U.S. patent application number 12/203072 was filed with the patent office on 2010-03-04 for liquified petroleum gas fracturing methods.
This patent application is currently assigned to Gas-Frac Energy Services Inc.. Invention is credited to Dwight N. Loree, Grant Nevison.
Application Number | 20100051272 12/203072 |
Document ID | / |
Family ID | 41723615 |
Filed Date | 2010-03-04 |
United States Patent
Application |
20100051272 |
Kind Code |
A1 |
Loree; Dwight N. ; et
al. |
March 4, 2010 |
LIQUIFIED PETROLEUM GAS FRACTURING METHODS
Abstract
Methods of tailoring a hydrocarbon fracturing fluid for a
subterranean formation are disclosed. Fluid in the subterranean
formation has a fluid temperature. A first critical temperature of
a hydrocarbon fluid is adjusted to a critical temperature above the
fluid temperature by adding a liquefied petroleum gas component to
the hydrocarbon fluid to produce the hydrocarbon fracturing fluid.
The liquefied petroleum gas component has a second critical
temperature, and the hydrocarbon fluid comprises liquefied
petroleum gas. A hydrocarbon fracturing fluid made by these methods
are also disclosed. Methods of treating a subterranean formation
are also disclosed. A hydrocarbon fracturing fluid is introduced
into the subterranean formation, the hydrocarbon fracturing fluid
having a critical temperature that is above a fluid temperature of
the hydrocarbon fracturing fluid when the hydrocarbon fracturing
fluid is in the subterranean formation. The hydrocarbon fracturing
fluid is subjected to pressures above the formation pressure.
Inventors: |
Loree; Dwight N.; (Black
Creek, CA) ; Nevison; Grant; (Bragg Creek,
CA) |
Correspondence
Address: |
CHRISTENSEN, O'CONNOR, JOHNSON, KINDNESS, PLLC
1420 FIFTH AVENUE, SUITE 2800
SEATTLE
WA
98101-2347
US
|
Assignee: |
Gas-Frac Energy Services
Inc.
Calgary
CA
|
Family ID: |
41723615 |
Appl. No.: |
12/203072 |
Filed: |
September 2, 2008 |
Current U.S.
Class: |
166/279 ;
507/203 |
Current CPC
Class: |
C09K 8/64 20130101; E21B
43/26 20130101 |
Class at
Publication: |
166/279 ;
507/203 |
International
Class: |
E21B 43/22 20060101
E21B043/22 |
Claims
1. A method of tailoring a hydrocarbon fracturing fluid for a
subterranean formation, fluid in the subterranean formation having
a fluid temperature, the method comprising: adjusting a first
critical temperature of a base hydrocarbon fluid to a critical
temperature above the fluid temperature by adding a critical
temperature adjusting fluid having a second critical temperature to
the hydrocarbon fluid to produce the hydrocarbon fracturing fluid,
the hydrocarbon fluid comprising liquefied petroleum gas.
2. The method of claim 1 in which the critical temperature
adjusting fluid comprises a liquefied petroleum gas component.
3. The method of claim 2 in which the base hydrocarbon fluid
comprises one or more of propane, butane and pentane, and the
critical temperature adjusting fluid comprises one or more of
ethane, propane, butane and pentane.
4. The method of claim 2 in which the second critical temperature
is higher than the first critical temperature.
5. The method of claim 4 in which the base hydrocarbon fluid
comprises propane.
6. The method of claim 5 in which the critical temperature
adjusting fluid comprises butane.
7. The method of claim 1 in which the first critical temperature is
below the fluid temperature.
8. The method of claim 1 in which the second critical temperature
is lower than the first critical temperature, and the first
critical temperature is above the fluid temperature.
9. The method of claim 8 in which the base hydrocarbon fluid
comprises at least one of propane and butane.
10. The method of claim 9 in which the critical temperature
adjusting fluid comprises one or more of propane and ethane.
11. The method of claim 10 in which the critical temperature
adjusting liquid comprises ethane.
12. The method of claim 1 in which the critical temperature of the
base hydrocarbon fracturing fluid is adjusted by mixing with
critical temperature adjusting fluid to be sufficiently close to
the fluid temperature that mixing of the hydrocarbon fracturing
fluid with formation gas reduces the critical temperature of the
hydrocarbon fracturing fluid to below the fluid temperature.
13. The method of claim 1 in which the critical temperature of the
hydrocarbon fracturing fluid is within 1 degree C. of the fluid
temperature.
14. A method of tailoring a hydrocarbon fracturing fluid for a
subterranean formation, fluid in the subterranean formation having
a fluid temperature, the method comprising: adjusting a first
critical temperature of a base hydrocarbon fluid by adding a
liquefied petroleum gas component having a second critical
temperature to the base hydrocarbon fluid to produce the
hydrocarbon fracturing fluid, the base hydrocarbon fluid comprising
liquefied petroleum gas.
15. The method of claim 14 in which the base hydrocarbon fluid
comprises one or more of propane, butane and pentane, and the
liquefied petroleum gas component comprises one or more of ethane,
propane, butane and pentane.
16. A hydrocarbon fracturing fluid made by the method of claim
1.
17. The hydrocarbon fracturing fluid of claim 16 further comprising
at least one gelling agent.
18. The hydrocarbon fracturing fluid of claim 17 further comprising
at least one activator.
19. The hydrocarbon fracturing fluid of claim 17 further comprising
at least one breaker.
20. A method of treating a subterranean formation containing
formation fluids, the method comprising: introducing a hydrocarbon
fracturing fluid into the subterranean formation, the hydrocarbon
fracturing fluid having a critical temperature that is above a
fluid temperature of the hydrocarbon fracturing fluid when the
hydrocarbon fracturing fluid is in the subterranean formation, the
hydrocarbon fracturing fluid comprising liquefied petroleum gas;
and subjecting the hydrocarbon fracturing fluid to pressures above
the formation pressure.
21. The method of claim 20 in which the hydrocarbon fracturing
fluid is subjected to pressures at or above fracturing
pressures.
22. The method of claim 20 where fluid in the subterranean
formation comprises formation gas, and the formation gas mixes with
the hydrocarbon fracturing fluid to reduce the critical temperature
of the hydrocarbon fracturing fluid in the subterranean formation
and assist in expelling the hydrocarbon fracturing fluid from the
subterranean formation and the well.
23. The method of claim 22 where the formation gas comprises
methane.
24. The method of claim 20 further comprising shutting-in the
hydrocarbon fracturing fluid in the subterranean formation for a
period of at least 4 hours.
25. The method of claim 24 further comprising shutting-in the
hydrocarbon fracturing fluid in the subterranean formation for a
period of at least 24 hours.
26. The method of claim 20 further comprising producing the
hydrocarbon fracturing fluid along with formation fluids to a sales
line.
27. The method of claim 26 where mixing of the hydrocarbon
fracturing fluid with formation gas assists in propelling recovered
hydrocarbon fracturing fluid into the sales line.
28. A method of treating an under-pressured subterranean formation
having a formation pressure and containing formation fluids, the
method comprising: providing a hydrocarbon fracturing fluid
comprising liquefied petroleum gas, the hydrocarbon fracturing
fluid having a density such that the static pressure of the
hydrocarbon fracturing fluid at the under-pressured subterranean
formation is less than the formation pressure; introducing the
hydrocarbon fracturing fluid into the under-pressured subterranean
formation; subjecting the hydrocarbon fracturing fluid to pressures
above the formation pressure; and recovering the hydrocarbon
fracturing fluid along with formation fluids.
