U.S. patent application number 13/272965 was filed with the patent office on 2012-04-19 for water injection systems and methods.
This patent application is currently assigned to SHELL OIL COMPANY. Invention is credited to Dirk Jacob LIGTHELM, Julija ROMANUKA, Bartholomeus Marinus Josephus Maria SUIJKERBUIJK.
Application Number | 20120090833 13/272965 |
Document ID | / |
Family ID | 44908108 |
Filed Date | 2012-04-19 |
United States Patent
Application |
20120090833 |
Kind Code |
A1 |
LIGTHELM; Dirk Jacob ; et
al. |
April 19, 2012 |
WATER INJECTION SYSTEMS AND METHODS
Abstract
There is disclosed a method for enhancing recovery of crude oil
from a porous subterranean carbonate formation of which the pore
spaces contain crude oil and connate water, the method comprising
determining an ionic strength of the connate water; and injecting
an aqueous displacement fluid having a lower ionic strength than
the connate water into the formation.
Inventors: |
LIGTHELM; Dirk Jacob;
(Rijswijk, NL) ; ROMANUKA; Julija; (The Hague,
NL) ; SUIJKERBUIJK; Bartholomeus Marinus Josephus Maria;
(Utrecht, NL) |
Assignee: |
SHELL OIL COMPANY
Houston
TX
|
Family ID: |
44908108 |
Appl. No.: |
13/272965 |
Filed: |
October 13, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61393471 |
Oct 15, 2010 |
|
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|
Current U.S.
Class: |
166/250.01 |
Current CPC
Class: |
C09K 8/58 20130101; C09K
8/592 20130101 |
Class at
Publication: |
166/250.01 |
International
Class: |
E21B 43/16 20060101
E21B043/16; E21B 43/20 20060101 E21B043/20; E21B 43/22 20060101
E21B043/22; E21B 47/00 20120101 E21B047/00 |
Claims
1. A method for enhancing recovery of crude oil from a porous
subterranean carbonate formation of which the pore spaces contain
crude oil and connate water, the method comprising: determining an
ionic strength of the connate water; and injecting an aqueous
displacement fluid having a lower ionic strength than the connate
water into the formation.
2. The method of claim 1, wherein the aqueous displacement fluid
has an Ionic Strength (I) less than about 10% of the Ionic Strength
of the connate water.
3. The method of claim 1, wherein the aqueous displacement fluid
has an Ionic Strength (I) less than about 0.5% of the Ionic
Strength of the connate water.
4. The method of claim 1, wherein the method further comprises:
determining a total level of multivalent cations (Moles/Volume) of
the connate water; and injecting an aqueous displacement fluid
having a lower total level of multivalent cations (Moles/Volume)
than the connate water.
5. The method of claim 1, wherein the aqueous displacement fluid
comprises at least one additive selected from a surfactant, a
foaming agent, a water soluble polymer, and a water soluble solvent
having a molar solubility in water of at least 1% and an
octanol-water partition coefficient of at least 1 that is selected
from the group consisting of an alcohol, an amine, a pyridine, an
ether, a carboxylic acid, an aldehyde, a ketone, a phosphate, a
quinine, and mixtures thereof.
6. The method of claim 1, wherein the aqueous displacement fluid
comprises steam and/or water obtained from an aquifer, river, lake,
sea, treated sewage effluent, or ocean.
7. The method of claim 1, wherein the formation is a
mineral-bearing carbonate formation.
8. The method of claim 1, wherein the aqueous displacement fluid
comprises a viscosifying polymer.
9. The method of claim 8, wherein the aqueous displacement fluid
has a viscosity level above 1 mPas and comprises at least 200 ppm
(mass) of viscosifying polymer.
10. The method of claim 8, wherein the viscosifying polymer
comprises a hydrolyzed polyacrylamide.
11. The method of claim 1, wherein the water is treated to provide
an aqueous displacement fluid having an ionic strength less than
about 5% of the ionic strength of the connate water.
