U.S. patent application number 12/253406 was filed with the patent office on 2010-04-22 for enhancing hydrocarbon recovery.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Kevin W. England, Jerald J. Hinkel.
Application Number | 20100096128 12/253406 |
Document ID | / |
Family ID | 42107294 |
Filed Date | 2010-04-22 |
United States Patent
Application |
20100096128 |
Kind Code |
A1 |
Hinkel; Jerald J. ; et
al. |
April 22, 2010 |
ENHANCING HYDROCARBON RECOVERY
Abstract
Recovery of hydrocarbon fluid from low permeability sources is
enhanced by introduction of a treating fluid. The treating fluid
may include one or more constituent ingredients designed to cause
displacement of hydrocarbon via imbibition. The constituent
ingredients may be determined based on estimates of formation
wettability. Further, contact angle may be used to determine
wettability. Types and concentrations of constituent ingredients
such as surfactants may be determined for achieving the enhanced
recovery of hydrocarbons.
Inventors: |
Hinkel; Jerald J.; (Houston,
TX) ; England; Kevin W.; (Houston, TX) |
Correspondence
Address: |
Schlumberger Technology Corporation
P. O. Box 425045
Cambridge
MA
02142
US
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Cambridge
MA
|
Family ID: |
42107294 |
Appl. No.: |
12/253406 |
Filed: |
October 17, 2008 |
Current U.S.
Class: |
166/270.1 ;
166/52 |
Current CPC
Class: |
E21B 43/16 20130101;
E21B 43/25 20130101 |
Class at
Publication: |
166/270.1 ;
166/52 |
International
Class: |
E21B 43/25 20060101
E21B043/25 |
Claims
1. A method for enhancing hydrocarbon recovery from a low
permeability source comprising: causing a treating fluid to contact
the source such that the treating fluid is imbibed by the source,
thereby increasing hydrocarbon recovery, wherein the source is
characterized by matrix permeability less than 0.2 milliDarcies
(mD).
2. The method of claim 1, further comprising: estimating source
wettability; determining constituents of said treating fluid based
on said estimated source wettability; formulating said treating
fluid using said determined constituents.
3. The method of claim 1 wherein estimating source wettability
includes estimating a contact angle.
4. The method of claim 1 wherein the recovered hydrocarbon
comprises a gas or a supercritical fluid.
5. The method of claim 4 wherein said source has a reservoir matrix
permeability of less than 0.1 mD.
6. The method of claim 1 wherein the recovered hydrocarbon
comprises an oil or a condensate.
7. The method of claim 6 wherein said source has a reservoir matrix
permeability of less than 0.01 mD.
8. The method of claim 1 wherein determining treating fluid
constituents includes selecting at least one constituent selected
from the group which includes scale inhibitors, formation
stabilizers, e.g., fines stabilizers and clay stabilizers, oxygen
scavengers, antioxidants, iron control agents, corrosion
inhibitors, emulsifiers, demulsifiers, foaming agents, anti-foaming
agents, buffers, pH adjusters and other additives that will alter
the available surface area.
9. The method of claim 8 including determining a surfactant type
and concentration to achieve the desired imbibition in order to
increase hydrocarbon recovery.
10. The method of claim 1 wherein said treating fluid includes an
anti-bacterial or biocidal agent.
11. The method of claim 1 wherein said treating fluid includes a
constituent that results in surface tension of said treating fluid
changing over time.
12. The method of claim 1 wherein said treating fluid includes a
constituent that causes surface tension of said treating fluid to
change in response to a temperature change.
13. The method of claim 1, wherein said treating fluid is placed
into contact with the source and hydrocarbon is recovered through
the same wellbore.
14. The method of claim 1, wherein said treating fluid is placed
into contact with the source and hydrocarbon is recovered through
different wellbores.
15. Apparatus for enhancing hydrocarbon recovery from a low
permeability source comprising: a container that stores a treating
fluid, said treating fluid characterized by one or more
constituents that facilitate imbibition; a fluid transfer device
that transfers said treating fluid from said container to the
source; and a conduit that recovers hydrocarbons released from the
source due to imbibition of said treating fluid, wherein the source
is characterized by matrix permeability less than 0.2 milliDarcies
(mD).
