U.S. patent application number 11/731388 was filed with the patent office on 2008-09-04 for method of removing filter cake.
This patent application is currently assigned to BJ Services Company. Invention is credited to Brian B. Beall, Paul H. Javora, Leonard J. Kalfayan, Qi Qu.
Application Number | 20080210428 11/731388 |
Document ID | / |
Family ID | 39732293 |
Filed Date | 2008-09-04 |
United States Patent
Application |
20080210428 |
Kind Code |
A1 |
Javora; Paul H. ; et
al. |
September 4, 2008 |
Method of removing filter cake
Abstract
A filter cake deposited by a drilling fluid, drill-in fluid or
fluid loss control pill may be removed from a wellbore by
introducing into the wellbore a dispersing agent of an organic
amino phosphonic acid, ester or salt. The dispersing agent forms a
dispersion containing at least a portion of the drilled solids. The
dispersing agent may be introduced into the wellbore as a component
of a filter cake removal treatment fluid or either prior to or
after introduction of the filter cake removal treatment fluid.
Inventors: |
Javora; Paul H.; (Spring,
TX) ; Qu; Qi; (Spring, TX) ; Beall; Brian
B.; (Spring, TX) ; Kalfayan; Leonard J.;
(Houston, TX) |
Correspondence
Address: |
JONES & SMITH , LLP
2777 ALLEN PARKWAY, SUITE 800
HOUSTON
TX
77019
US
|
Assignee: |
BJ Services Company
|
Family ID: |
39732293 |
Appl. No.: |
11/731388 |
Filed: |
March 30, 2007 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
60904317 |
Mar 1, 2007 |
|
|
|
Current U.S.
Class: |
166/312 |
Current CPC
Class: |
C09K 8/52 20130101 |
Class at
Publication: |
166/312 |
International
Class: |
E21B 37/06 20060101
E21B037/06 |
Claims
1. In a method of removing a filter cake containing drilled and
deposited solids from a wellbore by introducing into the wellbore a
treatment fluid capable of degrading the filter cake, the
improvement comprising further introducing into the wellbore and/or
treatment fluid a dispersing agent and digesting at least a portion
of the filter cake with the treatment fluid and dispersing agent
and further forming a dispersion containing at least a portion of
the drilled and/or deposited solids, the dispersing agent being an
organic amino phosphonic acid, ester or salt thereof.
2. The method of claim 1, wherein the dispersing agent is an
aminoalkyl phosphonic acid, ester or salt thereof.
3. The method of claim 2, wherein the dispersing agent is a
polyaminomethylene phosphonate having from 2 to about 10 nitrogen
atoms.
4. The method of claim 3, wherein the dispersing agent is selected
from the group consisting of ethylenediamine tetra(methylene
phosphonate), diethylenetriamine penta(methylene phosphonate) and
triamine- and tetraamine- polymethylene phosphonates having between
from about 2 to about 8 methylene groups between each N atom.
5. The method of claim 3, wherein the dispersing agent is either
bis-aminoalkyl ether phosphonate or a mixture of a monoalkanol
amine phosphonate and a bis-hexalkylene triamine phosphonate.
6. The method of claim 1, wherein the dispersing agent is a
polyphosphonic acid, ester or salt of the formula: ##STR00002##
wherein: each Z is independently --CHR.sup.1PO.sub.3(R)(R) or H,
provided that at least two Zs are --CHR.sup.1PO.sub.3(R)(R); each
R.sup.1 is independently selected from --H, --CH.sub.3,
--C(R.sup.2)(R.sup.2)(R.sup.2), C.sub.6H.sub.5.
--C(R.sup.2)(R.sup.2)-, --SO.sub.3H.sub.2 and --SO.sub.3M.sub.2;
each R.sup.2 is independently selected from --H, --CH.sub.3 and
--C.sub.2H.sub.5; each R is independently selected from --H,
--CH.sub.3, --C.sub.2H.sub.5 and M; each M is independently
selected from an alkali metal, 1/2 of an alkaline earth metal, 1/n
of a transition metal with +n charge, an ammonium ion and hydrogen
ion; n is between from about 1 to about 6, preferably from about 2
to about 4; m is between from about 1 to about 6, preferably from
about 2 to about 4; a is between from about 1 to about 10,
preferably from about 2 to about 4; b is between from about 1 to
about 10, preferably from about 2 to about 4; x is between from 0
to about 6, preferably from 0 to about 3; and y is between from 0
to about 6, preferably from 0 to about 2.