12. The method of claim 1, wherein the water is treated to provide
an aqueous displacement fluid having an ionic strength from about
0.1% to about 20% of the ionic strength of the connate water.
13. The method of claim 1, wherein the water is treated to provide
an aqueous displacement fluid having a total dissolved solids level
from about 0.1% to about 20% of the total dissolved solids level of
the connate water.
Description
PRIORITY CLAIM
[0001] The present application claims the benefit to priority of
U.S. Provisional Application No. 61/393,471 entitled "Water
Injection Systems and Methods" filed Oct. 15, 2010.
FIELD OF INVENTION
[0002] The present disclosure relates to systems and methods for
injecting water into a hydrocarbon bearing formation.
BACKGROUND
[0003] Oil accumulated within a subterranean oil-bearing formation
is recovered or produced therefrom through wells, called production
wells, drilled into the subterranean formation. A large amount of
such oil may be left in the subterranean formations if produced
only by primary depletion, i.e., where only formation energy is
used to recover the oil. Where the initial formation energy is
inadequate or has become depleted, supplemental operations, often
referred to as secondary, tertiary, enhanced or post-primary
recovery operations, may be employed. In some of these operations,
a fluid is injected into the formation by pumping it through one or
more injection wells drilled into the formation, oil is displaced
within and is moved through the formation, and is produced from one
or more production wells drilled into the formation. In a
particular recovery operation of this sort, seawater, field water
or field brine may be employed as the injection fluid and the
operation is referred to as a waterflood. The injection water may
be referred to as flooding liquid or flooding water as
distinguished from the in situ formation, or connate water. Fluids
injected later can be referred to as driving fluids.
[0004] Water may be injected by itself, or as a component of
miscible or immiscible displacement fluids. Sea water (for offshore
wells) and brine produced from the same or nearby formations (for
onshore wells) may be most commonly used as the water source.
[0005] Hiorth, Cathles, and Madland in their article "The Impact of
Pore Water Chemistry on Carbonate Surface Charge and Oil
Wettability" published Feb. 24, 2010 in Transp Porous Med (2010,
85:1-21) disclosed that water chemistry has been shown
experimentally to affect the stability of water films and the
sorption of organic oil components on mineral surfaces. When oil is
displaced by water, water chemistry has been shown to impact oil
recovery. At least two mechanisms could account for these effects,
the water chemistry could change the charge on the rock surface and
affect the rock wettability, and/or changes in the water chemistry
could dissolve rock minerals and affect the rock wettability. The
explanations need not be the same for oil displacement of water as
for water imbibition and displacement of oil. This article
investigates how water chemistry affects surface charge and rock
dissolution in a pure calcium carbonate rock similar to the Stevns
Klint chalk by constructing and applying a chemical model that
couples bulk aqueous and surface chemistry and also addresses
mineral precipitation and dissolution. They perform calculations
for seawater and formation water for temperatures between 70 and
130.degree. C. The model they construct predicts the surface
potential of calcite and the adsorption of sulfate ions from the
pore water. The surface potential changes are not able to explain
the observed changes in oil recovery caused by changes in pore
water chemistry or temperature. On the other hand, chemical
dissolution of calcite has the experimentally observed chemical and
temperature dependence and could account for the experimental
recovery systematics. Based on this preliminary analysis, they
conclude that although surface potential may explain some aspects
of the existing spontaneous imbibitions data set, mineral
dissolution appears to be the controlling factor.
[0006] PCT Patent Application Publication WO 2010/092095 discloses
a method for enhancing oil recovery (EOR) from a limestone or
dolomite formation containing crude oil and connate water.
[0007] PCT Patent Application Publication WO 2010/092097 discloses
a method for enhancing recovery of crude oil from a porous
subterranean formation of which the pore spaces contain crude oil
and connate water comprises:--determining the Ionic Strength
(Mol/l) of the connate water; and--injecting an aqueous
displacement fluid having a lower Ionic Strength (Mol/l) than the
connate water into the formation, which aqueous displacement fluid
furthermore has an Ionic Strength below 0.15 Mol/l. Injection of an
aqueous displacement fluid with lower Ionic Strength than the
connate water improves oil recovery (IOR).