16. An apparatus in accordance with claim 15, wherein said treating
fluid comprises one or more constituents selected based on
estimates of source wettability.
17. The apparatus of claim 15 wherein the estimate of source
wettability includes an estimate of contact angle.
18. The apparatus of claim 15 wherein the recovered hydrocarbon
comprises a gas or a supercritical fluid.
19. The apparatus of claim 18 wherein said source has a reservoir
matrix permeability of less than 0.1 mD.
20. The apparatus of claim 15 wherein the recovered hydrocarbon
comprises an oil or a condensate.
21. The apparatus of claim 20 wherein said source has a reservoir
matrix permeability of less than 0.01 mD.
22. The apparatus of claim 15 wherein said treating fluid includes
at least one constituent selected from the group which includes
scale inhibitors, source stabilizers, and surface area
modifiers.
23. The apparatus of claim 15 wherein said treating fluid includes
at least one surfactant having a type and concentration required to
achieve improved hydrocarbon recovery.
24. The apparatus of claim 15 wherein the treating fluid includes
an anti-bacterial or biocidal agent.
25. The apparatus of claim 23 wherein the treating fluid includes a
constituent that results in the surface tension changing over
time.
26. The apparatus of claim 23 wherein the treating fluid includes a
constituent that causes surface tension to change in response to a
temperature change.
27. The apparatus of claim 15, wherein said treating fluid is
transferred and said hydrocarbon is recovered through the same
wellbore.
28. The apparatus of claim 15, wherein said treating fluid is
transferred and said hydrocarbon is recovered through different
wellbores.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application is related to commonly-assigned and
simultaneously-filed U.S. patent application Ser. No. ______,
entitled "Method of Hydrocarbon Recovery", incorporated herein by
reference in its entirety.
FIELD OF THE INVENTION
[0002] The Invention is generally related to hydrocarbon recovery
from low permeability sources.
BACKGROUND OF THE INVENTION
[0003] Recovering hydrocarbons such as oil and gas from high
permeability reservoirs is well understood. However, recovery of
hydrocarbon resources from low permeability reservoirs is difficult
and less well understood. Consequently, operators have until
recently tended to bypass low permeability reservoirs such as
shales in favor of more conventional reservoirs such as sandstones
and carbonates. A shale reservoir typically includes a matrix of
small pores and may also contain naturally occurring
fractures/fissures (natural fractures). These natural fractures are
most usually randomly occurring on the overall reservoir scale. The
natural fractures can be open (have pore volume) under in-situ
reservoir conditions or open but filled in with material (have very
little or no pore volume) later in geologic time; for example,
calcite (CaCO.sub.3). These fractures can also be in a closed-state
(no pore volume) due to in-situ stress changes over time. Natural
fractures in any or all of these states may exist in the same
reservoir. For more complete understanding of the occurrence,
properties, behavior, etc. of naturally fractured reservoirs in
general, one may review the following references: Nelson, Ronald
A., Geologic Analysis of Naturally Fractured Reservoirs (2nd
Edition), Elsevier, and Aguilera, Roberto, Naturally Fractured
Reservoirs, PennWell Publishing. The permeability of the shale pore
matrix is typically quite low, e.g., in the less than one
milliDarcy range. In a shale gas reservoir, this presents a problem
because the pore matrix contains most of the hydrocarbons. Since
the low permeability of the pore matrix restricts fluid movement,
it would be useful to understand how to prompt mass transfer of
hydrocarbons from the pore matrix to the fracture network.
[0004] Research related to low permeability formations includes
Katsube, T. J., "Shale permeability and pore-structure evolution
characteristics", Geological Survey of Canada, Current Research
2000-E15 (2000), which describes several pore structure models, and
mercury intrusion and extrusion data. So-called "storage pores"
that are dead-ended, but contain fluids, are identified from
extrusion data. However, according to Katsube the storage pores do
not contribute to the migration of fluids through the rock
formation. Imbibition, a process where a wetting fluid
spontaneously displaces a non-wetting fluid from a porous medium
has long been recognized as an effective means to enhance recovery
of oil from low permeability, naturally fractured reservoirs. For
example, Hirasaki, G. and Zhang, D., "Surface Chemistry of Oil
Recovery From Fractured, Oil-Wet Carbonate Formation", SPE 80988
(2003) describe capillary pressure and the effects of surface
chemistry on imbibition for oil recovery. Penny, G. S., Pursley, J.