29. The method of claim 28 in which the hydrocarbon fracturing
fluid has a critical temperature that is above a fluid temperature
of the hydrocarbon fracturing fluid when the hydrocarbon fracturing
fluid is in the subterranean formation.
30. The method of claim 29 in which the hydrocarbon fracturing
fluid is subjected to pressures at or above fracturing
pressures.
31. The method of claim 28 where fluid in the subterranean
formation comprises formation gas, and the formation gas mixes with
the hydrocarbon fracturing fluid to reduce the critical temperature
of the hydrocarbon fracturing fluid in the subterranean formation
and assist in expelling the hydrocarbon fracturing fluid from the
subterranean formation and the well.
32. The method of claim 31 where the formation gas comprises
methane.
33. The method of claim 28 in which the recovered fluids are
directed to a sales line.
34. A method of treating a subterranean formation, the method
comprising: introducing a hydrocarbon fracturing fluid comprising
liquefied petroleum gas into the subterranean formation; subjecting
the hydrocarbon fracturing fluid to pressures above the formation
pressure; and shutting-in the hydrocarbon fracturing fluid in the
subterranean formation for a period of at least 4 hours.
35. The method of claim 34 in which the hydrocarbon fracturing
fluid is shut-in for a period of at least 24 hours.
36. A method of treating one or more hydrocarbon reservoirs
penetrated by a well, the method comprising: introducing
hydrocarbon fracturing fluid comprising liquefied petroleum gas
through the well into a first zone of the one or more hydrocarbon
reservoirs; subjecting the hydrocarbon fracturing fluid in the
first zone to pressures above the formation pressure of the first
zone; introducing hydrocarbon fracturing fluid comprising liquefied
petroleum gas through the well into a second zone of the one or
more hydrocarbon reservoirs; subjecting the hydrocarbon fracturing
fluid in the second zone to pressures above the formation pressure
of the second zone; and at least partially removing the hydrocarbon
fracturing fluid from the first zone and the second zone.
37. The method of claim 36 in which the well is a predominantly
horizontal well penetrating a hydrocarbon reservoir and the first
zone and the second zone are both in the hydrocarbon reservoir.
38. The method of claim 36 in which the well is a predominantly
vertical well penetrating at least a first hydrocarbon reservoir
and a second hydrocarbon reservoir and the first zone comprises at
least a portion of the first hydrocarbon reservoir and the second
zone comprises at least a portion of the second hydrocarbon
reservoir.
39. The method of claims 36 further comprising shutting in the
first zone before introducing hydrocarbon fracturing fluid into the
second zone.
40. The method of claim 39 in which the first zone is shut-in for a
period of at least 4 hours.
41. The method of claim 36 further comprising shutting in the
second zone before at least partially removing the hydrocarbon
fracturing fluid from the second zone.
42. The method of claim 36 in which the hydrocarbon fracturing
fluid introduced into the first zone has a different composition
from the hydrocarbon fracturing fluid introduced into the second
zone.
Description
TECHNICAL FIELD
[0001] This application relates to the field of LPG fracturing and
treatment systems and methods.
BACKGROUND
[0002] In the conventional fracturing of wells, producing
formations, new wells or low producing wells that have been taken
out of production, a formation can be fractured to attempt to
achieve higher production rates. Proppant and fracturing fluid are
mixed in a blender and then pumped into a well that penetrates an
oil or gas bearing formation. High pressure is applied to the well,
the formation fractures and proppant carried by the fracturing
fluid flows into the fractures. The proppant in the fractures holds
the fractures open after pressure is relaxed and production is
resumed. Various fluids have been disclosed for use as the
fracturing fluid, including various mixtures of hydrocarbons,
nitrogen and carbon dioxide.
[0003] Care must be taken over the choice of fracturing fluid. The
fracturing fluid must have a sufficient viscosity to carry the
proppant into the fractures, should minimize formation damage and
must be safe to use. A fracturing fluid that remains in the
formation after fracturing is not desirable since it may block
pores and reduce well production. For this reason, carbon dioxide
has been used as a fracturing fluid because, when the fracturing
pressure is reduced, the carbon dioxide gasifies and is easily
removed from the well.
[0004] Lower order alkanes such as propane have also been proposed
as fracturing fluids. Thus, U.S. Pat. No. 3,368,627 describes a
fracturing method that uses a combination of a liquefied C2-C6
hydrocarbon and carbon dioxide mix as the fracturing fluid. The mix
is designed to have a critical temperature below the formation
temperature, and after stimulation is completed and the pressure
reduced, the mix heats up to the formation temperature and is
gasified. As a lower order alkane, ethane, propane, butane and
pentane are inherently non-damaging to formations. However, this
patent does not describe how to achieve propane or butane injection
safely, or how to inject proppant into the propane or butane frac
fluid. Further, fracturing mixes contemplated by this patent are
not intended to be left in the formation for long periods of time,
since they gasify once heated to their critical temperature by the
formation. U.S. Pat. No. 5,899,272 also describes propane as a
fracturing fluid, but the injection system described in that patent
has not been commercialized. Thus, while propane and butane are
desirable fluids for fracturing due to their volatility, low weight
and easy recovery, those very properties tend to make propane and
butane hazardous, and thus LPG fracturing had been commercially
abandoned by the industry until proposed by the inventor Dwight
Loree in his Patent Cooperation Treaty Application No.
PCT/CA2007/000342 published Sep. 7, 2007 and related
applications.
SUMMARY
[0005] Methods of tailoring a hydrocarbon fracturing fluid for a
subterranean formation are disclosed. Fluid in the subterranean
formation has a fluid temperature. A first critical temperature of
a base hydrocarbon fluid is adjusted for example to a critical
temperature above the fluid temperature by adding a critical
temperature adjusting fluid such as a liquefied petroleum gas
component to the base hydrocarbon fluid to produce the hydrocarbon
fracturing fluid. The liquefied petroleum gas component has a
second critical temperature, and the base hydrocarbon fluid
comprises liquefied petroleum gas. A hydrocarbon fracturing fluid
made by these methods are also disclosed.
[0006] Methods of treating a subterranean formation are also
disclosed. A hydrocarbon fracturing fluid is introduced into the
subterranean formation, the hydrocarbon fracturing fluid having a
critical temperature that is above a fluid temperature of the
hydrocarbon fracturing fluid when the hydrocarbon fracturing fluid
is in the subterranean formation, the hydrocarbon fracturing fluid
comprising liquefied petroleum gas. The hydrocarbon fracturing
fluid is subjected to pressures above the formation pressure.
[0007] Methods of treating a subterranean formation are also
disclosed. A hydrocarbon fracturing fluid comprising liquefied
petroleum gas is introduced into the subterranean formation. The
hydrocarbon fracturing fluid is subjected to pressures above the
formation pressure. The hydrocarbon fracturing fluid is then
shut-in in the subterranean formation for a period of at least 4
hours. The period may be, for example longer than 12 hours or 24
hours and could be more than two days.
