijm separated by thin films, and controlling the peak droplet diameter of the oil to a value which is equal to or less than the peak pore diameter of the rock of the reservoir,
(b) diluting the emulsion with further quantities of an aqueous phase, and
(c) injecting the diluted emulsion into an injection well in the reservoir to act as a blocking agent in zones of high permeability so that subsequent flooding medium contacts less permeable oil bearing zones more readily.
One method of achieving control of the oil droplet size diameter is by controlling the ratio of the oil phase to the aqueous phase during the initial mixing stage. Decreasing this ratio increases the droplet size.
Other methods for controlling the oil droplet size are disclosed in EP 0 156 486 B1, which also discloses further details of the emulsification process.
Preferably the diluted emulsion contains 0.5 to 10% by volume of oil, most preferably about 1%, based on the total volume of oil and water.
Suitable oils of high viscosity for emulsification include viscous crude oils but the preferred oils are highly viscous materials such as oil refinery residues and oleaginous chemical and polymeric waste products which are currently of low or negative value.
It is a feature of the present invention that it adds value to such products and enables them to be utilised in an economical and environmentally sound manner.
Another mechanism for conformance control is believed to be involved when relatively unstable o/w emulsions are involved. In this case permeability reduction may be due to the liberation of free oil or to the inversion of the relatively free flowing o/w emulsion to a more viscous w/o emulsion. In either case, the consequent formation of oil films bridging pore throats will close many of the flow paths that were formerly available.
Making the emulsion relatively unstable by using saline water as the aqueous phase can therefore be beneficial under certain circumstances.
If the emulsion is not required to penetrate deeply into the reservoir then the benefits of an unstable emulsion can be realised.
If on the other hand, the emulsion is required to retain its integrity in the reservoir, eg to faciliate deep penetration then clearly an unstable emulsion is less suitable.
The invention is illustrated by the following Examples 1 and 2 and Figures 1-2 of the accompanying drawings.
Examples 1 and 2 show the effects of emulsions of peak droplet diameters 8 pm and 24 ijm respectively.
Figure 1 is a graph showing the effect of the oil/water phase ratio on the emulsion droplet size distribution.
Figure 2 is a graph showing the amount of surfactant in produced fluids for various pore volumes (PVs) injected in Example 1.
Examples
The following materials were employed:
Vacuum flashed refinery residue (RR). SG 0.9639 at 70"C.
Nonylphenol ethoxylate (NPx) CH3(CH2)8 (C2H40)xOH where x = 20 or 35
Purified water
Simulated sea water (SSW)
AR sodium chloride
Berea sandstone
Light crude oil (LCO)
AR toluene
An HIPR emulsion, stabilised with [NP2O]/oil phase = 1%, was prepared with purified water as described in EP 0156486 B1. The oil/water/surfactant system was heated to 70 C prior to shearing.
Oil droplet size distribution was measured using a Coulter
Multisizer.
The effect of phase ratio upon droplet size distribution is shown in Figure 1. Phase ratios of 90:10 oil to aqueous phase (Example 1) and 85:15 (Example 2) were selected to give peak droplet diameters of about 8 and 24 pm respectively (ie at and below the peak pore diameter in the Berea sandstone). A phase ratio of 82.5 to 17.5 (Example 3) produced a coarser emulsion with a larger peak droplet diameter and a wider droplet size distribution.
These were diluted with SSW and additional surfactant added, see below, as sea water is likely to be available for field application. The final oil concentration was chosen to be low (about 1%) so that the emulsions were of low viscosity (close to that of water). This facilitated their delivery to the core face.
A brief study of the enhancement of emulsion stability through the addition of extra surfactant at the dilution stage suggested that an optimum NP20 concentration was 10 %, based on the oil phase.
Laboratory core flood experiments were conducted with Berea sandstone saturated with SSW and LCO to measure the degree to which o/w emulsions reduced core permeability. This provided an indication of their ability to enhance reservoir conformance control.
The pore size distribution in a high permeability Berea sandstone was determined by mercury porosimetry. The peak pore diameter was found to be 24 pm. Cores (3.8 cm diameter and 20 cm length) were cut from the same block to ensure consistency. Each core was loaded into Viton rubber sleeving, fitted with end pieces and placed in a permeameter housed within a thermostatically controlled oven.
The core was then maintained at 50 bar under SSW for 12 hours to ensure dissolution of air trapped within the pore matrix. The initial permeability of the core to SSW was measured at ambient temperature at several flow rates. The temperature of the permeameter was raised to 700C. The core was then flooded (at 0.4 cm3 min -1) with LCO contained within an oil injection vessel at the same temperature. After injecting 6 pore volumes (PVs) the core inlet and outlet were shut for 24 hours to ensure complete saturation of all parts of the core. Injection of the core was then continued for a further 4 PVs. At this stage the core was reflooded with SSW while the temperature was lowered to ambient. The permeability of the (now LCO saturated) core to SSW was measured prior to, and immediately following, the o/w emulsion flood (again, at several flow rates).The flow rate used for the o/w emulsion flood was 0.4 cm3 min-l.