7. The method of claim 1, wherein the agent is bis-aminoethyl ether
phosphonate or a mixture of bis-hexamethylene triamine phosphonate
and monoethanol amine phosphonate and, optionally,
bis-hexamethylene triamine pentaphosphonate.
8. The method of claim 1, wherein the dispersing agent is a
component of the treatment fluid.
9. A method of removing a filter cake containing drilled and
deposited solids from a wellbore comprising: (a) introducing into
the wellbore a treatment fluid comprising a dispersing agent of an
organic amino phosphonic acid, ester or salt thereof; (b) digesting
at least a portion of the filter cake with the treatment fluid; (c)
forming a dispersion of drilled and deposited solids wherein at
least a portion of the drilled and deposited solids separate from
the filter cake; and (d) removing the dispersion containing the
separated drilled and deposited solids and at least a portion of
the filter cake from the wellbore.
10. The method of claim 9, wherein the dispersing agent is selected
from the group consisting of a bis-aminoalkyl ether phosphonate;
and a mixture of a monoalkanol amine phosphonate and a
bis-hexalkylene triamine phosphonate;
11. The method of claim 10, wherein the dispersing agent is
bis-aminoethyl ether phosphonate or a mixture of monoethanol amine
phosphonate and bis-hexamethylene triamine phosphonate and,
optionally, bis-hexamethylene triamine pentaphosphonate.
12. The method of claim 11, wherein the dispersing agent is
bis-aminoethyl ether phosphonate.
13. The method of claim 11, wherein the dispersing agent is a
mixture of bis-hexamethylene triamine phosphonate and monoethanol
amine phosphonate and, optionally, bis-hexamethylene triamine
pentaphosphonate.
14. A method of increasing the flow of production fluids from or
injection fluids into a subterranean formation by removing a filter
cake having fine particulates from the wellbore, the method
comprising: (a) introducing into the wellbore a treatment fluid and
a dispersing agent, wherein the dispersing agent is introduced into
the wellbore either before or after introduction of the treatment
fluid or as a component of the treatment fluid; (b) digesting or
degrading at least a portion of the filter cake with the treatment
fluid and dispersing agent; and (c) forming a dispersion of fine
particulates and dispersing agent; and (d) removing the dispersion
and at least a portion of the filter cake from the wellbore wherein
the dispersing agent is an organic amino phosphonic acid, ester or
salt thereof.
15. The method of claim 14, wherein the dispersing agent is
selected from the group consisting of a bis-aminoalkyl ether
phosphonate; and a mixture of a monoalkanol amine phosphonate and a
bis-hexalkylene triamine phosphonate;
16. The method of claim 15, wherein the dispersing agent is
bis-aminoethyl ether phosphonate or a mixture of monoethanol amine
phosphonate and bis-hexamethylene triamine phosphonate and,
optionally, bis-hexamethylene triamine pentaphosphonate.
17. The method of claim 15, wherein the dispersing agent is
bis-aminoethyl ether phosphonate.
18. The method of claim 15, wherein the dispersing agent is a
mixture of bis-hexamethylene triamine phosphonate and monoethanol
amine phosphonate and, optionally, bis-hexamethylene triamine
pentaphosphonate.
19. A method of removing a filter cake containing drilled and
deposited solids from a wellbore comprising: (a) introducing into
the wellbore a filter cake removal treatment fluid and a dispersing
agent selected from the group consisting of organic amino
phosphonic acids, esters and salts thereof; (b) contacting the
filter cake with the dispersing agent, digesting a portion of the
filter cake and forming a dispersion containing separated drilled
and deposited solids and dispersing agent; (c) removing the
resulting dispersion away from the vicinity of the filter cake; and
(d) further digesting the filter cake with the filter cake removal
treatment fluid and removing the filter cake from the wellbore.
20. The method of claim 19, wherein the dispersing agent is
introduced into the wellbore as a component of the filter cake
removal treatment fluid.
21. The method of claim 19, wherein the dispersing agent is
introduced into the wellbore either prior to or after introduction
of the filter cake removal treatment fluid.