[0008] Methods of treating plural zones of one or more hydrocarbon
reservoirs penetrated by a well are also disclosed. Hydrocarbon
fracturing fluid comprising liquefied petroleum gas is introduced
through the well into a first zone of the one or more hydrocarbon
reservoirs. The hydrocarbon fracturing fluid is subjected in the
first zone to pressures above the formation pressure of the first
zone. Hydrocarbon fracturing fluid comprising liquefied petroleum
gas is introduced through the well into a second zone of the one or
more hydrocarbon reservoirs. The hydrocarbon fracturing fluid is
subjected in the second zone to pressures above the formation
pressure of the second zone. The hydrocarbon fracturing fluid is at
least partially removed from the first zone and the second
zone.
[0009] A fluid is also disclosed, the fluid comprising hydrocarbon
fracturing fluid at least partially removed from the subterranean
formations of the methods disclosed herein. A subterranean
formation is also disclosed comprising the hydrocarbon fracturing
fluid introduced by any of the methods disclosed herein.
[0010] A method of treating under-pressured formations is also
disclosed. The under-pressured subterranean formation has a
formation pressure and contains formation fluids. A hydrocarbon
fracturing fluid comprising liquefied petroleum gas is prepared,
the hydrocarbon fracturing fluid having a density such that the
static pressure of the hydrocarbon fracturing fluid at the
under-pressured subterranean formation is less than the formation
pressure. The hydrocarbon fracturing fluid is introduced into the
under-pressured subterranean formation. The hydrocarbon fracturing
fluid is subjected to pressures above the formation pressure. The
hydrocarbon fracturing fluid is then recovered along with formation
fluids.
[0011] These and other aspects of the device and method are set out
in the claims, which are incorporated here by reference.
BRIEF DESCRIPTION OF THE FIGURES
[0012] Embodiments will now be described with reference to the
figures, in which like reference characters denote like elements,
by way of example, and in which:
[0013] FIG. 1 is a graph of the saturation curve of propane,
illustrating a fracturing process.
[0014] FIG. 2 is a graph of saturation curves of various mixtures
of propane and methane.
[0015] FIG. 3 is a schematic of a fracture created by conventional
fracturing techniques.
[0016] FIG. 4 is a schematic of a fracture created by the methods
disclosed herein.
[0017] FIG. 5 is a top plan schematic of a fracturing system
carrying out an embodiment of a method as disclosed herein,
illustrating proppant being loaded into proppant supply
vessels.
[0018] FIG. 6 is a top plan schematic of a fracturing system
carrying out an embodiment of a method as disclosed herein,
illustrating pressure testing the lines with inert gas.
[0019] FIG. 7 is a top plan schematic of a fracturing system
carrying out an embodiment of a method as disclosed herein,
illustrating the bleeding off of inert gas from the lines, and
commencement of the frac.
[0020] FIG. 8 is a top plan schematic of a fracturing system
carrying out an embodiment of a method as disclosed herein,
illustrating the loading of frac fluid in the well.
[0021] FIG. 9 is a top plan schematic of a fracturing system
carrying out an embodiment of a method as disclosed herein,
illustrating the completion of a frac treatment.
[0022] FIG. 10 is a top plan schematic of a fracturing system
carrying out an embodiment of a method as disclosed herein,
illustrating the purging of LPG-filled lines with inert gas.
[0023] FIG. 11 is a top plan schematic of a fracturing system
carrying out an embodiment of a method as disclosed herein,
illustrating the purging of the process blender with inert gas.
[0024] FIG. 12 is a top plan schematic of a fracturing system
carrying out an embodiment of a method as disclosed herein,
illustrating the production of well fluids upon completion of a
frac treatment.
[0025] FIG. 13 is a graph illustrating various specifications for
an exemplary treatment carried out using an embodiment of a method
as disclosed herein.
[0026] FIGS. 14A-C illustrate a method of treating plural
hydrocarbon reservoirs penetrated by a vertical well as disclosed
herein.
[0027] FIG. 14D illustrates a method of treating plural hydrocarbon
zones of a reservoir penetrated by a horizontal well as disclosed
herein.
[0028] FIG. 15 is a graph illustrating the viscosity of water and
LPG.
[0029] FIG. 16 is a graph illustrating the surface tension of water
and LPG.
[0030] FIG. 17 is a graph illustrating a gelled hydrocarbon
fracturing fluid breaking after a set amount of time.
[0031] FIG. 18 is a graph of the saturation curve of propane,
illustrating the separator operating region.
[0032] FIGS. 19A-B are tables that illustrate various examples of
formations fractured using the methods disclosed herein.
[0033] FIG. 20 is a flow schematic illustrating a method of
tailoring a hydrocarbon fracturing fluid for a subterranean
formation, fluid in the subterranean formation having a fluid
temperature.
[0034] FIG. 21 is a flow schematic illustrating a method of
treating a subterranean formation with a fracturing fluid that has
a critical temperature above the fluid temperature.
[0035] FIG. 22 is a flow schematic illustrating a further method of
treating a subterranean formation involving shutting-in the fluid
for an extended period of time.
[0036] FIG. 23 is a flow schematic illustrating a method of
treating plural zones of one or more hydrocarbon reservoirs
penetrated by a well.
[0037] FIG. 24 is a flow schematic illustrating a further method of
tailoring a hydrocarbon fracturing fluid for a subterranean
formation, fluid in the subterranean formation having a fluid
temperature.
[0038] FIG. 25 is a flow schematic illustrating a method of
treating an under-pressured subterranean formation having a
formation pressure and containing formation fluids.
DETAILED DESCRIPTION
[0039] Immaterial modifications may be made to the embodiments
described here without departing from what is covered by the
claims.
[0040] Liquefied Petroleum Gases (hereinafter LPG) include a
variety of petroleum and natural gases existing in a liquid state
at ambient temperatures and moderate pressures. In some cases, LPG
refers to a mixture of such fluids. These mixes are generally more
affordable and easier to obtain than any one individual LPG, since
they are hard to separate and purify individually. Unlike
conventional hydrocarbon based fracturing fluids, common LPGs are
tightly fractionated products resulting in a high degree of purity
and very predictable performance. Exemplary LPGs used in this
document include ethane, propane, butane, pentane, hexane, and
various mixes thereof. Further examples include HD-5 propane,
commercial butane, i-butane, i-pentane, n-pentane, and n-butane.
The LPG mixture may be controlled to gain the desired hydraulic
fracturing and clean-up performance.
[0041] LPGs tend to produce excellent fracturing fluids. LPG is
readily available, cost effective and is easily and safely handled
on surface as a liquid under moderate pressure. LPG is completely
compatible with formations and formation fluids, is highly soluble
in formation hydrocarbons and eliminates phase trapping--resulting
in increased well production. LPG may be readily and predictably
viscosified to generate a fluid capable of efficient fracture
creation and excellent proppant transport. After fracturing, LPG
may be recovered very rapidly, allowing savings on clean up costs.
Further, LPG may be recovered directly to sales gas without
flaring. Referring to FIGS. 3 and 4, fractures formed during
fracturing with conventional and LPG fluids, respectively, are
contrasted. Conventional stimulation techniques incorporate the use
of fluids such as oil, water, methanol, CO.sub.2, and N.sub.2 for
example. Referring to FIG. 3, the effective fracture length 12 is
much shorter than the created fracture length 14. The effective
fracture length 12 refers to the length of the created fracture
through which well fluids may be produced into the well. This may
occur as a result of the high surface tension of conventional
fluids creating liquid blocks in the pores of a formation. Because
the conventional fluids are not easily removed from the formation,
the liquid blocks effectively eliminate a large portion of fracture
through which fluids may otherwise be produced. Referring to FIG.
