U.S. patent application number 13/898438 was filed with the patent office on 2014-11-20 for method for enhanced oil recovery by in situ carbon dioxide generation.
This patent application is currently assigned to KING FAHD UNIVERSITY OF PETROLEUM AND MINERALS. The applicant listed for this patent is KING FAHD UNIVERSITY OF PETROLEUM AND MINERALS. Invention is credited to KHALED ZIDAN ABDELGAWAD, MOHAMED AHMED NASR EL-DIN MAHMOUD, ABDULLAH SAAD SULTAN.
Application Number | 20140338903 13/898438 |
Document ID | / |
Family ID | 51894851 |
Filed Date | 2014-11-20 |
United States Patent
Application |
20140338903 |
Kind Code |
A1 |
MAHMOUD; MOHAMED AHMED NASR EL-DIN
; et al. |
November 20, 2014 |
METHOD FOR ENHANCED OIL RECOVERY BY IN SITU CARBON DIOXIDE
GENERATION
Abstract
The method for enhanced oil recovery by in situ carbon dioxide
generation utilizes a chelating fluid injected into an oil
reservoir through a fluid injection system. The chelating fluid is
a low pH solution of a polyamino carboxylic acid chelating agent.
The polyamino carboxylic acid chelating agent may have a
concentration of about 5 wt %. The polyamino carboxylic acid
chelating agent is preferably either an aqueous solution of
H.sub.2Na.sub.2-ethylenediaminetetraacetic acid (pH 4.5),
H.sub.3-hydroxyethyl ethylenediamine triacetic acid (pH 2.5), or an
aqueous solution of H.sub.2NaHEDTA (pH 4). The injection of the
chelating fluid may be preceded by flooding the core with seawater,
and is followed by injection of either to seawater, a high pH
chelating agent, or low salinity water to ensure maximal extraction
of oil from the reservoir. The method is particularly for use in
formations where the core of the reservoir has a carbonate rock
matrix.
Inventors: |
MAHMOUD; MOHAMED AHMED NASR
EL-DIN; (DHAHRAN, SA) ; SULTAN; ABDULLAH SAAD;
(DHAHRAN, SA) ; ABDELGAWAD; KHALED ZIDAN;
(DHAHRAN, SA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
KING FAHD UNIVERSITY OF PETROLEUM AND MINERALS |
Dhahran |
|
SA |
|
|
Assignee: |
KING FAHD UNIVERSITY OF PETROLEUM
AND MINERALS
Dhahran
SA
|
Family ID: |
51894851 |
Appl. No.: |
13/898438 |
Filed: |
May 20, 2013 |
Current U.S.
Class: |
166/279 |
Current CPC
Class: |
E21B 43/20 20130101;
C09K 8/594 20130101; C09K 8/58 20130101 |
Class at
Publication: |
166/279 |
International
Class: |
E21B 43/20 20060101
E21B043/20 |
Claims
1. A method for enhanced oil recovery from a carbonate reservoir,
comprising the steps of: injecting an aqueous solution of a low pH
polyamino carboxylic acid chelating agent into the core of the
reservoir to generate the production of carbon dioxide in situ; and
subsequently injecting a fluid into the core to complete recovery
of oil from the reservoir, the fluid being selected from the group
consisting of seawater, a solution of a high pH chelating agent,
and a low salinity fluid.
2. The method for enhanced oil recovery according to claim 1,
wherein the aqueous solution comprises an aqueous solution of
H.sub.2Na.sub.2-ethylenediaminetetraacetic acid having a pH of
about 4.5.
3. The method for enhanced oil recovery according to claim 1,
wherein the aqueous solution comprises an aqueous solution of
H.sub.3-hydroxyethyl ethylenediamine triacetic acid having a pH of
about 2.5.
4. The method for enhanced oil recovery according to claim 1,
wherein the aqueous solution comprises an aqueous solution of
H.sub.2NaHEDTA having a pH of about 4.
5. The method for enhanced oil recovery according to claim 1,
wherein the aqueous solution has a concentration of about 5 wt
%.
6. The method for enhanced oil recovery according to claim 1,
wherein said step of injecting the aqueous solution further
comprises injecting the aqueous solution of a low pH polyamino
carboxylic acid chelating agent at a temperature of about
100.degree. C. and at an injection rate of 0.25 mL/min.
7. The method for enhanced oil recovery according to claim 1,
further comprising the step of flooding the core of the carbonate
reservoir with seawater prior to said step of injecting the aqueous
solution of the low pH polyamino carboxylic acid chelating agent
into the core.
Description
BACKGROUND OF THE INVENTION
[0001] 1. Field of the Invention
[0002] The present invention relates to oil recovery operations,
and particularly to a method for enhanced oil recovery by in situ
carbon dioxide generation.
[0003] 2. Description of the Related Art
[0004] Enhanced oil recovery (EOR) is a technique for increasing
the amount of crude oil that can be extracted from an oil field.