T., and Clawson, T. D., "Field Study of Completion Fluids to
Enhance Gas Production in the Barnett Shale", SPE 100434 (2006) and
Paktinat, J., Pinkhouse, J. A., Williams, C., Clark, G. A., and
Penny, G. S., "Field Case Studies: Damage Preventions Through
Leakoff Control of Fracturing Fluids in Marginal/Low-Pressure Gas
Reservoirs", SPE 100417 (2006), which are related to stimulation
treatments of shales, emphasize water sensitivity and the need to
remove water from the well soon after treatments using aqueous
fluids. Li, K. and Horne, R. N., "Characterization of Spontaneous
Water Imbibition into Gas-Saturated Rocks", SPE 62552 (2000),
provided an early analysis of the process where water is
spontaneously imbibed into gas-saturated rocks. The authors note
that this process is important to water coning in cases where
naturally fractured gas reservoirs are positioned over active
aquifers. Experimental results using packs of glass beads and Berea
cores showed water imbibition to be a piston-like displacement
process. Based upon this observation, the authors formulated a
theoretical model that accounts for both effective water
permeability and capillary pressure. Generally, the permeability of
the media was greater than 500 milli-Darcies (mD). Babadagli, T.,
Hatiboglu, C. U., "Analysis of counter-current gas-water capillary
imbibition transfer at different temperatures", Journal of
Petroleum Science and Engineering 55 (2007) 277-93 describes the
counter-current flow phenomenon. The authors speculate that
imbibition in gas-liquid systems is different from the case of
liquid-liquid systems as might be encountered in oil recovery.
Despite a favorable mobility ratio, the authors point out that
entrapment of the non-wetting gas phase is likely due to high
surface tension. The authors also point out that an efficient
matrix-fracture interaction based on the matrix characteristics
could be achieved via controllable parameters such as the viscosity
and surface tension of the injected fluid. Experiments using Berea
cores indicate that less gas trapping occurs when the viscosity and
interfacial tension of the imbibing fluid are lowered. The authors
note lower surface tension at higher test temperature, e.g., 72.9
dynes/cm at 20 degC vs. 60.8 dynes/cm at 90 degC, and they discuss
the effect of lower surface tension. The permeability of the porous
media tested by Babadagli et al., a sandstone and a limestone, are
500 and 15 mD respectively, which are 5-6 orders of magnitude
greater than the matrix permeability of typical gas shales being
developed today.
[0005] It is widely believed that water imbibition into a reservoir
from a well that will be used for production is deleterious in
several ways. See, for example, Bennion, D. B., et al., "Low
Permeability Gas Reservoirs: Problems, Opportunities and Solutions
for Drilling, Completion, Stimulation and Production," SPE 35577,
Gas Technology Conference, Calgary, Alberta, Canada, April 28-May
1, 1996, and Bennion, D. B., et al., "Formation Damage Processes
Reducing Productivity of Low Permeability Gas Reservoirs," SPE
60325, 2000 SPE Rocky Mountain Regional/Low Permeability Reservoirs
Symposium and Exhibition, Denver, Colo., Mar. 12-15, 2000. Imbibed
water increases the water saturation and is thought to become
trapped and to block hydrocarbon flow. If imbibed water is fresher
than formation water, it may affect fresh water sensitive expanding
clays. Furthermore, imbibition of water into formations such as
shales during drilling may be responsible for spalling and wall
collapse. For these reasons, operators often try to complete wells
with non-aqueous fluids. Water invasion of reservoirs, except in
water-flooding with distinct injectors and producers, is considered
a damage mechanism and is to be avoided.