4, on the other hand, the effective fracture length 12 is the same
as the created fracture length 14. This is due to the fact that the
LPG fluid may be cleaned up quickly and completely. The LPG may
clean up by vaporization with natural gas in the formation, or by
dissolving into solution with formation oil, thus eliminating the
relative permeability flow reduction seen with conventional fluids.
The vaporization of LPG with natural gas and the extremely low
viscosity of LPG permits rapid clean-up to be accomplished with
minimal drawdown.
[0042] Referring to FIG. 16, the extremely low surface tension of
the LPG eliminates or at least significantly reduces the formation
of liquid blocks created by fluid trapping in the pores of the
formation. This is contrasted with the high surface tension of
water, which makes water less desirable as a conventional fluid.
LPG is nearly half the density of water, and generates gas at
approximately 272 m.sup.3 gas/m.sup.3 of liquid. LPG comprising
butane and propane has a hydrostatic gradient at 5.1 kPa/m, which
greatly assists any post-treatment clean-up required, by allowing
greater drawdown. This hydrostatic head is approximately half the
hydrostatic head of water, indicating that LPG is a naturally under
balanced fluid. Referring to FIG. 15, LPG also has significantly
lowered viscosity than water in an ungelled state, which further
aids in the removal of LPG from a well.
[0043] Referring to FIG. 1, a propane saturation curve is
illustrated. The * indicates the critical point of propane, and
hence the critical temperature as well. The critical temperature is
understood as the temperature beyond which the fluid exists as a
gas, regardless of pressure. The region indicated by the reference
numeral 10 corresponds to low-pressure surface handling, which
refers to exemplary ranges of pressures and temperatures under
which LPG is typically stored prior to use in fracturing. Exemplary
critical temperatures of LPGs are denoted below in Table 1.
TABLE-US-00001 TABLE 1 LPG Critical Temperature (.degree. C.)
Ethane 32 Propane 97 n-Butane 152 Pentane 197
[0044] Referring to FIGS. 20 and 24, methods of tailoring a
hydrocarbon fracturing fluid for a subterranean formation is
illustrated. Fluid in the subterranean formation has a fluid
temperature. This may be the temperature of fluids contained
naturally in the formation, or the temperature of fracturing or
treatment fluids that have been in the formation long enough to
acclimatize with the formation. Referring to FIG. 20, in step 100,
a first critical temperature of a hydrocarbon fluid (base fluid) is
adjusted to a critical temperature above the fluid temperature by
adding a critical temperature adjusting fluid such as liquefied
petroleum gas component having a second critical temperature to the
hydrocarbon fluid to produce the hydrocarbon fracturing fluid. The
hydrocarbon fluid comprises liquefied petroleum gas. As a skilled
worker would understand, the formation temperature of each
formation to be fractured is different, as is the fluid temperature
in each of these formations. Thus, it is desirable to tailor each
hydrocarbon fluid such that it has a critical temperature that is
above the fluid temperature. This customization of the critical
temperature of the frac fluid composition allows one to improve the
recovery performance of the hydrocarbon fracturing fluid within the
reservoir under certain application pressures and temperatures. In
addition, this customization may allow one to maintain or improve
gel performance during the fracturing operation. Also, the critical
temperature may be adjusted to at or above the fluid temperature
achieved during placement of the hydrocarbon fracturing fluid in
order to avoid the degradation of the gel performance that may be
experienced as the fluid temperature approaches or exceeds the
mixture critical temperature due to heating in or by the formation.
In some embodiments, the critical temperature of the hydrocarbon
fracturing fluid needs only to be just above, for example by a
fraction of a degree, the fluid temperature, although it could be a
degree or more above such as at least 10, 20, 30, 50, 100 or 150,
degrees higher than the fluid temperature. The base fluid may be
one or more of propane, butane and pentane, and to adjust the
critical temperature may be mixed with one or more of ethane,
propane, butane and pentane. Adjusting the relative amounts of
ethane, propane, butane and pentane allows key fluid performance
aspects relating to recovery of the fracturing fluid to be
maximized, including viscosity, volatility and surface tension. The
added LPG component may comprise 1-99% by volume of the combined
base fluid and LPG component.
[0045] It may be desirous to produce a hydrocarbon fracturing fluid
that has a critical temperature that is above the fluid
temperature, but not so far above the fluid temperature that
subsequent removal from the formation is made difficult. The reason
for this is that, as hydrocarbon liquids and their liquid mixtures
approach the critical temperature, their properties become
increasingly more gas-like and thereby easier to recover from the
formation. These properties must be balanced, as gel degradation
becomes an issue if the fluid temperature is too close to the
critical temperature. This careful balance of the critical
temperature is necessary in order to achieve maximum performance of
the fluid. In some embodiments, the critical temperature of the
hydrocarbon fracturing fluid is within 50 degrees of the fluid
temperature. In further embodiments, the critical temperature of
the hydrocarbon fracturing fluid is within 40 degrees of the fluid
temperature. In other embodiments, the critical temperature of the
hydrocarbon fracturing fluid is within, for example 30, 20, 15, 10,
5 or 1 degrees of the hydrocarbon fracturing fluid.
[0046] In some embodiments, the second critical temperature is
higher than the first critical temperature. An example of this may
occur if the base hydrocarbon fluid is propane, and the LPG
component added to adjust the first critical temperature is butane.
In some embodiments, the second critical temperature is lower than
the first critical temperature, and the first critical temperature
is above the fluid temperature. These situations may arise when the
first critical temperature is far above the fluid temperature, and
a frac operator desires to lower the first critical temperature to
improve the recovery and performance of the hydrocarbon fracturing
fluid. In some embodiments, the base fluid comprises propane and
butane. In these embodiments, the critical temperature adjusting
fluid may be, for example propane and ethane.
[0047] Referring to FIG. 24, a further method of tailoring a
hydrocarbon fracturing fluid for a subterranean formation is
disclosed, fluid in the subterranean formation having a fluid
temperature. In step 122, a first critical temperature of a base
hydrocarbon fluid is adjusted by adding a liquefied petroleum gas
component having a second critical temperature to the base
hydrocarbon fluid to produce the hydrocarbon fracturing fluid. As
before, the base hydrocarbon fluid comprises liquefied petroleum
gas. The first critical temperature may be adjusted to, for example
above the fluid temperature. In some embodiments, it may be
advantageous to adjust the first critical temperature to below, for
example slightly below, the fluid temperature. The base hydrocarbon
fluid may comprise one or more of propane, butane and pentane, and
the liquefied petroleum gas component may comprise one or more of
ethane, propane, butane and pentane.
[0048] The hydrocarbon fracturing fluid produced by the above
methods may comprise at least one gelling agent. The gelling agent
may be any suitable gelling agent for gelling LPG, including
ethane, propane, butane, pentane or mixtures of ethane, propane,
butane and pentane, and may be tailored to suit the actual
composition of the frac fluid. One example of a suitable gelling
agent is created by first reacting phosphorus oxychloride and an
alcohol having hydrocarbon chains of 3-7 carbons long, or in a
further for example alcohols having hydrocarbon chains 4-6 carbons
long. The orthophosphate acid ester formed is then reacted with an
aluminum sulphate activator to create the desired gelling agent.