22. The method of claim 19, wherein the filter cake removal
treatment fluid contains a member selected from the group
consisting of enzymes, acids and oxidizers.
23. A method of removing a filter cake containing drilled and
deposited solids from a wellbore by: (a) digesting at least a
portion of the filter cake and forming a dispersion containing
separated drilled and deposited solids by introducing into the
wellbore a filter cake removal treatment fluid and a dispersing
agent; (c) removing the dispersion formed in step (a) away from the
vicinity of the filter cake; and (d) removing the filter cake from
the wellbore wherein the dispersing agent is an organic amino
phosphonic acid, ester or salt thereof.
24. The method of claim 23, wherein the dispersing agent is
introduced into the wellbore at the same time as introduction of
the filter cake removal treatment fluid.
25. The method of claim 23, wherein the dispersing agent is
introduced into the wellbore either before or after introduction of
the filter cake removal treatment fluid.
26. The method of claim 23, wherein the filter cake removal
treatment fluid contains a member selected from the group
consisting of enzymes, acids and oxidizers.
27. A method of removing a filter cake containing drilled and
deposited solids from a wellbore by digesting the filter cake and
removing the drilled and deposited solids from the wellbore, the
method consisting essentially of introducing into the wellbore a
filter cake removal treatment fluid and a dispersing agent, forming
a dispersion of the separated drilled and deposited solids and
dispersing agent and then removing the dispersion and the filter
cake from the wellbore, wherein the dispersing agent is an organic
amino phosphonic acid, ester or salt thereof.
Description
[0001] This application claims the benefit of U.S. patent
application Ser. No. 60/904,317, filed on Mar. 1, 2007.
FIELD OF THE INVENTION
[0002] The invention relates to a method of removing the filter
cake deposited by a drilling fluid, drill-in fluid, fluid loss
control pill or other filter-cake producing wellbore activities by
use of a dispersant.
BACKGROUND OF THE INVENTION
[0003] In a typical drilling operation, a drill bit, located on the
lower end of a drill pipe, penetrates the formation and creates a
wellbore. A drilling fluid, or drilling mud, is circulated down the
drill pipe, exits the drill bit and flows back to the surface
through an annulus between the drill pipe and the wall of the
wellbore. In addition to cooling the drill bit, the drilling fluid
further serves to flush out rock particles that are sheared off by
the drill bit during operation.
[0004] A drill-in fluid or drill-in mud, is a specific type of
drilling fluid, which is pumped through the drill pipe while
drilling through the producing, or payzone, area or the injection
zone of the formation. The amount of drilled solids which
contaminate the drilling fluid increases as the fluid continues to
drill into the payzone or injection zone.
[0005] The optimum drill-in fluid provides constant lubricity under
high shear conditions generated by the rotating drill bit and is
sufficiently viscous to prevent fluid loss into the formation while
at the time suspending solids and floating up debris from the
wellbore.
[0006] Drill-in fluids are principally composed of a high density
base-brine, such as sodium chloride, sodium bromide, calcium
chloride, calcium bromide, zinc bromide, sodium formate, potassium
formate, cesium formate or a mixture thereof. Drill-in fluids can
also be oil or synthetic oil based.
[0007] In addition, drill-in fluids typically contain additives to
impart desired physical and/or chemical characteristics to the
fluid. For instance, the drill-in fluid typically contains a
viscosifying agent to thicken the base fluid. This, in turn,
increases the ability of the fluid to suspend or flush out the rock
particles.
[0008] Drill-in fluids further typically contain other types of
rheological additives, fluid loss control additives and weighting
agents (either dissolved or suspended solids). In addition to
viscosifying agents, drill-in fluids may include clay materials and
lubricants to lubricate the drill bit. Such additives further serve
to suspend solids and help "float" cutting debris out of the
wellbore.
[0009] The drill-in fluid may further contain fluid loss control
additives which include bridging agents and/or sized particles to
prevent loss of the fluid to the neighboring formation. When used,
fluid loss control agents further provide the fluid with sufficient
viscosity to inhibit seepage of the fluid into the subterranean
strata.
[0010] The drill-in fluid serves further to deposit a low-permeable
filter cake on the walls of the wellbore to seal the permeable
formation exposed by the drilling bit. The filter cake further
limits the loss of fluid from the wellbore during cementing
operations. In addition, it can protect the formation from possible
damage by fluids which are capable of permeating into the
formation.