[0008] US Patent Application Publication US 2003/0230535 discloses
a method and well for desalinating saline aquifer water, wherein
saline aquifer water flows from a subsurface aquifer layer directly
into a downhole aquifer inflow region of a desalinated water
production well in which a downhole assembly of one or more
desalination and/or purification membranes is arranged, which
separate the saline aquifer water into a primary desalinated water
stream which is produced through the well to surface and a
secondary concentrated brine reject stream, which can be disposed
into a subsurface brine disposal zone.
[0009] US Patent Application Publication US 2009/0308609 discloses
a system comprising a well drilled into an underground formation; a
production facility at a topside of the well; a water production
facility connected to the production facility; wherein the water
production facility produces water by removing some ions and adding
an agent which increases the viscosity of the water and/or
increases a hydrocarbon recovery from the formation, and injects
the water into the well.
[0010] Referring to FIG. 1, there is illustrated prior art system
100. System 100 includes body of water 102, underground formation
104, underground formation 106, and underground formation 108.
Production facility 110 may be provided at the surface of body of
water 102. Well 112 traverses body of water 102 and formation 104,
and has openings in formation 106. A portion of formation 106 may
be fractured and/or perforated as shown at 114. Oil and gas may be
produced from formation 106 through well 112, to production
facility 110. Gas and liquid may be separated from each other, gas
may be stored in gas storage 116 and liquid may be stored in liquid
storage 118.
[0011] There is a need in the art for improved systems and methods
for producing oil and/or gas from a subterranean formation. In
particular, there is a need in the art for systems and methods for
providing an improved water flood, for example in a carbonate
formation.
SUMMARY OF THE INVENTION
[0012] One aspect of the invention provides a method for enhancing
recovery of crude oil from a porous subterranean carbonate
formation of which the pore spaces contain crude oil and connate
water, the method comprising determining an ionic strength of the
connate water; and injecting an aqueous displacement fluid having a
lower ionic strength than the connate water into the formation.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] FIG. 1 illustrates a prior art oil and gas production
system.
[0014] FIG. 2 illustrates an oil and gas production system.
[0015] FIG. 3 illustrates a water processing system.
[0016] FIG. 4 illustrates a water processing system.
[0017] FIG. 5 illustrates results from an experiment.
[0018] FIG. 6 illustrates results from an experiment.
DETAILED DESCRIPTION OF THE INVENTION
[0019] Referring now to FIG. 2, in one embodiment of the invention,
system 200 is illustrated. System 200 includes formation 202,
formation 204, formation 206, and formation 208. Production
facility 210 may be provided at the surface of formation 202. Well
212 traverses formation 202 and formation 204, and has openings at
formation 206. Portions of formation may be fractured and/or
perforated as shown at 214. As oil and gas is produced from
formation 206 it enters portions 214, and travels up well 212 to
production facility 210. Gas and liquid may be separated, and gas
may be sent to gas storage 216, and liquid may be sent to liquid
storage 218, and water may be sent to water production 230.
[0020] Production facility 210 is able to process water, for
example from formation 202 and/or well 212 or other sources of
water such as seawater, lakes, rivers, gray water from a sewage
treatment plant, municipal water supply, or others, which may be
processed and stored in water production 230. Water from well 212
may be sent to water production 230. Processed water may be pumped
down well 232, to fractured portions 234 of formation 206. Water
traverses formation 206 to aid in the production of oil and gas,
and then the water the oil and gas may be all produced to well 212,
to production facility 210. Water may then be recycled, for example
by returning water to water production 230, where it may be
processed, then re-injected into well 232.
[0021] Hydrocarbons, such as oil and/or gas, may be recovered from
the earth's subsurface formation 206 through production wellbore
212 that penetrate hydrocarbon-bearing formations or reservoirs.