The gelling agent created will have hydrocarbon chains from 3-7
carbons long or, as in the further example, 4-6 carbons long. The
hydrocarbon chains of the gelling agent may be thus commensurate in
length with the hydrocarbon chains of the liquid petroleum gas used
for the frac fluid. This gelling agent may be more effective at
gelling an ethane, propane or butane fluid than a gelling agent
with longer hydrocarbon chains. The proportion of gelling agent in
the frac fluid may be adjusted to obtain a suitable viscosity in
the gelled frac fluid. As indicated above, the hydrocarbon
fracturing fluid may comprise at least one activator. The gel
chemistry employed in the embodiments of this document may result
in visco-elastic rheology characteristics. In some embodiments, the
hydrocarbon fracturing fluid may further comprise at least one
breaker. Referring to FIG. 17, an exemplary plot of a gel
containing a tailored breaker is illustrated. The breaker employed
in this example has been tailored to begin to begin to break after
30-50 minutes, resulting in a full break at around 65 minutes. The
system may be comprised of the base gel component, an activator and
a breaker. Normal loadings at 8 L/m.sup.3 may result in viscosities
of 300 cP to 400 cP at 100 s.sup.-1. Break times have been achieved
from under 30 minutes to in excess of 4 hours. In some of the other
methods disclosed herein of treating a subterranean formation,
longer break times may be necessary. The broken fluid viscosity is
that of the base LPG fluid (0.05-0.2 cP).
[0049] Referring to FIG. 21, a method of treating a subterranean
formation is disclosed. In step 102, a hydrocarbon fracturing fluid
is introduced into the subterranean formation, the hydrocarbon
fracturing fluid having a critical temperature and comprising LPG.
The critical temperature is above a fluid temperature of the
hydrocarbon fracturing fluid when the hydrocarbon fracturing fluid
is in the subterranean formation. In step 104, the hydrocarbon
fracturing fluid is subjected to pressures above the formation
pressure. In some embodiments, the hydrocarbon fracturing fluid is
subjected to pressures at or above fracturing pressures. The method
may further comprise a step of at least partially removing the
hydrocarbon fracturing fluid from the formation. As described
above, the presence of LPG in the hydrocarbon fracturing fluid
greatly aids this step.
[0050] In some embodiments, the critical temperature of the
hydrocarbon fracturing fluid is within 100 degrees of the fluid
temperature of the hydrocarbon fracturing fluid when the
hydrocarbon fracturing fluid is in the subterranean formation. In
further embodiments, the critical temperature of the hydrocarbon
fracturing fluid is within 50 degrees of the fluid temperature of
the hydrocarbon fracturing fluid when the hydrocarbon fracturing
fluid is in the subterranean formation. In even further
embodiments, the critical temperature of the hydrocarbon fracturing
fluid is within 30 degrees of the fluid temperature of the
hydrocarbon fracturing fluid when the hydrocarbon fracturing fluid
is in the subterranean formation. It should be understood that this
hydrocarbon fracturing fluid may be the same as the hydrocarbon
fracturing fluids disclosed throughout this document. Accordingly,
the critical temperature of the hydrocarbon fracturing fluid may be
at least 1, for example at least 10 degrees higher than the fluid
temperature of the hydrocarbon fracturing fluid when the
hydrocarbon fracturing fluid is in the subterranean formation.
[0051] Referring to FIG. 22, another method of treating a
subterranean formation is disclosed. In step 106, a hydrocarbon
fracturing fluid comprising liquefied petroleum gas is introduced
into the subterranean formation. In step 108, the hydrocarbon
fracturing fluid is subjected to pressures above the formation
pressure. In step 110, the hydrocarbon fracturing fluid is shut-in
in the subterranean formation for a period of at least 1 hour. The
shutting-in period may comprise at least two periods combined, for
example if the period was broken up into two periods due to the
addition of extra hydrocarbon fracturing fluid at the halfway
point. Under conventional fracturing procedures, the hydrocarbon
fracturing fluid may be shut-in, but only for short periods of
time, usually until the fracturing itself has been completed. The
extending of the shutting-in period disclosed herein following the
fracture treatment enhances the subsequent clean-up of the fluid
due to the mixing of the fracturing fluid with the reservoir gas.
Mixing of the fracturing fluid with the reservoir gas results in
vaporization of the fracturing fluid, providing improved fluid
recovery properties from that of the fracturing fluid alone.
Further, allowing this mixing to occur results in improved clean up
capabilities as a result of the lowered properties of viscosity and
density from that of the fracturing fluid alone. The mixing of the
fracturing fluid with the reservoir gas also results in the mixture
having properties that significantly reduces the capillary pressure
of the mixture from that of the fracturing fluid alone. This
further prevents the liquid block situation discussed above, and
improves the resulting production from the formation into the
well.
[0052] In some embodiments, the hydrocarbon fracturing fluid is
shut-in for a period of at least 4 hours. In further embodiments,
the hydrocarbon fracturing fluid is shut-in for a period of at
least 7 hours. In further embodiments, the hydrocarbon fracturing
fluid is shut-in for a period of at least 10 hours. In even further
embodiments, the hydrocarbon fracturing fluid is shut-in for a
period of at least 15 hours. In even further embodiments, the
hydrocarbon fracturing fluid is shut-in for longer periods, for
example a period of at least 24 hours. The extended shut-in time
may be determined in order to maximize the mixing of the
hydrocarbon fracturing fluid with the reservoir gas in the most
efficient manner possible. The hydrocarbon fracturing fluid may
have a critical temperature that is above a fluid temperature of
the hydrocarbon fracturing fluid when the hydrocarbon fracturing
fluid is in the subterranean formation. The hydrocarbon fracturing
fluid may be shut in for a period longer than 4 hours, 12 hours or
24 hours. The method may further comprise producing the hydrocarbon
fracturing fluid along with formation fluids to a sales line.
[0053] Referring to FIG. 23, a method of treating one or more
plural hydrocarbon reservoirs 15 (shown in FIG. 14A-D) penetrated
by a well 16 is illustrated. FIGS. 14A-C illustrate the method
being carried out on plural reservoirs in a vertical well, and in
FIG. 14D, there is shown a horizontal well 16A penetrating multiple
zones 70, 72 and 74 of a single reservoir 18. The description below
refers to treatment of multiple reservoirs penetrated by a single
vertical well, but applies equally to treating multiple portions of
a single reservoir penetrated by a horizontal well. In each case,
zones are treated, the zones corresponding to the portions 70, 72
and 74 penetrated by the horizontal well or the multiple reservoirs
18, 20 or 30 penetrated by the vertical well In the embodiment
illustrated in FIG. 14D, a second hydrocarbon reservoir 20 may also
be treated according to the same methods as an additional zone
76.