Gas injection, or miscible flooding, is presently the most commonly
used approach in enhanced oil recovery. Miscible flooding is a
general term for injection processes that introduce miscible gases
into the reservoir. A miscible displacement process maintains
reservoir pressure and improves oil displacement because the
interfacial tension between oil and water is reduced by removal of
the interface between the two interacting fluids. This allows for
total displacement efficiency. Gases used for miscible flooding
include carbon dioxide, natural gas, and nitrogen.
[0005] The fluid most commonly used for miscible displacement is
carbon dioxide because of its ability to reduce the oil viscosity,
coupled with its relatively low cost, particularly when compared to
the more costly liquefied petroleum gas. Oil displacement by carbon
dioxide injection relies on the phase behavior of the mixtures of
the gas and the crude, which is strongly dependent on reservoir
temperature, pressure and crude oil composition. However, carbon
dioxide flooding processes frequently experience viscous fingering
and gravity override problems because of the very low density and
viscosity of the carbon dioxide when compared to those of crude
oil. As a result, sweep efficiency is decreased, compared with more
dense and/or viscous fluids, and significant amounts of oil are
left behind.
[0006] Enhanced oil recovery using carbon dioxide flooding
typically requires the addition of mobility control agents to
prevent the carbon dioxide from migrating to the upper part of the
reservoir, particularly in thick reservoirs. This migration leaves
the lower part of the reservoir unswept from oil. The need for
mobility control during carbon dioxide flooding has motivated
research into foam processes, which involve the injection of carbon
dioxide together with an aqueous solution of a carbon
dioxide-foaming agent.
[0007] Carbon dioxide has a very low viscosity compared with both
oil and water. However, when carbon dioxide is in a dispersed
phase, as in a foam, its apparent viscosity is greatly increased
and its mobility is improved. In the past, it has been generally
assumed that foam would preferentially impede flow in the higher
permeability layers or fractures in the reservoir that had already
been swept of their oil. In such a process, the unswept parts of
the reservoir would remain at least as accessible and available to
have their content displaced and forced into the production wells.
The overall success of the foaming process depends on foam
concentration, compatibility with the reservoir rock, stability in
solution over long periods of time, and thermal stability.
Surfactants have been used as foaming agents, but surfactants
suffer from thermal stability problems, typically being unstable at
temperatures exceeding 100.degree. C.
[0008] Due to the problems involved in the injection of carbon
dioxide into the reservoir, there has been significant interest in
generating carbon dioxide in situ. One prior technique used
ammonium carbamate to produce a significant amount of carbon
dioxide when the temperature rose to 85.degree. C. Using ammonium
carbamate in a one-dimensional sand pack column resulted in the
production of carbon dioxide in the column at temperatures between
80.degree. C. and 90.degree. C., along with decreases in oil
viscosity. The additional injection of a 0.5 vol % of 3% ammonium
carbamate solution with a polymer/surfactant chemical flood
improved crude oil recovery by 9.7% original oil in place (OOIP),
compared to a polymer/surfactant chemical flood without carbamate.
However, there was negligible oil recovery in experiments without
the presence of surfactants when using light oils, decane and Arrow
crude oil. Overall, oil recovery by this process was very low, with
only 43% residual oil recovery after surfactant/polymer
injection.
[0009] Another method for generating carbon dioxide in situ
involves the injection of sodium carbonate with hydrochloric acid
(HCl) into the formation, followed by reaction over a 24 hour
period. However, HCl is very corrosive. Thus, costly corrosion
inhibitors need to be added. Further, the corrosion inhibitor may
reverse the wettability of the formation, thus requiring water
wetting agents to also be added. A further problem is that the HCl
cannot be used in carbonate reservoirs due to the reaction between
the HCl with the carbonate.
[0010] Thus, a method for enhanced oil recovery by in situ carbon
dioxide generation solving the aforementioned problems is
desired.
SUMMARY OF THE INVENTION
[0011] The method for enhanced oil recovery by in situ carbon
dioxide generation utilizes a chelating fluid injected into an oil
reservoir through a fluid injection system. The chelating fluid is
a low pH solution of a polyamino carboxylic acid chelating agent.
The polyamino carboxylic acid chelating agent may have a
concentration of about 5 wt %. The polyamino carboxylic acid
chelating agent is preferably either an aqueous solution of
H.sub.2Na.sub.2-ethylenediaminetetraacetic acid (pH 4.5),
H.sub.3-hydroxyethyl ethylenediamine triacetic acid (pH 2.5), or an
aqueous solution of H.sub.2NaHEDTA (pH 4). The chelating fluid may
be injected at a rate of approximately 0.25 mL/min. The injection
of the chelating fluid may be preceded by flooding the core with
seawater, and is followed by injection of either seawater, a high
pH chelating agent, or low salinity water to ensure maximal
extraction of oil from the reservoir. The method is particularly
for use in formations where the core of the reservoir has a
carbonate rock matrix, since the carbon dioxide generation results
from acidic liberation of carbon dioxide from the carbonate
rock.