Perforations may be made from the production wellbore 206 to
portions of the formation 214 to facilitate flow of the
hydrocarbons from the hydrocarbon-bearing formations to the
production wellbores. Water may be injected under pressure into
injection zones 234 formed in the subsurface formation 206 to
stimulate hydrocarbon production through the production wells in a
field.
[0022] Water may be injected by itself or as a component of
miscible or immiscible displacement fluids. Sea water (for offshore
wells) and brine produced from the same or nearby formations (for
onshore wells) may be used as the water source. Such water may
contain amounts (concentration) of precursor ions, such as divalent
sulfate (SO.sub.4.sup.-), which may form insoluble salts when they
come in contact with cations, such as Ba.sup.++, Sr.sup.++ and
Ca.sup.++, resident in the formations. The resulting salts
(BaSO.sub.4, SrSO.sub.4 and CaSO.sub.4) can be relatively insoluble
at subsurface formation temperature and pressure. Such salts may
precipitate out of the solution. The precipitation of the insoluble
salts may accumulate and consequently plug the subsurface fluid
passageways. The plugging effects may be most severe in passageways
in the formation near the injection well 232 and at the
perforations of the production well 212. Solubility of the
insoluble salts may further decrease as the injection water is
produced to the surface through the production well 212, due to the
reduction of the temperature and pressure as the fluids move to the
surface through the production well. Subsurface or formation fluid
passageways may include pores in the formation matrix, fractures,
voids, cavities, vugs, perforations and fluid passages through the
wells, including cased and uncased wells, tubings and other fluid
paths in the wells. Precipitates may include insoluble salts,
crystals or scale. Plugging may include reduction in the porosity
and/or permeability of fluid passageways and the tubulars used in
producing the well fluids and processing of those fluids. Injection
water may include any fluid containing water that is injected into
a subsurface formation to facilitate recovery of hydrocarbons from
subsurface formations.
[0023] One purpose of injection well 232 is to aid the flow of
hydrocarbons from the reservoir to production well 212. One method
is to inject water under pressure adjacent to a production zone to
cause the hydrocarbons trapped in the formation 206 to move toward
the production well 212.
Formation:
[0024] In one embodiment, formation 206 may include carbonate rocks
such as limestone and/or dolostone, which are primarily oil
wet.
[0025] In addition to oil and/or gas, formation 206 may also
include water with various salts and other dissolved solids, such
as a connate water with a total dissolved solids (TDS) of 500 ppm
or more, for example a TDS of 1,000 ppm to about 100,000 ppm.
[0026] In general, a high TDS connate water provides for a
primarily oil wet carbonate rock, while providing a lower TDS
injection water serves to shift the carbonate rock towards more
water wet and less oil wet. In some embodiments, an injection water
may be used that has a TDS from about 0.001% to about 20% of the
TDS of the connate water, for example from about 0.01% to about
10%, or from about 0.1% to about 5%.
[0027] FIG. 3:
[0028] Referring now to FIG. 3, in some embodiments of the
invention, a system 300 for water production 330 is illustrated.
The method and systems used to process water, for example by
lowering the TDS of the water is not critical. Suitable methods are
set forth below with reference to FIGS. 3 and 4.
[0029] Water production 330 has an input of unprocessed water, for
example water from a body of water, a sea, a lake, a river, a water
well, connate water, city water supply, or another water supply. At
334 some cations may be removed from raw water 302, for example
multivalent cations, such as divalent or trivalent cations. At 340,
monovalent cations may be removed from raw water 302. Processed
water 303 is then produced from water production 330.
[0030] FIG. 4:
[0031] Referring now to FIG. 4, in some embodiments of the
invention, system 400 for water production 430 is illustrated.