[0054] Referring to FIG. 14A, in step 112 (shown in FIG. 23),
hydrocarbon fracturing fluid comprising liquefied petroleum gas is
introduced through the well 16 into a first hydrocarbon reservoir
18 of the one or more hydrocarbon reservoirs 15. In step 114 (shown
in FIG. 23), the hydrocarbon fracturing fluid in the first
hydrocarbon reservoir 18 is then subjected to pressures above the
formation pressure of the first hydrocarbon reservoir 18. Referring
to FIG. 14B, in step 116 (shown in FIG. 23) hydrocarbon fracturing
fluid comprising liquefied petroleum gas is introduced through the
well 16 into a second hydrocarbon reservoir 20 of the plural
hydrocarbon reservoirs 15. In step 118 (shown in FIG. 23), the
hydrocarbon fracturing fluid in the second hydrocarbon reservoir 20
is subjected to pressures above the formation pressure of the
second hydrocarbon reservoir 20. Referring to FIG. 23, in step 120
the hydrocarbon fracturing fluid is at least partially removed from
the first hydrocarbon reservoir 18 and the second hydrocarbon
reservoir 20. It should be understood that step 120 may comprise at
least partially removing the hydrocarbon fracturing fluid from the
first hydrocarbon reservoir 18, and at least partially removing the
hydrocarbon fracturing fluid from the second hydrocarbon reservoir
20. In some embodiments, step 120 may comprise at least partially
removing the hydrocarbon fracturing fluid from the second
hydrocarbon reservoir 20, and at least partially removing the
hydrocarbon fracturing fluid from the first hydrocarbon reservoir
18. Referring to FIG. 14A, the method may further comprise shutting
in the first hydrocarbon reservoir 18 before introducing
hydrocarbon fracturing fluid into the second hydrocarbon reservoir
20. In some embodiments, the second hydrocarbon reservoir 20 may be
shut in prior to the recovery of the hydrocarbon fracturing
fluids.
[0055] Referring to FIGS. 14A-C, an exemplary method of treating
plural hydrocarbon reservoirs 15 is illustrated. Referring to FIG.
14A, at least one packer 22 may be used to implement the method.
Packers 22 and 24 may be oriented within well 16 in order to
isolate at least first reservoir 18. Steps 112 and 114 are then
carried out, introducing hydrocarbon fracturing fluid into
reservoir 18 and pressuring up to fracture. It should be understood
that pressures above the formation pressure include pressures above
the fracturing pressure. After reservoir 18 is fractured, reservoir
18 may be shut-in with packer 22, and optionally packer 24 if
present. In general the first hydrocarbon reservoir 18 may be
shut-in with at least one packer 22. Referring to FIG. 14B, packers
26 and 28 are then positioned around second hydrocarbon reservoir
20 as shown. Steps 116 and 118 are then carried out, introducing
hydrocarbon fracturing fluid into reservoir 20 and pressuring up to
fracture. After reservoir 20 is fractured, reservoir 20 may be
shut-in with at least packer 28, and optionally packer 26 if
present. The shutting in of the first zone may occur before at
least partially removing the hydrocarbon fracturing fluid from the
first zone. Referring to FIG. 14C, at this stage, a third
hydrocarbon reservoir 30 may then be fractured, in a similar
fashion as illustrated for reservoirs 18 and 20. It should be
understood that these methods may be used to fracture more than 3
hydrocarbon reservoirs in a formation penetrated by well 16.
[0056] After all of the desired reservoirs have been fractured,
step 120 may be carried out, at least partially removing the
hydrocarbon fracturing fluid from reservoirs 18, 20, and 30. This
method may be contrasted with conventional methods, which involve
flowing back each reservoir individually before fracturing another
reservoir. This method of sequential fracturing is much more cost
effective and time efficient than conventional methods. In some
embodiments, this method may be used to fracture reservoirs
penetrated by a branched well, for example fracturing reservoirs in
parallel. In other embodiments, reservoir 30 may be fractured,
followed by reservoirs 18 and 20 respectively. By leaving the
hydrocarbon fracturing fluid in the first hydrocarbon reservoir 18
while reservoirs 20 and 30 are being fractured, the fracturing
fluid in reservoir 18 is allowed to mix with formation gas, making
recovery of the fracturing fluid much easier as discussed in more
detail above. In some embodiments, the shutting in of the second
zone occurs before at least partially removing the hydrocarbon
fracturing fluid from the second zone.
[0057] Each of reservoirs 18, 20, and 30 may be shut-in for
extended amounts of time as disclosed in this document for example,
in order to achieve this effect. In some embodiments, the
hydrocarbon fracturing fluid introduced into the first hydrocarbon
reservoir 18 is different from the hydrocarbon fracturing fluid
introduced into the second hydrocarbon reservoir 20. As each
reservoir will have different conditions and temperatures, it may
be desirable to tailor each hydrocarbon fracturing fluid to best
operate in each respective reservoir. It should be understood that
the hydrocarbon fracturing fluid(s) used in this method may be the
same as the hydrocarbon fracturing fluids disclosed throughout this
document. This method is illustrated as being carried out using
packers, but other implements may be used to achieve the same
result. In some embodiments, a single packer may be used, pulling
up the packer to each respective reservoir after fracturing the
previous one. For example, this method of isolating the intervals
may include the use of plugs, with appropriate perforation of the
wellbore to access the reservoir, or alternate mechanical diverting
assemblies within the wellbore. Additionally, the process is
applicable to deviated and horizontal wellbores and may access a
single reservoir at multiple points along that wellbore. In some
embodiments, at least a portion of the well is at least one of
deviated and horizontal, and at least one of the first hydrocarbon
reservoir and the second hydrocarbon reservoir is accessible from
the portion of the well.
[0058] It should be understood that all of the embodiments and
aspects of each of the methods disclosed herein may be combined and
incorporated into one another. It should also be understood that
the hydrocarbon fracturing fluid used at any point in this document
may be the same as the hydrocarbon fracturing fluids disclosed
throughout this document.
[0059] A fluid comprising the hydrocarbon fracturing fluid at least
partially removed from the subterranean formations of any of the
disclosed methods herein is also disclosed. Recovering this
flowback fracturing fluid is advantageous, as it may in many cases
be of suitable quality to pump directly to a sales line. Further,
in the event that the fracturing fluids have been allowed to mix
with the formation gas, the recovered fluid may be even more
valuable. The gas mixture of hydrocarbon fracturing fluid pumped
into a gas bearing formation that mixes with natural gas in the
formation may be recovered (produced) into a typical gas collection
system. In some embodiments, this collection or production may
exclude the recovery of the initial returns to the system without
extending the shut-in. In this embodiment, a line heater may be
employed to allow the recovery of the initial returns. In some
embodiments, the LPG recovery can be to directed to a pipeline or
flare, for example. Initial and immediate LPG recovery, certainly
wellbore fluids, are typically recovered as a liquid, although
later fluids may be predominantly gaseous in nature. The recovery
of the LPG load fluid can be measured accurately with a gas
chromatograph or estimated on dry gas wells using gas density.
Referring to FIG. 18, the separator operating region 32 illustrates
the phase region at which most of the LPG is recovered. To date, in
excess of 90% of the LPG load fluid has been recovered on all
applications.
[0060] Referring to FIG. 14A, also disclosed is a subterranean
formation (illustrated by plural hydrocarbon reservoirs 15 for
example) comprising the hydrocarbon fracturing fluid introduced
into the formation by any of the methods disclosed herein. Because
the formation, in this instance, contains salable product (the
hydrocarbon fracturing fluid and the formation gas), the formation
itself is quite valuable.
[0061] Referring to FIGS. 5-12, an exemplary process of fracturing
with LPG hydrocarbon fracturing fluid is illustrated. In the
following example, darkened lines in the drawings refer to lines
through which fluid is flowing. Referring to FIG. 5, an exemplary
set-up includes a treatment control van 34, an N.sub.2 storage
truck 36, an LPG trailer 38, a chemical control unit 40, a sand
truck 42, an LPG process blender 44, and LPG fracturing pumps 46A,
46B.