[0011] Since many drill-in fluids used today are brine-based, often
with liquid densities greater than 12 pounds per gallon (ppg), the
finely dispersed solids within the drilling fluid are virtually
impossible to remove mechanically and economically. As a result,
drill-in fluids normally used in the field today carry elevated
concentrations of finely divided drilled solids. Such solids are
incorporated into the deposited filter cake.
[0012] Conventional drilling fluids perform similar functions as
drill-in fluids but typically contain significantly more solids,
including drilled solids, weighting solids and bridging solids,
than drill-in fluids. At times, these fluids are also used to drill
payzones or injection zones and also deposit solids laden filter
cakes.
[0013] During normal wellbore operations, especially during the
completion operations, fluid loss control pills are sometimes
pumped into the wellbore to aid in the control of fluid lost to the
formation. These pills often contain bridging agents to augment
fluid loss control. A filter cake is typically deposited directly
against the formation and may become embedded in the formation.
[0014] In order to produce the hydrocarbons from the wellbore or
inject into the wellbore, the deposited filter cake must be
removed. Complete removal of the filter cake is necessary for
maximum hydrocarbon production or injection rates. In a typical
well completion process, the deposited filter cake is removed by
chemical treatments. Such chemicals attack the viscosifying and/or
fluid loss control polymer or agent and dissolvable materials
formulated into the drilling fluid, drill-in fluid or fluid loss
control pill.
[0015] Removal of the deposited filter cake is relatively easy when
the fluid or pill is freshly prepared. Newly prepared fluids or
pills do not contain any significant amount of drilled clay or
solids. Unfortunately, such chemical treatments have little or no
effect in the removal of drilled clays and solids. As the treatment
chemicals digest and remove the viscosifying or fluid loss control
agents and soluble materials, the drilled clays and solids
concentrate at the interface of the filter cake. As fluid is
increasingly lost to the formation due to digestion and removal of
the viscosifying or fluid loss control agent, the exposed drilled
and other solids are pushed into and concentrate in the remaining
filter cake, thereby hindering or blocking further removal of the
filter cake.
[0016] A substantial need exists for a treatment chemical that can
assist in maximizing the removal of drilled and other solids,
thereby maximizing the removal of the deposited filter cake.
SUMMARY OF THE INVENTION
[0017] A method of removing a filter cake deposited from drilling
fluid, drill-in fluid and/or fluid loss pill containing drilled
and/or deposited solids from a wellbore includes the use of a
dispersing agent of an organic amino phosphonic acid, ester or salt
thereof which forms a dispersion containing at least a portion of
the drilled and/or deposited solids.
[0018] The dispersing agent may be introduced into the wellbore as
a component of the filter cake removal treatment fluid or either
prior to or after introduction of the filter cake removal treatment
fluid. After introduction into the wellbore, the dispersing agent
contacts the filter cake. At least a portion of the drilled or
deposited solids is removed from the filter cake into the
dispersion. Contacting of the fluid containing the dispersing agent
with the filter cake typically results in soaking of the filter
cake. As a result of contacting, digestion or degradation of at
least a portion of the filter cake occurs. Thus, the dispersion
containing the dispersing agent and solids may further contain at
least a portion of digested filter cake. Thus, the dispersion
containing the dispersing agent assists in removal of the filter
cake from the wall.
[0019] When introduced prior to the filter cake removal treatment
fluid, the dispersing agent acts as a filter cake pre-soaking
agent, though preferably the dispersing agent is a component of the
filter cake removal treatment fluid.
[0020] The treatment fluid may include enzymes, acids, oxidizers,
etc. which are effective in the removal and/or degradation of
filter cakes.