[0006] Bennion, et al. (2000) illustrate both the present
understanding of one example of how capillary pressures lead to
phase trapping of water and to blocking of hydrocarbon production,
and give proposed solutions that are opposite the principles and
method of the present Invention. Bennion, et al. (2000) teach that
very low permeability gas reservoirs are typically in a state of
capillary undersaturation, where the initial water (and sometimes
oil) saturation is less than would be expected from conventional
capillary mechanics for the pore system under consideration.
Retention of fluids (phase trapping) is considered to be one of the
major mechanisms of reduced productivity, even in successfully
fractured completions in these types of formations. In a low
permeability gas reservoir, due to the very small size of the pore
throats and pore bodies, the tortuous nature of the pore system and
the high degree of micro-porosity, the observed radii of curvature
of the gas-liquid interfaces are very small, particularly at low
water saturations, which gives rise to the higher capillary
pressure values and higher irreducible water saturation values
which are commonly associated with poor quality porous media. In
general, as permeability and porosity decrease and the relative
fraction of micro-porosity increases, both the capillary pressure
and the irreducible water saturation tend to increase
substantially.
[0007] Bennion, et al. (2000) further teach that often associated
with this increase in trapped initial liquid saturation is a
significant reduction in the net effective permeability to gas,
caused by the occlusion of a large portion of the pore space by the
irreducible and immobile trapped initial liquid saturation present.
On a relative permeability basis, in general, the greater the value
of the initial trapped fluid saturation, the less original reserves
of gas in place are available for production, and also the lower
the initial potential productivity of the matrix. In reservoir
situations where exceptionally low matrix permeability is present,
one finds that, if the reservoir is in a normally saturated
condition (that is, if the reservoir is in free contact and
capillary equilibrium with mobile water and is at a normal level of
capillary saturation for the specific geometry of the porous media
under consideration), Bennion, et al. (2000) teach that very high
trapped initial liquid saturations tend to be present, and that it
can be observed that in reservoir rocks of permeability to gas on
an absolute basis of less than 0.1 mD, effective initial water
saturations are often in the 60% plus region. This often results in
significant reductions of the original reserves of gas in place in
the porous media, and may also result in a very low or zero
effective permeability to gas, as the gas saturation may be at or
near the critical mobile value, and hence it will exhibit limited
or no mobility when a differential pressure gradient is applied to
the formation during production operations.
[0008] Therefore, Bennion, et al. (2000) teach that in most cases
where very low permeability gas reservoirs are potentially
productive, the reservoir exists in a situation where the reservoir
sediments have been isolated from effective continual contact with
a free water source which is capable of establishing an equilibrium
and uniform capillary transition zone. They believe that a
combination of long-term regional migration of gas through the
isolated sediments (resulting in an extractive desiccating effect
as temperature and pore pressure are increased over geologic time),
or an osmotically-motivated suction of connate water into highly
hydrophilic clays or overlying/interbedded sentiments, may be
responsible for the establishment of what is commonly referred to
as a "sub-irreducible" initial water saturation condition.
[0009] A reservoir having a sub-irreducible initial water
saturation is defined by Bennion, et al. (2000) as a reservoir
which exhibits an average initial water saturation less than the
irreducible water saturation expected to be obtained for that
porous medium at the given column height present in the reservoir
above a free water contact (based on a conventional water-gas
capillary pressure drainage test). In situations where
exceptionally low matrix permeability is present in a gas-producing
reservoir, unless a sub-irreducibly saturated original condition is
present, the reservoir will exhibit insufficient initial
reserves/permeability to be a viable gas-producing candidate.
Therefore, Bennion, et al. (2000) believe that, with few
exceptions, the vast majority of ultra-low permeability gas
reservoirs that would be classified as exhibiting economic
gas-producing pay, would fall into this classification of
subnormally saturated systems. This phenomenon, they teach, gives
rise to one of the most severe potential damage mechanisms in low
permeability gas reservoirs: fluid retention or phase trapping.