Produced fluids were analysed for surfactant concentration by
W spectrophotometry with baseline correction for possible interference from water soluble components of the oil phase.
The results of core flooding Examples 1 and 2 are given in
Table 1.
Both emulsions quickly reduced the permeability of the Berea sandstone by more than 80%.
TABLE 1
Core type Berea sandstone
Core length (cm) 20
Cross-sectional area (cm2) 11.2
Peak pore diameter (pm) 23.9
Porosity (Z) 23
Flow rate (cm3/hr) 18.0
LCO viscosity (mPa.s @ 70 C) 4.60
Brine type SSW
Brine viscosity (mPa.s @ 70 "C) 0.48
Example 1 Example 2
Peak emulsion droplet diameter: 8pm 24pm
Permeability to SSW:
Before LCO flood 626 mD 647 mD
Before emulsion flood 67 mD 64 mD (PVs of emulsion injected 8.5 6)
After emulsion flood 12 mD 10 mD (PVs of extra emulsion flood 11.5 -) (PVs of SSW backflush 6)
After SSW backflush 55 mD
Following treatment in Example 1, the emulsion flood was continued for a further 11.5 PVs. There was no indication of RR emulsion droplets in the produced fluids.The core was removed from the permeameter and inspected. Although there was no indication of o/w emulsion at the core face, the RR had penetrated by about 3 cm.
There was no RR emulsion droplet elution during Example 2 either. Following Example 2 the core was subjected to a SSW backflush. After 6 PVs the permeability of the core to SSW was restored to close to its initial value.
A plot of surfactant concentration in eluted fluids against eluted volume in Example 1 is shown in Figure 2. It indicates that the NP20 used to stabilise the RR/SSW emulsion was readily adsorbed by the Berea sandstone. The level of surfactant retention calculated from these data is 2 mg g-l.
The ability of o/w emulsion to reduce the permeability of Berea sandstone is clear.
Regarding the blocking mechanism, it is interesting that the 8 um emulsion effected such efficient blocking. This may be due to the capture on pore walls of small droplets which together possess sufficient bulk to block the pore. The involvement of intact emulsion is supported by the 3 cm penetration observed following
Example 1 and the restoration of close to the original permeability observed during the backflush after Example 2. The high viscosity of "free" RR would likely preclude flow into, or out of the core.
The absence of RR emulsion droplets in the fluids produced during both core floods and at the core face following Example 1 provide evidence for an alternative blocking mechanism. Some permeability reduction may have been due to the liberation of free
RR (or to the formation of high viscosity w/o emulsion). The consequent formation of oil films bridging pore throats would have closed many of the flow paths that were formerly available for the flow of SSW and thus contributed to the pressure gradient behind the displacement front. The produced fluids analysis during Example 1 provides supporting evidence for this blocking mechanism. The level of surfactant adsorption was high. Therefore, the o/w emulsion, upon entering the core, experienced surfactant depletion. This will have contributed to emulsion instability and facilitated the in-situ liberation of non-emulsified RR.
The ability to restore original permeability by applying a backflush might be required in the field. For example this will allow the removal of emulsion from the face of an oil bearing zone following the application of a block to a highly permeable zone.
The potential benefits of adopting a different surfactant and less saline aqueous phase were also investigated. The results in
Table 2 indicate that extra emulsion stability with a saline aqueous phase would be obtained by using a more hydrophilic surfactant (NP35). The effect of reducing the salt content of the aqueous phase is also clear, with the emulsion prepared with pure water having excellent stability.
TABLE 2
EFFECT OF AQUEOUS PHASE COMPOSITION ON O/W EMULSION STABILITY*
Aqueous phase: Water 2% NaCl SSW
Surfactant:
NP35 0 18 27
NP20 22 26 45 * The figures in this table denote the percentage of RR which
irreversibly coalesced from coarse (about 40 pm) emulsions.
Claims (8)
1. A method for conformance control of a petroleum reservoir which method comprises the steps of:
(a) mixing 70 to 98% by volume of a viscous oil with 30 to 2% by volume of an aqueous solution of an emulsifying surfactant or an alkali, percentages being expressed as percentages by volume of the total mixture, wherein the oil has a viscosity in the range 200 to 250,000 mPa.s at the mixing temperature and mixing is effected under low shear conditions, in such manner that an emulsion is formed comprising distorted oil droplets having peak droplet diameters in the range 2 to 50 ijm separated by thin films, and controlling the peak droplet diameter of the oil to a value which is equal to or less than the peak pore diameter of the rock of the reservoir,
(b) diluting the emulsion with further quantities of an aqueous phase, and
(c) injecting the diluted emulsion into an injection well in the reservoir to act as a blocking agent in zones of high permeability so that subsequent flooding medium contacts less permeable oil bearing zones more readily.
2. A method according to claim 1 wherein mixing is effected under shear conditions in the range 10 to 1,000 reciprocal seconds.
3. A method according to either of the preceding claims wherein the oil droplet size diameter is controlled by controlling the ratio of the oil phase to the aqueous phase during the initial mixing stage.