Water production 430 has an input of unprocessed water 402, for
example water from the body of water from a well, sea water, city
water supply, or another water supply. At 432, primary filtration
may be accomplished to remove solids from water. At 433 sulphates
(SO.sub.4.sup.2-) may be removed. At 434, some divalent cations may
be removed, for example from about 60 to about 99% of the divalent
cations present. Divalent cations which may be removed include
magnesium (Mg), calcium (Ca), iron (Fe) and/or strontium (Sr).
[0032] In some embodiments, 433 and/or 434 may be performed with
nanofiltration membrane systems.
[0033] At 436, some monovalent ions may be removed, for example
from about 60 to about 99% of the cations present, such as sodium
(Na), and/or potassium (K), along with the associated anions, for
example chloride, fluoride, and/or bromide. Processed water 403 may
be produced by water production 430.
[0034] In some embodiments, water production 330 and/or 430 may use
a membrane based system, for example reverse osmosis (RO) and/or
nanofiltration (NF) technology, such as are used for seawater
desalination, filtration, and/or purification, although other water
treatment systems may be used.
[0035] In some embodiments, system 400 may include unprocessed
water 402, from an aqueous feed source such as seawater from the
ocean, or any saline water source having some divalent and
monovalent ions, such as produced water from a well. As one
example, raw seawater may be taken from the ocean, either from a
sea well or from an open intake, and initially subjected to primary
filtration 432 using a large particle strainer (not shown), and/or
multi-media filters, which might be typically sand and/or
anthracite coal, optionally followed by a cartridge filtration.
[0036] In some embodiments, a mechanical method, such as passing
the unprocessed water 402 through a nano-filtration membrane, may
be used to remove ions from the water at the surface before
injecting it into the wellbore and/or adding an agent 440. Sea
water may contain from about 2700 to about 2800 ppm of divalent
SO.sub.4.sup.2-. The nano-filtration membrane process may reduce
this concentration 433 to about 20 to about 150 ppm. A 99%
reduction in sulfate content may be achievable.
[0037] In some embodiments, processes 334, 433, and/or 434 may use
a NF device, such as a membrane. In some embodiments, processes 334
and/or 436 may use a RO device, such as a membrane.
[0038] In some embodiments of the invention, processed water 303
and/or 403 may be combined with one or more water soluble solvents,
for example, dimethyl ether, diethyl ether, and methyl-ethyl ether,
and then injected into a formation for enhanced oil recovery. Other
suitable water soluble solvents include alcohols, amines,
pyridines, ethers, carboxylic acids, aldehydes, ketones,
phosphates, quinines, and mixtures thereof, where the chemical has
a molar solubility in water of at least about 1% and an
octanol-water partition coefficient of at least 1.
[0039] In addition, a mixture of processed water with an agent for
increasing the viscosity, may be injected into a formation, for
example a water soluble polymer.
[0040] In addition, a mixture of processed water with an agent for
decreasing the interfacial tension between the oil and water, may
be injected into a formation, for example a surfactant.
[0041] Benefits:
[0042] At least two mechanisms could account for these effects, the
water chemistry could change the charge on the rock surface and
affect the rock wettability, and/or changes in the water chemistry
could dissolve rock minerals and affect the rock wettability.
[0043] The addition of low salinity water may cause a oil wet
reservoir to convert into a more water wet reservoir and release
the oil.
[0044] Low salinity water may lead to increased oil recovery for a
reservoir.
[0045] Low salinity water may lead to increased oil recovery for a
high salinity reservoir.
[0046] Water may be commonly injected into subterranean
hydrocarbon-bearing formations by itself or as a component of
miscible or immiscible displacement fluids to recover hydrocarbons
therefrom. Unprocessed water 302 and/or 402 can be obtained from a
number of sources including brine produced from the same formation,
brine produced from remote formations, or sea water. All of these
waters may have a high ionic content relative to fresh water.
[0047] In some embodiments of the invention, a low ionic strength
water may be used as processed water or a processed water mixture
303 and/or 403, for example a low ionic strength water from an
aquifer, stream, lake, river, city water supply, or gray water from
a sewage treatment plant, or other sources as are known in the
art.