[0010] Bennion, et al. (2000) then teach that "considerable
invasion, due to capillary suction effects, can occur when water
based fluids are in contact with the formation, even in the absence
of a significant overbalance pressure. A phenomena [sic] known as
countercurrent capillary imbibition has been well documented in the
literature in previous papers and studies by the authors . . . and
illustrates how a significant increase in water saturation in the
near wellbore or fracture face region can occur in such a
situation, even if underbalanced operations are being used when
water based fluids (including foams), are circulated in contact
with the formation face." They then propose that this problem can
be mitigated by not using water based fluids in drilling,
completion, and stimulation. If water based fluids must be used,
then they recommend minimizing the exposure time and the depth of
water invasion. They then advise that "Capillary pressure, which is
the dominant variable controlling fluid retention, is a direct
linear function of interfacial tension between the water and gas
phase. If this interfacial tension can be reduced between the
invading water based filtrate and the in-situ reservoir gas, the
magnitude of the capillary pressure and the degree of observed
fluid retention may also be lessened." and they teach that "natural
capillary imbibition will want to `wick` or imbibe water from the
high water saturation zone (encompassing the original invaded area)
deeper into the formation, resulting in a `smearing` of the water
saturation profile . . . . As long as a recharge source of unbound
water is removed from the wellbore or fracture, this will obviously
result in a gradual reduction in the value of the trapped water
saturation in the near wellbore or fracture face region, which may
result in a slow long term improvement in the permeability to gas
in the region which previously exhibited near zero gas
permeability." In other words, Bennion, et al. (2000) advise that
availability, let alone injection, of water should be minimized,
especially if the interfacial tension has been lowered. This is the
exact opposite of the method of the present Invention.
SUMMARY OF THE INVENTION
[0011] The Invention is predicated in part on recognition that in
low permeability sources the conditions which favor release of oil
due to imbibition differ from the conditions which favor release of
gas due to imbibition. Further, the interfacial tension between oil
and water is much lower than the interfacial tension between a
gaseous phase and water. In accordance with an embodiment of the
Invention, a method for enhancing hydrocarbon recovery from a low
permeability source comprises: causing treating fluid to contact
the source such that the treating fluid is imbibed by the source,
thereby increasing hydrocarbon recovery. In accordance with another
embodiment of the Invention, apparatus for enhancing hydrocarbon
recovery from a low permeability source comprises a container that
stores a treating fluid. The container may be, but is not limited
to, a stationary tank, mobile tank/trailer, earthen pit, lake,
river, or any other source where fluid may be drawn from. The
treating fluid may also be pre-mixed or all additives added
continuously on-the-fly as will be known to those knowledgeable of
such treatments. The treating fluid is characterized by
constituents that facilitate imbibition. The apparatus also
includes a fluid transfer device that transfers the treating fluid
from the container to the source and a conduit that recovers
hydrocarbons released from the source due to imbibition of the
treating fluid.
BRIEF DESCRIPTION OF THE FIGURES
[0012] FIG. 1 illustrates apparatus for recovering hydrocarbons
from a low permeability source in accordance with an embodiment of
the Invention.
[0013] FIG. 2 illustrates a method for formulating the treating
fluid.
[0014] FIG. 3 illustrates an example of how different treating
fluids interact with a reservoir.
[0015] FIG. 4 illustrates differences in gas recovery for treating
fluids having different formulations, specifically, different
surfactants, for a given shale reservoir sample.
DETAILED DESCRIPTION
[0016] FIG. 1 illustrates apparatus for enhancing recovery of
hydrocarbons (in this example gas 100) from a low permeability
hydrocarbon reservoir 102. The apparatus utilizes a borehole 103
which is formed by drilling through various layers of rock
(collectively, overburden 104), if any, to the low permeability
reservoir. The reservoir will be described as a shale reservoir.
However, the Invention is not limited to shale reservoirs. For
example, the reservoir may be of any type characterized by low
permeability. Further, it is believed that the technique can
practically be applied to any reservoirs having low matrix
permeability (i.e. between 100 nano-Darcies (nD) and 500 mD, where
1 D=9.87.times.10.sup.-13 m.sup.2).
[0017] For gas and/or supercritical fluid producing wells, the
technique is particularly advantageous when the matrix permeability
is less than 10 mD, even more advantageous when the matrix
permeability is less than 5 mD, and most advantageous when the
matrix permeability is less than 1 mD. The term "gas" means a
collection of primarily hydrocarbon molecules without a definite
shape or volume that are in more or less random motion, have
relatively low density and viscosity, will expand and contract
greatly with changes in temperature or pressure, and will diffuse
readily, spreading apart in order to homogeneously distribute
itself throughout any container. The term "supercritical fluid"
means any primarily hydrocarbon substance at a temperature and
pressure above its thermodynamic critical point, that can diffuse
through solids like a gas and dissolve materials like a liquid, and
has no surface tension, as there is no liquid/gas phase
boundary.