[0062] Treatment control van 34 provides centralized remote
operating and monitoring of the equipment of the fracturing system.
Van 34 may be provided with a Geo-Sat communication system, which
allows for real time internet based monitoring and VOIP phone lines
to communicate with systems operators. It also provides continuous
environmental monitoring of 4 wireless remote LEL sensors, and wind
direction and speed for example. Van 34 may perform all of the
required calculations, such as the optimum blend of LPG components
to add to tailor the hydrocarbon fracturing fluid to best fracture
the formation, as well as the optimum job program for fracturing
multiple reservoirs, for example. Calculations and adjustments may
be made on the fly, as needed.
[0063] The N.sub.2 storage truck may comprise a flameless N.sub.2
pumper, which is incorporated into the process to supply boost
pressure to move the LPG product through the process, and to purge
all equipment to a safe environment prior to and after the
stimulation. In some embodiments, no centrifugal pumps are may be
used in this process. The LPG fracturing process blender may be a
closed, pressurized system that uses integrated Process Logic
Control (PLC) to precisely control the addition of proppant to a
stream of Liquid LPG. Blender 44 may be operated and monitored from
the treatment control and command center (illustrated as treatment
control van 34 for example). Blender 44 may be provided with two 16
tonne proppant vessels 48A, B, from which proppant may be metered
by two automated density controlled augers. Monitoring of blender
44 includes monitoring of clean and slurry flow rate, Radioactive
Densitometer, Inline Process Viscometer, 4 Point load cell,
Pressure Transducers, and Closed Circuit cameras. The densitometer
may determine the proppant concentration being added, while the
viscometer determines the extent of gelling.
[0064] Chemical control unit 40 comprises an integrated and
automated chemical addition system, that may be operated by remote
or local operation. Control unit 40 may comprise six 4 stage
progressive cavity pumps monitored with mass flow meters, in order
to ensure the proper and precise addition of chemicals into blender
44. Such chemicals include, for example gelling agents, breakers,
activators, and tailoring LPG components, for example. Unit 40 may
further comprise an LEL monitoring and alarm system for safety
purposes. Unit 40 may be climate controlled with a high rate air
exchanger to ensure a safe working environment, and may further
comprise a drip proof containment system to protect a user and the
environment from chemicals.
[0065] The system may also comprise an Iron truck (not shown). The
iron truck may operate, for example, 100 m of 76.2 mm (3 inch)
103.4 MPa Treating Iron. Also, the iron truck may comprise
hydraulically operated PLC controlled Plug Valves, operated from
treatment control van 34 for example. Iron truck may further have
an integrated equipment emergency shut down system, and a hydraulic
accumulator system.
[0066] LPG Fracturing pumps 46A, B, are designed for increased
operating range and redundancy. Pumps 46A, B, may comprise OEM
rated 2,500 hhp Caterpillar motors, and may be designed to meet
2006 EPA Tier 2 Non-Road Emissions standards. Pumps 46A, B, may
also comprise 7 speed Caterpillar Transmissions, Quint-plex pumps,
and automatic over-speed emergency shut-down systems. LPG pumps
46A, B may be operated digitally from the Treatment Control and
Command Centre (illustrated as treatment control van 34 for
example). Operating features may include: One man operator control
of all pumps from one integrated operating screen, automatic
pressure testing modes, and automatically adjustments of individual
pump rates based on the total required rate and maximum
pressure.
[0067] Proppant is first loaded from a supply truck (illustrated as
sand truck 42) into the two proppant vessels 48A, 48B of the LPG
process blender 44 from a proppant line 50. Referring to FIG. 6,
air is then displaced out of the LPG process blender 44 proppant
blender vessels 48A, B using pressurized N.sub.2 gas supplied from
N.sub.2 storage truck 36. The LPG trailer 38 is also pressure
balanced with the blender 44 using N.sub.2 gas. In some
embodiments, plural LPG sources are supplied, for example in the
form of two or more LPG trailers 38. Each source may carry
different LPG components, for example, in order to tailor the final
mixture of LPG fracturing fluid. All lines are pressure tested with
N.sub.2, then with LPG, including lines 52,54 that lead to wellhead
56, sand separation tank 58, and flare stack 60, however, wellhead
56 is not pressurized at this point. Referring to FIG. 7, the LPG
pressure is then bled off to flare stack 60, to complete the
pressure test. Valve 62 is thus opened to open wellhead 56, and the
treatment commences, with hydrocarbon fracturing fluid being
provided to wellhead 56. Referring to FIG. 13, this point may
correspond to time=5 minutes on the graph. At this stage, the LPG
being pumped into the well may be ungelled, and the clean rate
equals the slurry rate. At this stage, steps 102 and 104 of the
method illustrated in FIG. 21 are being carried out, if the
hydrocarbon fracturing fluid has a critical temperature that is
above a fluid temperature of the hydrocarbon fracturing fluid when
the hydrocarbon fracturing fluid is in the subterranean formation.
The bottom hole pressure (Meas'd btmh) is only slightly higher than
the treating pressure, due at least partially to the hydrostatic
head and the formation pressure. Referring to FIG. 1, the phase of
the LPG fluid, if propane, follows path A at this stage, as it is
passes through blender 44 and through the HP pumps 46A, B, to the
wellhead 56. Referring to FIG. 8, wellhead 56 is then filled with
gelled LPG fluid. Valve 64 is closed, preventing any flow to flare
stack 60. At this stage, chemical control van 34 is supplying
gelling agents and other fracturing chemicals into LPG process
blender 44. In addition, LPG trailer 38 is supplying LPG to blender
44, and N.sub.2 storage truck 36 continues to provide pressure
balancing between LPG trailer 38 and blender 44. Blender 44 blends
and mixes the hydrocarbon fracturing fluid, while LPG fracturing
pumps 46A, B are operating to pump the fracturing fluid mix into
wellhead 56. Chemical control van 34 may provide a tailored amount
of gelling agents, as well as any additional LPG components
required to tailor the fracturing fluid to the subterranean
formation being fractured. In some embodiments, the additional LPG
components may be provided by separate LPG trailers 38 (not shown).
As the fracturing continues, the formation is broken down, and a
feed rate is established. Referring to FIG. 13, this may correspond
to time=14 minutes, where gelled and proppant loaded fracturing
fluid is being pumped into the well. Blender concentration
indicates the concentration of proppant in the frac fluid. Slurry
rate refers to overall rate of fluid entering the wellhead 56.
Referring to FIG. 8, a pad of frac fluid may be pumped down as per
the job program selected, as is illustrated in FIG. 13 from time=0
minutes to time=12 minutes. Proppant is added to the gelled LPG as
per the selected job program, through vessels 48A,B. N.sub.2 gas
replaces the surface volume of the displaced proppant and LPG in
vessels 48A,B and LPG trailer 38, respectively. The proppant is
under flushed to the perforations created downhole using the LPG
fluid. Referring to FIG. 1, the phase of the LPG fluid, if propane,
follows path B as it passes from the wellhead 56, through the
tubular, and into the fractures. As the LPG enters the fracture and
leaks-off to the reservoir conditions, the LPG fluid follows path
C.