[0012] These and other features of the present invention will
become readily apparent upon further review of the following
specification.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] FIG. 1 is a graph showing oil recovery using a low pH
solution of H.sub.3-hydroxyethyl ethylenediaminetriacetic acid for
in situ carbon dioxide generation for enhanced oil recovery
according to the present invention.
[0014] FIG. 2 is a graph showing oil recovery using a low pH
solution of H.sub.2Na.sub.2-ethylenediaminetetraacetic acid for in
situ carbon dioxide generation for enhanced oil recovery according
to the present invention.
[0015] Similar reference characters denote corresponding features
consistently throughout the attached drawings.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0016] The method for enhanced oil recovery by in situ carbon
dioxide generation utilizes a chelating fluid injected into an oil
reservoir through a fluid injection system. The chelating fluid is
a low pH solution of a polyamino carboxylic acid chelating agent.
The polyamino carboxylic acid chelating agent may have a
concentration of about 5 wt %. The polyamino carboxylic acid
chelating agent is preferably either an aqueous solution of
H.sub.2Na.sub.2-ethylenediaminetetraacetic acid (pH 4.5),
H.sub.3-hydroxyethyl ethylenediamine triacetic acid (pH 2.5), or an
aqueous solution of H.sub.2NaHEDTA (pH 4). The chelating fluid may
be injected at a rate of approximately 0.25 mL/min. The injection
of the chelating fluid may be preceded by flooding the core with
seawater, and is followed by injection of either seawater, a high
pH chelating agent, or low salinity water to ensure maximal
extraction of oil from the reservoir. The method is particularly
for use in formations where the core of the reservoir has a
carbonate rock (chalk and limestone) matrix (referred to as a
carbonate reservoir), since the carbon dioxide generation results
from acidic liberation of carbon dioxide from the carbonate
rock.
[0017] First, the low pH chelating agent will react with the
carbonate rock and produce CO.sub.2 that will diffuse to the oil
and increases oil mobility so that more oil will be produced. The
acidic part of the chelating agent that includes the hydrogen ions
will produce the carbon dioxide from the carbonate rock formations.
Then, the high pH chelating agent, seawater, or low salinity water
will displace the low pH chelating agent and the CO.sub.2. The
method does not require the use of surfactants or other additives,
and eliminates the problem of gravity override. Only a small volume
of the aqueous solution of the low pH chelating agent is needed to
generate the carbon dioxide, and when the concentration is limited
to about 5%, no additives are required to prevent corrosion.
[0018] In order to demonstrate the method, core flooding
experiments were performed using Indiana limestone cores, each
having a length of 5 inches, and a diameter of 1.5 inches.
H.sub.2Na.sub.2-ethylenediaminetetraacetic acid
(H.sub.2Na.sub.2-EDTA) with a pH of 4.5 and H.sub.3-hydroxyethyl
ethylenediaminetriacetic acid (H.sub.3-HEDTA) with a pH of 2.5 were
each tested as dual chelating agents and in situ carbon dioxide
generating agents. Each agent was dissolved in water, and the
solution was injected. The injection was followed by continuous
injection of seawater or continuous injection of a high pH
chelating agent.
[0019] FIG. 1 shows the effect of carbon dioxide generated from the
use of the H.sub.3-HEDTA chelating agent at 5 wt % concentration
and a pH of 2.5. The experiment was performed at 100.degree. C. and
at an injection rate of 0.25 mL/min. The core was first flooded by
seawater, which recovered 58% of the initial oil from the core
(i.e., 42% of the oil remained inside the core). A single pore
volume of 5 wt % H.sub.3-HEDTA was injected into the core, and it
recovered 34% oil from the oil in place or, in other words, 81% of
the residual oil. One pore volume of 5 wt % H.sub.3-HEDTA produced
enough carbon dioxide to recover more than 80% of the residual
oil.
[0020] FIG. 2 shows the results of a similar core flooding
experiment with H.sub.2Na.sub.2-EDTA at a pH of 4.5. Continuous
injection of this solution increased the oil recovery more than 90%
from the initial oil in place. H.sub.2Na.sub.2-EDTA did not produce
as much carbon dioxide as H.sub.3-HEDTA, thus larger volumes of the
H.sub.2Na.sub.2-EDTA solution were required to recover an
equivalent amount of oil. Further, in FIG. 2, H.sub.2Na.sub.2-EDTA
was tested against a 5 wt % conventional chelating agent,
Na.sub.4-EDTA, with the H.sub.2Na.sub.2-EDTA solution clearly
outperforming the conventional chelating solution of
Na.sub.4-EDTA.
[0021] It is to be understood that the present invention is not
limited to the embodiments described above, but encompasses any and
all embodiments within the scope of the following claims.
* * * * *