[0021] The dispersing agent is an aminoalkyl phosphonic acid, ester
or salt thereof. Preferably, the dispersing agent is a
polyaminomethylene phosphonate having from 2 to about 10 nitrogen
atoms, at least one methylene phosphonic group being attached to at
least one nitrogen atom. In a preferred embodiment, at least one
methylene phosphonic group of the phosphonate is attached to each
nitrogen atom. Suitable species include ethylenediamine
tetra(methylene phosphonate), diethylenetriamine penta(methylene
phosphonate) and triamine- and tetraamine-polymethylene
phosphonates having between from about 2 to about 10, preferably
between from about 2 to about 6, methylene groups between each N
atom. In a preferred embodiment, the dispersing agent is either
bis-aminoethyl ether phosphonate or a mixture of monoethanol amine
phosphonate and bis-hexamethylene triamine phosphonate and/or
bis-hexamethylene triamine pentaphosphonate.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0022] A filter cake deposited from drilling fluid, drill-in fluid
and/or fluid loss pill may be more effectively removed from a
subterranean formation surrounding a wellbore by use of an organic
amino phosphonic acid, ester or salt thereof. The organic amino
phosphonic acid, ester or salt acts as a dispersing agent and
assists in the digestion of the filter cake. In light of its
presence, drilled or deposited solids are dispersed within the
dispersion and moved away from the vicinity of the filter cake. The
filter cake removal fluid can therefore more efficiently digest the
filter cake with less hindrance from the solids.
[0023] While at least some of the drilled or deposited solids are
removed by the action of the dispersing agent, in some cases all of
the solids are removed. Further, the dispersing agent is typically
capable of degrading at least a portion of the filter cake. In some
cases, the filter cake is completely degraded by the action of the
dispersing agent.
[0024] The dispersing agent, which serves to disperse the solid
particles, is an organic amino phosphonic acid, ester or salt. The
dispersing agent may further function as a pH adjusting agent.
Suitable dispersing agents include aminoalkyl phosphonic acids,
ester or salts, like polyaminomethylene phosphonates having between
from about 2 to about 10 nitrogen atoms. In a preferred embodiment,
at least each nitrogen of the compound contains at least one
methylene phosphonic group. Examples of suitable aminoalkyl
phosphonic acids, esters and salts include ethylenediamine
tetra(methylene phosphonate), diethylenetriamine penta(methylene
phosphonate) and the triamine- and tetramine-polymethylene
phosphonates with from about two to about ten, preferably from
about 2 to about 6, methylene groups between each nitrogen atom. In
a preferred embodiment, the dispersing agent is either
bis-aminoalkyl ether phosphonate or a mixture of a monoalkanol
amine phosphonate and a bis-hexalkylene triamine phosphonate.
[0025] Further, the dispersing agent may be a linear or branched
polyphosphonic acid, ester or salt. Exemplary of such linear or
branched polyphosphonic acids, esters, or salts are those of the
formula:
##STR00001##
wherein:
[0026] each Z is independently --CHR.sup.1PO.sub.3(R)(R) or H,
provided that at least two Zs are --CHR.sup.1PO.sub.3(R)(R);
[0027] each R.sup.1 is independently selected from --H, --CH.sub.3,
--C(R.sup.2)(R.sup.2)(R.sup.2), C.sub.6H.sub.5,
--C(R.sup.2)(R.sup.2)--, --SO.sub.3H.sub.2 and
--SO.sub.3M.sub.2;
[0028] each R.sup.2 is independently selected from --H, --CH.sub.3
and --C.sub.2H.sub.5;
[0029] each R is independently selected from --H, --CH.sub.3,
--C.sub.2H.sub.5 and M;
[0030] each M is independently selected from an alkali metal, 1/2
of an alkaline earth metal, 1/n of a transition metal with +n
charge, an ammonium ion and hydrogen ion;
[0031] n is between from about 1 to about 6, preferably from about
2 to about 4;
[0032] m is between from about 1 to about 6, preferably from about
2 to about 4;
[0033] a is between from about 1 to about 10, preferably from about
2 to about 4;
[0034] b is between from about 1 to about 10, preferably from about
2 to about 4;
[0035] x is between from 0 to about 6, preferably from 0 to about
3; and
[0036] y is between from 0 to about 6, preferably from 0 to about
2.
Such compounds are disclosed in U.S. Pat. No. 5,261,491.
[0037] Typically, the dispersing agent is added to the filter cake
removal treatment fluid and such fluid is then introduced into the
wellbore. Other than being a component of the filter cake removal
treatment fluid, it is possible that the dispersing agent may be
added to the wellbore either prior to introduction of the filter
cake removal treatment fluid, subsequent to introduction of the
filter cake removal treatment fluid or simultaneously with the
introduction of the filter cake removal treatment fluid.