4. A method according to any of the preceding claims wherein the diluted emulsion contains 0.5 to 10% by volume of oil.
5. A method according to claim 4 wherein the diluted emulsion contains approximately 1Z by volume of oil.
6. A method according to any of the preceding claims wherein the oil is refinery residue, a chemical waste product or a polymeric waste product.
7. A method according to any of the preceding claims wherein the aqueous phase is saline water.
8. A method according to claim 1 as hereinbefore described with reference to the examples.
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| GB919100070A GB9100070D0 (en) | 1991-01-03 | 1991-01-03 | Method for the production of oil |
Publications (3)
| Publication Number | Publication Date |
|---|---|
| GB9126786D0 GB9126786D0 (en) | 1992-02-19 |
| GB2251445A true GB2251445A (en) | 1992-07-08 |
| GB2251445B GB2251445B (en) | 1994-09-14 |
Family
ID=10687907
Family Applications (2)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| GB919100070A Pending GB9100070D0 (en) | 1991-01-03 | 1991-01-03 | Method for the production of oil |
| GB9126786A Expired - Fee Related GB2251445B (en) | 1991-01-03 | 1991-12-18 | Method for the production of oil |
Family Applications Before (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| GB919100070A Pending GB9100070D0 (en) | 1991-01-03 | 1991-01-03 | Method for the production of oil |
Country Status (2)
| Country | Link |
|---|---|
| GB (2) | GB9100070D0 (en) |
| NO (1) | NO920006L (en) |
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| GB2377718A (en) * | 2001-07-17 | 2003-01-22 | Phillips Petroleum Co | A method of restricting fluid flow with the formation of solid gas hydrates |
| CN106433589A (en) * | 2016-09-19 | 2017-02-22 | 中国石油化工股份有限公司 | Emulsion for water plugging of horizontal well and preparation method of emulsion |
-
1991
- 1991-01-03 GB GB919100070A patent/GB9100070D0/en active Pending
- 1991-12-18 GB GB9126786A patent/GB2251445B/en not_active Expired - Fee Related
-
1992
- 1992-01-02 NO NO92920006A patent/NO920006L/en unknown
Cited By (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| GB2377718A (en) * | 2001-07-17 | 2003-01-22 | Phillips Petroleum Co | A method of restricting fluid flow with the formation of solid gas hydrates |
| GB2377718B (en) * | 2001-07-17 | 2005-06-29 | Phillips Petroleum Co | Fluid profile control in enhanced oil recovery |
| CN106433589A (en) * | 2016-09-19 | 2017-02-22 | 中国石油化工股份有限公司 | Emulsion for water plugging of horizontal well and preparation method of emulsion |
Also Published As
| Publication number | Publication date |
|---|---|
| NO920006L (en) | 1992-07-06 |
| GB9126786D0 (en) | 1992-02-19 |
| GB9100070D0 (en) | 1991-02-20 |
| GB2251445B (en) | 1994-09-14 |
| NO920006D0 (en) | 1992-01-02 |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| DE69303214T2 (en) | Gas hole treatment compositions and methods | |
| Hill et al. | Aqueous surfactant systems for oil recovery | |
| McAuliffe | Oil-in-water emulsions and their flow properties in porous media | |
| DE19882406B4 (en) | Solid-stabilized emulsion, its use for oil recovery and process for its preparation | |
| CA1283040C (en) | Continuous process for hydraulic fracturing with foam | |
| CA1308550C (en) | In situ chemical stimulation of diatomite formations | |
| CA1199785A (en) | High temperature stable crosslinked gel fracturing fluid | |
| US7549472B2 (en) | Method for increasing the production of hydrocarbon liquids and gases | |
| EP3212732B1 (en) | Polymer compositions | |
| US4817715A (en) | Aqueous flooding methods for tertiary oil recovery | |
| AU2008263581B2 (en) | Well treatment | |
| CN110945208B (en) | Method for improving oil recovery rate of stratum | |
| WO2018102679A1 (en) | Microemulsions and uses thereof to displace oil in heterogeneous porous media | |
| CA2091541C (en) | Anionic compositions for sludge prevention and control during acid stimulation of hydrocarbon wells | |
| US4582138A (en) | Method for oil recovery from reservoir rock formations | |
| JPH02240393A (en) | Substituting agent for recovering petroleum from underground source and using method thereof | |
| CA2499372A1 (en) | Fiber assisted emulsion system | |
| CN113372895A (en) | Crude oil expansion oil displacement agent and preparation method and application thereof | |
| US4813483A (en) | Post-steam alkaline flooding using buffer solutions | |
| US20080009424A1 (en) | Emulsified gelant | |
| Kohler et al. | Weak gel formulations for selective control of water production in high-permeability and high-temperature production wells | |
| GB2251445A (en) | Method for the production of oil | |
| DE2917534A1 (en) | PROCESS FOR INCREASED OIL PRODUCTION | |
| NO159117B (en) | PROCEDURE FOR EXTRACTION OF RAW OIL, AND MOBILITY REGULATING AGENT FOR TERTIAS OIL EXTRACTION. | |
| US20130306320A1 (en) | Composition and method for treating carbonate reservoirs |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| PCNP | Patent ceased through non-payment of renewal fee |
Effective date: 19951218 |