[0068] Referring to FIG. 9, upon completion of the treatment, the
wellhead 56 is closed. The supply from LPG trailer 38, proppant
supply vessels 48A,B, and chemical control van 40 are each closed
and isolated, for safety precautions. At this stage, wellhead 56
may be shut-in for an appropriate amount of time, as in the methods
disclosed herein, for example an extended amount of time. Step 110
of the method illustrated in FIG. 22 may be carried out at this
stage. Referring to FIG. 13, this may correspond to time=38
minutes, for example. Referring to FIG. 1, the phase of the LPG
fluid, if propane, follows path D as it flows back from the
reservoir to the surface, becoming more gas-like in the process.
Referring to FIG. 9, upon completion of the shut-in period, if any,
all high-pressure lines containing LPG frac fluid may be
de-pressurized to flare stack 60. Referring to FIG. 10, all
LPG-filled lines are then purged with N.sub.2 to flare stack 60.
Referring to FIG. 11, LPG Process blender 44 is then purged with
N.sub.2 to the flare stack 60 via line 66. All of the LPG
fracturing process equipment is then rigged out. Referring to FIG.
12, given that a flow line 68 is available on location, the
wellhead 56 can be produced back to the production facilities
saving the cost of testing equipment, and resulting in no damage,
limited cleanup, and no disposal.
[0069] It should be understood that the systems disclosed above may
be used to carry out the methods illustrated and described for FIG.
23. The job program required for this would be delegated from
treatment control van 34, and would involve manipulation of the
same system to achieve the goals of the method.
[0070] The LPG fracturing processes disclosed herein should be
implemented with design considerations to mitigate and eliminate
the potential risks, such as by compliance with the Enform
Document: Pumping of Flammable Fluids Industry Recommended Practice
(IRP), Volume 8-2002, and NFPA 58 "Liquefied Petroleum Gas
Code".
[0071] These methods may be used on sub-normally saturated and
under-pressured reservoirs, including gas, oil and water wells, to
eliminate altered saturations and relative permeability effects,
accelerate clean-up, realize full frac length, and improve
long-term production. Further, these methods may be used on
reservoirs that exhibit high capillary pressures with conventional
fluids to eliminate phase trapping. These methods may also be used
on low permeability reservoirs, which normally require long
effective frac lengths to sustain economic production, to
accelerate clean-up, realize full frac length quicker, and improve
production. These methods may also be used on recompletions with
recovery through existing facilities, in order to recover all LPG
fluid to sales gas--thus reducing clean-up costs, avoiding
conventional fluid recovery and handling costs, and eliminating
flaring. Multiple frac treatments may be completed without the need
for immediate frac clean-up between treatments, as the extended
shut-in simplifies and speeds the clean-up without detriment to
formation. These methods may also be used in exploration, as the
pumping of a completely reservoir compatible fluid provides
excellent stimulation plus rapid cleanup and evaluation, which
gives a fast turnaround and zero-damage evaluation in potentially
unknown reservoir and reservoir fluid characteristics.
[0072] FIGS. 19A and B illustrate examples of successful fracturing
procedures carried out using the methods as disclosed herein.
Various specifications of each job are indicated in those
figures.
[0073] Hydraulic fracturing with LPG has been done in the past, but
has since been deemed too dangerous by others, and as a result,
most development in this area has slowed or stopped. However, by
combining safety techniques, LPG fracturing can be made safe. LPG
Processes disclosed herein require no load fluids, CO.sub.2 or
N.sub.2 during initial production which is less taxing on the
production equipment, which results in reduced well clean-up time,
although in specific instances, there may be additional fluids
pumped with the LPG fluids.
[0074] Tailoring of the LPG component mix also enhances recovery in
under-pressured reservoirs via the combination of low hydrostatic,
mixing with native reservoir hydrocarbons, low viscosity and
minimized surface tension/capillary pressure. Under-pressured
refers to the formation pressure being lower than the hydrostatic
pressure at the formation depth. The density of a hydrocarbon
fracturing fluid comprising LPG may be adjusted by selection of LPG
components to produce a hydrocarbon fracturing fluid, the density
of which makes the static pressure of the hydrocarbon fracturing
fluid at the formation depth less than the formation pressure. All
frac fluid components may be recovered directly to the sales or
pipeline with no flaring or collection of liquids at surface by
making the hydrostatic pressure of the fracturing fluid in the
formation being treated low enough for the well to have a flowing
pressure that permits clean-up, and composition suitable for the
pipeline (no CO2, N2, methanol or water). Referring to FIG. 25, a
method is disclosed of treating an under-pressured subterranean
formation having a formation pressure and containing formation
fluids. In step 124, a hydrocarbon fracturing fluid comprising
liquefied petroleum gas is prepared, the hydrocarbon fracturing
fluid having a density such that the static pressure of the
hydrocarbon fracturing fluid at the under-pressured subterranean
formation is less than the formation pressure. In some embodiments
the hydrocarbon fracturing fluid is prepared. In step 126, the
hydrocarbon fracturing fluid is introduced into the under-pressured
subterranean formation. In step 128, the hydrocarbon fracturing
fluid is subjected to pressures above the formation pressure. In
step 130, the hydrocarbon fracturing fluid is recovered along with
formation fluids. In some embodiments, the hydrocarbon fracturing
fluid has a critical temperature that is above a fluid temperature
of the hydrocarbon fracturing fluid when the hydrocarbon fracturing
fluid is in the subterranean formation. In some embodiments, the
hydrocarbon fracturing fluid is subjected to pressures at or above
fracturing pressures. In some embodiments, the recovered fluids are
directed to a sales line.
[0075] In any of the disclosed embodiments of the methods described
here, when the fluid in the subterranean formation comprises
formation gas such as methane, the formation gas mixes with the
hydrocarbon fracturing fluid to alter the critical temperature of
the hydrocarbon fracturing fluid in the subterranean formation.
When the critical temperature is lowered as for example in the case
of mixing with methane, the resulting transition of the hydrocarbon
fracturing fluid to a more gaseous state assists in expelling the
hydrocarbon fracturing fluid from the subterranean formation and
the well.
[0076] In particular in the case of an under-pressured gas
reservoir, the LPG mixes with the reservoir gas, resulting in
vaporization and subsequent reduction in density much beyond the
originally low hydrostatic provided by the LPG fluid by itself.
This benefit is important when treating under-pressured reservoirs.
Thus, FIG. 2 shows the mixture properties of propane with methane.
The particular lines shown are the vapor-lines, that being the
pressure temperature relationship below which the mixture exists as
100% vapors. The end point of each curve is the critical
temperature of the mixture. The mixing desirably results in a
frac-fluid/reservoir composition where the critical temperature is
below the reservoir temperature. This mixing is intended to occur
within the formation following the fracturing treatment, during
shut-in and subsequent clean-up. Hence, the LPG mix is designed to
promote mixing with reservoir gas to achieve vaporization as
another primary mechanism for developing a suitable hydrostatic for
ready clean-up. The hydrostatic is important as it sets the surface
flowing pressure of the well during clean-up. If the surface flow
pressure is too low, then the well may not have sufficient pressure
to clean-up into the pipeline. This pipeline pressure may range
from under 20 psi to over 1,000 psi and the well flow condition
must exceed this pressure in order to enter it.
[0077] In the claims, the word "comprising" is used in its
inclusive sense and does not exclude other elements being present.
The indefinite article "a" before a claim feature does not exclude
more than one of the feature being present. Each one of the
individual features described here may be used in one or more
embodiments and is not, by virtue only of being described here, to
be construed as essential to all embodiments as defined by the
claims.
* * * * *