[0048] In some embodiments of the invention, processed water or a
processed water mixture 303 and/or 403 may be injected into
formation 206, produced from the formation 206, and then recovered
from the oil and gas, for example, by a centrifuge or gravity
separator, and then processing the water at water production 230,
then the processed water or a processed water mixture 303 and/or
403 may be re-injected into the formation 206.
[0049] In some embodiments of the invention, processed water or a
processed water mixture 303 and/or 403 may be injected into an
oil-bearing formation 206, optionally preceded by and/or followed
by a flush, such as with seawater, a surfactant solution, a
hydrocarbon fluid, a brine solution, or fresh water.
[0050] In some embodiments of the invention, processed water or a
processed water mixture 303 and/or 403 may be used to improve oil
recovery. The processed water or a processed water mixture 303
and/or 403 may be utilized to drive or push the now oil bearing
flood out of the reservoir, thereby "sweeping" crude oil out of the
reservoir. Oil may be recovered at production well 212 spaced apart
from injection well 232 as processed water or a processed water
mixture 303 and/or 403 pushes the oil out of the pores in formation
206 and to the production well 212. Once the oil/drive fluid
reaches the surface, it may be put into holding tanks 218, allowing
the oil to separate from the water through the natural forces of
gravity.
[0051] The amount of oil recovered may be measured as a function of
the original oil in place (OOIC). The amount of oil recovered may
be greater than about 5% by weight of the original oil in place,
for example 10% or greater by weight of the original oil in place,
or 15% or greater by weight of the original oil in place.
[0052] The process and system may be useful for the displacement
recovery of petroleum from oil-bearing formations. Such recovery
encompasses methods in which the oil may be removed from an
oil-bearing formation through the action of a displacement fluid or
a gas.
[0053] Other uses for the processed water or a processed water
mixture 303 and/or 403 prepared by the process and system of the
invention include near wellbore injection treatments, and injection
along interiors of pipelines to promote pipelining of high
viscosity crude oil. The processed water or a processed water
mixture 303 and/or 403 can also be used as hydraulic fracture fluid
additives, fluid diversion chemicals, and loss circulation
additives, to mention a few.
ILLUSTRATIVE EMBODIMENTS
[0054] In one embodiment, there is disclosed a method for enhancing
recovery of crude oil from a porous subterranean carbonate
formation of which the pore spaces contain crude oil and connate
water, the method comprising determining an ionic strength of the
connate water; and injecting an aqueous displacement fluid having a
lower ionic strength than the connate water into the formation. In
some embodiments, the aqueous displacement fluid has an Ionic
Strength (I) less than about 10% of an Ionic Strength of the
connate water. In some embodiments, the aqueous displacement fluid
has an Ionic Strength (I) less than about 0.5% of an Ionic Strength
of the connate water. In some embodiments, the method further
comprises determining a total level of multivalent cations
(Moles/Volume) of the connate water; and injecting an aqueous
displacement fluid having a lower total level of multivalent
cations (Moles/Volume) than the connate water. In some embodiments,
the aqueous displacement fluid comprises at least one additive
selected from a surfactant, a foaming agent, a water soluble
polymer, and a water soluble solvent such as dimethyl ether. In
some embodiments, the aqueous displacement fluid comprises steam
and/or water obtained from an aquifer, river, lake, sea, treated
sewage effluent, or ocean. In some embodiments, the formation is a
mineral-bearing carbonate formation. In some embodiments, the
aqueous displacement fluid comprises a viscosifying polymer. In
some embodiments, the aqueous displacement fluid has a viscosity
level above 1 mPas and comprises at least 200 ppm (mass) of
viscosifying polymer. In some embodiments, the viscosifying polymer
comprises a hydrolyzed polyacrylamide. In some embodiments, the
water is treated such that it is converted into an aqueous
displacement fluid having an ionic strength less than about 5% of
an ionic strength of the connate water. In some embodiments, the
water is treated such that it is converted into an aqueous
displacement fluid having an ionic strength from about 0.1% to
about 20% of an ionic strength of the connate water. In some
embodiments, the water is treated such that it is converted into an
aqueous displacement fluid having a total dissolved solids level
from about 0.1% to about 20% of a total dissolved solids level of
the connate water.