[0038] When introduced as a component of the filter cake removal
treatment fluid, the amount of dispersing agent present in the
fluid is an amount sufficient to maintain the dispersed drilled
solids in dispersion. Typically the amount of dispersing agent to
the fluid is between from about 0.1 to about 25 volume percent
(based on the total volume of the composition). In some uses, the
dispersant may be used up to full strength.
[0039] Typical drilling fluids, drill-in fluids and fluid loss
pills include those basically comprised of water, a viscosifying
agent, a particulate solid bridging agent, and when needed, a
weighting agent. Viscosifying agents are typically water-soluble
starches (such as corn based or potato based starches), water
soluble polysaccharides (such as xanthan polysaccharides, wellan
polysaccharides, scleroglucan polysaccharides, and guar
polysaccharides), water soluble celluloses (such as hydroxyalkyl
celluloses, like hydroxyethyl cellulose, as well as hydrophobically
modified hydroxyalkyl celluloses and cellulose ethers), water
soluble polyacrylamides and copolymers thereof (such as copolymers
of acrylamide with acrylate monomers), modified starches, modified
polysaccharides and chemically modified polysaccharides (such as
hydroxyalkyl starches and polysaccharides; starch and
polysaccharide esters, crosslinked starches and polysaccharides;
hypochlorite oxidized starches and polysaccharides; starch and
polysaccharide phosphate monoesters; cationic starches and
polysaccharides; starch and polysaccharide xanthates; and,
dialdehyde starches and polysaccharides). Specific examples of
suitable modified starches and modified polysaccharides include,
but are not necessarily limited to: carboxymethyl starches and
polysaccharides; hydroxyethyl starches and polysaccharides;
hydroxypropyl starches and polysaccharides; hydroxybutyl starches
and polysaccharides; carboxymethylhydroxyethyl starches and
polysaccharides; carboxymethylhydroxypropyl starches and
polysaccharides; carboxymethylhydroxybutyl starches and
polysaccharides; epichlorohydrin starches and polysaccharides;
alkylene glycol modified starches and polysaccharides.
[0040] Particulate solid bridging agents include, but are not
limited to, barite (barium sulfate), calcium carbonate, and soluble
salts such as sodium chloride when used in a salt saturated
system.
[0041] Weighting agents typically include salts such as barite
(barium sulfate), sodium bromide, sodium chloride, potassium
chloride, calcium chloride, calcium bromide, zinc bromide and
mixtures of these salts. The weighting agents provide the fluid
with sufficient density so the hydrostatic pressure of the dense
fluid in the wellbore counterbalances pressure exerted by the fluid
in the strata.
[0042] The following examples are illustrative of some of the
embodiments of the present invention. Other embodiments within the
scope of the claims herein will be apparent to one skilled in the
art from consideration of the description set forth herein. It is
intended that the specification, together with the examples, be
considered exemplary only, with the scope and spirit of the
invention being indicated by the claims which follow.
[0043] All percentages set forth in the Examples are given in terms
of weight units except as may otherwise be indicated.
EXAMPLES
Examples 1-3
[0044] A drill-in fluid or mud (DIF) was used to verify the
effectiveness of a dispersant. The DIF contained 1 barrel of a 2
weight percent KCl brine, 8 pounds per barrel (ppb) of polymeric
starch as fluid loss control additive, 2.5 ppb of a viscosifying
xanthan XC-type polymer, 0.1 ppb of KOH, for pH control, 30 ppb of
calcium carbonate as fluid loss control additive and about 40 ppb
of simulated drilling solids (RevDust.TM. clay, a product of
Milwhite, Inc.). The presence of the RevDust.TM. mimics the
presence of very fine-particle drilled-solids, which accumulates
during drilling operations. It is anticipated that DIF would be
difficult to remove since it contains 8 ppb starch for fluid loss
control, the normal level being typically around 4 ppb. While the
presence of excess starch controls fluid loss more effectively,
filter cakes deposited with excess starch are typically more
difficult to remove. Furthermore, DIF contained 2.5 ppb xanthan
polymer while the typical amount is around 1 ppb. This further adds
to the anticipated difficulty of removing a deposited filter
cake.
[0045] DIF was then heat-aged for 16 hours at 190.degree. F. before
conducting fluid loss experiments. The fluid loss cell was fitted
with a 400 md Aloxite disk and the permeability values were
determined in the production and injection directions by flowing
water through the disk at constant pressure. The heat-aged DIF was
added to a fluid loss cell, heated to 190.degree. F., and then
filtrate was collected dynamically at 300 RPM for one hour and then
statically for 15 hours through a 400 md Aloxite disk with a
differential pressure of 800 psi. Residual DIF was then poured off
the deposited filter cake.