[0018] For oil and/or condensate producing wells, the technique is
particularly advantageous when the matrix permeability is less than
500 mD, even more advantageous when the matrix permeability is less
than 250 mD, and most advantageous when the matrix permeability is
less than 100 mD. The term "oil" means any naturally occurring,
flammable or combustable liquid found in rock formations, typically
consisting of mixture of hydrocarbons of various molecular weights
plus other organic compounds such as is defined as any hydrocarbon,
including for example petroleum, gas, kerogen, paraffins,
asphaltenes, and condensate. The term "condensate" means a
low-density mixture of primarily hydrocarbon liquids that are
present as gaseous components in raw natural gas and condense out
of the raw gas when the temperature is reduced to below the
hydrocarbon dew point temperature of the raw gas.
[0019] The recovery enhancing apparatus may include a fluid storage
tank 106, a pump 108, a well head 110, and a gas recovery flowline
112. The fluid tank 106 contains a treating fluid formulated to
promote imbibition in the low permeability reservoir. For example,
the treating fluid may be an aqueous solution including surfactants
that result in a surface tension adjusted to optimize imbibition
based at least in part on determination or indication of the
wettability of the shale, permeability of the shale, or both. The
treating fluid 114 is transferred from the tank to the borehole
using the pump 108, where the treating fluid comes into contact
with the reservoir. The physical characteristics of the treating
fluid facilitate migration of the treating fluid into the shale
reservoir. In particular, the treating fluid enters the pore space
when exposed to the reservoir, e.g., for hours, days, weeks, or
longer. Entrance of the treating fluid into the pore space tends to
displace gas from the pore space. The displaced gas migrates from
the reservoir 116 to the borehole 103 through the pore space, via
the network of natural and/or induced fractures. Within the
borehole, the gas moves toward the surface as a result of
differential pressure (lower at the surface and higher at the
reservoir) and by having a lower density than the treating fluid.
The gas is then recovered via the pipe (flowline) at the wellhead.
The recovered gas is then transferred directly off site, e.g., via
flowline 112.
[0020] The principle of operation of the treating fluid is based on
capillary pressure. In particular, capillary pressure facilitates
imbibition of the treating fluid and displacement of the gas.
Capillary pressure can be calculated by the following equation:
P c = 2 .gamma. cos .theta. r , where ##EQU00001## [0021] .gamma.
represents interfacial tension, .theta. represents contact angle,
and r represents pore radius. As already described, shales exhibit
very low matrix permeability. A shale sample exhibiting a matrix
permeability of 500 nD may have an average pore radius of only
about 2.times.10.sup.-8 cm. Substituting example values for the
interfacial tension, contact angle and pore radius into the
equation above yields a capillary pressure in excess of 72,000 kPa,
or 10,440 psi. Increasing the contact angle to 60 degrees yields a
capillary pressure of 5,220 psi. The capillary pressure causes
imbibition of the treating fluid into the shale pore space.
Imbibition into either a closed capillary or an infinite capillary
results in co-current or counter-current flow, i.e., total flux is
zero. Further, co-current or counter-current imbibition will occur
when an element of the matrix is completely surrounded by wetting
fluid.
[0022] It should be noted that capillary pressure is defined as the
difference between the pressures in the wetting and non-wetting
fluids. Consequently, the imbibition of the treating fluid will be
spontaneous and independent of any positive applied differential
pressure.
[0023] FIG. 2 illustrates a method for calculating the constituents
of the treating fluid. The method includes a first preparatory step
200 of estimating capillary size and/or permeability. Estimation of
permeability may be based on examination of samples using standard
laboratory techniques as shown in step 208, or assumptions based on
pre-existing data or experience (collectively, assumptions
206).