DEFINITIONS
[0055] In this application, the terms are defined as follows:
[0056] Ionic Strength (I)--a function of the concentration of all
ions present in that solution expressed in (Mol/l) wherein
I = 1 2 i C i z i 2 , ##EQU00001##
[0057] with C.sub.i being molar concentration (Mol/l) and z.sub.i
being the valency of the specific ion and I being the summation
over all anions and cations in the solution.
[0058] Connate Water--liquids that are trapped in the pores of a
subterranean formation. These liquids are largely composed of
water, but also contain many mineral components such as ions in
solution.
[0059] Total Dissolved Solids--(abbreviated TDS) is a measure of
the combined content of all inorganic and organic substances
contained in a liquid in: molecular, ionized or micro-granular
(colloidal sol) suspended form. The solids must be small enough to
survive filtration through a sieve the size of two micrometer.
EXAMPLES
[0060] FIG. 5:
[0061] Results from spontaneous imbibition experiments on Middle
Eastern limestone core material at 70.degree. C. (Sample1). Dashed
line indicates a point in time when change of the brine in the
Amott cell took place.
[0062] A spontaneous imbibition test was carried out at 70.degree.
C. on Middle Eastern limestone core Sample 1 of about 50 mD
permeability and 22% porosity. The oil viscosity was 3.2 mPas. The
ionic strength of the formation brine was 4.39 mol/L, while fresh
water, used as wettability modifying brine, had ionic strength of
0.32 mol/L. Upon change from the formation water to the fresh
water, there was additional oil recovery of 20% indicating
wettability change towards more water-wet. Hence, reduction of
ionic strength of the brine by a factor of 14 leads to wettability
modification.
[0063] FIG. 6:
[0064] Results from spontaneous imbibition experiments on Middle
Eastern limestone core material at 70.degree. C. using solution of
NaCl as an imbibition brine.
[0065] Second experiment was performed using limestone rock from
Middle East (Sample 2) prepared under identical conditions as
limestone Sample 1, i.e. the same formulation of formation brine,
the same crude oil and identical experimental conditions. Sample 2
has permeability of 3.5 mD and porosity of 29.2%.
[0066] After finalizing spontaneous imbibition by formation water
(I=4.39 mol/L), the plug was surrounded by the solution of sodium
chloride (NaCl) with concentration of 10500 mg/L and lower ionic
strength of 0.18 mol/L. Upon brine change additional oil recovery
of 5% and hence wettability modification was observed. After this
step surrounding solution was refreshed and still additional oil
recovery was observed. This is an experimental artifact caused by
mixing of highly salinity formation brine and lower salinity
solution of NaCl inside the porous media and hence an increase in
the effective salinity of the imbibing brine. After the solution
was refreshed one more time, the oil production ceased due to
absence of salinity difference.
[0067] At the very last stage of the test the plug was surrounded
by the NaCl solution with concentration of 105 mg/L and ionic
strength of 0.002 mol/L. Again additional oil recovery of 10% was
observed. This experiment demonstrates that reduction of the ionic
strength of the imbibing brine as compared to the formation brine
causes wettability modification of the carbonate core material.
Wettability modification takes place upon reduction of ionic
strength of the brine by a factor of 24 or further reduction by a
factor of 2000.
[0068] Those of skill in the art will appreciate that many
modifications and variations are possible in terms of the disclosed
embodiments, configurations, materials and methods without
departing from their spirit and scope. Accordingly, the scope of
the claims appended hereafter and their functional equivalents
should not be limited by particular embodiments described and
illustrated herein, as these are merely exemplary in nature.
* * * * *