[0046] A filter cake removal treatment fluid was prepared based
upon an enzyme package designed to remove both starch and xanthan
polymer. This treatment fluid was composed of a 3% acetic acid
solution to which 50 pounds per thousand gallons (pptg)
Ferrotrol-300 (an iron control additive, a product of BJ Services
Company), 2.0 gallons per thousand gallons (gpt) C1-11 (except for
Example 3) (a corrosion inhibitor, a product of BJ Services
Company), 5.0 gpt NE-118 (a nonionic surfactant, a product of BJ
Services Company), 5.0 gpt dispersing agent when used, and 80 pptg
sodium acetate to create a buffer at pH 4. 50 gpt GBW-14C and 10
gpt GBW-16C (both enzymes available from BJ Services Company) were
then added. Example 2 and Comparative Example 1 further contained
about 50 gpt of 30-35% hydrogen peroxide added first to the acetic
acid solution, which is sometimes referred to as peroxyacetic
acid.
[0047] A dispersing agent was added to the filter cake removal
fluid in Examples 2-3. The dispersing agent A of Example 2 and 3
was an aqueous acid solution of bis-aminoalkyl ether phosphonate
containing less than 2 weight percent methanol. The fluid was then
added to the deposited DIF filter cake at 190.degree. F. The cell
was then pressurized and about 5 ml of filtrate was then removed.
The cell was then shut for about 16 hours, after which the filtrate
was collected. The resulting production and injection
permeabilities were then determined and compared with the initial
permeability values. The results are set forth in Table 1.
TABLE-US-00001 TABLE 1 Example No. Comp. Ex. 1 2 3 Treating
Oxidizing Oxidizing Non-Oxidizing Fluid Formulation Formulation
Formulation Composition (Without Dispersing (With Dispersing (With
Dispersing Agent) Agent A) Agent A) Hydrogen Yes Yes None Peroxide
Dispersing None 5 5 Agent, gpt Return 85 95 92 Perm, %, Prod Return
80 90 87 Perm, %, Inject gpt = gallons per thousand gallons
[0048] Table 1 illustrates that treatment of the filter cake with a
dispersing agent (Example 2) in accordance with the invention is
more effective than a similar treatment which did not contain a
dispersing agent (Comparative Example 1). A treatment fluid
containing the dispersing agent within the invention but not
hydrogen peroxide (Example 3) was still significantly more
effective in removal of the deposited filter cake than Comparative
Example 1.
Examples 4-5
[0049] The procedure of Examples 1-3. Example 4 uses the same
drill-in mud as set forth in Examples 1-3 above. In Example 5, the
drill-in mud (DIF-2) was prepared from 0.88 barrels of water, 9.5
ppb KCl, 55 ppb of a commercially available polymeric drill-in
fluid additive which further contains calcium carbonate, starch and
a viscosifying xanthan XC-type polymer, 11.3 ppb of calcium
carbonate as fluid loss control additive and about 36 ppb of
RevDust.
[0050] Further, the filter cake removal treatment fluid in Examples
4 and 5 was prepared from the same enzyme package described above.
The dispersing agent B was a mixture comprising an aqueous acid
solution of about 11 weight percent of bis-hexamethylene triamine
phosphonate, 13 weight percent of bis-hexamethylene triamine
pentaphosphonate and about 60 weight percent of monoethanol amine
phosphonate. Because the polymer system used in the DIF-2 was known
to be more difficult to break than xanthan polymer especially with
added drilled solids, the filter cake is more difficult to remove.
The results of the testing is set forth in Table II below:
TABLE-US-00002 TABLE II Example No. 4 5 Treating Fluid
Non-Oxidizing Non-Oxidizing Composition Formulation Formulation
(With Dispersing Agent B) (With Dispersing Agent B) Dispersing
Agent, gpt 5 5 Return Perm, %, Prod 91 96 Return Perm, %, Inject 86
89
[0051] From the foregoing, it will be observed that numerous
variations and modifications may be effected without departing from
the true spirit and scope of the novel concepts of the
invention.
* * * * *