[0024] A second preparatory step 202 is estimating formation
wettability. Wettability is an indication of the tendency of a
fluid to spread on the surface of a substance. At one extreme of
wettability the fluid responds to a solid so as to maximize the
surface area of the interface between the fluid and solid. At
another extreme of wettability the fluid forms a ball, thereby
minimizing the interfacial area. Estimation of wettability may be
based on examination of samples using standard laboratory
techniques, as indicated in step 210, assumptions based on
pre-existing data or experience (collectively, assumptions 212), or
contact angle measurement 214. The contact angle is the angle,
measured through the liquid, formed between the surface of a drop
of fluid and the surface of the substance upon which the drop is
placed. If the drop readily wets the surface, then the static
contact angle will be relatively small. Conversely, if the drop
doesn't wet the surface, it will form a bead and the static contact
angle will be large. Shales typically exhibit mixed wettability;
i.e. they are not completely 100% oil- or water-wet, although this
is not to say that they cannot be. Table 1 shows the relationship
between wettability and contact angle (static measurement). Given a
shale sample that is strongly water-wet, a treating fluid may be
formulated such that the contact angle formed between treating
fluid and the shale matrix approaches 0 degrees.
TABLE-US-00001 TABLE 1 Relationship between static contact angle
and wettability Contact Angle Wettability 0.degree.-70.degree.
Strongly water-wet 70.degree.-110.degree. Intermediate wettability
110.degree.-180.degree. Strongly oil-wet
[0025] The estimation of wettability is used to determine
constituent ingredients (e.g., surfactants) of the treating fluid
as shown in step 204. Correlations can then be used to determine
the type and concentration of surfactant to be used to achieve
enhanced gas recovery. It may also be desirable to include
anti-bacterial agents to inhibit growth that would compromise the
overall effectiveness of the process. Other constituents may also
be selected, including but not limited to scale inhibitors,
formation stabilizers, e.g., fines stabilizers and clay
stabilizers, oxygen scavengers, antioxidants, iron control agents,
corrosion inhibitors, emulsifiers, demulsifiers, foaming agents,
anti-foaming agents, buffers, pH adjusters and additives that will
alter the available surface area, e.g., by chemical means including
but not limited to oxidation and sulfonation.
[0026] FIG. 3 illustrates an example of how different treating
fluids interact with a formation sample. The example is based on
black shale formation samples. The treating fluids for this example
are water and toluene. Note that the data can be used to determine
a quantitative measure of the contact angle, i.e. after a
measurement of the permeability of various pack and fluid
properties.
[0027] FIG. 4 illustrates differences in gas recovery for wetting
fluids having different formulations, specifically, different
surfactants, for a given shale reservoir sample. The data show that
recovery from "un-treated" cores is significantly less than
recovery from "treated" cores, where treatment refers to the use of
surfactant in the treating fluid. It should be noted that the
un-treated cores yield far lower ultimate gas recovery.
[0028] A variation of the technique described above is to delay the
release (e.g., by encapsulation, solubility, etc.) of the
surfactant altering the wettability in order to reduce or eliminate
phase-trapping. Another variation is to use surfactants where the
hydrophilic-lipophilic balance (HLB) changes with temperature.
[0029] It should be noted that although the Invention has been
described with respect to recovery of hydrocarbon from a source, it
is envisioned that the Invention could also be applied to a source
that is obtained via mining operations, e.g., surface mining. For
example, material obtained from surface mining could be treated
with fluid to recover or remove hydrocarbon from the material, such
as overburden removed during coal mining operations.
[0030] While the Invention is described through the above exemplary
embodiments, it will be understood by those of ordinary skill in
the art that modification to and variation of the illustrated
embodiments may be made without departing from the inventive
concepts herein disclosed. Moreover, while the preferred
embodiments are described in connection with various illustrative
structures, one skilled in the art will recognize that the system
may be embodied using a variety of specific structures.
Accordingly, the Invention should not be viewed as limited except
by the scope and spirit of the appended claims.
* * * * *